18 CFR 161.3 Operating Expense Instructions
1. Supervision and engineering (Major natural gas companies). The
supervision and engineering includible in the operating expense accounts
shall consist of the pay and expenses of superintendents, engineers,
clerks, other employees and consultants engaged in supervising and
directing the operation and maintenance of each utility function.
Wherever allocations are necessary in order to arrive at the amount to
be included in any account the method and basis of allocation shall be
reflected by underlying records.
Labor:
1. Special tests to determine efficiency of equipment operation.
2. Preparing or reviewing budgets, estimates, and drawings relating
to operation or maintenance for departmental approval.
3. Preparing instructions for operations and maintenance activities.
4. Reviewing and analyzing operating results.
5. Establishing organizational setup of departments and executing
changes therein.
6. Formulating and reviewing routines of departments and executing
changes therein.
7. General training and instruction of employees by supervisors whose
pay is charge- able hereto. Specific instruction and training in a
particular type of work is chargeable to the appropriate functional
account. (See Gas Plant Instruction 3(19).)
8. Secretarial work for supervisory personnel, but not general
clerical and stenographic work chargeable to other accounts.
Expenses:
9. Consultants' fees and expenses.
10. Meals, traveling and incidental expenses.
2. Maintenance. A. The cost of maintenance chargeable to the various
operating expense and clearing accounts, includes labor, materials,
overheads and other expenses incurred in maintenance work. A list of
work operations applicable generally to utility plant is included
hereunder. Other work operations applicable to specific classes of
plant are listed in functional maintenance expense accounts.
B. Materials recovered in connection with the maintenance of property
shall be credited to the same account to which the maintenance cost was
charged.
C. If the book cost of any property is carried in account 102, Gas
Plant Purchased or Sold, the cost of maintaining such property shall be
charged to the accounts for maintenance of property of the same class
and use, the book cost of which is carried in other gas plant in service
accounts. Maintenance of property leased from others shall be treated
as provided in operating expense instruction 3.
1. Direct field supervision of maintenance.
2. Inspecting, testing, and reporting on condition of plant
specifically to determine the need for repairs, replacements, re-
arrangements and changes and inspecting and testing the adequacy of
repairs which have been made.
3. Work performed specifically for the purpose of preventing failure,
restoring serviceability or maintaining life of plant.
4. Rearranging and changing the location of plant not retired.
5. Repairing for reuse materials recovered from plant.
6. Testing for, locating and clearing trouble.
7. Net cost of installing, maintaining, and removing temporary
facilities to prevent interruptions in service.
8. Replacing or adding minor items of plant which do not constitute a
retirement unit. (See gas plant instruction 10.)
3. Rents. A. The rent expense accounts provided under the several
functional groups of expense accounts shall include all rents, including
taxes paid by the lessee on leased property, for property used in
utility operations, except (1) minor amounts paid for occasional or
infrequent use of any property or equipment and all amounts paid for use
of equipment that, if owned, would be includible in plant accounts 391
to 398, inclusive, which shall be treated as an expense item and
included in the appropriate functional account and (2) rents which are
chargeable to clearing accounts, and distributed therefrom to the
appropriate account. If rents cover property used for more than one
function, such as production and transmission, or by more than one
department, the rents shall be apportioned to the appropriate rent
expense or clearing accounts of each department on an actual, or, if
necessary, an estimated basis.
B. When a portion of property or equipment rented from others for use
in connection with utility operations is subleased, the revenue derived
from such subleasing shall be credited to the rent revenue account in
operating revenues: Provided, however, That in case the rent was
charged to a clearing account, amounts received from subleasing the
property shall be credited to such clearing account.
C. The cost, when incurred by the lessee, of operating and
maintaining leased property, shall be charged to the accounts
appropriate for the expense if the property were owned.
D. The cost incurred by the lessee of additions and replacements to
gas plant leased from other shall be accounted for as provided in gas
plant instruction 6.
4. Training costs. When it is necessary that employees be trained to
specifically operate or maintain plant facilities that are being
constructed, the related costs shall be accounted for as a current
operating and maintenance expense. These expenses shall be charged to
the appropriate functional accounts currently as they are incurred.
However, when the training costs involved relate to facilities which are
not conventional in nature, or are new to the company's operations, then
see Gas Plant Instruction 3(19) for accounting.
Balance Sheet Chart of Accounts
101 Gas plant in service.
101.1 Property under capital leases.
102 Gas plant purchased or sold.
103 Experimental gas plant unclassified (Major only).
103.1 Gas plant in process of reclassification (Nonmajor only).
104 Gas plant leased to others.
105 Gas plant held for future use.
105.1 Production properties held for future use (Major only).
106 Completed construction not classified -- Gas (Major only).
107 Construction work in progress -- Gas.
108 Accumulated provision for depreciation of gas utility plant
(Major only).
109 (Reserved)
110 Accumulated provision for depreciation, depletion, and
amortization of gas utility plant (Nonmajor only).
111 Accumulated provision for amortization and depletion of gas
utility plant (Major only).
111.1 -- 111.2 (Reserved)
112 (Reserved)
113.1 -- 113.2 (Reserved)
114 Gas plant acquisition adjustments.
115 Accumulated provision for amortization of gas plant acquisition
adjustments (Major only).
116 Other gas plant adjustments.
117 Gas stored underground -- Noncurrent (Major only).
118 Other utility plant.
119 Accumulated provision for depreciation and amortization of other
utility plant.
121 Nonutility property.
122 Accumulated provision for depreciation and amortization of
nonutility property.
123 Investment in associated companies (Major only).
123.1 Investment in subsidiary companies (Major only).
124 Other investments.
125 Sinking funds (Major only).
126 Depreciation fund (Major only).
128 Other special funds (Major only).
129 Special funds (Nonmajor only).
130 Cash and working funds (Nonmajor only).
131 Cash (Major only).
132 Interest special deposits (Major only).
133 Dividend special deposits (Major only).
134 Other special deposits (Major only).
135 Working funds (Major only).
136 Temporary cash investments.
141 Notes receivable.
142 Customer accounts receivable.
143 Other accounts receivable.
144 Accumulated provision for uncollectible accounts -- Cr.
145 Notes receivable from associated companies.
146 Accounts receivable from associated companies.
151 Fuel stock (Major only).
152 Fuel stock expenses undistributed (Major only).
153 Residuals and extracted products (Major only).
154 Plant materials and operating supplies (Major only).
155 Merchandise (Major only).
156 Other materials and supplies (Major only).
163 Stores expense undistributed (Major only).
164.1 Gas stored underground -- current.
164.2 Liquefied natural gas stored.
164.3 Liquefied natural gas held for processing (Major only).
165 Prepayments.
166 Advances for gas exploration, development, and production (Major
only).
167 Other advances for gas (Major only).
171 Interest and dividends receivable (Major only).
172 Rents receivable (Major only).
173 Accrued utility revenues (Major only).
174 Miscellaneous current and accrued assets.
181 Unamortized debt expense.
182.1 Extraordinary property losses.
182.2 Unrecovered plant and regulatory study costs.
183.1 Preliminary natural gas survey and investigation charges (Major
only).
183.2 Other preliminary survey and investigation charges (Major
only).
184 Clearing accounts (Major only).
185 Temporary facilities (Major only).
186 Miscellaneous deferred debits.
187 Deferred losses from disposition of utility plant.
188 Research, development, and demonstration expenditures (Major
only).
189 Unamortized loss on reacquired debt.
190 Accumulated deferred income taxes.
191 Unrecovered purchased gas costs.
201 Common stock issued.
202 Common stock subscribed (Major only).
203 Common stock liability for conversion (Major only).
204 Preferred stock issued.
205 Preferred stock subscribed (Major only).
206 Preferred stock liability for conversion (Major only).
207 Premium on capital stock (Major only).
208 Donations received from stockholders (Major only).
209 Reduction in par or stated value of capital stock (Major only).
210 Gain on resale or cancellation of reacquired capital stock (Major
only).
211 Miscellaneous paid-in capital.
212 Installments received on capital stock.
213 Discount on capital stock.
214 Capital stock expense.
215 Appropriated retained earnings.
216 Unappropriated retained earnings.
216.1 Unappropriated undistributed subsidiary earnings (Major only).
217 Reacquired capital stock.
218 Noncorporate proprietorship (Nonmajor only).
221 Bonds.
222 Reacquired bonds (Major only).
223 Advances from associated companies.
224 Other long-term debt.
225 Unamortized premium on long-term debt.
226 Unamortized discount on long-term debt -- Debit.
227 Obligations under capital leases -- noncurrent.
228.1 Accumulated provision for property insurance.
228.2 Accumulated provision for injuries and damages.
228.3 Accumulated provision for pensions and benefits.
228.4 Accumulated miscellaneous operating provisions.
229 Accumulated provision for rate refunds.
231 Notes payable.
232 Accounts payable.
233 Notes payable to associated companies.
234 Accounts payable to associated companies.
235 Customer deposits.
236 Taxes accrued.
237 Interest accrued.
238 Dividends declared (Major only).
239 Matured long-term debt (Major only).
240 Matured interest (Major only).
241 Tax collections payable (Major only).
242 Miscellaneous current and accrued liabilities.
243 Obligations under capital leases -- current.
252 Customer advances for construction.
253 Other deferred credits.
255 Accumulated deferred investment tax credits.
256 Deferred gains from disposition of utility plant.
257 Unamortized gain on reacquired debt.
281 Accumulated deferred income taxes -- Accelerated amortization
property.
282 Accumulated deferred income taxes -- Other property.
283 Accumulated deferred income taxes -- Other.
18 CFR 161.3 Balance Sheet Accounts
101 Gas plant in service.
A. This account shall include the original cost of gas plant,
included in accounts 301 to 399 prescribed herein, owned and used by the
utility in its gas operations, and having an expectation of life in
service of more than one year from date of installation. Including such
property owned by the utility but held by nominees. (See also account
106 for unclassified construction costs of completed plant actually in
service.)
B. The cost of additions to and betterments of property leased from
others, which are includible in this account, shall be recorded in
subdivisions separate and distinct from those relating to owned
property. (See gas plant instruction 6.)
101.1 Property under capital leases.
A. This account shall include the amount recorded under capital
leases for plant leased from others and used by the utility in its
utility operations.
B. The gas property included in this account shall be classified
separately according to the detailed accounts (301 to 399) prescribed
for gas plant in service.
C. Records shall be maintained with respect to each capital lease
reflecting: (1) Name of lessor, (2) basic details of lease, (3)
terminal date, (4) original cost fair market value of property leased,
(5) future minimum lease payments, (6) executory costs, (7) present
value of minimum lease payments, (8) the amounts representing interest
and the interest rate used, and (9) expenses paid.
102 Gas plant purchased or sold.
A. This account shall be charged with the cost of gas plant acquired
as an operating unit or system by purchase, merger, consolidation,
liquidation, or otherwise, and shall be credited with the selling price
of like property transferred to others pending the distribution to
appropriate accounts in accordance with gas plant instruction 5.
B. Within six months from the date of acquisition or sale of property
recorded herein, the utility shall file with the Commission the proposed
journal entries to clear from this account the amounts recorded herein.
103 Experimental gas plant unclassified (Major only).
A. This account shall include the cost of gas plant which was
constructed as a research, development, and demonstration project under
the provisions of paragraph C, Account 107, Construction Work in
Progress -- Gas, and due to the nature of the plant it is desirous to
operate it for a period of time in an experimental status.
B. Amounts in this account shall be transferred to Account 101, Gas
Plant in Service, or Account 121, Nonutility Property, as appropriate,
when the project is no longer considered as experimental. Prior to
transfer to account 101 the subject plant must be certified by the
Commission for use as gas plant in service.
C. The depreciation on property in this account shall be charged to
Account 403, Depreciation Expense, and credited to Account 108,
Accumulated Provision for Depreciation of Gas Utility Plant. The
amounts herein shall be depreciated over a period which would correspond
to the estimated useful life of the relevant project considering the
experimental characteristics involved. However, when projects are
transferred to Account 101, Gas Plant in Service, a new depreciation
rate based on the remaining service life and undepreciated amounts, will
be established.
D. Records shall be maintained with respect to each unit of
experiment so that full details may be obtained as to the cost,
depreciation, and the experimental status.
E. Should it be determined that experimental plants recorded in this
account will fail to satisfactorily perform its function, the costs
thereof shall be accounted for as directed or authorized by the
Commission.
103.1 Gas plant in process of reclassification (Nonmajor only).
A. This account shall include temporarily the balance of gas plant as
of the effective date of the prior system of accounts, which has not yet
been reclassified as of the effective date of this system of accounts.
The detail or primary accounts in support of this account employed prior
to such date shall be continued pending reclassification into the gas
plant accounts herein prescribed (301-399), but shall not be used for
additions, betterments, or new construction.
B. No charges other than as provided in paragraph A, above, shall be
made to this account, but retirements of such unclassified gas plant
shall be credited hereto and to the supporting (old) fixed capital
accounts until the reclassification shall have been accomplished.
104 Gas plant leased to others.
A. This account shall include the original cost of gas plant owned by
the utility but leased to others as operating units or systems, where
the lessee has exclusive possession.
B. The property included in this account shall be classified
according to the detailed accounts (301 to 399) prescribed for gas plant
in service and this account shall be maintained in such detail as though
the property were used by the owner in its utility operations.
105 Gas plant held for future use.
A. This account shall include the original cost of gas plant (except
land and land rights) owned and held for future use in gas service under
a definite plan for such use, to include: (1) Property acquired (except
land and land rights) but never used by the utility in gas service, but
held for such service in the future under a definite plan, and (2)
property (except land and land rights) previously used by the utility in
gas service, but retired from such service and held pending its reuse in
the future, under a definite plan, in gas service. This includes
production properties relating to leases acquired on or before October
7, 1969.
B. This account shall also include the original cost of land and land
rights owned and held for future use in gas service relating to leases
acquired on or before October 7, 1969, under a plan for such use, to
include land and land rights: (1) Acquired but never used by the
utility in gas service, but held for such service in the future under a
plan, and (2) previously held by the utility in gas service, but retired
from such service and held pending its reuse in the future under a plan,
in gas service. (See Gas Plant Instruction 7.)
C. In the event that property recorded in this account shall no
longer be needed or appropriate for future utility operations, the
company shall request Commission approval of journal entries to remove
such property from this account when the gain realized from the sale or
other disposition of the property is $100,000 or more, prior to their
being recorded. Such filings shall include the description and original
cost of individual properties removed from this account, the accounts
charged upon removal, and any associated gains realized upon disposition
of such property.
D. Gains or losses from the sale of land and land rights or other
disposition of such property previously recorded in this account and not
placed in utility service shall be recorded directly in accounts 411.6
or 411.7, as appropriate, except when determined to be significant by
the Commission. Upon such a determination, the amounts shall be
transferred to account 256, Deferred Gains from Disposition of Utility
Plant, or account 187, Deferred Losses from Disposition of Utility
Plant, and amortized to accounts 411.6, Gains from Disposition of
Utility Plant, or 411.7, Losses from Disposition of Utility Plant, as
appropriate.
E. The property included in this account shall be classified
according to the detail accounts (301 to 399) prescribed for gas plant
in service and the account shall be maintained in such detail as though
the property were in service.
Note A: Materials and supplies, meters and house regulators held in
reserve, and normal spare capacity of plant in service shall not be
included in this account.
Note B: Include in this account natural gas wells shut in after
construction which have not been connected with the line; also, natural
gas wells which have been connected with the line but which are shut in
for any reason except seasonal excess capacity or governmental proration
requirements or for repairs, provided that the related production leases
were acquired on or before October 7, 1969.
Note C (Nonmajor only): The loss on abandonment of natural gas
leases acquired after October 7, 1969, shall be charged to Account 338,
Unsuccessful Exploration and Development Costs.
105.1 Production properties held for future use (Major only).
A. This account shall include the cost of production properties
(except land and land rights) relating to leases acquired on or after
October 8, 1969, held under a definite plan for future use to insure a
future supply of natural gas for use in pipeline operations, to include:
(1) Production property (except land and land rights) acquired but
never used by the utility in gas service, but held for such service in
the future under a definite plan, and (2) production property (except
land and land rights) previously used by the utility in gas service, but
retired from such service and held pending its reuse in the future,
under a definite plan, in gas service.
B. This account shall also include the original cost of land and land
rights held under a plan for future use to insure a future supply of
natural gas for use in pipeline operations, relating to leases acquired
on or after October 8, 1969, to include land and land rights: (1)
Acquired but never used by the utility in gas service, but held for
service in the future under a plan, and (2) previously used by the
utility in gas service, but retired from such service and held pending
its reuse in the future under a plan, in gas service. (See Gas Plant
Instruction 7.)
C. In the event that property recorded in this account shall no
longer be needed or appropriate for future utility operations, the
company shall request Commission approval of journal entries to remove
such property from this account when the gain realized from the sale or
other disposition of the property is $100,000 or more, prior to their
being recorded. Such filings shall include the description and original
cost of individual properties removed from this account, the accounts
charged upon removal, and any associated gains realized upon disposition
of such property.
D. Gains or losses from the sale of land and land rights or other
disposition of such property previously recorded in this account and not
placed in utility service shall be recorded directly in accounts 411.6
or 411.7, as appropriate, except when determined to be significant by
the Commission. Upon such determination, the amounts shall be
transferred to account 256, Deferred Gains from Sale of Utility Plant,
or account 187, Deferred Losses from Sale of Utility Plant, and
amortized to accounts 411.6, Gains from Disposition of Utility Plant or
411.7, Losses from Disposition of Utility Plant, as appropriate.
E. The property included in this account shall be classified
according to the detailed accounts prescribed for natural gas production
and gathering plant in service and such classification shall be
maintained in the same detail as though the property were in service.
Note: Unsuccessful exploration and development costs incurred on
leases acquired after October 7, 1969, shall be charged to account 338,
Unsuccessful Exploration and Development Costs.
106 Completed construction not classified -- Gas (Major only).
At the end of the year or such other date as a balance sheet may be
required by the Commission, this account shall include the total of the
balances of work orders for gas plant which have been completed and
placed in service but which work orders have not been classified for
transfer to the detailed gas plant accounts.
Note: For the purpose of reporting to the Commission the
classification of gas plant in service by accounts is required, the
utility shall also report the balance in this account tentatively
classified as accurately as practicable according to prescribed account
classifications. The purpose of this provision is to avoid any
significant omissions in reported amounts of gas plant in service.
107 Construction work in progress -- Gas.
A. This account shall include the total of the balances of work
orders for gas plant in process of construction.
B. Work orders shall be cleared from this account as soon as
practicable after completion of the job. Further, if a project, such as
a gas production plant, a compressor station, or a transmission line, is
designed to consist of two or more units which may be placed in service
at different dates, any expenditures which are common to and which will
be used in the operation of the project as a whole shall be included in
gas plant in service upon the completion and the readiness for service
of the first unit. Any expenditures which are identified exclusively
with units of property not yet in service shall be included in this
account.
C. Expenditures on research, development, and demonstration projects
for construction of utility facilities are to be included in a separate
subdivision in this account. Records must be maintained to show
separately each project along with complete detail of the nature and
purpose of the research, development, and demonstration project together
with the related costs.
Note A: This account shall include certificate application fees paid
to the Federal Energy Regulatory Commission as provided for in gas plant
instruction 15.
Note B: Unsuccessful exploration and development costs incurred on
leases acquired after October 7, 1969, shall be transferred to account
338, Unsuccessful Exploration and Development Costs.
108 Accumulated provision for depreciation of gas utility plant
(Major only).
A. This account shall be credited with the following:
(1) Amounts charged to account 403, Depreciation Expense, or to
clearing accounts for current depreciation expense for gas plant in
service.
(2) Amounts charged to account 421, Miscellaneous Nonoperating
Income, for depreciation expense on property included in account 105,
Gas Plant Held for Future Use, or 105.1, Production Properties Held for
Future Use. Include also, the balance of accumulated provision for
depreciation on property when transferred to account 105 or 105.1, from
other property accounts. Normally, account 108 will not be used for
current depreciation provisions because, as provided herein, the service
life during which depreciation is computed commences with the date
property is includible in gas plant in service; however, if special
circumstances indicate the propriety of current accruals for
depreciation, such charges shall be made to account 421, Miscellaneous
Nonoperating Income.
(3) Amounts charged to account 413, Expenses of Gas Plant Leased to
Others, for gas plant included in account 104, Gas Plant Leased to
Others.
(4) Amounts charged to account 416, Costs and Expenses of
Merchandising, Jobbing and Contract Work, or to clearing accounts for
current depreciation expense.
(5) Amounts of depreciation applicable to gas properties acquired as
operating units or systems. (See gas plant instruction 5.)
(6) Amounts charged to account 182.1, Extraordinary Property Losses,
when authorized by the Commission.
(7) Amounts of depreciation applicable to gas plant donated to the
utility.
(The utility shall maintain separate subaccounts for depreciation
applicable to gas plant in service, gas plant leased to others and gas
plant held for future use.)
B. At the time of retirement of depreciable gas utility plant, this
account shall be charged with the book cost of the property retired and
the cost of removal and shall be credited with the salvage value and any
other amounts recovered, such as insurance. When retirements, cost of
removal and salvage are entered originally in retirement work orders,
the net total of such work orders may be included in a separate
subaccount hereunder. Upon completion of the work order, the proper
distribution to subdivision of this account shall be made as provided in
the following paragraph.
C. For general ledger and balance sheet purposes, this account shall
be regarded and treated as a single composite provision for
depreciation. For purposes of analysis, however, each utility shall
maintain subsidiary records in which this account is segregating
according to the following functional classification for gas plant:
(1) Production -- manufactured gas, (2) production and gathering --
natural gas, (3) products extraction -- natural gas, (4) underground gas
storage, (5) other storage, (6) base load LNG terminaling and processing
plant, (7) transmission, (8) distribution, and (9) general. These
subsidiary records shall reflect the current credits and debits to this
account in sufficient detail to show separately for each such functional
classification (a) the amount of provision for depreciation, (b) the
book cost of property retired, (c) cost of removal, (d) salvage, and (e)
other items, including recoveries from insurance.
D. When transfers of plant are made from one gas plant account to
another, or from or to another utility department, or from or to
nonutility property accounts, the accounting for the related accumulated
provision for depreciation shall be as provided in gas plant instruction
12.
E. The utility is restricted in its use of the provision for
depreciation to the purposes set forth above. It shall not transfer any
portion of this account to retained earnings or make any other use
thereof without authorization by the Commission.
109 (Reserved)
110 Accumulated provision for depreciation, depletion and
amortization of gas utility plant (Nonmajor only).
A. This account shall be credited with the following:
(1) Amounts charged to account 403, Depreciation and Depletion
Expense, to account 404, Amortization of Limited-Term Gas Plant, to
account 405, Amortization of Other Gas Plant, to account 413, Expenses
of Gas Plant Leased to Others, to account 416, Costs and Expenses of
Merchandising, Jobbing and Contract Work, or to clearing accounts for
currently accruing depreciation, depletion, and amortization.
(2) Amounts of depreciation, depletion or amortization applicable to
gas properties acquired as operating units or systems. (See gas plant
instruction 4.)
(3) Amounts chargeable to account 182.1, Extraordinary Property
Losses, when authorized by the Commission.
(4) Amounts of depreciation applicable to gas plant donated to the
utility.
B. At the time of retirement of gas plant, this account shall be
charged with the book cost of the property retired and the cost of
removal, and shall be credited with the salvage value and any other
amounts recovered, such as insurance. When retirements, cost of removal
and salvage are entered originally in retirement work orders, the net
total of such work orders may be included in a separate subaccount
hereunder. Upon completion of the work order, the property distribution
to subdivisions of this account shall be made as provided in the
following paragraph.
C. For general ledger and balance sheet purposes, this account shall
be regarded and treated as a single composite provision for
depreciation. The account shall be subdivided to show the amount,
applicable to Gas Plant in Service, Gas Plant Leased to Others, and Gas
Plant Held for Future Use. These subsidiary records shall show the
current credits and debits to this account in sufficient detail to show
separately for each subdivision, (1) the amount of accrual for
depreciation or amortization, (2) the book cost of property retired, (3)
cost of removal, (4) salvage and (5) other items, including recoveries
from insurance. The utility also shall maintain subsidiary records in
accordance with these provisions for accumulated depletion and
amortization provisions for natural gas land and land rights in service.
D. When transfers of plant made from one gas plant account to
another, or from or to nonutility property, the accounting shall be as
provided in gas plant instruction 10.
E. The utility is restricted in its use of the accumulated provision
for depreciation, depletion and amortization to the purposes set forth
above. It shall not transfer any portion of this account to retained
earnings or make any other use thereof without authorization by the
Commission.
111 Accumulated provision for amortization and depletion of gas
utility plant (Major only).
A. This account shall be credited with the following:
(1) Amounts charged to account 404.1, Amortization and Depletion of
Producing Natural Gas Land and Land Rights, for current amortization and
depletion of such land and land rights.
(2) Amounts charged to account 404.2, Amortization of Underground
Storage Land and Land Rights, for current amortization.
(3) Amounts charged to account 404.3, Amortization of Other
Limited-Term Gas Plant, for the current amortization of limited-term gas
plant.
(4) Amounts charged to account 421, Miscellaneous Nonoperating
Income, for amortization expense on property included in account 105,
Gas Plant Held for Future Use, or 105.1, Production Properties Held for
Future Use. Include also, the balance of accumulated provision for
amortization on property when transferred to account 105 or 105.1 from
other property accounts.
Note: See also paragraph A(2), of account 108, Accumulated Provision
for Depreciation of Gas Utility Plant.
(5) Amounts charged to account 405, Amortization of Other Gas Plant.
(6) Amounts charged to account 413, Expenses of Gas Plant Leased to
Others, for current amortization thereof.
(7) Amounts charged to account 797, Abandoned Leases, to provide for
the abandonment of nonproductive natural gas leases.
(8) Amounts charged to account 425, Miscellaneous Amortization, for
the amortization of intangible or other gas plant which does not have a
definite or terminable life and is not subject to charges for
depreciation expense, with Commission approval.
(The utility shall maintain subaccounts of this account for the
amortization applicable to producing natural gas land and land rights,
other gas plant in service, gas plant leased to others, abandonment of
leases and gas plant held for future use.)
B. When any property to which this account applies is sold,
relinquished, or otherwise retired from service, this account shall be
charged with the amount previously credited in respect to such property.
The book cost of the property so retired less the amount chargeable to
this account and less the net proceeds realized at retirement shall be
included in account 421.1, Gain on Disposition of Property, or account
421.2, Loss on Disposition of Property, as appropriate.
C. For general ledger and balance sheet purposes, this account shall
be regarded and treated as a single composite provision for
amortization.
For purposes of analysis, however, each utility shall maintain
subsidiary records in which this account is segregating according to the
following functional classification for gas plant:
(1) Production -- manufactured gas, (2) production and gathering --
natural gas, (3) products extraction -- natural gas, (4) underground gas
storage, (5) other storage, (6) base load LNG terminaling and processing
plant, (7) transmission, (8) distribution, and (9) general. These
subsidiary records shall reflect the current credits and debits to this
account in sufficient detail to show separately for each such functional
classification (a) the amount of provision for amortization, (b) the
book cost of property retired, (c) cost of removal, (d) salvage, and (e)
other items, including recoveries from insurance. Records shall be
maintained so as to show separately the balance applicable to each item
of land and land rights which is being amortized or depleted except that
natural gas land and land rights which comprise an interest in a
production area may be grouped to form a unit for amortization and
depletion and the accumulated provision applicable thereto need not be
segregated to show the amount related to each gas right included
therein. Records shall also be maintained so as to show separately the
balance applicable to each underground gas storage project.
D. The utility is restricted in its use of the accumulated provision
for amortization to the purposes set forth above. It shall not transfer
any portion of this account to retained earnings or make any other use
thereof without authorization by the Commission.
112 -- 113 (Reserved)
114 Gas plant acquisition adjustments.
A. This account shall include the difference between (a) the cost to
the accounting utility of gas plant acquired as an operating unit or
system by purchase, merger, consolidation, liquidation, or otherwise,
and (b) the original cost, estimated, if not known, of such property,
less the amount or amounts credited by the accounting utility at the
time of acquisition to accumulated provisions for depreciation,
depletion, and amortization and contributions in aid of construction
with respect to such property.
B. With respect to acquisitions after the effective date of this
system of accounts, this account shall be subdivided so as to show the
amounts included herein for each property acquisition and to gas plant
in service, gas plant held for future use and gas plant leased to
others. (See gas plant instruction 5.)
C. Debit amounts recorded in this account related to plant and land
acquisition may be amortized to account 425, Miscellaneous Amortization,
over a period not longer than the estimated remaining life of the
properties to which such amounts relate. Amounts related to the
acquisition of land only may be amortized to account 425 over a period
of not more than 15 years. Should a utility wish to account for debit
amounts in this account in any other manner, it shall petition the
Commission for authority to do so. Credit amounts recorded in this
account shall be accounted for as directed by the Commission.
115 Accumulated provision for amortization of gas plant acquisition
adjustments (Major only).
This account shall be credited or debited with amounts which are
includible in account 406, Amortization of Gas Plant Acquisition
Adjustments or account 425, Miscellaneous Amortization, for the purpose
of providing for the extinguishment of amounts in account 114, Gas Plant
Acquisition Adjustments, in instances where the amortization of account
114 is not being made by direct write-off of the account.
116 Other gas plant adjustments.
A. This account shall include the difference between the original
cost, estimated if not known, and the book cost of gas plant to the
extent that such difference is not properly includible in account 114
Gas Plant Acquisition Adjustments. (For Major companies, see gas plant
instruction 1C.)
B. Amounts included in this account shall be classified in such
manner as to show the origin of each amount and shall be disposed of as
the Commission may approve or direct.
Note: The provisions of this account shall not be construed as
approving or authorizing the recording of appreciation of gas plant.
117 Gas stored underground -- Noncurrent (Major only).
A. This account shall include the cost of recoverable gas purchased
or produced by the utility which is stored in depleted or partially
depleted gas or oil fields, or other underground reservoirs, and held
for use in meeting service requirements of the utility's customers.
B. Gas stored during the year shall be priced at cost according to
generally accepted methods of cost determination consistently applied
from year to year. Transmission expenses for facilities of the utility
used in moving the gas to the storage area and expenses of storage
facilities shall not be included in the inventory of gas except as may
be authorized or directed by the Commission.
Note B-1: In general, gas stored from the supply in an integrated
system shall be priced at the average cost of the gas constituting the
common supply of the system, although this general rule may be departed
from where conditions of system operation of gas supply and utilization
permit a valid presumption that the gas stored may be considered to be
from specified sources, as indicated below.
Note B-2: When in harmony with the over-all system operation of gas
supply and utilization, and the presumption is consistently observed
from year to year, gas stored during the year may be presumed to be from
total gas purchases, or from purchases from specified sources. When
either of these presumptions is proper, the cost of gas stored shall be
priced at the weighted average cost of all gas purchased, or at the
weighted average cost of purchases from the specified sources, as
appropriate. The weighted average cost may be the average for the
preceding twelve months, except where a significant change occurs in the
cost of gas, the full effect of such change shall be reflected for the
period after the change is effective.
Note B-3: When in harmony with the over-all system operation of gas
supply and utilization, and the presumptions are consistently observed
from year to year, gas stored during the year may be presumed to be from
identified sources of the utility's own production. Such stored gas
shall be priced at the weighted average cost of gas produced from the
specified production areas. Where this presumption is made, or where
the stored gas is identified as a matter of fact under circumstances
which do not permit a proper application of the theory of displacement,
the utility shall maintain separate records of the cost of gas produced
from such areas and the derivation of the cost used for stored gas from
such sources.
Note B-4: Where gas is purchased specifically for storage, or a
price concession received because of the storing of purchased gas, such
gas shall be priced at the net contract price of the gas so purchased
and stored.
Note B-5: The provisions of this instruction and the related
footnotes shall not be construed as permitting or authorizing a
restatement of the amounts at which stored gas inventories are stated on
the utility's books at the effective date of this instruction, except as
may be authorized by the Commission.
C. Withdrawals of gas may be priced according to the
first-in-first-out, last-in-first-out, or weighted average cost method,
in connection with which a ''base stock'' may be employed provided the
method adopted by the utility is used consistently from year to year and
the inventory records are maintained in accordance therewith. Approval
of the Commission must be obtained for any other pricing method, or
change in the pricing method adopted by the utility.
D. If the gas of any storage project is withdrawn below the amount
established as ''base stock'' or encroaches upon native gas of a storage
reservoir, and such gas is to be replaced within 12 months, it shall be
permissible to price such gas at the estimated cost of replacement with
purchased gas and to record a deferred credit therefor. For the purpose
of this instruction, account 808, Gas Withdrawn from Storage -- Debit,
shall be charged with the estimated cost of such replacement gas and
account 253, Other Deferred Credits, credited. When replacement of the
gas is made the amount in account 253 shall be cleared and this account
credited. This accounting will not affect normal accounting for inputs
and withdrawals from storage.
E. Separate records shall be maintained for each storage project of
the Mcf of gas delivered to storage, withdrawn from storage, and
remaining in storage. The projects shall be grouped, however, for the
purpose of maintaining inventory cost records of the cost of gas in
storage. Exceptions to this general rule are permitted in any of the
following circumstances:
(a) Projects at the supply end of long transmission lines,
(b) Projects located on separate noninterconnected pipeline systems,
and
(c) Projects which by contractual arrangements approved by the
Commission are devoted exclusively to the service of specified
customers, and no portion of the gas withdrawals from any such project
becomes part of the common system gas supply by displacement or
otherwise.
Where the utility establishes specified volumes of gas as ''base
stock,'' separate inventory cost records by projects shall be maintained
therefor.
F. Amounts debited to this account for gas placed in storage shall be
credited to account 808.2 Gas Delivered to Storage -- Credit. Amounts
credited to this account for gas withdrawn from storage shall be debited
to account 808, Gas Withdrawn from Storage -- Debit.
G. Adjustments for Inventory losses due to cumulative inaccuracies of
gas measurements, or from other causes, shall be charged to account 823,
Gas Losses. In the operation of storage projects, the utility shall
maintain such procedures of verification as will disclose and result in
prompt accounting recognition of significant losses.
This account shall be credited with an amount equal to that debited
to account 164.1, Gas Stored Underground -- Current, to classify for
balance sheet purposes such portion of the total inventory of gas stored
underground as constitutes a current asset according to conventional
rules for classification of current assets. (See account 164.1.)
118 Other utility plant.
This account shall include the balance in accounts for utility plant,
other than gas plant, such as electric, railway, etc.
119 Accumulated provision for depreciation and amortization of other
utility plant.
This account shall include the accumulated provision for depreciation
and amortization applicable to utility property other than gas plant.
121 Nonutility property.
A. This account shall include the book cost of land, structures,
equipment or other tangible or intangible property owned by the utility,
but not used in utility service and not properly includible in account
105, Gas Plant Held for Future Use.
B. This account shall also include the amount recorded under capital
leases for property leased from others and used by the utility in its
nonutility operations. Records shall be maintained with respect to each
lease reflecting: (1) name of lessor, (2) basic details of lease, (3)
terminal date, (4) original cost or fair market value of property
leased, (5) future minimum lease payments, (6) executory costs, (7)
present value of minimum lease payments, (8) the amount representing
interest and the interest rate used, and (9) expenses paid.
C. This account shall be subdivided so as to show the amount of
property used in operations which are nonutility in character but
nevertheless constitute a distinct operating activity of the company
(such as operation of an ice department where such activity is not
classed as a utility) and the amount of miscellaneous property not used
in operations. The records in support of each subaccount shall be
maintained so as to show an appropriate classification of the property.
Note: In the event of the subsequent sale or other disposition of
property included in this account which had been previously recorded in
account 105, Gas Plant Held for Future Use, or account 105.1, Production
Properties Held for Future Use, such property costs shall be accounted
for in accordance with paragraph C of accounts 105 and 105.1,
respectively.
122 Accumulated provision for depreciation and amortization of
nonutility property.
This account shall include the accumulated provision for depreciation
and amortization applicable to nonutility property.
123 Investment in associated companies (Major only).
A. This account shall include the book cost of investments in
securities issued or assumed by associated companies and investment
advances to such companies, including interest accrued thereon when such
interest is not subject to current settlement, provided that the
investment does not relate to a subsidiary company. (If the investment
relates to a subsidiary company it shall be included in account entry to
the recording of amortization of discount or premium on interest bearing
investments. Include herein the offsetting 123.1, Investment in
Subsidiary Companies.) (See account 419, Interest and Dividend Income.)
B. This account shall be maintained in such manner as to show the
investment in securities of, and advances to, each associated company
together with full particulars regarding any of such investments that
are pledged.
Note A: Securities and advances of associated companies owned and
pledged shall be included in this account, but such securities, if held
in special deposits or in special funds, shall be included in the
appropriate deposit or fund account. A complete record of securities
pledged shall be maintained.
Note B: Securities of associated companies held as temporary cash
investments are includible in account 136, Temporary Cash Investments.
Note C: Balances in open accounts with associated companies, which
are subject to current settlement, are includible in account 146,
Accounts Receivable from Associated Companies.
Note D: The utility may write down the cost of any security in
recognition of a decline in the value thereof. Securities shall be
written off or written down to a nominal value if there be no reasonable
prospect of substantial value. Fluctuations in market value shall not
be recorded but a permanent impairment in the value of securities shall
be recognized in the accounts. When securities are written off or
written down, the amount of the adjustment shall be charged to account
426.5, Other Deductions, or to an appropriate account for accumulated
provisions for loss in value established as a separate subdivision of
this account.
123.1 Investment in subsidiary companies (Major only).
A. This account shall include the cost of investments in securities
issued or assumed by subsidiary companies and investment advances to
such companies, including interest accrued thereon when such interest is
not subject to current settlement plus the equity in undistributed
earnings or losses of such subsidiary companies since acquisition. This
account shall be credited with any dividends declared by such
subsidiaries.
B. This account shall be maintained in such a manner as to show
separately for each subsidiary: The cost of such investments in the
securities of the subsidiary at the time of acquisition; the amount of
equity in the subsidiary's undistributed net earnings or net losses
since acquisition; advances or loans to such subsidiary; and full
particulars regarding any such investments that are pledged.
124 Other investments.
A. This account shall include the book cost of investments in
securities issued or assumed by nonassociated companies, investment
advances to such companies, and any investments not accounted for
elsewhere. Include also the offsetting entry to the recording of
amortization of discount or premium on interest bearing investments.
(See account 419, Interest and Dividend Income.)
B. The cost of capital stock of the utility reacquired by it under a
definite plan for resale pursuant to authorization by the Board of
Directors may, if permitted by statutes, be included in a separate
subdivision of this account. (See also account 210, Gain on Resale or
Cancellation of Reacquired Capital Stock, and account 217, Reacquired
Capital Stock.)
C. The records shall be maintained in such manner as to show the
amount of each investment and the investment advances to each person.
Note A: Securities owned and pledged shall be included in this
account, but securities held in special deposits or in special funds
shall be included in appropriate deposit or fund accounts. A complete
record of securities pledged shall be maintained.
Note B: Securities held as temporary cash investments shall not be
included in this account.
Note C: See Note D of account 123.
125 Sinking funds (Major only).
This account shall include the amount of cash and book cost of
investments held in sinking funds. A separate account, with appropriate
title, shall be kept for each sinking fund. Transfers from this account
to special deposit accounts, may be made as necessary for the purpose of
paying matured sinking-fund obligations, or obligations called for
redemption but not presented, or the interest thereon.
126 Depreciation fund (Major only).
This account shall include the amount of cash and the book cost of
investments which have been segregated in a special fund for the purpose
of identifying such assets with the accumulated provisions for
depreciation.
128 Other special funds (Major only).
This account shall include the amount of cash and book cost of
investments which have been segregated in special funds for insurance,
employee pensions, savings, relief, hospital, and other purposes not
provided for elsewhere. A separate account, with appropriate title
shall be kept for each fund.
Note: Amounts deposited with a trustee under the terms of an
irrevocable trust agreement for pensions or other employee benefits
shall not be included in this account.
Current and accrued assets are cash, those assets which are readily
convertible into cash or are held for current use in operations or
construction, current claims against others, payment of which is
reasonably assured, and amounts accruing to the utility which are
subject to current settlement, except such items for which accounts
other than those designated as current and accrued assets are provided.
There shall not be included in the group of accounts designated as
current and accrued assets any item, the amount or collectibility of
which is not reasonably assured, unless an adequate provision for
possible loss has been made therefor. Items of current character but of
doubtful value may be written down and for record purposes carried in
these accounts at nominal value.
129 Special funds (Nonmajor only).
This account shall include the amount of cash and book cost of
investments which have been segregated in special funds for bond
retirements, property additions and replacements, insurance, employees'
pensions, savings, relief, hospital, and other purposes not provided for
elsewhere. A separate account, with appropriate title, shall be kept
for each fund.
Note: Amounts deposited with a trustee under the terms of an
irrevocable trust agreement for pensions or other employees' benefits
shall not be included in this account.
Current and accrued assets are cash, those assets which are readily
convertible into cash or are held for current use in operations or
construction, current claims against others, payment of which is
reasonably assured, and amounts accruing to the utility which are
subject to current settlement, except such items for which accounts
other than those designated as current and accrued assets are made
therefor. There shall not be included in the group of accounts
designated as current and accrued assets any item, the amount or
collectibility of which is not reasonably assured, unless an adequate
provision for possible loss has been provided. Items of current
character but of doubtful value may be written down and for record
purposes carried in these accounts at nominal value.
130 Cash and working funds (Nonmajor only).
This account shall include the amount of cash on hand and in banks
and cash advanced to officers, agents, employees, and others as petty
cash or working funds. Special cash deposits for payment of interest,
dividends or other special purposes shall be included in this account in
separate subdivisions which shall specify the purpose for which each
such special deposit is made.
Note: Special deposits for more than one year, which are not offset
by current liabilities, shall not be charged to this account but to
account 125, Special Funds.
131 Cash (Major only).
This account shall include the amount of current cash funds except
working funds.
132 Interest special deposits (Major only).
This account shall include special deposits with fiscal agents or
others for the payment of interest.
133 Dividend special deposits (Major only).
This account shall include special deposits with fiscal agents or
others for the payment of dividends.
134 Other special deposits (Major only).
This account shall include deposits with fiscal agents or others for
special purposes other than the payment of interest and dividends. Such
special deposits may include cash deposited with federal, state, or
municipal authorities as a guaranty for the fulfillment of obligations;
cash deposited with trustees to be held until mortgaged property sold,
destroyed, or otherwise disposed of is replaced; cash realized from the
sale of the accounting utility's securities and deposited with trustees
to be held until invested in property of the utility, etc. Entries to
this account shall specify the purpose for which the deposit is made.
Note: Assets available for general corporate purposes shall not be
included in this account. Further, deposits for more than one year,
which are not offset by current liabilities, shall not be charged to
this account but to account 128, Other Special Funds.
135 Working funds (Major only).
This account shall include cash advanced to officers, agents,
employees, and others as petty cash or working funds.
136 Temporary cash investments.
A. This account shall include the book cost of investments, such as
demand and time loans, bankers' acceptances, United States Treasury
certificates, marketable securities, and other similar investments,
acquired for the purpose of temporarily investing cash.
B. This account shall be so maintained as to show separately
temporary cash investments in securities of associated companies and of
others. Records shall be kept of any pledged investments.
141 Notes receivable.
This account shall include the book cost, not includible elsewhere,
of all collectible obligations in the form of notes receivable and
similar evidences (except interest coupons) of money due on demand or
within one year from the date of issue, except, however, notes
receivable from associated companies. (See account 136, Temporary Cash
Investments, and account 145, Notes Receivable from Associated
Companies.)
Note: The face amount of notes receivable discounted, sold, or
transferred without releasing the utility from liability as endorser
thereon, shall be credited to a separate subdivision of this account and
appropriate disclosure shall be made in financial statements of any
contingent liability arising from such transactions.
142 Customer accounts receivable.
A. This account shall include amounts due from customers for utility
service, and for merchandising, jobbing, and contract work. This
account shall not include amounts due from associated companies.
B. This account shall be maintained so as to permit ready segregation
of the amounts due for merchandising, jobbing, and contract work.
143 Other accounts receivable.
A. This account shall include amounts due the utility upon open
accounts, other than amounts due from associated companies and from
customers for utility services and merchandising, jobbing, and contract
work.
B. This account shall be maintained so as to show separately amounts
due on subscriptions to capital stock and from officers and employees,
but the account shall not include amounts advanced to officers or others
as working funds. (See account 135, Working Funds.)
144 Accumulated provision for uncollectible accounts -- Cr.
A. This account shall be credited with amounts provided for losses on
accounts receivable which may become uncollectible, and also with
collections on accounts previously charged hereto. Concurrent charges
shall be made to account 904, Uncollectible Accounts, for amounts
applicable to utility operations, and to corresponding accounts for
other operations. Records shall be maintained so as to show the
write-offs of accounts receivable for each utility department.
B. This account shall be subdivided to show the provision applicable
to the following classes of accounts receivable:
Utility Customers.
Merchandising, Jobbing and Contract Work.
Officers and Employees.
Others.
Note A: Accretions to this account shall not be made in excess of a
reasonable provision against losses of the character provided for.
Note B: If provisions for uncollectible notes receivable or for
uncollectible receivables from associated companies are necessary,
separate subaccounts therefor shall be established under the account in
which the receivable is carried.
145 Notes receivable from associated companies.
146 Accounts receivable from associated companies.
These accounts shall include notes and drafts upon which associated
companies are liable, and which mature and are expected to be paid in
full not later than one year from date of issue, together with any
interest thereon, and debit balances subject to current settlement in
open accounts with associated companies. Items which do not bear a
specified due date but which have been carried for more than twelve
months and items which are not paid within twelve months from due date
shall be transferred to account 123, Investment in Associated Companies.
Note A: On the balance sheet, accounts receivable from an associated
company may be set off against accounts payable to the same company.
Note B: The face amount of notes receivable discounted, sold or
transferred without releasing the utility from liability as endorser
thereon, shall be credited to a separate subdivision of this account and
appropriate disclosure shall be made in financial statements of any
contingent liability arising from such transactions.
151 Fuel stock (Major only).
This account shall include the book cost of fuel on hand.
1. Invoice price of fuel less any cash or other discounts.
2. Freight, switching, demurrage and other transportation charges,
not including, however, any charges for unloading from the shipping
medium.
3. Excise taxes, purchasing agents' commissions, insurance and other
expenses directly assignable to cost of fuel.
152 Fuel stock expenses undistributed (Major only).
A. This account may include the cost of labor and of supplies used
and expenses incurred in unloading fuel from the shipping medium and in
the handling thereof prior to its use, if such expenses are sufficiently
significant in amount to warrant being treated as a part of the cost of
fuel inventory rather than being charged direct to expense as incurred.
B. Amounts included herein shall be charged to expense as the fuel is
used to the end that the balance herein, shall not exceed the expenses
attributable to the inventory of fuel on hand.
Labor:
1. Procuring and handling of fuel.
2. All routine fuel analyses.
3. Unloading from shipping facility and putting in storage.
4. Moving of fuel in storage and transferring from one station to
another.
5. Handling from storage or shipping facility to first bunker,
hopper, bucket, tank or holder of boiler house structure.
6. Operation of mechanical equipment, such as locomotives, trucks,
cars, boats, barges, cranes, etc.
Supplies and Expenses:
7. Tools, lubricants and other supplies.
8. Operating supplies for mechanical equipment.
9. Transportation and other expenses in moving fuel.
10. Stores expenses applicable to fuel.
153 Residuals and extracted products (Major only).
This account shall include the book cost of residuals or extracted
products produced in the manufacture of gas or in natural gas products
extraction operations including like products purchased for resale.
154 Plant materials and operating supplies.
A. This account shall include the cost of materials purchased
primarily for use in the utility business for construction, operation
and maintenance purposes. For Nonmajor utilities, this account shall
include the cost of fuel on hand and unapplied materials and supplies
(except meters and house regulators). For both Major and Nonmajor
utilities, it shall include also the book cost of materials recovered in
connection with construction, maintenance or the retirement of property,
such materials being credited to construction, maintenance or
accumulated depreciation provision, respectively, and included herein as
follows:
(1) Reusable materials consisting of large individual items shall be
included in this account at original cost, estimated if not known. The
cost of repairing such items shall be charged to the maintenance account
appropriate for the previous use.
(2) Reusable materials consisting of relatively small items, the
identity of which (from the date of original installation to the final
abandonment or sale thereof) cannot be ascertained without undue
refinement in accounting, shall be included in this account at current
prices new for such items. The cost of repairing such items shall be
charged to the appropriate expense account as indicated by previous use.
(3) Scrap and nonusable materials included in this account shall be
carried at the estimated net amount realizable therefrom. The
difference between the amounts realized for scrap and nonusable
materials sold and the net amount at which the materials were carried in
this account, as far as practicable, shall be adjusted to the accounts
credited when the materials were charged to this account.
B. Materials and supplies issued shall be credited hereto and charged
to the appropriate construction, operating expense, or other account on
the basis of a unit price determined by the use of cumulative average,
first-in-first out, or such other method of inventory accounting as
conforms with accepted accounting standards consistently applied.
C. For Nonmajor utilities, inventories of materials, supplies, fuel,
etc., shall be taken at least annually and the necessary adjustments
shall be made to bring this account into agreement with the actual
inventories. In effecting the adjustments, large differences which can
be assigned to important classes of materials shall be equitably
adjusted among the accounts to which such classes of materials have been
charged since the previous inventory. Other differences shall be
equitably apportioned among the accounts to which materials have been
charged.
1. Invoice price of materials less cash or other discounts.
2. Freight, switching or other transportation charges when
practicable to include as part of the cost of particular materials to
which they relate.
3. Customs duties and excise taxes.
4. Costs of inspection and special tests prior to acceptance.
5. Insurance and other directly assignable charges.
Note A: Where expenses applicable to materials purchased cannot be
directly assigned to particular purchases, they may be charged to a
stores expense clearing account (account 163, Stores Expenses
Undistributed, in the case of Major Utilities), and distributed
therefrom to the appropriate accounts.
Note B: When materials and supplies are purchased for immediate use,
they need not be carried through this account but may be charged
directly to the appropriate gas plant or expense account.
155 Merchandise (Major only).
This account shall include the book cost of materials and supplies,
and appliances and equipment held primarily for merchandising, jobbing,
and contract work. The principles prescribed in accounting for utility
materials and supplies shall be observed in respect to items carried in
this account.
156 Other materials and supplies (Major only).
This account shall include the book cost of materials and supplies
held primarily for nonutility purposes. The principles prescribed in
accounting for utility materials and supplies shall be observed in
respect to items carried in this account.
163 Stores expense undistributed (Major only).
A. This account shall include the cost of supervision, labor and
expenses incurred in the operation of general storerooms, including
purchasing, storage, handling and distribution of materials and
supplies.
B. This account shall be cleared by adding to the cost of materials
and supplies issued a suitable loading charge which will distribute the
expense equitably over stores issues. The balance in the account at the
close of the year shall not exceed the amount of stores expenses
reasonably attributable to the inventory of materials and supplies
exclusive of fuel, as any amount applicable to fuel cost should be
included in account 152, Fuel Stock Expenses Undistributed.
Labor:
1. Inspecting and testing materials and supplies when not assignable
to specific items.
2. Unloading from shipping facility and putting in storage.
3. Supervision of purchasing and stores department to extent
assignable to materials handled through stores.
4. Getting materials from stock and in readiness to go out.
5. Inventorying stock received or stock on hand by stores employees
but not including inventories by general department employees as part of
internal or general audits.
6. Purchasing department activities in checking material needs,
investigating sources of supply, analyzing prices, preparing and placing
orders, and related activities to extent applicable to materials handled
through stores. (Optional. Purchasing department expenses may be
included in administrative and general expenses.)
7. Maintaining stores equipment.
8. Cleaning and tidying storerooms and stores offices.
9. Keeping stock records, including recording and posting of material
receipts and issues and maintaining inventory record of stock.
10. Collecting and handling scrap materials in stores.
Supplies and Expenses:
11. Adjustments of inventories of materials and supplies but not
including large differences which can readily be assigned to important
classes of materials and equitably distributed among the accounts to
which such classes of materials have been charged since the previous
inventory.
12. Cash and other discounts not practically assignable to specific
materials.
13. Freight, express, etc., when not assignable to specific items.
14. Heat, light and power for storerooms and store offices.
15. Brooms, brushes, sweeping compounds and other supplies used in
cleaning and tidying storerooms and stores offices.
16. Injuries and damages.
17. Insurance on materials and supplies and on stores equipment.
18. Losses due to breakage, leakage, evaporation, fire or other
causes, less credits for amounts received from insurance, transportation
companies or others in compensation of such losses.
19. Postage, printing, stationery and office supplies.
20. Rent of storage space and facilities.
21. Communication service.
22. Excise and other similar taxes not assignable to specific
materials.
23. Transportation expense on inward movement of stores and on
transfer between storerooms but not including charges on materials
recovered from retirements which shall be accounted for as part of cost
of removal.
Note: A physical inventory of each class of materials and supplies
shall be made at least every two years.
164.1 Gas stored underground -- current.
This account shall be debited with such amounts as are credited to
account 117, Gas Stored Underground -- Noncurrent, to reflect
classification for balance sheet purposes of such portion of the
inventory of gas stored underground as represents a current asset
according to conventional rules for classification of current assets.
Note: It shall not be considered conformity to conventional rules of
current asset classification if the amount included in this account
exceeds an amount equal to the cost of estimated withdrawals of gas from
storage for purposes of sale within the 24-month period from date of the
balance sheet, or if the amount represents a volume of gas which, in
fact, could not be withdrawn from storage without impairing the pressure
level of any project for normal operating purposes.
164.2 Liquefied natural gas stored.
A. This account shall include the cost of liquefied natural gas
stored in above or below ground facilities.
B. Natural gas purchased in a liquefied form shall be priced at the
cost of such gas to the utility. Natural gas liquefied by the utility
shall be priced according to generally accepted methods of cost
determination consistently applied from year to year. Transmission
expenses for facilities to the utility used in moving the gas to the
storage facilities shall not be included in the inventory of gas except
as may be authorized by the Commission.
C. Amounts debited to this account for natural gas placed in stored
shall be credited to account 808.2, Gas Delivered to Storage -- Credit.
Amounts credited to this account for gas withdrawn from storage shall be
debited to account 808.1, Gas Withdrawn from Storage -- Debit.
D. Withdrawals of gas may be priced according to the
first-in-first-out, last-in-first-out, or weighted average cost method
provided the method adopted by the utility is used consistently from
year to year and inventory records are maintained in accordance
therewith. Commission approval must be obtained for any other pricing
method or for any change in the pricing method adopted by the utility.
Separate records shall be maintained for each storage project of the Mcf
of gas delivered to storage and remaining in storage.
E. Adjustments for inventory losses shall be charged to account
842.3, Gas Losses.
164.3 Liquefied natural gas held for processing (Major only).
A. This account shall include the cost of base load liquefied natural
gas available for vaporization and injection into the utility's natural
gas system.
B. Natural gas purchased in a liquefied form shall be priced at the
cost of such gas to the utility.
C. Amounts debited to this account for liquefied natural gas
purchased for processing shall be credited to account 809.2, Deliveries
of Natural Gas for Processing -- Credit. Amounts credited for liquefied
natural gas processed shall be debited to account 809.1, Withdrawals of
Liquefied Natural Gas Held for Processing -- Debit.
D. Withdrawals of gas held for vaporization may be priced according
to the first-in-first-out, last-in-first-out or weighted average cost
method provided the method adopted by the utility is used consistently
from year to year and inventory records are maintained in accordance
therewith. Commission approval must be obtained for any other pricing
method or for any change from the pricing method adopted by the utility.
Separate records shall be maintained for Mcf (or Btu) of gas purchased
for processing, processed, and remaining for processing.
E. Adjustments for inventory losses shall be charged to account
846.1, Gas Losses.
165 Prepayments.
A. This account shall include payments for undelivered gas and other
prepayments of rents, taxes, insurance, interest, and like disbursements
made prior to the period to which they apply. Prepayments for gas are
those amounts paid to a seller of gas under ''take or pay'' provisions
of a gas purchase contract for a sale certificated by the Commission
where future makeup of the gas not taken in the current period is
provided for by the contract.
B. As the periods covered by such prepayments expire, credit this
account and charge the proper operating expense or other appropriate
account with the amount applicable to the period.
C. This account shall be kept or supported in such a manner as to
disclose the amount of each class of prepayments.
166 Advances for gas exploration, development and production (Major
only).
A. This account shall include all advances made for gas (whether
called ''advances,'' ''contributions'' or otherwise) to independent
producers, affiliated or associated companies, or others operating
within the lower 48 states and Alaska; for exploration, development or
production (but not to include lease acquisition) of natural gas. Under
each agreement with payee, such payments must be made prior to initial
gas deliveries, or if the agreement provides for advances on a well by
well basis, each incremental payment must be made prior to deliveries
from an incremental well, or prior to Federal and/or State
authorization, as appropriate. All agreements executed after June 17,
1975, (issuance date of Order No. 529) shall specify that (1) the
pipeline shall have first call on any gas produced, attributable to the
advance payment, under a long-term contract which is for a minimum
initial term computed as the lesser of fifteen years or the life of the
reserve in the field, and (2) the selling price of the gas committed by
producers whose sales are subject to price regulation shall be governed
by and limited to the area rate or national rate or, under appropriate
showing of special circumstance, such other rate as may be authorized by
the Commission under the provisions of optional pricing and special
relief. As a determination of the initial rate, the time of first
delivery in interstate commerce to the purchaser shall govern.
Non-current advances not to be repaid within a two-year period shall be
reclassified and transferred to account 124, Other Investments, for
balance sheet purposes. This transfer is for reporting purposes only
and has no effect on accounting and ratemaking.
B. When a pipeline obtains a working interest as a result of funds
advanced to producers, such amounts shall be included in appropriate
production accounts for formal contractual agreements executed prior to
the date of issuance of Order No. 499. When an associated company
obtains a working interest as a result of funds advanced from a pipeline
company, the pipeline shall include such amounts in Account 123,
Investment in Associated Companies, or Account 146, Accounts receivable
from Associated Companies, as appropriate, for formal contractual
commitments made during the period on or after November 10, 1971
(effective date of Order 441) but prior to December 29, 1972, the date
of issuance of Order No. 465.
C. Outstanding advances shall be fully reduced within 5 years, or as
otherwise authorized by the Commission, from the date gas deliveries
commence or the date it is determined that recovery will be in other
than gas. This account shall be credited with advances not fully
recovered within the five-year period, and the unrecovered portion
charged directly to Account 426.5, Other Deductions. A sufficient
portion of all gas taken should be credited to the related outstanding
advance so as to eliminate the advance within the 5-year period or as
otherwise authorized by the Commission upon request by the pipeline
company. The reduction of the outstanding advance should not be
dependent on a buyer purchasing more than 100 percent of the minimum
take or pay quantity provided in the contract. In those instances where
the five-year recovery period has lapsed, but recovery of the advance
continues beyond the five-year period, the unrecovered advances shall be
removed from this account and transferred to Account 167, Other Advances
for Gas.
D. Where recovery is by gas, the recovered advance shall be credited
to this account and charged to the appropriate gas purchase account.
E. When an advance which is or has been included in this account and
in rate base results in a source of proven reserves of natural gas, gas
deliveries commence but no gas flows to the pipeline company making such
advance, the amount of the advance shall be removed from this account
(and from rate base) and recorded in account 167, Other Advances for
Gas. Any revenues collected as a result of the advance being included
in rate base shall be refunded by the pipeline company to its customers,
together with interest, per annum, at the rate established by Order No.
513, issued October 10, 1974, or as subsequently revised by Commission
Order, from the date of payment until refunded, within 12 months after
the removal of the advance from this account, unless otherwise directed
by the Commission. Where there is partial recovery of the advance by
gas, in this situation, the amount of the advance transferred from this
account to account 167 and the amount of revenues refunded, with
interest, shall be appropriately apportioned.
F. However, if 5 years elapses from the time the advance has been
included in this account and during such time no gas deliveries have
commenced or no determination has been made that the recovery will be in
economic consideration other than gas, the pipeline shall at the end of
the 5-year period, transfer the advance from this account to Account
167, and cease rate base treatment thereof, unless otherwise directed by
the Commission.
G. Whenever as a result of an advance included in this account, a
pipeline receives any amount in excess of a full recovery of the
advance, e.g. interest income, such amount must be credited to Account
813, Other Gas Supply Expenses, or as otherwise directed by the
Commission. If the income or return is received in other than money, it
shall be included at the market value of the assets received.
H. If the recipient of an advance is unable to repay it in full,
through no fault of the pipeline or contractual provisions, in gas or
other assets, the unpaid or nonrecoverable portion must be credited to
this account at the time such amount is recognized as nonrecoverable.
Nonrecoverable advances significant in amount must be eliminated within
5 years from the date of determination as nonrecoverable by either a
charge to account 435, Extraordinary Deductions, or when authorized by
the Commission, by a transfer to account 186, Miscellaneous Deferred
Debits, and amortization to account 813, Other Gas Supply Expenses.
Nonrecoverable advances insignificant in amount should be charged
directly to account 813 in the year recognized as nonrecoverable, when
authorized by the Commission.
I. No transfers shall be made to or from this account to any other
accounts, unless otherwise provided herein, except as specifically
authorized by the Commission upon request by the pipeline company.
J. Three copies of any agreement concerning advances will be filed
with the Secretary within 30 days of the initial related entry in
account 166.
Note A: This account may include advances for exploration (including
lease acquisition costs) made according to the provisions of Order Nos.
410 and 410-A, for which a contractual commitment was made prior to
November 10, 1971, (issue date of Order No. 441). All advances made
pursuant to contractual commitments made prior to November 10, 1971,
(issue date of Order No. 441) shall be subject to the provisions of
Order Nos. 410 and 410-A.
Note B: This account shall not include advances for exploration
(including lease acquisition costs) in accordance with Order No. 441,
for which a contractual commitment was made on or after November 10,
1971 (issue date of Order No. 441), but prior to December 29, 1972
(issue date of Order No. 465). All advances made pursuant to contractual
commitments made on or after November 10, 1971, but prior to December
29, 1972 (issue date of Order No. 465) shall be subject to the
provisions of Order No. 441.
Note C: This account shall not include advances for lease
acquisition costs but may include advances for exploration where such
advances are pursuant to contractual commitments made on or after
December 29, 1972 (issue date of Order No. 465).
Note D: All advances made pursuant to contractual commitments made
on or after December 29, 1972 (issue date of Order No. 465) but prior to
the date of issuance of Order No. 499, shall be subject to the
provisions of Order No. 465.
Note E: All advances made pursuant to contractual commitments made
on or after December 28, 1973 (issue date of Order No. 499), but prior
to the date of issuance of Order No. 529, shall be subject to the
provisions of Order No. 499.
Note F: This account shall not include advances expended for delay
rentals, nonproductive well drilling or abandoned leases where such
advances are related to lease acquisition, except in accordance with
Note A and Note B to this account.
Note G: To keep the Commission informed when an advance is
nonrecoverable by any means the company must submit the full details
including copies of Federal and State plugging and abandonment reports
involved as soon as such fact becomes known.
167 Other advances for gas (Major only).
This account shall include all advances not properly includible in
Account 166, exclusive of amounts advanced where a working interest is
obtained.
171 Interest and dividends receivable (Major only).
This account shall include the amount of interest on bonds,
mortgages, notes, commercial paper, loans, open accounts, deposits,
etc., the payment of which is reasonably assured, and the amount of
dividends declared or guaranteed on stocks owned.
Note A: Interest which is not subject to current settlement shall
not be included herein but in the account in which is carried the
principal on which the interest is accrued.
Note B: Interest and dividends receivable from associated companies
shall be included in account 146. Accounts Receivable from Associated
Companies.
172 Rents receivable (Major only).
This account shall include rents receivable or accrued on property
rented or leased by the utility to others.
Note: Rents receivable from associated companies shall be included
in account 146. Accounts Receivable From Associated Companies.
173 Accrued utility revenues (Major only).
At the option of the utility, the estimated amount accrued for
service rendered, but not billed at the end of any accounting period,
may be included herein. In case accruals are made for unbilled
revenues, they shall be made likewise for unbilled expenses, such as for
the purchase of gas.
174 Miscellaneous current and accrued assets.
This account shall include the book cost of all other current and
accrued assets, appropriately designated and supported so as to show the
nature of each asset included herein.
181 Unamortized debt expense.
This account shall include expenses related to the issuance or
assumption of debt securities. Amounts recorded in this account shall
be amortized over the life of each respective issue under a plan which
will distribute the amount equitably over the life of the security. The
amortization shall be on a monthly basis, and the amounts thereof shall
be charged to account 428, Amortization of Debt Discount and Expense.
Any unamortized amounts outstanding at the time that the related debt is
prematurely reacquired shall be accounted for as indicated in General
Instruction 17.
182.1 Extraordinary property losses.
A. When authorized or directed by the Commission, this account shall
include extraordinary losses, which could not reasonably have been
anticipated and which are not covered by insurance or other provisions,
such as unforeseen damages to property.
B. Application to the Commission for permission to use this account
shall be accompanied by a statement giving a complete explanation with
respect to the items which it is proposed to include herein, the period
over which, and the accounts to which it is proposed to write off the
charges, and other pertinent information.
182.2 Unrecovered plant and regulatory study costs.
A. This account shall include: (1) Nonrecurring costs of studies and
analyses mandated by regulatory bodies related to plants in service,
transferred from account 183.2, Other Preliminary Survey and
Investigation Charges, and not resulting in construction; and (2) when
authorized by the Commission, significant unrecovered costs of plant
facilities where construction has been cancelled or which have been
prematurely retired.
B. This account shall be credited and account 407.1, Amortization of
Property Losses, Unrecovered Plant and Regulatory Study Costs, shall be
debited, over the period specified by the Commission.
C. Any additional costs incurred, relative to the cancellation or
premature retirement, may be included in this account and amortized over
the remaining period of the original amortization period. Should any
gains of recoveries be realized relative to the cancelled or prematurely
retired plant, such amounts shall be used to reduce the unamortized
amount of the costs recorded herein.
D. In the event that the recovery of costs included herein is
disallowed in rate proceedings, the disallowed costs shall be charged to
account 426.5, Other Deductions, or account 435, Extraordinary
deductions, in the year of such disallowance.
183.1 Preliminary natural gas survey and investigation charges (Major
only).
A. This account shall be charged with all expenditures for
preliminary surveys, plans, investigations, etc. made for the purpose
of determining the feasibility of acquiring land and land rights to
provide a future supply of natural gas. If such land or land rights are
acquired, this account shall be credited and the appropriate gas plant
account (see gas plant instruction 7-G) charged with the amount of the
expenditures relating to such acquisition. If a project is abandoned
involving a natural gas lease acquired before October 8, 1969, the
expenditures related thereto shall be charged to account 798, Other
Exploration. If a project is abandoned involving a lease acquired after
October 7, 1969, the expenditures related thereto shall be charged to
account 338, Unsuccessful Exploration and Development Costs.
B. The records supporting the entries to this account shall be so
kept that the utility can furnish, for each investigation, complete
information as to the identification and location of territory
investigated, the number or other identification assigned to the land
tract or leasehold acquired, and the nature and respective amounts of
the charges.
Note: The amount of preliminary survey and investigation charges
transferred to gas plant shall not exceed the expenditures which may
reasonably be determined to contribute directly and immediately and
without duplication to gas plant.
183.2 Other preliminary survey and investigation charges (Major
only).
A. This account shall be charged with all expenditures for
preliminary surveys, plans, investigations, etc., made for the purpose
of determining the feasibility of utility projects under contemplation,
other than the acquisition of land and land rights to provide a future
supply of natural gas. If construction results, this account shall be
credited and the appropriate utility plant account charged. If the work
is abandoned, the charge shall be made to account 426.5, Other
Deductions, or the appropriate operating expense account.
B. This account shall also include costs of studies and analyses
mandated by regulatory bodies related to plant in service. If
construction results from such studies, this account shall be credited
and the appropriate utility plant account charged with an equitable
portion of such study costs directly attributible to new construction.
The portion of such study costs not attributible to new construction or
the entire cost if construction does not result shall be charged to
account 182.2, Unrecovered Plant and Regulatory Study Costs, or the
appropriate operating expense account. The costs of such studies
relative to plant under construction shall be included directly in
account 107, Construction Work in Progress -- Gas.
C. The records supporting the entries to this account shall be so
kept that the utility can furnish complete information as to the nature
and the purpose of the survey, plans, or investigations and the nature
and amounts of the several charges.
Note: The amount of preliminary survey and investigation charges
transferred to utility plant shall not exceed the expenditures which may
reasonably be determined to contribute directly and immediately and
without duplication to utility plant.
184 Clearing accounts (Major only).
This caption shall include undistributed balances in clearing
accounts at the date of the balance sheet. Balances in clearing
accounts shall be substantially cleared not later than the end of the
calendar year unless items held therein relate to a future period.
185 Temporary facilities (Major only).
This account shall include amounts shown by work orders for plant
installed for temporary use in utility service for periods of less than
one year. Such work orders shall be charged with the cost of temporary
facilities and credited with payments received from customers and net
salvage realized on removal of the temporary facilities. Any net credit
or debit resulting shall be cleared to account 488, Miscellaneous
Service Revenues.
186 Miscellaneous deferred debits.
A. For Major companies, this account shall include all debits not
elsewhere provided for, such as miscellaneous work in progress,
construction certificate application fees paid prior to final
disposition of the application as provided for in gas plant instruction
15A, and unusual or extraordinary expenses not included in other
accounts which are in process of amortization, and items the final
disposition of which is uncertain.
B. For Nonmajor companies, this account shall include the following
classes of items:
(1) Expenditures for preliminary surveys, plans, investigations,
etc., made for the purpose of determining the feasibility projects under
contemplation. If construction results, this account shall be credited
with the amount applicable thereto and the appropriate plant accounts
shall be charged with an amount which does not exceed the expenditures
which may reasonably be determined to contribute directly and
immediately and without duplication to plant. If the work is abandoned,
the charge shall be to account 462.5, Other Deductions, or to the
appropriate operating expense accounts.
(2) Expenditures for preliminary surveys, plans, investigations,
etc., made for the purpose of determining the feasibility of acquiring
land and land rights to provide a future supply of natural gas. If such
land or land rights are acquired, this account shall be credited and the
appropriate gas plant account (see gas plant instruction 6G) charged
with the amount of expenditures related to such acquisition. Such
preliminary survey and investigation charges transferred to gas plant
shall not exceed the expenditures which may reasonably be determined to
contribute directly and immediately and without duplication to the gas
plant. If a project is abandoned involving a natural gas lease acquired
before October 8, 1969, the expenditures related thereto shall be
charged to account 798, Other Exploration. If a project is abandoned
involving a lease acquired after October 7, 1969, the expenditures
related thereto shall be charged to account 338, Unsuccessful
Exploration and Development Costs.
(3) Undistributed balances in clearing account at the date of the
balance sheet. Balances in clearing accounts shall be substantially
cleared not later than the end of the calendar year unless items held
therein relate to a future period.
(4) Balances representing expenditures for work in progress other
than on utility plant. This includes jobbing and contract work in
progress.
(5) Other debit balances, the proper final disposition of which is
uncertain, and unusual or extraordinary expenses, not included in other
accounts, which are in process of being written off.
(6) All fees related to certificate applications involving
construction paid prior to the final disposition of the certificate
application. If the certificate is granted and accepted, the amount
recorded in this account shall be credited with the amount applicable
thereto and charged to the appropriate plant accounts. If the
certificate requested is not granted or is not accepted by the
applicant, the fees recorded in this account shall be cleared to account
928, Regulatory Commission Expenses.
C. The records supporting the entries to this account shall be so
kept that the utility can furnish full information as to each deferred
debit included herein. (In the case of Nonmajor companies, the records
supporting entries for preliminary natural gas surveys and
investigations shall be so kept that the utility can furnish, for each
investigation, complete information as to identification and location of
the territory investigated, the number of other identification assigned
to the land tract or leasehold acquired, and the nature and respective
amounts of the charges.)
187 Deferred losses from disposition of utility plant.
This account shall include losses from the sale or other disposition
of property previously recorded in account 105, Gas Plant Held for
Future Use and account 105.1, Production Properties Held for Future Use,
under the provisions of paragraphs B, C, and D thereof, where such
losses are significant and are to be amortized over a period of 5 years,
unless otherwise authorized by the Commission. The amortization of the
amounts in this account shall be made by debits to account 411.7, Losses
from Disposition of Utility Plant. Subdivision of this account shall be
maintained so that amounts relating to account 105, Gas Plant Held for
Future Use and account 105.1, Production Properties Held for Future Use,
can be readily identifiable. (See accounts 105, Gas Plant Held for
Future Use and 105.1, Production Properties Held for Future Use.)
188 Research, development, and demonstration expenditures (Major
only).
A. This account shall be charged with the cost of all expenditures
coming within the meaning of Research, Development, and Demonstration
(R.D. & D.) of this Uniform Systems of Accounts (see definition 28.B),
except those expenditures properly chargeable to Account 107,
Construction Work in Progress -- Gas.
B. Costs that are minor or of a general or recurring nature shall be
transferred from this account to the appropriate operating expense
function or if such costs are common to the overall operations or cannot
be feasibly allocated to the various operating accounts, then such costs
shall be recorded in account 930.2, Miscellaneous General Expenses.
C. In certain instances a company may incur large and significant
research, development, and demonstration expenditures which are
nonrecurring and which would distort the annual research, development,
and demonstration charges for the period. In such a case the portion of
such amounts that cause the distortion may be amortized to the
appropriate operating expense account over a period not to exceed five
years unless otherwise authorized by the Commission.
D. The entries in this account must be so maintained as to show
separately each project along with complete detail of the nature and
purpose of the research, development, and demonstration project together
with the related costs.
189 Unamortized loss on reacquired debt.
This account shall include the losses on long-term debt reacquired or
redeemed. The amounts in this account shall be amortized in accordance
with General Instruction 17.
190 Accumulated deferred income taxes.
A. This account shall be debited and account 411.1, Provision for
Deferred Income Taxes -- Credit, Utility Operating Income, or account
411.2, Provision for Deferred Income Taxes -- Credit, Other Income and
Deductions, as appropriate, shall be credited with an amount equal to
that by which income taxes payable for the year are higher because of
the inclusion of certain items in income for tax purposes, which items
for general accounting purposes will not be fully reflected in the
utility's determination of annual net income until subsequent years.
B. This account shall be credited and account 410.1, Provision for
Deferred Income Taxes, Utility Operating Income, or account 410.2,
Provision for Deferred Income Taxes, Other Income and Deductions, as
appropriate, shall be debited with an amount equal to that by which
income taxes payable for the year are lower because of prior payment of
taxes as provided by paragraph A above, because of difference in timing
for tax purposes of particular items of income or income deductions from
that recognized by the utility for general accounting purposes. Such
credit to this account and debit to account 410.1 or 410.2 shall, in
general, represent the effect on taxes payable in the current year of
the smaller amount of book income recognized, or the larger deduction
permitted, for tax purposes as compared to the amount recognized in the
utility's current accounts with respect to the item or class of items
for which deferred tax concept of accounting is affected.
C. Vintage year records with respect to entries to this account, as
described above, and the account balance shall be so maintained as to
show the factor of calculation with respect to each annual amount of the
item or class of items for which deferred tax accounting by the utility
is utilized.
D. The utility is restricted in its use of this account to the
purpose set forth above. It shall not make use of the balance in this
account or any portion thereof except as provided in the text of this
account, without prior approval of the Commission. Any remaining
deferred tax account balance with respect to an amount for any prior
year's tax deferral, the amortization of which or other recognition in
the utility's income accounts has been completed, or other disposition
made, shall be debited to account 410.1, Provision for Deferred Income
Taxes, Utility Operating Income, or account 410.2, Provision for
Deferred Income Taxes, Other Income and Deductions, as appropriate, or
otherwise disposed of as the Commission may authorize or direct. (See
General Instruction 18.)
191 Unrecovered purchased gas costs.
A. This account shall include purchase gas costs related to
Commission approved purchased gas adjustment clauses when such costs are
not included in the utility's rate schedule on file with the Commission.
This account shall also include such other costs as authorized by the
Commission.
B. This account shall be debited or credited, as appropriate, each
month for increases or decreases in purchased gas costs with contra
entries to Account 805.1, Purchased Gas Cost Adjustments.
C. After a change in a rate schedule recognizing the increases or
decreases in purchased gas costs recorded in this account is approved by
the Commission, this account shall be debited or credited, as
appropriate, with contra entries to expense Account 805.1, Purchased Gas
Cost Adjustments, so that the balance accumulated in this account will
be amortized on an appropriate basis over a succeeding 6-month period or
over such other periods that the Commission may have authorized. Any
over or under applied debits or credits to this account shall be carried
forward to the succeeding period of amortization.
D. Separate subaccounts shall be maintained for the amounts relating
to the period in which the increase or decrease is accumulated and for
the amortization of purchase gas increases or decreases, as applicable,
so as to keep each period separate.
201 Common stock issued.
202 Common stock subscribed (Major only).
203 Common stock liability for conversion (Major only).
204 Preferred stock issued.
A. These accounts shall include the par value or the stated value of
stock without par value if such stock has a stated value, and, if not,
the cash value of the consideration received for such nonpar stock, of
each class of capital stock actually issued, including the par or stated
value of such capital stock in account 124, Other Investments and
account 217, Reacquired Capital Stock.
B. When the actual cash value of the consideration received is more
or less than the par or stated value of any stock having a par or stated
value, the difference shall be credited or debited, as the case may be,
to the premium or discount account for the particular class and series.
C. When capital stock is retired, these accounts shall be charged
with the amount at which such stock is carried herein.
D. A separate ledger account, with a descriptive title, shall be
maintained for each class and series of stock. The supporting records
shall show the shares nominally issued, actually issued, and nominally
outstanding.
Note: When a levy or assessment, except a call for payment on
subscriptions, is made against holders of capital stock, the amount
collected upon such levy or assessment shall be credited to account 207,
Premium on Capital Stock (For Nonmajor companies, account 211,
Miscellaneous Paid-In Capital); provided, however, that the credit
shall be made to account 213, Discount on Capital Stock, to the extent
of any remaining balance of discount on the issue of stock.
205 Preferred stock subscribed (Major only).
A. These accounts shall include the amount of legally enforceable
subscriptions to capital stock of the utility. They shall be credited
with the par or stated value of the stock subscribed, exclusive of
accrued dividends, if any. Concurrently, a debit shall be made to
subscriptions to capital stock, included as a Other Accounts Receivable,
for the agreed price and any discount or premium shall be debited or
credited to the appropriate discount or premium account. When properly
executed stock certificates have been issued representing the shares
subscribed, this account separate subdivision of account 143, shall be
debited, and the appropriate capital stock account credited, with the
par or stated value of such stock.
B. The records shall be kept in such manner as to show the amount of
subscriptions to each class and series of stock.
206 Preferred stock liability for conversion (Major only).
A. These accounts shall include the par value or stated value, as
appropriate, of capital stock which the utility has agreed to exchange
for outstanding securities of other companies in connection with the
acquisition of properties of such companies under terms which allow the
holders of the securities of the other companies to surrender such
securities and receive in return therefor capital stock of the
accounting utility.
B. When the securities of the other companies have been surrendered
and capital stock issued in accordance with the terms of the exchange,
these accounts shall be charged and accounts 201, Common Stock Issued,
or 204, Preferred Stock Issued, as the case may be, shall be credited.
C. The records shall be kept so as to show separately the stocks of
each class and series for which a conversion liability exists.
207 Premium on capital stock (Major only).
A. This account shall include, in a separate subdivision for each
class and series of stock, the excess of the actual cash value of the
consideration received on original issues of capital stock over the par
or stated value and accrued dividends of such stock, together with
assessments against stockholders representing payments required in
excess of par or stated values.
B. Premium on capital stock shall not be set off against expenses.
Further, a premium received on an issue of a certain class or series of
stock shall not be set off against expenses of another issue of the same
class or series.
C. When capital stock which has been actually issued is retired, the
amount in this account applicable to the shares retired shall be
transferred to account 210, Gain on Resale or Cancellation of Reacquired
Capital Stock.
208 Donations received from stockholders (Major only).
This account shall include the balance of credits for donations
received from stockholders consisting of capital stock of the utility,
cancellation or reduction of debt of the utility, and the cash value of
other assets received as a donation.
209 Reduction in par or stated value of capital stock (Major only).
This account shall include the balance of credits arising from a
reduction in the par or stated value of capital stock.
210 Gain on resale or cancellation of reacquired capital stock (Major
only).
This account shall include the balance of credits arising from the
resale or cancellation of reacquired capital stock. (See account 217,
Reacquired Capital Stock.)
211 Miscellaneous paid-in capital.
This account shall include the balance of all other credits for
paid.in capital which are not properly includible in the foregoing
accounts. This account may include all commissions and expenses
incurred in connection with the issuance of capital stock.
(In the case of Nonmajor companies, this account shall be kept so as
to show the source of the credits includible herein.)
1. Premium received on original issues of capital stock.
2. Donations received from stockholders or reduction of debt of the
utility, and the cash value of other assets received as a donation.
3. Reduction in par or stated value of capital stock.
4. Gain or resale or cancellation of reacquired capital stock.
Note A (Major companies): Amounts included in capital surplus at the
effective date of this system of accounts which cannot be classified as
to the source thereof shall be included in this account.
Note B (Nonmajor companies): Premium on capital stock shall not be
set off against expenses. Further, a premium received on an issue of a
certain class or series of stock shall not be set off against expense of
another issue of the same class or series.
212 Installments received on capital stock.
A. This account shall include in a separate subdivision for each
class and series of capital stock the amount of installments received on
capital stock on a partial or installment payment plan from subscribers
who are not bound by legally enforceable subscription contracts.
B. As subscriptions are paid in full and certificates issued, this
account shall be charged and the appropriate capital stock account
credited with the par or stated value of such stock. Any discount or
premium on an original issue shall be included in the appropriate
discount or premium account.
213 Discount on capital stock.
A. This account shall include in a separate subdivision for each
class and series of capital stock all discount on the original issuance
and sale of capital stock, including additional capital stock of a
particular class or series as well as first issues.
B. When capital stock which has been actually issued is retired, the
amount in this account applicable to the shares retired shall be written
off to account 210, Gain on Resale or Cancellation of Reacquired Capital
Stock, provided, however, that the amount shall be charged to account
439, Adjustments to Retained Earnings, to the extent that it exceeds the
balance in account 210.
214 Capital stock expense.
A. This account shall include in a separate subdivision for each
class and series of stock all commissions and expenses incurred in
connection with the original issuance and sale of capital stock,
including additional capital stock of a particular class or series as
well as first issues. Expenses applicable to capital stock shall not be
deducted from premium on capital stock.
B. When capital stock which has been actually issued by the utility
is retired, the amount in this account applicable to the shares retired
shall be written off to account 210, Gain on Resale or Cancellation of
Reacquired Capital Stock, provided, however, that the amount shall be
charged to account 439, Adjustments to Retained Earnings, to the extent
that it exceeds the balance in account 210.
Note A: Expenses in connection with the reacquisition or resale of
the utility's capital stock shall not be included herein.
Note B: The utility may write off capital stock expense in whole or
in part by charges to account 211, Miscellaneous Paid-In Capital.
215 Appropriated retained earnings.
This account shall include the amount of earned surplus which has
been appropriated or set aside for specific purposes. Separate
subaccounts shall be maintained under such titles as will designate the
purpose for which each appropriation was made.
216 Unappropriated retained earnings.
This account shall include the balances, either debit or credit, of
unappropriated retained earnings arising from earnings of the utility.
This account shall not include any amounts representing the
undistributed earnings of subsidiary companies.
216.1 Unappropriated undistributed subsidiary earnings (Major only).
This account shall include the balances, either debit or credit, of
undistributed retained earnings of subsidiary companies since their
acquisition. When dividends are received from subsidiary companies and
the balances have been included in this account, this account shall be
debited and account 216, Unappropriated Retained Earnings, credited.
217 Reacquired capital stock.
A. This account shall include in a separate subdivision for each
class and series of capital stock, the cost of capital stock actually
issued by the utility and reacquired by it and not retired or canceled,
except, however, stock which is held by trustees in sinking or other
funds.
B. When reacquired capital stock is retired or canceled, the
difference between its cost, including commissions and expenses paid in
connection with the reacquisition, and its par or stated value plus any
premium and less any discount and expenses applicable to the shares
retired, shall be debited or credited, as appropriate, to account 210,
Gain on Resale or Cancellation of Reacquired Capital Stock, provided,
however, that debits shall be charged to account 439, Adjustments to
Retained Earnings, to the extent that they exceed the balance in account
210.
C. When reacquired capital stock is resold by the utility, the
difference between the amount received on the resale of the stock, less
expenses incurred in the resale, and the cost of the stock included in
this account shall be accounted for as outlined in paragraph B.
Note A: See account 124. Other Investments, for permissive
accounting treatment of stock reacquired under a definite plan for
resale.
Note B: The accounting for reacquired stock shall be as prescribed
herein unless otherwise specifically required by statute.
218 Noncorporate proprietorship (Nonmajor only).
This account shall include the investment in an unincorporated
utility by the proprietor thereof, and shall be charged with all
withdrawals from the business by its proprietor. At the end of each
calendar year the net income for the year, as developed in the income
account, shall be transferred to this account. (See optional accounting
procedure provided in Note C, hereunder.)
Note A: Amounts payable to the proprietor as just and reasonable
compensation for services performed shall not be charged to this account
but to appropriate operating expense or other accounts.
Note B: When the utility is owned by a partnership, a separate
account shall be kept to show the net equity of each member therein and
the transactions affecting the interest of each such partner.
Note C: This account may be restricted to the amount considered by
the proprietor to be the permanent investment in the business, subject
to change only by additional investment by the proprietor or the
withdrawal of portions thereof not representing net income. When this
option is taken, the retained earnings accounts shall be maintained and
entries thereto shall be made in accordance with the texts thereof.
221 Bonds.
This account shall include in a separate subdivision for each class
and series of bonds the face value of the actually issued and unmatured
bonds which have not been retired or canceled; also the face value of
such bonds issued by others the payment of which has been assumed by the
utility.
222 Reacquired bonds (Major only).
A. This account shall include the face value of bonds actually issued
or assumed by the utility and reacquired by it and not retired, or
canceled. The account for reacquired debt shall not include securities
which are held by trustee in sinking or other funds.
B. When bonds are reacquired, the difference between face value,
adjusted for unamortized discount, expenses or premium, and the amount
paid upon reacquisition, shall be included in account 189, Unamortized
Loss on Reacquired Debt, or account 257, Unamortized Gain on Reacquired
Debt, as appropriate. (See General Instruction 17.)
223 Advances from associated companies.
A. This account shall include the face value of notes payable to
associated companies and the amount of open book accounts representing
advances from associated companies. It does not include notes and open
accounts representing indebtedness subject to current settlement which
are includible in account 233, Notes Payable to Associated Companies, or
account 234, Accounts Payable to Associated Companies.
B. The records supporting the entries to this account shall be so
kept that the utility can furnish complete information concerning each
note and open account.
224 Other long-term debt.
A. This account shall include, until maturity, all long-term debt not
otherwise provided for. This covers such items as receivers'
certificates, real estate mortgages executed or assumed, assessments for
public improvements, notes and unsecured certificates of indebtedness
not owned by associated companies, receipts outstanding for long-term
debt, and other obligations maturing more than one year from date of
issue or assumption.
B. Separate accounts shall be maintained for each class of
obligation, and records shall be maintained to show for each class all
details as to date of obligation, date of maturity, interest dates and
rates, security for the obligation, etc.
Note: Miscellaneous long-term debt reacquired shall be accounted for
in accordance with the procedure set forth in account 222, Reacquired
Bonds.
225 Unamortized premium on long-term debt.
A. This account shall include the excess of the cash value of
consideration received over the face value upon the issuance or
assumption of long-term debt securities.
B. Amounts recorded in this account shall be amortized over the life
of each respective issue under a plan which will distribute the amount
equitably over the life of the security. The amortization shall be on a
monthly basis, with the amounts thereof to be credited to account 429,
Amortization of Premium on Debt -- Credit. (See General Instruction
17.)
226 Unamortized discount on long-term debt -- Debit.
A. This account shall include the excess of the face value of
long-term debt securities over the cash value of consideration received
therefor, related to the issue or assumption of all types and classes of
debt.
B. Amounts recorded in this account shall be amortized over the life
of the respective issues under a plan which will distribute the amount
equitably over the life of the securities. The amortization shall be on
a monthly basis, with the amounts thereof charged to account 428,
Amortization of Debt Discount and Expense. (See General Instruction
17.)
Current and accrued liabilities are those obligations which have
either matured or which become due within one year from the date
thereof; except, however, bonds, receivers' certificates and similar
obligations which shall be classified as long-term debt until date of
maturity; accrued taxes, such as income taxes, which shall be
classified as accrued liabilities even though payable more than one year
from date; compensation awards, which shall be classified as current
liabilities regardless of date due; and minor amounts payable in
installments which may be classified as current liabilities. If a
liability is due more than one year from date of issuance or assumption
by the utility, it shall be credited to a long-term debt account
appropriate for the transaction, except, however, the current
liabilities previously mentioned.
227 Obligations under capital leases -- noncurrent.
This account shall include the portion not due within one year, of
the obligations recorded for the amounts applicable to leased property
recorded as assets in account 101.1, Property under Capital Leases, or
account 121, Nonutility property.
No amounts shall be credited to these accounts unless authorized by a
regulatory authority or authorities to be collected in a utility's rate
levels.
228.1 Accumulated provision for property insurance.
A. This account shall include amounts reserved by the utility for
losses through accident, fire, flood, or other hazards to its own
property or property leased from others, not covered by insurance. The
amounts charged to account 924, Property Insurance, or other appropriate
accounts to cover such risks shall be credited to this account. A
schedule of risks covered shall be maintained, giving a description of
the property involved, the character of the risks covered and the rates
used.
B. Charges shall be made to this account for losses covered, not to
exceed the account balance. Details of these charges shall be
maintained according to the year the casualty occurred which gave rise
to the loss.
228.2 Accumulated provision for injuries and damages.
A. This account shall be credited with amounts charged to account
925, Injuries and Damages, or other appropriate accounts, to meet the
probable liability, not covered by insurance, for deaths or injuries to
employees and others, and for damages to property neither owned nor held
under lease by the utility.
B. When liability for any injury or damage is admitted by the utility
either voluntarily or because of the decision of a court or other lawful
authority, such as a workmens' compensation board, the admitted
liability shall be charged to this account and credited to the
appropriate current liability account. Details of these charges shall
be maintained according to the year the casualty occurred which gave
rise to the loss.
Note: Recoveries or reimbursements for losses charged to this
account shall be credited hereto; the cost of repairs to property of
others if provided for herein shall be charged to this account.
228.3 Accumulated provision for pensions and benefits.
A. This account shall include provisions made by the utility and
amounts contributed by employees for pensions, accident and death
benefits, savings, relief, hospital and other provident purposes, where
the funds are included in the assets of the utility either in general or
in segregated fund accounts.
B. Amounts paid by the utility for the purposes for which this
liability is established shall be charged hereto.
C. A separate account shall be kept for each kind of provision
included herein.
Note: If employee pension or benefit plan funds are not included
among the assets of the utility but are held by outside trustees,
payments into such funds, or accruals therefor, shall not be included in
this account.
228.4 Accumulated miscellaneous operating provisions.
A. This account shall include all operating provisions which are not
provided for elsewhere.
B. This account shall be maintained in such manner as to show the
amount of each separate provision and the nature and amounts of the
debits and credits thereto.
Note: This account includes only provisions as may be created for
operating purposes and does not include any reservations of income the
credits for which should be carried in account 215, Appropriated
Retained Earnings.
229 Accumulated provision for rate refunds.
A. This account shall be credited with amounts charged to Account
496, Provision for Rate Refunds, to provide for estimated refunds where
the utility is collecting amounts in rates subject to refund.
B. When a refund of any amount recorded in this account is ordered by
a regulatory authority, such amount shall be charged hereto and credited
to Account 242, Miscellaneous Current and Accrued Liabilities.
C. Records supporting the entries to this account shall be kept so as
to identify each amount recorded by the respective rate filing docket
number.
231 Notes payable.
This account shall include the face value of all notes, drafts,
acceptances, or other similar evidences of indebtedness, payable on
demand or within a time not exceeding one year from date of issue, to
other than associated companies.
232 Accounts payable.
This account shall include all amounts payable by the utility within
one year, which are not provided for in other accounts.
233 Notes payable to associated companies.
234 Accounts payable to associated companies.
These accounts shall include amounts owing to associated companies on
notes, drafts, acceptances, or other similar evidences of indebtedness,
and open accounts payable on demand or not more than one year from date
of issue or creation.
Note: Exclude from these accounts notes and accounts which are
includible in account 223, Advances from Associated Companies.
235 Customer deposits.
This account shall include all amounts deposited with the utility by
customers as security for the payment of bills.
236 Taxes accrued.
A. This account shall be credited with the amount of taxes accrued
during the accounting period, corresponding debits being made to the
appropriate accounts for tax charges. Such credits may be based upon
estimates, but from time to time during the year as the facts become
known, the amount of the periodic credits shall be adjusted so as to
include as nearly as can be determined in each year the taxes applicable
thereto. Any amount representing a prepayment of taxes applicable to
the period subsequent to the date of the balance sheet, shall be shown
under account 165, Prepayments.
B. If accruals for taxes are found to be insufficient or excessive,
correction therefor shall be made through current tax accruals.
C. Accruals for taxes shall be based upon the net amounts payable
after credit for any discounts, and shall not include any amounts for
interest on tax deficiencies or refunds. Interest received on refunds
shall be credited to account 419, Interest and Dividend Income, and
interest paid on deficiencies shall be charged to account 431, Other
Interest Expense.
D. The records supporting the entries to this account shall be kept
so as to show for each class of taxes, the amount accrued, the basis for
the accrual, the accounts to which charged, and the amount of tax paid.
237 Interest accrued.
This account shall include the amount of interest accrued but not
matured on all liabilities of the utility not including, however,
interest which is added to the principal of the debt on which incurred.
Supporting records shall be maintained so as to show the amount of
interest accrued on each obligation.
238 Dividends declared (Major only).
This account shall include the amount of dividends which have been
declared but not paid. Dividends shall be credited to this account when
they become a liability.
239 Matured long-term debt (Major only).
This account shall include the amount of long-term debt (including
any obligation for premiums) matured and unpaid, without specific
agreement for extension of the time of payment and bonds called for
redemption but not presented.
240 Matured interest (Major only).
This account shall include the amount of matured interest on
long-term debt or other obligations of the utility at the date of the
balance sheet unless such interest is added to the principal of the debt
on which incurred.
241 Tax collections payable (Major only).
This account shall include the amount of taxes collected by the
utility through payroll deductions or otherwise pending transmittal of
such taxes to the proper taxing authority.
Note: Do not include liability for taxes assessed directly against
the utility which are accounted for as part of the utility's own tax
expense.
242 Miscellaneous current and accrued liabilities.
This account shall include the amount of all other current and
accrued liabilities not provided for elsewhere appropriately designated
and supported so as to show the nature of each liability.
1. Dividends declared but not paid.
2. Matured long-term debt.
3. Matured interest.
4. Taxes collected through payroll deductions or otherwise pending
transmittal to the proper taxing authority.
243 Obligations under capital leases -- current.
This account shall include the portion due within one year, of the
obligations recorded for the amounts applicable to leased property
recorded as assets in account 101.1, Property under Capital Leases, or
account 121, Non-Utility Property.
252 Customer advances for construction.
This account shall include advances by customers for construction
which are to be refunded either wholly or in part. When a customer is
refunded the entire amount to which he is entitled, according to the
agreement or rule under which the advance was made, the balance, if any,
remaining in this account shall be credited to the respective plant
account.
253 Other deferred credits.
This account shall include advance billings and receipts and other
deferred credit items, not provided for elsewhere, including amounts
which cannot be entirely cleared or disposed of until additional
information has been received.
255 Accumulated deferred investment tax credits.
A. This account shall be credited with all investment tax credits
deferred by companies which have elected to follow deferral accounting,
partial or full, rather than recognizing in the income statement the
total benefits of the tax credit as realized. After such election, a
company may not transfer amounts from this account, except as authorized
herein and in accounts 411.4, Investment Tax Credit Adjustments, Utility
Operations, 411.5, Investment Tax Credit Adjustments, Nonutility
Operations, and 420, Investment Tax Credits, or with approval of the
Commission.
B. Where the company's accounting provides that investment tax
credits are to be passed on to customers, this account shall be debited
and account 411.4 credited with a proportionate amount determined in
relation to the average useful life of gas utility plant to which the
tax credits relate to such lesser period of time as allowed by a
regulatory agency having rate jurisdiction. If, however, the deferral
procedure provides that investment tax credits are not to be passed on
to customers the proportionate restorations to income shall be credited
to account 420.
C. If any of the investment tax credits to be deferred are related to
utility operations other than gas or to non- utility operations,
appropriate subdivisions of this account shall be maintained. Contra
entries affecting such subdivisions shall be appropriately recorded in
accounts 413, Expenses of Gas Plant Leased to Others; or 414, Other
Utility Operating Income.
D. Records shall be maintained identifying the properties related to
the investment tax credits for each year, the weighted average service
life of such properties, and any unused balance of such credits. Such
records are not necessary unless the credits are deferred.
256 Deferred gains from disposition of utility plant.
This account shall include gains from the sale or other disposition
of property previously recorded in account 105, Gas Plant Held for
Future Use and account 105.1, Production Properties Held for Future Use,
under the provisions of paragraphs B, C, and D thereof, where such gains
are significant and are to be amortized over a period of 5 years, unless
otherwise authorized by the Commission. The amortization of the amounts
in this account shall be made by credits to account 411.6, Gains from
Disposition of Utility Plant. Subdivision of this account shall be
maintained so that amounts relating to account 105, Gas Plant Held for
Future Use and account 105.1, Production Properties Held for Future Use,
can be readily identifiable. (See accounts 105, Gas Plant Held for
Future Use and account 105.1, Production Properties Held for Future
Use.)
257 Unamortized gain on reacquired debt.
This account shall include the amounts of discount realized upon
reacquisition or redemption of long-term debt. The amounts in this
account shall be amortized in accordance with General Instruction 17.
A. Before using the deferred tax accounts provided below refer to
General Instruction 18. Comprehensive Interperiod Income Tax
Allocation.
B. The text of these accounts are designed primarily to cover
deferrals of Federal income taxes. However, they are also to be used
when making deferrals of State and local income taxes. Natural gas
companies which, in addition to a gas utility department, have another
utility department, electric, water, etc., and nonutility property which
have deferred taxes on income with respect thereto shall separately
classify such deferrals in the accounts provided below so as to allow
ready identification of items relating to each utility department and to
Other Income and Deductions.
281 Accumulated deferred income taxes -- Accelerated amortization
property.
A. This account shall include tax deferrals resulting from adoption
of the principles of comprehensive interpe- riod tax allocation
described in General Instruction 18 of this system of accounts that
relate to property for which the utility has availed itself of the use
of accelerated (5-year) amortization of (1) certified defense facilities
as permitted by Section 168 of the Internal Revenue Code and (2)
certified pollution control facilities as permitted by Section 169 of
the Internal Revenue Code.
B. This account shall be credited and accounts 410.1, Provision for
Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for
Deferred Income Taxes, Other Income and Deductions, as appropriate,
shall be debited with tax effects related to property described in
paragraph A above where taxable income is lower than pretax accounting
income due to differences between the periods in which revenue and
expense transactions affect taxable income and the periods in which they
enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for
Deferred Income Taxes -- Credit, Utility Operating Income, or 411.2,
Provision for Deferred Income Taxes -- Credit, Other Income and
Deductions, as appropriate, shall be credited with tax effects related
to property described in paragraph A above where taxable income is
higher than pretax accounting income due to differences between the
periods in which revenue and expense transactions affect taxable income
and the periods in which they enter into the determination of pretax
accounting income.
D. The utility is restricted in its use of this account to the
purposes set forth above. It shall not transfer the balance in this
account or any portion thereof to retained earnings or make any use
thereof except as provided in the text of this account without prior
approval of the Commission. Upon the disposition by sale, exchange,
transfer, abandonment or premature retirement of plant on which there is
a related balance herein, this account shall be charged with an amount
equal to the related income tax expense, if any, arising from such
disposition and account 411.1, Provision for Deferred Income Taxes --
Credit, Utility Operating Income, or 411.2, Provision for Deferred
Income Taxes -- Credit, Other Income and Deductions, as appropriate,
shall be credited. When the remaining balance, after consideration of
any related income tax expense, is less than $25,000, this account shall
be charged and account 411.1 or 411.2, as appropriate, credited with
such balance. If after consideration of any related income tax expense,
there is a remaining amount of $25,000 or more, the Commission shall
authorize or direct how such amount shall be accounted for at the time
approval for the disposition of accounting is granted. When plant is
disposed of by transfer to a wholly owned subsidiary the related balance
in this account shall also be transferred. When the disposition relates
to retirement of an item or items under a group method of depreciation
where there is no tax effect in the year of retirement, no entries are
required in this account if it can be determined that the related
balances would be necessary to be retained to offset future group item
tax deficiencies.
282 Accumulated deferred income taxes -- Other property.
A. This account shall include the tax deferrals resulting from
adoption of the principle of comprehensive interperiod income tax
allocation described in General Instruction 18 of this system of
accounts which are related to all property other than accelerated
amortization property.
B. This account shall be credited and accounts 410.1, Provision for
Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for
Deferred Income Taxes, Other Income and Deductions, as appropriate,
shall be debited with tax effects related to property described in
paragraph A above where taxable income is lower than pretax accounting
income due to differences between the periods in which revenue and
expense transactions affect taxable income and the periods in which they
enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for
Deferred Income Taxes -- Credit, Utility Operating Income, or 411.2,
Provision for Deferred Income Taxes -- Credit, Other Income and
Deductions, as appropriate, shall be credited with tax effects related
to property described in paragraph A above where taxable income is
higher than pretax accounting income due to differences between the
periods in which revenue and expense transactions affect taxable income
and the periods in which they enter into the determination of pretax
accounting income.
D. The utility is restricted in its use of this account to the
purposes set forth above. It shall not transfer the balance in this
account or any portion thereof to retained earnings or make any use
thereof except as provided in the text of this account without prior
approval of the Commission. Upon the disposition by sale, exchange,
transfer, abandonment or premature retirement of plant on which there is
a related balance herein, this account shall be charged with an amount
equal to the related income tax expense, if any, arising from such
disposition and account 411.1, Income Taxes Deferred in Prior Years --
Credit, Utility Operating Income, or 411.2, Income Taxes Deferred in
Prior Years -- Credit, Other Income and Deductions, shall be credited.
When the remaining balance, after consideration of any related tax
expenses, is less than $25,000, this account shall be charged and
account 411.1 or 411.2, as appropriate, credited with such balance. If
after consideration of any related income tax expense, there is a
remaining amount of $25,000 or more, the Commission shall authorize or
direct how such amount shall be accounted for at the time approval for
the disposition of accounting is granted. When plant disposed of by
transfer to a wholly owned subsidiary, the related balance in this
account shall also be transferred. When the disposition relates to
retirement of an item or items under a group method of depreciation
where there is no tax effect in the year of retirement, no entries are
required in this account if it can be determined that the related
balance would be necessary to be retained to offset future group item
tax deficiencies.
283 Accumulated deferred income taxes -- Other.
A. This account shall include all credit tax deferrals resulting from
the adoption of the principles of comprehensive interperiod income tax
allocation described in General Instruction 18 of this system of
accounts other than those deferrals which are includible in Accounts
281, Accumulated Deferred Income Taxes -- Accelerated Amortization
Property and 282, Accumulated Deferred Income Taxes -- Other Property.
B. This account shall be credited and accounts 410.1 Provision for
Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for
Deferred Income Taxes, Other Income and Deductions, as appropriate,
shall be debited with tax effects related to items described in
paragraph A above where taxable income is lower than pretax accounting
income due to differences between the periods in which revenue and
expense transactions affect taxable income and the periods in which they
enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for
Deferred Income Taxes -- Credit, Utility Operating Income or 411.2,
Provision for Deferred Income Taxes -- Credit, Other Income and
Deductions, as appropriate shall be credited with tax effects related to
items described in paragraph A above where taxable income is higher than
pretax accounting income due to differences between the periods in which
revenue and expense transactions affect taxable income and the periods
in which they enter into the determination of pretax accounting income.
D. Records with respect to entries to this account, as described
above, and the account balance, shall be so maintained as to show the
factors of calculation with respect to each annual amount of the item or
class of items.
E. The utility is restricted in its use of this account to the
purposes set forth above. It shall not transfer the balance in the
account or any portion thereof to retained earnings or to any other
account or make any use thereof except as provided in the text of this
account, without prior approval of the Commission. Upon the disposition
by sale, exchange, transfer, abandonment or premature retirement of
items on which there is a related balance herein, this account shall be
charged with an amount equal to the related income tax effect, if any,
arising from such disposition and account 411.1, Provision For Deferred
Income Taxes -- Credit, Utility Operating Income, or 411.2, Provision
For Deferred Income Taxes -- Credit, Other Income and Deductions, as
appropriate, shall be credited. When the remaining balance, after
consideration of any related tax expenses, is less than $25,000, this
account shall be charged and account 411.1 or 411.2, as appropriate,
credited with such balance. If after consideration of any related
income tax expense, there is a remaining amount of $25,000 or more, the
Commission shall authorize or direct how such amount shall be accounted
for at the time approval for the disposition of accounting is granted.
When plant is disposed of by transfer to a wholly owned subsidiary,
the related balance in this account shall also be transferred. When the
disposition relates to retirement of an item or items under a group
method of depreciation where there is no tax effect in the year of
retirement, no entries are required in this account if it can be
determined that the related balance would be necessary to be retained to
offset future group item tax deficiencies.
Gas Plant Accounts
301 Organization.
302 Franchises and consents.
303 Miscellaneous intangible plant.
304 Land and land rights.
305 Structures and improvements.
306 Boiler plant equipment.
307 Other power equipment.
308 Coke ovens.
309 Producer gas equipment.
310 Water gas generating equipment.
311 Liquefied petroleum gas equipment.
312 Oil gas generating equipment.
313 Generating equipment -- Other processes.
314 Coal, coke, and ash handling equipment.
315 Catalytic cracking equipment.
316 Other reforming equipment.
317 Purification equipment.
318 Residual refining equipment.
319 Gas mixing equipment.
320 Other equipment.
325.1 Producing lands.
325.2 Producing leaseholds.
325.3 Gas rights.
325.4 Rights-of-way.
325.5 Other land and land rights.
326 Gas well structures.
327 Field compressor station structures.
328 Field measuring and regulating station structures.
329 Other structures.
330 Producing gas wells -- Well construction.
331 Producing gas wells -- Well equipment.
332 Field lines.
333 Field compressor station equipment.
334 Field measuring and regulating station equipment.
335 Drilling and cleaning equipment.
336 Purification equipment.
337 Other equipment.
338 Unsuccessful exploration and development costs.
340 Land and land rights.
341 Structures and improvements.
342 Extraction and refining equipment.
343 Pipe lines.
344 Extracted product storage equipment.
345 Compressor equipment.
346 Gas measuring and regulating equipment.
347 Other equipment.
350.1 Land.
350.2 Rights-of-way.
351 Structures and improvements.
352 Wells.
352.1 Storage leaseholds and rights.
352.2 Reservoirs.
352.3 Nonrecoverable natural gas.
353 Lines.
354 Compressor station equipment.
355 Measuring and regulating equipment.
356 Purification equipment.
357 Other equipment.
360 Land and land rights.
361 Structures and improvements.
362 Gas holders.
363 Purification equipment (Major only).
363.1 Liquefaction equipment (Major only).
363.2 Vaporizing equipment (Major only).
363.3 Compressor equipment (Major only).
363.4 Measuring and regulating equipment (Major only).
363.5 Other equipment.
364.1 Land and land rights (Major only).
364.2 Structures and improvements (Major only).
364.3 LNG processing terminal equipment (Major only).
364.4 LNG transportation equipment (Major only).
364.5 Measuring and regulating equipment (Major only).
364.6 Compressor station equipment (Major only).
364.7 Communication equipment (Major only).
364.8 Other equipment (Major only).
365.1 Land and land rights.
365.2 Rights-of-way.
366 Structures and improvements.
367 Mains.
368 Compressor station equipment.
369 Measuring and regulating station equipment.
370 Communication equipment.
371 Other equipment.
374 Land and land rights.
375 Structures and improvements.
376 Mains.
377 Compressor station equipment.
378 Measuring and regulating station equipment -- General.
379 Measuring and regulating station equipment -- City gate check
stations.
380 Services.
381 Meters.
382 Meter installations.
383 House regulators.
384 House regulatory installations.
385 Industrial measuring and regulating station equipment.
386 Other property on customers' premises.
387 Other equipment.
389 Land and land rights.
390 Structures and improvements.
391 Office furniture and equipment.
392 Transportation equipment.
393 Stores equipment.
394 Tools, shop and garage equipment.
395 Laboratory equipment.
396 Power operated equipment.
397 Communication equipment.
398 Miscellaneous equipment.
399 Other tangible property.
18 CFR 161.3 Gas Plant Accounts
301 Organization.
This account shall include all fees paid to Federal or State
governments for the privilege of incorporation and expenditures incident
to organizing the corporation, partnership, or other enterprises and
putting it into readiness to do business.
1. Cost of obtaining certificates authorizing an enterprise to engage
in the public utility business.
2. Fees and expenses for incorporation.
3. Fees and expenses for mergers or consolidations.
4. Office expenses incident to organizing the utility.
5. Stock and minute books and corporate seal.
Note A: This account shall not include any discounts upon securities
issued or assumed; nor shall it include any costs incident to
negotiating loans, selling bonds or other evidences of debt, or expenses
in connection with the authorization, issuance, or sale of capital
stock.
Note B: Exclude from this account and include in the appropriate
expense account the cost of preparing and filing papers in connection
with the extension of the term of incorporation unless the first
organization costs have been written off. When charges are made to this
account for expenses incurred in mergers, consolidations, or
reorganizations, amounts previously included herein or in similar
accounts in the books of the companies concerned shall be excluded from
this account.
302 Franchises and consents.
A. This account shall include amounts paid to the Federal Government,
to a State or to a political subdivision thereof in consideration for
franchises, consents, or certificates, running in perpetuity or for a
specified term of more than 1 year, together with necessary and
reasonable expenses incident to procuring such franchises, consents, or
certificates of permission and approval, including expenses of
organizing and merging separate corporations, where statutes require,
solely for the purpose of acquiring franchises.
B. If a franchise, consent, or certificate is acquired by assignment,
the charge to this account in respect thereof shall not exceed the
amount paid therefor by the utility to the assignor, nor shall it exceed
the amount paid by the original grantee, plus the expense of acquisition
to such grantee. Any excess of the amount actually paid by the utility
over the amount above specified shall be charged to account 426.5, Other
Deductions.
C. When any franchise has expired, the book cost thereof shall be
credited hereto and charged to account 426.5, Other Deductions, or to
account 111, Accumulated Provision for Amortization and Depletion of Gas
Utility Plant (For Nonmajor Companies; account 110, Accumulated
Provisions for Depreciation, Depletion and Amortization of Gas Utility
Plant), as appropriate.
D. Records supporting this account shall be kept so as to show
separately the book cost of each franchise or consent.
Note: Annual or other periodic payments under franchises shall not
be included herein but in the appropriate operating expense account.
303 Miscellaneous intangible plant.
A. This account shall include the cost of patent rights, licenses,
privileges, and other intangible property necessary or valuable in the
conduct of the utility's gas operations and not specifically chargeable
to any other account.
B. When any item included in this account is retired or expires, the
book cost thereof shall be credited hereto and charged to account 426.5,
Other Deductions, or account 111, Accumulated Provision for Amortization
and Depletion of Gas Utility Plant (For Nonmajor Companies; account
110, Accumulated Provisions for Depreciation, Depletion and Amortization
of Gas Utility Plant), as appropriate.
C. This account shall be maintained in such a manner that the utility
can furnish full information with respect to the amounts included
herein.
304 Land and land rights.
This account shall include the cost of land and land rights used in
connection with manufactured gas production. (See gas plant instruction
7.)
305 Structures and improvements.
This account shall include the cost of structures and improvements
used in connection with manufactured gas production. (See gas plant
instruction 8.)
Note: Include relief holders in this account.
306 Boiler plant equipment.
This account shall include the cost installed of furnaces, boilers,
steam and feed water piping, boiler apparatus, and accessories used in
the production of steam at gas production plants.
1. Accumulators.
2. Air preheaters, including fans and drives, and ducts not part of
building.
3. Ash disposal equipment, including sluiceways not part of a
building, pumps and piping, crane, ash bucket conveyor and drives, ash
cars, etc.
4. Belt conveyors, including drives.
5. Blast gate valves.
6. Blow-down tanks and piping.
7. Boilers, including valves attached thereto, casings, safety
valves, soot blowers, soot hoppers, superheaters, and feed water
regulators.
8. Cinder and dust catcher system, including mechanical and electric
types.
9. Coal and coke handling equipment, including hoppers, lorries,
etc., used wholly for boilers.
10. Combustion control system, including all apparatus installed for
the regulation and control of the supply of fuel or air to boilers.
11. Control apparatus.
12. Cranes, hoists, etc., wholly identified with apparatus listed
herein.
13. Desuperheaters and reducing valves.
14. Draft apparatus, including forced, induced, and other draft
systems, with blowers, fans, and ducts not part of building.
15. Economizers.
16. Emergency lighting systems, not part of building, keep-a-lite
systems, etc.
17. Emergency signal systems, in connection with boiler operation.
18. Feed water heaters, including primary and stage.
19. Flues, uptakes, and breeching, whether or not stacks are included
in this account.
20. Foundations and settings, specially constructed for and not
intended to outlast the apparatus for which provided.
21. Furnaces.
22. Gas firing system, including gas lines, burners, etc., for gas
fired boilers.
23. Injectors.
24. Mechanical stoker and feeding systems, clinker grinders,
including drives.
25. Meters, gauges, recording instruments, etc.
26. Oil burning equipment, including tanks, heaters, pumps with
drives, burner equipment, piping, and conditioning apparatus.
27. Painting, first cost.
28. Panels, control (for operating apparatus listed herein).
29. Piping system, steam header and exhaust header, including
accessory pipe hangers, steam traps, etc., make-up water, feed water,
drip, blow-off, water pipe lines used for steam plant, and valve control
system.
30. Platforms, railings, steps, gratings, etc., appurtenant to
apparatus listed herein.
31. Pulverizing equipment.
32. Pumps and driving units, for feed water, heater condensate,
condenser water, and drip.
33. Stacks -- brick, steel, and concrete, when set on separate
foundations independent of substructure or superstructure of building.
34. Steam reheaters.
35. Steelwork, especially constructed for apparatus listed herein.
36. Tanks, including surge, weighing, return, blow-off, feed water
storage.
37. Tar burning equipment for utilization of tar as boiler fuel,
including tanks, pumps, burner equipment, piping, etc.
38. Waste heat boilers and accessories -- stack valve and stack
irrespective of location.
39. Water treatment system, including purifiers, settling tanks,
filters, chemical mixing and dosing apparatus, etc.
Note A: This account shall not include boilers or steam pipes whose
primary purpose is the heating of buildings.
Note B: When the system for supplying boiler or condenser water is
elaborate, as when it includes a dam, reservoir, canal, or pipe line,
the cost shall not be charged to this account but to a special
subdivision of account 305, Structures and Improvements -- Manufactured
Gas.
307 Other power equipment.
A. This account shall include the cost installed of electric
generating and accessory equipment used for supplying electricity in gas
production plants.
B. This account shall also include the cost installed of
miscellaneous power equipment at gas production plants which is not
included in any other account.
1. Acid proofing of battery rooms.
2. Air duct runs in battery rooms.
3. Air pump, streamjet.
4. Batteries for control and general station use.
5. Belts, pulleys, hangers, shafts, and countershafts.
6. Cables between generators and switchboards.
7. Cabinets, control.
8. Compartments, including buses, connections, and items permanently
attached.
9. Enclosure equipment not an integral part of building.
10. Engines, including steam rotary or reciprocating, steam turbines,
and internal combustion engines.
11. Foundations and settings, specially constructed for and not
intended to outlast the apparatus for which provided.
12. Generators, a.c. or d.c., including excitation system.
13. Ground connections, for main station ground.
14. Lightning arresters.
15. Motor generators, frequency changers and converters.
16. Overhead power lines, including poles, crossarms, insulators,
conductors, etc.
17. Panels, control, including supports and instruments.
18. Piping applicable to apparatus listed herein.
19. Reactors.
20. Rectifiers.
21. Safety equipment, including rubber mats, remote closing devices,
glove cabinets.
22. Switchboards, including frames, panels, meters, and instruments.
23. Switching equipment, including oil circuit breakers,
disconnecting switches, and connections.
24. Synchronous converters.
25. Transformers, including transformer platforms.
26. Underground conduit system, including manholes and conductors.
Note: When any unit of equipment listed herein is wholly used to
furnish power to equipment included in another single account, its cost
shall be included in such account.
308 Coke ovens.
This account shall include the cost installed of coke ovens used for
the production of gas.
1. Apparatus for placing coal in ovens.
2. Bins, if not part of a building.
3. Cabinets, control.
4. Calorimeters.
5. Cars, quenching.
6. Charging lorry.
7. Clay mixers.
8. Coke guide.
9. Coke and pusher benches.
10. Collecting mains.
11. Control apparatus.
12. Conveyor, flight.
13. Cover lifting machinery.
14. Door handling machine.
15. Door luting machine.
16. Driving units for coke oven machinery.
17. Enclosures for machinery.
18. Engines, when not an integral part of the driven equipment.
19. Firing equipment.
20. Flues, uptakes, and breeching.
21. Foundations.
22. Fuel handling equipment used exclusively for coal to be
carbonized in ovens.
23. Fuel systems under ovens.
24. Hot coke wharves.
25. Hot coke cars.
26. Instruments or meters, electrical.
27. Locomotives.
28. Mud mill.
29. Motor control equipment.
30. Ovens.
31. Panel, control.
32. Piping, including ascension pipes, hydraulic main, liquor
flushing decanter tank, liquor pump, and return line to hydraulic main.
33. Pushers, including tracks and driving equipment.
34. Quenching station including structure, tank, well, piping, etc.
35. Quenching towers, piping, etc.
36. Regenerator, from bottom of oven floor tile to battery
foundation.
37. Reversing machine, with enclosure.
38. Scale, platform.
39. Signal system.
40. Skip hoist.
41. Stacks.
42. Steel and iron work supports, platforms, stairways, etc.
43. Switches and switchboards.
309 Producer gas equipment.
This account shall include the cost installed of equipment used for
the production of producer gas.
1. Ash handling equipment, used exclusively for producers.
2. Blast apparatus, including blowers, driving units, and blast
mains.
3. Control apparatus.
4. Coolers and scrubbers.
5. Driving apparatus for producers.
6. Foundations and settings, specially constructed for and not
intended to outlast the apparatus for which provided.
7. Fuel handling equipment, used exclusively for producers.
8. Humidifiers.
9. Piping -- air, steam (commencing at steam header), water (inside
of building), and producer gas (up to outlet of final piece of apparatus
in building).
10. Producer boosters, including driving units.
11. Producers.
12. Water separators.
310 Water gas generating equipment.
This account shall include the cost installed of equipment used in
the generation of water gas.
1. Automatic operation equipment.
2. Back-run installations.
3. Blast equipment, including blowers and driving units, piping and
supports.
4. Bridge, coal shed to generator house.
5. Carburetors.
6. Charging equipment, fuel.
7. Circulating water pumps.
8. Concrete or brick pits, including cover, not part of building.
9. Control apparatus.
10. Conveyors.
11. Dust collectors.
12. Enclosures for equipment (barriers, fire walls, guards, housings,
screens, etc.).
13. Flow meters.
14. Foundations and settings, specially constructed for and not
intended to outlast the apparatus for which provided.
15. Fuel handling equipment used exclusively for fuel for this
account.
16. Gauges, indicating and recording.
17. Generators.
18. Hot valves.
19. Hydraulic operation equipment.
20. Instruments and meters, electrical.
21. Oil handling and storage apparatus used solely for water gas
apparatus (tanks, pumps and oil lines, oil heaters, manholes, valve
pits, regulators, strainers, etc.).
22. Oil spray.
23. Operating floors and supports, stairways, etc.
24. Piling under foundations.
25. Piping and valves -- steam (commencing at steam header) tar (to
decanter) water (inside of building), and gas up to outlet of final
pieces of apparatus in building).
26. Pressure regulators.
27. Scales, when used in connection with items in this account.
28. Seal pots.
29. Superheaters and superheater stacks.
30. Tanks, hydraulic pressure.
31. Valve operating mechanisms.
32. Wash boxes.
311 Liquefied petroleum gas equipment.
A. This account shall include the cost installed of equipment used
for the production of gas from petroleum derivatives, such as propane,
butane, or gasoline.
B. Subdivisions of this account shall be maintained for each
producing process for which this account is provided. A separate
subaccount shall be maintained also for bottling equipment included
herein.
1. Blowers.
2. Boilers.
3. Calorimixer.
4. Carbureting equipment.
5. Compression equipment.
6. Controller.
7. Control apparatus.
8. Enclosures and protective fences.
9. Foundations and settings, specially constructed for and not
intended to outlast the apparatus for which provided.
10. Heat exchanger.
11. Gauges and instruments.
12. Mixing or proportioning equipment.
13. Motors, not an integral part of driven equipment.
14. Odorizing equipment.
15. Oil separator.
16. Piping -- steam (commencing at steam header), water (inside of
building), oil (from supply tank), and gas (up to outlet of final piece
of apparatus in building).
17. Pits.
18. Prime movers.
19. Pumps, including driving units.
20. Regulator.
21. Stairs, platforms, and ladders.
22. Storage equipment, tanks, etc.
23. Superheater.
24. Traps.
25. Valves -- regulating and check.
26. Vaporizing equipment.
312 Oil gas generating equipment.
This account shall include the cost installed of equipment used for
generating oil gas.
1. Air blast equipment, including blowers and driving units, piping
and supports.
2. Air inlet louvres and filters.
3. Foundations and settings, specially constructed for and not
intended to outlast the apparatus for which provided.
4. Generating equipment, including automatic cycle controls,
generators, operating floor, superheaters and wash boxes.
5. Instruments and instrument boards, complete with signal lights and
thermocouples and including gauge board, pressure gauges, and
pyrometers.
6. Meters and regulators, such as, air flow meter, generator oil
meter, steam flow meter, and steam regulator.
7. Piping and valves, air, steam (commencing at steam header), water
(inside building), and oil gas (up to outlet of final piece of apparatus
in building).
8. Pumps, hydraulic and oil.
9. Tanks, hydraulic accumulator, hydraulic return, oil and steam
accumulator.
313 Generating equipment -- Other processes.
This account shall include, with subdivisions for each type of gas
produced, the cost installed of generating equipment which is not
included in any of the foregoing accounts, such as benches and retorts
for the production of coal gas, equipment used for generating acetylene
gas, etc.
As to coal gas production equipment:
1. Benches.
2. Charging and drawing machines.
3. Control apparatus.
4. Equipment for steaming retorts.
5. Flues, uptakes and breeching, whether or not stacks are included
in this account.
6. Foundations.
7. Fuel handling equipment used exclusively for retorts, including
weight lorries, tracks, etc., and grinders, breakers, and screens
located in retort house.
8. Fuel system under retorts, including built-in producers.
9. Piping, including ascension pipes, hydraulic main, liquor flushing
decanter tank. liquor pump, and return line to hydraulic main.
10. Primary atmospheric condensers.
11. Retorts.
12. Stacks -- brick, steel, and concrete when set on separate
foundations independent of substructure or superstructure of buildings,
including lightning arresters.
314 Coal, coke, and ash handling equipment.
This account shall include the cost installed of structures or
equipment used for the transportation, storage, washing, and treatment
of coal, coke, and ashes, when used for general gas plant operations.
1. Bins -- mixing, refuse, storage, etc.
2. Boom operating mechanism.
3. Breaker equipment.
4. Bridges, bridge track, and machinery.
5. Bucket conveyors and supports.
6. Capstan.
7. Cars.
8. Chutes.
9. Circuit breakers.
10. Coal loaders.
11. Coal preparation machinery, including washing and drying
equipment.
12. Conduit, electrical.
13. Conveyors and supports.
14. Crane, caterpillar.
15. Driving apparatus for equipment listed herein.
16. Elevators.
17. Enclosure equipment.
18. Engines, not an integral part of driven equipment.
19. Foundations and settings, specially constructed for and not
intended to outlast the apparatus for which provided.
20. Gravity swing unloader.
21. Hoppers.
22. Instruments or meters, electrical.
23. Ladders, fixed.
24. Loading towers and equipment.
25. Locomotives.
26. Motor generators used only for equipment in this account.
27. Panel, control.
28. Pitts.
29. Pulverizing equipment.
30. Railroad sidings and yard tracks.
31. Sampling equipment.
32. Scales.
33. Screens.
34. Sheds and fencing.
35. Shuttle boom.
36. Signal system equipment.
37. Silo.
38. Skip hoist.
39. Stairs, railings, etc.
40. Transfer cars and trucks.
41. Trestles.
42. Turntable.
43. Unloaders.
44. Weightometer.
315 Catalytic cracking equipment.
This account shall include the cost installed of equipment used for
producing gas by the catalytic cracking process.
1. Caloric meters.
2. Catalytic furnace, including catalyst and foundation.
3. Combustion air blowers.
4. Compressors, air.
5. Control equipment.
6. Cooling coils, including foundations.
7. Cooling towers, including foundations.
8. Enclosures.
9. Fractionalizing units.
10. Piping and valves.
11. Preheaters.
12. Pressure regulators.
13. Proportioning controls.
14. Tanks.
15. Vaporizers.
316 Other reforming equipment.
This account shall include the cost installed of equipment, other
than catalytic cracking equipment, used primarily for reforming gas with
resultant changes in its chemical composition and calorific value.
1. Blast equipment, including blowers and driving units, piping, and
supports.
2. Control apparatus.
3. Foundations and settings, specially constructed for and not
intended to outlast the apparatus for which provided.
4. Fuel and ash handling equipment, used wholly in reforming gas.
5. Oil gas apparatus, used for reforming gas.
6. Piping -- steam (commencing at steam header), water (inside of
building), and gas (up to outlet of final piece of apparatus in
building).
7. Pumps and driving units.
8. Purifiers for gas to be reformed.
9. Regulators.
10. Water gas generators, used primarily for reforming gas.
317 Purification equipment.
This account shall include the cost installed of apparatus used for
the removal of impurities from gas and apparatus for conditioning gas,
including pumps, wells, and other accessory apparatus.
1. Blowers for revivifying.
2. Blowers for activators.
3. Condensers and washer coolers.
4. Control apparatus -- conduit, cable, cabinets, switchboards, etc.
5. Crane or cover lifting equipment, not part of the structure.
6. Dehydrators.
7. Engines, not an integral part of driven equipment.
8. Foundations and settings, specially constructed for and not
intended to outlast the equipment for which provided.
9. Instruments and meters, electric.
10. Lubricators.
11. Naphthalene and light oil scrubbers.
12. Other accessory equipment such as coolers, spray ponds, pumps,
platforms, railings, stairs.
13. Oxide elevators and pits, platforms, tables, and trenches.
14. Piping -- air, steam, water, gas, condensate, liquor, tar, etc.,
from inlet valve of first piece of apparatus to outlet valve of final
piece of apparatus (or, in building, from entrance to building to exit
from building).
15. Precipitators.
16. Purifiers -- iron oxide or liquid, including first filling.
17. Recording gauges and thermometers.
18. Revivifying air ducts.
19. Saturator with auxiliary equipment.
20. Scrubbers.
21. Seal and drip pots.
22. Signal system identified with equipment herein.
23. Sulphur removal apparatus.
24. Tar extractors and Cottrell precipitators.
25. Tar pumps and tanks.
26. Track runs for cranes and hoists.
27. Wash boxes.
28. Water meters, for cooling water.
318 Residual refining equipment.
This account shall include the cost installed of apparatus used in
refining and handling of residuals except where the apparatus is
necessary for the operation of property included in account 317,
Purification Equipment.
1. Ammonia stills, condensers, saturators, etc.
2. Apparatus for removal of residuals from purifier liquids.
3. Coke filter.
4. Coke handling and storage facilities used solely for coke held for
sale.
5. Condensers.
6. Control apparatus.
7. Coolers.
8. Decanters.
9. Foundations specially constructed for and not intended to outlast
the apparatus for which provided.
10. Gauges.
11. Heating equipment for apparatus included in this account.
12. Instruments.
13. Light oil stills, washers, etc.
14. Piping and pumps.
15. Platforms, stairs, and ladders.
16. Separators.
17. Storage tanks.
18. Supports.
19. Tar dehydrators, stills, etc.
319 Gas mixing equipment.
This account shall include the cost installed of equipment used for
mixing manufactured and natural gas, or the mixing of other gases
incident to delivery of such mixed gases to the distribution system.
1. Alcohol units.
2. Automatic mixing controls.
3. Btu adjustor.
4. Calorimeter.
5. Calorimixer.
6. Compressor.
7. Gas heater.
8. Gas scrubber (air filter, dust cleaner).
9. Gauges and instruments.
10. Meters.
11. Mixing chambers.
12. Odorizing equipment.
13. Oil pump units.
14. Panel and control equipment.
15. Piping and valves.
16. Regulators, pressure and ratio.
17. Safety alarm equipment.
320 Other equipment.
This account shall include the cost installed of equipment used in
the production of gas, when not assignable to any of the foregoing
accounts.
1. Cabinet, control.
2. Compressed air system.
3. Fire hose carts.
4. First aid room equipment.
5. Foamite system.
6. Foundations and settings specially constructed for and not
intended to outlast the apparatus for which provided.
7. Gasoline pumps.
8. Hand pumps.
9. Machine shop equipment, such as lathes, pipe cutting and threading
machines, vise grinders, power saw, shop motors, shafting and belting,
drill press, shapers, milling machines, planes, etc.
10. Odorizing equipment.
11. Office furniture and equipment.
12. Oil foggers.
13. Panel, control.
14. Piping -- yard, when not includible in other accounts.
15. Pits.
16. Platforms.
17. Portable scaffolds, ladders, etc.
18. Power shovels.
19. Production laboratory equipment.
20. Scales, not associated with other equipment.
21. Special signal equipment.
22. Tractors for general plant use.
23. Works exhauster including driving unit and governor.
24. Works station meters, including gauges, piping and accessories.
The net book value of amounts recorded in the natural gas production
accounts incurred on or related to leases acquired after October 7,
1969, shall, in general, not exceed the net realizable value (estimated
selling price less estimated costs of extraction, completion, and
disposal) of recoverable hydrocarbon reserves discovered on such leases.
After initiation of exploration and development on leases acquired
after October 7, 1969, the utility must determine after a reasonable
period of time, and annually thereafter, whether the net realizable
value of such recoverable reserves will be sufficient to absorb the net
book value of amounts recorded in the accounts. The recoverable
reserves shall be determined and attested to by independent appraisers
no less frequently than every 3 years. If the net realizable value of
recoverable reserves is not sufficient to absorb the net book value of
amounts in the production accounts, the utility shall reduce the net
book value of the amounts in the accounts to net realizable value of
recoverable reserves. The reduction shall be done by first reducing the
unamortized amounts recorded in Account 338, Unsuccessful Exploration
and Development Costs, by debiting Account 404.1, Amortization and
Depletion of Producing Natural Gas Land and Land Rights (for Nonmajor
companies, 403.1, Depreciation and Depletion Expense). Next, if the net
book value related to successful costs exceeds the net realizable value
of the recoverable reserves, the production plant accounts shall be
written down to such net realizable value by appropriate charges and
credits to the expense and valuation accounts.
325.1 Producing lands.
This account shall include the cost of lands held in fee on which
producing natural gas wells are located, and lands held in fee which are
being drained of natural gas through the operation by the utility of
wells on other land. (See gas plant instruction 7-G.)
325.2 Producing leaseholds.
A. This account shall include the cost of acquiring leaseholds on
which the utility pays royalties for natural gas obtained therefrom.
(See gas plant instruction 7-G.)
B. Exclude from this account rents paid periodically for rights
obtained under leases. Exclude also from this account the cost of
leaseholds which terminate in one year or less after they become
effective.
325.3 Gas rights.
This account shall include the cost of natural gas rights used in
producing natural gas, whereby the utility obtains ownership in gas
underlying land not owned or leased by the utility. It does not provide
for gas rights which are leased and which are properly chargeable to
account 325.2, Producing Leaseholds.
325.4 Rights-of-way.
This account shall include the cost of all interests in land which
terminate more than 1 year after they become effective and on which are
located gathering pipelines, telephone pole lines, and like property
used in connection with the production of natural gas. (See gas plant
instruction 7.)
325.5 Other land and land rights.
This account shall include the cost of land and land rights used in
connection with the production of natural gas, when not properly
assignable to any of the foregoing accounts. (See gas plant instruction
7.)
326 Gas well structures.
This account shall include the cost of well structures and
improvements used in connection with the housing of permanent bailers
and other equipment necessary to keep the wells in operation. (See gas
plant instruction 8.)
327 Field compressor station structures.
This account shall include the cost of structures and improvements
used in connection with the housing of compressor station equipment used
to raise the pressure of natural gas before it is conveyed to the
terminus of the field lines. (See gas plant instruction 8.)
328 Field measuring and regulating station structures.
This account shall include the cost of structures and improvements
used in connection with the housing of meters, regulators, and
appurtenant appliances for measuring and regulating natural gas before
the point where it enters the transmission or distribution system. (See
gas plant instruction 8.)
329 Other structures.
This account shall include the cost of structures and improvements
used in connection with natural gas production and gathering not
provided for elsewhere. (See gas plant instruction 8.)
330 Producing gas wells -- Well construction.
This account shall include the cost of drilling producing gas wells.
1. Clearing well site.
2. Hauling, erecting, dismantling, and removing boilers, portable
engines, derricks, rigs, and other equipment and tools used in drilling.
3. Drilling contractors' charges.
4. Drive pipe.
5. Fuel or power.
6. Labor.
7. Rent of drilling equipment.
8. Water used in drilling, obtained either by driving wells, piping
from springs or streams, or by purchase.
9. Hauling well equipment.
10. Shooting, fracturing, acidizing.
331 Producing gas wells -- Well equipment.
This account shall include the cost of equipment in producing gas
wells.
1. Bailing equipment.
2. Boilers and drives permanently connected.
3. Casing.
4. Derrick.
5. Fence, when solely an enclosure for equipment.
6. Fittings, including shut-in valves, bradenheads and casing heads.
7. Packing.
8. Tank, oil or water, etc.
9. Tubing.
332 Field lines.
This account shall include the cost installed of field lines used in
conveying natural gas from the wells to the point where it enters the
transmission or distribution system.
1. Gathering lines, including pipe, valves, fittings, and supports.
2. Cathodic protection equipment.
3. Creek crossings, suspension bridges and other special
construction.
4. Line drips and separators.
5. Line pack gas.
333 Field compressor station equipment.
This account shall include the cost installed of compressor station
equipment and associated appliances used to raise the pressure of
natural gas before it is conveyed to the terminus of the field lines.
1. Boiler plant, coal handling and ash handling equipment for steam
powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries,
foundations, guard rails and enclosures, etc.
4. Electric system equipment, including generating equipment and
driving units, power wiring, transformers, regulators, battery
equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling
tower and pond and associated equipment, dehydrators, fuel gas mixers,
special pipe bends and connections, and associated scrubbers,
separators, tanks, gauges and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks,
purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as
heating boilers, steel lockers, first-aid equipment, gasoline dispensing
equipment, lawn mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank,
water piping, cooling tower, spray fence, and water treatment equipment,
etc., but not including water system equipment solely for domestic and
general use.
334 Field measuring and regulating station equipment.
This account shall include the cost installed of meters, gauges, and
other equipment used in measuring and regulating natural gas collected
in field lines before the point where it enters the transmission or
distribution system.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc.,
and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
335 Drilling and cleaning equipment.
This account shall include the cost of implements and equipment used
in drilling and cleaning natural gas wells.
1. Bailers.
2. Bits and other drilling tools.
3. Boilers.
4. Derricks.
5. Drilling cables.
6. Drilling machines.
7. Engines.
8. Motors.
9. Pulling machines.
10. Pumps.
11. Rigs.
12. Tanks.
336 Purification equipment.
This account shall include the cost installed of apparatus used for
the removal of impurities from gas and apparatus for conditioning gas.
1. Condensers and washer coolers.
2. Dehydrators.
3. Foundations and settings, specially constructed for and not
intended to outlast the equipment for which provided.
4. Other accessory equipment, such as coolers, spray ponds, pumps,
platforms, railings, stairs.
5. Piping, from inlet valve of first piece of apparatus to outlet
valve of final piece of apparatus (or, in building, from entrance to
building to exit from building).
6. Scrubbers.
7. Sulphur removal apparatus.
8. Water supply system.
Note: In general this account shall include all dehydrators located
in or adjacent to production areas which are used to remove water and
other stray liquids from gas produced by the utility or purchased in or
adjacent to production areas. In some instances such dehydrators may be
located some distance from the production sources of the gas. Where,
however, the utility has no production and gathering facilities with
respect to any of the gas passing through the dehydrators, such as at
the purchase point at the head of a transmission pipe line company, the
dehydrators may be included in account 368, Compressor Station
Equipment, or account 367, Mains, whichever is the most practicable and
reasonable under the circumstances. Dehydrators which are an adjunct to
products extraction operations shall be included in account 342,
Extraction and Refining Equipment. Dehydrators used in connection with
underground gas storage operations shall be included in account 356,
Purification Equipment.
337 Other equipment.
This account shall include the cost installed of equipment used in
the production and gathering of natural gas, when not assignable to any
of the foregoing accounts.
1. Calorimeter.
2. Control installation.
3. Crane.
4. Laboratory equipment.
5. Odorizing unit.
6. Office furniture and equipment.
7. Oil fogger.
338 Unsuccessful exploration and development costs.
A. This account shall include unsuccessful exploration and
development costs incurred on or related to hydrocarbon leases, on
properties in the contiguous 48 States and the State of Alaska, acquired
after October 7, 1969. It shall also include costs of a preliminary
nature incurred in the search for natural gas in such areas after
October 7, 1969.
B. The costs recorded in this account shall be amortized by debiting
account 404.1, Amortization and Depletion of Producing Natural Gas Land
and Land Rights, and crediting this account using the unit-of-production
or other acceptable method of amortization as hydrocarbons are extracted
from producing wells.
C. In general, the unamortized costs recorded in this account shall
not exceed the net realizable value (estimated selling price less
estimated costs of extraction, completion and disposal) of proven
hydrocarbon reserves on leases acquired after October 7, 1969. (See
''Special Instructions -- Costs Related to Leases Acquired After October
7, 1969,'' above.)
340 Land and land rights.
This account shall include the cost of land and land rights used in
connection with the processing of natural gas for removal of gasoline,
butane, propane, or other salable products. (See gas plant instruction
7.)
341 Structures and improvements.
This account shall include the cost of structures and improvements
used in connection with the processing of natural gas for removal of
gasoline, butane, propane, or other salable products. (See gas plant
instruction 8.)
342 Extraction and refining equipment.
This account shall include the cost installed of equipment used for
the extraction from natural gas of gasoline, butane, propane, or other
salable products and for the refining of such products.
1. Boiler plant equipment, including boiler, boiler setting, heat
exchangers, etc.
2. Compressed air system, including air compressor, air storage tank,
etc.
3. Cooling equipment such as coolers, cooling tower and accessories
for gas, extracted products, etc.
4. Cranes, trolleys, and hoists.
5. Electrical system, including generator and driving unit, power
lines, transformers, switchboard, yard lighting system, etc.
6. Extraction and refining equipment, such as absorbers, reabsorbers,
stills, de- phlegmators, fractionating towers, stabilizing columns,
control apparatus.
7. Foundations and structural supports for equipment items not
intended to outlast the equipment for which provided.
8. Fuel regulating and measuring equipment.
9. Gasoline blending equipment including dye pot, educator pumps,
lead storage tanks, weighing device, etc.
10. Gauges and instruments.
11. Loading racks and associated other equipment.
12. Lubricating oil system.
13. Pumps of various types, such as boiler feed water pumps, loading
and transfer pumps, drip still pumps, oil pumps, skimmer basin pumps,
etc.
14. Tanks of various types such as accumulator and dewatering tanks,
separator tanks, gasoline feed tanks, compressed air tanks, oil surge
tanks, etc., except tanks classifiable as storage equipment, account
344.
15. Water supply system including water well, water tank and
supports, water softener or purification apparatus, traveling water
screen and drive.
16. Yard piping, gas, water, steam, compressed air, fuel, vapor,
extracted products, including headers, valves, etc., but not including
off-site lines includible in account 343, Pipe Lines.
343 Pipe lines.
This account shall include the cost installed of gas and liquids pipe
lines used in connection with the processing of natural gas for the
removal of gasoline, butane, propane, or other salable products,
exclusive of runs of pipe appropriately includible in other equipment
accounts, embracing principally off-site gas, gasoline gathering, and
loading lines not includible as yard piping in account 342, Extraction
and Refining Equipment.
1. Gas lines, off-site, relating solely to extraction operations.
2. Gasoline gathering lines connecting with off-site sources.
3. Gathering line drips.
4. Instruments, indicating and recording.
5. Loading lines connecting with remote off-site loading racks or
storage facilities.
6. Pumps and driving units.
344 Extracted product storage equipment.
This account shall include the cost installed of storage tanks and
associated equipment used in the storing, prior to sale, of gasoline,
butane, propane, and other salable products extracted from natural gas.
1. Foundations.
2. Instruments.
3. Regulators.
4. Storage tanks for partially or fully processed products.
5. Valves.
345 Compressor equipment.
This account shall include the cost installed of compressor equipment
and associated appliances used in connection with the receipt,
processing, and return of natural gas processed for removal of gasoline,
butane, propane, or other salable products.
(See account 333 for items.)
346 Gas measuring and regulating equipment.
This account shall include the cost installed of meters, gauges, and
other equipment used in measuring or regulating natural gas received
and/or returned from processing for removal of gasoline, butane,
propane, or other salable products.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc.,
and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
347 Other equipment.
This account shall include the cost installed of equipment used in
processing natural gas and refining gasoline, butane, propane, and other
salable products extracted from natural gas, when not assignable to any
of the foregoing accounts.
1. Fire fighting equipment.
2. Laboratory and testing equipment.
3. Miscellaneous equipment, such as first-aid cabinet, gasoline
dispensing pump, heating boiler, incinerator, lawn mower, warehouse
truck.
4. Office furniture and equipment.
5. Shop tools and equipment.
The above accounts are to be used by the transmission and
distribution companies for the classification of storage facilities used
for peak shaving operations. The accounts shall be subdivided to
classify the peak shaving storage facilities according to the
transmission or distribution function, if the utility operates both
transmission and distribution systems. Only base load liquefied natural
gas terminaling and processing facilities are to be classified in
accounts 364.1 through 364.8.
350.1 Land.
This account shall include the cost of lands held in fee on which
underground storage wells are located, and other lands held in fee
within an area utilized for the underground storage of gas. (See gas
plant instruction 7-G.)
350.2 Rights-of-way.
This account shall include the cost of all interests in land which do
not terminate until more than 1 year after they become effective and on
which are located underground storage lines, telephone poles lines, and
like property used in connection with underground gas storage
operations. (See gas plant instruction 7.)
351 Structures and improvements.
A. This account shall include the cost in place of structures and
improvements used wholly or predominantly in connection with underground
storage of natural gas. (See gas plant instruction 8.)
B. This account shall be subdivided as follows:
351.1 Well structures.
351.2 Compressor station structures.
351.3 Measuring and regulating station structures.
351.4 Other structures.
352 Wells.
This account shall include the drilling cost of wells used for
injection and withdrawal of gas from underground storage projects,
including wells kept open and used for observation.
Drilling:
1. Clearing well site.
2. Hauling, erecting, dismantling, and removing boilers, portable
engines, derricks, rigs, and other equipment and tools used in drilling.
3. Drilling contractors' charges.
4. Drive pipe.
5. Fuel or power.
6. Labor.
7. Rent of drilling equipment.
8. Water used in drilling, obtained either by driving wells, piping
from springs or streams, or by purchase.
9. Hauling well equipment.
10. Shooting, fracturing, acidizing.
Equipment:
11. Bailing equipment.
12. Boilers and drives permanently connected.
13. Casing.
14. Derrick.
15. Fence, when solely an enclosure for equipment.
16. Fittings, including shut-in valves, bradenheads and casing heads.
17. Packing.
18. Tank, oil or water, etc.
19. Tubing.
352.1 Storage leaseholds and rights.
A. This account shall include the cost of leaseholds, storage rights,
mineral deeds, etc. on lands for the purpose of utilizing subsurface
reservoirs for underground gas storage operations. (See gas plant
instruction 7-G.)
B. Exclude from this account rents or other charges paid periodically
for use of subsurface reservoirs for underground gas storage purposes.
Note: Items such as buildings, wells, lines, equipment and
recoverable gas used in storage operations acquired with land or storage
leaseholds and rights are to be classified in the appropriate accounts.
352.2 Reservoirs.
This account shall include costs to prepare underground reservoirs
for the storage of natural gas.
1. Geological, geophysical and seismic costs.
2. Plugging abandoned wells.
3. Fuel and power.
4. Drilling and equipping fresh water wells, disposal wells, and
solution wells.
5. Leaching of salt dome caverns.
6. Rentals on storage rights and leases incurred during construction
and development period.
7. Gas used during the development period.
8. Costs incident to maintaining covenants of production leaseholds
during the period required to convert them to storage leaseholds.
9. Other rehabilitation work.
352.3 Nonrecoverable natural gas.
A. This account shall include the cost of gas in underground
reservoirs, including depleted gas or oil fields and other underground
caverns or reservoirs used for the storage of gas which will not be
recoverable.
B. Such nonrecoverable gas shall be priced at the acquisition cost of
native gas or, when acquired for storage by purchase or presumed to be
supplied from the utility's own production, priced as outlined in
Paragraph B of account 117, Gas Stored Underground -- Noncurrent (for
Nonmajor companies, account 164.1, Gas Stored Underground). After
devotion to storage, the cost of the gas shall not be restated to effect
subsequent price changes in purchased gas or changes in the cost of gas
produced by the utility. When the utility has followed the practice of
adjusting nonrecoverable gas to the weighted-average cost of gas
purchased or supplied from its own production, cost shall be the
weighted-average cost of such gas at the effective date of this account.
353 Lines.
This account shall include the cost installed of gas pipe lines used
wholly or predominantly for conveying gas from point of connection with
transmission or field lines to underground storage wells and from
underground storage wells to the point where the gas enters the
transmission or distribution system.
1. Cathodic protection equipment.
2. Creek crossings, suspension bridges and other special
construction.
3. Lines, including pipe, valves, fittings, and supports.
4. Line drips and separators.
5. Line pack gas.
354 Compressor station equipment.
This account shall include the cost installed of compressor station
equipment used wholly or predominantly for the purpose of raising the
pressure of gas for delivery to underground storage or to raise the
pressure of gas withdrawn from underground storage for delivery to the
transmission or distribution system.
1. Boiler plant, coal handling and ash handling equipment for steam
powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries,
foundations, guard rails and enclosures, etc.
4. Electric system equipment, including generating equipment and
driving units, power wiring, transformers, regulators, battery
equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling
tower and pond and associated equipment, dehydrators, fuel gas mixers,
special pipe bends and connections, and associated scrubbers,
separators, tanks, gauges and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks,
purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as steel
lockers, first-aid equipment, gasoline dispensing equipment, lawn
mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank,
water piping, cooling tower, spray fence, and water treatment equipment,
etc., but not including water system equipment solely for domestic and
general use.
355 Measuring and regulating equipment.
This account shall include the cost installed if equipment used
wholly or predominantly for the purpose of measuring and regulating
deliveries of gas to underground storage and withdrawals of gas from
underground storage.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc.,
and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
356 Purification equipment.
This account shall include the cost installed of apparatus used
wholly or predominantly for the removal of impurities from and the
conditioning of, gas delivered to or removed from underground storage
fields.
1. Condensers and washer coolers.
2. Dehydrators.
3. Foundations and settings, specially constructed for and not
intended to outlast the equipment for which provided.
4. Other accessory equipment, such as coolers, spray ponds, pumps,
platforms, railings, stairs.
5. Piping, from inlet valve of first piece of apparatus to outlet
valve of final piece of apparatus (or, in building, from entrance to
building to exit from building).
6. Scrubbers.
7. Sulphur removal apparatus.
8. Water supply system.
357 Other equipment.
This account shall include the cost installed of equipment used
wholly or predominantly in connection with underground storage of gas,
when not assignable to any of the foregoing accounts.
1. Calorimeter.
2. Control installation.
3. Crane.
4. Odorizing unit.
5. Office furniture and equipment.
6. Oil foggers.
360 Land and land rights.
This account shall include the cost of land and land rights used in
connection with the storage of gas in holders. (See gas plant
instruction 7.)
361 Structures and improvements.
This account shall include the cost in place of structures and
improvements used in connection with the storage of gas in holders.
(See gas plant instruction 8.)
362 Gas holders.
This account shall include the cost installed of holders and
associated appliances used in the storage of gas above ground, or in
underground receptacles.
1. Alarm systems.
2. Buried piping, tanks or other underground construction for gas
storage.
3. Flood and fire control equipment.
4. Foundations.
5. Holder pistons.
6. Holders-waterless, including elevators, tar apparatus, and inlet
and outlet connections.
7. Holders-waterseal, including oil skimmer, heating equipment,
drips, and inlet and outlet connections.
8. Hortonspheres and high pressure tanks, including inlet and outlet
connections, access equipment, etc.
9. Lighting.
10. Pumps.
11. Ventilating equipment.
12. Walkways.
Note A: If the utility stores gas by the liquefaction process the
holders for such liquids, whether above or below ground, shall be
included in a separate subaccount hereunder.
Note B: Relief holders used in connection with manufactured gas
operations shall be included in account 305, Structures and
Improvements.
363 Purification equipment (Major only).
This account shall include the cost installed of apparatus used for
the removal of impurities from gas and apparatus for conditioning gas.
1. Condensers and washer coolers.
2. Dehydrators.
3. Foundations and settings, specially constructed for and not
intended to outlast the equipment for which provided.
4. Other accessory equipment, such as coolers, spray ponds, pumps,
platforms, railings, stairs.
5. Piping from inlet valve of first piece of apparatus to outlet
valve of final piece of apparatus (or, in building from entrance to
building to exit from building).
6. Scrubbers.
7. Sulphur removal apparatus.
8. Water supply system.
363.1 Liquefaction equipment (Major only).
This account shall include the cost installed of equipment used in
liquefaction of natural gas.
1. Cold box.
2. Heat exchanger.
3. Condensers.
4. Pumps.
5. Tanks.
363.2 Vaporizing equipment (Major only).
This account shall include the cost installed of vaporizing equipment
used in connection with liquefied natural gas storage.
363.3 Compressor equipment (Major only).
This account shall include the cost installed of compressor equipment
and associated appliances used in connection with other storage plant.
363.4 Measuring and regulating equipment (Major only).
This account shall include the cost installed of equipment used to
measure deliveries of gas to other storage and withdrawals of gas from
other storage.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc.,
and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
363.5 Other equipment.
This account shall include the cost installed of other equipment used
in connection with the storage of gas in holders.
1. Complete inlet and outlet connections.
2. Compressor.
3. Foundation.
4. Gauges and instruments.
5. Regulating apparatus.
6. Line pack gas.
364.1 Land and land rights (Major only).
A. This account shall include the cost of land and land rights used
in connection with liquefied natural gas terminaling and processing
operations. (See gas plant instruction 7.)
364.2 Structures and improvements (Major only).
A. This account shall include the cost in place of structures and
improvements used in connection with liquefied natural gas terminaling
and processing operations. (See gas plant instruction 8.)
B. This account shall be subdivided as follows:
1. Docking and harbor facilities.
2. LNG processing terminal structures.
3. Measuring and regulating structures.
4. Compressor station structures.
5. Other structures.
364.3 LNG processing terminal equipment (Major only).
This account shall include the cost installed of equipment used to
receive, hold, and regasify liquefied natural gas for delivery into the
utility's transmission or distribution system.
1. Aftercoolers.
2. Air compressors.
3. Air coolers.
4. Alarm systems.
5. Blowers.
6. Cold box, condensers.
7. Controls and control apparatus.
8. Dikes.
9. Drums.
10. Electrical power and ignition circuits including wiring and
conduits.
11. Emission control equipment.
12. Fire control devices and equipment.
13. Foundations.
14. Generators.
15. Heat exchangers.
16. Heaters and reheaters.
17. Instrumentation.
18. Intercoolers.
19. Liquefaction compressors.
20. Liquefied gas holders and storage tanks.
21. Nitrogen system equipment.
22. Plant piping including pipe supports.
23. Pollution control facilities.
24. Pumps and driving units.
25. Stacks.
26. Tanks, other than LNG storage tanks (including ladders, stairs,
walkways, and lighting).
27. Unloading and loading arms, and appurtenant equipment.
28. Valves.
29. Vaporizers.
30. Waste heat recovery units.
31. Water craft not to include LNG tankers and barges.
32. Miscellaneous other equipment.
33. Line pack gas.
364.4 LNG transportation equipment (Major only).
This account shall include the cost of vehicles used for the
transportation of liquefied natural gas.
1. LNG barges.
2. LNG maritime tankers.
3. LNG tank trucks.
4. Other LNG transportation equipment.
364.5 Measuring and regulating equipment (Major only).
This account shall include the cost installed of meters, gauges and
other equipment used in base load LNG operations for measuring or
regulating natural gas prior to its entrance into the utility's
transmission or distribution system.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundation, pits, etc.
4. Gas analyzer equipment.
5. Gas cleaners, scrubbers, separators, dehydrators, etc.
6. Gauges and instruments, including piping, fittings, wiring, etc.,
and panel boards.
7. Headers.
8. Meters, orifice or positive, including piping and connections.
9. Oil fogging equipment.
10. Odorizing equipment.
11. Regulators or governors, including controls and instruments.
12. Stabilization equipment.
13. Structures of a minor or portable type.
14. Other equipment.
364.6 Compressor station equipment (Major only).
This account shall include the cost installed of compressor station
equipment and associated appliances used in connection with liquefied
natural gas operations prior to entrance of vaporized gas into the
utility's transmission or distribution system.
1. Boiler plant, coal handling, and ash handling equipment for steam
powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries,
foundations, guard rails, and enclosures, etc.
4. Electric system equipment, including generating equipment and
driving units, power wiring, transformers, regulators, battery
equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling
tower and pond and associated equipment, dehydrators, fuel gas mixers,
special pipebends and connections, and associated scrubbers, separators,
tanks, gauges, and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks,
purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as steel
lockers, first-aid equipment, gasoline dispensing equipment, lawn
mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank,
water pipeline, cooling tower, spray fence, and water treatment
equipment, etc., but not including water system equipment used solely
for domestic and general use.
12. Other equipment.
364.7 Communication equipment (Major only).
This account shall include the cost installed of radio, telephone,
microwave, and other equipment used wholly or predominantly in
connection with the operation and maintenance of the liquefied natural
gas system. (See also accounts 370 and 397, Communication Equipment.)
1. Carrier terminal equipment including repeaters, power supply
equipment, transmitting and receiving sets.
2. Microwave equipment, including power supply equipment,
transmitters, amplifiers, paraboloids, towers, reflectors, receiving
equipment, etc.
3. Radio equipment, fixed and mobile, including antenna, power
equipment, transmitter units.
4. Telephone equipment including switchboards, power and testing
equipment, conductors, pole lines, etc.
5. Other equipment.
364.8 Other equipment (Major only).
This account shall include the cost installed of equipment used in
liquefied natural gas operations, when not assignable to any of the
foregoing accounts.
1. Garage and service equipment.
2. General tools, including power operated equipment.
3. Laboratory equipment.
4. Materials handling equipment.
5. Office furniture and equipment.
6. Power generation equipment.
7. Shop equipment.
8. Tools, other than small hand tools.
9. Other equipment.
365.1 Land and land rights.
This account shall include the cost of land and land rights except
rights-of-way used in connection with transmission operations. (See gas
plant instruction 7.)
365.2 Rights-of-way.
This account shall include the cost of rights-of-way used in
connection with transmission operations. (See gas plant instruction 7.)
366 Structures and improvements.
A. This account shall include the cost in place of structures and
improvements used in connection with transmission operations. (See gas
plant instruction 8.)
B. This account shall be subdivided as follows:
366.1 Compressor station structures.
366.2 Measuring and regulating station structures.
366.3 Other structures.
367 Mains.
A. This account shall include the cost installed of transmission
system mains.
B. The records supporting this account shall be so kept as to show
separately the cost of mains of different sizes and types and of each
tunnel, bridge, or river crossing.
1. Anti-freeze lubricating equipment.
2. Automatic valve operating mechanisms, including pressure tanks,
etc.
3. By-pass assembly.
4. Caissons, tunnels, trestles, etc., for submarine mains.
5. Cathodic protection equipment.
6. Drip lines and pots.
7. Excavation, including shoring, bracing, bridging, pumping,
backfill, and disposal of excess excavated material.
8. Foundations.
9. Gas cleaners, scrubbers, etc. when not part of compressor station
or measuring and regulating equipment.
10. Leak clamps. (See gas plant instruction 10-C (1).)
11. Line pack gas.
12. Linewalkers' bridges.
13. Manholes.
14. Municipal inspection.
15. Pavement disturbed, including cutting and replacing pavement,
pavement base, and sidewalks.
16. Permits.
17. Pipe coating.
18. Pipe and fittings.
19. Pipe laying.
20. Pipe supports.
21. Protection of street openings.
22. River, highway, and railroad crossings, including revetments,
pipe anchors, etc.
23. Valves.
24. Welding.
368 Compressor station equipment.
This account shall include the cost installed of compressor station
equipment and associated appliances used in connection with transmission
system operations.
1. Boiler plant, coal handling and ash handling equipment for steam
powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries,
foundations, guard rails and enclosures, etc.
4. Electric system equipment, including generating equipment and
driving units, power wiring, transformers, regulators, battery
equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling
tower and pond and associated equipment, dehydrators, fuel gas mixers,
special pipe bends and connections, and associated scrubbers,
separators, tanks, gauges and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks,
purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as steel
lockers, first-aid equipment, gasoline dispensing equipment, lawn
mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank,
water piping, cooling tower, spray fence, and water treatment equipment,
etc., but not including water system equipment solely for domestic and
general use.
369 Measuring and regulating station equipment.
This account shall include the cost installed of meters, gauges, and
other equipment used in measuring or regulating gas in connection with
transmission system operations.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc.,
and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
Note: Pipeline companies, including companies who measure deliveries
of gas to their own distribution system, shall include in the
transmission function classification city gate and main line industrial
measuring and regulating stations.
370 Communication equipment.
This account shall include the cost installed of radio, telephone,
microwave, and other equipment used wholly or predominantly in
connection with the operation and maintenance of the gas transmission
system. (See also account 397, Communication Equipment.)
1. Carrier terminal equipment including repeaters, power supply
equipment, transmitting and receiving sets.
2. Microwave equipment, including power supply equipment,
transmitters, amplifiers, paraboloids, towers, reflectors, receiving
equipment, etc.
3. Radio equipment, fixed and mobile, including antenna, power
equipment, transmitters and receivers, and portable receiver-transmitter
units.
4. Telephone equipment including switchboards, power and testing
equipment, conductors, pole lines, etc.
371 Other equipment.
This account shall include the cost installed of equipment used in
transmission system operations, when not assignable to any of the
foregoing accounts.
374 Land and land rights.
This account shall include the cost of land and land rights used in
connection with distribution operations. (See gas plant instruction 7.)
375 Structures and improvements.
This account shall include the cost in place of structures and
improvements used in connection with distribution operations. (See gas
plant instruction 8.)
376 Mains.
A. This account shall include the cost installed of distribution
system mains.
B. The records supporting this account shall be so kept as to show
separately the cost of mains of different sizes and types and of each
tunnel, bridge, or river crossing.
1. Caissons, tunnels, trestles, etc. for submarine mains.
2. Clamps, leak (bell and spigot) when installed at time of
construction; when clamps are installed subsequent to construction, the
accounting shall be in accordance with gas plant instruction 10,
paragraph (C) 1.
3. Drip lines and pots.
4. Electrolysis tests, in connection with new construction.
5. Excavation, including shoring, bracing, bridging, pumping,
backfill, and disposal of excess excavated material.
6. Hauling, unloading, and stringing pipe.
7. Lamping and watching new construction.
8. Line pack gas.
9. Municipal inspection.
10. Pavement disturbed, including cutting and replacing pavement,
pavement base, and sidewalks.
11. Permits.
12. Pipe coating.
13. Pipe and fittings.
14. Pipe laying.
15. Pipe supports.
16. Protection of street openings.
17. Relocating city storm and sanitary sewers, catch basins, etc., or
protecting same in connection with new construction.
18. Replacement of municipal drains and culverts in connection with
new construction.
19. Roadway boxes.
20. Shifting excavated material due to traffic conditions in
connection with new construction.
21. Sleeves and couplings.
22. Special crossovers, bridges and foundations for special
construction.
23. Surveying and staking lines.
24. Valves not associated with pumping or regulating equipment.
25. Welding.
26. Wood blocking.
377 Compressor station equipment.
This account shall include the cost installed of compressor station
equipment and associated appliances used in connection with distribution
system operations.
1. Boiler plant, coal handling and ash handling equipment for steam
powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries,
foundations, guard rails and enclosures, etc.
4. Electric system equipment, including generating equipment and
driving units power wiring, transformers, regulators, battery equipment,
switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling
tower and pond and associated equipment, dehydrators, fuel gas mixers,
special pipe bends and connections, and associated scrubbers,
separators, tanks, gauges and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks,
purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as steel
lockers, first-aid equipment, gasoline dispensing equipment, lawn
mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank
water piping, cooling tower, spray fence and water treatment equipment,
etc., but not including water system equipment solely for domestic and
general use.
378 Measuring and regulating station equipment -- General.
This account shall include the cost installed of meters, gauges and
other equipment used in measuring and regulating gas in connection with
distribution system operations other than the measurement of gas
deliveries to customers.
1. Automatic control equipment.
2. Foundations.
3. Gauges and instruments.
4. Governors or regulators.
5. Meters.
6. Odorizing equipment.
7. Oil fogging equipment.
8. Piping.
9. Pressure relief equipment.
10. Vaults or pits, including valves contained therein.
Note: By-passes outside governor pits are includible in account 376,
Mains.
379 Measuring and regulating station equipment -- City gate check
stations.
This account shall include the cost installed of meters, gauges, and
other equipment used in measuring and regulating the receipt of gas at
entry points to distribution systems.
Note: Pipeline companies, including companies who measure deliveries
of gas to their own distribution system, shall include in the
transmission function classification city gate and main line industrial
measuring and regulating stations.
(See account 378 for items.)
380 Services.
A. This account shall include the cost installed of service pipes and
accessories leading to the customers' premises.
B. A complete service begins with the connection on the main and
extends to but does not include the connection with the customer's
meter. A stub service extends from the main to the property line, or
the curb stop.
C. Services which have been used but have become inactive shall be
retired from utility plant in service immediately if there is no
prospect for reuse, and, in any event, shall be retired by the end of
the second year following that during which the service became inactive
unless reused in the interim.
1. Curb valves and curb boxes.
2. Excavation, including shoring, bracing, bridging, pumping,
backfill, and disposal of excess excavated material.
3. Landscaping, including lawns, and shrubbery.
4. Municipal inspection.
5. Pavement disturbed, including cutting and replacing pavement,
pavement base, and sidewalks.
6. Permits.
7. Pipe and fittings, including saddle, T, or other fitting on street
main.
8. Pipe coating.
9. Pipe laying.
10. Protection of street openings.
11. Service drips.
12. Service valves, at head of service, when installed or furnished
by the utility.
381 Meters.
A. This account shall include the cost installed of meters or devices
and appurtenances thereto, for use in measuring gas delivered to users,
whether actually in service or held in reserve.
B. When a meter is permanently retired from service, the installed
cost included herein shall be credited to this account.
C. The records of meters shall be so kept that the utility can
furnish information as to the number of meters of each type and capacity
in service and in reserve as well as the location of each meter.
1. Meters, including badging and initial testing.
Meter installations:
2. Cocks.
3. Labor.
4. Locks.
5. Meter bars.
6. Pipe and fittings.
7. Seals.
8. Shelves.
9. Swivels and bushings.
10. Transportation.
Note A: At the option of the utility, costs of meter installations
may be accounted for separately from the cost of meters in accordance
with the provisions of account 382, Meter Installations. The practice
of the utility, however, shall be consistent from year to year and
throughout the utility's system.
Note B: The cost of removing and resetting meters shall be charged
to account 878, Meter and House Regulator Expenses.
382 Meter installations.
A. This account shall include the cost of labor and materials used,
and expenses incurred in connection with the original installation of
customer meters.
B. When a meter installation is permanently retired from service, the
cost thereof shall be credited to this account.
1. Cocks.
2. Locks.
3. Labor.
4. Meter bars.
5. Pipe and fittings.
6. Seals.
7. Shelves.
8. Swivels and bushings.
9. Transportation.
Note: At the option of the utility, meter installations may be
accounted for as part of the cost installed of meters, in accordance
with the provisions of account 381, Meters. The practice of the
utility, however, shall be consistent from year to year and throughout
the utility's system.
383 House regulators.
A. This account shall include the cost installed of house regulators
whether actually in service or held in reserve.
B. When a house regulator is permanently retired from service, the
installed cost thereof shall be credited to this account.
1. House regulator.
House regulator installations:
2. Cocks.
3. Labor.
4. Locks.
5. Pipe and fittings.
6. Regulator vents.
7. Swivels and bushings.
8. Transportation.
Note: At the option of the utility, costs of house regulator
installations may be accounted for separately from the cost of house
regulators in accordance with the provisions of account 384, House
Regulator Installations. The practice of the utility, however, shall be
consistent from year to year and throughout the utility's system.
384 House regulator installations.
A. This account shall include the cost of labor and materials used
and expenses incurred in connection with the original installation of
house regulators.
B. When a house regulator installation is permanently retired from
service, the cost thereof shall be credited to this account.
1. Cocks.
2. Labor.
3. Locks.
4. Pipe and fittings.
5. Regulator vents.
6. Swivels and bushings.
7. Transportation.
Note: At the option of the utility, house regulator installations
may be accounted for as part of the cost installed of house regulators
in accordance with the provisions of account 383. House Regulators.
The practice, however, shall be consistent from year to year and
throughout the utility's system.
385 Industrial measuring and regulating station equipment.
This account shall include the cost of special and expensive
installations of measuring and regulating station equipment, located on
the distribution system, serving large industrial customers.
(See account 378 for items.)
Note A: Do not include in this account measuring and regulating
station equipment serving main line industrial customers. (See account
369.)
Note B: By-passes outside of governor pits are includible in account
376, Mains.
386 Other property on customers' premises.
This account shall include the cost, including first setting and
connecting, of equipment owned by the utility installed on customer
premises which is not includible in other accounts.
387 Other equipment.
This account shall include the cost installed of all other
distribution system equipment not provided for in the foregoing
accounts, including street lighting equipment.
1. Carbon monoxide tester and indicators.
2. Explosimeters.
3. Fire extinguisher.
4. Gas masks.
5. Lockers.
6. Portable pump.
7. Recording gauges.
8. Street lighting equipment.
9. Test meters.
10. Watchmen's clocks.
389 Land and land rights.
This account shall include the cost of land and land rights used for
utility purposes, the cost of which is not properly includible in other
land and land rights accounts. (See gas plant instruction 7.)
390 Structures and improvements.
This account shall include the cost in place of structures and
improvements used for utility purposes, the cost of which is not
properly includible in other structures and improvements accounts. (See
gas plant instruction 8.)
391 Office furniture and equipment.
This account shall include the cost of office furniture and equipment
owned by the utility and devoted to utility service, and not permanently
attached to buildings, except the cost of such furniture and equipment
which the utility elects to assign to other plant accounts on a
functional basis.
1. Book cases and shelves.
2. Desks, chairs, and desk equipment.
3. Drafting-room equipment.
4. Filing, storage and other cabinets.
5. Floor covering.
6. Library and library equipment.
7. Mechanical office equipment such as accounting machines,
typewriters, etc.
8. Safes.
9. Tables.
392 Transportation equipment.
This account shall include the cost of transportation vehicles used
for utility purposes.
1. Airplanes.
2. Automobiles.
3. Bicycles.
4. Electrical vehicles.
5. Motor trucks.
6. Motorcyles.
7. Repair cars or trucks.
8. Tractors and trailers.
9. Other transportation vehicles.
393 Stores equipment.
This account shall include the cost of equipment used for the
receiving, shipping, handling and storage of materials and supplies.
1. Chain falls.
2. Counters.
3. Cranes (portable).
4. Elevating and stacking equipment (portable).
5. Hoists.
6. Lockers.
7. Scales.
8. Shelving.
9. Storage bins.
10. Trucks, hand and power driven.
11. Wheelbarrows.
394 Tools, shop and garage equipment.
This account shall include the cost of tools, implements, and
equipment used in construction, repair work, general shops and garages
and not specifically provided for or includible in other accounts.
1. Air compressors.
2. Anvils.
3. Automobile repair shop equipment.
4. Battery charging equipment.
5. Belts, shafts and countershafts.
6. Boilers.
7. Cable pulling equipment.
8. Concrete mixers.
9. Derricks.
10. Drill presses.
11. Electric equipment.
12. Engines.
13. Forges.
14. Foundations and settings specially constructed for equipment in
this account and not expected to outlast the equipment for which
provided.
15. Furnaces.
16. Gas producers.
17. Gasoline pumps, oil pumps, and storage tanks.
18. Greasing tools and equipment.
19. Hoists.
20. Ladders.
21. Lathes.
22. Machine tools.
23. Motor driven tools.
24. Motors.
25. Pipe threading and cutting tools.
26. Pneumatic tools.
27. Pumps.
28. Riveters.
29. Smithing equipment.
30. Tool racks.
31. Vises.
32. Welding apparatus.
33. Work benches.
395 Laboratory equipment.
This account shall include the cost installed of laboratory equipment
used for general laboratory purposes and not specially provided for or
includible in other departmental or functional plant accounts.
1. Balances and scales.
2. Barometers.
3. Calorimeters-bomb, flow, recording types, etc.
4. Electric furnaces.
5. Gas burning equipment.
6. Gauges.
7. Glassware, beakers, burettes, etc.
8. Humidity testing apparatus.
9. Laboratory hoods.
10. Laboratory tables and cabinets.
11. Muffles.
12. Oil analysis apparatus.
13. Piping.
14. Specific gravity apparatus.
15. Standard bottles for meter prover testing.
16. Stills.
17. Sulphur and ammonia apparatus.
18. Tar analysis apparatus.
19. Thermometers -- indicating and recording.
20. Any other item of equipment for testing gas, fuel, flue gas,
water, residuals, etc.
396 Power operated equipment.
This account shall include the cost of power operated equipment used
in construction or repair work exclusive of equipment includible in
other accounts. Include, also, the tools and accessories acquired for
use with such equipment and the vehicle on which such equipment is
mounted.
1. Air compressors, including driving unit and vehicle.
2. Back filling machines.
3. Boring machines.
4. Bulldozers.
5. Cranes and hoists.
6. Diggers.
7. Engines.
8. Pile drivers.
9. Pipe cleaning machines.
10. Pipe coating or wrapping machines.
11. Tractors -- Crawler type.
12. Trenchers.
13. Other power operated equipment.
Note: It is intended that this account include only such large units
as are generally self-propelled or mounted on movable equipment.
397 Communication equipment.
This account shall include the cost installed of telephone, telegraph
and wireless equipment for general use in connection with the utility's
gas operations. (See account 370 for communication equipment used
wholly or predominantly in connection with operation and maintenance of
the transmission system.)
1. Carrier terminal equipment including repeaters, power supply
equipment, transmitting and receiving sets.
2. Microwave equipment, including power supply equipment,
transmitters, amplifiers, paraboloids, towers, reflectors, receiving
equipment, etc.
3. Radio equipment, fixed and mobile, including antenna, power
equipment, transmitters and receivers, and portable receiver-transmitter
units.
4. Telephone equipment including switchboards, power and testing
equipment, conductors, pole lines, etc.
398 Miscellaneous equipment.
This account shall include the cost of equipment, apparatus, etc.,
used and useful in gas operations, which is not includible in any other
account.
1. Hospital and infirmary equipment.
2. Kitchen equipment.
3. Operator's cottage furnishings.
4. Radios.
5. Recreation equipment.
6. Restaurant equipment.
7. Soda fountains.
8. Other miscellaneous equipment.
Note: Miscellaneous equipment of the nature indicated above wherever
practicable shall be assigned to the utility plant accounts on a
functional basis.
399 Other tangible property.
This account shall include the cost of tangible utility plant not
provided for elsewhere.
400 Operating revenues.
401 Operation expense.
402 Maintenance expense.
403 Depreciation expense (Major only).
403.1 Depreciation and depletion expense (Nonmajor only).
404 Amortization of limited-term gas plant (Nonmajor only).
404.1 Amortization and depletion of producing natural gas land and
land rights (Major only).
404.2 Amortization of underground storage land and land rights (Major
only).
404.3 Amortization of other limited-term gas plant (Major only).
405 Amortization of other gas plant.
406 Amortization of gas plant acquisition adjustments.
407.1 Amortization of property losses, unrecovered plant and
regulatory study costs.
407.2 Amortization of conversion expense.
408 (Reserved)
408.1 Taxes other than income taxes, utility operating income.
409 (Reserved)
409.1 Income taxes, utility operating income.
410 (Reserved)
410.1 Provision for deferred income taxes, utility operating income.
411 (Reserved)
411.1 Provision for deferred income taxes -- Credit, utility
operating income.
411.3 (Reserved)
411.4 Investment tax credit adjustments, utility operations.
411.6 Gains from disposition of utility plant.
411.7 Losses from disposition of utility plant. Total utility
operating expenses.
412 Revenues from gas plant leased to others.
413 Expenses of gas plant leased to others.
414 Other utility operating income. Net utility operating income.
415 Revenues from merchandising, jobbing and contract work.
416 Costs and expenses of merchandising, jobbing and contract work.
417 Revenues from nonutility operations.
417.1 Expenses of nonutility operations.
418 Nonoperating rental income.
418.1 Equity in earnings of subsidiary companies (Major only).
419 Interest and dividend income.
419.1 Allowance for other funds used during construction.
421 Miscellaneous nonoperating income.
421.1 Gain on disposition of property. Total other income.
421.2 Loss on disposition of property.
425 Miscellaneous amortization.
426 (Reserved)
426.1 Donations.
426.2 Life insurance.
426.3 Penalties.
426.4 Expenditures for certain civic, political and related
activites.
426.5 Other deductions. Total other income deductions. Total other
income and deductions.
408.2 Taxes other than income taxes, other income and deductions.
409.2 Income taxes, other income and deductions.
410.2 Provision for deferred income taxes, other income and
deductions.
411.2 Provision for deferred income taxes -- Credit, other income and
deductions.
411.5 Investment tax credit adjustments, nonutility operations.
420 Investment tax credits. Total taxes on other income and
deductions. Net other income and deductions.
427 Interest on long-term debt.
428 Amortization of debt discount and expense.
428.1 Amortization of loss on reacquired debt.
429 Amortization of premium on debt -- Credit.
429.1 Amortization of gain on reacquired debt -- Credit.
430 Interest on debt to associated companies.
431 Other interest expense.
432 Allowance for borrowed funds used during construction -- Credit.
Net interest charges.
434 Extraordinary income.
435 Extraordinary deductions.
409.3 Income taxes, extraordinary items. Net income
18 CFR 161.3 Income Accounts
400 Operating revenues.
There shall be shown under this caption the total amount included in
the gas operating revenue accounts provided herein.
401 Operation expense.
There shall be shown under this caption the total amount included in
the gas operation expense accounts provided herein. (See note to
operating expense instruction 3.)
402 Maintenance expense.
There shall be shown under this caption the total amount included in
the gas maintenance expense accounts provided herein.
403 Depreciation expense (Major only).
A. This account shall include the amount of depreciation expense for
all classes of depreciable gas plant in service except such depreciation
expense as is chargeable to clearing accounts or to account 416, Costs
and Expenses of Merchandising, Jobbing and Contract Work.
B. The utility shall keep such records of property and property
retirements as will reflect the service life of property which has been
retired and aid in estimating probable service life by mortality,
turnover, or other appropriate methods; and also such records as will
reflect the percentage of salvage and cost of removal for property
retired from each account, or subdivision thereof, for depreciable gas
plant.
Note A: Depreciation expense applicable to property included in
account 104, Gas Plant Leased to Others, shall be charged to account
413, Expenses of Gas Plant Leased to Others.
Note B: Depreciation expense applicable to transportation equipment,
shop equipment, tools, work equipment, power operated equipment and
other general equipment may be charged to clearing accounts as necessary
in order to obtain a proper distribution of expenses between
construction and operation.
403.1 Depreciation and depletion expense (Nonmajor only).
A. This account shall include the amount of depreciation expense for
all classes of depreciation gas plant in service except such
depreciation expense as is chargeable to clearing accounts or to account
416, Costs and Expenses of Merchandising, Jobbing and Contract Work. It
shall also include depletion and amortization expense with respect to
producing natural gas lands and land rights.
B. The utility shall keep such records of property and property
retirements as will reflect the service life of property which has been
retired, and also such records as will reflect the percentage of salvage
and cost of removal for property retired.
C. The charges to this account for amortization and depletion of
producing natural gas land and land rights shall be made in such manner
as to distribute the cost of producing natural gas land and land rights
over the period of their benefit to the utility, based upon the
exhaustion of the natural gas deposits recoverable from such land and
land rights.
Note A: Depreciation expense applicable to property included in
account 104, Gas Plant Leased to Others, shall be charged to account
413, Expenses of Gas Plant Leased to Others.
Note B: Depreciation expense applicable to transportation equipment,
shop equipment, tools, work equipment, power operated equipment, and
other general equipment may be charged to clearing accounts as
necessary, in order to obtain a proper distribution of expenses between
construction and operation.
404 Amortization of limited-term gas plant (Nonmajor only).
This account shall include amortization charges applicable to amounts
included in the gas plant accounts for limited-term franchises,
licenses, patent rights, limited-term interests in land other than land
rights held for the production of natural gas, and expenditures on
leased property where the service life of the improvements is terminable
by action of the lease. The charges to this account shall be such as to
distribute the book cost of each investment as evenly as may be over the
period of its benefit to the utility. (See account 110, Accumulated
Provision for Depreciation, Depletion, and Amortization of Gas Utility
Plant.)
404.1 Amortization and depletion of producing natural gas land and
land rights (Major only).
A. This account shall include charges for amortization and depletion
of producing natural gas land and land rights. (See account 111,
Accumulated Provision for Amortization and Depletion of Gas Utility
Plant).
B. The charges to this account shall be made in such manner as to
distribute the cost of producing natural gas land and land rights over
the period of their benefit to the utility, based upon the exhaustion of
the natural gas deposits recoverable from such land and land rights.
404.2 Amortization of underground storage land and land rights (Major
only).
A. This account shall include charges for amortization of land and
land rights of underground storage projects for natural gas. (See
account 111, Accumulated Provision for Amortization and Depletion of Gas
Utility Plant.)
B. The charges to this account shall be made in such manner as to
distribute the cost of amortizable land and land rights over the period
of their benefit to the utility, and with respect to any land or land
rights which include native gas in the storage reservoir, such amounts
shall be amortized or depleted on the basis of production of such native
gas after the volume of stored gas has been withdrawn from the
reservoir.
404.3 Amortization of other limited-term gas plant (Major only).
This account shall include amortization charges applicable to amounts
included in the gas plant accounts for limited-term franchises,
licenses, patent rights limited-term interests in land, and expenditures
on leased property where the service life of the improvements is
terminable by action of the lease. The charges to this account shall be
such as to distribute the book cost of each investment as evenly as may
be over the period of its benefit to the utility. (See account 111,
Accumulated Provision for Amortization and Depletion of Gas Utility
Plant.)
405 Amortization of other gas plant.
A. When authorized by the Commission, this account shall include
charges for amortization of intangible or other gas utility plant, which
does not have a definite or terminable life and which is not subject to
charges for depreciation expense.
B. This account shall be supported in such detail as to show the
amortization applicable to each investment being amortized, together
with the book cost of the investment and the period over which it is
being written off.
406 Amortization of gas plant acquisition adjustments.
This account shall be debited or credited, as the case may be, with
amounts includible in operating expenses, pursuant to approval or order
of the Commission, for the purpose of providing for the extinguishment
of the amount in account 114, Gas Plant Acquisition Adjustments.
407.1 Amortization of property losses, unrecovered plant and
regulatory study costs.
This account shall be charged with amounts credited to Account 182.1,
Extraordinary Property Losses, and Account 182.2 Unrecovered Plant and
Regulatory Study Costs, when the Commission has authorized the amount in
the latter account to be amortized by charges to gas operating expenses.
407.2 Amortization of conversion expenses.
This account shall be charged with amortization of amounts authorized
by the Commission to be included in Account 186, Miscellaneous Deferred
Debits, for expenses incurred in the conversion of distribution plant
from manufactured gas service to natural gas service.
408 (Reserved)
A. These accounts shall include the amounts of ad valorem, gross
revenue or gross receipts, taxes, state unemployment insurance,
franchise taxes, federal excise taxes, social security taxes, and all
other taxes assessed by federal, state, county, municipal, or other
local governmental authorities, except income taxes.
B. These accounts shall be charged in each accounting period with the
amounts of taxes which are applicable thereto, with concurrent credits
to account 236, Taxes Accrued, or account 165, Prepayments, as
appropriate. When it is not possible to determine the exact amounts of
taxes, the amounts shall be estimated and adjustments made in current
accruals as the actual tax levies become known.
C. The charges to these accounts shall be made or supported so as to
show the amount of each tax and the basis upon which each charge is
made. In the case of a utility rendering more than one utility service,
taxes of the kind includible in these accounts shall be assigned
directly to the utility department the operation of which gave rise to
the tax in so far as a specific utility department, it shall be
distributed among the utility departments or nonutility operations on an
equitable basis after appropriate study to determine such basis.
Note A: Special assessments for street and similar improvements
shall be included in the appropriate utility plant or nonutility
property account.
Note B: Taxes specifically applicable to construction shall be
included in the cost of construction.
Note C: Gasoline and other sales taxes shall be charged as far as
practicable to the same amount as the materials on which the tax is
levied.
Note D: Social security and other forms of so-called payroll taxes
shall be distributed to utility departments and to nonutility functions
on a basis related to payroll. Amounts applicable to construction shall
be charged to the appropriate plant accounts.
Note E: Interest on tax refunds or deficiencies shall not be
included in these accounts but in account 419, Interest and Dividend
Income, or 431, Other Interest Expense, as appropriate.
408.1 Taxes other than income taxes, utility operating income.
This account shall include those taxes other than income taxes which
relate to utility operating income This account shall be maintained so
as to allow ready identification of the various classes of taxes
relating to Utility Operating Income (by department), Utility Plant
Leased to Others and Other Utility Operating Income.
408.2 Taxes other than income taxes, other income and deductions.
This account shall include those taxes other than income taxes which
relate to Other Income and Deductions.
409 (Reserved)
A. These accounts shall include the amounts of local, state and
federal income taxes on income properly accruable during the period
covered by the income statement to meet the actual liability for such
taxes. Concurrent credits for the tax accruals shall be made to account
236, Taxes Accrued, and as the exact amounts of taxes become known, the
current tax accruals shall be adjusted by charges or credits to these
accounts so that these accounts as nearly as can be ascertained shall
include the actual taxes payable by the utility.
B. The accruals for income taxes shall be apportioned among utility
departments and to Other Income and Deductions so that, as nearly as
practicable, each tax shall be included in the expenses of the utility
department or Other Income and Deductions, the income from which gave
rise to the tax. The tax effects relating to Interest Charges shall be
allocated between utility and nonutility operations. The basis for this
allocation shall be the ratio of net investment in utility plant to net
investment in nonutility plant.
Note A: Taxes assumed by the utility on interest shall be charged to
account 431, Other Interest Expense.
Note B: Interest on tax refunds or deficiencies shall not be
included in these accounts but in account 419, Interest and Dividend
Income, or account 431, Other Interest Expense, as appropriate.
409.1 Income taxes, utility operating income.
This account shall include the amount of those local, state and
federal income taxes which relate to utility operating income. This
account shall be maintained so as to allow ready identification of tax
effects (both positive and negative) relating to Utility Operating
Income (by department), Utility Plant Leased to Others and Other Utility
Operating Income.
409.2 Income taxes, other income and deductions.
This account shall include the amount of those local, state and
federal income taxes (both positive and negative), which relate to Other
Income and Deductions.
409.3 Income taxes, extraordinary items.
This account shall include the amount of those local, state and
federal income taxes (both positive and negative), which relate to
Extraordinary Items.
410 (Reserved)
A. Accounts 410.1 and 410.2 shall be debited, and Accumulated
Deferred Income Taxes shall be credited with amounts equal to any
current deferrals of taxes on income or any allocations of deferred
taxes originating in prior periods, as provided by the texts of accounts
190, 281, 282 and 283. There shall not be netted against entries
required to be made to these accounts any credit amounts appropriately
includible in accounts 411.1 or 411.2.
B. Accounts 411.1 and 411.2 shall be credited, and Accumulated
Deferred Income Taxes shall be debited with amounts equal to any
allocations of deferred taxes originating in prior periods or any
current deferrals of taxes on income, as provided by the texts of
accounts 190, 281, 282, and 283. There shall not be netted against
entries required to be made to these accounts any debit amounts
appropriately includible in accounts 410.1 or 410.2.
410.1 Provision for deferred income taxes, utility operating income.
This account shall include the amounts of those deferrals of taxes
and allocations of deferred taxes which relate to Utility Operating
Income (by department).
410.2 Provision for deferred income taxes, other income and
deductions.
This account shall include the amounts of those deferrals of taxes
and allocations of deferred taxes which relate to other income and
deductions.
411 (Reserved)
411.1 Provision for deferred income taxes -- Credit, utility
operating income.
This account shall include the amounts of those allocations of
deferred taxes and deferrals of taxes, credit, which relate to Utility
Operating Income (by department).
411.2 Provision for deferred income taxes -- Credit, other income and
deductions.
This account shall include the amounts of those allocations of
deferred taxes and deferrals of taxes, credit, which relate to Other
Income and Deductions.
411.3 (Reserved)
A. Account 411.4 shall be debited with the amounts of investment tax
credits related to gas utility property that are credited to account
255, Accumulated Deferred Investment Tax Credits, by companies which do
not apply the entire amount of the benefits of the investment credit as
a reduction of the overall income tax expense in the year in which such
credit is realized (see account 255).
B. Account 411.4 shall be credited with the amounts debited to
account 255 for proportionate amounts of tax credit deferrals allocated
over the average useful life of gas utility property to which the tax
credits relate or such lesser period of time as may be adopted and
consistently followed by the company.
C. Account 411.5 shall also be debited and credited as directed in
paragraphs A and B, for investment tax credits related to non- utility
property.
411.4 Investment tax credit adjustments, utility operations.
This account shall include the amount of those investment tax credit
adjustments related to property used in Utility Operations (by
department).
411.5 Investment tax credit adjustments, nonutility operations.
This account shall include the amount of those investment tax credit
adjustments related to property used in Nonutility Operations.
411.6 Gains from disposition of utility plant.
This account shall include, as approved by the Commission, amounts
relating to gains from the disposition of future use utility plant
including amounts which were previously recorded in and transferred from
account 105, Gas Plant Held for Future Use and account 105.1, Production
Properties Held for Future Use, under the provisions of paragraphs B, C,
and D thereof. Income taxes relating to gains recorded in this account
shall be recorded in account 409.1, Income Taxes, Utility Operating
Income.
411.7 Losses from disposition of utility plant.
This account shall include, as approved by the Commission, amounts
relating to losses from the disposition of future use utility plant
including amounts which were previously recorded in and transferred from
account 105, Gas Plant Held for Future Use and account 105.1, Production
Properties Held for Future Use, under the provisions of paragraphs B, C,
and D thereof. Income taxes relating to losses recorded in this account
shall be recorded in account 409.1, Income Taxes, Utility Operating
Income.
412 Revenues from gas plant leased to others.
413 Expenses of gas plant leased to others.
A. These accounts shall include, respectively, revenues from gas
property constituting a distinct operating unit or system leased by the
utility to others, and which property is properly includible in account
104, Gas Plant Leased to Others, and the expenses attributable to such
property.
B. The detail of expenses shall be kept or supported so as to show
separately the following:
Operation.
Maintenance.
Depreciation.
Amortization.
Note: Related taxes shall be recorded in account 408.1, Taxes Other
Than Income Taxes, Utility Operating Income, or account 409.1, Income
Taxes, Utility Operating Income, as appropriate.
414 Other utility operating income.
A. This account shall include the revenues received and expenses
incurred in connection with the operations of utility plant, the book
cost of which is included in account 118, Other Utility Plant.
B. The expenses shall include every element of cost incurred in such
operations, including depreciation, rents, and insurance.
Note: Related taxes shall be recorded in account 408.1, Taxes Other
Than Income Taxes, Utility Operating Income, or account 409.1, Income
Taxes, Utility Operating Income, as appropriate.
415 Revenues from merchandising, jobbing and contract work.
416 Costs and expenses of merchandising, jobbing and contract work.
A. These accounts shall include, respectively, all revenues derived
from the sale of merchandise and jobbing or contract work, including any
profit or commission accruing to the utility on jobbing work performed
by it as agent under contracts whereby it does jobbing work for another
for a stipulated profit or commission, and all expenses incurred in such
activities. Interest related income from installment sales shall be
recorded in Account 419, Interest and Dividend Income.
B. Records in support of these accounts shall be so kept as to permit
ready summarization of revenues, costs and expenses by such major items
as are feasible.
Note A: The classification of revenues, costs and expenses of
merchandising, jobbing and contract work as nonoperating, and thus
inclusion in this account, is for accounting purposes. It does not
preclude consideration for justification to the contrary for ratemaking
or other purpose.
Note B: Related taxes shall be recorded in account 408.2, Taxes
Other Than Income Taxes, Other Income and Deductions, or account 409.2,
Income Taxes, Other Income and Deductions, as appropriate.
Account 415:
1. Revenues from sale of merchandise and from jobbing and contract
work.
2. Discounts and allowances made in settlement of bills for
merchandise and jobbing work.
Account 416:
Labor:
1. Canvassing and demonstrating appliances in homes and other places
for the purpose of selling appliances.
2. Demonstrating and selling activities in sales rooms.
3. Installing appliances on customer premises where such work is done
only for purchasers of appliances from the utility.
4. Installing piping or other property work on a jobbing or contract
basis.
5. Preparing advertising materials for appliance sales purposes.
6. Receiving and handling customer orders for merchandise or for
jobbing services.
7. Cleaning and tidying sales rooms.
8. Maintaining display counters and other equipment used in
merchandising.
9. Arranging merchandise in sales rooms and decorating display
windows.
10. Reconditioning repossessed appliances.
11. Bookkeeping and other clerical work in connection with
merchandise and jobbing activities.
12. Supervising merchandise and jobbing operations.
Materials and expenses:
13. Advertising in newspapers, periodicals, radio, television, etc.
14. Cost of merchandise sold and of materials used in jobbing work.
15. Stores expenses on merchandise and jobbing stocks.
16. Fees and expenses of advertising and commercial artists'
agencies.
17. Printing booklets, dodgers, and other advertising data.
18. Premiums given as inducement to buy appliances.
19. Light, heat, and power.
20. Depreciation on equipment used primarily for merchandise and
jobbing operations.
21. Rent of sales rooms or of equipment.
22. Transportation expense in delivery and pick-up of appliances by
utility's facilities or by others.
23. Stationery and office supplies and expenses.
24. Losses from uncollectible merchandise and jobbing accounts.
417 Revenues from nonutility operations.
417.1 Expenses of nonutility operations.
A. These accounts shall include revenues and expenses applicable to
operations which are nonutility in character but nevertheless constitute
a distinct operating activity of the enterprise as a whole, such as the
operation of an ice department where applicable statutes do not define
such operation as a utility, or the operation of a serv- icing
organization for furnishing supervision, management, engineering, and
similar services to others.
B. The expenses shall include all elements of costs incurred in such
operations, and the accounts shall be maintained so as to permit ready
summarization as follows:
Operation.
Maintenance.
Rents.
Depreciation.
Amortization.
Note B: Related taxes shall be recorded in account 408.2, Taxes
Other Than Income Taxes, Other Income and Deductions, or account 409.2,
Income Taxes, Other Income and Deductions, as appropriate.
418 Nonoperating rental income.
A. This account shall include all rent revenues and related expenses
of land, buildings, or other property included in account 121,
Nonutility Property, which is not used in operations covered by accounts
417 or 417.1.
B. The expenses shall include all elements of costs incurred in the
ownership and rental of property and the accounts shall be maintained so
as to permit ready summarization as follows:
Operation.
Maintenance.
Rents.
Depreciation.
Amortization.
Note: Related taxes shall be recorded in account 408.2, Taxes Other
Than Income Taxes, Other Income and Deductions, or account 409.2, Income
Taxes, Other Income and Deductions, as appropriate.
418.1 Equity in earnings of subsidiary companies (Major only).
This account shall include the utility's equity in the earnings or
losses of subsidiary companies for the year.
419 Interest and dividend income.
A. This account shall include interest revenues on securities, loans,
notes, advances, special deposits, tax refunds and all other
interest-bearing assets, and dividends on stocks of other companies,
whether the securities on which the interest and dividends are received
are carried as investments or included in sinking or other special fund
accounts.
B. This account may include the pro rata amount necessary to
extinguish (during the interval between the date of acquisition and the
date of maturity) the difference between the cost to the utility and the
face value of interest-bearing securities. Amounts thus credited or
charged shall be concurrently included in the accounts in which the
securities are carried.
C. Where significant in amount expenses, excluding operating taxes
and income taxes, applicable to security investments and to interest and
dividend revenues thereon shall be charged hereto.
Note A: Related taxes shall be recorded in account 408.2, Taxes
Other Than Income Taxes, Other Income and Deductions, or account 409.2,
Income Taxes, Other Income and Deductions, as appropriate.
Note B: Interest accrued, the payment of which is not reasonably
assured, dividends receivable which have not been declared or
guaranteed, and interest or dividends upon reacquired securities issued
or assumed by the utility shall not be credited to this account.
419.1 Allowance for other funds used during construction.
This account shall include concurrent credits for allowance for other
funds used during construction, not to exceed amounts computed in
accordance with the formula prescribed in Gas Plant Instruction 3(17).
420 Investment tax credits.
This account shall be credited as follows with investment tax credit
amounts not passed on to customers:
(a) By amounts equal to debits to accounts 411.4, Investment Tax
Credit Adjustments, Utility Operations, and 411.5, Investment Tax Credit
Adjustments, Nonutility Operations, for investment tax credits used in
calculating income taxes for the year when the company's accounting
provides for nondeferral of all or a portion of such credits; and,
(b) By amounts equal to debits to account 255, Accumulated Deferred
Investment Tax Credits, for proportionate amounts of tax credit
deferrals allocated over the average useful life of the property to
which the tax credits relate, or such lesser period of time as may be
adopted and consistently used by the company.
421 Miscellaneous nonoperating income.
This account shall include all revenue and expense items except taxes
properly includible in the income account and not provided for
elsewhere. Related taxes shall be recorded in account 408.2, Taxes
Other Than Income Taxes, Other Income and Deductions, or account 409.2,
Income Taxes, Other Income and Deductions, as appropriate.
1. Profit on sale of timber. (See gas plant instruction 7C.)
2. Profits from operations of others realized by the utility under
contracts.
3. Gains on disposition of investments. Also gains on reacquisition
and resale or retirement of utilities debt securities when the gain is
not amortized and used by a jurisdictional regulatory agency to reduce
embedded debt cost in establishing rates. See General Instruction 17.
421.1 Gain on disposition of property.
This account shall be credited with the gain on the sale, conveyance,
exchange or transfer of utility or other property to another. Amounts
relating to gains on land and land rights held for future use recorded
in accounts 105, Gas Plant Held for Future Use and 105.1, Production
Properties Held for Future Use (Major only), will be accounted for as
prescribed in paragraphs B, C, and D thereof. (See gas plant
instructions 5F, 7E, and 10E.) Income taxes on gains recorded in this
account shall be recorded in account 409.2, Income Taxes, Other Income
and Deductions.
421.2 Loss on disposition of property.
This account shall be charged with the loss on the sale, conveyance,
exchange or transfer of utility or other property to another. Amounts
relating to losses on land and land rights held for future use recorded
in accounts 105, Gas Plant Held for Future Use and 105.1, Production
Properties Held for Future Use (Major only), will be accounted for as
prescribed in paragraphs B, C, and D thereof. (See gas plant
instructions 5F, 7E, and 10E.) The reduction in income taxes relating to
losses recorded in this account shall be recorded in account 409.2,
Income Taxes, Other Income and Deductions.
425 Miscellaneous amortization.
This account shall include amortization charges not includible in
other accounts which are properly deductible in determining the income
of the utility before interest charges. Charges includible herein, if
significant in amount, must be in accordance with an orderly and
systematic amortization program.
1. Amortization of utility plant acquisition adjustments, or of
intangibles included in utility plant in service when not authorized to
be included in utility operating expenses by the Commission.
2. Other miscellaneous amortization charges allowed to be included in
this account by the Commission.
These accounts shall include miscellaneous expense items which are
nonoperating in nature but which are properly deductible before
determining total income before interest charges.
Note: The classification of expenses as nonoperating and their
inclusion in these accounts is for accounting purposes. It does not
preclude Commission consideration of proof to the contrary for
ratemaking or other purposes.
426.1 Donations.
This account shall include all payments or donations for charitable,
social or community welfare purposes.
426.2 Life insurance.
This account shall include all payments for life insurance of
officers and employees where company is beneficiary (net premiums less
increase in cash surrender value of policies).
426.3 Penalties.
This account shall include payments by the company for penalties or
fines for violation of any regulatory statutes by the company or its
officials.
426.4 Expenditures for certain civic, political and related
activities.
This account shall include expenditures for the purpose of
influencing public opinion with respect to the election or appointment
of public officials, referenda, legislation, or ordinances (either with
respect to the possible adoption of new referenda, legislation or
ordinances or repeal or modification of existing referenda, legislation
or ordinances) or approval, modification, or revocation of franchises;
or for the purpose of influencing the decisions of public officials, but
shall not include such expenditures which are directly related to
appearances before regulatory or other governmental bodies in connection
with the reporting utility's existing or proposed operations.
426.5 Other deductions.
This account shall include other miscellaneous expenses which are
nonoperating in nature, but which are properly deductible before
determining total income before interest charges.
1. Loss relating to investments in securities written-off or
written-down.
2. Loss on sale of investments.
3. Loss on reacquisition, resale or retirement of utility's debt
securities, when the loss is not amortized and used by a jurisdictional
regulatory agency to increase embedded debt cost in establishing rates.
See General Instruction 17.
4. Preliminary survey and investigation expenses related to abandoned
projects, when not written-off to the appropriate operating expense
account.
5. Costs of preliminary abandonment costs recorded in accounts 182.1,
Extraordinary Property Losses, and 182.2, Unrecovered Plant and
Regulatory Study Costs, not allowed to be amortized to account 407.1,
Amortization of Property Losses, Unrecovered Plant and Regulatory Study
Costs.
427 Interest on long-term debt.
A. This account shall include the amount of interest on outstanding
long-term debt issued or assumed by the utility, the liability for which
is included in account 221, Bonds, or account 224, Other Long-Term Debt.
B. This account shall be so kept or supported as to show the interest
accruals on each class and series of long-term debt.
Note: This account shall not include interest on nominally issued or
nominally outstanding long-term debt, including securities assumed.
428 Amortization of debt discount and expense.
A. This account shall include the amortization of unamortized debt
discount and expense on outstanding long-term debt. Amounts charged to
this account shall be credited concurrently to accounts 181, Unamortized
Debt Expense, and 226, Unamortized Discount on Long-Term Debt -- Debit.
B. This account shall be so kept or supported as to show the debt
discount and expense on each class and series of long-term debt.
428.1 Amortization of loss on reacquired debt.
A. This account shall include the amortization of the losses on
reacquisition of debt. Amounts charged to this account shall be
credited concurrently to account 189, Unamortized Loss on Reacquired
Debt.
B. This account shall be maintained so as to allow ready
identification of the loss amortized applicable to each class and series
of long-term debt reacquired. See General Instruction 17.
429 Amortization of premium on debt -- Credit.
A. This account shall include the amortization of unamortized net
premium on outstanding long-term debt. Amounts credited to this account
shall be charged concurrently to account 225, Unamortized Premium on
Long-Term Debt.
B. This account shall be so kept or supported as to show the premium
on each class and series of long-term debt.
429.1 Amortization of gain on reacquired debt -- Credit.
A. This account shall include the amortization of the gains realized
from reacquisition of debt. Amounts credited to this account shall be
charged concurrently to account 257, Unamortized Gain on Reacquired
Debt.
B. This account shall be maintained so as to allow ready
identification of the gains amortized applicable to each class and
series of long-term debt reacquired. See General Instruction 17.
430 Interest on debt to associated companies.
A. This account shall include interest accrued on amounts included in
account 223, Advances from Associated Companies, and on all other
obligations to associated companies.
B. The records supporting the entries to this account shall be so
kept as to show to whom the interest is to be paid, the period covered
by the accrual, the rate of interest and the principal amount of the
advances or other obligations on which the interest is accrued.
431 Other interest expense.
This account shall include all interest charges not provided for
elsewhere.
1. Interest on notes payable on demand or maturing one year or less
from date and on open accounts, except notes and accounts with
associated companies.
2. Interest on customers' deposits.
3. Interest on claims and judgments, tax assessments, and assessments
for public improvements past due.
4. Income and other taxes levied upon bondholders of utility and
assumed by it.
432 Allowance for borrowed funds used during construction -- Credit.
This account shall include concurrent credits for allowance for
borrowed funds used during construction, not to exceed amounts computed
in accordance with the formula prescribed in Gas Plant Instruction
3(17).
434 Extraordinary income.
This account shall be credited with gains of unusual nature and
infrequent occurrence, which would significantly distort the current
year's income computed before Extraordinary Items, if reported other
than as extraordinary items. Income tax relating to the amounts
recorded in this account shall be recorded in account 409.3, Income
Taxes, Extraordinary Items. (See General Instruction 7.)
435 Extraordinary deductions.
This account shall be debited with losses of unusual nature and
infrequent occurrence, which would significantly distort the current
year's income computed before Extraordinary Items, if reported other
than as extraordinary items. Income tax relating to the amounts
recorded in this account shall be recorded in account 409.3, Income
Taxes, Extraordinary Items. (See General Instruction 7.)
Retained Earnings Chart of Accounts
433 Balance transferred from income.
436 Appropriations of retained earnings.
437 Dividends declared -- preferred stock.
438 Dividends declared -- common stock.
439 Adjustments to retained earnings.
18 CFR 161.3 Retained Earnings Accounts
433 Balance transferred from income.
This account shall include the net credit or debit transferred from
income for the year.
436 Appropriations of retained earnings.
This account shall include appropriations of retained earnings.
1. Appropriations required under terms of mortgages, orders of
courts, contracts, or other agreements.
2. Appropriations required by action of regulatory authorities.
3. Other appropriations made at option of utility for specific
purposes.
437 Dividends declared -- preferred stock.
A. This account shall include amounts declared payable out of
retained earnings as dividends on actually outstanding preferred or
prior lien capital stock issued by the utility.
B. Dividends shall be segregated for each class and series of
preferred stock as to those payable in cash, stock and other forms. If
not payable in cash, the medium of payment shall be described with
sufficient detail to identify it.
438 Dividends declared -- common stock.
A. This account shall include amounts declared payable out of
retained earnings as dividends on actually outstanding common capital
stock issued by the utility.
B. Dividends shall be segregated for each class of common stock as to
those payable in cash, stock and other forms. If not payable in cash,
the medium of payment shall be described with sufficient detail to
identify it.
439 Adjustments to retained earnings.
A. This account shall, with prior Commission approval, include
significant nonrecurring transactions accounted for as prior period
adjustments, as follows:
(1) Correction of an error in the financial statements of a prior
year.
(2) Adjustments that result from realization of income tax benefits
of pre-acquisition operating loss carryforwards of purchased
subsidiaries.
All other items of profit and loss recognized during a year shall be
included in the determination of net income for that year.
B. Adjustments, charges, or credits due to losses on reacquisition,
resale or retirement of the company's own capital stock shall be
included in this account. (See account 210, Gain on Resale or
Cancellation of Reacquired Capital Stock, for the treatment of gains.)
Operating Revenue Chart of Accounts
480 Residential sales.
481 Commercial and industrial sales.
482 Other sales to public authorities (Major only).
483 Sales for resale.
484 Interdepartmental sales.
485 Intracompany transfers.
487 Forfeited discounts.
488 Miscellaneous service revenues.
489 Revenues from transportation of gas of others.
490 Sales of products extracted from natural gas.
491 Revenues from natural gas processed by others.
492 Incidental gasoline and oil sales.
493 Rent from gas property.
494 Interdepartmental rents.
495 Other gas revenues.
496 Provision for rate refunds.
18 CFR 161.3 Operating Revenue Accounts
480 Residential sales.
A. This account shall include the net billing for gas supplied for
residential or domestic purposes.
B. Records shall be maintained so that the quantity of gas sold and
the revenues received under each rate schedule shall be readily
available.
Note: When gas supplied through a single meter is used for both
residential and commercial purposes, the total revenue shall be included
in this account or account 481, Commercial and Industrial Sales,
according to the rate schedule which is applied. If the same rate
schedules are applicable to both residential and commercial service,
classification shall be according to principal use.
481 Commercial and industrial sales.
A. This account shall include the net billing for gas supplied to
commercial and industrial customers.
B. Records shall be maintained so that the quantity of gas sold and
revenue received under each rate schedule shall be readily available.
C. (Major companies) Records shall be maintained so as to show
separately the revenues from commercial and industrial customers, as
follows:
Large commercial and industrial sales (wherein shall be included the
revenues from customers which use large volumes of gas, generally in
excess of 200,000 Mcf per year or approximately 800 Mcf per day of
normal requirements. Reasonable deviations are permissible in order that
transfers of customers between the large and small classifications may
be minimized).
Small commercial and industrial sales (wherein shall be included the
revenues from customers which use volumes of gas generally less than
200,000 Mcf per year or less than approximately 800 Mcf per day of
normal requirements).
Note: When gas supplied through a single meter is used for both
commercial and residential purposes, the total revenue shall be included
in this account or in account 480, Residential Sales, according to the
rate schedule which is applied. If the same rate schedules are
applicable to both residential and commercial service, classification
shall be according to principal use.
482 Other sales to public authorities (Major only).
A. This account shall include the net billing for gas supplied to
municipalities or divisions or agencies of Federal or State Governments,
under special contracts or agreements or service classifications,
applicable only to public authorities, for general governmental and
institutional purposes, except any revenues under rate schedules the
revenues from which are includible in account 481 or 483, and except any
revenues from gas used for purposes such as powerplant fuel for publicly
owned electric systems, manufacturing processes of arsenals, etc., and
other major uses of gas which appropriately may be classified in account
481, Commercial and Industrial Sales.
B. Records shall be maintained so that the quantity of gas sold and
the revenue received from each customer and from each major special
contract shall be readily available.
483 Sales for resale.
A. This account shall include the net billing for gas supplied to
other gas utilities or to public authorities for resale purposes.
B. Records shall be maintained so that there shall be readily
available the revenues for each customer under each revenue schedule and
the billing determinants, as applicable, i.e., volume of gas (actual and
billing), contract demand, maximum actual demand, billing demand, and
Btu adjustment factor.
Note: Revenues from gas supplied to other public utilities for use
by them and not for distribution, shall be included in account 481,
Commercial and Industrial Sales, unless supplied under the same contract
as and not readily separable from revenues includible in this account.
484 Interdepartmental sales.
A. This account shall include amounts charged by the gas department
at tariff or other specified rates for gas supplied by it to other
utility departments.
B. Records shall be maintained so that the quantity of gas supplied
each other department and the charge made therefor shall be readily
available.
485 Intracompany transfers
A. This account shall include, for informational purposes only, the
amount recorded for gas supplied by the production division when the
price is not determined by a cost-of-service rate proceeding.
B. Records shall be maintained so that the quality of gas transferred
shall be readily available.
487 Forfeited discounts.
This account shall include the amount of discounts forfeited or
additional charges imposed because of the failure of customers to pay
gas bills on or before a specified date.
488 Miscellaneous service revenues.
This account shall include revenues from all miscellaneous services
and charges billed to customers which are not specifically provided for
in other accounts.
1. Fees for changing, connecting, or disconnecting service.
2. Profit on maintenance of appliances, piping, gas firing, and other
utilization facilities, or other installations on customers' premises.
3. Net credit or debit (cost less net salvage and less payment from
customers) on closing work orders for plant installed for temporary
service of less than 1 year. (For Major companies, see account 185,
Temporary Facilities.)
4. Recovery of expenses in connection with gas diversion cases.
(Billing for the gas consumed shall be included in the appropriate gas
revenue account.)
5. Services performed for other gas companies for testing and
adjusting meters, changing charts, etc.
489 Revenues from transportation of gas of others.
This account shall include revenues from transporting gas for other
companies through the production, transmission, and distribution lines,
or compressor stations of the utility.
490 Sales of products extracted from natural gas.
A. This account shall include revenues from sales of gasoline,
butane, propane, and other products extracted from natural gas, net of
allowances, adjustments, and discounts, including sales of similar
products purchased for resale.
B. Records shall be maintained so that the quantity, sales price, and
revenues for each type of product sold to each purchaser shall be
readily available.
491 Revenues from natural gas processed by others.
A. This account shall include revenues from royalties and permits, or
other bases of settlement, for permission granted others to remove
products from natural gas of the utility.
B. The records supporting this account shall be so maintained that
full information concerning determination of the revenues will be
readily available concerning each processor of gas of the utility,
including as applicable (a) the Mcf of gas and approximate average Btu
content thereof per cubic foot delivered to such other party for
processing, (b) the Mcf of gas and approximate average Btu content
thereof per cubic foot of gas received back from the processor, (c) the
field, general production area, or other source of the gas processed,
(d) Mcf of gas used for processing fuel, etc., which is chargeable to
the utility, (e) total gallons of each product recovered by the
processor and the utility's share thereof, (f) the revenues accruing to
the utility, and (g) the basis of determination of the revenues accruing
to the utility. Such records shall be maintained even though no
revenues are derived from the processor.
492 Incidental gasoline and oil sales.
This account shall include revenues from natural gas gasoline
produced direct from gas wells or recovered from drips or obtained in
connection with purification or dehydration processes, and revenues from
oil obtained from wells which produce oil and gas, the investment in
which is carried in accounts 330, Producing Gas Wells -- Well
Construction, and 331, Producing Gas Wells -- Well Equipment.
493 Rent from gas property.
A. This account shall include rents received for the use by others of
land, buildings, and other property devoted to gas operations by the
utility.
B. When property owned by the utility is operated jointly with others
under a definite arrangement for sharing the actual expenses among the
parties to the arrangement, any amount received by the utility for
interest or return or in reimbursement of taxes or depreciation on the
property shall be credited to this account.
Note: Do not include rent from property constituting an operating
unit or system in this account. (See account 412, Revenues From Gas
Plant Leased to Others.)
494 Interdepartmental rents.
This account shall include credits for rental charges made against
other departments of the utility. In the case of property operated
under a definite arrangement to allocate actual costs among the
departments using the property, any allowance to the gas department for
interest or return and depreciation and taxes shall be credited to this
account.
495 Other gas revenues.
This account shall include revenues derived from gas operations not
includible in any of the foregoing accounts.
1. Commission on sale or distribution of gas of others when sold
under rates filed by such others.
2. Compensation for minor or incidental services provided for others
such as customer billing, engineering, etc.
3. Profit or loss on sale of material and supplies not ordinarily
purchased for resale and not handled through merchandising and jobbing
accounts.
4. Sales of steam, water, or electricity, including sales or
transfers to other departments of the utility.
5. Service charges for storing gas of others.
6. Miscellaneous royalties received.
7. Revenues from dehydration and other processing of gas of others,
except products extraction where products are received as compensation
and sales of such are includible in account 490, Sales of Products
Extracted From Natural Gas, and except compression of gas of others,
revenues from which are includible in account 489, Revenues from
Transportation of Gas of Others.
8. Include (Major companies) in a separate subaccount revenues in
payment for rights and/or benefits received from others which are
realized through research, development, and demonstration ventures. In
the event the amounts received are so large as to distort revenues for
the year in which received (5 percent of net income before application
of the benefit) the amounts shall be credited to Account 253, Other
Deferred Credits, and amortized by credits to this account over a period
not to exceed 5 years.
496 Provision for rate refunds.
A. This account shall be charged with provisions for the estimated
pretax effects on net income of the portions of amounts being collected
subject to refund which are estimated to be required to be refunded.
Such provisions shall be credited to Account 229, Accumulated Provision
for Rate Refunds.
B. This account shall also be charged with amounts refunded when such
amounts had not been previously accrued.
C. Income tax effects relating to the amounts recorded in this
account shall be recorded in account 410.1, Provision for Deferred
Income Taxes, Utility Operating Income, or account 411.1, Provision for
Deferred Income Taxes -- Credit, Utility Operating Income, as
appropriate.
Operation and Maintenance Expense Chart of Accounts
700 Operation supervision and engineering (Major only).
701 Operation labor (Major only).
702 Boiler fuel (Major only).
703 Miscellaneous steam expenses (Major only).
704 Steam transferred -- Credit (Major only).
705 Maintenance supervision and engineering (Major only).
706 Maintenance of structures and improvements (Major only).
707 Maintenance of boiler plant equipment (Major only).
708 Maintenance of other steam production plant (Major only).
710 Operation supervision and engineering.
711 Steam expenses (Major only).
712 Other power expenses (Major only).
713 Coke oven expenses (Major only).
714 Producer gas expenses (Major only).
715 Water gas generating expenses (Major only).
716 Oil gas generating expenses (Major only).
717 Liquefied petroleum gas expenses (Major only).
718 Other process production expenses (Major only).
719 Fuel under coke ovens (Major only).
720 Producer gas fuel (Major only).
721 Water gas generator fuel (Major only).
722 Fuel for oil gas (Major only).
723 Fuel for liquefied petroleum gas process (Major only).
724 Other gas fuels (Major only).
724.1 Fuel (Nonmajor only).
725 Coal carbonized in coke ovens (Major only).
726 Oil for water gas (Major only).
727 Oil for oil gas (Major only).
728 Liquefied petroleum gas (Major only).
729 Raw materials for other gas processes (Major only).
729.1 Raw materials (Nonmajor only).
730 Residuals expenses (Major only).
731 Residuals produced -- Credit.
732 Purification expenses (Major only).
733 Gas mixing expenses (Major only).
734 Duplicate charges -- Credit (Major only).
735 Miscellaneous production expenses (Major only).
736 Rents.
737 Operation supplies and expenses (Nonmajor only).
740 Maintenance supervision and engineering (Major only).
741 Maintenance of structures and improvements (Major only).
742 Maintenance of production equipment (Major only).
743 Maintenance of production plant (Nonmajor only)
750 Operation supervision and engineering.
751 Production maps and records (Major only).
752 Gas wells expenses (Major only).
753 Field lines expenses (Major only).
754 Field compressor station expenses (Major only).
755 Field compressor station fuel and power.
756 Field measuring and regulating station expenses (Major only).
757 Purification expenses (Major only).
758 Gas well royalties.
759 Other expenses.
760 Rents.
761 Maintenance supervision and engineering (Major only).
762 Maintenance of structures and improvements (Major only).
763 Maintenance of producing gas wells.
764 Maintenance of field lines.
765 Maintenance of field compressor station equipment (Major only).
766 Maintenance of field measuring and regulating station equipment
(Major only).
767 Maintenance of purification equipment (Major only).
768 Maintenance of drilling and cleaning equipment (Major only).
769 Maintenance of other equipment (Major only).
769.1 Maintenance of other plant (Nonmajor only).
770 Operation supervision and engineering (Major only).
771 Operation labor (Major only).
772 Gas shrinkage (Major only).
773 Fuel (Major only).
774 Power (Major only).
775 Materials (Major only).
776 Operation supplies and expenses.
777 Gas processed by others (Major only).
778 Royalties on products extracted (Major only).
779 Marketing expenses (Major only).
780 Products purchased for resale (Major only).
781 Variation in products inventory (Major only).
782 Extracted products used by the utility -- Credit (Major only).
783 Rents (Major only).
784 Maintenance supervision and engineering (Major only).
785 Maintenance of structures and improvements (Major only).
786 Maintenance of extraction and refining equipment (Major only).
787 Maintenance of pipe lines (Major only).
788 Maintenance of extracted products storage equipment (Major only).
789 Maintenance of compressor equipment (Major only).
790 Maintenance of gas measuring and regulating equipment (Major
only).
791 Maintenance of other equipment (Major only).
792 Maintenance of products extraction plant (Nonmajor only).
795 Delay rentals.
796 Nonproductive well drilling.
797 Abandoned leases.
798 Other exploration.
799 Natural gas purchases (Nonmajor only).
800 Natural gas well head purchases (Major only).
800.1 Natural gas well head purchases, intracompany transfers.
801 Natural gas field line purchases (Major only).
802 Natural gas gasoline plant outlet purchases (Major only).
803 Natural gas transmission line purchases (Major only).
804 Natural gas city gate purchases (Major only).
804.1 Liquefied natural gas purchases (Major only).
805 Other gas purchases.
805.1 Purchased gas cost adjustments.
806 Exchange gas (Major only).
807 Purchased gas expenses.
808.1 Gas withdrawn from storage -- Debt.
808.2 Gas delivered to storage -- Credit.
809.1 Withdrawals of liquefied natural gas held for processing --
Debt (Major only).
809.2 Deliveries of natural gas for processing -- Credit (Major
only).
810 Gas used for compressor station fuel -- Credit (Major only).
811 Gas used for products extraction -- Credit.
812 Gas used for other utility operations -- Credit.
812.1 Gas used in utility operations -- credit (Nonmajor only).
813 Other gas supply expenses.
814 Operation supervision and engineering.
815 Maps and records (Major only).
816 Wells expenses (Major only).
817 Lines expenses (Major only).
818 Compressor station expenses (Major only).
819 Compressor station fuel and power (Major only).
820 Measuring and regulating station expenses (Major only).
821 Purification expenses (Major only).
822 Exploration and development (Major only).
823 Gas losses (Major only).
824 Other expenses.
825 Storage well royalties.
826 Rents.
827 Operation supplies and expenses (Nonmajor only).
830 Maintenance supervision and engineering (Major only).
831 Maintenance of structures and improvements (Major only).
832 Maintenance of reservoirs and wells.
833 Maintenance of lines (Major only).
834 Maintenance of compressor station equipment (Major only).
835 Maintenance of measuring and regulating station equipment (Major
only).
836 Maintenance of purification equipment (Major only).
837 Maintenance of other equipment (Major only).
838 Maintenance of other underground storage plant (Nonmajor only).
839 Maintenance of local storage plant (Nonmajor only).
840 Operation supervision and engineering (Major only).
841 Operation labor and expenses (Major only).
842 Rents (Major only).
842.1 Fuel (Major only).
842.2 Power (Major only).
842.3 Gas losses (Major only).
843.1 Maintenance supervision and engineering (Major only).
843.2 Maintenance of structures and improvements (Major only).
843.3 Maintenance of gas holders (Major only).
843.4 Maintenance of purification equipment (Major only).
843.5 Maintenance of liquefaction equipment (Major only).
843.6 Maintenance of vaporizing equipment (Major only).
843.7 Maintenance of compressor equipment (Major only).
843.8 Maintenance of measuring and regulating equipment (Major only).
843.9 Maintenance of other equipment (Major only).
844.1 Operation supervision and engineering (Major only).
844.2 LNG processing terminal labor and expenses (Major only).
844.3 Liquefaction processing labor and expenses (Major only).
844.4 LNG transportation labor and expenses (Major only).
844.5 Measuring and regulating labor and expenses (Major only).
844.6 Compressor station labor and expenses (Major only).
844.7 Communication system expenses (Major only).
844.8 System control and load dispatching (Major only).
845.1 Fuel (Major only).
845.2 Power (Major only).
845.3 Rents (Major only).
845.4 Demurrage charges (Major only).
845.5 Wharfage receipts -- credit (Major only).
845.6 Processing liquefied or vaporized gas by others (Major only).
846.1 Gas losses (Major only).
846.2 Other expenses (Major only).
847.1 Maintenance supervision and engineering (Major only).
847.2 Maintenance of structures and improvements (Major only).
847.3 Maintenance of LNG processing terminal equipment (Major only).
847.4 Maintenance of LNG transportation equipment (Major only).
847.5 Maintenance of measuring and regulating equipment (Major only).
847.6 Maintenance of compressor station equipment (Major only).
847.7 Maintenance of communication equipment (Major only).
847.8 Maintenance of other equipment (Major only).
850 Operation supervision and engineering.
851 System control and load dispatching (Major only).
852 Communication system expenses (Major only).
853 Compressor station labor and expenses (Major only).
853.1 Compressor station fuel and power (Nonmajor only).
854 Gas for compressor station fuel (Major only).
855 Other fuel and power for compressor stations (Major only).
856 Mains expenses (Major only).
857 Measuring and regulating station expenses (Major only).
857.1 Operation supplies and expenses (Nonmajor only).
858 Transmission and compression of gas by others.
859 Other expenses (Major only).
860 Rents.
861 Maintenance supervision and engineering (Major only).
862 Maintenance of structures and improvements (Major only).
863 Maintenance of mains.
864 Maintenance of compressor station equipment.
865 Maintenance of measuring and regulating station equipment (Major
only).
866 Maintenance of communication equipment (Major only).
867 Maintenance of other equipment (Major only).
868 Maintenance of other plant (Nonmajor only).
870 Operation supervision and engineering.
871 Distribution load dispatching (Major only).
872 Compressor station labor and expenses (Major only).
873 Compressor station fuel and power (Major only).
874 Mains and services expenses.
875 Measuring and regulating station expenses -- General (Major
only).
876 Measuring and regulating station expenses -- Industrial (Major
only).
877 Measuring and regulating station expenses -- City gate check
stations (Major only).
878 Meter and house regulator expenses.
879 Customer installations expenses.
880 Other expenses (Major only).
880.1 Miscellaneous distribution expenses (Nonmajor only).
881 Rents.
885 Maintenance supervision and engineering (Major only).
886 Maintenance of structures and improvements (Major only).
887 Maintenance of mains (Major only).
888 Maintenance of compressor station equipment (Major only).
889 Maintenance of measuring and regulating station equipment --
General (Major only).
890 Maintenance of measuring and regulating station equipment --
Industrial (Major only).
891 Maintenance of measuring and regulating station equipment -- City
gate check stations (Major only).
892 Maintenance of services (Major only).
892.1 Maintenance of lines (Nonmajor only).
893 Maintenance of meters and house regulators.
894 Maintenance of other equipment (Major only).
895 Maintenance of other plant (Nonmajor only).
901 Supervision (Major only).
902 Meter reading expenses.
903 Customer records and collection expenses.
904 Uncollectible accounts.
905 Miscellaneous customer accounts expenses (Major only).
906 Customer service and informational expenses (Nonmajor only).
907 Supervision (Major only).
908 Customer assistance expenses (Major only).
909 Informational and instructional advertising expenses (Major
only).
910 Miscellaneous customer service and informational expenses (Major
only).
911 Supervision (Major only).
912 Demonstrating and selling expenses (Major only).
913 Advertising expenses (Major only).
914 (Reserved)
915 (Reserved)
916 Miscellaneous sales expenses (Major only).
917 Sales expenses (Nonmajor only).
920 Administrative and general salaries.
921 Office supplies and expenses.
922 Administrative expenses transferred -- Credit.
923 Outside services employed.
924 Property insurance.
925 Injuries and damages.
926 Employee pensions and benefits.
927 Franchise requirements.
928 Regulatory commission expenses.
929 Duplicate charges -- Credit.
930.1 General advertising expenses.
930.2 Miscellaneous general expenses.
931 Rents.
933 Transportation expenses (Nonmajor only).
935 Maintenance of general plant.
18 CFR 161.3 Operation and Maintenance Expense Accounts
700 Operation supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of the operation of steam
production. (See operating expense instruction 1.)
701 Operation labor (Major only).
This account shall include the cost of labor used in boiler rooms and
elsewhere about the premises engaged in the production of steam or
assignable to the production of steam.
1. Blowing flues.
2. Cleaning boilers.
3. Handling coal, coke, and breeze from place of storage to boilers.
4. Janitorial, messenger, watchmen, and similar services.
5. Operating boilers.
6. Operating elevators.
7. Pulverizing coal.
8. Pumping tar from storage tank to boilers.
9. Removing ashes.
10. Testing steam meters, gauges, and other instruments.
702 Boiler fuel (Major only).
A. This account shall include the cost of coal, oil, gas, or other
fuel used in the production of steam, including applicable amounts of
fuel stock expenses. It shall also include the net cost of, or the net
amount realized from, the disposal of ashes.
B. Records shall be maintained to show the quantity and cost of each
type of fuel used. Respective amounts of fuel stock and fuel stock
expenses shall be readily available.
Note: The cost of fuel, except gas, and related fuel stock expenses,
shall be charged initially to appropriate fuel accounts carried under
accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed,
and cleared to this account on the basis of fuel used. See accounts 151
and 152 for basis of fuel costs and includible items of fuel stock
expenses.
703 Miscellaneous steam expenses (Major only).
This account shall include the cost of materials used and expenses
incurred in the production of steam, not includible in the foregoing
accounts.
1. Boiler compounds.
2. Building service expenses.
3. Chemicals.
4. Communication service.
5. Lubricants.
6. Miscellaneous supplies.
7. Pumping supplies and expenses.
8. Purification supplies and expenses.
9. Tools, hand.
10. Waste.
11. Water purchased.
12. Research, development, and demonstration expenses.
704 Steam transferred -- Credit (Major only).
A. This account shall include such portion of the cost of producing
steam as is charged to other gas operating expense accounts, or to
others or to a coordinate department under a joint facility arrangement.
B. The records supporting the entries to this account shall be so
kept that the utility can furnish readily an explanation of the bases of
the credits to this account and the amounts charged to (1) other gas
accounts, (2) other utility departments, and (3) outside parties under a
joint facility arrangement. The records shall show, likewise, the
amounts of steam production operation and steam production maintenance
expenses, respectively, chargeable to each of the foregoing.
Note A: If the utility produces gas by a single process at only one
plant, credits need not be made to this account for the cost of steam
used in such gas production facility.
Note B: Where steam is produced by producer gas equipment or waste
heat boilers, and such steam becomes part of the general plant supply,
this account should be charged and the steam expense account in the
appropriate functional group of accounts (coal gas production, water gas
production, etc.) credited with the value of such steam. However, if
the steam so produced is used in the same functional operation as that
through which derived, such entries need not be made.
705 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of maintenance of steam production
facilities. Direct field supervision of specific jobs shall be charged
to the appropriate maintenance accounts. (See operating expense
instruction 1.)
706 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures and improvements used
in steam production operations, the book cost of which is includible in
account 305, Structures and Improvements. (See operating expense
instruction 2.)
707 Maintenance of boiler plant equipment (Major only).
This account shall indicate the cost of labor, materials used and
expenses incurred in the maintenance of equipment used in steam
production the book cost of which is includible in account 306, Boiler
Plant Equipment. (See operating expense instruction 2.)
708 Maintenance of other steam production plant (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment used in steam
production operations, the book cost of which is includible in account
314, Coal, Coke, and Ash Handling Equipment, or account 320, Other
Equipment. (See operating expense instruction 2.)
710 Operation supervision and engineering.
A. For Major companies, this account shall include the cost of labor
and expenses occurred in the general supervision and direction of the
operation of manufactured gas stations. Direct supervision of specific
activities such as steam production and power operations, coke oven
operations, water gas generation, etc., shall be charged to the
appropriate account. (See operating expense instruction 1.)
B. For Nonmajor companies, this account shall include the cost of
supervision and labor in the operation of manufactured gas production
plants.
1. Supervising.
2. Operating or attending equipment and controls including boiler
plant, power equipment and other auxiliaries.
3. Cleaning, lubricating and oiling equipment and auxiliaries.
4. Loading and unloading and other handling of coal, coke, other
fuels, raw materials, residuals, waste materials, etc.
5. Observing, testing, checking and adjusting meters, gauges, and
other instruments and equipment.
6. Keeping plant logs and other records and preparing reports on
plant operation.
7. Cleaning boiler room, other buildings and yards.
8. Repacking glands and replacing gauge glasses and other similar
work if work is of a minor nature and performed by regular operating
crews. Where work is of a major character, such as that performed on
high pressure boilers, the word shall be considered maintenance.
9. Testing water, etc.
10. Janitorial, messenger, watchman and similar services.
11. Clerical and stenographic work at plant.
711 Steam expenses (Major only).
A. This account shall include the cost of steam used in manufactured
gas production. This includes the cost of steam transferred from the
gas department's own supply and charges for steam transferred from
others or from coordinate departments under joint facility arrangements.
(See account 704, Steam Transferred -- Credit.)
B. This account shall be so kept as to show separately for each
source of steam the point of delivery, the quantity, the charges
therefor, and the bases of such charges.
712 Other power expenses (Major only).
This account shall include the cost of electricity or other power,
except steam, used in manufactured gas operation. This includes the
cost of power purchased, the operation cost of electricity or other
power such as compressed air produced by the gas department and charges
from others or from coordinate departments for power produced under
joint facility arrangements.
713 Coke oven expenses (Major only).
This account shall include the cost of labor used and expenses
incurred in the operation of coke ovens for the production of coal gas,
exclusive of the cost of fuel for the coke ovens and coal carbonized.
Labor:
1. Supervising.
2. Work of the following character in operation of coke ovens:
a. Charging and leveling coal.
b. Heating ovens to produce coke.
c. Pushing, transporting, quenching, and dumping coke on wharf.
d. Reclaiming coke spillage, removing, replacing, and luting oven
doors and lids.
e. Handling and mixing luting mud.
f. Controlling oven heats and gas heating value with dilution gas.
g. Controlling flue temperature, stack drafts, collecting main
pressure and the flow of flushing liquor and drains.
h. Operating, cleaning, and lubricating equipment not incidental to
maintenance work, such as: charger, pusher, door operating and luting,
mud mixing, gas reversal, transportation machinery and equipment,
quenching pumps and tower, together with valves, instruments, meters,
controls, gauges, and records connected with their operation.
i. Tar chasing (spooning tar in hot drains.)
j. Cleaning doors, jambs, and stand pipes.
3. Handling and transporting coal from storage or boats to battery
bins.
4. Operating, cleaning and lubricating mechanical equipment, such as:
hoist machines, conveyors and their housing, hammermills and breakers,
mixing and battery bins, together with their control valves,
instruments, etc.
5. Wetting and handling coke to the coke wharf or storage including
cleaning and lubricating of equipment not incident to maintenance.
6. Pumping gas from ovens and maintaining the proper pressures on the
collecting main and throughout the apparatus train, including cleaning
and lubricating the oven gas exhausters and revivifying blowers, not
incident to maintenance.
7. Removing and disposing of carbon, fines, sediment, and waste
material.
8. Cleaning ovens and exhauster house, including janitor service in
the employees' locker and wash room within this operating area.
Materials and expenses:
9. Packing, waste, lubricants, etc.
10. Small hand tools.
11. Building service, communication service, transportation.
714 Producer gas expenses (Major only).
This account shall include the cost of labor used and expenses
incurred in making producer gas exclusive of the cost of fuel for
producer gas.
Labor:
1. Supervising.
2. Work of the following character in connection with operation of
producer gas sets (excepting the waste heat boiler and auxiliaries):
a. Inspecting, testing, clinkering, lighting and starting set.
b. Controlling fire and heats with fuel charges.
c. Barring, measuring, and rodding fires.
d. Observing pyrometers, pressures and CO2 in stack gases.
e. Regulating input materials, such as coke, steam and air and making
required flow rate and operating cycle changes.
f. Cleaning and removal of ash, dust, sediment and materials from the
set and connections, seal pots, duct pockets, bootlegs, collectors and
pumps.
g. Cleaning and reluting producer set doors.
h. Operating, cleaning and lubricating fuel charging lorries, grates,
jackets and auxiliaries, ash removal apparatus, and associated
instruments, meters, gauges, controls, etc.
3. Handling fuel from storage into bins with conveyors.
4. Operating, cleaning and lubricating auxiliary equipment, not
incident to maintenance work, such as coolers, pumps, blowers,
exhausters or boosters, fuel handling equipment, etc.
5. Removing and disposing of ashes, sediment and other waste
material.
6. Cleaning the producer and booster houses including janitorial and
similar services.
Materials and expenses:
7. Packing, waste, lubricants, etc.
8. Small hand tools.
9. Building service, communication service, transportation.
715 Water gas generating expenses (Major only).
This account shall include the cost of labor used and expenses
incurred in the operation of water gas sets exclusive of the cost of
fuel and oil for water gas production.
Labor:
1. Supervising.
2. Work of the following character in connection with the operation
of water gas sets (excepting the waste heat boiler and auxiliaries):
a. Inspecting, testing, clinkering, lighting and starting up.
b. Controlling fire and heats with fuel charges, barring and rodding
fires, operating grates and jackets, taking stains, observing
pyrometers, pressures, seal pot water flow and stack gases, regulating
input materials such as coke, oil, natural gas, steam and air.
c. Making required flow rate and operating cycle changes.
d. Cleaning and removing ashes, carbon, and sediment from the set and
connections, the wash box, seal pot, oil spray, duct pockets, bootlegs,
and collectors, and cleaning and reluting producer set doors.
e. Operating, cleaning and lubricating fuel charging lorries,
blowers, valves, automatic operators, and grates, together with their
instruments, gauges, and controls, also the ash belts.
3. Operating, cleaning and lubricating auxiliary equipment, such as
hydraulic pumps, circulating water pumps, oil pumps from storage to
sets, steam accumulators and regulators and reducers on natural gas for
reforming, exhausters, revivifying air blowers, and purifier exhausters.
4. Handling fuel from storage into bins with conveyors.
5. Removing and disposing of ashes, carbon, sediment, and other waste
material.
6. Cleaning of generator and exhauster houses, including janitorial
and similar services.
Materials and expenses:
7. Packing, waste, lubricants, etc.
8. Small hand tools.
9. Building service, communication service, transportation.
716 Oil gas generating expenses (Major only).
This account shall include the cost of labor used and expenses
incurred in the operation of equipment for the production of oil gas
exclusive of cost of the oil.
Labor:
1. Supervising.
2. Cleaning, firing and operating oil gas machines.
3. Handling oil from place of storage to oil gas sets.
4. Measuring oil.
5. Removing and disposing of carbon deposits, and other cleaning and
incidental labor.
Materials and expenses:
6. Packing, waste, lubricants, etc.
7. Small hand tools.
8. Building service, communication service, transportation.
717 Liquefied petroleum gas expenses (Major only).
This account shall include the cost of labor used and expenses
incurred in the operation of equipment used for vaporizing petroleum
derivatives such as propane, butane or gasoline exclusive of cost of the
materials vaporized or used for fuel in the vaporizing process.
Labor:
1. Supervising.
2. Operating, cleaning and lubricating liquid petroleum vaporizers
and injectors.
3. Taking pressures and temperatures, and reading gauges on storage
tanks.
4. Inspecting and testing equipment and setting and adjusting
controls and regulators.
5. Watching pressure gauges, maintaining pressures and relieving
excess pressures through lines.
6. Repressuring storage tanks.
Materials and expenses:
7. Packing, waste, lubricants, etc.
8. Small hand tools.
9. Building service, communication service, transportation.
718 Other process production expenses (Major only).
This account shall include the cost of labor used and expenses
incurred in operating equipment used for the production of gas by
processes not provided for in the foregoing accounts.
719 Fuel under coke ovens (Major only).
A. This account shall include the cost of gas, other than coke oven
gas or producer gas, or other fuel used under coke ovens for making coal
gas. Concurrent credits shall be made to account 734, Duplicate Charges
-- Credit, for gas made by the utility and so used, or account 812, Gas
Used for Other Utility Operations -- Credit, for other gas used under
coke ovens.
B. Records shall be kept to show the quantity and cost of each type
of fuel used and fuel handling expenses.
1. Gas made by the utility and used under coke ovens.
2. Natural and other purchased gas used under coke ovens.
720 Producer gas fuel (Major only).
A. This account shall include the cost of fuel used in making
producer gas including applicable amounts of fuel stock expenses. It
shall also include the net cost of, or the net amount realized from, the
disposal of ashes.
B. Records shall be kept to show the quantity and the cost of each
type of fuel used. Respective amounts of fuel stock and fuel stock
expenses shall be readily available.
Note: The cost of fuel and related fuel stock expenses shall be
charged initially to the appropriate fuel account carried under accounts
151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared
to this account on the basis of fuel used. See accounts 151 and 152 for
basis of fuel costs and includible items of fuel stock expenses.
721 Water gas generator fuel (Major only).
A. This account shall include the cost of fuel used in making water
gas, including applicable amounts of fuel stock expenses. It shall also
include the net cost of, or net proceeds from, the disposal of ashes.
B. Records shall be kept to show the quantity and cost of each type
of fuel used. Respective amounts of fuel stock and fuel stock expenses
shall be readily available.
Note: The cost of fuel and related fuel stock expenses shall be
charged initially to the appropriate fuel account carried under accounts
151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared
to this account on the basis of fuel used. See accounts 151 and 152 for
basis of fuel costs and includible items of fuel stock expenses.
722 Fuel for oil gas (Major only).
This account shall include the cost of fuel for the manufacture of
gas by the oil gas process.
723 Fuel for liquefied petroleum gas process (Major only).
This account shall include the cost of fuel for vaporization of
liquefied petroleum gas and for the compression of air in liquefied
petroleum gas process.
724 Other gas fuels (Major only).
This account shall include the cost of fuel for the manufacture of
gas by processes not provided for in the above fuel accounts.
724 Fuel (Nonmajor only).
A. This account shall include the cost, delivered alongside works, of
coal, oil, gas, or other fuel used in manufactured gas processes, and
for making steam or generating electricity. It shall also include the
net cost of, or the amount realized from, the disposal of ashes. (See
account 154, Materials and Supplies.)
B. Records shall be maintained to show the quantity and cost of each
type of fuel used.
725 Coal carbonized in coke ovens (Major only).
A. This account shall include the cost of coal used in coke ovens for
making coal gas, including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of coal
used. Respective amounts of fuel stock and fuel stock expenses shall be
readily available.
Note: The cost of coal carbonized and related fuel stock expenses
shall be charged initially to the appropriate account carried under
accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed,
and cleared to this account on the basis of coal used. See accounts 151
and 152 for basis of costs and includible items of fuel stock expenses.
726 Oil for water gas (Major only).
A. This account shall include the cost of oil used in carbureting
water gas, including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of oil
used. Respective amounts of fuel stock and fuel stock expenses shall be
readily available.
Note: The cost of oil and related fuel stock expenses shall be
charged initially to the appropriate accounts carried under accounts
151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared
to this account on the basis of oil used. See accounts 151 and 152 for
basis of costs and includible items of fuel stock expenses.
727 Oil for oil gas (Major only).
A. This account shall include the cost of oil used in making oil gas,
including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of oil
used. Respective amounts of fuel stock and fuel stock expenses shall be
readily available.
Note: The cost of oil and related fuel stock expenses shall be
charged initially to the appropriate raw materials account carried under
accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed,
and cleared to this account on the basis of oil used. See accounts 151
and 152 for basis of costs and includible items of fuel stock expenses.
728 Liquefied petroleum gas (Major only).
A. This account shall include the cost of liquefied petroleum gas,
such as propane, butane, or gasoline, vaporized for mixing with other
gases or for sale unmixed, including applicable amounts of fuel stock
expenses.
B. Records shall be kept to show the type, quantity, and cost of
liquefied petroleum gas. Respective amounts of fuel stock and fuel
stock expenses shall be readily available.
Note: The cost of liquefied petroleum gas and related fuel stock
expenses shall be charged initially to the appropriate accounts under
accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed,
and cleared to this account on the basis of liquefied petroleum gas
used. See accounts 151 and 152 for basis of costs and includible items
of fuel stock expenses.
729 Raw materials for other gas processes (Major only).
A. This account shall include the cost of raw materials used in the
production of manufactured gas by any process not provided for by the
foregoing accounts including the production of coal gas by use of
retorts, including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of each
raw material used, comparable to the accounting specified in the
foregoing accounts for specified types of gas processes. Respective
amount of fuel stock and fuel stock expenses shall be readily available.
Note: The cost of raw materials and fuel stock expenses shall be
charged initially to the appropriate accounts carried under accounts
151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared
to this account on the basis of raw materials used. See accounts 151
and 152 for basis of raw materials costs and includible items of raw
materials stock expenses.
729.1 Raw materials (Nonmajor only).
A. This account shall include the cost, delivered alongside works, of
coal, oil, liquefied petroleum gas, gas enricher, and other materials
used as raw materials in the manufacture of gas, including raw materials
for manufacture of gas by reforming. (See account 154, Materials and
Supplies.)
B. Records shall be maintained to show the quantity and cost of each
type of raw material used.
730 Residuals expenses (Major only).
A. This account shall include the cost of labor, materials used and
expenses incurred including uncollectible accounts in obtaining,
handling, preparing, refining, and marketing residuals produced in
manufactured gas production processes.
B. Divisions of this account shall be maintained for each of the
principal types of expenses chargeable hereto and for each residual or
by-product carried in account 731, Residuals Produced -- Credit.
731 Residuals produced -- Credit.
A. This account shall be credited and the appropriate subdivision of
account 153, Residuals and Extracted Products (for Nonmajor companies,
account 154, Plant Materials and Operating Supplies), debited monthly
with the estimated value of residuals and other by-products obtained in
connection with the production of manufactured gas, whether intended for
sale or for use in operations.
B. If the net amount realized from the sale of residuals is greater
or less than the amount at which they were originallly credited hereto,
an adjusting entry shall be made crediting or debiting this account and
charging or crediting the appropriate subdivision of account 153,
Residuals and Extracted Products (for Nonmajor companies, account 154,
Plant Materials and Operating Supplies), with the difference.
732 Purification expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating purification equipment and apparatus used
for conditioning manufactured gas.
Labor:
1. Supervising.
2. Operating conveyors, condensers, coolers, tar extractors and
precipitators, shaving scrubbers and naphthalene and light oil
scrubbers.
3. Emptying, rearranging, shifting, cleaning, purging, and refilling
purifier boxes.
4. Removing spent oxide to refuse pile.
5. Revivifying oxide.
6. Oiling dip sheets of purifier boxes.
7. Inspecting, testing, controlling adjustments, and taking stains.
8. Cleaning and lubricating purification equipment.
Materials and expenses:
9. Iron oxide.
10. Unslacked lime.
11. Shavings.
12. Soda ash for liquid purifiers.
13. Wash oil for naphthalene scrubber.
14. Sulphuric acid.
733 Gas mixing expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating equipment for mixing natural and
manufactured gas, or vaporized liquefied petroleum gases for delivery to
the distribution system.
Labor:
1. Supervising.
2. Mixing enrichment gas and other gases or air, including mixing of
liquid petroleum gas with air in a liquid petroleum air gas plant, and
operation of air jetting equipment and controls.
3. Operating, cleaning and lubricating of cleaners, reducers,
calorimeters, calorimixers, appliances and mixing apparatus with their
related recorders, gauges, valves and controls, and gravitometers.
4. Inspecting, testing and adjusting mixing equipment.
5. Reading instruments and gauges, changing charts, and recording
instrument and gauge readings.
Materials and expenses:
6. Packing, waste, lubricants, etc.
7. Small hand tools.
8. Building service, communication service, transportation.
734 Duplicate charges -- Credit (Major only).
This account shall include concurrent credits for charges which are
made to manufactured gas production operating expenses for manufactured
gas not entering common system supply, steam or electricity used for
which there is no direct money outlay.
Note: For manufactured gas used from the common system supply,
concurrent credits shall be made to account 812, Gas Used for Other
Utility Operations -- Credit.
735 Miscellaneous production expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in manufacturing gas production operations not
includible in any of the foregoing accounts.
Labor:
1. Supervising.
2. Cleaning gas works yard of coke dust and other waste materials.
3. Humidifying gas or oil fogging gas at the production plant.
4. Cutting grass and care of the grounds around the gas works.
5. Clearing gas works yard of snow.
6. Janitor service and messenger service.
7. Operating elevators and other conveyances for general use at the
gas works.
8. General clerical and stenographic work at gas works.
9. Guarding and patrolling plant and yard.
10. Testing plant instruments not elsewhere provided for.
11. Laboratory labor, except that chargeable to other accounts.
12. Reading manufactured gas meters, and calculating and recording
hourly volumes produced.
13. Pumping drips (water) at plant (not provided for elsewhere).
14. Odorizing manufactured gas.
15. Operating, cleaning, and lubricating of air compressors with
their tanks, instruments, meters, gauges, and controls when used to
supply compressed air into the plant's air system.
16. Operating effluent water treatment systems, including chemical
treatment ozonation, filter, and related equipment, including treatment
of carbon and residual sludge, and removing spent oxide, and spent
filtering materials.
17. Pumping water for cooling and condensing.
18. Cleaning filters and other operating duties of water system.
Materials and expenses:
19. Producer gas transferred from coke oven plant to water gas plant
for dilution purposes.
20. Building service, communication service, transportation.
21. First aid supplies and safety equipment.
22. Office supplies, printing and station- ery.
23. Meals, travelling and incidental expenses.
24. Fuel for heating plant, water for fire protection or general use,
and similar items.
25. Lubricants, packing, waste, etc.
26. Odorizing chemicals.
27. Hand tools, drills, saw blades, files, etc.
28. Fire protection supplies.
29. Fogging oils, alcohol, etc.
30. Chemicals, filter materials, etc., and payments to others for
disposal of plant effluents and waste.
31. Chemicals for water treatment.
32. Research, development, and demonstration expenses.
736 Rents.
This account shall include rents for property of others used,
occupied or operated in connection with manufactured gas production
operations. (See operating expense instruction 3.)
737 Operation supplies and expenses (Nonmajor only).
This account shall include the cost of supplies used and expenses
incurred in manufactured gas production operations not includible in any
of the foregoing accounts.
1. Lubricants, packing, waste, etc.
2. Water purchased.
3. Water purification supplies and expenses.
4. Tools, hand.
5. Gas purification supplies and expenses.
6. Oil for oil fogging process.
7. Royalties for purification process, etc.
8. Building service, communication service, transportation.
740 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of maintenance of manufactured gas
production facilities. Direct field supervision of specific jobs shall
be charged to the appropriate maintenance accounts. (See operating
expense instruction 1.)
741 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures, the book cost of
which is includible in account 305, Structures and Improvements. (See
operating expense instruction 2.)
742 Maintenance of production equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment for the production of
manufactured gas, the book cost of which is included in accounts 306 to
320, inclusive, except such equipment as is used for the production of
steam the maintenance of which is includible in accounts 707,
Maintenance of Boiler Plant Equipment, and 708, Maintenance of Other
Steam Production Plant. (See operating expense instruction 2.)
743 Maintenance of production plant (Nonmajor only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of manufactured gas production
plant the book cost of which is includible in plant accounts 305 to 320,
inclusive. (See operating expense instruction 2.)
750 Operation supervision and engineering.
A. For Major companies, this account shall include the cost of labor
and expenses incurred in the general supervision and direction of the
operation of production and gathering systems. Direct supervision of
specific activities such as turning on and shutting off wells, operating
measuring and regulating stations, etc., shall be charged to the
appropriate account. (See operating expense instruction 1.)
B. For Nonmajor companies, this account shall include the cost of
supervision and labor in the operation of gas wells, lines, compressors
and other equipment of the natural gas production and gathering system
including miscellaneous labor such as care of grounds, building service,
and general clerical and stenographic work at field offices.
1. Supervision. (See operating expense instruction 1.)
2. Gas depletion and gas reserve activities.
3. Geological activities in connection with gas production.
4. Rights-of-way office activities and supervision, not in connection
with construction or retirement work, or storage.
5. Gas well labor: turning wells on and off, bailing, swabbing,
blowing wells, etc.
6. Preparing and maintaining production maps and land records,
including surveys.
7. Field line labor: patrolling, attending and lubricating valves
and other equipment, blowing and cleaning lines and drips, taking line
pressures, etc.
8. Field compressor station labor: operating, attending, lubricating
and servicing equipment, recording pressures, replacing charts, etc.
9. Measuring and regulating labor: recording pressures, changing
charts, calculating gas volumes except for purchased gas and sales,
adjusting and calibrating measuring equipment, taking gas samples and
testing gas, inspecting and pumping drips, dewatering manholes and pits,
etc.
10. Purification labor: attending and servicing purification
apparatus, emptying, cleaning and refilling purifier boxes, unloading
and storing glycol, etc.
11. Inspecting and testing equipment, not specifically to determine
necessity for repairs or replacement of parts.
12. Lubricating equipment, valves, etc.
13. Hauling operating employees, materials, supplies, etc.
14. Moving equipment, minor structures, etc., not in connection with
construction, retirement or maintenance work.
15. Keeping log and other operating records, preparing reports of
operations, etc.
16. Cleaning structures, cutting grass and weeds, and minor grading
around stations.
17. Cleaning debris, cutting grass and weeds on rights-of-way.
18. Cleaning and repairing tools.
19. Building and repairing gate boxes, foot bridges, stiles, tool
boxes, etc.
20. Janitorial, watchmen and messenger services.
21. Clerical and stenographic work.
751 Production maps and records (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the preparation and maintenance of production maps
and records.
Labor:
With respect to production maps:
1. Supervising.
2. Preparing farm maps, field inventory maps, well location plats,
and other maps used in connection with natural gas production and
gathering operations.
3. Posting changes and making corrections of maps.
4. Maintaining files of maps and tracings.
5. Surveying deeds, leases, rights-of-way, well locations, etc., for
map revisions.
6. Reproducing maps (blueprints, photostats, etc.).
With respect to land records:
7. Supervising.
8. Abstracting titles to date for extension and renewal of leases.
9. Adjusting land and well rentals.
10. Checking free gas rights.
11. Maintaining land and lease records.
12. Delivering rental and royalty checks.
13. Assigning, pooling, merging, renewing, and extending leases.
14. Patrolling land.
15. Preparing expiration calendars.
16. Replacing leases (not involving additional consideration).
17. Transferring payees.
Materials and expenses:
18. Blueprints, photostats, etc.
19. Drafting materials and supplies.
20. Surveying materials and supplies.
21. Employee transportation and travel expenses.
22. Freight, express, parcel post, trucking, and other
transportation.
23. Janitor and washroom supplies, etc.
24. Office supplies, stationery and printed forms.
25. Utility services: light, water, and telephone.
752 Gas wells expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating producing gas wells.
Labor:
1. Supervising.
2. Testing, bailing, swabbing, blowing and gauging producing gas
wells.
3. Cleaning off old well locations.
4. Painting signs, etc.
5. Minor upkeep of well roads and fences, etc.
6. Turning wells off and on.
7. Pumping wells.
Materials and expenses:
8. Gas, gasoline, and oil used in pumping, bailing, heating, and
swabbing.
9. Lumber, nails, and other materials used for upkeep of fences,
making signs, etc.
10. Materials for upkeep of well roads, etc.
11. Well swabs.
12. Employees' transportation and travel expenses.
13. Freight, express, parcel post, trucking and other transportation.
14. Transportation: company and rented vehicles.
753 Field lines expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating field lines.
Labor:
1. Supervising.
2. Walking or patrolling lines.
3. Attending valves, lubricating valves and other equipment, blowing
and cleaning lines and drips, draining water from lines, operating and
cleaning scrubbers, thawing freezes.
4. Taking line pressures, changing pressure charts, operating alarm
gauges.
5. Building and repairing gate boxes, foot bridges, stiles, tool
boxes, etc., used in line operations, erecting line markers and warning
signs, repairing old line roads.
6. Cleaning debris, cutting grass and weeds on rights-of-way.
7. Inspecting and testing not specifically to determine necessity for
repairs.
8. Protecting utility property during work by others.
9. Standby time of emergency crews, responding to fire calls, etc.
10. Locating valve boxes or drip riser boxes.
11. Cleaning and repairing tools used in mains operations, making
tool boxes, etc.
12. Cleaning structures and equipment.
13. Driving trucks.
Materials and expenses:
14. Line markers and warning signs.
15. Lumber, nails, etc., used in building and repairing gate boxes,
foot bridges, stiles, tool boxes, etc.
16. Charts.
17. Scrubber oil.
18. Hand tools.
19. Lubricants, wiping rags, waste, etc.
20. Freight, express, parcel post, trucking and other transportation
charges.
21. Employees' transportation and travel expenses.
22. Janitor and washroom supplies.
23. Utility services: light, water, telephone.
24. Gas used in field line operations.
754 Field compressor station expenses (Major only).
This account shall include the cost of labor, materials used, except
fuel, and expenses incurred in operating field compressor stations.
Labor:
1. Supervising.
2. Operating and checking engines, equipment valves, machinery,
gauges, and other instruments, including cleaning, wiping, pol- ishing,
and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel
handling and ash disposal, recording fuel used, and unloading and
storing coal and oil.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing
reports of station operations.
6. Inspecting and testing equipment when not specifically to
determine necessity for repairs or replacement of parts.
7. Pumping drips at the station.
8. Taking dew point readings.
9. Testing water.
10. Cleaning structures, cutting grass and weeds, and minor grading
around station.
11. Cleaning and repairing hand tools used in operations.
12. Driving trucks.
13. Watching during shut downs.
14. Clerical work at station.
Materials and expenses:
15. Scrubber oil.
16. Lubricants, wiping rags, and waste.
17. Charts and printed forms, etc.
18. Gauge glasses.
19. Chemicals to test waters.
20. Water tests and treatment by other than employees.
21. Janitor and washroom supplies, first aid supplies, landscaping
supplies, etc.
22. Employees' transportation and travel expenses.
23. Freight, express, parcel post, trucking, and other
transportation.
24. Utility services: light, water, telephone.
755 Field compressor station fuel and power.
A. This account shall include the cost of gas, coal, oil, or other
fuel, or electricity, used for the operation of field compressor
stations, (including in the case of Major companies, applicable amounts
of fuel stock expenses).
B. Records shall be maintained to show the quantity of each type of
fuel consumed or electricity used at each compressor station, and the
cost of such fuel or power. For Major companies, respective amounts of
fuel stock and fuel stock expenses shall be readily available.
Note A (Major companies): The cost of fuel, except gas, and related
fuel stock expenses shall be charged initially to appropriate fuel
accounts carried in accounts 151, Fuel Stock, and 152, Fuel Stock
Expenses Undistributed, and cleared to this account on the basis of fuel
used. See accounts 151 and 152 for the basis of fuel costs and
includible fuel stock expenses.
Note B (Nonmajor companies): The cost of fuel, except gas, shall be
charged initially to account 154, Plant Materials and Operating
Supplies, and cleared to this account on the basis of fuel used.
756 Field measuring and regulating station expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating field measuring and regulating stations.
Labor:
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc., except gas purchases
and sales.
4. Calculating gas volumes from meter charts, except for gas
purchases and sales.
5. Adjusting and calibrating measuring equipment, changing meters,
orifice plates, gauges, clocks, etc., not in connection with maintenance
or construction.
6. Testing gas samples, inspecting and testing gas sample tanks and
other meter engineer's equipment, determining specific gravity and Btu
content of gas.
7. Inspecting and testing equipment not specifically to determine
necessity for repairs including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records, preparing reports of
operations, etc.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipes.
13. Inspecting and pumping drips, dewatering manholes and pits,
inspecting sumps, cleaning pits, etc., blowing meter drips.
14. Moving equipment, minor structures, etc., not in connection with
construction, retirement, or maintenance work.
Materials and expenses:
15. Charts and printed forms, stationery and office supplies, etc.
16. Lubricants, wiping rags, waste.
17. Employees' transportation and travel expense.
18. Freight, express, parcel post, trucking and other transportation.
19. Utility services: light, water, telephone.
757 Purification expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating equipment used for purifying,
dehydrating, and conditioning of natural gas.
Labor:
1. Supervising.
2. Changing charts on fuel meters.
3. Emptying, cleaning and refilling puri- fier boxes.
4. Oiling dip sheets of purifier covers.
5. Removing spent oxide to refuse piles.
6. Revivifying oxide.
7. Taking readings of inlet and outlet pressures and temperature.
8. Unloading and storing glycol.
9. Watching station and equipment.
10. Cutting grass and weeds, and minor grading around equipment and
stations.
11. Hauling operating employees, materials, supplies and tools, etc.
12. Inspecting and testing equipment, not specifically to determine
necessity for repairs or replacement of parts.
13. Lubricating equipment, valves, etc.
14. Operating and checking equipment, valves, instruments, etc.
Materials and expenses:
15. Liquid purifying supplies.
16. Iron oxide.
17. Odorizing materials.
18. Charts, printed forms, etc.
19. Employees' transportation and travel expenses.
20. Freight, express, parcel post, trucking, and other
transportation.
21. Gas used in operations.
22. Janitor, washroom, and landscaping supplies.
23. Lubricants, wiping rags, waste, etc.
24. Utility services: light, water, telephone.
Note: Inclusion of dehydration expenses in this account shall be
consistent with the functional classification of dehydration plant as to
which, see the note to account 336, Purification Plant, relating to
cases where dehydrators may be located some distance from the production
sources of gas.
758 Gas well royalties.
A. This account shall include royalties paid for natural gas produced
by the utility from wells on land owned by others.
B. Records supporting the entries to this account shall be so kept
that the utility can furnish the name of the parties to each contract
involving royalties, the terms of each contract, the location of the
property involved, the method of determining the royalties, and the
amounts payable.
759 Other expenses.
This account shall include the cost of labor (Major companies only),
materials used and expenses incurred in producing and gathering natural
gas and not includible in any of the foregoing accounts.
Labor (Major only):
1. Moving cleaning tools between locations.
2. Operating communications system.
3. Reading limited and unlimited free gas meters.
Materials and expenses:
4. Miscellaneous small tools, etc.
5. Research, development, and demonstration expenses.
(Nonmajor companies):
1. Scrubber oil.
2. Gas, gasoline, and oil, in pumping, bailing, heating and swabbing.
3. Well swabs.
4. Lumber, nails, and other materials used for upkeep of fences,
making signs, etc.
5. Material for upkeep of roads, etc.
6. Hand tools.
7. Lubricants, wiping rags, waste, etc.
8. Gas used in field line operation.
9. Charts and printed forms.
10. Gauge glasses.
11. Water tests and treatment by other than employees.
12. Gas purifying supplies.
13. Geological and gas reserve services by other than employees in
connection with gas production.
14. Office supplies, stationery, drafting materials, etc.
15. Janitor, washroom, landscaping, first aid supplies, etc.
16. Employees' transportation and travel expenses.
17. Freight, express, parcel post, trucking, and other
transportation.
18. Utility services: lights, water, telephone.
760 Rents.
This account shall include rents for property of others used,
occupied or operated in connection with the production and gathering of
natural gas, other than rentals on land and land rights held for the
supply of natural gas. (See operating expense instruction 3.)
Note: See account 795, Delay Rentals, for rentals paid on lands held
for the purpose of obtaining a supply of gas in the future.
761 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the general supervision and direction of
maintenance of the production and gathering facilities as a whole.
Direct field supervision of specific jobs shall be charged to the
appropriate maintenance account. (See operating expense instruction 1.)
762 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures and improvements, the
book cost of which is includible in accounts 326, Gas Well Structures,
327, Field Compressor Station Structures, 328, Field Measuring and
Regulating Station Structures, and 329, Other Structures. (See
operating expense instruction 2.)
763 Maintenance of producing gas wells.
This account shall include the cost of labor, materials used and
expenses incurred in maintenance of gas wells and equipment includible
in accounts 330. Producing Gas Wells -- Well Construction, and 331,
Producing Gas Wells -- Well Equipment. (See operating expense
instruction 2.)
764 Maintenance of field lines.
This account shall include the cost of labor, materials used and
expenses incurred in maintenance of field lines the book cost of which
is includible in account 332, Field Lines. (See operating expense
instruction 2.)
1. Electrolysis and leak inspections (not routine).
2. Installing and removing temporary lines, when necessitated by
maintenance.
3. Lamping and watching while making repairs.
4. Lowering and changing location of portion of lines, when the same
pipe is used.
5. Protecting lines from fires, floods, land slides, etc.
6. Rocking creek crossings.
765 Maintenance of field compressor station equipment (Major only).
This account shall include the cost of labor and expenses incurred in
the maintenance of field compressor station equipment includible in
account 333, Field Compressor Station Equipment. (See operating expense
instruction 2.)
766 Maintenance of field measuring and regulating station equipment
(Major only).
This account shall include the cost of labor, materials used and
expenses incurred in maintenance of field measuring and regulating
station equipment includible in account 334, Field Measuring and
Regulating Station Equipment. (See operating expense instruction 2.)
767 Maintenance of purification equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of purification equipment
includible in account 336, Purification Equipment. (See operating
expense instruction 2.)
Note: Inclusion of dehydration maintenance expenses in this account
shall be consistent with the functional classification of dehydration
plant as to which see the note to account 336, Purification Equipment,
relating to cases where dehydrators may be located some distance from
the production sources of gas.
768 Maintenance of drilling and cleaning equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of drilling and cleaning equipment
includible in account 335, Drilling and Cleaning Equipment, except such
costs of maintaining drilling tools or other equipment which are
assignable to the cost of drilling wells. (See operating expense
instruction 2.)
769 Maintenance of other equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in maintenance of other production and gathering
equipment includible in account 337, Other Equipment. (See operating
expense instruction 2.)
769.1 Maintenance of other plant (Nonmajor only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of plant the book cost of which is
includible in natural gas production and gathering plant except accounts
330, 331, and 332. (See operating expense instruction 2.)
770 Operation supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of products extraction and
refining operations, except supervision of marketing and selling
operations which shall be charged to account 779, Marketing Expenses.
Direct supervision of specific extraction and refining activities shall
be charged to the appropriate account. (See operating expense
instruction 1.)
771 Operation labor (Major only).
This account shall include the cost of labor used in the operation of
facilities for the extraction of gasoline, butane, propane, or other
salable products from natural gas and for refining such products.
Labor:
1. Supervising.
2. Operating, checking, lubricating, wiping, polishing, and cleaning
engines, equipment, valves, machinery, gauges, and other instruments,
etc.
3. Inspecting and testing equipment and instruments, not specifically
to determine necessity for repairs or replacement of parts.
4. Reading meters, gauges, and other instruments, changing charts,
preparing operating reports, etc.
5. Testing gasoline samples, water, etc.
6. Cleaning structures housing equipment, cutting grass and weeds and
doing minor grading work around equipment and structures, etc.
7. Driving trucks used in products extraction operations.
8. Cleaning and repairing hand tools used in operations, etc.
9. Watching plant during shut-down periods.
10. Making electricity or steam.
772 Gas shrinkage (Major only).
A. This account shall include the cost of gas lost or absorbed in the
process of extraction of salable products from natural gas, exclusive of
gas used as fuel, the cost of which shall be included in account 773,
Fuel.
B. Concurrent credits offsetting charges to this account shall be
made to account 811, Gas Used for Products Extraction -- Credit.
773 Fuel (Major only).
A. This account shall include the cost of natural gas or other fuel
used in extracting gasoline, butane, propane and other salable products
from natural gas, including fuel used for generation of electricity or
making steam.
B. Concurrent Credits offsetting charges to this account shall be
made to account 811, Gas Used for Products Extraction -- Credit.
774 Power (Major only).
This account shall include the cost of electricity purchased for
operation of facilities used in the extraction of gasoline, butane,
propane, or other salable products from natural gas.
775 Materials (Major only).
This account shall include the cost of materials used in extracting
salable products from natural gas and blending and refining such
products.
1. Absorption oil.
2. Charcoal.
3. Water (payments to others for water).
4. Steam (payments to others for steam).
5. Blending agents.
6. Natural gasoline removed from inventory for blending and refining
purposes.
7. Tetraethyl lead.
776 Operation supplies and expenses.
This account shall include supplies used and expenses incurred in the
operation of facilities for recovering salable products from natural gas
and in the case of Major companies, blending and refining such products,
not provided for elsewhere.
1. Employee transportation and travel expenses.
2. Freight, express, parcel post, trucking and other transportation.
3. Utility services: light, water, telephone.
4. Charts, gas measurement, etc.
5. Janitor, washroom and landscaping supplies.
6. Lubricants: oil and grease, wiping rags and waste, etc.
7. Testing equipment, hand tools, etc., of a portable nature and
relatively minor cost or of short life.
8. Research, development, and demonstration expenses.
Note (Nonmajor companies): If the products extraction operations of
the utility are other than a relatively minor part of the utility's
natural gas business, the utility shall use the accounts for products
extraction expenses of the Major gas companies with the respective
accounts prescribed therein identified as subaccounts to this account.
777 Gas processed by others (Major only).
A. This account shall include the cost of gas shrinkage, gas consumed
for fuel, royalties, and other expenses in connection with the
processing of gas of the utility by others for extraction of salable
products, for which the related revenues are includible in account 491,
Revenues from Natural Gas Processed by Others.
B. Concurrent credits offsetting charges to this account for the
difference between gas delivered to others for processing and gas
returned after processing, such as shrinkage in the processing
operations and gas of the utility used for fuel, shall be made to
account 811, Gas Used for Products Extraction of Credit.
C. Records supporting this account shall be so maintained that full
information will be readily available concerning gas shrinkage, gas used
for fuel, royalties, and other expenses assumed or paid by the utility
with regard to each processor of gas of the utility. (See paragraph B
of account 491, Revenues from Natural Gas Proc- essed by Others.)
1. Gas shrinkage, being cost of the reduction in gas from products
extraction operations of gas of the utility processed by others.
2. Gas for fuel, being cost of gas of the utility used for fuel in
connection with the products extraction processing of the utility's gas
by others.
3. Royalties, being payments of fractional interests of royalty
holders in products extracted by others from gas of the utility.
778 Royalties on products extracted (Major only).
This account shall include royalties paid by the utility to others
for the right to extract salable products from natural gas.
779 Marketing expenses (Major only).
A. This account shall include the cost of labor, materials used and
expenses incurred in the marketing of products extracted from natural
gas and of similar products purchased for resale.
B. The records supporting this account shall be so maintained that
summaries of the various types of expenses shall be readily available.
Labor:
1. Salaries of persons directly engaged in marketing operations.
Materials and expenses:
2. Employee transportation and travel expenses.
3. Tank car rentals.
4. Freight and hauling charges for products shipped.
5. Miscellaneous marketing expenses.
6. Building service charges for space occupied by marketing
personnel.
7. Uncollectible accounts for extracted products sold.
780 Products purchased for resale (Major only).
A. This account shall include the cost of gasoline, butane, propane,
or other salable products purchased from others for resale.
B. The records supporting this account shall be so maintained that
the kind, quantity, and cost of products purchased from each vendor are
readily available.
781 Variation in products inventory (Major only).
This account shall include credits for increases, and debits for
decreases in the inventories of salable products extracted from natural
gas or purchased for resale. The net debit or credit in this account
shall equal the difference between the inventory at the beginning of the
accounting year and the end of the accounting month.
782 Extracted products used by the utility -- Credit (Major only).
This account shall include concurrent credits for charges which are
made of operating expenses or other accounts of the gas department for
gasoline or other extracted products which are used from stocks
recovered in the natural gas extraction process or purchased for resale,
and for such products used for blending and refining processes, the
contra debit for which is account 775, Materials.
783 Rents (Major only).
This account shall include all rents for the property of others used,
occupied, or operated in connection with the extraction of salable
products from natural gas, exclusive of tank car rentals and other
similar rentals includible in account 779, Marketing Expenses. (See
operating expense instruction 3.)
784 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of maintenance of facilities used
in the extraction and refining of salable products from natural gas.
Direct field supervision of specific jobs shall be charged to the
appropriate maintenance account. (See operating expense instruction 1.)
785 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures, the book cost of
which is includible in account 341, Structures and Improvements. (See
operating expense instruction 2.)
786 Maintenance of extraction and refining equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 342, Extraction and Refining Equipment.
(See operating expense instruction 2.)
787 Maintenance of pipe lines (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 343, Pipe Lines. (See operating expense
instruction 2.)
788 Maintenance of extracted products storage equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 344, Extracted Products Storage
Equipment. (See operating expense instruction 2.)
789 Maintenance of compressor equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 345, Compressor Equipment. (See
operating expense instruction 2.)
790 Maintenance of gas measuring and regulating equipment (Major
only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 346, Gas Measuring and Regulating
Equipment. (See operating expense instruction 2.)
791 Maintenance of other equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 347, Other Equipment. (See operating
expense instruction 2.)
792 Maintenance of products extraction plant (Nonmajor only).
This account shall include the cost of labor, materials and supplies
used and expenses incurred in the maintenance of plant the book cost of
which is includible in accounts 341 to 347, inclusive. (See operating
expense instruction 1.)
795 Delay rentals.
A. This account shall be charged with the amount of rents paid
periodically on natural gas lands acquired by lease before October 8,
1969, in order to hold natural gas land and land rights for the purpose
of obtaining a supply of gas in the future.
B. Include also in this account, the cost of obtaining natural gas
leases for a period of 1 year or less when such leases were acquired
before October 8, 1969.
C. Records supporting this account shall be so kept that the utility
can furnish complete details of the charges made for each natural gas
leasehold. (See note to gas plant instruction 7G.)
Note: Rents paid periodically on natural gas lands acquired by lease
after October 7, 1969, shall be charged to account 105.1, Production
Properties Held for Future Use (in the case of Nonmajor Companies,
account 105, Gas Plant Held for Future Use).
796 Nonproductive well drilling.
This account shall include the net cost of drilling wells on natural
gas leases acquired before October 8, 1969, which prove to be
nonproductive.
Note A: Records in support of the charges to this account shall
conform, as appropriate, to Note B of General Instruction 12, Records
for Each Plant (in the case of Nonmajor companies, General Instruction
21, Gas Well Records).
Note B: The net cost of drilling wells on natural gas leases
acquired after October 7, 1969, which prove to be nonproductive, shall
be charged to account 338, Unsuccessful Exploration and Development
Costs.
797 Abandoned leases.
A. For Major companies, this account shall be charged with amounts
credited to account 111, Accumulated Provision for Amortization and
Depletion of Gas Utility Plant, to cover the probable loss on
abandonment of natural gas leases acquired before October 8, 1969,
included in account 105, Gas Plant Held for Future Use, which has never
been productive. For Nonmajor companies, this account shall be charged
with losses on abandonment of natural gas leases acquired before October
8, 1969, included in account 105, Gas Plant Held for Future Use, which
have never been productive, unless otherwise authorized by the
Commission. (See account 182.1.)
B. (Major only) when natural gas leaseholds which were acquired
before October 8, 1969, and which have never been productive are
abandoned, and the amounts provided in account 111, Accumulated
Provision for Amortization and Depletion of Gas Utility Plant, are not
sufficient to cover the cost thereof, the deficiency shall be charged to
this account unless otherwise authorized or directed by the Commission.
(See account 182.1.)
Note: Losses on abandonment of natural gas leases acquired after
October 7, 1969, shall be charged to account 338, Unsuccessful
Exploration and Development Costs.
798 Other exploration.
This account shall be charged with the cost of abandoned projects
involving natural gas leases acquired before October 8, 1969, on which
preliminary expenditures were made for the purpose of determining the
feasibility of acquiring acreage to provide a future supply of natural
gas (for Major companies see account 183.1, Preliminary Natural Gas
Survey and Investigation Charges; for Nonmajor companies, see account
186, Miscellaneous Deferred Debits).
Note: Preliminary expenditures on abandoned projects involving
natural gas leases acquired after October 7, 1969, shall be charged to
account 338, Unsuccessful Exploration and Development Costs.
799 Natural gas purchases (Nonmajor only).
A. This account shall include the cost at point of receipt by the
utility of natural gas purchased for resale.
B. The records supporting this account shall be so maintained that
there shall be readily available for each vendor and each point of
receipt, the quantity of gas, basis of charges, and the amount paid for
the gas.
800 Natural gas well head purchases (Major only).
A. This account shall include the cost at well head of natural gas
purchased from producers in gas fields or production areas where only
the utility's facilities are used in bringing the gas from the well head
into the utility's natural gas system.
B. The records supporting this account shall be so maintained that
there shall be readily available for each vendor and well head the
quantity of gas, basis of charges, and amount paid for the gas.
Note: If gas purchases are made under one contract covering both
well head and field line purchases and such amounts are not readily
separable, the utility may classify such purchases according to
predominant source or according to a reasonable estimate.
800.1 Natural gas well-head purchases; intracompany transfers.
A. This account shall include, for informational purposes only, the
amount recorded for gas supplied by the production division when the
price is not determined by a cost-of-service rate proceeding.
B. The records supporting this account shall be so maintained that
there will be readily available for each well-head, the quantity of gas,
the basis of intracompany charges, and the amount of intracompany
charges for gas.
801 Natural gas field line purchases (Major only).
A. This account shall include the cost, at point of receipt by the
utility, of natural gas purchased in gas fields or production areas at
points along gathering lines, and at points along the utility's
transmission lines within field or production areas, exclusive of
purchases at outlets of gasoline plants includible in account 802, where
facilities of the vendor or others are used in bringing the gas from the
well head to the point of entry into the utility's natural gas system.
B. The records supporting this account shall be so maintained that
there shall be readily available for each vendor and each point of
receipt, the quantity of gas, basis of charges, and amount paid for the
gas.
Note: If gas purchases are made under one contract covering both
well head and field line purchases and such amounts are not readily
separable, the utility may classify such purchases according to
predominant source or according to a reasonable estimate.
802 Natural gas gasoline plant outlet purchases (Major only).
A. This account shall include the cost, at point of receipt by the
utility, of natural gas purchased at the outlet side of vendor's natural
gas products extraction plants.
B. The records supporting this account shall be so maintained that
there shall be readily available for each vendor and for each products
extraction plant, the quantity of gas, basis of the charges, and the
amount paid for the gas.
803 Natural gas transmission line purchases (Major only).
A. This account shall include the cost, at point of receipt by the
utility, of natural gas purchased at points along the utility's
transmission lines not within gas fields or production areas, excluding
purchases at the outlets of products extraction plants includible in
account 802.
B. The records supporting this account shall be so maintained that
there shall be readily available for each vendor and each point of
receipt, the quantity of gas, basis of charges, and the amount paid for
the gas.
804 Natural gas city gate purchases (Major only).
A. This account shall include the cost, at point of receipt by the
utility, of natural gas purchased which is received at the entrance to
the distribution system of the utility.
B. The records supporting this account shall be so maintained that
there shall be readily available for each vendor and each point of
receipt, the quantity of gas, basis of the charges, and the amount paid
for the gas.
Note: Do not credit this account for gas used in reforming for which
the cost is charged to manufactured gas production expenses. Credits
for such gas should be made to account 812, Gas Used for Other Utility
Operations -- Credit.
804.1 Liquefied natural gas purchases (Major only).
A. This account shall include the cost, including transportation, at
point of receipt by the utility, of liquefied natural gas purchased for
the purpose of vaporization and injection into the utility's
transmission or distribution system for resale.
B. The records supporting this account shall be so maintained that
there shall be readily available for each vendor and point of receipt,
the quantity of liquefied natural gas purchased, basis of charges, the
amount paid for the liquefied gas, and transportation charges incurred
up to the point of receipt of the liquefied gas.
805 Other gas purchases.
A. This account shall include the cost, at point of receipt by the
utility, of manufactured gas, refinery gas, or any gas other than
natural gas, or other than any mixed gas in which the natural gas is an
important proportion of the mixture.
B. The records supporting this account shall be so maintained that
there shall be readily available for each vendor and each point of
receipt, the kind and quantity of gas, Btu content, basis of the
charges, and the amount paid for the gas.
805.1 Purchased gas cost adjustments.
A. This account shall be debited or credited with decreases or
increases in purchased gas costs related to Commission approved
purchased gas adjustment clauses when such costs are not included in the
utility's rate schedules on file with the Commission.
B. This account shall be debited or credited with amounts amortized
from Account 191, Unrecovered Purchased Gas Costs.
806 Exchange gas (Major only).
A. This account shall include debits or credits for the cost of gas
in unbalanced exchange transactions whereby gas is received from another
party in exchange for delivery of gas to such other party and receipt
and delivery of such gas is not completed during the accounting period.
Contra entries to those in this account shall be made to account 174,
Miscellaneous Current and Accrued Assets, for exchange gas receivable
and to account 242, Miscellaneous Current and Accrued Liabilities, for
exchange gas deliverable. Such entries shall be reversed and
appropriate contra entries made to this account when gas is received or
delivered in satisfaction of the amounts receivable or deliverable.
This accounting is not required for minor transactions.
B. If revenue is earned or amounts are payable in consideration of
the performance of exchange services, such revenue or expense should be
recorded in account 495, Other Gas Revenues, or account 813, Other Gas
Supply Expenses, as appropriate. See, however, accounts 489, Revenues
from Transportation of Gas of Others, and 858, Transmission and
Compression of Gas by Others, for transactions which, in fact, are for
transportation of gas rather than exchange of gas.
C. Records shall be maintained so that there is readily available for
each gas exchange the volume of gas received and delivered whether or
not entries of dollar amounts to this account are required.
807 Purchased gas expenses.
A. This account shall include expenses incurred directly in
connection with the purchase of gas for resale.
B. The utility shall not include as purchased gas expense, segregated
or apportioned expenses of operating and maintaining gathering system
plant whether such plant is devoted solely or partially to purchases of
gas, except that the utility shall include the cost of turning on and
off purchase gas wells and operating measuring stations devoted
exclusively to measuring purchased gas.
C. In general, it is intended that this account include only the
expenses directly related to purchased gas, including the expenses of
computing volumes of gas purchased, and special items directly related
to gas purchases which are not includible in other accounts.
D. (Major companies) This account shall be subdivided as follows:
807.1 Well expenses -- Purchased gas.
807.2 Operation of purchased gas measuring stations.
807.3 Maintenance of purchased gas measuring stations.
807.4 Purchased gas calculations expenses.
807.5 Other purchased gas expenses.
808.1 Gas withdrawn from storage -- Debit.
A. This account shall include debits for the cost of gas withdrawn
from storage during the year. Contra credits for entries to this
account shall be made to accounts 117, Gas Stored Underground --
Noncurrent (in the case of Nonmajor companies, account 164.1, Gas Stored
Underground) or 164.2, Liquefied Natural Gas Stored, as appropriate.
B. Withdrawal of gas from storage shall not be netted against
deliveries to storage. (See account 808.2.)
Note: Adjustments for gas inventory losses due to cumulative
inaccuracies in gas measurement, or from other causes, shall be entered
in account 823, Gas Losses. If, however, any adjustment is substantial,
the utility may, with approval of the Commission, amortize the amount of
the adjustment to account 823 over future operating periods.
808.2 Gas delivered to storage -- Credit.
A. This account shall include credits for the cost of gas delivered
to storage during the year. Contra debits for entries to this account
shall be made to accounts 117, Gas Stored Underground -- Noncurrent (in
the case of Nonmajor companies, account 164.1, Gas Stored Underground)
or 164.2, Liquefied Natural Gas Stored, as appropriate.
B. Deliveries of gas to storage shall not be netted against
withdrawals from storage. (See account 808.1.)
809.1 Withdrawals of liquefied natural gas held for processing --
Debit (Major only).
A. This account shall include debits for the cost of liquefied gas
withdrawn during the year. Contra credits for entries to this account
shall be made to account 164.3, Liquefied Natural Gas Held for
Processing.
B. Withdrawals of liquefied natural gas held for processing shall not
be netted against deliveries. (See account 809.2).
Note: Adjustments for gas inventory losses due to cumulative
inaccuracies in gas measurement, or from other causes, shall be entered
in account 846.1, Gas Losses, in the month determined, if, however, any
adjustment is substantial, the utility may, with approval of the
Commission, amortize the amount of the adjustment to account 846.1 over
future operating periods.
809.2 Deliveries of natural gas for processing -- Credit.
A. This account shall include credits for the cost of gas delivered
for processing during the year. Contra debits for entries to this
account shall be made to account 164.3, Liquefied Natural Gas Held for
Processing.
B. Deliveries of natural gas for processing shall not be netted
against withdrawals from processing. (See account 809.1).
810 Gas used for compressor station fuel -- Credit (Major only).
This account shall include concurrent credits for charges which are
made to operating expenses for gas consumed for compressor station fuel
from the common system gas supply.
811 Gas used for products extraction -- Credit (Major only).
This account shall include concurrent credits for charges which are
made to products extraction expenses for gas shrinkage and gas used for
fuel in products extraction operations of the utility and for similar
uses of gas of the utility by others processing gas of the utility for
extraction of salable products.
812 Gas used for other utility operations -- Credit (Major only).
This account shall include concurrent credits for charges which are
made to operating expenses or other accounts of the gas department for
gas consumed from the common system supply for operating and utility
purposes other than uses for which credits are includible in any of the
foregoing accounts. (See account 484, Interdepartmental Sales, for gas
supplied to departments other than the gas utility department.)
812.1 Gas used in utility operations -- Credit (Nonmajor only).
This account shall include concurrent credits for charges which are
made to operating expenses or other accounts of the gas department for
gas from the common system supply used for compressor station fuel or
other purposes. (See account 484, Interdepartmental Sales, for gas
supplied to departments other than the gas utility department.)
813 Other gas supply expenses.
This account shall include the cost of labor, materials used and
expenses incurred in connection with gas supply functions not provided
for in any of the above accounts, including, in the case of Major
companies, research and development expenses.
These accounts are to be used by both transmission and distribution
companies to account for natural gas storage expenses. If the utility
operates both transmission and distribution systems, subaccounts shall
be maintained classifying the expenses to the transmission or
distribution function.
814 Operation supervision and engineering.
A. For Major companies, this account shall include the cost of labor
and expenses incurred in the general supervision and direction of
underground storage operations. Direct supervision of specific
activities such as turning on and shutting off storage wells, compressor
station operations, etc., shall be charged to the appropriate account.
(See operating expense instruction 1.)
B. For Nonmajor companies, this account shall include the cost of
supervision and labor in the operation of storage facilities including
underground storage gas wells, lines, compressors and other equipment of
the underground storage system, and the labor and expense of preparing
and maintaining storage maps and lands records.
1. Operation of other storage facilities.
2. Operation of underground storage system.
(See account 750)
815 Maps and records (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the preparation and maintenance of storage maps and
land records.
Labor:
With respect to land records:
1. Supervising.
2. Abstracting titles to date for extension and renewal of leases.
3. Adjusting land and well rentals.
4. Renewing and extending leases or replacing leases not involving
additional consideration.
5. Transferring, assigning, pooling, and merging leases.
6. Delivering rental checks.
7. Clerical work in maintaining storage land and lease records.
8. Preparing and maintaining lease expiration calendars.
With respect to maps:
9. Supervising.
10. Preparing maps, well location plats, etc.
11. Reproducing maps (blueprints or photostats).
12. Posting and revising maps.
13. Surveying deeds, leases, rights-of-way, well locations, etc., for
map revisions.
14. Maintaining files of maps and tracings.
15. Field checking boundaries, markers, etc. in connection with
preparation of maps.
Materials and expenses (general):
16. Reproduction of land and lease records and maps (blueprints,
photostats, etc.).
17. Drafting materials and supplies.
18. Surveying materials and supplies.
19. Employees' transportation and travel expenses.
816 Wells expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating storage gas wells.
Labor:
1. Supervising.
2. Testing, bailing, swabbing, blowing, and gauging storage wells.
3. Painting signs, etc.
4. Minor upkeep of well roads, fences, etc.
5. Turning storage wells on and off.
6. Moving cleaning out tools between locations.
7. Driving trucks.
Materials and expenses:
8. Gas, gasoline, and oil used in pumping, bailing, heating, and
swabbing.
9. Lumber, nails, and other materials used for repairing old well
roads and fences.
10. Well swabs.
11. Employees' transportation and travel expenses.
12. Freight, express, parcel post, trucking, and other
transportation.
817 Lines expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating underground storage lines.
Labor:
1. Supervising.
2. Walking or patrolling lines.
3. Attending valves, lubricating valves and other equipment, blowing
and cleaning lines and drips, draining water from lines, operating and
cleaning scrubbers, thawing freezes.
4. Taking line pressures, changing pressure charts, operating alarm
gauges.
5. Building and repairing gate boxes, foot bridges, stiles, tool
boxes, etc., used in line operations, erecting line markers and warning
signs, repairing old line roads.
6. Cleaning debris, cutting grass and weeds on rights-of-way.
7. Inspecting and testing not specifically to determine necessity for
repairs.
8. Protecting utility property during work by others.
9. Standby time of emergency crews, responding to fire calls, etc.
10. Locating valve boxes or drip riser boxes.
11. Cleaning and repairing tools used in storage lines operations.
12. Cleaning structures and equipment.
13. Driving trucks.
Materials and expenses:
14. Line markers and warning signs.
15. Lumber, nails, etc., used in building and repairing gate boxes,
foot bridges, stiles, etc.
16. Charts.
17. Scrubber oil.
18. Hand tools.
19. Lubricants, wiping rags, waste, etc.
20. Freight, express, parcel post, trucking and other transportation.
21. Employees' transportation and travel expenses.
22. Janitor and washroom supplies.
23. Utility services: light, water, telephone.
24. Gas used in operations.
818 Compressor station expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating underground storage compressor stations.
Labor:
1. Supervising.
2. Operating and checking engines, equipment, valves, machinery,
gauges, and other instruments, including cleaning, wiping, pol- ishing,
and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel
handling and ash disposal, recording fuel used, and unloading and
storing coal and oil.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing
reports of station operations.
6. Inspecting and testing equipment when not specifically to
determine necessity for repairs or replacement of parts.
7. Pumping drips at the station.
8. Taking dew point readings.
9. Testing water.
10. Cleaning structures housing equipment, cutting grass and weeds,
and minor grading around station.
11. Cleaning and repairing hand tools used in operations.
12. Driving trucks
13. Watching during shut downs.
14. Clerical work at station.
Materials and expenses:
15. Scrubber oil.
16. Lubricants, wiping rags, and waste.
17. Charts and printed forms, etc.
18. Gauge glasses.
19. Chemicals to test water.
20. Water tests and treatment by other than employees.
21. Janitor and washroom supplies, first aid supplies, landscaping
supplies, etc.
22. Employees' transportation and travel expenses.
23. Freight, express, parcel post, trucking, and other
transportation.
24. Utility services: light, water, telephone.
819 Compressor station fuel and power (Major only).
A. This account shall include the cost of gas, coal, oil, or other
fuel, or electricity, used for the operation of underground storage
compressor stations, including applicable amounts of fuel stock
expenses.
B. Records shall be maintained to show the quantity of each type of
fuel consumed or electricity used at each compressor station, and the
cost of such fuel or power. Respective amounts of fuel stock and fuel
stock expenses shall be readily available.
Note: The cost of fuel, except gas, and related fuel stock expenses
shall be charged initially to appropriate fuel accounts carried in
accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed,
and cleared to this account on the basis of fuel used. See accounts 151
and 152 for the basis of fuel costs and includible fuel stock expenses.
820 Measuring and regulating station expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating underground storage measuring and
regulating stations.
Labor:
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc. except gas purchases
and sales.
4. Calculating gas volumes from meter charts except gas purchases and
sales.
5. Adjusting and calibrating measuring equipment, changing meters,
orifice plates, gauges, clocks, etc., not in connection with
construction or maintenance.
6. Testing gas samples, inspecting and testing gas sample tanks and
other meter engineers equipment, determining specific gravity and Btu
content of gas.
7. Inspecting and testing equipment not specifically to determine
necessity for repairs, including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records, preparing reports of
operation, etc.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipe.
13. Inspecting and pumping drips, dewatering manholes and pits,
inspecting sumps, cleaning pits, etc., blowing meter drips.
14. Moving equipment, minor structures, etc., not in connection with
maintenance or construction.
Materials and expenses:
15. Charts and printed forms, stationery and office supplies, etc.
16. Lubricants, wiping rags, waste.
17. Employees' transportation and travel expense.
18. Freight, express, parcel post, trucking and other transportation.
19. Utility services: light, water, telephone.
821 Purification expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating equipment used for purifying,
dehydrating, and conditioning of natural gas in connection with
underground storage operations.
Labor:
1. Supervising.
2. Changing charts on fuel meters.
3. Emptying, cleaning and refilling purifier boxes.
4. Oiling dip sheets of purifier covers.
5. Removing spent oxide to refuse piles.
6. Revivifying oxide.
7. Taking readings of inlet and outlet pressures and temperature.
8. Unloading and storing glycol.
9. Watching station and equipment.
10. Cutting grass and weeds, and minor grading around equipment and
stations.
11. Hauling operating employees, materials, supplies and tools, etc.
12. Inspecting and testing equipment, not specifically to determine
necessity for repairs or replacement of parts.
13. Lubricating equipment, valves, etc.
14. Operating and checking equipment, valves, instruments, etc.
Materials and expenses:
15. Liquid purifying supplies.
16. Iron oxide.
17. Odorizing materials.
18. Charts, printed forms, etc.
19. Employees' transportation and travel expenses in connection with
purification and dehydration operations.
20. Freight, express, parcel post, trucking and other transportation.
21. Gas used in operations.
22. Janitor, washroom and landscaping supplies.
23. Lubricants, wiping rags, waste, etc.
24. Utility services: light, water, telephone.
822 Exploration and development (Major only).
This account shall include expenses of investigation, exploration,
and development of underground storage projects under consideration
which prove not feasible. There also shall be included in this account
the net cost of drilling nonoperative wells within an existing storage
project. (For Major companies see account 183.2, Other Preliminary
Survey and Investigation Charges.)
Note: Include in account 352, Wells, the cost of wells which may be
drilled within a storage project for purposes of pressure observation
rather than for injection or withdrawal of gas.
823 Gas losses.
This account shall include the amounts of inventory adjustments
representing the cost of gas lost or unaccounted for in underground
storage operations due to cumulative inaccuracies of gas measurements or
other causes. (For Major companies, see paragraph G of account 117, Gas
Stored Underground -- Noncurrent.) If, however, any adjustment is
substantial, the utility may, with approval of the Commission, amortize
the amount of the adjustment to this account over future operating
periods.
824 Other expenses (Major only).
This account shall include the cost of labor, material used and
expenses incurred in operating underground storage plant, and other
underground storage operating expenses, not includible in any of the
foregoing accounts, including research, development, and demonstration
expenses.
825 Storage well royalties.
A. This account shall include royalties, rents, and other payments
includible in operating expenses for gas wells and gas land acreage
located within and comprising underground storage projects of the
utility. (See operating expense instruction 3.)
B. The records supporting this account shall be so maintained that
information will be readily available for each storage project, of the
parties to each contract, basis of the charges, and location of wells to
which the royalties or rents of each contract relate.
826 Rents.
This account shall include rents for property of others used in
connection with the storage of gas underground, other than rents and
royalties paid with respect to storage wells and gas lands utilized for
the holding of gas in underground storage. (See operating expense
instruction 3.)
827 Operation supplies and expenses (Nonmajor only).
This account shall include the cost of supplies used and expense
incurred in connection with storage operating functions not provided for
in any of the above accounts, including power and fuel for compressor
stations used in underground storage operations.
1. Supplies used in operation of other storage facilities.
2. Supplies used in operation of underground storage system. (See
account 713.)
830 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of maintenance of underground
storage facilities. Direct field supervision of specific jobs shall be
charged to the appropriate maintenance account. (See operating expense
instruction 1.)
831 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures, the book cost of
which is includible in account 351, Structures and Improvements. (See
operating expense instruction 2.)
832 Maintenance of reservoirs and wells.
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of storage wells, the book cost of
which is included in account 352, Wells, and the maintenance of
reservoirs, the book cost of which is included in account 352.2,
Reservoirs. (See operating expense instruction 2.)
833 Maintenance of lines (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of underground storage lines, the
book cost of which is includible in account 353, Lines. (See operating
expense instruction 2.)
834 Maintenance of compressor station equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 354, Compressor Station Equipment. (See
operating expense instruction 2.)
835 Maintenance of measuring and regulating station equipment (Major
only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 355, Measuring and Regulating Equipment.
(See operating expense instruction 2.)
836 Maintenance of purification equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of purification equipment, the book
cost of which is includible in account 356, Purification Equipment.
(See operating expense instruction 2.)
837 Maintenance of other equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 357, Other Equipment. (See operating
expense instruction 2.)
838 Maintenance of other underground storage plant (Nonmajor only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of plant the book cost of which is
includible in accounts 351 to 357, inclusive, except account 352. (See
operating expense instruction 2.)
839 Maintenance of other storage plant (Nonmajor only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of plant the book cost of which is
includible in accounts 361 to 363, inclusive. (See operating expense
instruction 2.)
840 Operation supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of the operation of other storage
facilities. Direct supervision of specific activities such as operation
of gas holders shall be charged to the appropriate account. (See
operating expense instruction 1.)
841 Operation labor and expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating storage holders and other storage
equipment.
Labor:
1. Supervising.
2. Operating, checking, lubricating, cleaning, and polishing
equipment, machinery, valves, instruments, and other local storage
equipment.
3. Reading meters, gauges and other instruments, changing charts,
preparing operating reports, etc.
4. Pumping inlet and outlet holder drips.
5. Inspecting and testing equipment when not specifically for repairs
or replacement of parts.
6. Cleaning structures and housing equipment, cutting grass and
weeds, and doing minor grading work around structures and equipment.
7. Cleaning and repairing hand tools used for operations, etc.
8. Operating steam lines for heating storage facilities.
Materials and expenses:
9. Charts for pressure gauges and meters, printed forms, etc.
10. Lubricants, wiping rags, waste, etc.
11. Janitor and washroom supplies, land- scaping supplies, etc.
12. Employee travel and transportation expenses.
13. Freight, express, parcel post, trucking, and other
transportation.
14. Utility services: light, water, and telephone.
15. Chemicals.
16. Refrigerants.
17. Research, development, and demonstration expenses.
842 Rents (Major only).
This account shall include rents for property of others used or
operated in connection with other storage operations. (See operating
expense instruction 3.)
842.1 Fuel (Major only).
A. This account shall include the cost of natural gas or other fuel
used in the operation of other storage plant.
B. Concurrent credits offsetting charges to this account for natural
gas used for fuel shall be made to account 812, Gas Used for Other
Utility Operations -- Credit.
842.2 Power (Major only).
This account shall include the cost of electricity consumed for
operation of facilities used in the operation of other storage plant.
842.3 Gas Losses (Major only).
This account shall include the amounts of inventory adjustments
representing the cost of gas lost or unaccounted for in other storage
operations due to shrinkage or other causes.
843.1 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of maintenance of other storage
facilities. Direct field supervision of specific jobs shall be charged
to the appropriate maintenance account. (See operating expense
instruction 1.)
843.2 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures, the book cost of
which is includible in account 361, Structures and Improvements. (See
operating expense instruction 2.)
843.3 Maintenance of gas holders (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of gas holders, the book cost of
which is includible in account 362, Gas Holders. (See operating expense
instruction 2.)
843.4 Maintenance of purification equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of purification equipment, the book
cost of which is includible in account 363, Purification Equipment.
(See operating expense instruction 2.)
843.5 Maintenance of liquefaction equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of liquefaction equipment, the book
cost of which is includible in account 363.1, Liquefaction Equipment.
(See operating expense instruction 2.)
843.6 Maintenance of vaporizing equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of vaporizing equipment, the book
cost of which is includible in account 363.2, Vaporizing Equipment.
(See operating expense instruction 2.)
843.7 Maintenance of compressor equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of compressor equipment, the book
cost of which is includible in account 363.3, Compressor Equipment.
(See operating expense instruction 2.)
843.8 Maintenance of measuring and regulating equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of measuring and regulating
equipment, the book cost of which is includible in account 363.4,
Measuring and Regulating Equipment. (See operating expense instruction
2.)
843.9 Maintenance of other equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment the book cost of which
is includible in account 363.5, Other Equipment. (See operating expense
instruction 2.)
844.1 Operations supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of operations of liquefied natural
gas facilities. Direct supervision of specific activities shall be
charged to the appropriate operations accounts.
844.2 LNG processing terminal labor and expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating liquefied natural gas processing
equipment.
Labor
1. Supervising.
2. Operating, checking, lubricating, cleaning, and polishing
equipment, machinery, valves, instruments, and other processing
equipment.
3. Reading meters, gauges and other instruments, changing charts,
preparing operating reports, etc.
4. Inspecting and testing equipment when not specifically for repairs
or replacement of parts.
5. Cleaning structures housing equipment, cutting grass and weeds,
and doing minor grading work around structures and equipment.
6. Cleaning and repairing hand tools used for operations, etc.
7. Operating offshore facilities such as piers, docks, loading and
unloading arms, water craft, etc.
Materials and expenses
8. Charts for pressure gauges and meters, printed forms, office
supplies, etc.
9. Lubricants, wiping rags, cleaning materials, etc.
10. Janitor and washroom supplies, landscaping supplies, etc.
11. Employee travel and transportation expenses.
12. Freight, express, parcel post, trucking, and other
transportation.
13. Utility services: light, water, and telephone.
14. Chemicals.
15. Refrigerants.
16. Small hand tools.
844.3 Liquefaction processing labor and expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating natural gas liquefaction equipment.
Labor
1. Supervising.
2. Operating, checking, lubricating, cleaning, and polishing
equipment, machinery, valves, instruments, and other processing
equipment.
3. Reading meters, gauges and other instruments, changing charts,
preparing operating reports, etc.
4. Inspecting and testing equipment when not specifically for repairs
or replacement of parts.
5. Cleaning structures housing equipment, cutting grass and weeds,
and doing minor grading work around structures and equipment.
6. Cleaning and repairing hand tools used for operations, etc.
7. Operating offshore facilities such as piers, docks, loading and
unloading arms, water craft, etc.
Materials and expenses
8. Charts for pressure gauges and meters, printed forms, office
supplies, etc.
9. Lubricants, wiping rags, cleaning materials, etc.
10. Janitor and washroom supplies, landscaping supplies, etc.
11. Employee travel and transportation expenses.
12. Freight, express, parcel post, trucking, and other
transportation.
13. Utility services: light, water, and telephone.
14. Chemicals.
15. Refrigerants.
16. Small hand tools.
844.4 LNG transportation labor and expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating LNG transportation equipment.
Labor
1. Supervision.
2. Operating LNG maritime tankers, LNG barges, LNG tank trucks and
other LNG transportation equipment.
3. Cleaning and lubricating equipment.
4. Inspecting and testing equipment.
Materials and expenses
5. Charts, printed forms, office supplies, etc.
6. Dry dock charges.
7. Lubricants, wiping rags, cleaning materials, etc.
8. Employee's transportation travel and temporary housing expenses.
844.5 Measuring and regulating labor and expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating, measuring and regulating stations in
connection with liquefied natural gas operations.
Labor
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc., except gas purchases
and sales.
4. Calculating gas volumes from meter charts, except gas purchases
and sales.
5. Adjusting and calibrating measuring equipment, changing meters,
orifice plates, gauges, clocks, etc., not in connection with
construction or maintenance.
6. Testing gas samples, determining specific gravity and Btu content
of gas.
7. Inspecting and testing equipment not specifically to determine
necessity for repairs including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records, preparing records of
operations, etc.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipe.
13. Inspecting and pumping drips, dewatering manholes and pits,
inspecting sumps, cleaning pits, blowing meter drips, etc.
14. Moving equipment, minor structures, etc., not in connection with
maintenance or construction.
Materials and expenses
15. Charts and printed forms.
16. Lubricants, wiping rags, waste.
17. Employees' transportation and travel expense.
18. Freight, express, parcel post, trucking and other transportation.
19. Utility services: light, water, telephone.
844.6 Compressor station labor and expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred, including fuel and power, in operating compressor
stations in connection with liquefied natural gas operations.
Labor
1. Supervising.
2. Operating and checking engines, equipment valves, machinery,
gauges, and other instruments, including cleaning, wiping, polishing,
and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel
handling, recording fuel used, etc.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing
reports of station operations.
6. Pumping drips at the station.
7. Taking dew point readings.
8. Testing water.
9. Cleaning structures housing equipment, cutting grass and weeds,
and minor grading around station.
10. Cleaning and repairing hand tools used in operations.
11. Driving trucks.
12. Watching during shutdowns.
13. Clerical work at station.
Materials and expenses
14. Scrubber oil.
15. Lubricants, wiping rags, waste.
16. Charts and printed forms, etc.
17. Gauge glasses.
18. Chemicals to treat water.
19. Water tests and treatment by other than employees.
20. Janitor and washroom supplies, first aid supplies, landscaping
supplies, etc.
21. Employees' transportation and travel expenses.
22. Freight, express, parcel post, trucking, and other
transportation.
23. Utility services: light, water, telephone.
844.7 Communication system expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in connection with the operation of liquefied natural
gas communications facilities, such as radio, telephone, microwave and
other communication systems, including payments to others for
communications services.
Labor
1. Supervising.
2. Operating switchboards, radio equipment, power generators,
microwave equipment, etc. (except general office switchboards).
3. Tagging telephone poles.
4. Testing and replacing telephone batteries, radio tubes, etc.
5. Cutting weeds and grass along telephone rights-of-way and around
structures and equipment.
6. Changing radio frequencies.
7. Securing FCC authorization to change frequencies.
8. Taking FCC radio operator tests.
9. Transferring mobile radios between vehicles and/or vessels.
10. Changing locations of telephones and other communications
equipment not in connection with maintenance or construction.
11. Inspecting and testing not specifically to determine necessity
for repairs.
12. Cleaning and lubricating equipment.
13. Cleaning structures housing equipment.
Materials and expenses
14. Payments to others for communications services.
15. Telephone batteries, radio tubes and other electronic components.
16. Radio crystals and other materials used in changing radio
frequencies.
17. Lubricants, wiping rags, and waste.
18. Employees' transportation and travel expenses.
19. Freight, express, parcel post, trucking and other transportation.
844.8 System control and load dispatching (Major only).
This account shall include the cost of labor and expenses incurred in
dispatching and controlling the supply and flow of liquefied gas and
vaporized gas prior to introduction of such vaporized gas into the
utility's transmission or distribution system.
Labor
1. Supervising.
2. Analysis of pressures for irregularities, as received.
3. Collecting pressures by telephone and radio.
4. Controlling mixture of various gases to maintain proper Btu
content.
5. Correspondence and records, typing and maintaining files.
6. Controlling inputs and withdrawals of liquefied gas for
processing.
7. Instructing field men to increase or decrease pressures at
regulators.
8. Maintaining pressures at compressor stations, key line junctions
and regulating stations to divide the available gas during heavy demand
periods.
9. Maintaining pressure log sheets.
10. Maintaining proper compression ratios at compressor stations,
consistent with economical operations.
11. Maintaining lowest necessary line pressures consistent with
satisfactory service.
12. Requesting pressure changes at compressor stations, regulating
stations, and key line junctions.
13. Rerouting gas during emergencies and planned shutdowns.
Materials and expenses
14. Consultants' fees and expenses.
15. Meals, traveling and incidental expenses in connection with
system load dispatching.
16. Office supplies, stationery and printed forms.
17. Transportation: company and rental vehicles.
18. Utility services: light, water, telephone.
845.1 Fuel (Major only).
A. This account shall include the cost of gas or other fuel used for
the operation of liquefied natural gas terminaling and processing
facilities, except compressor station fuel.
B. Concurrent credits offsetting charges to this account for natural
gas used for fuel shall be made to account 812, Gas Used for Other
Utility Operations -- Credit.
845.2 Power (Major only).
This account shall include the cost of purchased power used in
operation of liquefied natural gas processing facilities, except
compressor station power.
845.3 Rents (Major only).
This account shall include rents for property of others used,
occupied or operated in connection with liquefied natural gas processing
operations. (See operating expense instruction 3.)
845.4 Demurrage charges (Major only).
This account shall include demurrage charges incurred by the utility
relative to LNG shipments received or processed by the utility.
845.5 Wharfage receipts -- Credit (Major only).
This account shall include wharfage receipts received or receivable
from LNG shippers or other parties relative to LNG shipments received or
processed by the utility.
845.6 Processing of liquefied or vaporized gas by others (Major
only).
A. This account shall include amounts paid to others for the
processing of liquefied or vaporized gas of the utility.
B. Records supporting this account shall be so maintained that there
shall be readily available for each agreement, the name of the other
party, Mcf or Btu, as appropriate, of gas delivered to the other party
for processing and the Mcf or Btu, as appropriate, of gas received back
by the utility after processing, points of delivery to and receipt of
gas from the other party, amount and basis of charges for the processing
service.
Note: If in connection with any gas delivered to another for
processing such other party also processes the gas for extraction of
gasoline or other salable products, credits attributable to the products
so extracted shall be made to account 491, Revenues from Natural Gas
Processed by Others, to the end that amounts recorded in this account
shall only be charges for processing other than for extraction of
salable products.
846.1 Gas losses (Major only).
This account shall include the amounts of inventory adjustments
representing the cost of gas lost or unaccounted for in liquefied
natural gas operations due to cumulative inaccuracies of gas
measurements or other causes. (See paragraph E of account 164.3,
Liquefied Natural Gas Held for Processing.) If, however, any adjustment
is substantial, the utility may, with approval of the Commission,
amortize the amount of the adjustment to this account over future
operating periods.
846.2 Other expenses (Major only).
This account shall include the cost of labor, materials used, and
expenses incurred in operating liquefied natural gas plant not
includible elsewhere.
847.1 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of maintenance of liquefied
natural gas terminaling and processing facilities. Direct field
supervision of specific jobs shall be charged to the appropriate
maintenance accounts. (See operating expense instruction 1.)
847.2 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures and improvements, the
book cost of which is included in account 364.2, Structures and
Improvements. (See operating expense instruction 2.)
847.3 Maintenance of LNG processing terminal equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of LNG terminal processing
equipment, the book cost of which is included in account 364.3, LNG
Processing Terminal Equipment. (See operating expense instruction 2.)
847.4 Maintenance of LNG transportation equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of transportation equipment, the
book cost of which is included in account 364.4, LNG Transportation
Equipment. (See operating expense instruction 2.)
847.5 Maintenance of measuring and regulating equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of measuring and regulating
equipment, the book cost of which is included in account 364.5,
Measuring and Regulating Equipment. (See operating expense instruction
2.)
847.6 Maintenance of compressor station equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of compressor station equipment,
the book cost of which is included in account 364.6, Compressor Station
Equipment. (See operating expense instruction 2.)
847.7 Maintenance of communication equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of communication equipment, the
book cost of which is included in account 364.7, Communication
Equipment. (See operating expense instruction 2.)
847.8 Maintenance of other equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is included in account 364.8, Other Equipment. (See operating
expense instruction 2.)
850 Operation supervision and engineering.
A. For Major companies, this account shall include the cost of labor
and expenses incurred in the general supervision and direction of the
operation of transmission facilities. Direct supervision of specific
activities such as operation of transmission lines, compressor stations,
etc. shall be charged to the appropriate account. (See operating
expense instruction 1.)
B. For Nonmajor companies, this account shall include the cost of
supervision and labor in the operation of lines, compressor stations,
and other equipment of the transmission system.
1. Load dispatching labor.
2. Transmission communication system labor.
3. Compressor station labor.
4. Mains labor.
5. Measuring and regulating station labor.
6. Miscellaneous labor.
851 System control and load dispatching (Major only).
This account shall include the cost of labor and expenses incurred in
dispatching and controlling the supply and flow of gas through the
system.
Labor:
1. Supervising.
2. Analyses of pressures for irregularities, as received.
3. Collecting pressures by telephone and radio.
4. Controlling mixture of various gases to maintain proper Btu
content.
5. Correspondence and records, typing and maintaining files.
6. Controlling production and storage inputs and withdrawals.
7. Instructing field men to increase or decrease pressures at
regulators.
8. Maintaining pressures at compressor stations, key line junctions
and regulating stations to divide the available gas during heavy demand
periods.
9. Maintaining pressure log sheets.
10. Maintaining proper compression ratios at compressor stations,
consistent with economical operations.
11. Maintaining lowest necessary line pressures consistent with
satisfactory service.
12. Maintaining well operation record by well classification.
13. Requesting pressure changes at compressor stations, regulating
stations, and key line junctions.
14. Rerouting gas during emergencies and planned shut downs.
Materials and expenses:
15. Consultants' fees and expenses.
16. Meals, traveling, and incidental expenses in connection with
system load dispatching.
17. Office supplies, stationery and printed forms.
18. Transportation: company and rental vehicles.
19. Utility services: light, water, telephone.
852 Communication system expenses (Major only).
A. This account shall include the cost of labor, materials used and
expenses incurred in connection with the operation of transmission
communications facilities, such as radio and telephone communications
systems, including payments to others for communications services for
transmission and load dispatching operations.
B. Credits shall be made to this account and charges made to
production, distribution and other gas utility functions and to other
utility departments for equitable portions of transmission
communications expenses attributable to use of transmission
communications facilities other than in connection with gas transmission
and load dispatching operation.
Labor:
1. Supervising.
2. Operating switchboards, radio equipment, power generators,
microwave equipment, etc. (except general office switchboards.)
3. Tagging telephone poles.
4. Testing and replacing telephone batteries, radio tubes, etc.
5. Cutting weeds and grass along telephone rights-of-way and around
structures and equipment.
6. Changing radio frequencies.
7. Securing FCC authorization to change frequencies.
8. Taking FCC radio operator tests.
9. Transferring mobile radios between vehicles.
10. Changing locations of telephones and other communications
equipment not in connection with maintenance or construction.
11. Inspecting and testing not specifically to determine necessity
for repairs.
12. Cleaning and lubricating equipment.
13. Cleaning structures housing equipment.
Materials and expenses:
14. Payments to others for communications services.
15. Telephone batteries, radio tubes, etc.
16. Radio crystals and other materials used in changing radio
frequencies.
17. Lubricants, wiping rags, and waste.
18. Employees' transportation and travel expenses.
19. Freight, express, parcel post, trucking, and other
transportation.
853 Compressor station labor and expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred (other than fuel and power) in operating transmission
compressor stations.
Labor:
1. Supervising.
2. Operating and checking engines, equipment valves, machinery,
gauges, and other instruments, including cleaning, wiping, pol- ishing,
and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel
handling and ash disposal, recording fuel used, and unloading and
storing coal and oil.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing
reports of station operations.
6. Inspecting and testing equipment not specifically to determine
necessity for repairs.
7. Pumping drips at the station.
8. Taking dew point readings.
9. Testing water.
10. Cleaning structures housing equipment, cutting grass and weeds,
and minor grading around station.
11. Cleaning and repairing hand tools used in operations.
12. Driving trucks.
13. Watching during shut downs.
14. Clerical work at station.
Materials and expenses:
15. Scrubber oil.
16. Lubricants, wiping rags, and waste.
17. Charts and printed forms, etc.
18. Gauge glasses.
19. Chemicals to treat water.
20. Water tests and treatment by other than employees.
21. Janitor and washroom supplies, first aid supplies, landscaping
supplies, etc.
22. Employees' transportation and travel expenses.
23. Freight, express, parcel post, trucking, and other
transportation.
24. Utility services: light, water, telephone.
853.1 Compressor station fuel and power (Nonmajor only).
A. This account shall include the cost of gas, or other fuel or
electricity, used for the operation of transmission compressor stations.
B. Records shall be maintained to show the Mcf of gas or quantity of
each other type of fuel consumed or electricity used at each compressor
station, and the cost of such fuel or power.
854 Gas for compressor station fuel (Major only).
A. This account shall include the cost of gas used for the operation
of transmission compressor stations.
B. Records shall be maintained to show the Mcf of gas consumed at
each compressor station, and the cost of such gas.
855 Other fuel and power for compressor stations (Major only).
A. This account shall include the cost of coal, oil, and other fuel,
or electricity, used for the operation of transmission compressor
stations, including applicable amounts of fuel stock expenses.
B. Records shall be maintained to show the quantity of each type of
fuel consumed or electricity used at each compressor station, and the
cost of such fuel or power. Respective amounts of fuel stock and fuel
stock expenses shall be readily available.
Note: The cost of fuel, includible in this account, and related fuel
stock expenses shall be charged initially to appropriate fuel accounts
carried in accounts 151, Fuel Stock, and 152, Fuel Stock Expenses
Undistributed, and cleared to this account on the basis of fuel used.
See accounts 151 and 152 for the basis of fuel costs and includible fuel
stock expenses.
856 Mains expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating transmission mains.
Labor:
1. Supervising.
2. Walking or patrolling lines.
3. Attending valves, lubricating valves and other equipment, blowing
and cleaning lines and drips, draining water from lines, operating and
cleaning scrubbers, thawing freezes.
4. Taking line pressures, changing pressure charts, operating alarm
gauges.
5. Building and repairing gate boxes, foot bridges, stiles, etc.,
used in line operations, erecting line markers and warning signs,
repairing old line roads.
6. Cleaning debris, cutting grass and weeds on rights-of-way.
7. Inspecting and testing not specifically to determine necessity for
repairs.
8. Protecting utility property during work by others.
9. Standby time of emergency crews, responding to fire calls, etc.
10. Locating valve boxes or drip riser boxes.
11. Cleaning and repairing tools used in mains operations, making
tool chests, etc.
12. Cleaning structures and equipment.
13. Driving trucks.
Materials and expenses:
14. Line markers and warning signs.
15. Lumber, nails, etc., used in building and repairing gate boxes,
foot bridges, stiles, etc.
16. Charts.
17. Scrubber oil.
18. Hand tools.
19. Lubricants, wiping rags, waste, etc.
20. Freight, express, parcel post, trucking and other transportation.
21. Employees' transportation and travel expenses.
22. Janitor and washroom supplies.
23. Utility services: light, water, telephone.
24. Gas used in mains operations.
857 Measuring and regulating station expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating transmission measuring and regulating
stations.
Labor:
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc., except gas purchases
and sales.
4. Calculating gas volumes from meter charts, except gas purchases
and sales.
5. Adjusting and calibrating measuring equipment, changing meters,
orifice plates, gauges, clocks, etc. not in connection with
construction or maintenance.
6. Testing gas samples, inspecting and testing gas sample tanks and
other meter engineers' equipment, determining specific gravity and Btu
content of gas.
7. Inspecting and testing equipment not specifically to determine
necessity for repairs including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records, preparing reports of
operations, etc.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipe.
13. Inspecting and pumping drips, dewatering manholes and pits,
inspecting sumps, cleaning pits, etc., blowing meter drips.
14. Moving equipment, minor structures, etc., not in connection with
maintenance or construction.
Materials and expenses:
15. Charts and printed forms.
16. Lubricants, wiping rags, waste.
17. Employees' transportation and travel expense.
18. Freight, express, parcel post, trucking and other transportation.
19. Utility services: light, water, telephone.
857.1 Operation supplies and expenses (Nonmajor only).
This account shall include the cost of supplies used and expenses
incurred in connection with transmission system operating functions not
provided for in any of the above accounts.
1. Consultants' fees and expenses.
2. Payments to others for transmission communications services.
3. Telephone batteries, radio tubes, radio crystals, etc.
4. Scrubber oil.
5. Charts and printed forms.
6. Gauge glasses.
7. Water treatment chemicals.
8. Water tests and treatment other than by employees.
9. Line markers and warning signs.
10. Lumber, nails, etc., used in building and repairing gate boxes,
foot bridges, stiles, etc.
11. Lubricants, wiping rags, waste, etc.
12. Hand tools.
13. Freight, express, parcel post, trucking and other transportation.
14. Employees' transportation and travel expenses.
15. Janitor and washroom supplies, first aid supplies, etc.
16. Utility services; light, water, telephone.
858 Transmission and compression of gas by others.
A. This account shall include amounts paid to others for the
transmission and compression of gas of the utility.
B. Records supporting this account shall be so maintained that there
shall be readily available for each agreement, name of other party, Mcf
of gas delivered to the other party for transmission or compression and
the Mcf of gas received back by the utility after transmission or
compression, points of delivery to and receipt of gas from other party,
amount and basis of charges for the transmission or compression service.
Note: If in connection with any gas delivered to another for
transmission or compression such other party also processes the gas for
extraction of gasoline or other salable products, credits attributable
to the products so extracted shall be made to account 491, Revenues from
Natural Gas Processed by Others, to the end that amounts recorded in
this account shall only be charges for transportation or compression
service.
859 Other expenses (Major only).
This account shall inlcude the cost of labor, material used and
expenses incurred in operating transmission system equipment and other
transmission system expenses not includible in any of the foregoing
accounts, including research, development, and demonstration expenses.
860 Rents.
This account shall include rents for property of others used,
occupied or operated in connection with the operation of the
transmission system. Include herein rentals paid for regulator sites,
railroad crossings, rights-of-way, annual payments to governmental
bodies and others for use of public or private lands, and reservations
for rights-of-way. (See operating expense instruction 3.)
861 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of maintenance of transmission
system facilities. Direct field supervision of specific jobs shall be
charged to the appropriate maintenance accounts. (See operating expense
instruction 1.)
862 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures, the book cost of
which is includible in account 366, Structures and Improvements. (See
operating expense instruction 2.)
863 Maintenance of mains.
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of mains, the book cost of which is
includible in account 367, Mains. (See operating expense instruction
2.)
1. Supervising.
2. Electrolysis and leak inspection.
3. Installing and removing temporary lines, when necessitated by
maintenance.
4. Lamping and watching while making repairs.
5. Lowering and changing location of lines, when the same pipe is
used.
6. Protecting lines from fires, floods, landslides, etc.
7. Rocking creek crossings.
864 Maintenance of compressor station equipment.
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 368, Compressor Station Equipment. (See
operating expense instruction 2.)
865 Maintenance of measuring and regulating station equipment (Major
only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 369, Measuring and Regulating Station
Equipment. (See operating expense instruction 2.)
866 Maintenance of communication equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 370, Communication Equipment. (See
operating expense instruction 2.)
867 Maintenance of other equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 371, Other Equipment. (See operating
expense instruction 2.)
868 Maintenance of other plant (Nonmajor only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures and equipment, the
book cost of which is includible in accounts 366, 369, 370, and 371.
(See operating expense instruction 2.)
870 Operation supervision and engineering.
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of distribution system operations.
Direct supervision of specific activities such as load dispatching
(Major only), mains operation, removing and resetting meters, etc.,
shall be charged to the appropriate account. (For Major companies, see
operating expense instruction 1.)
871 Distribution load dispatching (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in dispatching and controlling the supply and flow of
gas through the distribution system.
Labor:
1. Supervising.
2. Analyzing pressures for irregularities.
3. Collecting pressures by telephone and radio.
4. Controlling mixture of various gases to maintain proper Btu
content.
5. Correspondence and records, typing and maintaining files.
6. Controlling gas-make and inputs to distribution system.
7. Maintaining pressures at key points to divide the available gas
during heavy demand periods.
8. Maintaining pressure log sheets.
9. Maintaining lowest necessary line pressures consistent with
satisfactory service.
10. Rerouting gas during emergencies and planned shut downs.
Materials and expenses:
11. Consultants' fees and expenses.
12. Meals, traveling, and incidental expenses.
13. Office supplies, stationery and printed forms.
14. Transportation: company and rented vehicles.
15. Utility services: light, water, telephone.
872 Compressor station labor and expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating distribution compressor stations.
Labor:
1. Supervising.
2. Operating and checking engines, equipment valves, machinery,
gauges, and other instruments, including cleaning, wiping, pol- ishing,
and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel
handling and ash disposal, recording fuel used, and unloading and
storing coal and oil.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing
reports of station operations.
6. Inspecting and testing equipment and instruments when not
specifically to determine necessity for repairs or replacement of parts.
7. Pumping drips at the station.
8. Taking dew point readings.
9. Testing water.
10. Cleaning structures housing equipment, cutting grass and weeds,
and doing minor grading around station.
11. Cleaning and repairing hand tools used in operations.
12. Driving trucks.
13. Watching during shut downs.
14. Clerical work at station.
Materials and expenses:
15. Scrubber oil.
16. Lubricants, wiping rags, and waste.
17. Charts and printed forms, etc.
18. Gauge glasses.
19. Chemicals to test water.
20. Water tests and treatment by other than employees.
21. Janitor and washroom supplies, first aid supplies, landscaping
supplies, etc.
22. Employees' transportation and travel expenses.
23. Freight, express, parcel post, trucking, and other
transportation.
24. Utility services: light, water, telephone.
873 Compressor station fuel and power (Major only).
A. This account shall include the cost of gas, coal, oil, or other
fuel, or electricity, used for the operation of distribution compressor
stations, including applicable amounts of fuel stock expenses.
B. Records shall be maintained to show the quantity of each type of
fuel consumed or electricity used at each compressor station, and the
cost of such fuel or power. Respective amounts of fuel stock and fuel
stock expenses shall be readily available.
Note: The cost of fuel, except gas, and related fuel stock expenses
shall be charged initially to appropriate fuel accounts carried in
accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed,
and cleared to this account on the basis of fuel used. See accounts 151
and 152 for the basis of fuel costs and includible fuel stock expenses.
874 Mains and services expenses.
This account shall include the cost of labor, materials used and
expenses incurred in operating distribution system mains and services.
Labor (Major only):
1. Supervising.
2. Walking or patrolling lines.
3. Attending valves, lubricating valves and other equipment, blowing
and cleaning lines and drips, draining water from lines, thawing
freezes.
4. Taking line pressures, changing pressure charts, operating alarm
gauges.
5. Building and repairing gate boxes, foot bridges, stiles, etc.
used in distribution mains operations, erecting line markers and warning
signs, etc.
6. Cleaning debris, cutting grass and weeds on rights-of-way.
7. Inspecting and testing equipment not specifically to determine
necessity for repairs.
8. Protecting utility property during work by others.
9. Standby time of emergency crews, responding to fire calls, etc.
10. Locating and inspecting valve boxes or drip riser boxes, service
lines, mains, etc.
11. Cleaning and repairing tools used in mains operations, making
tool boxes, etc.
12. Cleaning structures and equipment.
13. Driving trucks used in mains and service operations.
14. Making routine leak survey.
15. Oil fogging.
Labor (Nonmajor only):
1. Mains and services labor.
2. Pumping station labor.
3. Measuring and regulating station labor.
Materials and Expenses (Major and Nonmajor):
1. Line markers and warning signs.
2. Lumber, nails, etc., used in building and repairing gate boxes
(foot bridges, stiles, tool boxes, etc.) (Major only).
3. Charts and printed forms.
4. Scrubber oils.
5. Hand tools.
6. Lubricants, wiping rags, waste, etc.
7. Freight, express, parcel post, trucking and other transportation.
8. Uniforms (Major only).
9. Employee transportation and travel expenses (Major only).
10. Janitor and washroom supplies (Major only).
11. Utility services: light, water, telephone (Major only).
12. Gas used in mains operation (Major only).
13. Oil for fogging.
875 Measuring and regulating station expenses -- General (Major
only).
This account shall include the cost of labor, materials used and
expenses incurred in operating general distribution measuring and
regulating stations.
Labor:
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc. except purchases and
sales.
4. Calculating gas volumes from meter charts, except gas purchases
and sales.
5. Adjusting and calibrating measuring equipment, changing meters,
orifice plates, gauges, clocks, etc.
6. Taking and testing gas samples, inspecting and testing valves,
regulators, gas sample tanks and other meter engineers' equipment,
determining specific gravity and Btu content of gas.
7. Inspecting and testing equipment and instruments not specially to
determine necessity for repairs, including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipe.
13. Inspecting and pumping drips, dewatering manholes and pits,
inspecting sumps, cleaning pits, blowing meter drips, etc.
14. Moving equipment, minor structures, etc., not in connection with
maintenance or construction.
Materials and expenses:
15. Charts and printed forms, stationery and office supplies, etc.
16. Lubricants, wiping rags, waste.
17. Uniforms.
18. Employee transportation and travel expenses.
19. Freight, express, parcel post, trucking and other transportation.
20. Utility services: light, water, telephone.
876 Measuring and regulating station expenses -- Industrial (Major
only).
This account shall include the cost of labor, materials used and
expenses incurred in operating large measuring and regulating stations
located on local distribution systems to serve specific commercial and
industrial customers.
(See account 875 for items.)
877 Measuring and regulating station expenses -- City gate check
stations (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in operating measuring and regulating stations used to
measure and regulate the receipt of gas at entry points to distribution
systems.
Note: Pipe line companies shall include in the transmission
functional classification city gate and main line industrial measuring
and regulating stations, except that where pipe line companies measure
deliveries of gas at entry points to their own distribution systems,
they shall have the option, if consistently observed, of including such
stations either in the transmission or distribution function for
accounting purposes.
(See account 875 for items.)
878 Meter and house regulator expenses.
This account shall include the cost of labor, materials used and
expenses incurred in connection with removing, resetting, changing,
testing, and serv- icing customer meters and house regulators.
Labor:
(a) Removing, reinstalling, and changing or exchanging customer
meters and house regulators:
1. Initiating or terminating service, including incidental meter
reading (Major only).
2. Periodic replacement of meters and house regulators because of age
(Major only).
3. Changing or exchanging meters and house regulators because of
complaints or removal for inspection (Major only).
4. Resetting meters on existing connections (Major only).
5. Handling meters and house regulators to and from customer premises
and meter shop (Major only).
6. Listing, tagging, and placing meter labels, etc., for removed and
reset meters (Major only).
7. Changing position of meters or house regulators on the same
premises (Major only).
8. Installing or removing blank linings (Major only).
9. Unproductive calls, etc (Major only).
(b) Turning on and turning off meters, except for failures of
customers to pay bills:
10. Turning on meters, including necessary time to insure that gas
lines are proper to use and that appliances are in usable condition
(Major only).
11. Turning off meters including time to make safety precautions
(Major only).
(c) Other:
12. Supervising (Major only).
13. Clerical work on meter history and associated equipment record
cards, test cards, and reports.
14. Handling and recording meters for stock.
15. Inspecting and testing meters and house regulators.
16. Inspecting and adjusting meter testing equipment.
17. Driving trucks used in meter operations.
Materials and expenses:
18. Meter locks and seals.
19. Lubricants, wiping rags, waste, etc.
20. Uniforms (Major only).
21. Freight, express, parcel post, trucking, and other
transportation.
22. Utility services: light, water, telephone, heating.
23. Office supplies, stationery and printing.
24. Employees' transportation expenses.
25. Janitor, washroom, first aid supplies, etc.
Note: The cost of the first setting of a meter or house regulator
shall be charged to account 382, Meter Installations, or account 384,
House Regulator Installations, as appropriate.
879 Customer installations expenses.
A. This account shall include the cost of labor, materials used and
expenses incurred in work on customer premises other than expenses
includible in account 878, Meter and House Regulator Expenses, including
the cost of servicing customer-owned appliances when the cost of such
work is borne by the utility.
B. Damage to customer equipment by employees of the utility whether
incidental to the work or the result of negligence, shall be charged to
the job on which the employee was engaged at the time of damage.
Labor:
1. Supervising (Major only).
2. Altering customer-owned service extensions or meter connections
(Major only).
3. Investigating and correcting pressure difficulties or stoppages in
customer-owned piping.
4. Adjusting and repairing burner pilots because of impurities in the
gas or failure of the distribution system (Major only).
5. Oiling or spraying noisy customer meters (Major only).
6. Investigating and stopping gas leaks on customers' premises caused
by defective meter, customer-owned piping, or customer appliances (Major
only).
7. Inspecting new installations to determine that the customers'
equipment and piping are properly installed and connected.
8. Consolidating meter installations, without change of size, due to
elimination of separate meters for different service classifications.
9. Investigating and adjusting complaints of service on customers'
premises (Major only).
10. Gas load surveys including the incidental preparations and
replacement of meters.
11. Unproductive calls (Major only).
12. Stenographic and clerical work (Major only).
13. Janitorial services, etc (Major only).
14. Installing demand or test meters.
15. Inspecting, cleaning, repairing and adjusting customer-owned
appliances for domestic, industrial, or commercial use, including house
heating furnaces and other space heating appliances, hotel and
restaurant appliances.
16. Replacing defective parts in customer-owned appliances and
salvaging reusable appliance parts.
Materials and expenses:
17. Lubricants, wiping rags, waste, etc.
18. Uniforms.
19. Replacement parts for appliances.
20. Office supplies, printing and station- ery.
21. Janitor, washroom, first aid supplies, etc.
22. Employees' transportation and travel expenses.
23. Utility services: light, water, telephone.
Note: Amounts billed customers for any work, the cost of which is
charged to this account, shall be credited to this account. Any excess
over costs resulting therefrom shall be transferred to account 488,
Miscellaneous Service Revenues.
880 Other expenses (Major only).
This account shall include the cost of distribution maps and records,
distribution office expenses, and the cost of labor and materials used
and expenses incurred in distribution systems operations not provided
for elsewhere, including the expenses of operating street lighting
systems and research, development, and demonstration expenses.
880.1 Miscellaneous distribution expenses (Nonmajor only).
This account shall include the cost of labor, materials used and
expenses incurred, general distribution office work, preparation and
maintenance of distribution maps and records, and other expenses not
provided for elsewhere, including expenses of operating any street
lighting systems.
881 Rents.
This account shall include rents for property of others used,
occupied or operated in connection with the operation of the
distribution system. Include herein rentals paid for regulator sites,
railroad crossings, rights-of-way, annual payments to governmental
bodies and others for use of public or private lands, and reservations
for rights-of-way. (See operating expense instruction 3.)
885 Maintenance supervision and engineering (Major only).
This account shall include the cost of labor and expenses incurred in
the general supervision and direction of maintenance of distribution
system facilities. Direct field supervision of specific jobs shall be
charged to the appropriate maintenance accounts. (See operating expense
instruction 1.)
886 Maintenance of structures and improvements (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures, the book cost of
which is includible in account 375, Structures and Improvements. (See
operating expense instruction 2.)
887 Maintenance of mains (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of distribution mains, the book
cost of which is includible in account 376, Mains. (See operating
expense instruction 2.)
1. Supervising.
2. Trenching, backfilling, and breaking and restoring pavement in
connection with the installation of leak or reinforcing clamps.
3. Work performed as the result of municipal improvements, such as
street widening, sewers, etc., where the gas mains are not retired.
4. Municipal inspections relating to maintenance work.
5. Other work of the following character:
a. Locating leaks incident to maintenance.
b. Cutting off mains without replacement. (Minor cuts not retired.)
c. Repairing leaking joints.
d. Repairing broken mains.
e. Repairing leaks on main drip riser or valve test pipe.
f. Bringing main valve box, main drip riser box, valve test pipe box,
or pressure pipe roadway box up to grade.
g. Cleaning, repainting, coating, and wrapping exposed mains.
h. Repacking main valves.
i. Locating and clearing gas main faults.
j. Lowering and changing location of mains.
k. Trenching, backfilling, cutting-in or removal of pipe not retired
in connection with the installation of leak clamps, valves, or drips.
l. Watching and lamping open cuts associated with maintenance.
m. Restoration of permanent pavement in connection with work
chargeable to maintenance.
n. Emergency stand-by time associated with maintenance.
o. Repairing sewers, drains, walls, etc., when damaged by maintenance
work.
p. Making electrolysis tests to maintain life of plant.
q. Repairing property of others damaged by maintenance work.
888 Maintenance of compressor station equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 377, Compressor Station Equipment. (See
operating expense instruction 2.)
889 Maintenance of measuring and regulating station equipment --
General (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 378, Measuring and Regulating Station
Equipment -- General. (See operating expense instruction 2.)
890 Maintenance of measuring and regulating station equipment --
Industrial (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 385, Industrial Measuring and Regulating
Station Equipment. (See operating expense instruction 2.)
891 Maintenance of measuring and regulating station equipment -- City
gate check stations (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of equipment, the book cost of
which is includible in account 379, Measuring and Regulating Station
Equipment -- City Gate Check Stations. (See operating expense
instruction 2.)
892 Maintenance of services (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of serv- ices, the book cost of
which is includible in account 380, Services. (See operating expense
instruction 2.)
1. Supervising.
2. Testing pipe for leaks and condition of wrapping.
3. Testing for, locating, and clearing trouble on company maintained
services.
4. Inspecting and testing after repairs have been made.
5. Reporting on the condition of gas serv- ices to determine the need
for repairs.
6. Making minor repairs and changes.
7. Rearranging and changing the location of services not retired.
8. Repairing service valves for reuse.
9. Stopping leaks on service pipes and drip risers.
10. Lowering and raising curb boxes to grade.
11. Replacing less than a complete service when not retired.
12. Installing fittings, valves, drips, frost protection devices, or
replacing similar items on existing services.
13. Cutting and replacing pavement, pavement base and sidewalks in
connection with maintenance work.
14. Restoring condition of services damaged by fire, storm, leakage,
flood, accident or other casualties.
15. Repairing property of others damaged by maintenance work.
16. Transferring services in connection with the installation of new
mains.
17. Installing, maintaining, and removing temporary facilities to
prevent the interruption of service.
18. Converting low pressure gas distribution service to medium or
high pressure service.
19. Relocating and rerouting gas service temporarily during
alterations of buildings.
20. Performing work resulting from municipal improvements, such as
street widening, sewers, etc.
21. Replacing service valve box or drip riser box.
22. Installing, removing or replacing service valve, drip pot, or
drip riser.
23. Repacking service valve.
892.1 Maintenance of lines (Nonmajor only).
This account shall include the cost of labor, materials and supplies
used and expenses incurred in the maintenance of plant the book cost of
which is includible in accounts 376, 377, 378, 379, 380, and 385. (See
operating expense instruction 2.)
Mains:
1. Trenching, backfilling, and breaking and restoring pavement in
connection with the installation of leak or reinforcing clamps.
2. Work performed as the result of municipal improvements such as
street widening, sewers, etc., where the gas mains are not retired.
3. Municipal inspections relating to maintenance work.
4. Other work of the following character:
a. Locating leaks incident to maintenance.
b. Cutting off mains without replacement. (Minor cuts not retired.)
c. Repairing broken mains, leaking joints, leaking drip riser, etc.
d. Bringing main valve box, main drip riser box, valve test pipe box,
or pressure pipe roadway box up to grade.
e. Cleaning, repainting, coating, and wrapping exposed mains.
f. Repacking main valves.
g. Lowering and changing location of mains.
h. Trenching, backfilling, cutting-in or removal of pipe not retired
in connection with the installation of leak clamps, valves, or drips.
i. Restoration of permanent pavement in connection with work
chargeable to maintenance.
j. Emergency stand-by time associated with maintenance.
k. Repairing sewers, drains, walls, etc., when damaged by maintenance
work.
l. Making electrolysis tests to maintain life of plant.
m. Repairing property of others damaged by maintenance work.
Compressor station equipment: (See operating expense instruction 1.)
Measuring and regulating station equipment: (See operating expense
instruction 1.)
Services:
5. Testing pipe for leaks, stoppage, or other trouble and making
necessary repairs.
6. Reporting on the condition of gas services to determine the need
for repairs.
7. Rearranging and changing the location of services not retired.
8. Repairing service valves for reuse.
9. Lowering and raising curb boxes to grade.
10. Replacing less than a complete service, when not retired.
11. Installing fittings, valves, drips, frost protection devices, or
replacing similar items on existing services.
12. Cutting and replacing pavement, pavement base and sidewalks in
connection with maintenance work.
13. Restoring condition of services damaged by fire, storm, leakage,
flood, accident, or other casualties.
14. Repairing property of others damaged by maintenance work.
15. Transferring services in connection with the installation of new
mains.
16. Installing, maintaining, and removing temporary facilities to
prevent the interruption of service.
17. Converting low pressure gas distribution service to medium or
high pressure service.
18. Relocating and rerouting gas service temporarily during
alterations of buildings.
19. Performing work resulting from municipal improvements, such as
street widening, sewers, etc.
20. Replacing service valve box or drip riser box.
21. Installing, removing or replacing service valve, drip pot, or
drip riser.
22. Repacking service valve.
893 Maintenance of meters and house regulators.
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of meters and house regulators, the
book cost of which is includible in accounts 381, Meters, and 383, House
Regulators. (See operating expense instruction 2.)
1. Inspecting and testing meters and house regulators on customers'
premises or in shops in connection with repairs.
2. Cleaning, repairing, and painting meters, house regulators, and
accessories and equipment.
3. Repairing testing equipment.
4. Rebuilding and overhauling meters without changing their rated
capacities.
5. Resealing house regulators with mercury, replacing diaphragms,
springs and other defective or worn parts.
6. Replacing or adding any item not constituting a retirement unit.
894 Maintenance of other equipment (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of street lighting equipment and
all other distribution system equipment not provided for elsewhere, the
book cost of which is includible in accounts 386, Other Property on
Customers' Premises, and 387, Other Equipment. (See operating expense
instruction 2.)
895 Maintenance of other plant (Nonmajor only).
This account shall include the cost of labor, materials used and
expenses incurred in the maintenance of structures, and all other
distribution system plant not provided for elsewhere, the book cost of
which is includible in accounts 375, 386, and 387. (See operating
expense instruction 2.)
1. Work of similar character to that listed in other distribution
maintenance accounts.
2. Maintenance of office furniture and equipment used by distribution
system department.
901 Supervision (Major only).
This account shall include the cost of labor and expenses incurred in
the general direction and supervision of customer accounting and
collecting activities. Direct supervision of a specific activity shall
be charged to account 902, Meter Reading Expenses, or account 903,
Customer Records and Collection Expenses, as appropriate. (See
operating expense instruction 1.)
902 Meter reading expenses.
This account shall include the cost of labor, materials used and
expenses incurred in reading customer meters, and determining
consumption when performed by employees engaged in reading meters.
Labor:
1. Addressing forms for obtaining meter readings by mail.
2. Changing and collecting meter charts used for billing purposes.
3. Inspecting time clocks, checking seals, etc., when performed by
meter readers and the work represents a minor activity incidental to
regular meter reading routine.
4. Meter reading -- small consumption, and obtaining load information
for billing purposes. (Exclude and charge to account 878, Meter and
House Regulator Expenses, or to account 903, Customer Records and
Collection Expenses, as applicable, the cost of obtaining meter
readings, first and final, if incidental to the operation of removing or
resetting, sealing or locking, and disconnecting, or reconnecting
meters.)
5. Measuring gas -- large consumption, including reading meters,
changing charts, calculating charts, estimating lost meter
registrations, determining specific gravity, etc., for billing purposes.
6. Computing consumption from meter reader's book or from reports by
mail when done by employees engaged in reading meters.
7. Collecting from prepayment meters when incidental to meter
reading.
8. Maintaining record of customers' keys.
9. Computing estimated or average consumption when performed by
employees engaged in reading meters.
Materials and expenses:
10. Badges, lamps, and uniforms.
11. Demand charts, meter books and binders and forms for recording
readings, but not the cost of preparation.
12. Postage and supplies used in obtaining meter readings by mail.
13. Communication service (Nonmajor only).
14. Miscellaneous office supplies and expenses and stationery and
printing (Nonmajor only).
903 Customer records and collection expenses.
This account shall include the cost of labor, materials used and
expenses incurred in work on customer applications, contracts, orders,
credit investigations, billing and accounting, collections and
complaints.
Labor:
1. Receiving, preparing, recording and handling routine orders for
service, disconnections, transfers or meter tests initiated by the
customer, excluding the cost of carrying out such orders, which is
chargeable to the account appropriate for the work called for by such
orders.
2. Investigations of customers' credit and keeping of records
pertaining thereto, including records of uncollectible accounts written
off.
3. Receiving, refunding or applying customer deposits and maintaining
customer deposit, line extension, and other miscellaneous records.
4. Checking consumption shown by meter readers' reports where
incidental to preparation of billing data.
5. Preparing address plates and addressing bills and delinquent
notices.
6. Preparing billing data.
7. Operating billing and bookkeeping machines.
8. Verifying billing records with contracts or rate schedules.
9. Preparing bills for delivery, and mailing or delivering bills.
10. Collecting revenues, including collection from prepayment meters
unless incidental to meter reading operations.
11. Balancing collections, preparing collections for deposit, and
preparing cash reports.
12. Posting collections and other credits or charges to customer
accounts and extending unpaid balances.
13. Balancing customer accounts and controls.
14. Preparing, mailing, or delivering delinquent notices and
preparing reports of delinquent accounts.
15. Final meter reading of delinquent accounts when done by
collectors incidental to regular activities.
16. Disconnecting and reconnecting services because of nonpayment of
bills.
17. Receiving, recording, and handling of inquiries, complaints, and
requests for investigations from customers, including preparation of
necessary orders, but excluding the cost of carrying out such orders,
which is chargeable to the account appropriate for the work called for
by such orders.
18. Statistical and tabulating work on customer accounts and
revenues, but not including special analyses for sales department, rate
department, or other general purposes, unless incidental to regular
customer accounting routines.
19. Preparing and periodically rewriting meter reading sheets.
20. Determining consumption and computing estimated or average
consumption when performed by employees other than those engaged in
reading meters.
Materials and expenses:
21. Address plates and supplies.
22. Cash overages and shortages.
23. Commissions or fees to others for collecting.
24. Payments to credit organizations for investigations and reports.
25. Postage.
26. Transportation expenses, including transportation of customer
bills and meter books under centralized billing procedure (Major only).
27. Transportation, meals, and incidental expenses.
28. Bank charges, exchange, and other fees for cashing and depositing
customers' checks.
29. Forms for recording orders for services, removals, etc.
30. Rent of mechanical equipment.
31. Communication service (Nonmajor only).
32. Miscellaneous office supplies and expenses and stationery and
printing (Nonmajor only).
Note: The cost of work on meter history and meter location records
is chargeable to account 878, Meter and House Regulator Expenses.
904 Uncollectible accounts.
This account shall be charged with amounts sufficient to provide for
losses from uncollectible utility revenues. Concurrent credits shall be
made to account 144, Accumulated Provision for Uncollectible Accounts --
Credit. Losses from uncollectible accounts shall be charged to account
144.
905 Miscellaneous customer accounts expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred not provided for in other accounts.
Labor:
1. General clerical and stenographic work.
2. Miscellaneous labor.
Materials and expenses:
3. Communication service.
4. Miscellaneous office supplies and expenses and stationery and
printing other than those specifically provided for in accounts 902 and
903.
906 Customer service and informational expenses (Nonmajor only).
This account shall include the cost of supervision, labor, and
expenses incurred in customer service and informational activities, the
purpose of which is to encourage safe and efficient use of the utility's
service, to encourage conservation of the utility's service, and to
assist present customers in answering specific inquiries as to the
proper and economic use of the utility's service and the customer's
equipment utilizing the service.
907 Supervision (Major only).
This account shall include the cost of labor and expenses incurred in
the general direction and supervision of customer service activities,
the object of which is to encourage safe, efficient and economical use
of the utility's service. Direct supervision of a specific activity
within customer service and informational expense classification shall
be charged to the account wherein the costs of such activity are
included. (See operating expense instruction 1.)
908 Customer assistance expenses (Major only).
This account shall include the cost of labor, materials used, and
expenses incurred in providing instructions or assistance to customers,
the object of which is to promote safe, efficient and economical use of
the utility's service.
Labor:
1. Direct supervision of department.
2. Processing customer inquiries relating to the proper use of gas
equipment, the replacement of such equipment and information related to
such equipment.
3. Advice directed to customers as to how they may achieve the most
efficient and safest use of gas equipment.
4. Demonstrations, exhibits, lectures, and other programs designed to
instruct customers in the safe, economical or efficient use of gas
service, and/or oriented toward conservation of energy.
5. Engineering and technical advice to customers, the object of which
is to promote safe, efficient and economical use of the utility's
service.
Materials and expenses:
6. Supplies and expenses pertaining to demonstrations, exhibits,
lectures, and other programs.
7. Loss in value on equipment and appliances used for customer
assistance programs.
8. Office supplies and expenses.
9. Transportation, meals, and incidental expenses.
Note: Do not include in this account expenses that are provided for
elsewhere, such as accounts 416, Costs and Expenses of Merchandising,
Jobbing and Contract Work, 879, Customer Installations Expenses, and
912, Demonstrating and Selling Expenses.
909 Informational and instructional advertising expenses (Major
only).
This account shall include the cost of labor, materials used and
expenses incurred in activities which primarily convey information as to
what the utility urges or suggests customers should do in utilizing gas
service to protect health and safety, to encourage environmental
protection, to utilize their gas equipment safely and economically, or
to conserve natural gas.
Labor:
1. Direct supervision of informational activities.
2. Preparing informational materials for newspapers, periodicals,
billboards, etc., and preparing and conducting informational motion
pictures, radio and television programs.
3. Preparing informational booklets, bulletins, etc., used in direct
mailings.
4. Preparing informational window and other displays.
5. Employing agencies, selecting media and conducting negotiations in
connection with the placement and subject matter of information
programs.
Materials and expenses:
6. Use of newspapers, periodicals, billboards, radio, etc., for
informational purposes.
7. Postage on direct mailings to customers exclusive of postage
related to billings.
8. Printing of informational booklets, dodgers, bulletins, etc.
9. Supplies and expenses in preparing informational materials by the
utility.
10. Office supplies and expenses.
Note A: Exclude from this account and charge to account 930.2,
Miscellaneous General Expenses, the cost of publication of stockholder
reports, dividend notices, bond redemption notices, financial
statements, and other notices of a general corporate character. Exclude
also all expenses of a promotional, institutional, goodwill or political
nature, which are includible in such accounts as 913, Advertising
Expenses, 930.1, General Advertising Expenses, and 426.4, Expenditures
for Certain Civic, Political and Related Activities.
Note B: Entries relating to informational advertising included in
this account shall contain or refer to supporting documents which
identify the specific advertising message. If references are used,
copies of the advertising message shall be readily available.
910 Miscellaneous customer service and informational expenses (Major
only).
This account shall include the cost of labor, materials used and
expenses incurred in connection with customer service and informational
activities which are not includible in other customer information
expense accounts.
Labor:
1. General clerical and stenographic work not assigned to specific
customer service and information programs.
2. Miscellaneous labor.
Materials and expenses:
3. Communication service.
4. Printing, postage and office supplies expenses.
911 Supervision (Major only).
This account shall include the cost of labor and expenses incurred in
the general direction and supervision of sales activities, except
merchandising. Direct supervision of a specific activity, such as
demonstrating, selling, or advertising shall be charged to the account
wherein the costs of such activity are included. (See operating expense
instruction 1.)
912 Demonstrating and selling expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in promotional, demonstrating, and selling activities,
except by merchandising, the object of which is to promote or retain the
use of utility services by present and prospective customers.
Labor:
1. Demonstrating uses of utility services.
2. Conducting cooking schools, preparing recipes, and related home
service activities.
3. Exhibitions, displays, lectures, and other programs designed to
promote use of utility services.
4. Experimental and development work in connection with new and
improved appliances and equipment, prior to general public acceptance.
5. Solicitation of new customers or of additional business from old
customers, including commissions paid employees.
6. Engineering and technical advice to present or prospective
customers in connection with promoting or retaining the use of utility
services.
7. Special customer canvasses when their primary purpose is the
retention of business or the promotion of new business.
Materials and expenses:
8. Supplies and expenses pertaining to demonstration, and
experimental and development activities.
9. Booth and temporary space rental.
10. Loss in value on equipment and appliances used for demonstration
purposes.
11. Transportation, meals, and incidental expenses.
913 Advertising expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in advertising designed to promote or retain the use
of utility service, except advertising the sale of merchandise by the
utility.
Labor:
1. Direct supervision of department.
2. Preparing advertising material for newspapers, periodicals,
billboards, etc., and preparing and conducting motion pictures, radio
and television programs.
3. Preparing booklets, bulletins, etc., used in direct mail
advertising.
4. Preparing window and other displays.
5. Clerical and stenographic work.
6. Investigating advertising agencies and media and conducting
negotiations in connection with the placement and subject matter of
sales advertising.
Materials and expenses:
7. Advertising in newspapers, periodicals, billboards, radio, etc.,
for sales promotion purposes, but not including institutional or
goodwill advertising includible in account 930.1, General Advertising
Expenses.
8. Materials and services given as prizes or otherwise in connection
with canning, or cooking contests, bazaars, etc., in order to publicize
and promote the use of utility services.
9. Fees and expenses of advertising agencies and commercial artists.
10. Novelties for general distribution.
11. Postage on direct mail advertising.
12. Premiums distributed generally, such as recipe books, etc., when
not offered as inducement to purchase appliances.
13. Printing booklets, dodgers, bulletins, etc.
14. Supplies and expenses in preparing advertising material.
15. Office supplies and expenses.
Note A: The cost of advertisements which set forth the value or
advantages of utility service without reference to specific appliances,
or, if reference is made to appliances, invites the reader to purchase
appliances from his dealer, or refer to appliances not carried for sale
by the utility, shall be considered sales promotion advertising and
charged to this account. However, advertisements which are limited to
specific makes of appliances sold by the utility and prices, terms,
etc., thereof, without referring to the value or advantages of utility
service, shall be considered as merchandise advertising and the cost
shall be charged to Costs and Expenses of Merchandising, Jobbing and
Contract Work, accounts 416.
Note B: Advertisements which substantially mention or refer to the
value or advantages of utility service, together with specific reference
to makes of appliances sold by the utility and the price, terms, etc.,
thereof, and designed for the joint purpose of increasing the use of
utility service and the sales of appliances, shall be considered as a
combination advertisement and the costs shall be distributed between
this account and account 416 on the basis of space, time, or other
proportional factors.
Note C: Exclude from this account and charge to account 930.2,
Miscellaneous General Expenses, the cost of publication of stockholder
reports, dividend notices, bond redemption notices, financial
statements, and other notices of a general corporate character. Exclude
also all institutional or goodwill advertising. (See account 930.1,
General Advertising Expenses.)
914 -- 915 (Reserved)
916 Miscellaneous sales expenses (Major only).
This account shall include the cost of labor, materials used and
expenses incurred in connection with sales activities, except
merchandising, which are not includible in other sales expense accounts.
Labor:
1. General clerical and stenographic work not assigned to specific
functions.
2. Special analysis of customer accounts and other statistical work
for sales purposes not a part of the regular customer accounting and
billing routine.
3. Miscellaneous labor.
Materials and expenses:
4. Communication service.
5. Printing, postage, and office supplies and expenses applicable to
sales activities, except those chargeable to account 913, Advertising
Expenses.
917 Sales expenses (Nonmajor only).
This account shall include the cost of labor and expenses incurred
for the purpose of promoting the sale of gas, other than merchandising,
jobbing, or contract work activities.
1. Advertising.
2. Demonstrating uses of utility service.
3. Home service activities.
4. Solicitation of new business.
920 Administrative and general salaries.
A. This account shall include the compensation (salaries, bonuses,
and other consideration for services, but not including directors' fees)
of officers, executives, and other employees of the utility properly
chargeable to utility operations and not chargeable directly to a
particular operating function.
B. This account may be subdivided in accordance with a classification
appropriate to the departmental or other functional organization of the
utility.
921 Office supplies and expenses.
A. This account shall include office supplies and expenses incurred
in connection with the general administration of the utility's
operations which are assignable to specific administrative or general
departments and are not specifically provided for in other accounts.
This includes the expenses of the various administrative and general
departments, the salaries and wages of which are includible in account
920.
B. This account may be subdivided in accordance with a classification
appropriate to the departmental or other functional organization of the
utility.
Note: Office expenses which are clearly applicable to any group of
operating expenses other than the administrative and general group shall
be included in the appropriate account in such group. Further, general
expenses which apply to the utility as a whole rather than to a
particular administrative function shall be included in account 930.2,
Miscellaneous General Expenses.
1. Automobile service, including charges through clearing account.
2. Bank messenger and service charges.
3. Books, periodicals, bulletins and subscriptions to newspapers,
newsletters, tax services, etc.
4. Building service expenses for customer accounts, sales, and
administrative and general purposes.
5. Communication service expenses.
6. Cost of individual items of office equipment used by general
departments which are of small value or short life.
7. Membership fees and dues in trade, technical, and professional
associations paid by a utility for employees. (Company memberships are
includible in account 930.2.)
8. Office supplies and expenses.
9. Payment of court costs, witness fees, and other expenses of legal
department.
10. Postage, printing and stationery.
11. Meals, traveling and incidental expenses.
922 Administrative expenses transferred -- Credit.
This account shall be credited with administrative expenses recorded
in accounts 920 and 921 which are transferred to construction costs or
to nonutility accounts. (See gas plant instruction 4.)
923 Outside services employed.
A. This account shall include the fees and expenses of professional
consultants and others for general services which are not applicable to
a particular operating function or to other accounts. It shall include
also the pay and expenses of persons engaged for a special or temporary
administrative or general purpose in circumstances where the person so
engaged is not considered as an employee of the utility.
B. This account shall be so maintained as to permit ready
summarization according to the nature of service and the person
furnishing the same.
1. Fees, pay and expenses of accountants and auditors, actuaries,
appraisers, attorneys, engineering consultants, management consultants,
negotiators, public relations counsel, tax consultants, etc.
2. Supervision fees and expenses paid under contracts for general
management services.
Note: Do not include inspection and brokerage fees and commissions
chargeable to other accounts or fees and expenses in connection with
security issues which are includible in the expenses of issuing
securities.
924 Property insurance.
A. This account shall include the cost of insurance or reserve
accruals to protect the utility against losses and damages to owned or
leased property used in its utility operations. For Major companies, it
shall include also the cost of labor and related supplies and expenses
incurred in property insurance activities.
B. Recoveries from insurance companies or others for property damages
shall be credited to the account charged with the cost of the damage.
If the damaged property has been retired, the credit shall be to the
appropriate account for accumulated provision for depreciation.
C. Records shall be kept so as to show the amount of coverage for
each class of insurance carried, the property covered, and the
applicable premiums. Any dividends distributed by mutual insurance
companies shall be credited to the accounts to which the insurance
premiums were charged.
1. Premiums payable to insurance companies for fire, storm, burglary,
boiler explosion, lightning, fidelity, riot, and similar insurance.
2. Amounts credited to account 228.1, Accumulated Provision for
Property Insurance; for similar protection.
3. Special costs incurred in procuring insurance.
4. Insurance inspection service.
5. Insurance counsel, brokerage fees, and expenses.
Note A: The cost of insurance or reserve accruals capitalized shall
be charged to construction either directly or by transfer to
construction work orders from this account.
Note B: The cost of insurance or reserve accruals for the following
classes of property shall be charged as indicated.
(1) Materials and supplies and stores equipment, to account 163,
Stores Expense Undistributed (stores expenses in the case of Nonmajor
companies) or appropriate materials account.
(2) For Major companies, transportation and other general equipment
to appropriate clearing accounts that may be maintained. For Nonmajor
companies, transportation and garage equipment, to account 933,
Transportation expenses.
(3) Gas plant leased to others, to account 413, Expenses of Gas Plant
Leased to Others.
(4) Nonutility property, to the appropriate nonutility income
account.
(5) Merchandise and jobbing property, to account 416, Costs and
Expenses of Merchandising, Jobbing and Contract Work.
Note C (Major only): The cost of labor and related supplies and
expenses of administrative and general employees, who are only
incidentally engaged in property insurance work, may be included in
accounts 920 and 921, as appropriate.
925 Injuries and damages.
A. This account shall include the cost of insurance or reserve
accruals to protect the utility against injuries and damages claims of
employees or others, losses of such character not covered by insurance,
and expenses incurred in settlement of injuries and damages claims. For
Major companies, it shall also include the cost of labor and related
supplies and expenses incurred in injuries and damages activities.
B. Reimbursements from insurance companies or others for expenses
charged hereto on account of injuries and damages and insurance
dividends or refunds shall be credited to this account.
1. Premiums payable to insurance companies for protection against
claims from injuries and damages by employees or others, such as public
liability, property damages, casualty, employee liability, etc., and
amounts credited to account 228.2, Accumulated Provision for Injuries
and Damages; for similar protection.
2. Losses not covered by insurance or reserve accruals on account of
injuries or deaths to employees or others and damages to the property of
others.
3. Fees and expenses of claim investigators.
4. Payment of awards to claimants for court costs and attorneys'
services.
5. Medical and hospital service and expenses for employees as the
result of occupational injuries, or resulting from claims of others.
6. Compensation payments under workmen's compensation laws.
7. Compensation paid while incapacitated as the result of
occupational injuries. (See Note A.)
8. Cost of safety, accident prevention and similar educational
activities.
Note A: Payments to or in behalf of employees for accident or death
benefits, hospital expenses, medical supplies or for salaries while
incapacitated for service or on leave of absence beyond periods normally
allowed, when not the result of occupational injuries, shall be charged
to account 926, Employee Pensions and Benefits. (See also Note B of
account 926.)
Note B: The cost of injuries and damages or reserve accruals
capitalized shall be charged to construction directly or by transfer to
construction work orders from this account.
Note C: Exclude herefrom the time and expenses of employees (except
those engaged in injuries and damages activities) spent in attendance at
safety and accident prevention educational meetings, if occurring during
the regular work period.
Note D: The cost of labor and related supplies and expenses of
administrative and general employees, who are only incidentally engaged
in injuries and damages activities, may be included in accounts 920 and
921, as appropriate.
926 Employee pensions and benefits.
A. This account shall include pensions paid to or on behalf of
retired employees, or accruals to provide for pensions, or payments for
the purchase of annuities for this purpose, when the utility has
definitely, by contract, committed itself to a pension plan under which
the pension funds are irrevocably devoted to pension purposes, and
payments for employee accident, sickness, hospital, and death benefits,
or insurance therefor. Include, also, expenses incurred in medical,
educational or recreational activities for the benefit of employees, and
administrative expenses in connection with employee pensions and
benefits.
B. The utility shall maintain a complete record of accruals or
payments for pensions and be prepared to furnish full information to the
Commission of the plan under which it has created or proposes to create
a pension fund and a copy of the declaration of trust or resolution
under which the pension plan is established.
C. There shall be credited to this account the portion of pensions
and benefits expenses which is applicable to nonutility operations or
which is charged to construction unless such amounts are distributed
directly to the accounts involved and are not included herein in the
first instance.
D. For Major companies, records in support of this account shall be
so kept that the total pensions expense, the total benefits expense, the
administrative expenses included herein, and the amounts of pensions and
benefits expenses transferred to construction or other accounts will be
readily available.
1. Payment of pensions under a nonaccrual or nonfunded basis.
2. Accruals for or payments to pension funds or to insurance
companies for pension purposes.
3. Group and life insurance premiums (credit dividends received).
4. Payments for medical and hospital serv- ices and expenses of
employees when not the result of occupational injuries.
5. Payments for accident, sickness, hospital, and death benefits or
insurance.
6. Payments to employees incapacitated for service or on leave of
absence beyond periods normally allowed, when not the result of
occupational injuries, or in excess of statutory awards.
7. Expenses in connection with educational and recreational
activities for the benefit of employees.
Note A: The cost of labor and related supplies and expenses of
administrative and general employees who are only incidentally engaged
in employee pension and benefit activities, may be included in accounts
920 and 921, as appropriate.
Note B: Salaries paid to employees during periods of nonoccupational
sickness may be charged to the appropriate labor account rather than to
employee benefits.
927 Franchise requirements.
A. This account shall include payments to municipal or other
governmental authorities, and the cost of materials, supplies and
services furnished such authorities without reimbursement in compliance
with franchise, ordinance, or similar requirements; provided, however,
that the utility may charge to this account at regular tariff rates,
instead of cost, utility service furnished without charge under
provisions of franchises.
B. When no direct outlay is involved, concurrent credit for such
charges shall be made to account 929, Duplicate Charges -- Cr.
C. The account shall be maintained so as to readily reflect the
amounts of cash outlays, utility service supplied without charge, and
other items furnished without charge.
Note A: Franchise taxes shall not be charged to this account but to
account 408.1, Taxes Other Than Income Taxes, Utility Operating Income.
Note B: Any amount paid as initial consideration for a franchise
running for more than one year shall be charged to account 302,
Franchises and Consents.
928 Regulatory commission expenses.
A. This account shall include all expenses (except pay of regular
employees only incidentally engaged in such work) properly includible in
utility operating expenses, incurred by the utility in connection with
formal cases before regulatory commissions, or other regulatory bodies,
or cases in which such a body is a party, including payments made to a
regulatory commission for fees assessed against the utility for pay and
expenses of such commission, its officers, agents, and employees.
B. Amounts of regulatory commission expenses which by approval or
direction of the Commission are to be spread over future periods shall
be charged to account 186, Miscellaneous Deferred Debits, and amortized
by charges to this account.
C. The utility shall be prepared to show the cost of each formal
case.
1. Salaries, fees, retainers, and expenses of counsel, solicitors,
attorneys, accountants, engineers, clerks, attendants, witnesses, and
others engaged in the prosecution of, or defense against petitions or
complaints presented to regulatory bodies, or in the valuation of
property owned or used by the utility in connection with such cases.
2. Office supplies and expenses, payments to public service or other
regulatory commissions, stationery and printing, traveling expenses, and
other expenses incurred directly in connection with formal cases before
regulatory commissions.
3. All application fees except those involving construction
certificate applications which have been approved. (See Gas Plant
Instruction 16.)
Note A: Exclude from this account and include in other appropriate
operating expense accounts, expenses incurred in the improvement of
service, additional inspection, or rendering reports, which are made
necessary by the rules and regulations, or orders, of regulatory bodies.
Note B: Do not include in this account amounts includible in account
302, Franchises and Consents, account 181, Unamortized Debt Expense, or
account 214, Capital Stock Expense.
929 Duplicate charges -- Credit.
This account shall include concurrent credits for charges which may
be made to operating expenses or to other accounts for the use of
utility service from its own supply. Include, also, offsetting credits
for any other charges made to operating expenses for which there is no
direct money outlay.
930.1 General advertising expenses.
This account shall include the cost of labor, materials used, and
expenses incurred in advertising and related activities, the cost of
which by their content and purpose are not provided for elsewhere.
Labor:
1. Supervision.
2. Preparing advertising material for newspapers, periodicals,
billboards, etc., and preparing or conducting motion pictures, radio and
television programs.
3. Preparing booklets, bulletins, etc., used in direct mail
advertising.
4. Preparing window and other displays.
5. Clerical and stenographic work.
6. Investigating and employing advertising agencies, selecting media
and conducting negotiations in connection with the placement and subject
matter of advertising.
Materials and expenses:
7. Advertising in newspapers, periodicals, billboards, radio, etc.
8. Advertising matter such as posters, bulletins, booklets and
related items.
9. Fees and expenses of advertising agencies and commercial artists.
10. Postage and direct mail advertising.
11. Printing of booklets, dodgers, bulletins, etc.
12. Supplies and expenses in preparing advertising materials.
13. Office supplies and expenses.
Note A: Properly includible in this account is the cost of
advertising activities on a local or national basis of a goodwill or
institutional nature, which is primarily designed to improve the image
of the utility or the industry, including advertisements which inform
the public concerning matters affecting the company's operations, such
as, the cost of providing service, the company's efforts to improve the
quality of service, the company's efforts to improve and protect the
environment, etc. Entries relating to advertising included in this
account shall contain or refer to supporting documents which identify
the specific advertising message. If references are used, copies of the
advertising message shall be readily available.
Note B: Exclude from this account and include in account 426.4.
Expenditures for Certain Civic, Political and Related Activities,
expenses for advertising activities, which are designed to solicit
public support or the support of public officials in matters of a
political nature.
930.2 Miscellaneous general expenses.
This account shall include the cost of labor and expenses incurred in
connection with the general management of the utility not provided for
elsewhere.
Labor:
1. Miscellaneous labor not elsewhere provided for:
Expenses:
2. Industry Association dues for company memberships.
3. Contributions for conventions and meetings of the industry.
4. For Major companies, research, development, and demonstration
expenses not charged to other operation and maintenance expense accounts
on a functional basis. For Nonmajor companies, experimental and general
research work for the industry.
5. Communication service not chargeable to other accounts.
6. Trustee, registrar, and transfer agent fees and expenses.
7. Stockholders meeting expenses.
8. Dividend and other financial notices.
9. Printing and mailing dividend checks.
10. Directors' fees and expenses.
11. Publishing and distributing annual reports to stockholders.
12. Public notices of financial, operating, and other data required
by regulatory statutes, not including, however, notices required in
connection with security issues or acquisitions of property.
931 Rents.
This account shall include rents properly includible in utility
operating expenses for the property of others used, occupied, or
operated in connection with the customer accounts, customer service and
informational, sales, and general and administrative functions of the
utility. (See operating expense instruction 3.)
933 Transportation expenses (Nonmajor only).
A. This account shall include the cost of labor, materials used and
expenses incurred in the operation and maintenance of general
transportation equipment of the utility.
B. This account may be used as a clearing account in which event the
charges hereto shall be cleared by apportionment to the appropriate
operating expense, gas plant, or other accounts on a basis which will
distribute the expenses equitably. Credits to this account shall be
made in such detail as to permit ready analysis.
1. Supervision.
2. Building service.
3. Care of grounds, including snow removal, cutting grass, etc.
4. Utility services.
5. Depreciation of transportation equipment.
6. Fuel and lubricants for vehicles (including sales and excise taxes
thereon.)
7. Insurance on garage equipment and transportation equipment,
including public liability and property damage.
8. Maintenance of transportation and garage equipment.
9. Compensation of drivers, mechanics, clerks, and other garage
employees.
10. Rent of garage buildings and grounds, vehicles or equipment.
11. Replacement of tires, tubes, batteries, etc.
12. Direct taxes, licenses, and permits.
13. Miscellaneous garage supplies, tools, and equipment.
14. Miscellaneous office supplies and expenses, printing, and
stationery.
15. Transportation, meals, and incidental expenses.
Note A: The pay of employees driving trucks or other transportation
equipment incidental to their regular occupation, shall not be included
herein but charged directly to the appropriate expense or other account.
Note B: Transportation expenses applicable to construction shall not
be included in operating expenses.
935 Maintenance of general plant.
A. This account shall include the cost assignable to customer
accounts, sales and administrative and general functions of labor,
materials used and expenses incurred in the maintenance of property, the
book cost of which is includible in account 390, Structures and
Improvements, account 391, Office Furniture and Equipment, account 397,
Communication Equipment, and account 398, Miscellaneous Equipment. For
Nonmajor companies, include also other general equipment accounts (not
including transportation equipment). (See operating expense instruction
2.)
B. Maintenance expenses on office furniture and equipment used
elsewhere than in general, commercial and sales offices shall be charged
to the following accounts:
18 CFR 161.3 PART 204 -- (RESERVED)
Note: For the Uniform System of Accounts for Natural Gas Companies
subject to the Natural Gas Act, see part 201 of this subchapter. (Order
390, 49 FR 32526, Aug. 14, 1984; 50 FR 5745, Feb. 12, 1985)
18 CFR 161.3 Pt. 216
18 CFR 161.3 PART 216 -- UNITS OF PROPERTY FOR USE IN ACCOUNTING FOR
ADDITIONS TO AND RETIREMENTS OF GAS PLANT
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (1982); E.O. 12009, 3 CFR 142 (1978); Natural Gas Act, 15
U.S.C. 717-717w (1982).
Source: Order 236, 26 FR 9892, Oct. 21, 1961, unless otherwise
noted.
Editorial Note: For Federal Register citations affecting part 216,
see the List of CFR Sections Affected in the Finding Aids section of
this volume.
18 CFR 161.3 Instructions
1. The retirement units listed herein are prescribed and are to be
accounted for in accordance with Gas Plant Instruction 10, Additions and
Retirements of Gas Plant, of the Uniform System of Accounts Prescribed
for Natural Gas Companies.
2. The list of units may be expanded by any utility without other
authorization from the Commission, but the list shall not be condensed.
Thus the units listed herein are of maximum size and while subdivision
thereof, or of the addition of other units is permitted, the combination
or the increase in size of such units is not permitted without the
approval of the Commission.
3. Wherever appropriate, the retirement of any retirement unit in the
structures or equipment accounts shall include all costs of associated
items which pertain solely to that unit, such as the cost of
foundations, supports, ladders, runways, enclosures, guards, driving
mechanisms, indicating, recording, and measuring devices with their
mountings, starting, control, regulating, protective, and safety
devices, switchboards, special lighting conduits and wiring, pipes,
ducts, spouts, chutes, hoppers, etc.
4. The appearance of a retirement unit under an account warrants the
inclusion of the unit in the account mentioned only when the text of the
account also indicates the inclusion as the same unit frequently appears
under more than one account.
The omission of an item from the list in an account or its inclusion
in a functional system does not preclude its treatment as a retirement
unit if it is relatively costly and not an integral part of a larger
retirement unit. The List of General Retirement Units, instruction 6
below, should be read in connection with the lists under the respective
accounts since in some cases retirement units have not been separately
listed because they appear in the List of General Retirement Units and
are common to more than one account. Likewise the List of General
Retirement Units and these instructions should be considered in
connection with listed retirement units designated as ''system,'' etc.
In these cases, particularly if ''system,'' etc., be extensive, a
component of such system, such as a relatively costly piece of apparatus
not an integral part of a larger retirement unit, or a unit specified in
the List of General Retirement Units, should be separately treated as a
retirement unit.
5. It is contemplated that the list of units contained herein will be
revised and amended from time to time as experience and conditions
warrant.
Note A: The term ''relatively costly'' applies to the relationship
of the cost of the item to the cost of other items in that particular
account or sub-account for the particular station or plant.
Note B: The term ''integral part'' is used in a physical rather than
a functional sense. For instance, both the pump and heat exchanger
mounted separately in a vaporizing system will be considered retirement
units, as contrasted with a packaged unit where both would be considered
an integral part of the package.
6. List of General Retirement Units:
In all accounts where they occur, the following shall be considered a
retirement unit, if relatively costly and not an integral part of the
retirement unit specifically listed.
(1) Assembly for two or more retirement units.
(2) Blower or fan.
(3) Control installation, automatic, semi-automatic, or remote (such
as pressure, speed, level, weight and volume regulators).
(4) Coupling device, i.e., speed reducer, speed increaser, clutch
coupling, etc.
(5) Driving unit, i.e., prime mover, motor, gas engine, etc.
(6) Enclosure for two or more retirement units (fence, guard railing,
etc.).
(7) Foundation for a unit of equipment, when not an integral part of
a building and its usefulness is not intended to outlast the equipment
for which provided.
(8) Instrument or device for indicating, measuring, recording or
weighing.
(9) Landscaping (complete at one location).
(10) Plant piping, a run of any system (oil, gas, steam, water,
etc.), 6 inches or over in size, with or without valves, between two or
more retirement units of property, and/or a header. (See Note A and
item 16.)
(11) Piping header, 6'' and over in size, with or without valves and
blocking. (See Note A and item 16.)
(12) Platforms, ladders, stairs, runways (complete section).
(13) Pump.
(14) Road, walk, parking lot, etc.
(15) Tank, vessel, bin, sphere, holder, etc.
(16) Valve, power operated, pressure reducing, atmospheric relief, 6
inch nominal pipe size and larger or relatively costly valve.
Note A: Whenever appropriate, the ''piping'' cost of additions and
retirements shall include all costs for pipes, valves, fittings,
specials, covering, hangers, supports, etc., pertaining to the run or
header in question.
18 CFR 161.3 List of Retirement Units
(The article a, an, or the, as appropriate, should be read in
connection with each retirement unit of property listed herein)
18 CFR 161.3 2. Production Plant
18 CFR 161.3 a. manufactured gas production plant
305 Structures and Improvements.
1. Air conditioning, ventilating system, heating system, or any
combination thereof.
2. Bin or bunker (when part of structure framework).
3. Bridge, trestle, etc.
4. Bulkhead, retaining wall, etc.
5. Canal, dam, dock, pier, wharf, etc.
6. Drainage and sewerage system.
7. Elevator, crane, hoist, etc., complete with operating mechanism.
8. Equipment item, such as, a generator, engine, turbine, compressor,
or similar item of equipment includible in structures, with or without
associated wiring, control equipment, etc.
9. Fence complete with gates.
10. Fire escape system.
11. Fire protection system.
12. Foundation (equipment) when includible in structure.
13. Light and power system complete.
14. Plumbing system.
15. Refrigeration system.
16. Railroad or track system, including culverts, etc.
17. Relief holder.
18. Roof, with or without supporting members. (A structure of
irregular shape having more than one roof level may have several
isolated roofs, each of which shall be considered an entire roof. In the
case of structures to which lateral extensions have been made, even
though having but one roof level, that part of the roof covering an
entire section built at one time shall be considered an entire roof.)
19. Structure complete, with or without stack or chimney.
20. Tunnel, pipe line, etc.
21. Vacuum cleaning system.
22. Water basin or reservoir.
23. Water supply system, including well.
24. Yard drainage system.
25. Yard lighting system.
306 Boiler Plant Equipment.
A. Steam Boiler Installation:
1. Boiler (each) complete with fuel burning equipment, furnace,
furnace walls or arches, setting, grates, etc.
2. Desuperheater.
3. Foundation, boiler, when independent of structure.
4. Reheater, when separate from boiler.
5. Soot blower system for one boiler.
6. Superheater, when separate from boiler.
B. Draft Equipment:
1. Air duct system.
2. Air heater.
3. Breeching system.
4. Cinder or fly ash collecting equipment, such as, cinder catcher,
precipitator, hopper concentrator, etc.
5. Stack, with or without foundation.
C. Feed Water System:
1. Deaerator.
2. Economizer, when separate from boiler.
3. Heater, feed water (main or stage).
4. Heat exchanger.
5. Regulator, feed water.
D. Coal Fuel Equipment:
1. Bin or bunker not includible in structures.
2. Bin unloader.
3. Barge.
4. Capstan, winch or power moving equipment.
5. Car, lorry.
6. Car dumper, puller, shaker, thawing system, etc.
7. Chutes or spouts, system of.
8. Coal moving equipment (bulldozer, carry-all, tractor, drag
scraper, etc.).
9. Conveyor system (belt, cable way, portable screw, etc.).
10. Crane (locomotive, gantry or monorail).
11. Crusher.
12. Dust collecting unit.
13. Electric trolley or third rail system.
14. Elevator (vertical, bucket, skip hoist).
15. Gates, chutes, downtakes, spreaders, or hoppers, for one boiler.
16. Hoist, or derrick.
17. Hopper, track or weigh.
18. Locomotive.
19. Sampling system.
20. Screening or sizing installation.
21. Separator, magnetic.
22. Structure, fuel handling (not includible in structures account).
23. Track system.
24. Trestle.
25. Weighing device, including track scale, coal meter, etc.
E. Pulverized Fuel Equipment:
1. Air filter or washer.
2. Air preheater.
3. Air compressor.
4. Conveyor.
5. Chutes, ducts or transport pipes, system of.
6. Coal feeder, raw or powdered.
7. Crusher.
8. Dryer.
9. Hopper or bin.
10. Pulverizer.
11. Screening or sizing installation.
12. Separator, electric or mechanical (dust collector or
concentrated).
F. Oil Fuel Equipment:
1. Heater.
Note: See list of general retirement units.
G. Gas Fuel Equipment:
Note: See list of general retirement units.
H. Ash Handling Equipment:
1. Ash hopper (when not includible in structure).
2. Car.
3. Clinker grinder.
4. Conveyor or elevator.
5. Crane hoist or derrick.
6. Dust collecting system.
7. Electric trolley or third rail system.
8. Locomotive.
9. Removal system (vacuum, steam jet, or hydraulic).
10. Sluiceway or piping system.
11. Storage bin or pit.
12. Sump dredge.
13. Track system.
I. Water Supply and Purification System:
1. Pipe or tunnel, intake or discharge (when not includible in
structure).
2. Water softener or purification system, including demineralizer,
etc.
3. Well.
Note: See list of general retirement units.
J. Ventilating Equipment:
1. Air duct system.
2. Cooler or heater.
3. Washer.
K. Controls:
1. Automatic control installation.
2. Master controller installation.
3. Panel or panels, devoted to a single purpose, with equipment
associated thereto.
L. Boiler Plant Piping and Miscellaneous:
Note: See list of general retirement units.
307 Other Power Equipment.
A. Steam Power Equipment:
a. Engine-driven generating installation:
1. Drive or connection between engine and generator.
2. Engine.
3. Exciter, direct connected or belt-driven.
4. Foundation, independent of structure.
5. Generator.
6. Governor control system.
b. Turbo-generator installation:
1. Equipment, starting and turning.
2. Exciter, direct connected or belt-driven.
3. Foundation, independent of structure.
4. Generator.
5. Governor control system.
6. Turbine.
c. Condensing and Cooling Water System:
1. Air ejector apparatus for one condenser.
2. Condenser.
3. Condenser tube protective system (chemical, electric,
electrolytic, etc.).
4. Cooling tower.
5. Intake or discharge, screen and mechanism.
6. Spraying system.
d. Central generator cooling system:
1. Air duct system.
2. Air washer.
3. Cooler.
4. Hydrogen system.
e. Central lubricating system:
1. Accumulator.
2. Cooler.
3. Purifier or filter.
f. Controls:
1. Panel or panels, devoted to a single purpose, with equipment
associated thereto.
g. Engine and turbine plant piping and miscellaneous:
Note: See list of general retirement units.
B. Gas and Oil Power Equipment:
a. Internal Combustion Engine:
1. Air intake equipment for one engine.
2. Engine, with or without foundation.
3. Governor control system.
4. Heat exchanger.
5. Muffler.
6. Stack.
7. Starting and turning equipment.
8. Panel or panels and instruments for one engine.
b. Central lubricating system:
1. Cooler.
2. Piping system, oil.
3. Purifier or filter.
c. Central cooling water system:
1. Heat exchanger.
2. Piping system, cooling water.
3. Purification system, water.
4. Spraying system.
5. Tower, cooling.
d. Central starting system:
1. Compressor.
2. Piping system, starting.
e. Central intake air supply:
1. Air duct system.
2. Air filter or screen.
3. Silencer.
f. Central exhaust gas system:
1. Heat exchanger or waste heat boiler.
2. Muffler.
3. Piping system, exhaust.
4. Stack.
g. Fuel holders, producers, and accessories:
1. Boiler, heating.
2. Booster.
3. Compressor.
4. Heater, not a part of tank.
5. Holder.
6. Piping system, fuel oil.
7. Piping system, gas.
8. Purifier.
9. Regenerator.
10. Scrubber or washer.
11. Vaporizing unit for butane gas.
C. Generators:
1. Exciter, direct connected or belt-driven.
2. Generator.
3. Panel or panels devoted to a single purpose, with equipment
accessory thereto.
D. Accessory Electric Equipment:
1. Air compressor.
2. Air duct system.
3. Auxiliary generator set.
4. Battery charging set.
5. Capacitor, set or bank of.
6. Condenser, synchronous.
7. Conduit, with or without manholes, pullboxes and risers --
continuous run between retirement units, or complete functional system,
if appropriate.
8. Control installation, system operators.
9. Converter, synchronous or rotary.
10. Exciter, separately driven.
11. Fire protection system.
12. Frequency changer.
13. Frequency control system.
14. Fuse equipment, set of high tension.
15. Generator voltage regulator system.
16. Induction regulator.
17. Lightning arrester, 23KV or higher, set of.
18. Lighting system.
19. Oil circuit breaker or oil switch.
20. Panel or panels, devoted to a single purpose, with electric
equipment accessory thereto.
21. Pole line, including attachments, conductors and supports.
22. Reactor or resistor.
23. Rectifier.
24. Storage battery, set or bank for station control and power.
25. Structure forming a support for one or more units of equipment.
26. Switches, airbreak, grounding or set of disconnecting.
27. Switchgear (compartment, cubicle, etc.) complete assembly.
28. Telemetering equipment, each installation.
29. Testing equipment, set of.
30. Truck switch with wiring and instruments.
31. Transformer, not accessory to a panel.
32. Unit station complete.
33. Wire and cable, including accessories -- continuous run between
retirement units, or complete functional system, if appropriate.
E. Miscellaneous Power Plant Equipment:
Each principal item, system or set of equipment such as:
1. Air compressor.
2. Air conditioning or ventilating equipment (portable).
3. Barge, boat, or similar item of marine equipment.
4. Car, railway.
5. Communication system, station signal of call.
6. Compressed air system.
7. Crane, hoist or derrick.
8. Exhaust heat exchanger.
9. Fire protection equipment (general station use).
10. Laboratory equipment, principal item, such as drying oven,
calorimeter, etc.
11. Locomotive.
12. Oil reclaiming installation.
13. Tool, each principal item, such as forge, lathe, drill press.
14. Vacuum cleaning system.
Note: If any of the units of property listed above are a part of a
structure and includible in account 305 Structures and Improvements,
they shall be accounted for through that account.
308 Coke Ovens.
1. Bunker or bin (when independent of structure).
2. Charging lorry.
3. Clay mixer.
4. Coke oven.
5. Conveyor.
6. Door extractor.
7. Hydraulic main for one oven.
8. Pusher.
9. Quenching car.
10. Quenching tower.
11. Regenerator.
12. Reversing damper installation.
13. Wharf.
309 Producer Gas Equipment.
1. Bunker or bin (when independent of structure).
2. Condenser or cooler.
3. Conveyor.
4. Driving apparatus or linkage for one producer.
5. Producer.
6. Producer gas holder.
7. Scrubber.
8. Separator.
310 Water Gas Generating Equipment.
1. Automatic charger.
2. Automatic control.
3. Backrun valve.
4. Bunker or bin (when independent of structure).
5. Carburetor.
6. Control panel or board.
7. Dust collector.
8. Fuel and ash handling system.
9. Generator.
10. Hoist or elevator.
11. Oil heater.
12. Seal pot.
13. Superheater.
311 Liquefied Petroleum Gas Equipment.
1. Boiler.
2. Bottling apparatus installation.
3. Compressor.
4. Calorimixer.
5. Carbureting system.
6. Heater.
7. Heat exchanger.
8. Mixing system.
9. Odorizing system.
10. Prime mover.
11. Proportioning system.
12. Superheater.
13. Storage system.
14. Vaporizing system.
312 Oil Gas Generating Equipment.
Use equivalent or similar units for other accounts.
313 Generating Equipment -- Other processes.
Use equivalent or similar units for other accounts.
314 Coal, Coke, and Ash Handling Equipment.
A. Dock Equipment:
1. Bridge.
2. Capstan or winch, power.
3. Conveyor.
4. Crane.
5. Elevator.
6. Loading tower.
7. Unloading device.
B. Loading and Grading Equipment:
1. Bin.
2. Bin unloader.
3. Chute.
4. Complete screen.
5. Crusher.
6. Grizzly.
7. Separator.
8. Skip hoist.
C. Yard Equipment:
1. Bridge.
2. Car.
3. Car puller.
4. Conveyor.
5. Conveyor structure.
6. Hoist.
7. Locomotive.
8. Pulverizing system.
9. Railroad siding.
10. Scales (platform, track, or other)
11. Signal system.
12. Track hopper.
13. Tractor.
14. Trestle.
315 Catalytic Cracking Equipment.
1. Air dryer.
2. Air proportioning machine.
3. Alarm system.
4. Boiler.
5. B.t.u. adjuster.
6. Calorimixer.
7. Catalytic furnace.
8. Compressor.
9. Condenser.
10. Cooler.
11. Cooling tower.
12. Cooling tower basin.
13. Crane.
14. Fractionalizing towers.
15. Filter.
16. Heater.
17. Heat exchanger.
18. Panel or panels, devoted to a single purpose, with equipment.
19. Separator.
20. Spray pond.
21. Turbine.
22. Unloading station.
23. Vaporizer.
24. Washer cooler.
25. Water treatment plant.
26. Well.
316 Other Reforming Equipment.
Use equivalent or similar units shown for other accounts.
317 Purification Equipment.
1. Absorber or adsorber.
2. Actifyer.
3. Compressor.
4. Condenser.
5. Cooling coil.
6. Decanter.
7. Filter.
8. Oxide conditioner.
9. Purifying box.
10. Precipitator.
11. Scrubber.
12. Signal system.
13. Spray pond.
14. Stack.
15. Thionizer.
16. Tar extractor.
17. Washbox.
18. Washer cooler.
19. Well.
318 Residual Refining Equipment.
A. Ammonia Recovery Apparatus:
1. Absorber or adsorber.
2. Condenser.
3. Decanter.
4. Drier.
5. Extractor.
6. Fixed still.
7. Free still.
8. Heat exchanger.
9. Lime leg.
10. Lime mixer.
11. Well.
B. Other Refining Equipment:
Use equivalent or similar units shown for other accounts.
C. Phenol Recovery Apparatus:
Use equivalent or similar units shown for other accounts.
D. Sulphur Recovery Apparatus:
1. Autoclave.
2. Bin.
3. Filter.
4. Washer.
E. Tar Refining Apparatus:
1. Centrifuge.
2. Condenser.
3. Cooler.
4. Dehydrator.
5. Heater.
6. Still pot.
7. Well.
319 Gas Mixing Equipment.
1. Alarm system.
2. Alcohol units.
3. Calorimeter.
4. Compressor.
5. Control system.
6. Mixing system.
7. Odorizing system.
8. Oil fogger.
9. Scrubber.
320 Other Equipment.
Each principal item, system or set of equipment such as:
1. Communication system.
2. Compressed air system.
3. Fire protection system.
4. First aid equipment.
5. Gasoline pump.
6. Machine shop equipment.
7. Odorizing equipment.
8. Office furniture and equipment.
9. Oil fogger.
10. Power equipment (portable).
11. Production laboratory equipment.
12. Signal system.
13. Telemetering equipment.
14. Works exhauster.
18 CFR 161.3 b. natural gas production plant
18 CFR 161.3 B-1. Natural Gas Production and Gathering Plant
326 Gas Well Structures.
327 Field Compressor Station Structures.
328 Field Measuring and Regulating Station Structures.
329 Other Structures.
(See Acct. 366 -- Transmission Structures and Improvements.)
330 Producing Gas Wells -- Well Construction.
1. Well. (Includes only costs incident to drilling well.)
331 Producing Gas Well -- Well Equipment.
1. Bailing equipment.
2. Boiler or heater, complete with accessories.
3. Casing head valve assembly, Christmas Tree.
4. Casing.
5. Derrick.
6. Pumping outfit.
7. Separator.
8. Tubing.
332 Field Lines.
(See Acct. 367 -- Transmission Mains for applicable retirement units
of property.)
333 Field Compressor Station Equipment.
(See Acct. 368 -- Transmission Compressor Station Equipment for
applicable retirement units of property.)
334 Field Measuring and Regulating Station Equipment.
(See Acct. 369 -- Transmission Measuring and Regulating Station
Equipment for applicable retirement units of property.)
335 Drilling and Cleaning Equipment.
1. Bailing machine complete.
2. Boiler complete with accessories.
3. Derrick, hoist or crane.
4. Drilling machine or rig.
5. Special equipment, such as mud or water tanks, blowout preventors,
etc.
6. Tanks, pumps, etc.
336 Purification Equipment.
1. Boiler complete with accessories.
2. Cooling tower, basin or pond.
3. Gas cleaner, cooler, separator, scrubber, etc.
4. Heat exchanger, fuel gas, oil and water cooling, etc.
5. Panel or panels, devoted to a single purpose, with equipment
associated thereto such as instruments, wiring, etc.
6. Piping.
7. Portable or packaged unit.
8. Power and light system complete.
9. Still or reboiler.
10. Sulfur removal apparatus.
11. Tank or vessel.
337 Other Equipment.
(See Acct. 371 -- Transmission Other Equipment for applicable
retirement units of property.)
18 CFR 161.3 B-2. Products Extraction Plant
341 Structures and Improvements.
(See Acct. 366 -- Transmission Structures and Improvements for
applicable retirement units of property.)
342 Extraction and Refining Equipment.
1. Absorber, adsorber, reabsorber, still, dephlegmator, etc.
2. Air compressor, with or without driving unit and accessories.
3. Boiler complete with accessories.
4. Communication equipment, intrastation.
5. Cooling facilities; cooling tower, basin, pond, induced draft
apparatus, etc.
6. Crane, trolley and hoist, etc.
7. Fire protection equipment.
8. Fuel measuring and regulating equipment. (See Acct. 369 for
applicable units.)
9. Foundation.
10. Fractionating tower.
11. Furniture and fixtures and general equipment, etc. (See Accts.
391 and 398 for applicable units.)
12. Gas compressor, with or without driving unit and accessories.
13. Heat exchanger, fuel, gas, oil, or water cooling, etc.
14. Loading rack complete.
15. Panel or panels, devoted to a single purpose with equipment
associated thereto such as instruments, wiring, etc.
16. Plant piping.
17. Power and light system.
18. Power generating equipment. (See Acct. 307 for applicable
retirement units.)
19. Portable or package unit.
20. Pump, with or without driving unit and accessories.
21. Tank or vessel.
22. Water treatment system.
23. Water supply system.
343 Pipe Lines.
(See Acct. 367 -- Transmission Mains for applicable retirement units
of property.)
344 Extracted Products Storage Equipment.
1. Foundation.
2. Regulator.
3. Tank or vessel.
4. Underground cavern.
345 Compressor Equipment.
(See Acct. 368 -- Transmission Compressor Station Equipment for
applicable retirement units of property.)
346 Gas Measuring and Regulating Equipment.
(See Acct. 369 -- Transmission Measuring and Regulating Station
Equipment for applicable retirement units of property.)
347 Other Equipment.
(See Acct. 371 -- Transmission Other Equipment for applicable
retirement units of property.)
18 CFR 161.3 3. Natural Gas Storage Plant
18 CFR 161.3 a. underground storage plant
351 Structures and Improvements.
(See Acct. 366 -- Transmission Structures and Improvements for
applicable retirement units of property.)
352 Wells.
1. Bailing equipment.
2. Boiler or heater.
3. Casing.
4. Casing head valve assembly (Christmas Tree).
5. Derrick.
6. Separator.
7. Tubing.
8. Well (all intangible costs).
353 Lines.
(See Acct. 367 -- Transmission Mains for applicable retirement units
of property.)
354 Compressor Station Equipment.
(See Acct. 368 -- Transmission Compressor Station Equipment for
applicable retirement units of property.)
355 Measuring and Regulating Equipment.
(See Acct. 369 -- Transmission Measuring and Regulating Station
Equipment for applicable retirement units of property.)
356 Purification Equipment.
(See Acct. 336 -- Natural Gas Production Purification Equipment for
applicable retirement units of property.)
357 Other Equipment.
(See Acct. 371 -- Transmission Other Equipment for applicable
retirement units of property.)
18 CFR 161.3 b. other storage plant
361 Structures and Improvements.
(See Acct. 366 -- Transmission Structures and Improvements for
applicable retirement units of property.)
362 Gas Holders.
1. Buried pipe holder (each bank or group).
2. Fire protection equipment.
3. Foundation, including pit and tank where integral with foundation.
4. Holder.
5. Holder heating system.
6. Hortonsphere and/or high pressure tanks.
7. Underground cavern.
363 Purification equipment.
(See Acct. 336 -- Natural Gas Production Purification Equipment for
applicable retirement units of property.)
363.1 Liquefaction equipment.
1. Cold box.
2. Heat exchanger.
3. Compressors.
4. Condensers.
5. Instrumentation.
6. Pumps.
7. Separators.
8. Tanks.
363.2 Vaporizing equipment.
1. Compressors.
2. Instrumentation.
3. Piping.
4. Pumps.
5. Valves.
6. Vaporizers.
363.3 Compressor equipment.
(See Acct. 368 -- Compressor Station Equipment for applicable
retirement units of property.)
363.4 Measuring and regulating equipment.
(See Acct. 369 -- Transmission Measuring and Regulating Station
Equipment for applicable retirement units of property.)
363.5 Other equipment.
(See Acct. 371 -- Transmission Other Equipment for applicable
retirement units of property.)
18 CFR 161.3 c. base load liquefied natural gas terminaling and
processing plant
364.2 Structures and improvements.
1. Air conditioning system, ventilating system, heating system, or
any combination thereof.
2. Bin or bunker (when part of structure framework).
3. Bridge, trestle, etc.
4. Bulkhead, retaining wall, etc.
5. Canal or dam.
6. Dock, pier, platform or wharf.
7. Drainage and sewerage system.
8. Elevator, crane, hoist, etc., complete with operating mechanism.
9. Fence complete with gates.
10. Fire escape system, nonmarine.
11. Fire protection system.
12. Foundation (equipment) when includible in structure.
13. Light and power system complete.
14. Plumbing system.
15. Railroad or track system, including culverts, etc.
16. Roof, with or without supporting members. (A structure of
irregular shape having more than one roof level may have several
isolated roofs, each of which shall be considered an entire roof. In the
case of structures to which lateral extensions have been made, even
though having but one roof level, that part of the roof covering an
entire section built at one time shall be considered an entire roof.)
17. Structure complete, with or without stack or chimney.
18. Tunnel, pipe line.
19. Tunnel, marine.
20. Vacuum cleaning system.
21. Water basin or reservoir.
22. Water supply system, including well.
23. Yard drainage system.
24. Yard lighting system.
364.3 LNG processing terminal equipment.
Liquefaction processing equipment
1. Cooling units.
2. Heat exchanger.
3. Compressor.
4. Condensor.
5. Instrumentation.
6. Pumps.
7. Separators.
8. Tanks.
Transfer system
1. Holders.
2. Blowers.
3. Instrumentation.
4. Piping.
5. Pumps.
6. Unloading arms.
7. Valves.
Storage facilities
1. Berm or Dike.
2. Holders (Tanks).
3. Instrumentation.
4. Piping.
5. Valves.
Vaporization system
1. Compressors.
2. Instrumentation.
3. Piping.
4. Pumps.
5. Valves.
6. Vaporizers.
BTU stabilization equipment
1. Compressors.
2. Heat exchangers.
3. Instrumentation.
4. Piping.
5. Pumps.
6. Valves.
Electric system
1. Battery.
2. Generator.
3. Switchgear.
4. Motor control center.
Nitrogen system
1. Compressor.
2. Holders (Tanks).
3. Instrumentation.
4. Piping.
5. Pumps.
6. Valves.
Truck loading system
1. Loading racks.
2. Piping.
3. Pumps.
4. Tanks.
5. Other equipment.
Marine facilities
1. Capstran.
2. Control power/pulpit.
3. Evacuation Systems.
4. Unloading arms.
364.4 LNG transportation equipment.
1. LNG barge.
2. LNG maritime tankers.
3. LNG tank truck.
4. Other LNG transportation equipment.
364.5 Measuring and regulating equipment.
(See Acct. 369 -- Transmission Measuring and Regulating Station
Equipment for applicable retirement units of property.)
364.6 Compressor station equipment.
(See Acct. 368 -- Transmission Compressor Station Equipment for
applicable retirement units of property.)
364.7 Communication equipment.
(See Acct. 397 -- General Communication Equipment for applicable
retirement units of property.)
364.8 Other equipment.
(See Acct. 371 -- Transmission Other Equipment for applicable
retirement units of property.)
18 CFR 161.3 4. Transmission Plant
366 Structures and Improvements.
366.1 Compressor Station Structures.
366.2 Measuring and Regulating Station Structures.
366.3 Other Structures.
Note: Many retirement units set forth in the following detail
indicate the basic intention of treating relatively costly items as
retirement units wherever they occur. Under certain conditions some
small items, even though specifically listed, shall be considered part
of larger units where they are not relatively costly (for instance,
minor landscaping, equipment accessories, etc.) or where they are
essentially packaged type units.
1. Air conditioning system, ventilating system, heating system, or
any combination thereof.
2. Bin or bunker (when part of structure framework).
3. Bridge, trestle, etc.
4. Bulkhead, retaining wall, etc.
5. Canal, dam, dock, pier, wharf, etc.
6. Drainage and sewerage system.
7. Elevator, crane, hoist, etc., complete with operating mechanism.
8. Equipment item, such as, a generator, engine, turbine, compressor,
or similar item of equipment includible in structures, with or without
associated wiring, control equipment, etc.
9. Fence complete with gates.
10. Fire escape system.
11. Fire protection system.
12. Foundation (equipment) when includible in structure.
13. Light and power system complete.
14. Plumbing system.
15. Refrigeration system.
16. Railroad or track system, including culverts, etc.
17. Roof, with or without supporting members. (A structure of
irregular shape having more than one roof level may have several
isolated roofs, each of which shall be considered an entire roof. In the
case of structures to which lateral extensions have been made, even
though having but one roof level, that part of the roof covering an
entire section built at one time shall be considered an entire roof.)
18. Structure complete, with or without stack or chimney.
19. Tunnel, pipe line, etc.
20. Vacuum cleaning system.
21. Water basin or reservoir.
22. Water supply system, including well.
23. Yard drainage system.
24. Yard lighting system.
367 Mains.
1. Bridge, trestle, catenary suspension or other special overhead
crossing structure.
2. Cathodic protection equipment; rectifier complete with
transformer, or other power facility, including ground bed. (See item 8
below.)
3. Crossover or tie-over.
4. Drip. (See item 8 below.)
5. Header or other special construction feature.
6. Multiple mains connected to headers or other expensive
construction feature.
7. Pigging or special cleaning assembly.
8. Pipe, 100 ft. length (may include pipe, fittings, specials,
drips, joints, blocking, cathodic protection, clamps, and other
accessory items).
9. Revetment.
10. River crossing, aerial or submerged including header.
11. Scrubber, dust catcher or cleaner.
12. Tank or vessel.
13. Tunnel.
14. Valve, power operated, with or without appurtenant fittings,
by-passes and platforms, 6'' and larger. (See item 8 above.)
368 Compressor Station Equipment.
A. Compressor Equipment:
1. Aeration tower.
2. Aftercooler.
3. Air cleaner, with or without piping.
4. Air compressing unit, with or without prime mover and accessories.
5. Agitator complete with motor and accessories.
6. Boiler complete (heating).
7. Boiler plant equipment. (For applicable retirement units of
property see Account 306 -- Boiler Plant.)
8. Cathodic protection equipment; rectifier complete with
transformer, or other power facility, and ground bed.
9. Chlorinator.
10. Compressor -- Gas, with or without prime mover and accessories.
11. Cooling coil.
12. Cooling tower basin.
13. Cooling tower superstructure.
14. Coupling device, i.e. speed reducer, speed increaser, clutch
coupling, etc.
15. Demineralizer.
16. Driving unit -- prime mover.
17. Exciter.
18. Fan or blower, with or without prime mover and accessories.
19. Fin fan structure complete with supports.
20. Foundation.
21. Gauge board, panel or panels, devoted to a single purpose, with
equipment accessory thereto.
22. Generator, with or without driving unit and accessories.
23. Heater, gas, complete with packing glands.
24. Heat exchanger.
25. Lube oil cooler, with or without piping.
26. Lube oil filter, with or without piping.
27. Main Switchboard -- panel or panels, devoted to a single purpose,
with equipment accessory thereto.
28. Meter, displacement, or orifice including flanges, vanes, plates,
etc.
29. Motor generator set, with accessories.
30. Motor control cubicle.
31. Muffler, with or without piping.
32. Odorizing equipment.
33. Other Power Equipment. (For applicable retirement units of
property see Account 307 -- Other Power Equipment.)
34. Piping header, 6'' and over in size, with or without valves and
blocking. (See Note A -- General Instructions.)
35. Plant piping, a run of any system (oil, gas, steam, water, etc.,
6 inches or over in size, with or without valves, between two or more
retirement units of property and/or a header). (See Note A -- General
Instructions.)
36. Proportional feeder, with accessories.
37. Pump, with or without driving unit and accessories.
38. Regulator, pressure complete, with or without control equipment,
including pilot regulators, fittings, etc.
39. Special or other costly prefabricated items of a special nature.
40. Supercharging equipment.
41. Switchgear (compartment, cubicle, etc.), complete assembly.
42. Tank or vessel such as absorber, air receiver, fractionator,
preheater, scrubber, separator, still, storage tank, etc.
43. Telemetering equipment.
44. Transformer and/or capacitor not accessory to a panel.
45. Unit substation, complete. (For applicable retirement units of
property see Account 307 -- Other Power Equipment.)
46. Valve, power operated, pressure reducing, atmospheric relief, 6
inch normal size and larger or relatively costly.
47. Well.
48. Wire, cable, supports and duct lines. (For applicable retirement
units of property see Account 307, Group D.)
B. Fire Protection Apparatus -- each principal item of equipment such
as:
1. Fire engine.
2. Foamite engine.
3. Hose cart, complete with hose.
C. Office Furniture and Equipment:
(See Account 391 for applicable retirement units of property.)
D. Tools, Shop and Garage Equipment:
(See Account 394 for applicable retirement units of property.)
E. Laboratory Equipment:
(See Account 395 for applicable retirement units of property.)
F. Miscellaneous Equipment -- each principal item of equipment if
includible in this account.
369 Measuring and Regulating Station Equipment.
1. Automatic control equipment (including small regulators, pipe
fittings and valves, etc.).
2. Calorimeter.
3. Fogger equipment or system.
4. Foundation.
5. Instruments. (See general instructions.)
6. Line heater.
7. Meter, displacement, or orifice including support, flanges, vanes
and plates.
8. Odorizer equipment or system.
9. Panel or panels, devoted to a single purpose, with equipment
associated thereto such as instruments, wiring, piping, etc.
10. Pit or vault.
11. Piping, a run of any system 6 inches or over in size with or
without valves, between two or more units of property and/or a header.
(See Note A General Instructions.)
12. Piping header, 6 inches and over in size, with or without valves
or blocking. (See Note A General Instructions.)
13. Portable or package unit.
14. Regulator complete, with or without control equipment, including
pilot regulators, fittings, etc.
15. Tanks and vessels, such as scrub-regulators, fittings, etc.
16. Telemetering equipment.
17. Valve, power operated, pressure reducing, atmospheric relief, 6
inch nominal pipe size and larger or relatively costly valve.
370 Communication Equipment.
Each principal item or set of equipment such as:
1. Antenna and supporting structure.
2. Carrier current coupling capacitor.
3. Carrier current transmitting and receiving set.
4. Intercommunicating telephone apparatus.
5. Microwave apparatus.
6. Receiver, stationary or mobile.
7. Storage battery set, or motor generator set.
8. Teletype apparatus.
9. Transmitter, stationary or mobile.
10. Wire, cable, supports and duct lines. (For applicable retirement
units of property see Account 307, Group D.)
371 Other Equipment.
1. Air compressor.
2. Communication equipment, intrastation.
3. Fire protection equipment.
4. Gasoline dispensing equipment.
5. Hospital and infirmary equipment.
6. Laboratory equipment.
7. Odorizing equipment.
8. Office furniture and equipment.
9. Supervisory control (telemetering) equipment.
10. Tool, shop and garage equipment.
18 CFR 161.3 5. Distribution Plant
375 Structures and Improvements.
(See Acct. 366 -- Transmission Structures and Improvements for
applicable retirement units of property.)
376 Mains.
(See Acct. 367 -- Transmission Mains for applicable retirement units
of property.)
377 Compressor Station Equipment.
(See Acct. 368 -- Transmission Compressor Station Equipment for
applicable retirement units of property.)
378 Measuring and Regulating Station Equipment -- General.
379 Measuring and Regulating Station Equipment -- City Gate Check
Stations.
(See Acct. 369 -- Transmission Measuring and Regulating Station
Equipment for applicable retirement units of property.)
380 Services.
1. Complete service.
381 Meters.
1. Meter.
382 Meter Installations.
1. Meter installation.
Note: At the option of the utility, meter installations may be
accounted for as part of the cost installed of meters in accordance with
the provisions of Acct. 381, Meters.
383 House Regulators.
1. House regulator.
384 House Regulator Installations.
1. House regulator installation.
Note: At the option of the utility, house regulator installations
may be accounted for as part of the cost installed of house regulators
in accordance with the provisions of Acct. 383, House Regulators.
385 Industrial Measuring and Regulating Station Equipment.
(See Acct. 369 -- Transmission Measuring and Regulating Station
Equipment for applicable retirement units of property.)
386 Other Property on Customers' Premises.
Each principal item of equipment if includible in this account.
387 Other Equipment.
(See Acct. 371 -- Transmission Other Equipment for applicable
retirement units of property.)
18 CFR 161.3 6. General Plant
390 Structures and Improvements.
(See Acct. 366 -- Transmission Structures and Improvements for
applicable retirement units of property.)
391 Office Furniture and Equipment.
Each principal item of equipment:
1. Duplicating equipment, such as blueprint machine, photostat
machine, offset press, photocopy machine, transcopy machine.
2. Mechanical processing equipment, such as, key punch, sorter,
tabulator, electronic calculator.
3. Office equipment, such as, accounting machine, adding machine,
calculating machine, coin counter, signature writer, typewriter.
4. Office furniture, such as, desk, cabinet, safe, file.
392 Transportation Equipment.
Each principal item of equipment such as:
1. Airplane.
2. Automobile.
3. Boat.
4. Electrical vehicle.
5. Motor truck.
6. Motorcycle.
7. Tractor.
8. Trailer, wagon.
393 Stores Equipment.
Each principal item of equipment such as:
1. Crane, hoist, or chainfall.
2. Counter, shelving, bins or racks, each location.
3. Portable elevating and stacking equipment.
4. Truck.
394 Tool, Shop and Garage Equipment.
Each principal item of equipment:
1. Garage and repair equipment, such as, gasoline or oil pump,
battery charging set, car lift, power-driven greasing machine.
2. Shop equipment and tools, such as, drill press, welding machine,
forge, furnace, lathe, planer, shaper.
3. Tools and work equipment, such as, pneumatic tool, welding set,
power saw, transit, level, concrete mixer.
395 Laboratory Equipment.
Each principal item of equipment such as:
1. Analysis apparatus.
2. Analytical balance.
3. Automatic electronic prover.
4. Binocular electronic reader.
5. Calorimeter.
6. Centrifuge.
7. Drying oven.
8. Hydro-pneumatic meter tester.
9. Indicating transmitter.
10. Metameter test set.
11. Meter prover.
12. Odormeter.
13. Recording flow meter.
14. Recording orifice.
15. Test meter.
16. Vaportester.
396 Power Operated Equipment.
Each principal item of equipment such as:
1. Air compressor, including driving unit and vehicle.
2. Back filling machine.
3. Boring machine.
4. Bulldozer.
5. Crane or hoist.
6. Digger.
7. Pile driver.
8. Pipe cleaning machine.
9. Pipe coating or wrapping machine.
10. Tractor.
11. Trencher.
397 Communication Equipment
Each principal item of equipment such as:
1. Antenna and supporting structure.
2. Carrier current coupling capacitor.
3. Carrier current transmitting and receiving set.
4. Intercommunicating telephone apparatus.
5. Microwave apparatus.
6. Receiver, stationary or mobile.
7. Storage battery set or motor generator set.
8. Teletype apparatus.
9. Transmitter, stationary or mobile.
10. Wire, cable, supports and duct lines.
(For applicable retirement units of property see Account 307, Group
D.)
398 Miscellaneous Equipment.
Each principal item of equipment if includible in this account.
399 Other Tangible Equipment.
Units to be assigned as items of property are included herein.
18 CFR 161.3 PART 225 -- PRESERVATION OF RECORDS OF NATURAL GAS
COMPANIES
Sec.
225.1 Promulgation.
225.2 General instructions.
225.3 Schedule of records and periods of retention.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (1982); E.O. 12009, 3 CFR 142 (1978); Natural Gas Act, 15
U.S.C. 717-717w (1982); Natural Gas Policy Act, 15 U.S.C. 3301-3432
(1982); Federal Power Act, 16 U.S.C. 792-828c (1982).
18 CFR 225.1 Promulgation.
(a) This part is prescribed and promulgated as the regulations
governing the preservation of records by natural gas companies subject
to the jurisdiction of the Commission, to the extent and in the manner
set forth therein;
(b) This part shall, as to all natural gas companies now subject to
the jurisdiction of the Commission, become effective as herein revised
on January 1, 1972. As to any natural gas company which may hereafter
become subject to the jurisdiction of the Commission, this part shall
become effective as of the date when such natural gas company becomes
subject to the jurisdiction of the Commission.
(Order 450, 37 FR 6304, Mar. 28, 1972)
18 CFR 225.2 General instructions.
(a) Scope of this part. (1) The regulations in this part apply to
all books of account and other records prepared by or on behalf of the
natural gas company. See subsection 64 of the schedule for those
records which come into possession of the natural gas company in
connection with the acquisition of property, such as purchase,
consolidation, merger, etc.
(2) The regulations in this part shall not be construed as excusing
compliance with any other lawful requirement for the preservation of
records for periods longer than those prescribed herein.
(3) Unless otherwise specified in the schedule ( 225.3), duplicate
copies of records may be destroyed at any time: Provided, however, That
such duplicate copies contain no significant information not shown on
the originals.
(4) Records other than those listed in the schedule may be destroyed
at the option of the natural gas company: Provided, however, That
records which are used in lieu of those listed shall be preserved for
the periods prescribed for the records used for substantially similar
purposes. And, provided further, That retention of records pertaining
to added services, functions, plant, etc., the establishment of which
cannot be presently foreseen, shall conform to the principles embodied
herein.
(5) Notwithstanding the provisions of the Records Retention Schedule,
the Commission may, upon the request of the company, authorize a shorter
period of retention for any record listed therein upon a showing by the
company that preservation of such record for a longer period is not
necessary or appropriate in the public interest or for the protection of
investors or consumers.
(b) Designation of supervisory official. Each natural gas company
subject to the regulations in this part shall designate one or more
persons with official responsibility to supervise the natural gas
company's program for preservation and the authorized destruction of its
records.
(c) Protection and storage of records. The natural gas company shall
provide reasonable protection for records subject to the regulations in
this part from damage by fires, floods, and other hazards and, in the
selection of storage spaces, safeguard the records from unnecessary
exposure to deterioration from excessive humidity, dryness, or lack of
proper ventilation.
(d) Definition of record media. (1) For the purpose of these
regulations, the data constituting the records listed in the schedule
may be retained in any of the media forms in Figure 1 below, provided
that the media selected has a standard life expectancy equal to or in
excess of the specified retention period. However, records supporting
plant cost shall be retained in their original form unless microfilmed.
(See general instruction (j), for periods of retention.) In no instance,
except in emergencies, will media regeneration to achieve the full
length of period retention be allowed without Commission approval of the
request of the company. In emergency cases management shall take action
as prudence calls for and notify the Commission immediately thereafter
(2) If the media form of the record retained is other than a readable
paper copy, then reader and/or printer equipment and related printout
programs, if required, shall be provided by the utility for data
reference.
(3) The media form initially selected for the record becomes the
''original'' for that particular record. If subsequent conditions
(e.g., improved media life expectancy, increased company resources,
environmental factors) require and the remaining retention period
permits a change in the media forms the company may convert to another
media and dispose of its old equipment, provided the certification
processes described in paragraph (e) of this section are observed and
data referencing capability is maintained.
(e) Microform and tape certification. (1) As the initial recording
media --
(i) Except as provided in paragraph (e)(1)(ii) of this section, each
microform record series:
(A) Shall contain, at the beginning, a microform introduction stating
the title of the record series, the date prepared, the name of the
official responsible for validating or confirming the data contained
therein; and
(B) Shall be closed with a clear and standard microform notation
indicating the completion of the series and the date.
(ii) If an official permanent record series is a computer output
product (i.e., output paper or microfilm, jacketed microfiche, or
aperture cards), any certification that may otherwise be required under
paragraph (e)(1)(i) of this section is not required if:
(A) The series is prepared in accordance with written standard
procedures developed, or accepted general business practices followed,
by the company that ensure the integrity of record series that are the
product of computer output; and
(B) Such procedures or practices include the name or title of the
official responsible for validating or confirming the data contained in
the record series and confirming that a particular computer output
record series was produced in accordance with the standard procedures or
practices.
(iii) If after validation, supplemental data and/or corrections
(i.e., resulting from computer programing) are required, said microform
may be produced separately or as a part of the series rerun, but shall
be affixed to the original microform certificate as described in
subparagraph (1)(i) of this paragraph.
(iv) Each tape record series shall be externally labeled and shall
include, as a basic part of the program, at the beginning of that series
an introduction stating the record series title, date prepared, the name
of the official responsible for validating or confirming the data
contained therein and an index where appropriate. Each record series
shall be closed with a clear and standard notation indicating the
completion of that series and the date.
(2) Conversion from other media --
(i) Each microform record series shall include, as an integral part,
a certificate(s) stating that the microforms are direct and facsimile
reproductions of the original records and that they have been made in
accordance with prescribed instructions. Such certificate(s) shall be
executed by a person(s) having personal knowledge of the facts covered
thereby.
(ii) Each microform record series shall commence and end with a
statement as to the nature and arrangement of the records reproduced,
and the date. Rolls of film shall not be cut except to produce jacketed
microfiche. Supplemental or retaken film, whether of misplaced or
omitted documents or of portions of microform found to be defective,
shall be attached to the beginning of the microform record series.
However, if a retrieval system using such methods as, for example, image
count indexing or ''blipping'' is used, the supplemental or retaken film
may be attached at the end of the series if provisions at the beginning
of the series advise the viewer of the location of the problem frames
and the location of the supplemental or retaken frames. If supplemental
or retaken film of misplaced or omitted documents, or of portions of
microform found to be defective, are attached to the microform record
series, the certificate described in paragraph (e)(1)(i) of this section
shall cover the supplemental or retaken film and shall state the reasons
for the attachment.
(iii) If, in accordance with the provisions of paragraph (f) of this
section, the natural gas company elects to convert records to the tape
media, the same certification provision specified in paragraph
(e)(1)(iii) of this section must be provided in the conversion program.
(f) Change of media for existing records. Those records prepared and
maintained under previous regulations in a paper media and whose
remaining retention period falls within the life expectancy range of any
of the media detailed in Figure 1, may be converted to that media at the
natural gas company's option, provided the applicable certification
processes described in paragraph (e) of this section are observed and an
audit referencing capability maintained.
(g) Media. (1) All records created or maintained in a media and a
format other than readable entries on paper shall:
(i) Be prepared, arranged, classified, identified, and indexed as to
permit the subsequent location, examination, and reproduction of the
record to a readable media;
(ii) Be stored in such a manner as to provide reasonable protection
from hazards such as fire, flood, theft, etc.; and maintained in a
controlled environment;
(iii) Be regenerated, including proper certification, when damaged.
(Also see 225.2(d)(1).)
(2) The company shall be prepared to furnish, at its own expense,
standard facilities for reading media and shall additionally provide, if
the Commission so directs, copies of the record in a readable form.
(3) All film stock shall be of approved
operationally-permanent-record micro-copying type, which meets the
current specifications of the American National Standards Institute.
(h) Destruction of records. The destruction of the records permitted
to be destroyed under the provisions of the regulations in this part may
be performed in any manner elected by the natural gas company concerned.
Precautions should be taken, however, to macerate or otherwise destroy
the legibility of records, the content of which is forbidden by law to
be divulged to unauthorized persons.
(i) Premature destruction or loss of records. When records are
destroyed or lost before the expiration of the prescribed period of
retention, a certified statement listing, as far as may be determined,
the records destroyed and describing the circumstances of accidental or
other premature destruction or loss shall be filed with the Commission
within ninety (90) days from the date of discovery of such destruction.
(j) Schedule of records and periods of retention. The schedule of
records, 225.3, shows the period of time that designated records shall
be preserved. However, records related to plant shall be retained a
minimum of 25 years unless accounting adjustments resulting from
reclassification and original cost studies have been approved by the
regulatory commission having jurisdiction, and either (1) continuing
plant inventory records are maintained (see Definition No. 8,
''Continuing Plant Inventory Records,'' parts 201 and 204 of this
subchapter), or (2) unitization of construction costs appear in work
orders.
(k) Retention periods designated ''Destroy at option''. Use of the
retention period, ''Destroy at option,'' in the regulations in this part
constitutes authorization for such destruction under the conditions
specified for the particular types of records, only if such optional
destruction is appropriate to limited managerial interest in such
records and if such optional destruction is not in conflict with other
legal retention requirements or usefulness of such records in satisfying
pending regulatory actions or directives.
(l) Records of services performed by associated companies. The
natural gas company to which the regulations in this part apply shall
assure the availability of records of services performed by associated
companies for the periods indicated herein, as are necessary, to support
the cost of services rendered to it by an associated company.
(m) Index of records. At each office of the natural gas company
where records are kept or stored, such records as are herein required to
be preserved shall be so arranged, filed and currently indexed that they
may be readily identified and made available to representatives of the
Commission.
(n) Schedule of notes: (1) For the purposes of the regulation, a
stockholder's account may be treated as a closed account at the time
that such stockholder ceases to be a holder of record of the particular
class and series of stock of the company and the 6-year retention period
prescribed herein shall run from that date. If such person subsequently
acquires shares of capital stock of the company and thus again becomes a
stockholder of the company, the record of such acquisition shall be
treated as a new stockholder account.
(2) The terms ''bonds'' and ''debentures,'' as used in paragraphs (a)
through (f) of this section, shall include all debt securities, such as
bonds, debentures, or notes other than debt securities which evidence
temporary borrowings and which are expected to be repaid out of the
proceeds of the sale of longer term securities. Typical of such
temporary debt securities as described in 4(i) would be notes issued to
banks evidencing temporary working capital and construction loans and
gas storage loans.
(3) Canceled bonds and debentures and paid interest coupons
pertaining thereto may be destroyed, provided that a certificate of
destruction giving full descriptive reference to the documents destroyed
shall be made by the person or persons authorized to perform such
destruction and shall be retained by the company for the period herein
prescribed. The certificate of destruction evidencing the destruction
of paid interest coupons pertaining to bonds or debentures need not
contain a listing of the bond or debenture serial numbers pertaining to
such paid interest coupons. When documents represent debt secured by
mortgage, the certificate of destruction shall also be authorized by a
representative of the trustee(s) acting in conjunction with the person
or persons destroying the documents or shall have the trustee(s)
acceptance thereon. The certificate of destruction above described may
be destroyed 6 years after the payment and discharge of the bonds or
debentures or interest coupons described in such certificate.
(4) If a retention period is prescribed elsewhere in the schedule
with respect to any document which is included as an exhibit to any
filing retained pursuant to the requirements of this item, the company
need retain only one copy of such document in its files provided
appropriate cross references are established.
(5) Life or mortality study data for depreciation purposes shall be
retained for 25 years or for 10 years after plant is retired, whichever
is longer.
(Order 450, 37 FR 6304, Mar. 28, 1972, as amended by Order 258, 47 FR
42724, 42725, Sept. 29, 1982; Order 335, 48 FR 44483, Sept. 29, 1983)
18 CFR 225.3 Schedule of records and periods of retention.
1 Capital stock records. (Reserved)
2 Proxies and voting lists. (Reserved)
3 Reports to stockholders.
4 Debt security records. (Reserved)
5 Filings with and authorization by regulatory agencies. (Reserved)
6 Organizational documents:
(a) Minute books.
7 Contracts and agreements.
8 Accountants' and auditors' reports.
9 Automatic data processing records.
10 General and subsidiary ledgers.
11 Journals.
12 Journal vouchers and entries.
13 Cash books.
14 Voucher register.
15 Vouchers.
16 Accounts receivable. (Reserved)
17 Records of securities owned. (Reserved)
18 Payroll records. (Reserved)
19 Assignments, attachments and garnishments. (Reserved)
20 Insurance records.
21 Injuries and damages. (Reserved)
22 Production -- Gas.
23 Transmission and distribution -- Gas.
23.1 Underground storage of natural gas.
24 Customers service. (Reserved)
25 Records of auxiliary and other operations. (Reserved)
26 Maintenance work orders and job orders.
27 Personnel records. (Reserved)
28 Employees benefit and pension records. (Reserved)
29 Instruction to employees and other. (Reserved)
30 Plant ledgers.
31 Construction work in progress.
32 Retirement work in progress.
33 Summary sheets.
34 Appraisals and valuations.
35 Maps. (Reserved)
36 Engineering records.
37 Contracts and other agreements relating to utility plant.
38 Reclassification of utility plant account records.
39 Accumulated depreciation and depletion of utility plant account
records.
40 Procurements.
41 Material ledgers.
42 Materials and supplies received and issued.
43 Records of sale of scrap and materials and supplies.
44 Inventory of materials and supplies. (Reserved)
45 Customers service applications and contracts.
46 Rate schedules.
47 Customer guarantee deposits. (Reserved)
48 Meter reading sheets and records. (Reserved)
49 Maximum demand pressure temperature.
50 Miscellaneous billing data.
51 Revenue summaries.
52 Customers ledgers. (Reserved)
53 Merchandise sales. (Reserved)
54 Collection reports and records. (Reserved)
55 Customers' account adjustments. (Reserved)
56 Uncollectible accounts. (Reserved)
57 Tax records.
58 Statement of funds and deposits.
59 Records of deposits with banks and others.
60 Records of receipts and disbursements.
61 Statistics.
62 Budgets and other forecasts.
63 Correspondence. (Reserved)
64 Records of predecessor and former associates.
65 Reports to Federal and State regulatory commissions.
66 Copies of advertisements.
(Order 450, 37 FR 6304, Mar. 28, 1972, as amended by Order 258, 47 FR
42726, Sept. 29, 1982; Order 335, 48 FR 44483, Sept. 29, 1983; Order
95-A, 51 FR 7932, Mar. 7, 1986)
18 CFR 225.3 SUBCHAPTER G -- APPROVED FORMS, NATURAL GAS ACT
18 CFR 225.3 Pt. 250
18 CFR 225.3 PART 250 -- FORMS
Sec.
250.1 (Reserved)
250.2 Form of proposed cancellation of tariff or part thereof (see
154.64).
250.3 Form of proposed cancellation or termination of contract or
part thereof (see 154.64).
250.4 Form of certificate of adoption (see 154.65).
250.5 Contract summary to be filed by all applicants for certificates
of public convenience and necessity, including successors in interest
(see 157.24(a) of this chapter).
250.6 Form of application to be filed by distributor under section
7(a), seeking gas service of not more than 2,000 Mcf per day (3d year of
operation) for a single community (see 156.3(d) of this chapter).
250.7 Form of contract summary for abandonment applications.
250.8 Summary to accompany rate schedule filed by an assignee as
successor in interest.
250.9 Form of notice of proposed cancellation or termination of
independent producer rate schedule or part thereof, where no new
schedule is to be filed in its place.
250.10 Application for small producer exemption.
250.11 (Reserved)
250.12 Escrow agreement.
250.13 (Reserved)
250.14 Independent producer rate change or initial billing statement.
250.15 (Reserved)
250.16 Format of compliance plan for transportation services and
affiliate transactions.
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.
250.1 (Reserved)
18 CFR 250.2 Form of proposed cancellation of tariff or part thereof
(see 154.64).
Name of Company
FPC Gas Tariff Original Volume No.
Revised Sheet No.
Superseding Sheet(s) No.
Notice is hereby given that effective ---------- (date) FPC Gas
Tariff of ---------------- (Name of Company) is to be cancelled.
Notice is hereby given that effective ---------- (date) Rate Schedule
---------- constituting ---------- Sheet(s) No.(s) ------ of the FPC Gas
Tariff of ---------------- (Name of Company) is to be cancelled.
Notice is hereby given that effective ---------- (date) Sheet(s)
No.(s) ------ of the FPC Gas Tariff of ---------------- (Name of
Company) is to be cancelled.
Issued by ---------------- (Name and Title of Issuing Officer)
Effective ---------- (date).
Issued on
(Order 144, 13 FR 6376, Oct. 30, 1948)
18 CFR 250.3 Form of proposed cancellation or termination of contract
or part thereof (see 154.64).
Notice is hereby given that effective the ------------ day of
------------ , ---- , the contract with -------------------- , (Name of
purchaser or purchasers) dated ------------ and relating to service
under rate schedule(s) ---------------------- (Here identify the rate
schedule(s), giving sheet numbers in the Tariff) is to be
---------------------- (Specify whether it automatically terminates by
its terms or is to be canceled by action of the parties)
---------------------- (Name of natural-gas company filing notice)
By
(Title)
Dated --------------------
(Order 144, 13 FR 6376, Oct. 30, 1948)
18 CFR 250.4 Form of certificate of adoption (see 154.65).
The ------------------------ (Exact name of company or person)
-------------------------------- (Address) effective
------------------------ (Effective date of adoption) hereby adopts,
ratifies, and makes its own, in every respect, the Tariff and contracts
listed below, which have heretofore been filed with the Federal Power
Commission by ---------------------- (Exact name of predecessor)
---------------------- (Here identify the Tariff and contracts adopted.)
---------------------- (Name of successor)
By
(Title)
Dated -------------------- , 194 -- .
(Order 144, 13 FR 6376, Oct. 30, 1948)
18 CFR 250.5 Contract summary to be filed by all applicants for
certificates of public convenience and necessity, including successors
in interest. (See 157.24(a) of this chapter.)
OMB Reference: ''Format No. FERC 558'' is the identification number
used by the Commission and the Office of Management and Budget to
reference the filing requirements in 250.5
All applicants shall complete part I. An applicant who is an
assignee (including farmout) filing as a successor shall also complete
part II-A and part II-B if the related rate schedule is under
suspension, if the rate is in effect subject to refund, or if the sale
is being made by the assignor under termporary certificate with a rate
refund condition. The reporting pressure base is 14.73 psia. The
information in this format will not be treated as confidential or
proprietary.
Date
(1) Name of applicant
(2) Person responsible for application:
(a) Name and title
(b) Mailing address
(c) Telephone No.
(3) Name of purchaser
(4) Are applicant and purchaser affiliated?
No ------ Yes ------
(5) Location of sale
(Field, County, State)
(6) Type of application2
(7) Date of contract
(8) Base price in dollars per MMBtu (exclusive of any statutory
adjustments and tax reimbursements)
--
(9) Statutory adjustments, including tax reimbursements, to be added
to the base price in Item (8) above3
--
(10) Estimated sales for the first month of deliveries (MMBtu or Mcf
per month)
--
(11) Estimated delivery pressure
(12) Delivery point, e.g., wellhead, plant tailgate, central point in
field, etc.
--
(13) Advance payments: Yes No
(14) Assignor
(15) Description of service to be continued:
(a) FERC Docket No.(s) under which assignor was originally
authorized:
(b) Proposed disposition of assignor's FERC Gas Rate Schedule(s)
(16) Suspension Docket No.
(17) Price currently being collected subject to refund (in dollars
per MMBtu)
(18) Date price made effective subject to refund
(19) Estimated amount subject to possible annual refund $
(20) In addition to the refund obligation required by 154.92(d)(3),
does assignee intend to file bond or undertaking to assure total refund:
(a) from the date increased rate of assignor became effective subject
to refund or (b) from date operation commenced under assignor's
temporary certificate containing a refund condition? Yes No
2Specify whether initial service, add acreage, delete acreage,
continue service of predecessor, farmout, or other. If ''other'', give
details.
3Specify the amount for each type of statutory adjustment (e.g.,
gathering, dehydration, compression, liquefiable hydrocarbons, etc.) in
the manner actually billed and received, either in cents per MMBtu of
Mcf.
18 CFR 250.6 Form of application to be filed by distributor under
section 7(a), seeking gas service of not more than 2,000 Mcf per day (3d
year of operation) for a single community (see 156.3(d) of this
chapter).
1. Name of applicant (indicate whether individual, corporation or
municipality).
2. Address.
3. Name, title, mailing address, and telephone number of person to be
contacted concerning the application.
4. Name of natural gas company from whom service is desired.
5. Are you now rendering gas service? If so, briefly describe
operations.
6. Nature of service sought, giving a brief description of proposal,
including location of community, population, number of residences and
kind of service sought and to be rendered, showing:
(a) Is this an initial connection with the pipe line, or is it an
extension or improvement of existing facilities?
(b) Estimate of maximum day requirements for residential, commercial
and industrial customers for each of the first three years of proposed
operations (Mcf at 14.73 psia), and how the estimates were derived;
(c) Estimate of annual requirements for residential, commercial and
industrial customers for each of the first three years of proposed
operations (Mcf at 14.73 psia), and how the estimates were derived.
7. Do you have or do you need a franchise to render the proposed
service? If you have filed an application for such a franchise, with
whom was it filed and what action has been taken on it?
8. Do you have or do you need a state certificate approving the
proposed distribution system project? If you have filed an application
for such a certificate, with whom was it filed and what action has been
taken on it?
9. When do you propose to start construction and when do you estimate
it will be completed? When do you propose to start selling gas?
10. How much are the facilities expected to cost? Show separately
the estimated cost of the distribution system, the connecting supply
lines, legal fees, financing fees and engineering fees, and briefly
state how the estimates were derived.
11. Have you used the services of an engineering consultant? If so,
the consultant should state his experience in the design of distribution
systems, cost data of systems now in service compared with his initial
estimates, and the actual rate at which new customers were attached in
the new distribution systems.
12. How do you propose to finance the proposed facilities? Submit
evidence that the money will be available. (This evidence need not be
submitted if you have a state certificate for your project.)
13. For each of the first three years of operation of the proposed
facilities, show (a) the estimated gross annual revenues for the natural
gas estimated to be sold to residential, commercial and industrial
customers as shown in item 6(c) and the rates you propose to charge, and
(b) the cost of gas purchased by you (state the rate to be paid to the
pipeline supplier and the pipeline's rate schedule under which you will
purchase said gas), other operating and maintenance expenses and
operating revenue deductions, and (c) the net operating revenues. If
you have received a certificate of public convenience and necessity
issued by a local regulatory commission, it may be submitted in lieu of
this requirement.
14. Municipalities should submit a bond amortization and interest
schedule for the life of the bond issue related to the project and
computation of the average debt service coverage ratio over the life of
the issue. State briefly how all estimates were derived. Exhibits to
be furnished:
Exhibit A. A geographical map showing clearly all of the
transmission facilities proposed to be installed and operated by you
between your distribution system and the transmission pipeline system of
the proposed supplier, including:
(a) Location, length and size of your transmission lines;
(b) Location and size (related horsepower) of your transmission
compressor stations (if any);
(c) Location and designation of each point of connection of your
proposed transmission facilities with proposed pipeline supplier;
(d) And if known, location, length and size of facilities to be
installed by the proposed supplier.
Exhibit B. A flow diagram showing the maximum daily capacity of the
proposed connecting pipeline to carry gas from the supplier to the
community to be served. The diagram should show expected operating
pressures on the connecting pipeline at the point of connection with the
supplier and at the other terminal of the connecting pipeline flow of
gas through the connecting pipeline in Mcf per day; length of the
connecting pipeline and its inside and outside diameter.
(Order 280, 29 FR 4879, Apr. 7, 1964)
18 CFR 250.7 Form of contract summary for abandonment applications.
(See 157.30(b) of this chapter.)
1. Name of seller
2. Sale authorized in Docket No.
3. Name of purchaser
4. Location of sale
(Field, county, state)
5. Date of basic contract and Rate Schedule No.
6. Last effective rate (cents/Mcf)
7. Measurement pressure base (psia)
8. Involved in suspension proceeding: No ---- Yes ---- Docket No.
9. Purchaser has indicated concurrence: Yes ---- No ---- .
10. Reasons for abandonment (Specify)
(Order 278, 29 FR 3700, Mar. 25, 1964)
18 CFR 250.8 Summary to accompany rate schedule filed by an assignee as
successor in interest.
(See 154.92(d) of this chapter.)
(1) Name of assignee
(2) Name of assignor
(3) Designation of assignor's FPC Gas Rate Schedule
(4) Effective date of transfer of ownership
(5) Proposed effective date of assignment
(6) (a) Is related certificate application filed herewith: Yes ( );
No ( ). If no, reason(s)
(b) Is motion to be substituted for assignor being filed in any
formal rate docket involving the assignor's rate schedule: Yes ( ); No
( ). If yes, give docket number(s).
(7) Additional comments:
(8)
(Signature (or name) of assignee)
By
(Title)
Dated:
Parties served copies of this summary:
(Order 278, 29 FR 3700, Mar. 25, 1964)
18 CFR 250.9 Form of notice of proposed cancellation or termination of
independent producer rate schedule or part thereof, where no new
schedule is to be filed in its place.
(See 154.97(a) of this chapter.)
Date ----------------
(1) Rate schedule proposed to be canceled
(2) Type of cancellation -- Partial ( ); Complete ( ).
(3) Proposed effective date of cancellation
(4) (a) Has service ceased from acreage involved: Yes ( ); No ( ).
(b) Is application to abandon filed herewith: Yes ( ); No ( ). (1)
If no, give reason:
(5) Reason for cancellation (not necessary if the reasons are stated
in any related accompanying abandonment application)
(6) Additional comments
(7) Signature and title of producer or person authorized to sign in
his behalf:
(Signature)
(Title)
(8) The following persons have been served with copies of this
notice:
(Order 278, 29 FR 3701, Mar. 25, 1964)
18 CFR 250.10 Application for small producer exemption.
(See 157.40(b)(4) of this chapter.)
Note: Independent Producers of natural gas whose total
jurisdictional sales on a nationwide basis for the preceding calendar
year, combined with those of ''affiliated producers,'' were not in
excess of 10,000,000 Mcf may file the information called for in this
form for a Small Producer Exemption to sell gas (in four copies).
Include volume of gas paid for but not taken under prepayment clauses or
otherwise, and volumes of gas sold under other independent producer rate
schedules in the proportion that the independent producer seeking to
come within 157.40 has an interest in such sales. Do not include sales
made pursuant to percentage sales contracts. If insufficient space is
given for a complete answer, continue the answer on the reverse side or
on a separate sheet, noting the relevant number.
1. Name of applicant
2. State of organization
3. Location of principal place of business
4. Type of organization (corporation, partnership, joint venture,
etc.)
5. Person responsible for application name, title, and mailing
address
6. Total jurisdictional sales volumes at ------ psia for calendar
year preceding application. (If more than one applicant is to be
covered by this exemption, give the total jurisdictional sales volumes
of each applicant separately.)
7. List all certificates presently held by docket number and list all
contracts on file with the Commission as rate schedules by rate schedule
name and number. Include in such listing applicants' interests in gas
sales covered by other producers' certificates and rate schedules. List
all interest owners and the amount of their interest for each sale to be
covered by this exemption. (See reverse side for reporting)
8. List all owners of more than 10 percent interest in applicant:
(a) Individual name; (b) percent of ownership
9. List all interest owned by the individually named owners in other
natural gas companies: (a) Individual name; (b) company names; (c)
percent of applicant ownership
10. List for each owner the positions held by these individual owners
in applicant company or any other natural gas company
11. Is applicant or any individual owner listed, affiliated with any
purchaser of jurisdictional gas from applicant? (If so list name of
buyer and seller for each sale and nature of affiliation.)
Signature
Title
Date
(Order 308, 30 FR 14011, Nov. 5, 1965, as amended by Order 428, 36 FR
5602, Mar. 25, 1971; 46 FR 15876, Mar. 10, 1981)
250.11 (Reserved)
18 CFR 250.12 Escrow agreement.
(a) A natural-gas company which has been ordered by the Commission to
retain refundable moneys in an escrow account pending further action of
the Commission prescribing the disposition of such refund moneys, and
has executed an escrow agreement in the form prescribed in paragraph (b)
of this section, may file, in lieu of filing the agreement with the
Commission, an original and two conformed copies of a certificate
attesting to the fact that it has executed such an agreement.
(b) Form of escrow agreement:
(Name of Respondent)
and
(Name of Escrow Agent)
This agreement made between (Name of Respondent) hereinafter called
Respondent and (Name of Bank), a banking institution, association, or
trust company, used as a depository for funds of the U.S. Government,
(Address), hereinafter called ''Escrow Agent;''
Witnesseth:
Section 1.01. As used in this agreement, the following expressions
shall have the meanings respectively indicated:
(a) ''Commission'' means the Federal Power Commission, an agency of
the United States of America.
(b) ''Secretary'' means the Secretary, the Acting Secretary, or the
Office of the Secretary of the Commission.
(c) ''Proceeding'' means the proceeding or proceedings before the
Commission entitled: ''(Name of Respondent), Docket No. ------ .''
(d) ''Respondent'' means the party, whether a producer, seller or
jurisdictional pipeline purchaser, who is directed by order of the
Commission to place refund moneys in escrow.
(e) ''Refund moneys'' means the amounts of revenue, including
applicable interest, for gas sales charged and collected by Respondent
computed as ordered by the Commission, which are to be placed in escrow
under this Escrow Agreement.
Sec. 2.01. Respondent hereby transfers and assigns to the Escrow
Agent the amount of refund moneys ordered to be held in escrow, and to
that end, agrees to deposit, or cause to be deposited, such moneys
within 10 days of the date hereof with the Escrow Agent plus interest as
ordered by the Commission.
Sec. 2.02. Respondent, the Escrow Agent, and the successors and
assigns of each, shall be, and hereby are bound to the Commission to pay
all or any portion of such moneys and the interest thereon to such
person or persons as may be identified and designated by the Commission
and in the manner which it may be directed by the Commission in the
proceeding.
Sec. 2.03. The Escrow Agent shall invest and reinvest such monies
only in obligations of the United States of America which are due and
payable within 1 year or less from the date of purchase.
Sec. 2.04. The Escrow Agent shall be liable only for such interest as
the invested funds described in sections 2.01 and 2.03 shall earn, and
no other interest may be collected from the Escrow Agent.
Sec. 2.05. The Escrow Agent shall be entitled to such compensation as
is fair, reasonable, and customary for its services as such, which
compensation shall be paid out of the corpus, and earned interest of the
Escrow Fund. The Escrow Agent shall likewise be entitled to
reimbursement for its reasonable expenses, necessarily incurred in the
administration of this escrow, which reimbursement shall be made out of
the corpus, or earned interest of the Escrow Fund.
Sec. 2.06. The Escrow Agent shall report to the Secretary of the
Commission annually certifying the amount deposited in escrow, and
accounting for any disbursements therefrom for the annual period.
Sec. 2.07. Should Respondent be released by final order of the
Commission from any or all obligation with respect to such refundable
monies, this Escrow Fund shall be discharged in like amount; otherwise
it shall remain in full force and effect.
Sec. 3.01. Upon receipt by the Escrow Agent of a copy of an order of
the Commission directing disbursement by Respondent of the refund
monies, the Escrow Agent shall transfer and deliver to Respondent such
monies for payment to the parties ultimately determined by the
Commission to be entitled thereto, and to that end the Escrow Agent
shall liquidate all securities held in the Escrow Fund necessary to make
such payments, and this Escrow Fund shall thereupon cease and terminate.
Sec. 4.01. The Escrow Agent shall be fully protected in acting and
relying on any order, certificate, direction, communication, or other
document, from the Commission, which the Escrow Agent in good faith
believes to be genuine and what it purports to be.
Sec. 4.02. The Escrow Agent may at any time and from time to time
consult with legal counsel of its own choice, and shall be fully
protected in acting and relying on the advice of such counsel with
respect to any matter arising in the administration of this Escrow Fund.
Sec. 4.03. The Escrow Agent shall have no liability for damage
resulting from any action or omission of it hereunder, unless it be
established that such damage was caused by negligence contributing to
such damages, or willful bad faith of the Escrow Agent.
Sec. 4.04. Nothing in sections 4.02 and 4.03 in this Article IV shall
be construed as limiting or impairing the obligation of the Escrow Agent
under section 2.02 hereof.
Sec. 4.05. The obligations of the Escrow Agent hereunder shall be
limited to the amounts deposited with it hereunder, and the interest
thereon resulting from investments as herein directed.
Sec. 4.06. The Escrow Agent joins herein for the purpose of
evidencing its approval and consent to the terms hereof and its
acceptance of the fund hereby created, and the Escrow Agent agrees to
hold, invest, administer and dispose of the funds deposited hereunder
with it in accordance with the terms hereof.
Sec. 5.01. This instrument may be amended by an order, letter or
other communication of the Commission, provided that no such amendment
shall substantially increase the duties or diminish the compensation,
privileges, or immunities of the Escrow Agent.
Sec. 5.02. The Escrow Agent may resign at any time upon thirty (30)
days' prior written notice given to the Commission. Upon the
resignation of the Escrow Agent, a successor bank or trust company used
as a depository for funds of the U.S. Government, shall be designated by
Respondent. However, resignation of an Escrow Agent shall not become
effective until a qualified successor Escrow Agent has indicated its
acceptance of the appointment as such. Upon the designation and
acceptance of the appointment of the qualified successor Escrow Agent,
the resigning Escrow Agent shall transfer and deliver, without charge,
all property, funds and accounts then held thereunder to the successor
Escrow Agent.
Executed this ------ day of
19 -- .
(Name of Respondent)
By
(Name of Escrow Agent)
Attest:
------------------------
Attest:
------------------------
(Order 400, 35 FR 7011, May 2, 1970)
250.13 (Reserved)
18 CFR 250.14 Independent producer rate change or initial billing
statement.
(See 154.92 and 154.94)
OMB Reference: ''Format FERC No. 559'' is the identification number
used by the Commission and the Office of Management and Budget to
reference the filing requirements in 250.14.
This format is to be used to file either a Notice of Change in Rate
or an Initial Billing Statement by checking the appropriate box and
answering the applicable questions. Rates should be shown in dollars to
three decimal places. The reporting pressure base is 14.73 psia. The
information in this format will not be treated as confidential or
proprietary.
Check One:
Rate Change Statement ( 154.94)
Initial Billing Statement ( 154.92)
(1) Producer
(2) Buyer
(3) Gas Rate Schedule No.
(4) Basic Contract Date
(5) Location:
(a) Field/Plant (b) County/Parish (c) State
(6) Type of change
(7) Contract Basis
(8) Proposed Effective Date
(9) Are future escalations to be covered by affidavit filed under
154.94(h)?
(10)(a) FERC Notice of Determination Control No.
(b) Date jurisdictional agency's well determination is received
by the FERC, as published in the Federal Register
(11) Rate Information:
Check One: $ per MMBtu $ per Mcf
(12) Remarks
-- --
(13) Person responsible for this filing:
(a) Name and title (b) Signature (c) Address -- (d) Contact Person
(if different from person identified in (a) (e) Telephone number
of person to be contacted -- (f) Date
18 CFR 250.14 Instructions
Item (6): Use only for reporting rate changes (e.g., change in
contract rate; change in minimum rate or maximum lawful price under
sections 102(d), 104, 106(a), 108, or any other applicable section of
the NGPA).
Item (7): Specify the basic article or section of the contract. If
the basis for the proposed rate is an amendment, supply the date of the
amendment.
Item (9): This information applies only to the first sales for which
qualification to collect the NGPA base rate under the rate schedule is
being established.
Item (10): This information applies to the first well under a rate
schedule that qualifies for the gas ceilings under either sections
102(d), 108, or any other applicable section of the NGPA.
Item (11)(c): Report the total adjustment amounts and explain under
Item (12), ''Remarks''. These adjustments include tax reimbursements
(if the proposed change is to base rates other than to the maximum
lawful price under the NGPA), dehydration, compression, etc.
250.15 (Reserved)
18 CFR 250.16 Format of compliance plan for transportation services and
affiliate transactions.
(a) Who must comply. An interstate natural gas pipeline that
transports natural gas for others pursuant to subparts B, G, H, or K of
part 284 and is affiliated, as that term is defined in 161.2 of this
chapter, in any way with a natural gas marketing or brokering entity
(except a pipeline that does not conduct any transportation transactions
with its affiliated marketer) must:
(1) File the information prescribed in paragraph (b) of this section,
(2) Maintain and provide the information specified in paragraph (c)
of this section, and
(3) Maintain all information required under this section from the
time the information is received until December 31, 1993.
(b) What to file. An interstate pipeline must file the following
information:
(1) New or existing tariff provisions containing the following:
(i) A complete list of operating personnel and facilities shared by
the interstate natural gas pipeline and the affiliated marketing or
brokering company;
(ii) The specific information and format required from a shipper for
a valid request for transportation service, including, for transactions
in which an affiliated marketer is involved, the items of information in
paragraph (b)(2) of this section;
(iii) The procedures used to address and resolve complaints by
shippers and potential shippers including a provision that the pipeline
will respond initially within 48 hours and in writing within 30 days to
such complaints;
(iv) The procedures used by the natural gas pipeline to inform
affiliated and nonaffiliated shippers and potential shippers on:
(A) The availability and pricing of transportation service; and
(B) The capacity of the pipeline available for transportation.
(2) FERC Form No. 592, consisting of a log that contains the
following information on all requests for transportation service made by
affiliated marketers or in which an affiliated marketer is involved for
transportation that would be conducted pursuant to subparts B, G, H, or
K of part 284:
(i) The date of receipt of the request,
(ii) The date that the request was accepted as valid,
(iii) The specific affiliation of the requester with the interstate
pipeline, and the extent of the pipeline's affiliation, if any, with the
person to be provided transportation service,
(iv) The extent of the supplier's affiliation with the interstate
pipeline from whom service is requested,
(v) The identity of the shipper making the request for service
including designating whether the shipper is a local distribution
company, an interstate pipeline, an intrastate pipeline, an end-user, a
producer, or a marketer,
(vi) The maximum daily contract volume of gas requested to be
transported and the total contract volume of gas requested to be
transported over the life of the contract,
(vii) The producing area of the source of the gas requested to be
transported,
(viii) The date service is requested to commence and terminate,
(ix) A list of all receipt and delivery points between which the gas
is requested to be transported and the distance between the receipt and
delivery points that are the furthest apart,
(x) Whether the service requested is firm or interruptible,
(xi) The state of the ultimate end user of the gas,
(xii) The identity of the transportation rate schedules and the
transportation rates applicable for such service,
(xiii) Whether any of the gas being transported is subject to
take-or-pay relief for the transporting pipeline and, if so, how much,
(xiv) Whether and by how much the cost of the gas to the affiliated
marketer exceeds the price received for the sale of the gas by the
affiliated marketer, after deducting associated costs, including those
incurred for transportation; i.e., whether the gas is being sold at a
loss,
(xv) Current status of the request, including whether the request is:
(A) Incomplete,
(B) Complete and awaiting service,
(C) Complete, a contract signed, and awaiting commencement of
service,
(D) Complete, service has begun and the Commission docket number
assigned to the transaction,
(E) Withdrawn, or
(F) Denied and the reason why,
(xvi) The position of the request in the transportation request
queue,
(xvii) The disposition of the request, includng the date the
requester was notified of availability of capacity, the date the
contract was executed, the date service actually commenced, and any
explanation concerning the disposition of the request,
(xviii) Any complaints by the shipper or end user concerning the
requested or furnished service and the disposition of such complaints,
(xix) Whether the transportation is being requested, offered or
provided at discounted rates, duration of the discount requested,
offered or provided, the maximum rate or fee, the rate or fee actually
charged during the billing period, the shipper, corporate affiliation
between the shipper and the transporting pipeline, and the quantity of
gas scheduled at the discounted rate during the billing period for each
delivery point, and
(xx) Whether the pipeline has granted a waiver of a tariff provision
in providing the requested service.
(c) What to maintain. (1) An interstate pipeline must maintain the
information in paragraph (b)(2) of this section for all requests for
transportation services made by nonaffiliated shippers or in which a
nonaffiliated shipper is involved from the time the information is
received until December 31, 1993.
(2) The information required to be maintained by this section will be
available from September 12, 1988 until December 31, 1994 to:
(i) The Commission on request, and
(ii) The public under subpart D of part 385 of this chapter.
(3) The information required to be maintained by this section must be
maintained on 9-track magnetic tape or computer disk. The format and
specifications for maintenance of the information can be obtained at the
Federal Energy Regulatory Commission, Division of Public Information,
825 North Capitol Street NE., Washington, DC 20426.
(d) When to file. (1) The information in paragraph (b)(1) of this
section and entries in the log specified in paragraph (b)(2) of this
section relating to transportation requests for which transportation has
commenced 30 days or more previously, which have been denied, or which
have been pending for more than six months, must be filed initially with
the Commission by September 19, 1988, and thereafter as required by
paragraphs (d)(2) and (d)(4) until the earlier of: 90 days after the
Commission has determined that the pipeline is in full compliance with
the requirements of Order No. 636; or December 31, 1993. This
requirement applies to transportation service that commenced or
transportation requests that were denied after July 14, 1988, or that
were pending for six months or more on July 14, 1988.
(2) The information required in paragraph (b)(1) of this section must
be filed quarterly if any changes occur.
(3) The information in paragraph (b)(2) of this section relating to
transportation requests must be updated on a daily basis if any changes
occur.
(4) The information in paragraph (b)(2) of this section relating to
transportation requests for which transportation has commenced 30 days
or more previously, which have been denied, or which have been pending
more than six months, must be filed:
(i) For the items in paragraph (b)(2)(i) through (xviii) and
(b)(2)(xx) of this section, at the end of the month following the month
any changes occur; and
(ii) For the items in paragraph (b)(2)(xix) of this section, within
15 days of the close of the pipeline's billing period. A report of a
discount under this section satisfies a pipeline's obligation to report
under 284.7(d)(5)(iv) of this chapter.
(e) How to file. (1) Each filing made with the Commission under this
section must be made on 9-track magnetic tape or computer disk. The
format and specifications for submission of the information prescribed
by this section on magnetic tape or computer disk can be obtained at the
Federal Energy Regulatory Commission, Division of Public Information,
825 North Capitol St. NE., Washington, DC 20426.
(2) The magnetic tape or computer disk must be accompanied by one
paper printout of all the FERC Form No. 592 information submitted on
the magnetic tape or computer disk. The format for the paper printout
can be obtained at the Federal Energy Regulatory Commission, Division of
Public Information, 825 North Capitol Street NE., Washington, DC 20426.
(3) The magnetic tape or computer disk, and paper printout, submitted
must be accompanied by a cover letter. The cover letter must include
the file name, file attribute, and recording density of the magnetic
tape submitted by the natural gas pipeline company. The cover letter
must also include the subscription provided in 385.2005(a) of this
chapter.
(4) The subscription provided in paragraph (d)(3) of this section
must certify in addition to the requirements in 385.2005(a) of this
chapter, that the paper printout contains the same information as the
magnetic tape or computer disk and that the signer has read and knows
the contents of the paper printout are true to the best knowledge and
belief of the signer.
(f) Where to file. (1) The magnetic tape or computer disk and
accompanying paper printout and cover letter must be submitted to:
Office of the Secretary, Federal Energy Regulatory Commission, 825 North
Capitol Street NE., Washington, DC 20426.
(2) Hand deliveries of a magnetic tape or computer disk and
accompanying paper printout and cover letter may be made to: Office of
the Secretary, Federal Energy Regulatory Commission, room 3110, 825
North Capitol Street NE., Washington, DC 20426.
(g) Public access. (1) An interstate pipeline must maintain and make
available to the public all filings with the Commission under paragraph
(b)(1) of this section by providing:
(i) One paper copy at the pipeline's principal place of business
during regular business hours and;
(ii) Copies by mail of any item requested within seven calendar days
of a written request, for which the pipeline may charge the cost of
postage and fifteen cents per page photocopied or per computer printout
page provided.
(2) An interstate pipeline must provide 24-hour access, by electronic
means, to the date specified in paragraph (b)(2) of this section.
Access to the information must be provided once the service has begun.
A pipeline must, on a daily basis, either update the information or
indicate that no changes have occurred in the log information.
(h) Penalty for failure to comply. (1) Any person who transports gas
for others pursuant to subparts B, G, H, or K of part 284 of this
chapter and who knowingly violates the requirements of 161.3, 250.16,
or 284.13 of this chapter will be subject, pursuant to sections 311(c),
501, and 504(b)(6) of the Natural Gas Policy Act of 1978, to a civil
penalty, which the Commission may assess, of not more than $5,000 for
any one violation.
(2) For purposes of this paragraph, in the case of a continuing
violation, each day of the violation will constitute a separate
violation.
(Order 497, 53 FR 22161, June 14, 1988; 55 FR 1808, Jan. 19, 1990;
Order 497-B, 55 FR 53292, Dec. 28, 1990; Order 497-C, 57 FR 11, Jan. 2,
1992; Order 497-D, 57 FR 58982, Dec.14, 1992)
18 CFR 250.16 PART 260 -- STATEMENTS AND REPORTS (SCHEDULES)
Sec.
260.1 FERC Form No. 2, Annual report for Major natural gas
companies.
260.2 FERC Form No. 2-A, Annual report for Nonmajor natural gas
companies.
260.3 FERC Form No. 11, Natural gas pipeline company monthly
statement.
260.4 Form No. 14, Annual report for importers and exporters of
natural gas.
260.5 -- 260.6 (Reserved)
260.7 FERC Form No. 15, Interstate pipeline's annual report of gas
supply.
260.7a Annual statement of gas transported by interstate pipelines
for other interstate pipelines.
260.8 System flow diagrams: Format No. FERC 567.
260.9 Report by natural gas pipeline companies on service
interruptions occurring on the pipeline system.
260.11 Form No. 8, Underground gas storage report.
260.12 FERC Form No. 16, Report of gas supply and requirements.
260.13 FERC Form No. 549-ST, Form of self-implementing
transportation reports.
260.15 Form No. 69, Report of alternate fuel demand due to natural
gas curtailments.
260.200 Original cost statement of utility property.
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352.
Editorial Note: For Federal Register citations affecting forms
listed in part 260, please consult the List of CFR Sections Affected in
the Finding Aids section of this volume.
18 CFR 260.1 FERC Form No. 2, Annual report for Major natural gas
companies.
(a) The form of Annual Report of Natural Gas Companies (Class A and
Class B), designated herein as FERC Form No. 2, is prescribed for the
reporting year 1980 and thereafter.
(b) Each natural gas company, as defined in the Natural Gas Act (15
U.S.C. 717, et seq.) which is a major company (as defined in part 201 of
subchapter F of this chapter) must prepare and file with the Commission
for the calendar year beginning January 1, 1980, and for each calendar
year thereafter, on or before April 30 following the close of such
calendar year, FERC Form No. 2.
(1) Before December 30, 1988, an original and such number of
conformed copies of the above-designated FERC Form No. 2 as indicated
in the general instructions set out in that form all properly filled out
and verified. One copy of the report should be retained by the
respondent in its files. The conformed copies may be carbon copies, or
other reproductions, if legible.
(2) On or after December 30, 1988, the form must be filed as
prescribed in 385.201 of this chapter and as indicated in the general
instructions set out in that form, all properly filled out and verified.
One copy of this report should be retained by the respondent in its
files.
(Order 121, 46 FR 6887, Jan. 22, 1981, as amended by Order 390, 49 FR
32527, Aug. 14, 1984; Order 493, 53 FR 15030, Apr. 27, 1988)
18 CFR 260.2 FERC Form No. 2-A, Annual report for Nonmajor natural gas
companies.
(a) Prescription. The form of Annual Report for Nonmajor Natural Gas
Companies, designated herein as FERC Form No. 2 -- A, is prescribed for
the year 1980 and each year thereafter.
(b) Filing requirements -- (1) Who must file. Each natural gas
company, as defined by the Natural Gas Act, which is considered nonmajor
as defined in part 201 of subchapter F of this chapter, must prepare and
file with the Commission FERC Form No. 2-A.
(i) Before December 30, 1988, an original and conformed copies
pursuant to the general instructions set out in that form must be filed.
(ii) On or after December 30, 1988, the form must be filed as
prescribed in 385.2011 of this chapter and as indicated in the general
instructions set out in that form.
(2) When to file. Such report be filed on or before March 31 of each
year for the previous calendar year, beginning with a filing by March
31, 1981 for the 1980 calendar year.
(Natural Gas Act, as amended, 15 U.S.C. 717-717w; Natural Gas Policy
Act of 1978, 15 U.S.C. 3301-3432; Federal Power Act, as amended, 16
U.S.C. 792-828c; Department of Energy Organization Act, 42 U.S.C.
7101-7352; E.O. 12009, 3 CFR part 142 (1978))
(Order 101, 45 FR 60900, Sept. 15, 1980, as amended by Order 390, 49
FR 32527, Aug. 14, 1984; Order 493, 53 FR 15031, Apr. 27, 1988)
18 CFR 260.3 FERC Form No. 11, Natural gas pipeline company monthly
statement.
(a) This form, which is applicable to natural gas companies
designated therein, is designed to obtain on a monthly basis information
concerning selected revenues, income statements, and other items, as
well as details of operation and maintenance expenses.
(b)(1) Who must file. Each natural gas company, as defined in the
Natural Gas Act, whose combined gas sold for resale and gas transported
or stored for a fee exceeded 50 million Mcf at 14.73 pisa (60 F) in the
previous calendar year, must prepare and file with the Commission for
the month beginning March 1, 1980 and for each month thereafter FERC
Form No. 11.
(i) Before November 30, 1988, an original and two copies of the form
must be filed.
(ii) On or after November 30, 1988, the form must be filed as
prescribed in 385.2011 of this chapter and as indicated in the general
instructions in that form.
(2) When to file. Such reports shall be filed within 40 days after
the end of the reported month and shall be signed by the person
authorized to sign such report, but are not required to be filed under
oath.
(Order 74, 45 FR 21625, Apr. 2, 1980, as amended by Order 493, 53 FR
15031, Apr. 27, 1988; Order 493-A, 53 FR 30031, Aug. 10, 1988)
18 CFR 260.4 Form No. 14, Annual report for importers and exporters of
natural gas.
(a) The form of the annual report for importers and exporters of
natural gas is prescribed for the calendar year ending December 31,
1972, and thereafter, and is designated as FPC Form No. 14.
(b) Each person have authorization from the Federal Energy Regulatory
Commission pursuant to section 3 of the Natural Gas Act, to import or
export natural gas must, beginning with the reporting year 1972, and
thereafter annually, file on or before March 31, Form No. 14.
(1) Before December 30, 1988, an original and 3 conformed copies of
the form, signed and certified by an officer of the reporting company.
(2) On or after December 30, 1988, the form must be submitted in the
manner prescribed in 385.2011 of this chapter.
(Order 471, 38 FR 4246, Feb. 12, 1973, as amended by Order 493, 53 FR
15031, Apr. 27, 1988)
260.5 -- 260.6 (Reserved)
18 CFR 260.7 FERC Form No. 15, Interstate pipeline's annual report of
gas supply.
(a) Prescription. The form of Interstate Pipeline's Annual Report of
Gas Supply, designated herein as FERC Form No. 15, is prescribed for
the year 1981 and thereafter.
(b) Filing requirements -- (1) Who must file -- (i) General rule.
Except as provided in paragraph (b)(1)(ii) of this section, all
interstate pipeline companies, as defined by section 2(15) of the
Natural Gas Policy Act (15 U.S.C. 3302(15)), must prepare and file FERC
Form No. 15 in accordance with the instructions set out in the form.
(A) Before December 30, 1988, companies must prepare and file an
original and four copies of the form, or a magnetic tape and
accompanying copy of the form.
(B) On or after December 30, 1988, companies must prepare and file
the FERC Form No. 15 as prescribed in 385.2011 of this chapter and as
indicated in the general instructions in that form.
(ii) Exceptions. The following types of interstate pipelines must
prepare and file, in accordance with the instructions set out in FERC
Form No. 15, before March 30, 1989 an original and four copies, and on
or after March 30, 1989, as prescribed in 385.2011 of this chapter,
only the Identification Schedule (with Certification), the ''Synopsis of
Gas Supply,'' and Schedule II of FERC Form No. 15:
(A) Any interstate pipeline whose total year-end remaining
recoverable gas reserves are owned by such pipeline or controlled by
such pipeline pursuant to producer contracts, and which amount to less
than 50 billion cubic feet of natural gas at the end of any reporting
year; or
(B) Any interstate pipeline purchasing its entire supply of natural
gas from one or more interstate pipelines that are subject to the
general rule in paragraph (b)(1)(i) of this section, or from foreign
suppliers.
(2) When to file. Such reports shall be filed on or before April 1,
for each calendar year ending December 31 of the previous year.
(Order 168, 46 FR 42265, Aug. 20, 1981, as amended by Order 493, 53
FR 15031, Apr. 27, 1988)
18 CFR 260.7a Annual statement of gas transported by interstate
pipelines for other interstate pipelines.
Each interstate pipeline, as defined by section 2(15) of the Natural
Gas Policy Act (15 U.S.C. 3302(15)), which acts only as a transporter of
natural gas for another company in interstate commerce, shall prepare
and file, in accordance with the instructions in Form No. 15, an
original and four copies of a statement which contains the name and
address of each such company for which it transports the gas. Such
statement shall be filed on or before April 1 for each calendar year
ending December 31 of the previous year.
(Order 168, 46 FR 42265, Aug. 20, 1981)
18 CFR 260.8 System flow diagrams: Format No. FERC 567.
(a) Each Major natural gas pipeline company, having a system delivery
capacity in excess of 100,000 Mcf per day (measured at 14.73 p.s.i.a.
and 60 F.), shall file with the Commission by June 1 of each year five
(5) copies of a diagram or diagrams reflecting operating conditions on
its main transmission system during the previous twelve months ended
December 31. For purposes of system peak deliveries, the heating season
overlapping the year's end shall be used. Facilities shall be those
installed and in operation on December 31 of the reporting year. All
volumes shall be reported on a uniform stated pressure and temperature
base.
(b) The diagram or diagrams shall include the following items of
information:
(1) Nominal diameter (inches) of each pipeline.
(2) Miles of pipeline (to nearest 0.1 mile) between points of intake,
delivery, river crossings, storage fields, crossovers, compressor
stations and connections with other pipeline companies.
(3) Direction of flow in the pipelines. If direction of flow can be
reversed at compressor stations, so indicate.
(4) Maximum permissible operating pressure for each pipeline at
discharge side of each compressor station or other critical point,
determined by the Department of Transportation's safety standards.
(5) Total horsepower of compressor engines installed at each
compressor station.
(6) Designed suction pressure for each compressor station, p.s.i.g.
(7) Designed discharge pressure for each station, p.s.i.g.
(8) Maximum volume, Mcf per day that can be compressed at each
compressor station under conditions of suction and discharge set forth
in paragraphs (b) (6) and (7) of this section. If direction of flow
affects these factors provide the information for each direction of
flow.
(9) The fuel requirement at each compressor station under conditions
described in paragraph (b)(8) of this section.
(10) Pressure in the pipeline at points of emergency interconnection
with other pipeline companies which can normally be expected to exist,
and the volume which could be delivered or received at such emergency
interconnection points at such pressures. Give the name of the
interconnecting company.
(11) For each storage field, connected to the system and operated by
the respondent pipeline company, the maximum dependable daily and
seasonal withdrawal volumes available under normal conditions of
operation.
(12) Volumes delivered: (i) The average daily volumes delivered at
each takeoff point, (ii) the volumes delivered at each takeoff point on
the day of maximum coincidental delivery, and (iii) the maximum daily
volumes (noncoincidental) delivered to each customer under rates subject
to FERC jurisdiction.
(13) The average daily volume received at each intake point to the
transmission pipeline system.
(14) The volume received into the transmission pipeline system at
each intake point on the day of maximum coincidental delivery.
(15) The information required by paragraphs (b)(12), (13) and (14),
of this section may be furnished in tabular form, or by reference to
FERC Form No. 2, providing, that the information is suitably keyed to
the diagram by appropriate identifying symbol or number.
(Order 303-A, 31 FR 7226, May 18, 1966, as amended by Order 345, 32
FR 7332, May 17, 1967; Order 430, 36 FR 7052, Apr. 14, 1971; Order
215, 47 FR 10203, Mar. 10, 1982; Order 390, 49 FR 32527, Aug. 14,
1984)
18 CFR 260.9 Report by natural gas pipeline companies on service
interruptions occurring on the pipeline system.
(a) Every natural gas pipeline company shall report to the Federal
Energy Regulatory Commission (Commission) serious interruptions of
service to any wholesale customer involving facilities operated under
certificate authorization from the Commission. Such serious
interruptions of service shall include interruptions of service to
communities, major Government installations and large industrial plants
outside of communities or any other interruptions which are significant
in the judgment of the pipeline company. Interruptible service
interrupted in accordance with the provisions of filed tariffs,
interruptions of service resulting from planned maintenance or
construction and interruptions of service of less than 3-hours duration
need not be reported.
(b) Natural gas pipeline companies must report such interruptions to
service by telegram to the Director, Division of Engineering, Market and
Environmental Analysis, Office of Pipeline and Producer Regulation,
Federal Energy Regulatory Commission, 825 North Capitol Street NE.,
Washington, DC 20425, at the earliest feasible time following such
interruption to service and must state briefly:
(1) The location of the interruption,
(2) The time of the interruption,
(3) The customers affected by the interruption, and
(4) Emergency actions take to maintain service.
(c) If so directed by the Commission or the Director, Division of
Engineering, Market and Environmental Analysis, the company must provide
any supplemental information so as to provide a full report of the
circumstances surrounding the occurrence.
(d) Natural gas pipeline companies shall furnish to the Commission
within 20 days of each interruption to service involving failure of
facilities on any part of the pipeline system operated under certificate
authorization from the Commission a copy of such failure reports as
required by the Department of Transportation reporting requirement under
the Natural Gas Pipeline Safety Act of 1968.
(e) Copies of the telegraphic report on interruption of service shall
be sent to the State commission in those States where service has been
or might be affected.
(Order 401, 35 FR 7413, May 13, 1970, as amended by Order 508, 53 FR
45901, Nov. 15, 1988)
18 CFR 260.11 Form No. 8, Underground gas storage report.
(a) The Form of Underground Gas Storage Report as FPC Form No. 8, is
prescribed.
(b) Each person found by the Commission to be a natural gas company,
as defined by the Natural Gas Act, as amended, including any
jurisdictional affiliate, as defined in 157.40(a)(3) of the
Commission's regulations, that operates an underground natural gas
storage field located in the United States must prepare and file with
the Commission by the tenth day of each month an Underground Gas Storage
Report, FERC Form No. 8, before November 30, 1988, an original and four
copies and, on or after November 30, 1988, as prescribed in 385.2011 of
this chapter. Parts IV, V, VI and VII (page Nos. 2 and 3) of FERC Form
No. 8 are only required to be completed for the initial filing of FERC
Form No. 8, and thereafter whenever any changes or additions of
information initially reported are made.
(Order 534, 40 FR 43894, Sept. 24, 1975, as amended by Order 493, 53
FR 15031, Apr. 27, 1988; Order 493-A, 53 FR 30031, Aug. 10, 1988)
18 CFR 260.12 FERC Form No. 16, Report of gas supply and requirements.
1
(a) Prescription. The form of Report of Gas Supply and Requirements,
designated herein as FERC Form No. 16, is prescribed.
(b) Filing requirements -- (1) Who must file. Each natural gas
pipeline company making sales in interstate commerce of natural gas for
resale must prepare and file if due before April 30, 1989, an original
and four copies, and if due on or after April 30, 1989, as prescribed in
385.2011 of this chapter, FERC Form No. 16, Report of Gas Supply and
Requirements.
(2) When to file. Such reports shall be filed on or before April 30
and September 30 of each year.
(c) Waiver. Upon good cause being shown, the Commission will grant
requests by any company for waiver of the requirement to file Form No.
16.
(Order 88, 45 FR 37816, June 5, 1980, as amended by Order 493, 53 FR
15031, Apr. 27, 1988; Order 493-A, 53 FR 30031, Aug. 10, 1988)
1FERC Form No. 16 filed with the Office of the Federal Register as
part of the original document. Copies may be obtained from Office of
the Secretary, Federal Energy Regulatory Commission, 825 North Capitol
St., NE., Washington, DC 20426.
18 CFR 260.13 FERC Form No. 549-ST, Form of self-implementing
transportation reports.
(a) Prescription. The Form of Self-Implementing Transportation
Reports designed herein as FERC Form No. 549-ST, is prescribed.
(b) Filing requirements -- (1) Who must file. Any interstate or
intrastate pipeline, Hinshaw company or local distribution company
undertaking a transportation transaction under 18 CFR part 284, subparts
B, C, or G, must file FERC Form No. 549-ST. Copies of FERC Form No.
549-ST can be obtained at the:
Energy Information Administration, National Energy Information
Center, EI-207, Forrestal Building, Room 1-F-048, Washington, DC 20585,
Phone Number, 1-202-252-8800
(2) When to file. Initial reports are to be filed within 30 days
after commencing a transportation transaction under part 284.
Subsequent reports are to be filed within 30 days of any material change
in the transportation arrangement under part 284.
(3) What to file. Each reporting company must submit an original and
five copies of FERC Form No. 549-ST and the necessary suport for the
required reporting elements. If a reporting company is unable to supply
a data element, it should attach an explanation.
(4) Where to file. An original and five copies of FERC Form No.
549-ST should be submitted to:
Office of the Secretary, Federal Energy Regulatory Commission, 825
North Capitol Street, NW., Washington, DC 20426.
Hand deliveries of an original and five copies may be made to:
Office of the Secretary, Federal Energy Regulatory Commission, Room
3110, 825 North Capitol Street, NE., Washington, DC 20426.
(Order 458, 51 FR 44284, Dec. 9, 1986)
18 CFR 260.15 Form No. 69,2 Report of alternate fuel demand due to
natural gas curtailments.
(a) The form Alternate Fuel Demand Due to Natural Gas Curtailments
designated as FPC Form No. 69 is prescribed.
(b) Each natural gas company making direct sales in interstate
commerce of natural gas (including SNG and LUG) to customers consuming
such gas shall prepare and file with the Commission an original and four
copies of Report of Alternate Fuel Demand Due to Natural Gas
Curtailments, FPC Form No. 69 on or before August 1, 1975, for the
actual annual period from April 1, 1974, to March 31, 1975, and for the
quarterly period ending June 30th and thereafter on a quarterly basis on
or before April 30th, July 30th, October 30th, and January 30th of each
year.
(Order No. 531, 40 FR 27647, July 1, 1975)
2Form No. 69 was discontinued and replaced with Form No. EIA-50 at
43 FR 27178, June 23, 1978.
18 CFR 260.200 Original cost statement of utility property.
Any natural gas company becoming subject to the jurisdiction of the
Commission shall file, insofar as applicable, the following statements
properly sworn to by the officer in responsible charge of their
compilation:
Statement A showing the origin and development of the company,
including, particularly, a description (giving names of parties and
dates) of each consolidation and merger to which the company, or a
predecessor, was a party and each acquisition of a gas operating unit or
system. Any affiliation existing between the parties shall be stated.
Statement B showing for each acquisition of a gas operating unit or
system by the reporting company or any of its predecessors: (1) The
original cost (estimated only if not determinable from existing
records), (2) the cost of the acquiring company, (3) the amount entered
in the books as of the date of acquisition, (4) the difference between
the original cost and the amount entered in the books, (5) a summary of
all transactions affecting such difference, including retirements,
between the date of each acquisition and the end of the calendar year
prior to the year in which the filing is made, and (6) the amount of
such difference remaining at the latter date.
If the depreciation, retirement, or amortization reserve was adjusted
as of the date of acquisition and in connection therewith, a full
disclosure of the pertinent facts shall be made.
The amount to be included in account 114, Gas Plant Acquisition
Adjustments, shall be subdivided so as to show the amounts applicable to
(a) gas plant in service, (b) gas plant leased to others, and (c) gas
plant held for future use.
The procedure followed in determining the original cost of the gas
plant acquired as operating units or systems shall be described in
sufficient detail so as to permit a clear understanding of the nature of
the investigations and analyses which were made for that purpose.
Where estimates are used in arriving at original cost or the amount
to be included in account 114, a full disclosure of the method and
underlying facts shall be given. The proportion of the original cost of
each acquisition which has been determined from actual recorded costs
and the proportion estimated shall be shown for each functional class of
plant. In addition there shall be furnished in respect to each
predecessor or vendor company for which complete construction costs are
not available, a description of such plant records as are available,
including the years covered thereby.
Statement C showing any amounts arrived at by appraisals in the gas
plant accounts (and not eliminated) in lieu of cost to the reporting
company. This statement should describe the appraisal and give the
complete journal entry at the time the appraisal was originally
recorded. If the entry had the effect of appreciating or writing up the
gas plant account, the amount of the appreciation or writeup should be
traced, by proper description and explanation of changes, from the date
recorded through the end of the calendar year prior to the year in which
the filing is made.
Statement D showing in detail gas plant as classified in the books of
account immediately prior to reclassification in accordance with the
Uniform System of Accounts, including, under appropriate descriptive
headings, any unclassified amounts applicable jointly to the gas
department and other departments of the utility.
Statement E showing the adjustments necessary to state accounts 101,
103-107, 114, and 116, and amount of common utility plant includible in
account 118, as prescribed in the Uniform System of Accounts.
Statement F showing gas plant classified according to the accounts
prescribed in the Uniform System of Accounts, and showing also the
amount includible in account 116, Other Gas Plant Adjustments, and the
amount of common utility plant includible in account 118, Other Utility
Plant.
Statement G showing a comparative balance sheet reflecting the
accounts and amounts appearing in the books before the adjusting entries
have been made and after such entries shall have been made. The balance
sheet shall be classified by the accounts set forth in the Uniform
System of Accounts Prescribed for Natural Gas Companies.
Statement H giving a suggested plan for depreciating, amortizing, or
otherwise disposing of, in whole or in part, the amounts includible in
account 114, Gas Plant Acquisition Adjustments, and account 116, Other
Gas Plant Adjustments.
Statement I furnishing the following statistical information relative
to gas plant:
Show separately for each producing plant the name and location of
plant, date of original construction, type of plant (whether coal gas,
coke ovens, water gas, etc.), rated 24-hour capacity in Mcf of each unit
and of the total plant, and date of installation of each unit installed
after original construction. Show also the original cost according to
the System of Accounts for each plant, by accounts 304 to 319,
inclusive.
For each ''field'' includible in account 101, Gas Plant in Service,
furnish the number of acres each of gas producing lands owned, of gas
producing lands leased by the company, and of land on which gas rights
only are owned, as included in accounts 325.1, 325.2, 325.3,
respectively. The same information, classified by subaccounts, shall be
furnished for producing and nonproducing acreage includible in account
104, Gas Plant Leased to Others, and in account 105, Gas Plant Held for
Future Use.
For each ''field'' state number of feet of each size pipe used in
field gathering lines.
For each ''field'' state number of wells included in accounts 330 and
331 segregated to show the number of wells on each type of producing
lands classified under accounts 325.1, 325.2, 325.3.
When pumping or compressing plants exist within the production plant,
include the same information as that requested for compressor stations
under transmission plant.
State type and character of purification equipment and residual
refining equipment included in accounts 336 and 337, respectively.
Show the original cost according to the System of Accounts for
natural gas production plant by each ''field'' and by accounts 325.1 to
340.
Show separately for each location the name of plant, date of
construction, type and total capacity (Mcf) of each gas holder. State
also the original cost according to the System of Accounts for each
location, by accounts 350.1 to 351, inclusive.
If depleted gas fields are being repressured, the statements
furnished shall reflect the number of acres involved and the original
cost according to the System of Accounts (accounts 350.1 to 351,
inclusive).
State the number of feet of each size of main.
State separately for each compressor boosting station the name of
plant, location, date of original construction, rated capacity, type and
character of power unit, and rated capacity and type of compressor
units. Also state the capacity, type, and date of installation of each
additional power or compressor unit. Show for each station the original
cost according to the System of Accounts by accounts 365.1, 365.2, 366,
368, and 369.
State number of feet of each size of main and the number of active
meters, house regulators, and services. Give a general description of
the district regulators and number, by sizes.
Where pumping or compressor stations exist within the distribution
plant, include the same information requested for similar stations under
transmission plant.
Describe the principal structures and improvements.
State the number and type of transportation vehicles and appurtenant
equipment.
Give a description of store, shop, and laboratory equipment and
miscellaneous equipment.
Furnish maps, drawn to scale, upon which indicate transmission mains,
location of production plants (artificial and natural), producing and
nonproducing leaseholds (indicating thereon producing wells, dry holes
and depleted wells), gathering systems, booster and compressor stations,
communities served (noting as to wholesale or retail), and large
industrial consumers. Where gas is purchased from or sold to other gas
utilities, indicate location of measuring stations or gates. If scale
maps are not available, furnish sketch maps upon which should be
indicated approximate distances between the locations above specified.
(Order 477, 38 FR 7215, Mar. 19, 1973)
18 CFR 260.200 SUBCHAPTER H -- FIRST SALE REGULATION UNDER THE NATURAL GAS POLICY ACT OF 1978
18 CFR 260.200 PART 270 -- RULES GENERALLY APPLICABLE TO REGULATED SALES OF NATURAL GAS
18 CFR 260.200 Subpart A -- General Rules and Definitions
Sec.
270.101 Application of ceiling prices to first sales of natural gas.
270.102 Definitions.
270.103 Effective date.
18 CFR 260.200 Subpart B -- Special Rules
270.201 Good faith negotiation procedures.
270.202 Resales.
270.203 Pipeline, distributor and affiliate production.
270.204 Btu content per cubic foot of natural gas.
270.205 Contractual authorization to collect NGPA rates.
270.206 Applicability of section 314 ''Limitation on Effectiveness of
Commingling and Similar Clauses''.
270.207 (Reserved)
270.208 Applicability of section 121.
Authority: Natural Gas Act, 15 U.S.C. 717-717w (l988); Department
of Energy Organization Act, 42 U.S.C. 7101-7352 (1982); E.O. 12009, 3
CFR 1978 Comp., p. 142; Natural Gas Policy Act of 1978, 15 U.S.C.
3301-3432 (1988).
18 CFR 260.200 Subpart A -- General Rules and Definitions
18 CFR 270.101 Application of ceiling prices to first sales of natural
gas.
(a) Maximum lawful price. It is unlawful for any person to sell
natural gas (other than deregulated natural gas) at a first sale price
in excess of the highest maximum lawful price applicable to such gas
under part 271. No maximum lawful price applies to deregulated natural
gas.
(b) Effect of maximum lawful price on contract price. If the price
established under a contract for the first sale of natural gas does not
exceed the applicable maximum lawful price, then such maximum lawful
price does not supersede or nullify the effectiveness of the price
established under such contract.
(c) Maximum lawful prices requiring jurisdictional agency
determinations. Except to the extent that a seller is authorized to
make interim collection under part 273:
(1) Any maximum lawful price under any of the following subparts of
part 271 applies to a first sale of natural gas only if a determination
of a particular well or new OCS lease by a jurisdictional agency that
such gas qualifies under such subpart has become final in accordance
with parts 274 and 275:
(i) Subpart B (relating to new natural gas and certain OCS gas);
(ii) Subpart C (relating to new, onshore production well);
(iii) Subpart G (relating to high-cost natural gas); and
(iv) Subpart H (relating to stripper well natural gas).
(2) The price of gas is deregulated only if such gas is deregulated
natural gas as defined in 272.103(a).
(d) Other categories of natural gas -- (1) Certain committed or
dedicated natural gas. The maximum lawful prices under subpart D of
part 271 (relating to certain committed or dedicated natural gas) apply
to a first sale to the extent provided in such subpart, if the
applicable filing requirements under 154.92 and 154.94 of this chapter
are met.
(2) Existing intrastate contracts; intrastate rollover contracts;
certain other categories. The maximum lawful prices under subparts E,
F, and I of part 271 (relating to existing intrastate contracts,
intrastate rollover contracts, and certain other categories of natural
gas) apply to first sales of natural gas without requirement of a prior
determination by the Commission or a jurisdictional agency.
(e) General refund obligation and filing requirements for first
sellers. (1) Any price collected with respect to a first sale of
natural gas to which subchapter H applies is collected subject to a
general obligation to refund any portion of the price, together with
interest determined in accordance with 154.102 (c) and (d) of this
chapter, which is in excess of the maximum lawful price or collection of
which is not authorized by subchapter H. The refund, including
interest, must be paid within 120 days after the seller is notified by
Commission staff or a purchaser that a refund is due unless the refund
is recovered through a billing adjustment as provided in paragraphs
(e)(2) or (e)(3) of this section. Compliance with the specific refund
requirements of 273.302 of this chapter will not terminate the general
refund obligation under subchapter H.
(2)(i) A purchaser may not use a billing adjustment to recover a
refund required by paragraph (e)(1) of this section before the
expiration of the 120-day period for the seller to make the refund. If
the seller fails to make a refund within the 120-day period, the
purchaser may use a billing adjustment to recover the refund without
agreement by the seller. Before making a billing adjustment, the
purchaser must provide the seller written notice of the amount of the
refund to be recovered and the time period during which the billing
adjustment will be completed. The time period for the billing
adjustment can be a reasonable period of time not to exceed one year
from the date a first seller is notified of a refund obligation.
(ii) If a first seller appeals an action by the Director of the
Office of Pipeline and Producer Regulation notifying the first seller of
a refund due, or files a complaint or protest in response to a
purchaser's notice of billing adjustment, a purchaser may not use the
billing adjustment mechanism to collect refunds until issuance of a
final Commission order on the appeal, complaint or protest.
(3)(i) Except as provided in paragraph (e)(3)(ii) of this section,
within 150 days after the seller is notified by Commission staff or a
purchaser that a refund is due, the seller must file an original and two
copies of a refund report, accompanied by a purchaser's concurrence,
containing the information specified in 273.302(f) of this chapter. A
seller is not required to include in a report filed under this paragraph
any information regarding a refund recovered by an interstate pipeline
purchaser through a billing adjustment.
(ii) If a purchaser does not provide the seller with its concurrence
within the time period specified in paragraph (e)(3)(i) of this section,
the seller may file the refund report without the purchaser's
concurrence.
(f) Filing requirements. An interstate pipeline must include with
any Purchased Gas Adjustment (PGA) filing under 154.301 through
154.310 of this chapter, a refund report identifying all billing
adjustments that are reflected in the interstate pipeline's PGA filing
to effect refunds required to be made to it by sellers under paragraph
(e) of this section. The interstate pipeline must file with the
Commission the original and two copies of a refund report showing for
each seller:
(1) The amounts of overcharges and interest to be refunded by that
seller as determined in accordance with paragraph (e) of this section;
(2) The amounts of, and dates on which, billing adjustments were made
by the pipeline to satisfy the seller's refund obligations under
paragraph (e) of this section in whole or in part;
(3) The well name and, if available, American Petroleum Institute
Well Number of the well that produced the natural gas for which the
interstate pipeline was overcharged by that seller; and
(4) The date that overcollection began or, if applicable, the date of
stripper gas well disqualification.
(Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Natural Gas
Act as amended, 15 U.S.C. to 712-717; Department of Energy Organization
Act, 42 U.S.C. 7101-7352; 42 CFR 142; Interstate Commerce Act, 49
U.S.C. 1, et seq.; Natural Gas Act, 15 U.S.C. 717-717w)
(43 FR 56544, Dec. 1, 1978, as amended at 44 FR 53505, Sept. 14,
1979; Order 78, 45 FR 28097, Apr. 28, 1980; Order 273, 48 FR 1288,
Jan. 12, 1983; Order 406, 49 FR 46883, Nov. 29, 1984; Order 423, 50 FR
23674, June 5, 1985; Order 479, 52 FR 29005, Aug. 5, 1987; Order
483-A, 52 FR 43888, Nov. 17, 1987; Order 515, 54 FR 32809, Aug. 10,
1989; 54 FR 47022, Nov. 8, 1989; Order 515-A, 55 FR 22, Jan. 2, 1990)
Editorial Note: For a document relating to clarification ''that
270.101 can be utilized to recover Btu refunds that are due and owing'',
see 55 FR 32026, Aug. 6, 1990.
18 CFR 270.102 Definitions.
(a) NGPA definitions. Terms defined in the NGPA shall have the same
meaning for purposes of this subchapter as they have under the NGPA,
unless further defined in this subchapter.
(b) Subchapter H definitions. For purposes of this subchapter:
(1) NGPA means the Natural Gas Policy Act of 1978.
(2) British thermal unit or Btu means the quantity of heat required
to raise the temperature of one pound avoirdupois of pure water from
58.5 degrees to 59.5 degrees Fahrenheit, determined in accordance with
270.204.
(3) MMBtu means million British thermal units.
(4)(i) Except as provided in clause (ii), production in commercial
quantities means production of natural gas from a well or reservoir
which is either:
(A) Sold and delivered to one other than the operator; or (B)
(subject to 271.204(e)) retained by the operator, or any owner of the
production at severance, for beneficial economic use.
(ii) Natural gas used for the testing of natural gas wells or for
other field uses which are production related shall not be considered
produced in commercial quantities.
(iii) Any of the following information may be considered as evidence
of sale and delivery, or production for the operator's or other owner's
beneficial economic use:
(A) Payment of severance taxes;
(B) Payment of royalties;
(C) Production reports filed with a jurisdictional agency;
(D) A sales contract together with verification by a purchaser that
natural gas had been delivered and paid for under the contract; or
(E) Any other substantial evidence that production has been sold and
delivered, or retained for the beneficial use of the operator or other
owner of production at severance.
(5) Crude oil means a mixture of hydrocarbons that exists in the
liquid phase in natural underground reservoirs and remains liquid at
atmospheric pressure after passing through surface separating facilities
(6) Surface location means the point on the Earth's surface from
which drilling of a well is commenced except that in the case of a well
drilled in permanent surface waters, the Earth's surface means the mean
elevation of the surface of the water.
(7) OCS means the Outer Continental Shelf as defined in section 2(35)
of the NGPA.
(8) Existing intrastate contract means any intrastate contract for
the first sale of natural gas in existence on November 8, 1978. A
contract is in existence on November 8, 1978 if on that date, there is a
promise or a set of promises for the breach of which the law gives a
remedy, or the performance of which the law in some way recognizes as a
duty. For the purposes of this subchapter ''existing intrastate
contract'' includes a ''successor to an existing intrastate contract.''
(9) Successor to an existing intrastate contract means any contract,
other than a rollover contract, entered into on or after November 9,
1978, for the first sale of natural gas which was previously subject to
an existing intrastate contract, whether or not there is an identity of
parties or terms with those of such existing intrastate contract. The
term ''successor to an existing intrastate contract'' includes a
contract the primary term of which has not expired but which has been
assigned to a different party in interest.
(10) Intrastate contract means any contract applicable to the sale of
natural gas which was not committed or dedicated to interstate commerce
on November 8, 1978.
(11) Intrastate rollover contract means any contract, entered into on
or after November 9, 1978, for the first sale of natural gas that was
previously subject to an existing intrastate contract which expired at
the end of a fixed term (not including any extension thereof taking
effect on or after November 9, 1978), specified by the provisions of
such existing contract, as such contract was in effect on November 9,
1978, whether or not there is an identity of parties or terms with those
of such existing contract.
(12) Jurisdictional agency means the State or Federal agency
identified in subpart E of part 274.
(13) New well means any well --
(i) The surface drilling of which began on or after February 19,
1977; or
(ii) The depth of which was increased, by means of drilling on or
after February 19, 1977, to a completion location which is located at
least 1,000 feet below:
(A) The depth of the deepest completion location of such well
attained before February 19, 1977, if such well had a completion
location; or
(B) If such well had no completion location because it was a dry hole
the drilling of which was terminated prior to February 19, 1977, the
deepest drilled depth attained in such dry hole.
(14) For the definition of ''deregulated natural gas,'' see
272.103(a).
(15) Intracompany operating statement means a statement indicating
how an interstate pipeline intends to manage its own production of gas.
(Natural Gas Act, 15 U.S.C. 717-717w (1982); Natural Gas Policy Act
of 1978, 15 U.S.C. 3301-3432 (1982); Department of Energy Organization
Act, 42 U.S.C. 7101-7352 (1982); E. O. 12009, 3 CFR part 142 (1978);
Energy Supply and Environmental Coordination Act, 15 U.S.C. 791, et seq.
(1982))
(43 FR 56544, Dec. 1, 1978, as amended at 44 FR 34474, June 15, 1979;
44 FR 53493, Sept. 14, 1979; Order 68, 45 FR 5684, Jan 24, 1980;
Order 78, 45 FR 28098, Apr. 28, 1980; Order 273, 48 FR 1289, Jan. 12,
1983; Order 94-A, 48 FR 5178, Feb. 3, 1983; Order 391, 49 FR 33859,
Aug. 27, 1984; Order 406, 49 FR 46883, Nov. 29, 1984)
18 CFR 270.103 Effective date.
The provisions of this subchapter apply to deliveries of natural gas
on or after December 1, 1978.
(43 FR 56547, Dec. 1, 1978)
18 CFR 270.103 Subpart B -- Special Rules
18 CFR 270.201 Good faith negotiation procedures.
(a) Applicability, definitions, and general rules. (1) This section
applies to requests for renegotiation of the price of old gas sold under
an existing contract.
(2) For purposes of this section:
(i) ''Old gas'' means natural gas which, if sold, would be subject to
a maximum lawful ceiling price under section 104 or 106(a) of the NGPA.
(ii)(A) ''Existing contract'' means a contract in effect on July 18,
1986, or an expired contract pursuant to which sales of natural gas are
continuing on that date under the service obligation of a certificate of
public convenience and necessity, that includes the sale of any old gas
and provides authority for the first seller to collect a higher price
upon establishment by the Commission of a higher maximum lawful price.
(B) An existing contract includes the sale of old gas if, on July 18,
1986, the contract encompasses the sale of any gas that has not been
abandoned under section 7(b) of the Natural Gas Act and which, if sold,
would be priced as old gas, whether or not any old gas is sold on that
date.
(iii) The terms ''first seller'' and ''party to a contract'' include:
(A) An owner of a working interest in an oil or gas lease that has a
direct contractual relationship with a purchaser for a ''first sale'' of
gas, as defined in section 2(21) of the NGPA; and
(B) An operator of an oil or gas lease that has a direct contractual
relationship with a purchaser for a ''first sale'' on behalf of any
owner of a working interest in the lease that does not have such a
relationship.
(3)(i) Any existing contract under which old gas is sold may be
renegotiated or amended at any time to provide for a price up to the
alternative maximum lawful price under 271.402(c)(7)(i) of this chapter
without using the good faith negotiation procedures.
(ii) A price for old gas that exceeds the otherwise applicable
maximum lawful price under 271.402 of this chapter may be collected
under an existing contract only if the first seller and purchaser agree
upon a price up to the alternative maximum lawful price under
271.402(c)(7)(ii) in accordance with this section.
(4) A party to an existing contract may not request a nomination of a
price under the provisions of this section for any gas sold under the
contract, if that party:
(i) And the purchaser or first seller have renegotiated the price or
any other term for the sale of any old gas under the contract after July
18, 1986, without using the good faith negotiation procedures of this
section, and have not agreed in writing to preserve their rights under
this section;
(ii) Has previously requested nomination of a price under paragraph
(b)(1) of this section for any gas sold under the contract; or
(iii) Has been requested under this section to nominate a price for
any gas sold under the contract, and the last date has passed under
paragraphs (b)(2) or (b)(3) of this section to request the other party
to nominate a price for gas sold under the contract.
(5)(i) A first seller that validly assigns or otherwise transfers gas
subject to an existing contract on or after June 3, 1987 may not request
a nomination of price under the provisions of this section for any gas
sold under any existing contract with that purchaser unless the
purchaser's right to renegotiate, under the provisions of this section,
the terms of sale of the assigned gas are unaffected by the assignment.
(ii) A first seller to whom gas subject to an existing contract is
validly assigned, or otherwise transferred, on or after June 3, 1987 may
not request nomination of a price under the provisions of this section
for the assigned gas, unless the purchaser's right to renegotiate, under
the provisions of this section, the terms of sale of all gas sold under
any existing contract between the purchaser and the assignor on June 3,
1987 are unaffected by the assignment.
(6) Any request for nomination of a price under this section, any
nomination of a price in response to such a request, and any notice of
abandonment of sales or termination of purchases under this section must
be sent by U.S. mail, return receipt requested.
(7) Any deadline under this section for requesting a nomination of a
price, or for nominating a price in response to such a request, may be
extended by mutual agreement of the parties in writing. Any notice
required under this section to be given before a first seller or
purchaser abandons or terminates sales or purchasers may be shortened by
mutual agreement of the parties in writing.
(8) A party nominating a price may propose a change in any other term
of the existing contract, and for purposes of this section, the terms
''nominated price'' and ''nomination'' may include such a proposed
change.
(b) Requests for negotiation and nomination of price.
(1)(i) At any time after January 23, 1987, a first seller may request
the purchaser to nominate a price at which the purchaser is willing to
continue buying old gas under any existing contract by submitting a
written request to the purchaser, and may specify the wells or category
of wells under each contract for which the first seller requests a
renegotiated price.
(ii) When requesting a nomination of a price under this paragraph, a
first seller may also request the purchaser to provide the first seller
with a current list of all of the purchaser's firm sales customers,
including the name and address of an employee or agent responsible for
negotiating purchases of natural gas on behalf of the customer. The
purchaser must send the list of customers to the first seller within 30
days after receiving the request, and must include a certification of
its completeness and accuracy. The list must be sent by U.S. mail,
return receipt requested.
(2) Within 30 days after receiving a request for nomination of a
price under paragraph (b)(1) of this section, the purchaser may request
the first seller to nominate a price at which the first seller is
willing to continue selling any gas, including old gas for which the
first seller has requested a nomination of price by the purchaser, under
any existing contract with the purchaser that includes the sale of any
old gas, whether or not named in the first seller's request, by
submitting a written request to the first seller.
(3) Within 30 days after receiving a request from a purchaser for
nomination of a price for any gas under a contract that is not named in
the first seller's request and that includes the sale of any old gas,
the first seller may request the purchaser to nominate a price at which
the purchaser is willing to continue buying any old gas under that
contract, including old gas for which the purchaser has requested a
nomination of price by the first seller, by submitting a written request
to the purchaser.
(4) A first seller's request for nomination of a price under
paragraph (b)(1) of this section constitutes an offer to release the
purchaser from its contract obligation to purchase any gas sold under
any existing contract with the first seller, whether or not named in the
first seller's request, that includes the sale of any old gas.
(5)(i) The provisions of this paragraph apply when (A) a first seller
validly assigns (or otherwise transfers) gas subject to an existing
contract to another first seller on or after June 3, 1987 and (B) the
assignor or assignee is eligible to request nomination of a price under
paragraph (b)(1) of this section.
(ii) If the assignor requests nomination of a price, under paragraph
(b)(1) of this section, for old gas sold under any contract between it
and the purchaser, the purchaser may request nomination of a price under
paragraph (b)(2) of this section for any gas which on June 3, 1987 was
subject to an existing contract between the purchaser and the assignor.
(iii) If the assignee requests nomination of a price under paragraph
(b)(1) of this section for the assigned gas, the purchaser may request
nomination of a price for any gas which on June 3, 1987, was subject to
an existing contract between the assignor and the purchaser, but the
purchaser may not request nomination of a price for any other gas.
(iv) If the assignee requests nomination of a price under paragraph
(b)(1) of this section for old gas other than the assigned gas, the
purchaser may not request nomination of a price under paragraph (b)(2)
of this section for the assigned gas.
(v) The purchaser must address any requests for nomination of a price
authorized by paragraphs (b)(5) (ii) or (iii) of this section to the
first seller currently selling it the gas for which nomination of a new
price is requested.
(vi) If a first seller receives a request for nomination of a price
authorized by paragraph (b)(5) (ii) or (iii) of this section with
respect to an existing contract for which it did not make a nomination
request under paragraph (b)(1) of this section, the first seller may
request under paragraph (b)(3) of this section that the purchaser
nominate a price for any old gas sold under that contract, whether or
not the contract was named in the nomination request of the assignor or
assignee under paragraph (b)(1) of this section.
(c) No response to request for nomination. (1) If the purchaser does
not nominate a price in writing within 60 days after receiving the first
seller's request for nomination of a price, the first seller may offer
to sell all or part of the gas named in its request for nomination to a
new purchaser. The first seller is authorized, upon 30-days written
notice to the existing purchaser, to abandon the sale of the gas if the
first seller enters into a written contract for the sale of all or part
of the gas to a new purchaser after any necessary compliance with
paragraph (g) of this section.
(2) If the first seller does not nominate a price in writing within
60 days after receiving the purchaser's request for nomination of a
price, the purchaser may terminate its purchases of all or part of the
gas named in its request for nomination at any time upon 60-days written
notice to the first seller.
(d) Purchaser's nomination of highest price. If the purchaser
nominates in writing the highest price to which an existing contract
price could escalate with the purchaser's agreement under
271.402(c)(7)(ii) of this chapter, and the purchaser does not propose a
change in any term of the contract, sales must continue at the nominated
price under the terms of the existing contract.
(e) Purchaser's nomination of lower price; first seller's options.
(1) If the purchaser nominates in writing a price less than the highest
price to which the existing contract price could escalate or proposes a
change in any other term of the contract, the first seller must accept
or reject the nominated price in writing within 30 days after receiving
the nomination. If the first seller does not accept the purchaser's
nominated price in writing within 30 days, the nominated price is deemed
rejected.
(2) If the first seller accepts the nominated price, sales must
continue at the agreed-upon price under the other terms of the existing
contract, unless such terms are renegotiated by the parties.
(3) If the first seller rejects the nominated price, the first seller
must continue sales to the purchaser at the existing price until the
sale of the gas is abandoned under this paragraph. At any time after a
rejection, the first seller may offer to sell to a new purchaser all or
part of the gas for which no price is agreed upon under this paragraph.
(4) A first seller is authorized, upon 30-days written notice to the
existing purchaser, to abandon the sale of any gas offered under this
paragraph for which the first seller enters into a written contract with
a new purchaser after any necessary compliance with paragraph (g) of
this section.
(f) First seller's nomination of price; purchaser's options. (1) If
the first seller nominates a price in writing in response to the
purchaser's request under paragraph (b)(2) of this section, the
purchaser must accept or reject the nominated price in writing within 30
days after receiving the nomination. If the purchaser does not accept
the first seller's nominated price in writing within 30-days, the
nominated price is deemed rejected.
(2) If the purchaser accepts the nominated price, purchases must
continue at the agreed-upon price under the other terms of the existing
contract, unless such terms are renegotiated by the parties.
(3) If the purchaser rejects the nominated price, the purchaser may
at any time terminate its purchases of all or part of the gas named in
its request for nomination upon 60-days written notice to the first
seller.
(4) The terms of the existing contract apply until the purchaser
accepts the first seller's nominated price or terminates purchases of
the gas under this paragraph.
(5) A first seller is authorized to abandon sales of the gas to the
purchaser if the purchaser terminates purchases of gas under this
section and the first seller enters into a written contract for the sale
of the gas to a new purchaser after any necessary compliance with
paragraph (g) of this section.
(g) Existing firm sales customers' riqht of first refusal -- (1)
General rule. (i) If the first seller offers to sell gas subject to
release due to termination or abandonment under paragraphs (c), (e), or
(f) of this section (''offer'') to a new purchaser that is not an
existing firm sales customer of the existing purchaser, the first seller
must present the same offer to all existing firm sales customers, if:
(A) The existing purchaser is not subject to the non-discriminatory
access provisions of 284.8(b) or 284.9(b) of this chapter, and;
(B) The offer encompasses the sale of any gas subject to the
Commission's jurisdiction under section 1(b) of the Natural Gas Act and
is substantially accepted in principle by the new purchaser in an
arms-length transaction.
(ii) Any existing firm sales customer has a right of first refusal to
purchase the gas under the terms of the offer. The offer must be
presented in accordance with the provisions of this paragraph.
(2) Making the offer. The offer to a new purchaser that is not an
existing firm sales customer must be presented to all such customers of
the existing purchaser not later than 10 days after the offer is
substantially accepted in principle by the new purchaser. The offer
must be tendered by U.S. mail, return receipt requested.
(3) Acceptance and rejection of offer; no counteroffer. (i) An
existing firm sales customer must accept the offer in writing within 20
days after receiving the offer. The offer is deemed accepted when it is
signed and placed in the U.S. mail, return receipt requested. If the
offer is not accepted by an existing firm sales customer within 20 days
of its receipt, the offer is deemed rejected.
(ii) Any written counteroffer by an existing firm sales customer
constitutes a rejection.
(iii) If the first seller receives more than one acceptance from an
existing firm sales customer, the first seller may determine which such
customer will become the new purchaser.
(4) Termination of right of first refusal. If no existing firm sales
customer accepts the offer made under this paragraph within 20 days of
receiving the offer, the first seller may execute a written contract
with the new purchaser that substantially accepted the offer before it
was sent to the existing firm sales customers. Such written contract
with a new purchaser is not subject to a right of first refusal.
(5) Definition. For purposes of this section, ''existing firm sales
customer'' means a customer with which the existing purchaser has a
contract for the sale of gas not subject to a prior claim by another
customer or another class of service, and at the same priority as any
other class of firm service, which is in effect on the date a new
purchaser substantially accepts in principle an offer under paragraph
(g)(1) of this section.
(h) Transportation by existing pipeline purchaser. A purchaser that
is an interstate pipeline not subject to the non-discriminatory access
provisions of 284.8(b) or 284.9(b) of this chapter must transport any
gas released due to termination or abandonment under this section, on
behalf of any shipper, to any existing customer of the interstate
pipeline or to any pipeline to which the interstate pipeline is
interconnected, and in accordance with 284.225 of this chapter, if the
purchaser:
(1) Does not submit a timely nomination of a price for gas under
paragraph (c)(1) of this section in response to the first seller's
request for nomination of a price;
(2) Nominates a price under paragraph (e)(1) of this section that is
less than the highest price to which its existing contract price could
escalate if it were a new or amended contract;
(3) Terminates purchases of gas under paragraph (c)(2) of this
section when the first seller does not submit a timely nomination of a
price; or
(4) Terminates purchases of gas under paragraph (f)(3) of this
section after rejecting a price for gas nominated by the first seller.
(Order 451, 51 FR 22219, June 18, 1986, as amended by Order 451-A, 51
FR 46818, Dec. 24, 1986; Order 451-B, 52 FR 21677, June 9, 1987)
18 CFR 270.202 Resales.
(a) General rule. In the case of any first sale of natural gas which
is a resale of such gas, the maximum lawful price shall be the higher
of:
(1) The maximum lawful price which would be applicable to such sale
if it were not a resale; or
(2) The maximum lawful price applicable to the natural gas sold to
the reseller. In the case of natural gas which when sold to the
reseller was subject to more than one maximum lawful price, the reseller
may determine the maximum lawful price for purposes of this paragraph
(a)(2) on the basis of the average of the maximum lawful prices
applicable to the natural gas sold to the reseller (weighted according
to the number of purchased Btu's that are subject to each different
maximum lawful price).
(b) Special rule for interim collections. (1) If the price for a
first sale to a reseller is charged and collected under the authority of
part 273 (relating to interim collection), then:
(i) The price authorized to be collected under part 273 shall be
treated as a maximum lawful price for purposes of paragraph (a)(2) of
this section; and
(ii) The price charged and collected by the reseller shall be subject
to the same refund conditions under part 273 as are imposed on the
person who sold the natural gas to the reseller.
(2) The reseller is not obligated by 273.202(d) or by 273.203 to
make any filings with the Commission, or to serve notice to a purchaser,
if such filings or notice have been made by:
(i) The person who sold the natural gas to the reseller; or
(ii) A person designated under 273.103(b) by the person in clause
(b)(2)(i) of this section to make such filings or notice.
(c) Allowances. (1) A resale of natural gas shall not be considered
to exceed any maximum lawful price established in paragraph (a) of this
section if it exceeds such price to the extent necessary to recover
state severance taxes or production-related costs which are borne by the
reseller and if such recovery by the reseller is allowed under subpart K
of part 271.
(2) If a price for a first sale to a reseller of natural gas is not
considered to exceed the applicable maximum lawful price applicable to
such sale by reason of an amount allowed under subpart K, then for
purposes of applying paragraph (a)(2) of this section the maximum lawful
price applicable to the natural gas sold to the reseller shall be
considered to be increased by the amount so allowed.
(d) Adjustments. Pursuant to section 502(c) of the NGPA and subpart
K of part 385 of this chapter, a reseller may apply to the Commission
for an adjustment of the maximum lawful price in paragraph (a) of this
section on the grounds that such price results in special hardship,
inequity or an unfair distribution of burdens.
(e) Definitions. For purposes of this section:
(1) Resale of natural gas means the sale of natural gas, all or a
portion of which was both purchased and resold in transactions that are
first sales as defined in the NGPA.
(2) A reseller means the seller in a resale of such natural gas.
(3) Percentage-of-proceeds sale means a sale of natural gas the price
for which is computed as a percentage of the proceeds from the resale of
natural gas attributable to such sale.
(f) Record retention. In addition to any records required to be
retained by reason of an election made by the reseller under
276.101(b), such reseller shall maintain such records as are sufficient
to demonstrate that prices charged for the resale of natural gas do not
exceed the maximum lawful prices prescribed in this section. Such
records shall include:
(1) A record of each resale of natural gas by the reseller, including
the identity of the purchaser and the volume and price of such sale;
(2) A record of each sale of natural gas to the reseller which has
been sold in a resale by such reseller, including the volume and price
of such sale;
(3) A copy of the contracts covering the purchase and resale of
natural gas; and
(4) A record of the method by which the reseller computes the maximum
lawful price applicable to each resale and the documents relied on to
make such computations.
(g) Period for keeping records. Each reseller required to maintain
records under this section shall maintain and preserve contracts for any
sale to which this section applies for at least three years after the
expiration date of such contracts and such other records for at least
three years after the date of the relevant transaction or event.
(h) Special rules for percentage-of-proceeds sales. (1) In the case
of natural gas purchased by a reseller in a percentage-of-proceeds sale,
the reseller may determine the maximum lawful price for the resale under
paragraph (a)(1) of this section. If the reseller so determines his
maximum lawful price, any sale to such reseller in such
percentage-of-proceeds sale shall not be treated as a first sale for
purposes of this subchapter.
(2) Natural gas subject to a percentage-of-proceeds contract is
deregulated on the earlier of:
(i) The date such percentage-of-proceeds contract is deregulated as a
first sale, or
(ii) The date the price paid under the resale contract is
deregulated.
(Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Natural Gas
Act, as amended, 15 U.S.C. 717, et seq.; Department of Energy
Organization Act, 42 U.S.C. 7107-7352; E.O. 12009, 42 FR 46267;
Administrative Procedure Act, 5 U.S.C. 553)
(Order 93, 45 FR 49081, July 23, 1980, as amended by Order 131, 46 FR
12203, Feb. 13, 1981; Order 225, 47 FR 19057, May 3, 1982; Order
406-A, 49 FR 50641, Dec. 31, 1984; Order 523, 55 FR 17431, Apr. 25,
1990)
18 CFR 270.203 Pipeline, distributor, and affiliate production.
(a) General rule. The definition of first sale in section 2(21) of
the NGPA includes gas produced by an interstate pipeline, intrastate
pipeline, local distribution company, or any affiliate thereof.
(b) Intracompany transfer -- (1) First sales by interstate pipelines.
A transfer, at the wellhead, of gas produced by an interstate pipeline
company's production divisional unit to its transmission divisional unit
is that pipeline's first sale under the NGPA. It must be evidenced in
an intracompany operating statement.
(2) First sales by intrastate pipelines. A transfer, at the
wellhead, of gas produced by an intrastate pipeline company's production
divisional unit to its transmission divisional unit is that pipeline's
first sale under the NGPA.
(3) First sales by a local distribution company. A transfer, at the
wellhead, of gas produced by a local distribution company's production
unit is that company's first sale under the NGPA.
(c) Circumvention rule for certain sales by affiliates. Any sale by
an affiliate of an interstate pipeline, intrastate pipeline, or local
distribution company, that is not itself such a pipeline or local
distribution company is that affiliate's first sale under the NGPA
unless the Commission, on application, determines not to treat such sale
as a first sale.
(Order 391, 49 FR 33859, Aug. 27, 1984; Order 406, 49 FR 39293, Nov.
29, 1984)
18 CFR 270.204 Btu content per cubic foot of natural gas.
(a) Measurement. The Btu content of one cubic foot of natural gas
under the standard conditions specified in paragraph (b) of this section
is the number of Btu's produced by the complete combustion of such cubic
foot of gas, at constant pressure with air of the same temperature and
pressure as the gas, when the products of combustion are cooled to the
initial temperature of the gas and air and when the water formed by such
combustion is condensed to a liquid state.
(b) Standard conditions. The standard conditions for purposes of
paragraph (a) of this section are as follows: The gas is saturated with
water vapor at 60 degrees Fahrenheit under a pressure equivalent to that
of 30.00 inches of mercury at 32 degrees Fahrenheit, under standard
gravitational force (980.665 centimeters per second squared).
(c) Application of the maximum lawful price. The maximum lawful
price prescribed by the NGPA for any first sale of natural gas applies
to the quantity of Btu's determined on the basis of the standard
conditions described in 270.204(b). The standard conditions apply,
regardless of the actual delivery pressure and temperature conditions
and the actual water vapor content of gas delivered by a first seller.
(Order 356, 49 FR 3073, Jan. 25, 1984)
18 CFR 270.205 Contractual authorization to collect NGPA rates.
(a) Existing interstate contracts. In the case of an existing
contract for a first sale of natural gas to which the Natural Gas Act
applies:
(1) Any contractual provision for a change in price in such contract
which by its terms specifically permits collection of NGPA rates or of
maximum lawful prices prescribed by legislation, constitutes contractual
authorization to charge and collect the NGPA rates applicable to such
first sale.
(2) A contractual provision described in 154.93 (b-1) (relating to
area rate clauses), or similar provision, generally will be considered
to constitute contractual authorization to charge and collect an NGPA
rate to the extent the parties intended to authorize charging and
collection of one or more NGPA rates under the contract.
(b) Existing intrastate contracts. In the case of an existing
contract (other than a contract to which paragraph (a) applies):
(1) Except as provided in paragraph (b)(2) of this section, any
contractual provision for a change in price may operate according to the
terms of such provision except that such provision is not operative to
authorize a seller to charge and collect an amount in excess of the
highest applicable NGPA rate.
(2) If natural gas sold under such contract is subject to section
105(b)(1) of the NGPA and qualifies for no higher maximum lawful price,
no contractual provision for a change in the price under such contract
may operate to permit a price under the contract in excess of the new
natural gas price under section 102 of the NGPA. However, if a seller
collects an adjustment for production-related costs or State severance
taxes in accordance with subpart K of part 271, that amount shall not be
considered to be in excess of the new natural gas price under section
102 of the NGPA.
(c) Modification of contracts. The NGPA does not prohibit the
parties to a contract for the first sale of natural gas from amending or
modifying such contract to permit the seller to charge and collect any
applicable NGPA rate or an adjustment under subpart K of part 271 for
production-related costs or State severance taxes. If natural gas sold
under such contract is subject to section 105(b)(1) of the NGPA and
qualifies for no higher maximum lawful price under any other provision
of the NGPA, no amendment or modification of such contract may provide
authorization for a seller to charge and collect a price which exceeds
the price under the terms of the contract as in effect on November 9,
1978, except to the extent the amendment provides authorization to
collect an adjustment for production-related costs or State severance
taxes in accordance with subpart K of part 271.
(d) Definition. For purposes of this section, ''NGPA rate'' means
maximum lawful price prescribed by or under the NGPA (including any
price collection of which is authorized by part 273) of this chapter.
(44 FR 16908, Mar. 30, 1979, as amended by Order 23-A, 44 FR 34473,
June 15, 1979; Order 108-A, 48 FR 48228, Oct. 18, 1983)
18 CFR 270.206 Applicability of section 314 ''Limitation on
Effectiveness of Commingling and Similar Clauses''.
For the purposes of section 314(a) of the NGPA, (relating to
unenforceability of commingling and similar clauses) the term ''natural
gas covered by this Act'' means natural gas which is described in any
one or more of the following paragraphs:
(a) Natural gas which is not committed or dedicated to interstate
commerce as of November 8, 1978.
(b) Natural gas, the sale in interstate commerce of which (1) is
authorized under NGPA section 302(a) or 311(b); or (2) is pursuant to
an assignment under NGPA section 312(a).
(c) Natural gas, the transportation in interstate commerce of which
is (1) pursuant to any order under NGPA section 302(c) or NGPA section
303(b), (c), (d), or (h); or (2) authorized by the Commission under
NGPA section 311(a).
(44 FR 18967, Mar. 30, 1979)
270.207 (Reserved)
18 CFR 270.208 Applicability of section 121.
First sales of natural gas that is deregulated natural gas as defined
in 272.103(a) is price deregulated and not subject to the maximum
lawful prices of the NGPA, regardless of whether the gas also meets the
criteria for some other category of gas subject to a maximum lawful
price under Subtitle A of Title I of the NGPA.
(Order 406, 49 FR 46883, Nov. 29, 1984)
18 CFR 270.208 Pt. 271
18 CFR 270.208 PART 271 -- CEILING PRICES
18 CFR 270.208 Subpart A -- Summary Tables and Calculations
Sec.
271.101 Ceiling prices for certain categories of natural gas.
271.102 Calculation of inflation adjustment for certain maximum
lawful prices.
18 CFR 270.208 Subpart B -- New Natural Gas and Certain Natural Gas
Produced From the Outer Continental Shelf
271.201 Applicability.
271.202 Maximum lawful price.
271.203 Definitions.
271.204 Special rules.
18 CFR 270.208 Subpart C -- New, Onshore Production Wells
271.301 Applicability.
271.302 Maximum lawful price.
271.303 Definition of new, onshore production well.
271.304 Waivers of well-spacing requirements.
271.305 Special rule applicable to existing proration units.
18 CFR 270.208 Subpart D -- Natural Gas Committed or Dedicated to
Interstate Commerce
271.401 Applicability.
271.402 Maximum lawful prices.
271.403 Special rule regarding carrying charge adjustment for advance
payments.
18 CFR 270.208 Subpart E -- Sales Under Existing Intrastate Contracts
271.501 Applicability.
271.502 Maximum lawful prices.
271.503 Recordkeeping.
271.504 Determination of contract price.
18 CFR 270.208 Subpart F -- Intrastate Rollover Contracts
271.601 Applicability.
271.602 Maximum lawful price.
271.603 Recordkeeping.
18 CFR 270.208 Subpart G -- High-Cost Natural Gas
271.701 Applicability.
271.702 General rules.
271.703 Tight formations.
271.704 Qualified production enhancement gas.
18 CFR 270.208 Subpart H -- Stripper Well Natural Gas
271.801 Applicability.
271.802 Maximum lawful price.
271.803 Definitions.
271.804 Special rules.
271.805 Continuing qualification.
271.806 Jurisdictional agency determinations and Commission review.
271.807 Maximum efficient rate of flow.
18 CFR 270.208 Subpart I -- Other Categories of Natural Gas
271.901 Applicability.
271.902 Maximum lawful price.
271.903 Recordkeeping.
271.904 Special rule.
18 CFR 270.208 Subpart J -- (Reserved)
18 CFR 270.208 Subpart K -- Allowances for State Severance Taxes and
Certain Production-Related Costs
271.1100 Applicability.
271.1101 Definitions.
271.1102 State severance taxes.
271.1103 Record retention.
271.1104 Production-related costs.
271.1105 Compliance procedures under the Production-Related Costs
Board.
271.1106 Adjustments.
Authority: 15 U.S.C. 717-717w; 15 U.S.C. 3301-3432; 42 U.S.C.
7101-7352.
18 CFR 270.208 Subpart A -- Summary Tables and Calculations
18 CFR 271.101 Ceiling prices for certain categories of natural gas.
(a) The maximum lawful price for natural gas subject to subparts B,
C, G, H, and I of this part, and certain natural gas subject to subpart
F thereof, are specified in Table I. The maximum lawful prices for
certain categories of natural gas subject to subpart D of this part are
specified in Table II.
104 and 106(a) (Subpart D, Part 271)
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271)_Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271) -- Continued
104 and 106(a) (Subpart D, Part 271)
104 and 106(a) (Subpart D, Part 271)
104 and 106(a) (Subpart D, Part 271)
(b) Caveat. The tables in paragraph (a) of this section are
summaries of applicable maximum lawful prices and may not be relied upon
to establish qualification for a particular price. The seller should
examine the other provisions of this subchapter in order to ascertain
whether the natural gas in question qualifies for the price appearing in
the table or some other price.
(c) Cross reference. For maximum lawful prices applicable to natural
gas sold under existing intrastate contracts or intrastate rollover
contracts, see part 271, subparts E and F.
(Natural Gas Act, as amended, (15 U.S.C. 717 et seq.), Natural Gas
Policy Act of 1978, Pub. L. 95-621, 92 Stat. 3350, Energy Supply and
Environmental Coordination Act, (15 U.S.C. 791, et seq.), Federal Energy
Administration Act, (15 U.S.C. 761, et seq.), Department of Energy
Organization Act, (42 U.S.C. 7107 et seq.), Pub. L. 95-91, E.O. 12009,
42 FR 46267))
(43 FR 56551, Dec. 1, 1978)
Editorial Note: For Federal Register citations affecting 271.101,
see the List of CFR Sections Affected in the Finding Aids section of
this volume.
18 CFR 271.102 Calculation of inflation adjustment for certain maximum
lawful prices.
(a) Maximum lawful prices for first sales of certain categories of
natural gas to which subparts D, E, and F apply are to be calculated in
the following manner:
(1) Determine the base price applicable for the base month.
(2) For the month following the base month, multiply the inflation
adjustment applicable for such following month by the base price.
(3) For each succeeding month (through the month of delivery),
multiply the inflation adjustment applicable for such succeeding month
by the price calculated under this paragraph for the prior month.
(b) The price determined for each month under paragraph (a) shall be
rounded to the nearest mill (rounding to the next highest mill only that
fraction which is one-half a mill or greater).
(c) Inflation adjustment. The inflation adjustment applicable to
each month, beginning with May 1977, and ending with the last month of
the present quarter, is specified in the following table:
(d) Definitions. For purposes of this section:
(1) Base price means:
(i) For maximum lawful prices to be calculated under 271.402(c)(1)
(relating to certain committed or dedicated gas), the just and
reasonable rate for April 20, 1977;
(ii) For maximum lawful prices to be calculated under 271.502(b)(2)
(relating to certain existing intrastate contracts), the contract price
per MMBtu on November 9, 1978; and
(iii) For maximum lawful prices to be calculated under 271.602(a)(1)
(relating to certain rollover contracts), the contract price per MMBtu
under the expired contract for the month in which the effective date of
the rollover contract occurs.
(2) Base month means:
(i) April 1977, for maximum lawful prices under 271.402(c)(1);
(ii) November 1978, for maximum lawful prices under 271.502(b)(2);
and
(iii) The month in which the effective date of the rollover contract
occurs, for maximum lawful prices under 271.602(a)(1).
(Natural Gas Act, as amended, (15 U.S.C. 717 et seq.), Natural Gas
Policy Act of 1978, Pub. L. 95-621, 92 Stat. 3350, Energy Supply and
Environmental Coordination Act, (15 U.S.C. 791, et seq.), Federal Energy
Administration Act, (15 U.S.C. 761, et seq.), Department of Energy
Organization Act, Pub. L. 95-91, 42 U.S.C. 7107 et seq., (E.O. 12009,
42 FR 46267))
(43 FR 56551, Dec. 1, 1978; 43 FR 59482, Dec. 21, 1978)
Editorial Note: For Federal Register citations affecting 271.102,
see the List of CFR Sections Affected in the Finding Aids section of
this volume.
18 CFR 271.102 -- Subpart B -- New Natural Gas and Certain Natural Gas
Produced From the Outer Continental Shelf
Authority: Natural Gas Act, as amended, 15 U.S.C. 717 et seq.;
Natural Gas Policy Act of 1978, Pub. L. 95-621, 92 Stat. 3350;
Department of Energy Organization Act, 42 U.S.C. 7107 et seq.; E.O.
12009, 42 FR 46267.
18 CFR 271.201 Applicability.
This subpart implements section 102 of the NGPA and applies to the
first sale of:
(a) New natural gas which is not deregulated natural gas (see
272.103(a)); or
(b) Natural gas produced from a new OCS reservoir on an old OCS
lease.
(Order 42, 44 FR 48183, Aug. 17, 1979, as amended by Order 406, 49 FR
46883, Nov. 29, 1984)
18 CFR 271.202 Maximum lawful price.
The maximum lawful price, per MMBtu, for natural gas to which this
subpart applies shall be the price specified for subpart B of part 271
in Table I of 271.101(a).
(44 FR 48664, Aug. 20, 1979)
18 CFR 271.203 Definitions.
For purposes of this subpart:
(a) New natural gas means natural gas which a jurisdictional agency
has determined, in accordance with parts 274 and 275 and section 102(c)
of the NGPA, to be new natural gas.
(b) Natural gas from a new OCS reservoir on an old OCS lease means
natural gas which the jurisdictional agency determines, in accordance
with parts 274 and 275 and under section 102(d) (1), (2), (3), (4), and
(5) of the NGPA, to be natural gas produced from a reservoir which is on
an old OCS lease and which was not discovered before July 27, 1976.
(c) OCS lease means a lease of submerged acreage which is entered
into with the Secretary of the Interior under the Outer Continental
Shelf Lands Act, as amended, (43 U.S.C. 1331, et seq.)
(d) New OCS lease means an OCS lease entered into by the Secretary of
the Interior on or after April 20, 1977.
(e) Old OCS lease means an OCS lease other than a new OCS lease.
(44 FR 48183, Aug. 17, 1979)
18 CFR 271.204 Special rules.
(a) Vertical measurement of 1,000 feet between completion locations.
For the purpose of determining under section 102(c)(1)(B)(ii) of the
NGPA the vertical distance between the deepest marker well completion
location and the completion location for the new well for which the
determination is sought, measurement shall be the true vertical depth
measured from the highest perforation point of the deepest marker well
completion location to the highest perforation point of the new well
completion location. In the case of any well which is an open-hole
completion, measurement shall be from the highest elevation point within
the well bore of the reservoir being produced.
(b) Capable of producing in paying quantities. For purposes of
section 102(d)(2)(B) (i) and (ii) of the NGPA, a reservoir is capable of
producing in paying quantities if a well completed therein can
reasonably be expected to produce natural gas in quantities sufficient
to yield revenues in excess of operating costs. For the purposes of
this paragraph, operating costs include those out-of-pocket cash
expenses necessary to operate and maintain a well.
(c) Commercially producible. For purposes of section
102(d)(2)(B)(iii) of the NGPA, a reservoir is commercially producible if
a well completed therein can reasonably be expected to produce natural
gas in quantities sufficient to yield revenues in excess of operating
costs. For the purposes of this paragraph, operating costs include
those out-of-pocket cash expenses necessary to operate and maintain as
well.
(d) Suitable facilities. For purposes of section
102(c)(1)(C)(iii)(II) of the NGPA (but subject to section
102(c)(1)(C)(iv) thereof), suitable facilities for the production and
delivery of natural gas described in section 102(c)(1)(C)(iii)(I) of the
NGPA were in existence on April 20, 1977, if on that date facilities for
the production and delivery of natural gas to a pipeline were:
(1) Installed; or
(2) Substantially installed and additional facilities necessary for
such production and delivery were readily available and could have been
installed by April 20, 1977.
(e) Production in commercial quantities. For purposes of determining
whether production of natural gas in commercial quantities has occurred
under section 102(c)(1)(C) of the NGPA:
(1) A rebuttable presumption exists that production from a reservoir
in commercial quantities has not occurred if natural gas has not been
sold and delivered from such reservoir before April 20, 1977. Such
presumption may be rebutted by evidence of retention of the natural gas
by the operator, or owner of the production at severance, for beneficial
economic use; and
(2) Quantities of natural gas sold in interstate commerce (within the
meaning of the Natural Gas Act) before November 9, 1978, shall not be
taken into account if such sales were made:
(i) Under section 6 of the Emergency Natural Gas Act of 1977; or
(ii) Under the emergency sale authority pursuant to Opinion No.
699-B, issued by the Commission under section 7(c) of the Natural Gas
Act.
(f) Could have been produced in commercial quantities. For purposes
of determining under section 102(c)(1)(C)(ii)(II) of the NGPA, whether
natural gas from a reservoir could have been produced in commercial
quantities thru an old well which penetrated such reservoir before April
20, 1977:
(1) A rebuttable presumption exists that a reservoir could not have
been produced in commercial quantities prior to April 20, 1977, through
such old well if:
(i) No sales and deliveries of natural gas were made prior to April
20, 1977, through such well; and,
(ii) No sales and deliveries of natural gas from the subject
reservoir were made through such well on or after April 20, 1977, and
before November 9, 1978.
(2) If such rebuttable presumption is not met, then the first seller
must clearly demonstrate that the sale of the production from such
reservoir through such old well at the market price reasonably available
as of April 20, 1977, could not reasonably have generated revenues (net
of royalty) equal to or greater than the sum of (i) 1.6 times the
minimum incremental costs (properly allocable to such production) of
installing cost-efficient facilities (not in existence as of April 20,
1977) reasonably required to market such production, plus (ii) the
minimum incremental expenses (properly allocable to such production)
reasonably required to operate such facilities. All costs, expenses,
and revenues shall be determined as of April 20, 1977.
(Order 42, 44 FR 48183, Aug. 17, 1979, as amended by Order 42-A, 44
FR 69647, Dec. 4, 1979)
18 CFR 271.204 Subpart C -- New, Onshore Production Wells
Authority: Natural Gas Act, as amended, 15 U.S.C. 717 et seq.;
Department of Energy Organization Act, 42 U.S.C. 7107 et seq., E.O.
12009, 42 FR 46267, Natural Gas Policy Act of 1978, Pub. L. 95-621, 92
Stat. 3350.
18 CFR 271.301 Applicability.
This subpart implements section 103 of the NGPA and applies to the
first sale of natural gas produced from a new, onshore production well,
if such gas is not deregulated natural gas (see 272.103(a)).
(Order 406, 49 FR 46883, Nov. 29, 1984)
18 CFR 271.302 Maximum lawful price.
The maximum lawful price, per MMBtu, for natural gas to which this
subpart applies shall be the price specified for subpart C of part 271
in Table I of 271.101(a).
(44 FR 49655, Aug. 24, 1979)
18 CFR 271.303 Definition of new, onshore production well.
(a) For purposes of this subpart, the term ''new, onshore production
well'' means a well which a jurisdictional agency has determined, in
accordance with parts 274 and 275, to be a new, onshore production well
(as defined in section 103(c) of the NGPA).
(b) A determination that gas is produced from a well that qualifies
as a ''new, onshore production well'' applies to:
(1) Any natural gas produced from any completion location for which
the applicable state or Federal agency grants a well completion permit,
provided the completion location is the first completion location in the
proration unit and the surface drilling of the well began on or after
February 19, 1977; or
(2) Any natural gas for which a finding has been made under 271.305
of this subpart.
(Approved by the Office of Management and Budget under control number
1902-0112.)
(Order 336, 48 FR 44517, Sept. 29, 1983, as amended at 48 FR 54947,
Dec. 7, 1983)
18 CFR 271.304 Waivers of well-spacing requirements.
If a jurisdictional agency alters or grants a waiver of any
applicable well-spacing requirements, the new well for which a
determination is sought shall be deemed to satisfy any applicable
Federal or State well-spacing requirements as required by section
103(c)(2) of the NGPA.
(44 FR 67111, Nov. 23, 1979)
18 CFR 271.305 Special rule applicable to existing proration units.
(a) Applicability. (1) This section applies only to a jurisdictional
agency determination with respect to a new well which is within a State
law proration unit:
(i) Which was in existence at the time the surface drilling of such
well began;
(ii) Which was applicable to the reservoir from which natural gas
from such well is produced; and
(iii) Which applied to a well:
(A) Which produced natural gas in commercial quantities; or
(B) The surface drilling of which was begun before February 19, 1977,
and which was thereafter capable of producing natural gas in commercial
quantities.
(2) For purposes of this paragraph, State law proration unit means a
proration unit, drilling unit or similar unit expressly designated in
accordance with State law or Federal law (other than the NGPA).
(b) Wells spudded on or after February 19, 1977. (1) In order for
natural gas from a well to which this section applies to qualify for the
maximum lawful price under this subpart, the jurisdictional agency must
explicitly find that the well is necessary to effectively and
efficiently drain a portion of the reservoir covered by the proration
unit which cannot be effectively and efficiently drained by any existing
well within the proration unit. This explicit finding must be based on
appropriate geological and engineering data and such data must be
included in the notice of determination submitted to the Commission.
(2) (Reserved)
(c) Notice of finding. If the jurisdictional agency makes a finding
under paragraph (b)(1) of this section, it shall notify the Commission
of such a determination in accordance with 274.104.
(d) Rebuttable presumption for certain wells drilled on existing
proration units. For the purposes of section 103(c)(3)(C) of the NGPA
and paragraph (a)(1)(iii) of this section, if a well has been plugged
and abandoned prior to January 1, 1970 and has not produced natural gas
on or after that date, a rebuttable presumption is created that the well
has not produced and is not capable of producing natural gas in
commercial quantities.
(44 FR 67112, Nov. 23, 1979)
18 CFR 271.305 Subpart D -- Natural Gas Committed or Dedicated to
Interstate Commerce
Authority: Natural Gas Act, 15 U.S.C. 717-717w (1982); Department
of Energy Organization Act, 42 U.S.C. 7101-7352 (1982); E.O. 12009, 3
CFR 142 (1978); Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432
(1982).
18 CFR 271.401 Applicability.
This subpart implements sections 104 and 106(a) of the NGPA and
applies to the first sale of natural gas committed or dedicated to
interstate commerce on November 8, 1978, and for which a just and
reasonable rate under the Natural Gas Act was in effect on November 8,
1978, for the sale of such gas.
(45 FR 1871, Jan. 9, 1980)
18 CFR 271.402 Maximum lawful prices.
(a) Ceiling prices. Unless a different rate is applicable under
paragraph (c) of this section, the maximum lawful price for a category
of natural gas to which this subpart applies shall be the price
specified in Table II of 271.101(a) for such category of gas.
(b) Definitions. For the purposes of this section:
(1) Post-1974 gas means natural gas to which this subpart applies
which is produced from a well the surface drilling of which commenced on
or after January 1, 1975.
(2) 1973-1974 biennium gas means natural gas, to which this subpart
applies, from a well the surface drilling of which commenced on or after
January 1, 1973, and prior to January 1, 1975.
(3) Interstate rollover gas means:
(i) Natural gas to which this subpart applies which is sold under a
rollover contract as defined in section 2(12) of the NGPA; or
(ii) Natural gas to which this subpart applies which is sold under a
contract which would have been a rollover contract, but for the fact
that the expiration of the previous contract occurred prior to November
9, 1978.
(4) Replacement contract gas or recompletion gas means natural gas to
which this subpart applies which is:
(i) Sold under a replacement contract which was executed on or after
January 1, 1973, but prior to November 9, 1978, where the prior contract
expired by its own terms prior to January 1, 1973; or
(ii) Sold under a replacement contract executed prior to November 9,
1978, where the prior contract expired by its own terms after January 1,
1973; or
(iii) Sold under a contract for the sale of natural gas from well
commenced prior to January 1, 1973, and not sold in interstate commerce
prior to January 1, 1973, (excluding gas sold prior to such date under
2.68, 2.70, 157.22 or 157.29 of this chapter); or
(iv) Produced as a result of a completion operation into a different
formerly nonproductive reservoir, commenced on or after January 1, 1973,
and produced through a well commenced prior to January 1, 1973.
(5) Certain Permian Basin gas means natural gas (other than
replacement contract gas or recompletion gas) to which this subpart
applies and which is produced in the Permian Basin Area, as defined in
FPC Opinion No. 662 (50 F.P.C. 390 at 400-401) and is sold pursuant to
a contract executed on or after October 1, 1968.
(6) Certain Rocky Mountain gas means natural gas (other than
replacement contract gas or recompletion gas) to which this subpart
applies and which is produced in the Rocky Mountain Area, as defined in
154.109(b) of this chapter and sold pursuant to a contract executed on
or after October 1, 1968.
(7) Certain Appalachian Basin gas means natural gas (other than
replacement contract gas or recompletion gas) to which this subpart
applies and which is produced by a large producer either (i) in the
south sub-area under contracts dated October 7, 1969, or (ii) in the
north sub-area, of the Appalachian Basin Area, as defined in 154.107 of
this chapter.
(8) Flowing gas means natural gas to which this subpart applies
(other than natural gas described in the preceding subparagraphs of this
paragraph) produced from a well the surface drilling of which commenced
prior to January 1, 1973.
(9) Minimum rate gas means natural gas to which this subpart applies
produced from a well the surface drilling of which commenced prior to
January 1, 1973, and which is sold pursuant to a contract providing for
a fixed rate lower than that applicable to such gas under paragraph (c)
of this section.
(10) A sale qualifies as a small producer sale under this subpart:
(i) If it is a small producer sale (as defined in 157.40(a)) covered by
a blanket certificate under 157.40 (b) and (d), or (ii) if it is a sale
by a large producer from small producer reserves, and such sale is
entitled to the small producer rate under 157.40(f)(2).
(11) A large producer sale is a first sale which does not qualify as
a small producer sale under paragraph (b)(10) of this section.
(c) Applicable higher rates. (1) If a just and reasonable rate in
effect on April 20, 1977, under former 2.56a(g), 2.56b(h), 2.76, or
2.77 of this chapter was applicable on November 30, 1978, to a first
sale of natural gas, then such rate (plus an inflation adjustment from
April, 1977, determined in accordance with 271.102), if higher, shall
apply in lieu of the rate determined under paragraph (a) of this
section.
(2) Any just and reasonable rate for a sale of natural gas which was
established by the Commission after April 20, 1977, and before November
9, 1978, shall be the maximum lawful price applicable to such sale if
higher than the otherwise applicable rate prescribed under paragraph (a)
or (c)(1) of this section.
(3) In the case of any first sale under any rollover contract to
which this subpart applies, the maximum lawful price for the month in
which the effective date of such rollover contract occurs is the highest
of:
(i) The maximum lawful price applicable to the expiring contract in
the month in which the rollover contract becomes effective;
(ii) The price specified in Table II of 271.101(a) for interstate
rollover gas; or
(iii) The price specified in Table II of 271.101(a) for post-1974
gas if the rollover contract becomes effective after July 18, 1986.
(4) For purposes of 271.402(b) (1) and (2), production from
reservoirs penetrated for the first time through deeper drilling in an
existing well is eligible for the same rate as if the deeper drilling
constituted the commencement of surface drilling of such well. Deeper
drilling means drilling after the first completion and production in a
well bore have been accomplished, or drilling below an uncompleted
nonproductive horizon where the initial well bore was plugged and
abandoned.
(5) Any seller seeking to charge a rate in excess of the applicable
maximum lawful price described in paragraphs (a), or (c) (1), (2), or
(7) of this section must file a petition seeking special relief fully
justifying the relief sought. Such seller may not file a rate increase
for, or charge or collect any rate in excess of the maximum lawful price
otherwise applicable under this section unless the Commission has
granted such petition for special relief.
(6) Notwithstanding 270.101(b), the minimum rate for minimum rate
gas (at 14.73 psia and 60 F) shall be the rate specified for minimum
rate gas in Table II of 271.101(a).
(7) The maximum lawful price, per MMBtu, for the first sales of all
categories of gas otherwise subject to lower maximum lawful prices under
this subpart is the price specified in Table II of 271.101(a) for
post-1974 gas, if the price is established:
(i) Under a contract or contract amendment executed after July 18,
1986; or
(ii) In accordance with the good faith negotiation procedures of
270.201 of this chapter.
(Order 64, 45 FR 1871, Jan. 9, 1980, as amended at 44 FR 48664, Aug,
1979; 45 FR 5685, Jan. 24, 1980; 45 FR 16173, Mar. 13, 1980; Order
225, 47 FR 19058, May 3, 1982; 49 FR 21913, May 23, 1984; Order 451,
51 FR 22220, June 18, 1986)
18 CFR 271.403 Special rule regarding carrying charge adjustment for
advance payments.
The rate prescribed in 271.402 for post-1974 gas to which Opinion
No. 770-A applies shall be subject to a deduction of 83 cents per MMBtu
as a carrying charge adjustment if the seller has accepted advance
payments on or after 1:00 p.m., EST, November 5, 1976, under an advance
payments contract with an interstate pipeline company and such pipeline
company has received rate base treatment of such advance payments made.
The resulting adjusted rate shall be employed in the discharge of the
obligations of any advance payments after 1:00 p.m., EST, November 5,
1976, for all deliveries until an amount of natural gas has been
delivered at the adjusted rate such that the total carrying charge
credits equal the amounts lawfully collected by the jurisdictional
pipeline company as a result of including the advance payments in rate
base.
(45 FR 1872, Jan. 9, 1980)
18 CFR 271.403 Subpart E -- Sales Under Existing Intrastate Contracts
Authority: Natural Gas Act, as amended, 15 U.S.C. 717, et seq.;
Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O.
12009, 42 FR 46267; Natural Gas Policy Act of 1978; 15 U.S.C.
3301-3432.
18 CFR 271.501 Applicability.
This subpart implements section 105 of the NGPA and applies to the
first sale of natural gas under an existing intrastate contract or under
a successor to an intrastate contract, if such natural gas is not
deregulated natural gas (see 272.103(a)). This subpart is not
applicable to sales made under an intrastate rollover contract as
defined in 270.102(b)(11) of this part.
(Order 68, 45 FR 5684, Jan. 24, 1980, as amended by Order 406, 49 FR
46884, Nov. 29, 1984)
18 CFR 271.502 Maximum lawful prices.
(a) In the case of a first sale of natural gas to which this subpart
applies (other than a first sale to which paragraph (b) applies), the
maximum lawful price for natural gas delivered in any month shall be the
lower of:
(1) The price for such month under the terms of the existing
intrastate contract to which such natural gas was subject on November 9,
1978, as such contract was in effect on November 9, 1978; or
(2) The maximum lawful price per MMBtu for such month specified for
new natural gas (subpart B of part 271) in Table I of 271.101(a).
(b) The maximum lawful price per MMBtu for natural gas delivered in
any month which is:
(1) Gas to which the subpart applies;
(2) Gas for which the price paid exceeds $1.00 per MMBtu on December
31, 1984 (or would exceed $1.00 per MMBtu if sold on such date); and
(3) Gas which is sold at a price established under an indefinite
price escalator clause as defined in section 105(b)(3)(B) of the NGPA;
Shall be the higher of the price specified for subpart E of part 271
in Table I of 271.101(a) or the contract price per MMBtu on November 9,
1978, adjusted for inflation in accordance with 271.102 of this part.
(Order 68, 45 FR 5684, Jan. 24, 1980, as amended by Order 406, 49 FR
46884, Nov. 29, 1984; Order 406-A, 49 FR 50642, Dec. 31, 1984)
18 CFR 271.503 Recordkeeping.
Any person who collects a price under this subpart for the first sale
of natural gas shall keep:
(a) Any books and records related to the sale for three years from
the end of each billing period; and
(b) Any contract related to the sale for three years after the
expiration of the contract.
(Order 272, 48 FR 646, Jan. 6, 1983)
18 CFR 271.504 Determination of contract price.
For purposes of this subpart:
(a) Contract price. ''Contract price,'' when used with respect to
any specific date and contract, means:
(1) The total price paid per MMBtu for delivery of natural gas
occurring on that date (including any amounts which were required to be
paid as reimbursement from the purchaser for State severance taxes paid
by the seller).
(2) If no deliveries of natural gas occurred under such contract on
that date, the total price per MMBtu that would have been paid for
delivery of natural gas on that date (including any amount which would
have been required to be paid as reimbursement from the purchaser for
State severance taxes which would have been paid by the seller).
(b) Price under the terms of the existing contract. ''Price under
the terms of the existing contract'' when used with respect to any
specific date and contract means the total price under the terms of the
existing contract, as such contract was in effect on November 9, 1978
(including any amounts which are required to be paid as reimbursement
from the purchaser for State severance taxes paid by the seller).
(c) Take-or-pay clauses. If the contract contains a take-or-pay
clause and payments were made under such clause for deliveries on
November 9, 1978, the contract price on November 9, 1978, shall be
determined as if volumes obligated to be taken were taken.
(Order 108, 45 FR 76670, Nov. 20, 1980)
Effective Date Note: At 46 FR 2975, Jan. 13, 1981, the effective
date of Jan. 1, 1981, was stayed for 271.504(a) and (b).
18 CFR 271.504 Subpart F -- Intrastate Rollover Contracts
Authority: Natural Gas Act, 15 U.S.C. 717-717w (1982); Department
of Energy Organization Act, 42 U.S.C. 7101-7352 (1982); E.O. 12009, 3
CFR 142 (1978); Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432
(1982).
18 CFR 271.601 Applicability.
This subpart implements section 106(b) of the NGPA and applies to the
first sale of natural gas under an intrastate rollover contract, if such
natural gas is not deregulated natural gas (see 272.103(a)).
(Order 406, 49 FR 46884, Nov. 29, 1984)
18 CFR 271.602 Maximum lawful price.
(a) General rule. The maximum lawful price for a first sale of
natural gas under an intrastate rollover contract to which section
106(b)(1) of the NGPA applies shall be the highest of:
(1)(i) The maximum lawful price, per MMBtu, paid under the expired
contract, in the month in which the rollover contract becomes effective;
and
(ii) In any month after the month in which the rollover contract
becomes effective, the maximum lawful price, per MMBtu, prescribed under
this paragraph for the preceding month adjusted for inflation in
accordance with 271.102;
(2) The alternative maximum lawful price specified in Table I of
271.101(a) for certain intrastate rollover gas; or
(3) The price specified in Table II of 271.101(a) for post-1974 gas,
if the price is established under a contract or contract amendment
executed after July 18, 1986.
(b) Certain State or Indian production or royalty shares. The
maximum lawful price, per MMBtu, for natural gas to which section
106(b)(2) of the NGPA (relating to certain State or Indian natural gas
production or royalty interests) applies shall be the price specified
for new natural gas (subpart B of part 271) in Table I of 271.101(a).
(c) Qualified production enhancement gas. For purposes of paragraph
(a)(1)(i) of this section, the maximum lawful price, per MMBtu, paid
under the expired contract is deemed to include any amount paid by
reason of a maximum lawful price allowed under 271.704 (relating to
qualified production enhancement gas.)
(Order 68, 45 FR 5684, Jan. 24, 1980, as amended by Order 107, 45 FR
77429, Nov. 24, 1980; Order 451, 51 FR 22220, June 18, 1986)
18 CFR 271.603 Recordkeeping.
Any person who collects a price under this subpart for the first sale
of natural gas shall keep:
(a) Any books and records related to the sale for three years from
the end of each billing period; and
(b) Any contract related to the sale for three years after the
expiration of the contract.
(Order 272, 48 FR 646, Jan. 6, 1983)
18 CFR 271.603 Subpart G -- High-Cost Natural Gas
Authority: Dept. of Energy Organization Act (42 U.S.C. 7101, et
seq.); E.O. 12009, 42 FR 46267; Natural Gas Policy Act of 1978 (15
U.S.C. 3301-3432; Natural Gas Act, as amended, 15 U.S.C. 717, et seq.
18 CFR 271.701 Applicability.
This subpart implements section 107 (b) and (c) of the NGPA and
applies to the first sale of natural gas which is:
(a) Tight formation gas for there is a negotiated contract price.
(b) Qualified production enhancement gas.
(Order 99, 45 FR 56044, Aug. 22, 1980, as amended by Order 99-A, 45
FR 71564, Oct. 29, 1980; Order 107, 45 FR 77429, Nov. 24, 1980)
18 CFR 271.702 General rules.
(a) Definitions. For purposes of this subpart:
(1) Negotiated contract price means any price established by a
contract provision that specifically references the incentive pricing
authority of the Commission under section 107 of the NGPA, by a contract
provision that prescribes a specific fixed rate, or by the operation of
a fixed escalator clause.
(2) A fixed escalator clause is a provision in a contract for the
first sale of natural gas which changes the price for the gas by a
specified amount on a specified date.
(3) For the definition of crude oil, see 270.102(b)(5).
(4) Pipeline production price means any price which is paid by the
transmission divisional unit of a pipeline in a first sale to the
production divisional unit of that pipeline and which does not exceed
the amount paid in comparable first sales between persons not affiliated
with such pipeline.
(b) Cross reference. For special rules applicable to high-cost
natural gas retroactive collections, see 273.204.
(Order 99, 45 FR 56044, Aug. 22, 1980, as amended by Order 99-A, 45
FR 71565, Oct. 29, 1980; Order 391, 49 FR 33859, Aug. 27, 1984)
18 CFR 271.703 Tight formations.
(a) Maximum lawful price for tight formation gas. (1) The maximum
lawful price, per MMBtu, for the first sale of tight formation gas for
which there is a negotiated contract price or a pipeline production
price shall be the lesser of:
(i) The negotiated contract price or the pipeline production price,
as applicable; or
(ii) 200% of the maximum lawful price specified for subpart C -- NGPA
section 103(b)(1) of part 271 in table I of 271.101(a).
(2) The maximum lawful price does not apply to:
(i) New tight formation gas from a well the surface drilling of which
began on or after May 13, 1990; and
(ii) Recompletion tight formation gas from a well the surface
drilling of which was begun before July 16, 1979, if the recompletion
work for the well from such designated formation was begun on or after
May 13, 1990.
(b) Definitions. (1) Tight formation gas means natural gas that a
jurisdictional agency has determined in accordance with parts 274 and
275 to be new tight formation gas or recompletion tight formation gas.
(2) New tight formation gas is natural gas:
(i) Which is new natural gas, (as defined in section 102(c)), certain
OCS gas qualifying for the new natural gas ceiling price (as defined in
section 102(d)), or gas produced through a new onshore production well
(as defined in section 103(c)); and
(ii) Which is produced from a designated tight formation through a
well the surface drilling of which began on or after July 16, 1979.
(3) Recompletion tight formation gas is natural gas which is produced
from a designed tight formation through a well, the surface drilling of
which was begun before July 16, 1979,
(i) If such well was not completed for production from such
designated formation prior to July 16, 1979, or
(ii) If such well was completed for production from such designated
formation prior to July 16, 1979, such gas is produced from a completion
location completed after December 27, 1983, and such gas could not have
been produced from any completion location which was in existence in the
wellbore on or before December 27, 1983.
(4) Formation means any geological formation, or portion thereof
described by geological as well as geographical parameters.
(5) A designated tight formation is a natural gas formation as
determined by the appropriate jurisdictional agency, pursuant to
paragraph (c)(3) of this section. Appropriate jurisdictional agencies
are identified in 274.501 of this chapter.
(6) Infill drilling means any drilling in a substantially developed
formation (or a portion thereof) subject to requirements respecting
well-spacing or proration units which were amended by the jurisdictional
agency after the formation (or portion thereof) was substantially
developed and which were adopted for the purpose of more effective and
efficient drainage of the reservoirs in such formation. Such amendment
may provide for the establishment of smaller drilling or production
units or may permit the drilling of additional wells on the original
units.
(c) Determination of tight formations --
(1) General. Determinations by a jurisdictional agency must be made
in the form and manner prescribed in part 274 of this chapter.
(2) Guidelines. (i) The guidelines for tight formations are as
follows:
(A) The estimated average in situ gas permeability, throughout the
pay section, is expected to be 0.1 millidarcy or less.
(B) The stabilized production rate, against atmospheric pressure, of
wells (other than horizontally drilled wells) completed in the
formation, without stimulation, is not expected to exceed the production
rate determined in accordance with the following table:
(C) No well drilled into the recommended tight formation is expected
to produce, without stimulation, more than five barrels of crude oil per
day.
(D) If the formation or any portion thereof was authorized to be
developed by infill drilling prior to the date of determination and the
jurisdictional agency has information which in its judgment indicates
that such formation or portion subject to infill drilling can be
developed absent the incentive price established in paragraph (a) of
this section then the jurisdictional agency shall not include such
formation or portion thereof in its determination.
(ii) The jurisdictional agency may designate as a tight formation any
formation which meets the guidelines contained in paragraph (c)(2)(i)
(B) and (C) of this section, but does not meet the guideline contained
in paragraph (c)(2)(i)(A) of this section, if the jurisdictional agency
makes an adequate showing that the formation exhibits low permeability
characteristics and the price established in paragraph (a) of this
section is necessary to provide reasonable incentives for production of
the natural gas from the determined formation due to the extraordinary
costs associated with such production.
(3) Notice to the Commission. Any jurisdictional agency making a
determination that a natural gas formation qualifies as a tight
formation will provide timely notice in writing of the determination to
the Commission. Such notice shall include substantiation provided in
paragraph (4) of this section and be in the manner prescribed in
274.104 of this chapter.
(4) Content of determinations. A determination that a formation
qualifies as a designated tight formation shall contain the following
information:
(i) Geological and geographical descriptions of the formation which
is determined to qualify as a tight formation;
(ii) Geological and engineering data to support the determination and
the source of that data;
(iii) A map which clearly locates wells which are currently producing
from the determined tight formation or a list locating all wells which
are currently producing natural gas from the determined tight formation;
(iv) A report of the extent to which existing State and Federal
regulations will assure development of the determined tight formation
will not adversely affect any fresh water aquifers (during both
hydraulic fracturing and waste disposal operations) that are or are
expected to be used as a domestic or agricultural water supply;
(v) If the formation is determined under paragraph (c)(2)(ii) of this
section, the types and extent of enhanced production techniques which
are expected to be necessary and the estimated expenditures necessary
for employing those techniques; and the degree of increase in
production to be expected from use of such techniques and engineering
and geological data to support that estimate; and
(vi) Any other information which the jurisdictional agency deems
relevant.
(5) Commission review of determinations. Upon receipt of a
determination submitted in accordance with this section, the Commission
will review the jurisdictional agency's determination in accordance with
the procedures established in part 275 of this chapter
(d) Designated tight formations. The following formations are
designated as tight formations. A more detailed description of the
geographical extent and geological parameters of the designated tight
formations is located in the Commission's official file for Docket No.
RM79-76, subindexed as indicated, and is also located in the official
files of the jurisdictional agency that submitted the recommendation.
(1) The Cotton Valley Group in Texas. RM79-76 (Texas-1).
(i) The Cotton Valley Group consisting of the Cotton Valley
Sandstone, the Bossier Shale and the Cotton Valley Lime Formations --
(A) Delineation of formation. The northern boundary of the Cotton
Valley Group is the Texas-Oklahoma border extending through Fannin,
Lamar, and Red River Counties; the eastern boundary is formed by the
Texas-Arkansas border and the Texas-Lousiana border; the southern
boundary is along the Angelina-Caldwell flexture, running through
Sabine, San Augustine, Angelina and Trinity Counties; the western
boundary is set by the Mexia-Talco fault zone through Limestone, Navarro
and Kaufman Counties.
(B) Depth. The Cotton Valley Sandstone is encountered at an average
depth of approximately 7,000 feet to the north, 8,000 feet to the east,
between 10,000 and 11,000 feet to the south, and 5,000 feet to the west;
the Bossier Shale is encountered at 7,700 feet to the north, 10,720
feet to the east, 12,600 feet to the south, and 5,340 feet to the west:
the Cotton Valley Lime is encountered at 8,000 feet to the north, 11,400
feet to the east, 13,200 feet to the south, and 5,500 feet to the west.
(ii) The Cotton Valley Sandstone in the Paige, N. E. Field area --
(A) Delineation of formation. The Cotton Valley Sandstone in the Paige,
N. E. Field area is found in the eastern portion of Bastrop County,
Texas, in Railroad Commission District No. 1. The boundaries of the
Cotton Valley Sandstone are approximately 2.5 miles around the Hou-Tex
Oil and Gas No. 1 O. R. Mitchell Well. This well is in the Paige, N.
E. Field, located two miles from Paige, Texas, in the Wm. Boatwright
Survey, A-82.
(B) Depth. The top and base of the Cotton Valley Sandstone in the
Paige, N. E. Field area are found at the approximate subsea depths of
^11,520 feet and ^12,780 feet, respectively. The maximum thickness of
the formation is approximately 1,790 feet.
(2) The Mancos ''B'' Formation in Colorado. RM79-76 (Colorado-2).
(i) Delineation of formation. The Mancos ''B'' Formation is located
approximately midway between Grand Junction and Rangely, Colorado, and
straddles the Rio Blanco-Garfield county line from the Utah-Colorado
state line east to the Douglas Pass and Baxter Pass Unit Area,
underlying appoximately 195,200 contiguous acres of land in Rio Blanco
and Garfield Counties, Colorado.
(ii) Depth. The average depth to the top of the Mancos ''B''
Formation is approximately 3,475 feet.
(3) The Frontier Formation in Wyoming. RM79-76 (Wyoming-1).
(i) Delineation of formation. The Frontier Formation is located in
the Moxa Arch area in portions of Sweetwater, Uinta, and Lincoln
Counties, Wyoming.
(ii) Depth. The top of the Frontier Formation is marked by the
Hilliard Shale above, and the bottom of the formation is marked by the
Mowry Shale, below. The average depth of the top of the Frontier
Formation ranges from approximately 11,100 feet to 11,140 feet.
(4) The Mesaverde Formation in Wyoming. RM79-76 (Wyoming-2).
(i) Delineation of formation. The Mesaverde Formation is located in
the Wamsutter Area in portions of Sweetwater, and Carbon Counties,
Wyoming.
(ii) Depth. The top of the Mesaverde Formation is marked the Lewis
Shale above, and the bottom of the formation is marked by the Steele
Shale, below. The average depth to the top of the formation is
approximately 10,125 feet.
(5) The Austin-Mississippian Formation in New Mexico. RM79-76 (New
Mexico-1).
(i) Delineation of formation. The Austin-Mississippian Formation is
located entirely within Lea County, New Mexico. The area consists of
138,240 contiguous acres of land located approximately 6 to 12 miles
north of Lovington, New Mexico.
(ii) Depth. The average depth to the top of the Austin-Mississippian
Formation is approximately 13,250 feet.
(6) The Mancos ''B'' Formation in Colorado. RM79-76 (Colorado-6).
(i) Delineation of formation. The Mancos ''B'' Formation is located
in northwestern Colorado in the North Douglas Creek area in Rio Blanco
County, Colorado, approximately 10 miles south of the town of Rangely,
Colorado, on the Douglas Creek Arch which separates the Uinta and
Piceance Creek Geologic Basins.
(ii) Depth. The average depth to the top of the Mancos ''B''
Formation is approximately 2,500 feet.
(7) The Fort Union Formation in Colorado. RM79-76 (Colorado-4).
(i) Delineation of formation. The Fort Union Formation is located in
the Rio Blanco and Dry Gulch Units of Rio Blanco County, Colorado,
approximately 40 miles southwest of Meeker, Colorado, and 30 miles
northwest of Rifle, Colorado. The area is bounded on the north and
south by synclinal and anticlinal trends, and on the northeast by an
anticlinal closure known as the Piceance Creek Dome.
(ii) Depth. The average depth to the top of the Fort Union Formation
is approximately 4,700 feet.
(8) The Mesaverde Formation in Colorado. RM79-76 (Colorado-4).
(i) Delineation of formation. The Mesaverde Formation is located in
the Rio Blanco and Dry Gulch Units of Rio Blanco County, Colorado,
approximately 40 miles southwest of Meeker, Colorado, and 30 miles
northwest of Rifle, Colorado. The area is bounded on the north and
south by synclinal and anticlinal trends, and on the northeast by an
anticlinal closure known as the Piceance Creek Dome.
(ii) Depth. The average depth to the top of the Mesaverde Formation
is approximately 7,200 feet.
(9) The Mancos Formation to the base of the Mancos ''B'' Zone in
Colorado. RM79-76 (Colorado-4).
(i) Delineation of formation. The Mancos Formation to the base of
the Mancos ''B'' Zone is located in the Rio Blanco and Dry Gulch Units
in Rio Blanco County, Colorado, approximately 40 miles southwest of
Meeker, Colorado, and 30 miles northwest of Rifle, Colorado. The area
is bounded on the north and south by synclinal and anticlinal trends,
and on the northeast by an anticlinal closure known as the Piceance
Creek Dome.
(ii) Depth. The average depth to the top of Mancos Formation is
approximately 10,500 feet.
(10) Canyon Sandstone Formation in Texas. RM79-76 (Texas-2)
(i) The Canyon Sandstone Formation in Crockett, Edwards, Schleicher,
Sutton, Terrell and Val Verde Counties, Texas.
(A) Delineation of formation. The Canyon Sandstone Formation is
found in portions of Crockett, Edwards, Schliecher, Sutton, Terrell and
Val Verde Counties, Texas.
(B) Depth. In the east, the top of the Upper Canyon (Sonora) of the
Canyon Sandstone Formation is encountered at a depth of approximately
4,775 feet and the base of the Lower Canyon extends to 8,953 feet, for a
total thickness of 4,178 feet. In the west, the top of the Upper Canyon
(Ozona), the only section of the Canyon Sandstone Formation to occur in
the west, is encountered at an approximate depth of 2,675 feet in the
south and 6,100 feet in the north. The base of the Upper Canyon (Ozona)
appears at an approximate depth of 3,915 feet in the south, and 7,278
feet in the north, and its thickness ranges from approximately 1,240
feet in the north to 1,178 feet in the south.
(ii) The Canyon Sandstone Formation in the KWB (Canyon) Field, Tom
Green County, Texas.
(A) Delineation of formation. The designated area of the Canyon
Sandstone Formation in the KWB (Canyon) Field is located 2.5 miles south
of the town of Carlsbad in Tom Green County, Texas, and consists of the
following surveys: TTRR Co. 1113 and 1135; TCRR Co. 1137 and 1139;
H & TC RR Co. 37; J. S. Turner 1132; W. Turner 1114, 1136, 1138, and
1140; Mason-Perry Co. (Subdivision 1 of Collins Ranch) 48, 49, 52
thru 58 and 214 A&B thru 295; Mason-Perry Co. (Subdivision 2 of
Collins Ranch) 29.
(B) Depth. The top of the Canyon Sandstone Formation within the
designated area ranges from approximately 3,200 to 3,800 feet subsea and
is identified on the log of the Mitchell Energy Corporation McWhorter
218 No. 2 well as a 900 foot thick interval occurring between the
measured depths of 5,100 and 6,000 feet.
(iii) Irion County -- (A) Delineation of formation. The Canyon
Sandstone Formation is located in all of the portion of Irion County
which lies to the east of a straight line directed between the junction
of Crockett, Schleicher, and Irion Counties at the south end of the line
and the junction of Reagan, Tom Green, and Irion Counties at the north
end of the line.
(B) Depth. The Canyon Sandstone Formation is that interval from
6,290 feet to the top of the Strawn Formation at 7,870 feet shown on the
electric log of the John H. Hill, McManus No. 1 well located in the
north central part of Irion County in Section 35, Block 6, H&TC RR. Co.
Survey. The top of the formation dips at a rate of approximately 50 feet
per mile in a west-southwest direction across the designated area.
(11) Wattenberg J Sand Formation in Colorado. RM79-76 (Colorado-1).
(i) Wattenberg J Sand Formation -- (A) Delineation of formation. The
Wattenberg J Sand Formation is located north and east of Denver,
Colorado, on the western flank of the Denver-Julesberg Basin, underlying
approximately 702,000 acres of land in Boulder, Adams, Larimer, and Weld
Counties, Colorado. This formation underlies portions of Township 1
South, Range 64 through 68 West; Township 2 South, Ranges 64 and 65
West; Townships 1 and 2 North, Ranges 63 through 69 West: Townships 3
and 4 North, Ranges 63 through 68 West; Township 5 North, Ranges 63
through 69 West, 6th P.M.; Township 2 North, Range 68 West, 6th P.M.,
Sec. 13W/2.
(B) Depth. The Wattenberg J Sand Formation ranges in depth from
7,600 feet to 8,400 feet. The average depth is 8,000 feet.
(ii) The J Sand Formation. RM79-76 (Colorado-1 Addition) -- (A)
Delineation of formation. This formation underlies all or portions of
Townships 1 and 2 South, Ranges 69 and 70 West; Townships 1 and 2
North, Range 70 West; Townships 3 and 4 North, Ranges 69 and 70 West;
Township 5 North, Range 63 West: Township 6 North, Ranges 63 through 69
West, 6th P.M., in Boulder, Larimer, Jefferson and Weld Counties,
Colorado.
(B) Depth. The J Sand Formation ranges from a depth of 7,600 feet to
8,400 feet. The average depth is approximately 8,000 feet.
(iii) The J Sand Formation. RM79-76 (Colorado-1 Addition II) -- (A)
Delineation of formation. This formation underlies all or portions of
Township 1 South, Range 63 West, and Township 2 South, Ranges 63 and 64
West, 6th P.M., in Adams County, Colorado.
(B) Depth. The J Sand Formation ranges from a depth of 7,600 feet to
8,400 feet. The average depth is approximately 8,000 feet.
(12) Cisco Sandstone Formation in Texas. RM79-76 (Texas-3)
(i) The Sallie (Cisco) Field -- (A) Delineation of formation. The
Sallie (Cisco) Field in the Cisco Sandstone Formation is located in
Sections 58, 59, 60, and 72, Block 2, T&P RR Survey, northeast Reagan
County, Texas, and Section 42, Block 2 T&P RR Survey, southwest Sterling
County, Texas.
(B) Depth. The top of the Cisco Sandstone Formation is located at an
approximate depth of 8,030 feet and is approximately 300 feet thick.
(ii) The Credo, East (Cisco, Upper) Field -- (A) Delineation of
formation. The Upper Cisco Formation is located in the northwestern
corner of Sterling County, in west Texas, Railroad Commission District
8, and includes Sections 149, 150, 151, 170, 171, 172, 177, 178, 179,
198 through 207 and 226 through 230 of Block 29, W&NW RR Co. Survey;
Sections 1 through 6 and 15 through 18 of Block 30, W&NW RR Co. Survey;
Sections 1 through 5, 5 1/2, 5 3/4, 6(A-1013), 6(A-1269, A-1293 and
A-1305), 7 through 10, 10 1/2, and 11 through 13 of Block 31, TWP. 4-S,
T&P RR Co. Survey; Section 2 of Lily Roberts Survey; Sections 1, 2
and 4 of J. G. Soulard, Survey; Sections 5 through 8, and 18 of Block
14, SP & RR Co. Survey; Sections 1 through 36 of Block 23, H & TC RR
Co. Survey; and Sections 46 through 50, 95 through 101, 127, 182, and
207 of Block 17, SP & RR Co. Survey.
(B) Depth. The top and base of the Upper Cisco Formation located in
the Credo, East (Cisco, Upper) Field, are found at an approximate depth
of 7,125 feet and 7,550 feet, respectively, as measured in the log of
the HNG Oil Co. No. 21-1 McEntire well.
(iii) The Cisco-Canyon Formation -- (A) Delineation of formation.
The Cisco-Canyon Formation is found in the area of the Conger (Penn)
Field and the Conger, S.W. (Penn) Field in Glasscock, Reagan and
Sterling Counties, Texas, Railroad Commission Districts 7C and 8. The
area includes the following surveys: T&P RR Block 33, T-5-S, Sections
34, 36, and W 1/2 of 38; T&P RR, Block 32, T-5-S, Sections 13 through
17, 20 through 29, 32 through 42 and 44 through 48; EL & RR RR Sections
1, 2, 3 and 4; D. L. Carver Section 4; H. T. Tweedle Section 2; T&P
RR, Block 2, Sections 3, 4, 9 through 14, 21 through 26, 33 through 36,
41, 43, 44, 49 through 52, 61, 62, 69, 70, 71, 89 through 92, 100, 118,
128, 146, 155 and 156; GC & SF RR Sections 1 and 3; GC & SF RY Section
1; W. C. Elam Section 4; CT & MC RR Section 2; W. R. Barton Section
4; S. H. Birdwell Section 17; Brooks & Burleson Sections 1 and 2; T.
B. Wilson Section 2; C&M RR Section 1; H&TC RR, Block 22, Sections 19
through 36; T&P RR, Block 31, T-5-S, Sections 4, 5, and 7 through 30;
O. R. Wilson Section 2; Mrs. Ann Morrison Section 7; F. A. Brooks
Section 4; and the north 656.65 acres of the north part of Moses Herrin
No. 6 Block A.
(B) Depth. The depth to the top of the Cisco Formation varies from
approximately 8,670 feet in the southwest part of the area to 6,990 feet
in the northeast. The depth to the top of the Canyon Formation varies
from approximately 8,810 feet in the southwest to 7,370 feet in the
northeast. Total thickness of the two formations varies from
approximately 200 feet in the southwest to 710 feet in the northeast.
(13) The Vicksburg UV Formation in Texas. RM79-76 (Texas-4).
(i) Delineation of formation. The Vicksburg UV Formation is found in
Hidalgo County, Texas.
(ii) Depth. The top of the Vicksburg UV Formation is located at an
approximate depth of 12,304 feet with an approximate thickness of 1,155
feet.
(14) The Vicksburg Y Formation in Texas. RM79-76 (Texas-5).
(i) Delineation for formation. The Vicksburg Y Formation is found in
Hidalgo County, Texas.
(ii) Depth. The top of the Vicksburg Y Formation in the McAllen
Ranch Field is located at an approximate depth of 13,595 feet in the
north and 13,244 feet in the south and ranges in thickness from
approximately 1,955 feet in the north to 1,717 feet in the south.
(15) The Arkadelphia Formation in Louisiana. RM79-76 (Louisiana-1).
(i) Delineation of formation. The Arkadelphia Formation is found in
Union Parish, Louisiana.
(ii) Depth. The Arkadelphia Formation is defined as that formation
occuring between the measured depths of 2,028 feet and 2,080 feet.
(16) The Fort Union Formation in Wyoming. RM79-76 (Wyoming-3).
(i) Delineation of formation. The Fort Union Formation is found in
Pinedale Field in Sublette County, Wyoming.
(ii) Depth. The Fort Union Formation is defined as that formation
occurring between the Wasatch Formation above and the Lance Formation
below, at an average measured depth interval of 7,258 feet to 10,516
feet.
(17) The Midway (11,740') Sandstone Formation in Texas. RM79-76
(Texas-6).
(i) Delineation of formation. The Midway (11,740') Sandstone
Formation is located in the northwestern portion of Montgomery County
and the southeastern portion of Grimes County, Texas.
(ii) Depth. The top of the Midway (11,740') Sandstone Formation is
located at an approximate depth of 11,746 feet and the base is located
at an approximate depth of 11,774 feet, giving it a thickness of 28
feet.
(18) Lower Wilcox Formation in Texas. RM79-76 (Texas-7).
(i) Three County Area -- (A) Delineation of formation. The Lower
Wilcox Formation is found in the southern portion of Austin County, the
northern portion of Wharton County, and the eastern portion of Colorado
County, Texas.
(B) Depth. The top of the Lower Wilcox Formation is located at an
approximate depth of 11,700 feet and the base is located at an
approximate depth of 12,700 feet, giving a thickness of 1,000 feet.
(ii) Bonus, S. (Wilcox 13,900') Field -- (A) Delineation of
formation. The Lower Wilcox Formation is found in the Bonus, S.
(Wilcox 13,900') Field, Wharton County, Texas, approximately 10 miles
south of the town of Eagle Lake. The formation is described by a 2.5
mile radius around the Laurel Fuel Company Winterman No. 3 well, and
covers approximately 19.6 square miles.
(B) Depth. The top of the Lower Wilcox Formation is at an
approximate depth of 13,900 feet and is between 60 and 70 feet thick.
(iii) Lower Wilcox (Midcox) Formation -- (A) Delineation of
formation. The Lower Wilcox (Midcox) Formation is found approximately
five miles northeast of the town of Rock Island in central Colorado
County, Texas, Railroad Commission District 3. The designated area is
within a 2.5 mile radius around the Holt Oil & Gas Corporation (formerly
Perkins Oil Company) Kleimann Unit No. 1 well located in the J. E.
Hester Survey A-740.
(B) Depth. The top of the Lower Wilcox (Midcox) Formation is found
at an approximate log depth of 11,650 feet in the Kleimann Unit No. 1
well and is 344 thick.
(19) Atoka Formation in New Mexico. RM79-76 (New Mexico -- 2).
(i) Delineation of formation. The Atoka Formation is found in Lea
County, New Mexico, and underlies an area approximately 9 miles north of
Lovington, New Mexico, 3 miles southwest of Tatum, New Mexico, and 15
miles west of the Texas border. The formation underlies Township 12
South, Range 35 East, Sections 31 through 36; Township 12 South, Range
36 East, Sections 31 through 36; Township 13 South, Ranges 35 and 36;
All; Township 14 South, Range 35 East, Sections 1 through 24; and
Township 14 South, Range 36 East, Sections 1 through 24, NMPM.
(ii) Depth. The Atoka Formation is defined as that formation the
depth to the top of which ranges from 11,500 to 12,450 feet, and
averages 12,200 feet, and the base of which is defined by the top of the
Morrow Formation. The thickness varies from 375 to 750 feet.
(20) The Niobrara Formation in Colorado. RM79-76 (Colorado-3).
(i) Delineation of formation. The Niobrara Formation is located in
north and east of Denver, Colorado, on the eastern flank of the
Denver-Julesberg Basin, underlying all lands in Cheyenne, Kit Carson,
Lincoln, Logan, Phillips, Sedgwick, Washington, and Yuma Counties,
Colorado. The designated formation does not include the Mildred and
Waverly Fields, or that portion of the Beecher Island Field on which
wells were drilled prior to the issuance of the infill drilling order of
Colorado, No. 300-5.
(ii) Depth. The depth of the Niobrara Formation ranges from 1300
feet to approximately 3000 feet.
(21) The Clinton Sandstone Formation in Ohio. RM79-76 (Ohio-1).
(i) Delineation of formation. The Clinton Sandstone Formation is
found in eastern Ohio, and extends from Lake Erie on the north, to the
Kentucky border on the south, and from Licking County in central Ohio on
the west to the Pennsylvania and West Virginia borders on the east. The
designated tight formation does not include any areas which are gas
storage reservoirs or reservoir protective areas, as defined by maps on
file with the Ohio Oil and Gas Division, Department of Resources and the
Commission.
(ii) Depth. The Clinton Sandstone Formation occurs within the
Silurian Cataract System, between the Dayton Limestone and the Queenston
Shale, found at approximately 2,500 feet in the updip areas near its
pinch out, dipping to the southeast approximately 50 feet per mile.
(22) Haynesville Formation in Louisiana. RM79-76 (Louisiana-2).
(i) Arkana Field, Bossier Parish -- (A) Delineation of the formation.
The Haynesville Formation is found in the northern part of Bossier
Parish, Louisiana, on the Arkansas border and consists of the following:
Township 23 North, Range 12 West, Sections 5 through 8, and 17 through
19; Township 23 North, Range 13 West, Sections 1 through 24; Township
23 North, Range 14 West, Sections 1, 2, 6 through 24, and 27 through 34;
and Township 23 North, Range 15 West, Sections 1 through 3, 22 through
27, and 34 through 36.
(B) Depth. The top of the Haynesville Formation is located at a
measured depth of 10,360 feet, with the base located at 10,845 feet on
the induction electrical log of the Crystal Oil Company Hall No. 1
Well. In the Arkana Field, the Haynesville Formation consists of three
members; the upper member varies in thickness from 120 to 220 feet, the
middle member, the Haynesville Sand, ranges between 120 and 220 feet
thick, and the lowest member, the Buckner, is between 200 and 400 feet
thick.
(ii) Colquitt Field, Claiborne Parish -- (A) Delineation of
formation. The Haynesville Formation Reservoir B, in the Colquitt
Field, is located in Claiborne Parish, Louisiana, and consists of the S
1/2 of the S/W 1/4 of Section 27, the S 1/2 and the S 1/2 of the NW 1/4
of Section 29, and the S 1/2 and the NW 1/4 and the S 1/2 of the NE 1/4
of Section 30, and the N 1/2 of Section 34, Township 23 North, Range 6
West, and the W 1/2 of Section 24, and the N 1/2 and the SE 1/4 of
Section 25, Township 23 North, Range 7 West.
(B) Depth. The Haynesville Formation, Reservoir B, is defined as
that gas and condensate bearing formation occurring between the depths
of 9,510 feet and 10,730 feet, on the electric log measurement of the
Cities Service Company Hatter A No. 1 Well, located in Section 29,
Township 23, Range 6 West.
(23) The Mancos ''B'' Formation in Colorado. RM79-76 (Colorado-11).
(i) Delineation of formation. The Mancos ''B'' Formation is found in
the Douglas Creek Arch area in Rio Blanco County, Colorado.
(ii) Depth. The Mancos ''B'' Formation is a member of the Mancos
Shale of upper Cretaceous age, occurring in the approximate middle third
of the Mancos sequence. The average depth to the top of the Mancos
''B'' Formation is 3603 feet.
(24) The Mancos ''B'' Formation in Colorado. RM79-76 (Colorado-13).
(i) Delineation of formation. The Mancos ''B'' Formation is found in
Rio Blanco County, Colorado, Approximately 70 miles northwest of Grand
Junction, Colorado, on the northeast flank of the Douglas Creek Arch in
the Piceance Basin.
(ii) Depth. The Mancos ''B'' Formation is a member of the Mancos
Shale of upper Cretaceous age, occurring in the approximate upper third
of the Mancos sequence. The thickness of the Mancos ''B'' Formation
ranges from 400 to 700 feet. The depth to the top of the Mancos ''B''
Formation ranges from 1,500 to 8,400 feet and averages 3,500 feet.
(25) The Lower Mesaverde Formation in Colorado. RM79-76
(Colorado-5).
(i) Delineation of formation. The Lower Mesaverde Formation,
consisting of the Rollings, Cozzett and Corcoran Sandstone members, is
located in the Plateau Creek Field area 30 miles east-northeast of Grand
Junction, Colorado in Mesa County, Colorado. The designation area
includes Township 9 South, Range 95 West, Sections 19 through 23, 26
through 36; Township 9 South, Range 96 West, Section 25 through 36,
Township 9 South, Range 97 West, Sections 25 and 36; Township 10 South,
Range 94 West, Sections 6, 7, 18, 19, 30 and 31; Township 10 South,
Range 95 West, Section 1 through 16 NW 1/4 and SE 1/4 of Section 17, 20
through 29, 31 through 36; Township 10 South, Range 96 West, Sections 1
through 11, 14 through 22, 29 through 32, S 1/2 and NE 1/4 of Section
33, Sections 34 through 36; Township 10 South, Range 97 West, Sections
1, 12, 13, 24, 25 and 36; All from the 6th P.M.
(ii) Depth. The average to the top of the Lower Mesaverde Formation
is 3,850 feet.
(26) The Dakota Formation in Colorado. RM79-76 (Colorado-7).
(i) Delineation of formation. The Dakota Formation is found in La
Plata and Archuleta Counties, Colorado, underlying Township 34 North,
Ranges 6 through 8 West (North of the Ute Line), Sections 1 through 18;
Township 34 North, Range 9 West (North of the Ute Line), Sections 1
through 12; Township 34 1/2 North, Range 9 West (North of the Ute
Line), Sections 31 through 36; Township 35 North, Ranges 6 through 8
West, Sections 1 through 36; and Township 35 North, Range 9 West,
Sections 1 through 3, 10 through 15, 22 through 27, and 34 through 36.
(ii) Depth. The Dakota Formation is defined as that formation, the
top of which varies in depth from 7500 feet to 8000 feet and the bottom
of which is defined by the top of the Morrison Formation.
(27) Sanastee Formation in Colorado. RM79-76 (Colorado-8).
(i) Delineation of formation. The Sanastee Formation is found in La
Plata and Archuleta Counties, Colorado, underlying Township 34 North,
Ranges 6 and 7 West (South of the Ute Line), Sections 1 through 36; and
Township 34 North, Ranges 8 and 9 West (South of the Ute Line), Sections
1 through 24.
(ii) Depth. The Sanastee Formation is defined as that formation
occurring within the Mancos shale at intervals from approximately 7500
to 7700 feet.
(28) Dakota Formation in Colorado. RM79-76 (Colorado-8).
(i) Delineation of formation. The Dakota Formation is found in La
Plata and Archuleta Counties, Colorado, underlying Township 34 North,
Ranges 6 and 7 West (South of the Ute Line), Sections 1 through 36; and
Township 34 North, Ranges 8 and 9 West (South of the Ute Line), Sections
1 through 24.
(ii) Depth. The Dakota Formation is defined as that formation the
depth to the top of which averages approximately 7600 feet and the base
of which is defined by the top of the Morrison Formation.
(29) Cozzette Formation in Colorado. RM79-76 (Colorado-9).
(i) Delineation of formation. The Cozzette Formation is found in
Mesa and Garfield Counties, Colorado. It is located northeast of the
City of Grand Junction, Colorado, and occupies an area known locally as
the Wagon Track Tight Gas and Sand area. The Cozzette Formation
underlies Township 8 South, Ranges 98 and 99 West, Sections 1 through
36, and Range 100 West, Sections 21 through 28 and 33 through 36;
Township 9 South, Range 97 West, Sections 1 through 24, 26 through 35,
Ranges 98 and 99 West, Sections 1 through 36, Range 100 West, Sections 1
through 4, 9 through 14, 23, 24, 25 and 36; Township 10 South, Range 97
West, Sections 2 through 11, Range 98 West, Sections, 1 through 12, and
Range 99 West, Sections 1 through 5 and 9 through 12.
(ii) Depth. The Cozzette Formation is defined as that formation
occurring within the Mount Garfield Formation in the Mesaverde Group and
which is found at an average measured depth of 2478 feet.
(30) Corcoran Formation in Colorado. RM79-76 (Colorado-9).
(i) Delineation of formation. The Corcoran Formation is found in
Mesa and Garfield Counties, Colorado. It is located northeast of the
City of Grand Junction, Colorado, and occupies an area locally known as
the Wagon Track Tight Sand area. The Corcoran Formation underlies
Township 8 South, Ranges 98 and 99 West, Sections 1 through 36, and
Range 100 West, Sections 21 through 28 and 33 through 36; Township 9
South, Range 97 West, Sections 1 through 24, 26 through 35, Ranges 98
and 99 West, Sections 1 through 36, Range 100 West, Sections 1 through
4, 9 through 14, 23, 24, 25 and 36; Township 10 South, Range 97 West,
Sections 2 through 11, Range 98 West, Sections 1 through 12, and Range
99 West, Sections 1 through 5 and 9 through 12.
(ii) Depth. The Corcoran Formation is defined as that formation
occurring within the Mount Garfield Formation of the Mesaverde Group and
which is found at an average depth of 2673 feet.
(31) The Abo Formation in New Mexico. RM79-76 (New Mexico-3).
(i) Delineation of formation. The Abo Formation is located in DeBaca
County, New Mexico, Township 2 South, Ranges 22 through 27 East, and
Township 3 South, Ranges 22 through 26 East, and in Chaves County, New
Mexico, Township 3 South, Range 27 East, Townships 4, 5, 9 and 10 South,
Ranges 22 through 27 East, Townships 6 through 8 South, Ranges 22
through 28 East, Township 11 South, Ranges 22 through 25 East, Township
12 South, Ranges 22 through 24 East, Township 13 South, Ranges 22 and 23
East, Township 9 South, Range 24 East, Township 9 1/2 South, Range 24
East, and Township 14 South, Range 22 East.
(ii) Depth. The Abo Formation averages about 677 feet in thickness
and the depth to the top of the formation averages about 3650 feet.
(32) Fruitland Formation in New Mexico. RM79-76 (New Mexico-4).
(i) Delineation of formation. The Fruitland Formation consists of
the Northeast Blanco Unit, found in San Juan and Rio Arriba Counties,
New Mexico, approximately 18 miles east of the city of Aztec, New
Mexico, on the northeast flank of the San Juan Basin. It encompasses
the following: Township 30 North, Range 7 West, Sections 2 through 10,
17 through 21, Section 16-W/2, Section 29-N/2; Township 30 North, Range
8 West, Sections 1, 12, 13 and 24; Township 31 North, Range 6 West,
Section 6-Lots 8, 9, 10, 11 and S/2, Sections 7, 18, 19, 20, 30;
Township 31 North, Range 7 West, Section 1-Lots 5 through 8 and S/2,
Section 9-S/2, and 10-S/2, Sections 11 through 16 and 19 through 36;
Township 31 North, Range 8 West, Sections 25 and 36.
(ii) Depth. The Fruitland Formation is below the Kirtland Shale and
Farmington Sandstone and above the Pictured Cliffs Formation. The
average depth to the top of the Fruitland Formation underlying the
Northeast Blanco Unit is 2800 feet.
(33) Cozzette Formation in Colorado. RM79-76 (Colorado-12).
(i) Delineation of formation. The Cozzette Formation is located in
the Piceance Creek Basin in Garfield County, Colorado, approximately 12
miles southwest of the town of Glenwood Springs, Colorado. The
formation consists of the following: Township 7 South, Range 90 West,
6th P.M., Sections 1 through 36; Township 7 South, Range 91 West, 6th
P.M., Sections 1 through 36; and Township 8 South, Range 90 West, 6th
P.M., Sections 1 through 12.
(ii) Depth. The Cozzette Formation is a member of the lower
Mesaverde Group. The average depth to the top of the Cozzette Formation
is 7,477 feet. Its base is defined as the top of the Corcoran
Formation.
(34) Corcoran Formation in Colorado. RM79-76 (Colorado-12).
(i) Delineation of formation. The Corcoran Formation is located in
the Piceance Creek Basin in Garfield County, Colorado, approximately 12
miles southwest of the town of Glenwood Springs, Colorado. The
formation consists of the following: Township 7 South, Range 90 West,
6th P.M., Sections 1 through 36; Township 7 South, Range 91 West, 6th
P.M., Sections 1 through 36; and Township 8 South, Range 90 West, 6th
P.M., Sections 1 through 12.
(ii) Depth. The Corcoran Formation is a member of the lower
Mesaverde Group. The average depth to the top of the Corcoran Formation
is 7,677 feet. Its base is defined as the top of the Mancos Shale
Formation.
(35) Geopressured Wilcox Lobo Sandstone Formation in Texas. RM79-76
(Texas-8).
(i) Delineation of formation. The Geopressured Wilcox Lobo Sandstone
Formation is located in the southern part of Texas in Webb and Zapata
Counties, Railroad District 4, and is located below the Lower Wilcox
Group and above the Wills Point Formation which is part of the Midway
Group.
(ii) Depth. The highest portion of the Geopressured Wilcox Lobo
Sandstone Formation appears at 5,840 feet. The approximate thickness
varies from 1,175 feet in the north to 3,130 feet in the south.
(36) The Travis Peak Formation in Texas. RM79-76 (Texas-9) and
(Texas-9 Addition).
(i) Sym-Jac, West (Hosston) Field -- (A) Delineation of formation.
The Travis Peak Formation in the Sym-Jac, West (Hosston) Field is found
in Cherokee County, Texas, Railroad Commission District 6.
(B) Depth. The top and the base of the Travis Peak Formation in the
Sym-Jac, West (Hosston) Field are found at approximately 9,850 feet and
12,050 feet, respectively, giving it a thickness of approximately 2,200
feet.
(ii) Bear Grass Area -- (A) Delineation of formation. The Travis
Peak Formation in the Bear Grass area is found in portions of Freestone
and Leon Counties, Texas, Railroad Commission District 5. The area is
elliptical with a northeast/southwest major axis and contains
approximately 5 square miles. The center of the area is approximately 2
miles east of the point of intersection of Freestone, Leon and Limestone
Counties and is situated in portions of the following surveys: Gertrude
Diaz A-178 and A-1276, Isaac Connelly A-117 and A-1152, William F. Gray
A-296, L. W. Gideon A-1018 and Thomas Hardee A-1022.
(B) Depth. The top and the base of the Travis Peak Formation in the
Bear Grass area are found at approximate subsea depths of -- 8,379 feet
and -- 11,462 feet, respectively, giving a thickness of approximately
3,100 feet.
(iii) Melrose, South (Travis Peak) Field. (A) Delineation of
formation. The Travis Peak Formation in the Melrose, South (Travis
Peak) Field is located four miles south of the city of Melrose,
southeastern Nacogdoches County, Texas Railroad Commission District 6,
and is within a 2.5 mile radius around the Texlan Oil Company, Inc.
T.W. Baker No. 1 well.
(B) Depth. The top of the Travis Peak Formation is encountered at
8,920 feet and the base of the formation is at 9,940 feet (log depths).
(iv) Martinsville (Travis Peak) Field -- (A) Delineation of
formation. The designated portion of the Travis Peak Formation is
located immediately south of the town of Martinsville in eastern
Nacogdoches County, Texas, Railroad Commission District 6, and includes
all of the area within a 2.5 mile radius around the Getty Oil Company,
Manuel Herrera Well No. 1 located in the Jose Huerra Survey, A-289.
(B) Depth. The designated portion of the Travis Peak is found at
sub-sea depths ranging from approximately 8,100 feet on the north to
8,500 feet on the south.
(v) (Reserved)
(vi) Toolan (Travis Peak) Field -- (A) Delineation of formation. The
designated portion of the Travis Peak Formation consists of all or part
of the surveys located in the Toolan Field, in portions of Nacogdoches
and Rusk Counties, Texas, specifically the area encompassed by a 2.5
mile radius around Hill International Production Company's E. J.
Edwards, et al., No. 1 well, located approximately one mile southwest of
the town of Garrison, Texas, Francis Kellett Survey, Abstract 329.
(B) Depth. These Travis Peak sands are found in the interval 7,100
feet subsea to 9,200 feet subsea, or from the base of the Pettit to the
top of the Cotton Valley intervals.
(37) Cotton Valley Sandstone Formation in Louisiana. RM79-76-089
(Louisiana -- 3).
(i) Delineation of formation. The Cotton Valley Sandstone Formation
is located in northern Louisiana. It is situated in all of Bienville,
Bossier, Caddo, Caldwell, Claiborne, DeSoto, Franklin, Jackson, Lincoln,
Natchitoches, Quachita, Red River, Sabine, Tensas, Union, Vernon,
Webster and Winn Parishes and parts of Allen, Beauregard, Catahoula,
Concordia, Grant, La Salle, Madison, Morehouse, Rapides and Richland
Parishes. Certain portions of the Cotton Valley Sandstone Formation in
the following fields are excluded from the designated area: Arkana,
Athens, Beekman, Benton, Blackburn, Caddo-Pine Island, Cadeville,
Calhoun, Cartwright, Cheniere, Cotton Valley, East Dykesville, East
Haynesville, Greenwood-Waskom, Haynesville, Hico-Knowles, Lisbon,
Longwood, Middlefork, Millhaven, Minden, North Carlton, Northeast
Lisbon, North Missionary Lake, Plain Dealing, Ruston, Sentell,
Shongaloo, Sligo, South Drew, South Downsville, Sugar Creek, Terryville,
Tremont, Unionville and West Lisbon. Additional excluded areas that are
not included in the fields are: Section 12, Township 19 North, Range 16
West; Sections 5 and 20, Township 21 North, Range 4 West; Sections 5
and 6, Township 21 North, Range 6 West; Section 30, Township 21 North,
Range 7 West; Sections 28 and 32, Township 21 North, Range 11 West;
Sections 30 and 32, Township 22 North, Range 4 West; Section 1,
Township 22 North, Range 6 West; Section 34, Township 23 North, Range 2
East; Section 36, Township 23 North, Range 4 West; Sections 26, 34
through 36, Township 23 North, Range 6 West; Section 24, Township 23
North, Range 7 West; Section 9 and 29, Township 23 North, Range 9 West;
and Section 28, Township 23 North, Range 15 West.
(ii) Depth. The Cotton Valley Sandstone Formation is defined as that
interval encountered between the measured depths of 9,740 feet and
11,421 feet on the induction electrical log of the Phillips Petroleum
Company -- Martin B No. 1 Well located in Section 32, Township 11
North, Range 10 West, Natchitoches Parish, Louisiana.
(38) Gray Sand, Reservoir A in Louisiana. RM79-76 (Louisiana-4).
(i) Delineation of formation. The Gray Sand, Reservoir A, consists
of interbedded sandstone, limestone and shale, and is found in the
following portions of Lincoln and Claiborne Parishes, north Louisiana:
T18N-R4W, Sections 3-6; T18N-R5W, Section 1; T19N-R4W, Sections 3-10,
15-23, 26-34; T19N-R5W, all Sections; T19N-R6W, Sections 1, 12, 13,
24, 25, 36.
(ii) Depth. The Gray Sand, Reservoir A, is defined as that sand
occurring between the measured depths of 12,840 feet, and 13,350 feet on
the induction log of the IMC Exploration Company -- Eugene Tinsley et
al. No. 1 Well located in Section 33, Township 19 North, Range 4 West,
Lincoln Parish.
(39) Basal Pennsylvanian Sand Formation in Alabama. RM79-76
(Alabama-1).
(i) Delineation of formation. The Basal Pennsylvanian Sand Formation
is found in Townships 14, 15, and 16 South, Ranges 2, 3, and 4 West, and
Townships 15, 16, 17, and 18 South, Ranges 5, 6, and 7 West, in
Jefferson, Walker and Tuscaloosa Counties, Alabama.
(ii) Depth. The Basal Pennsylvanian Sand Formation is a series of
massive sand 300 to 600 feet thick, extending from the base of the Black
Creek coal seam to the base of the Pennsylvanian series.
(40) Dakota Formation in Colorado. RM79-76 (Colorado-15).
(i) Delineation of formation. The Dakota Formation is found in Mesa,
Garfield, and Rio Blanco Counties, Colorado, and consists of all or
portions of Townships 3 through 8 South, Ranges 98 through 103 West, 6th
P. M.
(ii) Depth. The depth to the top of the Dakota Formation ranges from
5,480 feet to 9,225 feet, and averages 6,993 feet. The base of the
Dakota Formation is found at the top of the Cedar Mountain Sandstone
Formation.
(41) Ravencliff Formation in West Virginia. RM79-76 (West
Virginia-1).
(i) Delineation of formation. The Ravencliff Formation underlies
portions of Fayette and Raleigh Counties, West Virginia.
(ii) Depth. The Ravencliff Formation lies below the Princeton
Sandstone and above the Maxton Sandstone. The Ravencliff Formation
ranges in thickness from thin sand stringers in the eastern portion of
the two counties, to a maximum thickness of 140 feet in the central
portion of the designated area.
(42) Injun-Squaw Formation in West Virginia. RM79-76 (West
Virginia-1).
(i) Delineation of formation. The Injun-Squaw Formation underlies
portions of Fayette and Raleigh Counties, West Virginia.
(ii) Depth. The Injun-Squaw Formation lies below the Big Lime-Keener
Formation and above the Weir Formation. The Injun-Squaw Formation
ranges in thickness from a maximum of 20 feet in northwestern Fayette
County, to thin stringers to the south and east.
(43) Weir Formation in West Virginia. RM79-76 (West Virginia-1).
(i) Delineation of formation. The Weir Formation underlies portions
of Fayette and Raleigh Counties, West Virginia.
(ii) Depth. The Weir Formation lies approximately 200 feet below the
Injun-Squaw Formation and approximately 200 feet above the Berea
Formation. The Weir Formation ranges in thickness from 50 to 80 feet in
the northeastern portion of the designated area, to 100 feet in the
southern portion of the area.
(44) Berea Formation in West Virginia. RM79-76 (West Virginia-1).
(i) Delineation of formation. The Berea Formation underlies portions
of Fayette and Raleigh Counties, West Virginia.
(ii) Depth. The Berea Formation lies approximately 200 feet below
the Weir Formation. The Berea Formation ranges in thickness from 55
feet in northwestern Fayette County, to thin shaley sandstone stringers
in the southern portion of designated area.
(45) The Morrow Formation in Colorado. RM79-76 (Colorado-10).
(i) Delineation of formation. The Morrow Formation is found in Kiowa
County, Colorado. It is located north of the town of Lamar in
southeastern Colorado, and underlies all of Township 18, South, Range 45
West, 6th p.m.
(ii) Depth. The Morrow Formation is defined as that formation
occurring at an average measured depth of 4,500 feet.
(46) Wasatch/Mesaverde Formation in Utah. RM79-76 (Utah-1).
(i) Delineation of formation. The Wasatch/Mesaverde Formation is
found in the Bitter Creek -- Red Wash area of Uintah County, Utah, and
is the general area of Township 7 South through 12 South, and Ranges 18
East through 25 East.
(ii) Depth. The average depth to the top of the Wasatch/Mesaverde
Formation is 4,559 feet.
(47) Fox Hills Formation in Wyoming. RM79-76 (Wyoming-4).
(i) Delineation of formation. The Fox Hills Formation is found in
Sweetwater County, Wyoming, in Township 16 North, Ranges 97 through 99
West; Township 17 North, Ranges 96 through 98 West; Township 17 North,
Range 99 West, Sections 24 through 28 and 33 through 36; Township 18
North, Ranges 96 and 97 West; and Township 18 North, Range 98 West,
Sections 24 through 26 and 34 through 36.
(ii) Depth. The Fox Hills Formation vertical limits are defined by
the Lance Formation above and the Lewis Shale below. The average depth
to the top of the Fox Hills Formation is 7,412 feet.
(48) Edwards Limestone Formation in Texas. RM79-76 (Texas-10).
(i) Delineation of formation. The Edwards Limestone Formation is
encountered in the following named fields. These fields are found along
the Gulf coast in the southeastern part of Texas in DeWitt, Karnes, and
Lavaca Counties, Railroad Commission District 2.
DeWitt County: Yoakum (Edwards) Field
Karnes County: Kennedy, East (Edwards) Field
Lavaca County: Sweethome (Edwards) Field
Lavaca County: Word (Edwards) Field
Lavaca County: Word, North (Edwards) Field
Lavaca County: Yoakum (Edwards) Field
(ii) Depth. The top of the Edwards Limestone Formation, in the west,
is at approximately 13,460 feet and the base is undetermined. In the
east, the top of the formation is at an approximate depth of 13,150 feet
and the base is at 14,500 feet resulting in a thickness of approximately
1,350 feet.
(iii) Live Oak County -- (A) Delineation of formation. The Edwards
Formation is found to the north of the City of Three Rivers in Live Oak
County, Texas, Railroad Commission District 2. The designated area is
bounded on the south by the Frio River and includes the following
surveys: Mrs. M. D. Proctor A-904, A. E. Brown A-828, John Hefferman
A-11, Bridget Haughey A-9, Thos. Henry A-13, Partick Henry A-12, Simon
Ryan A-35, Lewis Ayers A-2, Walter Henry A-15, Daniel O'Boyle A-32, Mark
Killely A-20, S. M. & S. A. A-442, S. M. & S. A. A-443, Lawrence
Jacobs A-659, and G. H. & H. R. R. A-205.
(B) Depth. The top of the Edwards Formation varies in depth from
approximately 12,000 feet subsea on the eastern side of the designated
area to 14,000 feet subsea on the west side.
(iv) Karnes County -- (A) Delineation of formation. The Edwards
Limestone Formation is located in Karnes County, Texas, Railroad
Commission District 2. The designated area is all that portion of the
Kennedy S.W. (Edwards) Field within the area encompassed by a circle 1.5
miles radially distant from and centered upon the Estelle Rolf Gas Unit
No. 2, Well No. 2. The Estelle Rolf Gas Unit No. 2, Well No. 2 is
located in the Carlos Martinez Survey A-6, Estelle Rolf lease, at a
point 660 feet from the southwest leaseline and 1,250 feet from the
southeast leaseline.
(B) Depth. The top of the designated portion of the Edwards
Limestone Formation ranges from 12,500 feet to 13,500 feet below sea
level. The average depth to the top of the Edwards Limestone Formation
in the designated area is 13,042 feet.
(49) Upper Hosston Formation in Mississippi. RM79-76
(Mississippi-1).
(i) Delineation of formation. The Upper Hosston Formation is found
in the south half of Township 9 North, Range 19 West, Jefferson Davis
County, Mississippi.
(ii) Depth. The top of the Upper Hosston Formation varies from
14,000 feet to 14,700 feet and the base of the formation is at
approximately 15,900 feet.
(50) The Rea Sand of the Mississippian Formation in Mississippi.
(Mississippi-2).
(i) Delineation of formation. The Rea Sand of the Mississippian
Formation is found in portions of Township 16 South, Range 5 East;
Township 17 South, Range 5 East; Township 16 South, Range 6 East; and
Township 17 South, Range 6 East, in Clay County, Mississippi.
(ii) Depth. The Rea Sand of the Mississippian Formation occurs at
depths ranging from 8,865 feet to 9,975 feet and varies in thickness
from 30 feet to 160 feet.
(51) The Mancos ''B'' Formation in Utah. RM79-76 (Utah-2).
(i) Delineation of formation. The Mancos ''B'' Formation is found in
the southeast Uinta Basin, underlying portions of Uintah and Grand
Counties, Utah, in Township 13 South, Ranges 20 through 22 East,
Sections 31 through 36; Township 13 South, Ranges 23 through 26 East,
all Sections; Township 14 and 15 South, Ranges 20 through 26 East, all
Sections; Township 15 1/2 South, Ranges 23 through 25 East, Sections 31
through 36; Township 15 1/2 South, Range 26 East, Sections 31 through
33; Township 16 South, Ranges 23 and 24 East, all Sections; Township
16 South, Range 25 East, Sections 1 through 12; and Township 16 South,
Range 26 East, Sections 4 through 9.
(ii) Depth. The average depth to the top of the Mancos ''B''
Formation is 5,049 feet.
(52) Frontier Formation in Wyoming. RM79-76 (Wyoming-5).
(i) Delineation of formation. The Frontier Formation is located in
Carbon County, Wyoming, in Township 14 North, Range 89 West, Sections 5
through 8, 17 through 20, 29 and 30; Township 14 North, Range 90 West,
Sections 1 through 5, 8 through 17, and 21 through 28; Township 15
North, Range 89 West, Sections 18 through 20, and 29 through 32; all of
Township 15 North, Range 90 West, excluding Sections 1 and 31; Township
15 North, Range 91 West, Sections 1 and 12; Township 16 North, Range 90
West, Sections 19, 20, and 28 through 34; and Township 16 North, Range
91 West, Sections 24, 25 and 36.
(ii) Depth. The top of the Frontier Formation is found at depths
ranging from 5500 feet in the east to 7500 feet in the west, and
averaging 6000 feet. The Frontier Formation is defined as that
formation found immediately beneath the Carlisle Shale and immediately
above the Mowry Shale.
(53) Frontier Formation in Wyoming. RM79-76 (Wyoming-7).
(i) Delineation of formation. The Frontier Formation is located in
Lincoln, Sweetwater and Sublette Counties, Wyoming, in Townships 25
throught 28 North, Ranges 110 and 111 West; and Township 28 North,
Range 112 West, Sections 1 through 4, 9 through 16, 21 through 28, and
33 through 36.
(ii) Depth. The Frontier Formation's vertical limits are defined by
the Baxter Shale Formation above and the Mowry Shale Formation below.
The depth to the top of the Frontier Formation varies from 9,000 to
10,500 feet.
(54) The Bear River Formation in Wyoming. RM 79-76 (Wyoming-6).
(i) Delineation of formation. The Bear River Formation is found in
Lincoln, Sweetwater and Sublette Counties, Wyoming, in Townships 25
through 28 North, Ranges 110 and 111 West; and Township 28 North, Range
112 West, Sections 1 through 4, 9 through 16, 21 through 28, and 33
through 36.
(ii) Depth. The Bear River Formation's vertical limits are defined
by the Mowry Shale Formation above and the Thermopolis Shale Formation
below. The depth to the top of the Bear River Formation varies from
9,400 feet to 11,200 feet.
(55) The Medina Group in Pennsylvania. RM79-76 (Pennsylvania-1).
(i) Delineation of formation. The Medina Group is found in Erie,
Crawford, Mercer, Venango and Warren Counties, Pennsylvania.
(ii) Depth. The Medina Group is defined as that formation occurring
within the Lower Silurian System between the Reynales Dolomite and the
Queenston Shale, found at an approximate depth of 3,000 feet in the
updip area, dipping to the southeast at approximately 50 feet per mile.
(56) The Berea Formation in Virginia. RM79-76 (Virginia-1).
(i) Delineation of formation. The Berea Formation is found in the
Plateau Region of southwestern Virginia, an area including all of
Dickenson County, and parts of Lee, Scott, Wise, Russell, Buchanan and
Tazewell Counties, Virginia.
(ii) Depth. The thickness of the Berea Formation ranges from 20 feet
to 125 feet, thickening toward the central portion of the Plateau
Region. The depth to the top of the Berea Formation ranges from 3,365
feet in northern Buchanan County to 6,028 feet in eastern Buchanan
County.
(57) The Frio Formation in Texas. RM79-76 (Texas-12).
(i) Delineation of formation -- The Frio Formation is encountered in
the LaSal Vieja (8 9680-9935) Field, located in the central portion of
Willacy County, Texas Railroad District No. 4.
(ii) Depth. The top of the Frio Formation is located at
approximately 9,635 feet below sea level and extends to approximately
9,887 feet, giving it a maximum thickness of 252 feet.
(58) (Reserved)
(59) Atoka Formation in Oklahoma. RM79-76 (Oklahoma-1).
(i) Delineation of formation. The Atoka formation is found in
Washita County, Oklahoma, in Township 9 North, Range 14 West, Sections 2
through 11; Township 9 North, Range 15 West, Sections 1 through 3, 11
and 12; Township 10 North, Range 14 West, Section 5 through 8, 17
through 21, and 27 through 35; Township 10 North, Range 15 West,
Sections 6 through 30, 33 through 36; Township 10 North, Range 16 West,
Sections 1 through 5, 8 through 14, 24 and 25; Township 11 North, Range
16 West, Sections 16, 20 through 22, 27 through 29, and 32 through 35.
(ii) Depth. The Atoka formation is defined as the uppermost
sandstone development in the Atoka Series of the Lower Pennsylvania
System which underlies the Cherokee/Red Fork Group and overlies the
post-13 Finger Lime shale. The average depth to the Atoka formation is
approximately 14,800 feet.
(60) The Dakota Formation in New Mexico. RM79-76 (New Mexico-6).
(i) Delineation of formation. The Dakota Formation underlies
portions of Townships 24 and 25 North, Ranges 7 through 10 West, in San
Juan and Rio Arriba Counties, New Mexico. The producing interval of the
Basin Dakota Field in the Dakota Formation is defined as beginning at
the base of the Greenhorn Limestone, and extending to a point 400 feet
below the base of the Greenhorn Limestone.
(ii) Depth. The average depth to the top of the Dakota Formation is
6,350 feet. The Dakota Formation begins at the base of the Greenhorn
Limestone and is 200 to 350 feet in gross thickness.
(61) Sussex Formation in Colorado. RM79-76 (Colorado-16).
(i) Delineation of formation. The Sussex Formation is found in Weld
County, Colorado, in Township 4 North, Range 66 West, 6th P.M., Sections
2, 3, and 10, Section 11-N 1/2, Section 15-W 1/2; Township 5 North,
Range 66 West, 6th P.M., Sections 33, 34, and 35.
(ii) Depth. The average depth to the top of the Sussex Formation is
4,400 and 4,500 feet.
(62) Pictured Cliffs Formation in New Mexico. RM79-76 (New
Mexico-7).
(i) Delineation of formation. The Pictured Cliffs Formation is found
in the San Juan Basin and underlies portions of Townships 30 and 31
North, Ranges 7 and 8 West, and Township 31 North, Range 6 West, NMPM,
in San Juan and Rio Arriba Counties, New Mexico.
(ii) Depth. The average depth to the top of the Pictured Cliffs
Formation is approximately 3,200 feet. The thickness of the Pictured
Cliffs Formation ranges from 150 to 250 feet.
(63) The Wilcox Formation in Texas. RM79-76 (Texas-11).
(i) Aviators -- N. (12,000) Field -- (A) Delineation of formation.
The Wilcox Formation found in the area of the Aviators, N. (12,000)
Field, Webb County, Texas, is within a 2.5 mile radius around the
Pennzoil Producing Company No. 53-1 B.M.T.-Alice B. Hall well and
covers approximately 19.6 square miles.
(B) Depth. The top of the Wilcox Formation, Aviators, N. (12,000)
Field is at approximately ^11,085 feet subsea and is 114 feet thick.
(ii) Roma -- W. (Wilcox 10,100) Field -- (A) Delineation of
formation. The Wilcox Formation found in the area of the Roma, W.
(Wilcox 10,100) Field, Starr County, Texas, is within a 2.5 mile radius
around the Border Exploration Company No. 1 H. P. Guerra Jr., et al.
well and is adjacent to the Rio Grande River.
(B) Depth. The top of the Wilcox Formation, Roma, W. (Wilcox
10,100) Field is at approxiamtely 9,750 feet and extends to 10,750 feet,
resulting in a total thickness of 1,000 feet.
(iii) West Cole Field -- (A) Delineation of formation. The Wilcox
Formation in the area of the West Cole Field, Webb County, Texas, is
located approximately 36 miles east of the city of Laredo, Texas, and is
within a 2.5 mile radius around the Forest Oil Corporation No. 1 Rosa
V. de Benavides well.
(B) Depth. The top of the Wilcox Formation, West Cole Field, is at
approximately 9,135 feet and extends to 10,315 feet (log depths)
resulting in a total thickness of 1,180 feet.
(iv) Taquachie Creek Field -- (A) Delineation of formation. The
Wilcox Formation found in the area of the Taquachie Creek (Wilcox
11,162) Field, Zapata County, Texas, is located approximately 7 miles
south of Mirando City, Texas, and is within a 2.5 mile radius around the
Blocker Exploration Company No. 1-252 L. Amour Hinnant well.
(B) Depth. The top of the Wilcox Formation, Taquachie Creek (Wilcox
11,162) Field is log-measured at approximately 11,162 feet and extends
to 11,200 feet, resulting in a total thickness of 38 feet.
(v) Wilcox First Hinnant Formation in Jim Hogg County -- (A)
Delineation of formation. The Wilcox First Hinnant Formation is located
entirely within the northwestern portion of Jim Hogg County in south
Texas, Railroad Commission District 4, approximately 7 miles northeast
of the city of Randado, Texas. The designated area is rectangular and
begins at a point at the southwest corner of Section 164, C. Gutierrez
Survey A-145, then due north 22,700 feet to a point in Section 98, E.
L. Armstrong A-3 Survey (scaled 2,100 feet FWL and 1,800 feet FSL of
Survey), then due west 32,200 feet to a point in Los Animos, Heirs of
Felipe de la Pena Grant, A-244 (scaled 9,200 feet FSL and 24,500 feet
FEL of said Grant), then due south 22,700 feet to a point scaled on the
common boundary between Section 578, R. L. Robinson A-267, and Section
575, W. W. Ferguson A-104, being 6,000 feet south of the north line of
the common north boundary of said Sections 578 and 575, then due east
32,200 feet to point of beginning, comprising 16,700 acres, or
approximately 26 square miles.
(B) Depth. The top of the Wilcox First Hinnant Formation is
encountered at 12,292 feet in the Edwin L. Cox and Berry R. Cox,
Martinez No. 1 Well. The thickness reaches a maximum of 100 feet in
the Northeast Thompsonville Field area, located 4 1/2 miles northwest of
the Cox Martinez No. 1 well. Downdip from the Northeast Thompsonville
Field area, at the Cox Martinez No. 1 well, the sand has noticeably
thinned and become shalier, with a total thickness of 58 feet.
(vi) South Campana (Wilcox 10,400') Field -- (A) Delineation of
formation. The Wilcox 10,400' Formation is located in the South Campana
(Wilcox 10,400') Field in McMullen and Duval Counties, in south Texas,
Railroad Commission Districts 1 and 4, approximately 18 miles northeast
of Freer, Texas. The designated area includes all of the acreage within
a 2.5 mile radius around the ARCO H. C. Edrington I No. 33 well, which
is located in the southeast quarter of Section 61, A. B. & M. Survey,
Abstract 43, McMullen County, Texas.
(B) Depth. The average depth to the top of the Wilcox 10,400'
Formation is approximately 10,890 feet. The subject formation averages
from 10 to 12 feet in thickness within the geographical area.
(64) Mesaverde Formation in Colorado. RM79-76 (Colorado-17).
(i) Delineation of formation. The Mesaverde Formation is found in
Garfield County, Colorado, in Township 6 South, Range 93 West, 6th P.M.,
Sections 3 through 10, 15 through 22, 27 through 34; Township 6 South,
Range 94 West, 6th P.M., Sections 1 through 3, 7 through 36; Township 6
South, Range 95 West, 6th P.M., Sections 25 through 36; Township 7
South, Range 94 West, 6th P.M., Sections 1 through 9, 16 through 18;
Township 7 South, Range 95 West, 6th P.M., Sections 1 through 24, 27
through 34; Township 7 South, Range 96 West, 6th P.M., Sections 1
through 36; Township 8 South, Range 96 West, 6th P.M., Sections 1
through 6.
(ii) Depth. The Mesaverde Formation is defined as that formation
encountered between the base of the Wasatch Formation (Tertiary) and the
top of the Mancos shale. The average depth to the top of the Mesaverde
Formation is 4,475 feet.
(65) The Upper Mancos Formation in Colorado. RM79-76 (Colorado-20).
(i) Delineation of formation. The Upper Mancos Formation is found in
Rio Blanco County, Colorado, in Townships 2 and 3 South, Ranges 100 and
101 West, 6th P.M.
(ii) Depth. The Upper Mancos Formation is defined as being between
the base of the Mesaverde Formation and the top of the Lower Mancos
Formation. The average depth to the top of the Upper Mancos Formation
is 1,800 feet.
(66) Medina Group in New York. RM79-76 (New York-1).
(i) Delineation of formation. The Medina Group is found in
Chautauqua and Cattaraugus Counties, New York (and is equivalent to the
U.S. Geological Survey's Albion Group). The Medina Group consists of
the Grimsby Sandstone Formation, the Power Glen Shale Formation (also
known as the Cabot Head Shale Formation), and, where present, the
Whirlpool Sandstone Formation. The Medina Group is bounded by the
overlying Thorold Formation, where present. Where the Thorold Formation
is not present, the Medina group is overlaid by the Reynales Limestone
Formation (also known as the ''Packer Shell''). The Queenston Shale
Formation is the underlying boundary of the Medina Group. Excluded from
the delineated Medina Group are any Medina gas storage areas, including
buffer zones, or any area within ''existing'' Medina fields that have
been substantially developed absent an incentive price.
(ii) Depth. The average depth to the top of the Medina Group is
approximately 3,850 feet with a range to the top of the formation of
1,700 to 6,000 feet. The average pay thickness of the formation is 55
feet.
(67) Morrison Formation in Utah. RM 79-76 (Utah-4).
(i) Delineation of formation. The Morrison formation is found is the
Book Cliffs area of Grand, Emery, and Uintah Counties, Utah, in the area
of Townships 15 South through 20 South, and Ranges 17 East through 24
East.
(ii) Depth. The average depth to the top of the Morrison Formation
is 6,315 feet. The Morrison Formation averages 600 feet in thickness
with the vertical limits defined by the Dakota Formation above and the
Entrada Formation below.
(68) Smackover C Zone in Louisiana. RM79-76-221 (Louisiana 5 and 5
Addition).
(i) Delineation of formation. The Smackover C Zone is found within
the East Dykesville Field in Clairborne and Webster Parishes, Louisiana,
in the area of Township 22 North, Range 8 West, Sections 3-10, 15-18;
Township 22 North, Range 9 West, Sections 1-18; Township 23 North,
Range 8 West, Sections 30-34; and Township 23 North, Range 9 West,
Sections 25-36.
(ii) Depth. The Smackover C Zone occurs between the measured depths
of 11,290 feet and 11,340 feet on the induction electrical log of the
Wheless Industries -- Pelto Oil -- Guy Lewis et al. No. 1 well and
between 11,534 feet and 11,568 on the electric log of the Cities Service
Oil and Gas Corporation -- Hearn No. 1 well.
(69) James Lime Formation in Louisiana. RM79-76 (Louisiana-6).
(i) Delineation of formation. The James Lime Formation is found in
the Benson Field in the southern portion of De Soto Parish, Louisiana,
in the area of Township 10 North, Range 13 West, Sections 1-18;
Township 10 North, Range 14 West, Sections 1-18; Township 11 North,
Range 13 West, Sections 1-36; and Township 11 North, Range 14 West,
Sections 1-36.
(ii) Depth. The top of the James Lime Formation is encountered at
approximately ^5,072 feet subsea in the northwest portion and at
approximately ^5,400 feet subsea in the southern portion. It is
situated directly below the Bexar Formation and above the Pine Island
Formation. The maximum thickness of the formation is approximately 260
feet.
(70) Wolfcamp Formation in Texas. RM79-76 (Texas-14).
(i) Wolfcamp Formation in the Gomez, NW. (Wolfcamp) Fields -- (A)
Delineation of formation. The specific areas of the Wolfcamp Formation
are found in (1) the Gomez, NW. (Wolfcamp) Field, in northern Pecos
County northwest of Fort Stockton, Texas, underlying approximately
24,457 acres, and in (2) the Wolf (Wolfcamp) Field, in the extreme
southwestern portion of Loving County, between the town of Mentone,
Texas, and the Pecos River in Sections 78-82, Block 33, H&TC RR Company
Survey.
(B) Depth. The top and base of the Wolfcamp Formation are
encountered at the approximate depths of 11,384 feet and 11,720 feet,
respectively, in the Gomez, N.W. (Wolfcamp) Field, and at the
approximate depths of 10,118 feet and 10,696 feet, respectively, in the
Wolf (Wolfcamp) Field.
(ii) Wolfcamp Formation in Sutton County -- (A) Delineation of
Formation. The Wolfcamp Formation is found in Sutton County, Texas,
Railroad Commission District 7C. The designated area consists of
Sections 50, 51, 55, 56, 57, and 77, Block B, H. E. & W. T. RR Survey.
(B) Depth. The Wolfcamp Formation in the designated area lies at a
subsea depth of approximately 2,400 feet, with an approximate thickness
of 1,270 feet. The Wolfcamp Formation in the designated area is defined
as that interval found between the log depths of 3,530 feet to 4,800
feet in the William Perlman Fields 50 No. 1 well.
(71) Niobrara Formation in Nebraska. RM79-76 (Nebraska -- 1).
(i) Delineation of formation. The Niobrara Formation is found in all
of Chase, Deuel, Dundy, Hitchcock, Keith, Lincoln and Perkins Counties,
the western half of Frontier County (Townships 5 through 8 North, Ranges
27 through 30 West), the eastern half of Cheyenne County (Townships 12
through 17 North, Ranges 46 through 49 West), and the southern most
third of Garden County (Townships 15 through 19 North, Ranges 41 through
46 West), Nebraska.
(ii) Depth. The Niobrara Formation underlies the Pierre Shale
Formation and overlies the Fort Hays Limestone Formation. The depth to
the top of the Niobrara Formation ranges from 900 to 4,000 feet and
averages 2,450 feet.
(72) Frontier Formation in Wyoming. RM79-76 (Wyoming-8).
(i) Delineation of formation. The Frontier Formation is found in
Lincoln, Sublette, and Sweetwater Counties, Wyoming, encompassing all or
parts of Townships 25 and 26 North, Range 109 West; Township 29 North,
Range 111 West; Townships 26 through 31 North, Range 112 West; and
Townships 28 through 31 North, Range 113 West.
(ii) Depth. The Frontier Formation's vertical limits are defined by
the Baxter Shale Formation above the Mowry Shale Formation below. The
gross thickness of the formation varies from 50 to 150 feet. The
average depth to the top of the Frontier Formation is 7,700 feet.
(73) Massive ''A'' Sand Formation in Texas. RM79-76 (Texas-17).
(i) Delineation of formation. The Massive ''A'' Sand Formation is
found in the Chapa, East Field in southwestern Live Oak County, Texas,
Railroad Commission District 2. The formation is described by a 2.5
mile radius around the Aminoil USA, Inc., El Paso Natural Gas No. 5
well located in Section 299, Hooper & Wade A-250 Survey, approximately 4
miles east of the McMullen County line.
(ii) Depth. The average depth to the top of the Massive ''A'' Sand
Formation is approximately 11,600 feet and the thickness varies from 220
feet in the northwest to 560 feet in the southeast.
(74) Navarro Formation in the Laredo Field in Texas. RM79-76
(Texas-13).
(i) Delineation of formation. The Navarro Formation in the Laredo
Field is found in Webb County, Texas, Railroad Commission District 4.
(ii) Depth. The depth to the top of the Navarro Formation in the
Laredo Field is approximately ^7,227 feet (subsea) in the northwest
portion of the area. The base of the Navarro Formation is found at
^7,735 feet (subsea) in the southeastern portion of the area. The
maximum thickness of the Navarro Formation is approximately 28 feet.
(75) The Dakota Formation in Colorado. RM79-76 (Colorado-18).
(i) Delineation of formation. The Dakota Formation underlies
portions of Townships 32, 33 and 34 North (South of Ute Line), Ranges 6
through 11 West, in La Plata and Archuleta Counties, Colorado, and it is
within the Ignatio-Blanco Field.
(ii) Depth. The Dakota Formation is below the Graneros Shale and
above the Morrison Formation. The average depth to the top of the
Dakota Formation is 7,950 feet. The formation is approximately 225 to
250 feet in thickness.
(76) Mesaverde Formation in Colorado. RM79-76 (Colorado-19).
(i) Delineation of formation. The Mesaverde Formation underlines
Townships 32, 33 and 34 North (South of Ute Line), Ranges 6 through 11
West, in La Plata and Archuleta Counties, Colorado. The formation is
within the Ignacio-Blanco Field.
(ii) Depth. The Mesaverde Formation is below the Lewis Shale
Formation and above the Mancos Shale Formation. The average depth to
the top of the Mesaverde Formation is 5,380 feet. The formation is
approximately 900 feet in thickness.
R6W T32N: Sections 5 S 1/2, 6, 7, 8 W 1/2, 10 W 1/2, 12 S 1/2, 13 S
1/2, 14 N 1/2, 15 W 1/2, 16, 17 W 1/2, 18, 19, 20 W 1/2, 24 E 1/2, and E
1/2 of W 42.
R7W T32N: Sections 1-16, 17 N 1/2, 18-22, 23 W 1/2, 24 E 1/2 and E
1/2 of W 1/2.
R7W T33N: Sections 7 E 1/2, 8 S 1/2, 15, 16 S 1/2, 17 N 1/2, 18 W
1/2, 19 W 1/2, 21, 22 N 1/2, 23 S 1/2, 25 S 1/2, 26, 27 W 1/2, 28 W 1/2,
19 W 1/2, 30-33, 34 E 1/2, 35 and 36.
R8W T32N: Sections 1-3, 4 N 1/2, 5, 6 W 1/2, 9 E 1/2, 10 E 1/2,
11-14, 15 E 1/2, 17 S 1/2, 18, 19 W 1/2, and W 1/2 of E 1/2, 22 E 1/2 of
E 1/2, 23 and 24.
R8W T33N: Sections 1, 2, 3 S 1/2, 4 S 1/2, 5-9, 10 S 1/2, 11 S 1/2,
15-23, 24 S 1/2, and 25-36.
R9W T32N: Sections 1 N 1/2, 2 S 1/2, 3 S 1/2, 4 S 1/2, 5 E 1/2, 6-9,
10 S 1/2, 11 S 1/2, 13 N 1/2, 15 W 1/2, 16, 17, 18 E 1/2, 19 W 1/2, and
W 1/2 of E 1/2.
R9W T33N: Sections 1 N 1/2, 2 S 1/2, 3 N 1/2, 4-14, 15 W 1/2, 17-20,
22, 23 S 1/2, 24 W 1/2, 25-28, 29 E 1/2, 30, 31, 32 W 1/2, 33, 34 S 1/2,
35, and 36 W 1/2.
R9W T34N: Sections 19 W 1/2, 29 E 1/2, 30 through 32, 33 W 1/2.
R10W T32N: Sections 1, 2, 3 E 1/2, 4 S 1/2, 5 N 1/2, 6 N 1/2, 7, 8,
9 N 1/2, and 10-24.
R10W T33N: Sections 1 W 1/2, 2, 3, 4 S 1/2, 5 S 1/2, 6, 8, 9 W 1/2,
10-15, 21 W 1/2, 22 S 1/2, 23, 24, 25 E 1/2, 26, 27, 28 S 1/2, 29 S 1/2,
30 E 1/2, 31 E 1/2, 32 and 34-36.
R10W T34N: Sections 24 S 1/2, 25, 26 E 1/2, 27 S 1/2, 28 S 1/2, 31 S
1/2, 32 N 1/2, 33 N 1/2, 34, 35 E 1/2 and 36.
R11W T32N: Sections 1, 10-16, 18 S 1/2, and 19-24.
R11W T33N: Sections 14 N 1/2, 25 E 1/2, 27 E 1/2, and 34 S 1/2.
(77) Frontier Formation in Wyoming. RM79-76 (Wyoming-9).
(i) Delineation of formation. The Frontier Formation is found in
Sweetwater County, Wyoming, in Townships 23, 24 and 25 North, Ranges 101
and 102 West; Townships 24, 25 and 26 North, Range 103 West; and
Townships 24 and 25 North, Range 104 West.
(ii) Depth. The Frontier Formation is defined as being between the
base of the Baxter Formation and the top of the Mowry Formation. The
average depth to the top of the Frontier Formation is 9,500 feet.
(78) Frontier Formation in Wyoming. RM79-76 (Wyoming-10).
(i) Delineation of formation. The Frontier Formation is found in
Sweetwater and Lincoln Counties, Wyoming, and encompasses Township 24
North, Range 114 West, Sections 1 and 12; Township 25 North, Ranges 112
and 113 West; Townships 26 North, Range 112 West, Sections 4, 9, 16 and
19-36; and Township 26 North, Range 113 West, Sections 25-36.
(ii) Depth. The vertical limits of the Frontier Formation are
defined by the Baxter Shale above and the Mowry Shale below. The gross
thickness of the formation averages between 200 and 250 feet, and the
average depth to the top of the Frontier Formation is 8,500 feet.
(79) The Lewis Formation in Wyoming. RM79-76 (Wyoming-11).
(i) Delineation of formation. The Lewis Formation is found in Carbon
and Sweetwater Counties, Wyoming, encompassing all or parts of:
Townships 21 and 22 North, Range 89 West
Townships 19 through 25 North, Range 90 West
Townships 13, 14, 18 through 21, and 23 through 25 North, Range 91
West
Townships 13 through 21 and 23 through 25 North, Range 92 West
Townships 13 through 25 North, Range 93 West
Townships 12 through 25 North, Range 94 West
Townships 12 through 25 North, Range 95 West
Townships 12 through 26 North, Range 96 West
Townships 12 through 26 North, Range 97 West
Townships 12 through 17 and 22 through 26 North, Range 98 West
Townships 12 through 16 and 22 through 26 North, Range 99 West
Townships 14 through 16 and 23 through 26 North, Range 100 West
(ii) Depth. The Lewis Formation's vertical limits are defined by the
Fox Hills Formation above, or in the case where the Fox Hills Formation
is not present, the Lance Formation above, and the Mesa Verde Formation
below. The average depth to the top of the Lewis Formation is 7,800
feet.
(80) Nugget Formation in Wyoming. RM79-76 (Wyoming-12).
(i) Delineation of formation. The Nugget Formation is found in
Carbon County, Wyoming, in Township 21 North, Range 79 West, Sections 3
through 10, and 15 through 18; and Township 22 North, Range 79 West,
Sections 31 through 34.
(ii) Depth. The vertical limits of the Nugget Formation are the
Basal Sundance Formation above and the Chugwater Formation below. The
average depth to the top of the Nugget Formation is 11,690 feet.
(81) Mesaverde Formation (including the Rollins Member) in Colorado.
RM79-76 (Colorado -- 22).
(i) Delineation of formation. The Mesaverde Formation is located in
the southeast portion of the Piceance Basin in Garfield, Mesa, Delta,
Pitkin and Gunnison Counties, Colorado, approximately 15 miles northeast
of the city of Grand Junction, Colorado. The Mesaverde Formation
underlies Townships 6 through 11 South, Ranges 89 through 97 West, 6th
P.M., with certain specified exclusions.
(ii) Depth. The Mesaverde Formation varies in thickness from zero to
approximately 6,000 feet with its base defined as the bottom of the
Rollins Members. The average depth to the top of the Mesaverde
Formation is 5,641 feet.
(82) Cozzette Formation in Colorado. RM79-76 (Colorado -- 22).
(i) Delineation of formation. The Cozzette Formation is located in
the southeast portion of the Piceance Basin in Garfield, Mesa, Delta,
Pitkin and Gunnison Counties, Colorado, approximately 15 miles northeast
of the city of Grand Junction, Colorado. The Cozzette Formation
underlies Townships 6 through 11 South, Ranges 89 through 97 West, 6th
P.M., with certain specified exclusions.
(ii) Depth. The Cozzette Formation is a member of the Upper Mancos
Formation. The average depth to the top of the Cozzette Formation is
6,869 feet.
(83) Corcoran Formation in Colorado. RM79-76 (Colorado -- 22).
(i) Delineation of formation. The Corcoran Formation is located in
the southeast portion of the Piceance Basin in Garfield, Mesa, Delta,
Pitkin and Gunnison Counties, Colorado, approximately 15 miles from the
city of Grand Junction, Colorado. The Corcoran Formation underlies
Townships 6 through 11 South, Ranges 89 through 97, West, 6th P.M., with
certain specified exclusions.
(ii) Depth. The Corcoran Formation is a member of the Upper Mancos
Formation. The average depth to the top of the Corcoran Formation is
7,069 feet.
(1) The area designated by the Commission as a tight formation in
Docket No. RM79-76 (Colorado -- 5), Order No. 148, under 271.703 for
the Rollins, Corcoran and Cozzette Formation.
(2) Township 10 South, Range 95 West, 6th P.M., Sections 17, 18, 19,
30, and Township 10 South, Range 96 West, 6th P.M., Sections 12, 13, 23
through 28, 33m for the Rollins, Cozzette and Corcoran Formations.
(Infill Drilling)
(3) Township 9 South, Range 97 West, 6th P.M., Sections 1 through 24,
26 through 35, and Township 10 South, Range 97 West, 6th P.M. Sections
2 through 11, for the Cozzette and Corcoran. (Designated in Order No.
151, Docket No. RM79-76 (Colorado -- 9))
(4) The area designated in Docket No. RM79-76 (Colorado -- 12) Order
No. 156, under 271.703 for the Cozzette, and Corcoran.
(5) Township 6 South, Range 93 West, 6th P.M., Sections 5, 6, 7, 8,
17, 18, 19, 20, and Township 6 South, Range 94 West, 6th P.M. Sections
1, 2, 3, 8 through 17, 19 through 24, 27 through 33, for the Mesaverde
Formation. (Designated in Order No. 205, Docket No. RM79-76 (Colorado
-- 17))
(6) The Wolf Creek Unit area. (Storage)
(84) Berea Sandstone and the ''Second Berea'' zone of the Bedford
Shale in Ohio. RM79-76 (Ohio-2) and RM79-76-177 (Ohio-2 Addition).
(i) Delineation of formation. The Berea Sandstone and the ''Second
Berea'' zone of the Bedford Shale occur within the Lower Mississippian
System. The Berea Sandstone (also called the ''First Berea'' or ''Berea
Grit'') lies above the Bedford Shale, which includes the ''Second
Berea'' zone near its base. The Berea Sandstone is found in the
following townships:
Athens County: Alexander, Ames, Athens, Bern, Canaan, Carthage,
Dover, Lodi, Rome, Troy.
Belmont County: Somerset, Washington, Wayne, York.
Gallia County: Addison, Cheshire, Gallipolis, Springfield (Sections
1 through 12).
Meigs County: all except Columbia.
Monroe County: all.
Morgan County: all.
Muskingum County: Blue Rock, Meigs, Rich Hill, Salt Creek, Wayne
(Sections 29 and 32).
Noble County: all.
Perry County: Bearfield (Sections 1, 2, 3, 10 through 15, 22 through
27).
Washington County: all.
The ''Second Berea'' zone of the Bedford Shale is found in the
following townships:
Athens County: Alexander, Ames, Athens, Bern, Canaan, Carthage
(Sections 25, 26, 29 through 36, Fractions 24, 32 through 35), Dover,
Lodi, Rome.
Gallia County: Addison, Cheshire, Gallipolis, Springfield (Sections
1 through 12).
Meigs County: Bedford (All sections except 1 through 4), Orange
(Sections 35 and 36), Rutland, Salem, Salisbury, Scipio.
Morgan County: Bloom, Bristol, Deerfield, Homer, Malta, Marion,
Meigsville (Sections 5, 6, 7, 8, 18, 19), Morgan, Penn, Union, York.
Muskingum County: Blue Rock, Meigs, Rich Hill, Salt Creek, Wayne
(Sections 29 and 32).
Perry County: Bearfield (Sections 1, 2, 3, 10 through 15, 22 through
27).
Washington County: Wesley (Section 6).
(ii) Depth. The vertical limits of the designated interval are
defined by the base of the Sunbury Shale (called ''Coffee Shale'' by
drillers) above and the top of the Upper Devonian Ohio Shale below. The
depth to the top of the interval ranges from approximately 1,000 feet to
2,400 feet. The Berea Sandstone ranges from 10 to 54 feet in thickness,
and the ''Second Berea'' zone of the Bedford Shale has a maximum
thickness of 36 feet. The ''Second Berea'' is separated from the Berea
Sandstone by approximately 10 to 50 feet of red to gray shales and
siltstones.
(85) Chacra Formation in New Mexico. RM79-76 (New Mexico-10).
(i) Delineation of formation. The Chacra Formation is found in
Township 21 North, Range 5 West, Sections 6, 7, 8, 16 through 22 and 26
through 36; Township 21 North, Range 6 West, Sections 1 through 18, 20
through 27, 35 and 36; Township 21 North, Range 7 West, Sections 1
through 4, and 10 through 13; Township 22 North, Range 6 West, Sections
6, 7, 8, 16 through 22, and 26 through 36; and Township 22 North, Range
7 West, Sections 1 through 36, NMPM in Sandoval County, New Mexico. The
formation is on the Chaco Slope of the Southern San Juan Basin.
(ii) Depth. The Chacra Formation averages 300 feet in thickness and
is the uppermost sand formation below the Huerfanito bentonite bed. The
average depth to the top of the Chacra Formation is 1,658 feet.
(86) Mesaverde Formation in Colorado. RM79-76 (Colorado -- 24).
(i) Delineation of formation. The Mesaverde Formation is found in
the southwestern portion of Rio Blanco County, Colorado, about 70 miles
northwest of the town of Grand Junction. The Mesaverde Formation is
located in Township 1 South, Ranges 98 and 99 West, 6th P.M., all;
Township 1 South, Range 100 West, 6th P.M. Sections 1 through 3, 10
through 15, 22 through 27, and 34 through 36; Township 2 Range 98 West,
6th P.M., Sections 4 through 8; Township 2 South, Range 99 West, 6th
P.M., Sections 1 through 12, 15 through 22, and 27 through 34; and
Township 2 South, Range 100 West, 6th P.M., Sections 1 through 3, 10
through 15, 22 through 27, and 34 through 36.
(ii) Depth. The Mesaverde Formation varies in thickness from 2,900
to 3,600 feet. The average depth to the top of the Mesaverde Formation
is 6,693 feet.
(87) Mancos Formation in Colorado. RM79-76 (Colorado -- 24).
(i) Delineation of formation. The Mancos Formation is found in the
southwestern portion of Rio Blanco County, Colorado, about 70 miles
northwest of the town of Grand Junction. The Mesaverde Formation is
located in Township 1 South, Ranges 98 and 99 West, 6th P.M., all;
Township 1 South, Range 100 West, 6th P.M., Sections 1 through 3, 10
through 15, 22 through 27, and 34 through 36; Township 2 Range 98 West,
6th P.M., Sections 4 through 8; Township 2 South, Range 99 West, 6th
P.M., Sections 1 through 12, 15 through 22, and 27 through 34; and
Township 2 South, Range 100 West, 6th P.M., Sections 1 through 3, 10
through 15, 22 through 27, and 34 through 36.
(ii) Depth. The Mancos Formation is approximately 5,000 feet thick.
The average depth to the top of the Mancos Formation is 9,495 feet.
(88) Dakota Formation in New Mexico RM79-76 (New Mexico -- 8).
(i) Delineation of formation. The Dakota Formation is found in
Townships 30 and 31 North, Ranges 2 through 7, in San Juan and Rio
Arriba Counties, New Mexico. The formation is within the Basin-Dakota
Gas Pool, in the Rosa Area of the San Juan Basin.
(ii) Depth. The Dakota Formation is below the Graneros Shale
Formation and above the Morrison Formation. The average depth to the
top of the Dakota Formation is 7,950 feet. The formation is
approximately 250 feet in thickness.
(89) Pictured Cliffs Formation in New Mexico. RM79-76-108 (New
Mexico -- 11).
(i) Delineation of formation. The Pictured Cliffs Formation is found
in the southeastern portion of the San Juan Basin in Rio Arriba County,
New Mexico. The area is divided into two non-contiguous tracts
described as Area A and Area B. Area A encompasses Township 25 North,
Range 6 West, Sections 21, 22, 23, 26, 27, 28 NE/4, 34, 35, and 36 W/2.
Area B encompasses Township 25 North, Range 7 West, Sections 4, 5 E/2, 8
NE/4, 9 N/2, and 10 N/2; Township 26 North, Range 6 West, Section 31;
Township 26 North, Range 7 West, Sections 17 S/2, 18, 19 N/2, and SE/4,
20, 21, S/2, 22 S/2, 25 SW/4, 26 S/2, 27, 28, and 33 through 36.
(ii) Depth. The Pictured Cliffs Formation's vertical limits are
defined by the Fruitland Formation above and the Lewis Shale Formation
below. The average thickness through the formation is 70 feet, and the
average depth to the top of the Pictured Cliffs Formation is 2,387 feet.
(90) Hartselle Sandstone Formation in Alabama. RM79-76-096
(Alabama-2).
(i) Delineation of formation. The Hartselle Sandstone Formation in
Alabama is found in Township 11 South, Ranges 7 to 9 West and Township
12 South, Ranges 6 to 10 West, in Winston County, and in Townships 12 to
17 South, Ranges 4 to 10 West, in Walker County. The Jasper Field
located in Township 13 South, Range 7 West, Sections 21 through 28, and
33 through 36, in Walker County, is excluded from the designation.
(ii) Depth. The depth of the formation varies from approximately 400
feet in the northern part of the formation, to 3,000 feet in the
southern part. It varies in thickness from zero feet at the downdip
pinchout in southern Walker County and along the western border of
Walker County, to over 150 feet in northern Walker County and southern
Winston County.
(91) Vicksburg (9000') Formation in Texas. RM79-76 (Texas -- 20).
(i) Monte Christo Vicksburg 9000' Formation -- (A) Delineation of
formation. The Monte Christo Vicksburg 9000' Formation is located in a
portion of Hidalgo County, Texas, and is encountered in portions of the
following surveys: Jackson Subdivision of the San Salvadore Del Tule
Grant, Juan Jose Balli Survey A-290; Section 203, Tex.-Mex. Ry. Co.
Survey A-124; Section 206 Tex.-Mex. Ry. Co. Survey A-637; Section 207,
Tex.-Mex. Ry. Co. Survey A-126; Section 210, W. T. Bomar Survey
A-624; Section 211, Tex.-Mex. Ry. Co. Survey A-128; Section 214;
Macedonia Vela, Jr. Survey A-623. Excluded from the designation is a
rectangular area in the Juan Jose Balli Survey A-290, two sides of which
extend due north and south, the north line being 750' north of and the
west line being 750' west of the Shell Oil Co, Bright & Schiff Hamman 1
Well, and the south side being 750' south of the the east line being
750' east of the Shell Oil Co. Bright & Hamman 2 Well.
(B) Depth. The Monte Christo Vicksburg 9000' Formation ranges from a
depth of approximately 9000 feet to approximately 9700 feet, with a
gross average thickness of approximately 650 feet. The bottom of the
formation may extend as deep as 10,400 feet in the undeveloped areas.
(ii) Monte Christo, South (9000') Formation -- (A) Delineation of
formation. The Monte Christo, South (9000') Formation is located in the
southern portion of Hidalgo County, Texas, Railroad Commission District
4. The designated area includes the following surveys: Macedonia Jr.
Vela No. 214, A-623; Tex.-Mex. R.R. No. 215, A-130; W. T. Bomar No.
218, A-626; Jas. L. Hudson, A-649; Walter A. Hoffhein, A-797; W. H.
Kozel, A-798; Tex.-Mex. R.R. No. 217, A-131; the northernmost 500
acres of both the Nicolas Zamora Porcion No. 48, A-76 and the Torebio
Zamora Porcion No. 49, A-78; and the southernmost 900 acres of the
northern 1,800 acres of the Francisco Cantu Porcion No. 80, A-570.
(B) Depth. The top of the Monte Christo, South (9000') Formation
varies from 8,750 feet subsea to 9,600 feet subsea. The maximum
thickness of the formation is 1,030 feet.
(92) James Limestone Formation in Texas. RM79-76-172 (Texas-21).
(i) Southern Shelby and Northern San Augustine Counties -- (A)
Delineation of formation. The James Limestone Formation is found in
northern San Augustine County and southern Shelby County, in Railroad
District No. 6 in Texas. The area includes 67,900 acres surrounding
and extending northwest of the city of San Augustine, Texas.
(B) Depth. The top of the James Limestone Formation ranges from
^6,700 feet subsea in the north to ^7,750 feet subsea in the south, with
a thickness of approximately 202 feet.
(ii) Shelby County -- (A) Delineation of Formation. The James
Limestone Formation is located in Shelby County, Railroad Commission
District 6, East Texas. The James Limestone Formation is included as a
subdivision of the Trinity Group of Lower Cretaceous (Commanchean) Age.
(B) Depth. The James Limestone Formation ranges from approximately
^5,100 feet subsea in the North to ^6,700 feet subsea in the south. The
James Limestone overlies the Pine Island Shale and underlies the Bexar
Shale.
(93) Berea Sandstone in Kentucky. RM79-76-113 (Kentucky -- 1).
(i) Delineation of formation. The Berea Sandstone is delimited by
the underlying Ohio Shale of Devonian age, also known as ''Devonian
Shale'' or ''Cinnamon'' (drillers' terms), and by the overlying Sunbury
Shale of Mississippian age, also known as ''Coffee Shale'' (drillers'
term). The Berea Sandstone is also known as ''grit'' or ''Bedford
Shale'' (drillers' terms) in the designated area, and is used as a
marker for the base of the Mississippian age deposits. The designated
area includes all of Lawrence County, Kentucky, with the exception of
two areas encompassing approximately three square miles near the 38th
parallel in the south-central part of the county.
(ii) Depth. The average depth to the top of the Berea Sandstone is
1,400 feet, and the interval is about 100 feet thick throughout Lawrence
County.
(94) Lance Formation in Wyoming. RM79-76-112 (Wyoming -- 13)
(i) Delineation of formation. The Lance Formation is located in
Fremont and Natrona Counties, Wyoming, in Township 38 North, Range 88
West, Sections 3 through 11, 13 through 36; Township 38 North, Range 89
West; Township 38 North, Range 90 West, Sections 1 through 3, 6 through
36; Township 38 North, Range 91 West; Township 38 North, Range 92
West, Sections 1, 2, 11 through 14, 23, 24, 25; Township 39 North,
Range 88 West, Sections 19, 29 through 33; Township 39 North, Range 89
West, Sections 4 through 10, 13 through 36; Township 39 North, Range 90
West, Sections 1 through 32, 36; Township 39 North, Range 91 West;
Township 39 North, Range 92 West, Sections 12, 13, 14, 23 through 26, 35
and 36.
(ii) Depth. The Lance Formation lies between the base of the Lower
Fort Union Formation and the top of the Meeteetse Formation. The
average depth to the top of the Lance Formation is 8,915 feet.
(95) Meeteetse Formation in Wyoming. RM79-76-112 (Wyoming -- 13).
(i) Delineation of formation. The Meeteetse Formation is located in
Fremont and Natrona Counties, Wyoming, in Township 38 North, Range 88
West, Sections 3 through 11, 13 through 36; Township 38 North, Ranges
89, 90 and 91 West; Township 38 North, Range 92 West, Sections 1, 2, 11
through 14, 23, 24, 25; Township 39 North, Range 88 West, Sections 19,
29 through 33; Township 39 North, Range 89 West, Sections 4 through 10,
13 through 36; Township 39 North, Ranges 90 and 91 West; Township 39
North, Range 92 West, Sections 12, 13, 14, 23 through 26, 35 and 36.
(ii) Depth. The Meeteetse Formation lies between the base of the
Lance Formation and the top of the Mesaverde Formation. The average
depth to the top of the Meeteetse Formation is 14,319 feet.
(96) Mesaverde Formation in Wyoming. RM79-76-112 (Wyoming -- 13).
(i) Delineation of formation. The Mesaverde Formation is located in
Fremont and Natrona Counties, Wyoming, in Township 38 North, Range 89
West, Sections 6, 7; Township 38 North, Range 90 West, Sections 1
through 12, 15 through 18; Township 38 North, Range 91 West, Sections
2, 3, 4, 9 through 12; Township 39 North, Range 90 West, Sections 28
through 36; Township 39 North, Range 91 West, Sections 25, 26, 34, 35,
36.
(ii) Depth. The Mesaverde Formation lies between the base of the
Meeteetse Formation and the top of the Cody Shale Formation. The
average depth to the top of the Mesaverde Formation is 15,396 feet.
(97) Mesaverde Formation in New Mexico. RM79-76-109 (New Mexico --
12).
(i) Delineation of formation. The Mesaverde Formation is located in
San Juan County, New Mexico, and is found in Township 32 North, Range 8
West, NMPM, Sections 30 and 31 and Township 32 North, Range 9 West,
NMPM, Sections 25, 26, 27, 34 and 35.
(ii) Depth. The Mesaverde Formation is within the Blanco Mesaverde
Gas Pool in the San Juan Basin, and consists of three Sand areas: the
Cliffhouse member, which averages 50 feet in thickness, the Menefee
member, which ranges in thickness from 230 feet to 290 feet, and the
Point Lookout member which ranges in thickness from 150 feet to 200
feet. The vertical limits of the Mesaverde Formation are from the
Huerfanito Bentonite in the Lewis Shale above, to a point 500 feet below
the top of the Point Lookout member. The average depth to the top of
the Mesaverde Formation is 5,463 feet.
(98) Permo-Penn Formation in New Mexico. RM79-76-110 (New Mexico --
13).
(i) Delineation of formation. The Permo-Penn Formation is located in
Eddy County, New Mexico, in Township 17 South, Ranges 24 through 26
East; Township 18 South, Ranges 24 and 25 East; Township 19 South,
Ranges 23 through 25 East; Township 20 South, Ranges 21, 23, and 24
East; Township 20 1/2 South, Ranges 21 and 22 East; Township 21 South,
Ranges 21 and 22 East; Township 22 South, Range 21 East, Sections 1
through 12; and Township 22 South, Range 22 East, Sections 1 through
12, NMPM.
(ii) Depth. The Permo-Penn Formation varies in thickness from 1,000
feet to 1,400 feet, and lies between the base of the Wolfcamp Formation
and the top of the Canyon Formation. The Permo-Penn includes the Third
Sister, the Antelope Sink, and the Cisco Formations. The average depth
to the top of the Permo-Penn Formation is 5,822 feet.
(99) Atoka-Morrow Formation in New Mexico. RM79-76-116 (New Mexico
-- 15).
(i) Delineation of formation. The Atoka-Morrow Formation is located
in Chaves County, New Mexico, approximately 23 miles northeast of
Roswell, New Mexico. The Atoka-Morrow Formation is found in Township 7
South, Range 28 East, Sections 22 through 27, and 34 through 36;
Township 7 South, Range 29 East, Sections 19 through 36; Township 7
South, Range 30 East, Sections 19 through 36; township 7 South, Range
31 East, Sections 19, 20, 21, and 28 through 33; Township 8 South,
Range 28 East, Sections 1, 2, 3, 10 through 15, 22 through 27, and 34,
35, 36; Township 8 South, Range 29 East, Sections 1 through 36;
Township 8 South, Range 30 East, Sections 1 through 36; Township 8
South, Range 31 East, Sections 4 through 9, 16 through 21, and 28
through 33; Township 9 South, Range 28 East, Sections 1, 2, 3, and 10
through 15; Township 9 South, Range 29 East, Sections 1 through 18;
Township 9 South, Range 30 East, Sections 1 through 18; Township 9
South, Range 31 East, Sections 4 through 9, and 16, 17, and 18.
(ii) Depth. The Atoka-Morrow Formation varies in thickness from 91
feet to 895 feet. The average depth to the top of the Atoka-Morrow
Formation is 8,100 feet.
(100) ''Princeton'' Zone of the Mauch Chunk Group in West Virginia.
RM79-76-092 (West Virginia -- 1).
(i) Delineation of formation. The ''Princeton'' zone of the Mauch
Chunk Group underlies portions of Mercer, McDowell and Wyoming Counties,
West Virginia. The ''Princeton'' zone is also called ''Salt Sands'' or
''Maxton'' by drillers.
(ii) Depth. The ''Princeton'' zone ranges in thickness from 0 to 100
feet, and is found at a depth of approximately 1,400 to 1,500 feet in
north-central Wyoming County. It is bounded above by the Pottsville
Group of Pennsylvanian age (referred to as ''Salt Sands'' or ''Rosedale
Gas Sands'' by drillers) or by the Bluestone Formation of Mississippian
age (also called ''Salt Sands'' by drillers).
(101) ''Ravencliff'' zone of the Mauch Chunk Group in West Virginia.
Docket No. Rm79-76-092 (West Virginia -- 1 Addition).
(i) Delineation of formation. The ''Ravencliff'' zone of the Mauch
Chunk Group, also called ''Salt Sands'' or ''Maxton'' by drillers, is
found in portions of Mercer, McDowell and Wyoming Counties, West
Virginia.
(ii) Depth. The ''Ravencliff'' zone ranges in thickness from
stringers in the western portion of the designated area, to 150 feet in
the central and southwestern portion of the area. It is found at depths
varying from 1,100 to 2,100 feet.
(102) ''Injun'' Zone of the Pocono Group in West Virginia. Docket
No. RM79-76-092 (West Virginia -- 1 Addition).
(i) Delineation of formation. The ''Injun'' zone of the Pocono
Group, also called ''Big Injun'', underlies portions of Mercer, McDowell
and Wyoming Counties, West Virginia.
(ii) Depth. The ''Injun'' zone varies in thickness from 50 feet in
Wyoming County to stringers in the southern and eastern portions of the
designated area. The depth to the top of the ''Injun'' zone ranges from
approximately 3,100 feet to 4,300 feet.
(103) ''Weir'' Zone of the Pocono Group in West Virginia.
RM79-76-092 (West Virginia -- 1 Addition).
(i) Delineation of formation. The ''Weir'' zone of the Pocono Group
underlies portions of Mercer, McDowell and Wyoming Counties, West
Virginia.
(ii) Depth. The ''Weir'' zone ranges in thickness from stringers in
the eastern and western portion of the designated area, to 70 feet in
the central part of the area. The ''Weir'' zone is found at depths
varying from 3,250 feet to 4,550 feet.
(104) ''Berea'' zone of the Pocono Group in West Virginia.
RM79-76-092 (West Virginia -- 1 Addition).
(i) Delineation of formation. The ''Berea'' zone of the Pocono Group
underlies portions of Mercer, McDowell and Wyoming Counties, West
Virignia.
(ii) Depth. The ''Berea'' zone has a maximum thickness of 45 feet in
the central portion of McDowell and Wyoming Counties, and varies to
shaley sandstone stringers in the eastern portion of the designated
area. The ''Berea'' zone is found at depths ranging form 3,600 feet to
4,950 feet.
(105) Wasatch Formation in Colorado. RM79-76-061 (Colorado-21).
(i) Delineation of formation. The Wasatch Formation is found in
Garfield County, Colorado, in Township 6 South, Range 93 West, 6th P.M.,
Sections 3 through 10, 15 through 22, and 27 through 34, and Township 6
South, Range 94 West, 6th P.M., Sections 1 through 3, 10 through 15, 22
through 27, and 34 through 36. Excluded from this designation are the
Naval Oil Shale leaseholds found in portions of Township 6 South, Range
94 West, Sections 2, 3 and 10.
(ii) Depth. The Wasatch Formation extends from the surface of the
ground to the top of the Williams Fork and Iles members of the Mesaverde
Formation. The average depth to the top of the producing interval of
the Wasatch Formation is 1,767 feet.
(106) Strawn-Detrital Formation in Texas. RM79-76 (Texas -- 22) --
(i) University Block 31 (Strawn-Detrital) and Howards Creek (Penn)
Fields -- (A) Delineation of formation. The Strawn-Detrital Formation
in the area of the University Block 31 and Howards Creek Fields located
in Crockett County, Texas, Railroad Commission District 7C. The
designated area consists of Sections 7, 8, 9, the south half of Section
10, Sections 16 through 20, the south half of Section 21, Sections 29
through 32, Block 30, University Lands Survey; all Sections in Block
31, University Lands Survey; Sections 1, 2, 3, the south half of
Section 4, Sections 5 through 8, the south half of Section 9, Sections
11 through 14 and the north half of Section 18, Block 32, University
Lands Survey; Sections 6 through 20, Block 33, University Lands Survey;
the southwest 1/4 of Section 12, Sections 29, 30, 31, the south half of
Section 32, Sections 50, 51 and the southeast 1/4 of Section 53, Block
UV, GC & SF RR Co. Survey; Section 2, Block ST-2, GC & SF RR Co.
Survey; the north half of Hampton Survey; Section 1001 of W. G. Hall
Survey; Section 1002 of J. M. Jean Survey; Section 1003 of M. F.
Lopez Survey; Sections 1, 2, 14 through 18, Block ST,GC & SF RR Co.
Survey; the north half of Section 49, Sections 50 through 53, the south
half Section 54, Sections 66 through 70, the east half of Section 71,
Sections 76 through 79, the south half of Section 90, Sections 91, 92,
93 and the north half of Section 94, Block OP, GC & SF RR Co. Survey;
Sections 20, 21, 22, 29, 37, 38, the western 75 acres of Section 34, the
western half of Section 36 and the eastern half of Section 41, Block ST,
T.C.R.R. Survey; Section 28, Block ST, H.E. & W.T. Survey; Section 8
and the northern 480 acres of Sections 7 and 10, Block SL, T. & S.T.L.
Survey; and the northern 98 acres of Block Z, J. W. Henderson Survey.
(B) Depth. The vertical extent of the Strawn-Detrital Formation in
the University Block 31 Field is defined as the interval from the base
of the Canyon Formation (top of the Strawn series) to the top of the
Simpson Shale (base of the Devonian), which includes the Strawn,
Strawn-Detrital and Devonian zones. The average depth to the top of the
Strawn series is approximately 7,900 feet in the north and 8,900 feet in
the south.
(ii) Perner Ranch Area -- (A) Delineation of formation. The Detrital
Formation in the Perner Ranch Area is located approximately 23 miles
west-southwest of the city of Ozona, Crockett County, Texas, Railroad
Commission District 7C. The area includes the following sections: L &
SV Survey, Sections 199 and 200, and T.C. RR Survey, Sections 43 and 45.
(B) Depth. The depth to the top of he Detrital Formation varies from
^6,000 feet to the northwest part to the area to ^6,700 feet in the
southeast. The approximate thickness of the formation is 110 feet.
(iii) Ozona, S.W. (Strawn) Field -- (A) Delineation of Formation.
The Strawn-Detrital Formation in the area of the Ozona, S.W. (Strawn)
Field is located in Crockett County, Texas, Railroad Commission District
7C. The designated area consists of the south half of Section 1,
Sections 2, 3, 4, the east half of Section 8, Sections 9, 10, 11, the
south halves of Sections 12 and 13, Sections 14, 15, 16, the west half
of Section 17, Section 21, and the west half of Section 23, Block M, GC
and S.F. Survey; Sections 4, 5, 6, the south quarters of Sections 7 and
10, Sections 11, 12 and 13, Block S.L., T and S.T.L. Survey; and a
portion ot Block Z, J. W. Henderson Survey.
(B) Depth. The vertical extent of the Strawn-Detrital Formation in
the Ozona, S.W. (Strawn) Field is defined as the interval from the base
of the Canyon Formation (top of the Strawn series) to the top of the
Simpson Shale (base of the Devonian), which includes the Strawn,
Strawn-Detrital and Devonian zones. The average depth to the top of the
Strawn series is approximately 8,800 feet.
(107) Chacra Formation in New Mexico. RM79-76-117 (New Mexico --
16).
(i) Delineation of formation. The Chacra Formation is located in all
of Sections 16, 21, 22, 25 through 28, 34 through 36, and the S/2 of
Section 23, Township 25 North, Range 6 West, NMPM, in Rio Arriba County,
New Mexico.
(ii) Depth. The Chacra Formation averages approximately 130 feet in
thickness. The average depth to the top of the Chacra Formation is
3,390 feet.
(108) Dakota-Lakota Formation in Colorado. RM79-76-123 (Colorado --
26).
(i) Delineation of formation. The Dakota-Lakota Formation is located
in Boulder County, Colorado, in Township 1 North Range 69 West, 6th
P.M., Sections 25 through 36; Township 1 South, Range 69 West, 6th
P.M., Sections 3 through 10, 15 through 22, and 27 through 34; Township
1 South, Range 70 West, 6th P.M., Sections 1 through 3, 10 through 15,
22 through 27, and 34 through 36.
(ii) Depth. The producing interval of the Dakota-Lakota Formation is
approximately 175 to 185 feet thick, and begins at the base of the Skull
Creek Formation and extends to the top of the Morrison Formation. The
average depth to the top of the Dakota-Lakota Formation is 9,100 feet.
(109) Codell Formation in Colorado. RM79-76-122 (Colorado-25).
(i) Delineation of formation. The Codell Formation underlies
portions of Adams, Boulder, Jefferson, Larimer and Weld Counties,
Colorado, and is located on the western flank of the Denver-Julesberg
Basin a few miles north of Denver, Colorado. The Codell Formation is
found in the following areas: Township 1 South, Ranges 64 through 70
West; Township 2 South, Ranges 69 and 70 West; Township 1 North,
Ranges 64 through 70 West; Township 2 North, Ranges 64 through 69 West,
all sections, Range 70 West, Sections 1 through 5, and 8 through 36;
Township 3 North, Ranges 64 through 69 West, all sections, Range 70
West, Sections 1, 12, 13, 21 through 28, and 33 through 36; Township 4
North, Ranges 64 through 69 West; Township 5 North, Ranges 64 through
68 West, all sections, Range 69 West, Sections 1 through 4, 9 through
16, 20 through 29, and 31 through 36, Township 6 North, Ranges 64
through 68, all sections, Range 69 West, Sections 1 through 4, 9 through
16, 21 through 28, and 33 through 36.
(ii) Depth. The Codell Formation ranges in depth from 3,000 to 8,000
feet, and is generally found at a depth of 7,000 feet, and averages 15
feet in thickness.
(110) The Dakota Producing Interval in New Mexico. RM79-76-103 (New
Mexico -- 9).
(i) Delineation of formation. The Dakota Producing Interval is found
within the Basin-Dakota Gas Pool in the northwestern portion of the San
Juan Basin near the Hogback Monocline. It is found in San Juan County,
in Township 31 North, Range 10 West, NMPM, Sections 1 through 36;
Township 31 North Range 11 West, NMPM, Sections 1, 12, 13, 22 through 27
and 34, 35 and 36; Township 32 North, Range 10 West, NMPM, Sections 7
through 36; Township 32 North, Range 11 West, NMPM, Sections 7 through
27 and 34, 35 and 36; Township 32 North, Range 12 West, NMPM, Sections
7 through 24, 28 through 31; and Township 32 North, Range 13 West,
NMPM, Sections 7 through 29 and 32 through 36.
(ii) Depth. The Dakota Producing Interval begins at the base of the
Greenhorn Limestone and consists of the Graneros Formation, the Dakota
Formation and the productive upper limit of the Morrison Formation. The
average depth to the top of the Dakota Producing Interval is 6,753 feet.
The gross thickness of the interval averages 400 feet.
(111) The Olmos Formation in Texas. Rm79-76 (Texas -- 16) -- (i)
Dimmit and Webb Counties -- (A) Delineation of formation. The Olmos
Formation is located in the northwest portion of Webb County and the
southern portion of Dimmit County in Texas. The Formation includes all
of that portion of Dimmit County extending approximately 14 miles north
of the boundary of Webb County, and all of that portion of northwest
Webb County west of a north-south line extending south from a point
approximately 1.5 miles east of the southwest corner of La Salle County,
and north of an eastwest line located approximately 22 miles south of
the southwest corner of La Salle County.
(B) Depth. The top and base of the Olmos Formation are found at
approximate depths of 4,146 feet and 5,237 feet respectively, on the log
of the Trans Delta Corporation Petty Well No. 6-7. This well is located
in Section 7, Block 8, of the I&G.N.R.R. Co. Survey in the S.W. Catarina
Field, Webb County, Texas.
(ii) A.W.P. (Olmos) Field, McMullen County -- (A) Delineation of
formation. The Olmos Formation designated area underlies portions of
the A.W.P. Olmos Field and consists of 4,853 contiguous acres located 3
1/2 to 5 miles southeast of Tilden, Texas. Specifically, the area is
all of Sections 24, 25, 27, 37, 38, 39, the west 1/2 Section 23, the
southwest 1/4 of Section 28, the north 1/2 of Section 41, and the north
1/2 of Section 42, out of the Two Rivers Ranch Subdivision as shown by
plat recorded in Volume O, page 460 (Bracken Lease) and page 464
(McClaugherty Lease) of the Deed Records, McMullen County, Texas.
(B) Depth. The top of the Olmos Formation occurs at depths of from
9,100 feet to 9,600 feet below mean sea level.
(iii) A.W.P. (Olmos) Field, McMullen County -- (A) Delineation of
formation. The designated portion of the Olmos Formation located to the
east and southeast of Tilden, in McMullen County, Texas, and consists of
approximately 7,506 acres containing four leases; the 3,480.6 acre
Bracken Ranch lease, the 320 acre Dan Foster lease, the 2,431.46 acre
R.P. Horton lease and the 1,274 acre R.P. Horton ''C'' lease.
(B) Depth. The top of the Olmos Formation occurs at depths of from
9,100 feet to 9,600 feet below mean sea level.
(112) The Mancos ''B'' Formation in Colorado. RM79-76 (Colorado-27)
(i) Delineation of formation. The Mancos ''B'' Formation is located
in the Douglas Creek Arch area of western Colorado, in Rio Blanco
County. The Mancos ''B'' Formation underlies Township 1 North, Range
101 West, Sections 17 through 20 and 29 through 32; Township 1 North,
Range 102 West, Sections 7 through 9 and 13 through 36; Townships 1
North and 1 South, Range 103 West, all sections; Townships 1 North and
1 South, Range 104 West, Sections 1 through 3, 10 through 15, 22 through
27, and 34 through 36; Township 1 South, Range 102 West, Sections 1
through 10, 16 through 21, and 28 through 33; Township 2 South, Range
102 West, Sections 4 through 6; Township 2 South, Range 103 West,
Sections 1 through 6, 17, 18, 20, 29, 32, and 33; and Township 2 South,
Range 104 West, Sections 1 through 3 and 10 through 15. The additional
area is contiguous to that part of the Mancos ''B'' Formation described
above on its northern border. The addition to the Mancos ''B''
Formation is located in Rio Blanco County, Colorado, along the western
flank and northern end of the Douglas Creek Arch in Township 2 South,
Range 102 West N 1/2 of Section 8 and N 1/2 and SE 1/4 of Section 9. On
its eastern border, the specified acreage is adjacent to lands described
in 271.703(d)(6).
(ii) Depth. The Mancos ''B'' Formation ranges in thickness from 150
to 325 feet. The average depth to the top of the Mancos ''B'' Formation
is 3,000 feet. The additional area, located in the southern part of the
Mancos ''B'' Formation, has an average depth to the top of the formation
of 2,621 feet and an average gross thickness of 375 feet.
(113) The Clearfork Formation in Texas. RM79-76-114 (Texas-23).
(i) Delineation of formation. The Clearfork Formation is found in
Pecos County, Texas. The designated area is located approximately 12
miles southeast of the City of Imperial, Texas, within the H&TC RR Block
2 and H&GN RR Block 9 Surveys.
(ii) Depth. The top of the Clearfork Formation ranges from a
measured depth of 2,900 feet in the west to 3,000 feet in the east. A
typical Clearfork section occurs between the measured depths of 2, 895
feet and 4,124 feet, on the well log of the George T. Abell No. 1-A
Well.
(114) The J Sand Formation in Colorado. RM79-76-133 (Colorado-29).
(i) Delineation of formation. The J Sand Formation is located in
Adams and Arapahoe Counties, Colorado, approximately 24 miles due east
of the city of Denver. The J Sand Formation underlies Township 3 South,
Range 62 West, Sections 17 through 20, and 29 through 32; Township 3
South, Range 63 West, Sections 13 through 36; Township 4 South, Range
62 West, Sections 5 through 8, 17 through 20, and 29 through 32; and
Township 4 South, Range 63, All Sections, 6th P. M.
(ii) Depth. The J Sand Formation ranges in thickness from 20 to 180
feet. The average depth to the top of the J. Sand Formation is 7,700
feet.
(115) Dakota Formation in New Mexico. RM79-76-138 (New Mexico-17).
(i) Delineation of formation. The Dakota Formation is located in the
northwestern portion of the San Juan Basin in San Juan County, New
Mexico. The Dakota Formation underlies all of Township 26 North, Ranges
12 and 13 West; Township 27 North, Range 12 West, Section 8-S/2, 9-S/2,
and 16 through 36; Township 27 North, Range 13 West, Sections 3-W/2, 4
through 9, 10-W/2, and 14 through 36; Township 28 North, Range 13 West,
Sections 7 through 9, 16 through 21, 28 through 33, and 34-W/2;
Township 29 North, Range 13 West, Sections 4 through 9, 16 through 19,
20-W/2, 29-W/2, 30, 31, and 32-W/2; Township 29 North, Range 14 West,
Sections 1, 2-W/2 and SE/4, 3 through 18, 19-NE/4, 20 through 27, 28-N/2
and SE/4, 34-N/2, 35 and 36; Township 29 North, Range 15 West, Sections
1 through 6, 7-N/2, 8-N/2, 9-N/2, 10-N/2 and SE/4, 11, 12, 13-N/2 and
14-N/2; Township 30 North, Range 14 West, Sections 1 through 12, 15
through 23, and 26 through 34; and all of Township 30 North, Range 15
West, NMPM.
(ii) Depth. The Dakota Formation ranges in thickness from 250 to 300
feet. The average depth to the top of the Dakota Formation is 5,952
feet.
(116) ''Cleveland Sand'' of the ''Kansas City Group'' in Oklahoma.
RM79-76-120 (Oklahoma -- 2).
(117) Gray Sand in Smackover Formation in Louisiana. RM79-76-124
(Louisiana -- 8).
(i) Delineation of formation. The Gray Sand in the Smackover
Formation is located in the following portions of Bienville, Bossier,
Claiborne, Lincoln, Ouchita, Union, and Webster Parishes, north
Louisiana: Township 22 North, Range 8 West through 13 West; Township
21 North, Range 2 West through 13 West; Township 20 North, Range 2 West
through 13 West; Township 19 North, Range 1 East; Township 19 North,
Range 1 West through 10 West; Township 18 North, Range 1 East;
Township 18 North, Range 1 West through 5 West.
(ii) Depth. The Gray Sand in the Smackover Formation is defined as
that formation occurring between the measured depths of 11,000 and
11,570 feet on the induction electric log of the Sun Oil Company --
Northcott No. 2 Well, located in Section 29, Township 22 North, Range
11 West, Bossier Parish.
(118) Medina Group and Queenston Shale in New York. RM79-76-118 (New
York-2).
(i) Delineation of formation. The Medina Group and Queenston Shale
are found in Erie, Genesee, Wyoming, Allegany, Livingston, Ontario,
Yates, Seneca, Cayuga, and Tompkins Counties, New York. Excluded from
the delineated Medina-Queenston interval are any Medina gas storage
areas, including buffer zones, or any areas within Medina or Queenston
''existing fields'' (as defined in Title 6, New York Code of Rules and
Regulations, Section 550.3(q)). The Medina Group (also known as the
Albion Group) is of Early Silurian age and overlies the Upper Ordovician
Queenston Shale (called the ''red shale'' by some drillers). The Medina
Group is bounded above by the base of the Thorold Formation or the time
equivalent Kodak Sandstone. The Medina Group consists of (from base to
top) the Whirlpool Sandstone (called ''white Medina'' by drillers), the
Power Glen Shale (also known as the Cabot Head Shale), and the Grimsby
Sandstone (called ''red Medina'' by drillers). The Queenston Shale has
a gradational contact with the underlying Oswego Sandstone.
(ii) Depth. The depth to the top of the Medina Group varies from
less than 1,000 feet in the northwestern portion of the designated area
to as much as 5,500 feet in the southeastern portion. The Medina Group
ranges in thickness from approximately 60 to 120 feet. The thickness of
the Queenston Shale is indefinite due to the transitional nature of its
contact with the underlying Oswego Sandstone, but the Queenston-Oswego
sequence ranges in a thickness from approximately 1,000 feet in Western
New York to more than 1,300 feet in southern and central New York.
(119) Dakota Formation in Utah. RM79-76-074 (Utah-3).
(i) Delineation of formation. The Dakota Formation is found in the
Book Cliffs area of Grand and Uintah Counties, Utah and is in the
general area of Townships 15 South through 20 South and Ranges 16 East
through 24 East.
(ii) Depth. The average depth to the top of the Dakota Formation is
6, 034 feet. The Dakota Formation is defined as the interval from the
top of the Dakota Silt down to the top of the Morrison Formation, a
thickness of approximately 250 feet.
(120) Basin-Dakota Formation in New Mexico. RM79-76-139 (New Mexico
-- 18).
(i) Delineation of formation. The Basin-Dakota Formation is located
in San Juan County, New Mexico, in Township 32 North, Range 7 West,
Sections 7, 8, 9, 16 through 21, and 25 through 36; Township 32 North,
Range 8 West, Sections 7 through 36; Township 32 North, Range 9 West,
Sections 7 through 36, Township 31 North, Range 8 West, Sections 1
through 31, and 33 through 36; Township 31 North, Range 9 West,
Sections 1 through 26, and 29 through 36; Township 30 North, Range 8
West, Sections 1, 2, 6 through 34, and 36; Township 30 North, Range 9
West, Sections 1 through 30, 35 and 36; Township 30 North, Range 10
West, Sections 1 through 18 and 24; Township 29 North, Range 8 West,
Sections 1 through 6; Township 29 North, Range 9 West, Sections 1 and
2, NMPM.
(ii) Depth. The Basin-Dakota Formation is defined as that interval
including the Graneros, Dakota, and Morrison Formations, and is found
below a depth of 7,251 feet as indicated on the Induction-Electrical and
Gamma Ray log from the El Paso Natural Gas Gartner No. 9 Well. The
average depth to the top of the Basin-Dakota Formation is 7,575 feet.
Gross thickness of the Basin-Dakota Formation ranges from 250 to 300
feet.
(121) Atoka Formation in Oklahoma. RM79-76-131 (Oklahoma -- 4) --
(i) Delineation of formation. The Atoka Formation of Pennsylvanian age
is located in Washita County, Oklahoma, in Sections 6 and 7, Township 9
North, Range 19 West and Sections 1, 2, 3, 10, 11, and 12, Township 9
North, Range 20 West. It is bounded above by the base of the
Pennsylvanian Des Moinesian Series, called ''Cherokee Group'' by
drillers and below by the top of the Pennsylvanian Morrowan Series,
called ''Morrow Shale'' by drillers.
(ii) Depth. The depth to the top of the designated interval varies
from approximately 10,850 to 12,150 feet below mean sea level. Its
thickness ranges from 2,200 to 2,800 feet.
(122) Garza Sand in Texas. RM79-76-141 (Texas-24).
(i) Delineation of Formation. The Garza Sand is found in Duval
County in Texas. The designated area is located approximately 3 miles
west of the city of Concepcion, Texas, in Railroad Commission District 4
and includes portions of the following surveys: Andres Garcia Heirs
Survey, Abstract 657; Santos Flores Survey, Abstract 475; R. Ramirez
Survey, Abstract 475; and Marcello Ynojosa Survey, Abstract 628.
(ii) Depth. The top of the Garza Sand ranges from a measured depth
of ^6,700 feet to approximately ^7,400 feet subsea.
(123) Anacacho formation in Texas. RM79-76-145 (Texas-26).
(i) Delineation of formation. The Anacacho formation is located in
the northwestern part of Atascosa County, Texas, Railroad Commission
District 1 and is comprised of the following surveys: F. Brockinzen
A-90, Abram Cole A-158 and A-159, W. J. Viser A-873 and A-874, Craner
Ford A-247 and A-248, John C. Held A-368, John Sharp A-761, Robert C.
Rogers A-721, J. S. Joline A-500, H. P. Benningfield A-97, Wm. H.
Morris A-899, and Nepomucinco Flores A-244.
(ii) Depth. The Anacacho Formation in the Benton City Area is
encountered at measured depths ranging from 1,600 feet to 2,100 feet.
(124) Mancos ''B'' Formation in Utah. RM79-76-155 (Utah-7) -- (i)
Delineation of formation. The Mancos ''B'' Formation is located in
Carbon County, Utah and comprises all of Township 12 South, Range 13
East, SLM.
(ii) Depth. The Mancos ''B'' Formation is a distinct lithologic unit
of the Mancos Shale, occurring 200 to 300 feet below the top of the
Mancos Formation. The formation varies in thickness from 1,400 to 1,600
feet and is found at an average depth of 7,490 feet.
(125) Monte Christo, South (10,500') Formation in Texas. RM79-76
(Texas -- 25).
(i) Delineation of formation. The Monte Christo, South (10,500')
Formation is located in the southern portion of Hidalgo County, Texas,
Railroad Commission, District 4, and includes the following surveys:
Macedonia Jr. Vela No. 214, A-623; Tex. -- Mex. R.R. No. 215, A-130;
W. T. Bomar No. 218, A-626; Jas. L. Hudson, A-649; Walter A.
Hoffhein, A-797; W. H. Kozel, A-798; Tex. -- Mex. R.R. No. 217,
A-131; the northernmost 500 acres of both the Nicholas Zamora Porcion
No. 48, A-76 and the Torebio Zamora Porcion No. 49, A-78; and the
southernmost 900 acres of the northern 1,800 acres of the Francisco
Cantu Porcion No. 80, A-570.
(ii) Depth. The depth to the top of the Monte Christo, South
(10,500') Formation varies from 10,200 feet subsea to 10,600 feet
subsea. The maximum thickness of the formation is approximately 900
feet.
(126) Abo-Wolfcamp Formation in New Mexico. RM79-76-180 (New
Mexico-20).
(i) Delineation of formation. The Abo-Wolfcamp Formation is located
in Chaves County, New Mexico, in Township 15 South, Ranges 23, 24, and
25 East, All Sections; Townships 19 and 20 South, Range 20 East, All
Sections; in Eddy County, New Mexico in Township 16 South, Ranges 23,
24, and 25 East, All Sections; Township 16 South, Range 26 East,
Sections 4 through 9, 16 through 21, and 28 through 33; Township 17
South, Ranges 21, 23, and 24 East, All Sections; Township 17 South,
Range 25 East, Sections 1 through 12, 16 through 21, and 30 and 31;
Township 18 South, Ranges 21, 23, and 24 East, All Sections; Township
18 South, Range 25 East, Sections 6 and 7, 18 and 19, and 30 and 31;
Township 19 South, Ranges 21 and 23 East, All Sections; Township 19
South, Range 24 East, Sections 1 through 20, and 29 through 32;
Township 20 South, Ranges 21 and 23 East, All Sections; and Township 20
South, Range 24 East, Sections 5 through 8, NMPM
(ii) Depth. The average depth to the top of the Abo-Wolfcamp
Formation is 3,615 feet. The top and base of the Abo-Wolfcamp Formation
are found at 4,722 feet and 5,122 feet, respectively, as measured on the
Induction-Electrical Log of the Yates Petroleum Corporation State DF
well No. 1.
(127) Mesaverde Formation in Colorado. RM79-76-163 (Colorado-31).
(i) Delineation of formation. The Mesaverde Formation is located in
Rio Blanco County, Colorado, in Township 2 South, Range 96 West, Section
31 S 1/2, S 1/2, NW 1/4, Section 32 S 1/2, S 1/2, Section 33 SW 1/4, SW
1/4; Township 2 South, Range 97 West, Section 4 W 1/2, W 1/2, Sections
5, 8, 9, 16, 17, 20, 21, 22, All, Section 23 W 1/2, Section 25 SW 1/4,
Section 26 W 1/2, SE 1/4, Sections 27, 28, 29, 31 through 36, All;
Township 3 South, Range 97 West, Sections 3 through 7, All; all 6th
P.M.
(ii) Depth. The average depth to the top of the Mesaverde Formation
is approximately 7,790 feet. The producing interval is approximately
4,800 feet in thickness and begins at the base of the Ohio Creek
Conglomerate and extends to the top of the Marine Mancos Shale.
(128) Vicksburg Formation in the Portilla (9000') Field in Texas.
RM79-76 (Texas -- 29).
(i) Delineation of formation. The Vicksburg Formation in the
Portilla (9000') Field is located in the northern portion of San
Patricio County, Texas, Railroad Commission District 4, approximately
six miles northeast of Sinton, Texas, and underlies 15,000 acres of land
bounded by the Chiltipin Creek to the south, U.S. Highway 77 to the
west, and the Aransas River to the north. The eastern boundary is a
line extending from the Chiltipin Creek on the south to the Aransas
River on the north and approximately bisecting the following surveys;
Isaac Clover A-89, N.J. Devenny A-105, and Ralph Ellis Hrs. A-115.
(ii) Depth. The depth to the top of the Vicksburg Formation in the
Portilla (9000') Field varies between 8,600 feet and 9,000 feet and the
formation extends to depths in excess of 11,000 feet.
(129) Cleveland Formation in Texas. RM79-76 (Texas-18).
(i) Delineation of formation. The Cleveland Formation is found in
the northeast Texas Panhandle and consists of all of Lipscomb, Ochiltree
and Hansford Counties, virtually all of Hemphill County, approximately
the northern halves of Hutchinson and Roberts Counties, and
approximately the northeast quarter of Wheeler County, Texas.
(ii) Depth. The top of the Cleveland Formation is located near 2500
feet subsea to the west in Hansford County, Texas, and near 9700 feet
subsea in Wheeler County, Texas, to the southeast. The Cleveland
Formation is approximately 154 feet thick as demonstrated in a type log
from the Diamond Shamrock Corporation No. 1 J. A. Little Well in
Lipscomb County, Texas.
(130) Middle Wilcox (11,000-15,000') Formation in Texas. RM79-76
(Texas-27).
(i) Delineation of formation. The Middle Wilcox Formation is located
in Lavaca County, Texas, Railroad Commission District 2. The designated
area is located 14 miles east-southeast of the Halletsville, Texas, and
8 miles south-southeast of Sublime, Texas, and is comprised of the
following 15 surveys: James Ryan A-42, Miguel Muldoon A-34, E. W.
Perry A-359, Lev. T. Bostiok A-95, F. W. Perry A-358, P. Ansuldua
A-621, F. Baseldua A-622, Peter Garza A-632, J. A. Wynmaker A-499,
John W. Seymour A-431, H. I. and B.P.R. A-523, A. M. Gillespie A-633,
H. F. and W.T.R.R. A-551, H. E. and W.T.R.R. A-550, and North 1/3
John D. Ragsdale A-377.
(ii) Depth. The Middle Wilcox Formation is defined as that formation
which is encountered between 11,000 feet and 15,000 feet as measured on
the log of the Mitchell Energy Corporation C. F. Aschbacher No. 1
well. The top of the Middle Wilcox pay ranges in depth from
approximately ^11,200 feet in the north to ^13,300 feet in the south.
(131) Devonian Formation in Texas. RM79-76 (Texas -- 35).
(i) Delineation of the formation. The Devonian Formation is located
in the Nine Mile Draw Field area of Reeves County, Texas, Railroad
Commission District 8. The designated area consists of Sections 12, 13,
24, 25, 36 and 37 of T&P RR Block 55, and Sections 5, 6, 11, 12, 13, 14,
17, 18, 19, 20, 21, and 22 of T&P RR Block 54, TWP 7, Reeves County,
Texas.
(ii) Depth. The top of the Devonian Formation is encountered between
the measured depths of 13,080 and 14,120 feet, with an approximate
thickness of 100 feet.
(132) Fusselman Formation in Texas. RM79-76 (Texas -- 35).
(i) Delineation of the formation. The Fusselman Formation is located
in the Nine Mile Draw Field area of Reeves County, Texas, Railroad
Commission District 8. The designated area consists of Sections 12, 13,
24, 25, 36 and 37 of T&P RR Block 55, and Sections 5, 6, 11, 12, 13, 14,
17, 18, 19, 20, 21, and 22 of T&P RR Block 54, TWP 7, Reeves County
Texas.
(ii) Depth. The Fusselman Formation is encountered between the
measured depths of 13,340 and 14,396 feet, with an approximate thickness
of 80 feet.
(133) The Montoya Formation in Texas. RM79-76 (Texas -- 35).
(i) Delineation of the formation. The Montoya Formation is located
in the Nine Mile Draw Field area of Reeves County, Texas, Railroad
Commission District 8. The designated area consists of Sections 12, 13,
24, 25, 36 and 37 of T&P RR Block 55, and Sections 5, 6, 11, 12, 13, 14,
17, 18, 19, 20, 21, and 22 of T&P RR Block 54, TWP 7, Reeves County,
Texas.
(ii) Depth. The Montoya Formation is encountered between the
measured depths of 13,395 and 14,490 feet, with an approximate thickness
of 475 feet.
(134) Mesaverde Formation in New Mexico. RM79-76-179 (New
Mexico-19).
(i) Delineation of formation. The Mesaverde Formation is located in
San Juan County, New Mexico, Township 32 North, Range 8 West, NMPM,
Sections 7, 8, and 17 through 20. The Mesaverde Formation is in the
Blanco Mesaverde Gas Pool in the southwestern flank of the San Juan
Basin.
(ii) Depth. The Mesaverde Formation consists of three members: the
Cliffhouse member which average 50 feet in thickness, the Menefee member
with thickness range of 230 to 290 feet, and the Point Lookout member
which ranges from 150 to 200 feet in thickness. The vertical limits of
the Mesaverde Formation are from the Huerfanito Bentonite in the Lewis
Shale above to a point 500 feet below the top of the Point Lookout
member. The average depth to the top of the Mesaverde Formation is
5,600 feet.
(135) Morrow Formation in New Mexico. RM79-76-187 (New Mexico-22).
(i) Delineation of formation. The Morrow Formation is located in Lea
and Eddy Counties, New Mexico, in Township 19 South, Range 31 East,
Sections 27 S/2, 33 E/2, 34 and 35; Township 20 South, Range 30 East,
Sections 25, 26, 31 through 34, 35 N/2 and 36; Township 20 South, Range
31 East, Sections 1 through 36; Township 20 South, Range 32 East,
Sections 2 through 11, 14 through 23, and 26 through 35; Township 21
South, Range 28 East, Sections 1 and 2, 3: Lots 3, 4, 5, 6, 11, 12, 13,
14, and S/2, 4 through 20, 21 W/2, 22 through 25, 26 S/2, 27, 28, 29
S/2, and 30 through 36; Township 21 South, Range 29 East, Sections 1
through 7, 8 N/2, and 9 through 36; Township 21 South, Range 30 East,
Sections 1 through 12, 14 through 23, and 27 through 34; Township 21
South, Range 31 East, Sections 1 through 12; Township 22 South, Range
28 East, Sections 1 through 28, and 33 through 36; Township 22 South,
Range 29 East, Sections 1 through 36; Township 22 South, Range 30 East,
Sections 3 through 10, 13 W/2 W/2 and NE/4 NW/4, 14 through 23, 24 W/2
NW/4, and 26 through 36; Township 23 South, Range 29 East, Sections 1
through 3, 10 through 12, 13 W/2 14, 15, 22 through 27, and 34 through
36; Township 23 South, Range 30 East, Sections 1 through 17, 18 S/2 and
19 through 36; Township 23 South, Range 31 East, Sections 19, 30, and
31; Township 24 South, Range 29 East, Sections 1 and 2, 11 through 14,
23 through 26, 35, and 36; Township 24 South, Range 30 East, Sections 1
through 7, 8 N/2, 9 through 16, 17 E/2, and 18 through 36; Township 24
South, Range 31 East, Sections 6, 7, 15 through 22, and 27 through 34;
Township 25 South, Range 30 East, Sections 1 through 36; Township 25
South, Range 31 East, Sections 3 through 10, 15 through 22, and 27
through 34; Township 26 South, Range 30 East, Sections 1 through 12;
Township 26 South, Range 31 East, Sections 3 through 10; NMPM
(ii) Depth. The Morrow Formation is defined as that interval located
stratigraphically above the Mississippian Barnett Shale and below the
Pennsylvanian Atoka Formations. The average depth to the top of the
Morrow Formation is 13,600 feet. The Morrow Formation varies in
thickness form 928 feet to 1,475 feet.
(136) Chacra Formation in New Mexico. RM79-76-188 (New Mexico-23).
(i) Delineation of formation. The Chacra Formation is located
approximately 30 miles southeast of the town of Bloomfield in
northwestern New Mexico in the southeastern portion of the San Juan
Basin. The Chacra Formation is located in all of Sections 4 through 8,
and the N/2 of Sections 9 and 10 in Township 25 North, Range 7 West,
NMPM; as well as all of Sections 5 through 9, 15 through 22, 26 through
36, the W/2 of Section 10, the S/2 of Section 14, and the SW/4 of
Sections 23 and 25 in Township 26 North, Range 7 West, NMPR, in Rio
Arriba County, New Mexico.
(ii) Depth. The type section for the Chacra Formations is found at a
depth of approximately 3,734 feet to 3,844 feet on an Induction Gamma
Ray Log from the Curtis J. Little Turner Well No. 2. The average depth
to the top of the Chacra Formation is 3,350 feet. Thickness of the
Chacra Formation ranges from 110 to 130 feet.
(137) Vicksburg Formation in Texas. RM 79-76-160 (Texas -- 30).
(i) Delineation of formation. The Vicksburg Formation is located in
southwestern Hidalgo County, Texas, Railroad District No. 4,
approximately 15 miles west of the city of McAllen. The area comprises
the westerly portion of the Los Ejidos de Renosa Viejo Survey A-70 and
is bounded on the west and north by the boundary lines of the
aforementioned survey. The eastern boundary is a line beginning at a
point on the north line of the survey 1,200 feet east of the
southwestern corner of the Yldifonso Ramirez Survey, A-584, and
extending south for a distance equal and parallel the length of the
western boundary line. The southern boundary is a line extending from
the south end of the eastern boundary westward to the Rio Grande River
which forms the remainder ot the southern boundary of the area.
(138) Devonian/Strawn/Detrital Formation in Texas. RM 79-76-170
(Texas -- 33).
(i) Delineation of formation. The Devonian/Strawn/Detrital Formation
is found in northeast Terrell County and adjacent portions of western
Crockett County in Texas. The designated area consists of the listed
portions of the following Terrell County surveys: Sections 10-31, 73,
Block 1, I&GN RR Co.; Section 19, Mrs. M. E. Hope; Section 21, J. M.
Anderson; Section 22, C. M. Shaw (J. D. Blair); Section 23 P. H.
Terry; Section 24, Mrs. N. King; Section 1, Block A-4, J McMurty;
Section 2 Block A-4, A. C. W.; Section 3 Block A-4, P. L. Kinman;
Section 4, Block A-4, F. Baumgarner; Section 5, Block A-4, J. H.
Felps; Section 6, Block A-4, J. L. Cunningham; Section 7, Block A-4,
J. A. Manes; Section 8, Block A-4, Mrs. A. Pride; Section 9 Block
A-4, Mrs. L. Martin; Section 10, Block A-4, I. N., Bloodworth;
Section 11, Block AJ-4, J. E. R.; Section 1-12, Block 176, TM RR;
Section 1-38, Block B-2, CCSD & RGNG; and the following Crockett County
surveys: Section 24-38, 40-42, 45, 48-50, Block 2, I&GN RR Co.; Section
39-46, Block ST, TC RR; Section 199, 200, L&SV; Section 48, Block ST,
TC RR; Section 13-20, Block 2, J. H. Gibson; Section 99, 100, Block
NN, GC & SF; Section 22, Block NN-2, WM. Hornsbuckle (A-4873);
Section 48 1/2, J. B. Brown; Section 1, Block NN, L. G. Moses;
Section 2, Block NN, W. L. Lacy; Section 3,4, Block NN, Robert Rankin;
Section 22-35, Block 1, I&GN RR Co.; Section 14, 22-24, west half of
25, Block 28, University Lands.
(ii) Depth. The top of the Strawn section of the
Devonian/Strawn/Detrital ranges from a measured depth of 8,442 feet in
the east to 10,200 feet in the southwest. The Strawn varies in
thickness from 28 feet in the east to 205 feet in the west. The top of
the Detrital section ranges from a measured depth of 8,500 feet in the
east to 10,310 feet in the southwest. The Detrital varies in thickness
from 46 feet in the east to 230 feet in the southwest. The top of the
Devonian section ranges from a measured depth of 8,570 feet in the east
to 10,900 feet in the southwest. The Devonian varies in thickness from
275 feet in the north central to 600 feet in the northwest. In the
western third of the designated area the Detrital and Devonian sections
are separated by a wedge of Mississippian age rock units up to 500 feet
thick.
(139) ''J'' Sand Formation in Colorado. RM79-76 (Colorado -- 35).
(i) Delineation of formation. The ''J'' Sand Formation is located in
Adams, Arapahoe, and Elbert Counties, Colorado; approximately 12 miles
east of the city of Denver. The ''J'' Sand Formation in Adams County
underlies Township 2 South, Range 63 West, Sections 7, 8, 18, 19, 30, 31
and S 1/2 of Section 32; Township 2 South, Range 64 West, Sections 10
through 15, 22 through 27, and 34 through 36; Township 2 South, Range
65 West, Sections 25 through 36; Township 3 South, Range 63 West,
Sections 1 through 12; Township 3 South, Range 64 West, Sections 1
through 36; Township 3 South, Range 65 West, Sections 1 through 36. In
Arapahoe County, the ''J'' Sand Formation underlies Township 4 South,
Range 64 West, Sections 1 through 30 and 32 through 36; Township 4
South, Range 65 West, Sections 1 through 30; Township 5 South, Range 63
West, Sections 1 through 36; Township 5 South, Range 64 West, Sections
1 through 5, 8 through 17, 20 through 29, and 32 through 36. In Elbert
County, the subject formation underlies Township 6 South, Range 63 West,
Sections 1 through 35; Township 6 South, Range 64 West, Sections 1
through 5, 8 through 17, 20 through 29, and 34 through 36; Township 7
South, Range 63 West, Sections 4 through 9, 16 through 21, and 28
through 33; Township 7 South, Range 64 West, Sections 1 through 3, 10
through 15, 22 through 27, and 34 through 36, all 6th p.m.
(ii) Depth. The ''J'' Sand Formation ranges in thickness from 40 to
95 feet, and begins at the base of the ''D'' Sand and extends to the top
of the Skull Creek Shale. The average depth to the top of the ''J''
Sand Formation is approximately 8,100 feet.
(140) ''Jones Sand member'' of the ''Cleveland Sand'' interval of the
Skiatook Group in Oklahoma. RM79-76-148 (Oklahoma -- 5).
(i) Delineation of formation. The ''Jones Sand member'' of the
''Cleveland Sand'' interval is found in Sections 1 through 4 and 9
through 12, Township 13 North, Range 2 East; Sections 4 through 8,
Township 13 North, Range 3 East; Sections 21 through 28 and 33 through
36, Township 14 North, Range 2 East; and Sections 19, 20 and 28 through
33, Township 14 North, Range 3 East, in Lincoln County, central
Oklahoma. The ''Jones Sand member'' consists of three quartz sandstone
zones (''upper,'' ''middle'' and ''lower'') and two interbedded zones of
predominantly shale.
(ii) Depth. The depth of the designated interval ranges from 3,910
to 4,500 feet, and it is approximately 200 feet thick. The top of the
designated interval is overlain by a shale zone (ranging from 200 to 280
feet in thickness), the ''Upper Cleveland sand'' and the ''Checkerboard
limestone'' of the Lower Skiatook Group; the base of the interval is
underlain by a shale zone (ranging from 100 to 150 feet in thickness)
which separates the ''Oswego limestone'' of the Marmaton Group (Des
Moinesian age) from the ''Lower Jones sand'' zone.
(141) Hosston B Zone in Louisiana RM79-76-192 (Louisiana-9)
(i) Leatherman Creek Field Area -- (A) Delineation of formation. The
Hosston B Zone is located in north Louisiana and underlies parts of the
Leatherman Creek Field, Claiborne Parish and includes Township 19 North,
Range 7 West, Sections 7 through 11, 14 through 23, and 26 through 35,
and Township 19 North, Range 8 West, Sections 12, 13, 24, 25 and 36.
(B) Depth. The top of the Hosston B Zone is measured at 8,260 feet
and the base at 10,000 feet giving a total thickness of 1,740 feet, on
the induction electric log of the McGoldrick Oil Company Bessie Sherrill
No. 1 well, located in Section 21 of Township 19 North, Range 7 West.
(ii) Bear Creek Field Area -- (A) Delineation of formation. The
Hosston B Zone Reservoir A, is located in north Louisiana and underlies
part of the Bear Creek Field, Bienville Parish and includes the south
three-quarters of Section 22, the west three-quarters of Section 26, and
all of Sections 27 and 28 of Township 16 North, Range 6 West.
(B) Depth. The top of the Hosston B Zone, Reservoir A, is measured
at 8,890 feet and the base at 9,801 feet, giving a total thickness of
911 feet, on the induction electric log of the Franks Petroleum, Inc.,
Lucius C. Gresham B No. 1 well located in the southeast quarter of
Section 28, Township 16 North, Range 6 West.
(142) Upper Mesaverde Formation. RM79-76-168 (Colorado -- 32).
(i) Delineation of formation. The Upper Mesaverde Formation is
located in Mesa County, Colorado, in Township 8 South, Range 98 West,
Section 25, N 1/2, SE 1/4, N 1/2SW 1/4, SE 1/4SW 1/4; Section 26, N
1/2, SW 1/4, NW 1/4SE 1/4; Sections 27 through 34; Section 35, W 1/2,
SE 1/4, W 1/2NE 1/4, SE 1/4NE 1/4; Section 36; Township 9 South, Range
98 West, Sections 1 through 12, 6th P.M.
(ii) Depth. The average depth to the top of the Upper Mesaverde
Formation is 500 feet. The Upper Mesaverde Formation is defined as that
formation which occurs between the top of the Cozzette-Corcoran members
and the base of the Wasatch Formation, including the Rollins member.
The Upper Mesaverde Formation averages 2,200 feet in thickness.
(143) Morrison Formation in Colorado. RM79-76 (Colorado-37)
(i) Delineation of formation. The Morrison Formation is located in
Mesa and Garfield Counties, Colorado, in Township 7 South, Ranges 95
through 100 West; Township 8 South, Ranges 95 through 100 West;
Township 9 South, Ranges 95 through 99 West; Township 9 South, Range
100 West, Sections 1 through 4, 9 through 16, 22 through 26, and 36;
Township 10 South, Ranges 95 through 99 West; Township 11 South, Ranges
95, 96 and 99 West; Township 11 South, Range 98 West, Sections 1
through 14, 23 and 24; and Township 11 South, Range 97 West, Sections 1
through 12, 17 through 20, 6th P.M.
(ii) Depth. The average depth to the top of the Morrison Formation
is 8,050 feet. The Morrsion Formation is overlain by the Dakota
Formation and consists of the upper Brushy Basin Member and the lower
Salt Wash Member. The Morrison Formation varies from 400 to 600 feet in
thickness.
(144) Cook Mountain Formation in Texas. RM79-76 (Texas -- 36).
(i) Delineation of formation. The Cook Mountain Formation is located
in Harris County, Texas, Railroad Commission District 3. The designated
area is the upper 275 feet of the formation as found in an area roughly
rectangular in shape and approximately 6.4 miles by 18.9 miles and
located approximately 2.5 miles northwest of the City of Houston, Texas.
(ii) Depth. The Cook Mountain Formation is found at subsea depths
ranging from ^7,300 feet in the west to ^8,000 feet in the southeast and
is identified as that formation occurring between the measured depths of
7,730 feet and 8,005 feet on the log of the Pringle Petroleum Inc. John
Ivy No. 1 well.
(145) Abo Formation in New Mexico. RM79-76 (New Mexico-21).
(i) Delineation of formation. The Abo Formation is located in San
Miguel County: Townships 10 and 11 North, Ranges 14 and 15 East;
Torrance County: Townships 1 through 9 North, Ranges 14 and 15 East;
Guadalupe County: Townships 2 through 4 North, Ranges 16 through 19
East, Township 5 North, Ranges 16 through 23 East, Township 6 North,
Ranges 16 through 24 East, and Townships 7 through 11 North, Ranges 16
through 26 East; DeBaca County: Townships 1 through 4 North, Ranges 20
through 27 East, Township 5 North, Ranges 24 through 26 East, Township 6
North, Ranges 25 and 26 East, Township 1 South, Ranges 20 through 27
East, Township 2 South, Ranges 20 and 21 East, and Township 3 South,
Range 21 East; Lincoln County: Township 1 North, Ranges 16 through 19
East, Townships 1 through 5 South, Ranges 14 through 19 East, Township 6
South, Ranges 15 through 20 East, Townships 7 through 9 South, Ranges 15
through 20 East, excepting, however, all lands within the Capitan
Wilderness Area, Townships 10 and 11 South, Ranges 15 through 20 East,
and Townships 12 and 13 South, Ranges 17 through 20 East; Chaves
County: Township 3 South, Range 20 East, Townships 4 and 5 South,
Ranges 20 and 21 East, Townships 6 through 11 South, Range 21 East,
Township 12 South, Ranges 21 and 21 1/2 East, Township 13 South, Range
21 East, and Township 14 South, Ranges 17 through 21 East, NMPM,
containing some 5,775,360 acres, more or less, and designated by New
Mexico as the Pecos Slope Extension Area.
(ii) Depth. The Abo Formation, for designation as a tight formation
in the Pecos Slope Extension Area, shall be defined as being from the
base of the Yeso Formation vertically downward to the top of the Hueco
Limestone, or in the absence of said Hueco lime, to the top of the
Pennsylvanian Limestone, or in the absence of both Hueco lime and
Pennsylvanian lime, to the top of the Pre-Cambrian, provided, however,
that tongues of the Hueco lime overlain and underlain by the Abo
mudstones, sand or shales, shall be considered to be part of the Abo
Formation. The average depth to the top of the Abo Formation is 3,025
feet. The average thickness of the Abo Formation is 1,058 feet.
(146) Frontier Formation in Wyoming. FM79-76-151 (Wyoming-14).
(i) Delineation of formation. The Frontier Formation is located in
Fremont County, Wyoming, in the Wind River Basin of central Wyoming.
The Frontier Formation underlies Township 1 South, Range 4 East,
Sections 13 through 15, 22 through 27, and 34 through 36; Township 1
South, Range 5 East, Sections 16 through 21 and 28 through 33; Township
2 South, Range 4 East, Sections 1 through 3 and 10 through 12; and
Township 2 South, Range 5 East, Sections 4 through 9.
(ii) Depth. The Frontier Formation has an average gross thickness of
950 feet. The average depth to the top of the first productive
sandstone member of the Frontier Formation is 8,188 feet.
(147) Muddy Formation in Wyoming. RM79-76-152 (Wyoming-15).
(i) Delineation of formation. The Muddy Formation is located in
Fremont County, Wyoming, in Township 1 South, Range 4 East, Sections 13
and 14, 23 through 26, 35 and 36; Township 1 South, Range 5 East,
Sections 17 through 20, and 29 through 32; Township 2 South, Range 4
East, Sections 1, 2, 11 and 12; Township 2 South, Range 5 East,
Sections 5 through 8.
(ii) Depth. The Muddy Formation lies between the base of the Shell
Creek Formation and the top of the Dakota Formation. The average depth
to the top of the Muddy Formation is 9,337 feet.
(148) Dakota Formation in Wyoming. RM79-76-152 (Wyoming-15).
(i) Delineation of formation. The Dakota Formation is located in
Fremont County, Wyoming, in Township 1 South, Range 4 East, Sections 13
and 14, 23 through 26, 35 and 36; Township 1 South, Range 5 East,
Sections 17 through 20, and 29 through 32; Township 2 South, Range 4
East, Sections 1, 2, 11 and 12; Township 2 South, Range 5 East,
Sections 5 through 8.
(ii) Depth. The Dakota Formation lies between the base of the Muddy
Formation and the top of the Lakota Formation. The average depth to the
top of the Dakota Formation is 9,514 feet.
(149) Lakota Formation in Wyoming. RM79-76-152 (Wyoming-15).
(i) Delineation of formation. The Lakota Formation is located in
Fremont County, Wyoming, in Township 1 South, Range 4 East, Sections 13
and 14, 23 through 26, 35 and 36; Township 1 South, Range 5 East,
Sections 17 through 20, and 29 through 32; Township 2 South, Range 4
East, Sections 1, 2, 11 and 12; Township 2 South, Range 5 East,
Sections 5 through 8.
(ii) Depth. The Lakota Formation lies between the base of the Dakota
Formation and the top of the Morrison Formation. The average depth to
the top of the Lakota Formation is 9,639 feet.
(150) Monteagle Formation in Tennessee. RM79-76 (Tennessee-1)
(i) Delineation of formation. The Monteagle Formation is found in
Morgan, Scott, and portions of Fentress Counties located in the
north-central part of the State of Tennessee.
(ii) Depth. The average depth to the top of the Monteagle Formation
is 1,100 feet. The thickness varies from 180 to 250 feet.
(151) Mid Cockfield Sand in Louisiana. RM79-76-193 (Louisiana-10).
(i) Delineation of formation. The Mid Cockfield Sand is found in the
Krotz Springs Field in St. Landry Parish, Louisiana. The area includes
all or parts of Township 6 South, Range 7 East, Sections 12, 13, 14, and
19 through 24; Township 7 South, Range 7 East, Sections 5 and 6;
Township 6 South Range 6 East, Sections 24, 25, 26, 35 and 36; and
Township 7 South, Range 6 East, Section 1.
(ii) Depth. The depth to the top of the structure in Section 21,
Township 6 South Range 7 East, the top of the structure in Section 21,
Township 6 South, Range 7 East, the top of the Mid Cockfield Sand is
found at 10,670 feet and the base at 10,740 feet (log depths) on a type
log located on the eastern flank of a large domal structure, the Gulf
Oil Corporation KZS SU FU No. 51 well located in Section 20, Township 6
South, Range 7 East. On the top of the structure in Section 21,
Township to South, Range 7 East, the top of the Mid Cockfield Sand is at
an approximate log depth of 10,410 feet. The approximate thickness of
the sand is 70 feet.
(152) The Morrow Formation in New Mexico. RM79-76-199 (New
Mexico-24)
(i) Delineation of formation. The Morrow Formation underlies all of
Sections 25 and 36, Township 23 South, Range 26 East.
(ii) Depth. The top of the Morrow Formation is found at an average
depth of 11,553 feet and the Morrow Formation is approximately 190 feet
in thickness.
(153) Dakota Formation in Colorado. RM79-76-197 (Colorado -- 36)
(i) Delineation of formation. The Dakota Formation is located at
Township 11 South, Range 95 West, 6th P.M., Sections 1 through 36
inclusive and Township 11 South, Range 96 West, 6th P.M., Sections 1
through 36, inclusive. The designated area is roughly rectangular in
shape and consists of approximately 50,830 acres.
(ii) Depth. The average depth to the top of the Dakota Formation is
8,100 feet.
(154) The Vicksburg (12,000' Boyt Sand) Formation in Texas.
RM79-76-158 (Texas -- 28).
(i) Delineation of formation. The Vicksburg (12,000' Boyt Sand)
Formation is located in Hidalgo County, Texas, Railroad Commission
District 4. The designated area is within a 2.5 mile radius, the center
point of which is located 18,275 feet south and 1,800 feet east of the
northwest corner of the Dyonisio Ramirez Porcion 79, Abstract No. 563.
(ii) Depth. The Vicksburg (12,000' Boyt Sand) Formation is
identified as that formation occurring between the measured depths of
11,802 feet and 12,186 feet on the induction electrical log of the CNG
Producing Company Boyt No. 1 Well.
(155) Plainview Formation in Colorado. RM79-76-153 (Colorado-30).
(i) Delineation of formation. The Plainview Formation is located in
Adams and Weld Counties, Colorado, in Township 1 North, Range 67 West,
Sections 31 through 33; Township 1 South, Range 67 West, Sections 1
through 36; and Township 1 South, Range 68 West, Sections 1 through 36,
6th P.M.
(ii) Depth. The average depth to the top of the Plainview Formation
is 8,586 feet. The producing interval is approximately 78 feet in
thickness and begins at the base of the Skull Creek Shale and extends to
the top of the Lakota Formation.
(156) Bear River Formation in Wyoming. RM79-76-209 (Wyoming -- 17).
(i) Delineation of formation. The Bear River Formation is found in
Lincoln, Sublette and Sweetwater Counties, Wyoming, in Townships 25 and
26 North, Range 109 West, All; Township 26 North, Range 112 West,
Northeast 1/4; Township 27 North, Range 112 West, East 1/2; Township
28 North, Range 112 West, West 1/3; Township 28 North, Range 113 West,
Northeast 1/4; Township 29 North, Range 111 West, West 1/2; Township
29 North, Range 112 West, All; Township 29 North, Range 113 West,
Sections 1 through 27, and 34 through 36; Townships 30 and 31 North,
Ranges 112 and 113 West, All; 6th P.M.
(ii) Depth. The Bear River Formation's vertical limits are defined
by the Mowry Shale Formation above and the Thermopolis Shale Formation
below. The gross thickness of the formation varies from 10 to 40 feet.
The average depth to the top of the Bear River Formation is 9,000 feet.
(157) Austin Chalk Formation in Texas. RM79-76-212 (Texas -- 38).
(i) Delineation of formation. The Austin Chalk Formation is found in
Grimes County, Texas, Railroad Commission District 3. The area lies
within a 2.5 mile radius around the Tenneco Oil Company L. R. Fuqua
No. 1 well, located 5,200 feet from the north line and 1,500 feet from
the east line of the John Bowman Survey, A-7.
(ii) Depth. The Austin Chalk Formation in the designated area is
defined as the stratigraphic interval above the Eagleford Formation and
below the Pecan Gap Formation. The top of the Austin Chalk Formation is
found at 12,210 feet subsea, with the base at 12,484 feet subsea, in the
L. R. Fuqua No. 1 Well.
(158) Upper Wilcox (Mackhank) (First Tom Lyne) Formation in Texas.
RM79-76-162 (Texas -- 31).
(i) Delineation of formation. The Upper Wilcox (Mackhank) (First Tom
Lyne) Formation is located in the southwestern portion of Live Oak
County, Texas, Railroad Commission District 2, approximately five miles
east of the townsite of Clegg, Texas, and consists of the following
surveys: A. B. & M. 167 A-47, and 173 A-50, B. S. & F. 301 A-741, 29
A-132, 251 A-113, 253 A-114, 255 A-115, 257 A-116, 259 A-117, 177 A-92,
261 A-118, 181 A-94, 263 A-19, 265 A-120, 175 A-81, and 179 A-93, F. L.
Beall 178 A-823, R. H. Brown 526 A-734, and 525 A-732, R. F. Byler 530
A-999, T. J. Davis 32 A-567, A. A. Dinn 182 A-941, 82 A-940, and 90
A-939, James Dinn 296 A-942, J. A. Dowdy 298 A-944, and 266 A-919, C.
R. Evans 36 A-969, and 176 A-945, G. H. & RR. 1 A-198, G. M. & D. 4
A-214, F. E. Goodwin 2 A-640, H & G. N. RR. 45 A-249, and 47 A-248,
D. Harris 7 A-235, J. A. Harrymans 174-A-922, Hooper & Wade 303 A-251,
James Latham 3 A-275, R. McCampbell 262 A-929, 96 A-928, 94 A-927, and
50 A-926, Jno. McClane 48 A-765, L. A. McIntosh 31 A-542, J.
Poitevent 95 A-378, 93 A-377, 49 A-350, 35 A-347, 31 A-363, 29 A-359, 95
A-1084, 91 A-376, and 89 A-375, Joe Russell 36 A-932, S. K. & K. 297
A-515, Pat Sheeran 254 A-783, O. B. & E. E. Shipp 92 A-811, J. M.
Torres 62 A-884, O. Torres 60 A-882, Pedro Torres 61 A-883, 264 A-1023
and A-1083, and 50 A-1036 and A-926, W. Tullos 3 A-1037, G. I.
Vanmeter 168 A-848, and 46 A-847, Geo. W. West 408 A-794, and 260
A-818, Ike West 3 A-822, Isaac West 258 A-819, and 186 A-820, Jacob
White 174 A-955, O. P. Williams 6 A-487, W. Williams 67 A-908, and
Jessie Wilson 2 A-995.
(ii) Depth. The average depth to the top of the Upper Wilcox
(Mackhank) (First Tom Lyne) Formation is approximately 14,000 feet and
the thickness is between 300 feet and 400 feet.
(159) Lower Vicksburg (P though S) Sandstone in Texas. RM 79-76-202
(Texas -- 37).
(i) Delineation of formation. The Lower Vicksburg (P through S)
Sandstone is located in Hidalgo County, Texas, Railroad Commission
District 4, approximately seven miles east of the city of La Reforma and
includes approximately 16,000 acres in the north part of the ''Santa
Anita'' Manuel Gomez A-63 Grant.
(ii) Depth. The top of the Lower Vicksburg (P through S) Sandstone
is the top of the ''P'' sand which occurs at an average depth of about
10,600 feet in the western portion of the designated area. In the east,
the ''P'' sand is found at a depth of about 12,000 feet. The top of the
lowermost section of the designated sandstone, the ''S'' sand, occurs at
an average depth of about 13,500 feet in the west. In the east, the
''S'' sand is found at a depth of about 13,000 feet. Total thickness is
approximately 4,000 feet.
(160) Lower Mississippian Little Valley Formation in Virginia.
RM79-76-211 (Virginia -- 2).
(i) Delineation of formation. The Lower Mississippian Little Valley
Formation is found in Scott and Washington Counties, Virginia. The
designated area consists of approximately 89 square miles comprising all
of the Mendota and Wallace quadrangles south of the Holston River in
Virginia.
(ii) Depth. The average depth to the top of the Lower Mississippian
Little Valley Formation is 3,191 feet. The formation has an average
thickness of 673 feet.
(161) Berea Sandstone in Kentucky. RM79-76-210 (Kentucky-2).
(i) Delineation of formation. The Berea Sandstone (called Berea grit
by drillers) encompasses all of Pike County, Kentucky, with the
exception of 14 irregularly-shaped areas as shown on maps on file with
the Commission.
(ii) Depth. The Berea Sandstone occurs near the base of
Mississippian-age deposits between the Sunbury Shale (called Coffee
shale by drillers) and the Ohio Shale (called Devonian shale by
drillers). The average depth of the top of the Berea Sandstone is 2,400
feet in western Pike County and increases to 3,500 feet in the eastern
part of the county; however, the range of the depth to the top of the
Berea is from the surface to 4,617 feet.
(162) ''Big Lime'' Zone of the Greenbrier Group in West Virginia. RM
79-76-244 (West Virginia-2 Addition).
(i) Delineation of formation. The ''Big Lime'' Zone of the
Greenbrier Group is defined as the stratigraphic interval overlying the
''Keener'' and ''Big Injun'' Zones of the Pocono Group and underlying
the ''Blue Monday'' and ''Little Lime'' Zones of the Mauch Chunk Group.
The ''Big Lime'' Zone is found in portions of Fayette, McDowell,
Raleigh, Wyoming, Boone, Cabell, Kanawha, Lincoln, Logan, Mingo, Putman,
and Wayne Counties and all of Mercer County.
(ii) Depth. The depth to the top of the ''Big Lime'' Zone ranges
from approximately 1,375 feet in the northwest portion to 3,100 feet
along the eastern edge and ranges in thickness from approximately 150
feet in the west to a maximum thickness of approximately 1,800 feet in
the southeastern portion of the designated area.
(163) Dakota Formation in Colorado. RM79-130 (Colorado -- 28).
(i) Delineation of formation. The Dakota Formation is located in
Garfield, Mesa, and Rio Blanco Counties, Colorado, in all or parts of
Townships 1 North, 1 South, 2 South, 3 South, Ranges 100 through 104
West, 6th P.M., Townships 4 and 5 South, Ranges 102 through 104 West,
6th P.M., Townships 6 through 8 South, Ranges 103 through 105 West, 6th
P.M., Townships 9 and 10 South, Ranges 103 and 104 West, 6th P.M., and
Townships 1 and 2 North, Ranges 2 and 3 West, Ute P.M.
(ii) Depth. The Dakota Formation is overlain by the Dakota Silt and
is underlain by the Morrison Formation. The average thickness is about
150 feet. The average depth to the top of the Dakota Formation is 5,450
feet.
(164) Morrison Formation in Colorado. RM79-76-130 (Colorado -- 28).
(i) Delineation of formation. The Morrison Formation is located in
Garfield, Mesa, and Rio Blanco Counties, Colorado, in all or parts of
Townships 1 North, 1 South, 2 South, and 3 South, Ranges 100 through 104
West, 6th P.M., Townships 4 and 5 South, Ranges 102 through 104 West,
6th P.M., Townships 9 and 10 South, Ranges 103 and 104 West, 6th P.M.,
and Townships, 1 and 2 North, Ranges 2 and 3 West, Ute P.M.
(ii) Depth. The Morrison Formation is overlain by the Dakota
Formation and is underlain by the Entrada Formation. The thickness
ranges from about 300 to more than 600 feet. The average depth to the
top of the Morrison Formation is 5,590 feet.
(165) Granite Wash Formation in Texas. RM79-76-164 (Texas -- 32).
(i) Delineation of formation. The Granite Wash Formation in the
Anadarko Basin is located in the panhandle area of Texas Railroad
Commission District 10. The designated area includes all of Hemphill
and Roberts Counties; Sections 45 through 396 of Block 43, H&TC RR
Survey, Lipscomb and Ochiltree Counties; Sections 89 through 152 of
Block 13, T&NO RR Survey, Ochiltree County; and all sections north of
an east-west line passing through the southern boundary of Section 21,
Block A-9 in Wheeler County except Sections 3, 5, and 6, A.B.&M.
Survey, and Section 4, Block L, J.M. Lindsey Survey.
(ii) Depth. The Granite Wash Formation is that interval from the top
of the A-1 zone to the base of the Granite Wash Formation. The top of
the A-1 zone ranges in depth from 6,934 feet in Roberts County to 11,386
feet in Wheeler County.
(166) Niobrara Formation in Colorado. RM79-76-226 (Colorado-38).
(i) Delineation of formation. The Niobrara Formation is located in
Weld County, Colorado, in Township 4 North, Range 68 West, Sections 4
through 6; and in Larimer County, Colorado, in Township 4 North, Range
69 West, Sections 1 through 10, 15 through 22; Township 5 North, Range
68 West, Sections 19 through 21, 28 through 33; Township 5 North, Range
69 West, Sections 25 through 36, 6th P.M.
(ii) Depth. The average depth to the top of the Niobrara Formation
is 3,000 feet. The Niobrara Formation averages 300 feet in thickness.
(167) Muddy Formation in Wyoming. RM79-76-189 (Wyoming-16).
(i) Delineation of formation. The Muddy Formation is located in
Natrona County, Wyoming, in Township 36 North, Range 86 West, 6th P.M.,
Sections 4 through 9, Sections 15 through 22, and Sections 28 through
30; Township 36 North, Range 87 West, 6th P.M., Sections 1 through 3,
Sections 11 through 14, NE 1/4 of Section 23, and N 1/2,, N 1/2 S 1/2 of
Section 24; Township 37 North, 86 West, 6th P.M., Sections 19, 20, and
28 through 33; Township 37 North, Range 87 West, 6th P.M., Sections 23
through 26, and Sections 35 and 36.
(ii) Depth. The vertical limits of the Muddy Formation are defined
as the Mowry Shale above, and the Thermopolis Shales below. The average
depth to the top of the formation is 19,800 feet.
(168) Lakota Formation in Wyoming. RM79-76-189 (Wyoming-16).
(i) Delineation of formation. The Lakota Formation is located in
Natrona County, Wyoming, in Township 36 North, Range 86 West, 6th P.M.,
Sections 4 through 9, Sections 15 through 22, and Sections 28 through
30; Township 36 North, Range 87 West, 6th P.M., Sections 1 through 3,
Sections 11 through 14, NE 1/4 of Section 23, and N 1/2, N 1/2 S 1/2 of
Section 24; Township 37 North, 86 West, 6th P.M., Sections 19, 20, and
28 through 33; Township 37 North, Range 87 West, 6th P.M., Sections 23
through 26, and Sections 35 and 36.
(ii) Depth. The vertical limits of the Lakota Formation are defined
as the Thermopolis Shale above, and the Morrison Shale below. The
average depth to the top of the formation is 20,020 feet.
(169) Morrison Formation in Wyoming. RM79-76-189 (Wyoming-16).
(i) Delineation of formation. The Morrison Formation is located in
Natron County, Wyoming in Township 36 North, Range 86 West, 6th P.M.,
Sections 4 through 9, Sections 15 through 22, and Sections 28 through
30; Township 36 North, Range 87 West, 6th P.M., Sections 1 through 3,
Sections 11 through 14, NE 1/4 of Sections 23, and N 1/2, N 1/2 S 1/2,
of Section 24; Township 37 North, 86 West, 6th P.M., Sections 19, 20
and 28 through 33; Township 37 North, Range 87 West, 6th P.M., Sections
23 through 26, and Sections 35 and 36.
(ii) Depth. The vertical limits of the Morrison Formation are
defined as the Lakota Shale above, and the Sundance Shale below. The
average depth to the top of the formation is 20,100 feet.
(170) Sundance Formation in Wyoming. RM79-76-189 (Wyoming-16).
(i) Delineation of formation. The Sundance Formation is located in
Natrona County, Wyoming, in Township 36 North, Range 86 West, 6th P.M.,
Sections 4 through 9, Sections 15 through 22, and Sections 28 through
30; Township 36 North, Range 87 West, 6th P.M., Sections 1 through 3,
Sections 11 through 14, NE 1/4 of Section 23, and N 1/2, N 1/2 S 1/2 of
Section 24; Township 37 North, 86 West, 6th P.M., Sections 19, 20, and
28 through 33; Township 37 North, Range 87 West, 6th P.M., Sections 23
through 26, and Sections 35 and 36.
(ii) Depth. The vertical limits of the Sundance Formation are
defined as the Morrision Shale above, and the Triassic Shale below. The
average depth to the top of the formation is 20,300 feet.
(171) Vicksburg Formation in Texas. RM79-76-088 (Texas 15).
(i) The Deep Vicksburg Formation in Starr County, Texas.
(A) Delineation of formation. The Deep Vicksburg Formation covers an
area of approximately 4.8 square miles in portions of the Ygnacio Flores
A-725 and Nicolasa Salinas A-411 surveys located in eastern Starr
County, Texas, Railroad Commission District 4.
(B) Depth. The top of the Deep Vicksburg Formation is defined as the
top of the 9250 sand, or the unconformity where the 9250 sand has been
eroded. The base of the formation is the base of the V-23 sand.
(ii) The Lower Vicksburg Formation in Starr County, Texas.
(A) Delineation of formation. The Vicksburg Formation is located in
Railroad Commission District 4 in the eastern half of Starr County,
Texas.
(B) Depth. The top of the Vicksburg Formation is defined as the top
of the Rincon Sand and the base as the top of the Yegua sand.
Specifically, it is defined as that interval on the log of the Corpus
Christi Oil and Gas Company, Heard 1 Well that occurs between a
measured depth of 8,260 feet to 10,836 feet, which yields a gross
thickness of 2,217 feet.
(172) Injun Zone of the Pocono Group in West Virginia. RM79-76-137
(West Virginia-1 Addition II).
(i) Delineation of formation. The Injun Zone is a depositional unit
of Mississippian age. It is located in the Appalachian Basin in Boone,
Cabell, Kanawha, Lincoln, Logan, Mingo, Putnam and Wayne Counties, in
southwestern West Virginia, with certain specified excluded areas. (A
map showing the excluded areas is on file with the Commission.)
(ii) Depth. The designated zone has a depth ranging from 1,200 feet
to 3,000 feet. The top of the zone is marked by the base of the
Greenbrier Group, and the zone is separated below from the Berea
Sandstone of the Pocono Group by an interval of interbedded sandstones
and shales (which may include the Squaw and Weir zones) ranging from 350
to 700 feet thick. The Injun zone has a thickness ranging from 10 to 75
feet.
(173) Squaw zone of the Pocono Group in West Virginia. RM79-76-127
(West Virginia-1 Addition II).
(i) Delineation of formation. The Squaw zone is a depositional unit
of Mississippian age. It is located in the Appalachian Basin in Boone,
Cabell, Kanawha, Lincoln, Logan, Mingo, Putnam, and Wayne Counties in
Southwestern West Virginia, with certain specified excluded areas. (A
map showing the excluded areas is on file with the Commission.)
(ii) Depth. The designated zone has a depth ranging from 1,250 to
3,000 feet where it is present in the stratigraphic sequence. The zone
is separated from the Greenbrier Group above by a sequence of
interbedded sandstones and shales (which may include the Injun zone)
ranging from 10 to 75 feet thick. It is separated below from the Berea
Sandstone by a sequence of sandstones and shales (which may include the
Weir zone) approximately 450 feet thick. The zone has a thickness
ranging from 0 to 10 feet.
(174) Weir zone of the Pocono Group in West Virginia. RM79-76-127
(West Virginia-1 Addition II).
(i) Delineation of formation. The Weir zone is a depositional unit
of Mississippian age. It is located in the Appalachian Basin in Boone,
Cabell, Kanawha, Lincoln, Logan, Mingo, Putnam, and Wayne Counties in
southwestern West Virginia, with certain specified excluded areas. (A
map showing the excluded areas is on file with the Commission.)
(ii) Depth. The designated zone has a depth ranging from 2,000 to
2,250 feet where it exists in the stratigraphic sequence. The zone is
separated from the Greenbrier Group above by a sequence of interbedded
sandstones and shales (which may include the Injun and Squaw zones)
ranging from 100 to 200 feet thick. It is separated from the Berea
Sandstone below by a sequence of interbedded sandstones and shales
approximately 400 feet thick. The zone has a thickness ranging from 0
to 100 feet.
(175) Berea Sandstone of the Pocono Group in West Virginia.
RM79-76-127 (West Virginia-1 Addition II).
(i) Delineation of formation. The Berea Sandstone is a depositional
unit of Mississippian age. It is located in the Appalachian Basin in
Boone, Cabell, Kanawha, Lincoln, Logan, Mingo, Putnam, and Wayne
Counties in southwestern West Virginia, with certain specified excluded
areas. (A map showing the excluded areas is on file with the
Commission.)
(ii) Depth. The designated formation has a depth ranging from 1,600
to 3,450 feet. The formation is separated from the Greenbrier Group
above by a sequence of interbedded shales and sandstones (which may
include the Injun, Squaw, and Weir zones) ranging from 360 to 775 feet
thick. It overlies the Bedford Shale of Mississippian age, where
present, or shales of Devonian age. The formation ranges from 5 to 125
feet thick.
(176) Venango Group in Pennsylvania. RM79-76-206 (Pennsylvania --
2).
(i) Delineation of formation. The Venango Group underlies Fayette,
Westmoreland, Indiana Counties, Jefferson County excluding the townships
of Barnett and Heath, and eastern Armstrong County including the
townships of Pine, Mahoning, Redbank, Wayne, Boggs, Rayburn, Valley,
Cowanshannock, Plumcreek, Kittanning, Manor, Bethel, Burrell, South
Bend, Kiskiminetas, Parks, and Gilpin. Excluded from the designated
area are any known ''sweet spots,'' and all areas identified by
Pennsylvania in its recommendation on July 5, 1983, as gas storage areas
or oil pools. The Venango Group consists of a sequence of interbedded
sandstones and shales of the Upper Devonian System. The Venango Group
is the younger of two Upper Devonian sand packages which are bounded by
the overlying Mississippian Pocono Group and the underlying Upper
Devonian Brallier Shale or its equivalent. The following sands are
included in the Venango Group: Hundred Foot, Shannopin, Fifty Foot,
Gantz, Upper Nineveh, Lower Nineveh, Snee, Boulder, Hickory, Blue
Monday, Gordon, Gordon Stray, 2nd Butler, 1st Venango, Rosenberry, 2nd
Venango, Shira, 3rd Venango, 3rd Venango Stray, 3rd, 4th and 5th Knox,
Clarion, Byram, Fifth, Bayard, and Elizabeth.
(ii) Depth. The average subsurface depth to the top of the Venango
Group is approximately 1,500 feet. The thickness of the formation
ranges from 500 feet along the western edge of the designated area to
800 feet along the eastern edge.
(177) Bradford Group in Pennsylvania. RM79-76-207 (Pennsylvania --
3).
(i) Delineation of formation. The Bradford Group underlies Fayette,
Westmoreland, and Indiana Counties, Jefferson County excluding the
townships of Barnett and Heath, and eastern Armstrong County including
the townships of Pine, Mahoning, Redbank, Wayne, Boggs, Rayburn, Valley,
Cowanshannock, Plumcreek, Kittanning, Manor, Bethel, Burrell, South
Bend, Kiskiminetas, Parks, and Gilpin. Excluded from the designated
area are any known ''sweet spots,'' and all areas identified by
Pennsylvania in its recommendation on July 5, 1983, as gas storage areas
or oil pools. The Bradford Group consists of a sequence of interbedded
sandstones and shales of the Upper Devonian System. The Bradford Group
is the older of two sand packages which are bounded by the overlying
Mississippian Pocono Group and the underlying Upper Devonian Brallier
Shale or its equivalent. The following sands are included in the
Bradford Group: 1st and 2nd Warren, Speechley, Tiona, Balltown,
Sheffield, 1st, 2nd, and 3rd Bradford, and Kane.
(ii) Depth. The average subsurface depth to the top of the Bradford
Group is approximately 2,500 feet. The thickness of the formation
ranges from near zero along the western edge of the designated area to
approximately 1,300 feet along the eastern edge.
(178) Catskill/Lock Haven Formation in Pennsylvania. RM79-76-208
(Pennsylvania -- 4).
(i) Delineation of formation. The ''Catskill/Lock Haven'' Formation
underlies Cambria and Clearfield Counties, western Clinton County
including the townships of Noyes, Leidy, East Keating, and West Keating,
southern Cameron County including the townships of Grove and Gibson, and
southeastern Elk County including the townships of Benezette and Jay.
Excluded from the designated area are any known ''sweet spots,'' and all
areas identified by Pennsylvania in its recommendation on July 5, 1983,
as gas storage areas or oil pools. The ''Catskill/Lock Haven''
Formation consists of a sequence of interbedded sandstones and shales of
the Upper Devonian System which underlies the Mississippian Pocono Group
and overlies the Upper Devonian Brallier Shale or its equivalent. The
following sands are included in the ''Catskill/Lock Haven'' Formation:
Hundred Foot, Fifth, Bayard, Elizabeth, Warren, Speechley, Balltown,
Sheffield, Tiona, 1st, 2nd, and 3rd Bradford, and Kane.
(ii) Depth. The average subsurface depth to the top of the
''Catskill/Lock Haven'' Formation is approximately 1,400 feet. The
thickness of the formation ranges from approximately 1,500 to 3,500
feet.
(179) Pictured Cliffs Formation in New Mexico. RM79-76-204 (New
Mexico -- 25).
(i) Delineation of formation. The Pictured Cliffs Formation is
located in Rio Arriba and Sandoval Counties, New Mexico, in Township 22
North, Range 2, 3, 4 and 5 West, all; Township 23 North, Range 2 West,
Sections 5 through 9, 16 through 21, and 25 through 36; Township 23
North, Ranges 3, 4 and 5 West, all Sections; Township 24 North, Range 3
West, Sections 19, 20, 26 through 35, and S 1/2 of 36; Township 24
North, Range 4 West, Sections 3 through 10 and 13 through 36; Township
24 North, Range 5 West, all Sections; Township 25 North, Range 4 West,
Sections S 1/2 of 30, 31 and 32; Township 25 North, Range 5 West,
Sections 15 through 23 and S 1/2 of 24, and 25 through 36, NMPM.
(ii) Depth. The Picture Cliffs Formation is defined as that interval
at a depth of approximately 3,046 feet to 3,141 feet on the Induction
Electric Log from the John E. Schalk, Cinco Diablos Well No. 6. The
average depth to the top of the Pictured Cliffs Formation is 2,685 feet.
(180) Dakota Formation in New Mexico. RM79-76-218 (New Mexico --
26).
(i) Delineation of formation. The Dakota Formation is located in San
Juan County, New Mexico, in Township 25 North, Range 9 West, Section 16,
17 E 1/2, 28 W 1/2, 29 E 1/2 and 30 W 1/2 NMPM; Township 25 North,
Range 10 West, Section 25 W 1/2, NMPM.
(ii) Depth. The Dakota formation is defined as that interval at a
depth of approximately 6,234 feet to 6,599 feet on the Induction
Spherically Focused Log from the M.J. Brannon 28 No. 2 well. The
average depth to the top of the Dakota formation is 6,400 feet.
(181) ''Maxon'' sands of the Mauch Chunck Group and the
''Injun-Weir'' sands of the Pocono Group in Virginia. RM79-76-217
(Virginia -3)
(i) Delineation of formation. The ''Maxon'' sands and the
''Injun-Weir'' sands underlie all of Dickenson and Buchanan Counties and
portions of Lee, Scott, Wise, Russell, and Tazewell Counties, Virginia.
(ii) Depth. The average depth to the top of the ''Maxon'' sands
ranges from 2,610 feet in the eastern portion to 2,930 feet in the
western portion of the designated area. The average depth to the top of
the ''Injun-Weir'' sands ranges from 3,855 feet in the eastern portion
to 4,040 feet in the western portion of the designated area.
(182) Strawn Formation in Texas. RM79-232 (Texas -- 40).
(i) Delineation of formation. The Strawn Formation is found in the
western part of the State of Texas. The designated area lies primarily
in the extreme western part of Sutton County, and extends north into the
southwest part of Schleicher County, and to the west into the eastern
part of Crockett County.
(ii) Depth. The vertical limits of the Strawn Formation are defined
by the Canyon sand and shale formations above and the Atoka formation
below. The depth to the top of the formation is approximately 7,383
feet in the northeast part of the designated area and dips to 9,858 feet
in the southwest, having an average depth of 8,300 feet to the top of
the formation. In a type log, the Amoco Production Company Edwin S.
Mayer, Jr. No. C-8 well, located in the northern part of the designated
area, the thickness of the Strawn Formation is 306 feet. A gradual
thickening of the formation occurs toward the south part of the
designated area.
(183) Morrow Formation in New Mexico. RM79-76-234 (New Mexico-27).
(i) Delineation of formation. The Morrow Formation is located in Lea
County, New Mexico, in Township 24 South, Range 33 East, NMPM, Section
11 through 14, 23 through 26, and 35 and 36 Township 24 South, Range 34
East, NMPM, Section 8 S/2, 9 S/2, 14 W/2, 15 through 17, 19 through 22,
23 W/2, 26 W/2, 27 through 34, and 35 W/2.
(ii) Depth. The Morrow Formation has a gross pay thickness of
approximately 96 feet and begins at the base of the Atoka Formation and
extends to the top of the Chester Formation. The average depth to the
top of the Morrow Formation is 14,287 feet.
(184) Niobrara Formation in Colorado. RM79-76-235 (Colorado-39).
(i) Delineation of formation. The Niobrara Formation is located in
Weld County, Colorado, in Township 4 North, Range 66 West, 6th P.M.,
Sections 2 through 10, and 15 through 18; Township 5 North, Range 64
West, 6th P.M., Sections 1 through 24; Township 5 North, Range 65 West,
6th P.M., Section 1; Township 5 North, Range 66 West, 6th P.M.,
Sections 2 through 11, and 14 through 35; Township 5 North 67 West, 6th
P.M., Sections 1 through 3, 11 through 14, 23 and 24; Township 6 North,
Range 64 West, 6th P.M., Sections 7, and 13 through 36; Township 6
North, Range 65 West, 6th P.M., Sections 7 through 31, and 34 through
36; Township 6 North, Range 66 West, 6th P.M., Sections 6 through 36;
Township 6 North, Range 67 West, 6th P.M., all Sections; and in Larimer
County, Colorado, in Township 6 North, Range 68 West, 6th P.M., Sections
1 and 2, 11 through 14, 23 through 26, 35 and 36.
(ii) Depth. The Niobrara Formation is defined as that interval which
begins at a depth of approximately 6,900 feet and varies in thickness
from 280 feet to 320 feet.
(185) The Berea Sandstone and ''Second Berea'' zone of the Pocono
Group and the ''Gordon'' zone of the Hampshire Group in West Virginia.
RM79-76 (West Virginia -- 4).
(i) Delineation of formation. The Berea Sandstone, ''Second Berea''
zone, and ''Gordon'' zone underlie portions of Jackson, Mason, and Wood
Counties. The Berea Sandstone lies immediately below the Sunbury Shale
and the ''Gordon'' zone lies above the ''Brown Shale'' zone.
(ii) Depth. The average depth to the top of the Berea Sandstone and
''Second Berea'' zone ranges from 1,500 feet in western Mason County to
over 2,700 feet in eastern Jackson County. The average depth to the top
of the ''Gordon'' zone ranges from 2,538 feet in Wood County to 2,852
feet in Jackson County.
(186) Arbuckle Formation in Arkansas. RM79-76-223 (Arkansas-1).
(i) Delineation of formation. The Arbuckle Formation is found in
White County, Arkansas. The designated area includes Sections 1, 2, 11,
12, 13, and 14 of Township 8 North, Range 8 West, and Sections 6, 7, and
18 of Township 8 North, Range 7 West.
(ii) Depth. The Arbuckle Formation's vertical limits are defined by
the Everton Formation above and the Cambrian sequence below. The depth
to the top of the formation averages 6,400 feet and the gross thickness
varies from approximately 1,000 to 1,500 feet.
(187) ''Corniferous-Big Six'' Formation of the Hunton Group and the
''Clinton'' Formation of the Crab Orchard Group in Kentucky.
RM79-76-241 (Kentucky-4)
(i) Delineation of formations. The ''Corniferous-Big Six'' Formation
of the Hunton Group and the ''Clinton'' Formation of the Crab Orchard
Group is found in Lawrence and Johnson Counties, Kentucky. Several
areas in these counties are excluded from the designation and are shown
on maps on file with the Commission.
(ii) Depth. The average depth to the top of the ''Corniferous-Big
Six'' Formation ranges from 2,900 feet in the east to 1,750 feet in the
west and has a thickness ranging from 500 feet to 775 feet. It is
overlain by the Devonian Ohio Shale and underlain by the Silurian Rose
Hill Shale. The average depth to the top of the ''Clinton'' Formation
ranges from 2,460 feet in the west to 4,050 feet in the east and has
thickness ranging from 0 to 35 feet. It is overlain by the Rose Hill
Shale and underlain by the Brassfield Dolomite.
(188) Dakota Formation in Utah. RM79-76-136 (Utah-5).
(i) Delineation of formation. The Dakota Formation is located in
Grand and Uintah Counties, Utah, in the area of Township 12 South,
Ranges 21 through 25 East; Township 13 South, Ranges 20 through 26
East; Township 14 South, Ranges 20 through 26 East; Township 15 South,
Ranges 20, W/2 21, N/2 23, and 24 through 26 East; and Township 15 1/2
South, Range 24, Sections 33 through 36, and Ranges 25 and 26 East.
(ii) Depth. The Dakota Formation's vertical limits are defined by
the Dakota Silt Formation above and the Morrison Formation below. The
average thickness throughout the proposed area is approximately 200 feet
and the average depth to the top of the Dakota Formation is 8,925 feet.
(189) Niobrara Formation in Colorado. RM79-76-240 (Colorado-40).
(i) Delineation of formation. The Niobrara Formation is located in
Adams County, Colorado, in Township 1 South, Range 68 West, Sections 1
through 24; in Boulder County, Colorado, in Township 1 South, Range 69
West, Sections 1 through 24; Township 1 North, Range 69 West, Sections
1 through 36; and in Weld County, Colorado, in Township 1 North, Range
68 West, Sections 1 through 36, 6th P.M.
(ii) Depth. The average depth to the top of the Niobrara Formation
is 7,600 feet. The Niobrara Formation varies in thickness from 250 to
450 feet.
(190) Niobrara Formation in Colorado. RM79-76-245 (Colorado-40
Addition).
(i) Delineation of formation. The Niobrara Formation is located in
Adams County, Colorado, in Township 1 South, Range 67 West, Sections 1
through 36; Township 1 South, Range 68 West, Sections 25 through 36;
and in Weld County, Colorado, in Township 1 North, Range 67 West,
Section 32 S/2, 6th P.M.
(ii) Depth. The average depth to the top of the Niobrara Formation
is 7,500 feet. The Niobrara Formation varies in thickness from 250 to
450 feet.
(191) Strawn Formation in Texas. RM79-76-237 (Texas-40) Massie
(Strawn) Field, Crockett and Val Verde Counties.
(i) Delineation of formation. The designated area is located
approximately 25 miles south of Ozona, Texas, along the common Crockett
and Val Verde County lines. The designated area is specifically located
in the eastern half of Section 13; the entire portion of Sections 14,
15, 16, 25, 26, 27, 28, 52, 53, 54, 55, 56, 65, 66, 67, 68, 69, 92, 93,
94, 95, 96, 105, 106, 107, 108 and 109 of Block O, GH & SA RR Survey;
Section 95 of Block A, TC RR Survey; and Section 182 of Block O, M.A.
Sharp Survey.
(ii) Depth. The average depth to the top of the designated area is
11,165 feet and the thickness varies from approximately 200 feet on the
top of the Massie (Strawn) Field anticline to over 550 feet off
structure.
(192) Turner Formation in Wyoming. RM79-76-242 (Wyoming 18).
(i) Delineation of formation. The Turner Formation underlies
approximately 85,760 acres within Campbell and Converse Counties,
Wyoming, in Township 40 North, Range 69 West, 6th P.M., Sections 7, 18,
19, 30, and 31; Township 40 North, Range 70 West, 6th P.M., All
Sections; Township 40 North, Range 71 West, 6th P.M., Sections 1, 2, 3,
11, 12, and 13; Township 41 North, Range 70 West, 6th P.M. Sections 4
through 9, 16 through 22, and 25 through 36; Township 41 North, Range
71 West, 6th P.M., Sections 1 through 5, 8 through 17, 20 through 26,
28, 34, 35, and 36; Township 42 North, Range 70 West, 6th P.M.,
Sections 18, 19, 30, and 31; Township 42, Range 71 West, 6th P.M.,
Sections 1 through 22, 24, 25, 27 through 29, and 32 through 36.
(ii) Depth. The Turner Formation's vertical limits are defined by
the Sage Breaks Shale Formation above and the Carlile Shale Formation
below. The average depth to the top of the Turner Formation is 9,400
feet and has an average thickness of 30 feet.
(193) ''Riley-Benson'' zones of the Chemung Group in West Virginia.
RM79-76-135 (West Virginia-3).
(i) Delineation of formation. The ''Riley-Benson'' zones cover an
area of approximately 3,197 square miles in portions of Barbour,
Doddridge, Gilmer, Harrison, Lewis, Upshur, and Randolph Counties, West
Virginia.
(ii) Depth. The ''Riley-Benson'' interval is approximately 350 feet
in thickness. The top of the ''Riley-Benson'' zones interval ranges
from 5,200 feet in the western portion to 3,000 feet in the eastern
portion with the average depth to the top of the interval being 3,783
feet.
(194) Barnett Shale Formation in Texas. RM79-76 (Texas -- 39).
(i) Delineation of formation. The Barnett Shale Formation is found
in Texas in all of Wise County and the western one-half of Denton
county, Railroad Commission District 9; and the north-western
one-quarter of Tarrant County, Railroad Commission District 5. The
designated area covers 1,592 square miles.
(ii) Depth. The Barnett Shale Formation in the designated area lies
uncomformably over the Ordovician (Ellenburger) and lies below the
Barnett Lime or Pennsylvanian Morrow. The depth to the top of the
Barnett Shale Formation varies from an estimated sub-sea depth of 4,800
feet in Wise County to 7,900 feet in Tarrant County, with an approximate
thickness ranging from 236 feet in Wise County to 300 feet in Tarrant
County. A typical Barnett Shale section occurs between the electric log
depths of 7,194 feet and 7,444 feet on the well log of the Mitchell
Energy Corporation C. W. Slay No. 1 well.
(195) Upper Marchand Sand of the Hoxbar Group in Oklahoma.
RM79-76-246 (Oklahoma-7).
(i) Delineation of formation. The Upper Marchand Sand of the Hoxbar
Group is found in Section 11, Township 3 North, Range 9 West, in
Comanche County, Oklahoma.
(ii) Depth. The depth to the top of the Upper Marchand Sand is 9,976
feet. The average net thickness of the recommended zone is 50 feet.
The recommended zone consists of the upper half of the Marchand Sand.
The Marchand Sand is overlain by the Medrano Sandstone and underlain by
the Culp-Melton Zone.
(196) Hosston Formation in Louisiana. RM79-76 (Louisiana-7).
(i) Delineation of formation. The Hosston Formation is located in
Township 12 North, Ranges 7, 8, and 9 West; Township 13 North, Ranges
7, 8, and 9 West; and Township 14 North, Ranges 7, 8, and 9 West;
comprising approximately 324 square miles of portions of Bienville,
Natchitoches, and Red River Parishes, Louisiana.
(ii) Depth: The Hosston Formation is defined as being that gas and
condensate bearing sand encountered between the measured depths of 7,320
feet and 10,090 feet on the induction electrical log of the Amerada Hess
Corporation -- Placid Oil Company -- Charles Beach Jr. No. 1 well,
located in section 34, Township 12 North, Range 8 West, Red River
Parish, Louisiana.
(197) Dakota Producing Interval in New Mexico. RM79-76 (New
Mexico-14).
(i) Delineation of formation. The Dakota Producing Interval is
located in Township 31 North, Range 13 West, sections 1 through 12,
sections 14 through 21, sections 28 through 32, NMPM, San Juan County,
New Mexico. The interval is within the Basin -- Dakota Gas Pool, in the
northwestern portion of the San Juan Basin near the Hogback Monocline.
(ii) Depth. The Dakota Producing Interval is composed of the
Granerous Shale Formation, the Dakota Formation, and the productive
upper portion of the Morrison Formation. The average depth to the top
of the Dakota Formation is 6,544 feet. Gross thickness of the interval
is approximately 400 feet.
(198) The Maxton, Little Lime, and Blue Monday zones of the Mauch
Chunk Group; the Big Lime and Keener zones of the Greenbrier Group;
and the Big Injun and Squaw zones of the Pocono Group underlying
portions of Braxton and Clay Counties, West Virginia. RM79-76-233 (West
Virginia -- 5)
(i) Delineation of formation. The Maxton zone underlies the Salt
Sands zone of the Pottsville Group of Pennsylvania age and overlies the
Little Lime zone of the Mauch Chunk Group. The Little Lime zone
underlies the Maxton zone and overlies the Blue Monday zone of the Mauch
Chunk Group. The Blue Monday zone underlies the Little Lime zone and
overlies the Big Lime zone of the Greenbrier Group. The Big Lime zone
underlies the Blue Monday zone and overlies the Keener zone of the
Greenbrier Group. The Keener zone underlies the Big Lime zone and
overlies the Big Injun zone of the Pocono Group. The Big Injun zone
underlies the Keener zone and overlies the Squaw zone of the Pocono
Group. The Squaw zone underlies the Big Injun zone and overlies the
Weir zone of the Pocono Group.
(ii) Depth. The average depth to the top of each of the zones is as
follows: Maxton, 1,550 feet; Little Lime, 1,650 feet; Blue Monday,
1,685 feet; Big Lime, 1,735 feet; Keener, 1,845 feet; Big Injun,
1,865 feet; and Squaw, 2,025 feet.
(199) Dakota Formation in Colorado, RM79-76 (Colorado-23).
(i) Delineation of formation. The Dakota Formation is located in
Garfield and Mesa Counties, Colorado and underlies portions of Townships
7 through 13 South, Ranges 97 through 98 and 100 through 104 West, 6th
P.M.; Township 1 North, Ranges 1 and 2 West, Ute P.M.; Township 2 North
Range 2 West, Ute P.M.; Township 1 North, Range 1 East, Ute P.M.;
Township 1 South Range 1 West, Ute P.M.; and Townships 1 through 3
South, Ranges 1 and 2 East, Ute P.M.
(ii) Depth. The average depth to the top of the Dakota formation is
2,815 feet.
(200) Morrison Formation in Colorado, RM79-76 (Colorado-23).
(i) Delineation of formation. The Morrison Formation is located in
Garfield and Mesa Counties, Colorado and underlies portions of Township
7 through 13 South, Ranges 97 through 98 and 100 through 104 West, 6th
P.M.; Townships 1 and 2 North, Ranges 1 and 2 West, Ute P.M.; Township 1
North, Range 1 East, Ute P.M.; Township 1 South, Range 1 West, Ute P.M.;
and Townships 1 through 3 South, Ranges 1 and 2 East, Ute P.M.
(ii) Depth. The average depth to the top of the Morrison Formation
is 3,005 feet.
(201) Niobrara Formation in Colorado. (Colorado-38 Addition).
(i) Delineation of formation. The Niobrara Formation is located in
Weld County, Colorado, in Township 4 North, Range 68 West, Sections 7,
8, 17-20, 29-32, in Larimer County, Colorado, in Township 4 North, Range
69 West, Sections 11-14, 23-27, 34-36, and Township 3 North, Range 69
West, Sections 1-3, 6th P.M.
(ii) Depth. The Niobrara Formation underlies the Pierre Shale and
overlies the Codell Formation. The top of the Niobrara Formation varies
in depth from zero at 7,000 feet and averages 5,300 feet. The Niobrara
Formation averages 225 feet in thickness.
(202) Niobrara Formation in Colorado. (Colorado-39 Addition).
(i) Delineation of formation. The Niobrara Formation is located in
Weld County, Colorado, in Township 4 North, Range 64 West, 6th P.M., all
Sections; Township 4 North, Range 65 West, 6th P.M., all Sections;
Township 5 North, Range 64 West, 6th P.M., Sections 25 through 36;
Townships 5 North, Range 65 West, 6th P.M., Sections 2 through 36;
Township 5 North, Range 66 West, 6th P.M., Sections 1, 12, 13, and 36;
and Township 6 North, Range 65 West, 6th P.M., Sections 31 and 32.
(ii) Depth. The Niobrara Formation is defined as that interval which
begins at a depth of approximately 7,000 feet and varies in thickness
from 250 feet to 350 feet. The Niobrara in this area is found between
the bottom of the Sharon Springs Shale and the top of the Codell
Sandstone.
(203) The ''Big Lime'' Formation in Virginia. (Virginia-4).
(i) Delineation of formation. The ''Big Lime'' Formation is located
in the plateau region of southwestern Virginia and consists of most of
Dickenson County and portions of Lee, Scott, Wise, Russell, and Tazewell
Counties (maps showing the area are on file with the Commission).
(ii) Depth. The depth to the top of the formation ranges from above
sea level along the Pine Mountain thrust exposure and on top of the
Powell Mountain anticline near the northwest boundary to 1,950 feet
below sea level to the south in Wise County. The formation ranges in
thickness from 450 feet in the northwest to 950 feet toward the
southeast.
(Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432 (1982);
Department of Energy Organization Act, 42 U.S.C. 7101-7352 (1982): E.
O. 12009, 3 CFR part 142 (1978); Administrative Procedure Act, 5 U.S.C.
553 (1982))
(Order 99, 45 FR 56044, Aug. 22, 1980)
Editorial Note: For Federal Register citations affecting 271.703,
see the List of CFR Sections Affected in the Finding Aids section of
this volume.
18 CFR 271.704 Qualified production enhancement gas.
(a) Maximum lawful price for qualified production enhancement gas.
(1) The maximum lawful price, per MMBtu, for the first sale of
qualified production enhancement gas shall be the lesser of:
(i) The renegotiated price or the pipeline production price, as
applicable, as stated in the application; or
(ii) The section 109 price.
(2) Requirement of completed production enhancement work. If the
production enhancement work has not been completed on or before the date
the application is filed, the maximum lawful price provided in paragraph
(a)(1) of this section shall not apply until the production enhancement
work is completed and the seller has given written notice to the
purchaser stating that the production enhancement work upon which the
application for determination of eligibility is based, has been
completed. The applicant must retain a copy of this notice in his
records for a period of three years after the month in which the first
sales priced under this section occurred.
(3) Elimination of price controls. For purposes of determining the
price paid, under section 121(a)(3) of the NGPA, any amount paid solely
by reason of a maximum lawful price allowed by this section shall be
disregarded.
(b) Definitions. For purposes of this subpart:
(1) Qualified production enhancement gas means natural gas that a
jurisdictional agency has determined in accordance with parts 274 and
275 meets the qualification requirements in paragraph (c) of this
section.
(2) Production enhancement work means an operation or installation of
equipment described in paragraph (d) of this section.
(3) Renegotiated price means a price (not in excess of the section
109 price) agreed to after November 9, 1978, in connection with the
production enhancement work which is the subject of an application under
this section.
(4) Section 109 price means the maximum lawful price specified for
subpart I of part 271 in Table I of 271.101(a).
(5) Pipeline production price means any price which is paid by the
transmission divisional unit of a pipeline in a first sale to the
production divisional unit of that pipeline and which does not exceed
the amount paid in comparable first sales between persons not affiliated
with such interstate pipelines.
(c) Qualified production enhancement gas. For purposes of this
section:
(1) Qualified production enhancement gas is natural gas:
(i) Which is produced --
(A) For wells or zones for which a maximum lawful price prescribed by
subpart E of part 271 applies (but for this section):
(1) From a well on which production enhancement work (other than
production enhancement work described in paragraph (d)(3) of this
section) was commenced on or after May 29, 1980, but on or before May
12, 1990; or
(2) From a zone that is perforated in accordance with paragraph
(d)(3) of this section on or after May 29, 1980, but on or before May
12, 1990;
(B) For wells or zones for which a maximum lawful price prescribed by
subpart D or F of part 271 applies (but for this section):
(1) From a well on which production enhancement work (other than
production enhancement work described in paragraph (d)(3) of this
section) was commenced on or after September 26, 1983, but on or before
May 12, 1990; or
(2) From a zone that is perforated in accordance with paragraph
(d)(3) of this section on or after September 26, 1983, but on or before
May 12, 1990.
(ii) For which a maximum lawful price prescribed by subparts D, E, or
F of part 271 applies (but for this section);
(iii) For which a renegotiated price is applicable;
(iv) For the production of which there is a reasonable basis,
grounded in part on the amount of the investment, to conclude that:
(A) The price prescribed in paragraph (a) of this section is
necessary as a reasonable incentive; and
(B) But for the availability of the price prescribed in paragraph (a)
of this section, the production enhancement work would not have been
performed or will not be performed; and
(v) The production of which (as calculated by the seller for a five
year period beginning from the month of application (''test period''),
based on estimates filed pursuant to 274.205(f)(4)) will result in a
projected increase in revenue which, when divided by the projected
increase in units of production, does not exceed 200 percent of the
maximum lawful price specified for subpart C -- NGPA section 103(b)(1)
for the month that the application is filed.
(2) Projected increase in revenue means:
(i) The product of (A) the estimated units of gas production
(MMBtu's) which would be produced from the well during the test period
if production enhancement work has been completed on the day that the
application is filed, times (B) the section 109 price (unless paragraph
(c)(4) of this section otherwise permits) for the month that the
application is filed, less
(ii) The product of (A) the estimated units of gas production
(MMBtu's) which would be produced from the well during the test period
if the production enhancement work is not performed, or had not been
performed, times (B) the maximum lawful price otherwise applicable to
natural gas from the well as of the date the application is filed.
(3) Projected increase in units of production means:
(i) The estimated units of gas production (MMBtu's) which would be
produced from the well during the test period if the production
enhancement work had been completed on the day that the application is
filed, less
(ii) The estimated units of gas production (MMBtu's) which would be
produced from the well during the test period if the production
enhancement work is not performed, or had not been performed.
(4) For purposes of paragraph (c)(2)(i)(B) of this section, if the
renegotiated price is a fixed price or a percentage of the section 109
price, such renegotiated price (as of the date of application) may be
substituted for the section 109 price in making the determination
required in paragraph (c)(2) of this section.
(d) Production enhancement work defined. For purposes of this
section, ''production enhancement work'' means any work that is
performed for one or more of the following purposes:
(1) Re-entry into a well which has been plugged and abandoned.
(2) Re-entry into a well for the purpose of deeper drilling, or
sidetracking, to a different completion location.
(3) Recompletion by reperforation of a zone from which natural gas
has been produced or by perforation of a different zone.
(4) Repair or replacement of faulty or damaged casing, tubing or
related downhole equipment.
(5) Fracturing, acidizing or the installing of compression equipment.
(6) Installing equipment necessary for removal of excessive water,
brine or condensate from the wellbore in order to establish, continue or
increase production of gas from the well.
(7) Workover operations to reduce excessive water or brine production
in order to establish, continue or increase production of gas from the
well.
(8) Operations to dispose of water or brine produced from the well,
the presence of which prevents or severely limits gas production from
the well.
(9) Workover operations to reduce excessive sand production or
operations to remove excessive sand from the well-bore in order to
continue production of gas from the well.
(10) Injection of nitrogen gas or other inert gas necessary to
establish, continue or increase production of gas from the reservoir.
(e) Cross reference. For the rule establishing the maximum lawful
price for qualified production enhancement gas which becomes subject to
an intrastate rollover contract, see 271.602(c).
(Order 107, 45 FR 77429, Nov. 24, 1980, as amended at 48 FR 45102,
Oct. 3, 1983; Order 391, 49 FR 33859, Aug. 27, 1984; Order 406, 49 FR
46884, Nov. 29, 1984; Order 519, 55 FR 6377, Feb. 23, 1990)
18 CFR 271.704 Subpart H -- Stripper Well Natural Gas
Authority: Natural Gas Policy Act of 1978, Pub. L. 95-621, 92 Stat.
3350; Department of Energy Organization Act, 42 U.S.C. 7107, et seq.,
E.O. 12009, 42 FR 46267.
Source: Order 44, 44 FR 49662, Aug. 24, 1979, unless otherwise
noted.
18 CFR 271.801 Applicability.
This subpart implements section 108 of the NGPA and applies to any
first sale of natural gas which a jurisdictional agency determines is
stripper well natural gas.
18 CFR 271.802 Maximum lawful price.
The maximum lawful price, per MMBtu, for natural gas to which this
subpart applies shall be the price specified for subpart H of part 271
in Table I of 271.101(a).
18 CFR 271.803 Definitions.
For purposes of this subpart:
(a) Recognized enhanced recovery techniques. ''Recognized enhanced
recovery techniques'' means processes or equipment, or both, which when
performed or installed by the producer, increase the rate of production
of gas from a well. Processes qualifying as recognized enhanced
recovery techniques include mechanical as well as chemical stimulation
of the reservoir formation. Equipment may include items installed in
the well bore or on the surface.
Normal well maintenance, repair, or replacement of equipment or
facilities does not qualify as enhanced recovery techniques. Normal
completion operations (as defined by the jurisdictional agency or, if
the agency has not defined the term, by state custom or practice) which
are performed within two years of the initial completion do not qualify
as recognized enhanced recovery techniques. Any drilling activity which
results in production from another reservoir does not qualify as a
recognized enhanced recovery technique.
(b) Nonassociated natural gas. ''Nonassociated natural gas'' means
natural gas produced from a well which a jurisdictional agency
determines produced an average number of barrels of crude oil per
production day during the production period upon which the determination
is based, which does not exceed the numer of barrels determined in
accordance with the following table:
(c) 90-day production period. (1) ''90-day production period'' means
any period of 90 consecutive calendar days excluding any day during
which natural gas is not produced for reasons other than voluntary
action of any person with the right to control production of natural gas
from such well.
(2) Where records for a 90-consecutive-calendar-day period indicate
that the well produced 60 Mcf or less per production day during that
period, a rebuttable presumption is created that the well produced 60
Mcf or less per production day during the 90-day production period
defined in paragraph (c)(1) of this section.
(d) Production day. ''Production day'' means:
(1) Any day during which natural gas is produced; and
(2) Any day during which natural gas is not produced if production
during such day is prohibited by a requirement of State law or a
conservation practice recognized or approved by the State agency having
regulatory jurisdiction over the production of natural gas.
(e) Produced. Natural gas is produced, within the meaning of section
108(b)(3)(A) and (B) of the NGPA:
(1) On any day during which there is measurable production of natural
gas from a well, and
(2) On any day during which a well is open to the line but is unable
to produce measurable quantities of gas.
(Order 44, 44 FR 49662, Aug. 24, 1979, as amended by Order 188, 46 FR
57466, Nov. 24, 1981)
18 CFR 271.804 Special rules.
(a) Rate of production. For purposes of determining the rate of
production from a well for which a stripper well determination is
sought:
(1) The total volume of natural gas produced from the well shall
constitute its daily production regardless of whether the well is
completed in more than one interval or the production is separately
metered from separate intervals;
(2) Production may be measured either before or after the extraction
of natural gas liquids.
(b) Averaging of production. If a determination of stripper well
status is sought with respect to wells which are not individually
metered, rates of production of natural gas and oil may, in the absence
of other reliable evidence, be averaged equally among the non-metered
wells.
(c) Applications for determinations. Applications under this subpart
shall be based on a 90-day production period which falls entirely within
the 180 days prior to the date on which the application is filed.
(d) Seasonally affected wells. (1) If together with a petition for
qualification as a stripper well, the applicant submits to the
jurisdictional agency production reports for a period of at least 24
months ending concurrently with the 90-day production period which is
the basis for the application under paragraph (c) of this section and if
such reports demonstrate that the well is subject to seasonal
fluctuations which temporarily increase average production above 60 Mcf
per production day, the jurisdictional agency may, upon request,
designate the well as ''seasonally affected.'' Such designation shall be
granted by the jurisdictional agency only if it finds that the seasonal
fluctuations have not increased and cannot reasonably be expected to
increase production levels above an average of 60 Mcf per production day
for any 12-month period.
(2) If at any time subsequent to a final determination of stripper
well status, the operator acquires production reports for a period of 24
consecutive months which demonstrate that the well is ''seasonally
affected'', a petition may be filed with the jurisdictional agency for
designation as a seasonally affected well. The jurisdictional agency
shall make the designation according to the standards described in
paragraph (d)(1) of this section.
(3) If a well is designated as seasonally affected, the operator of
such well and the purchaser of production from such well are exempt from
the filing requirements of 271.805(d) unless the average rate of
production exceeds 60 Mcf per production day for a 12-month period.
(e) Temporary pressure buildup in previously qualifying stripper
wells. (1) A previously qualifying stripper well which produces natural
gas at a rate in excess of an average of 60 Mcf per production day
during any 90-day production period shall not be disqualified if the
jurisdictional agency finds pursuant to a petition filed under 271.805
that:
(i) The rate of production in excess of 60 Mcf per production day is
the result of pressure buildup which occurred when the well was
temporarily shut-in;
(ii) Total production for the relevant 90-day production period did
not exceed 5400 Mcf; and
(iii) Based on the well's production history and any other available
data, the well could reasonably have been expected to produce at an
average rate not exceeding 60 Mcf per production day during the relevant
90-day production period had the well been continuously open to the line
during such period.
(2) A previously qualifying stripper well is a well which:
(i) Has been determined by a jurisdictional agency to qualify as a
stripper well pursuant to this subpart, or is the subject of a pending
application before a jurisdictional agency, and
(ii) If disqualified, has requalified prior to the 90-day production
period in which the temporary pressure buildup occurs.
(3) If a previously qualifying stripper well, which qualified
pursuant to paragraph (e)(1) subsequently produces in excess of an
average of 60 Mcf per production day for a 90-day period because of
pressure buildup occurring during a temporary shut-in, a new petition
pursuant to paragraph (e)(1) need not be filed to avoid disqualification
of the well so long as production does not exceed 5400 Mcf for a 90-day
production period. If a well is disqualified as a stripper well after
qualifying for a pressure buildup determination pursuant to paragraph
(e)(1) but requalifies before a subsequent 90-day production period in
which a temporary pressure buildup occurs, it will continue to qualify
pursuant to this paragraph based on the prior petition filed pursuant to
paragraph (e)(1).
(4) If a well which produces in excess of 60 Mcf per production day
continues to qualify for stripper well prices under paragraph (e)(3),
the operator of such well and the purchaser of production from such well
are exempt from the filing requirements of 271.805(d) for subsequent
period.
(f) Enhanced recovery technique wells. An enhanced recovery
technique cannot be applied to a well during any 90-day production
period in which the production exceeds an average of 60 Mcf per
production day.
(Approved by the Office of Management and Budget under control number
1902-0112)
(Order 44, 44 FR 49662, Aug. 24, 1979, as amended at 46 FR 6902, Jan.
22, 1981; Order 336, 48 FR 44517, Sept. 29, 1983; 48 FR 54947, Dec. 7,
1983; Order 445, 51 FR 4310, Feb. 4, 1986)
18 CFR 271.805 Continuing qualification.
(a) General rule for qualification. The maximum lawful price
specified in 271.802 shall apply to gas produced from:
(1) A well for which an application has been filed under part 274 or
a determination has been made under part 274 that the well produced
nonassociated natural gas at a rate not exceeding an average of 60 Mcf
per production day for a 90-day production period; or
(2) A well for which an application has been filed under part 274 or
has been designated a seasonally affected well (as defined by
271.803(b) of this subpart) at a rate not exceeding an average of 60 Mcf
per production day for any 12-month period.
(b) General rule for disqualification. The maximum lawful price
specified in 271.802 shall not apply to a well otherwise qualified
under paragraph (a) of this section which produces an average of more
than 60 Mcf of natural gas per production day for any 90-day production
period or any 12-month production period for seasonally affected wells
without regard to the production of crude oil. The ceiling price for
gas produced from such a disqualified well shall be the otherwise
applicable maximum lawful price.
(c) General rule for requalification. The maximum lawful price
specified in 271.802 shall apply to natural gas produced from a well
which was qualified under paragraph (a)(1) of this section but was
disqualified under paragraph (b) of this section provided the production
from that well decreases to a level not exceeding an average of 60 Mcf
of natural gas per production day for a new 90-day production period
without regard to the production of crude oil. An application to a
jurisdictional agency is not required to requalify under this paragraph.
Natural gas produced from a well which was qualified under paragraph
(a)(2) of this section but was disqualified under paragraph (b) of this
section can requalify as stripper well natural gas under this section
but only be requalified as natural gas produced from a seasonally
affected well by receiving a new jurisdictional agency seasonally
affected determination that the natural gas qualifies under 271.804(d)
of this subpart.
(d) Notice of disqualification. (1) Unless exempt under
271.804(d)(3) or 271.804(e)(4), the operator and any purchaser of
natural gas shall give written notice if a well has been disqualified
under paragraph (b) of this section.
(2) Notice required under paragraph (d)(1) of this section shall be
given within 90 days after the last day of the 90-day or the 12-month
production period in which the increased production of natural gas
occurred.
(3) Such notice shall be served on the Commission and on the operator
and any purchaser, as appropriate.
(e) Petition under 271.806. (1) The operator or purchaser may file
with the jurisdictional agency:
(i) A motion contesting the disqualification or requalification under
paragraph (b) or (c) of this section, (or continuing qualification under
paragraph (e)(3) of 271.804), and include a copy if applicable, of the
notice filed under paragraph (d) in the motion;
(ii) A petition for a determination under 271.806 that the increased
production of natural gas is:
(A) The result of the application of an enhanced recovery technique;
(B) If the well has not been designated as seasonally affected, the
result of seasonal fluctuations; or
(C) The result of pressure buildup which occurred when the well was
temporarily shut-in.
(2) A petition or motion filed under paragraph (e)(1) of this section
may be filed at any time after notice is given under paragraph (d) of
this section. A copy of the petition or motion and of the notice
required under paragraph (d)(1) of this section shall be provided to the
purchaser or operator, as appropriate.
(f) Collection subject to refund. (1) An operator who files a
petition or motion under paragraph (e) may collect, subject to refund,
the maximum lawful price provided in 271.802:
(i) From the last day of the 90-day or the 12-month disqualifying
period if the petition or motion is filed within 150 days after the last
day of the 90-day or the 12-month disqualifying period, or
(ii) In all other cases, after the date the petition is filed.
(2) When the petition or motion filed under paragraph (e) of this
section is denied or withdrawn, the operator or purchaser must comply
with the provisions of 270.101(e) of this chapter.
(g) Refunds due to disqualification. (1) Unless the seller files a
petition under 271.806 within 150 days after the last day of the
disqualifying 90-day or 12-month period, and unless the refund is
recovered through a billing adjustment as provided in 270.101(e) (1)
and (2) of this chapter, the seller must refund to the purchaser the
amount collected in excess of the maximum lawful price, together with
interest determined in accordance with 154.102 (c) and (d) of this
chapter, within 180 days after the last day of the disqualifying 90-day
or 12-month period. Compliance with the specific refund requirements of
273.302 of this chapter will not terminate the general refund
obligation under subpart H.
(2)(i) Except as provided in paragraph (g)(2)(ii) of this section,
within 210 days after the last day of the disqualifying 90-day or
12-month period, the seller must file either:
(A) An original and two copies of a refund report, accompanied by a
purchaser concurrence, containing the information specified in
273.302(f) of this chapter;
(B) A statement, accompanied by a purchaser concurrence, that no
refunds are due; or
(C) An affidavit that the seller did not collect more than the
otherwise applicable maximum lawful price.
(ii) If a purchaser does not provide the seller with its concurrence
within the time period specified in paragraph (g)(2)(i) of this section,
the seller may file the refund reports or statements that no refunds are
due without the purchaser's concurrence.
(3) A seller is not required to include in a report filed under this
paragraph any information regarding a refund recovered by an interstate
pipeline purchaser through a billing adjustment.
(h) Filing requirements for increased production based on enhanced
recovery techniques. If subsequent to the filing of a petition it is
determined that the increase in production of natural gas is the result
of recognized enhanced recovery techniques, neither the operator nor the
purchaser shall be obligated to report average production levels above
60 Mcf per day during any 90-day production period unless there is an
increase in production resulting from causes other than use of
recognized enhanced recovery techniques determined to have been used.
(Approved by the Office of Management and Budget under control number
1902-0112)
(Order 186, 46 FR 57469, Nov. 24, 1981, as amended by Order 336, 48
FR 44517, Sept. 29, 1983; 48 FR 54947, Dec. 7, 1983; Order 445, 51 FR
4310, Feb. 4, 1986; Order 515, 54 FR 32810, Aug. 10, 1989)
18 CFR 271.806 Jurisdictional agency determinations and Commission
review.
(a) Petition under 271.804(d) and (e) and 271.803(a). The
jurisdictional agency shall treat the following petitions as if they
were applications for initial determinations and shall comply with the
applicable provisions of subpart A of part 274 of this chapter:
(1) Petitions to designate a well as seasonally affected pursuant to
271.804(d);
(2) Petitions to determine that production is excess of an average of
60 Mcf per production day was due to,
(i) Use of recognized enhanced recovery techniques defined in
271.803(a), or
(ii) Temporary pressure buildup pursuant to 271.804(e).
(b) Motion contesting a disqualification or a requalification. The
jurisdictional agency shall treat a motion contesting a disqualification
or a requalification under 271.805(e)(1)(i) as if it were an
application for initial determination and shall comply with the
application provisions of subpart A of part 274 of this chapter.
(c) Review of determinations. Upon receipt of notice of a
determination made under paragraph (a) or (b) of this section, the
Commission will review such determination pursuant to the applicable
provisions of subpart B of part 275.
(d) Declaratory order or staff interpretation. A jurisdictional
agency, when making a determination under 271.806(a) (relating to
production in excess of 60 Mcf per production day resulting from the
application of recognized enhanced recovery techniques), may seek a
declaratory order or staff interpretation from the Commission that a
process (or type of process) or the installation of equipment (or type
of equipment) qualifies as a recognized enhanced recovery technique as
defined in 271.803(a). The petition for declaratory order shall be
filed in accordance with the requirements of 1.7(c) of the Commission's
Rules of Practice and Procedure (18 CFR 1.7(c)).
(Approved by the Office of Management and Budget under control number
1902-0112)
(Order 44, 44 FR 49662, Aug. 24, 1979, as amended at 46 FR 6902, Jan.
22, 1981; Order 187, 46 FR 54767, Nov. 24, 1981; Order 336, 48 FR
44518, Sept. 29, 1983; 48 FR 54947, Dec. 7, 1983)
18 CFR 271.807 Maximum efficient rate of flow.
(a) Determination under recognized conservation practice. If a
maximum efficient rate of flow for a well, determined in accordance with
recognized conservation practices designed to maximize the ultimate
recovery of natural gas, has been established by a jurisdictional
agency, production of natural gas at that rate shall be deemed to be
production at the maximum efficient rate of flow.
(b) Alternative methods for determination. If a maximum efficient
rate of flow has not been determined in accordance with paragraph (a) of
this section by a jurisdictional agency, for a well which has produced
nonassociated gas at an average rate of 60 Mcf per production day or
less for a 90-day production period, the jurisdictional agency shall
establish maximum efficient rate of flow in accordance with one of the
following methods:
(1) Prior production data available. If production data are
available for the 12-month period ending concurrently with such 90-day
production period, the applicant shall submit such data.
(i) If such 12-months' production data established that the well
produced natural gas at a rate which did not exceed an average of 60 Mcf
per production day for such 12-month period, there is a rebuttable
presumption that the well produced at its maximum efficient rate of
flow.
(ii) If such 12-months' production data established that the well
produced natural gas at a rate which did not exceed an average of 70 Mcf
per production day for such 12-month period, the jurisdictional agency
shall make a deferred determination in accordance with paragraph (c) of
this section.
(2) Prior production data not available. If production data are not
available for the 12-month period ending concurrently with such 90-day
production period, the jurisdictional agency shall make a deferred
determination in accordance with paragraph (c) of this section.
(3) Other evidence. The jurisdictional agency may base the
determination upon other substantial evidence, such as flow tests, which
measure the capability of the well to produce natural gas under normal
operating conditions.
(c) Deferred determination procedure. If a determination is deferred
under paragraph (b)(1)(ii) or (b)(2) of this section, the jurisdictional
agency shall designate a 12-month period during which the applicant may
secure the data establishing that the well produced natural gas at an
average rate not in excess of 60 Mcf per production day. The applicant
may submit such data not later than 90 days after the close of such
12-month period, and if such data show that the well's production did
not exceed 60 Mcf per production day, the jurisdictional agency shall
make an affirmative determination.
(d) Negative determinations. The jurisdictional agency shall make a
negative determination as to eligibility if:
(1) The production data submitted by the applicant indicate that for
the 12 months ending concurrently with the 90-day production period the
well produced natural gas at a rate which exceeded an average of 70 Mcf
per production day, unless the jurisdictional agency determines that the
well produced at its maximum efficient rate of flow pursuant to
paragraph (a)(1) or paragraph (b)(3) of this section,
(2) The production data submitted by the applicant indicate that for
the deferred 12-month period established by the jurisdictional agency,
the well produced natural gas at a rate which exceeded an average of 60
Mcf per production day, or
(3) The applicant fails to submit available production data pursuant
to paragraph (b)(1) of this section or fails to submit production data
pursuant to paragraph (c).
(e) Interim collection. When the jurisdictional agency defers making
a determination on an application pursuant to paragraph (b)(1)(ii) or
(b)(2) of this section, the applicant shall be permitted to make interim
collections of the maximum lawful price provided in 271.802 pursuant to
the requirements of 273.202. If the filing requirements of 273.202(d)
have previously been complied with, the applicant shall not be required
to make such filings again.
18 CFR 271.807 Subpart I -- Other Categories of Natural Gas
Authority: Natural Gas Act, as amended, 15 U.S.C. 717 et seq.;
Department of Energy Organization Act, 42 U.S.C. 7107 et seq. E.O.
12009, 42 FR 46267; Natural Gas Policy Act of 1978, Pub. L. 95-621, 92
Stat. 3350.
Source: Order 72, 45 FR 18919, Mar. 24, 1980, unless otherwise
noted.
18 CFR 271.901 Applicability.
This subpart implements section 109 of the NGPA and applies to a
first sale of natural gas that is not covered by a maximum lawful price
under section 102, 103, 104, 105, 106, 107 or 108 of the NGPA.
18 CFR 271.902 Maximum lawful price.
The maximum lawful price, per MMbtu, for natural gas to which this
subpart applies shall be the price specified for subpart I of part 271
in Table I of 271.101(a).
18 CFR 271.903 Recordkeeping.
Any person who collects a price under this part for the first sale of
natural gas shall keep:
(a) Any books and records related to the sale for three years from
the end of each billing period;
(b) Any contract related to the sale for three years after the
expiration of the contract.
(Order 272, 48 FR 646, Jan. 6, 1983)
18 CFR 271.904 Special rule.
First sales of natural gas described in section 109(a0(1), (2) (3) or
(4) of the NGPA are covered by the subpart only to the extent such first
sales are not covered by an maximum lawful price under section 102, 103,
104, 105, 106, 107 or 108 of the NGPA.
18 CFR 271.904 Subpart J -- (Reserved)
18 CFR 271.904 Subpart K -- Allowances for State Severance Taxes and Certain Production-Related Costs
18 CFR 271.1100 Applicability.
(a) General. This subpart prescribes regulations under which a price
for a first sale of natural gas shall not be considered to exceed the
applicable maximum lawful prices set forth in this part if such first
sale price exceeds the maximum lawful price determined under subparts B
through J of this part to the extent necessary to recover:
(1) State severance taxes under 271.1102; and
(2) Production-related costs allowed under 271.1104.
(Order 94, 45 FR 53115, Aug. 11, 1980, as amended by Order 94-A, 48
FR 5178, Feb. 3, 1983)
18 CFR 271.1101 Definitions.
(a) Except as provided in paragraph (b), the term State severance tax
as used in this subpart means any severance, production, or similar tax,
fee, or other levy imposed on the production of natural gas:
(1) By any State;
(2) By any Indian tribe recognized as eligible for services provided
by the Secretary of the Interior to Indians; or
(3) By any political subdivision of a State if the authority to
impose such tax, fee, or other levey is granted to such political
subdivision under State law.
(b) The term State severance tax does not include any amount of tax
which results from a provision of State law enacted on or after December
1, 1977, unless such provision of law is equally applicable to natural
gas produced in such State and delivered in interstate commerce and to
natural gas produced in such State and not so delivered.
(Order 94, 45 FR 53115, Aug. 11, 1980)
18 CFR 271.1102 State severance taxes.
(a) Except as provided in paragraph (b) of this section, the price
for any first sale of natural gas shall not be considered to have
exceeded the maximum lawful price applicable to that sale as set forth
in this part if such first sale price exceeds the maximum lawful price
to the extent necessary to recover State severance taxes borne by the
seller.
(b) The maximum lawful prices prescribed under this part for
interstate sales of natural gas produced from the Permian Basin area
include State severance taxes in the amount of 2.6 cents for large
producers and 3.05 cents for small producers. To the extent maximum
lawful prices are established by reference to the Permian Basin area
rate, only amounts of State severance tax in excess of those amounts
already included may be considered under paragraph (a) of this section.
(43 FR 56551, Dec. 1, 1978, as amended by Order 108-A, 48 FR 48228,
Oct. 18, 1983)
18 CFR 271.1103 Record retention.
(a) State severance taxes. A seller in a first sale in which the
price includes State severance taxes permitted under 271.1102 shall
retain a record of the sale which shall identify the seller, and shall
retain such other records as are necessary to demonstrate that such
seller has borne the amount of State severance taxes included in the
sale price. Such records shall be preserved for at least three years
from the date on which the sale occurred.
(b) Production-related costs. A seller in a first sale in which the
price includes an amount necessary to recover production-related costs
permitted under 271.1104 shall retain such records of the sale as may
be necessary to identify the amount collected and demonstrate the basis
for the collection. Such records shall be retained for at least three
years from the date on which the sale occurred.
(Order 94-A, 48 FR 5178, Feb. 3, 1983)
18 CFR 271.1104 Production-related costs.
(a) General rule. Except as provided in paragraph (b) of this
section, the price for a first sale of natural gas shall not be
considered to exceed the maximum lawful price applicable to that sale,
as determined under subparts B through I of this part, if:
(1) Such first sale price exceeds the maximum lawful price by an
amount necessary to recover a production-related cost as determined in
accordance with paragraph (d) of this section;
(2) The production-related cost is borne by the seller; and
(3) The seller is expressly authorized, as defined in paragraph
(c)(4) of this section, to be compensated for bearing that
production-related cost.
(b) Exclusions. This section does not apply to a first sale of
natural gas:
(1) Produced from the Prudhoe Bay Unit of Alaska and transported
through the natural gas transportation system approved under the Alaska
Natural Gas Transportation Act of 1976; or
(2) In which the price applicable to that sale has been established
under 2.75 of this chapter (optional rate procedures), unless:
(i) The certificate authorizing the sale of the gas has been amended
to delete the limitations imposed by 2.75(m) of this chapter; or
(ii) The gas is no longer sold subject to the jurisdiction of the
Commission under the Natural Gas Act.
(c) Definitions. For purposes of this section the following
definitions apply:
(1) Borne by the seller means costs incurred by the seller in
providing a production-related service, or in having other persons
provide a production-related service on behalf of the seller.
(2) Commencement of construction means the date site preparation was
begun.
(3) Deliver means to gather or transport natural gas through a
natural gas pipeline.
(4) Expressly authorized means that the gas sales contract governing
the first sale expressly provides that:
(i) The seller agrees to provide a specified production-related
service; and
(ii) The purchaser agrees to compensate the seller for the cost of
providing that specified service as evidenced by either:
(A) A contract provision expressing an amount, or a method for
determining an amount, that the purchaser agrees to pay the seller for
providing the specified service; or
(B) An area rate clause as defined in 154.93(b-1) of this chapter,
except that such clause shall be considered to evidence only the
purchaser's agreement to compensate the seller for the cost of
delivering the natural gas and then only with respect to sales having an
applicable maximum lawful price determined under subparts B through D
and G through I of this part.
(5) Production costs means all costs incurred for:
(i) Exploration;
(ii) Development;
(iii) Production, including:
(A) Enhanced recovery techniques (including costs of compression
incurred in the production of stripper well natural gas to which the
pricing provisions of subpart H of part 271 of this chapter apply);
(B) Gas-lift, pumping, or other liquid lifting equipment located on
or in the vicinity of the wellhead or in the vicinity of the point of
commingling the gas on the offshore platform from which the gas is
produced; or
(C) Compression necessary for lifting liquids, cycling gas in a gas
condensate reservoir or pressurizing a gas condensate or oil reservoir;
or
(iv) Abandonment operations.
(6) Production-related service means any activity that results in the
incurrence of a production-related cost.
(7) Production-related costs means costs, other than production
costs, that are incurred:
(i) To deliver, compress, treat, liquefy, or condition natural gas;
or
(ii) For services, other than processing, that benefit the gas
customer and are incurred to construct or operate facilities to recover,
separate, extract, treat, dehydrate, store, or transport crude oil,
condensate or similar liquids or liquefiable hydrocarbons removed from
the natural gas stream, to the extent:
(A) Such costs are properly allocable to the gas stream in accordance
with the method approved by the Commission with respect to the
particular service and seller; or
(B) If no such method has been approved by the Commission, such costs
as do not exceed an amount equal to the total costs of constructing and
operating the facilities, multiplied by the fraction whose numerator is
the quantity of Btu's contained in the natural gas stream delivered to
the pipeline and whose denominator is the sum of the quantity of Btu's
contained in the natural gas stream delivered to the pipeline and the
quantity of Btu's contained in the liquids and liquefiable hydrocarbons
removed from the gas stream; provided that the use of this method has
not been expressly prohibited by the Commission with respect to the
particular service and seller.
(C) The cost allocation method described under paragraph
(c)(7)(ii)(B) of this section shall apply only to the allocation of
costs incurred by first sellers and then only to determine appropriate
production-related costs to be allowed those sellers under section 110
of the NGPA. This limited application is not, in any way, an approval
or disapproval of the propriety of using the cost allocation methodology
of paragraph (c)(7)(ii)(B) of this section in any other circumstance.
(d) Amounts necessary to recover production-related costs -- (1)
General rule. Except as otherwise provided in subparagraphs (d) (2) and
(3) of this section, the amount necessary to recover a
production-related cost borne by a seller delivering gas to any
intrastate pipeline, interstate pipeline, local distribution company, or
any person for use by such person is the lesser of the amount that the
seller is expressly authorized to collect under the terms of the
contract for the recovery of the cost, as evidenced under paragraph
(c)(4)(ii)(A) of this section, or the appropriate allowance permitted
under this subparagraph.
(i) For old delivery systems. For delivery of any natural gas for
which the maximum lawful prices are specified in this part, except any
gas under subparts E and F of this part, through a delivery system, the
construction of which commenced prior to November 9, 1978, the seller
may collect an amount not to exceed five cents ($0.05) per MMBtu,
regardless of the length of the delivery system.
(ii) For recent delivery systems. For delivery of any natural gas
for which the maximum lawful prices are specified in this part, through
a delivery system, the construction of which commenced, on or after
November 9, 1978, the seller may collect an amount not to exceed seven
cents ($0.07) per MMBtu for the first mile of gas haul, or fraction
thereof, plus two cents ($0.02) per MMBtu for each additional mile of
gas haul, or fraction thereof, measured in a continuous line of gas haul
from the single gas wellhead, platform, or first lease separator to a
maximum distance of 20 miles (maximum allowance of forty-five cents
($0.45) per MMBtu)). Except for direct sales to a person for use by such
person, the gas hauled must be commingled with other gas at or before
the point of the final first sale in order to be eligible for the
allowance under this clause. For purposes of this subparagraph, ''final
first sale'' is the first sale, as defined in NGPA section (2)(21), at
which a volume of natural gas is transferred for value to a purchaser
that will not also be a first seller of that gas.
(iii) Combined old and recent delivery systems. If the seller
delivers any natural gas for which the maximum lawful prices are
specified in this part, through a delivery system that combines both a
delivery system the construction of which commenced on or after November
9, 1978, and a delivery system the construction of which commenced prior
to November 9, 1978, the seller may collect the applicable allowances
under paragraphs (d)(1) (i) and (ii) of this section.
(iv) For compression facilities -- (A) For recent compression
facilities. For compressing natural gas by compressor facilities, the
construction of which commenced on or after November 9, 1978, used to
effectuate delivery of such gas to any interstate pipeline, intrastate
pipeline, local distribution company or any person for use by such
person, the seller may collect an amount not to exceed:
(1) Six cents ($0.06) per MMBtu for each qualified stage of
compression set at a ratio of 3.5 to 1 (representing the overall
compression ratio of the outlet pressure of the last stage of
compression to the inlet pressure of the first stage of compression),
not to exceed three stages; plus
(2) The cost of fuel or power to drive the compressor.
(3) For purposes of the compression allowance under this clause,
''construction'' of facilities includes the complete and necessary
replacement of old facilities with new facilities and the necessary
addition of any new stage of compression to existing facilities.
(B) For old compression facilities -- (1) Authority for collecting
the allowance. If expressly authorized under paragraph (c)(4)(ii)(A) of
this section, for compressing natural gas by compressor facilities, the
construction of which commenced on or before November 8, 1978, used to
effectuate delivery of such gas to any interstate pipeline, intrastate
pipeline, local distribution company or any other person for use by such
person, the seller may collect the cost of fuel or power to drive the
compressor.
(2) Procedure for collecting the allowance -- (i) Blanket affidavit.
If a seller has made an effective filing under 154.94(h) of the
Commission's regulations, prior to collecting the allowance, the seller
must amend its blanket affidavit under 154.94(k) and Appendix B, or
file a blanket affidavit under 154.94(k) and Appendix B, if it has not
previously done so.
(ii) Method of payment. Amounts owed under this paragraph (
271.1104(d)(1)(iv)(B)) are due in a lump sum payment within 60 days of
the submission required under paragraph (f) of this section, for each
qualified stage of compression set at a ratio of 3.5 to 1.
(iii) Retroactivity. Except for gas subject to subparts E and F of
this part, amounts owed under this paragraph ( 271.1104 (d)(1)(iv)(B))
may be collected retroactive from August 10, 1987, to July 25, 1980, or
any earlier date on which the seller filed an application with the
Commission to recover these costs, with interest computed under
154.102(c)(2)(iii) (A) and (B) of this chapter, if interest is expressly
authorized by contract. For gas subject to subparts E and F of this
part, amounts owed under this paragraph ( 271.1104(d)(1)(iv)(B)) may be
collected retroactive from August 10, 1987, to March 7, 1983, with
interest computed under 154.102(c)(2)(iii) (A) and (B) of this chapter,
if interest is expressly authorized by contract.
(iv) Effective date of blanket affidavit. Blanket affidavits filed
under 154.94(k) of this chapter to collect amounts owed under this
paragraph (271.1104(d)(1)(iv)(B)) that are received within 60 days of
August 10, 1987, shall become effective on August 10, 1987; a blanket
affidavit filed more than 60 days after August 10, 1987, shall become
effective on the date of filing.
(v) Collection and distribution. Any person collecting any allowance
under this subparagraph must make a fair and proportional distribution
of that allowance to any other first seller who, by sales made to that
person, incurred delivery or compression costs to effectuate delivery of
the gas sold by that person.
(2) Delivery allowances for sales subject to NGPA sections 105 and
106(b). An amount necessary to recover a production-related cost borne
by the seller for delivering natural gas to any interstate pipeline,
intrastate pipeline, local distribution company or any person for use by
such person by delivery systems, the construction of which commenced
prior to November 9, 1978, for sales having an applicable maximum lawful
price determined under subparts E and F of this part shall not exceed
the amount that the seller is expressly authorized to collect under the
terms of the contract for the recovery of the cost in accordance with
paragraph (c)(4)(ii)(A) of this section; except that, if the seller
amends the terms of the contract for the recovery of such delivery costs
after March 7, 1983, it shall not exceed an amount reasonably comparable
to the section 110 adjustments collected by similarly situated sellers
for gas delivery. Any person collecting an allowance under this clause
shall make a fair and proportional distribution of that allowance to any
other first seller who, by sales made to that person, incurred delivery
costs in moving the gas sold by that person.
(3) Allowances for costs other than for delivery or compression. For
any other production-related costs, an amount necessary to recover
production-related costs shall be the lesser of the amount that the
seller is expressly authorized to collect under the terms of the
contract for the recovery of the cost, as evidenced under paragraph
(c)(4)(ii)(A) of this section, or an amount per unit of gas determined
by dividing the average annual cost of service of the facility used to
provide the production-related service (as determined under paragraph
(d)(3)(A) of this section) by the total volumes (MMBtu) of natural gas
available after the service is provided; except that, if the service is
one described under paragraph (c)(7)(ii) of this section (involving
crude oil, condensate or similar liquids or liquefiable hydrocarbons),
the provisions of paragraph (d)(3)(B) of this section shall apply.
(A) The average annual cost of service is to be computed on the basis
of the following:
(1) Operation and maintenance expenses developed for the year 1985
and each calendar year thereafter on the basis of actual expenses
incurred in the last two calendar years, as available, and estimates of
future expenses;
(2) An average annual net plant investment developed for the year
1985 and each calendar year thereafter using the amount of undepreciated
investment as of January 1, 1981, for facilities in operation on that
date, or such later date as the facility becomes operational, and
depreciating the investment, using the amount of depreciation booked
annually for the particular facility or for that class of investment,
whichever method is used by the company;
(3) An average annual depreciation expense for the year 1985 and each
calendar year thereafter computed from the annual amounts used to
depreciate the plant investment; and
(4) After tax earnings at an amount no greater than 15.0 percent
times the average annual net plant investment for the year 1985 and each
calendar year thereafter, with taxes computed using the debt/equity
ratios of the company's overall capital structure unless it can be
demonstrated that the facility was financed by a particular source of
capital, in which case taxes should be computed consistent with the
particular financing arrangement used.
(5) Taxes other than income taxes for the year 1985 and each calendar
year thereafter on the basis of actual taxes paid in the last two years,
as available and estimates of future taxes.
(B) If the service is one described under paragraph (c)(7)(ii) of
this section (involving crude oil, condensate or similar liquids or
liquefiable hydrocarbons), the amount determined by using the average
annual cost of service computed under paragraph (d)(3)(A) of this
section shall be reduced to the amount allocated to the gas stream as
provided for under paragraph (c)(7)(ii)(A) or (B) of this section as
appropriate; and further reduced, as necessary, to reflect revenues
received for sales of constituents removed for the gas stream but having
no energy content. The resulting amount shall be divided by the MMBtu's
of gas that are expected to be available at the discharge side of the
facility.
(e) Collecting past costs incurred to deliver or compress natural
gas. (1) Subject to the provisions of paragraphs (e)(2) and (e)(3) of
the section, a first seller for sales having an applicable maximum
lawful price determined under subparts B through D and G through I of
this part, may collect the amounts provided under paragraph (d) of this
section for delivering and compressing natural gas, to recover the costs
incurred in providing those services prior to March 7, 1983 but after
the earlier of July 25, 1980, or the date on which the seller filed an
application with the Commission to recover these costs; provided that
the seller is expressly authorized, as defined in paragraph (c)(4) of
this section, to provide such service and be compensated for so doing,
and that this authorization was in effect during the period the costs to
be collected were incurred; however, amounts so collected must be
reduced by any amounts collected prior to March 7, 1983 to recover these
costs.
(2) In addition to the amount collected under paragraph (e)(1) of
this section, the seller may, if expressly authorized under the terms of
the contract governing the first sale, collect interest on that portion
of the amount due but not yet collected, subject to the limits specified
under 154.102 of this chapter.
(3) Amounts collected under paragraphs (e)(1) and (e)(2) of this
section are to be collected through installments over a period of time
commencing with March 3, 1983 and ending December 31, 1984; and such
installments should, to the maximum extent practicable, be of equal
amounts.
(f) Description of charges -- (1) Submission to purchaser. A first
seller charging an amount, or changing the basis for a
previously-charged amount, under the provisions of this section must
submit to the gas purchaser to be charged that amount by the seller, a
written description of the basis for the charges at a reasonable time
prior to that charge. The description must state, on a well-by-well or
completion location basis:
(i) The amount per MMBtu to be charged;
(ii) The specified production-related service for which the charge is
to be made; and
(iii) The contractual provisions expressly authorizing the charge.
(2) Retention of descriptions. A gas purchaser receiving a
description made under paragraph (f)(1) of this section must retain a
copy of that description for a period of at least three years from the
date of the last sale for which the purchaser paid a charge based on the
description.
(g) Other. In the event that a first seller performs services for
which the provisions of paragraphs (b) through (e) of this section, are
not representative (e.g. delivering natural gas through a natural gas
pipeline system at a distance greater than 20 miles, delivering natural
gas by methods other than a natural gas pipeline, performing more than
three stages of compression or proposing some other method for computing
costs) then application may be made to the Commission for an allowance
to recover these costs under section 110 of the NGPA, to the extent they
are determined to be production-related and in an amount necessary to
recover those costs.
(h) Pipeline list submissions and protest procedure -- (1) Pipeline
filings. The information required by 271.1104(h) (2) and (3) must be
filed with the Commission by September 8, 1987. A pipeline may submit
the information required under 271.1104(h) (2) and (3) in any original
and supplemental evidentiary submission, purchased gas adjustment, or
rate filing with the Commission, or by providing specific references
sufficient to locate the data in any of these prior filings.
(2) Statements of contractual authority. An interstate pipeline must
file the following information for every first seller that sells gas to
that pipeline and that asserts contractual authority to collect delivery
allowances pursuant to any area rate clause:
(i) A statement specifying for each first seller whether, in the
opinion of the interstate pipeline, that first seller has, or does not
have, contractual authority to collect production-related costs
permitted under 271.1104 of this chapter;
(ii) Any data that supports the statement made under paragraph
(h)(2)(i);
(iii) A copy of any data submitted under paragraph (f) of this
section for each first seller; and
(iv) The rate schedule number (or if none has been assigned, the date
of the contract) and the name of the seller for each first sale of
natural gas where the seller has made a submission under paragraph (f)
of this section.
(3) Lists of first sellers. An interstate pipeline must also file a
list of first sellers and a list of the respective contracts that the
pipeline identified under paragraph (h)(2) of this section to be
published by the Commission in the Federal Register.
(4) Protests -- (i) Delivery allowances. A protest to the delivery
allowances claimed on the pipeline submissions filed under paragraph
(h)(2) of this section must be submitted to the Commission, within 90
days of the publication in the Federal Register of the pipeline list,
described in paragraph (h)(3) of this section, referencing the contract
which governs the filed-for production-related delivery costs to which
the protestant objects. Parties may waive the 90-day filing deadline by
written mutual agreement, in furtherance of voluntary settlement of
protests. The waiver agreement may not extend further than 180 days
from the date the protest would otherwise be due, and must be filed with
the Commission to be effective.
(ii) Compression allowances. First sellers and third-parties may
assert contractual authority to collect compression allowances pursuant
to an area rate clause. A protest under this section must be filed by
May 3, 1988.
(5) Contents of protests. A protest filed under paragraph (h)(4) of
this section must:
(i) Specifically identify each contract that is protested;
(ii) Set forth the text of the contractual provisions which the
protestant believes to be:
(A) Inconsistent with the conclusion that the contract authorizes the
seller to collect delivery costs and the specific reasons why the
protestant believes such inconsistency exists; or
(B) Consistent with the conclusion that the contract authorizes the
seller to collect compression allowances and the specific reasons for
reaching this conclusion.
(iii) Provide any other evidence which the protestant believes is
relevant to the issue of the existence of contractual authorization to
collect the production-related costs.
(6) Protest procedure. (i) The Commission will publish in the
Federal Register a notice of a protest filed under paragraph (h)(4) of
this section. Any protest must be served by any interested
pipeline-purchasers or first sellers, at the same time the protest is
submitted to the Commission. Pipeline-purchasers will provide the names
and addresses of effected first sellers to any third parties that must
make service under this section upon request.
(ii) The Commission will transmit to the Chief Administrative Law
Judge:
(A) In disputes concerning delivery allowances, the pipeline protest
filing, the protest filed under paragraph (h)(4) of this section and the
list of first sellers identified as not having contractual authority to
collect production-related costs; or
(B) In disputes concerning compression allowances, the first seller
protest filing.
(iii) Protests will be set for hearing, unless summary disposition is
made of the protest.
(iv) Upon receipt by the Commission of any third-party staff protest,
or pipeline protest of first sellers identified as not having
contractual authority to collect production-related costs referred to in
this section, the seller in the first sale will be joined as a party.
(v) Upon receipt by the Commission of a first seller protest, the
pipeline in the first sale will be joined as a party.
(7) Authority of Chief Administrative Law Judge. In the case of any
proceeding relating to a third party, staff, pipeline protest or first
seller protest filed under this section, the Chief Administrative Law
Judge is authorized to issue such procedural orders, including orders
setting matters for hearing, severing and consolidating proceedings, and
certifying questions to the Commission, as he determines necessary or
appropriate for the expeditious consideration of such protests. The
Chief Administrative Law Judge may, by such order, authorize the
Administrative Law Judge to whom a protest is assigned to issue similar
procedural orders relating to that protest.
(8) Rules of practice and procedure. Part 385 of this chapter
(relating to rules of practice) will apply to such third party, staff,
first seller and pipeline protest proceedings except to the extent
otherwise provided by a procedural order issued by the Chief or
Presiding Administrative Law Judge under paragraph (h)(7) of this
section. Section 385.715 of this chapter will apply to any procedural
order issued under paragraph (h)(7) of this section.
(Order 94-A, 48 FR 5178, as amended by Order 94-B, 48 FR 5190, Feb.
3, 1983; Order 334, 48 FR 44507, Sept. 29, 1983; 48 FR 52031, Nov. 16,
1983; Order 408, 49 FR 49625, Dec. 21, 1984; Order 473, 52 FR 21668,
June 9, 1987; 52 FR 23030, June 17, 1987; Order 473-A, 53 FR 18, Jan.
4, 1988)
Editorial Note: For a document clarifying ''that a producer with an
area rate clause is entitled to collect a compression allowance in all
cases where there is no protest to its claims,'' see 55 FR 47743, Nov.
15, 1990.
18 CFR 271.1105 Compliance procedures under the Production-Related
Costs Board.
(a) Applicability. This section establishes a Production-Related
Costs Board to resolve disputes regarding:
(1) The appropriate allowance that a seller in a first sale is
authorized to collect under 271.1104 for production-related costs in
excess of the otherwise applicable maximum lawful price; and
(2) The amount of refunds that may be due as the result of a seller
in a first sale collecting an amount not authorized to be collected
under 271.1104.
(b) Definitions. The definitions of decisional authority, presiding
officer, party, participant, and respondent in 385.102 of this chapter
apply, except that ''party'' also means the seller or purchaser of
natural gas in a transaction involving production-related costs.
(c) Nature of the Board. (1) The Production-Related Costs Board
(Board) is a panel of at least two members of the Commission staff that
the Commission is designating as the presiding officer and decisional
authority to make determinations under this section.
(2) The members of the Board are appointed by the Chairman of the
Commission.
(3) Any decisions of the Board will become the Commission's decision
unless Commission review is requested under paragraph (h) of this
section.
(d) Initiation of proceedings -- (1) General rule. A proceeding
before the Board may be initiated:
(i) By staff under paragraph (d)(2) of this section if, pursuant to a
compliance audit and in accordance with paragraph (d)(2), it finds
probable non-compliance with 271.1104;
(ii) By any person or party that files a complaint in accordance with
paragraph (d)(3) of this section; or
(iii) By Commission referral to the Board of any production-related
cost issues, in accordance with paragraph (d)(4) of this section.
(2) Referral to Board after compliance audit -- (i) Notice. If a
compliance audit conducted by Commission staff indicates a probable
non-compliance with 271.1104 such that reimbursement or refund may be
due, the Director of the Office of Pipeline and Producer Regulation or a
designee (Director) will notify the seller of the probable violation in
writing. A copy of the notice shall be sent to any other affected
party.
(ii) Response. Within sixty days of the date of the Director's
notice under this paragraph, the seller in alleged non-compliance must
respond, as appropriate, by either:
(A) Filing with the Commission a refund report that identifies the
subject contract(s) and specifies the amount of the overcharges and the
interest to be refunded, the date(s) on which any overcharges were made,
and the date(s) on which any refunds were paid; or
(B) Submitting a written statement to the Director that sets forth
the reasons why it believes that no violation has occurred, or that a
refund is not due or is not due in the amount stated in the Notice.
(iii) Referral to Board. The Director will refer the matter to the
Board for resolution if, after the expiration of the sixty days from the
date of the notice, the seller in alleged non-compliance:
(A) Has not responded in accordance with this paragraph;
(B) Has not filed a refund report with the Commission, as
appropriate; or
(C) Has not resolved, to the Director's satisfaction, any question as
to the collection or collectibility of an allowance for
production-related costs.
(3) Complaint procedure. The Board will consider any complaint,
filed by any party or person in accordance with 385.206 of this
chapter, that alleges either that:
(i) An allowance for production-related costs was collected or is
being charged by a seller contrary to 271.1104 of this chapter; or
(ii) A purchaser is refusing to pay an allowance for
production-related costs that it believes is contrary to 271.1104 of
this chapter.
(4) Referral by the Commission. The Commission may, by order, refer
to the Board for disposition in accordance with this section, any
production-related cost issue under 271.1104 that may arise in other
proceedings, as appropriate.
(e) Notice by Board. Upon referral of a matter to the Board under
paragraph (d) of this section, the Board will initiate an informal
proceeding by publishing in the Federal Register and serving on the
parties a Notice that contains:
(1) A brief explanation of the nature of the dispute;
(2) The identity of the parties; and
(3) Any other appropriate matter.
(f) Intervention. A motion to intervene in a proceeding before the
Board must be filed with the Commission in accordance with 385.214 of
this chapter not later than 15 days after publication of the Notice in
the Federal Register under paragraph (e) of this section.
(g) Proceedings before the Board. (1) Any proceeding before the
Board will be informal. Subpart E of part 385 does not apply.
(2) Participants and parties will be given an opportunity to submit
written comments, data, views, and arguments to the Board. If the Board
finds that oral presentations would be useful, the parties will be
afforded an opportunity to participate in a public hearing before the
Board.
(3) At any time during the proceeding, the Board, in its discretion,
may:
(i) Request additional written submissions from the parties;
(ii) Establish any procedures necessary for a full and fair
disclosure of the facts or provide any procedural relief; and
(iii) Issue notices to carry out this section.
(h) Determinations by the Board. (1) As soon as practicable after
receipt of the written comments or after a hearing, if one is held, the
Board will issue an order either summarily disposing of the matter,
wholly or in part, for good cause, or determining the allowability of
any disputed amount and, if appropriate, requiring the seller to make a
refund including interest calculated in accordance with the provisions
of 154.102 of this chapter. The Board will serve the order on the
parties to the proceeding.
(2) Any order of the Board under this paragraph is final 30 days
after issuance, unless, during that period, an aggrieved party files a
petition for review pursuant to 385.1902 of this chapter.
(i) Referral to Enforcement Division. Nothing in this section shall
preclude Staff, the Board, or the Commission from referring matters
involving disputed amounts under this section to the Enforcement
Division of the Office of the General Counsel for appropriate action.
(Order 334, 48 FR 44494, Sept. 29, 1983)
18 CFR 271.1106 Adjustments.
For procedures to obtain an adjustment on the grounds of special
hardship, inequity, or unfair distribution of burdens, see subpart K of
part 385 of this chapter.
(Order 94, 45 FR 53116, Aug. 11, 1980, as amended by Order 94-A, 48
FR 5180, Feb. 3, 1983)
18 CFR 271.1106 PART 272 -- DEREGULATED NATURAL GAS
Sec.
272.101 Applicability.
272.102 Price deregulation.
272.103 Definitions.
272.104 Special rules for measuring the depth of deregulated natural
gas.
272.105 Separate billing.
Authority: Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432
(1988); Natural Gas Wellhead Decontrol Act of 1989, Pub. L. 101-60,
July 26, 1989.
18 CFR 272.101 Applicability.
This part implements section 121 of the NGPA and applies to the first
sale of natural gas which is deregulated natural gas.
(Order 476, 52 FR 26474, July 15, 1987)
18 CFR 272.102 Price deregulation.
(a) No maximum lawful price applies to any first sale of deregulated
natural gas.
(b) For special rules on:
(1) Circumvention of maximum lawful prices, see 270.207; and
(2) Interim and retroactive collection, see 273.202 (a)(2) and
(d)(1)(i)(B), 273.203(a)(2) and 273.204(a)(2).
(Order 78, 45 FR 28098, Apr. 26, 1980, as amended by Order 406, 49 FR
46884, Nov. 29, 1984)
18 CFR 272.103 Definitions.
(a) Deregulated natural gas means:
(1) Natural gas for which a jurisdictional agency determination has
become final under parts 274 and 275 that the gas qualifies as:
(i) Deep, high-cost natural gas;
(ii) Gas produced from geopressured brine;
(iii) Occluded natural gas produced from coal seams; or
(iv) Gas produced from Devonian shale.
(2) Natural gas for which a jurisdictional agency determination
becomes final under parts 274 and 275 and which is sold in a first sale
on or after January 1, 1985, and such gas qualifies as:
(i) New natural gas as defined in 271.203;
(ii) Natural gas produced from any new, onshore production well if
such gas as defined in 271.303:
(A) Was not committed or dedicated to interstate commerce (as defined
in NGPA section 2(18)) on April 20, 1977; and
(B) Is produced from a completion location which is located at a
depth of more than 5,000 feet.
(3) Natural gas for which a jurisdictional agency determination
becomes final under parts 274 and 275 of this chapter and which is sold
in a first sale on or after July 1, 1987, and such gas qualifies as
natural gas produced from any new, onshore producton well if such gas as
defined in 271.303:
(i) Was not committed or dedicated to interstate commerce (as defined
in NGPA section 2(18)) on April 20, 1977; and
(ii) Is produced from a completion location which is located at a
depth of 5,000 feet or less.
(4) Natural gas sold under an existing intrastate contract, any
successor to an existing intrastate contract, or any intrastate rollover
contract, if:
(i) Such natural gas was not committed or dedicated to interstate
commerce on November 8, 1978; and
(ii) In the case of any existing or successor intrastate contract,
(A) The price paid for the last deliveries of such natural gas
occurring on December 31, 1984, or, if no deliveries occurred on such
date, the price that would have been paid if deliveries occurred on such
date is higher than $1.00 per MMBtu, and
(B) Such gas is not subject to the maximum lawful price in
271.502(b); or
(iii) In the case of any rollover contract, the price paid on
December 31, 1984, or if no deliveries occurred on such date, the price
that would have been paid had deliveries occurred on such date is higher
than $1.00 per MMBtu.
(5) Natural gas to which no first sale contract applies on July 26,
1989.
(6) Natural gas to which a first sale contract applies on July 26,
1989, but to which such contract expires or terminates after that date.
Such gas is deregulated as of the date such contract expires or
terminates.
(7) Natural gas to which a first sale contract applies on July 26,
1989, where the parties have expressly agreed in writing after March 23,
1989, that all or part of the gas sold under such contract shall not be
subject to any maximum lawful price. Such gas is deregulated as of the
date specified by the parties, but not before July 26, 1989.
(8) Natural gas to which a first sale contract applies on July 26,
1989, and which is produced from a well the surface drilling of which
began after July 26, 1989. Such gas is deregulated on May 15, 1991, or
the date on which that contract expires or is terminated, whichever is
earlier.
(b) Deep, high-cost natural gas is natural gas which is produced:
(1) From any well, the surface drilling of which began on or after
February 19, 1977; and
(2) From a completion location which is located at a depth of more
than 15,000 feet.
(c) Natural gas produced from geopressured brine is natural gas which
is dissolved before initial production of the natural gas in subsurface
brine aquifers with at least 10,000 parts of dissolved solids per
million parts of water and with an initial reservoir geopressure
gradient in excess of 0.465 pounds per square inch for each vertical
foot of depth.
(d) Occluded natural gas produced from coal seams means naturally
occurring natural gas released from entrapment from the fractures, pores
and bedding planes of coal seams.
(e) Natural gas produced from Devonian shale means natural gas
produced from fractures, micropores and bedding planes of shales
deposited during the Paleozoic Devonian Period.
(1) Shales deposited during the Paleozoic Devonian Period can be
defined as either:
(i) The gross Devonian age stratigraphic interval encountered by a
well bore, at least 95 percent of which has a gamma ray index of 0.7 or
greater; or
(ii)(A) Except as provided in paragraph (e) (ii) (B) of this section,
one continuous interval within the gross Devonian age stratigraphic
interval, encountered by a well bore, as long as at least 95 percent of
the selected Devonian shale interval has a gamma ray index of 0.7 or
greater.
(B) If the interval selected is more than 200 feet thick, the bottom
and top 100 foot portions must meet the five percent test independently.
(2) When measuring the Devonian age stratigraphic interval under
paragraph (e)(1) of this section, the gamma ray index at any point is to
be calculated by dividing the gamma ray log value at that point by the
gamma log value at the shale base line established over the entire
Devonian age interval penetrated by the well bore.
(Order 78, 45 FR 28098, Apr. 26, 1980, as amended by Order 406, 49 FR
46884, Nov. 29, 1984; Order 406-A, 49 FR 50642, Dec. 31, 1984; Order
476, 52 FR 26475, July 15, 1987; Order 501, 53 FR 28194, July 27, 1988;
Order 523, 55 FR 17431, Apr. 25, 1990)
Editorial Note: For a document relating to clarification that ''the
gamma ray index should be calculated for the entire Devonian age
interval when the producer is seeking to qualify the well under
272.103(e)(1)(i) or for the selected interval when the producer is
seeking to qualify the well under 272.103(e)(1)(ii)'', see 55 FR 3944,
Feb. 6, 1990.
18 CFR 272.104 Special rules for measuring the depth of deregulated
natural gas.
For purposes of determining the depth of a completion location under
272.103(a)(2)(ii)(B), 272.103(a)(3)(ii), and 272.103(b), measurement
shall be the true vertical depth from the surface location to the
highest perforation point in the completion location.
(Order 476, 52 FR 26475, July 15, 1987)
18 CFR 272.105 Separate billing.
All first sales of deregulated natural gas, and gas for which an
application that the gas qualifies as deregulated natural gas is
pending, shall be billed separately from all other sales of gas.
(Order 78, 45 FR 28098, Apr. 26, 1980, as amended by Order 406, 49 FR
46884, Nov. 29, 1984)
18 CFR 272.105 PART 273 -- COLLECTION AUTHORITY; REFUNDS
18 CFR 272.105 Subpart A -- General Provisions
Sec.
273.101 Private contractual rights.
273.102 Definition of final eligibility determination.
273.103 General provisions relating to filing and notice.
273.104 Cross reference.
18 CFR 272.105 Subpart B -- Interim Collection Authority
273.201 Transitional rule for certain new wells.
273.202 Collection pending jurisdictional agency determination of
eligibility.
273.203 Collection pending review of jurisdictional agency
determination.
273.204 Retroactive collection after final determination.
18 CFR 272.105 Subpart C -- Refund Obligation
273.301 General refund obligation.
273.302 Refunds of interim collections.
Authority: Natural Gas Act, 15 U.S.C. 717-717w (1982); Department
of Energy Organization Act, 42 U.S.C. 7102-7352 (1982); E.O. 12009, 3
CFR 1978 Comp., p. 142; Natural Gas Policy Act of 1978, 15 U.S.C.
3301-3432 (1982), unless otherwise noted.
Source: Order 36, 44 FR 37496, June 27, 1979, unless otherwise
noted.
18 CFR 272.105 Subpart A -- General Provisions
18 CFR 273.101 Private contractual rights.
Authorization by this part to collect a price for natural gas does
not affect any person's contractual right to purchase natural gas at a
lower price.
18 CFR 273.102 Definition of final eligibility determination.
(a) For purposes of this part, eligibility determination means
(1) An affirmative or negative determination by a jurisdictional
agency respecting eligibility for a particular well or new OCS lease to
collect a deregulated price under part 272 or a maximum lawful price
under subpart B, C, G or H of part 271, and
(2) Any Commission finding affirming or reversing such a
jurisdictional agency determination.
(b) An eligibility determination becomes final
(1) In the case of a jurisdictional agency determination which is
reversed or affirmed by a final finding by the Commission, at such time
as the Commission's finding is no longer subject to judicial review
under section 503(b)(4)(B) of the NGPA; and
(2) In any other case, at such time as such determination is no
longer subject to remand or reversal (other than on grounds specified in
section 503(d)(1)(A) or (B) of the NGPA) by the Commission under part
275.
(Order 36, 44 FR 37496, June 27, 1979, as amended by Order 479, 52 FR
29007, Aug. 5, 1987)
18 CFR 273.103 General provisions relating to filing and notice.
(a) Who must file. Except as provided in paragraph (b) of this
section, any seller making an interim collection under this part shall
make the filings and serve the notices required by this part. Sellers
include persons owning a working interest in a well and royalty interest
owners who take the royalty in kind and sell the natural gas taken in
kind; other royalty owners are not required to make filings and serve
notices under this part.
(b) Persons designated to file and serve notice. A seller required
to make filings and serve notices under this part may, with respect to
any well for which filings and notices are made, designate any other
working interest owner of the well, the operator of the well (whether or
not such operator is a working interest owner), or a royalty interest
owner in the well, to make the filings and serve the notices required by
this part. Such designation shall not relieve the seller of the
obligation to make the filings and serve the notices required by this
part unless a filing is made or notice is served on behalf of such
seller by the person designated under this paragraph.
(c) Content of filing or notice. Any person making a filing or
serving a notice on behalf of any seller shall identify by name and
address each seller on whose behalf the filing is made or the notice is
served.
(Natural Gas Act, as amended, 15 U.S.C. 717, et seq.; Department of
Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267;
Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432, Administrative
Procedure Act, 5 U.S.C. 553)
(Order 131, 46 FR 12203, Feb. 13, 1981)
18 CFR 273.104 Cross reference.
(a) For special rule applicable to resellers, see 270.202(b).
(b) For special rule applicable to certain jurisdictional
applications for stripper well determination, see 271.807(e).
(c) For special rule applicable to withdrawal of an application for a
well determination before the Commission, see 275.202(d)(4).
(Natural Gas Act, as amended, 15 U.S.C. 717, et seq.; Department of
Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267;
Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432, Administrative
Procedure Act, 5 U.S.C. 553)
(Order 36, 44 FR 37496, June 27, 1979, as amended by Order 131, 46 FR
12203, Feb. 13, 1981)
18 CFR 273.104 Subpart B -- Interim Collection Authority
18 CFR 273.201 Transitional rule for certain new wells.
(a) General rule. (1) The price determined under 271.902 of this
section may be charged and collected for any first sale of natural gas
from a new well to which this section applies.
(2) This section does not apply to a first sale if the seller is
collecting a price under the authority of 273.202 or 273.203.
(b) Period of collection. (1) Except as provided in paragraph (b)(2)
of this section, the price authorized by paragraph (a) of this seciton
may be charged and collected for natural gas deliveries:
(i) Beginning on the date on which the seller first meets the
requirements of paragraph (c) of this section; and
(ii) Ending on the date on which the Commission receives a notice of
jurisdictional agency determination under 274.104.
(2) No collection may be made under this section for deliveries of
natural gas on or after March 1, 1979, unless before March 1, 1979, the
seller has filed an application with a jurisdictional agency for a
determination respecting such natural gas under subpart B, C, G, or H of
part 271.
(c) Filing requirements. (1) Prior to making any collection under
the authority of this section, the seller shall file with the Commission
and the jurisdictional agency a statement under oath that:
(i) The natural gas for which the collection is made is produced from
a new well;
(ii) The seller believes in good faith that such natural gas is
eligible under the NGPA to be sold at a price not less than the price
specified in paragraph (a) of this section; and
(iii) The seller has filed, or will cause to be filed not later than
March 1, 1979, an application with the jurisdictional agency for a
determination of qualification under subpart B, C, G, or H of part 271.
Where the seller is not eligible to apply directly for a determination,
the seller shall file either a duplicate of FERC Form No. 121 already
submitted to the jurisdictional agency or a statement under oath by a
person eligible to file the application that it will be filed not later
than March 1, 1979.
(2) The statement shall include any well identification number
assigned to the well or if none has been assigned, other information
sufficient to identify the well, and shall specify the extent to which
such natural gas was committed or dedicated to interstate commerce on
November 8, 1978, and if so committed or dedicated, the just and
reasonable rate applicable to such natural gas under the Natural Gas Act
on November 8, 1978, and any rate schedules for such natural gas on file
with the Commission on November 8, 1978.
18 CFR 273.202 Collection pending jurisdictional agency determination
of eligibility.
(a) General rule. (1) If an application has been filed with the
jurisdictional agency for a determination of eligibility under subpart
B, C, G, or H of part 271 (relating to new natural gas and certain OCS
natural gas, natural gas from new onshore production wells, regulated
high-cost natural gas or stripper well natural gas), the price specified
in 273.201(a)(1) or the highest maximum lawful price which is specified
in any of the subparts for which application is made may be charged and
collected.
(2) If an application has been filed with the jurisdictional agency
for a determination of eligibility under part 272 (relating to
deregulated natural gas), the deregulated price may be charged pending
the jurisdictional agency determination.
(b) Period of collection. Except to the extent prohibited by
paragraph (c) of this section, the price authorized by paragraph (a) of
this section may be charged for natural gas deliveries occurring on or
after the date on which the application is filed with the jurisdictional
agency and may be collected for such deliveries:
(1) Beginning on the date on which the seller complies with the
requirements of paragraph (d) of this section; and
(2) Ending on the earlier of:
(i) 12 months after the first delivery for which collection is made
under this section (18 months in the case of deliveries beginning before
May 1, 1979), but in no case before July 31, 1980; or
(ii) The date on which the Commission receives a notice of
jurisdictional agency determination under 274.104.
(c) Special limitation on collections. No filing may be made under
this section unless (1) the Commission has given public notice that the
jurisdictional agency has filed a report in conformance with 274.105,
and (2) the jurisdictional agency has notified the Commission in writing
that such agency has the authority to process applications for
determinations under subparts B, C, G and H of part 271 and is making
such determinations.
(d) Conditions and filings. In order to make an interim collection
under this section with respect to a first sale of natural gas a seller
must meet the following conditions:
(1) If the natural gas was committed or dedicated to interstate
commerce on November 8, 1978, and subject to a rate schedule on file
with the Commission under the Natural Gas Act, the seller shall file
with the Commission a notice of intent to make interim collection under
this section. The notice shall specify the category under part 271 and
the applicable rate schedule on file with the Commission for the natural
gas for which an application has been filed under part 274 and for which
interim collection is intended to be made. The notice shall also
include the just and reasonable rate applicable to such natural gas
under the Natural Gas Act on November 8, 1978, and a copy of the FERC
Form No. 121 submitted to the jurisdictional agency. If a notice is
filed with the Commission under this subparagraph, no filing shall be
required for any subsequent interim collection for gas under the same
category and rate schedule contained in the filing.
(2) The seller shall serve each purchaser a notice of intent to make
interim collection pursuant to this section. The notice shall include a
copy of the FERC Form No. 121 submitted to the jurisdictional agency,
and a duplicate of any items filed with the Commission under paragraph
(d)(1) of this section.
(3) If requested by a purchaser, the seller must secure by a surety
bond or hold in escrow any amount collected under this section which, in
the case of a new well, is in excess of the price specified in
273.201(a)(1), or in the case of any other well, is in excess of the
otherwise applicable maximum lawful price. Such surety bond or escrow
shall be in a form satisfactory to the purchaser.
(e) Limitation. Upon termination of the interim collection authority
for any first sale, no further interim collections can be made for any
first sales of natural gas from the same well unless any previous
affirmative determination qualified gas from the well to be eligible
under subpart B, C, G, or H of part 271.
(Natural Gas Act, as amended, 15 U.S.C. 712-717, and, Department of
Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267;
Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432, Administrative
Procedure Act, 5 U.S.C. 553)
(Order 36, 44 FR 37496, June 27, 1979, as amended by Order 78, 45 FR
28098, Apr. 28, 1980; 45 FR 30068, May 7, 1980; Order 131, 46 FR
12203, Feb. 13, 1981; Order 406, 49 FR 46884, Nov. 29, 1984)
18 CFR 273.203 Collection pending review of jurisdictional agency
determination.
(a) General rule. (1) If the jurisdictional agency has determined in
accordance with part 274 that natural gas qualifies for a maximum lawful
price under subpart B, C, G, or H of part 271, the seller may charge and
collect such price during the period described in paragraph (b) of this
section.
(2) If a jurisdictional agency has determined in accordance with part
274 that natural gas qualifies under part 272 (relating to deregulated
natural gas), the seller may charge and collect the deregulated price
during the period described in paragraph (b) of this section.
(b) Period of collection. The price authorized by paragraph (a) of
this section may be charged and collected for natural gas deliveries:
(1) Beginning on the date on which the Commission receives notice
under 274.104(a) of an affirmative determination of a jurisdictional
agency with respect to such gas; and
(2) Ending on the date the eligibility determination for such gas
becomes final, except that (i) if the determination of the
jurisdictional agency is remanded by final finding of the Commission,
such period ends 6 months after the date of such remand, and (ii) if the
determination of the jurisdictional agency is reversed by final finding
of the Commission pursuant to 275.202(g), such period ends on the date
of such final finding by the Commission.
(c) Conditions and filings. Unless the seller previously has
complied with the conditions and filings set forth in 273.202(d), in
order to make an interim collection under this section with respect to a
first sale of natural gas, the seller shall undertake the conditions and
filings described in 273.202(d).
(Natural Gas Act, as amended, 15 U.S.C. 712-717 and 717, et seq.;
Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O.
12009, 42 FR 46267; Natural Gas Policy Act of 1978, 15 U.S.C.
3301-3432; Administrative Procedure Act, 5 U.S.C. 553)
(Order 36, 44 FR 37496, June 27, 1979, as amended at 44 FR 66789,
Nov. 21, 1979; Order 78, 45 FR 28099, Apr. 28, 1980; Order 131, 46 FR
12203, Feb. 13, 1981; Order 406, 49 FR 46885, Nov. 29, 1984)
18 CFR 273.204 Retroactive collection after final determination.
(a) General rule. Subject to the provisions of paragraphs (b) and
(c) of this section:
(1) if an eligibility determination that first sales of natural gas
from a well qualify for a maximum lawful price under subpart B, C, G, or
H of part 271 has become final under parts 274 and 275, and such maximum
lawful price exceeds the price collected for deliveries of such natural
gas for any period between the date of filing for the determination and
the date on which the eligibility determination became final, then the
seller may retroactively charge and collect for such period the amount
of such excess; except that:
(i) If the application for determination was filed before April 1,
1979, then the amount of such excess may be computed, charged, and
collected for first sales of natural gas delivered after November 30,
1978.
(ii) In the case of tight formation gas (as defined in 271.703(b)),
the amount of such excess may be computed, charged, and collected for
first sales of such natural gas delivered on or after July 16, 1979.
(iii) In the case of qualified production enhancement gas (as defined
in 271.704(c)), the amount of such excess may be computed, charged, and
collected for first sales of such natural gas delivered on or after the
date that the production enhancement work was completed.
(iv) In the case of new natural gas (as defined in 271.203) and
natural gas produced from a new, onshore production well (as defined in
271.303) which also satisfies the criteria of 272.103(a)(2)(ii), if the
application for determination was filed on or before January 1, 1985,
then for first sales of such natural gas delivered on or after January
1, 1985, the seller may retroactively collect the amount by which the
deregulated price exceeds the price collected during such period.
(v) In the case of natural gas produced from a new, onshore
production well (as defined in 271.303) which also satisfies the
criteria of 272.103(a)(3), if the application for determination was
filed on or before July 1, 1987, then for first sales of such natural
gas delivered on or after July 1, 1987, the seller may retroactively
collect the amount by which the deregulated price exceeds the price
collected during such period.
(2) If an eligibility determination that first sales of natural gas
from a well are deregulated under part 272.103(a)(1) has become final
under parts 274 and 275, the seller may retroactively charge and collect
for any period between the date of filing for the determination and the
date on which the eligibility determination became final, the amount by
which the price permitted under the sales contract exceeds the price
collected during such period, except that if the application for
determination was filed on or before June 23, 1980, then the amount of
such excess may be computed, charged and collected for first sales of
such natural gas delivered on or after November 1, 1979.
(b) Special limitation on retroactive collection. Retroactive
collections otherwise authorized by paragraph (a) of this section may
not be collected for a period after April 1, 1979 and prior to the later
of the date on which (1) the Commission has given public notice that the
jurisdictional agency has filed a report in conformance with 274.105,
and (2) the jurisdictional agency has notified the Commission in writing
that such agency has the authority to process applications for
determinations under subparts B, C, G and H of part 271 and is making
such determinations.
(c) Conditions and filings. In order to make a retroactive
collection under this section with respect to a first sale of natural
gas a seller must satisfy the following conditions and filings:
(1) Retroactive collections may not begin until 45 days after the
eligibility determination becomes final.
(2) A seller may not collect any amount under this section from any
purchaser unless the seller has paid to such purchaser all amounts that
are due to be refunded under this subchapter by the seller to such
purchaser on or before any date on which retroactive collections are
made.
(3) If the natural gas was committed or dedicated to interstate
commerce on November 8, 1978, is subject to a rate schedule on file with
the Commission, and if the provisions of the Natural Gas Act continue to
apply after a determination has become final, within fifteen (15) days
after a retroactive collection begins for any first sale, the seller
shall file with the Commission, and shall serve concurrently each
purchaser of the gas, a notice of retroactive collection under this
section. The notice shall specify:
(i) The category under part 271 and the applicable rate schedule on
file with the Commission for gas for which retroactive collection is
undertaken and
(ii) The just and reasonable rate applicable to such natural gas
under the Natural Gas Act on November 8, 1978.
(4) Collection under this section may be made only to the extent
permitted by the applicable sales contract.
(5) Carrying charges may be collected only to the extent provided by
a written agreement of the parties to the applicable sales contract (or
amendment thereto). The carrying charges shall be computed at an
interest rate which does not exceed the rate specified in 154.102(c).
(Department of Energy Organization Act, 42 U.S.C. 7101, et seq.; E.O.
12009, 42 FR 46267; Natural Gas Policy Act of 1978; (15 U.S.C.
3301-3432); Administrative Procedure Act, 5 U.S.C. 553)
(Order 36, 44 FR 37496, June 27, 1979, as amended by Order 78, 45 FR
28099, Apr. 28, 1980; Order 99, 45 FR 56046, Aug. 22, 1980; Order 107,
45 FR 77430, Nov. 24, 1980; Order 113, 46 FR 12204, Feb. 13, 1981; 49
FR 3644, Jan. 30, 1984; Order 406, 49 FR 46885, Nov. 29, 1984; Order
406-A, 49 FR 50642, Dec. 31, 1984; Order 476, 52 FR 26475, July 15,
1987)
18 CFR 273.204 Subpart C -- Refund Obligation
18 CFR 273.301 General refund obligation.
The acceptance of a first sale price under this part by any person
obligates such person, his successors, heirs, and assigns to refund any
portion of any amount accepted which is in excess of the applicable
maximum lawful price or the collection of which is not authorized by
this subchapter, without regard to whether the seller has made a filing
required by part 273 or has designated a person to make such filings on
his behalf.
18 CFR 273.302 Refunds of interim collections.
(a) Applicability. The provisions of this section apply to any
interim collections made under the authority of subpart B of this part.
(b) Refund obligations. (1) Any interim collection under this part,
whether made by a seller or any person designated by a seller pursuant
to 273.103(b), shall constitute a general undertaking to comply with
the refund provisions of this subpart by the designee and any seller on
whose behalf the collection is made.
(2) Additional refund assurance may be required at any time by order
of the Commission.
(c) Escrow. For special rule applicable to escrow of amounts
received during interim collections, see 273.202(d)(3).
(d) Records. (1) If any interim collection is made under subpart B,
for each billing period and for each purchaser the seller shall keep
accurate accounts of:
(i) The price charged pursuant to subpart B of this part;
(ii) Resulting revenues as computed under the price being charged
pursuant to this part;
(iii) The maximum lawful price that would have been applicable if
interim collections under subpart B of this part had not been made;
(iv) The revenues that would have been collected under the maximum
lawful price described in paragraph (d)(1)(iii) of this section; and
(v) The difference in revenues described in paragraphs (d)(1) (ii)
and (iv) of this section.
(2) Such books and records shall be retained for a period of three
(3) years after the termination of the interim collection period. Any
contract under which any interim collections have occurred must be
preserved for three (3) years after its expiration.
(e) Refund payments. (1)(i) Except as provided in paragraph
(e)(1)(ii) of this section, within sixty (60) days after a determination
becomes final denying a first sale eligibility for the price collected
under this part, or within sixty (60) days after the date on which an
application for determination is withdrawn by the applicant, while it is
before the Commission or the jurisdictional agency, the seller must
refund to the purchaser the refund amount computed under paragraph (h)
of this section together with interest determined in accordance with
154.102(c) and (d) of this chapter on the excess charges that have been
collected from the date of payment until the date of refund.
(ii) If a refund required by paragraph (e)(1)(i) of this section is
made through a billing adjustment, the seller and purchaser may agree
that the billing adjustment will be completed in a reasonable period
which may exceed sixty (60) days.
(iii) A purchaser may not use a billing adjustment to recover a
refund required by paragraph (e)(1)(i) of this section before the
expiration of the sixty (60) day period for the seller to make the
refund unless the seller has previously agreed to the billing
adjustment. If the seller fails to make a refund within the sixty (60)
day period, the purchaser may use a billing adjustment to recover the
refund without agreement by the seller. Before making a billing
adjustment, a purchaser must provide the seller written notice of the
amount of the refund to be recovered and the time period during which
the billing adjustment will be completed.
(2) No interest is required to be paid on any portion of a refund:
(i) Which represents payments of royalties of taxes of Federal or
State governmental authorities, except to the extent that such
authorities pay interest to the seller when refunding overpayments of
royalties or taxes; or
(ii) Which is paid from escrow except that interest which accrued in
the escrow account on the amount required to be refunded shall be paid
at the time of refund.
(f) Filing requirements -- (1) Sellers. (i) Except as provided in
paragraph (f)(1)(ii), within ninety (90) days of either the date a final
determination of eligibility is obtained that the sale is not eligible
for the price category stated in the application for determination, or
the date a seller withdraws an application, the seller must:
(A) File with the Commission (1) an original and two copies of a
refund report showing, for each purchaser, the amount of overcharges and
interest to be refunded, as determined in accordance with paragraph (e)
of this section, the dates on which any refunds were due, and the dates
on which refunds were paid; or
(2) A statement certifying that no refund is due under this section.
Either the refund report or the certification that no refund is required
must include the following information: the well name; the American
Petroleum Institute Well Number, if available; the jurisdictional
agency with which the application for determination was filed; and, if
applicable, the date of withdrawal of the application; and
(B) File with the Commission (1) a statement of concurrence by the
purchaser that all proper refunds have been made; or
(2) If a purchaser does not submit a statement of concurrence to the
seller, a statement that no concurrence was received.
(ii) A seller is not required to include in a report filed under
paragraph (f)(1)(i) any information regarding a refund recovered by an
interstate pipeline through a billing adjustment.
(2) Interstate pipelines. (i) An interstate pipeline must include
with any Purchased Gas Adjustment filing under 154.301 through 154.310
of this chapter, a refund report identifying all billing adjustments
that are reflected in the interstate pipeline's PGA filing to effect
refunds required to be made to it by sellers under paragraph (e) of this
section. The interstate pipeline must file with the Commission the
original and two copies of the refund showing for each seller:
(A) The amounts of overcharges and interest to be refunded by that
seller as determined in accordance with paragraph (e) of this section;
(B) The dates on which any refunds by the seller were due;
(C) The amounts of, and the dates on which, billing adjustments were
made by the pipeline to satisfy the seller's refund obligations under
paragraph (e) of this section in whole or in part;
(D) The well name and, if available, American Petroleum Institute
Well Number of the well that produced the natural gas for which the
interstate pipeline was overcharged by that seller; and
(E) If applicable, the date of withdrawal of the seller's
application.
(ii) If the interstate pipeline does not submit a statement of
concurrence to the seller concerning refunds under 273.302 of this
chapter, the interstate pipeline must submit to the Commission such
concurrence or a statement indicating the reason for its refusal to
submit its concurrence with the seller. The interstate pipeline's
submission is due within thirty (30) days of the date that a refund
report or statement that does not include a statement of concurrence by
the purchaser is filed by the seller. A duplicate of the submission
must be served upon the seller.
(g) Satisfaction and discharge of obligation. If a determination
becomes final that natural gas is eligible for at least the price stated
in the application filed with the jurisdictional agency, then at such
time the bond, escrow or other security undertaking shall become
discharged to the extent it applies to first sales from the well for
which the determination was made. If any refunds required by this
section are made in conformity with the terms of the bond, escrow or
other security undertaking, any remaining amounts of the bond, escrow or
other security undertaking not used in satisfying the refund obligations
shall be returned to the seller.
(h) Refund computation. (1) Where the final eligibility
determination that the sale is not eligible for at least the price
collected under subpart B also includes a final eligibility
determination of the maximum lawful price for that sale, that finally
determined price, to the extent permitted by the applicable sales
contract, shall be used to compute the excessive interim collections and
refund amount.
(2) In any other case, the appropriate maximum lawful price specified
under subpart D, E, F, or I of part 271, to the extent permitted by the
applicable sales contract, shall be used to compute the excessive
interim collections and refund amount.
(Natural Gas Act, as amended, 15 U.S.C. 717, et seq.; Department of
Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267;
Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Administrative
Procedure Act, 5 U.S.C. 553; Department of Energy Organization Act, 42
U.S.C. 7101-7352; 42 CFR 142; Interstate Commerce Act, 49 U.S.C. 1, et
seq.; Natural Gas Act, 15 U.S.C. 717-717w)
(Order 36, 44 FR 37496, June 27, 1979, as amended by Order 131, 46 FR
12204, Feb. 13, 1981; Order 273, 48 FR 1288, Jan. 12, 1983; Order 423,
50 FR 23674, June 5, 1985; Order 483, 52 FR 43889, Nov. 17, 1987)
18 CFR 273.302 PART 274 -- DETERMINATIONS BY JURISDICTIONAL AGENCIES
18 CFR 273.302 Subpart A -- General Provisions
Sec.
274.101 Applicability.
274.102 Definition of determination.
274.103 Determinations by jurisdictional agencies.
274.104 Notice to the Commission.
274.105 Reports of determination process.
18 CFR 273.302 Subpart B -- Requirements for Filings with
Jurisdictional Agencies
274.201 General requirements.
274.202 New natural gas.
274.203 New reservoirs on old OCS leases.
274.204 New, onshore production wells.
274.205 High-cost natural gas.
274.206 Stripper well natural gas.
274.207 Alternative filing and notice requirements.
274.208 Alternative filing and notice requirements accepted by the
Commission.
18 CFR 273.302 Subpart C -- Waivers
274.301 Applicability.
274.302 Requests for waiver.
274.303 Termination or revocation of agreements.
274.304 Notice.
18 CFR 273.302 Supbart D -- Delegations to State Agencies
274.401 Delegation of authority to receive certain reports.
18 CFR 273.302 Subpart E -- Identification of State and Federal
Jurisdictional Agencies
274.501 Jurisdictional agency.
Authority: Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432
(1988); Department of Energy Organization Act, 42 U.S.C. 7101-7352
(1982).
Source: Order 41, 44 FR 48668, Aug. 20, 1979, unless otherwise
noted.
18 CFR 273.302 Subpart A -- General Provisions
18 CFR 274.101 Applicability.
This part applies to determinations of jurisdictional agencies (as
defined in 274.501) made under 272.103(a)(1) and the following
subparts of part 271:
(a) Subpart B (relating to new natural gas and certain OCS natural
gas);
(b) Subpart C (relating to new, onshore production wells);
(c) Subpart G (relating to high-cost natural gas); and
(d) Subpart H (relating to stripper well natural gas).
(Order 41, 44 FR 48668, Aug. 20, 1979, as amended by Order 406, 49 FR
46885, Nov. 29, 1984)
18 CFR 274.102 Definition of determination.
For purposes of this part and part 275, a determination has been made
by a jurisdictional agency when such determination is administratively
final before such agency.
18 CFR 274.103 Determinations by jurisdictional agencies.
A jurisdictional agency shall make determinations to which this part
applies in accordance with procedures applicable to it under the law of
its jurisdiction for making such determinations or for making comparable
determinations.
18 CFR 274.104 Notice to the Commission.
(a) Affirmative determinations. Except as provided in paragraph (c)
of this section, within 15 days after making a determination that
natural gas qualifies under this part, the jurisdictional agency shall
give written notice of such determination to the Commission. Unless
alternative notice requirements under 274.207 have been approved, such
notice shall include the following:
(1) A list of all participants in the proceeding as well as any
persons who submitted or who sought an opportunity to submit written
comments (whether or not such persons participated in the proceeding);
(2) A statement indicating whether the matter was opposed before the
jurisdictional agency;
(3) The information set forth in paragraphs (a)(1) through (7) of
274.105 as applied to the determination in question, unless the
jurisdictional agency has on file with the Commission a report
describing its determination process under that section;
(4) A copy of the application together with a copy or description of
all other materials upon which the jurisdictional agency relied in the
course of making the determination, together with any information which
may be inconsistent with the determination.
(5) The information required to be filed under subpart B of part 274,
under 274.207, or under paragraph 271.703(c)(4), and in any case in
which other materials in the record constitute portions of such
information, a copy of those portions of the record; and
(6) An explanatory statement, including appropriate factual findings
and references, which is sufficient to enable a person examining the
notice to ascertain the basis for the determination without reference to
information or data not contained in the notice.
(b) Negative determinations. Within 15 days after making a
determination that natural gas does not qualify under this part for a
maximum lawful price, the jurisdictional agency shall give written
notice of such determination to the Commission, including a copy of FERC
Form No. 121; except that if the applicant or any aggrieved party so
requests within the 15 days following the determination, the notice
shall be supplemented (within 20 days following the determination) to
include all of the information specified in paragraph (a) of this
section.
(c) Affirmative determinations under section 102(c)(1)(A).
Notification to the Commission by the U.S. Department of the Interior
Minerals Management Service of OCS leases issued on or after April 20,
1977, will constitute a determination that natural gas produced from
such lease qualifies as new natural gas under section 102(c)(1)(A).
Such notification shall be given within 60 days after the grant of a new
OCS lease and shall include the lease number, the area and block number,
and the date on which the lease was issued by the Secretary of the
Interior. Such notification will be treated as a notice of
determination under part 275.
(Order 41, 44 FR 48668, Aug. 2, 1979, as amended by Order 336, 48 FR
44518, Sept. 29, 1983; Order 406, 49 FR 46885, Nov. 29, 1984; Order
479, 52 FR 29007, Aug. 5, 1987)
18 CFR 274.105 Reports of determination process.
(a) Report. A jurisdictional agency may file with the Commission a
report which states that it will take such steps as are reasonably
necessary or appropriate to perform its functions under this part and
which describes the method by which such agency will make determinations
to which this part applies. The report shall be in narrative form and
shall include:
(1) Any filing requirements imposed by the jurisdictional agency in
addition to those required by subpart B of this part (including specific
forms), as well as any more specific identification of documents listed
as minimum requirements subpart B;
(2) The type of notice of filing that applicants will be required to
give;
(3) The public or specific notice that will be given by the agency of
filings, hearings, and determinations;
(4) The internal procedures applicable to such determinations,
including specific references to the use of hearings, examiners, and
formal consideration by the agency;
(5) The extent to which applicable rules permit interested parties to
intervene, participate, or express views in proceedings before the
agency;
(6) A description of the relevant data contained in the official
records of other agencies to which the jurisdictional agency has access;
and
(7) A detailed explanation of the manner in which the agency will
review applications, including identification of the official records
which will be examined.
(b) Change in procedures. The jurisdictional agency shall give
written notice to the Commission of any change in procedures described
in the report filed pursuant to this section.
(c) Public files. Reports and any changes thereto filed by the
jurisdictional agency will be placed in the public files of the
Commission.
18 CFR 274.105 Subpart B -- Requirements for Filings with Jurisdictional Agencies
18 CFR 274.201 General requirements.
(a) Filing requirements applicable if alternative requirements are
not adopted. The provisions of 274.201 through 274.206 of this
subpart apply to the extent not superseded by alternative filing
requirements which have taken effect under 274.207 and 274.208.
(b) Who may file. An application to which this subpart applies may
be filed with the jurisdictional agency and signed by any person the
jurisdictional agency designates as eligible to make filings with
respect to the well for which the application is made.
(c) Additional information. The documents required by this subpart
are the minimum required in support of a request for a determination.
The jurisdictional agency may require additional support as it deems
appropriate, and may more specifically identify the documents indicated
as the minimum required.
(d) Notice to purchasers. Where an application for a determination
is sought for natural gas for which the applicant has an identified
purchaser, the application shall include a statement that the applicant
has delivered or mailed a copy of the completed FERC Form No. 121 to
the purchaser.
(e) Filing fees. Each applicant must pay the fee prescribed in
381.402 of this chapter. The applicant will be billed annually by the
Commission for each jurisdictional agency determination received by the
Commission. The applicant shall submit the fee, or petition for waiver
pursuant to 381.106, within 30 days following the billing date.
(Order 65, 45 FR 3894, Jan. 21, 1980, as amended by Order 394, 49 FR
35364, Sept. 7, 1984)
18 CFR 274.202 New natural gas.
(a) Applications for determination. A person seeking a determination
for purposes of subpart B of part 271 that production from a well
qualifies as new natural gas shall file an application with the
jurisdictional agency for a determination that:
(1) Such production is from a new onshore well, in accordance with
paragraph (b) of this section; or
(2) Such production is from a new onshore reservoir, in accordance
with paragraph (c) of this section.
(b) New onshore wells. An application for a determination that a
well is a new onshore well may be filed under paragraph (b) (1) or (2)
of this section, or both.
(1) 2.5 mile test. For purposes of demonstrating that a new onshore
well is not within 2.5 miles of any marker well, the applicant shall
file:
(i) FERC Form No. 121;1
(ii) The well completion report;
(iii) The directional drilling survey, if the jurisdictional agency
requires such a survey to be conducted;
(iv) A location plat which locates and identifies the well for which
the determination is sought and any other well which produced natural
gas after January 1, 1970, and before April 20, 1977, and is within the
2.5 mile radius drawn from the well for which a determination is sought;
(v) A statement by the applicant under oath, that on the basis of the
results of the search and examination required by 274.202(d), he has
concluded that to the best of his information, knowledge and belief,
there is no marker well within 2.5 miles of the well for which he seeks
a determination;
(vi) The oath statements set forth in 274.202(d).
(2) 1,000 feet deeper test. For purposes of demonstrating that the
completion location of a new onshore well is at least 1,000 feet deeper
than the deepest completion location of each marker well within a 2.5
mile radius of the well for which a determination is sought, the
applicant shall file:
(i) FERC Form No. 121;
(ii) The well completion report;
(iii) Identification of the deepest completion location of the marker
well with the deepest completion location of all marker wells located
within 2.5 miles of the well for which the determination is sought;
(iv) A statement by the applicant, under oath, that on the basis of
the results of the search and examination required by 274.202(d), he
has concluded that to the best of his information, knowledge and belief,
there is no marker well within 2.5 miles of the well for which he seeks
a determination which has a completion location less than 1,000 feet
above the completion location of the new well; and
(v) The oath statements set forth in 274.202(d).
(c) New onshore reservoir. (1) For purposes of demonstrating that
production is from a new onshore reservoir, the applicant shall file:
(i) FERC Form No. 121; 1
(ii)(A) A copy of the state order issued on or after April 20, 1977,
designating new field or reservoir status to the subject reservoir, or
(B) If a state order is not available, such geological information
shall be submitted which includes to the extent reasonably available to
the applicant at the time the application is filed:
(1) Well logs;
(2) Bottom hole or surface pressmure surveys;
(3) Well potential tests;
(4) Formation structure maps;
(5) Subsurface cross-section charts; and
(6) Gas analyses.
If any of the information specified in paragraph (c)(1)(ii)(B) (1)
through (6) of this section has already been filed in a previous
application for determination with the same jurisdictional agency, and
such application and determination of eligibility for such application
are on file with the Commission, the applicant may submit, in lieu of
such information, a statement identifying such information and the
application by jurisdictional agency docket number, FERC docket or
control number, and the API well number.
(iii) The well completion report;
(iv) The directional drilling survey if the jurisdictional agency
requires such a survey to be conducted; and
(v) A statement by the applicant under oath that on the basis of the
results of the search and examination required in 274.202(d), he has
concluded that to the best of his information, knowledge and belief, the
natural gas to be produced and for which he seeks a determination is
from a new onshore reservoir;
(vi) The oath statement set forth in paragraphs (c)(2) and (d) of
this section.
(2) The applicant, in his statement under oath required under
paragraph (d) of this section, shall also answer, to the best of his
information, knowledge and belief, and on the basis of the results of
his search and examination, the following questions:
(i) Was natural gas produced in commercial quantities from the
reservoir prior to April 20, 1977?
(ii)(A) If the question in paragraph (c)(2)(i) of this section is
answered in the negative, was the reservoir penetrated before April 20,
1977, by an old well from which natural gas or crude oil was produced in
commercial quantities from any reservoir?
(B) If the question in paragraph (c)(2)(ii)(A) of this section is
answered in the affirmative, could natural gas have been produced in
commercial quantities from the reservoir before April 20, 1977, from any
old well described in paragraph (c)(2)(ii)(A) of this section?
(C) If the question in paragraph (c)(2)(ii)(B) of this section is
answered in the negative, were any sales and deliveries of natural gas
made from any other reservoir through any old well described in
paragraph (c)(2)(ii)(A) of this section prior to April 20, 1977, and
were any sales and deliveries of natural gas made from the subject
reservoir through such old well on or after April 20, 1977, and before
November 9, 1978?
(D) If the applicant is unable to answer both questions in paragraph
(c)(2)(ii)(C) of this section in the negative, he must demonstrate that
the Behind-the-Pipe Exclusion in section 102(c)(1)(C)(ii) of the NGPA
does not apply by submitting the following:
(1) Proof that a final eligibility determination has been made that
the subject reservoir is a new onshore reservoir by identifying such
determination by the jurisdictional agency and FERC Docket number and
the API well numbers, or,
(2) Evidence clearly demonstrating that the sale of production from
the subject reservoir (net of royalty) through any well described in
paragraph (c)(2)(ii)(A) of this section at the market price reasonably
available as of April 20, 1977 could not have generated revenues
sufficient to equal or exceed the sum of (i) 1.6 times the minimum
incremental costs properly allocable to such production of installing
cost-efficient facilities not in existence as of April 20, 1977,
reasonably required to market such production, plus (ii) the minimum
incremental expenses properly allocable to such production reasonably
required to operate such facilities. All costs, expenses and revenues
shall be determined as of April 20, 1977. The applicant shall also
provide an explanation of the basis of all estimates accompanied by
substantiating workpapers and such other evidence necessary to
substantiate fully the conclusion that the Behind-the-Pipe Exclusion
does not apply.
(iii)(A) If the natural gas is to be produced through an old well,
were suitable facilities for the production and delivery to a pipeline
of such natural gas in existence on April 20, 1977?
(B) If the question in paragraph (c)(2)(iii)(A) of this section is
answered in the affirmative, were such suitable facilities installed to
carry out sales and deliveries of natural gas under section 6 of the
Emergency Natural Gas Act of 1977 or under the emergency sale authority
pursuant to Opinion 699-B issued by the Federal Power Commission?
(d) Oath statements by the applicant. With each application for
determination submitted under this section, the applicant shall submit a
statement under oath:
(1) That the applicant has made, or has caused to be made pursuant to
his instructions, a diligent search of all records (including but not
limited to production, State severance tax, and royalty payment records
and records of jurisdictional agency determinations) which are
reasonably available and contain information relevant to the
determination of eligibility;
(2) Describing the search made, the records reviewed, the location of
such records, and a description of any records which the applicant
believes may contain information relevant to the determination but which
he has determined are not reasonably available to him;
(3) That the applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusion
that the well qualifies for the well category determination sought.
(e) Determinations under section 102(c)(1)(A). Once notification to
the Commission by the U.S. Department of the Interior Minerals
Management Service is made in accordance with 274.104(c) of this part,
no further filings are required to qualify natural gas subject to
section 102(c)(1)(A).
(Order 65, 45 FR 3894, Jan. 21, 1980, as amended by Order 336, 48 FR
44518, Sept. 29, 1983; Order 336-A, 49 FR 568, Jan. 5, 1984)
1Filed as part of the original document.
1Filed as part of the original document.
18 CFR 274.203 New reservoirs on old OCS leases.
A person seeking a determination for purposes of subpart B of part
271 that natural gas is produced from a new reservoir on an old OCS
lease (as defined in 271.203(b)), shall file an application with the
jurisdictional agency which contains the following items:
(a) FERC Form No. 121;
(b) The date the reservoir was penetrated;
(c) Geological information sufficient to support a determination that
the reservoir is a new reservoir on an old OCS lease.
(1) Such information shall include to the extent reasonably available
to the applicant at the time of the determination:
(i) Well logs;
(ii) Bottom hole or surface pressure surveys;
(iii) Well potential tests;
(iv) Formation structure maps;
(v) Subsurface cross-section charts;
(vi) Gas analyses,
(2) If any of the information specified in paragraph (c)(1) of this
section has already been filed in a previous application for
determination with the same jurisdictional agency, and such application
and a determination of eligibility for such application are on file with
the Commission, the applicant may submit, in lieu of such information, a
statement identifying such information and the application by
jurisdictional agency docket number, FERC docket or control number, and
the API well number.
(d) The well completion report;
(e) If the date of penetration of the reservoir is prior to July 27,
1976:
(1) Then to the extent such tests were performed on or before July
27, 1976,
(i) The results of any production test meeting the requirements of
OCS Order No. 4 with respect to such reservoir; and
(ii) Any production capability evidence meeting the requirements of
OCS Order No. 4 with respect to such reservoir; and
(iii) Any induction-electric logs, sidewall cores and core analyses,
or wire line formation tests with respect to such reservoir; or
(2) A statement by the applicant, under oath, that no such production
tests were performed and that no evidence existed on or before July 27,
1976 that the reservoir was capable of producing in paying quantities;
(f) A statement by the applicant, under oath:
(1) That the applicant has made, or has caused to be made pursuant to
his instructions, a diligent search of all records (including but not
limited to production and royalty payment records) which are reasonably
available and contain information relevant to the determination of
eligibility;
(2) Describing the search made, the records reviewed, the location of
the records, and a description of any records which the applicant
believes may contain information relevant to the determination but which
he has determined are not reasonably available to him;
(3) That on the basis of the results of this search and examination,
the applicant has concluded that to the best of his information,
knowledge and belief, the natural gas for which the applicant seeks a
determination is produced from an old lease on the OCS from a reservoir
which was not discovered before July 27, 1976; and
(4) That he has no knowledge of any other information not described
in the application which is inconsistent with his conclusion;
(Order 65, 45 FR 3894, Jan. 21, 1980, as amended by Order 336, 48 FR
44519, Sept. 29, 1983)
18 CFR 274.204 New, onshore production wells.
A person seeking a determination for purposes of subpart C of part
271 that a well is a new, onshore production well shall file an
application with the jurisdictional agency which contains the following
items:
(a) FERC Form No. 121;
(b) The well completion report;
(c) A location plat which locates and identifies the State law
proration unit (as defined in 271.305(a)(2)) and the well for which a
determination is sought and all other wells within the State law
proration unit in which the well for which a determination is sought is
located;
(d) A statement by the applicant, under oath:
(1) That the surface drilling of the well for which he seeks a
determination was begun on or after February 19, 1977;
(2) That the well satisfies any applicable Federal or State well
spacing requirements;
(3) That, except as provided in paragraphs (e) and (f) of this
section, the well is not within a State law proration unit (as defined
in 271.305(a)(2)):
(i) Which was in existence at the time the surface drilling of the
well began;
(ii) Which was applicable to the reservoir from which such natural
gas is produced; and
(iii) Which applied to any other well which either produced natural
gas in commercial quantities or the surface drilling of which was begun
before February 19, 1977, and which was thereafter capable of producing
natural gas in commercial quantities;
(4) That on the basis of the documents submitted in the application,
the applicant has concluded that to the best of his information,
knowledge and belief, the natural gas for which the applicant seeks a
determination is produced from a new, onshore production well; and
(5) That the applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusion;
(e) If the applicant is seeking a determination with respect to a new
well drilled into an existing State law proration unit pursuant to
271.305, the applicant must file all items required in paragraphs (a)
through (d) of this section, except for the portion of the oath
statement described in paragraph (d)(3) of this section and demonstrate
by appropriate geological evidence and engineering data that the new
well is necessary to effectively and efficiently drain a portion of the
reservoir covered by the proration unit which cannot be effectively and
efficiently drained by any existing well within the proration unit.
(f) For the purposes of paragraph (d)(3)(iii) of this section, the
applicant may rely on the rebuttable presumption created in 271.305(d)
unless the applicant knew that a well in the proration unit, which was
plugged and abandoned prior to January 1, 1970 and has not produced
natural gas on or after that date, produced natural gas in commercial
quantities or, after February 19, 1977, was capable of producing natural
gas in commercial quantities.
(Order 65, 45 FR 3894, Jan. 21, 1980, as amended by Order 336, 48 FR
44519, Sept. 29, 1983)
18 CFR 274.205 High-cost natural gas.
(a) Deep, high-cost natural gas. (1) A person seeking a
determination for purposes of part 272 that natural gas is deep,
high-cost natural gas shall file an application with the jurisdictional
agency. An application filed under this paragraph shall cover natural
gas produced from the completion location identified in the application
and any deeper location that may be completed after the date of the
application.
(2) An application required by paragraph (a)(1) of this section shall
contain the following items:
(i) FERC Form No. 121;
(ii) All well completion reports for the well for which a
determination is sought;
(iii) The log heading together with the relevant portion of the well
log or well servicing company reports or such other information which
will corroborate the depth of the completion location reported in the
well completion report;
(iv) Directional drilling surveys, if available; and
(v) A statement by the applicant, under oath, that the surface
drilling of the well for which the applicant seeks a determination began
on or after February 19, 1977, that the well completion location is
located at a true vertical depth of more than 15,000 feet, and that the
applicant has no knowledge of any information not described in the
application which is inconsistent with his conclusions.
(b) Natural gas produced from geopressured brine. A person seeking a
determination for purposes of part 272 that natural gas is produced from
geopressured brine shall file an application with the jurisdictional
agency which contains the following items:
(1) FERC Form No. 121;
(2) The well completion report;
(3) A bottom-hole pressure test report and other information
establishing the initial reservoir pressure gradient;
(4) Evidence to establish that, before production, the gas from the
well was in solution in a brine aquifer with at least 10,000 parts of
dissolved solids per million parts of water;
(5) A statement by the applicant, under oath, that the information
establishing the initial reservoir geopressure gradient indicates a
reservoir geopressure gradient in excess of 0.465 pounds, that the gas
from the well was in solution in a brine aquifer with at least 10,000
parts of dissolved solids per million parts of water and that the
applicant has no knowledge of any information not described in the
application which is inconsistent with his conclusions.
(c) Occluded natural gas produced from coal seams. A person seeking
a determination for purposes of part 272 that natural gas is occluded
natural gas produced from coal seams shall file an application with the
jurisdictional agency which contains the following items:
(1) FERC Form No. 121;
(2) The well completion report, if the gas is produced through a well
bore, or a detailed description of the production process if the gas is
not produced through a well bore;
(3) A radioactivity, electric or other log which will define the coal
seams or, if such logs are not reasonably available, a detailed
lithologic description of the gas-producing interval;
(4) Evidence to establish that the natural gas was produced from a
coal seam;
(5) A statement by the applicant, under oath, that the gas was
produced from a coal seam and that the applicant has no knowledge of any
information not described in the application which is inconsistent with
his conclusion.
(d) Natural gas produced from Devonian shale. A person seeking a
determination for purposes of part 272 that natural gas is produced from
Devonian shale shall file an application with the jurisdictional agency
which contains the following items:
(1) FERC Form No. 121;
(2) The well completion report;
(3)(i) For wells completed on or after November 1, 1979, a gamma ray
log with superimposed indications of the shale base line and the gamma
ray index of 0.7 over the Devonian age stratigraphic section designated
pursuant to 272.103(e);
(ii) For wells completed before November 1, 1979:
(A) A gamma ray log, if reasonably available, with superimposed
indications of the shale base line and the gamma ray index of 0.7 over
the Devonian age stratigraphic section designated pursuant to
272.103(e); or
(B) If a gamma ray log is not reasonably available, a driller's log,
or similar report, indicating the general characteristics of the strata
penetrated and the corresponding depths at which they are encountered
throughout the Devonian age stratigraphic section designated pursuant to
272.103(e);
(4) A sworn statement:
(i) Calculating the percentage of footage of the producing interval
which is not Devonian shale as indicated by a Gamma ray index of less
than 0.7 if a gamma ray log described in paragraph (d)(3)(i) or
(d)(3)(ii)(A) of this section, has been filed, or as indicated by the
report described in paragraph (d)(3)(ii)(B) of this section;
(ii) Demonstrating that the percentage of potentially disqualifying
nonshale footage for the stratigraphic section selected is equal to or
less than 5 percent of the Devonian stratigraphic age interval
designated pursuant to 272.103(e);
(iii) That the applicant has no knowledge of any information not
described in the application which is inconsistent with his conclusions;
(5) A reference to a standard stratigraphic chart or text
establishing that the producing interval is a shale of Devonian age.
(e) Natural gas produced from designated tight formations -- (1) New
tight formation gas. A person seeking a determination for purposes of
subpart G of part 271 that natural gas is new tight formation gas shall
file with the jurisdictional agency an application which contains the
following items:
(i) (A) If the gas is produced from a well which qualifies as a new,
onshore production well, all information required in 274.204 (except
for the item specified in paragraph (d)(1) of that section); or
(B) If the gas qualifies for the new natural gas price, the
information required in 274.202 or 274.203;
(ii) The heading and pertinent portions of the well log, or a
drilling report identifying the designated tight formation; and
(iii) A statement by the applicant, under oath, that:
(A) The surface drilling of the well for which a determination is
sought was begun on or after July 16, 1979;
(B) The gas is being produced from a designated tight formation; and
(C) The applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusions.
(2) Recompletion tight formation gas. A person seeking a
determination for purposes of subpart G of part 271 of this chapter that
natural gas is recompletion tight formation gas shall file with the
jurisdictional agency an application which contains the following items:
(i) FERC Form No. 121;
(ii) The well completion report;
(iii) The heading and pertinent portions of the well log, or a
drilling report identifying the designated tight formation; and
(iv) A statement by the applicant, under oath, that:
(A) The gas is being produced from a designated tight formation; and
(B) The well was not completed for production in the designated tight
formation prior to July 16, 1979; or, if the well was completed for
production in the designated tight formation prior to July 16, 1979,
then the gas subject to the application is being produced from a
completion location which was completed on or after (the effective date
of the final rule), and such gas could not have bey throduced from any
completion location which was in existence in the well bore prior to
December 27, 1983; and
(C) The applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusion.
(v) If the well was completed for production in the designated tight
formation prior to July 16, 1979,
(A) A gamma ray log on which all completion locations in the wellbore
which were completed for production prior to December 27, 1983, and the
completion locations which are the subject of the application are
identified, and which demonstrates that the strata between the
completion locations contain a minimum of 20 vertical feet of
impermeable structure; or
(B) The results of bottom hole pressure surveys, gas analyses, or
other methods or calculations comparing the completion locations which
are the subject of the application and any completion locations in the
wellbore which were completed for production prior to December 27, 1983;
and an explanation of the engineering principles, calculations, and
reasoning used in making the judgment that these comparisons demonstrate
that the gas to be produced from the subject completion locations could
have been produced from any completion locations in existence prior to
December 27, 1983.
(f) Qualified production enhancement gas. A person seeking a
determination for purposes of 271.704 that natural gas is qualified
production enhancement gas shall file with the jurisdictional agency an
application which contains the following items:
(1) FERC Form No. 121;
(2) A detailed statement describing the production enhancement work
that has been performed on the well, including the dates such work was
commenced and completed, or that will be performed on the well;
(3) An itemized statement of costs incurred in performing the
production enhancement work described in 271.704(d), including copies
of invoices and bills for such work or, if the work has not yet been
completed, estimates of such cost;
(4) An statement estimating, for the five year period begining from
the month in which the application is filed, the units of gas production
(MMBtu's) that:
(i) Would be produced from the well if the production enhancement
work had been completed on the day that the application is filed; and
(ii) Would be produced from the well if the production ehancement
work is not performed or had not been performed;
(5) The calculation, based on the estimates required by paragraph
(f)(4) of this section, that is required by 271.704(c)(1)(v);
(6) The renegotiated price and a copy of that portion of the sales
contract that authorizes collections of such price;
(7) A statement by the applicant, under oath, that:
(i) The production enhancement work is necessary, and can be
reasonably expected, to enhance production;
(ii) The maximum lawful price that would be applicable but for
qualification of the gas under 271.704, does not, or will not, provide
adequate incentive for the performance of the production enhancement
work;
(iii) But for the availability of a price at least as high as the
renegotiated price specified in paragraph (f)(6) of this section, the
production enhancement work would not have been or will not be
performed;
(iv) The production enhancement work was not commenced before:
(A) May 29, 1980, for wells otherwise subject to the maximum lawful
price prescribed by subpart E of part 271; or
(B) September 26, 1983, for wells otherwise subject to the maximum
lawful price prescribed by subparts D and F of part 271.
(v) To the best of the applicant's knowledge and belief, the
estimates required by paragraph (f)(4) of this section are reasonable;
and
(vi) The applicant has no knowledge of any other information not
described in the application which is inconsistent with these statements
and estimates;
(8) A statement by the purchaser, under oath, that to the best of the
purchaser's knowledge or belief:
(i) There is a reasonable basis for the statements and estimates made
by the applicant pursuant to this paragraph; and
(ii) The purchaser has no knowledge of any information not described
in the application which is inconsistent with such statements and
estimates; and
(9) (i) If the application is based to any extent on fracturing
operations described in 271.704(d)(5), a statement that:
(A) Describes the minimum separation between the target production
zone and fresh water aquifers which are, or are expected to be, used as
domestic or agricultural water supplies; and
(B) Identifies the measures that have been, or will be, taken by the
applicant to protect the quality of such fresh water aquifers and to
protect the intergrity of the separating strata between the target
production zone and the fresh water acquifers if the fracturing
operations might result in fluid communication between these formations;
(ii) The jurisdictional agency may waive the requirements of
paragraph (f)(9)(i) of this section if it determines that the state has
a program reasonably designed to assure that no damage will result, from
fracturing operations, to fresh water aquifers which are, or are
expected to be, used as domestic or agricultural water supplies.
(Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432, Natural Gas Act
as amended, 15 U.S.C. 712-717)
(Order 78, 45 FR 28099, Apr. 28, 1980, and Order 99, 45 FR 56046,
Aug. 22, 1980, as amended by Order 107, 45 FR 77430, Nov. 24, 1980;
Order 336, 48 FR 44519, Sept. 29, 1983; 48 FR 45102, Oct. 3, 1983;
Order 345, 48 FR 49509, Oct. 26, 1983; Order 501, 53 FR 28194, July 27,
1988)
18 CFR 274.206 Stripper well natural gas.
A person seeking a determination for purposes of subpart H of part
271 that a well either qualifies or continues to qualify as a stripper
well shall file an application with the jurisdictional agency which
contains the following items:
(a) Application for determination. For purposes of initially
qualifying a stripper well, the applicant shall file;
(1) FERC Form No. 121;
(2) Production records, if available, and if not, tax records, if
available, or verified copies of billing statements upon which the
average production for the 90-day production period is based; or, if so
permitted by the jurisdictional agency's filing requirements, summaries
of such records or billing statements;
(3) A copy of the results of any tests which establish a maximum
efficient rate of flow under 271.807(a);
(4) Where the maximum efficient rate of flow for the well has not
been established under 271.807(a):
(i) Production records, if available, and if not, tax records, if
available, or verified copies of billing statements for the 12 months
ending on the last day of the 90-day production period upon which the
application is based, or if so permitted by the jurisdictional agency's
filing requirements, summaries of such records or billing statements;
or
(ii) A copy of the results of any tests which measure the production
capability of the well, or any other evidence upon which the
jurisdictional agency could establish maximum efficient rate of flow.
(5) Where the determination is deferred pursuant to
271.807(b)(1)(ii) or (b)(2), within 90 days after the last day of the
deferred period, production data for the deferred period, including the
90-day production period upon which the application is based.
(6) The number of days natural gas was produced during the 90-day
production period described in 271.803(c)(2).
(7) The number of days natural gas was not produced during the 90-day
production period described in 271.803(c)(2), and
(i) A description of the state law or conservation practice, as set
forth in 271.803(d)(2), pursuant to which the well did not produce on
any such day or days, or
(ii) An explanation of any other reason the well did not produce on
any such day or days.
(8) The production records for crude oil produced from the well for
the 90-day production period upon which the application is based, or if
no crude oil was produced from the well, a statement under oath to that
effect.
(9) If the well is multiple completion well, production records for
each completion location penetrated by the well bore:
(i) For the 90-day production period on which the application is
based; and
(ii) For the 12 month period on which the maximum efficient rate of
flow presumption is based, if applicable.
(10) A statement under oath, (i) that the applicant has made, or has
caused to be made pursuant to his instructions, a diligent search of all
records which are reasonably available and contain information relevant
to the determination;
(ii) Describing the search made, the records reviewed, and the
results of this search and examination upon which he has concluded that
to the best of his information, knowledge and belief, the well qualifies
as a stripper well;
(iii) That the production records, tax records, billing statements,
or summaries of such records or billing statements relied upon in the
application are correct; and
(iv) A statement that the applicant has no knowledge of any other
information which is inconsistent with his conclusion that the well
qualifies as a stripper well.
(b) Notice by an operator or purchaser of an increase in production.
For purpose of the notices required under 271.805, the person filing
shall include:
(1) The names and addresses of the operator and purchaser(s) with a
designation of who is filing the notice;
(2) Identification of the subject well and accurate record reference
to the original determination qualifying the well as a stripper well;
(3) The monthly production reports, tax records or billing statements
upon which the notice is based for the period of production in question
or, if so permitted by the jurisdictional agency's filing requirements,
summaries of such records or billing statements;
(4) A statement of the average production per production day for the
period in question;
(5) A statement that all of the information contained in the notice
is true to the best of his information, knowledge and belief; and that
the notice has been served on the appropriate entities specified in
271.805(d)(3).
(c) Determination of increased production resulting from recognized
enhanced recovery techniques. For purposes of a determination under
271.805(g) that increased production resulted from the use of recognized
enhanced recovery techniques, the applicant shall file:
(1) The names and addresses of the applicant and purchaser(s);
(2) An identification of the well and accurate reference to the
original determination qualifying the well as a stripper well and the
notice, if any, filed by a purchaser pursuant to 271.805;
(3) The well completion report;
(4) A description of all processes used and equipment installed
together with all dates of use or installation which constitute enhanced
recovery techniques;
(5) An inventory of the lease and production equipment used such as
compression facilities, pumps, chokes and intermittors for the well for
the past 24 months or, if less, the period the well has been in
production prior to the institution of recovery techniques;
(6) A statement, under oath, that to the best of his information,
knowledge and belief, the information supplied and the conclusions drawn
are true, that the operator has no knowledge of any information not
described in the application which is inconsistent with any of his
conclusions; and that the petition for recognized enhanced recovery
techniques has been served on any purchaser.
(d) Designation that a well is seasonally affected. For purposes of
a determination under 271.804(d) that a well is seasonally affected,
the applicant shall file:
(1) The names and addresses of the applicant and purchaser(s);
(2) An identification of the well and accurate record reference, if
applicable, to the origninal determination qualifying the well as a
stripper well and any notice filed by a purchaser pursuant to 271.805;
(3) Production records, tax records or billing statements for a
period of 24 months, including the 90-day production period which is the
subject of the notice by the operator or the purchaser or, if so
permitted by the jurisdictional agency's requirements, summaries of such
records or billing statements;
(4) A description of the nature of the seasonal fluctuations as
inferred from the date supplied;
(5) A statement, under oath, that the production records, tax records
or billing statements, or summaries of such records or billing
statements, if so permitted by the jurisdictional agency's filing
requirements, relied upon in the application for the designation are
correct; that the operator has no knowledge of any information not
described in the application which is inconsistent with any of his
conclusions; and that the petition for seasonally affected designation
has been served on any purchaser.
(e) Determination of increased production resulting from temporary
pressure buildup. For purposes of a determination under 271.806(a)
that excess production resulted from temporary pressure buildup in the
well bore, the applicant shall file:
(1) The name and addresses of the applicant and purchaser(s);
(2) An identification of the well and accurate reference to;
(i) The original determination qualifying the well as a stripper well
or the pending application before a jurisdictional agency, and
(ii) The notice, if any filed by a purchaser pursuant to 271.805(d).
(3) The monthly production reports, tax records or billing statements
for the 90-day production period in question or, if permitted by the
jursidictional agency's filing requirements, summaries of such records
or billing statements;
(4) A statement of the total production for the period in question,
and the average production per production day;
(5) A statement of the number of days the well was shut-in and a
description of the reason for the shut-in;
(6) Engineering, geological and/or production data to support a
finding that the increased rate of production was the result of a
pressure buildup which occurred when the well was shut-in;
(7) A statement, under oath, that to the best of his information,
knowledge and belief:
(i) The well would have produced at an average rate not exceeding 60
Mcf per production day during the relevant 90-day production period had
the well been continuously open to the line during such period;
(ii) The information supplied is true; and
(iii) The petition for this determination has been served on any
purchaser.
(f) Motion contesting a disqualification or requalification. An
operator or purchaser seeking a determination under 271.806(b), of a
motion contesting a disqualification or requalification, shall file:
(1) The names and addresses of the operator and purchaser(s);
(2) An identification of the well and accurate reference to,
(i) The original determination qualifying the well as a stripper well
or the pending application for the stripper well determination, and
(ii) If applicable, the notice of disqualification filed by the
purchaser pursuant to 271.805(d);
(3) A statement summarizing the reasons why the well should not be
disqualified;
(4) Any documentary evidence that supports the statement made
pursuant to paragraph (f)(3) of this section; and
(5) A statement, under oath, that all of the information contained in
the motion is true to the best of the operator's information, knowledge,
and belief and that the motion has been served on the purchaser(s).
(Order 65, 45 FR 3984, Jan. 21, 1980, as amended at 45 FR 15524, Mar.
11, 1980; 46 FR 6902, Jan. 22, 1981; Order 187, 46 FR 57467, Nov. 24,
1981; Order 336, 48 FR 44519, Sept. 29, 1983; Order 336-A, 49 FR 568,
Jan. 5, 1984)
18 CFR 274.207 Alternative filing and notice requirements.
(a) General. Upon written application by a jurisdictional agency
pursuant to this section, the Commission may approve:
(1) Filing requirements which differ from those in 274.201 through
274.206; and
(2) Notice requirements which differ from those in 274.104;
(b) Contents of applications. Applications for approval of
alternative filing or notice requirements shall include:
(1) Each requirement of this part for which an alternative is
proposed;
(2) A description of the specific requirements which will replace the
requirements in paragraph (b)(1) of this section including copies of any
forms to be used by the agency;
(3) The reasons for requesting approval of each alternative
requirement, which may include the fact that such information is not
available; and
(4) The basis for the belief that filings under the alternative
filing requirements will provide substantial evidence on which the
jurisdictional agency may base a determination or that notice under the
alternative notice requirements will provide the Commission with an
adequate basis upon which to review the determination.
(c) Commission review of applications. Upon receipt of an
application pursuant to this section, the Commission shall give public
notice of such application and after review of any written comments, may
issue an order approving the alternative requirements. The Commission
will publish the order in the Federal Register.
(d) Effective date of alternative filing and notice requirements.
(1) With respect to applications received by a jurisdictional agency
after the effective date of approval of alternative filing requirements,
such alternate requirements as are specified and approved in 274.208
shall apply in lieu of the provisions of 274.201 through 274.206.
(2) With respect to determinations made by a jurisdictional agency
after the effective date of approved alternative notice requirements,
the alternative notice requirements as are specified and approved in
274.208 shall apply in lieu of the provisions of 274.104 of this
subpart.
(e) Termination of alternative filing and notice requirements. (1) A
jurisdictional agency may, upon notice to the Commission, discontinue
the use of any alternative filing or notice requirements approved under
this subpart.
(2) The Commission may, after a public comment period of no less than
30 days, give notice to a jurisdictional agency that the Commission has
terminated its approval of alternative filing or notice requirements, if
it finds that the alternative filing or notice requirements:
(i) Are not sufficient to carry out the purpose of the NGPA; or
(ii) After notice and opportunity for hearing, the jurisdictional
agency has not complied, or required compliance, with the alternative
provisions.
(3) Applications for determinations received by jurisdictional
agencies after notice of termination of the applicability of alternative
filing requirements pursuant to this section and 274.208 shall be
subject to the filing requirements set forth in 274.201 through
274.206.
(4) Notice of determinations made by jurisdictional agencies after
notice of termination of the applicability of alternative notice
requirements pursuant to this section and 274.208 shall be subject to
the notice requirements set forth in 274.104.
(Order 65, 45 FR 3984, Jan. 21, 1980)
18 CFR 274.208 Alternative filing and notice requirements accepted by
the Commission.
(a) Certain Infill Wells in the Blanco-Messaverde and Basin-Dakota
Pools in New Mexico.
(1) A person seeking a determination for purposes of subpart C of
part 271 than an infill well in New Mexico, drilled in accordance with
the New Mexico Oil Conservation Division Order No. R 1670-Tin the
Blanco-Mesaverde pool or Order No. R-1670-V in the Basin-dakota pool,
is a new, onshore production well shall file with the New Mexico
jurisdictional agency or the Area Oil and Gas Supervisor of the Untied
States Geological Survey, as appropriate, an application which contains,
in lieu of the information specified in 274.204, the following items:
(i) FERC Form No. 121;
(ii) The well completion report;
(iii) A location plat which locates and identifies the State law
proration unit (as defined in 271.305(a)(2)) and the well for which a
determination is sought and all other wells within the State law
proration unit in which the well for which a determination is sought is
located;
(iv) A statement by the applicant, under oath:
(A) That the surface drilling of the well for which he seeks a
determination was begun on or after February 19, 1977;
(B) That the well satisfies any applicable Federal or State well
spacing requirements;
(C) That the applicant has concluded that to the best of his
information, knowledge and belief, the natural gas for which he seeks a
determination is produced from a new, onshore production well; and
(D) That the applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusion;
(v) A statement referencing New Mexico Oil Conservation Division
Order No. R-1670-T if the well is located in the Blanco-Mesaverde pool
or New Mexico Oil Conservation Division Order No. R-1670-V if the well
is located in the Basin-Dakota pool.
(2) With respect to wells to which this section applies, receipt by
the Commission of a notice of determination pursuant to 274.104 shall
be deemed to satisfy:
(i) The requirement of notice to the Commission under 271.305(c);
and
(ii) The requirement of 271.305(b)(1) that appropriate geological
and engineering data be included in the notice of determination.
(b) Certain Infill Wells in the Ignatio Blanco Field in La Plata and
Archuleta Counties, Colorado and the Wattenberg Field in Adams and Weld
Counties, Colorado.
(1) A person seeking a determination for purposes of subpart C of
part 271 that an infill well in Colorado, drilled in accordance with the
Colorado Department of Natural Resources, Oil and Gas Conservation
Commission's Order No. 112-46, as ratified by the United States
Geological Survey's Oil and Gas Supervisor for the Southern Rocky
Mountain Area, in the Fruitland-Pictured Cliffs, Mesaverde or
Dakota-Morrison Formations, Ignatio Blanco Field is a new, onshore
production well, shall file with the Colorado jurisdictional agency or
the Area Oil and Gas Supervisor of the United States Geological Survey,
as appropriate, an application which contains, in lieu of the
information specified in 274.204, the following items:
(i) FERC Form No. 121;
(ii) The well completion report;
(iii) A location plat which locates and identifies the State law
proration unit (as defined in 271.305(a)(2)) and the well for which a
determination is sought and all other wells within the State Law
proration unit in which the Well for determination is sought is located;
(iv) A statement by the applicant, under oath:
(A) That the surface drilling of the well for which he seeks a
determination was begun on or after February 19, 1977;
(B) That the well satisfies any applicable Federal or State well
spacing requirements;
(C) That the applicant has concluded that to the best of his
information, knowledge and belief, the natural gas for which he seeks a
determination is produced from a new, onshore production well; and
(D) That the applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusion;
(v) A statement referencing Colorado's Oil and Gas Conservation
Commission Order No. 112-46 if the well is located in the Fruitland
Pictured Cliffs, Mesaverde or Dakota-Morrison formations of the Ignatio
Blanco Field.
(2) A person seeking a determination for purposes of subpart C of
part 271 that an infill well in Colorado, drilled in accordance with the
Colorado Department of Natural Resources, Oil and Gas Conservation
Commission's Order No. 232-20 in the ''J'' Sand Formation of the
Wattenberg Field is a new, onshore production well, shall file with the
Colorado jurisdictional agency an application which contains, in lieu of
the information specified in 274.204, the following items:
(i) The items specified in paragraphs (b)(1) (i) through (iv) of this
section; and
(ii) A statement referencing Colorado's Oil and Gas Conservation
Commission Order No. 232-20 if the well is located in the ''J'' Sand
Formation of the Wattenberg field.
(3) With respect to wells to which this paragraph applies, receipt by
the Commission of a notice of determination applies, receipt by the
Commission of a notice of determination pursuant to 274.104 shall be
deemed to satisfy:
(i) The requirement of notice to the Commission under 271.305(c);
and
(ii) The requirement of 271.305(b)(1) that appropriate geological
and engineering data be included in the notice of determination.
(c) Certain Infill Wells in the Sussex and Shannon reservoirs in the
Spindle field and in the Sussex reservoir in the Hambert Field in Adams
and Weld Counties, Colorado. (1) A person seeking a determination for
purposes of subpart C of part 271 that a second well drilled in
accordance with the Colorado Department of Natural Resources' Oil and
Gas Conservation Commission's Order Nos. 304-5, 250-12, 250-14, 250-16,
250-17, 250-19, 250-20, 250-21, and 250-23 in the Sussex and Shannon
reservoirs in the Spindle field and in the Sussex reservoir in the
Hambert Field in Adams and Weld Counties, Colorado is a new, onshore
production well, shall file with the Colorado jurisdictional agency an
application which contains, in lieu of the information specified in
274.204, the following items:
(i) FERC Form No. 121;
(ii) The well completion report;
(iii) A location plat which locates and identifies the State law
proration unit (as defined in 271.305(a)(2)) and the well for which a
determination is sought and all other wells within the State Law
proration unit in which the well for which a determination is sought is
located;
(iv) A statement by the applicant, under oath:
(A) That the surface drilling of the well for which he seeks a
determination was begun on or after February 19, 1977;
(B) That the well satisfies any applicable Federal or State well
spacing requirements;
(C) That the applicant has concluded that to the best of his
information, knowledge and belief, the natural gas for which he seeks a
determination is produced from a new, onshore production well; and
(D) That the applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusion;
(v) A statement referencing Colorado's Oil and Gas Conservation
Commission's Order Nos. 304-5, 250-12, 250-14, 250-16, 250-17, 250-19,
250-21, or 250-23, as appropriate.
(2) With respect to wells to which this paragraph applies, receipt by
the Commission of a notice of determination pursuant to 274.104 shall
be deemed to satisfy:
(i) The requirement of notice to the Commission under 271.305(c);
and
(ii) The requirement of 271.305(b)(1) that appropriate geological
and engineering data be included in the notice of determination.
(d) Applications for well determinations under section 103, subpart C
of part 271, filed with the Oklahoma Corporation Commission.
(1) A person seeking a determination for purposes of subpart C of
part 271 that an additional well on an existing statutorily-established
proration unit in Oklahoma, for which an increased density order
containing a finding of necessity has been issued, is a new, onshore
production well, shall file with the Oklahoma jurisdictional agency an
application which contains in lieu of the information specified in
274.204, the following items:
(i) FERC Form No. 121;
(ii) The well completion report;
(iii) A location plat which locates and identifies the State law
proration unit (as defined in 271.305(a)(2)) and the well for which a
determination is sought and all other wells within the State law
proration unit in which the well for which a determination is sought is
located;
(iv) A statement by the applicant, under oath;
(A) That the surface drilling of the well for which he seeks a
determination was begun on or after February 19, 1977;
(B) That the well satisfies any applicable Federal or State well
spacing requirements;
(C) That the applicant has concluded that to the best of his
information, knowledge and belief, the natural gas for which he seeks a
determination is produced from a new, onshore production well; and
(D) That the applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusion;
(v) A copy of the increased density order issued by the Oklahoma
Corporation Commission which contains the finding of necessity for
additional wells in the proration unit in which the well for which the
determination is being sought is located.
(2) With respect to wells to which this paragraph applies, receipt by
the Commission of a notice of determination pursuant to 274.104 shall
be deemed to satisfy:
(i) The requirement of notice to the Commission under 271.305(c),
and
(ii) The requirement of 271.305(b)(1) that appropriate geological
and engineering data be included in the notice of determination.
(e) Certain Devonian shale wells in the State of Michigan.
(1) A person seeking a determination for purposes of part 272 that a
well completed on or after November 1, 1979, for which a gamma ray log
is not available, is producing gas from the Devonian age Antrim Shale in
Michigan, shall file with the Michigan jurisdictional agency an
application which contains, in lieu of the information specified in
274.204, the following items:
(i) FERC Form No. 121;
(ii) The well completion report;
(iii) A gamma ray log from the closest available well bore (producing
or dry hole) that is within a one mile radius of the well for which a
determination is sought, with superimposed indications of:
(A) The shale base line and the gamma ray index of 0.7 over the
Devonian age stratigraphic section penetrated by the well bore; and
(B) The boundary between the Antrim Shale and the overlying formation
(Berea Sandstone, Ellsworth, Bedford, or Sunbury Shales, or their
equivalents);
(iv) A location plat showing the well for which the determination is
sought and the well for which a gamma ray log has been filed;
(v) A mud log from the well for which the determination is sought,
with a detailed description of samples taken from 10-foot, or less,
intervals throughout the Devonian age stratigraphic section penetrated
by the well bore;
(vi) A driller's log, or similar report, from the well for which the
determination is sought, indicating the general characteristics of the
strata penetrated and the corresponding depths at which they are
encountered throughout the Devonian age stratigraphic section penetrated
by the well bore;
(vii) A sworn statement:
(A) Calculating the percentage of footage of the producing interval
(or the Antrim Shale in the event the well is a dry hole) in the well
for which a gamma ray log was submitted which is not Devonian shale as
indicated by a gamma ray index of less than 0.7;
(B) Demonstrating that the percentage of potentially disqualifying
nonshale footage for the Devonian age stratigraphic section penetrated
by the well bore for which a gamma ray log was submitted is equal to or
less than 5 percent; and
(C) Declaring that the applicant has no knowledge of any information
not described in the application which is inconsistent with these
conclusions;
(viii) A reference to a standard stratigraphic chart or text
establishing that the producing interval is a shale of Devonian age.
(f) Certain infill wells in the Hugoton Gas Field, Chase Group in the
state of Kansas.
(1) A person seeking a determination for purposes of subpart C of
part 271 that an infill well drilled in the Hugoton Field, Chase Group,
Kansas, in accordance with the State Corporation Commission of the State
of Kansas orders in Docket No. C-164, is a new, onshore production
well, shall file with the Kansas jurisdictional agency an application
which contains in lieu of the information specified in 274.204, the
following items:
(i) FERC Form No. 121;
(ii) The well completion report;
(iii) A location plat which locates and identifies the State law
proration unit (as defined in 271.305(a)(2)) and the well for which a
determination is sought and all other wells within the State law
proration unit in which the well for which a determination is sought is
located;
(iv) A statement by the applicant under oath;
(A) That the surface drilling of the well for which he seeks a
determination was begun on or after February 19, 1977;
(B) That the well satisfies any applicable Federal or State well
spacing requirements;
(C) That the applicant has concluded that to the best of his
information, knowledge and belief, the natural gas for which he seeks a
determination is produced from a new, onshore production well; and
(D) That the applicant has no knowledge of any other information not
described in the application which is inconsistent with his conclusion;
(v) A statement referencing Kansas' order in Docket No. C-164.
(2) With respect to wells to which this paragraph applies, receipt by
the Commission of a notice of determination pursuant to 274.104 shall
be deemed to satisfy:
(i) The requirement of notice to the Commission under 271.305(c),
and
(ii) The requirement of 271.305(b)(1) that appropriate geological
and engineering data be included in the notice of determination.
(Natural Gas Act, as amended, 15 U.S.C. 717 et seq.; Department of
Energy Organization Act, 42 U.S.C. 7107, et seq.; Exec. Order No.
12009, 42 FR 46267; Natural Gas Policy Act of 1978, 15 U.S.C. 3301, et
seq.)
(Order 66, 45 FR 3900, Jan 21, 1980, as amended at 45 FR 12411, Feb.
26, 1980; 45 FR 24125, Apr. 9, 1980; 45 FR 35323, May 27, 1980; Order
336, 48 FR 44519, Sept. 29, 1983; Order 520, 55 FR 5984, Feb. 21,
1990; Order 524, 55 FR 20452, May 17, 1990)
18 CFR 274.208 Subpart C -- Waivers
Source: Order 41, 44 FR 48668, Aug, 20, 1979, unless otherwise
noted.
18 CFR 274.301 Applicability.
This subpart contains the procedures by which jurisdictional agencies
and the Commission may enter into agreements under which jurisdictional
agencies waive to the Commission authority to make the determinations
set forth in subpart A of this part.
18 CFR 274.302 Requests for waiver.
(a) General. A jurisdictional agency may file with the Commission a
request to enter into a written agreement waiving, in whole or in part,
the authority of the jurisdictional agency to make determinations
pursuant to subpart A of this part.
(b) Contents of requests. Requests filed pursuant to this section
shall include:
(1) The name of the jurisdictional agency;
(2) Each class of determination for which a waiver is sought;
(3) The reasons the jurisdictional agency believes a waiver is
necessary; and
(4) The length of time any waiver is to remain in effect.
(c) Commission action on requests. After consideration of any
request under this section, the Commission may execute a written
agreement including:
(1) Provision that upon written acceptance of the agreement by the
jurisdictional agency, the Commission, in lieu of such agency, will make
the determinations waived in the agreement, and
(2) Any terms and conditions the Commission deems appropriate with
respect to such waiver, including the date on which the waiver shall
terminate; and
(3) The effective date of the waiver.
18 CFR 274.303 Termination or revocation of agreements.
Agreements pursuant to this subpart shall remain in effect until
public notice of the following is given by the Commission:
(a) Expiration. Notice that the agreement of waiver has expired
pursuant to a term or condition of the waiver agreement;
(b) Termination. Notice that the Commission has received written
notice from the jurisdictional agency that such agency terminates the
agreement as of a specific date and assumes the authority to make
determinations under subpart A of this part; or
(c) Revocation. Notice that the Commission has revoked the agreement
pursuant to a term or condition of the waiver agreement.
18 CFR 274.304 Notice.
The Commission shall cause public notice to be made of agreements of
waiver and of any termination or revocation of a waiver.
18 CFR 274.304 Subpart D -- Delegations to State Agencies
18 CFR 274.401 Delegation of authority to receive certain reports.
(a) Delegation. The Commission may delegate to a State agency the
authority to receive the reports required by 276.102(d) and 276.103(d)
to be filed by an intrastate pipeline pursuant to sales made under
sections 105 and 106(b) of the NGPA.
(b) State agency. A delegation pursuant to this section shall be
made only to a State agency with jurisdiction over the rates and charges
of the intrastate pipelines required to make filings under 276.102(d)
and 276.103(d).
(c) Terms of the delegation. If a delegation is made under paragraph
(a) of this section the Commission and the State agency shall execute a
delegation agreement containing such terms and conditions as the parties
deem appropriate, including the manner in which the Commission will be
provided with such copies of the reports as it may require. Notice of
the delegation agreement shall be published in the Federal Register.
(Order 41, 44 FR 48669, Aug. 20, 1979)
18 CFR 274.401 Subpart E -- Identification of State and Federal Jurisdictional Agencies
18 CFR 274.501 Jurisdictional agency.
(a) Definition. Except as provided in paragraph (b),
''jurisdictional agency'' means:
(1) With respect to a well the surface location of which is on the
OCS, the Federal or State agency having regulatory jurisdiction with
respect to the production of natural gas. The following agencies have
notified the Commission of their authority in this regard.
(i) For OCS wells located in the Gulf Coast Region: Area Oil & Gas
Supervisor, 1201 Wholesalers Parkway, New Orleans, LA 70123.
(ii) For OCS wells located in the Atlantic Region: Area Oil & Gas
Supervisor, Atlantic OCS Operations, 1951 Kidwell Drive, Vienna, VA
22180.
(iii) For OSC wells located offshore Alaska: Area Oil & Gas
Supervisor, P.O. Box 101159, 800 A Street, Anchorage, AK 99510.
(iv) For OCS wells located offshore California: Area Oil & Gas
Supervisor, 160 Federal Building, 1340 W. 6th Street, Room 200, Los
Angeles, CA 90017.
(2) With respect to a well the surface location of which is on lands
within the boundaries of a State (including Federal lands and offshore
State lands), the Federal or State agency having regulatory jurisdiction
with respect to the production of natural gas. The following agencies
have notified the Commission of their authority in this regard:
(b) Waiver. In the case of any determination to which a waiver made
under subpart C of part 274 is applicable, ''jurisdictional agency''
means the Commission.
(c) Federal lands. For purposes of this section, ''Federal lands''
means:
(1) All lands leased under:
(i) The Mineral Lands Leasing Act, as amended, 30 U.S.C. 181 et seq.;
and
(ii) The Mineral Leasing Act for Acquired Lands, as amended, 30
U.S.C. 351 et seq.;
(2) All Indian lands which are under the supervision of the United
States Geological Survey (30 CFR part 221); and
(3) All Indian lands which are under the supervision of the Osage
Indian Agency, Bureau of Indian Affairs, U.S. Department of the
Interior.
(d) Divided-interest leases. Unless an agreement under paragraph (f)
of this section provides otherwise, where a well is located on a
divided-interest lease involving Federal (or Indian) and private (or
State) ownership:
(1) The Federal jurisdictional agency shall make the determination
where the majority lease interest is Federal (or Indian);
(2) The State jurisdictional agency shall make the determination
where the majority lease interest is private (or State); and
(3) The State jurisdictional agency shall make the determination
where the lease interest is divided equally.
(e) Drilling units. Unless an agreement under paragraph (f) of this
section provides otherwise, where a drilling unit is drained by two or
more wells, the Federal jurisdictional agency shall make the
determination if the completion location of the well in question is
located on a Federal (or Indian) lease, and the State jurisdictional
agency shall make the determination if the completion location of the
well in question is located on a private (or State) lease.
(f) Agreements. If the United States Geological Survey and any State
jurisdictional agency enter into an agreement authorizing such State
agency to make determinations under subpart A of this part with respect
to wells located on Federal lands, or authorizing the U.S. Geological
Survey to make such determinations with respect to wells located on
State lands, such agreement shall be filed with the Commission. Upon
the filing of such an agreement the agency so authorized in the
agreement shall be considered the jurisdictional agency with respect to
wells on the designated lands to the extent provided in the agreement.
(Natural Gas Act, as amended, 15 U.S.C. 717-717w; Department of
Energy Organization Act, 42 U.S.C. 7101-7352; Natural Gas Policy Act of
1978, 15 U.S.C. 3301-3432; Administrative Procedure Act, 5 U.S.C. 553)
(Order 41, 44 FR 48669, Aug. 20, 1979 as amended by Order 373, 49 FR
20281, May 5, 1984; Order 479, 52 FR 29007, Aug. 5, 1987)
18 CFR 274.501 PART 275 -- COMMISSION DETERMINATIONS AND REVIEW OF JURISDICTIONAL AGENCY DETERMINATIONS
18 CFR 274.501 Subpart A -- (Reserved)
18 CFR 274.501 Subpart B -- Procedure for Commission Review of
Jurisdictional Agency Determinations
Sec.
275.201 Publication of notice from jurisdictional agency.
275.202 Commission review of final determinations.
275.203 Protests to the Commission.
275.204 Contents of protests to the Commission.
275.205 Procedure for reopening determinations.
275.206 Confidentiality.
18 CFR 274.501 Subpart A -- (Reserved)
18 CFR 274.501 Subpart B -- Procedure for Commission Review of
Jurisdictional Agency Determinations
Authority: Natural Gas Act, as amended, 15 U.S.C. 717 et seq. ;
Energy Supply and Environmental Coordination Act (15 U.S.C. 791, et
seq.; Natural Gas Policy Act of 1978, Pub. L. 95-621, 92 Stat. 3350;
Department of Energy Organization Act, Pub. L. 95-91, E.O. 12009, 42 FR
46267.
18 CFR 275.201 Publication of notice from jurisdictional agency.
Upon receipt of a notice of determination by a jurisdictional agency
under 274.104, the Commission will send an acknowledgement to the
applicant and will post acknowledgement in the Commission's Division of
Public Information. Another source of the information is the
Commission's printing contractor: TS Infosystems, Inc., Attn: Mr.
Milton Chichester, 825 North Capitol Street, room 1000, Washington, DC
20426.
The acknowledgement will contain the following:
(a) The date on which the jurisdictional agency notice was received;
(b) Certain information contained in FERC Form No. 121;
(c) A statement that the application and a copy or description of
other materials in the record on which such determination was made is
available for inspection, except to the extent the material is treated
as confidential under 275.206, at the offices of the Commission; and
(d) A statement that persons objecting to the final determination
may, in accordance with this subpart, file a protest with the Commission
within 20 days after the date that notice of receipt of a determination
is issued by the Commission pursuant to 275.201 of this subpart.
(43 FR 56608, Dec. 1, 1978, as amended at 44 FR 34477, June 15, 1979;
Order 362, 49 FR 7114, Feb. 27, 1984)
18 CFR 275.202 Commission review of final determinations.
(a) Review by Commission. Except as provided in paragraphs (b), (c)
and (d) of this section, a determination submitted to the Commission by
a jurisdictional agency shall become final 45 days after the date on
which the Commission received notice of the determination, unless within
the 45-day period, the Commission:
(1) Makes a preliminary finding that:
(i) The determination is not supported by substantial evidence in the
record on which the determination was made; or
(ii) The determination is not consistent with information which is
contained in the public records of the Commission and which was not part
of the record on which the jurisdictional agency made the determination,
and
(2) Issues written notice of such preliminary finding, including the
reasons for the preliminary finding. Copies of the written notice will
be sent to the jurisdictional agency which made the determination, to
the persons identified in the notice under 274.104 of such
determination, and to any persons who have filed a protest.
(b) Incomplete notice. Notwithstanding the provisions of paragraph
(a) of this section, the 45-day period for Commission review of a
determination shall not begin if:
(1) The notice forwarded to the Commission pursuant to subpart A of
part 274 does not contain all (information required in 274.104(a) (4),
(5), and
(2) The Commission notifies the jurisdictional agency, the purchaser
and the parties to the proceeding before the jurisdictional; agency,
within 45 days after the date on which the Commission receives notice of
the determination, that the notice is incomplete.
(c) Withdrawal of notice. (1) The jurisdictional agency may withdraw
a notice of determination by giving notice as specified in paragraph
(c)(2) of this section at any time prior to the issuance of a final
order with respect to such determination under paragraphs (g)(1) and
(g)(2) of this section, or at any time prior to the date such
determination becomes final under paragraphs (a) or (g)(4) of this
section. Such notice shall include the jurisdictional agency's reasons
for the withdrawal.
(2) Withdrawal of a notice of determination shall take effect at such
time as the jurisdictional agency has notified the Commission, the
parties to the proceeding before the agency, and the purchaser of such
withdrawal.
(3) Withdrawal of a notice of determination shall nullify such notice
of determination.
(d) Withdrawal of application. (1) An applicant may withdraw an
application for a determination which is before the Commission by giving
notice as specified in paragraph (d)(2) of this section at any time
prior to the issuance of a final order with respect to such
determination under paragraphs (g)(1) and (g)(2) of this section, or at
any time prior to the date such determination becomes final under
paragraphs (a) or (g)(4) of this section.
(2) Withdrawal of an application shall take effect at such time as
the applicant has notified the Commission, the jurisdictional agency and
the purchaser.
(3) Withdrawal of an application shall nullify such application and
the notice of determination on such application.
(4) The applicant's right to make interim collections under part 273
of this chapter shall cease and the refund obligations of part 273 of
this chapter shall begin when the withdrawal takes effect under this
paragraph.
(e) Public notice. The Commission shall publish notice of the
preliminary finding in the Federal Register and shall post the notice in
its Office of Public Information. The notice shall set forth the
reasons for the preliminary finding.
(f) Procedures following notice of preliminary finding. Any state or
federal agency or any person may, within 30 days after issuance of the
preliminary finding, submit written comments and request an informal
conference with the Commission staff. Any jurisdictional agency, any
state agency and any person receiving notice under paragraph (a)(2) of
this section, may request an informal conference with the Commission
staff. All timely requests for conferences will be granted. Notice of,
and permission to attend, such conferences will be given to persons
identified in paragraph (a)(2) of this section, and to state or federal
agencies or persons who submitted comments under this paragraph.
(g) Final orders. (1) In any case in which a protest was filed with
the Commission pursuant to this subpart and a preliminary finding was
issued, the Commission shall issue a final order within 120 days after
issuance of the preliminary finding.
(2) In any case in which no protest was filed with the Commission
pursuant to this subpart, and a preliminary finding was issued, the
Commission may issue a final order within 120 days after issuance of the
preliminary finding.
(3) A final order issued under paragraph (g)(1) or (2) of this
section shall either affirm, reverse, or remand the determination of the
jurisdicational agency. Such order shall state the specific basis for
the Commission's action. Notice of the issuance of such order shall be
given to the jurisdictional agency, to participants in the proceeding
before the jurisdictional agency, and to participants in the proceeding
before the Commission under paragraph (f) of this section and under
275.203.
(4) In the event that the Commission fails to issue a final order
within 120 days after issuance of the preliminary finding, the
determination of the jurisdicational agency shall become final.
(43 FR 56608, Dec. 1, 1978, as amended at 44 FR 34477, June 15, 1979;
Order 41, 44 FR 48671, Aug. 20, 1979; 44 FR 66789, Nov. 21, 1979)
18 CFR 275.203 Protests to the Commission.
(a) Who may file. Any person may file a protest with the Commission
with respect to a determination of a jurisdictional agency within 20
days after the date that notice of receipt of a determination is issued
by the Commission pursuant to 275.201 of this subpart.
(b) Grounds. Protests may be based only on the grounds that the
final determination is:
(1) Not supported by substantial evidence;
(2) Not consistent with information which is contained in the public
records of the Commission and which was not part of the record on which
the determination was made;
(3) Not consistent with information submitted with the protest for
inclusion in the public records of the Commission, which information was
not part of the record on which the determination was made; or
(4) Not based on an application which complied with the filing
requirements set forth in subpart B of part 274, or alternative filing
requirements approved pursuant to 274.207.
(43 FR 56603, Dec. 1, 1978, as amended at 44 FR 34477, June 15, 1979;
Order 362, 49 FR 7115, Feb. 27, 1984)
18 CFR 275.204 Contents of protests to the Commission.
Each protest shall include:
(a) An identification of the determination protested;
(b) The name and address of the person filing the protest;
(c) A statement of whether or not the person filing the protest
participated in the proceeding before the jurisdictional agency, and if
not, the reason for his nonparticipation;
(d) A statement of the effect the determination will have on the
protestor;
(e) A statement of the precise grounds under 275.203 for the
protest, and all supporting documents or references to any information
relied on which is in the record on which the determination is based or
is in or to be inserted in the public files of the Commission; and
(f) A statement that the protestor has served, in accordance with
385.2010 of this chapter, a copy of the protest together with all
supporting documents on the jurisdictional agency and all persons listed
in the notice of determination pursuant to 274.104(a)(1) of this
subchapter.
(43 FR 56603, Dec. 1, 1978, as amended at 45 FR 17131, Mar. 18, 1980;
Order 225, 47 FR 19058, May 3, 1982)
18 CFR 275.205 Procedure for reopening determinations.
(a) Grounds. At any time subsequent to the time a determination
becomes final pursuant to this subpart, the Commission, on its own
motion, or in response to a petition filed by any person aggrieved or
adversely affected by the determination, may reopen the determination if
it appears that:
(1) In making the determination, the Commission or the jurisdictional
agency relied on any untrue statement of material fact; or
(2) There was omitted a statement of material fact necessary in order
to make the statements made not misleading, in light of the
circumstances under which they were made to the jurisdictional agency or
the Commission.
(b) Contents of petition. A petition to reopen the determination
procedings shall contain the following information, under oath:
(1) The name and address of the person filing the petition;
(2) The interest of the petitioner in the outcome of the
determination proceeding;
(3) The statement of material fact that is alleged to be untrue or
omitted;
(4) A statement explaining why the outcome of the determination
proceeding would have been different had the statement or omission not
occurred; and
(5) Copies of all documents relied on by the petitioner, or
references to such documents if they are contained in the public files
of the Commission.
(c) Procedures after reopening. In the event the Commission reopens
a determination pursuant to this section it shall:
(1) Give notice to the jurisdictional agency and all persons who
participated, before both that agency and the Commission, in the
proceedings resulting in the determination in question;
(2) Permit the jurisdictional agency and other persons receiving
notice pursuant to paragraph (c)(1) of this section, to submit whatever
documentary evidence such agency or persons deem relevant; and
(3) Take such other action or hold or cause to be held such
proceedings as it deems necessary or appropriate for a full disclosure
of the facts.
(d) Final order of Commission. Within 150 days after issuance of the
notice under paragraph (c)(1) of this section, the Commission shall
issue a final order. If the Commission finds that the grounds referred
to in paragraph (a) of this section exist, it shall vacate the
determination, and if appropriate, order refund or other action. The
right to collect the previously determined maximum lawful price shall
terminate on the date of the order vacating the determination.
(43 FR 56603, Dec. 1, 1978, as amended at 44 FR 34477, June 15, 1979)
18 CFR 275.206 Confidentiality.
(a) Except as provided in paragraph (b), the Commission will accord
confidential protection to, and not disclose to the public, any
information submitted to the Commission by a jurisdictional agency under
274.104(a)(4), if:
(1) The jurisdictional agency, on its own motion or on request of the
applicant, afforded such information confidential treatment before the
jurisdictional agency; and
(2) The agency order or the applicant's request stated grounds for
confidential treatment which fall within one of the exemptions described
in paragraphs (1) through (9) of 5 U.S.C. 552(b).
(b) Upon receipt of a request for disclosure of information treated
as confidential under paragraph (a), the Commission will determine in
accordance with 5 U.S.C. 552 whether the information is exempt under 5
U.S.C. 552(b). If it determines the information is not exempt, the
information will be made public. If it determines that the information
is exempt, the Commission will not make it public unless the Commission
determines that its conduct of the proceeding to review the
jurisdictional agency determination requires making such information
available to the public or to particular parties, subject to such
conditions (including a protective order) as the Commission may
prescribe. Before making any information public under this paragraph,
the Commission shall provide at least 5 days notice to the person who
submitted the information. Such notice shall be sent to telegraph.
(43 FR 56603, Dec. 1, 1978, as amended at 44 FR 34478, June 15, 1979;
45 FR 17131, Mar. 18, 1980)
18 CFR 275.206 PARTS 276 -- 279 (RESERVED)
18 CFR 275.206 FINDING AIDS
A list of CFR titles, subtitles, chapters, subchapters and parts and
an alphabetical list of agencies publishing in the CFR are included in
the CFR Index and Finding Aids volume to the Code of Federal Regulations
which is published separately and revised annually.
Table of CFR Titles and Chapters
Alphabetical List of Agencies Appearing in the CFR
Table of OMB Control Numbers
List of CFR Sections Affected
Chap.
18 CFR 275.206 Table of CFR Titles and Chapters
18 CFR 275.206 Title 1 -- General Provisions
I Administrative Committee of the Federal Register (Parts 1 -- 49)
II Office of the Federal Register (Parts 50 -- 299)
III Administrative Conference of the United States (Parts 300 -- 399)
IV Miscellaneous Agencies (Parts 400 -- 500)
18 CFR 275.206 Title 2 -- (Reserved)
18 CFR 275.206 Title 3 -- The President
I Executive Office of the President (Parts 100 -- 199)
18 CFR 275.206 Title 4 -- Accounts
I General Accounting Office (Parts 1 -- 99)
II Federal Claims Collection Standards (General Accounting Office --
Department of Justice) (Parts 100 -- 299)
18 CFR 275.206 Title 5 -- Administrative Personnel
I Office of Personnel Management (Parts 1 -- 1199)
II Merit Systems Protection Board (Parts 1200 -- 1299)
III Office of Management and Budget (Parts 1300 -- 1399)
IV Advisory Committee on Federal Pay (Parts 1400 -- 1499)
V The International Organizations Employees Loyalty Board (Parts 1500
-- 1599)
VI Federal Retirement Thrift Investment Board (Parts 1600 -- 1699)
VII Advisory Commission on Intergovernmental Relations (Parts 1700 --
1799)
VIII Office of Special Counsel (Parts 1800 -- 1899)
IX Appalachian Regional Commission (Parts 1900 -- 1999)
XI United States Soldiers' and Airmen's Home (Parts 2100 -- 2199)
XIV Federal Labor Relations Authority, General Counsel of the Federal
Labor Relations Authority and Federal Service Impasses Panel (Parts 2400
-- 2499)
XV Office of Administration, Executive Office of the President (Parts
2500 -- 2599)
XVI Office of Government Ethics (Parts 2600 -- 2699)
18 CFR 275.206 Title 6 (Reserved)
18 CFR 275.206 Title 7 -- Agriculture
Subtitle A -- Office of the Secretary of Agriculture (Parts 0 -- 26)
Subtitle B -- Regulations of the Department of Agriculture
I Agricultural Marketing Service (Standards, Inspections, Marketing
Practices), Department of Agriculture (Parts 27 -- 209)
II Food and Nutrition Service, Department of Agriculture (Parts 210
-- 299)
III Animal and Plant Health Inspection Service, Department of
Agriculture (Parts 300 -- 399)
IV Federal Crop Insurance Corporation, Department of Agriculture
(Parts 400 -- 499)
V Agricultural Research Service, Department of Agriculture (Parts 500
-- 599)
VI Soil Conservation Service, Department of Agriculture (Parts 600 --
699)
VII Agricultural Stabilization and Conservation Service (Agricultural
Adjustment), Department of Agriculture (Parts 700 -- 799)
VIII Federal Grain Inspection Service, Department of Agriculture
(Parts 800 -- 899)
IX Agricultural Marketing Service (Marketing Agreements and Orders;
Fruits, Vegetables, Nuts), Department of Agriculture (Parts 900 -- 999)
X Agricultural Marketing Service (Marketing Agreements and Orders;
Milk), Department of Agriculture (Parts 1000 -- 1199)
XI Agricultural Marketing Service (Marketing Agreements and Orders;
Miscellaneous Commodities), Department of Agriculture (Parts 1200 --
1299)
XIV Commodity Credit Corporation, Department of Agriculture (Parts
1400 -- 1499)
XV Foreign Agricultural Service, Department of Agriculture (Parts
1500 -- 1599)
XVI Rural Telephone Bank, Department of Agriculture (Parts 1600 --
1699)
XVII Rural Electrification Administration, Department of Agriculture
(Parts 1700 -- 1799)
XVIII Farmers Home Administration, Department of Agriculture (Parts
1800 -- 2099)
XXI Foreign Economic Development Service, Department of Agriculture
(Parts 2100 -- 2199)
XXII Office of International Cooperation and Development, Department
of Agriculture (Parts 2200 -- 2299)
XXV Office of the General Sales Manager, Department of Agriculture
(Parts 2500 -- 2599)
XXVI Office of Inspector General, Department of Agriculture (Parts
2600 -- 2699)
XXVII Office of Information Resources Management, Department of
Agriculture (Parts 2700 -- 2799)
XXVIII Office of Operations, Department of Agriculture (Parts 2800 --
2899)
XXIX Office of Energy, Department of Agriculture (Parts 2900 -- 2999)
XXX Office of Finance and Management, Department of Agriculture
(Parts 3000 -- 3099)
XXXI Office of Environmental Quality, Department of Agriculture
(Parts 3100 -- 3199)
XXXII Office of Grants and Program Systems, Department of Agriculture
(Parts 3200 -- 3299)
XXXIII Office of Transportation, Department of Agriculture (Parts
3300 -- 3399)
XXXIV Cooperative State Research Service, Department of Agriculture
(Parts 3400 -- 3499)
XXXVI National Agricultural Statistics Service, Department of
Agriculture (Parts 3600 -- 3699)
XXXVII Economic Research Service, Department of Agriculture (Parts
3700 -- 3799)
XXXVIII World Agricultural Outlook Board, Department of Agriculture
(Parts 3800 -- 3899)
XXXIX Economic Analysis Staff, Department of Agriculture (Parts 3900
-- 3999)
XL Economics Management Staff, Department of Agriculture (Parts 4000
-- 4099)
XLI National Agricultural Library, Department of Agriculture (Part
4100)
XLII Rural Development Administration, Department of Agriculture
(Part 4284 )
18 CFR 275.206 Title 8 -- Aliens and Nationality
I Immigration and Naturalization Service, Department of Justice
(Parts 1 -- 499)
18 CFR 275.206 Title 9 -- Animals and Animal Products
I Animal and Plant Health Inspection Service, Department of
Agriculture (Parts 1 -- 199)
II Packers and Stockyards Administration, Department of Agriculture
(Parts 200 -- 299)
III Food Safety and Inspection Service, Meat and Poultry Inspection,
Department of Agriculture (Parts 300 -- 399)
18 CFR 275.206 Title 10 -- Energy
I Nuclear Regulatory Commission (Parts 0 -- 199)
II Department of Energy (Parts 200 -- 699)
III Department of Energy (Parts 700 -- 999)
X Department of Energy (General Provisions) (Parts 1000 -- 1099)
XV Office of the Federal Inspector for the Alaska Natural Gas
Transportation System (Parts 1500 -- 1599)
XVII Defense Nuclear Facilities Safety Board (Parts 1700 -- 1799)
18 CFR 275.206 Title 11 -- Federal Elections
I Federal Election Commission (Parts 1 -- 9099)
18 CFR 275.206 Title 12 -- Banks and Banking
I Comptroller of the Currency, Department of the Treasury (Parts 1 --
199)
II Federal Reserve System (Parts 200 -- 299)
III Federal Deposit Insurance Corporation (Parts 300 -- 399)
IV Export-Import Bank of the United States (Parts 400 -- 499)
V Office of Thrift Supervision, Department of The Treasury (Parts 500
-- 599)
VI Farm Credit Administration (Parts 600 -- 699)
VII National Credit Union Administration (Parts 700 -- 799)
VIII Federal Financing Bank (Parts 800 -- 899)
IX Federal Housing Finance Board (Parts 900 -- 999)
XI Federal Financial Institutions Examination Council (Parts 1100 --
1199)
XIV Farm Credit System Insurance Corporation (Parts 1400 -- 1499)
XV Thrift Depositor Protection Oversight Board (Parts 1500 -- 1599)
XVI Resolution Trust Corporation (Parts 1600 -- 1699)
18 CFR 275.206 Title 13 -- Business Credit and Assistance
I Small Business Administration (Parts 1 -- 199)
III Economic Development Administration, Department of Commerce
(Parts 300 -- 399)
18 CFR 275.206 Title 14 -- Aeronautics and Space
I Federal Aviation Administration, Department of Transportation
(Parts 1 -- 199)
II Office of the Secretary, Department of Transportation (Aviation
Proceedings) (Parts 200 -- 399)
III Office of Commercial Space Transportation, Department of
Transportation (Parts 400 -- 499)
V National Aeronautics and Space Administration (Parts 1200 -- 1299)
18 CFR 275.206 Title 15 -- Commerce and Foreign Trade
Subtitle A -- Office of the Secretary of Commerce (Parts 0 -- 29)
Subtitle B -- Regulations Relating to Commerce and Foreign Trade
I Bureau of the Census, Department of Commerce (Parts 30 -- 199)
II National Institute of Standards and Technology, Department of
Commerce (Parts 200 -- 299)
III International Trade Administration, Department of Commerce (Parts
300 -- 399)
IV Foreign-Trade Zones Board (Parts 400 -- 499)
VII Bureau of Export Administration, Department of Commerce (Parts
700 -- 799)
VIII Bureau of Economic Analysis, Department of Commerce (Parts 800
-- 899)
IX National Oceanic and Atmospheric Administration, Department of
Commerce (Parts 900 -- 999)
XI Technology Administration, Department of Commerce (Parts 1100 --
1199)
XII United States Travel and Tourism Administration, Department of
Commerce (Parts 1200 -- 1299)
XIII East-West Foreign Trade Board (Parts 1300 -- 1399)
XIV Minority Business Development Agency (Parts 1400 -- 1499)
Subtitle C -- Regulations Relating to Foreign Trade Agreements
XX Office of the United States Trade Representative (Parts 2000 --
2099)
Subtitle D -- Regulations Relating to Telecommunications and
Information
XXIII National Telecommunications and Information Administration,
Department of Commerce (Parts 2300 -- 2399)
18 CFR 275.206 Title 16 -- Commercial Practices
I Federal Trade Commission (Parts 0 -- 999)
II Consumer Product Safety Commission (Parts 1000 -- 1799)
18 CFR 275.206 Title 17 -- Commodity and Securities Exchanges
I Commodity Futures Trading Commission (Parts 1 -- 199)
II Securities and Exchange Commission (Parts 200 -- 399)
IV Department of the Treasury (Parts 400 -- 499)
18 CFR 275.206 Title 18 -- Conservation of Power and Water Resources
I Federal Energy Regulatory Commission, Department of Energy (Parts 1
-- 399)
III Delaware River Basin Commission (Parts 400 -- 499)
VI Water Resources Council (Parts 700 -- 799)
VIII Susquehanna River Basin Commission (Parts 800 -- 899)
XIII Tennessee Valley Authority (Parts 1300 -- 1399)
18 CFR 275.206 Title 19 -- Customs Duties
I United States Customs Service, Department of the Treasury (Parts 1
-- 199)
II United States International Trade Commission (Parts 200 -- 299)
III International Trade Administration, Department of Commerce (Parts
300 -- 399)
18 CFR 275.206 Title 20 -- Employees' Benefits
I Office of Workers' Compensation Programs, Department of Labor
(Parts 1 -- 199)
II Railroad Retirement Board (Parts 200 -- 399)
III Social Security Administration, Department of Health and Human
Services (Parts 400 -- 499)
IV Employees' Compensation Appeals Board, Department of Labor (Parts
500 -- 599)
V Employment and Training Administration, Department of Labor (Parts
600 -- 699)
VI Employment Standards Administration, Department of Labor (Parts
700 -- 799)
VII Benefits Review Board, Department of Labor (Parts 800 -- 899)
VIII Joint Board for the Enrollment of Actuaries (Parts 900 -- 999)
IX Office of the Assistant Secretary for Veterans' Employment and
Training, Department of Labor (Parts 1000 -- 1099)
18 CFR 275.206 Title 21 -- Food and Drugs
I Food and Drug Administration, Department of Health and Human
Services (Parts 1 -- 1299)
II Drug Enforcement Administration, Department of Justice (Parts 1300
-- 1399)
III Office of National Drug Control Policy (Parts 1400 -- 1499)
18 CFR 275.206 Title 22 -- Foreign Relations
I Department of State (Parts 1 -- 199)
II Agency for International Development, International Development
Cooperation Agency (Parts 200 -- 299)
III Peace Corps (Parts 300 -- 399)
IV International Joint Commission, United States and Canada (Parts
400 -- 499)
V United States Information Agency (Parts 500 -- 599)
VI United States Arms Control and Disarmament Agency (Parts 600 --
699)
VII Overseas Private Investment Corporation, International
Development Cooperation Agency (Parts 700 -- 799)
IX Foreign Service Grievance Board Regulations (Parts 900 -- 999)
X Inter-American Foundation (Parts 1000 -- 1099)
XI International Boundary and Water Commission, United States and
Mexico, United States Section (Parts 1100 -- 1199)
XII United States International Development Cooperation Agency (Parts
1200 -- 1299)
XIII Board for International Broadcasting (Parts 1300 -- 1399)
XIV Foreign Service Labor Relations Board; Federal Labor Relations
Authority; General Counsel of the Federal Labor Relations Authority;
and the Foreign Service Impasse Disputes Panel (Parts 1400 -- 1499)
XV African Development Foundation (Parts 1500 -- 1599)
XVI Japan-United States Friendship Commission (Parts 1600 -- 1699)
18 CFR 275.206 Title 23 -- Highways
I Federal Highway Administration, Department of Transportation (Parts
1 -- 999)
II National Highway Traffic Safety Administration and Federal Highway
Administration, Department of Transportation (Parts 1200 -- 1299)
III National Highway Traffic Safety Administration, Department of
Transportation (Parts 1300 -- 1399)
18 CFR 275.206 Title 24 -- Housing and Urban Development
Subtitle A -- Office of the Secretary, Department of Housing and
Urban Development (Parts 0 -- 99)
Subtitle B -- Regulations Relating to Housing and Urban Development
I Office of Assistant Secretary for Equal Opportunity, Department of
Housing and Urban Development (Parts 100 -- 199)
II Office of Assistant Secretary for Housing-Federal Housing
Commissioner, Department of Housing and Urban Development (Parts 200 --
299)
III Government National Mortgage Association, Department of Housing
and Urban Development (Parts 300 -- 399)
V Office of Assistant Secretary for Community Planning and
Development, Department of Housing and Urban Development (Parts 500 --
599)
VI Office of Assistant Secretary for Community Planning and
Development, Department of Housing and Urban Development (Parts 600 --
699)
VII Office of the Secretary, Department of Housing and Urban
Development (Section 8 Housing Assistance Programs and Public and Indian
Housing Programs) (Parts 700 -- 799)
VIII Office of the Assistant Secretary for Housing -- Federal Housing
Commissioner, Department of Housing and Urban Development (Section 8
Housing Assistance Programs and Section 202 Direct Loan Program) (Parts
800 -- 899)
IX Office of Assistant Secretary for Public and Indian Housing,
Department of Housing and Urban Development (Parts 900 -- 999)
X Office of Assistant Secretary for Housing -- Federal Housing
Commissioner, Department of Housing and Urban Development (Interstate
Land Sales Registration Program) (Parts 1700 -- 1799)
XI Solar Energy and Energy Conservation Bank, Department of Housing
and Urban Development (Parts 1800 -- 1899)
XII Office of Inspector General, Department of Housing and Urban
Development (Parts 2000 -- 2099)
XV Mortgage Insurance and Loan Programs under the Emergency
Homeowners' Relief Act, Department of Housing and Urban Development
(Parts 2700 -- 2799)
XX Office of Assistant Secretary for Housing -- Federal Housing
Commissioner, Department of Housing and Urban Development (Parts 3200 --
3699)
XXV Neighborhood Reinvestment Corporation (Parts 4100 -- 4199)
18 CFR 275.206 Title 25 -- Indians
I Bureau of Indian Affairs, Department of the Interior (Parts 1 --
299)
II Indian Arts and Crafts Board, Department of the Interior (Parts
300 -- 399)
III National Indian Gaming Commission (Parts 500 -- 599)
IV Office of Navajo and Hopi Indian Relocation (Parts 700 -- 799)
18 CFR 275.206 Title 26 -- Internal Revenue
I Internal Revenue Service, Department of the Treasury (Parts 1 --
799)
18 CFR 275.206 Title 27 -- Alcohol, Tobacco Products and Firearms
I Bureau of Alcohol, Tobacco and Firearms, Department of the Treasury
(Parts 1 -- 299)
18 CFR 275.206 Title 28 -- Judicial Administration
I Department of Justice (Parts 0 -- 199)
III Federal Prison Industries, Inc., Department of Justice (Parts 300
-- 399)
V Bureau of Prisons, Department of Justice (Parts 500 -- 599)
VI Offices of Independent Counsel, Department of Justice (Parts 600
-- 699)
VII Office of Independent Counsel (Parts 700 -- 799)
18 CFR 275.206 Title 29 -- Labor
Subtitle A -- Office of the Secretary of Labor (Parts 0 -- 99)
Subtitle B -- Regulations Relating to Labor
I National Labor Relations Board (Parts 100 -- 199)
II Bureau of Labor-Management Relations and Cooperative Programs,
Department of Labor (Parts 200 -- 299)
III National Railroad Adjustment Board (Parts 300 -- 399)
IV Office of Labor-Management Standards, Department of Labor (Parts
400 -- 499)
V Wage and Hour Division, Department of Labor (Parts 500 -- 899)
IX Construction Industry Collective Bargaining Commission (Parts 900
-- 999)
X National Mediation Board (Parts 1200 -- 1299)
XII Federal Mediation and Conciliation Service (Parts 1400 -- 1499)
XIV Equal Employment Opportunity Commission (Parts 1600 -- 1699)
XVII Occupational Safety and Health Administration, Department of
Labor (Parts 1900 -- 1999)
XX Occupational Safety and Health Review Commission (Parts 2200 --
2499)
XXV Pension and Welfare Benefits Administration, Department of Labor
(Parts 2500 -- 2599)
XXVI Pension Benefit Guaranty Corporation (Parts 2600 -- 2699)
XXVII Federal Mine Safety and Health Review Commission (Parts 2700 --
2799)
18 CFR 275.206 Title 30 -- Mineral Resources
I Mine Safety and Health Administration, Department of Labor (Parts 1
-- 199)
II Minerals Management Service, Department of the Interior (Parts 200
-- 299)
III Board of Surface Mining and Reclamation Appeals, Department of
the Interior (Parts 300 -- 399)
IV Geological Survey, Department of the Interior (Parts 400 -- 499)
VI Bureau of Mines, Department of the Interior (Parts 600 -- 699)
VII Office of Surface Mining Reclamation and Enforcement, Department
of the Interior (Parts 700 -- 999)
18 CFR 275.206 Title 31 -- Money and Finance: Treasury
Subtitle A -- Office of the Secretary of the Treasury (Parts 0 -- 50)
Subtitle B -- Regulations Relating to Money and Finance
I Monetary Offices, Department of the Treasury (Parts 51 -- 199)
II Fiscal Service, Department of the Treasury (Parts 200 -- 399)
IV Secret Service, Department of the Treasury (Parts 400 -- 499)
V Office of Foreign Assets Control, Department of the Treasury (Parts
500 -- 599)
VI Bureau of Engraving and Printing, Department of the Treasury
(Parts 600 -- 699)
VII Federal Law Enforcement Training Center, Department of the
Treasury (Parts 700 -- 799)
VIII Office of International Investment, Department of the Treasury
(Parts 800 -- 899)
18 CFR 275.206 Title 32 -- National Defense
Subtitle A -- Department of Defense
I Office of the Secretary of Defense (Parts 1 -- 399)
V Department of the Army (Parts 400 -- 699)
VI Department of the Navy (Parts 700 -- 799)
VII Department of the Air Force (Parts 800 -- 1099)
Subtitle B -- Other Regulations Relating to National Defense
XII Defense Logistics Agency (Parts 1200 -- 1299)
XVI Selective Service System (Parts 1600 -- 1699)
XIX Central Intelligence Agency (Parts 1900 -- 1999)
XX Information Security Oversight Office (Parts 2000 -- 2099)
XXI National Security Council (Parts 2100 -- 2199)
XXIV Office of Science and Technology Policy (Parts 2400 -- 2499)
XXVII Office for Micronesian Status Negotiations (Parts 2700 -- 2799)
XXVIII Office of the Vice President of the United States (Parts 2800
-- 2899)
XXIX Presidential Commission on the Assignment of Women in the Armed
Forces (Part 2900)
18 CFR 275.206 Title 33 -- Navigation and Navigable Waters
I Coast Guard, Department of Transportation (Parts 1 -- 199)
II Corps of Engineers, Department of the Army (Parts 200 -- 399)
IV Saint Lawrence Seaway Development Corporation, Department of
Transportation (Parts 400 -- 499)
18 CFR 275.206 Title 34 -- Education
Subtitle A -- Office of the Secretary, Department of Education (Parts
1 -- 99)
Subtitle B -- Regulations of the Offices of the Department of
Education
I Office for Civil Rights, Department of Education (Parts 100 -- 199)
II Office of Elementary and Secondary Education, Department of
Education (Parts 200 -- 299)
III Office of Special Education and Rehabilitative Services,
Department of Education (Parts 300 -- 399)
IV Office of Vocational and Adult Education, Department of Education
(Parts 400 -- 499)
V Office of Bilingual Education and Minority Languages Affairs,
Department of Education (Parts 500 -- 599)
VI Office of Postsecondary Education, Department of Education (Parts
600 -- 699)
VII Office of Educational Research and Improvement, Department of
Education (Parts 700 -- 799)
18 CFR 275.206 Title 35 -- Panama Canal
I Panama Canal Regulations (Parts 1 -- 299)
18 CFR 275.206 Title 36 -- Parks, Forests, and Public Property
I National Park Service, Department of the Interior (Parts 1 -- 199)
II Forest Service, Department of Agriculture (Parts 200 -- 299)
III Corps of Engineers, Department of the Army (Parts 300 -- 399)
IV American Battle Monuments Commission (Parts 400 -- 499)
V Smithsonian Institution (Parts 500 -- 599)
VII Library of Congress (Parts 700 -- 799)
VIII Advisory Council on Historic Preservation (Parts 800 -- 899)
IX Pennsylvania Avenue Development Corporation (Parts 900 -- 999)
XI Architectural and Transportation Barriers Compliance Board (Parts
1100 -- 1199)
XII National Archives and Records Administration (Parts 1200 -- 1299)
18 CFR 275.206 Title 37 -- Patents, Trademarks, and Copyrights
I Patent and Trademark Office, Department of Commerce (Parts 1 --
199)
II Copyright Office, Library of Congress (Parts 200 -- 299)
III Copyright Royalty Tribunal (Parts 300 -- 399)
IV Assistant Secretary for Technology Policy, Department of Commerce
(Parts 400 -- 499)
V Under Secretary for Technology, Department of Commerce (Parts 500
-- 599)
18 CFR 275.206 Title 38 -- Pensions, Bonuses, and Veterans' Relief
I Department of Veterans Affairs (Parts 0 -- 99)
18 CFR 275.206 Title 39 -- Postal Service
I United States Postal Service (Parts 1 -- 999)
III Postal Rate Commission (Parts 3000 -- 3099)
18 CFR 275.206 Title 40 -- Protection of Environment
I Environmental Protection Agency (Parts 1 -- 799)
V Council on Environmental Quality (Parts 1500 -- 1599)
18 CFR 275.206 Title 41 -- Public Contracts and Property Management
Subtitle B -- Other Provisions Relating to Public Contracts
50 Public Contracts, Department of Labor (Parts 50-1 -- 50-999)
51 Committee for Purchase from the Blind and Other Severely
Handicapped (Parts 51-1 -- 51-99)
60 Office of Federal Contract Compliance Programs, Equal Employment
Opportunity, Department of Labor (Parts 60-1 -- 60-999)
61 Office of the Assistant Secretary for Veterans Employment and
Training, Department of Labor (Parts 61-1 -- 61-999)
Subtitle C -- Federal Property Management Regulations System
101 Federal Property Management Regulations (Parts 101-1 -- 101-99)
105 General Services Administration (Parts 105-1 -- 105-999)
109 Department of Energy Property Management Regulations (Parts 109-1
-- 109-99)
114 Department of the Interior (Parts 114-1 -- 114-99)
115 Environmental Protection Agency (Parts 115-1 -- 115-99)
128 Department of Justice (Parts 128-1 -- 128-99)
132 Department of the Air Force (Parts 132-1 -- 132-99)
Subtitle D -- Other Provisions Relating to Property Management
(Reserved)
Subtitle E -- Federal Information Resources Management Regulations
System
201 Federal Information Resources Management Regulation (Parts 201-1
-- 201-99)
Subtitle F -- Federal Travel Regulation System
301 Travel Allowances (Parts 301-1 -- 301-99)
302 Relocation Allowances (Parts 302-1 -- 302-99)
303 Payment of Expenses Connected with the Death of Certain Employees
(Parts 303-1 -- 303-2)
304 Payment from a non-Federal source for travel expenses (Parts
304-1 -- 304-99)
18 CFR 275.206 Title 42 -- Public Health
I Public Health Service, Department of Health and Human Services
(Parts 1 -- 199)
IV Health Care Financing Administration, Department of Health and
Human Services (Parts 400 -- 499)
V Office of Inspector General-Health Care, Department of Health and
Human Services (Parts 1000 -- 1999)
18 CFR 275.206 Title 43 -- Public Lands: Interior
Subtitle A -- Office of the Secretary of the Interior (Parts 1 --
199)
Subtitle B -- Regulations Relating to Public Lands
I Bureau of Reclamation, Department of the Interior (Parts 200 --
499)
II Bureau of Land Management, Department of the Interior (Parts 1000
-- 9999)
18 CFR 275.206 Title 44 -- Emergency Management and Assistance
I Federal Emergency Management Agency (Parts 0 -- 399)
IV Department of Commerce and Department of Transportation (Parts 400
-- 499)
18 CFR 275.206 Title 45 -- Public Welfare
Subtitle A -- Department of Health and Human Services, General
Administration (Parts 1 -- 199)
Subtitle B -- Regulations Relating to Public Welfare
II Office of Family Assistance (Assistance Programs), Administration
for Children and Families, Department of Health and Human Services
(Parts 200 -- 299)
III Office of Child Support Enforcement (Child Support Enforcement
Program), Administration for Children and Families, Department of Health
and Human Services (Parts 300 -- 399)
IV Office of Refugee Resettlement, Administration for Children and
Families Department of Health and Human Services (Parts 400 -- 499)
V Foreign Claims Settlement Commission of the United States,
Department of Justice (Parts 500 -- 599)
VI National Science Foundation (Parts 600 -- 699)
VII Commission on Civil Rights (Parts 700 -- 799)
VIII Office of Personnel Management (Parts 800 -- 899)
X Office of Community Services, Administration for Children and
Families, Department of Health and Human Services (Parts 1000 -- 1099)
XI National Foundation on the Arts and the Humanities (Parts 1100 --
1199)
XII ACTION (Parts 1200 -- 1299)
XIII Office of Human Development Services, Department of Health and
Human Services (Parts 1300 -- 1399)
XVI Legal Services Corporation (Parts 1600 -- 1699)
XVII National Commission on Libraries and Information Science (Parts
1700 -- 1799)
XVIII Harry S. Truman Scholarship Foundation (Parts 1800 -- 1899)
XXI Commission on Fine Arts (Parts 2100 -- 2199)
XXII Christopher Columbus Quincentenary Jubilee Commission (Parts
2200 -- 2299)
XXIV James Madison Memorial Fellowship Foundation (Parts 2400 --
2499)
XXV Commission on National and Community Service (Parts 2500 -- 2506)
18 CFR 275.206 Title 46 -- Shipping
I Coast Guard, Department of Transportation (Parts 1 -- 199)
II Maritime Administration, Department of Transportation (Parts 200
-- 399)
III Coast Guard (Great Lakes Pilotage), Department of Transportation
(Parts 400 -- 499)
IV Federal Maritime Commission (Parts 500 -- 599)
18 CFR 275.206 Title 47 -- Telecommunication
I Federal Communications Commission (Parts 0 -- 199)
II Office of Science and Technology Policy and National Security
Council (Parts 200 -- 299)
III National Telecommunications and Information Administration,
Department of Commerce (Parts 300 -- 399)
18 CFR 275.206 Title 48 -- Federal Acquisition Regulations System
1 Federal Acquisition Regulation (Parts 1 -- 99)
2 Department of Defense (Parts 200 -- 299)
3 Department of Health and Human Services (Parts 300 -- 399)
4 Department of Agriculture (Parts 400 -- 499)
5 General Services Administration (Parts 500 -- 599)
6 Department of State (Parts 600 -- 699)
7 Agency for International Development (Parts 700 -- 799)
8 Department of Veterans Affairs (Parts 800 -- 899)
9 Department of Energy (Parts 900 -- 999)
10 Department of the Treasury (Parts 1000 -- 1099)
12 Department of Transportation (Parts 1200 -- 1299)
13 Department of Commerce (Parts 1300 -- 1399)
14 Department of the Interior (Parts 1400 -- 1499)
15 Environmental Protection Agency (Parts 1500 -- 1599)
16 Office of Personnel Management Federal Employees Health Benefits
Acquisition Regulation (Parts 1600 -- 1699)
17 Office of Personnel Management (Parts 1700 -- 1799)
18 National Aeronautics and Space Administration (Parts 1800 -- 1899)
19 United States Information Agency (Parts 1900 -- 1999)
20 Nuclear Regulatory Commission (Parts 2000 -- 2099)
22 Small Business Administration (Parts 2200 -- 2299)
24 Department of Housing and Urban Development (Parts 2400 -- 2499)
25 National Science Foundation (Parts 2500 -- 2599)
28 Department of Justice (Parts 2800 -- 2899)
29 Department of Labor (Parts 2900 -- 2999)
34 Department of Education Acquisition Regulation (Parts 3400 --
3499)
35 Panama Canal Commission (Parts 3500 -- 3599)
44 Federal Emergency Management Agency (Parts 4400 -- 4499)
51 Department of the Army Acquisition Regulations (Parts 5100 --
5199)
52 Department of the Navy Acquisition Regulations (Parts 5200 --
5299)
53 Department of the Air Force Federal Acquisition Regulation
Supplement (Parts 5300 -- 5399)
57 African Development Foundation (Parts 5700 -- 5799)
61 General Services Administration Board of Contract Appeals (Parts
6100 -- 6199)
63 Department of Transportation Board of Contract Appeals (Parts 6300
-- 6399)
99 Cost Accounting Standards Board, Office of Federal Procurement
Policy, Office of Management and Budget (Parts 9900 -- 9999)
18 CFR 275.206 Title 49 -- Transportation
Subtitle A -- Office of the Secretary of Transportation (Parts 1 --
99)
Subtitle B -- Other Regulations Relating to Transportation
I Research and Special Programs Administration, Department of
Transportation (Parts 100 -- 199)
II Federal Railroad Administration, Department of Transportation
(Parts 200 -- 299)
III Federal Highway Administration, Department of Transportation
(Parts 300 -- 399)
IV Coast Guard, Department of Transportation (Parts 400 -- 499)
V National Highway Traffic Safety Administration, Department of
Transportation (Parts 500 -- 599)
VI Federal Transit Administration, Department of Transportation
(Parts 600 -- 699)
VII National Railroad Passenger Corporation (AMTRAK) (Parts 700 --
799)
VIII National Transportation Safety Board (Parts 800 -- 899)
X Interstate Commerce Commission (Parts 1000 -- 1399)
18 CFR 275.206 Title 50 -- Wildlife and Fisheries
I United States Fish and Wildlife Service, Department of the Interior
(Parts 1 -- 199)
II National Marine Fisheries Service, National Oceanic and
Atmospheric Administration, Department of Commerce (Parts 200 -- 299)
III International Regulatory Agencies (Fishing and Whaling) (Parts
300 -- 399)
IV Joint Regulations (United States Fish and Wildlife Service,
Department of the Interior and National Marine Fisheries Service,
National Oceanic and Atmospheric Administration, Department of
Commerce); Endangered Species Committee Regulations (Parts 400 -- 499)
V Marine Mammal Commission (Parts 500 -- 599)
VI Fishery Conservation and Management, National Oceanic and
Atmospheric Administration, Department of Commerce (Parts 600 -- 699)
18 CFR 275.206 CFR Index and Finding Aids Subject/Agency Index
List of Agency Prepared Indexes Parallel Tables of Statutory Authorities
and Rules Acts Requiring Publication in the Federal Register List of CFR
Titles, Chapters, Subchapters, and Parts Alphabetical List of Agencies
Appearing in the CFR
18 CFR 275.206 Alphabetical List of Agencies Appearing in the CFR
CFR Title, Subtitle or
Agency
Chapter
ACTION 45, XII
Administrative Committee of the Federal Register 1, I
Administrative Conference of the United States 1, III
Advisory Commission on Intergovernmental Relations 5, VII
Advisory Committee on Federal Pay 5, IV
Advisory Council on Historic Preservation 36, VIII
African Development Foundation 22, XV; 48, 57
Agency for International Development 22, II; 48, 7
Agricultural Marketing Service 7, I, IX, X, XI
Agricultural Research Service 7, V
Agricultural Stabilization and Conservation Service 7, VII
Agriculture Department
Agricultural Marketing Service 7, I, IX, X, XI
Agricultural Research Service 7, V
Agricultural Stabilization and Conservation Service 7, VII
Animal and Plant Health Inspection Service 7, III; 9, I
Commodity Credit Corporation 7, XIV
Cooperative State Research Service 7, XXXIV
Economic Analysis Staff 7, XXXIX
Economic Research Service 7, XXXVII
Economics Management Staff 7, XL
Energy, Office of 7, XXIX
Environmental Quality, Office of 7, XXXI
Farmers Home Administration 7, XVIII
Federal Acquisition Regulation 48, 4
Federal Crop Insurance Corporation 7, IV
Federal Grain Inspection Service 7, VIII
Finance and Management, Office of 7, XXX
Food and Nutrition Service 7, II
Food Safety and Inspection Service 9, III
Foreign Agricultural Service 7, XV
Foreign Economic Development Service 7, XXI
Forest Service 36, II
General Sales Manager, Office of 7, XXV
Grants and Program Systems, Office of 7, XXXII
Information Resources Management, Office of 7, XXVII
Inspector General, Office of 7, XXVI
International Cooperation and Development Office 7, XXII
National Agricultural Library 7, XLI
National Agricultural Statistics Service 7, XXXVI
Operations Office 7, XXVIII
Packers and Stockyards Administration 9, II
Rural Electrification Administration 7, XVII
Rural Telephone Bank 7, XVI
Secretary of Agriculture, Office of 7, Subtitle A
Soil Conservation Service 7, VI
Transportation, Office of 7, XXXIII
World Agriculture Outlook Board 7, XXXVIII
Air Force Department 32, VII; 41, Subtitle C, Ch. 132
Federal Acquisition Regulation Supplement 48, 53
Alaska Natural Gas Transportation System, Office of the Federal
Inspector 10, XV
Alcohol, Tobacco and Firearms, Bureau of 27, I
AMTRAK 49, VII
American Battle Monuments Commission 36, IV
Animal and Plant Health Inspection Service 7, III; 9, I
Appalachian Regional Commission 5, IX
Architectural and Transportation Barriers Compliance Board 36, XI
Arms Control and Disarmament Agency, U.S. 22, VI
Army Department 32, V
Engineers, Corps of 33, II; 36, III
Federal Acquisition Regulation 48, 51
Assistant Secretary for Technology Policy, Department of Commerce 37,
IV
Benefits Review Board 20, VII
Bilingual Education and Minority Languages Affairs, Office of 34, V
Blind and Other Severely Handicapped, Committee for Purchase from 41,
51
Board for International Broadcasting 22, XIII
Budget, Office of Management and 5, III
Census Bureau 15, I
Central Intelligence Agency 32, XIX
Child Support Enforcement, Office of 45, III
Children and Families, Administration for 45, II, III, IV, X
Christopher Columbus Quincentenary Jubilee Commission 45, XXII
Civil Rights Commission 45, VII
Civil Rights, Office for (Education Department) 34, I
Claims Collection Standards, Federal 4, II
Coast Guard 33, I; 46, I, III; 49, IV
Commerce Department 44, IV
Census Bureau 15, I
Assistant Secretary for Technology Policy 37, IV
Economic Affairs, Under Secretary 37, V
Economic Analysis, Bureau of 15, VIII
Economic Development Administration 13, III
Endangered Species Committee 50, IV
Export Administration Bureau 15, VII
Federal Acquisition Regulation 48, 13
Fishery Conservation and Management 50, VI
International Trade Administration 15, III; 19, III
National Institute of Standards and Technology 15, II
National Marine Fisheries Service 50, II, IV
National Oceanic and Atmospheric Administration 15, IX; 50, II, III,
IV, VI
National Telecommunications and Information Administration 15, XXIII;
47, III
Patent and Trademark Office 37, I
Productivity, Technology and Innovation, Assistant Secretary for 37,
IV
Secretary of Commerce, Office of 15, Subtitle A
Technology Administration 15, XI
Under Secretary for Technology 37, V
United States Travel and Tourism Administration 15, XII
Commercial Space Transportation, Office of, Department of
Transportation 14, III
Commission on National and Community Service 45, XXV
Committee for Purchase from People who are Blind or Severely Disabled
41, 51
Commodity Credit Corporation 7, XIV
Commodity Futures Trading Commission 17, I
Community Planning and Development, Office of Assistant Secretary for
24, V, VI
Community Services, Office of 45, X
Comptroller of the Currency 12, I
Construction Industry Collective Bargaining Commission 29, IX
Consumer Product Safety Commission 16, II
Cooperative State Research Service 7, XXXIV
Copyright Office 37, II
Copyright Royalty Tribunal 37, III
Cost Accounting Standards Board, Office of Federal Procurement Policy
48, 99
Council on Environmental Quality 40, V
Customs Service, United States 19, I
Defense Department 32, Subtitle A
Air Force Department 32, VII; 41, Subtitle C, Ch. 132
Army Department 32, V; 33, II; 36, III, 48, 51
Engineers, Corps of 33, II; 36, III
Federal Acquisition Regulation 48, 2
Navy Department 32, VI; 48, 52
Secretary of Defense, Office of 32, I
Defense Logistics Agency 32, XII
Defense Nuclear Facilities Safety Board 10, XVII
Delaware River Basin Commission 18, III
Drug Enforcement Administration 21, II
East-West Foreign Trade Board 15, XIII
Economic Affairs, Under Secretary (Commerce) 37, V
Economic Analysis, Bureau of 15, VIII
Economic Analysis Staff, Department of Agriculture 7, XXXIX
Economic Development Administration 13, III
Economics Management Staff 7, XL
Economic Research Service 7, XXXVII
Education, Department of
Bilingual Education and Minority Languages Affairs, Office of 34, V
Civil Rights, Office for 34, I
Educational Research and Improvement, Office of 34, VII
Elementary and Secondary Education, Office of 34, II
Federal Acquisition Regulation 48, 34
Postsecondary Education, Office of 34, VI
Secretary of Education, Office of 34, Subtitle A
Special Education and Rehabilitative Services, Office of 34, III
Vocational and Adult Education, Office of 34, IV
Educational Research and Improvement, Office of 34, VII
Elementary and Secondary Education, Office of 34, II
Employees' Compensation Appeals Board 20, IV
Employees Loyalty Board, International Organizations 5, V
Employment and Training Administration 20, V
Employment Standards Administration 20, VI
Endangered Species Committee 50, IV
Energy, Department of 10, II, III, X; 41, 109
Federal Acquisition Regulation 48, 9
Federal Energy Regulatory Commission 18, I
Energy, Office of, Department of Agriculture 7, XXIX
Engineers, Corps of 33, II; 36, III
Engraving and Printing, Bureau of 31, VI
Environmental Protection Agency 40, I; 41, 115; 48, 15
Environmental Quality, Office of (Agriculture Department) 7, XXXI
Equal Employment Opportunity Commission 29, XIV
Equal Opportunity, Office of Assistant Secretary for 24, I
Executive Office of the President 3, I
Administration, Office of 5, XV
Export Administration Bureau 15, VII
Export-Import Bank of the United States 12, IV
Family Assistance, Office of 45, II
Farm Credit Administration 12, VI
Farm Credit System Insurance Corporation 12, XIV
Farmers Home Administration 7, XVIII
Federal Acquisition Regulation 48, 1
Federal Aviation Administration 14, I
Federal Claims Collection Standards 4, II
Federal Communications Commission 47, I
Federal Contract Compliance Programs, Office of 41, 60
Federal Crop Insurance Corporation 7, IV
Federal Deposit Insurance Corporation 12, III
Federal Election Commission 11, I
Federal Emergency Management Agency 44, I; 48, 44
Federal Energy Regulatory Commission 18, I
Federal Financial Institutions Examination Council 12, XI
Federal Financing Bank 12, VIII
Federal Grain Inspection Service 7, VIII
Federal Highway Administration 23, I, II; 49, III
Federal Home Loan Mortgage Corporation 1, IV
Federal Housing Finance Board 12, IX
Federal Information Resources Management Regulations 41, Subtitle E,
Ch. 201
Federal Inspector for the Alaska Natural Gas Transportation System,
Office of 10, XV
Federal Labor Relations Authority, and General Counsel of the Federal
Labor Relations Authority 5, XIV; 22, XIV
Federal Law Enforcement Training Center 31, VII
Federal Maritime Commission 46, IV
Federal Mediation and Conciliation Service 29, XII
Federal Mine Safety and Health Review Commission 29, XXVII
Federal Pay, Advisory Committee on 5, IV
Federal Prison Industries, Inc. 28, III
Federal Procurement Policy Office 48, 99
Federal Property Management Regulations 41, 101
Federal Property Management Regulations System 41, Subtitle C
Federal Railroad Administration 49, II
Federal Register, Administrative Committee of 1, I
Federal Register, Office of 1, II
Federal Reserve System 12, II
Federal Retirement Thrift Investment Board 5, VI
Federal Service Impasses Panel 5, XIV
Federal Trade Commission 16, I
Federal Transit Administration 49, VI
Federal Travel Regulation System 41, Subtitle F
Finance and Management, Department of Agriculture 7, XXX
Fine Arts Commission 45, XXI
Fiscal Service 31, II
Fish and Wildlife Service, United States 50, I, IV
Fishery Conservation and Management 50, VI
Fishing and Whaling, International Regulatory Agencies 50, III
Food and Drug Administration 21, I
Food and Nutrition Service 7, II
Food Safety and Inspection Service 9, III
Foreign Agricultural Service 7, XV
Foreign Assets Control, Office of 31, V
Foreign Claims Settlement Commission of United States 45, V
Foreign Economic Development Service 7, XXI
Foreign Service Grievance Board 22, IX
Foreign Service Impasse Disputes Panel 22, XIV
Foreign Service Labor Relations Board 22, XIV
Foreign-Trade Zones Board 15, IV
Forest Service 36, II
General Accounting Office 4, I, II
General Sales Manager, Office of 7, XXV
General Services Administration
Contract Appeals Board 48, 61
Federal Acquisition Regulation 48, 5
Federal Information Resources Management Regulations 41, Subtitle E,
Ch. 201
Federal Property Management Regulations System 41, 101, 105
Federal Travel Regulation System 41, Subtitle F
Payment of Expenses Connected With the Death of Certain Employees 41,
303
Relocation Allowances 41, 302
Travel Allowances 41, 301
Geological Survey 30, IV
Government Ethics, Office of 5, XVI
Government National Mortgage Association 24, III
Grants and Program Systems, Office of 7, XXXII
Great Lakes Pilotage 46, III
Harry S. Truman Scholarship Foundation 45, XVIII
Health and Human Services, Department of 45, Subtitle A
Child Support Enforcement, Office of 45, III
Children and Families, Administration for 45, II, III, IV, X
Community Services, Office of 45, X
Family Assistance, Office of 45, II
Federal Acquisition Regulation 48, 3
Food and Drug Administration 21, I
Health Care Financing Administration 42, IV
Human Development Services Office 45, XIII
Inspector General, Office of 42, V
Public Health Service 42, I
Refugee Resettlement, Office of 45, IV
Social Security Administration 20, III; 45, IV
Health Care Financing Administration 42, IV
Housing and Urban Development, Department of
Community Planning and Development, Office of Assistant Secretary for
24, V, VI
Equal Opportunity, Office of Assistant Secretary for 24, I
Federal Acquisition Regulation 48, 24
Government National Mortgage Association 24, III
Housing -- Federal Housing Commissioner, Office of Assistant
Secretary for 24, II, VIII, X, XX
Inspector General, Office of 24, XII
Mortgage Insurance and Loan Programs Under Emergency Homeowners'
Relief Act 24, XV
Public and Indian Housing, Office of Assistant Secretary for 24, IX
Secretary, Office of 24, Subtitle B, VII
Solar Energy and Energy Conservation Bank 24, XI
Housing -- Federal Housing Commissioner, Office of Assistant
Secretary for 24, II, VIII, X, XX
Human Development Services Office 45, XIII
Immigration and Naturalization Service 8, I
Indian Affairs, Bureau of 25, I
Indian Arts and Crafts Board 25, II
Information Agency, United States 22, V; 48, 19
Information Resources Management, Office of, Agriculture Department
7, XXVII
Information Security Oversight Office 32, XX
Inspector General, Office of, Agriculture Department 7, XXVI
Inspector General, Office of, Health and Human Services Department
42, V
Inspector General, Office of, Housing and Urban Development
Department 24, XII
Inter-American Foundation 22, X
Intergovernmental Relations, Advisory Commission on 5, VII
Interior Department
Endangered Species Committee 50, IV
Federal Acquisition Regulation 48, 14
Federal Property Management Regulations System 41, 114
Fish and Wildlife Service, United States 50, I, IV
Geological Survey 30, IV
Indian Affairs, Bureau of 25, I
Indian Arts and Crafts Board 25, II
Land Management Bureau 43, II
Minerals Management Service 30, II
Mines, Bureau of 30, VI
National Park Service 36, I
Reclamation Bureau 43, I
Secretary of the Interior, Office of 43, Subtitle A
Surface Mining and Reclamation Appeals, Board of 30, III
Surface Mining Reclamation and Enforcement, Office of 30, VII
United States Fish and Wildlife Service 50, I, IV
Internal Revenue Service 26, I
International Boundary and Water Commission, United States and Mexico
22, XI
International Cooperation and Development Office, Department of
Agriculture 7, XXII
International Development, Agency for 22, II
International Development Cooperation Agency 22, XII
International Development, Agency for 22, II
Overseas Private Investment Corporation 22, VII
International Joint Commission, United States and Canada 22, IV
International Organizations Employees Loyalty Board 5, V
International Regulatory Agencies (Fishing and Whaling) 50, III
International Trade Administration 15, III; 19, III
International Trade Commission, United States 19, II
Interstate Commerce Commission 49, X
James Madison Memorial Fellowship Foundation 45, XXIV
Japan-United States Friendship Commission 22, XVI
Joint Board for the Enrollment of Actuaries 20, VIII
Justice Department 28, I; 41, 128
Drug Enforcement Administration 21, II
Federal Acquisition Regulation 48, 28
Federal Claims Collection Standards 4, II
Federal Prison Industries, Inc. 28, III
Foreign Claims Settlement Commission of the United States 45, V
Immigration and Naturalization Service 8, I
Offices of Independent Counsel 28, VI
Prisons, Bureau of 28, V
Labor Department
Benefits Review Board 20, VII
Employees' Compensation Appeals Board 20, IV
Employment and Training Administration 20, V
Employment Standards Administration 20, VI
Federal Acquisition Regulation 48, 29
Federal Contract Compliance Programs, Office of 41, 60
Federal Procurement Regulations System 41, 50
Labor-Management Relations and Cooperative Programs, Bureau of 29, II
Labor-Management Standards, Office of 29, IV
Mine Safety and Health Administration 30, I
Occupational Safety and Health Administration 29, XVII
Pension and Welfare Benefits Administration 29, XXV
Public Contracts 41, 50
Secretary of Labor, Office of 29, Subtitle A
Veterans' Employment and Training, Office of the Assistant Secretary
for 41, 61; 20, IX
Wage and Hour Division 29, V
Workers' Compensation Programs, Office of 20, I
Labor-Management Relations and Cooperative Programs, Bureau of 29, II
Labor-Management Standards, Office of 29, IV
Land Management, Bureau of 43, II
Legal Services Corporation 45, XVI
Library of Congress 36, VII
Copyright Office 37, II
Management and Budget, Office of 5, III; 48, 99
Marine Mammal Commission 50, V
Maritime Administration 46, II
Merit Systems Protection Board 5, II
Micronesian Status Negotiations, Office for 32, XXVII
Mine Safety and Health Administration 30, I
Minerals Management Service 30, II
Mines, Bureau of 30, VI
Minority Business Development Agency 15, XIV
Miscellaneous Agencies 1, IV
Monetary Offices 31, I
Mortgage Insurance and Loan Programs Under the Emergency Homeowners'
Relief Act, Department of Housing and Urban Development 24, XV
National Aeronautics and Space Administration 14, V; 48, 18
National Agricultural Library 7, XLI
National Agricultural Statistics Service 7, XXXVI
National Archives and Records Administration 36, XII
National Bureau of Standards 15, II
National Capital Planning Commission 1, IV
National Commission for Employment Policy 1, IV
National Commission on Libraries and Information Science 45, XVII
National and Community Service, Commission on 45, XXV
National Credit Union Administration 12, VII
National Drug Control Policy, Office of 21, III
National Foundation on the Arts and the Humanities 45, XI
National Highway Traffic Safety Administration 23, II, III; 49, V
National Indian Gaming Commission 25, III
National Institute of Standards and Technology 15, II
National Labor Relations Board 29, I
National Marine Fisheries Service 50, II, IV
National Mediation Board 29, X
National Oceanic and Atmospheric Administration 15, IX; 50, II, III,
IV, VI
National Park Service 36, I
National Railroad Adjustment Board 29, III
National Railroad Passenger Corporation (AMTRAK) 49, VII
National Science Foundation 45, VI; 48, 25
National Security Council 32, XXI
National Security Council and Office of Science and Technology Policy
47, II
National Telecommunications and Information Administration 15, XXIII;
47, III
National Transportation Safety Board 49, VIII
Navy Department 32, VI; 48, 52
Neighborhood Reinvestment Corporation 24, XXV
Nuclear Regulatory Commission 10, I; 48, XX
Occupational Safety and Health Administration 29, XVII
Occupational Safety and Health Review Commission 29, XX
Office of Independent Counsel 28, VII
Office of National Drug Control Policy 21, III
Office of Navajo and Hopi Indian Relocation 25, IV
Offices of Independent Counsel, Department of Justice 28, VI
Operations Office, Department of Agriculture 7, XXVIII
Overseas Private Investment Corporation 22, VII
Packers and Stockyards Administration 9, II
Panama Canal Commission 48, 35
Panama Canal Regulations 35, I
Patent and Trademark Office 37, I
Payment of Expenses Connected With the Death of Certain Employees 41,
303
Peace Corps 22, III
Pennsylvania Avenue Development Corporation 36, IX
Pension and Welfare Benefits Administration, Department of Labor 29,
XXV
Pension Benefit Guaranty Corporation 29, XXVI
Personnel Management, Office of 5, I; 45, VIII; 48, 17
Federal Employees Health Benefits Acquisition Regulation 48, 16
Postal Rate Commission 39, III
Postal Service, United States 39, I
Postsecondary Education, Office of 34, VI
President's Commission on White House Fellowships 1, IV
Presidential Commission on the Assignment of Women in the Armed
Forces 32, XXIX
Presidential Documents 3
Prisons, Bureau of 28, V
Productivity, Technology and Innovation, Assistant Secretary
(Commerce) 37, IV
Property Management Regulations System, Federal 41, Subtitle C
Public Contracts, Department of Labor 41, 50
Public Health Service 42, I
Railroad Retirement Board 20, II
Reclamation Bureau 43, I
Reduction in Meeting and Training Allowance Payments 41, 304
Refugee Resettlement, Office of 45, IV
Regional Action Planning Commissions 13, V
Relocation Allowances 41, 302
Research and Special Programs Administration 49, I
Resolution Trust Corporation 12, XVI
Rural Electrification Administration 7, XVII
Rural Telephone Bank 7, XVI
Saint Lawrence Seaway Development Corporation 33, IV
Science and Technology Policy, Office of 32, XXIV
Science and Technology Policy, Office of, and National Security
Council 47, II
Secret Service 31, IV
Securities and Exchange Commission 17, II
Selective Service System 32, XVI
Small Business Administration 13, I; 48, 22
Smithsonian Institution 36, V
Social Security Administration 20, III; 45, IV
Soil Conservation Service 7, VI
Solar Energy and Energy Conservation Bank, Department of Housing and
Urban Development 24, XI
Soldiers' and Airmen's Home, United States 5, XI
Special Counsel, Office of 5, VIII
Special Education and Rehabilitative Services, Office of 34, III
State Department 22, I
Federal Acquisition Regulation 48, 6
Surface Mining and Reclamation Appeals, Board of 30, III
Susquehanna River Basin Commission 18, VIII
Technology Administration 15, XI
Tennessee Valley Authority 18, XIII
Thrift Depositor Protection Oversight Board 12, XV
Thrift Supervision Office, Department of the Treasury 12, V
Trade Representative, United States, Office of 15, XX
Transportation, Department of 44, IV
Coast Guard 33, I; 46, I, III; 49, IV
Commercial Space Transportation, Office of 14, III
Contract Appeals Board 48, 63
Federal Acquisition Regulation 48, 12
Federal Aviation Administration 14, I
Federal Highway Administration 23, I, II; 49, III
Federal Railroad Administration 49, II
Federal Transit Administration 49, VI
Maritime Administration 46, II
National Highway Traffic Safety Administration 23, II, III; 49, V
Research and Special Programs Administration 49, I
Saint Lawrence Seaway Development Corporation 33, IV
Secretary of Transportation, Office of 14, II; 49, Subtitle A
Transportation, Office of, Department of Agriculture 7, XXXIII
Travel Allowance 41, 301
Travel and Tourism Administration, United States 15, XII
Treasury Department 17, IV
Alcohol, Tobacco and Firearms, Bureau of 27, I
Comptroller of the Currency 12, I
Customs Service, United States 19, I
Engraving and Printing, Bureau of 31, VI
Federal Acquisition Regulation 48, 10
Federal Law Enforcement Training Center 31, VII
Fiscal Service 31, II
Foreign Assets Control, Office of 31, V
Internal Revenue Service 26, I
Monetary Offices 31, I
Secret Service 31, IV
Secretary of the Treasury, Office of 31, Subtitle A
Thrift Supervision Office 12, V
United States Customs Service 19, I
Truman, Harry S. Scholarship Foundation 45, XVIII
Under Secretary for Technology, Department of Commerce 37, V
United States and Canada, International Joint Commission 22, IV
United States Arms Control and Disarmament Agency 22, VI
United States Customs Service 19, I
United States Fish and Wildlife Service 50, I, IV
United States Information Agency 22, V; 48, 19
United States International Development Cooperation Agency 22, XII
United States International Trade Commission 19, II
United States Postal Service 39, I
United States Soldiers' and Airmen's Home 5, XI
United States Trade Representative, Office of 15, XX
United States Travel and Tourism Administration 15, XII
Veterans Affairs Department 38, I; 48, 8
Veterans' Employment and Training, Office of the Assistant Secretary
for 41, 61; 20, IX
Vice President of the United States, Office of 32, XXVIII
Vocational and Adult Education, Office of 34, IV
Wage and Hour Division 29, V
Water Resources Council 18, VI
Workers' Compensation Programs, Office of 20, I
World Agriculture Outlook Board 7, XXXVIII
18 CFR 275.206 18 CFR (4-1-93 Edition)
18 CFR 275.206 OMB Control Numbers
18 CFR 275.206
18 CFR 275.206
18 CFR 275.206 Table of OMB Control Numbers
The OMB control numbers for the Federal Energy Regulatory Commission,
Department of Energy, appear in 389.101 of Chapter I. For the
convenience of the user, 389.101 is reprinted below.
18 CFR 275.206 PART 389 -- OMB CONTROL NUMBERS FOR COMMISSION INFORMATION COLLECTION REQUIREMENTS
18 CFR 389.101 OMB control numbers assigned pursuant to the Paperwork
Reduction Act.
(a) Purpose. This part collects and displays control numbers
assigned to information collection requirements of the Commission by the
Office of Management and Budget (OMB) pursuant to the Paperwork
Reduction Act of 1980. This part fulfills the requirements of section
3507(f) of the Paperwork Reduction Act, which requires that agencies
display a current control number assigned by the Director of OMB for
each agency information collection requirement.
(b) Display.
(49 FR 12692, Mar. 30, 1984)
Editorial Note: For Federal Register citations affecting 389.101,
see the List of CFR Sections Affected in the Finding Aids section of 18
CFR parts 280-399.
18 CFR 389.101 18 CFR (4-1-93 Edition)
18 CFR 389.101 List of CFR Sections Affected
18 CFR 389.101 List of CFR Sections Affected
All changes in this volume of the Code of Federal Regulations which
were made by documents published in the Federal Register since January
1, 1986, are enumerated in the following list. Entries indicate the
nature of the changes effected. Page numbers refer to Federal Register
pages. The user should consult the entries for chapters and parts as
well as sections for revisions.
For the period before January 1, 1986, see the ''List of CFR Sections
Affected, 1949-1963, 1964-1972, and 1973-1985,'' published in seven
separate volumes.
18 CFR 389.101 1986
18 CFR
51 FR
Page
Chapter I
154 Deadline postponed 41080
154.94 (h)(1) and Appendix A amended 22218
Effective date deferred 27018
Petitions denied 27529
Petition granted 28331
154.111 Responses to court decision 23530
157 Authority citation revised 9186, 22218
Petitions denied 11566, 11569
157.22 Removed; eff. 6-2-86 9186
Removal effective date changed 11717
157.29 Removed; eff. 6-2-86 9186
Removal effective date changed 11717
157.40 (c)(1)(v)(A) amended 22218
Effective date deferred 27018
Petitions denied 27529
Petition granted 28331
157.45 -- 157.52 (Subpart C) Removed; eff. 6-2-86 9186
(Subpart C) Removal effective date changed 11717
157.102 (a)(1) revised 43607
157.205 (b) amended 43607
157.208 Cost limits 3771
157.215 Cost limits 3771
157.301 (Subpart G) Added 22218
Effective date deferred 27018
Petitions denied 27529
Petition granted 28331
159.1 Removed 43607
159.2 Heading revised; introductory text amended 43607
159.2a -- 159.4 Removed 43607
225 Authority citation revised 7932
225.3 Table amended; eff. 5-21-86 7933
Table amendment effective date confirmed 19327
250.15 Removed 44283
260.13 Added 44284
270 Authority citation revised 22218
270.201 Added 22219
(a)(3)(i) revised; interim 26243
Effective date deferred 27018
Petitions denied 27529
Petition granted 28331
(b)(1)(i) suspended to 12-18-86 40973
(a), (b)(1)(i) and (3), (c)(2), (d), (e)(1), and (f)(3) revised; (h)
amended 46818
271 Authority citation revised 4310
271.101 (a) Tables I and II amended 3582, 16158, 27405, 40974
271.102 (c) Table III amended 3583, 16158, 27406, 40974
271.401 -- 271.403 (Subpart D) Authority citation revised 22220
271.402 (c)(3) revised; (c)(5) amended; (c)(7) added 22220
Effective date deferred 27018
Petitions denied 27529
Petition granted 28331
271.601 -- 271.603 (Subpart F) Authority citation revised 22220
271.602 (a) revised 22220
Effective date deferred 27018
Petitions denied 27529
Petition granted 28331
271.703 (d)(162) revised 192
(d)(194) added 1365
(d)(193) added 1366
(d)(191) published at 50 FR 40192, (191) published at 50 FR 40361,
(192), (193), (204), and (211) redesignated as (d)(189), (192), (190),
(188), (191), and (187) 1367
(d)(195) added 4905
(d)(36)(v) added; (d)(36) introductory text republished 19165
(d)(111) revised; (d) heading republished 22068
(d)(196) added 26876
Rehearing granted 26876
(d)(197) added 28069
(d)(198) added 44054
271.804 (d)(3) amended; (e)(3) and (4) added; eff. 4-21-86 4310
271.805 (d)(1) amended; (e)(1)(i) revised; eff. 4-21-86 4310
277 Authority citation revised 7933
277.205 (b)(3) amended; eff. 5-21-86 7933
(b)(3) amendment effective date confirmed 19327
277.206 (d) revised; eff. 5-21-86 7933
(d) revision effective date confirmed 19327
277.209 (a) amended; eff. 5-21-86 7933
(a) amendment effective date confirmed 19327
277.210 Revised; eff. 5-21-86 7933
Revision effective date confirmed 19327
18 CFR 389.101 1987
18 CFR
52 FR
Page
Chapter I
154 Authority citation revised 21292,
21668
Rehearing denied 29659
154.28 Revised 43879
Effective date suspended 48407
154.38 (h)(3)(v) amended 15714
(d)(6) added 21292
Clarification 23650
Technical correction 24153
Petitions granted 28463
Order on remand 30146
(d)(6)(ii) revised; rehearing granted in part 36021
Rehearing granted 37928, 44859
(d)(4) revised; (h) removed 43880
Effective date suspended 48407
154.42 Order on remand 30146
Rehearing granted 37928
(e)(2) revised 43880
Effective date suspended 48407
154.52 (c) revised 43880
Effective date suspended 48407
154.63 (b) (3) and (4) and (f) amended 43880
Effective date suspended 48407
154.94 (k)(4) revised 21668
Rehearing granted 5533,
29008
154.111 Rehearing denied and clarification 31987
154.206 (b)(1)(i) revised 43880
Effective date suspended 48407
154.208 (b)(1) revised 43880
Effective date suspended 48407
154.209 (a)(2) amended 43880
Effective date suspended 48407
154.212 Amended 43880
Effective date suspended 48407
154.301 -- 154.310 Undesignated center heading added 43880
Effective date suspended 48407
154.301 Added 43880
Effective date suspended 48407
154.302 Added 43880
Effective date suspended 48407
154.303 Added 43881
Effective date suspended 48407
154.304 Added 43883
Effective date suspended 48407
154.305 Added 43883
Effective date suspended 48407
154.306 Added 43886
Effective date suspended 48407
154.308 Added 43886
Effective date suspended 48407
154.309 Added 43887
Effective date suspended 48407
154.310 Added 43887
Effective date suspended 48407
157 Rehearing denied 29659
Order on remand 30146
Rehearing granted 37928
Authority citation revised 47910
157.40 Rehearing granted 5533
157.102 (b)(1)(v) revised 47910
157.208 Cost limits 3223
(c)(11) revised 47910
157.215 Cost limits 3223
157.301 (Subpart G) Rehearing granted 5533
201 Authority citation revised; text amended 28467
Order on remand 30146
Rehearing granted 37928
270 Authority citation revised 29005,
43888
Rehearing denied 29659
270.101 (c)(1) revised 29005
(f) introductory text revised 43888
Effective date suspended 48407
270.102 Order on remand 30146
Rehearing granted 37928
270.201 Rehearing granted 5533
(a) (5) through (7) redesignated as (a) (6) through (8); new (a)(7)
revised; new (a)(5) and (b)(5) added 21677
270.203 Order on remand 30146
Rehearing granted 37928
271 Clarification 4137
Recommendation remanded 6545
Authority citation revised 21668,
23030, 29006
Rehearing denied 29659
271.101 (a) Tables I and II amended 3113,
15714, 28468, 41416
271.102 (c) Table III amended 3114,
15715, 28469, 41417
271.402 Rehearing granted 5533
271.602 Rehearing granted 5533
271.702 Order on remand 30146
Rehearing granted 37928
271.703 (d)(36)(v) removed 2404
(d)(111)(iii) added 10741
(b)(5) and (c) revised; (d) (199) and (200) added 29006
Order on remand 30146
Rehearing granted 37928
(d) (201), (202) and (203) added 46074
271.704 Order on remand 30146
Rehearing granted 37928
271.1104 (d)(1)(iv) revised; (h) added 21668
(h)(1) revised; (h)(2) added 23030
Rehearing granted 29008
272 Authority citation revised 26474
272.101 Revised 26474
272.103 (a)(3) redesignated as (a)(4); new (a)(3) added 26475
272.104 Revised 26475
273 Authority citation revised 26475,
29007, 43888
273.102 (a)(1) revised 29007
273.204 (a)(1)(v) added 26475
273.302 (f)(2)(i) introductory text revised 43889
Effective date suspended 48407
274 Authority citation revised 29007
274.104 (a)(5) revised 29007
274.501 (a)(1) (i) through (iv) revised; (a)(2) table amended 29007
18 CFR 389.101 1988
18 CFR
53 FR
Page
Chapter I
154 Authority citation revised 7502, 15026
Programs availability 30047
Record formats revised 35312, 44004
Software availability 45758
154.1 Revised 15026
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(b) and (c) amended 30031, 49653
Implementation conference 32891
154.14 Revised 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
154.15 Revised 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
154.16 Revised 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
154.26 Revised 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(b) amended 30031, 49653
Implementation conference 32891
154.28 Rehearing granted 867
Technical correction 2826
154.31 Revised 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(a) and (b) amended 30031, 49653
Implementation conference 32891
154.32 Revised 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(a) and (b) amended 30031, 49653
Implementation conference 32891
154.34 (a) revised 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(a) (1) and (2) amended 30031, 49653
Implementation conference 32891
154.38 Rehearing granted 867, 1748
Technical correction 2826
Petition dismissed and rehearing denied 3886
154.42 Rehearing granted 867
Technical correction 2826
Petition dismissed and rehearing denied 3886
154.52 Rehearing granted 867
Technical correction 2826
154.61 Revised 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Amended 30031, 49653
Implementation conference 32891
154.62 (a) and (b) redesignated as (b) and (c); new (a) added 15027
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(a) amended 30031, 49653
Implementation conference 32891
154.63 Rehearing granted 867
Technical correction 2826
(b)(1) introductory text, (c)(1), (d)(3), (e)(4), and (f)
introductory text, (i) revised; (b)(1)(iv) and (5) added 15028
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(b)(1)(iv) and (5), (c)(1) (i) and (ii), (d)(3) and (e)(4)(i) amended
30031
Implementation conference 32891
(b)(1)(iv), (5), (c)(1) (i) and (ii), (d)(3), and (e)(4)(i) amended
49653
154.67 (c)(1) and (2)(iii)(B) corrected 14788
154.206 Rehearing granted 867
Technical correction 2826
154.208 Rehearing granted 867
Technical correction 2826
154.209 Rehearing granted 867
Technical correction 2826
154.212 Rehearing granted 867
Technical correction 2826
154.301 -- 154.310 Rehearing granted 867
Technical correction 2826
154.301 Rehearing granted 867
Technical correction 2826
154.302 Rehearing granted 867
Technical correction 2826
154.303 Rehearing granted 867
Technical correction 2826
(e)(1)(ii) revised 15028
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(e)(1)(ii) amended 30031, 49653
Implementation conference 32891
154.304 Rehearing granted 867
Technical correction 2826
(c) revised; eff. 4-8-88 7502
(c) correctly revised 11991
154.305 Rehearing granted 867
Technical correction 2826
(c)(1)(ii), (h)(3)(i), and (i)(1) (i), (ii), and (iii), and (3)
revised; (c)(4) added; eff. 4-8-88 7502
(e) introductory text, (i)(3) (i) and (ii) correctly revised 11992
154.306 Rehearing granted 867
Technical correction 2826
(d) (1) and (2) revised; (d)(3) added; eff. 4-8-88 7503
(c) correctly revised 13254
154.308 Rehearing granted 867
Technical correction 2826
154.309 Rehearing granted 867
Technical correction 2826
154.310 Rehearing granted 867
Technical correction 2826
157 Petition dismissed and rehearing denied 3886
Rehearing granted 11845
Authority citation revised 4133, 15028, 15381
Programs availability 30047
Record formats revised 35312, 44004
Software availability 45758
157.6 Heading and (a) revised 15028
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(a)(1) amended 30031, 49653
Implementation conference 32891
157.7 (a), (b)(3) (i), (ii) and (iii), (5)(i), and (7)(i), (c)
introductory text, and (4) introductory text, (d) introductory text, (e)
introductory text, (2), and (3) introductory text, and (g)(3)
introductory text and (iv) introductory text amended 15028
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.13 (a) amended 15029
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.14 (a) introductory text revised 15029
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(a) amended 30031, 49653
Implementation conference 32891
157.16 Introductory text revised 15029
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.17 Revised 15029
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(a) and (b) amended 30031, 49653
Implementation conference 32891
157.18 Introductory text revised 15029
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.20 (c) introductory text and (d) introductory text revised 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(c) and (d) amended 30031
Implementation conference 32891
(c) introductory text and (d) introductory text amended 49653
157.21 Added; eff. 4-12-88 4133
(d) amended 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(a) revised 29009
Implementation conference 32891
157.30 (a) amended; (c) through (f) added; eff. 4-12-88 4133
(e) introductory text corrected 8176
(c) revised 29009
(a) and (e) introductory text corrected 37291
157.102 Rehearing granted 3584
(a)(1) revised 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.204 (a) revised 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.205 (b) revised 15030
(b) revised; (c) through (h) redesignated as (d) through (i); new
(c) added 15381
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(b)(1) amended 30031
Implementation conference 32891
(b) introductory text revised 49653
157.207 Amended 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.208 Rehearing granted 3584
(d) Table I revised 11644
(e) introductory text amended 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.211 (c) introductory text amended 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.214 (c) introductory text amended 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.215 (a) Table II revised 11644
(b)(1) introductory text and (2) introductory text amended 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
157.301 (a) revised; eff. 4-12-88 4133
(c) introductory text corrected 7504
(a) corrected 8176
161 Added 22161
Rehearing granted 29654
FERC Form No. 592 corrected 34277
Filing time extended 36273
161.3 (j) corrected 25240
201 Petition dismissed and rehearing denied 3886
250 Authority citation revised 22161
250.16 Added 22161
(c)(2) introductory text and (d)(1) corrected 25240
Rehearing granted 29654
FERC Form No. 592 corrected 34277
Filing time extended 36273
260 Authority citation revised 15030, 45901
Programs availability 30047
Record formats revised 35312
Software availability 45758
260.1 (b) revised 15030
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
FERC Form No. 2 amended 40875
Record formats revised 44004
260.2 (b)(1) revised 15031
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
FERC Form No. 2-A amended 40875
Record formats revised 44004
260.3 (b)(1) revised 15031
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(b)(1) (i) and (ii) amended 30031
Implementation conference 32891
260.4 (b) revised 15031
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
260.7 (b)(1) (i) and (ii) introductory text revised 15031
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
Implementation conference 32891
260.9 (a) amended; (b) and (c) revised 45901
260.11 (b) revised 15031
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(b) amended 30031
Implementation conference 32891
260.12 (b)(1) revised 15031
Rehearing granted and effective date suspended 16058
Eff. 8-1-88 19283
(b)(1) amended 30031
Implementation conference 32891
270 Rehearing granted 867
270.101 Rehearing granted 867
Technical correction 2826
270.102 Petition dismissed and rehearing denied 3886
270.203 Petition dismissed and rehearing denied 3886
271.101 (a) Tables I and II amended 3019, 16541,
32374, 44008
271.102 (c) Table III amended 3020,
16542, 32374, 44009
271.702 Petition dismissed and rehearing denied 3886
271.703 Petition dismissed and rehearing denied 3886
271.704 Petition dismissed and rehearing denied 3886
271.1104 (d)(1)(iv)(B)(2)(iii) and (h) (1) and (4) through (8)
revised 18
Technical correction 2826
Pipeline filings 21415
Pipeline filings corrected 30047
List of producers 43192
272.103 (e) revised 28194
273 Rehearing granted 867
273.302 Rehearing granted 867
Technical correction 2826
274 Authority citation revised 28194
274.205 (d) (3) and (4)(ii) revised 28194
18 CFR 389.101 1989
18 CFR
54 FR
Page
Chapter I
Policy statement 9031
154 Software availability 602, 8301
Print software availability; record formats revised 37303
Record formats revised 13670, 21200, 25107
Record formats revisions and corrections 8729
Implementation conference; record formats amended 809
154.1 (b) and (c) revised 21198
(a) amended 47760
154.31 (b) revised 21199
154.61 Revised 21199
154.305 (h)(4)(ii) revised; interim 25237
Regulation at 54 FR 25237 confirmed 41086
157 Software availability 602, 8301
Implementation conference; record formats amended 809
Record formats revisions and corrections 8729
Record formats revised 13670,
21200, 25107
Print software availability; record formats revised 37303
157.208 (d) Table I revised 6120
157.215 (a) Table II revised 6120
161.1 Revised 52791
161.2 Amended 52792
161.3 (c), (e), (f), and (i) revised; (k) and (l) added 52792
201 General Instruction 1 amended 5427
Amended 11902
250.16 (a), (b) introductory text, (1), (2), (6) (ix), (xiii),
(xviii) and (xix), (c), (d), (e)(2), (g) and (h)(1) revised; (b)(6)(xx)
added 52792
260 Software availability 602, 8301
Record formats revised 13670, 21200, 25107
Print software availability; record formats revised 37303
Implementation conference; record formats amended 809
Record formats revisions and corrections 8729
260.1 FERC Form No. 2 amended (OMB number) 8529
260.2 FERC Form No. 2-A amended (OMB number) 8529
270.101 (e) revised 32809
(e) correctly designated 47022
271.101 (a) Tables I and II amended 5075, 19162,
31939, 46048
271.102 (c) Table III amended 5076, 19162,
31939, 46048
271.805 (f) revised; (g) redesignated as (h); new (g) added 32810
271.1104 Pipeline filings 24167
277 Removed 8531
18 CFR 389.101 1990
18 CFR
55 FR
Page
Chapter I
154 Record formats revised 1174
157 Record formats revised 1174
157.208 (d) Table I revised 4995
157.215 (a) Table II revised 4995
250 Authority citation revised 53292
250.16 (a) through (d), (e)(2), (g), and (h)(1) revised 1808
(a)(3), (c)(1), (2) introductory text and (d)(1) revised 53292
260 Record formats revised 1174
270 Authority citation revised 22
Clarification 32026
270.101 (e)(2) redesignated as (e)(2)(i); (e)(2)(ii) added 22
270.202 (h)(2) revised 17431
Order 29567
270.207 Removed 17431
Order 29567
271 Authority citation revised 4602, 6377
Clarification 47743
271.101 (a) Tables I and II amended 4602,
31379, 46660
Tables I and II amended; footnote 4 revised 18865
271.102 (c) Table III amended 4603,
18865, 31380, 46661
271.703 (b)(2)(ii), (3)(i) and (ii) revised 6377
(a), (b)(2)(ii), (3)(i), and (ii) revised 18106
271.704 (c)(1)(i)(A)(1), (2), (B)(1), and (2) revised 6377
272 Clarification 3944
Authority citation revised 17431
272.103 (a)(5) through (8) added 17431
Order 29567
274 Authority citation revised 5984
274.208 (e) added 5984
(f) added 20452
18 CFR 389.101 1991
18 CFR
56 FR
Page
Chapter I
154 Authority citation revised 52382
Technical correction 56544
Technical conference 57255, 63648, 65990
154.401 -- 154.406 Undesignated center heading added 52382
Regulation at 56 FR 52382 effective date delayed 58845
154.401 Added 52382
Regulation at 56 FR 52382 effective date delayed 58845
154.402 Added 52382
Regulation at 56 FR 52382 effective date delayed 58845
154.403 Added 52382
Regulation at 56 FR 52382 effective date delayed 58845
154.404 Added 52382
Regulation at 56 FR 52382 effective date delayed 58845
154.405 Added 52382
Regulation at 56 FR 52382 effective date delayed 58845
154.406 Added 52385
Regulation at 56 FR 52385 effective date delayed 58845
157 Authority citation revised 50245
Technical correction 56544
Technical conference 57255, 63648, 65990
157.5 (b) and (c) redesignated as (c) and (d); new (b) added 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.6 (a)(1) and (4) amended 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.8 OMB number 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.9 OMB number 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.10 Heading revised; existing text designated as (a) and amended;
(b) added (OMB number) 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.11 OMB number 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.12 OMB number 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.14 (a) introductory text, (a)(6) introductory text and (iv)
amended; (a)(6-d) removed; (a)(6-a), (6-b) and (10) revised 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.100 -- 157.104 (Subpart E) Revised 52386
Regulation at 56 FR 52386 effective date delayed 58845
157.202 (b)(3), (4), (6), (10) and (11) removed; (b)(2), (5), (7),
(8), (9), (12), (13) and (14) redesignated as (b)(3) through (10); new
(b)(2) added 52395
Regulation at 56 FR 52395 effective date delayed 58845
157.203 (b) and (c) amended 52395
Regulation at 56 FR 52395 effective date delayed 58845
157.204 (a) and (d)(1) amended 52396
Regulation at 56 FR 52396 effective date delayed 58845
157.205 (a) introductory text amended 50245
(a) introductory text, (2), (b)(5), (6), (f)(1), (g), (h) and (i)(2)
amended; (b)(7) added; (e) revised 52396
Regulation at 56 FR 52396 effective date delayed 58845
157.206 (d) removed; (e) through (h) redesignated as (d) through (g)
52396
Regulation at 56 FR 52396 effective date delayed 58845
157.207 Introductory text, (a) and (c) through (h) redesignated as
(a) introductory text and (1) through (7); (b) removed; new (b) added
52396
Regulation at 56 FR 52396 effective date delayed 58845
157.208 (d) Table I revised 7565
(a) and (b) revised; (a)(6), (c)(11) and (e)(8) removed; (c)(7),
(8), (9) and (e)(9) redesignated as (c)(6), (7), (8) and (e)(8); new
(c)(9) added; (d) Table I amended 52396
Regulation at 56 FR 52396 effective date delayed 58845
157.211 Removed 52396
Regulation at 56 FR 52396 effective date delayed 58845
157.212 Revised 52396
Regulation at 56 FR 52396 effective date delayed 58845
157.215 (b)(1)(vi) removed 52397
Regulation at 56 FR 52397 effective date delayed 58845
(a) Table II revised 7565
157.216 (a)(2), (c)(3), (4), (d)(3) and (4) amended; (a)(3), (c)(5)
and (d)(5) added 52397
Regulation at 56 FR 52397 effective date delayed 58845
157.201 -- 157.218 (Subpart F) Appendixes I and II removed 52397
Removal at 56 FR 52397 effective date delayed 58845
271.101 (a) Tables I and II corrected 3208
(a) Tables I and II amended 4173
(a) Table I and Table II amended 20346, 37146
(a) Table I and Table II amended 56466
(a) Table I and Table III amended 4852
271.102 (c) Table III amended 4174
(c) Table III amended 20347, 37147
(c) Table III amended 56466
18 CFR 389.101 1992
18 CFR
57 FR
Page
Chapter I
152 Heading and authority citation revised 32894
152.1 Heading revised; existing text designated as (a); (b) added
32894
154 Authority citation revised 21893
Technical conference; questions 794
154.81 -- 154.86 Undesignated center heading removed 21893
154.81 Removed 21893
154.82 Removed 21893
154.83 Removed 21893
154.84 Removed 21893
154.85 Removed 21893
154.86 Removed 21893
155 Removed 21893
157 Authority citation revised 21893
Technical conference; questions 794
Rehearing denied 29631
157.7 (b) through (h) removed 21893
157.42 Removed 21894
157.208 (d) Table I revised 4717
157.215 (a) Table II revised 4717
159 Removed 21894
160 Removed 21894
161 Authority citation revised 58982
161.3 (f) revised 58982
250 Authority citation revised 11, 58982
Rehearing denied 5815
250.16 (a)(3), (c)(1), (c)(2) introductory text, (d)(1) and (e)(2)
revised 11
(a)(3), (c)(1), (2) introductory text and (d)(1) revised 58982
260 Authority citation revised 21894
260.100 Removed 21894
271 Authority citation revised 13018, 34682
Maximum lawful prices supplemental order 4853
Rehearing 31123
271.101 (a) Table I and Table II amended 19252, 34682, 49648
271.102 (c) Table amended 4853
(c) Table III amended 19253, 34683, 49648
271.703 (c)(2)(i)(B) revised 13018
18 CFR 389.101 1993
18 CFR
58 FR
Page
Chapter I
154 Authority citation revised 7986
154.26 (c) revised 7986
154.401 Regulation at 56 FR 52382 withdrawn 15418
154.402 Regulation at 56 FR 52382 withdrawn 15418
154.403 Regulation at 56 FR 52382 withdrawn 15418
154.404 Regulation at 56 FR 52382 withdrawn 15418
154.405 Regulation at 56 FR 52382 withdrawn 15418
154.406 Regulation at 56 FR 52382 withdrawn 15418
157.5 Regulation at 56 FR 52386 withdrawn 15418
157.6 Regulation at 56 FR 52386 withdrawn 15418
157.8 Regulation at 56 FR 52386 withdrawn 15418
157.9 Regulation at 56 FR 52386 withdrawn 15418
157.10 Regulation at 56 FR 52386 withdrawn 15418
157.11 Regulation at 56 FR 52386 withdrawn 15418
157.12 Regulation at 56 FR 52386 withdrawn 15418
157.14 Regulation at 56 FR 52386 withdrawn 15418
157.100 -- 157.104 (Subpart E) Regulation at 56 FR 52386 withdrawn
15418
157.201 -- 157.218 (Subpart F) Regulation at 56 FR 52397 withdrawn
15418
157.202 Regulation at 56 FR 52395 withdrawn 15418
157.203 Regulation at 56 FR 52395 withdrawn 15418
157.204 Regulation at 56 FR 52395 withdrawn 15418
157.205 Regulation at 56 FR 52396 withdrawn 15418
157.206 Regulation at 56 FR 52396 withdrawn 15418
157.207 Regulation at 56 FR 52396 withdrawn 15418
157.208 (d) table I revised 6893
Regulation at 56 FR 52396 withdrawn 15418
157.211 Removal at 56 FR 52396 withdrawn 15418
157.212 Regulation at 56 FR 52396 withdrawn 15418
157.215 (a) table II revised 6893
Regulation at 56 FR 52397 withdrawn 15418
157.216 Regulation at 56 FR 52397 withdrawn 15418
18
Conservation of Power and Water Resources
PARTS 150 TO 279
Revised as of April 1, 1993
CONTAINING
A CODIFICATION OF DOCUMENTS
OF GENERAL APPLICABILITY
AND FUTURE EFFECT
AS OF APRIL 1, 1993
With Ancillaries
Published by
the Office of the Federal Register
National Archives and Records
Administration
as a Special Edition of
the Federal Register
Washington, DC 20402-9328
18 CFR 389.101 Table of Contents
Page
Explanation v
Title 18:
Chapter I -- Federal Energy Regulatory Commission, Department of
Energy (Continued)
Finding Aids:
Table of CFR Titles and Chapters
Alphabetical List of Agencies Appearing in the CFR
Table of OMB Control Numbers
List of CFR Sections Affected
18 CFR 389.101 Explanation
The Code of Federal Regulations is a codification of the general and
permanent rules published in the Federal Register by the Executive
departments and agencies of the Federal Government. The Code is divided
into 50 titles which represent broad areas subject to Federal
regulation. Each title is divided into chapters which usually bear the
name of the issuing agency. Each chapter is further subdivided into
parts covering specific regulatory areas.
Each volume of the Code is revised at least once each calendar year
and issued on a quarterly basis approximately as follows:
Title 1 through Title 16 as of January 1
Title 17 through Title 27 as of April 1
Title 28 through Title 41 as of July 1
Title 42 through Title 50 as of October 1
The appropriate revision date is printed on the cover of each volume.
LEGAL STATUS
The contents of the Federal Register are required to be judicially
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie
evidence of the text of the original documents (44 U.S.C. 1510).
HOW TO USE THE CODE OF FEDERAL REGULATIONS
The Code of Federal Regulations is kept up to date by the individual
issues of the Federal Register. These two publications must be used
together to determine the latest version of any given rule.
To determine whether a Code volume has been amended since its
revision date (in this case, April 1, 1993), consult the ''List of CFR
Sections Affected (LSA),'' which is issued monthly, and the ''Cumulative
List of Parts Affected,'' which appears in the Reader Aids section of
the daily Federal Register. These two lists will identify the Federal
Register page number of the latest amendment of any given rule.
EFFECTIVE AND EXPIRATION DATES
Each volume of the Code contains amendments published in the Federal
Register since the last revision of that volume of the Code. Source
citations for the regulations are referred to by volume number and page
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states a date certain for expiration, an appropriate note will be
inserted following the text.
OMB CONTROL NUMBERS
The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires Federal
agencies to display an OMB control number with their information
collection request. Many agencies have begun publishing numerous OMB
control numbers as amendments to existing regulations in the CFR. These
OMB numbers are placed as close as possible to the applicable
recordkeeping or reporting requirements.
OBSOLETE PROVISIONS
Provisions that become obsolete before the revision date stated on
the cover of each volume are not carried. Code users may find the text
of provisions in effect on a given date in the past by using the
appropriate numerical list of sections affected. For the period before
January 1, 1986, consult either the List of CFR Sections Affected,
1949-1963, 1964-1972, or 1973-1985, published in seven separate volumes.
For the period beginning January 1, 1986, a ''List of CFR Sections
Affected'' is published at the end of each CFR volume.
CFR INDEXES AND TABULAR GUIDES
A subject index to the Code of Federal Regulations is contained in a
separate volume, revised annually as of January 1, entitled CFR Index
and Finding Aids. This volume contains the Parallel Table of Statutory
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in the Federal Register (Table II). A list of CFR titles, chapters, and
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also included in this volume.
An index to the text of ''Title 3 -- The President'' is carried
within that volume.
The Federal Register Index is issued monthly in cumulative form.
This index is based on a consolidation of the ''Contents'' entries in
the daily Federal Register.
A List of CFR Sections Affected (LSA) is published monthly, keyed to
the revision dates of the 50 CFR titles.
REPUBLICATION OF MATERIAL
There are no restrictions on the republication of material appearing
in the Code of Federal Regulations.
INQUIRIES AND SALES
For a summary, legal interpretation, or other explanation of any
regulation in this volume, contact the issuing agency. Inquiries
concerning editing procedures and reference assistance with respect to
the Code of Federal Regulations may be addressed to the Director, Office
of the Federal Register, National Archives and Records Administration,
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Orders, P.O. Box 371954, Pittsburgh, PA 15250-7954. Charge orders may
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Martha L. Girard,
Director,
Office of the Federal Register.
April 1, 1993.
18 CFR 389.101 THIS TITLE
Title 18 -- Conservation of Power and Water Resources is composed of
four volumes. The first three volumes, parts 1 to 149, parts 150 to
279, and parts 280 to 399 contain chapter I, the current regulations of
the Federal Energy Regulatory Commission, Department of Energy. The
fourth volume, containing part 400 to end, includes all current
regulations issued by the Delaware River Basin Commission, the Water
Resources Council, the Susquehanna River Basin Commission, and the
Tennessee Valley Authority as of April 1, 1993.
The OMB control numbers for the Federal Energy Regulatory Commission,
Department of Energy, appear in 389.101 of chapter I. For the
convenience of the user, 389.101 is reprinted in the Finding Aids
section of the first and second volumes.
For this volume, Steven H. Karsteter was Chief Editor. The Code of
Federal Regulation publication program is under the direction of Richard
L. Claypoole, assisted by Alomha S. Morris.
18 CFR 0.0 18 CFR Ch. I (4-1-93 Edition)
18 CFR 0.0 Federal Energy Regulatory Commission
18 CFR 0.0 Title 18 -- Conservation of Power and Water Resources
18 CFR 0.0 (This book contains parts 280 to 399)
Part
chapter i -- Federal Energy Regulatory Commission, Department of
Energy (Continued) 280
Cross References: Applications and entries conflicting with lands
reserved or classified as power sites, or covered by power applications:
See Public Lands, Interior, 43 CFR Subpart 2320.
Interstate Commerce Commission: See Transportation, 49 CFR Chapter
X.
Irrigation projects; electrification, Bureau of Indian Affairs,
Department of the Interior: See Indians, 25 CFR parts 172-177.
Regulations of the Bureau of Land Management relating to
rights-of-way for power, telephone, and telegraph purposes: See Public
Lands, Interior, 43 CFR Group 2800.
Rights-of-way over Indian lands: See Indians, 25 CFR parts 169, 170,
and 265.
Commodity Futures Trading Commission and Securities and Exchange
Commission: See Commodity and Securities Exchanges, 17 CFR Chapters I
and II.
Withdrawal of public lands: See Public Lands, Interior, 43 CFR Group
2300.
290 Collection of cost of service information under section 133 of
the Public Utility Regulatory Policies Act of 1978
292 Regulations under sections 201 and 210 of the Public Utility
Regulatory Policies Act of 1978 with regard to small power production
and cogeneration
294 Procedures for shortages of electric energy and capacity under
section 206 of the Public Utility Regulatory Policies Act of 1978
18 CFR 0.0
18 CFR 0.0 SUBCHAPTER L -- REGULATIONS FOR FEDERAL POWER MARKETING
ADMINISTRATIONS
300 Confirmation and approval of the rates of Federal power marketing
administrations
301 Average system cost methodology for sales from utilities to
Bonneville Power Administration under Northwest Power Act
18 CFR 0.0
18 CFR 0.0 SUBCHAPTER P -- REGULATIONS UNDER THE INTERSTATE COMMERCE
ACT
340 Rate schedules and tariffs
341 Oil pipeline tariffs: Pipeline companies subject to section 6 of
the Interstate Commerce Act and carriers jointly therewith
342 Long-and-short-haul and aggregate-of-intermediate rates --
pipelines
343 Posting tariffs of common carrier pipelines
344 Filing quotations for Government shipments at reduced rates
345 Section 5a applications
347 Competitive bids oil pipeline
18 CFR 0.0
18 CFR 0.0 SUBCHAPTER Q -- ACCOUNTS UNDER THE INTERSTATE COMMERCE ACT
351 Financial statements released by carriers
352 Uniform systems of accounts prescribed for oil pipeline companies
subject to the provisions of the Interstate Commerce Act
18 CFR 0.0
18 CFR 0.0 SUBCHAPTER R -- APPROVED FORMS, INTERSTATE COMMERCE ACT
356 Preservation of records
357 Annual special or periodic reports: Carriers subject to part I
of the Interstate Commerce Act
18 CFR 0.0
18 CFR 0.0 SUBCHAPTER S -- VALUATION, INTERSTATE COMMERCE ACT
360 Reporting of data for initial pipeline valuation
361 Regulations governing the reporting of property changes, pipeline
carriers
362 Uniform system of records and reports of property changes
18 CFR 0.0
18 CFR 0.0 SUBCHAPTER T -- REGULATIONS UNDER SECTION 32 OF THE PUBLIC
UTILITY HOLDING COMPANY ACT OF 1935
365 Filing reguirements and ministerial procedures for persons
seeking exempt wholesale generator status
18 CFR 0.0
18 CFR 0.0 SUBCHAPTER W -- REVISED GENERAL RULES
375 The Commission
376 Organization, mission, and functions; operations during
emergency conditions
380 Regulations implementing the National Environmental Policy Act
381 Fees
382 Annual charges
18 CFR 0.0
18 CFR 0.0 SUBCHAPTER X -- PROCEDURAL RULES
385 Rules of practice and procedure
388 Information and requests
389 OMB control numbers for Commission information collection
requirements
390-399 (Reserved)
Abbreviations: The following abbreviations are used in this
chapter:
M.c.f.=Thousand cubic feet. B.t.u.=British thermal units.
ICC=Interstate Commerce Commission.
18 CFR 0.0 18 CFR Ch. I (4-1-93 Edition)
18 CFR 0.0 Federal Energy Regulatory Commission
18 CFR 0.0 SUBCHAPTER I -- OTHER REGULATIONS UNDER THE NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES
18 CFR 0.0 PART 280 -- GENERAL PROVISIONS APPLICABLE TO SUBCHAPTER I
Authority: Natural Gas Policy Act of 1978, Pub. L. 95-621; 92
Stat. 3350, 15 U.S.C. 3301-3432; Outer Continental Shelf Lands Act
Amendment of 1978, Pub. L. 95-372, 43 U.S.C. 1862.
18 CFR 280.101 Definitions.
(a) NGPA definitions. Terms defined in the NGPA shall have the same
meaning for purposes of this subchapter as they have under the NGPA,
unless further defined in this subpart.
(b) Other definitions. For purposes of this subchapter:
(1) NGPA means the Natural Gas Policy Act of 1978.
(2) OCS means the Outer Continental Shelf as defined in section 2(35)
of the NGPA.
(44 FR 12409, Mar. 7, 1979, as amended by Order 92, 45 FR 49252, July
24, 1980)
18 CFR 280.101 PART 281 -- NATURAL GAS CURTAILMENT UNDER THE NATURAL GAS POLICY ACT OF 1978
18 CFR 280.101 Subpart A (Reserved)
18 CFR 280.101 Subpart B -- Permanent Curtailment Rule
281.201 Purpose.
281.202 Applicability.
281.203 Definitions and cross references.
281.204 Tariff filing requirements.
281.205 General rules.
281.206 Priority 1 reclassification.
281.207 Priority 2 classification.
281.208 Calculation of essential agricultural requirements and
attributable priority 2 entitlements.
281.209 Attribution.
281.210 Conflicting data.
281.211 Filing and documentation.
281.212 Draft tariff sheets and index of entitlements.
281.213 Data Verification Committee.
281.214 Notice, complaint and remedy.
281.215 Additional relief.
18 CFR 280.101 Subpart C -- Alternative Fuel Determination
281.301 Purpose.
281.302 Applicability.
281.303 Definitions.
281.304 Computation of alternative fuel volume.
281.305 General rule.
Appendix A
Authority: 15 U.S.C. 717-717w, 3301-3432; 16 U.S.C. 2601-2645; 42
U.S.C. 7101-7352.
Source: 44 FR 13470, Mar. 12, 1979, unless otherwise noted.
18 CFR 280.101 Subpart A (Reserved)
18 CFR 280.101 Subpart B -- Permanent Curtailment Rule
18 CFR 281.201 Purpose.
The purpose of this subpart is to implement section 401 of the NGPA
in order to provide that effective November 1, 1979, the curtailment
plans of interstate pipelines protect, to the maximum extent
practicable, deliveries of natural gas for essential agricultural uses
and for high-priority uses in accordance with the provisions of this
subpart.
(44 FR 26862, May 8, 1979)
18 CFR 281.202 Applicability.
This subpart applies to the following interstate pipe lines:
Alabama-Tennessee Pipeline Company.
Algonquin Gas Transmission Company.
Arkansas Louisiana Natural Gas Company.
Cities Service Gas Company.
Colorado Interstate Gas Company.
Columbia Gas Transmission Corporation.
Consolidated Gas Supply Corporation.
East Tennessee Natural Gas Company.
Eastern Shore Natural Gas Company.
El Paso Natural Gas Company.
Florida Gas Transmission Company.
Great Lakes Gas Transmission Company.
Inter-City Minnesota Pipelines, Ltd., Inc.
Kansas-Nebraska Natural Gas Company, Inc.
Lawrenceburg Gas Transmission Company.
Michigan-Wisconsin Pipeline Company.
Mid-Louisiana Gas Company.
Midwestern Gas Transmission Company.
Mississippi River Transmission Company.
Montana Dakota Utilities Company.
National Fuel Gas Supply Company.
North Penn Gas Company.
Northern Natural Gas Company.
Northwest Pipeline Corporation.
Panhandle Eastern Pipeline Company.
South Georgia Natural Gas Company.
Southern Natural Gas Company.
Southwest Gas Corporation.
Tennessee Gas Pipeline Company, a Division of Tenneco, Inc.
Tennessee Natural Gas Lines.
Texas Eastern Transmission Corporation.
Texas Gas Transmission Corporation.
The Inland Gas Company.
Transwestern Pipeline Company.
Trunkline Gas Company.
United Gas Pipe Line Company.
Western Gas Interstate Company.
(44 FR 26862, May 8, 1979, as amended at 44 FR 48184, Aug. 17, 1979)
18 CFR 281.203 Definitions and cross references.
(a) Definitions. For purposes of this subpart:
(1) Direct sale customer means an essential agricultural user of high
priority use which purchases natural gas directly from an interstate
pipeline and consumes such natural gas for a high-priority use or an
essential agricultural use.
(2) Essential agricultural use means any use of natural gas which is
certified by the Secretary of Agriculture as an ''essential agricultural
use'' under section 401(c) of the NGPA, as identified in 7 CFR part
2900, et seq.
(3) Essential agricultural user means a person who uses natural gas
for an essential agricultural use.
(4) High-priority use means any use of natural gas which qualifies
the user as a high-priority user.
(5) High-priority user means any person who uses natural gas:
(i) In a residence;
(ii) In a small commercial establishment;
(iii) In a school or a hospital; or
(iv) For police protection, for fire protection, in a sanitation
facility or a correctional facility.
(6) End-use curtailment plan means a provision in the tariff of an
interstate pipeline that requires that under circumstances of supply
shortage natural gas deliveries will be curtailed based at least in part
upon factors which consider the end-use of the natural gas.
(7) Indirect sale customer of an interstate pipeline means an
essential agricultural end-user served by a local distribution company
which is served directly by the interstate pipeline.
(8) Residence means a dwelling using natural gas predominantly for
residential purposes such as space heating, air conditioning, hot water
heating, cooking, clothes drying, and other residential uses and
includes apartment buildings and other multi-unit buildings.
(9) Small commercial establishment means any establishment (including
institutions and local, state and Federal Government agencies) engaged
primarily in the sale of goods or services where natural gas is used:
(i) In amounts of less than 50 Mcf on a peak day; and
(ii) For purposes other than those involving manufacturing or
electric power generation.
(10) Hospital means a facility, the primary function of which is
delivering medical care to patients who remain at the facility including
nursing and convalescent homes. Outpatient clinics or doctors' offices
are not included in this definition.
(11) School means a facility, the primary function of which is to
deliver instruction to regularly enrolled students in attendance at such
facility. Facilities used for both educational and noneducational
activities are not included under this definition unless the latter
activities are merely incidental to the delivery of instruction.
(12) Local distribution company means a local distribution company
served directly by an interstate pipeline.
(13) Rolling base period means a time period in which entitlements of
the customers of an interstate pipeline are established pursuant to the
pipeline's currently effective curtailment plan and which is
periodically updated to reflect recent gas requirements of such
customers.
(14) Entitlements of a direct sale customer or a local distribution
company customer with respect to a particular interstate pipeline means
the amount of natural gas that customer is permitted to receive under
the interstate pipeline's currently effective curtailment plan.
(15) Interstate pipeline purchaser means an interstate pipeline which
received deliveries of natural gas from another interstate pipeline.
(16) Alternative fuel means alternative fuel as it is defined in
Subpart C of this part.
(b) Cross references. (1) Essential agricultural requirements are
calculated in accordance with 281.208.
(2) Index of entitlements is that index of entitlements prepared in
accordance in 281.204(b).
(44 FR 26862, May 8, 1979, as amended by Order 29-C, 44 FR 61344,
Oct. 25, 1979; Order 55-B, 45 FR 54739, July 18, 1980)
18 CFR 281.204 Tariff filing requirements.
(a) General rule. Each interstate pipeline listed in 281.202 shall
file tariff sheets, including an index of entitlements, which provides
that if the interstate pipeline is in curtailment, natural gas will be
delivered in accordance with the provisions of this subpart. If the
interstate pipeline has curtailment provisions in its currently
effective tariff, the tariff sheets shall amend the existing curtailment
provisions. If the interstate pipeline has no curtailment plan in its
currently effective tariff, when it files tariff sheets to amend its
currently effective tariff to include a curtailment plan such
curtailment plan shall comply with the requirements of this subpart.
The tariff sheets shall be filed no later than October 1, 1979, with a
proposed effective date of November 1, 1979. The Data Verification
Committee report prepared in accordance with 281.213 shall be filed
with the tariff sheets.
(b) Index of entitlements. (1) The index of entitlements for an
interstate pipeline shall identify the natural gas entitlements in
priority of service categories 1 and 2 (established in accordance with
281.205(a)) for each direct sale customer, each local distribution
company customer and each interstate pipeline purchaser on a daily,
monthly, seasonal or other periodic basis used in the currently
effective curtailment plan.
(2) Periodic update. Each interstate pipeline shall update its index
of entitlements annualy to reflect changes in Priority 2 entitlements.
The new index of requirements shall be filed on September 15 of each
year with a proposed effective date of November 1, except that if the
interstate pipeline uses a rolling base period in its currently
effective curtailment plan it shall file its new index of entitlements
on the date upon which other end-uses of the customers of the interstate
pipeline are updated in accordance with the currently effective tariff.
(3) Alternative fuel determination. The index of entitlements shall
not include the volumes of natural gas for which volumes the essential
agricultural user has the ability to use an alternative fuel, as
determined under Subpart C of this part. Each interstate pipeline shall
amend its index of entitlements pursuant to paragraph (b)(2) of this
section to remove from the priority 2 entitlements and place in an
appropriate priority of service category any such volumes or natural gas
included in any index of entitlements that is effective on or after
October 31, 1979.
(c) Other tariff provisions. (1) Every tariff filed under this
subpart shall contain provisions that will require the interstate
pipeline:
(i) To provide for deliveries of sufficient volumes of natural gas to
respond to emergency situations (including environmental emergencies)
during periods of curtailment where additional supplies are required to
forestall irreparable injury to life or to property; and
(ii) To provide for deliveries of sufficient volumes of natural gas
to provide for minimum plant protection when the plant is shut down.
(2) Volumetric delivery requirements. Notwithstanding any other
provisions of this subpart, an interstate pipeline which is delivering
natural gas in accordance with this subpart shall not be required to
deliver to any customer volumes of natural gas on a daily, monthly,
seasonal or other periodic basis which exceed the volumes of natural gas
that the interstate pipeline may deliver to such customer without
causing the interstate pipeline to violate any daily, monthly, seasonal
or other periodic volumetric limitations established in the contract
between the interstate pipeline and such customer.
(Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Department of
Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267;
Administrative Procedure Act, 5 U.S.C. 551 et seq.)
(44 FR 26862, May 8, 1979, as amended at 44 FR 45923, Aug. 6, 1979;
44 FR 62490, Oct. 31, 1979; Order 55-B, 45 FR 54739, July 18, 1980;
Order 145, 46 FR 27913, May 22, 1981)
18 CFR 281.205 General rules.
(a) Priority of service categories -- (1) Priority 1. Each
interstate pipeline shall establish a new high-priority use category of
service designated priority one (1) which shall include all the
high-priority entitlements calculated in accordance with 281.206 and
those storage injection volumes calculated in accordance with paragraph
(c)(2) of this section.
(2) Priority 2. Each interstate pipeline shall establish a new
priority of service category designated priority two (2) which shall
include all the essential agricultural use requirements calculated in
accordance with 281.207 and those storage injection volumes calculated
in accordance with paragraph (c)(2) of this section.
(3) Other priority of service categories. Each interstate pipeline
may retain the priority of service categories in its currently effective
tariff, but such categories shall be placed at priorities below the new
priorities 1 and 2. Each interstate pipeline shall reduce the
entitlements in all other existing categories of service to the extent
such entitlements have been placed into the new priority of service
categories 1 or 2.
(b) Method of curtailment. All deliveries to all customers of the
interstate pipeline for all volumes of natural gas not included in
priorities 1 and 2 shall be fully curtailed by the interstate pipeline
before priorities 1 and 2 entitlements are curtailed. Deliveries for
priority 2 entitlements shall be fully curtailed by the interstate
pipelines (in accordance with the currently effective curtailment plan)
before priority 1 entitlements are curtailed by the interstate
pipelines. Nothing in this paragraph is intended to alter the operation
of any ''small customer'' or ''small distributor'' exemption or waiver
(as defined in an interstate pipeline's currently effective curtailment
plan).
(c) Storage -- (1) General rule. Interstate pipelines shall classify
customer storage injection volumes in the same manner as that used in
the currently effective curtailment plan.
(2) Storage sprinkling. Interstate pipelines which classify customer
storage injection volumes on the basis of the actual end-use of the
natural gas shall recalculate storage injection volumes placed in each
priority of service category based upon the index of entitlements to be
filed on September 15.
(3) Other treatment of storage. Except as provided in paragraph
(c)(2) of this section, no interstate pipeline shall recalculate or
reclassify any customer storage injection volumes, and no customer
storage injection volumes shall be included as priority 1 or 2
entitlements.
(44 FR 26862, May 8, 1979, as amended by Order 29-C, 44 FR 61344,
Oct. 25, 1979; Order 145, 46 FR 27913, May 22, 1981)
18 CFR 281.206 Priority 1 reclassification.
(a) Definitions. For purposes of this section ''high-priority
entitlements'' means, with respect to a particular interstate pipeline.
(1) In the case of a direct sale customer, the volume of natural gas
such direct sale customer is entitled to receive for high-priority uses
(as defined in 281.203) under the currently effective curtailment plan
of the interstate pipeline;
(2) In the case of a local distribution company, the volume of
natural gas which such local distribution company is entitled to receive
on account of the high-priority uses (as defined in 281.203) of its
high-priority user customers under the currently effective curtailment
plan of the interstate pipeline;
(3) In the case of an interstate pipeline purchaser the volume of
natural gas such interstate pipeline purchaser is entitled to receive
from an interstate pipeline supplier for the high-priority entitlements
of its direct sale customers, local distribution company customers and
interstate pipeline customers.
(b) Direct sale customer and local distribution company customers.
(1)(i) Subject to paragraph (b)(2) of this section, and 281.211 each
direct sale customer may request each of its direct interstate pipeline
suppliers to reclassify its high-priority entitlements in its currently
effective curtailment plan as priority 1 entitlements.
(ii) Subject to paragraph (b)(2) of this section, and 281.211 each
local distribution company must request each of its direct interstate
pipeline suppliers to reclassify its high priority entitlements in its
currently effective curtailment plan as priority 1 entitlements.
(2) The direct sale customer or local distribution company customer
shall designate the entitlements in each priority of service category in
the currently effective curtailment plan for which priority 1
reclassification is requested. It shall request that those entitlements
for which priority 1 reclassification is requested be excluded from the
category of service in which they are included in the currently
effective plan.
(3) Subject to 281.210, the interstate pipeline shall reclassify all
such high-priority entitlements as priority 1 entitlements and shall
reduce by an equal amount the entitlements in such other priority of
service categories as designated by the direct sale customer or local
distribution company customer, (in accordance with paragraph (b)(2) of
this section).
(c) Interstate pipeline. (1) Subject to paragraph (b)(2) of this
section, and 281.211 an interstate pipeline purchaser may request each
of its direct interstate pipeline suppliers to reclassify its
high-priority entitlements in its currently effective curtailment plan
(equal to the attributed priority 1 entitlements calculated in
accordance with 281.209) as priority 1 entitlements in the currently
effective curtailment plan of the interstate pipeline supplier.
(2) The interstate pipeline purchaser shall designate the
entitlements in each priority of service category in the currently
effective curtailment plan for which priority 1 reclassification is
requested. It shall request that those entitlements for which priority
1 classification is requested be excluded from the category of service
in which they are included in the currently effective plan.
(3) Subject to 281.210, the interstate pipeline supplier shall
reclassify all such high-priority entitlements as priority 1
entitlements and shall reduce the high-priority entitlements in other
priority of service categories as designated by the interstate pipeline
customer, (in accordance with paragraph (c)(2) of this section).
(44 FR 26862, May 8, 1979)
18 CFR 281.207 Priority 2 classification.
(a) Direct sale customer. (1) Subject to paragraph (a)(2) of this
section, and 281.211 a direct sale customer may request each of its
direct interstate pipeline suppliers to classify its essential
agricultural requirements (calculated in accordance with 281.208) as
priority 2 entitlements.
(2) The essential agricultural user shall designate the entitlements
in each priority of service category in the currently effective
curtailment plan which reflect the essential agricultural requirements.
It shall request that entitlements which are reflected in priority of
service categories in the currently effective curtailment plan are
removed from such priority of service categories.
(3) Subject to 281.210, the interstate pipeline shall classify all
such essential agricultural requirements as priority 2 entitlements and
reduce the entitlements in such other priority of service categories as
designated by the direct sale customer, (in accordance with paragraph
(b)(2) of this section).
(b) Indirect sale customer. Subject to 281.211 an indirect sale
customer which is an essential agricultural user may ask each of its
local distribution company direct suppliers to request each interstate
pipeline supplier to classify the indirect essential agricultural
requirements as priority 2 entitlements.
(c) Local distribution companies. (1) The local distribution company
shall attribute (in accordance with 281.209) the indirect essential
agricultural requirements for which reclassification is sought under
paragraph (b) of this section to its direct interstate pipeline
suppliers. Subject to paragraph (b)(2) of this section, and 281.211
the local distribution company shall request each of its direct
interstate pipeline suppliers to classify the attributed indirect
essential agricultural requirements as priority 2 entitlements.
(2) The local distribution company shall designate the entitlements
in each priority of service in the currently effective curtailment plan
which reflect the attributed indirect essential agricultural
requirements. It shall request that those entitlements which are
reflected in each category in the currently effective curtailment plan
are removed from such priority of service category.
(3) Subject to 281.210, the interstate pipeline shall classify all
such attributed indirect essential agricultural requirements as priority
2 entitlements and shall reduce the entitlements of the local
distribution company in such other priority of service categories as
designated by the local distribution company, (in accordance with
paragraph (b)(2) of this section).
(d) Interstate pipeline. (1) Subject to paragraph (d)(2) of this
section, and 281.211 an interstate pipeline purchaser may request each
of its direct interstate pipeline suppliers to classify the attributed
priority 2 entitlements (calculated under 281.209) as priority 2
entitlements in the currently effective curtailment plan of the
interstate pipeline supplier.
(2) The interstate pipeline purchaser shall designate the
entitlements in each priority of service category in the currently
effective curtailment plan of the interstate pipeline supplier which
reflects the attributed priority 2 entitlements and request that those
entitlements which are reflected in such priority of service categories
in the currently effective curtailment plan are removed from such
priority of service category.
(3) Subject to 281.210, the interstate pipeline supplier shall
classify the attributed priority 2 entitlements as priority 2
entitlements and shall reduce the entitlements of the interstate
pipeline purchaser in such other priority of service categories as
designated by the interstate pipeline purchaser, (in accordance with
paragraph (d)(2) of this section).
(44 FR 26862, May 8, 1979)
18 CFR 281.208 Calculation of essential agricultural requirements and
attributable priority 2 entitlements.
(a) Scope. This section sets forth the method by which:
(1) An essential agricultural user calculates total essential
agricultural requirements, direct essential agricultural requirements,
and indirect essential agricultural requirements;
(2) A local distribution company calculates attributable indirect
essential agricultural requirements for its essential agricultural user
customers; and
(3) An interstate pipeline purchaser calculates it attributable
priority 2 entitlements.
(b) Calculation by an essential agricultural user -- (1) Total
essential agricultural requirements -- (i) General Rule. (A) The
essential agricultural requirements of an essential agricultural user
are those volumes (expressed in daily, monthly, seasonal or other
appropriate periodic volumes) designated by the Secretary of Agriculture
and calculated in accordance with 7 CFR 2900.4; less
(B) Alternative fuel volumes (determined under 281.304).
(ii) Definitions. Current requirements as used in 7 CFR part 2900
means the lesser of
(A) The energy consumption from the most recent 12 month period for
which actual data is available, with necessary adjustments; or
(B) The maximum volume of natural gas for which the essential
agricultural user has installed capability to use for essential
agricultural uses.
(2) Attribution of total essential agricultural requirement and
indirect essential agricultural requirements. (i) The essential
agricultural user shall attribute its total essential agricultural
requirements among all its sources of supply of natural gas in
accordance with 281.209.
(ii) The direct essential agricultural requirement with respect to a
particular interstate pipeline supplier is that part of the total
essential agricultural requirements attributed under 281.209 to the
direct interstate pipeline supplier. The indirect essential
agricultural requirement with respect to a particular local distribution
company supplier is that part of the total essential agricultural
requirements attributed under 281.209 to a direct local distribution
company supplier.
(c) Calculation by local distribution companies. (1) A local
distribution company shall attribute under 281.209 the indirect
essential agricultural requirements of each of its essential
agricultural user customers (calculated under paragraph (b)(2) of this
section) among all the interstate pipelines which are direct suppliers
of the local distribution company.
(2) That part of the indirect essential agricultural requirements
which the local distribution company attributes to a particular
interstate pipeline supplier is the attributed indirect essential
agricultural requirements attributed to that interstate pipeline.
(d) Interstate pipelines. (1) An interstate pipeline purchaser may
attribute under 281.209 the priority 2 entitlements it includes in its
index of entitlements among its direct interstate pipeline suppliers.
(2) The attributable priority 2 entitlements attributed to a
particular interstate pipeline supplier is that part of the priority 2
entitlements of the interstate pipeline purchaser which it attributes to
a particular interstate pipeline supplier.
(44 FR 26862, May 8, 1979, as amended at 44 FR 62490, Oct. 31, 1979)
18 CFR 281.209 Attribution.
(a) Applicability. (1) This section sets forth the rules for
attributing total essential agricultural requirements by an essential
agricultural user, indirect essential agricultural requirements of an
essential agricultural user by its local distribution company supplier
and priority 1 and 2 entitlements by an interstate pipeline purchaser.
(2) This section does not apply to an essential agricultural user or
local distribution company which receives all its natural gas supplies
from a single source, or an interstate pipeline purchaser which does not
receive natural gas from any other interstate pipeline.
(b) Natural gas supplies included for purposes of attribution. (1)
For purposes of attribution in accordance with this section, natural gas
from all direct sources, including but not limited to pipeline
production, production by independent producers, production by
affiliates, SNG facilities and natural gas purchased from local
distribution companies, and interstate pipelines shall be included.
(2)(i) An essential agricultural user, which attributes under
paragraph (d) a portion of the volumes which are its total essential
agricultural requirements to a direct source of natural gas other than a
direct supplier may not seek classification to priority 2 under 281.207
for such portion of its total essential agricultural requirements.
(ii) A local distribution company which attributes under paragraph
(e) a portion of the volumes which are its indirect essential
agricultural requirements to a direct source of natural gas other than a
direct supplier may not seek classification to priority 2 under 281.207
for such portion of its indirect essential agricultural requirements.
(iii) An interstate pipeline purchaser which attributes under
paragraph (f) a portion of the volumes of its priority 1 or 2
entitlements to a direct source of natural gas other than a direct
supplier may not seek reclassification to priority 1 or classification
to priority 2, respectively, for such portion of its priority 1 and 2
entitlements.
(c) Definitions. For purposes of this section:
(1) Direct supplier means, with respect to an essential agricultural
user, an interstate pipeline or local distribution company which
directly supplies such essential agricultural user, with respect to a
local distribution company, an interstate pipeline which directly
supplies such local distribution company and, with respect to an
interstate pipeline purchaser, and interstate pipeline which directly
supplies the interstate pipeline purchaser.
(2) Base period of a direct supplier means the fixed historical
period in which entitlements of the customer of the direct supplier were
established for purposes of the currently effective curtailment plan of
such direct supplier.
(3) Annual quantity entitlements with respect to a particular direct
supplier means the total entitlements an essential agricultural user,
local distribution company or interstate pipeline is entitled to
purchase from that direct supplier in a calendar year under the
currently effective curtailment plan.
(d) Essential agricultural user. (1) An essential agricultural user
shall calculate its attributable essential agricultural requirements
attributable to a particular direct supplier by multiplying its total
essential agricultural requirements by the Annual Quantity Entitlements
from such direct supplier and dividing the product (numerator) by the
sum of all Annual Quantity Entitlements and all volumes received from
sources not providing an Annual Quantity Entitlement to such user
(denominator).
(2) If an essential agricultural user does not have annual quantity
entitlements only with respect to one of its direct suppliers, the
attributable essential agricultural requirements attributable to such
direct supplier shall be that part of the total essential agricultural
requirements not attributed under paragraph (d)(1) of this section.
(3) If an essential agricultural user does not have Annual Quantity
Entitlements with respect to more than one of its direct suppliers, the
attributable essential agricultural requirements attributable to a
particular direct supplier shall be calculated by multiplying its total
essential agricultural requirements by the total volume of natural gas
received from such supplier in 1972 and dividing the product (numerator)
by the total supplies of natural gas received from all sources in 1972
(denominator).
(e) Local distribution company. A local distribution company shall
calculate its attributable indirect essential agricultural requirements
among its direct suppliers in the same manner as it attributed its
supplies to its direct suppliers for purposes of establishing
entitlements in the currently effective curtailment plans of such direct
supplier.
(f) Interstate pipelines. An interstate pipeline shall attribute
Priority 1 and 2 entitlements respectively among its direct pipeline
suppliers in the same manner as it attributed its supplies to its direct
pipeline suppliers for purposes of establishing entitlements in the
currently effective curtailment plans of such direct suppliers.
(44 FR 26862, May 8, 1979, as amended by Order 29-C, 44 FR 61344,
Oct. 25, 1979)
18 CFR 281.210 Conflicting data.
(a) Interstate pipelines. Notwithstanding any other provision of
this subpart, if the records of an interstate pipeline contain
information which directly conflicts with a request for reclassification
of priority 1 entitlements under 281.206, or classification of priority
2 entitlements under 281.207, the interstate pipeline may not include
such volumes in priority 1 or 2 of its index of entitlements.
(b) Local distribution companies. Notwithstanding the provisions of
281.207(c), if the records of a local distribution company contain
information which directly conflicts with a request from an essential
agricultural user to have the local distribution company to seek
classification of volumes in priority 2, the local distribution company
may not seek classification for such volumes.
(44 FR 26862, May 8, 1979)
18 CFR 281.211 Filing and documentation.
(a) Priority 1 -- (1) Direct sales customers and local distribution
companies. (i) Each request of a direct sale customer and local
distribution company customer for reclassification of high-priority
entitlements (as defined in 281.206) to priority 1 entitlements shall
be made in writing no later than July 31, 1979, and shall be accompanied
by the data described in paragraph (a)(1)(ii) of this section.
(ii)(A) A table indicating high-priority entitlements (as defined in
281.206) and the end-use of the natural gas in each priority of service
category in the currently effective curtailment plan for which priority
1 reclassification is requested.
(B) A copy of the end-use data used to establish the high-priority
requirements and designated end-use of the natural gas.
(2) Interstate pipelines. (i) Each interstate pipeline purchaser
which reclassifies high-priority requirements of its customers as
priority 1 entitlements may request that its high-priority requirements
in the currently effective curtailment plan of its interstate pipeline
suppliers (equal to the attributable priority 1 entitlements) be
reclassified as priority 1 entitlements. Such requests shall be made in
writing no later than August 31, 1979 and shall be accompanied by the
data described in paragraph (a)(2)(ii) of this section.
(ii)(A) A table indicating high-priority entitlements (as defined in
281.206) and end-use of the natural gas in each priority of service
category in the currently effective curtailment plan of the interstate
pipeline supplier for which priority 1 reclassification is requested.
(B) A copy of the end-use data used to establish the high-priority
requirements and designated end-use of the natural gas.
(C) A table indicating the volumes and priority of service categories
for which each of direct sale customers and local distribution company
customers sought reclassification to priority 1.
(b) Priority 2 -- (1) Essential agricultural users. (i) Each request
for classification of essential agricultural requirements as priority 2
entitlements shall be made in writing to the local distribution company
supplier or the direct interstate pipeline supplier, as appropriate, no
later than June 15 of each year, and shall set forth all calculations
made in accordance with this subpart.
(ii) The request shall be accompanied by a statement that;
(A) Indicates the intended end-use(s) and volume(s) of the natural
gas for which priority 2 entitlements are requested.
(B) Indicates the SIC Code activities of the essential agricultural
user which qualifies it as an essential agricultural user in accordance
with 7 CFR 2900.3.
(C) Includes the data and calculations used to determine essential
agricultural requirements under 7 CFR 2900.4.
(D) Includes with respect to any essential agricultural user to which
Subpart C applies the data and calculations necessary to determine
alternative fuel volumes under 281.304.
(iii) The statement under paragraph (b)(1)(ii) shall be signed by a
responsible official of the essential agricultural user. Such official
shall swear or affirm that the statements are true to the best of his
information, knowledge and belief.
(2) Local distribution companies. Each request for classification of
essential agricultural requirements as priority 2 requirements shall be
made in writing to the direct interstate pipeline supplier no later than
June 30 of each year, and shall set forth all calculations made in
accordance with this subpart and all copies of all requests received
from its essential agricultural uses under paragraph (b)(1) of this
section.
(3) Interstate pipelines. Each request of an interstate pipeline
purchaser for classification of attributable priority 2 entitlements as
priority 2 entitlements shall be made in writing to the direct
interstate pipeline supplier no later than July 15 of each year, and
shall set forth all calculations made in accordance with this subpart
and shall include copies of all requests of essential agricultural users
and local distribution companies under paragraphs (b)(1) and (2) of this
section.
(4) Subsequent request. (i) For 1979, changes in priority 2
entitlements for essential agricultural use establishments that have the
ability to use an alternative fuel shall be filed under Subpart C of
this part.
(ii) For years subsequent to 1979, the data required by this
paragraph must be filed only to the extent that there has been a change
in essential agricultural requirements.
(Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432; Department of
Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267;
Administrative Procedure Act, 5 U.S.C. 551 et seq.)
(44 FR 26862, May 8, 1979, as amended at 44 FR 45923, Aug. 6, 1979;
44 FR 62490, Oct. 31, 1979; Order 55-B, 45 FR 54740, July 18, 1980;
Order 145, 46 FR 27913, May 22, 1981)
18 CFR 281.212 Draft tariff sheets and index of entitlements.
(a) Each interstate pipeline shall prepare draft tariff sheets and a
draft index of entitlements in accordance with this subpart.
(b) The draft tariff sheets and index of entitlements shall be served
on all customers of the interstate pipeline no later than August 1 of
each year.
(c) Copies of all documents received by the interstate pipeline under
281.210, the draft tariff sheets and the draft index of entitlements
shall be served on the Data Verification Committee no later than August
1 of each year.
(Natural Gas Policy Act of 1978, Pub. L. 95-621. Department of Energy
Organization Act, 42 U.S.C. 7107 et seq.: E.O. 12009, 42 FR 46267;
Administrative Procedure Act, 5 U.S.C. 551 et seq.)
(44 FR 26862, May 8, 1979, as amended at 44 FR 45923, Aug. 6, 1979;
Order 145, 46 FR 27913, May 22, 1981)
18 CFR 281.213 Data Verification Committee.
(a) Each interstate pipeline shall establish a Data Verification
Committee no later than August 1, 1979. It shall include, at a minimum,
a representative of the interstate pipeline, Commission staff, a large
and small local distribution company, and an essential agricultural
user. The appropriate state and local regulatory bodies, and a
representative of the United States Department of Agriculture may, at
their option, be members.
(b) The Data Verification Committee shall review all calculations
behind the draft tariff sheets and the proposed index of entitlements.
The Data Verification Committee may request, and the interstate pipeline
shall immediately supply, any information requested by the Data
Verification Committee.
(c) Any interested person may file a written protest concerning the
index of entitlements. Such protests shall be filed with the Data
Verification Committee no later than August 15 of each year.
(d) The Data Verification Committee shall review the draft tariff
sheets and index of entitlements and shall review the underlying data
for uniformity in preparation.
(e) The Data Verification Committee shall prepare a report concerning
the proposed index of requirements and the draft tariff sheets for the
interstate pipeline. It shall, at a minimum, specify all arithmetic
errors and contain an evaluation of all protests. It may contain a
proposed settlement of contested draft tariff sheets. The report shall
be submitted to the interstate pipeline no later than September 1 of
each year.
(Natural Gas Act. 15 U.S.C. 717-717w; Natural Gas Policy Act of
1978, 15 U.S.C. 3301-3432; Department of Energy Organization Act, 42
U.S.C. 7101-7352; E.O. 12009, 42 FR 46267; Administrative Procedure
Act, 5 U.S.C. 551 et seq.)
(44 FR 26862, May 8, 1979, as amended at 44 FR 45923, Aug. 6, 1979;
Order 29-C, 44 FR 61345, Oct. 25, 1979; Order 145, 46 FR 27913, May 22,
1981)
18 CFR 281.214 Notice, complaint and remedy.
(a) Complaint. Any interested person may file a complaint concerning
an alleged violation of this subpart under 385.206 of this chapter.
(b) Remedy. If the Commission determines that a violation of this
subpart has occurred, it shall take whatever action it deems appropriate
in the circumstances. Such action may include payback, in kind or in
dollars, by the person benefitting from the violation.
(44 FR 26862, May 8, 1979, as amended at 44 FR 61345, Oct. 25, 1979;
Order 225, 47 FR 19058, May 3, 1982)
18 CFR 281.215 Additional relief.
If an interstate pipeline rejects (under 281.210 or otherwise) a
request for reclassification under 281.206 or classification under
281.207 or if a local distribution company does not request (for any
reason including the provisions of 281.210) classification under
281.206 on behalf of its high priority uses or reclassification on
behalf of its essential agricultural users, the person aggrieved by such
action may file a request for relief from curtailment under 385.206 of
this chapter. The request shall contain the information required in
2.78(b) of the Commission Regulations.
(44 FR 26862, May 8, 1979, as amended by Order 225, 47 FR 19058, May
3, 1982)
18 CFR 281.215 Subpart C -- Alternative Fuel Determination
Authority: Natural Gas Policy Act of 1978, 15 U.S.C. 3301-3432;
Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O.
12009, 42 FR 46267.
Source: 44 FR 62490, Oct. 31, 1979, unless otherwise noted.
18 CFR 281.301 Purpose.
The purpose of this subpart is to determine the economic
practicability and reasonable availability of alternative fuels, as
prescribed in section 401(b) of the Natural Gas Policy Act of 1978 for
use by essential agricultural use establishments that seek priority 2
entitlements for natural gas.
18 CFR 281.302 Applicability.
This subpart applies to --
(a) Any essential agricultural use establishment for which an
essential agricultural user:
(1) Has requested that natural gas be classified as priority 2
entitlements by an interstate pipeline under 281.207; and
(2) Which has requested from any direct supplier priority 2
entitlements in excess of 300 Mcf per day; and
(b) Any essential agricultural use establishment with a new boiler,
other than a diesel engine or turbine designed to use distillate fuels
as the only alternative to natural gas, that:
(1) Has a capacity in excess of 300 Mcf of natural gas per day; and
(2) Is put into service for the first time after August 29, 1979.
18 CFR 281.303 Definitions.
For purposes of this subpart --
(a) Ability to use a particular alternative fuel means that an
essential agricultural use establishment had, on August 29, 1979, or
thereafter acquired the installed physical capability to use the
alternative fuel and has used that alternative fuel, in any amount, at
any time after 1973, for an essential agricultural use.
(b) Alternative fuel means coal or residual fuel oil.
(c) Boiler means any fuel burning device that is used for generating
steam or electricity or producing hot water for space heating or
manufacturing processes.
(d) Capacity means the volumes of natural gas used if the boiler is
operated at nameplate rated capacity for a continuous 16-hour period.
(e) Coal means lignite or any rank of bituminous coal or anthracite
coal.
(f) Direct supplier means, with respect to an essential agricultural
use establishment, an interstate pipeline or local distribution company
which directly supplies such essential agricultural use establishment;
with respect to a local distribution company, an interstate pipeline
which directly supplies such local distribution company; and, with
respect to an interstate pipeline purchaser, an interstate pipeline
which directly supplies the interstate pipeline purchaser.
(g) Distillate fuel means Nos. 1 and 2 heating oils, diesel fuel,
and No. 4 fuel oil, as defined in the standard specification for fuel
oils published by the American Society for Testing and Materials, ASTM,
D396 and D975.
(h) Essential agricultural requirements means volumes of natural gas
certified by the Secretary of Agriculture and calculated in accordance
with 7 CFR 2900.4 and 281.208(b) of this part.
(i) Essential agricultural use means any use of natural gas, as
defined in 281.203(a)(2) of this chapter and 7 CFR 2900.3.
(j) Essential agricultural user means an essential agricultural user
as defined in 281.203(b)(3).
(k) Essential agricultural use establishment is used as defined in 7
CFR 2900.2.
(l) Local distribution company means a local distribution company
served directly by an interstate pipeline.
(m) Priority 2 entitlements means the essential agricultural
requirements of an essential agricultural use establishment which
requirements are classified by an interstate pipeline as priority 2 in
its curtailment plan under Subpart B.
(n) Residual fuel oil means Nos. 5 and 6 oil, Bunker C, and Navy
Special as defined in the standard specification for fuel oils published
by the American Society for Testing and Materials, ASTM, D396.
(44 FR 62490, Oct. 31, 1979, as amended by Order 55-B, 45 FR 54740,
July 18, 1980)
18 CFR 281.304 Computation of alternative fuel volume.
(a) General rule. For purposes of 281.208(b)(1)(i)(B), and
281.305:
(1) Alternative fuel volume of an essential agricultural user is
equal to the sum of the alternative fuel volumes for each agricultural
use establishment for which such user has requested from any direct
supplier priority 2 entitlements in excess of 300 Mcf.
(2) Alternative fuel volume for an agricultural use establishment is
that portion of such establishment's natural gas requirements for which
such establishment has requested priority 2 curtailment and for which
the establishment had on August 29, 1979, or thereafter, the ability to
use alternative fuel.
(b) New boilers. For purposes of 281.208(b)(1)(i)(B) and 281.305:
any new boiler of an essential agricultural use establishment shall be
deemed to have alternative fuel volumes, if the boiler:
(1) Has a capacity in excess of 300 Mcf of natural gas per day;
(2) Is put into service for the first time after August 29, 1979;
and
(3) Is not a diesel engine or turbine designed to use distillate
fuels as the only substitute for natural gas.
(44 FR 62490, Oct. 31, 1979, as amended by Order 55-B, 45 FR 54740,
July 18, 1980)
18 CFR 281.305 General rule.
Any essential agricultural user subject to this subpart that has
requested from any direct supplier priority 2 classification for volumes
for any essential agricultural use establishment shall reduce its
essential agricultural requirements calculated under 281.208 to reflect
the exclusion of volumes of natural gas for which its essential
agricultural establishment has alternative fuel volumes under 281.304.
1976 -- January 1980
18 CFR 281.305 Pt. 284
18 CFR 281.305 PART 284 -- CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES
18 CFR 281.305 Subpart A -- General Provisions and Conditions
Sec.
284.1 Definitions.
284.2 Refunds and interest.
284.3 Jurisdiction under the Natural Gas Act.
284.4 Reporting.
284.5 Further terms and conditions.
284.6 Rate interpretations.
284.7 Rates.
284.8 Firm transportation service.
284.9 Interruptible transportation service.
284.10 Conversion to firm transportation.
284.11 Environmental compliance.
284.12 Filing of capacity.
284.13 Recordkeeping requirement.
284.14 Provisions governing pipeline restructuring.
18 CFR 281.305 Subpart B -- Certain Transportation by Interstate
Pipelines
284.101 Applicability.
284.102 Transportation by interstate pipelines.
284.103 -- 284.104 (Reserved)
284.105 Effectiveness of existing transportation arrangements.
284.106 Reporting requirements.
18 CFR 281.305 Subpart C -- Certain Transportation by Intrastate
Pipelines
284.121 Applicability.
284.122 Transportation by intrastate pipelines.
284.123 Rates and charges.
284.124 Terms and conditions.
284.125 Effectiveness of existing transportation services.
284.126 Reporting requirements.
18 CFR 281.305 Subpart D -- Certain Sales by Intrastate Pipelines
284.141 Applicability.
284.142 Sales by intrastate pipelines.
284.143 Definitions.
284.144 Rates and charges.
284.145 Terms and conditions.
284.146 Extensions.
284.147 Terminations.
284.148 Reporting requirements.
18 CFR 281.305 Subpart E -- Assignment of Contractual Rights to Receive
Surplus Natural Gas
284.161 Applicability.
284.162 General rule.
284.163 Special rule.
284.164 Terms and conditions.
284.165 Filing requirements.
18 CFR 281.305 Subpart F -- (Reserved)
18 CFR 281.305 Subpart G -- Blanket Certificates Authorizing Certain
Transportation by Interstate Pipelines on Behalf of Others and Services
by Local Distribution Companies
284.221 General rule; transportation by interstate pipelines on
behalf of others.
284.222 Transportation by interstate pipelines on behalf of other
interstate pipelines
284.223 Transportation by interstate pipelines on behalf of shippers
other than interstate pipelines.
284.224 Certain transportation, sales, and assignments by local
distribution companies.
284.225 Transportation by interstate and intrastate pipelines of gas
released under the good faith negotiation procedures.
284.226 Transportation by interstate and intrastate pipelines
upstream of pipelines releasing gas under the good faith negotiation
procedures.
284.227 Certain transportation by intrastate pipelines.
18 CFR 281.305 Subpart H -- Assignment of Capacity on Interstate
Pipelines
284.241 Applicability.
284.242 Assignment of firm capacity on upstream pipelines.
284.243 Release of firm capacity on interstate pipelines.
18 CFR 281.305 Subpart I -- Emergency Natural Gas Sale, Transportation,
and Exchange Transactions
284.261 Purpose.
284.262 Definitions.
284.263 Exemption from section 7 of Natural Gas Act and certain
regulatory conditions.
284.264 Terms and conditions.
284.265 Cost recovery by interstate pipeline.
284.266 Rates and charges for Interstate Pipelines.
284.267 Intrastate pipeline emergency transportation rates.
284.268 Local distribution company emergency transportation rates.
284.269 Intrastate pipeline and local distribution company emergency
sales rates.
284.270 Reporting requirements.
284.271 Waiver.
18 CFR 281.305 Subpart J -- Blanket Certificates Authorizing Certain
Natural Gas Sales by Interstate Pipelines
284.281 Applicability.
284.282 Definitions.
284.283 Point of unbundling.
284.284 Blanket certificates for unbundled sales services.
284.285 Pregrant of abandonment of unbundled sales services.
284.286 Standards of conduct for unbundled sales service.
284.287 Implementation and effective date.
284.288 Reporting requirements.
18 CFR 281.305 Subpart K -- Transportation of Natural Gas on the Outer
Continental Shelf by Interstate Natural Gas Pipelines on Behalf of
Others
284.301 Applicability.
284.302 Definitions.
284.303 OCS blanket certificates.
284.304 Allocation of firm and interruptible capacity on the OCS.
284.305 Transportation rates.
18 CFR 281.305 Subpart L -- Certain Sales for Resale by Non-interstate
Pipelines
284.401 Definitions.
284.402 Blanket marketing certificates.
Authority: 15 U.S.C. 717-717w, 3301-3432; 42 U.S.C. 7101-7352; 43
U.S.C. 1331-1356.
Source: 44 FR 52184, Sept. 7, 1979, unless otherwise noted.
18 CFR 281.305 Subpart A -- General Provisions and Conditions
18 CFR 284.1 Definitions.
(a) Transportation includes storage, exchange, backhaul,
displacement, or other methods of transportation.
(b) Appropriate state regulatory agency means a state agency which
regulates intrastate pipelines and local distribution companies within
such state. When used in reference to rates and charges, the term
includes only those agencies which set rates and charges on a
cost-of-service basis.
(c) Market center means an area where gas purchases and sales occur
at the intersection of different pipelines.
(44 FR 52184, Sept. 7, 1989, as amended by Order 636, 57 FR 13315,
Apr. 16, 1992)
18 CFR 284.2 Refunds and interest.
(a) Refunds. Any rate or charge collected for any sale,
transportation, or assignment conducted pursuant to this part which
exceeds the rates or charges authorized by this part shall be refunded.
(b) Interest. All refunds made pursuant to this section shall include
interest at an amount determined in accordance with 154.102(c).
(44 FR 52184, Sept. 7, 1979, as amended at 44 FR 53505, Sept. 14,
1979; Order 273, 48 FR 1288; Jan. 12, 1983)
18 CFR 284.3 Jurisdiction under the Natural Gas Act.
(a) For purposes of section 1(b) of the Natural Gas Act, the
provisions of such Act and the jurisdiction of the Commission under such
Act shall not apply to any transportation, sale or assignment in
interstate commerce of natural gas if such a transaction is authorized
pursuant to section 311 or 312 of the NGPA.
(b) For purposes of the Natural Gas Act, the term ''natural gas
company'' (as defined by section 2(6) of such Act) shall not include any
person by reason of, or with respect to, any transaction involving
natural gas if the provisions of the Natural Gas Act do not apply to
such transaction by reason of paragraph (a) of this section.
(c) The Natural Gas Act shall not apply to facilities utilized solely
for transportation authorized by section 311(a) of the NGPA.
(44 FR 52184, Sept. 7, 1979)
18 CFR 284.4 Reporting.
All reports filed pursuant to this part shall indicate quantities of
natural gas in MMBtu's, as defined in 270.102(b) (2) and (3) of this
chapter.
(44 FR 52184, Sept. 7, 1979, as amended at 44 FR 68821, Nov. 30,
1979; Order 436, 50 FR 42493, Oct. 18, 1985)
18 CFR 284.5 Further terms and conditions.
The Commission may prospectively, by rule or order, impose such
further terms and conditions as it deems appropriate on transactions
authorized by this part.
18 CFR 284.6 Rate interpretations.
(a) Procedure. A pipeline may obtain an interpretation pursuant to
subpart L of part 385 of this chapter concerning whether particular
rates and charges comply with the requirements of this part.
(b) Address. Requests for interpretations should be addressed to:
FERC part 284 Interpretations, Office of General Counsel, Suite 8000,
825 North Capitol Street, Washington, DC 20426.
(44 FR 66791, Nov. 21, 1979; 44 FR 75383, Dec. 20, 1979, as amended
by Order 225, 47 FR 19058, May 3, 1982)
18 CFR 284.7 Rates.
(a) Applicability. Any rate charged for transportation service under
subparts B and G of this part must be established under a rate schedule
that is filed with the Commission prior to commencement of such service
and that conforms to the requirements of this section.
(b) Interim rates for part 284 transactions. (1) Any person
providing transportation service under subpart B or G of this part may
charge an interim rate for that service until an appropriate rate is
established in accordance with this section, if the interim rate is a
one part rate filed and included in an appropriate rate schedule on file
with the Commission and effective prior to November 1, 1985, for
transportation authorized under this part or 157.209, as effective
prior to November 1, 1985, and provided such person complies with
paragraph (b)(2) of this section.
(2) Any person offering a transportation service subject to this
section must file rates in accordance with paragraph (a) of this section
to be effective not later than July 1, 1986. Any interim rate under
this paragraph may be charged only until new transportation rates under
this section are effective.
(c) Rate objectives. Maximum rates for both peak and offpeak periods
must be designed to achieve the following three objectives:
(1) Rates for service during peak periods should ration capacity;
(2) Rates for firm service during off-peak periods and for
interruptible service during all periods should maximize throughput;
and
(3) The pipeline's revenue requirement allocated to firm and
interruptible services should be attained by providing the projected
units of service in peak and off-peak periods at the maximum rate for
each service.
(d) Rate design -- (1) Volumetric rates. Except as provided in
284.8(d), any rate filed for service subject to this section must be a
one-part rate that recovers the costs allocated to the service to the
extent that the projected units of that service are actually purchased
and may not include a demand charge, a minimum bill or minimum take
provision or any other provision that has the effect of guaranteeing
revenue. Such rate must separately identify cost components
attributable to transportation, storage, and gathering costs.
(2) Based on projected units of service. Any rate filed for service
subject to this section must be designed to recover costs on the basis
of projected units of service. The fixed costs allocated to capacity
reservations, as determined in accordance with 284.8(d), should be used
along with the projected nominations accepted by the pipeline to compute
the unit reservation fee. The remaining fixed costs and all variable
costs should be used to determine the volumetric rate computed on the
basis of projected volumes to be transported. The units projected for
the service in rates filed under this section may be changed only in a
subsequent rate filing under section 4 of the Natural Gas Act.
(3) Differentiation due to time and distance. Any rate filed for
service subject to this section must reasonably reflect any material
variation in the cost of providing the service due to:
(i) Whether the service is provided during a peak or an off-peak
period; and
(ii) The distance over which the transportation is provided.
(4) Cost basis for rates.
(i) Any maximum rate filed under this section must be designed to
recover on a unit basis, solely those costs which are properly allocated
to the service to which the rate applies.
(ii) Any minimum rate filed under this section must be based on the
average variable costs which are properly allocated to the service to
which the rate applies.
(5) Rate flexibility.
(i) Any rate schedule filed under this section must state a maximum
rate and a minimum rate.
(ii)(A) Except as provided in paragraph (d)(5)(ii)(B) of this section
the pipeline may charge an individual customer any rate that is neither
greater than the maximum rate nor less than the minimum rate on file for
that service.
(B) If a pipeline does not hold a blanket certificate under Subpart G
of this part, it may not charge, in a transaction involving its
marketing affiliate, a rate that is lower than the highest rate it
charges in any transaction not involving its marketing affiliate.
(iii) The pipeline may not file a revised or new rate designed to
recover costs not recovered under rates previously in effect.
(iv) If, during any billing period, a pipeline charges a rate or
collects a reservation fee that is less than the maximum rate or fee,
the pipeline must, within 15 days of the close of the billing period,
file a report with the Commission identifying:
(A) The maximum rate or fee and the rate or fee actually charged
during the billing period;
(B) The shipper; and
(C) Any corporate affiliation between the shipper and the
transporting pipeline.
(Order 436, 50 FR 42493, Oct. 18, 1985, as amended at 50 FR 52274,
Dec. 23, 1985; 53 FR 22163, June 14, 1988; Order 522, 55 FR 12169,
Apr. 2, 1990)
18 CFR 284.8 Firm transportation service.
(a) Firm transportation availability. (1) An interstate pipeline
that provides transportation service under subpart B or G or this part
must offer such transportation service on a firm basis and separately
from any sales service.
(2) An intrastate pipeline that provides transportation service under
Subpart C may offer such transportation service on a firm basis.
(3) Service on a firm basis means that the service is not subject to
a prior claim by another customer or another class of service and
receives the same priority as any other class of firm service.
(4) An interstate pipeline that provided a firm sales service on May
18, 1992, and that offers transportation service on a firm basis under
subpart B or G of this part, must offer a firm transportation service
under which firm shippers may receive delivery up to their firm
entitlements on a daily basis without penalty.
(b) Non-discriminatory access. (1) An interstate pipeline or
intrastate pipeline that offers transportation service on a firm basis
under subpart B, C or G must provide such service without undue
discrimination, or preference, including undue discrimination or
preference in the quality of service provided, the duration of service,
the categories, prices, or volumes of natural gas to be transported,
customer classification, or undue discrimination or preference of any
kind.
(2) An interstate pipeline that offers transportation service on a
firm basis under subpart B or G of this part must provide each service
on a basis that is equal in quality for all gas supplies transported
under that service, whether purchased from the pipeline or another
seller.
(3) An interstate pipeline that offers transportation service on a
firm basis under subpart B or G of this part must provide all shippers
with equal and timely access to information relevant to the availability
of such service, including, but not limited to, the availability of
capacity at receipt points, on the mainline, at delivery points, and in
storage fields, and whether the capacity is available directly from the
pipeline or through capacity release.
(4) The requirement of paragraph (b)(3) of this section must be
implemented through the use of an Electronic Bulletin Board on which the
pipeline must provide for:
(i) Downloading by users,
(ii) Daily back-up of information displayed on the board, which must
be available for user review for at least three years,
(iii) Purging information on completed transactions from current
files,
(iv) Display of most recent entries ahead of information posted
earlier, and
(v) On-line help, a search function that permits users to locate all
information concerning a specific transaction, and a menu that permits
users to separately access notices of available capacity, each record in
the transportation log, and standards of conduct information.
(5) An interstate pipeline that offers transportation service on a
firm basis under subpart B or G of this part may not include in its
tariff any provision that inhibits the development of market centers.
(c) Reasonable operational conditions. Consistent with paragraph (b)
of this section, a pipeline may impose reasonable operational conditions
on any service provided under this part. Such conditions must be filed
by the pipeline as part of its transportation tariff.
(d) Reservation fee. Where the customer purchases firm service, a
pipeline may impose a reservation fee or charge on a shipper as a
condition for providing such service. Except for pipelines subject to
subpart C of this part, if a reservation fee is charged, it must recover
all fixed costs attributable to the firm transportation service, unless
the Commission permits the pipeline to recover some of the fixed costs
in the volumetric portion of a two-part rate. A reservation fee may not
recover any variable costs or fixed costs not attributable to the firm
transportation service. Except as provided in this paragraph, the
pipeline may not include in a rate for any transportation provided under
subpart B, C or G of this part any minimum bill or minimum take
provision, or any other provision that has the effect of guaranteeing
revenue.
(e) Limitation. A person providing service under Subpart B, C or G
of this part is not required to provide any requested transportation
service for which capacity is not available or that would require the
construction or acquisition of any new facilities.
(Order 436, 50 FR 42493, Oct. 18, 1985, as amended by Order 500, 52
FR 30353, Aug. 14, 1987; 52 FR 35539, Sept. 22, 1987; 52 FR 39632,
Oct. 23, 1987; 52 FR 48992, Dec. 29, 1987; Order 500-D, 53 FR 8440,
Mar. 15, 1988; Order 500-H, 54 FR 52394, Dec. 21, 1989; Order 500-I,
55 FR 6631, Feb. 26, 1990; Order 522, 55 FR 12169, Apr. 2, 1990; Order
500-k, 56 FR 14851, Apr. 12, 1991; Order 636, 57 FR 13315, Apr. 16,
1992)
18 CFR 284.9 Interruptible transportation service.
(a) Interruptible transportation availability. (1) An interstate
pipeline that provides firm transportation service under subpart B or G
of this part must also offer transportation service on an interruptible
basis under that subpart or subparts and separately from any sales
service.
(2) An intrastate pipeline that provides transportation service under
Subpart C may offer such transportation service on an interruptible
basis.
(3) Service on an interruptible basis means that the capacity used to
provide the service is subject to a prior claim by another customer or
another class of service and receives a lower priority than such other
classes of service.
(b) Non-discriminatory access. (1) An interstate or intrastate
pipeline that offers interruptible service under subpart B, C or G must
provide such service without undue discrimination, or preference,
including undue discrimination or preference in the quality of service
provided, the duration of service, the categories, prices, or volumes of
natural gas to be transported, customer classification, or undue
discrimination or preference of any kind.
(2) An interstate pipeline that offers transportation service on an
interruptible basis under subpart B or G of this part must provide each
service on a basis that is equal in quality for all gas supplies
transported under that service, whether purchased from the pipeline or
another seller.
(3) An interstate pipeline that offers transportation service on an
interruptible basis under subpart B or G of this part must provide all
shippers with equal and timely access to information relevant to the
availability of such service.
(4) The requirement of paragraph (b)(3) of this section must be
implemented through the use of an Electronic Bulletin Board with the
features required under 284.8(b)(4).
(5) An interstate pipeline that offers transportation service on an
interruptible basis under subpart B or G of this part may not include in
its tariff any provision that inhibits the development of market
centers.
(c) Reasonable operational conditions. Consistent with paragraph (b)
of this section, a pipeline may impose reasonable operational conditions
on any service provided under this part. Such conditions must be filed
by the pipeline as part of its transportation tariff.
(d) Reservation fee. No reservation fee may be imposed for
interruptible service. A pipeline's rate for any transportation service
provided under this section may not include any minimum bill provision,
minimum take provision, or any other provision that has the effect of
guaranteeing revenue.
(e) Limitation. A person providing service under subparts B, C or G
of this part is not required to provide any requested transportation
service for which capacity is not available or that would require the
construction or acquisition of any new facilities.
(Order 436, 50 FR 42494, Oct. 18, 1985, as amended by Order 500, 52
FR 30353, Aug. 14, 1987; 52 FR 35539, Sept. 22, 1987; 52 FR 39632,
Oct. 23, 1987; 52 FR 48993, Dec. 29, 1987; Order 500-D, 53 FR 8440,
Mar. 15, 1988; Order 500-H, 54 FR 52394, Dec. 21, 1989; Order 500-I,
55 FR 6631, Feb. 26, 1990; Order 522, 55 FR 12169, Apr. 2, 1990; Order
500-k, 56 FR 14851, Apr. 12, 1991; Order 636, 57 FR 13315, Apr. 16,
1992)
18 CFR 284.10 Conversion to firm transportation.
(a) General rule. An interstate pipeline must offer its firm sales
customers the option set out in paragraph (c) of this section, if it:
(1) Commences or continues a new transportation arrangement under
authority of 284.102 or 284.243 of this chapter after June 30, 1986;
or
(2) Accepts a certificate issued under 284.221 of this chapter.
(b) Definition. For purposes of this section, eligible firm sales
service agreement means an agreement, between an interstate pipeline
subject to this section and a customer, that was entered into before the
date the pipeline accepted a certificate issued under 284.221 of this
chapter or began transporting natural gas under authority of 284.102 or
284.243 of this chapter, as those sections were revised effective
November 1, 1985.
(c) Procedures -- (1) Customer option. An interstate pipeline
subject to this section agrees to offer, and is deemed to offer, every
firm sales customer the option, under this paragraph, to convert a
portion of its firm sales entitlements under any eligible firm sales
service agreement to a volumetrically equal amount of firm
transportation service.
(2) Notice. Unless the pipeline agrees otherwise, a customer that
wishes to exercise its option under this paragraph must provide the
pipeline written notice not later than 60 days before the proposed
conversion.
(3) Level of conversion. (i) A customer of a pipeline subject to
this section may convert to firm transportation its existing firm sales
entitlements under any eligible firm sales service agreement with that
pipeline, in accordance with the following schedule:
(A) During the first twelve-month period after the pipeline first
becomes subject to this section, up to 15 percent of the level of its
firm sales entitlements in existence on the date the pipeline first
becomes subject to this section, under any eligible firm sales service
agreement with that pipeline;
(B) During the second twelve-month period after the pipeline first
becomes subject to this section, up to 30 percent of the level of its
firm sales entitlements in existence on the date the pipeline first
becomes subject to this section, under any eligible firm sales service
agreement with that pipeline;
(C) During the third twelve-month period after the pipeline first
becomes subject to this section, up to 50 percent of the level of its
firm sales entitlements in existence on the date the pipeline first
becomes subject to this section, under any eligible firm sales service
agreement with that pipeline;
(D) During the fourth twelve-month period after the pipeline first
becomes subject to this section, up to 75 percent of the level of its
firm sales entitlements in existence on the date the pipeline first
becomes subject to this section, under any eligible firm sales service
agreement with that pipeline; and
(E) Beginning the fifth twelve-month period after the pipeline first
becomes subject to this section, up to 100 percent of the level of its
firm sales entitlements in existence on the date the pipeline first
becomes subject to this section, under any eligible firm sales service
agreement with that pipeline.
(ii) A pipeline subject to this section may, at any time, permit a
firm sales customer to convert to firm transportation by more than the
amount provided in the schedule in paragraph (c)(3)(i) of this section.
(4) Reservation fee. Where a customer exercises its option under
this paragraph to convert to firm transportation service, the pipeline
may impose a reservation fee as provided in 284.8(d) of this subpart.
(5) Effect of conversion on minimum bills. If a customer converts
under this paragraph any portion of its firm sales entitlements from a
pipeline, each unit of firm transportation service purchased must be
credited to any minimum commodity bill obligation that the customer may
have under its firm sales service agreements with that pipeline.
(d) Abandonment. (1) If a firm sales customer exercises a conversion
option under paragraph (c) of this section, abandonment of the
pipeline's sales service obligation is approved to the extent of the
conversion.
(2) Notice of an intent by a customer to exercise an option under
paragraph (c) of this section constitutes consent by that customer to
the abandonment under this paragraph.
(3) Abandonment of a sales service under this paragraph is deemed
permitted by the present or future public convenience and necessity.
(Order 436, 50 FR 42494, Oct. 18, 1985; 50 FR 45908, Nov. 5, 1985,
as amended at 50 FR 52274, Dec. 23, 1985; 51 FR 6399, Feb. 24, 1986;
Order 500, 52 FR 27799, July 24, 1987; 52 FR 30354, Aug. 14, 1987; 52
FR 35540, Sept. 22, 1987; 52 FR 39633, Oct. 23, 1987; 54 FR 52395,
Dec. 21, 1989)
18 CFR 284.11 Environmental compliance.
(a) Any activity involving the construction of, or the abandonment
with removal of, facilities that is authorized pursuant to 284.3(c) and
Subpart B or C of this part is subject to the terms and conditions of
157.206(d) of this chapter.
(b) Advance notification -- (1) General rule. Except as provided in
paragraph (b)(2) of this section, at least 30 days prior to commencing
construction a company must file notification with the Commission of any
activity described in paragraph (a) of this section.
(2) Exception. The advance notification described in paragraph
(b)(1) of this section is not required if the cost of the project does
not exceed the cost limit specified in Column 1 of Table I of
157.208(d) of this chapter.
(c) Contents of advance notification. The advance notification
described in paragraph (b)(1) of this section must include the following
information:
(1) A brief description of the facilities to be constructed or
abandoned with removal of facilities (including pipeline size and
length, compression horsepower, design capacity, and cost of
construction);
(2) Evidence of having complied with each provision of 157.206(d) of
this chapter;
(3) Current U.S. Geological Survey 7.5-minute series topographical
maps showing the location of the facilities; and
(4) A description of the procedures to be used for erosion control,
revegetation and maintenance, and stream and wetland crossings.
(d) Reporting requirements -- (1) One-time report. A company must
file (on electronic media pursuant to 385.2011 of this chapter,
accompanied by 7 paper copies) a one-time report with the Commission, by
December 9, 1992, that includes all of the information required in
paragraph (c) of this section, for any activity described in paragraph
(a) of this section that cost more than $6.2 million and was commenced
between July 14, 1992 and November 9, 1992.
(2) Annual report. On or before May 1 of each year, a company must
file (on electronic media pursuant to 385.2011 of this chapter,
accompanied by 7 paper copies) an annual report that lists for the
previous calendar year each activity that is described in paragraph (a)
of this section, and which was completed during the previous calendar
year and exempt from the advance notification requirement pursuant to
paragraph (b)(2) of this section. For each such activity, the company
must include all of the information described in paragraph (c) of this
section.
1. American Gas Association (AGA)
2. ANR Pipeline Company and Colorado Interstate Gas Company (ANR)
3. Arkla Pipeline Group (Arkla)
4. Associated Gas Distributors, Inc. (AGD)
5. Association of Texas Intrastate Natural Gas Pipelines (Association
of Texas Intrastates)
6. CNG Transmission Corporation (CNG)
7. Columbia Gas Transmission Corporation and Columbia Gulf
Transmission Company (Columbia)
8. Enron Interstate Pipeline Companies (Enron)
9. Great Lakes Gas Transmission Limited Partnership (Great Lakes)
10. Interstate Natural Gas Association of America (INGAA)
11. K N Energy, Inc. (K N Energy)
12. Northern Illinois Gas Company, The Peoples Gas Light and Coke
Company, and North Shore Gas Company (NI-Gas)
13. Pacific Gas Transmission Company (PGT)
14. Pacific Offshore Pipeline Company (Pacific Offshore)
15. Questar Pipeline Company (Questar)
16. Southern California Gas Company (So-Cal)
17. Southern Natural Gas Company (Southern)
18. Tennessee Gas Pipeline Company (Tennessee)
19. Texas Eastern Transmission Corporation, Panhandle Eastern Pipe
Line Company, Trunkline Gas Company, and Algonquin Gas Transmission
Company (Texas Eastern)
20. Texas Gas Transmission Corporation (Texas Gas)
21. Transcontinental Gas Pipe Line Corporation (Transco)
22. United Gas Pipe Line Company (United)
23. Williston Basin Interstate Pipeline Company (Williston)
(Order 544, 57 FR 46495, Oct. 9, 1992)
18 CFR 284.12 Filing of capacity.
Each interstate pipeline that provides transportation subject to the
provisions of subpart A of this part must make an annual filing by March
1 of each year showing the estimated peak day capacity of the pipeline's
system, and the estimated storage capacity and maximum daily delivery
capability of storage facilities under reasonably representative
operating assumptions and the respective assignments of that capacity to
the various firm services provided by the pipeline.
(Order 436, 50 FR 42495, Oct. 18, 1985, as amended by Order 636, 57
FR 13315, Apr. 16, 1992)
18 CFR 284.13 Recordkeeping requirement.
(a) Within 30 days after commencement of any transportation
arrangement under subpart B or G of this part, the interstate pipeline
that provides such service must keep a log of the request for such
service that, at a minimum, includes:
(1) The date of the request;
(2) The name of the person requesting transportation; and
(3) The volume of gas to be transported.
(b) The log required under this section must be available for public
inspection at the company's corporate headquarters during the company's
normal business hours.
(50 FR 52276, Dec. 23, 1985, as amended by Order 522, 55 FR 12169,
Apr. 2, 1990)
18 CFR 284.14 Provisions governing pipeline restructuring.
(a) Applicability. This section applies to any interstate natural
gas pipeline that offers transportation service under subpart B or G of
this part on May 18, 1992.
(b) Compliance filing. (1) The pipelines subject to this section
must make a compliance filing on or before the dates set forth in
paragraph (b)(4) of this section to implement the provisions of
284.1(a), 284.8(a)(1), (a)(4), (b)(2)-(5), and (d), 284.9(a)(1) and
(b)(2)-(5), 284.221(d), and subparts H and J of this part, including,
but not limited to, tariff provisions to implement without undue
discrimination:
(i) Unbundled sales and transportation services,
(ii) Open access storage service,
(iii) Reasonable and non-discriminatory terms and conditions for
operating unbundled open-access transportation,
(iv) Equality of transportation service for all gas transported under
each rate schedule,
(v) Allocation of aggregate receipt point capacity, individual
receipt point capacity, mainline segment capacity, storage capacity, and
delivery point capacity,
(vi) Shipper flexibility in changing receipt and delivery points,
(vii) Scheduling of gas injections into the mainline and into
storage, scheduling of gas deliveries from storage and from the
mainline, the setting and charging of penalties, balancing rights, and
the instantaneous receipt and delivery of gas,
(viii) No-notice transportation service, with separately identified
cost components,
(ix) Equality of access to information on availability of service,
(x) Non-discriminatory plans for operating under curtailment of
capacity and gas supply (if the pipeline sells gas),
(xi) Rate design and cost allocation changes,
(xii) A capacity release mechanism,
(xiii) Right-of-first-refusal procedures for use upon the expiration
of long-term, firm transportation contracts, and
(xiv) Assignment of capacity rights on upstream pipelines to firm
customers.
(2) The compliance filing must be filed no later than the date
specified for each pipeline in paragraph (b)(4) of this section in the
restructuring proceeding instituted by the Commission for the
implementation of the provisions listed in paragraph (b)(1) of this
section.
(3)(i) The changes in rates, charges, classifications, or services,
or in any rule, regulation, or service agreement, necessary to comply
with this paragraph must be filed as pro forma tariff sheets, for
illustrative purposes only, with rates that are designed to recover the
same revenue requirement as the pipeline's rates in effect on the date
the compliance filing is made.
(ii) The compliance filing must also include a comparison of the
revenue responsibility of each of the pipeline's historical customer
classes for the unbundled services under
(A) the pipeline's last approved cost classification method for cost
allocation and rate design, and
(B) the straight fixed-variable (SFV) cost classification method for
cost allocation and rate design. Under the straight fixed-variable
method all fixed costs are classified to the demand component. If the
comparison shows that adopting SFV for cost allocation and rate design
will result in a 10 percent or greater increase in revenue
responsibility for any customer class, the compliance filing must
include a plan for phasing-in the cost shift due to SFV over no more
than a four year period.
(iii) The compliance filing must include a cost-based sales rate for
small customers that are entitled to purchase gas under a pipeline's
one-part, imputed-load-factor rate schedule on the effective date of a
pipeline's blanket certificate under 284.284, to apply for a period of
one year from that date.
(iv)(A) Except as provided in paragraph (b)(3)(iv)(B) of this
section, a pipeline that offered a sales or transportation service to
small customers with a one-part volumetric rate at an imputed load
factor on May 18, 1992, must include tariff provisions in its compliance
filing to charge a rate for firm transportation services under 284.8 on
the same basis and under the same eligibility criteria as the small
customer sales or transportation rate under the pipeline's last-approved
tariff provisions for those services.
(B) A pipeline may increase the permissible daily service levels for
the small customer transportation rate up to 10,000 Mcf or Dth per day.
A customer that receives service under its small customer transportation
rate may not ship gas under any interruptible transportation rate
schedule available from the pipeline or ship gas as a replacement
shipper on the pipeline under 284.243, unless the customer has
exhausted its daily levels of firm transportation from the pipeline. A
pipeline's firm transportation service for small customers may not
contain service conditions more restrictive than the restrictions
permitted by paragraph (b)(3)(iv) of this section.
(v) The compliance filing must also include an estimate of the costs
of implementing the provisions of this paragraph and any mechanisms
proposed for recovering those costs.
(4) The following pipelines must file on or before October 1, 1992:
ANR Pipeline Company
ANR Storage Company
Arkla Energy Resources
Colorado Interstate Gas Company
Columbia Gas Transmission Corporation
Columbia Gulf Transmission Corporation
Michigan Gas Storage
Northern Natural Gas Company
Questar Pipeline Company
Southern Natural Gas Company
Texas Eastern Transmission Corporation
Williams Natural Gas Company
Williston Basin Interstate Pipeline
The following pipelines must file on or before November 2, 1992:
CNG Transmission Corporation
Equitrans, Inc.
Florida Gas Transmission Company
Iroquois Gas Transmission
Kentucky-West Virginia Gas Company
KN Energy, Inc.
Mid Louisiana Gas Company
National Fuel Gas Supply Corporation
Panhandle Eastern Pipe Line Company
Tennessee Gas Pipeline Company
Texas Gas Transmission Corporation
Trunkline Gas Company
United Gas Pipe Line Company
The following pipelines must file on or before December 1, 1992:
Alabama Tennessee Natural Gas Company
Algonquin Gas Transmission Company
Altamont Gas Transmission Company
Carnegie Natural Gas Company
Cornerstone Pipeline Company
Delta Pipeline Company
East Tennessee Natural Gas Company
Gas Gathering Corporation
Gas Transport Inc.
Gateway Pipeline Company
Green Canyon Pipeline Company
Gulf States Transmission Corporation
Inland Gas Company, Inc.
Louisiana Nevada Transit Company
Midwestern Gas Transmission Company
MIGC, Inc.
Mississippi River Transmission Corporation
Moraine Pipeline Company
Natural Gas Pipeline Company of America
Pacific Gas Transmission Company
Phillips Gas Pipeline Company
Riverside Pipeline Company
South Georgia Natural Gas Company
Valero Interstate Transmission Company
Valley Gas Transmission, Inc.
Viking Gas Transmission Company
Western Gas Interstate Company
Western Transmission Corporation
Wyoming California Pipeline
The following pipelines must file on or before December 31, 1992:
Black Marlin Pipeline Company
Canyon Creek Compression Company
Caprock Pipeline Company
Chandeleur Pipe Line Company
El Paso Natural Gas Company
Freeport Interstate Pipeline Company
Gasdel Pipeline System, Inc.
Great Lakes Gas Transmission
High Island Offshore System
Kern River Gas Transmission Company
Mojave Pipeline Company
Northern Border Pipeline Company
Northern Penn Gas Company
Northwest Pipeline Corporation
OkTex Pipeline Company
Overthrust Pipeline Company
Ozark Gas Transmission System
Pacific Interstate Offshore Company
Pacific Offshore Pipeline Company
Paiute Pipeline Company
Pelican Interstate Gas System
Point Arguello Natural Gas Line Company
Sabine Pipe Line Company
Sea Robin Pipeline Company
Seagull Interstate Corporation
Stingray Pipeline Company
Superior Offshore Pipeline Company
Tarpon Transmission Company
Texas Sea Rim Pipe Line, Inc.
Trailblazer Pipeline Company
Transcontinental Gas Pipe Line Corporation
Transwestern Pipeline Company
U-T Offshore System
West Gas Interstate, Inc.
Wyoming Interstate Company, Ltd.
(c) Restructuring discussions. (1) By June 8, 1992, a pipeline
subject to this section must initiate restructuring discussions
concerning implementation of the provisions of this section with all its
customers and other interested parties that intervene in its
restructuring proceeding instituted by the Commission for implementation
of the provisions listed in paragraph (b)(1) of this section.
(2) By July 7, 1992, a pipeline subject to this section must prepare
and serve a summary of its proposed restructuring plan on every
intervenor in its restructuring proceeding, addressing each and every
element of the compliance filing required under paragraph (b)(1) of this
section.
(d) Adjustments to obligations to purchase gas; automatic
abandonment of sales. (1) Any firm sales customer of a pipeline subject
to this section may reduce or terminate its right or obligation to
purchase gas under any contract with that pipeline for the sale of
natural gas in effect on May 18, 1992, by giving notice to the pipeline
during the pipeline's restructuring proceeding.
(2) A pipeline subject to this section is authorized to abandon the
sale of gas to any purchaser to the extent:
(i) The purchaser exercises its right to reduce or terminate its
right or obligation to purchase under the provisions of paragraph (d)(1)
of this section, or
(ii) The purchaser refuses to pay the rate the pipeline offers for
unbundled gas sales. The pipeline must file a report of any such
abandonment of sales with the Commission within 30 days of the date of
abandonment.
(3) The reduction or termination of service under the contract and
the abandonment of sales under paragraph (d)(2) of this section will be
effective on the effective date (as approved by the Commission) of the
tariff sheets implementing service under the pipeline's blanket
certificate for unbundle sales services under 284.284.
(e) Adjustments to firm transportation service; automatic
abandonment. (1) Any firm shipper on a pipeline subject to this section
must give notice to the pipeline during the pipeline's restructuring
proceeding whether the shipper wants to retain, reduce, or terminate its
contractual rights to firm transportation service.
(2) Except as provided in paragraph (e)(4) of this section, any firm
shipper may reduce or terminate its contractual rights and obligations
for firm transportation service subject to this section, if the shipper
gives notice of its desire to reduce or terminate service under
paragraph (e)(1) of this section, and
(i) The pipeline receives an offer for the available firm
transportation service from a creditworthy shipper that is equal to or
greater than the rate the existing firm shipper is contractually
obligated to pay, up to the maximum rate, or
(ii) The pipeline agrees to the reduction or termination of the
existing firm shippers' contractual obligations.
(3) Except as provided in paragraph (e)(4) of this section, a
pipeline subject to this section may abandon firm transportation service
under a contract with a firm shipper:
(i) To the extent the shipper reduces or terminates its contractual
obligations under paragraph (e)(2) of this section, or
(ii) If, during the pipeline's restructuring proceeding, another
creditworthy shipper offers a higher rate for the service than the
existing firm shipper, up to the maximum rate, which the existing
shipper declines to match, and the pipeline is not contractually
precluded from charging the higher rate to the existing firm shipper.
(4) Paragraphs (e)(1)-(3) of this section do not apply to the firm
transportation service provided for a downstream pipeline subject to
subpart B or G of this part on an upstream pipeline subject to subpart B
or G of this part, unless the existing firm customers of the downstream
pipeline concur in the decision of the downstream pipeline to reduce or
terminate its firm transportation service on the upstream pipeline.
(5) The authority to abandon service under this paragraph is
effective:
(i) On the effective date of the contract to provide the service to
another shipper, or
(ii) On the effective date of the pipeline's agreement to the
reduction or termination of the existing firm shipper's contractual
obligations.
(Order 636, 57 FR 13315, Apr. 16, 1992, as amended by Order 636-A, 57
FR 36217, Aug. 12, 1992)
18 CFR 284.14 Subpart B -- Certain Transportation by Interstate Pipelines
18 CFR 284.101 Applicability.
This subpart implements section 311(a)(1) of the NGPA and applies to
the transportation of natural gas by any interstate pipeline on behalf
of:
(a) Any intrastate pipeline; or
(b) Any local distribution company.
18 CFR 284.102 Transportation by interstate pipelines.
(a) Subject to paragraphs (d) and (e) of this section, other
provisions of this subpart, and the conditions of subpart A of this
part, any interstate pipeline is authorized without prior Commission
approval, to transport natural gas on behalf of:
(1) Any intrastate pipeline; or
(2) Any local distribution company.
(b) Any rates charged for transportation under this subpart may not
exceed the just and reasonable rates established under subpart A of this
part.
(c) Any interstate pipeline that engages in transportation
arrangements under this subpart must file reports in accordance with
284.106 of this chapter.
(d) Transportation of natural gas is not on behalf of an intrastate
pipeline or local distribution company or authorized under this section
unless:
(1) The intrastate pipeline or local distribution company has
physical custody of and transports the natural gas at some point; or
(2) The intrastate pipeline or local distribution company holds title
to the natural gas at some point, which may occur prior to, during, or
after the time that the gas is being transported by the interstate
pipeline, for a purpose related to its status and functions as an
intrastate pipeline or its status and functions as a local distribution
company; or
(3) The gas is delivered at some point to a customer that either is
located in a local distribution company's service area or is physically
able to receive direct deliveries of gas from an intrastate pipeline,
and that local distribution company or intrastate pipeline certifies
that it is on its behalf that the interstate pipeline is providing
transportation service.
(e) An interstate pipeline shall obtain from it shippers
certifications including sufficient information to verify that their
services qualify under this section. An interstate pipeline shall file
by January 3, 1992, any tariff revisions or additions necessary to
clarify that it may require such certifications. Prior to commencing
transportation service described in paragraph (d)(3) of this section, an
interstate pipeline must receive the certification required from a local
distribution company or an intrastate pipeline pursuant to paragraph
(d)(3).
(Order 436, 50 FR 42495, Oct. 18, 1985, as amended by Order 526, 55
FR 33011, Aug. 13, 1990; Order 526-A, 55 FR 40829, Oct. 5, 1990; Order
537, 56 FR 50245, Oct. 4, 1991)
284.103 -- 284.104 (Reserved)
18 CFR 284.105 Effectiveness of existing transportation arrangements.
(a) Any transportation service authorized and commenced on or before
October 9, 1985, under this subpart or under 284.221 of subpart G as
such subparts were effective before November 1, 1985, may be continued
under the terms and conditions that applied prior to November 1, 1985,
with the exception of the requirements of 284.7 and 284.106, until the
earlier of:
(1) The expiration of the original or extended term of any authorized
transportation arrangement as it was in effect on the date of issuance
of this order; or
(2) October 9, 1987.
(b) Effective November 1, 1985, the reporting requirements of
284.106 apply to all transportation authorized under this subpart which
commenced either prior to, or subsequent to, November 1, 1985.
(Order 436, 50 FR 42495, Oct. 18, 1985; 50 FR 45908, Nov. 5, 1985)
18 CFR 284.106 Reporting requirements.
(a) Initial full report. Within thirty days after commencing
transportation (except storage) under 284.102, an interstate pipeline
must file with the Commission an initial full report, signed under oath
by a senior official of the company, consisting of an original and five
conformed copies, containing the following information:
(1) The identity of the interstate pipeline and its affiliation, if
any, with the other entities involved in the transaction and the
identity, title, mailing address, and phone number of the person or
persons with whom to communicate about the transportation arrangement;
(2) A general description of the interstate pipeline's existing
operations;
(3) A description of the transportation including:
(i) The identity of the parties;
(ii) The dates of commencement and projected termination of the
service;
(iii) The estimated total and maximum daily quantities of natural gas
to be transported by the interstate pipeline;
(iv) The points between which the natural gas is to be transported by
the interstate pipeline;
(v) The location (i.e., state) of the original source and the
location (i.e., state) of the ultimate delivery point of the gas; and
(vi) A statement that the contract provides that the transportation
arrangement is subject to the provisions of this subpart.
(4) If such transportation is provided to a customer that is located
in the service area of a local distribution company, a statement that
the interstate pipeline has notified the local distribution company and
the local distribution company's appropriate regulatory agency in
writing of the proposed transportation prior to comments.
(b) Subsequent reports -- (1) An interstate pipeline that files an
initial report under paragraph (a) of this section must amend that
report to reflect any material change in the pertinent transportation
arrangement.
(2) Any changes in the initial report required by this paragraph must
be filed with the Commission within thirty days of the related changed
circumstances, and must be signed under oath by a senior official of the
company, and consist of an original and five conformed copies.
(c) Annual report. Not later than March 1 of each year, an
interstate pipeline must file with the Commission an annual report that
contains, for each docketed transportation service (except storage)
provided during the preceding calendar year under 284.102, the
following information:
(1) The docket number assigned to the transaction;
(2) Total volumes transported for the transaction; and
(3) Total revenues received for the transaction.
(d) Notification of termination. Not later than thirty days after
the termination of any transportation arrangement (except storage) under
284.102, the interstate pipeline must file with the Commission an
original and five conformed copies of a statement including the
following information:
(1) The docket number assigned to the transaction and the date the
transaction was terminated;
(2) The total volumes transported under the arrangement;
(3) The total revenues received; and
(4) A statement certifying that the service was provided under the
terms and conditions previously reported in that docket.
(e) Filing fees. Each initial full report required by paragraph (a)
of this section must be accompanied by the fee prescribed in 381.404 of
this chapter or by a petition for waiver under 381.106 of this chapter.
(f) Reporting form. Each initial report filed under paragraph (a) of
this section and each subsequent report filed under paragraph (b) of
this section must utilize FERC Form No. 549-ST.
(g) Semi-annual storage report. Within 30 days of the end of each
complete storage injection and withdrawal season, the interstate
pipeline shall file with the Commission a report of storage activity
provided under the authority of 284.102. The report must be signed
under oath by a senior official, consist of an original and give
conformed copies, and contain a summary of storage injection and
withdrawal activities to include the following:
(1) The identify of each customer injecting gas into storage and/or
withdrawing gas from storage, identifying any affiliation with the
interstate pipeline;
(2) The rate schedule under which the storage injection or withdrawal
service was performed;
(3) The maximum storage quantity and maximum daily withdrawal
quantity applicable to each storage customer;
(4) For each storage customer, the volume of gas (in dekatherms)
injected into and/or withdrawn from storage during the period;
(5) The unit charge and total revenues received during the
injection/withdrawal period from each storage customer, noting the
extent of any discounts permitted during the period; and
(6) The related docket numbers in which the interstate pipeline
reported storage related injection/withdrawal transportation services.
(Order 436, 50 FR 42495, Oct. 18, 1985, as amended at 50 FR 52276,
Dec. 23, 1985; Order 458, 51 FR 44284, Dec. 9, 1986; Order 636, 57 FR
13317, Apr. 16, 1992)
18 CFR 284.106 Subpart C -- Certain Transportation by Intrastate Pipelines
18 CFR 284.121 Applicability.
This subpart implements section 311(a)(2) of the NGPA and applies to
the transportation of natural gas by any intrastate pipeline on behalf
of:
(a) Any interstate pipeline, or
(b) Any local distribution company served by any interstate pipeline.
18 CFR 284.122 Transportation by intrastate pipelines.
(a) Subject to paragraphs (d) and (e) of this section, other
provisions of this subpart, and the applicable conditions of Subpart A
of this part, any intrastate pipeline may, without prior Commission
approval, transport natural gas on behalf of:
(1) Any interstate pipeline; or
(2) Any local distribution company served by an interstate pipeline.
(b) No rate charged for transportation authorized under this subpart
may exceed a fair and equitable rate under 284.123.
(c) Any intrastate pipeline engaged in transportation arrangements
authorized under this section must file reports as required by 284.126.
(d) Transportation of natural gas is not on behalf of an interstate
pipeline or local distribution company served by an interstate pipeline
or authorized under this section unless:
(1) The interstate pipeline or local distribution company has
physical custody of and transports the natural gas at some point; or
(2) The interstate pipeline or local distribution company holds title
to the natural gas at some point, which may occur prior to, during, or
after the time that the gas is being transported by the intrastate
pipeline, for a purpose related to its status and functions as an
interstate pipeline or its status and functions as a local distribution
company.
(e) If the transportation service commenced prior to August 2, 1990,
and the requirements of paragraph (e) of this section are not satisfied,
transportation service is not authorized under this section after
January 31, 1992.
(Order 436, 50 FR 42495, Oct. 18, 1985, as amended by Order 537, 56
FR 50245, Oct. 4, 1991; Order 537-A, 57 FR 46501, Oct. 9, 1992)
18 CFR 284.123 Rates and charges.
(a) General rule. Rates and charges for transportation of natural
gas authorized under 284.122(a) shall be fair and equitable as
determined in accordance with paragraph (b) of this section.
(b) Election of rates. (1) Subject to the conditions in 284.8 and
284.9 of this chapter, an intrastate pipeline may elect to:
(i) Base its rates upon the methodology used:
(A) In designing rates to recover the cost of gathering, treatment,
processing, transportation, delivery or similar service (including
storage service) included in one of its then effective firm sales rate
schedules for city-gate service on file with the appropriate state
regulatory agency; or
(B) In determining the allowance permitted by the appropriate state
regulatory agency to be included in a natural gas distributor's rates
for city-gate natural gas service; or
(ii) To use the rates contained in one of its then effective
transportation rate schedules for intrastate service on file with the
appropriate state regulatory agency which the intrastate pipeline
determines covers service comparable to service under this subpart.
(2)(i) If an intrastate pipeline does not choose to make any election
under paragraph (b)(1) of this section, it shall apply for Commission
approval, by order, of the proposed rates and charges by filing with the
Commission the proposed rates and charges, and information showing the
proposed rates and charges are fair and equitable. Each petition for
approval filed under this paragraph must be accompanied by the fee set
forth in 381.403 or by a petition for waiver pursuant to 384.106 of
this chapter. Upon filing the petition for approval, the intrastate
pipeline may commence the transportation service and charge and collect
the proposed rate, subject to refund.
(ii) 150 days after the date on which the Commission received an
application filed pursuant to paragraph (b)(2)(i) of this section, the
rate proposed in the application will be deemed to be fair and equitable
and not in excess of an amount which interstate pipelines would be
permitted to charge for providing similar transportation service, unless
within the 150 day period, the Commission either extends the time for
action, or institutes a proceeding in which all interested parties will
be afforded an opportunity for written comments and for the oral
presentation of views, data and arguments. In such proceeding, the
Commission either will approve the rate or disapprove the rate and order
refund, with interest, of any amount which has been determined to be in
excess of those shown to be fair and equitable or in excess of the rates
and charges which interstate pipelines would be permitted to charge for
providing similar transportation service.
(iii) A Commission order approving or disapproving a transportation
rate under this paragraph supersedes a rate determined in accordance
with paragraph (b)(1) of this section.
(c) Treatment of revenues. The Commission presumes that all revenues
received by an intrastate pipeline in connection with transportation
authorized under 284.122(a) and computed in accordance with paragraph
(b)(1) of this section have been or will be taken into account by the
appropriate state regulatory agency for purposes of establishing
transportation charges by the intrastate pipeline for service to
intrastate customers.
(d) Presumptions. If the intrastate pipeline is charging a rate
computed pursuant to 284.123(b)(1), the rate charged is presumed to be:
(1) Fair and equitable; and
(2) Not in excess of the rates and charges which interstate pipelines
would be permitted to charge for providing similar transportation
service.
(e) Filing requirements -- (1) General rule. Except as provided in
paragraph (e)(2) of this section, within 30 days of commencement of new
service, any intrastate pipeline that engages in transportation
arrangements under this subpart must file with the Commission a one-time
statement that describes how the pipeline will engage in these
transportation arrangements, including operating conditions, such as,
quality standards and financial viability of the shipper. If the
pipeline changes its operations under this subpart, it must amend the
statement and file such amendments not later than 30 days after
commencement of the change in operations.
(2) Exception. Any intrastate pipeline that engages in
transportation arrangements authorized under this subpart before
December 15, 1985, must file the statement described in paragraph (e)(1)
not later than February 1, 1985. Any amendments to this statement must
be filed in accordance with paragraph (e)(1).
(44 FR 52184, Sept. 7, 1979, as amended at 44 FR 66791, Nov. 21,
1979; Order 394, 49 FR 35364, Sept. 7, 1984; Order 436, 50 FR 42496,
Oct. 18, 1985; 50 FR 52276, Dec. 23, 1985)
18 CFR 284.124 Terms and conditions.
Contracts for the transportation of natural gas authorized under this
subpart shall provide that the transportation arrangement is subject to
the provisions of this subpart.
18 CFR 284.125 Effectiveness of existing transportation services.
(a) Any transportation service authorized and commenced on or before
October 9, 1985, under this subpart or 284.222 of subpart G as such
subparts were effective before November 1, 1985, may be continued under
the terms and conditions that applied prior to November 1, 1985, with
the exception of reporting requirements, until the earlier of:
(1) The expiration of the original or extended term of any authorized
transportation arrangement as it was in effect on the date of issuance
of this order.
(2) October 9, 1987.
(b) Effective November 1, 1985, the reporting requirements of
284.126 apply to all transportation authorized under this subpart which
commenced either prior to, or subsequent to, November 1, 1985.
(Order 436, 50 FR 42496, Oct. 18, 1985; 50 FR 45908, Nov. 5, 1985)
18 CFR 284.126 Reporting requirements.
(a) Initial full report. Within thirty days after commencing
transportion (except storage) under by this subpart, an intrastate
pipeline must file with the Commission and the appropriate state
regulatory agency an initial full report, signed under oath by a senior
official of the company, consisting of an original and five conformed
copies to the Commission, containing the following information:
(1) The identity of the intrastate pipeline and the identity, title,
mailing address, and phone number of the person or persons with whom to
communicate about the transportation arrangement;
(2) A general description of the intrastate pipeline's existing
operations;
(3) A description of the transportation including:
(i) The identity of the parties;
(ii) The dates of commencement and projected termination of the
service;
(iii) The estimated total and maximum daily quantities of natural gas
to be transported by the intrastate pipeline;
(iv) The points between which the natural gas is to be transported by
the intrastate pipeline;
(v) The location (i.e., state) of the original source and the
location (i.e., state) of the ultimate delivery point of the gas; and
(vi) The rate to be charged.
(4) A statement of the basis upon which the intrastate pipeline
determined that the service provided is comparable to service provided
for under that rate schedule, if the intrastate pipeline is charging a
rate under 284.123(b)(1)(ii) of this chapter; and
(5) A statement that:
(i) The appropriate state regulatory agency has been notified that
the Commission presumes that all revenues received by an intrastate
pipeline under rates for transportation under 284.122 established under
284.123(b)(1) of this chapter, have been or will be taken into account
by the appropriate state regulatory agency for purposes of establishing
transportation rates charged by that intrastate pipeline for service to
intrastate customers; and
(ii) Any contract for the transportation arrangement provides that it
is subject to this subpart.
(6) If such transportation is provided to a customer that is located
in the service area of a local distribution company, a statement that
the intrastate pipeline has notified the local distribution company and
the local distribution company's appropriate state regulatory agency in
writing of the proposed transportation prior to commencement.
(b) Subsequent reports. (1) An intrastate pipeline that files an
initial report under paragraph (a) of this section must amend that
report to reflect any material change with pertinent transportation
arrangement.
(2) Any changes in the initial report required by this paragraph must
be filed with the Commission and the appropriate state regulatory agency
within 30 days of the material change, and must be signed under oath by
a senior official of the company, and consist of an original and five
conformed copies to the Commission.
(c) Annual report. Not later than March 1 of each year, each
intrastate pipeline must file an annual report with the Commission and
the appropriate state regulatory agency that contains, for each docketed
transportation service (except storage) provided during the preceding
calendar year under 284.122, the following information:
(1) The docket number assigned to the transaction;
(2) Total volumes transported for the transaction; and
(3) Total revenues received for the transaction.
(d) Notification of termination. Not later than thirty days after
the termination of any transportation arrangement (except storage)
authorized under 284.122, the intrastate pipeline must file with the
Commission and with the appropriate state regulatory agency a statement,
consisting of an original and five conformed copies to the Commission,
including the following information:
(1) The docket number assigned to the transaction and the date the
transaction was terminated;
(2) The total volumes transported under the arrangement;
(3) The total revenues received; and
(4) A statement certifying that the service was provided under the
terms and conditions previously reported in that docket.
(e) Filing fees. Each initial report required by paragraph (a) of
this section must be accompanied by the fee set forth in 381.404 of
this chapter, or a petition for waiver under 381.106 of this chapter.
(f) Reporting form. Each initial report filed under paragraph (a) of
this section and each subsequent report filed under paragraph (b) of
this section must utilize FERC Form No. 549-ST.
(g) Semi-annual storage report. Within 30 days of the end of each
complete storage injection and withdrawal season, the intrastate
pipeline shall file with the Commission a report of storage activity
provided under the authority of 284.122. The report must be signed
under oath by a senior official, consist of an original and five
conformed copies, and contain a summary of storage injection and
withdrawal activities to include the following:
(1) The identity of each customer injecting gas into storage and/or
withdrawing gas from storage;
(2) The docket where the storage injection or withdrawal rates were
approved;
(3) The maximum storage quantity and maximum daily withdrawal
quantity applicable to each storage customer;
(4) For each storage customer, the volume of gas (in dekatherms)
injected into and/or withdrawn from storage during the period;
(5) The unit charge and total revenues received during the
injection/withdrawal period from each storage customer; and
(6) The related docket numbers in which the intrastate pipeline
reported storage related injection/withdrawal transportation services.
(Order 436, 50 FR 42496, Oct. 18, 1985, as amended at 50 FR 52276,
Dec. 23, 1985; Order 458, 51 FR 44284, Dec. 9, 1986; Order 636, 57 FR
13317, Apr. 16, 1992)
18 CFR 284.126 Subpart D -- Certain Sales by Intrastate Pipelines
Source: 44 FR 12409, Mar. 7, 1979, unless otherwise noted.
Redesignated at 44 FR 52184, Sept. 7, 1979.
18 CFR 284.141 Applicability.
This subpart implements section 311(b) of the NGPA and applies to
certain sales of natural gas by intrastate pipelines to:
(a) Interstate pipelines; and
(b) Local distribution companies served by interstate pipelines.
18 CFR 284.142 Sales by intrastate pipelines.
Any intrastate pipeline may, without prior Commission approval, sell
natural gas to any interstate pipeline or any local distribution company
served by an interstate pipeline, in accordance with the provisions of
this subpart.
18 CFR 284.143 Definitions.
(a) Weighted average acquisition cost of natural gas means the system
supply cost of natural gas to an intrastate pipeline for any billing
period in which deliveries pursuant to this subpart occur, computed by:
(1) Determining the actual quantities of natural gas (expressed in
terms of MMBtu's) purchased by the intrastate pipeline from each source
of supply, excluding any quantities for which the intrastate pipeline
makes an adjustment under 284.144(b), during the most recent calendar
month for which data are available prior to five days before the
commencement of the billing period in which deliveries pursuant to the
sale are to occur and for which deliveries the weighted average
acquisition cost is to be charged;
(2) Multiplying the MMBtu's attributable to each source of supply by
the latest price per MMBtu actually paid during the calendar month that
the volumes are computed under paragraph (a)(1) of this section with
respect to each source of supply; and
(3) Dividing the sum of the products computed under paragraph (a)(2)
of this section by the sum of the MMBtu's determined under paragraph
(a)(1) of this section.
(b) Billing period is any period during which deliveries are made
pursuant to this subpart and for which the purchaser will be charged a
unit cost for the volumes so delivered calculated in accordance with
284.144. Such period may not be less than a calendar month.
18 CFR 284.144 Rates and charges.
(a) Basic rate. The rates and charges by an intrastate pipeline
pursuant to this subpart may not exceed:
(1) Its actual weighted average acquisition cost of natural gas
calculated at least five days before the first day of the billing period
for which the weighted average acquisition cost will be charged for
deliveries made during that billing period; plus
(2) An adjustment to reflect any difference between the weighted
average acquisition cost of natural gas used for billing purposes for
the most recent billing period and the actual weighted average
acquisition cost experienced during that same billing period for which
actual data are now available and for which the actual weighted average
acquisition costs of natural gas have not yet been recovered; plus
(3) An amount to recover the costs of gathering, treating,
processing, transporting, and delivering the natural gas (including an
opportunity to earn a reasonable profit thereon) as determined in
accordance with 284.123; plus
(4) An adjustment as may be determined under paragraph (b) of this
section.
(b) Adjustment. With respect to natural gas sold pursuant to this
subpart which:
(1) Is acquired under an existing contract;
(2) Is in excess of quantities which the intrastate pipeline would
otherwise have acquired; and
(3) The price of which exceeds the intrastate pipeline's weighted
average acquisition cost of natural gas, the intrastate pipeline may add
to the basic rate under paragraph (a) of this section an amount
sufficient to offset the increase in its weighted average acquisition
cost of natural gas.
18 CFR 284.145 Terms and conditions.
(a) No sale pursuant to this subpart or extension thereof may be for
a period exceeding two years.
(b) Any sale pursuant to this subpart shall be subject to
interruption to the extent that natural gas subject to the sale is
required by the intrastate pipeline to provide adequate service to the
pipeline's customers at the time of the sale.
(c) No sale pursuant to this subpart may involve natural gas acquired
by the intrastate pipeline under a sales contract with the producer or
other supplier entered into solely or primarily for the purpose of
resale pursuant to this subpart. The Commission shall consider, in
determining whether an intrastate pipeline's contract with a producer or
other supplier has been entered into solely or primarily for resale of
the subject gas pursuant to this subpart, whether the intrastate
pipeline did or could have reasonably projected that the natural gas
subject to the contract was necessary to meet the pipeline's future
market and buyer requirements, including growth, both in the number of
customers and in the demands of existing customers.
(d) The purchaser under this subpart shall be notified of the rate to
be charged under 284.144 at least five days prior to the beginning of
each billing period.
(e) The Commission may by rule or order impose other terms and
conditions as it deems appropriate and in the public interest.
(f) The Commission presumes that the cost of gathering, treating,
processing, transporting and delivery recovered under 284.144 will be
considered by the state regulatory authority in arriving at sales and
transportation rates to enable the intrastate pipeline company to
recover such costs and earn its allowed rate of return.
18 CFR 284.146 Extensions.
(a) An intrastate pipeline seeking to extend a sale pursuant to this
subpart shall file an extension report as provided by 284.148(c).
(b) If an extension report as required in 284.148(c) is duly filed,
the proposed extension may take effect unless the Commission, prior to
the beginning of the proposed extension, after opportunity for the oral
presentation of data, views and arguments and for written comments,
determines by order that the proposed extension is not approved. If the
Commission determines, by order, that the proposed extension shall be
modified, the extension may take effect only as modified.
18 CFR 284.147 Terminations.
(a) Upon complaint of any interested person or upon the Commission's
own motion, the Commission may by order terminate a sale pursuant to
this subpart.
(b) Prior to issuing an order under paragraph (a) of this section,
the Commission shall afford an opportunity for the oral presentation of
data, views and arguments, and for written comments.
(c) A sale under this subpart may be terminated if the Commission
determines that:
(1) The termination is required to enable the intrastate pipeline to
provide adequate service to its customers at the time of the sale;
(2) The sale involves natural gas acquired by the intrastate pipeline
solely or primarily for the purpose of resale pursuant to this subpart;
(3) The sale violates any provision of this subpart or any term or
condition established by rule or order of the Commission applicable to
the sale; or
(4) The sale circumvents or violates any provision of the NGPA.
(d) Upon complaint of any interested person or upon its own motion,
the Commission may, prior to a hearing as provided in paragraph (b) of
this section, suspend a sale pursuant to this subpart pending the
hearing if it determines that any of the findings under paragraph (c) of
this section is likely to be made following the hearing.
18 CFR 284.148 Reporting requirements.
(a) Initial report. Within 60 days after commencing deliveries under
a sale pursuant to this subpart, an intrastate pipeline shall file with
the appropriate state regulatory agency and with the Commission an
initial report, under oath, signed by a senior official of the company,
containing the following information:
(1) The exact legal name of the intrastate pipeline and the name,
title and mailing address of the person or persons to whom
communications regarding the sale pursuant to this subpart should be
addressed;
(2) A description of the sale, including:
(i) The identity of the parties;
(ii) The dates of commencement and anticipated termination of the
sale;
(iii) The estimated total and daily quantities (in MMBtu's) of
natural gas; and
(iv) The rate to be charged;
(3) A computation showing the methodology for determining the
weighted average acquisition cost of natural gas under this subpart;
(4) A computation showing the methodology used to determine any unit
cost difference between the weighted average acquisition cost used for
billing period purposes and actual cost for the same billing period;
(5) A computation showing the methodology to be employed for arriving
at the rate charged to recover the cost of gathering, treating,
processing, transporting and delivering the natural gas associated with
the sale;
(6) Computation of an adjustment, if any, under 284.144(b),
including:
(i) The basis for attributing certain additional acquisitions of
natural gas to a sale pursuant to this subpart;
(ii) The identity of the existing contract under which the additional
acquisitions are made and the price (per MMBtu) of natural gas purchased
under the contract; and
(iii) Each point of delivery of additional acquisitions of natural
gas to the intrastate pipeline; and
(7) An affidavit that service pursuant to the sale is subject to
interruption to the extent that natural gas subject to the sale under
this subpart is required to enable the intrastate pipeline involved to
provide adequate service to its customers at the time of the sale.
(b) Subsequent report. If any significant change occurs with respect
to the information filed under paragraph (a) of this section, the
intrastate pipeline shall file with the Commission and the appropriate
state regulatory agency, under oath, appropriate amendments to its
initial report, signed by a senior official of the company.
(c) Extension report. Not less than 90 days prior to the expiration
of a contract for the sale of natural gas pursuant to this subpart, an
intrastate pipeline seeking to extend the sale beyond the initial
two-year period or any period of extension shall file with the
Commission and the appropriate state regulatory agency an extension
report signed by a senior official of the company, under oath, stating:
(1) Current information with respect to any matters required to be
reported under paragraph (a) of this section; and
(2) The proposed terms of the extension.
(d) Final report. Within 60 days after the termination of any sale
or extension under this subpart, the interstate pipeline or local
distribution company served by an interstate pipeline which purchased
natural gas pursuant to this subpart shall file with the Commission and
the appropriate state regulatory agency, under oath, a final report
signed by a senior official of the company, stating:
(1) The actual quantities of natural gas purchased, on a monthly and
total basis;
(2) The actual rate paid (per MMBtu) for each month and the total
amount paid; and
(3) The points of delivery.
(e) Filing fees. Each initial report required by paragraph (a) of
this section and each extension report required by paragraph (c) of this
section must be accompanied by the fee prescribed in 381.404 of this
chapter or by a petition for waiver pursuant to 381.106 of this
chapter.
(44 FR 12409, Mar. 7, 1979, as amended at 44 FR 20078, Apr. 4, 1979;
Order 394, 49 FR 35365, Sept. 7, 1984)
18 CFR 284.148 Subpart E -- Assignment of Contractual Rights to Receive Surplus Natural Gas
18 CFR 284.161 Applicability.
This subpart implements section 312 of the NGPA and applies to
assignment by any intrastate pipeline to any interstate pipeline or
local distribution company of its contractual right to receive surplus
natural gas at any first sale.
18 CFR 284.162 General rule.
Except as provided in 284.163, no assignment pursuant to this
subpart may take place unless the Commission authorizes, by order, an
application for assignment filed in accordance with 284.165(a) upon a
determination that the assignment is consistent with the NGPA and this
subpart and is necessary or appropriate in the public interest.
18 CFR 284.163 Special rule.
An intrastate pipeline is authorized to assign, without compensation,
to any interstate pipeline or local distribution company all or any
portion of its contractual right to receive surplus natural gas at any
first sale, without prior approval of the Commission, if:
(a) Surplus determination. The appropriate state regulatory agency
has determined that the natural gas to be assigned exceeds the then
current demands on the assigning intrastate pipeline for natural gas;
(b) Price. The price per MMBtu for the natural gas delivered in any
month under the contract to be assigned does not and will not exceed an
amount equal to the maximum lawful price per MMBtu for new natural gas
as prescribed in Table I in 271.101(a); and
(c) Reports. The reports required under 284.4(b) and 284.165(d)
are timely filed.
(d) Filing fees. The reports required under 284.4(b) and
284.165(d) are accompanied by the fee prescribed in 381.404 of this
chapter or by a petition for waiver pursuant to 381.106 of this
chapter.
(44 FR 12409, Mar. 7, 1979, as amended by Order 394, 49 FR 35365,
Sept. 7, 1984)
18 CFR 284.164 Terms and conditions.
(a) General terms and conditions. Upon authorization by the
Commission of an application for assignment, filed in accordance with
284.165(a) or in the case of compliance with 284.163, an intrastate
pipeline may assign, without compensation, to any interstate pipeline or
local distribution company all or any portion of its contractual right
to receive surplus natural gas at any first sale. Rates charged for any
gathering, treatment, processing, transportation, delivery or similar
service (including storage service) performed in connection with an
assignment authorized under this subpart shall be computed in accordance
with subpart C of this part.
(b) Termination. Upon receipt and review of reports required under
284.165(d) for assignments authorized without prior Commission approval,
the Commission reserves the right, by order, to terminate the
authorization of the assignment if it determines such termination is
required in the public interest.
18 CFR 284.165 Filing requirements.
(a) Contents. Pursuant to 284.162, an application for authorization
of an assignment shall be filed by the intrastate pipeline, under oath,
with the Commission, and the appropriate state regulatory agency, and
shall set forth the following information:
(1) A description of the proposed assignment agreement, including:
(i) The identity of the parties;
(ii) The estimated quantities of natural gas, on a total and maximum
daily basis;
(iii) The price per MMBtu applicable to the quantities to be
delivered pursuant to the assignment and any other terms of the
assignment relating to price; and
(iv) The point of delivery;
(2) A copy of the contract which covers the natural gas being
assigned as surplus natural gas and any ancillary agreements;
(3) Evidence that the appropriate state regulatory agency has
determined that the natural gas to be assigned exceeds the then current
natural gas demands of the assigning intrastate pipeline.
(4) An attestation that the particular supplies of natural gas were
not committed or dedicated to interstate commerce on November 8, 1978;
and
(5) The computation of any rates to be charged pursuant to subpart C
of this part for any gathering, treatment, processing, transportation,
delivery or similar service (including storage service) to be performed
by the intrastate pipeline under the assignment agreement.
(b) Oath statement -- price. An interstate pipeline or local
distribution company to which an intrastate pipeline would make an
assignment authorized under 284.162 shall file with the Commission a
statement, under oath, signed by a senior official of the company, in
support of the application under paragraph (a) of this section, that to
the best of his knowledge, information and belief the price to be paid
for the natural gas under the assignment (exclusive of any rates to be
charged pursuant to subpart C of this part does not and will not exceed
the maximum lawful price applicable to first sales of such gas under the
NGPA and part 271 of this chapter.
(c) Oath statement -- effect. An interstate pipeline to which an
intrastate pipeline would make an assignment authorized under 284.162
shall, in addition to the statement required under paragraph (a) of this
section, file, under oath, with the Commission a statement in support of
the application under paragraph (a) containing the following:
(1) The extent of curtailment, if any, anticipated to occur in the
period in which the natural gas is to be delivered pursuant to the
assignment;
(2) The effect which the price of the natural gas is expected to have
on the interstate pipeline's average purchased gas cost in the period in
which the natural gas is to be delivered pursuant to the assignment;
and
(3) The reasons why in the opinion of the interstate pipeline the
assignment should be authorized as necessary or appropriate in the
public interest.
(d) Initial full report. Within 60 days of the commencement of
deliveries under an assignment authorized under 284.163 without prior
approval of the Commission, the following information shall be filed,
under oath, with the Commission:
(1) By the intrastate pipeline:
(i) A description of the proposed assignment, including:
(A) The identity of the parties;
(B) The quantities of natural gas delivered and estimated to be
delivered, on a total and maximum daily basis;
(C) The price per MMBtu applicable to quantities delivered and to be
delivered pursuant to the assignment and any other terms of the
assignment relating to price; and
(D) The point of delivery;
(ii) A copy of the contract which covers the natural gas being
assigned as surplus natural gas and any ancillary agreements;
(iii) Evidence that the appropriate state regulatory agency has
determined that the natural gas to be assigned exceeds the then current
demands on such pipeline for natural gas;
(iv) An attestation that the particular supplies of natural gas were
not committed or dedicated to interstate commerce on November 8, 1978;
and
(v) The computation of any rates charged or to be charged pursuant to
subpart C of this part for any gathering, treatment, processing,
transportation, delivery or similar service (including storage service)
performed or to be performed by the intrastate pipeline under the
assignment agreement;
(2) By the interstate pipeline or local distribution company to which
the assignment is made, a statement under oath, signed by a senior
official of the company that to the best of his knowledge, information
and belief the price for natural gas under the assignment (exclusive of
any rates charged or to be charged pursuant to subpart C of this part)
does not and will not exceed the maximum lawful price applicable to
first sales of such gas under the NGPA and part 271 of this chapter.
18 CFR 284.165 Subpart F -- (Reserved)
18 CFR 284.165 Subpart G -- Blanket Certificates Authorizing Certain Transportation by Interstate Pipelines on Behalf of Others and Services by Local Distribution Companies
18 CFR 284.221 General rule; transportation by interstate pipelines on
behalf of others.
(a) Blanket certificate. Any interstate pipeline may apply under
this section for a single blanket certificate authorizing the
transportation of natural gas on behalf of others in accordance with
this subpart. A certificate of public convenience and necessity under
this section is granted pursuant to section 7 of the Natural Gas Act.
(b) Application procedure. (1) An application for a blanket
certificate under this section must be accompanied by the fee prescribed
in part 381 of this chapter or a petition for waiver pursuant to
381.106 of this chapter. On or after October 31, 1989, the application
must be in the manner prescribed in 385.2011 of this chapter and must
include:
(i) The name of the interstate pipeline; and
(ii) A statement by the interstate pipeline that it will comply with
the conditions in paragraph (c) of this section.
(2) Upon receipt of an application under this section, the Commission
will conduct a hearing pursuant to section 7(c) of the Natural Gas Act
and 157.11 of this chapter and, if required by the public convenience
and necessity, will issue to the interstate pipeline a blanket
certificate authorizing such pipeline company to transport natural gas,
as provided under this subpart.
(c) General conditions. Any blanket certificate under this subpart
is subject to the conditions of subpart A of this part.
(d) Pre-grant of abandonment. (1) Except as provided in 284.14(e),
and paragraphs (d)(2) and (d)(3) of this section, abandonment of
transportation services is authorized pursuant to section 7(b) of the
Natural Gas Act upon the expiration of the contractual term or upon
termination of each individual transportation arrangement authorized
under a certificate granted under this section.
(2) Paragraph (d)(1) of this section does not apply if the individual
transportation arrangement is for firm transportation under a contract
with a term of one year or more, and the firm shipper:
(i) Exercises any contractual right to continue such service; or
(ii) Gives notice that it wants to continue its transportation
arrangement and will match the longest term and highest rate for its
firm service, up to the maximum rate under 284.7, offered to the
pipeline during the period established in the pipeline's tariff for
receiving such offers by any other person desiring firm capacity, and
executes a contract matching the terms of any such offer.
(3) Paragraph (d)(1) of this section does not apply where, after
February 13, 1991, and before May 18, 1992, a shipper converted from
sales service to firm transportation service under the provisions of
284.10 or under a separate agreement (to the extent of conversion of
pre-existing sales volumes).
(e) Availability of regular certificates. This subpart does not
preclude an interstate pipeline from applying for an individual
certificate of public convenience and necessity for any particular
transportation service.
(f) Cross references. (1) Any local distribution company served by
an interstate pipeline may apply for a blanket certificate to perform
certain services under 284.224 of this chapter.
(2) Any interstate pipeline may apply under subpart F of part 157 of
this chapter for a blanket certificate to construct or acquire and
operate certain natural gas facilities that are necessary to provide
transportation under 284.222 or 284.223.
(3) Section 157.208 of this chapter provides automatic authorization
for the construction, acquisition, operation, and miscellaneous
rearrangement of certain eligible facilities, as defined in 157.202 of
this chapter, subject to limits specified in 157.208(d) of this chapter
and 284.11.
(4) Authorization for sales taps is subject to the prior notice
procedures under 157.211(b) and 157.205.
(g) Flexible receipt point authority -- (1) An interstate pipeline
authorized to transport gas under a certificate granted under this
section may, at the request of the shipper and without prior notice:
(i) Reduce or discontinue receipts of natural gas at a particular
receipt point from a supplier; and
(ii) Commence or increase receipts at a particular receipt point from
that supplier or any other supplier.
(2) The total natural gas volumes received by the interstate pipeline
following any such reassignment under this paragraph must not exceed the
total volume of natural gas that the interstate pipeline may transport
on behalf of the shipper under a certificate granted under this section.
(3) The receipt points to which natural gas volumes may be reassigned
under this paragraph include eligible facilities under 157.208 which
are authorized to be constructed and operated pursuant to a certificate
issued under subpart F of part 157 of this chapter.
(h) Flexible delivery point authority -- (1) An interstate pipeline
authorized to transport gas under a certificate issued pursuant to this
section may at the request of the shipper and without prior notice:
(i) Reduce or discontinue deliveries of natural gas to a particular
delivery point; and
(ii) Commence or increase deliveries at a particular delivery point.
(2) The total natural gas volumes delivered by the interstate
pipeline following any such reassignment must not exceed the total
amount of natural gas that the interstate pipeline is authorized under a
certificate issued pursuant to this section to transport on behalf of
the shipper.
(3) The delivery points to which natural gas volumes may be
reassigned under this paragraph include facilities authorized to be
constructed and operated only under 157.211 and 157.212 and the prior
notice conditions of 157.205 of this chapter.
(Order 436, 50 FR 42496, Oct. 18, 1985, as amended by Order 433-A, 51
FR 43607, Dec. 3, 1986; 53 FR 15031, Apr. 27, 1988; 53 FR 49653, Dec.
9, 1988; Order 636, 57 FR 13317, Apr. 16, 1992; Order 636-A, 57 FR
36217, Aug. 12, 1992)
Editorial Note: At 56 FR 6964, Feb. 21, 1991, 284.221 was amended
by suspending in part paragraph (d), effective February 13, 1991.
18 CFR 284.222 Transportation by interstate pipelines on behalf of
other interstate pipelines.
An interstate pipeline issued a certificate under 284.221 may
transport natural gas on behalf of another interstate pipeline subject
to the same terms and conditions, rates and charges, and reporting
requirements as apply to transactions authorized under subpart B of this
part.
(Order 436, 50 FR 42497, Oct. 18, 1985)
18 CFR 284.223 Transportation by interstate pipelines on behalf of
shippers other than interstate pipelines.
(a) Subject to the provisions of this subpart and the conditions of
Subpart A of this part, any interstate pipeline issued a certificate
under 284.221 is authorized, without prior notice to or approval by the
Commission, to transport natural gas for any duration for any shipper
for any end-use by that shipper or any other person.
(b) Fees. When filed with the Commission, each initial report
required by paragraph (f)(1) of this section, other than an initial
report on a transaction authorized pursuant to paragraph (h) of this
section, must be accompanied by the fee set forth in 381.404 of this
chapter, or a petition for waiver pursuant to 381.106 of this chapter.
(c) Reporting form. Each initial report filed under paragraph (f)(1)
of this section and each subsequent report filed under paragraph (f)(2)
of this section must utilize FERC Form No. 549-ST.
(d) Reporting requirements -- (1) Initial full report. Within thirty
days after commencing transportation (except storage) authorized by
paragraph (a) or (h) of this section, an interstate must file with the
Commission an initial full report, signed under oath by a senior
official of the company, consisting of an original and five conformed
copies containing a description of the transportation service,
including:
(i) The identities of the parties;
(ii) The dates of commencement and projected termination of the
service;
(iii) The estimated total and maximum daily quantities of natural gas
to be transported by the interstate pipeline;
(iv) The points between which the natural gas is to be transported by
the interstate pipeline;
(v) The location (i.e., state) of the original source and the
location (i.e., state) of the ultimate delivery point of the gas; and
(vi) If such transportation is provided to a customer that is located
in the service area of a local distribution company and the interstate
pipeline will not be delivering the customer's gas to that local
distribution company, a statement that the interstate pipeline notified
the local distribution company and the local distribution company's
appropriate regulatory agency in writing of the proposed transportation
prior to commencement.
(2) Subsequent reports. (i) An interstate pipeline that files an
initial report under paragraph (d)(1) of this section must amend that
report to reflect any material change in the pertinent transportation
arrangement.
(ii) Any changes in the initial report required by this paragraph
must be filed with the Commission within thirty days of the related
changed circumstances, and must be signed under oath by a senior
official of the company, and consist of an original and five conformed
copies.
(3) Annual report. Not later than March 1 of each year, each
interstate pipeline must file with the Commission an annual report that
contains, for each docketed transportation service (except storage)
provided during the preceding calendar year under authority of this
section, the following information:
(i) The docket number assigned to the transaction;
(ii) Total volumes transported for the transaction; and
(iii) Total revenues received for the transaction.
(4) Notification of termination. Not later than 30 days after the
termination of any transportation arrangement (except storage) under
this section, the interstate pipeline company must file with the
Commission an original and five conformed copies of a statement
including the following information:
(i) The docket number assigned to the transaction and the date the
transaction was terminated;
(ii) The total volumes transported under the arrangement;
(iii) The total revenues received; and
(iv) A statement certifying that the service was provided under the
terms and conditions previously reported in this docket.
(5) Semi-annual storage reports. Within 30 days of the end of each
complete storage injection and withdrawal season, the interstate
pipeline shall file with the Commission a report of storage activity
provided under the authority of this section. The report must be signed
under oath by a senior official, consist of an original and five
conformed copies, and contain a summary of storage injection and
withdrawal activities to include the following:
(i) The identity of each customer injecting gas into storage and/or
withdrawing gas from storage, identifying any affiliation with the
interstate pipeline;
(ii) The rate schedule under which the storage injection or
withdrawal service was performed;
(iii) The maximum storage quantity and maximum daily withdrawal
quantity applicable to each storage customer;
(iv) For each storage customer, the volume of gas (in dekatherms)
injected into and/or withdrawn from storage during the period;
(v) The unit charge and total revenues received during the
injection/withdrawal period from each storage customer, noting the
extent of any discounts permitted during the period; and
(vi) The related docket numbers in which the interstate pipeline
reported storage related injection/withdrawal transportation services.
(e) Transitional rule for transportation arrangements (1) In the case
of transportation authorized under 157.209(a)(1) which commenced on or
before October 9, 1985, such transportation is deemed to be authorized
under this section for the full term originally certificated subject to
the provisions of 284.7 of this chapter. In all other respects, the
terms and conditions existing prior to November 1, 1985, shall continue
for this period.
(2) Except as provided in paragraph (3) of this section, a
transportation service authorized under 157.209(e) prior to November 1,
1985, is authorized under this section for its full term if:
(i) The interstate pipeline company files before November 1, 1985, a
statement of notification that it will, beginning November 1, 1985,
comply with 284.8(b) and 284.9(b) and 284.7; and
(ii) The existing transportation service was --
(A) Subject to the notice and protest procedures of 157.205 and the
application was not protested or any protest was withdrawn; or
(B) Authorized on a self-implementing basis pursuant to
157.209(e)(1) for 120 days, and time remains in that 120-day term past
October 31, 1985.
(3) Authorization for transportation service under paragraph (g)(2)
of this section;
(i) Ceases at 11:59 p.m. December 16, 1985, unless the pipeline files
for a blanket certificate under 284.221 before that time; and
(ii) Is subject to compliance with the requirements of 284.8(b), or
284.9(b), as appropriate and 284.7.
(4) Effective November 1, 1985, the reporting requirements of
284.223(f) apply to all transportation authorized under this section
which commenced either prior to, or subsequent to, November 1, 1985.
(f)(1) An interstate pipeline issued a certificate under 284.221 may
transport gas under this section for any shipper in accordance with the
terms and provisions of service agreements in effect on August 2, 1990
for transportation service under 284.102 of subpart B of this part,
subject to the following conditions:
(i) Shippers whose transportation services are converted under this
section shall retain their same respective places in the pipeline's
transportation queues following conversion; and
(ii) Conversions under this section must be made prior to November 1,
1990.
(2) An interstate pipeline's FERC tariff provisions are waived to the
extent they would prevent shippers from retaining their same respective
places in the pipeline's transportation queues following conversion
under this section.
(Order 436, 50 FR 42497, Oct. 18, 1985; 50 FR 45908, Nov. 5, 1985,
as amended at 50 FR 52276, Dec. 23, 1985; Order 458, 51 FR 44284, Dec.
9, 1986; Order 526, 55 FR 33011, Aug. 13, 1990; Order 526-A, 55 FR
40830, Oct. 5, 1990; Order 537, 56 FR 50245, Oct. 4, 1991; Order 636,
57 FR 13318, Apr. 16, 1992)
18 CFR 284.224 Certain transportation, sales, and assignments by local
distribution companies.
(a) Applicability. This section applies to local distribution
companies served by interstate pipelines, including persons who are not
subject to the jurisdiction of the Commission, by reason of section 1(c)
of the Natural Gas Act.
(b) Blanket certificate -- (1) Any local distribution company served
by an interstate pipeline or any Hinshaw pipeline may apply for a
blanket certificate under this section.
(2) Upon application for a certificate under this section, a hearing
will be conducted under section 7(c) of the Natural Gas Act, 157.11 of
this chapter, and subpart H of part 385 of this chapter.
(3) The Commission will grant a blanket certificate to such local
distribution company or Hinshaw pipeline under this section, if required
by the present or future public convenience and necessity. Such
certificate will authorize the local distribution company to engage in
the sale, transportation, or assignment of natural gas that is subject
to the Commission's jurisdiction under the Natural Gas Act, to the same
extent that and in the same manner that intrastate pipelines are
authorized to engage in such activities by subparts C, D, and E of this
part, except as otherwise provided in paragraph (e)(2) of this section.
(c) Application procedure. Applications for blanket certificates
must be accompanied by the fee prescribed in part 381 of this chapter or
a petition for waiver pursuant to 381.106 of this chapter and shall
state:
(1) The exact legal name of applicant; its principal place of
business; whether an individual, partnership, corporation or otherwise;
the state under the laws of which it is organized or authorized; the
agency having jurisdiction over rates and tariffs; and the name, title,
and mailing address of the person or persons to whom communications
concerning the application are to be addressed;
(2) The volumes of natural gas which:
(i) Were received during the most recent 12-month period by the
applicant within or at the boundary of a state, and
(ii) Were exempt from the Natural Gas Act jurisdiction of the
Commission by reason of section 1(c) of the Natural Gas Act, if any;
(3) The total volume of natural gas received by the applicant from
all sources during the same time period;
(4) Citation to all currently valid declarations of exemption issued
by the Commission under section 1(c) of the Natural Gas Act if any;
(5) A statement that the applicant will comply with the conditions in
paragraph (e) of this section;
(6) A form of notice suitable for publication in the Federal
Register, as contemplated by 157.9 of this chapter, which will briefly
summarize the facts contained in the application in such way as to
acquaint the public with its scope and purpose; and
(7) A statement of the methodology to be used in calculating rates
for services to be rendered, setting forth any elections under 284.123
or paragraph (e)(2) of this section and a sample calculation employing
the methodology using current data. If a rate election is made under
paragraph (e)(2) of this section, this statement shall contain the
following items (reflecting the 12-month period used to justify costs in
the most recently approved rate case conducted by an appropriate state
regulatory agency):
(i) Total operating revenues,
(ii) Purchase gas costs,
(iii) Distribution costs (which include that portion of the common
costs allocated to the distribution function),
(iv) The volume throughput of the system categorized by sales,
transportation and exchange service, and
(v) A study which determines transportation costs on a unit revenue
basis in accordance with paragraph (e)(2) of this section, including any
supporting work papers.
(d) Effect of certificate. (1) Any certificate granted under this
section will authorize the certificate holder to engage in transactions
of the type authorized by subparts C, D, and E of this part.
(2) Acceptance of a certificate or conduct of an activity authorized
thereunder will:
(i) Not impair the continued validity of any exclusion under section
1(c) of the Natural Gas Act which may be applicable to the certificate
holder, and
(ii) Not subject the certificate holder to the Natural Gas Act
jurisdiction to the Commission except to the extent necessary to enforce
the terms and conditions of the certificate.
(e) General conditions. (1) Except as provided in paragraph (e)(2)
of this section, any transaction authorized under a blanket certificate
is subject to the same rates and charges, terms and conditions, and
reporting requirements that apply to a transaction authorized for an
intrastate pipeline under subparts C, D, and E of this part.
(2) Rate election. If the certificate holder does not have any
existing rates on file with the appropriate state regulatory agency for
city-gate service, the certificate holder may make the rate election
specified in 284.123(b)(1) only if:
(i) The certificate holder's existing rates are approved by an
appropriate state regulatory agency,
(ii) The rates and charges for any transportation are computed by
using the portion of the certificate holder weighted average annual unit
revenue (per MMBtu) generated by existing rates which is attributable to
the cost of gathering, treatment, processing, transportation, delivery
or similar service (including storage service), and
(iii) The Commission has approved the method for computing rates and
charges specified in paragraph (e)(2)(ii) of this section.
(3) Volumetric test. The volumes of natural gas sold or assigned
under the blanket certificate may not exceed the volumes obtained from
sources other than interstate supplies.
(4) Filings. Any filings made with the Commission that report
individual transactions shall reference the docket number of the
proceeding in which the blanket certificate was granted.
(5) Tariff filings. (i) The tariff filing requirements of part 154
of this chapter shall not apply to transactions authorized by the
blanket certificate.
(ii) The certificate holder shall file with the Commission a copy of
all contracts applicable to a transaction authorized by the blanket
certificate as a part of the initial full report required by 284.126
and 284.148. The certificate holder shall also file with the Commission
each amendment to such contracts, within 30 days of the execution of the
amendment.
(f) Pregrant of abandonment. Abandonment of transportation services
or sales, pursuant to section 7(b) of the Natural Gas Act, is authorized
upon the expiration of the contractual term of each individual
arrangement authorized by a blanket certificate under this section.
(g) Hinshaw pipeline without blanket certificate. A Hinshaw pipeline
that does not obtain a blanket certificate under this section is not
authorized to sell, assign, or transport natural gas as an intrastate
pipeline actions by subparts C, D, and E of this part.
(h) Definitions. For the purposes of this section:
(1) A Hinshaw pipeline means any person engaged in the transportation
of natural gas which is not subject to the jurisdiction of the
Commission under the Natural Gas Act solely by reason of section 1(c) of
the Natural Gas Act.
(2) Interstate supplies means any natural gas obtained, either
directly or indirectly, from:
(i) The system supplies of an interstate pipeline, or
(ii) Natural gas reserves which were committed or dedicated to
interstate commerce on November 8, 1978.
(45 FR 1875, Jan. 9, 1980, as amended by Order 319, 48 FR 34891, Aug.
1, 1983; 48 FR 35635, Aug. 5, 1983; Order 433, 50 FR 40346, Oct. 3,
1985. Redesignated and amended by Order 436, 50 FR 42497, 42498, Oct.
18, 1985; Order 478, 52 FR 28467, July 30, 1987)
18 CFR 284.225 Transportation by interstate and intrastate pipelines of
gas released under the good faith negotiation procedures.
(a) Applicability. This section applies to any interstate pipeline
that is required to transport natural gas under paragraph (h) of this
section of the good faith negotiation procedures in 270.201 of this
chapter and to any intrastate pipeline that purchased gas immediately
before its release due to termination or abandonment under 270.201 (c),
(e), or (f) of this chapter.
(b) Blanket certificate for interstate pipelines. An interstate
pipeline is granted a blanket certificate of public convenience and
necessity that authorizes firm and interruptible transportation of
natural gas to any existing customer of the interstate pipeline or to
any pipeline to which the interstate pipeline is interconnected, if the
gas is released due to termination or abandonment under 270.201 (c),
(e), or (f) of this chapter.
(c) Blanket certificate for intrastate pipelines. An intrastate
pipeline is granted a blanket limited jurisdiction certificate of public
convenience and necessity that authorizes firm and interruptible
transportation of natural gas, on behalf of any interstate pipeline or
any local distribution company served by an interstate pipeline, to any
existing customer of the intrastate pipeline or to any pipeline to which
the intrastate pipeline is interconnected, if the gas is released due to
termination or abandonment under 270.201 (c), (e), or (f) of this
chapter.
(d) Definition. For purposes of this section, existing customer
means a customer with which the interstate or intrastate pipeline has a
contract for the sale or transportation of gas which is in effect on the
date a written contract is executed to purchase the gas for which
transportation service is available under this section.
(e) Transportation rates for interstate pipelines -- (1)
Transportation service within contract demand. If an interstate
pipeline provides transportation of gas to an existing customer under
this section and, as a result, the total volumes of gas sold and
transported to that customer on a firm basis do not exceed existing firm
contract demand by that customer, the interstate pipeline:
(i) Must base its transportation rate for such gas on the rate in a
transportation rate schedule on file with the Commission that conforms
to 284.7 and 284.8(d);
(ii) Must waive any transportation reservation fee to the extent that
a customer pays for facilities associated with such transportation
service through demand charges under its firm sales rate schedule;
(iii) Must credit the volumes of gas transported against any minimum
commodity bill obligation; and
(iv) May recover costs, on an Mcf or MMBtu basis, associated with
standing by to serve a firm sales rate schedule customer that does not
reduce its contract demand, if the interstate pipeline revises its sales
rate schedules on file with the Commission.
(2) Transportation service in excess of contract demand. If an
interstate pipeline provides transportation of gas to an existing
customer under this section and, as a result, the total volumes of gas
sold and transported to that customer exceed existing firm contract
demand to that customer, the transportation rate for such gas must be
the rate in a transportation rate schedule on file with the Commission
that conforms to 284.7 and either 284.8(d) for firm service or
284.9(d) for interruptible service.
(3) Transportation service for other customers. If an interstate
pipeline provides transportation of gas under this section to any
pipeline or customer other than an existing customer on a firm basis,
the transportation rate for such gas must be the rate in a
transportation rate schedule on file with the Commission that conforms
to 284.7 and either 284.8(d) for firm service or 284.9(d) for
interruptible service.
(4) Interim rates. If an interstate pipeline does not have a
transportation rate schedule on file with the Commission that conforms
to 284.7 and either 284.8(d) for firm service or 284.9(d) for
interruptible service, the interstate pipeline must file such a rate
schedule within 60 days after first providing transportation service
under this section. Until such a rate schedule becomes effective, the
interstate pipeline must provide the transportation service using the
rate in one of the interstate pipeline's transportation rate schedules
on file with the Commission which the interstate pipeline determines
covers service comparable to transportation service authorized under
this section.
(f) Transportation rates for intrastate pipelines -- (1) General
rule. Rates and charges for transportation of natural gas by intrastate
pipelines under this section shall be fair and equitable as determined
in accordance with 284.123(b) of this chapter, but the intrastate
pipeline's election under 284.123(b) shall not be subject to the
conditions in 284.8(b) and 284.9(b) of this chapter.
(2) Treatment of revenues. The Commission presumes that all revenues
received by an intrastate pipeline in connection with transportation
authorized under this section and computed in accordance with
284.123(b)(1) of this chapter have been or will be taken into account by
the appropriate state regulatory agency for purposes of establishing
transportation charges by the intrastate pipeline for service to
intrastate customers.
(3) Presumptions. If the intrastate pipeline is charging a rate
computed pursuant to 284.123(b)(1) of this chapter the rate charged is
presumed to be:
(i) Fair and equitable; and
(ii) Not in excess of the rates and charges which interstate
pipelines would be permitted to charge for providing similar
transportation service.
(4) Filing requirements. Within 30 days of commencement of new
service, any intrastate pipeline that engages in transportation
arrangements under this section must file with the Commission a one-time
statement that describes how the pipeline will engage in these
transportation arrangements, including operating conditions, such as
quality standards and financial viability of the shipper. If the
pipeline changes its operations under this subpart, it must amend the
statement and file such amendments not later than 30 days after
commencement of the change in operations.
(g) Reporting requirements. An interstate pipeline that transports
gas under a certificate granted by this section is subject to the
reporting requirements of 284.223(f). An intrastate pipeline that
transports gas under a certificate granted by this section is subject to
the reporting requirements of 284.126.
(h) Terms and conditions of service. (1) The terms and conditions of
service provided under a blanket certificate granted by this section
must conform to the transportation requirements of the shipper, subject
to reasonable operating conditions of the pipeline and its available
pipeline capacity.
(2) An interstate pipeline that transports gas under a certificate
granted by this section and is not otherwise subject to the
non-discriminatory access provisions of 284.8(b) of 284.9(b) is not
required to transport on behalf of others any gas not released due to
termination or abandonment under the good faith negotiation procedures
of 270.201 of this chapter.
(3) If a pipeline that transports gas under a certificate granted by
this section becomes subject to the non-discriminatory access provisions
of 284.8(b) or 284.9(b), its authority and service obligation under
the certificate to transport gas purchased under a contract in effect
before the pipeline becomes subject to those provisions terminates only
when the contract expires or is terminated.
(Order 451-B, 52 FR 21678, June 9, 1987)
18 CFR 284.226 Transportation by interstate and intrastate pipelines
upstream of pipelines releasing gas under the good faith negotiation
procedures.
(a) Applicability. This section applies to any upstream interstate
or intrastate pipeline that is not subject to the non-discriminatory
access provisions of 284.8(b) or 284.9(b) of this chapter and that
provided transportation of gas immediately prior to its release by any
interstate or intrastate pipeline due to termination or abandonment
under the good faith negotiation procedures in 270.201 of this chapter.
Such upstream pipelines were those authorized under any Commission
regulation to transport natural gas, prior to the release of that gas
due to termination or abandonment under 270.201 (c), (e), or (f) of
this chapter, along any line between the wellhead and the pipeline that
purchased the gas immediately before its release.
(b) Blanket certificate. (1) Upstream interstate pipelines are
granted a blanket certificate of public convenience and necessity that
authorizes transportation of natural gas release due to termination or
abandonment under 270.201 (c), (e) or (f) of this chapter on behalf of
any shipper to any interstate pipeline releasing gas under 270.201 of
this chapter, under the same terms and conditions as previously provided
to the releasing pipeline.
(2) Upstream intrastate pipelines are granted a blanket limited
jurisdiction certificate of public convenience and necessity that
authorizes transportation of natural gas released due to termination of
abandonment under 270.201 (c), (e) or (f) of this chapter, on behalf of
any interstate pipeline or local distribution company served by an
interstate pipeline, to any pipeline releasing gas under 270.201 of
this chapter, under the same terms and conditions as previously provided
to the releasing pipeline.
(c) Transportation rates. The rates charged by such third-party,
upstream pipelines for transportation under this section shall be
identical to the rates charged under any pre-existing transportation
authorization for the same service previously provided to the releasing
pipeline.
(d) Reporting requirements. An interstate pipeline that transports
gas under the certificate granted by this section is subject to the
reporting requirement of 284.223(f). An intrastate pipeline that
transports gas under the certificate granted by this section is subject
to the reporting requirements of 284.126.
(Order 451-B, 52 FR 21679, June 9, 1987)
18 CFR 284.227 Certain transportation by intrastate pipelines.
(a) Blanket certificate. A blanket certificate shall issue under
this section to any intrastate pipeline that receives natural gas
produced in adjacent Federal waters or onshore or offshore in an
adjacent state, provided that:
(1) The gas must be received by the intrastate pipeline from a
gatherer or other intrastate pipeline;
(2) The intrastate pipeline delivers the gas in the intrastate
pipeline's state of operation to an end user or another intrastate
pipeline; and
(3) The gas ultimately used by an end user in the same state.
(b) Effective date. If an intrastate pipeline is providing a
transportation service described in paragraph (a) of this section as of
February 1, 1992, and the service is not a qualifying service under
284.122 of subpart C of this part, a blanket certificate shall issue
under paragraph (a) of this section and become effective as of February
1, 1992. If an intrastate pipeline is not providing a transportation
service described in paragraph (a) of this section as of February 1,
1992 the blanket certificate shall issue and become effective on the
date that the intrastate pipeline commences such a service that is not a
qualifying service under 284.122 of subpart C of this part.
(c) Acceptance of certificate. An intrastate pipeline shall be
deemed to have accepted a blanket certificate under this section if it
continues after February 1, 1992, a service described in paragraph (a)
of this section that is not a qualifying service under 284.122 of
subpart C or commences such a service after November 4, 1991.
(d) Conversion report. The first report filed pursuant to 284.126
of subpart C by an intrastate pipeline for a service authorized under
this section shall state that the service is being provided under this
section. If service under this section is an extension of service
originally commenced under subpart C of this part, the first required
report shall be the subsequent report pursuant to 284.126(b) of subpart
C, which shall identify the ST docket number in which the initial report
for the service was filed when the service initially commenced under
subpart C.
(e) Terms and conditions. An intrastate pipeline's blanket
certificate transportation authority under this section is subject to
its compliance with all terms and conditions of subpart C of this part,
except that service under this section does not have to be on behalf of
an interstate pipeline or local distribution company served by an
interstate pipeline.
(f) Pregrant of abandonment. Abandonment of transportation services,
pursuant to section 7(b) of the Natural Gas Act, is authorized upon the
expiration of the contractual term of each individual arrangement
authorized by a blanket certificate under this section.
(g) Effect of certificate. Acceptance of a certificate issued under
this section or conduct of activity authorized under this section will
not subject the certificate holder to the Natural Gas Act jurisdiction
of the Commission except to the extent necessary to enforce the terms
and conditions of the certificate.
(Order 537, 56 FR 50246, Oct. 4, 1991, as amended by Order 544, 57 FR
46501, Oct. 9, 1992)
18 CFR 284.227 Subpart H -- Assignment of Capacity on Interstate
Pipelines
Source: Order 636, 57 FR 13318, Apr. 16, 1992, unless otherwise
noted.
18 CFR 284.241 Applicability.
This subpart applies to any interstate pipeline that offers
transportation service under subpart B or G of this part.
18 CFR 284.242 Assignment of firm capacity on upstream pipelines.
An interstate pipeline that offers transportation service on a firm
basis under subpart B or G of this part must offer without undue
discrimination to assign to its firm shippers its firm transportation
capacity, including contract storage, on all upstream pipelines, whether
the firm capacity is authorized under part 284 or part 157. An upstream
pipeline is authorized and required to permit a downstream pipeline to
assign its firm capacity to the downstream pipeline's firm shippers.
(Order 636, 57 FR 13318, Apr. 16, 1992, as amended by Order 636-A, 57
FR 36217, Aug. 12, 1992)
18 CFR 284.243 Release of firm capacity on interstate pipelines.
(a) An interstate pipeline that offers transportation service on a
firm basis under subpart B or G of this part must include in its tariff
a mechanism for firm shippers to release firm capacity to the pipeline
for resale by the pipeline on a firm basis under this section.
(b) Firm shippers must be permitted to release their capacity, in
whole or in part, on a permanent or short-term basis, without
restriction on the terms or conditions of the release. A firm shipper
may arrange for a replacement shipper to obtain its released capacity
from the pipeline. A replacement shipper is any shipper that obtains
released capacity.
(c) Except as provided in paragraph (h) of this section, a firm
shipper that wants to release any or all of its firm capacity must
notify the pipeline of the terms and conditions under which the shipper
will release its capacity. The firm shipper must also notify the
pipeline of any replacement shipper designated to obtain the released
capacity under the terms and conditions specified by the firm shipper.
(d) The pipeline must provide notice of offers to release or to
purchase capacity, the terms and conditions of such offers, and the name
of any replacement shipper designated in paragraph (b) of this section,
on an electronic bulletin board, for a reasonable period.
(e) The pipeline must allocate released capacity to the person
offering the highest rate (not over the maximum rate) and offering to
meet any other terms and conditions of the release. If more than one
person offers the highest rate and meets the terms and conditions of the
release, the released capacity may be allocated on a basis provided in
the pipeline's tariff, provided however, if the replacement shipper
designated in paragraph (b) of this section offers the highest rate, the
capacity must be allocated to the designated replacement shipper.
(f) Unless otherwise agreed by the pipeline, the contract of the
shipper releasing capacity will remain in full force and effect, with
the net proceeds from any resale to a replacement shipper credited to
the releasing shipper's reservation charge.
(g) To the extent necessary, a firm shipper on an interstate pipeline
that offers transportation service on a firm basis under subpart B or G
of this part is granted a limited-jurisdiction blanket certificate of
public convenience and necessity pursuant to section 7 of the Natural
Gas Act solely for the purpose of releasing firm capacity pursuant to
this section.
(h)(1) A release of capacity by a firm shipper to a replacement
shipper for any period of less than one calendar month need not comply
with the notification and bidding requirements of paragraphs (c) through
(e) of this section. A release under this paragraph may not exceed the
maximum rate. Notice of a firm release under this paragraph must be
provided on the pipeline's electronic bulletin board as soon as
possible, but not later than forty-eight hours, after the release
transaction commences.
(2) A firm shipper may not rollover, extend, or in any way continue a
release under this paragraph without complying with the requirements of
paragraphs (c) through (e) of this section, and may not re-release to
the same replacement shipper under this paragraph until thirty days
after the first release period has ended.
(Order 636, 57 FR 13318, Apr. 16, 1992, as amended by Order 636-A, 57
FR 36217, Aug. 12, 1992)
18 CFR 284.243 Subpart I -- Emergency Natural Gas Sale, Transportation,
and Exchange Transactions
Source: Order 449, 51 FR 9187, Mar. 18, 1986, unless otherwise
noted.
18 CFR 284.261 Purpose.
This subpart exempts a person who engages in an emergency natural gas
transaction, as defined for purposes of this subpart, in interstate
commerce from the certificate requirements of section 7 of the Natural
Gas Act and from the conditions of 284.7, except as provided in
284.266, and 284.8-284.13 of subpart A of this chapter.
18 CFR 284.262 Definitions.
For purposes of this subpart:
(a)(1) Emergency means, except as provided in paragraph (a)(2):
(i) Any situation in which an actual or expected shortage of gas
supply would require an interstate pipeline company, intrastate
pipeline, local distribution company, or Hinshaw pipeline to curtail
deliveries of gas or provide less than the projected level of service to
any customer, including any situation in which additional supplies are
necessary to maintain levels of natural gas storage inventories
sufficient to ensure a pipeline's projected level of service to any
customer, but not including any situation in which additional supplies
are needed to increase the projected level of service to an existing
customer or to provide service to new customers; or
(ii) A sudden unanticipated loss of natural gas supply or a sudden
unanticipated increase in demand; or
(iii) Any situation in which the participant, in good faith,
determines that immediate action is required or is reasonably
anticipated to be required for protection of life or health or for
maintenance of physical property.
(2) Emergency does not mean any situation under paragraph (a)(1)
resulting solely from a failure by any person to transport natural gas
under subpart B, C or G of this part.
(b) Projected level of service means the level of service projected
level by the company for each customer which the company uses to compile
the total projected level of service that it reports in its FERC Form
No. 16 and additional supplies needed by a customer due solely to a
weather-induced increase in requirements.
(c) Emergency natural gas means natural gas sold, transported, or
exchanged in an emergency natural gas transaction.
(d) Emergency natural gas transaction means the sale, transportation,
or exchange of natural gas (including the construction and operation of
necessary facilities) conducted pursuant to this subpart that is:
(1) Necessary to alleviate an emergency; and
(2) Not anticipated to extend for more than 60 days in duration.
(e) Emergency costs means the amount paid by a recipient of emergency
natural gas and all associated costs, including all transportation
costs.
(f) Participant means any first seller, interstate pipeline,
intrastate pipeline, local distribution company or Hinshaw pipeline that
participates in an emergency natural gas transaction under this subpart.
(g) Recipient means:
(1) In the case of the sale of emergency natural gas, the purchaser
of such gas; or
(2) In the case of a transportation or exchange of emergency natural
gas when there is no sale of emergency natural gas under this subpart,
the participant who receives the gas.
(h) Hinshaw pipeline means a pipeline that is exempt from the Natural
Gas Act jurisdiction of the Commission by reason of section 1(c) of the
Natural Gas Act.
(Order 449, 51 FR 9187, Mar. 18, 1986, as amended by Order 522, 55 FR
12169, Apr. 2, 1990)
18 CFR 284.263 Exemption from section 7 of Natural Gas Act and certain
regulatory conditions.
Any participant that engages in an emergency natural gas transaction
conducted in accordance with this subpart is exempt from the
requirements of section 7 of the Natural Gas Act and the conditions of
284.7, except as provided in 284.266, and from the requirements of
284.8-284.13 of Subpart A of this part. Participation in any emergency
natural gas transaction will not subject any participant to the
jurisdiction of the Commission under section 7 of the Natural Gas Act
except to the extent such transaction is provided for in this subpart.
18 CFR 284.264 Terms and conditions.
(a) General conditions. (1) A participant must make every reasonable
attempt to minimize use of emergency natural gas transactions.
(2) Before deliveries of emergency natural gas commence, a
responsible official of the recipient must provide any participants in
the emergency natural gas transaction sufficient information to enable
the participants to form a good faith belief that an emergency exists or
is imminent.
(3) No participant may engage in an emergency natural gas transaction
if its participation will adversely affect service to its existing
customers.
(4) A participant may not sell emergency natural gas if, during the
term of the sale, it is also purchasing emergency natural gas under this
subpart, except when natural gas is being sold to relieve an emergency
on another, separate segment of the participant's system.
(5) An interstate pipeline, acting in an emergency gas transaction as
a broker or agent on behalf of another participant or any other person,
may not receive compensation for such brokerage or agency service.
(6) A recipient of emergency natural gas that directly benefits from
the service must:
(i) Provide line loss and the fuel volumes required to transport the
emergency natural gas; and
(ii) Pay for the facilities required to be constructed to conduct the
emergency natural gas transaction.
(b) Duration -- (1) Emergency sale or transportation. An emergency
natural gas transaction is limited to 60 consecutive calender days,
except that such transaction may be continued for an additional 60
consecutive days if:
(i) Fifteen days prior to the end of the initial 60-day period, the
recipient of emergency natural gas files a petition that:
(A) Describes fully the continued emergency,
(B) Requests a waiver of the intitial 60-day limitation and
permission for an extension of the transaction for an additional 60
days; and
(ii) Within the 15-day period, the Commission does not, by order,
prohibit continuation of the emergency natural gas transaction for the
additional 60-day period.
(2) Redelivery in emergency exchange. The redelivery of emergency
natural gas received under an exchange arrangement must occur within 180
consecutive days following the termination of deliveries of the
emergency natural gas.
18 CFR 284.265 Cost recovery by interstate pipeline.
(a) Except as provided in paragraph (b), an interstate pipeine that
provides emergency natural gas, whether from its system supply or by
special purchase, must directly assign the emergency gas costs to the
recipient.
(b) If an interstate pipeline cannot identify individual recipients,
the interstate pipeline must roll the emergency gas costs into its
general system supply costs.
18 CFR 284.266 Rates and charges for interstate pipelines.
(a) Transportation rates -- (1) Rate on file. If an interstate
pipeline has on file with the Commission an effective transportation
rate schedule that conforms to 284.7, it must use volumetric rates
based upon fully-allocated costs and adjusted only for time and
distance.
(2) Rate not on file. If an interstate pipeline does not have on
file with the Commission a transportation rate schedule that conforms to
284.7, it may:
(i) Base its rates upon the methodology used in designing rates to
recover the transmission and related storage costs included in one of
its then-effective sales rates schedules; or
(ii) Use the rates contained in one of its transportation rate
schedules on file with the Commission which the interstate pipeline
determines covers service comparable to transportation service
authorized under this subpart.
(b) Sales rates -- (1) Rate on file. An interstate pipeline must
determine its rates for sales of emergency natural gas under this
subpart according to a rate schedule applicable or comparable to this
type of service.
(2) Rate not on file. If no applicable or comparable rate schedule
is on file for this type of service, the interstate pipeline must
determine its rates according to the methodology used in designing its
then effective sales rates, including its current purchased gas cost.
(c) Treatment of revenues. (1) Except as provided in paragraph
(c)(2),
(i) All revenues received by an interstate pipeline for
transportation or, if the interstate pipeline includes the cost of
emergency natural gas in its Purchase Gas Adjustment, for sales
authorized under this subpart in excess of an allowance of one cent per
MMBtu must be credited to Account No. 191 and flowed back to the
interstate pipeline's customers.
(ii) All revenues received by the interstate pipeline for
transportation or, if the interstate pipeline does not include the cost
of emergency natural gas in its Purchased Gas Adjustment, for sales
authorized under this subpart in excess of the sum of (A) the cost of
purchased gas plus (B) an allowance of one cent per MMBtu must be
credited to Account No. 191 and flowed back to the interstate
pipeline's customers.
(iii) If an interstate pipeline's tariff does not provide for
Purchased Gas Rate Adjustments, all revenues received by the interstate
pipeline for transportation authorized under this subpart in excess of
one cent per MMBtu must be flowed back to the interstate pipeline's
customers by credits to current bills.
(2) An interstate pipeline is not required to credit revenues
received for transportation or sales authorized under this subpart:
(i) If representative levels of revenues attributable to
transportation or sales, as applicable, under authority of this subpart
have been credited in arriving at a test period cost-of-service; or
(ii) If representative levels of volumes transported or sold, as
applicable, under authority of this subpart have been included in
billing determinants for the purpose of establishing rates; or
(iii) Which, upon application, the Commission finds to have been
demonstrated as representing the out-of-pocket expenses of the
interstate pipeline in connection with a transaction authorized under
this subpart.
(d) Interstate pipeline costs excluded from rate base. An interstate
pipeline may not include in its jurisdictional rate base any cost
associated with facilities installed and operated in connection with an
emergency natural gas transaction unless a certificate of public
convenience and necessity has been issued authorizing the costs. Absent
a certificate, such facilities may only be used to conduct emergency
natural gas transactions or transactions authorized under section 311 of
the NGPA.
18 CFR 284.267 Intrastate pipeline emergency transportation rates.
General rule. Rates and charges for transportation of emergency gas
by intrastate pipelines authorized under this subpart must be determined
in accordance with 284.123 of this chapter.
18 CFR 284.268 Local distribution company emergency transportation
rates.
(a) Rate on file. A local distribution company that has a rate on
file with an appropriate state regulatory agency for city-gate
transportation services must determine its rates and charges for
transportation of emergency natural gas in accordance with 284.123 of
this chapter.
(b) Rate not on file. A local distribution company that does not
have a rate on file with an appropriate state regulatory agency for
city-gate transportation services must determine its rates and charges
for transportation of emergency natural gas (per unit volume of
emergency natural gas transported) in accordance with 284.224(e)(2)(ii)
of this chapter.
18 CFR 284.269 Intrastate pipeline and local distribution company
emergency sales rates.
An intrastate pipeline or local distribution company must determine
its rates for sales of emergency natural gas under this subpart in
accordance with 284.144.
18 CFR 284.270 Reporting requirements.
(a) Forty-eight hour report for sales transactions. Within 48 hours
after deliveries of emergency natural gas commence, the purchasing
participant must notify the Commission by telegraph or other written
report of the sale, stating, in the following sequences:
(1) That the report is submitted pursuant to 284.270 for an
emergency natural gas transaction;
(2) The date deliveries commenced;
(3) The specific nature of the situation, explained in sufficient
detail to demonstrate how the situation qualifies as an emergency under
284.262 and under the conditions of 284.264, and anticipated duration
of the emergency;
(4) The estimated total amount and average daily amount of emergency
natural gas to be purchased during the term of the transaction;
(5) The purchase price of the emergency natural gas;
(6) The transportation rate; and
(7) The identity of all participants involved in the transaction,
including any customers to whom the emergency natural gas is to be
assigned.
(b) Forty-eight hour report for transportation (excluding exchanges).
Within 48 hours after deliveries commence in an emergency natural gas
transaction which does not involve the sale of emergency natural gas,
the recipient of emergency natural gas shall notify the Commission by
telegram or other written report of the transportation, stating, in the
following sequence:
(1) That the report is submitted pursuant to 284.270 for an
emergency transaction;
(2) The date deliveries commenced;
(3) The specific nature of the situation, explained in sufficient
detail to demonstrate how the situation qualifies as an emergency under
284.262 and under the conditions of 284.264, and anticipated duration
of the emergency;
(4) The estimated total amount and average daily amount of emergency
natural gas to be transported during the term of the transaction;
(5) The transportation rate; and
(6) The identity of all the participants involved in the transaction.
(c) Forty-eight hour report for exchanges. Within 48 hours after an
exchange transaction for emergency natural gas commences, the initial
recipient of the exchange volumes must notify the Commission by telegram
or other written report of the exchange, stating, in the following
sequence:
(1) That the report is for and submitted pursuant to 284.270 for an
emergency transaction;
(2) The date the exchange commenced;
(3) The specific nature of the situation, explained in sufficient
detail to clearly demonstrate how the situation qualifies as an
emergency under 284.262 and under the conditions of 284.264, and
anticipated duration of the emergency;
(4) The estimated total amount and average daily amount of emergency
natural gas to be exchanged during the term of the transaction;
(5) The identity of all participants involved in the transaction;
(6) Whether the exchange is simultaneous or deferred, or any
imbalances in the volumes;
(7) Whether the exchange is on a thermal or volumetric basis; and
(8) The rates or charges, if any, for the exchange service.
(d) Termination report. Within thirty days after the emergency
natural gas transaction ends, the participant that received the
emergency natural gas shall file with the Commission a sworn statement
and two conformed copies thereof, which must include the following
information in the following sequence:
(1) A description of the emergency natural gas transaction, including
sufficient information to clearly demonstrate how the situation
qualifies as an emergency under 284.262 and under the conditions of
284.264; the commencement and termination dates; the date of the
48-hour report, and the method of resolving the emergency;
(2) Any corrections to the 48-hour report information supplied to the
Commission under paragraphs (a) through (c) of this section or a
statement that the information was correct;
(3) The volumes of the emergency natural gas delivered during the
transaction;
(4) The total compensation received by the seller for the emergency
sale;
(5) The total compensation paid for the emergency natural gas
transportation or exchange service, if any;
(6) The methods by which such compensation was derived;
(7) The total volumes of natural gas whose cost was assigned to
specific customers, and the total volumes whose cost was included in
system supply;
(8) The information supplied to any other participant pursuant to
284.264(a)(2); and
(9) A statement that the emergency natural gas transaction was
carried out in accordance with this subpart, and that identifies the
circumstances demonstrating an emergency existed or was imminent so as
to require an emergency natural gas transaction.
18 CFR 284.271 Waiver.
The Commission may, by order, waive the requirements of this subpart
in connection with any emergency natural gas transaction to the extent
required by the public interest.
18 CFR 284.271 Subpart J -- Blanket Certificates Authorizing Certain
Natural Gas Sales by Interstate Pipelines
Source: Order 636, 57 FR 13318, Apr. 16, 1992, unless otherwise
noted.
18 CFR 284.281 Applicability.
This subpart applies to any interstate pipeline that offers
transportation service under subpart B or G of this part.
18 CFR 284.282 Definitions.
(a) Bundled sales service is gas sales service that is not sold
separately from transportation service.
(b) Sales service includes firm or interruptible gas sales.
(c) Unbundled sales service is gas sales service that is sold
separately from transportation service.
(d) Small customer is a customer that purchases gas from a pipeline
under the pipeline's one-part imputed load factor rate schedule on the
effective date of the blanket certificate.
(Order 636, 57 FR 13318, Apr. 16, 1992, as amended by Order 636-A, 57
FR 36218, Aug. 12, 1992)
18 CFR 284.283 Point of unbundling.
A sales service is unbundled when gas is sold at a point before it
enters a mainline system, at an entry point to a mainline system from a
production area, or at an intersection with another pipeline system.
18 CFR 284.284 Blanket certificates for unbundled sales services.
(a) Authorization. An interstate pipeline that offers transportation
service under subpart B or G of this part is granted a blanket
certificate of public convenience and necessity pursuant to section 7 of
the Natural Gas Act authorizing it to provide unbundled firm or
interruptible sales in accordance with the provisions of this section.
(b) Conversion to unbundled firm sales service and firm
transportation service. On the effective date of the pipeline's blanket
certificate for unbundled sales services under paragraph (a) of this
section, firm sales entitlements under any firm sales service agreement
for a bundled sales service are converted to an equivalent amount of
unbundled firm sales service and an equivalent amount of unbundled firm
transportation service, except as adjusted in 284.14 (d) and (e).
(c) Conversion to unbundled interruptible sales service and
interruptible transportation service. On the effective date of the
pipeline's blanket certificate for unbundled sales services under
paragraph (a) of this section, interruptible sales volumes under any
interruptible sales service agreement for a bundled sales service are
converted to an equivalent amount of unbundled sales service and an
equivalent amount of unbundled interruptible transportation service.
(d) A pipeline that provides unbundled sales service under this
section may serve as an agent of the sales customer to arrange for any
pipeline-provided service necessary to deliver gas to the customer.
(e) Small customer cost-based rate. A pipeline that provided bundled
sales service to a small customer before the effective date of the
blanket certificate granted in paragraph (a) of this section is required
to offer a sales service to that customer at a cost-based rate for one
year from the effective date of the certificate. The obligation to sell
at the cost-based rate expires one year after the effective date of the
certificate.
(Order 636, 57 FR 13318, Apr. 16, 1992, as amended by Order 636-A, 57
FR 36218, Aug. 12, 1992)
18 CFR 284.285 Pregrant of abandonment of unbundled sales services.
Abandonment of unbundled sales services is authorized pursuant to
section 7(b) of the Natural Gas Act upon the expiration of the
contractual term or upon termination of each individual sales
arrangement authorized under 284.284.
18 CFR 284.286 Standards of conduct for unbundled sales service.
(a) To the maximum extent practicable, the pipeline must organize its
unbundled sales and transportation operating employees so that they
function independently of each other.
(b) The pipeline must conduct its business to conform to the
requirements set forth in 284.8(b)(2) and 284.9(b)(2) with respect to
the equality of service by not giving shippers of gas sold by the
pipeline any preference over shippers of gas sold by any other merchant
in matters relating to part 284 transportation.
(c) The pipeline must comply with 161.3 (a), (b), (d) and (l) of
this chapter and comply with 161.3 (c), (e), (f), (g), (h), and (i) of
this chapter by considering its unbundled sales operating employees as
an operational unit which is the functional equivalent of a marketing
affiliate.
(d) The pipeline must comply with 250.16 of this chapter by
considering its unbundled sales operating employees as an operational
unit which is the functional equivalent of a marketing affiliate.
(e) A pipeline that provides unbundled sales service under 284.284
must file tariff provisions and procedures as part of its compliance
filing under 284.14 indicating how the pipeline is complying with the
standards of this section.
18 CFR 284.287 Implementation and effective date.
(a) Except as provided in paragraph (b) of this section, a pipeline
that offers transportation under subpart B or G of this part must file
revised tariff sheets to implement the requirements of this subpart J as
part of the compliance filing required under 284.14.
(b) A pipeline that offers transportation under subpart B or G of
this part that is not authorized to make sales for resale as of the date
of its required filing under 284.14 need not file to implement this
subpart J with its filing under 284.14, but prior to offering any sales
service, such a pipeline must file revised tariff sheets to implement
this subpart J.
(c) A blanket certificate issued under 284.284 will be effective on
the effective date (as approved by the Commission) of the tariff sheets
implementing service under that certificate. For a pipeline that is
required to file under 284.14, the tariff sheets implementing service
under the blanket certificate will not be effective until after
Commission approval of the compliance filings required by 284.14(b).
18 CFR 284.288 Reporting requirements.
Interstate pipelines engaging in sales under a certificate granted
under 284.284 must file with the Commission by March 1 of each year, an
annual report for the preceding calendar year describing for each
transaction the identities of the parties, the type of service provided
(firm or interruptible), the total volumes sold, and the total revenues
received. The report must be signed under oath by a senior official of
the company.
Note: This appendix will not appear in the Code of Federal
Regulations. Appendix: Separate Opinion of Commissioner Langdon.
Jerry J. Langdon, Commissioner, concurring in part and dissenting in
part:
This Order represents a watershed for the natural gas industry. It
marks a turning point for parties to permanently leave outmoded and
failed governmental policies behind to face a largely market-driven
regulatory regime. Those who fail to take advantage of this opportunity
to craft market-sensitive solutions to their energy needs will
undoubtedly be left behind. This Order provides a road map to guide all
parties toward a competitive market for natural gas without mandating
which route they should choose.
I fully support this Order as a final major move toward realizing the
promises first set forth in Order No. 436. In the past few years, the
Commission has been criticized for its piecemeal approach to
implementing important policy objectives. This piecemeal approach has
unnecessarily prolonged the transition of the industry by limiting or
obviating competitive choices by individual segments of the industry.
By dealing globally with a number of inter-related issues, the
Commission will allow market forces -- and not regulators -- to begin to
drive the natural gas industry.
I only regret that we did not take two more steps to facilitate the
process:
Provide an additional mechanism to shorten the transition cost
recovery process to allow true market signals to emerge sooner rather
than later, and
Devise an alternative cost recovery mechanism for the non-market
sensitive Great Plains gas.
As to the former I concur; as to the latter, I dissent as discussed
below.
Order No. 636 provides only two mechanisms which act to limit gas
supply realignment costs which may result from restructuring
negotiations: eligibility and prudence. I take seriously the Order No.
636 process for both mechanisms in light of the billions of dollars
that have already been billed to consumers in take-or-pay costs.
The Commission's past record on prudence review has been impotent at
best. But, as a result of the full pass-through of transition costs
allowed by this rule, the Commission has a new, larger prudence role to
play. First, we must ensure that transition costs recovered pursuant to
Order No. 636 are closely limited to contract realignments occurring as
a direct result of implementing this rule. Second, we must determine
that the remaining supply contracts are the product of prudent
market-driven transactions.
In discussions leading up to the Final Order, I strongly favored an
additional, optional mechanism which would have encouraged pipelines to
offer 10 percent absorption of gas supply realignment costs in exchange
for their customers' forgoing their rights to challenge prudence. I
believe this optional approach is reasonable, and moreover, is not
precluded by the rule. I expect that the pipelines and parties may well
use this mechanism as an alternative to lengthy, costly and uncertain
prudence reviews.
As to the Order No. 636 treatment of Great Plains gas, every comma,
word, sentence and paragraph of the Order is internally inconsistent.
Order No. 636's sweeping changes are driven by the overriding need to
make natural gas a competitive commodity. We do this by eliminating
cross-subsidies and by billing away costs associated with the old way of
doing business. Yet in Great Plains, we are timid. I fail to see how
the pass-through of such extraordinary gas costs will ultimately benefit
the consumer, or transmit accurate pricing signals.
I understand the public trust responsibility with respect to
recoupment of the public investment in Great Plains and I would support
a proposal to retire that investment through a surcharge on natural gas
transportation. The continued operational feasibility of Great Plains,
however, should be a choice consumers should make by their willingness
to pay the cost of converting coal to gas.
In all other regards, I enthusiastically support the Order. I expect
that it will significantly contribute to improving the health and
efficiencies of the natural gas industry to the benefit of the nation's
consumers.
18 CFR 284.288 Subpart K -- Transportation of Natural Gas on the Outer
Continental Shelf by Interstate Natural Gas Pipelines on Behalf of
Others
Source: Order 509, 53 FR 50938, Dec. 19, 1988, unless otherwise
noted.
18 CFR 284.301 Applicability.
This subpart implements section 5 of the Outer Continental Shelf Land
Act (OCSLA) and applies to any jurisdictional interstate natural gas
pipeline that holds a certificate under section 7 of the Natural Gas Act
(NGA) authorizing the construction and operation of facilities on the
Outer Continental Shelf (OCS).
18 CFR 284.302 Definitions.
For the purposes of this subpart, the term:
(a) Outer Continental Shelf (OCS) has the same meaning as found in
section 2(a) of the OCSLA (43 U.S.C. 1331(a)); and
(b) OCS pipeline means an interstate natural gas pipeline that holds
a certificate under section 7 of the NGA authorizing the construction
and operation of facilities on the OCS, and includes all of the OCS
pipeline's facilities that fall within the scope of the Commission's
jurisdiction under section 7 of the NGA to the full extent that such
facilities are used or necessary to transport natural gas on or across
the OCS between:
(1) Any locations on the OCS (if the pipeline does not have an
interconnection off the OCS), or
(2) The OCS and the first point of interconnection on the shoreward
side of the OCS where the pipeline delivers or receives natural gas to
or from either:
(i) A natural gas conditioning or processing facility, or
(ii) Another pipeline, or
(iii) A distributor or end user of natural gas.
(Order 509, 53 FR 50938, Dec. 19, 1988, as amended at Order 509-A, 54
FR 8313, Feb. 28, 1989)
18 CFR 284.303 OCS blanket certificates.
(a) Every OCS pipeline (as that term is defined in 284.302(b)) is
issued a blanket certificate authorizing the transportation of natural
gas on or across the OCS on behalf of others under Subpart G of this
Part. This certificate becomes effective on the date that the OCS
pipeline's rates under 284.305 become effective. However, if the
Commission does not permit rates filed pursuant to 284.305(b) to become
effective on or before April 1, 1989, the certificate becomes effective
on the date on which the rates filed pursuant to 284.305(b) would have
gone into effect if they had not been suspended.
(b) OCS pipelines must provide open and nondiscriminatory access to
the transportation service provided under paragraph (a) of this section.
(c) The certificate issued under paragraph (a) of this section
provides an OCS pipeline with the authorization to:
(1) Transport natural gas under section 7(c) of the NGA,
(2) Abandon transportation services that are performed under the
blanket certificate, and
(3) Abandon firm transportation services to implement a reallocation
of firm capacity under 284.304(a) and 284.304(c) of this part.
(d) The certificate and abandonment authority conferred by this
section is conditioned upon the OCS pipeline's compliance with
157.20(e) of this chapter.
(e) A blanket certificate issued under this section does not
authorize the construction of new facilities on the OCS.
18 CFR 284.304 Allocation of firm and interruptible capacity on the
OCS.
(a) Open season for firm transportation. Not later than April 1,
1989, all OCS pipeline must poll all of their existing firm shippers to
ascertain whether any of them want to relinquish any or all of their
firm transportation capacity.
(1) If an OCS pipeline has either uncommitted firm transportation
capacity or firm transportation capacity that an existing shipper wants
to relinquish, it must afford all existing and potential shippers an
opportunity to request the available firm capacity.
(2) The OCS pipeline must provide reasonable notice of the open
season.
(3) The open season can be for no less than 10 days and no more than
30 days.
(4)(i) Except as provided in paragraph (a)(4)(iv) below, if the
requests for firm capacity exceed the firm capacity that is available,
the OCS pipeline must allocate to each requesting shipper a pro rata
share of the available firm capacity.
(ii) If the available firm capacity exceeds the requests for such
capacity, and if the available firm capacity includes capacity that one
or more existing shippers wants to relinquish, each shipper
relinquishing capacity must be allowed to satisfy the requests for firm
capacity on a pro rata basis. To the extent that the OCS pipeline
itself has uncommitted firm capacity available, it may assign that
uncommitted capacity to the new shipper(s) before reallocating the
capacity of existing shippers.
(iii) In reallocating firm capacity under paragraphs (a)(4)(i) or
(a)(4)(ii), the OCS pipeline must take into account the capacity
available at the particular receipt and delivery points specified by
both shippers requesting firm capacity and the shippers voluntarily
relinquishing firm capacity.
(iv) If an OCS pipeline already has a list of potential shippers who
want firm capacity, and if that list was compiled in a nondiscriminatory
manner pursuant to the conditions of an order issuing a Part 284 blanket
certificate or pursuant to the provisions of a tariff filed to implement
Part 284 requirements, the pipeline shall accord priority to those
potential firm shippers at the open season.
(b) Open season for interruptible capacity. (1) No later than April
1, 1989, all OCS pipelines must commence an open season for
interruptible transportation.
(2) The OCS pipeline must provide reasonable notice of the open
season.
(3) The open season can be for no less than 10 days and no more than
30 days.
(4) The requirements of paragraph (b) of this section do not apply to
any OCS pipeline that has accepted a blanket transportation certificate
under Subpart G of this part prior to February 17, 1989.
(5) In establishing an initial priority for interruptible
transportation, OCS pipelines shall give priority to transportation
currently (as of February 17, 1989) authorized under existing individual
certificates (provided that such transportation will be performed at
transportation rates no lower than the transportation rates paid or to
be paid by other interruptible shippers).
(c) Voluntary reallocation of firm capacity. (1) If an OCS pipeline
receives a request for firm transportation at any time after it has
conducted the open season described in paragraph (a) of this section, it
must, within 10 days of receiving the request, provide the requesting
shipper with a list of all firm shippers under contract with the
pipeline.
(2) If the requesting shipper finds an existing firm shipper that
wants to voluntarily relinquish all or a portion of its firm capacity,
the OCS pipeline must reallocate that firm capacity. In the event that
more than one shipper wants to acquire that firm capacity, the
reallocation may be conducted on either a first-come, first-served
basis, a pro rata basis, or any other nondiscriminatory method that is
consistent with the OCS pipeline's transportation rate schedule on file
with the Commission. If the OCS pipeline has uncommitted firm capacity
available, it may assign part or all of that capacity before
reallocating the capacity of existing shippers.
(3) The blanket certificate issued under 284.303(a) provides an OCS
pipeline with the authority under section 7(b) of the NGA to abandon
service with respect to the shipper voluntarily relinquishing firm
capacity, even if the service was authorized prior to the issuance of
the blanket certificate under 284.303(a).
(Order 509, 58 FR 50938, Dec. 19, 1988, as amended at Order 509-A, 54
FR 8313, Feb. 28, 1989)
18 CFR 284.305 Transportation rates.
(a) Except to the extent authorized by paragraph (d)(2), the
transportation rate for transportaton of gas on the OCS by an OCS
pipeline must be the rate in a transportation rate schedule on file with
the Commission that conforms to 284.7, and to either 284.8(d) for firm
service or to 284.9(d) for interruptible service.
(b) If an OCS pipeline does not have a transportation rate schedule
on file with the Commission that conforms to 284.7, to 284.8(d) for
firm service and to 284.9(d) for interruptible service, the OCS
pipeline must file conforming rate schedules by March 1, 1989, to be
effective no later than April 1, 1989. The OCS pipeline must use it
current rates until the Commission permits the rates filed pursuant to
this paragraph to become effective.
(c) The rate schedules filed by a pipeline under paragraph (b) of
this section must be supported by an annual cost and revenue study in
the form required by 154.303(e) of this chapter. If a pipeline has a
pending rate proceeding under 154.63, 154.38 or 154.303(e) of this
chapter, it does not have to submit an annual cost and revenue study and
may use the base period data from the proceeding so long as the base
period ended within 12 months of the filing of the rates required in
paragraph (b) of this section.
(d)(1) Except as provided in paragraph (d)(2) of this section, the
rates filed under paragraph (b) of this section apply to all
transportation services offered by an OCS pipeline.
(2) An OCS pipeline may continue to use its current rates to perform
transportation pursuant to certificates other than Part 284 blanket
transportation certificates. An OCS pipeline that elects to use its
current rates for that transportation after April 1, 1989, must file, no
later than March 1, 1989, a notification to that effect plus a statement
explaining why it believes that continued use of those rates would not
be unjust, unreasonable, or unduly discriminatory in light of activities
it performs under the blanket certificate issued by 284.303(a) and the
rates filed to implement that certificate.
(e) By March 1, 1989, to be effective no later than April 1, 1989,
all OCS pipelines must file tariff provisions setting forth the method
by which firm transportation capacity will be reallocated under
284.304(c) in the event that two or more shippers seek to obtain the
firm capacity that one or more shippers offer to relinquish.
(Order 509, 53 FR 50938, Dec. 19, 1988, as amended at Order 509-A, 54
FR 8313, Feb. 28, 1989)
18 CFR 284.305 Subpart L -- Certain Sales for Resale by Non-interstate Pipelines
18 CFR 284.401 Definitions.
Affiliated marketer. For purposes of this subpart, an ''affiliated
marketer'' is a person engaged in the ''marketing'' of natural gas that
is an ''affiliate'' of an interstate pipeline as those terms are defined
in 161.2 of this chapter.
(Order 547, 57 FR 57959, Dec. 8, 1992)
18 CFR 284.402 Blanket marketing certificates.
(a) Authorization. Any person who is not an interstate pipeline is
granted a blanket certificate of public convenience and necessity
pursuant to section 7 of the Natural Gas Act authorizing the certificate
holder to make sales for resale at negotiated rates in interstate
commerce of any category of gas that is subject to the Commission's
Natural Gas Act jurisdiction. A blanket certificate issued under
Subpart L is a certificate of limited jurisdiction which will not
subject the certificate holder to any other regulation under the Natural
Gas Act jurisdiction of the Commission by virtue of transactions under
the certificate.
(b) The authorization granted in paragraph (a) of this section will
become effective on January 7, 1993 except as otherwise provided in
paragraph (c) of this section.
(c)(1) The authorization granted in paragraph (a) of this section
will become effective for an affiliated marketer with respect to
transactions involving affiliated pipelines when:
(i) An affiliated pipeline receives its blanket certificate pursuant
to 284.284,
(ii) A transportation-only affiliated pipeline's compliance filing
under 284.14(b) is approved by the Commission, or
(iii) As of the date of an order by the Commission terminating the
affiliated pipeline's RS proceeding. RS proceedings terminated prior to
the issuance of the final rule are deemed terminated on the effective
date of this rule.
(2) Should a marketer be affiliated with more than one pipeline, the
authorization granted in paragraph (a) of this section will not be
effective for transactions involving other affiliated interstate
pipelines until such other pipelines' meet the criteria set forth in
paragraph (c)(1) of this section. The authorization granted in
paragraph (a) of this section is not extended to affiliates of persons
who transport gas in interstate commerce and who do not have a tariff on
file with the Commission under part 284 of this subchapter with respect
to transactions involving that person.
(d) Abandonment of the sales service authorized in paragraph (a) of
this section is authorized pursuant to section 7(b) of the Natural Gas
Act upon the expiration of the contractual term or upon termination of
each individual sales arrangement.
(Order 547, 57 FR 57959, Dec. 8, 1992)
18 CFR 284.402 PART 286 -- ADMINISTRATIVE PROCEDURES
Sec.
286.101 Application for stay.
286.102 Application for rehearing.
Authority: Administrative Procedure Act, 5 U.S.C. 551 et seq.,
Natural Gas Policy Act of 1978, Pub. L. 95-621, 92 Stat. 3350,
Department of Energy Organization Act, Pub. L. 95-91, E.O. 12009, 42 FR
46267.
18 CFR 286.101 Application for stay.
(a) General rule. Any person who believes that any provision of a
final or interim regulation issued under the Natural Gas Policy Act of
1978 is unlawful as applied to such person may file an application for
stay.
(b) Content of application. The application shall state, clearly and
concisely:
(1) The provision of the regulation, by section, paragraph,
subparagraph and clause, as appropriate, which applicant seeks to have
stayed;
(2) The conditions which the applicant believes require the stay,
including the irreparable injury which the applicant believes will
result if the stay is not granted; and
(3) The factual and legal basis for applicant's contention that the
final or interim regulation is unlawful.
(c) Filing requirements. The application shall be under oath. An
original and three conformed copies shall be filed with the Secretary of
the Commission.
(d) Commission action. The Commission may grant the application, in
whole or in part, by issuing an order specifying the scope of the stay
granted and the effective dates of the stay.
(43 FR 57599, Dec. 8, 1978, as amended at 44 FR 13473, Mar. 12, 1979)
18 CFR 286.102 Application for rehearing.
(a) General rule. Any person aggrieved by any order or regulation or
any amendment to a regulation issued under the NGPA and subject to
judicial review under section 506(a) or (b) thereof shall file a
petition for rehearing within 30 days after the order or regulation is
issued by the Commission or February 3, 1979, whichever is later. There
has not been an exhaustion of administrative remedies until a petition
for rehearing has been filed under this section and the proceeding is
complete by the denial of the request, or if rehearing is granted, an
order affirming, modifying or revoking the challenged order or
regulation is issued.
(b) Specifications of error. The application for rehearing shall
state clearly and concisely with respect to the challenged order or
regulation:
(1) The provision of the order or the regulation, by section, and
where appropriate, by paragraph;
(2) Applicant's interest in the particular provision; and
(3) The facts and legal analysis upon which the request for rehearing
is based.
(c) Procedural requirements. Except as otherwise provided in this
section, the procedures for rehearing in 385.713 of this chapter shall
apply.
(d) Commission action upon the application. (1) The Commission may
grant the request for rehearing, in whole or in part, by issuing an
order specifying the scope of rehearing. If, and to the extent that
rehearing is granted, the Commission may request Staff, applicant or any
other party to file briefs. In every case where rehearing is granted,
the Commission will issue an order affirming, modifying or revoking the
challenged order or regulation.
(2) The Commission may modify the original order or regulation
without further hearing.
(3) Unless the Commission acts upon the application within 30 days
after it is filed, such application shall be considered to have been
denied. If the Commission grants rehearing in part, any part of the
application outside the scope of the order granting rehearing shall be
considered to have been denied.
(44 FR 2383, Jan. 11, 1979, as amended by Order 225, 47 FR 19058, May
3, 1982)
18 CFR 286.102 SUBCHAPTER J -- REGULATIONS UNDER THE POWERPLANT AND INDUSTRIAL FUEL USE ACT OF 1978
18 CFR 286.102 PART 287 -- RULES GENERALLY APPLICABLE TO POWERPLANT AND
INDUSTRIAL FUEL USE
Authority: Department of Energy Organization Act, 42 U.S.C. 7107 et
seq.; Powerplant and Industrial Fuel Use Act of 1978, Pub. L. 95-620.
18 CFR 287.101 Determination of powerplant design capacity.
For the purpose of section 103 of the Powerplant and Industrial Fuel
Use Act of 1978, a powerplant's design capacity shall be determined as
follows:
(a) Steam-electric generating unit. The design capacity of a
steam-electric generating unit shall be maximum generator nameplate
rating measured in kilowatts or, if the nameplate does not have a rating
measured in kilowatts, the product of the generator's kilovolt-amperes
nameplate rating and power factor nameplate rating.
(b) Combustion turbine. The design capacity of a combusition turbine
shall be its nameplate rating measured in kilowatts, adjusted for
peaking service at an ambient temperature of 59 degrees Fahrenheit (15
degrees Celsius) and at the unit's site elevation.
(c) Combined cycle unit. The design capacity of a combined cycle
shall be the sum of its combustion turbine nameplate rating measured in
kilowatts, based on baseload operation adjusted for site elevation, and
the maximum generator nameplate rating measured in kilowatts of the
steam turbine portion of the unit.
(d) Internal combustion engine. The design capacity of an internal
combustion engine shall be the generator's nameplate rating measured in
kilowatts.
(44 FR 38839, July 3, 1979)
18 CFR 287.101 SUBCHAPTER K -- REGULATIONS UNDER THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978
18 CFR 287.101 PART 290 -- COLLECTION OF COST OF SERVICE INFORMATION UNDER SECTION 133 OF THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978
18 CFR 287.101 Subpart A -- Coverage, Compliance and Definitions
Sec.
290.101 Applicability and exemptions.
290.102 Information gathering and filing.
290.103 Time of filing and reporting period.
Appendix A -- Nonexempt Electric Utilities
Authority: 16 U.S.C. 791a-828c, 2601-2645; 42 U.S.C. 7101-7352.
Source: Order 48, 44 FR 58697, Oct. 11, 1979, unless otherwise
noted.
18 CFR 287.101 Subpart A -- Coverage, Compliance and Definitions
18 CFR 290.101 Applicability and exemptions.
(a) Except as provided in paragraph (b), this part shall apply to
each electric utility, in any calendar year, if the total sales of
electric energy by such utility for purposes other than resale exceed
500 million kilowatt-hours during any calendar year beginning after
December 31, 1975, and before the immediately preceding calendar year.
(b) The Commission exempts from compliance with this part any
utility:
(1) Listed by name in Appendix A to this part; or
(2) That has total sales of electric energy for purposes other than
resale of less than 2 billion kilowatt-hours per year.
(Order 353, 48 FR 55449, Dec. 13, 1983, as amended at 49 FR 4939,
Feb. 9, 1984)
18 CFR 290.102 Information gathering and filing.
All nonexempt electric utilities must file the data required by
section 133(a) of the Public Utility Regulatory Policies Act of 1978, 16
U.S.C. 2643, with their state regulatory authorities. All nonexempt,
nonregulated electric utilities shall, to the extent the data are
collected and compiled, make these data publicly available. All
nonexempt electric utilities shall file an affidavit with the Commission
certifying that the requisite state filing was made. All nonexempt,
nonregulated electric utilities shall file an affidavit with the
Commission certifying that the data were made publicly available.
(Order 545, 57 FR 53991, Nov. 16, 1992)
18 CFR 290.103 Time of filing and reporting period.
All nonexempt electric utilities must file with any state regulatory
authority having ratemaking authority for such utilities the information
gathered pursuant to 290.102, and all nonexempt, nonregulated electric
utilities must make such information available to the public as follows:
(a) Biennial filing. Information required to be filed under 290.102
must be filed biennially in even-numbered years on or before June 30 of
that year.
(b) Reporting period. The reporting period is the calendar year
immediately preceding the filing year. Information for previous years
and projected information for future years must be reported on a
calendar year basis.
(c) Alternate reporting period. Use of an alternate reporting period
is permitted as follows:
(1) Except as provided in paragraph (c)(2) of this section, if a
nonexempt electric utility has gathered all of the information specified
in 290.102 and has filed such information, based on a recent 12-month
reporting period, either with its state regulatory authority or
governing authority in connection with a retail rate proceeding, the
nonexempt electric utility may substitute such information for the
equivalent information required by this part in fulfillment of the
biennial filing requirements.
(2) If a nonexempt electric utility not subject to the jurisdiction
of a state regulatory authority maintains accounting records other than
on a calendar year basis, such utility may use such other basis as the
reporting period for purposes of compliance with this part, provided
such reporting period is a 12-month period.
(Public Utility Regulatory Policies Act of 1978, 16 U.S.C.
2601-2645; Energy Supply and Environmental Coordination Act, 15 U.S.C.
791-798; Federal Power Act, as amended, 16 U.S.C. 792-828C; Department
of Energy Organization Act, 42 U.S.C. 7101-7352, E.O. 12009, 42 FR
46267)
(Order 48, 44 FR 58697, Oct. 11, 1979, as amended by Order 353, 48 FR
55449, Dec. 13, 1983; Order 545, 57 FR 53991, Nov. 16, 1992)
18 CFR 290.103 Pt. 290, App. A
18 CFR 290.103 Appendix A -- Nonexempt Electric Utilities
Electric utilities that are not exempt from part 290, as of the date
of publication of the Commission's Order No. 545 are as follows:
Department of Water and Power of the City of Los Angeles, California.
Pacific Gas & Electric Co.
San Diego Gas and Electric Co.
Southern California Edison Co.
Western Area Power Administration.
(Order 545, 57 FR 53991, Nov. 16, 1992)
18 CFR 290.103 PART 292 -- REGULATIONS UNDER SECTIONS 201 AND 210 OF THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978 WITH REGARD TO SMALL POWER PRODUCTION AND COGENERATION
18 CFR 290.103 Subpart A -- General Provisions
Sec.
292.101 Definitions.
18 CFR 290.103 Subpart B -- Qualifying Cogeneration and Small Power
Production Facilities
292.201 Scope.
292.202 Definitions.
292.203 General requirements for qualification.
292.204 Criteria for qualifying small power production facilities.
292.205 Criteria for qualifying cogeneration facilities.
292.206 Ownership criteria.
292.207 Procedures for obtaining qualifying status.
292.208 Special requirements for hydroelectric small power production
facilities located at a new dam or diversion.
292.209 Exceptions from requirements for hydroelectric small power
production facilities located at a new dam or diversion.
292.210 Petition alleging commitment of substantial monetary
resources before October 16, 1986.
292.211 Petition for initial determination on whether a project has a
substantial adverse effect on the environment (AEE petition).
18 CFR 290.103 Subpart C -- Arrangements Between Electric Utilities and
Qualifying Cogeneration and Small Power Production Facilities Under
section 210 of the Public Utility Regulatory Policies Act of 1978
292.301 Scope.
292.302 Availability of electric utility system cost data.
292.303 Electric utility obligations under this subpart.
292.304 Rates for purchases.
292.305 Rates for sales.
292.306 Interconnection costs.
292.307 System emergencies.
292.308 Standards for operating reliability.
18 CFR 290.103 Subpart D -- Implementation
292.401 Implementation of certain reporting requirements.
292.402 Waivers.
18 CFR 290.103 Subpart E -- (Reserved)
18 CFR 290.103 Subpart F -- Exemption of Qualifying Small Power
Production Facilities and Cogeneration Facilities From Certain Federal
and State Laws and Regulations
292.601 Exemption to qualifying facilities from the Federal Power
Act.
292.602 Exemption to qualifying facilities from the Public Utility
Holding Company Act and certain State law and regulation.
Authority: 16 U.S.C. 791a-824r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
18 CFR 290.103 Subpart A -- General Provisions
18 CFR 292.101 Definitions.
(a) General rule. Terms defined in the Public Utility Regulatory
Policies Act of 1978 (PURPA) shall have the same meaning for purposes of
this part as they have under PURPA, unless further defined in this part.
(b) Definitions. The following definitions apply for purposes of
this part.
(1) Qualifying facility means a cogeneration facility or a small
power production facility which is a qualifying facility under Subpart B
of this part of the Commission's regulations.
(2) Purchase means the purchase of electric energy or capacity or
both from a qualifying facility by an electric utility.
(3) Sale means the sale of electric energy or capacity or both by an
electric utility to a qualifying facility.
(4) System emergency means a condition on a utility's system which is
likely to result in imminent significant disruption of service to
customers or is imminently likely to endanger life or property.
(5) Rate means any price, rate, charge, or classification made,
demanded, observed or received with respect to the sale or purchase of
electric energy or capacity, or any rule, regulation, or practice
respecting any such rate, charge, or classification, and any contract
pertaining to the sale or purchase of electric energy or capacity.
(6) Avoided costs means the incremental costs to an electric utility
of electric energy or capacity or both which, but for the purchase from
the qualifying facility or qualifying facilities, such utility would
generate itself or purchase from another source.
(7) Interconnection costs means the reasonable costs of connection,
switching, metering, transmission, distribution, safety provisions and
administrative costs incurred by the electric utility directly related
to the installation and maintenance of the physical facilities necessary
to permit interconnected operations with a qualifying facility, to the
extent such costs are in excess of the corresponding costs which the
electric utility would have incurred if it had not engaged in
interconnected operations, but instead generated an equivalent amount of
electric energy itself or purchased an equivalent amount of electric
energy or capacity from other sources. Interconnection costs do not
include any costs included in the calculation of avoided costs.
(8) Supplementary power means electric energy or capacity supplied by
an electric utility, regularly used by a qualifying facility in addition
to that which the facility generates itself.
(9) Back-up power means electric energy or capacity supplied by an
electric utility to replace energy ordinarily generated by a facility's
own generation equipment during an unscheduled outage of the facility.
(10) Interruptible power means electric energy or capacity supplied
by an electric utility subject to interruption by the electric utility
under specified conditions.
(11) Maintenance power means electric energy or capacity supplied by
an electric utility during scheduled outages of the qualifying facility.
(Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601 et
seq., Energy Supply and Environmental Coordination Act, 15 U.S.C. 791 et
seq. Federal Power Act, 16 U.S.C. 792 et seq., Department of Energy
Organization Act, 42 U.S.C. 7101 et seq., E.O. 12009, 42 FR 46267)
(45 FR 12233, Feb. 25, 1980)
18 CFR 292.101 Subpart B -- Qualifying Cogeneration and Small Power
Production Facilities
Authority: Public Utility Regulatory Policies Act of 1978, (16
U.S.C. 2601, et seq.), Energy Supply and Environmental Coordination Act,
(15 U.S.C. 791 et seq.), Federal Power Act, as amended, (16 U.S.C. 792,
et seq.), Department of Energy Organization Act, (42 U.S.C. 7101 et
seq.), E.O. 12009, 42 FR 46267, Natural Gas Policy Act of 1978, (15
U.S.C. 3301, et seq.).
18 CFR 292.201 Scope.
This subpart applies to the criteria for and manner of becoming a
qualifying small power production facility and a qualifying cogeneration
facility under sections 3(17)(C) and 3(18)(B), respectively, of the
Federal Power Act, as amended by section 201 of the Public Utility
Regulatory Policies Act of 1978 (PURPA).
(45 FR 17972, Mar. 20, 1980)
18 CFR 292.202 Definitions.
For purposes of this subpart:
(a) Biomass means any organic material not derived from fossil fuels;
(b) Waste means by-product materials other than biomass;
(c) Cogeneration facility means equipment used to produce electric
energy and forms of useful thermal energy (such as heat or steam), used
for industrial, commercial, heating, or cooling purposes, through the
sequential use of energy;
(d) Topping-cycle cogeneration facility means a cogeneration facility
in which the energy input to the facility is first used to produce
useful power output, and the reject heat from power production is then
used to provide useful thermal energy;
(e) Bottoming-cycle cogeneration facility means a cogeneration
facility in which the energy input to the system is first applied to a
useful thermal energy process, and the reject heat emerging from the
process is then used for power production;
(f) Supplementary firing means an energy input to the cogeneration
facility used only in the thermal process of a topping-cycle
cogeneration facility, or only in the electric generating process of a
bottoming-cycle cogeneration facility;
(g) Useful power output of a cogeneration facility means the electric
or mechanical energy made available for use, exclusive of any such
energy used in the power production process;
(h) Useful thermal energy output of a topping-cycle cogeneration
facility means the thermal energy made available for use in any
industrial or commercial process, or used in any heating or cooling
application;
(i) Total energy output of a topping-cycle cogeneration facility is
the sum of the useful power output and useful thermal energy output;
(j) Total energy input means the total energy of all forms supplied
from external sources;
(k) Natural gas means either natural gas unmixed, or any mixture of
natural gas and artificial gas;
(l) Oil means crude oil, residual fuel oil, natural gas liquids, or
any refined petroleum products; and
(m) Energy input in the case of energy in the form of natural gas or
oil is to be measured by the lower heating value of the natural gas or
oil.
(n) Electric utility holding company means a holding company, as
defined in section 2(a)(7) of the Public Utility Holding Company Act of
1935, 15 U.S.C. 79b(a)(7) which owns one or more electric utilities, as
defined in section 2(a)(3) of that Act, 15 U.S.C 79b(a)(3), but does not
include any holding company which is exempt by rule or order adopted or
issued pursuant to sections 3(a)(3) or 3(a)(5) of the Public Utility
Holding Company Act of 1935, 15 U.S.C. 79c(a)(3) or 79c(a)(5).
(o) Utility geothermal small power production facility means a small
power production facility which uses geothermal energy as the primary
energy resource and of which more than 50 percent is owned either:
(1) By an electric utility or utilities, electric utility holding
company or companies, or any combination thereof.
(2) By any company 50 percent or more of the outstanding voting
securities of which of which are directly or indirectly owned,
controlled, or held with power to vote by an electric utility, electric
utility holding company, or any combination thereof.
(p) New dam or diversion means a dam or diversion which requires, for
the purposes of installing any hydroelectric power project, any
construction, or enlargement of any impoundment or diversion structure
(other than repairs or reconstruction or the addition of flashboards of
similar adjustable devices);
(q) Substantial adverse effect on the environment means a substantial
alteration in the existing or potential use of, or a loss of, natural
features, existing habitat, recreational uses, water quality, or other
environmental resources. Substantial alteration of particular resource
includes a change in the environment that substantially reduces the
quality of the affected resources; and
(r) Commitment of substantial monetary resources means the
expenditure of, or commitment to expend, at least 50 percent of the
total cost of preparing an application for license or exemption for a
hydroelectric project that is accepted for filing by the Commission
pursuant to 4.32(e) of this chapter. The total cost includes (but is
not limited to) the cost of agency consultation, environmental studies,
and engineering studies conducted pursuant to 4.38 of this chapter, and
the Commission's requirements for filing an application for license
exemption.
(Energy Security Act, Pub. L. 96-294, 94 Stat. 611 (1980) Public
Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy
Supply and Environmental Coordination Act, 15 U.S.C. 791 et seq.,
Federal Power Act, as amended, 16 U.S.C. 792 et seq., Department of
Energy Organization Act, 42 U.S.C. 7101 et seq., E.O. 12009, 42 FR
46267)
(45 FR 17972, Mar. 20, 1980, as amended at 45 FR 33958, May 21, 1980;
45 FR 66789, Oct. 8, 1980; Order 135, 46 FR 19231, Mar. 30, 1981; 46
FR 32239, June 22, 1981; Order 499, 53 FR 27002, July 18, 1988)
18 CFR 292.203 General requirements for qualification.
(a) Small power production facilities. Except as provided in
paragraph (c) of this section, a small power production facility is a
qualifying facility if it:
(1) Meets the maximum size criteria specified in 292.204(a);
(2) Meets the fuel use criteria specified in 292.204(b); and
(3) Meets the ownership criteria specified in 292.206.
(b) Cogeneration facilities. A cogeneration facility, including any
diesel and dual-fuel cogeneration facility, is a qualifying facility if
it:
(1) Meets any applicable operating and efficiency standards specified
in 292.205 (a) and (b); and
(2) Meets the ownership criteria specified in 292.206.
(c) Hydroelectric small power production facilities located at a new
dam or diversion. (1) A hydroelectric small power production facility
that impounds or diverts the water of a natural watercourse by means of
a new dam or diversion (as that term is defined in 292.202(p)) is a
qualifying facility if it meets the requirements of:
(i) Paragraph (a) of this section; and
(ii) Section 292.208.
(2) (Reserved)
(45 FR 17972, Mar. 20, 1980, as amended by Order 70-E, 46 FR 33027,
June 26, 1981; 52 FR 5280, Feb. 20, 1987; 52 FR 9161, Mar. 23, 1987;
Order 478, 52 FR 28467, July 30, 1987; Order 499, 53 FR 27002, July 18,
1988; Order 541, 57 FR 21734, May 22, 1992)
18 CFR 292.204 Criteria for qualifying small power production
facilities.
(a) Size of the facility -- (1) Maximum size. The power production
capacity of the facility for which qualification is sought, together
with the capacity of any other facilities which use the same energy
resource, are owned by the same person, and are located at the same
site, may not exceed 80 megawatts.
(2) Method of calculation. (i) For purposes of this paragraph,
facilities are considered to be located at the same site as the facility
for which qualification is sought if they are located within one mile of
the facility for which qualification is sought and, for hydroelectric
facilities, if they use water from the same impoundment for power
generation.
(ii) For purposes of making the determination in clause (i), the
distance between facilities shall be measured from the electrical
generating equipment of a facility.
(3) Waiver. The Commission may modify the application of paragraph
(a)(2) of this section, for good cause.
(b) Fuel use. (1) (i) The primary energy source of the facility must
be biomass, waste, renewable resources, geothermal resources, or any
combination thereof, and 75 percent or more of the total energy input
must be from these sources.
(ii) Any primary energy source which, on the basis of its energy
content, is 50 percent or more biomass shall be considered biomass.
(2) Use of oil, natural gas, and coal by a facility may not, in the
aggregate, exceed 25 percent of the total energy input of the facility
during any calendar year period.
(Energy Security Act, Pub. L. 96-294, 94 Stat. 611 (1980) Public
Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy
Supply and Environmental Coordination Act, 15, U.S.C. 791, et seq.,
Federal Power Act, as amended, 16 U.S.C. 792 et seq., Department of
Energy Organization Act, 42 U.S.C. 7101, et seq.; E.O. 12009, 42 FR
46267)
(45 FR 17972, Mar. 20, 1980, as amended by Order 135, 46 FR 19231,
Mar. 30, 1981)
18 CFR 292.205 Criteria for qualifying cogeneration facilities.
(a) Operating and efficiency standards for topping-cycle facilities
-- (1) Operating standard. For any topping-cycle cogeneration facility,
the useful thermal energy output of the facility must, during any
calendar year period, be no less than 5 percent of the total energy
output.
(2) Efficiency standard. (i) For any topping-cycle cogeneration
facility for which any of the energy input is natural gas or oil, and
the installation of which began on or after March 13, 1980, the useful
power output of the facility plus one-half the useful thermal energy
output, during any calendar year period, must:
(A) Subject to paragraph (a)(2)(i)(B) of this section be no less than
42.5 percent of the total energy input of natural gas and oil to the
facility; or
(B) If the useful thermal energy output is less than 15 percent of
the total energy output of the facility, be no less than 45 percent of
the total energy input of natural gas and oil to the facility.
(ii) For any topping-cycle cogeneration facility not subject to
paragraph (a)(2)(i) of this section there is no efficiency standard.
(b) Efficiency standards for bottoming-cycle facilities. (1) For any
bottoming-cycle cogeneration facility for which any of the energy input
as supplementary firing is natural gas or oil, and the installation of
which began on or after March 13, 1980, the useful power output of the
facility must, during any calendar year period, be no less than 45
percent of the energy input of natural gas and oil for supplementary
firing.
(2) For any bottoming-cycle cogeneration facility not covered by
paragraph (b)(1) of this section, there is no efficiency standard.
(c) Waiver. The Commission may waive any of the requirements of
paragraphs (a) and (b) of this section upon a showing that the facility
will produce significant energy savings.
(45 FR 17972, Mar. 20, 1980, as amended by Order 478, 52 FR 28467,
July 30, 1987)
18 CFR 292.206 Ownership criteria.
(a) General rule. A cogeneration facility or small power production
facility may not be owned by a person primarily engaged in the
generation or sale of electric power (other than electric power solely
from cogeneration facilities or small power production facilities).
(b) Ownership test. For purposes of this section, a cogeneration or
small power production facility shall be considered to be owned by a
person primarily engaged in the generation or sale of electric power, if
more than 50 percent of the equity interest in the facility is held by
an electric utility or utilities, or by an electric utility holding
company, or companies, or any combination thereof. If a wholly or
partially owned subsidiary of an electric utility or electric utility
holding company has an ownership interest of a facility, the
subsidiary's ownership interest shall be considered as ownership by an
electric utility or electric utility holding company.
(c) Exceptions. For purposes of this section a company shall not be
considered to be an ''electric utility'' company if it:
(1) Is a subsidiary of an electric utility holding company which is
exempt by rule or order adopted or issued pursuant to section 3(a)(3) or
3(a)(5) of the Public Utility Holding Company Act of 1935, 15 U.S.C.
79c(a)(3), 79c(a)(5); or
(2) Is declared not to be an electric utility company by rule or
order of the Securities and Exchange Commission pursuant to section
2(a)(3)(A) of the Public Utility Holding Company Act of 1935, 15 U.S.C.
79b(a)(3)(A).
(45 FR 17972, Mar. 20, 1980, as amended by Order 70-B, 45 FR 52780,
Aug. 8, 1980; Order 70-D, 46 FR 11253, Feb. 6, 1981)
18 CFR 292.207 Procedures for obtaining qualifying status.
(a) Qualification. (1) A small power production facility or
cogeneration facility which meets the criteria for qualification set
forth in 292.203 is a qualifying facility.
(2) The owner or operator of any facility qualifying under this
paragraph shall furnish notice to the Commission providing the
information set forth in paragraphs (b)(2) (i) through (iv) of this
section.
(b) Optional procedure -- (1) Application for Commission
certification. Pursuant to the provisions of this paragraph, the owner
or operator of the facility may file with this Commission an application
for Commission certification that the facility is a qualifying facility.
(2) General contents of application. The application must be
accompanied by the fee prescribed in 381.505 of this chapter and must
contain the following information:
(i) The name and address of the applicant and location of the
facility;
(ii) A brief description of the facility, including a statement
indicating whether such facility is a small power production facility or
a cogeneration facility;
(iii) The primary energy source used or to be used by the facility;
(iv) The power production capacity of the facility; and
(v) The percentage of ownership by any electric utility or by any
electric utility holding company, or by any person owned by either.
(3) Additional application requirements for small power production
facilities. An application by a small power producer for Commission
certification shall contain the following additional information:
(i) The location of the facility in relation to any other small power
production facilities located within one mile of the facility, owned by
the applicant which use the same energy source; and
(ii) Information identifying any planned usage of natural gas, oil or
coal.
(4) Additional application requirements for cogeneration facilities.
An application by a cogenerator for Commission certification shall
contain the following additional information:
(i) A description of the cogeneration system, including whether the
facility is a topping or bottoming cycle and sufficient information to
determine that any applicable requirements under 292.205 will be met;
and
(ii) The date installation of the facility began or will begin.
(5) Commission action. Within 90 days of the filing of an
application, the Commission shall issue an order granting or denying the
application, tolling the time for issuance of an order, or setting the
matter for hearing. Any order denying certification shall identify the
specific requirements which were not met. If no order is issued within
90 days of the filing of the complete application, it shall be deemed to
have been granted.
(6) Notice. (i) Applications for certification filed under this
paragraph shall include a copy of a notice of the request for
certification for publication in the Federal Register. The notice shall
state the applicant's name, the date of the application, and a brief
description of the facility for which qualification is sought. This
description shall include:
(A) A statement indicating whether such facility is a small power
production facility or a cogeneration facility;
(B) The primary energy source used or to be used by the facility;
(C) The power production capacity of the facility; and
(D) The location of the facility.
(ii) The notice shall be in the following form:
(Name of Applicant)
Docket No. QF-
On (date application was filed), (name and address of applicant)
filed with the Federal Energy Regulatory Commission an application to be
certified as a qualifying (small power production) (cogeneration)
facility pursuant to 292.207 of the Commission's rules.
(Brief description of the facility).
Any person desiring to be heard or objecting to the granting of
qualifying status should file a petiton to intervene or protest with the
Federal Energy Regulatory Commission, 825 North Capitol Street, N.E.,
Washington, D.C. 20426, in accordance with 385.209 and 385.214 of this
chapter. All such petitions or protests must be filed within 30 days
after the date of publication of this notice and must be served on the
applicant. Protests will be considered by the Commission in determining
the appropriate action to be taken but will not serve to make
protestants parties to the proceeding. Any person wishing to become a
party must file a petition to intervene. Copies of this filing are on
file with the Commission and are available for public inspection.
(c) Notice requirements for facilities of 500 kW or more. An
electric utility is not required to purchase electric energy from a
facility with a design capacity of 500 kW or more until 90 days after
the facility notifies the utility that it is a qualifying facility, or
90 days after the facility has applied to the Commission under paragraph
(b) of this section.
(d) Revocation of qualifying status. (1) The Commission may revoke
the qualifying status of a qualifying facility which has been certified
under this section if such facility fails to comply with any of the
statements contained in its application for Commission certification.
(2) Prior to undertaking any substantial alteration or modification
of a qualifying facility which has been certified under this section, a
small power producer or cogenerator may apply to the Commission for a
determination that the proposed alteration or modification will not
result in a revocation of qualifying status.
(45 FR 17972, Mar. 20, 1980, as amended by Order 70-A, 45 FR 33603,
May 20, 1980; Order 70-B, 45 FR 52780, Aug. 8, 1980; Order 225, 47 FR
19058, May 3, 1982; Order 435, 50 FR 40358, Oct. 3, 1985; Order 494,
53 FR 15381, Apr. 29, 1988)
18 CFR 292.208 Special requirements for hydroelectric small power
production facilities located at a new dam or diversion.
(a) A hydroelectric small power production facility that impounds or
diverts the water of a natural watercourse by means of a new dam or
diversion (as that term is defined in 292.202(p)) is a qualifying
facility only if it meets the requirements of:
(1) Paragraph (b) of this section;
(2) Section 292.203(c); and
(3) Part 4 of this chapter.
(b) A hydroelectric small power production described in paragraph (a)
is a qualifying facility only if:
(1) The Commission finds, at the time it issues the license or
exemption, that the project will not have a substantial adverse effect
on the environment (as that term is defined in 292.202(q)), including
recreation and water quality;
(2) The Commission finds, at the time the application for the license
or exemption is accepted for filing under 4.32 of this chapter, that
the project is not located on any segment of a natural watercourse
which:
(i) Is included, or designated for potential inclusion in, a State or
National wild and scenic river system; or
(ii) The State has determined, in accordance with applicable State
law, to possess unique natural, recreational, cultural or scenic
attributes which would be adversely affected by hydroelectric
development; and
(3) The project meets the terms and conditions set by the appropriate
fish and wildlife agencies under the same procedures as provided for
under section 30(c) of the Federal Power Act.
(c) For the Commission to make the findings in paragraph (b) of this
section an applicant must:
(1) Comply with the applicable hydroelectric licensing requirements
in Part 4 of this chapter, including:
(i) Completing the pre-filing consultation process under 4.38 of
this chapter, including performing any environmental studies which may
be required under 4.38(b)(2)(i)(D) through (F) of this chapter; and
(ii) Submitting with its application an environmental report that
meets the requirements of 4.41(f) of this chapter, regardless of
project size;
(2) State whether the project is located on any segment of a natural
watercourse which:
(i) Is included in or designated for potential inclusion in:
(A) The National Wild and Scenic River System (28 U.S.C. 1271-1278
(1982)); or
(B) A State wild and scenic river system;
(ii) Crosses an area designated or recommended for designation under
the Wilderness Act (16 U.S.C. 1132) as:
(A) A wilderness area; or
(B) Wilderness study area; or
(iii) The State, either by or pursuant to an act of the State
legislature, has determined to possess unique, natural, recreational,
cultural, or scenic attributes that would be adversely affected by
hydroelectric development.
(d) If the project is located on any segment of a natural watercourse
that meets any of the conditions in paragraph (c)(2) of this section,
the applicant must provide the following information in its application:
(1) The date on which the natural watercourse was protected;
(2) The statutory authority under which the natural watercourse was
protected; and
(3) The Federal or state agency, or political subdivision of the
state, that is in charge of administering the natural watercourse.
(Order 499, 53 FR 27003, July 18, 1988)
18 CFR 292.209 Exceptions from requirements for hydroelectric small
power production facilities located at a new dam or diversion.
(a) The requirements in 292.208(b)(1) through (3) do not apply if:
(1) An application for license or exemption is filed for a project
located at a Government dam, as defined in section 3(10) of the Federal
Power Act, at which non-Federal hydroelectric development is
permissible; or
(2) An application for license or exemption was filed and accepted
before October 16, 1986.
(b) The requirements in 292.208(b) (1) and (3) do not apply if an
application for license or exemption was filed before October 16, 1986,
and is accepted for filing by the Commission before October 16, 1989.
(c) The requirements in 292.208(b)(3) do not apply to an applicant
for license or exemption if:
(1) The applicant files a petition pursuant to 292.210; and
(2) The Commission grants the petition.
(d) Any application covered by paragraphs (a), (b), or (c) of this
section is excepted from the moratorium imposed by section 8(e) of the
Electric Consumers Protection Act of 1986, Pub. L. No. 99-495.
(Order 499, 53 FR 27003, July 18, 1988)
18 CFR 292.210 Petition alleging commitment of substantial monetary
resources before October 16, 1986.
(a) An applicant covered by 292.203(c) whose application for license
or exemption was filed on or after October 16, 1986, but before April
16, 1988, may file a petition for exception from the requirement in
292.208(b)(3) and the moratorium described in 292.203(c)(2). The
petition must show that prior to October 16, 1986, the applicant
committed substantial monetary resources (as that term is defined in
292.202(r)) to the development of the project.
(b) Subject to rebuttal under paragraph (d)(7)(ii) of this section, a
showing of the commitment of substantial monetary resources will be
presumed if the applicant held a preliminary permit for the project and
had completed environmental consultations pursuant to 4.38 of this
chapter before October 16, 1986.
(c) Time of filing petition. -- (1) General rule. Except as
provided in paragraph (c)(2) of this section, the applicant must:
(i) File the petition with the application for license or exemption;
or
(ii) Submit with the application for license or exemption a request
for an extension of time, not to exceed 90 days or April 16, 1988,
whichever occurs first, in which to file the petition.
(2) Exception. If the application for license or exemption was filed
on or after October 16, 1986, but before March 23, 1987, the petition
must have been filed by June 22, 1987.
(d) Filing requirements. A petition filed under this section must
include the following information or refer to the pages in the
application for license or exemption where it can be found:
(1) A certifcate of service, conforming to the requirements set out
in 385.2010(h) of this chapter, certifying that the applicant has
served the petition on the Federal and State agencies required to be
consulted by the applicant pursuant to 4.38 of this chapter;
(2) Documentation of any issued preliminary permits for the project;
(3) An itemized statement of the total costs expended on the
application;
(4) An itemized schedule of costs the applicant expended, or
committed to be expended, before October 16, 1986, on the application,
accompanied by supporting documentation including but not limited to:
(i) Dated invoices for maps, surveys, supplies, geophysical and
geotechnical services, engineering services, legal services, document
reproduction, and other items related to the preparation of the
application, and
(ii) Written contracts and other written documentation demonstrating
a commitment made before October 16, 1986, to expend monetary resources
on the preparation of the application, together with evidence that those
monetary resources were actually expended; and
(5) Correspondence or other documentation to support the items listed
in paragraphs (d)(3) and (d)(4) of this section to show that the
expenses presented were directly related to the preparation of the
application.
(6) The applicant must include in its total cost statement and in its
schedule of the costs expended or committed to be expended before
October 16, 1986, the value of services that were performed by the
applicant itself instead of contracted out.
(7)(i) If the applicant held a preliminary permit for the project and
had completed pre-filing consultation pursuant to 4.38 of this chapter
prior to October 16, 1986, the applicant may, instead of submitting the
information listed in paragraphs (d)(3), (d)(4), and (d)(5) of this
section, submit a statement identifying the preliminary permit by
project number.
(ii) If any interested person objects (pursuant to 385.211 of this
chapter) to the presumption in paragraph (b) of this section, the
applicant must supply the information listed in paragraphs (d)(3),
(d)(4), and (d)(5) of this section.
(8) If the application is deficient pursuant to 4.32(e) of this
chapter, the applicant must include with the information correcting
those deficiencies a statement of the costs expended to make the
corrections.
(e) Processing of petition. (1) The Commission will issue a notice
of the peition filed under this section and publish the notice in the
Federal Register. The petition will be available for inspection and
copying during regular business hours in the Public Reference Room
maintained by the Division of Public Information.
(2) Comments on the petition. The Commission will provide the public
45 days from the date the notice of the petition is issued to submit
comments. The applicant for license or exemption has 15 days after the
expiration of the public comment period to respond to the comments filed
with the Commission.
(3) Commission action on petition. The Director of the Office of
Hydropower Licensing will determine whether or not the applicant for
license or exemption has made the showing required under this section.
(Order 499, 53 FR 27003, July 18, 1988)
18 CFR 292.211 Petition for initial determination on whether a project
has a substantial adverse effect on the environment (AEE petition).
(a) An applicant that has filed a petition under 292.210 may also
file an AEE petition with the Commission for an initial determination on
whether the project satisfies the requirement that it has no substantial
adverse effect on the environment as specified in 292.208(b)(1).
(b) The filing of the AEE petition does not relieve the applicant of
the filing requirements of 292.208(c).
(c) The Commission will act on the AEE petition only if the
Commission has granted the applicant's commitment of resources petition
under 292.210.
(d) Time of filing petition. The applicant may file the AEE petition
with the application for license or exemption or at any time before the
Commission issues the license or exemption.
(e) Contents of petition. The AEE petition must identify the project
and request that the Commission make an initial determination on the
adverse environmental effects requirements in 292.208(b)(1).
(f) The Director of the Office of Hydropower Licensing will make the
initial determination on the AEE petition. In making this
determination, the Director will consider the following:
(1) Any proposed mitigative measures;
(2) The consistency of the proposal with local, regional, and
national resource plans and programs;
(3) The mandatory terms and conditions of fish and wildlife agencies
under section 210(j) of PURPA, or section 30(c) of the Federal Power
Act; or the recommended terms and conditions of fish a wildlife
agencies under Section 10(j) of the Federal Power Act, whichever is
appropriate; and
(4) Any other information which the Director believes is relevant to
consider.
(g) Initial finding on the petition. The Director of the Office of
Hydropower Licensing will make the initial determination on the AEE
petition after the close of the public notice period for the accepted
application. If the Director's initial determination finds:
(1) No substantial adverse effect on the environment, the Commission
must wait at least 45 days before making a final determination that the
project satisfies the requirements of 292.208(b)(1).
(2) A substantial adverse effect on the environment, the applicant
may file, within 90 days of the initial finding that the project does
not satisfy the requirements in 292.208(b)(1), proposed measures to
mitigate the adverse environmental effects found.
(3)(i) The Commission will provide written notice of the Director's
initial finding on the petition to the applicant, to the federal and
state agencies that the applicant must consult under 4.38 of this
chapter and to any intervenors in the proceeding.
(ii) The Commission will publish notice of the Director's initial
finding in the Federal Register.
(h) Notice and Comment on the Mitigative measures. (1) The
Commission will issue notice of the mitigative measures filed by an
applicant under paragraph (g)(2) of this section and will publish the
notice in the Federal Register. The mitigative measures will be on file
and available for inspection or copying during regular business hours in
the Public Reference Room maintained by the Division of Public
Information;
(2) The Commission will provide the State and interested persons
within 90 days from the date the notice is issued to review and submit
comments on the mitigative measures. The applicant for license or
exemption has 15 days after the expiration of the public comment period
to respond to the comments filed with the Commission.
(i) Material amendments to application. The proposed mitigative
measures filed under paragraph (g)(2) of this section will not be
considered a material amendment to the application unless the Commission
finds that the proposed measures are unnecessary to, or exceed the scope
of, mitigating substantial adverse effects. If the Commission finds the
proposed mitigative measures constitute a material amendment, the
application will be considered filed with the Commission on the date on
which the applicant filed the proposed mitigative measures, and all
other provisions of 4.35(a) of this chapter will apply.
(j) Final determination on the petition. The Commission will make a
final determination on the petition at the time the Commission issues a
license or exemption for the project.
(k) Presumption (1) If, between the Commission's initial and final
findings on the AEE petition, the State does not take any action under
292.208(b)(2), the failure to take action can be the basis for a
presumption that there is not substantial adverse effect on the
environment (as that term is defined in 292.202(q)).
(2) If the presumption in paragraph (k)(1) of this section comes into
effect, it:
(i) Is only available for those adverse effects related to the
natural, recreational, cultural, or scenic attributes of the
environment;
(ii) Can only operate during the time between the Commission's
initial and final findings on the AEE petition; and
(iii) Has no affect on the Commission's independent obligation to
find that the project will not have a substantial adverse effect on the
environment under 292.208(b)(1).
(3) The presumption in paragraph (k)(1) of this section does not take
effect if the State, the Commission or an interested person demonstrates
that the State has acted to protect the natural watercourse under
292.208(b)(2).
(4) The presumption in paragraph (k)(1) of this section can be
rebutted if:
(i) The Commission determines that the project will have a
substantial adverse effect on the environment related to the
environmental attributes listed in paragraph (k)(2)(i) of this section;
or
(ii) Any interested person, including a State, demonstrates that the
project will have a substantial adverse effect on the environment
related to the environmental attributes listed in paragraph (k)(2)(i) of
this section.
(Order 499, 53 FR 27004, July 18, 1988, as amended at Order 499-A, 53
FR 40724, Oct. 18, 1988)
18 CFR 292.211 Subpart C -- Arrangements Between Electric Utilities and
Qualifying Cogeneration and Small Power Production Facilities Under
Section 210 of the Public Utility Regulatory Policies Act of 1978
Authority: Public Utility Regulatory Policies Act of 1978, 16 U.S.C.
2601 et seq., Energy Supply and Environmental Coordination Act, 15
U.S.C. 791 et seq. Federal Power Act, 16 U.S.C. 792 et seq., Department
of Energy Organization Act, 42 U.S.C. 7101 et seq., E.O. 12009, 42 FR
46267.
Source: 45 FR 12234, Feb. 25, 1980, unless otherwise noted.
18 CFR 292.301 Scope.
(a) Applicability. This subpart applies to the regulation of sales
and purchases between qualifying facilities and electric utilities.
(b) Negotiated rates or terms. Nothing in this subpart:
(1) Limits the authority of any electric utility or any qualifying
facility to agree to a rate for any purchase, or terms or conditions
relating to any purchase, which differ from the rate or terms or
conditions which would otherwise be required by this subpart; or
(2) Affects the validity of any contract entered into between a
qualifying facility and an electric utility for any purchase.
18 CFR 292.302 Availability of electric utility system cost data.
(a) Applicability. (1) Except as provided in paragraph (a)(2) of
this section, paragraph (b) applies to each electric utility, in any
calendar year, if the total sales of electric energy by such utility for
purposes other than resale exceeded 500 million kilowatt-hours during
any calendar year beginning after December 31, 1975, and before the
immediately preceding calendar year.
(2) Each utility having total sales of electric energy for purposes
other than resale of less than one billion kilowatt-hours during any
calendar year beginning after December 31, 1975, and before the
immediately preceding year, shall not be subject to the provisions of
this section until June 30, 1982.
(b) General rule. To make available data from which avoided costs
may be derived, not later than November 1, 1980, June 30, 1982, and not
less often than every two years thereafter, each regulated electric
utility described in paragraph (a) of this section shall provide to its
State regulatory authority, and shall maintain for public inspection,
and each nonregulated electric utility described in paragraph (a) of
this section shall maintain for public inspection, the following data:
(1) The estimated avoided cost on the electric utility's system,
solely with respect to the energy component, for various levels of
purchases from qualifying facilities. Such levels of purchases shall be
stated in blocks of not more than 100 megawatts for systems with peak
demand of 1000 megawatts or more, and in blocks equivalent to not more
than 10 percent of the system peak demand for systems of less than 1000
megawatts. The avoided costs shall be stated on a cents per
kilowatt-hour basis, during daily and seasonal peak and off-peak
periods, by year, for the current calendar year and each of the next 5
years;
(2) The electric utility's plan for the addition of capacity by
amount and type, for purchases of firm energy and capacity, and for
capacity retirements for each year during the succeeding 10 years; and
(3) The estimated capacity costs at completion of the planned
capacity additions and planned capacity firm purchases, on the basis of
dollars per kilowatt, and the associated energy costs of each unit,
expressed in cents per kilowatt hour. These costs shall be expressed in
terms of individual generating units and of individual planned firm
purchases.
(c) Special rule for small electric utilities. (1) Each electric
utility (other than any electric utility to which paragraph (b) of this
section applies) shall, upon request:
(i) Provide comparable data to that required under paragraph (b) of
this section to enable qualifying facilities to estimate the electric
utility's avoided costs for periods described in paragraph (b) of this
section; or
(ii) With regard to an electric utility which is legally obligated to
obtain all its requirements for electric energy and capacity from
another electric utility, provide the data of its supplying utility and
the rates at which it currently purchases such energy and capacity.
(2) If any such electric utility fails to provide such information on
request, the qualifying facility may apply to the State regulatory
authority (which has ratemaking authority over the electric utility) or
the Commission for an order requiring that the information be provided.
(d) Substitution of alternative method. (1) After public notice in
the area served by the electric utility, and after opportunity for
public comment, any State regulatory authority may require (with respect
to any electric utility over which it has ratemaking authority), or any
non-regulated electric utility may provide, data different than those
which are otherwise required by this section if it determines that
avoided costs can be derived from such data.
(2) Any State regulatory authority (with respect to any electric
utility over which it has ratemaking authority) or nonregulated utility
which requires such different data shall notify the Commission within 30
days of making such determination.
(e) State Review. (1) Any data submitted by an electric utility
under this section shall be subject to review by the State regulatory
authority which has ratemaking authority over such electric utility.
(2) In any such review, the electric utility has the burden of coming
forward with justification for its data.
(45 FR 12234, Feb. 25, 1980; 45 FR 24126, Apr. 9, 1980)
18 CFR 292.303 Electric utility obligations under this subpart.
(a) Obligation to purchase from qualifying facilities. Each electric
utility shall purchase, in accordance with 292.304, any energy and
capacity which is made available from a qualifying facility:
(1) Directly to the electric utility; or
(2) Indirectly to the electric utility in accordance with paragraph
(d) of this section.
(b) Obligation to sell to qualifying facilities. Each electric
utility shall sell to any qualifying facility, in accordance with
292.305, any energy and capacity requested by the qualifying facility.
(c) Obligation to interconnect. (1) Subject to paragraph (c)(2) of
this section, any electric utility shall make such interconnections with
any qualifying facility as may be necessary to accomplish purchases or
sales under this subpart. The obligation to pay for any interconnection
costs shall be determined in accordance with 292.306.
(2) No electric utility is required to interconnect with any
qualifying facility if, solely by reason of purchases or sales over the
interconnection, the electric utility would become subject to regulation
as a public utility under Part II of the Federal Power Act.
(d) Transmission to other electric utilities. If a qualifying
facility agrees, an electric utility which would otherwise be obligated
to purchase energy or capacity from such qualifying facility may
transmit the energy or capacity to any other electric utility. Any
electric utility to which such energy or capacity is transmitted shall
purchase such energy or capacity under this subpart as if the qualifying
facility were supplying energy or capacity directly to such electric
utility. The rate for purchase by the electric utility to which such
energy is transmitted shall be adjusted up or down to reflect line
losses pursuant to 292.304(e)(4) and shall not include any charges for
transmission
(e) Parallel operation. Each electric utility shall offer to operate
in parallel with a qualifying facility, provided that the qualifying
facility complies with any applicable standards established in
accordance with 292.308.
18 CFR 292.304 Rates for purchases.
(a) Rates for purchases. (1) Rates for purchases shall:
(i) Be just and reasonable to the electric consumer of the electric
utility and in the public interest; and
(ii) Not discriminate against qualifying cogeneration and small power
production facilities.
(2) Nothing in this subpart requires any electric utility to pay more
than the avoided costs for purchases.
(b) Relationship to avoided costs. (1) For purposes of this
paragraph, ''new capacity'' means any purchase from capacity of a
qualifying facility, construction of which was commenced on or after
November 9, 1978.
(2) Subject to paragraph (b)(3) of this section, a rate for purchases
satisfies the requirements of paragraph (a) of this section if the rate
equals the avoided costs determined after consideration of the factors
set forth in paragraph (e) of this section
(3) A rate for purchases (other than from new capacity) may be less
than the avoided cost if the State regulatory authority (with respect to
any electric utility over which it has ratemaking authority) or the
nonregulated electric utility determines that a lower rate is consistent
with paragraph (a) of this section, and is sufficient to encourage
cogeneration and small power production.
(4) Rates for purchases from new capacity shall be in accordance with
paragraph (b)(2) of this section, regardless of whether the electric
utility making such purchases is simultaneously making sales to the
qualifying facility.
(5) In the case in which the rates for purchases are based upon
estimates of avoided costs over the specific term of the contract or
other legally enforceable obligation, the rates for such purchases do
not violate this subpart if the rates for such purchases differ from
avoided costs at the time of delivery.
(c) Standard rates for purchases. (1) There shall be put into effect
(with respect to each electric utility) standard rates for purchases
from qualifying facilities with a design capacity of 100 kilowatts or
less.
(2) There may be put into effect standard rates for purchases from
qualifying facilities with a design capacity of more than 100 kilowatts.
(3) The standard rates for purchases under this paragraph:
(i) Shall be consistent with paragraphs (a) and (e) of this section;
and
(ii) May differentiate among qualifying facilities using various
technologies on the basis of the supply characteristics of the different
technologies.
(d) Purchases ''as available'' or pursuant to a legally enforceable
obligation. Each qualifying facility shall have the option either:
(1) To provide energy as the qualifying facility determines such
energy to be available for such purchases, in which case the rates for
such purchases shall be based on the purchasing utility's avoided costs
calculated at the time of delivery; or
(2) To provide energy or capacity pursuant to a legally enforceable
obligation for the delivery of energy or capacity over a specified term,
in which case the rates for such purchases shall, at the option of the
qualifying facility exercised prior to the beginning of the specified
term, be based on either:
(i) The avoided costs calculated at the time of delivery; or
(ii) The avoided costs calculated at the time the obligation is
incurred.
(e) Factors affecting rates for purchases. In determining avoided
costs, the following factors shall, to the extent practicable, be taken
into account:
(1) The data provided pursuant to 292.302(b), (c), or (d), including
State review of any such data;
(2) The availability of capacity or energy from a qualifying facility
during the system daily and seasonal peak periods, including:
(i) The ability of the utility to dispatch the qualifying facility;
(ii) The expected or demonstrated reliability of the qualifying
facility;
(iii) The terms of any contract or other legally enforceable
obligation, including the duration of the obligation, termination notice
requirement and sanctions for non-compliance;
(iv) The extent to which scheduled outages of the qualifying facility
can be usefully coordinated with scheduled outages of the utility's
facilities;
(v) The usefulness of energy and capacity supplied from a qualifying
facility during system emergencies, including its ability to separate
its load from its generation;
(vi) The individual and aggregate value of energy and capacity from
qualifying facilities on the electric utility's system; and
(vii) The smaller capacity increments and the shorter lead times
available with additions of capacity from qualifying facilities; and
(3) The relationship of the availability of energy or capacity from
the qualifying facility as derived in paragraph (e)(2) of this section,
to the ability of the electric utility to avoid costs, including the
deferral of capacity additions and the reduction of fossil fuel use;
and
(4) The costs or savings resulting from variations in line losses
from those that would have existed in the absence of purchases from a
qualifying facility, if the purchasing electric utility generated an
equivalent amount of energy itself or purchased an equivalent amount of
electric energy or capacity.
(f) Periods during which purchases not required. (1) Any electric
utility which gives notice pursuant to paragraph (f)(2) of this section
will not be required to purchase electric energy or capacity during any
period during which, due to operational circumstances, purchases from
qualifying facilities will result in costs greater than those which the
utility would incur if it did not make such purchases, but instead
generated an equivalent amount of energy itself.
(2) Any electric utility seeking to invoke paragraph (f)(1) of this
section must notify, in accordance with applicable State law or
regulation, each affected qualifying facility in time for the qualifying
facility to cease the delivery of energy or capacity to the electric
utility.
(3) Any electric utility which fails to comply with the provisions of
paragraph (f)(2) of this section will be required to pay the same rate
for such purchase of energy or capacity as would be required had the
period described in paragraph (f)(1) of this section not occurred.
(4) A claim by an electric utility that such a period has occurred or
will occur is subject to such verification by its State regulatory
authority as the State regulatory authority determines necessary or
appropriate, either before or after the occurrence.
18 CFR 292.305 Rates for sales.
(a) General rules. (1) Rates for sales:
(i) Shall be just and reasonable and in the public interest; and
(ii) Shall not discriminate against any qualifying facility in
comparison to rates for sales to other customers served by the electric
utility.
(2) Rates for sales which are based on accurate data and consistent
systemwide costing principles shall not be considered to discriminate
against any qualifying facility to the extent that such rates apply to
the utility's other customers with similar load or other cost-related
characteristics.
(b) Additional Services to be Provided to Qualifying Facilities. (1)
Upon request of a qualifying facility, each electric utility shall
provide:
(i) Supplementary power;
(ii) Back-up power;
(iii) Maintenance power; and
(iv) Interruptible power.
(2) The State regulatory authority (with respect to any electric
utility over which it has ratemaking authority) and the Commission (with
respect to any nonregulated electric utility) may waive any requirement
of paragraph (b)(1) of this section if, after notice in the area served
by the electric utility and after opportunity for public comment, the
electric utility demonstrates and the State regulatory authority or the
Commission, as the case may be, finds that compliance with such
requirement will:
(i) Impair the electric utility's ability to render adequate service
to its customers; or
(ii) Place an undue burden on the electric utility.
(c) Rates for sales of back-up and maintenance power. The rate for
sales of back-up power or maintenance power:
(1) Shall not be based upon an assumption (unless supported by
factual data) that forced outages or other reductions in electric output
by all qualifying facilities on an electric utility's system will occur
simultaneously, or during the system peak, or both; and
(2) Shall take into account the extent to which scheduled outages of
the qualifying facilities can be usefully coordinated with scheduled
outages of the utility's facilities.
18 CFR 292.306 Interconnection costs.
(a) Obligation to pay. Each qualifying facility shall be obligated
to pay any interconnection costs which the State regulatory authority
(with respect to any electric utility over which it has ratemaking
authority) or nonregulated electric utility may assess against the
qualifying facility on a nondiscriminatory basis with respect to other
customers with similar load characteristics.
(b) Reimbursement of interconnection costs. Each State regulatory
authority (with respect to any electric utility over which it has
ratemaking authority) and nonregulated utility shall determine the
manner for payments of interconnection costs, which may include
reimbursement over a reasonable period of time.
18 CFR 292.307 System emergencies.
(a) Qualifying facility obligation to provide power during system
emergencies. A qualifying facility shall be required to provide energy
or capacity to an electric utility during a system emergency only to the
extent:
(1) Provided by agreement between such qualifying facility and
electric utility; or
(2) Ordered under section 202(c) of the Federal Power Act.
(b) Discontinuance of purchases and sales during system emergencies.
During any system emergency, an electric utility may discontinue:
(1) Purchases from a qualifying facility if such purchases would
contribute to such emergency; and
(2) Sales to a qualifying facility, provided that such discontinuance
is on a nondiscriminatory basis.
18 CFR 292.308 Standards for operating reliability.
Any State regulatory authority (with respect to any electric utility
over which it has ratemaking authority) or nonregulated electric utility
may establish reasonable standards to ensure system safety and
reliability of interconnected operations. Such standards may be
recommended by any electric utility, any qualifying facility, or any
other person. If any State regulatory authority (with respect to any
electric utility over which it has ratemaking authority) or nonregulated
electric utility establishes such standards, it shall specify the need
for such standards on the basis of system safety and reliability.
18 CFR 292.308 Subpart D -- Implementation
Authority: Public Utility Regulatory Policies Act of 1978, 16 U.S.C.
2601 et seq., Energy Supply and Environmental Coordination Act, 15
U.S.C. 791 et seq., Federal Power Act, 16 U.S.C. 792 et seq., Department
of Energy Organization Act, 42 U.S.C. 7101 et seq., E.O. 12009, 42 FR
46267.
Source: 45 FR 12236, Feb. 25, 1980, unless otherwise noted.
18 CFR 292.401 Implementation of certain reporting requirements.
Any electric utility which fails to comply with the requirements of
292.302(b) shall be subject to the same penalties to which it may be
subjected for failure to comply with the requirements of the
Commission's regulations issued under section 133 of PURPA.
(45 FR 12236, Feb. 25, 1980. Redesignated bu Order 541, 57 FR 21734,
May 22, 1992)
18 CFR 292.402 Waivers.
(a) State regulatory authority and nonregulated electric utility
waivers. Any State regulatory authority (with respect to any electric
utility over which it has ratemaking authority) or nonregulated electric
utility may, after public notice in the area served by the electric
utility, apply for a waiver from the application of any of the
requirements of subpart C (other than 292.302 thereof).
(b) Commission action. The Commission will grant such a wavier only
if an applicant under paragraph (a) of this section demonstrates that
compliance with any of the requirements of subpart C is not necessary to
encourage cogeneration and small power production and is not otherwise
required under section 210 of PURPA.
(45 FR 12236, Feb. 25, 1980. Redesignated bu Order 541, 57 FR 21734,
May 22, 1992)
18 CFR 292.402 Subpart E -- (Reserved)
18 CFR 292.402 Subpart F -- Exemption of Qualifying Small Power Production Facilities and Cogeneration Facilities from Certain Federal and State Laws and Regulations
18 CFR 292.601 Exemption to qualifying facilities from the Federal
Power Act.
(a) Applicability. This section applies to qualifying facilities,
other than those described in paragraph (b) of this section.
(b) Exclusion. This section does not apply to a qualifying small
power production facility with a power production capacity which exceeds
30 megawatts, if such facility uses any primary energy source other than
geothermal resources.
(c) General rule. Any qualifying facility described in paragraph (a)
of this section shall be exempt from all sections of the Federal Power
Act, except:
(1) Section 1-18, and 21-30;
(2) Sections 202(c), 210, 211, and 212;
(3) Sections 305(c); and
(4) Any necessary enforcement provision of Part III with regard to
the sections listed in paragraphs (c)(1), (2) and (3) of this section.
(Energy Security Act, Pub. L. 96-294, 94 Stat. 611 (1980) Public
Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy
Supply and Environmental Coordination Act, 15 U.S.C. 791, et seq.,
Federal Power Act, as amended, 16 U.S.C. 792 et seq., Department of
Energy Organization Act, 42 U.S.C. 7101, et seq.; E.O. 12009, 42 FR
46267)
(Order 135, 46 FR 19232, Mar. 30, 1981)
18 CFR 292.602 Exemption to qualifying facilities from the Public
Utility Holding Company Act and certain State law and regulation.
(a) Applicability. This section applies to any qualifying facility
described in 292.601(a), and to any qualifying small power production
facility with a power production capacity over 30 megawatts if such
facility produces electric energy solely by the use of biomass as a
primary energy source.
(b) Exemption from the Public Utility Holding Company Act of 1935. A
qualifying facility described in paragraph (a) of this section or a
utility geothermal small power production facility shall not be
considered to be an ''electric utility company'' as defined in section
2(a)(3) of the Public Utility Holding Company Act of 1935, 15 U.S.C.
79b(a)(3).
(c) Exemption from certain State law and regulation. (1) Any
qualifying facility shall be exempted (except as provided in paragraph
(c)(2)) of this section from State law or regulation respecting:
(i) The rates of electric utilities; and
(ii) The financial and organizational regulation of electric
utilities.
(2) A qualifying facility may not be exempted from State law and
regulation implementing subpart C.
(3) Upon request of a State regulatory authority or nonregulated
electric utility, the Commission may consider a limitation on the
exemptions specified in paragraph (c)(1) of this section.
(4) Upon request of any person, the Commission may determine whether
a qualifying facility is exempt from a particular State law or
regulation.
(Energy Security Act, Pub. L. 96-294, 94 Stat. 611 (1980) Public
Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601, et seq., Energy
Supply and Environmental Coordination Act, 15 U.S.C. 791, et seq.,
Federal Power Act, as amended, 16 U.S.C. 792 et seq., Department of
Energy Organization Act, 42 U.S.C. 7101, et seq.; E.O. 12009, 42 FR
46267)
(45 FR 12237, Feb. 25, 1980, as amended by Order 135, 46 FR 19232,
Mar. 30, 1981)
18 CFR 292.602 PART 294 -- PROCEDURES FOR SHORTAGES OF ELECTRIC ENERGY
AND CAPACITY UNDER SECTION 206 OF THE PUBLIC UTILITY REGULATORY POLICIES
ACT OF 1978
Authority: Public Utility Regulatory Policies Act of 1978, Pub. L.
95-617, 92 Stat. 3117; Federal Power Act, 16 U.S.C. 792 et seq. ;
Department of Energy Organization Act, 42 U.S.C. 7107 et seq. ; E.O.
12009, 42 FR 46267; Administrative Procedure Act, 5 U.S.C. 553.
18 CFR 294.101 Shortages of electric energy and capacity.
(a) Definition of shortages of electric energy and capacity. For
purposes of this section, the term anticipated shortages of electric or
energy means:
(1) Any situation anticipated to occur in which the generating and
bulk purchased power capability of a public utility will not be
sufficient to meet its anticipated demand plus appropriate reserve
margins and this shortage would affect the utility's capability
adequately to supply electric services to its firm power wholesale
customers; or
(2) Any situation anticipated to occur in which the energy supply
capability of a public utility is not sufficient to meet its customers'
energy requirements and this shortage would affect the utility's
capability adequately to supply electric services to its firm power
wholesale customers.
(b) Accommodation of shortages. (1) Each public utility now serving
firm power wholesale customers, shall submit a brief statement
indicating how it would accommodate any shortages of electric energy or
capacity affecting its firm power wholesale customers.
(2) This statement shall:
(i) Describe how the utility would assure that direct and indirect
customers are treated without undue prejudice or disadvantage; and
(ii) It shall also identify any agreement, law, or regulation which
might impair the utility's ability to accommodate such a shortage.
(3) Each utility shall file a copy of its statement with any
appropriate State regulatory agency and all firm power wholesale
customers.
(4) If a plan for accommodating any shortages of electric energy or
capacity affecting its firm power wholesale customers as described in
the brief statement submitted pursuant to paragraph (b)(1) of this
section is modified, the utility must submit to the Commission and the
persons described in paragraph (b)(3) of this section within 15 days of
any such modification, a supplemental statement informing the Commission
of those modifications.
(c) Reporting requirements. Each public utility shall immediately
report to the Commission, to any State regulatory authority and to firm
power wholesale customers, any anticipated shortage of electric energy
or capacity. The report shall include the following information:
(1) The nature and projected duration of the anticipated capacity or
energy supply shortage;
(2) A list showing all firm power wholesale customers affected or
likely to be affected by the anticipated shortage;
(3) Procedures for accommodating the shortage, if different from
those described in paragraph (b) of this section;
(4) An estimate of the effects (reduced power and energy usage) of
use of these procedures upon the utility's wholesale and retail
customers; and
(5) The name, title, address and telephone number of an officer or
employee of the utility who may be contacted for further information
regarding the shortage and planned actions of the utility.
(d) Reports to other government entities. Any report filed with
another governmental entity that contains the information that must be
reported under this part may be filed to comply with this part.
(e) Number of copies. Any public utility that files under this part
must provide an original of any filing and at least two exact copies to
this Commission and one copy to any state regulatory authority and firm
power wholesale customers, unless otherwise required by the Commission.
(44 FR 37502, June 27, 1979, as amended at 47 FR 20297, May 12, 1982;
Order 401, 49 FR 39538, Oct. 9, 1984; Order 401-A, 54 FR 41087, Oct.
5, 1989)
18 CFR 294.101 SUBCHAPTER L -- REGULATIONS FOR FEDERAL POWER MARKETING ADMINISTRATIONS
18 CFR 294.101 PART 300 -- CONFIRMATION AND APPROVAL OF THE RATES OF FEDERAL POWER MARKETING ADMINISTRATIONS
18 CFR 294.101 Subpart A -- General Provisions
Sec.
300.1 Applicability and definitions.
300.2 Informal conference.
18 CFR 294.101 Subpart B -- Filing Requirements
300.10 Application for confirmation and approval.
300.11 Technical support for the rate schedule.
300.12 Analysis of supporting data.
300.13 Waiver of filing requirements.
300.14 Filings under section 7(k).
18 CFR 294.101 Subpart C -- Commission Rate Review and Approval
300.20 Interim acceptance and review of Bonneville Power
Administration rates.
300.21 Final confirmation and approval.
Authority: 16 U.S.C. 825s, 832-8321, 838-838k, 839-839h; 42 U.S.C.
7101-7352; 43 U.S.C. 485-485k.
Source: Order 382, 49 FR 25235, June 20, 1984, unless otherwise
noted.
18 CFR 294.101 Subpart A -- General Provisions
18 CFR 300.1 Applicability and definitions.
(a) Applicability. This part sets forth procedures governing the
filing, review and disposition of the rate schedules for the sale or
transmission of power and energy established by the Alaska, Bonneville,
Southeastern, Southwestern and Western Area Power Administrations.
Except as otherwise provided by rule or order, the Commission's general
rules of practice and procedure (part 385 of this chapter) will apply to
any filings, hearings or other procedures under this part, as
applicable.
(b) Definitions. For purposes of this part, the following
definitions apply:
(1) Administrator means the administrator of a power marketing
administration.
(2) Electric service means any transmission or sale of electric power
and energy, including capacity sales, energy sales, firm power sales,
transmission services, or any combination of these services, and the
utilization, by means of ownership, contractual arrangements, leasing,
or other arrangements, of any facility to provide such sales or
services.
(3) Historic period means the period commencing with the date of
first commercial operation of a powerplant or transmission facility and
ending on the last day of the latest year for which actual cost data are
available, provided that the period does not end more than 18 months
before the date on which the Administrator tenders the rate schedule for
filing with the Commission, or such longer period requested by the
Deputy Secretary of Energy or Administrator and granted by the
Commission.
(4) Initial capital investment means the cost of acquisition or
construction of a power facility or non-power facility which has been
assigned to be repaid from the power revenues, including but not limited
to any cost of planning, design, land acquisition, construction,
interest during construction, and testing incurred before the date on
which the facility becomes operational or revenue-producing.
(5) Power repayment study or PRS means a study of the annual
repayment of production and transmission investments and other costs
through the application of revenues during the repayment period.
(6) Proposed rate approval period means the period for which
confirmation and approval of the rate schedules is requested. This
period must not exceed five years.
(7) Rate schedule means a statement describing:
(i) Type of service to which the rate is to be applied;
(ii) Rates and charges for, or in connection with, electric service;
and
(iii) Classifications and other provisions which directly affect such
rates and charges.
(8) Rate test or cost evaluation period means a period, commencing
with the end of the historic period, as defined in paragraph (b)(3) of
this section, and continuing through the proposed rate approval period
as defined in paragraph (b)(6) of this section, during which future
estimates of costs and revenues should be modified by the Administrator
to reflect changing conditions.
(9) Replacement means any substitution of a unit of property with
another unit of like character.
(Order 382, 49 FR 25235, June 20, 1984, as amended by Order 323-B, 52
FR 20709, June 3, 1987)
18 CFR 300.2 Informal conference.
The Administrator or a designee may confer with Commission staff
prior to submitting an application under subpart B, with respect to the
appropriate form and content of such application.
18 CFR 300.2 Subpart B -- Filing Requirements
18 CFR 300.10 Application for confirmation and approval.
(a) General provisions -- (1) Contents of filing. Any application
under this subpart for confirmation and approval or rate schedules must
include, as described in this section a letter of request for rate
approval, a notice of filing suitable for publication in the Federal
Register, the rate schedule, a statement of revenue and related costs,
the order, if any, placing the rates into effect on an interim basis,
the Administrator's Record of Decision or explanation of the rate
development process, supporting documents, a certification, and
technical supporting information and analysis.
(2) Incorporation of information by reference. Any information
required under this subpart that has previously been submitted to the
Commission in substantially the same form as specified in this section
may be incorporated by reference only.
(3) Time of filing. (i) Rate schedules put into effect on an interim
basis by the Secretary of the Department of Energy, or a designee, and
filed for final Commission approval must be filed not later than five
days after interim approval is granted.
(ii) Rate schedules of the Bonneville Power Administration for which
interim approval by the Commission is requested must be filed not later
than 60 days in advance of the proposed effective date.
(iii) Rate schedules for which interim approval is not requested must
be filed not later than 180 days in advance of the proposed effective
date.
(b) Letter of request for rate approval. A letter of request for
rate approval must contain the following information:
(1) A description of the period for which Commission approval is
requested, delineated by an effective date and an expiration date, and,
for the Bonneville Power Administration, a request, if any, for interim
approval of the rates;
(2) A brief description of the proposed rates and charges under
existing and proposed rate schedules and the expected changes, if any,
in annual revenues; and
(3) A description of how the filed rate differs in rate level or rate
structure from the rate schedule currently effective.
(c) Notice of filing. The notice of filing, suitable for publication
in the Federal Register, must contain the following information:
(1) The identification number or description of the rate schedule or
contract;
(2) If the rate schedule includes changes in rates, the dollar amount
and percent increase or decrease in rates;
(3) If the rate schedule includes changes other than rates, a brief
description of the changes;
(4) A brief explanation of the reasons for any proposed change in the
rate schedule;
(5) A statement whether interim approval of Bonneville Power
Administration rates is requested;
(6) The proposed effective date of the rate schedule; and
(7) The proposed rate approval period.
(d) Rate schedules. A filed rate schedule, as defined in
300.1(b)(7), must describe the following, as appropriate:
(1) The class of service to which each rate schedule will apply and
service areas or zones which will be affected by the filed rate;
(2) The rate to be applied to capacity and energy services or other
services;
(3) Special provisions, such as discounts, penalties, power factor
adjustments, service interruptions, unauthorized overruns and other
similar provisions which may affect the rate and charges; and
(4) The period during which the rates will be effective.
(e) Statement of Revenue and Related Costs. Each filing shall
include a statement which includes cost (if available) and revenue data
for each class of service as specified in each rate schedule for the
proposed period.
(f) Explanation of rate development process and supporting documents.
(1) The Administrator must file the entire record on which the final
decision establishing a rate scheduled is based.
(2) The Administrator must file a Record of Decision, if one is made,
or an explanation of the rate development process, if a Record of
Decision is not made. The Record of Decision or the explanation of the
rate development process must include:
(i) A discussion of issues raised by customers or the public and how
such issues were resolved;
(ii) A discussion of all statutory, regulatory, or other requirements
which governed the Administrator's decision;
(iii) A description of any methodology used for determining revenue
requirements and for developing appropriate rate structures;
(iv) A list identifying all documents submitted for Commission
consideration; and
(g) Certification. The Administrator must file a statement
certifying that the rate is consistent with applicable laws and that it
is the lowest possible rate consistent with sound business principles.
(h) Additional filing requirements. (1) The Administrator must file
with the Commission any other information relevant ot the Commission's
ratemaking decision.
(2) The Administrator must file any other information requested by
the Office of Electric Power Regulation as needed for Commission
analysis of the rate filing.
(Order 382, 49 FR 25235, June 20, 1984, as amended by Order 541, 57
FR 21734, May 22, 1992)
18 CFR 300.11 Technical support for the rate schedule.
(a) Filing requirement. The Administrator must submit, in
conjunction with any application under 300.10, the technical support
data described under paragraph (b) of this section and the analysis of
data described under 300.12 of this subpart.
(b) Data -- (1) Statement A -- Sales and Revenues. Statement A must
include:
(i) Sales and revenues for each rate schedule for the last five years
of the historic period, as defined in section 300.1(b)(3);
(ii) For the rate test period, the estimated annual sales and
revenues for the existing and each proposed rate schedule, including a
separate aggregation of any revenues from sources not covered by the
rate schedule according to general classifications of such revenues;
and
(iii) Brief explanations of how sales and revenue estimates are
prepared and explanations of any changes in sales or revenues during the
last five years of the historic period.
(2) Statement B -- Power Resources. Statement B must contain a list
of the capacity and energy resources for the last five years of the
historic period and for the rate test period, used to support the sales
and revenues figures contained in Statement A. The statement should
identify resources according to the powerplant and any purchase or
exchange agreement.
(3) Statement C -- Capitalized investments or costs. (i) Statement C
must account for all capitalized investments to be repaid from power
revenues.
(ii) The statement shall include a listing, by year, of the
following:
(A) All initial investments and additions to plant, including
interest during construction, that produced revenue during the historic
period or are expected to produce revenue during the rate test period;
(B) Capitalized deferred expenses; and
(C) Replacements made during the historic period and replacements
projected to be made during the balance of the repayment period.
(iii) For each such investment, the statement shall specify:
(A) Whether the investment is an initial investment, an addition, a
replacement, or a capitalized deferred annual expense;
(B) The date the investment was made;
(C) The year in which repayment is due to be completed;
(D) Whether the investment was financed through the issuance of
revenue bonds, the appropriate interest rate, and the terms and
conditions for such bonds; and
(E) The authority or administrative procedure used for the adoption
of such interest rate.
(iv) If available, the amount repaid on each investment to date must
be stated, except that if repayment on individual investments is not
recorded, the amount repaid to date on each group of investments having
common interest rates should be stated.
(v) For each year, the sum of unpaid individual investments or the
unpaid portion of interest groups shown above must equal the unamortized
investment shown in the power repayment study for that year.
(vi) The statement must describe the methods used to forecast
replacements and the price level used to estimate replacement costs.
(4) Statement D -- Interest Expenses; Repayment of Investments and
Debt Capital. (i) For each capitalized investment and cost listed in
Statement C, Statement D must describe, by interest group:
(A) The total unpaid balance outstanding at the end of the historic
period;
(B) Payments made on principal and interest during each of the last
five years of the historic period; and
(C) Annual payments expected to be made through the cost evaluation
period.
(ii) The statement must describe how the interest expense was
determined for each type of investment and include examples of such
computations.
(5) Statement E -- Operation, Maintenance and Other Annual Expenses.
Statement E must contain, for the last five years of the historic period
and for the rate test period, as appropriate, a tabulation of actual and
projected operation and maintenance, administrative and general,
purchased power, wheeling, and any other expenses, other than interest.
Statement E must:
(i) List expenses for each individual source, if purchased power and
other similar expenses are derived from more than one source;
(ii) Explain any significant deviations from trends in expenses or
any extraordinary expenses; and
(iii) Explain the price level used for estimating expenses.
(6) Statement F -- Cost Allocations. (i) Statement F must contain,
for each multiple-purpose reservoir project, unit, division, or system,
a table or other summary showing total investment costs, the total
annual operation and maintenance costs, and the allocation of all such
costs among the various authorized purposes.
(ii) The statement must show the amount of power costs suballocated
to irrigation functions, any changes from previous allocations, and the
procedure used in allocating such costs. Currently valid allocations
previously submitted to the Commission need not be furnished, if
referenced.
18 CFR 300.12 Analysis of supporting data.
(a) An analysis of the data provided under 300.11 must be supported
by an appropriate methodology developed by the Administrator.
(b) Revenue recovery study. (1) A study must be provided which
supports the filed rate and charges, including a narrative statement
that explains how the rates and charges meet the objective of recovering
the revenue necessary to repay the Federal investment and other costs in
a reasonable period of time.
(2) Any Power Repayment Study (PRS) submitted for this purpose must
be developed using currently approved rates for estimating future
revenues. If the filed rates differ from the current rates, the
Administrator must provide a PRS which uses the level of revenues
produced by the proposed rates. Unless otherwise required by statute, a
PRS must contain only those investments in plant which will be in
commercial operation during the proposed rate approval period, except
replacements. Forecasts of costs beyond the rate test period must be
based on conditions prevailing during the period, unless unusual
circumstances warrant otherwise.
(3) A PRS must include, but need not be limited to, those items
listed below:
(i) Operating revenues;
(ii) Operating expenses;
(iii) Interest expense;
(iv) Investment placed in service (using totals if the supporting
statement annually shows a breakdown into the appropriate subcategories
under each major heading), including the initial project, additions,
replacements, and the total investment;
(v) Investment amortized;
(vi) Remaining unamortized investment;
(vii) Allowable unamortized investment (using totals if the
supporting statement annually shows a breakdown into the appropriate
subcategories under each major heading), including initial project,
additions, replacements, and total investment;
(viii) Irrigation investment assigned to be repaid from power
revenues (using totals if the supporting statement annually shows a
breakdown into the appropriate subcategories under each major heading),
including irrigation investment assigned to power, investment repaid,
remaining unpaid investment, and allowable unpaid investment; and
(ix) Cumulative status of repayment.
(c) Cost of service study. For any project or system which provides
more than one class of service for which differing rates are proposed, a
cost of service study, if available, must be provided which shows how
the costs of providing each service have been determined. If rates and
charges have not been formulated on a cost related basis, the basis for
each rate or charge should be explained.
18 CFR 300.13 Waiver of filing requirements.
The Administrator must request waiver of any requirement of this
subpart if an application that does not fully comply with that
requirement is not to be considered deficient. The request must state
the Administrator's reasons for such noncompliance and show good cause
for any waiver.
18 CFR 300.14 Filings under section 7(k).
Any application for Commission review and approval of a rate or rate
schedules established by the Administrator of the Bonneville Power
Administration pursuant to section 7(k) of the Pacific Northwest
Electric Power Planning and Conservation Act must be filed in compliance
with the provisions of 35.13(a)(2) of part 35 of this chapter and with
the provisions of this part, and must include the classifications,
practices, rules and regulations affecting the rate and charges and all
contracts which in any manner affect or relate to such rate, charges,
classifications, services, rules, regulations, or practices. However,
such classifications, practices, rules, regulations or contracts which
may affect or relate to rates will not be subject to Commission approval
unless they are determined to be rates or rate schedules.
(Order 323-B, 52 FR 20709, June 3, 1987)
18 CFR 300.14 Subpart C -- Commission Rate Review and Approval
18 CFR 300.20 Interim acceptance and review of Bonneville Power
Administration rates.
(a) Opportunity to comment. The Commission will publish in the
Federal Register. notice of any filing made under this part, for which
interim approval is requested. This notice will give interested persons
an opportunity to submit written comments on whether interim approval
should be granted.
(b) Action on request for interim rate acceptance -- (1) Deficient
applications. Upon receipt of an application that does not comply with
the requirements of this part, the Commission may:
(i) Accept the application and order the rate schedule into effect on
an interim basis, effective on the date requested by the Administrator
or at such time as the Commission may otherwise order, on the condition
that any deficiencies in the filing are corrected by the Administrator
to the satisfaction of and within such time specified by the Director of
the Office of Electric Power Regulation; or
(ii) Deny the Administrator's interim rate request and reject the
application, if the Commission determines that the Administrator's
application:
(A) Is patently deficient with respect to the filing requirements of
this part; or
(B) Fails to comply with the applicable provisions of the Northwest
Power Act or such other Acts as may be applicable.
(2) Applications that are in compliance. Upon receipt of an
application that complies with the requirements of this part, the
Commission may:
(i) Order the rate schedule into effect on an interim basis,
effective on the date requested by the Administrator or at such time as
the Commission may otherwise order; or
(ii) Deny the Administrator's interim rate request and review the
application for final confirmation and approval of the rate schedule
pursuant to the provisions of this part.
(c) Condition of acceptance. Any rate schedule the Commission allows
to become effective on an interim basis under paragraph (b) of this
section is subject to refund with interest.
(d) Notice of action on interim approval. The Commission will
publish in the Federal Register a notice of any action taken under
paragraph (b) of this section and will mail notice to any person on the
Commission's service list.
18 CFR 300.21 Final confirmation and approval.
(a) Opportunity to comment and intervene. (1) The Commission will
publish notice in the Federal Register giving interested persons an
opportunity:
(i) To submit initial and reply comments on any filing made under
subpart B; and
(ii) To intervene in any proceeding held on such filing.
(2) With respect to the Bonneville Power Administration:
(i) Such notice will also give interested persons an opportunity to
comment on whether it is necessary to hold a hearing on non-regional
rates under section 7(k) of the Northwest Power Act and the issues to be
resolved at such hearing.
(ii) This notice may be part of any Commission order granting interim
approval under 300.20 of this part.
(b) Proceedings under section 7(k). For the Bonneville Power
Administration, the Commission will publish a separate order if it
determines that a hearing is necessary under section 7(k) of the
Northwest Power Act. This order will, if appropriate, delineate the
issues to be resolved at such hearing. Such hearing will be held in
accordance with the procedures established for ratemaking by the
Commission pursuant to the Federal Power Act.
(c) Standards of review for the Bonneville Power Adminstration -- (1)
Rates under section 7(a). The Commission will review any rate
established by the Administrator under section 7(a) of the Northwest
Power Act for compliance with the following standards:
(i) The rates must be sufficient to ensure repayment of the Federal
investment in the Federal Columbia River Power System over a reasonable
number of years after first meeting the Administrator's other costs.
(ii) The rates must be based upon the Administrator's total system
costs.
(iii) With respect to transmission rates, the rates must equitably
allocate the costs of the Federal transmission system between Federal
and non-federal power utilizing such system.
(2) Rates under section 7(k). The Commission will review any rate
established by the Administrator under section 7(k) of the Pacific
Northwest Electric Power Planning and Conservation Act for compliance
with the requirements of the Bonneville Project Act, the Flood Control
Act of 1944, and the Federal Columbia River Transmission System Act.
(d) Standards of review for other power marketing administrations.
The Commission will review the rates of the Alaska, Southeastern,
Southwestern, and Western Area Power Marketing Administrations in
accordance with the terms of any delegation made by the Secretary of
Energy.
(e) Action on request for final confirmation and approval of rates.
Filed rates will be considered for final confirmation and approval if
the relevant filing complies with the filing requirements of subpart B
of these regulations. The Commission may take any of the following
actions:
(1) Confirm and approve the rate schedules for the period beginning
with the date such rates where placed in effect on an interim basis or
the effective date requested in the application to the expiration date
requested in the application but not to exceed a five-year period, or
for such lesser period, as the Commission deems appropriate;
(2) Remand the filing for further development of the record to
support the filed rate schedules;
(3) Order an evidentiary hearing if there are questions of fact which
can not be resolved from the record or through staff evaluation;
(4) Disapprove the filed rates; or
(5) Take such other action that the Commission considers appropriate.
(f) Procedures upon disapproval. If the Commission disapproves the
rates, the Administrator will be provided a 120-day period, or other
period as the Commission may deem appropriate, to prepare substitute
rates that resolve the Commission's concerns. If the filed rates have
been approved on an interim basis, the rates will continue in effect on
an interim basis until the Commission takes final action.
(g) Refund and interest -- (1) Refund. If a rate collected by any
power marketing administration on an interim basis exceeds the rate
which is confirmed and approved by the Commission as a final rate, the
Administrator, pursuant to any conditions established by the Commission,
must refund with interest any portion of the rate increase collected
during the interim period which exceeds the final rate. The
Administrator may make refunds by means of a net energy billing which
reflects the value of any overcharge or other appropriate methods.
(2) Interest. Except as otherwise provided by the Commission, the
Administrator must compute any amount of interest based on the revenues
collected subject to refund and required to be refunded under this
paragraph by using:
(i) With respect to the rates of the Bonneville Power Adminstration,
the rate of interest or a weighted average of all rates of interest
charged to the Bonneville Power Administration by the U.S. Treasury
during the period for which the computation is made;
(ii) With respect to the rates of other Power Marketing
Administrations, the rates of interest computed in accordance with the
formula contained in DOE Order No. RA 6120.2, available from the
Department of Energy (Office of Power Marketing Coordination) and the
Power Marketing Administrations.
(h) Notice of action on final approval. The Commission's Secretary
will publish in the Federal Register a notice of any action taken under
paragraph (e) of this section and will mail the notice to the persons on
the Commission's service list.
(Order 382, 49 FR 25235, June 20, 1984, as amended by Order 323-B, 52
FR 20709, June 3, 1987)
18 CFR 300.21 PART 301 -- AVERAGE SYSTEM COST METHODOLOGY FOR SALES
FROM UTILITIES TO BONNEVILLE POWER ADMINISTRATION UNDER NORTHWEST POWER
ACT
Authority: Pacific Northwest Electric Power Planning and
Conservation Act, 16 U.S.C. 839 -- 839h.
18 CFR 301.1 Average system cost methodology.
(a) Applicability. This section applies to the sales of electric
power by any public utility to the Bonneville Power Administration
pursuant to section 5(c) of the Pacific Northwest Electric Power
Planning and Conservation Act (Northwest Power Act), 16 U.S.C.
839-839h.
(b) Definitions. For purposes of this section the following
definitions apply:
(1) Average system cost (ASC) means for each jurisdiction and each
exchange period the quotient obtained by dividing Contract Systems Costs
by Contract System Load.
(2) Contract system costs means the Utility's Costs for production
and transmission resources, including power purchases and conservation
measures, which Costs are includable in, jurisdictionally allocated by,
and subject to the provisions of Appendix 1. Contract System Costs do
not include Costs excluded from ASC by section 5(c)(7) of the Northwest
Power Act.
(3) Contract system load means the firm energy load used by the State
Commission for the purpose of establishing retail rates, adjusted
pursuant to the Average System Cost Methodology rule.
(4) Costs means the aggregate dollar amount or any portion of the
amount allowed or relied upon by the State Commission to determine the
test period revenue requirement for the Utility in a Jurisdiction.
(5) Exchange period means the period of time during which a Utility's
jurisdictional retail rate schedules are in effect, commencing with the
effective date of these schedules and ending with the effective date of
new retail rate schedules in the Jurisdiction; provided that no
Exchange Period shall commence prior to or extend beyond the term of the
Utility's Residential Purchase and Sales Agreement. For the purposes of
any initial Appendix 1 filing, the Exchange Period shall commence on the
date such Appendix 1 is filed and end with the effective date of the
next retail rate change.
(6) Jurisdiction means the service territory of the exchanging
Utility within which a State Commission has authority to approve the
retail rates.
(7) New large single load means that load defined in section 3(13) of
the Northwest Power Act, and as determined by BPA as specified in power
sales contracts with its customers.
(8) Regional power sales customer means any entity that contracts
directly with BPA for the purchase of power delivery in the region as
defined by section 3(14) of the Northwest Power Act.
(9) Test period means the time period (not less than 12 months) used
by the State Commission to determine Cost for retail ratemaking.
(10) State Commission means a State regulatory body, preference
utility governing body, or other entity authorized to establish retail
electric rates in a Jurisdiction.
(11) File or filed means that the Appendix 1 has been:
(i) Hand delivered to the Division of Financial Requirements;
Bonneville Power Administration; Portland, Oregon; or
(ii) Mailed to BPA by certified mail, return receipt requested, to
the following address:
Bonneville Power Administration, Division of Financial Requirements,
Routing: DN, P.O. Box 3621, Portland, Oregon 97208
and has been received by BPA. An Appendix 1 shall be considered to
be filed as of the date of the postmark on the certified mailing.
(12) Review period means that period of time during which a Utility's
Appendix 1 is under review by the Administrator. The review period
begins when an Appendix 1 is Filed and ends two hundred and ten (210)
days after the Utility Filed its Appendix 1.
(c) Phase-in. For the period beginning with the effective date of
this rule and ending June 30, 1985, a utility's ASC will be the average
of the ASC in effect on July 1, 1984 and the ASC calculated under this
section. Beginning July 1, 1985, each utility's ASC will be calculated
exclusively under this section.
(d) Filing procedures. The procedures established by the
Administrator provide the filing requirements for all utilities that
file an Appendix 1.
(1) Appendix 1 is a form that identifies Contract System Costs and
Contract System Load and permits the calculation of ASC.
(2) For each Exchange Period and for each regional Jurisdiction in
which a Utility provides service, the Utility shall complete and file
three copies of Appendix 1, in accordance with the Administrator's
procedures and 35.30 of this chapter.
Appendix 1 is the form on which a Utility participating in a
Residential Purchase and Sale Agreement shall report its Contract System
Costs and other necessary data for the calculation of ASC.
The form consists of four schedules that shall be completed by the
Utility in accord with these instructions and the provisions of the
footnotes following the schedules. Any items not applicable to the
Utility shall be so identified.
The schedules are as follows:
Schedule 1 -- Plant Investment/Rate Base/Rate of Return
Schedule 2 -- Weighted Average Cost of Long Term Debt
Schedule 3 -- Expenses
Schedule 4 -- Average System Cost
The filing Utility shall reference and attach workpapers that support
Costs, including details of allocation and functionalization.
All references to the Commission accounts are to the Commission
Uniform System of Accounts as of July 1, 1984. The Costs includable in
the attached schedules are those includable by reason of the definitions
in the Commission accounts. If the Commission accounts are later
revised or renumbered, any changes shall be incorporated into this form
by reference, except to the extent that BPA determines that a particular
change results in a change in the type of Costs allowable for exchange
purposes. If the Utility does not follow the Commission accounts, its
filing must include a reconciliation between its accounts and the items
allowed as Contract System Costs.
BPA may require the Utility to account for purchased power
transactions with affiliated entities as though the affiliated entities
were owned in whole or in part by the Utility, if necessary to properly
determine and/or functionalize the Utility's Costs.
A utility operating in more than one Jurisdiction shall allocate its
total system Costs among Jurisdictions in accord with the same
allocation methods and procedures used by the State Commission to
establish jurisdictional Costs and resulting revenue requirements.
Appendix 1 shall include details of the allocation. This allocation
also accomplishes the exclusion of the Costs of additional resources to
meet loads outside the region, as required by section 5(c)(7) of the
Northwest Power Act.
All schedule entries and supporting data shall be in accord with
generally accepted accounting principles and practices as these
principles and practices apply to the electric utility industry.
aTransmission plant and the associated cost to be used in the
calculation to the average system cost (ASC) are limited to:
(1) For transmission plant in service as of July 1, 1984,
transmission plant will be as defined by the Federal Energy Regulatory
Commission Uniform System of Accounts and will include radial
transmission lines.
(2) For transmission plant commencing service after July 1, 1984,
transmission plant costs which can be exchanged are limited to
transmission that is directly required to integrate resources to the
transmission system grid. Specifically, transmission costs which can be
exchanged are limited to the lesser of the costs of transmission
facilities required to transmit power from the generating resource to
the exchanging utility's system or the sum of the costs of the
transmission facilities required to integrate the generating resource to
the BPA system and the wheeling costs necessary to wheel the power to
the exchanging utility's system. If the utility chooses to construct
facilities which are more costly than the facilities required to
interconnect to the BPA system, the total costs to be exchanged shall be
no greater than the facility costs that would have been incurred to
interconnect with the BPA system.
bDistribution plant means all land, structures, conversion equipment,
lines, line transformers, and other facilities employed between the
primary source of supply (i.e., generating station, point of receipt in
the case of purchased power) and of delivery to customers, which are not
includable in transmission system, as defined in footnote a(1), whether
or not such land, structures, and facilities are operated as part of a
transmission system or as part of a distribution system. Stations that
change electricity from transmission to distribution voltage shall be
classified as distribution stations.
Where poles or towers support both transmission and distribution
conductors, the poles, towers, anchors, guys, and rights-of-way shall be
classified as transmission facilities. The conductors shall be
classified as transmission or distribution facilities according to the
purpose for which they are used. Land (other than rights-of-way) and
structures used jointly for transmission and distribution purposes shall
be classified as transmission or distribution according to their major
use.
cContract System Costs shall reflect the costs and the revenues
arising from conservation and/or retail rate schedules implemented to
induce conservation, and for which the utility receives billing credits.
These billing credit revenues shall be functionalized on the same basis
as the cost of the related conservation measures.
dThe overall rate of return to be applied to a utility's Exchange
Period rate base as shown in Appendix 1 shall be equal to its weighted
average cost of long term debt. The utility's overall rate of return
times rate base will equal the utility's return provided that if
depreciation is not used for jurisdictional ratesetting, then return
will be equal to the lessor of: (1) Interest expense plus depreciation,
or (2) debt service and revenue financed captial expenditures. In no
event will the sum of Contract System Cost and Distribution/Other costs
be greater than the revenue requirement used to set rates.
eA tax-exempt utility may include in-lieu taxes up to an amount that
is comparable, for each unit of government paid in-lieu taxes, with
taxes that would have been paid by a nontax exempt utility to that unit
of government. In no event shall the utility's regional total in column
2 be greater than the actual amount paid or the amount used to determine
the total revenue requirement for the test period. In-lieu taxes shall
be functionalized according to a direct analysis included with the
Appendix 1 or to Distribution/Other.
fThe cost of additional resources sufficient to serve any New Large
Single Load that was not contracted for, or committed to, prior to
September 1, 1979, is to be determined as follows:
(1) To the extent that any New Single Loads are served by dedicated
resources, at the cost of those resources, including applicable
transmission;
(2) In the amount that New Large Single Loads are not served by
dedicated resources, at BPA's New Resources rates as established from
time to time pursuant to section 7(f) of the Regional Act and as
applicable to the utility, and applicable BPA transmission charges if
transmission costs are excluded in the determination of BPA's New
Resource rate, to the extent such costs are recovered by the utility's
retail rates in the applicable jurisdiction; and
(3) To the extent that New Large Single Loads are not served by
dedicated resources plus the utility's purchases at the new Resource
Rate, the costs of such excess load shall be determined by multiplying
the kilowatt-hours not served under subsections (1) and (2) above by the
cost (annual fixed plus variable cost, including an appropriate portion
of general plant, administrative and general expense and other items not
directly assignable) per kilowatt-hour of all baseload resources and
long term power purchases (five years or more in duration), as allowed
in the regulatory jurisdiction to establish retail rates during the
Exchange Period, exclusive of the following resources and purchases:
(a) Purchases at the New Resources rate pursuant to section 7(f) of the
Act; (b) purchases at the Federal Base System rate, pursuant to section
5(c) of the Act; (c) resources sold to BPA, pursuant to section 6(c)(1)
of the Act; (d) dedicated resources specified in footnote k(1) of this
methodology; (e) resources and purchases committed to the utility's
load as of September 1, 1979, under a power requirements contract or
that would have been so committed had the utility entered into such a
contract; and (f) experimental or demonstration units or purchases
therefrom. Transmission needed to carry power from such generation
resources or power purchases shall be priced at the average cost of
transmission during the Exchange Period.
(4) Any kilowatt-hours of New Large Single Loads not met under
subsection (1), (2), or (3) above will be assumed to be supplied from
the most recently completed or acquired baseload resource(s) or long
term power purchase(s), exclusive of dedicated resources and
experimental or demonstration resources or purchases therefrom, that are
committed to the utility's load as of September 1, 1979, under a power
requirements contract. The cost of these generation resources and
long-term power purchases and the transmission cost associated with
these resources or purchases will be calculated as specified in
subsection (3) above.
(5) If the New Large Single Load is served on any energy or capacity
interruptive basis, the utility shall prepare a calculation subject to
review by BPA of the fixed (if any) and variable costs of providing such
service, except that the amount excluded from ASC for the New Large
Single Load shall not be less than the transmission and generation cost
included in the retail rate charged the New Large Single Load.
gThe losses shall be the distribution energy losses occurring between
the transmission portion of the utility's system and the meters
measuring firm energy load. Losses shall be established according to a
study (engineering, statistical and other) that is submitted to BPA by
the exchanging utility subject to review by BPA. This study shall be in
sufficient detail so as to accurately identify average distribution
losses associated with the utility's total load, excluded loads, and the
residential load. Distribution losses shall include losses associated
with distribution substations, primary distribution facilities,
distribution transformer, secondary distribution facilities and service
drops.
hCash Working Capital greater than 1/8th Operations and Maintenance
expenses less fuel and purchased power expenses is functionalized to
Distribution/Other. The remainder of Cash Working Capital shall be
functionalized on the basis of Operations and Maintenance expenses less
fuel and purchased power.
iConservation costs are costs of measures or resources for which
power is (or is planned to be) saved by means of physical improvements,
alterations, devices, or other installations which are measurable in
units. A contract charge paid pursuant to BPA's long term conservation
contract will be an allowable conservation cost in Average System cost.
Only conservation cost funded by the utility will be functionalized to
Production in the Utility's Average System Cost. Conservation costs
incurred to promote changes in consumer behavior including costs
attributable to audits, brochures, advertising pamphlets, leaflets, and
similar items, or required by a government entity through building code
provisions or programmatic conservation costs in lieu of building code
provisions, will be functionalized to Distribution/Other. Conservation
surcharges imposed pursuant to section 4(f)(2) of the Northwest Power
Act, or other similar surcharges or penalties imposed on a Utility for
failure to meet required conservation efforts will also be
functionalized to Distribution/Other. Conservation and associated costs
must be generally consistent with the Regional Council's resource plan
as determined by the Administrator.
jFunctionalization:
Except for those accounts that are required to be functionalized
under subsection III(C) below, functionalization of each account
included in the Utility's ASC shall be by either, but not both, of the
following two methods:
(1) Direct analysis, or (2) according to the specific
functionalization ratios applied to the various Uniform System of
Accounts. These two methods are described below in subsections III(A)
and III(B), respectively.
(A) If a Utility has previously functionalized an account by direct
analysis as set forth in subsection III(A) below, the utility is not
allowed to use the specific functionalization ratio method without prior
approval from BPA.
(B) The Utility must submit with its ASC filing any and all
workpapers, documents, or other materials that demonstrate that the
functionalization under its direct analysis assigns costs based upon the
actual and/or intended functional use of those items. Failure to submit
such documentation will result in the entire account being
functionalized to Distribution/Other.
(C) For Accounts 389, 390, 391 and 392 and Accounts 920, 921, 922,
930.2 and 932, the utility may functionalize these accounts using one,
but not any combination, of the following functionalization methods,
whichever assigns the highest cost to the Production and Transmission
function:
1. Subsection III(A) described below;
2. Subsection III(B) described below; or
3. For publicly-owned and cooperative utilities that have neither
generation facilities nor affiliated generation organization over which
the utility exercises over half of the voting rights, 10 percent of
gross plant investment may be assigned directly to Production and 10
percent of labor costs assigned to Production. The remainder of
Accounts 389, 390, 391, and 392 will be functionalized using
Transmission and Distribution Gross Plant Ratios excluding General
Plant.
The remainder of Accounts 920, 921, 922, 930.2 and 932 will be
functionalized usiing the Labor Ratio for Transmission and Distribution,
and the balance assigned to Distribution/Other.
For purposes of subsections III(A) and III(B) Labor Ratios is defined
as the ratios which assign costs on a pro rata basis using salary and
wage data for production, transmission, and distribution/other functions
included in the Test Period costs on which Appendix 1 is based. If
however, this information is unavailable, comparable data shall be used
for the most recent calendar year as reported on the Federal Energy
Regulatory Commission Form 1 (at page 355), or similar document for
those utilities not required to file Federal Energy Regulatory
Commission Form 1.
(A) By direct analysis which assigns costs to either the production,
transmission, or distribution function of the utility. Such analysis is
subject to BPA review and approval.
(B) According to the following specific functionalization methods:
310-373 (Plant in Service) -- Functionalize directly according to the
Federal Energy Regulatory Commission System of Accounts.
389 (Land and Land Rights) -- Functionalize on the ratios of
Production, Transmission and Distribution Gross Plant excluding General
Plant.
390 (Structures and Improvements) -- Functionalize on the ratios of
Production, Transmission and Distribution Gross Plant excluding General
Plant.
391 (Office Furniture and Equipment) -- Labor ratios.
392 (Transportation Equipment) -- Functionalize on the ratio of
Transmission and Distribution Gross Plant excluding General Plant.
393 (Stores Equipment) -- Functionalize on the ratio of Production,
Transmission and Distribution Gross Plant excluding General Plant.
394 (Tools, Shop and Garage Equipment) -- Functionalize on the ratio
of Production, Transmission and Distribution Gross Plant excluding
General Plant.
395 (Laboratory Equipment) -- Functionalize on the ratio of
Production, Transmission and Distribution Gross Plant excluding General
Plant.
396 (Power Operated Equipment) -- Functionalize on the ratio of
Production, Transmission and Distribution Gross Plant excluding General
Plant.
397 (Communication Equipment) -- Functionalize on the ratio of
Production, Transmission and Distribution Gross Plant excluding General
Plant.
398 (Miscellaneous Equipment) -- Functionalize to Distribution/Other.
399 (Other Tangible Property) -- Functionalize on the ratio of
Production, Transmission and Distribution Gross Plant excluding General
Plant.
301-303 (Intangible Plant) -- Functionalize on the ratio of
Production, Transmission and Distribution Gross Plant excluding General
Plant.
114 (Acquisition Adjustment) -- Labor Ratios.
105 (Plant Held for Future Use) -- Functionalize on the ratio of
Production, Transmission and Distribution Gross Plant excluding General
Plant.
120.2-120-4 less 120.5 (Nuclear Fuel) -- Functionalize to Production.
186 (Miscellaneous Debits) -- Labor Ratios.
252 (Customer Advances) -- Functionalize to Distribution/Other.
253 (Other Deferred Credits) -- Functionalize to Distribution/Other.
255 (Accumulated Deferred Investment Tax Credits) -- Functionalize to
Distribution/Other.
257 (Unamortized Gain on Reacquired Debt) -- Functionalize on the
ratio of Production, Transmission and Distribution Gross Plant excluding
General Plant.
281-283 (Accumulated Deferred Income Taxes) -- Functionalize to
Distribution/Other.
151-152 (Fuel Stock) -- Functionalize to Production.
153-157, 163 (Materials and Supplies) -- Functionalize on the ratio
of Transmission and Distribution Gross Plant including General Plant.
106 (Completed Construction not Classified) -- Functionalize on the
ratio of Production, Transmission and Distribution Gross Plant excluding
General Plant.
124 (Other Investment) -- Functionalize to Distribution/Other.
184 (Clearing Accounts) -- Labor Ratios.
Other Rate Base Accounts -- Functionalize to Distribution/Other.
501-577 (Fuel, Purchased Power and Power Production Expenses) --
Functionalize to Production.
560-573 (Transmission Expenses) -- Functionalize to Transmission.
580-598 (Distribution Expenses) -- Functionalize to
Distribution/Other.
901-905 (Customer Accounts Expenses) -- Functionalize to
Distribution/Other.
907 (Customer Service Information Expenses-Supervision) --
Functionalize to Distribution/Other.
908-910 (Other Customer Service Information Expenses) --
Functionalize to Distribution/Other.
911-916 (Sales Expenses) -- Functionalize to Distribution/Other.
920 (Administrative & General Salaries) -- Labor Ratios.
921 (Office Supplies & Expenses) -- Labor Ratios.
922 (Administrative Expenses Transferred-Cr.) -- Labor Ratios.
923 (Outside Services Employed) -- Labor Ratios.
924 (Property Insurance) -- Functionalize on the ratio of Production,
Transmission, and Distribution Gross Plant including General Plant.
925 (Injuries & Damages) -- Labor Ratios.
926 (Employee Pensions & Benefits) -- Labor Ratios.
927 (Franchise Requirements) -- Functionalize to Distribution/Other.
928 (Regulatory Comm. Fees & Expenses) -- Functionalize to
Distribution/Other.
929 (Duplicate Charges-Cr.) -- Labor Ratios.
930.1 (General Advertising) -- Functionalize to Distribution/Other.
930.2 (Miscellaneous General Expenses) -- Functionalize to
Distribution/Other.
931 (Rents) -- Functionalize to Distribution/Other.
447 (Sales For Resale) -- Functionalize to Production.
450-455 (Other Operating Revenues) -- Functionalize to Production.
456 (Wheeling Revenues) -- Functionalize to Transmission.
107, 120.1 (CWIP) -- Functionalize to Distribution/Other.
108 (PIS Depreciation Reserve) -- The same functionalization used for
accounts 310-373, Plant in Service (PIS).
108 (General Plant Depreciation Reserve) -- Functionalize according
to the General Plant ratio.
111 (Accumulated Amortization) -- The same functionalization used for
accounts 301-303, Intangible Plant.
256 (Deferred Gain from Disposition of Utility Plant) -- The same
functionalization used for account 105, Electric Plant Held for Future
Use.
403-407 (PIS Depreciation Expense) -- The same functionalization used
for accounts 310-373, Plant in Service.
408.1 (Other Taxes) -- With the exception of property taxes and labor
related taxes, all taxes will be functionalized to Distribution/Other.
Property taxes will be functionalized using the gross plant ratio
including general plant. Labor related taxes will be functionalized
using labor ratios.
409.1, 410.1, 411.1, 411.4 (Income Taxes) -- Functionalize to
Distribution/Other.
932 (Maintenance of General Plant) -- Functionalize according to the
ratio developed from the functionalized totals of accounts 390, 391, 397
and 398.
411.6, 411.7 (Gain from Disposition of Utility Plant) -- The same
functionalization used for account 105, Plant Held for Future Use.
3031E
(Approved by the Office of Management and Budget under control number
1902-0096)
(46 FR 50520, Oct. 14, 1981. Redesignated and amended by Order 337,
48 FR 46976 and 46977, Oct. 17, 1983; 49 FR 1177, Jan. 10, 1984; Order
400, 49 FR 39301, Oct. 5, 1984)
18 CFR 301.1 -- -- SUBCHAPTER P -- REGULATIONS UNDER THE INTERSTATE COMMERCE ACT
18 CFR 301.1 -- -- PART 340 -- RATE SCHEDULES AND TARIFFS
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352; E.O. 12009, 43 CFR 142; Interstate Commerce Act, 49 U.S.C.
1, et seq. ; Natural Gas Act, 15 U.S.C. 717-717w.
18 CFR 340.1 Suspended rate schedules; procedure; refund requirement;
administered by the Federal Energy Regulatory Commission
(a) Effectiveness of suspended rate schedules. If a rate suspension
proceeding initiated under section 15(7) of the Interstate Commerce Act
has not been concluded and an order has not been issued by the
Commission at the expiration of the suspension period, the proposed
rate, charge, classification, or service shall go into in effect so long
as the pipeline company complies with all of the requirements of this
section.
(b) Recordkeeping. Any pipeline company whose proposed rates or
charges were suspended and have gone into effect pending final order of
the Commission pursuant to section 15(7) of the Interstate Commerce Act
shall keep accurate accounts in detail of all amounts received by reason
of the rates or charges made effective as provided in the Commission's
order, for each billing period, including the following information by
billing period, and by shipper:
(1) The monthly billing determinants of petroleum or petroleum
by-products transported to each consignee under the suspended tariffs;
(2) The revenues which would result from such transportation services
if they were computed under the rates in effect immediately prior to the
date the proposed change became effective, if applicable;
(3) The revenues resulting from such transportation services as
computed under the proposed increased rates or charges that became
effective after the suspension period; and
(4) The difference between the revenues computed in paragraphs (b)(2)
and (3) of this section, if applicable.
(c) Refunds. (1) Any pipeline company that collects charges pursuant
to this section shall refund at such time, in such amounts, and in such
manner as may be required by final order of the Commission, the portion
of any rates and charges found by the Commission in that proceeding not
to be justified, together with interest as required in paragraph (c)(2)
of this section.
(2) Interest shall be computed from the date of collection until the
date refunds are made as follows:
(i) At an average prime rate for each calendar quarter on amounts
held on or after February 11, 1983. The applicable average prime rate
for each calendar quarter shall be the arithmetic mean, to the nearest
one-hundredth of one percent, of the prime rate values published in the
Federal Reserve Bulletin, or in the Federal Reserve's ''Selected
Interest Rates'' (Statistical Release G. 13) for the most recent three
months preceding the beginning of the calendar quarter; and
(ii) The interest required to be paid under paragraph (c)(2)(i) of
this section shall be compounded quarterly.
(3) Any pipeline company required to make refunds pursuant to this
section shall bear all costs of such refunding.
(4) If any rate or charge described in paragraph (a) of this section
that is found not to be justified by the Commission is shared between
two or more pipeline companies, each pipeline company which shared in
the unjustified rates or charges is required to refund to the pipeline
company that published the tariff, not less than five days prior to the
refund date ordered by the Commission under paragraph (c)(1) of this
section,
(i) That portion of the unjustified rates or charges shared, and
(ii) The appropriate interest as required in paragraph (c)(2) of this
section for the period during which the refundable amounts were held.
The pipeline company that published the tariff shall, on the date set
by the Commission in its final order, make refunds with interest to the
appropriate shipper for the full period during which the refundable
amounts were held.
(Order 273, 48 FR 1289; Jan. 12, 1983)
18 CFR 340.1 PART 341 -- OIL PIPELINE TARIFFS: PIPELINE COMPANIES
SUBJECT TO SECTION 6 OF THE INTERSTATE COMMERCE ACT AND CARRIERS JOINTLY
THEREWITH
Sec.
341.0 General provisions; definitions.
341.1 Form size, and arrangement.
341.2 Changes to be indicated in tariff or supplement.
341.3 Contents of tariff title page.
341.4 Content of tariffs.
341.5 Proportional rates.
341.6 Commodity-list tariffs.
341.7 Alternating rates.
341.8 Transfer and cancellation of rates.
341.9 Amendments and supplements.
341.10 Terminal and special services; distance and mileage rates.
341.11 Index of tariffs.
341.12 Restoration and discontinuance of water service.
341.13 Filing tariffs.
341.14 Statutory notice; additional procedure in filing tariffs.
341.15 -- 341.16 (Reserved)
341.17 Tariffs issued through an agent.
341.18 Powers of attorney.
341.19 Concurrences.
341.20 Filing of powers of attorney and concurrences.
341.21 Certificate stating correct name of carrier to be filed.
341.22 Transfer of authority from one agent to another agent.
341.23 Procedure when one publishing agent succeeds another.
341.24 FERC numbers of tariffs issued by a new agent or alternate
agent.
341.25 Powers of attorney and concurrences in special situations.
341.26 Amendment and revocation of powers of attorney and
concurrences.
341.27 Intermediate application of rates.
341.28 Tariff notations in connection with fourth section orders.
341.29 Letter of transmittal.
341.30 Transmission of publications to subscribers.
341.31 -- 341.50 (Reserved)
341.51 Movement of shipments refused by consignees.
341.52 Responsibilities of carriers under tariffs.
341.53 Withdrawal of filed tariffs not permitted.
341.54 Changes in rates.
341.55 Legal rate.
341.56 Reduction of rate to equal the aggregate of the intermediate
rates.
341.57 Newly constructed pipelines.
341.58 Applications under section 6 for authority to make changes in
tariffs.
341.59 Diversion or reconsignment privileges and rules.
341.60 (Reserved)
341.61 Demurrage on interstate shipment.
341.62 -- 341.63 (Reserved)
341.64 In absence of routes, rates apply via lines parties to
tariffs.
341.65 -- 341.66 (Reserved)
341.67 Export and import traffic -- ocean carriers.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (Supp. V 1981); Interstate Commerce Act, 49 U.S.C. 1-27
(1976); E.O. 12009, 3 CFR Part 142 (1978).
Source: 32 FR 20510, Dec. 20, 1967, unless otherwise noted.
Redesignated and amended at 49 FR 12899 and 12906, Mar. 30, 1984.
18 CFR 341.0 General provisions; definitions.
(a) General application; conformation to rules; reissue. (1) This
part contains regulations issued by the Interstate Commerce Commission
under the Interstate Commerce Act, as amended and transferred to the
Federal Energy Regulatory Commission under authority of section 705(a)
of the Department of Energy Organization Act, as amended, to govern the
construction and filing of tariffs of pipeline companies filing under
the Interstate Commerce Act. The regulations in this part shall also
govern the construction and filing of tariffs naming through routes and
joint rates over the lines of common carriers by pipeline subject to the
Interstate Commerce Act, on the one hand, and vessel-operating common
carriers by water engaged in the foreign commerce of the United States,
as defined in the Shipping Act, 1916, on the other hand, for the
transportation of oil between any place in the United States and any
place in a foreign country. See 341.67.
(2) All tariffs filed on or after October 1, 1928, except as
otherwise provided in this part or unless otherwise authorized by
special permission of the Commission, must conform to the rules in this
part. The Commission may direct the reissue of any tariff, power of
attorney, or concurrence at any time.
Cross Reference: For filing tariffs, see 341.13. For provisions
covering statutory notice, additional procedure in filing tariffs,
rejection of tariffs or schedules, see 341.14. For provisions
concerning powers of attorney and concurrences, see 341.17 to 341.26,
inclusive.
(b) Definitions -- (1) Local rate. The term ''local rate,'' as used
in this part, is construed to mean a rate that extends over the lines of
one carrier only.
(2) Local tariffs. ''Local tariffs'' are those which contain ''local
rates.''
(3) Joint rate. The term ''joint rate,'' as used in this part, is
construed to mean a rate that extends over the lines of two or more
carriers and that is made by arrangement or agreement between such
carriers and evidenced by concurrence or power of attorney.
(4) Joint tariffs. ''Joint tariffs'' are those which contain ''joint
rates.''
Cross Reference: For joint tariffs issued by joint agents, see
341.18(e).
(5) Through rate. The term ''through rate'' is construed to mean the
total rate from point of origin to destination. It may be a local rate,
a joint rate, or a combination of separately established rates.
(32 FR 20510, Dec. 20, 1967, as amended at 38 FR 16231, June 21,
1973. Redesignated and amended at 49 FR 12899, Mar. 30, 1984)
18 CFR 341.1 Form size, and arrangement.
(a) All tariffs and supplements thereto must be in book, pamphlet, or
loose-leaf form of size 8 to 8 1/2 inches wide and 10 1/2 to 11 inches
long, and must be plainly printed on hard calendered or No. 1 machine
finished book paper of durable quality using type of size not less than
8-point bold or full face, except as provided in 341.3(b) as to FERC
number and 341.9(k) as to vacation notice and except further that not
less than 6-point bold-face type may be used for reference marks, for
explanation of reference marks when such explanation appears on the page
on which such reference marks appear, and for column headings and other
places where only a few words are used continuously. Stereotype,
planograph, or other similar durable process may be used, provided the
copies posted and filed are clear and legible in all respects.
Reproductions by hectograph or similar process, typewritten sheets or
proof sheets must not be used for posting or filing. Alterations in
writing or erasures must not be made in tariffs filed with the
Commission or posted at points.
(b) A margin of not less than five-eighths of an inch without any
printing thereon must be allowed at the binding edge of each tariff.
When rates or numerals used for other purposes are shown in tables, the
page shall be ruled from top to bottom. When not more than three
figures or letters, including reference characters, are employed, the
columns shall be not less than one-fourth of an inch in width with a
correspondingly greater width when more than three figures or letters,
including reference characters, are employed. In such tables a break in
the printed matter of at least one space across the page or a ruled line
shall appear after each sixth line or less.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
Mar. 30, 1984; 49 FR 44629, Nov. 8, 1984)
18 CFR 341.2 Changes to be indicated in tariff or supplement.
(a) Symbols. (1) All tariff publications and supplements thereto
must indicate changes thereby made in existing rates or charges, rules,
regulations or practices, or classifications by use of the following
uniform symbols in connection with such changes:
to indicate reductions.
# to denote increases.
to denote changes in wording which result in neither increases nor
reductions in charges.
(2) Explanation of such symbols must be provided in the tariff or
supplement in which used, and these symbols shall not be used for any
other purpose.
(3) When a change of the same character is made in all or in
substantially all rates in a tariff or supplement, or a page thereof,
that fact and the nature of such change may be indicated in distinctive
type at the top of the title page of such issue, or at the top of each
page, respectively, in the following manner, ''All rates in this issue
are increases,'' or ''All rates on this page are reductions except as
otherwise provided in connection with the rates.'' Under this paragraph
of the rule a bold-face dot, '' '' must be used to symbolize a rate in
which no change has been made. This symbol must not be used for any
other purpose.
(b) Omissions from previous tariff. When a tariff or supplement
canceling a previous issue omits points of origin or destination, or
rates, ratings, rules or regulations, or routes which were contained in
such previous issue, the new tariff or supplement shall indicate the
cancellation in the manner prescribed in 341.8(e), and if such
omissions effect changes in charges or services that fact shall be
indicated by the use of the uniform symbols prescribed in paragraph (a)
of this section.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12906, Mar. 30, 1984)
18 CFR 341.3 Content of tariff title page.
The title page of every tariff and of every supplement shall show in
the order named:
(a) (Reserved)
(b) On the upper right-hand corner, the FERC identification, in which
each carrier or agent numbers each new issue consecutively. (All
tariffs filed after January 1, 1985 must use a FERC identification
number.) The type shall be bold-face and of not less than 12 point.
Immediately under this number, in smaller type, shall be shown the FERC
number of each tariff or the number of each supplement cancelled
thereby. If the number of cancelled publications is so large as to
render it impracticable to thus enter them on the title page, they must
be shown immediately following the table of contents, provided specific
reference thereto is entered on the title page directly under the FERC
number.
(c) Corporate name of issuing carrier or name of agent issuing under
power of attorney. (See 341.4(b).)
(d) Whether tariff or supplement contains local, joint, proportional,
export, or import rates, or any combination of such rates; whether it
contains commodity rates and whether it contains all pipeline or
intermodal pipeline rates, or any combination of such rates.
(e) The territory or points from and to which the tariff or
supplement applies, briefly stated by Territories, States, points, or
carriers. Where the publication contains both specific and distance or
mileage rates, the title-page description must include the application
of the distance or mileage rates as well as that of the specific rates.
(See 341.4(d).)
(f)(1) Reference by name and FERC number to the rules tariff, if any,
governing the tariff. The following form modified as required shall be
used.
Governed, except as otherwise provided herein, by rules and
regulations shown in FERC No. ---- , by exceptions thereto, supplements
thereto or successive issues thereof.
(2) A tariff is not governed by a rules tariff, except when and to
the extent stated on or in the tariff.
(g) Date of issue and date effective. A provision in a tariff or
supplement that the same or any part thereof, will expire with a given
date, is not a guaranty that the tariff or supplement, or such part of
it, will remain effective until and including that date. Such provision
if used, will be held to mean that the tariff or supplement, or
specified part of it, will expire with the date named, unless the date
is changed on statutory notice, or under authority of special permission
of the Commission. In such tariffs or supplements the term ''Expires
with (date) ------------ , unless sooner canceled, changed or extended''
must be used. The term ''Expires with close of business'' on a named
date must not be used.
(h) On every tariff or supplement in which all the rates, rules, or
regulations are made effective on less than 30 days' notice under
authority of the Commission, notation that it is issued on ------ days'
notice under authority of ------ (here show the authority).
Cross Reference: For exceptions to general effective date, see
341.9(d).
(i) At the bottom of the title page -- name, title and mail address
of the individual actually responsible for compiling and filing the
schedule. If the tariff is issued by a natural person as agent, his
name must be shown with the title of ''Agent.'' If issued by a
corporation or association as agent, the name and title of the person
responsible for the actual compilation and filing must be shown.
(Sec. 310a, 5 U.S.C. 553, 558; 49 U.S.C. 20, 310a, 318, 319, 904,
906, 1003, 1005, 1013; sec. 20, 24 Stat. 386; 49 Stat. 561, 563; sec.
210a, 52 Stat. 1237, 1238; secs. 304, 306, 54 Stat. 933, 935; secs.
403, 405, 413, 56 Stat. 285, 287, 295; 80 Stat. 378; 49 U.S.C. 10762)
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
Mar. 30, 1984; 49 FR 44629, Nov. 8, 1984)
18 CFR 341.4 Content of tariffs.
Tariffs shall contain in the order named:
(a) Table of contents. A full and complete statement, in
alphabetical order, of the exact location where information under
general headings, by subjects, will be found, specifying page or item
numbers. If a tariff contains so small a volume of matter that its
title page or its interior arrangement plainly discloses its contents,
the table of contents may be omitted.
(b) Names of participating carriers. A list, alphabetically
arranged, of the correct names of all carriers participating therein,
together with the form and number of power of attorney or certificate of
concurrence. If there be not more than 10 participating carriers, their
names and power of attorney or concurrence forms and numbers may be
shown on the title page. Reference to the forms and numbers of powers
of attorney and concurrences may be omitted provided this information is
furnished to the Commission in an acceptable form.
Cross Reference: For provisions concerning powers of attorney and
concurrences, see 341.17 to 341.26, inclusive.
(c) Index of commodities. (1) A complete index, alphabetically
arranged, of all articles upon which commodity rates are named therein,
together with reference to each item (or page) where such article is
shown. When nouns are not sufficiently distinctive, articles shall also
be indexed under their adjectives. All of the entries relating to
different kinds or species of the same commodity shall be grouped
together. For example, all items of petroleum ''Petroleum,'' and
descriptive word or words following, as ''Petroleum, crude'', Petroleum
Products, butane,''; etc.
(2) When articles are grouped together in one list under a generic
heading as authorized in paragraph (i)(5) of this section, such generic
heading shall be shown in the index and opposite thereto shall be shown
reference to each item (or page) where the generic term is used. Each
article in the list must be shown separately in its proper alphabetical
order in the index, together with reference to each item (or page) where
such article is shown by name, but reference to the items (or pages)
containing rates applying on the complete list may be omitted provided
reference is given to the generic heading as it appears in the index or
to an item in that tariff which contains a complete list of the articles
covered by the generic term or to the FERC number of a separate tariff
which contains such list.
(3) If all of the commodity rates to each destination in a general
commodity tariff are arranged in alphabetical order by commodities, the
index of commodities may be omitted from that tariff.
Cross Reference: For commodity-list tariffs see 341.6.
(d) Index of origins and destinations. (1) An alphabetical index of
all points from which rates apply, and a separate alphabetical index of
all points to which rates apply together with the names of the States or
Territories in which located, except that when the rates apply in both
directions between all or substantially all of the points, the points of
origin and destination may be shown in one index. Such index or indexes
must contain the item numbers in which rates from or to such points
appear, except that when points are arranged in numerical order or when
points are alphabetically arranged in commodity items, and such
commodity items are referred to in the commodity index prescribed by
paragraph (c) of this section, item numbers and page numbers may be
omitted from the index of points. When item numbers are not used the
index or indexes must contain the index numbers of the points and the
pages on which rates from or to such points will be found, except that
when the index numbers are arranged in the rate tables in numerical
order the page numbers may be omitted from the index. If there be not
more than 12 points of origin or 12 points of destination, the name of
each, if practicable, may be shown in alphabetical order on the title
page of the tariff and the index of such points of origin or
destination, as the case may be, may be omitted.
(2) If rates are shown in the tariff by territorial groups, such as
''Colorado common points,'' ''Chicago and points taking the same
rates,'' or ''Chicago and points taking the same rates and arbitraries
or differentials to be added to or deducted therefrom,'' the indexes of
points of origin and destination required by the paragraph (d)(1) of
this section must show for each point in such groups the pipeline on
which it is located and the group to which it is assigned, except that
where reference is made to a separate publication for lists of points in
such groups, such points may be omitted from the indexes, Provided, That
(i) there is shown in the table of contents specific reference to the
item or page which gives FERC reference to the separate publication, and
(ii), if the tariff contains any index of points, there is shown at the
head of such index FERC reference to the separate publication.
(3) If points of origin or of destination are shown throughout the
tariff of rates, or throughout one or more sections of such tariff,
alphabetically by States, and such States are alphabetically arranged,
or if points of origin or of destination are shown throughout the tariff
of rates in continuous alphabetical order no index of such points of
origin or of destination will be required. But when such alphabetical
arrangement in the tariff is used, the table of contents must refer to
the pages on which points are shown and when arranged by States must
give reference to the pages on which rates from or to points in each
State will be found.
(4) When the application of a tariff is extended to cover additional
points by an intermediate rule as authorized in 341.27, no index of
such points need be shown.
(e) Public holding out. (1) Tariffs must contain only rates,
charges, and related provisions that cover services in strict conformity
with each carrier's public holding out. No provision may be published
in tariffs, supplements, or revised pages which results in restricting
service to less than the carrier's full obligation to the public to
provide and furnish transportation or which exceeds such carrier's
lawful public holding out.
(f) (Reserved)
(g) Explanatory statements. Such explanatory statements in clear and
explicit terms regarding the rates and rules contained in the tariff as
may be necessary to remove all doubt as to their proper application.
(h) Rules governing the tariffs. (1) Rules and regulations which
govern the tariff, the title of the subject of each rule or regulation
to be shown in distinctive type. Under this head all of the rules,
regulations, or conditions which in any way affect the rates named in
the tariff shall be entered, except as otherwise provided in this part.
A special rule affecting a particular item or rate must be specifically
referred to in such item or in connection with such rate.
(2) Each rule or regulation should be given a separate number;
portions which can be understandingly read without recourse to the whole
may be published in separate paragraphs, and such paragraphs be given
subnumbers or letters.
(3) Except as provided in 341.27, no rule or regulation shall be
included which in any way or in any terms authorizes substituting for
any rate named in the tariff a rate found in any other tariff, nor shall
any rule be provided to the effect that traffic of any nature will be
''taken only by special agreement'' or other provision of like import.
(4) Where it is not desirable or practicable to include the governing
rules and regulations in the rate tariff, such rules and regulations may
be seperately published in tariffs filed by an individual carrier or by
an agent. A carrier may have not more than two such rules tariffs, one
published by an individual carrier and the other by an agent, except as
follows: The following tariffs will not be counted in applying the
provisions of this section: Tariffs containing exclusively rules,
regulations, and/or charges applying to the special services covered by
341.10(a); tariffs containing rules and regulations governing the
transportation of explosive materials and other dangerous substances.
(5) Separate publications may be made of the rules and regulations
pertaining to a specific commodity to which reference by FERC number may
be made in tariffs that contain rates on that commodity only, provided
the general rules tariff published under this section shall also contain
a reference as follows:
For rules and regulations applying on ---- (here name commodity) see
FERC No. -- .
(6) When rules or regulations are thus separately published, rate
tariffs may be made subject thereto only by specific FERC reference in
the rate tariff. This reference should be made in substantially the
following form:
Governed, except as otherwise provided herein, by rules and
regulations shown in ---- FERC No. -- , supplements thereto or
successive issues thereof.
(7) When tariffs of joint rates make reference to separate
publications for governing rules and regulations such separate
publications must be concurred in by all of the carriers parties to such
joint rates.
(8) Tariffs which contain rates for the transportation of explosive
materials and other dangerous substances must also contain the hazardous
material regulations of the Department of Transportation governing the
transportation thereof, must bear specific reference to the FERC number
of the publication which contains such rules and regulations. When the
latter plan is adopted, the tariff referred to shall contain no matter
other than the regulations promulgated by the Department of
Transportation.
(i) Rates. (1) An explicit statement of the rates, in cents or in
dollars and cents, per 100 pounds, per ton, per gallon, per barrel, or
other unit, together with the names or designation of the places from
and to which they apply, all arranged in a simple and systematic manner.
Complicated plans or ambiguous terms must not be used.
(2) Insofar as possible such rates should be subdivided into small
sections (by items, index numbers, or similar method) to each of which
should be assigned an identifying number to facilitate reference
thereto.
(3) If all rates in a tariff are stated in the same unit, that fact
may be indicated on the title page immediately in connection with the
application of the tariff. Tariffs containing rates per ton must state
that rates apply per ton of 2,000 pounds or per ton of 2,240 pounds as
the case may be. Where rates are stated in amounts per barrel definite
specifications of the barrels on which such rates apply must be shown or
reference must be made to the FERC number of a publication containing
such specifications.
(4) Minimum volumes governing the application of commodity rates must
be specifically stated in immediate conjunction with such rates or shown
in such manner as will avoid an extensive search therefor, except as
provided in paragraph (i)(5) of this section.
(5) An item of a commodity tariff may provide rates on a group of
related products by means of a generic description and without naming
the individual products, provided such item refers to another item of
the same tariff or to another tariff (as authorized by 341.6(a) and
341.10) which contains under an identical generic description a complete
list of the products included; for example, ''Petroleum products'' as
described under that heading in Item ------ of ------ (Tariff) FERC No.
------ .'' Where cross reference is made to a list of commodities on
which rates apply (as authorized in the preceding sentence), the minimum
volume (or volumes) governing the application of the rates may be
omitted from the commodity-rate item and published with the list of
commodities to which reference is made, provided the commodity-rate item
specifically states that the minimum volume (or volumes) will be found
in the list of commodities referred to.
(6) If a carrier (not an agent) publishes, either for itself or
jointly with other carriers, a tariff containing only commodity rates on
a single commodity or a group of related commodities, it must include
therein all commodity rates which it (not an agent) publishes on the
same product or products from the same points of origin to the same
destination area. If additional commodity rates, local or joint, are
published for it by an agent on the same product or products from any of
the same points of origin to other points in the same destination area,
the individually-published commodity tariff must so state and make
reference to the agency tariff in which the additional rates are
published.
(7) A general commodity tariff shall contain reference to other
tariffs in which rates on other commodities are published from any point
of origin to any point of destination named therein via the same route.
Such reference shall include the FERC number or numbers of such other
tariff or tariffs with a brief description of the character of traffic
and territory or points of origin and of destination and may be shown in
the index, or in alphabetical order in the rate tables, or in a separate
list arranged alphabetically by commodities, such list to be
specifically referred to in the table of contents. For example,
''Butane, from ------ to ------ , ------ FERC No. ------ .'' Carriers'
tariff numbers may also be shown. The publication of commodity rates
which duplicate or conflict with the rates published in some other
tariff via the same route is not permissible and except as otherwise
authorized in 341.7, 341.10(g) and 341.27, the publication of a
statement in a tariff to the effect that the rates published therein
take precedence over the rates published in some other tariff, or that
the rates published in some other tariff take precedence over the rates
published therein, is hereby prohibited.
(j) (Reserved)
(k) Routing. (1) Routing over which the rates apply, stated in such
manner that such routes may be definitely ascertained.
This must be accomplished by one of the following plans: (i) By
providing that the rates in the tariff apply only via the routes
specifically shown therein, or (ii) by providing that the rates apply
via all routes made by use of the pipelines of the carriers parties to
the tariff except as otherwise specifically provided in the tariff.
When it is desired to follow the plan listed in paragraph (k)(1)(i)
of this section and provide complete routing for all rates shown in the
tariff, the following notation must be shown in the tariff under the
heading ''Routing instructions'':
The rates herein apply only via the routes specified on pages (or in
items -- ).
When it is desired to use the plan listed in paragraph (k)(1)(ii) of
this section and provide complete routing for some but not all of the
rates in the tariff, or incomplete routing for all of the rates, the
following notation must be included in the tariff under the heading
''Routing Instructions'':
The rates herein apply via all routes made by use of the pipelines of
any of the carriers parties to this tariff, except as otherwise
specifically provided on pages -- , in individual rate items, or in
connection with individual rates.
The exceptions referred to in the notation shown next preceding may
be provided either by showing affirmative routing, viz, a statement of
routes (for one or more carriers, for all or a part of the route)
together with a definite statement that the rates apply between such
points and for account of such carrier or carriers only via the route or
routes specified; and/or by showing negative routing, viz, a statement
of routes (for one or more carriers, for all or a part of the route) via
which the rates do not apply.
Note: This section does not authorize departures from the
long-and-short-haul provisions of the fourth section of the act.
In lieu of showing in rate tariffs the affirmative routes provided in
the plans listed in paragraphs (k)(1)(i) and/or (ii) of this section
such affirmative routes may be published in a separate publication (or
publications) filed either by a carrier or by an agent, and specific
FERC reference must be made in the rate tariff to such guide. Such a
separate publication will hereinafter be designated as a ''Routing
guide,'' and may be used only in accordance with the provisions of
paragraphs (k)(2)-(5) of this section.
(2) When in a tariff containing joint rates it is desired to refer to
a routing guide or guides for all of the routes, the following notation
shall be used:
The rates herein apply only via the routes of the carriers parties to
this tariff specified in ------ FERC No. ---- , supplements thereto or
successive issues thereof.
When in a tariff containing local rates it is desired to refer to a
routing guide for all of the routes, an appropriate modification of the
notation shown next above shall be used.
When it is desired to refer to a routing guide or guides for routes
in connection with some but not all of the rates in a tariff, or for
routes for account of some but not all of the carriers parties to the
tariff, an appropriate notation in lieu of those above set forth shall
be used. When it is desired to provide that certain rates published in
a tariff will not apply via all the routes shown in a routing guide to
which the rate tariff is made subject, the rate tariff must show clearly
what routes in the routing guide are not applicable, or are the only
routes applicable, in connection with such rates. When a tariff which
refers to a routing guide also shows routes, it must show clearly
whether the routes named therein are in addition to the routes shown in
the routing guide or are the only routes via which the rates will apply.
No one rate may be made subject to more than one routing guide for
account of any initial carrier except that
(i) A subsidiary or small carrier which connects with two or more
parent or connecting carriers may authorize each of such parent or
connecting carriers to publish its routes via each of such carriers and
its joint rates may be made subject to the routing guides of each of
such carriers for routes via which rates apply via their respective
lines; (ii) Where complete through routes are shown in connection with
joint rates (either in the rate tariff or in a routing guide or guides
to which it is subject), such rates may be made subject to the separate
routing guides of any of the carriers parties thereto for internal
routing over their respective lines.
(3) A routing guide must contain three sections, (i) an alphabetical
list of all of the points from and to which routes are provided, with
the pipeline location of each point which is served by more than one
carrier, together with an index number for each of such points, (ii) a
table containing the points from which routes apply, the points to which
routes apply (or between which routes apply), and the numbers of the
routes provided from and to (or between) such points, and (iii) a table
containing all the route numbers in numerical order with a full
statement of the route opposite each of such numbers.
A routing guide must be concurred in by all carriers over whose lines
routes are provided therein. Such guides must not contain exceptions to
the routes provided therein. All exceptions thereto, if any, must be
published in the tariffs making reference thereto.
(4) Routing guides must show on their title pages the following
notation:
The routes provided herein may be used only in connection with rates
made subject thereto by specific FERC reference to this guide in the
tariffs containing such rates. Its use in connection with any tariff is
restricted to the carriers and to the application provided in such
tariff.
(5) If desired, the following tariff provision may be incorporated
under the heading ''Routing instructions'' in rate tariffs:
The rates named in this tariff will apply only via the routes and
junction points authorized herein except that when in the case of
capacity shortage (not an embargo), washout, or other similar emergency,
or through carriers' error, carriers forward shipments via other
junction points of the same carriers or via the pipelines of other
carriers parties to the tariff, the rate to apply will be that specified
in this tariff but not higher than the rate applicable via the route of
movement.
Note: If desired, the words ''or via the lines of other carriers
parties to the tariff'' may be omitted from the emergency routing
clause.
The above clause may not be shown in routing guides. Its publication
in a rate tariff does not relieve carriers from the requirements of the
fourth section of the act via the route used.
(l) (Reserved)
(m) Explanation of abbreviations and reference marks. (1) At the end
of each tariff, except loose-leaf tariffs, there shall appear an
Explanation of Abbreviations, followed by an Explanation of Reference
Marks. Under the Explanation of Abbreviations shall appear an
explanation of all abbreviations used in the tariff, except that
commonly used abbreviations of State names may be omitted, and except
further that the abbreviations of the names of participating carriers
may be explained in the list of such carriers, provided a statement to
that effect is included under the Explanation of Abbreviations.
(2) Under the Explanation of Reference Marks shall appear an
explanation of all reference marks used in the tariff except reference
marks used only once or a few times, which shall be explained on the
page or pages of the tariff on which they appear.
(3) The following reference marks shall be used, and shall only be
used, for the purposes indicated:
to indicate reductions.
# to denote increases.
to denote changes in wording which result in neither increases nor
reductions in charges.
to denote no change in rate. (See 341.2(a).)
+ to denote intrastate application only.
to denote reissued matter. (See 341.9(d).)
(4) At the end of each supplement there shall likewise appear an
Explanation of Abbreviations followed by an Explanation of Reference
Marks. Under those headings shall be shown, subject to the exceptions
stated in the preceding paragraphs of this section, an explanation of
all abbreviations appearing in the supplement which were not explained
in the original tariff (if explained in a prior supplement, the
explanation shall be repeated); and an explanation of all reference
marks appearing in the supplement.
(5) In loose-leaf tariffs an Explanation of Abbreviations followed by
an Explanation of Reference Marks as provided for in this rule may be
shown immediately following the index of points.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12900, Mar. 30, 1984; 49 FR 44629, Nov. 8, 1984)
18 CFR 341.5 Proportional rates.
Tariffs containing proportional rates must clearly and definitely
show the application thereof. If the application is not restricted,
such proportional rates will be useable in connection with any other
applicable rates from or to the proportional rate point. It will not be
permissible for a tariff to state that a proportional rate applies from
(or to) points from (or to) which no through rates are published. Such
a provision is not sufficiently definite to restrict the application of
the rate. If a proportional rate is intended for use on movements
destined to a restricted territory such territory should be clearly
defined. For example, a tariff naming a proportional rate to St. Louis
intended for use on movements destined to Kansas should state that the
rates apply on movements destined to Kansas only.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12900, Mar. 30, 1984)
18 CFR 341.6 Commodity-list tariffs.
(a) A rate tariff may not refer to another rate tariff for a list of
commodities on which rates apply. A separate tariff not containing
rates may be filed either by a carrier or by an agent, showing under
appropriate generic headings lists of commodities which are accorded
common treatment for rate or other tariff purposes; and rate and other
tariffs may be made subject thereto. When any commodity list consists
of less than 20 articles it may not be published in a commodity-list
tariff and must be published in the tariff naming the related rates or
ratings. The commodities in each list shall be alphabetically arranged.
Such tariffs shall be known as general commodity-list tariffs. No
carrier or agent may maintain in effect at any time more than one such
publication.
(b) In addition to one such general commodity-list tariff, a carrier
or agent may file for the same purpose separate tariffs, each containing
under an appropriate generic heading a single list of commodities (not
less than 20, alphabetically arranged). Such publications shall be
known as specific commodity-list tariffs. Rate and other tariffs may be
made subject thereto.
(c) The title page of the tariffs authorized in this section shall
contain the following: (1) In the case of the general commodity-list
tariff, in large type the words ''List of commodities upon which rates
or other provisions affecting charges are published in tariffs making
reference hereto''; and in the case of specific commodity-list tariffs,
in large type the words ''List of (here insert the generic description
of the commodities listed in the tariffs, such as 'petroleum products')
upon which rates or other provisions affecting charges are published in
tariffs making reference hereto;'' and (2) in smaller type ''This tariff
is applicable only in connection with tariffs specifically made subject
hereto.'' Rate or other tariffs governed by a commodity-list tariff
shall, to the extent they are so governed, employ the same generic
descriptions or headings as the commodity-list tariff, followed in each
case by the words ''as shown in Item ------ of ------ FERC No. ------
,'' or language equally definite. Commodity-list tariffs shall contain
no other matter than that authorized in this section, except that they
may contain minimum volumes as authorized by 341.4(i) and except
further that a specific commodity-list tariff may also contain rules
applicable in connection therewith.
(d) All carriers that are parties to a tariff making reference to a
general or specific commodity-list tariff must also be parties to the
tariff so referred to.
(e) Where a tariff contains commodity rates on a given article
(termed in this paragraph the basic article) rates may be provided in
the same tariff on one or more related articles either (1) by a
statement that the rates for the related articles will be specified
amounts more or less than the rates for the basic article between the
same points, or (2) by a table showing in adjoining columns what the
rate for the related articles will be when the rate for the basic
article is a specified amount.
(f) When commodity rates are established, the description of the
commodity must be specific and the rates thereon must not be applied to
analogous products. As far as possible, uniform commodity descriptions
should be used in all tariffs.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12900, Mar. 30, 1984)
18 CFR 341.7 Alternating rates.
(a) Alternative rates or ratings subject to different minimum volume
or quantity limitations. (1) Where it is desired to provide for the
alternating application of rates or ratings subject to different minimum
volume or quantity limitations otherwise than as authorized in paragraph
(b) or (c) of this section, the following procedures must be observed:
(i) Alternating commodity rates must be published together, that is,
in the same item or on the same page of the tariff.
(ii) Alternating ratings must be published in the same item of the
tariff.
(iii) There must be published in the same tariff a note or rule
plainly stating, in substance, that where rates or ratings are so
published the applicable rate on any given shipment will be that which,
subject to the minimum attached thereto, produces the lowest charge.
(b) Alternative use of rates in sectional tariffs. (1) Except as
authorized or required by paragraph (a) of this section, alternation of
rates may be provided by publishing such rates in different sections of
a single tariff in the manner herein prescribed. When alternating rates
are so provided, carriers and publishing agents shall, at frequent
intervals, carefully check the rates in one section against those in
other sections and make proper cancellations to avoid unnecessary
alternation of rates. Alternating reference obviously should not be
given to another section unless that section contains rates which in
fact alternate.
(2) The first page of each section, which shall be known as the title
page of the section, shall contain the number of the section and, if
desired, the application of the rates published in that section. Each
succeeding page of the section shall also bear the section number. The
title page of each section containing alternating rates (not the
non-alternating section hereinafter referred to) shall also contain the
following notation:
If the charge accruing on a given shipment under section ------ or
------ of this tariff is lower than that accruing under this section,
the charge accruing under section ------ or ------ , whichever is lower,
will apply.
(3) Where the purpose is to provide for application of the higher or
highest of the alternating rates or charges, rather than the lower or
lowest of such charges, the foregoing notation and other notations
prescribed in this section shall be appropriately changed.
(4) Each commodity tariff arranged in alternating sections shall also
contain a section hereinafter referred to as the non-alternating
section. That section shall contain only commodity rates which in all
instances result in charges lower than would result from the application
of the commodity rates in any other section. If the tariff contains
only commodity rates, the non-alternating section shall be section 1.
The title page of the non-alternating section shall contain either of
the two following notations, as appropriate:
When rates are published in this section on a given shipment, such
rates will apply to the exclusion of the rates in any other section.
or
When rates are published in this section on a given shipment, such
rates will apply to the exclusion of the rates in any other commodity
section.
(5) The title page of each other commodity section of the tariff
shall contain the following notation preceding that prescribed in
paragraph (b)(2) of this section:
When rates are published in section ------ (the non-alternating
section) on a given shipment, such rates will apply to the exclusion of
the rates in this section.
(6) The publication of alternating rates in different sections of a
tariff is subject to the following restrictions: (i) That commodity
rates in one section may alternate with commodity rates in not more than
two other sections; (ii) that rates published in another tariff may not
be reproduced for purposes of alternation; (iii) that one section of a
tariff may not alternate with more than three other sections; and (iv)
that alternating sections may not be subdivided and, except as
authorized in paragraph (a)(1) of this section, a rate in one section
may not be alternated with a rate in the same section.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12900, Mar. 30, 1984; 49 FR 44629, Nov. 8, 1984)
18 CFR 341.8 Transfer and cancellation of rates.
(a) Transfer of rates from one tariff to another. (1) If a tariff or
supplement to a tariff or a revised page is issued which is to displace
a part of another tariff which is in force at the time, and which tariff
is not thereby canceled in full, it shall specifically state the portion
of such other tariff or such other supplement which is thereby canceled,
and such other tariff shall at the same time be correspondingly amended,
effective on the same date, in the regular way; that is, by reissue if
tariff is of four pages or less, by reissue or supplement if tariff is
of more than four pages, and by revised pages if tariff is a loose-leaf
tariff. (See paragraph (e) of this section and 341.9(e), (k).) Such
reissue, supplement, or revised page must state where rates will
thereafter be found and must be filed at the same time and in connection
with the tariff or supplement which contains the new rates.
Cancellation may be indicated substantially as follows: ''cancels
------ FERC No. ------ , to the extent shown in supplement No. ------
thereto.''
(2) A tariff canceling more than one tariff in whole or in part must
include a brief description of such tariffs.
(3) If a tariff is canceled by the issuance of another tariff to take
its place, cancellation notice must not be given by supplement, but by
notice printed, in the new tariff, as provided in 341.3(b). (See
341.2(b))
(4) Cancellation of a tariff also cancels supplements to such tariff,
if any in effect.
(b) Transfer of rates from carriers' to agents' tariff and from
agents' to carriers' tariff. (1) An agent who acts under authority of
power of attorney is fully authorized to act for the principals that
have named him their agent and attorney, and therefore, when an agent
publishes rates in his tariffs which are to displace the rates in his
principals' tariff, the agent must cancel the rates in his principals'
tariffs as per paragraph (a) of this section.
(2) A carrier must not publish in its individual tariff rates which
are to displace the rates published in a tariff of a duly authorized
agent unless the tariff is accompanied by a supplement issued by the
agent canceling the rates in his tariff effective on the same date, as
per paragraph (a) of this section.
(c) Concurrence does not confer authority to cancel. A concurrence
does not confer authority upon a carrier to cancel tariffs of the
concurring carrier, and tariffs issued under concurrence must not assume
to do so. Such cancellations must be made by the carrier which issued
the tariff that is to be canceled.
(d) Cancellation notice must be by supplement. If a tariff is
canceled with the purpose of canceling entirely the rates named therein,
or when, through error or omission, a later issue failed to cancel the
previous issue and such tariff is canceled for the purpose of perfecting
the records, the cancellation notice must not be given a new FERC
number, but must be issued as a supplement to the tariff (including
loose-leaf tariffs) which it cancels. In the issuance of such
supplement the provisions of 341.9(e) need not be observed.
(e) Notice to specify where rates can be found. When a tariff is
canceled in whole or in part by a supplement thereto, the supplement
must show where the rates will thereafter be found or what rates will
thereafter apply. When a tariff is canceled by another tariff which
does not contain all of the rates shown in the tariff to be canceled the
canceling tariff must show where rates not shown therein will thereafter
be found, or what rates will thereafter apply. For example: ''Rates in
------ FERC No. ------ will apply,'' or ''Combination rates will
apply.'' (See 341.2(b).)
(f) Cancellation by item numbers. (1) When portions of a tariff
(excepting a tariff in loose-leaf form), or of a supplement to a tariff,
are designated as items, they must be given numbers and the cancellation
of an item by supplement must be made by bringing forward the item
number with a capital letter suffix in alphabetical sequence. For
example, if Item 445 is to be canceled, it shall be done by one of the
following methods:
State the numbers of both the canceling and the canceled item. For
example: ''Item 445-A cancels Item 445.''
or
Bring forward the item number with letter suffix; for example:
''Item 445-A'', ''Item 445-B''. When cancellation under this method is
used the following provision is to be published in the general rules
section of the tariff proper:
As this tariff is supplemented numbered items with letter suffixes
cancel correspondingly numbered items in the original tariff or in a
prior supplement. Letter suffixes will be used in alphabetical sequence
starting with A. Example: Item 445-A cancels Item 445, and Item 365-B
cancels Item 365-A in a prior supplement, which in turn canceled Item
365.
(2) When special circumstances require, appropriate variations of the
above methods may be used. For example, if an item is to be republished
on the same or an earlier effective date, the following may be used:
''Item 40-B cancels Item 40-A and 40.''
(3) When due to suspension or other circumstances, a portion of an
item is to be canceled or items cannot be canceled in consecutive
sequence, the following may be used: ''Item 40-B cancels Item 40-A
except portions under suspension.'' or ''Item 40-B cancels Item 40-A and
completes the cancellation of Item 40.''
(4) If an item or any part thereof is transferred to another item of
different number in the same tariff, the cancellation must be carried
under the original item number and must show in what item or items the
effective rates are to be found.
(5) If an item is withdrawn in its entirety, leaving no rates or
provisions in effect in that item, the cancellation must be brought
forward in subsequent supplements as a reissued item.
(6) If an item in a supplement expires by its own terms, and that
supplement is canceled by a subsequent supplement, the item, or more
accurately, the item number, must be brought forward in the new
supplement, together with a statement reading, ''Expired with ------
(date), in Supplement ------ .''
(7) An item once lawfully eliminated by cancellation or expiration
may not be reinstated except by republication under a new effective
date. Such republication must be under the same item number and must be
given the next letter suffix. For example: If the canceling item is
445-B then the newly published item should be numbered 445-C.
(8) When withdrawing a rule or item designated by an item number the
canceled matter need not be reproduced in connection with the item
effecting the cancellation except to the extent necessary to identify
the item.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
12901, Mar. 30, 1984)
18 CFR 341.9 Amendments and supplements.
(a) Amendment procedure. (1) A change in or addition to a tariff
shall be known as an amendment, and, excepting amendments to tariffs of
less than five pages and amendments to tariffs in loose-leaf form, shall
be published in a supplement to the tariff. When an amendment is made
in a numbered item or other unit, such item or other unit must be
published in a supplement in its entirety as amended, except that
additions, changes, or eliminations in a numbered item or other unit
consisting of a list of commodities or a list of points comprising 10
lines or more (measured along the left margin), may be made without
publishing such items or units as amended in their entirety, provided
that only one such partial amendment of any such item or unit may be in
effect at any one time. When rates are published in numbered items,
cancellation shall be made as prescribed in 341.8(f). When rates are
published in numbered units other than item numbers, supplements
effecting such change must specifically provide for cancellation of
previously effective matter by reference to the number of the unit it
cancels. When such a change is made in matter published in a supplement
in a numbered unit other than an item, the new supplement must also give
reference by number to the previous supplement. In those instances
where matter is not published in numbered units, the changed provision
must be published in the supplement in its entirety and reference must
be made to the page or pages of the tariff on which the matter to be
canceled is shown. If such matter has been canceled by a previous
supplement, specific cancellation must be made of the corresponding
matter in the ''tariff as amended'' and specific reference shall be made
by number to page or pages of the previous supplement containing the
matter to be changed, and to the page or pages of the original tariff
formerly containing such matter corresponding thereto.
(2) The matter contained in each supplement shall be arranged in the
same general manner and order as in the tariff which it amends and when
points in a tariff are given index numbers the same index number must be
assigned to the same point in all supplements to the tariff.
(b) Cancellation of rates when participating carrier is eliminated.
When a participating carrier is eliminated by supplement or by a revised
page of a loose-leaf tariff, the tariff must be amended on the same
effective date to provide for the cancellation of rates and other
provisions in connection with that carrier. This may be done either by
appropriate amendment of the individual items or provisions, or by a
notation immediately following the statement that the carrier has been
eliminated, reading:
This has the effect of canceling all rates and other provisions
published in connection with this carrier in this tariff.
(1) When the notation method is used in a supplement the notation
must be brought forward as reissued matter, together with reference to
the supplement in which the change first appeared.
(2) When the notation method is used in loose-leaf tariffs,
subsequent revised pages containing the list of participating carriers
must bear reference to such elimination so long as the name of the
eliminated carrier appears elsewhere in the tariff, the reference to be
shown in the following manner:
(Show name of carrier here)
eliminated as a participating carrier in this tariff and all rates
and other provisions published in connection with that carrier canceled
effective ------ . See ------ Revised Page ------ .
(c) Supplement number and cancellations. Supplements to a tariff
shall be numbered consecutively. Each supplement shall specify on its
title page the supplement or supplements or tariff or tariffs which it
cancels, and shall also show what supplements contain actual changes
from the rates, rules, or regulations in the original tariff.
Supplements filed under the authority of paragraphs (i), (j), (k), (m)
of this section, and 341.12(d), and blanket or special supplements that
do not change rates, rules or regulations, must be shown separately and
the nature of each such supplement must be clearly indicated.
(d) Effective date; reissued matter. (1) Every publication which
contains rates, rules, or regulations effective upon a date different
from the general effective date of such publication must show on its
title page the following notation:
''Effective ------ , 19 -- , (except as otherwise provided herein)''
or ''except as provided in Item -- )'' or ''(except as provided on page
-- ).''
(2) Every publication which consists partly but not wholly of matter
established upon less than statutory notice shall show in connection
with each change made effective on less than statutory notice a notation
that such matter is issued on ------ days' notice under authority of
------ , (here give specific reference to the special permission,
decision, order, rule, or other authority).
(3) Matter brought forward without change from a tariff which has not
been in effect 30 days, also matter brought forward without change from
one supplement to another, must be designated ''Reissued'' in
distinctive type and must show the original effective date and the
number of the supplement or tariff from which it is reissued; or must
be uniformly indicated by the letter T in a square when reissued from
another tariff or from a supplement to another tariff and by numerals
commencing with 1 in squares when reissued from a prior supplement to
the same tariff, printed in distinctive type and shown in a conspicuous
manner, and the explanation thereof must be made in the tariff or
supplement in which the symbols are used. Examples: ''1 Reissued from
FERC No. ------ or (supplement No. ------ to FERC No. ------ ),
effective (date upon which item became effective in former tariff or
supplement to another tariff ------ , 19 -- )''; ''1 Reissued from
Supplement No. 1, effective ------ ,
19 -- '', and so on numerically, the figures of the symbols always
representing the number of the supplement to the same tariff from which
the reissued item is brought forward. If items in a tariff or
supplement are made effective on dates other than the general effective
date shown on the title page, reissue of such items may be indicated in
later publications by showing a letter suffix or other symbol in
connection with, and as a part of, the letter T or the numerals in
squares as authorized in this paragraph. When the reissued item became
effective in a supplement to another tariff, the FERC number of that
tariff must also be given.
(4) The letter T in a square and numerals commencing with 1 in a
square shall not be used as reference marks or symbols for any other
purpose in any tariff or supplement.
(e) Amount of supplemental matter; loose-leaf tariffs. (1) Except
as authorized in 341.8(d), paragraphs (i), (j), (k), (m) of this
section, 341.11 and 341.12(d), the following is the maximum number of
effective supplements permitted to any tariff:
4 pages or less -- No supplements.
5 to 16 pages, inclusive -- 1 supplement.
17 to 80 pages, inclusive -- 2 supplements.
81 to 200 pages, inclusive -- 3 supplements.
201 pages or more -- 4 supplements.
In addition to the above, tariffs of 17 pages or more may have one
additional supplement not exceeding 4 pages.
(2) Except as authorized in 341.8(d), paragraphs (f), (h), (i),
(j), (k), (m) of this section, 341.11 and 341.12(d), tariffs having 5 or
more pages may have supplemental matter aggregating not more than 50
percent of the total number of pages in the tariff, except that if the
number of pages in the supplement which brings the volume up to that
authorized by this rule is not evenly divisible by 4, it may exceed the
volume authorized to the extent necessary to bring the number of pages
of such supplement to the next multiple of 4. The concluding page or
pages of supplements on which appear only explanations of abbreviations
and reference marks shall not be counted in applying this paragraph.
(3) The provisions of paragraphs (a), (b) of this section will also
apply to tariffs filed prior to October 1, 1928.
(4) Pages of loose-leaf tariffs shall be printed on thin paper of
strong texture, on one side only, and must be consecutively numbered and
designated as ''Original page 1,'' ''Original page 2,'' etc. Each page
must show at the top of the page the name of the issuing carrier, or of
the issuing agent (identified as ''Agent''). If the issuing agent is a
corporation or association, there shall also be shown the full name of
the bureau, committee or regional association, if any, under whose
auspices the schedule is compiled and filed. It shall also show the
page number and the FERC number of the tariff. At the bottom of the
page shall be shown the date of issue, the effective date, and the name,
title, and mail address of the individual actually responsible for
compiling and filing the schedule. If the tariff is issued by an
individual agent, his name must be shown with the title of ''Agent.'' If
issued by a corporation or association as agent, the name and title of
the person responsible for the actual compilation and filing must be
shown.
(5) Changes in and additions to loose-leaf tariffs shall be made by
reprinting the page upon which change or addition is made, and such
changed page shall be designated as a revised page. For example,
''First revised page 1 cancels original page 1,'' or ''Second revised
page 2 cancels first revised page 2,'' etc. When a revised title-page
is issued the following notation shall be shown in connection with its
effective date:
Original tariff effective
(here show effective date of the original tariff).
(6) If on account of expansion of matter on any page it becomes
necessary to add an additional page in order to take care of the
additional matter, such additional page shall be given the same number
with a letter suffix; for example ''Original page 4-A,'' ''Original
page 4-B,'' etc. If it is necessary to change matter on original page
4-A it may be done by issuing first revised page 4-A, which shall
provide for the cancellation of original page 4-A.
(7) When a revised page is issued which omits rates, rules, or
regulations theretofore published on the page which it cancels, and such
rates, rules, or regulations are published on another page, the revised
page must make specific reference to the page on which the rates, rules,
or regulations will be found, and the page to which reference is so made
must contain the following notation in connection with such rates,
rules, regulations, etc.:
For
(here insert rates, rules, regulations, etc., as case may be) in
effect prior to the effective date hereof see page -- .
Subsequently revised pages of the same number must omit this notation
insofar as this particular matter is concerned.
(8) If after a tariff has been filed with the Commission it is
desired to file additional pages, such pages may be subsequently filed
to the tariff and numbered beginning with the next successive page
number to the last page of the tariff, and must be designated as
''Original page -- .'' For example, when the tariff filed has 150 pages,
page 151 when filed must not be designated as an ''Additional'' page but
should be designated as ''Original page 151.'' Such a page can be filed
only for the purpose of adding new matter which does not change the
rates, rules, or regulations then in force on other pages of the tariff.
(9) The page of every loose-leaf tariff next to the title page shall
be designated as ''Original page 1'' and shall be known as a ''check
sheet.'' When the original tariff is filed the check sheet must show the
number of pages contained in the tariff. For example, ''Pages 1 to 150,
inclusive, of this tariff are effective as of the date shown.'' When new
pages numbered 151, 152, etc., are added, the above notation must be
correspondingly revised to include the added pages. When pages are
revised, when new pages (including pages with letter suffix) are added
to the tariff, or when supplements are issued the check sheet must be
revised accordingly and, in addition to the above notation, shall show
under the heading ''Original and revised pages as named below and
supplement No. ---- contain all changes from the original tariff that
are in effect on the date hereof'' in numerical order a list of all
original pages that have been added to the tariff and the pages which
have been revised, including the revision number. For example:
(10) Revised check sheets listing the added or revised pages must
accompany such pages when forwarded to the Commission for filing.
(11) Changes shall be indicated as required by 341.2(a). Items which
have been in effect 30 days or more need not be shown as reissued items
on revised pages but may be republished as effective on 30 days' notice.
Items which have not been in effect 30 days when brought forward on
revised page must be shown as reissued in the manner prescribed in
paragraph (d) of this section.
(12) When protective covers for loose-leaf tariffs are used, only
such information should appear thereon as will remain constant and in
use during the life of the tariffs.
(13) Supplements shall not be issued to loose-leaf tariffs, except
for the purposes authorized by paragraphs (i), (j), and (k) of this
section, and 341.12(d). When all changes made by a supplement to a
loose-leaf tariff have been incorporated in the tariff proper by
revision of the appropriate pages, the supplement shall be canceled.
Such cancellation must be made by the reissue of the check sheet page
(page 1) and by adding in the upper right-hand corner immediately
following the words ''cancels revised page 1'' the words ''also cancels
Supplement No. ------ .''
(f) Periodical tariffs. A tariff may provide that it will be
reissued periodically, but not less frequently than once a year. Such
tariff must carry on its title page the notation:
A reissue of this tariff will become effective not later than ------
, 19 -- .
Supplements may be issued to such tariffs without limit as to volume.
(g) Index to supplement. (1) A supplement of 5 or more pages must
have an index of the matter which it contains, and a supplement of more
than 23 pages must also contain a table of contents. In view of the
provision of 341.8(f) which requires that cancellation of a numbered
item must be made under the same item number in a supplement as that
given to that item in the tariff, and the requirement of paragraph (a)
of this section which provides that the index number assigned to a point
in a supplement must be the number assigned to that point in the tariff,
the table of contents and indexes in a supplement of five or more pages
need not contain therein entries which are shown in the table of
contents or indexes in the tariff: Provided, That in connection with
the index of points of origin (or destination) the following notation
shall be shown:
The index numbers of points in this supplement correspond with the
index numbers of the same points shown on pages -- to -- , inclusive, of
the tariff, with the following additions and exceptions.
(2) The table of contents and indexes in such a supplement may be
omitted if 341.4 does not require the tariff, to which the supplement
is issued, to contain a table of contents and indexes.
(h) Supplement to tariff filed not yet effective. (1) If a tariff is
filed on statutory notice cancelling another tariff and after such
filing a supplement to the tariff to be so cancelled should be issued
effective prior to the general effective date of such new tariff, rates
in such supplement could not continue in effect for the 30 days required
by law because the cancellation of the former tariff also cancels
supplements to it. In such a case, and confined to additions or to
changes in rates or provisions which were brought forward in the new
tariff without change, the provisions of paragraph (e) of this section
need not be observed as to the old tariff, and a supplement making the
same changes in or additions to both tariffs may be issued as
supplements both to the tariff in effect and to the tariff which will
effect cancellation, and be given both FERC numbers. In other words,
such issue must be a supplement both to the old and the new tariffs and
copies must be posted and filed accordingly. Only one such supplement
may be in effect at any time.
(2) Rates or provisions which have been established in an old tariff
and reproduced or reissued in a new tariff may be changed upon lawful
notice by supplement to the new tariff, effective not earlier than the
general effective date of the new tariff, by showing in the following
manner in connection with the changed rates or provisions that the rates
or provisions changed thereby have been in effect 30 days or more, in
the former issue. Example: ''Item 40-A cancels item 40. Item 40
effective ------ , brought forward without change from Item No. ------
of FERC No. ------ (former issue).'' New rates or provisions which do
not change rates or provisions in either the old or new tariff may be
established upon lawful notice by supplement to the new tariff,
effective not earlier than the general effective date of the new tariff,
by showing in the following manner, in connection with the new rates or
provisions that the rates or provisions previously applicable have been
in effect 30 days or more in a former issue, Example: ''Addition.
Changes commodity rates which became effective ------ in FERC No.
------ .'' Unless the provisions of this paragraph are complied with no
supplement to a tariff that is on file and not yet effective may be made
effective within 30 days from the effective date of the tariff without
special permission.
This section does not waive the requirements of 341.14 and 341.54.
Cross Reference: For additional procedure of statutory notice in
filing tariffs, see 341.13.
(i) Complete adoption notice. (1) When the name of a carrier is
changed, or when its operating control is transferred to another company
the carrier which will thereafter operate the properties shall file and
post an adoption notice, numbered in its FERC series, reading as
follows:
The ------ (corporate name of adopting carrier) hereby adopts,
ratifies, and makes its own, in every respect as if the same had been
originally filed and posted by it, all tariffs, rules, notices,
concurrences, movement agreements, divisions, authorities, powers of
attorney, or other instruments whatsoever, including supplements or
amendments thereto, filed with the Federal Energy Regulatory Commission
by or heretofore adopted by, the ------ (corporate name of old company)
prior to ------ (date).
(2) In addition to the above adoption notice the new carrier shall
immediately file a consecutively numbered supplement to each of the
tariffs covered by the adoption notice, reading as follows:
Effective ------ (here insert date shown in the adoption notice) this
tariff, or as amended, became the tariff of the ------------ (corporate
name of new carrier) as per its adoption notice FERC No. ------ .
(3) Such supplements issued under authority of this section must
contain no other matter, must bear reference to this section and may be
issued without regard to the provisions of paragraph (e) of this
section.
(4) Succeeding supplements to such tariffs filed by the adopting
carrier must be numbered consecutively following the number of the
adoption supplement. New tariffs reissuing or succeeding such tariffs
shall be numbered in the FERC series of the adopting carrier. When
adopted tariffs are canceled by new tariffs of the adopting carrier, the
cancellation reference must describe the canceled tariff by using the
name or initials of the former issuing carrier.
(5) Tariffs issued by other carriers or agents in which the pipeline
absorbed, taken over, operated by another carrier, or whose name is
changed, is named as a participating carrier, shall be amended on
statutory notice, to eliminate the name of the old carrier and to show
the name of the new carrier by the first subsequent supplement. Such
supplement shall also contain the following provision:
The ------ (corporate name of adopting carrier) by its adoption
notice FERC No. ------ having taken over tariffs, etc., of the ------
(corporate name of old carrier) the ------ (corporate name of adopting
carrier) is hereby substituted for the ------ (corporate name of old
carrier) wherever it appears in this tariff.
(6) A similar adoption notice must immediately be filed by a receiver
when he assumes possession and control of a carrier's lines. The
adoption notice bears a FERC number and it must be consecutively
numbered in the FERC series of the adopted carrier. When the
receivership is terminated, the carrier taking over the properties shall
file an adoption notice and shall also file supplements as hereinabove
prescribed if a change in the name of the carrier has been made.
(7) Notices of adoption should be filed with the Commission
immediately, and if possible, on or before the date shown therein.
Copies must be sent to each agent or carrier to which power of attorney
or concurrence has been given. The notice must refer to this section
and its effective date must be the date (as shown in body of notice) on
which the change in name or operation occurs. If prior approval of such
change is necessary, reference must also be made to the order of the
Commission.
(8) Concurrences and powers of attorney adopted by a carrier or a
receiver must within 120 days be replaced and superseded by new
concurrences and powers of attorney issued by and numbered in the series
of the new carrier or receiver except that if desired the receiver may
number concurrences and powers of attorney in the old series. The
cancellation reference to the former concurrence or power of attorney
must include name or initials of the former issuing carrier.
Concurrences and powers of attorney which will not be replaced by new
issues must be regularly revoked on the notice and in the manner
prescribed in 341.26(b).
(9) If a carrier ceases operation without having a successor, its
tariffs, concurrences, and powers of attorney must be regularly canceled
on statutory notice, unless otherwise specifically provided by order of
the Commission and when canceled on less than statutory notice the
cancellation notice must show that cancellation is made on account of
discontinuance of operation and must refer to the authority of the
Commission permitting such discontinuance.
Cross Reference: For provisions concerning powers of attorney and
concurrences, see 341.18 to 341.26, inclusive.
(j) Partial adoption notice. (1) When the operating control of only
a part of a carrier's properties is transferred to another company, the
carrier which will thereafter operate the properties shall file and post
an adoption notice, numbered in its FERC series, reading as follows:
The ------ (corporate name of adopting carrier) hereby adopts,
ratifies, and makes its own, in every respect as if the same had been
originally filed and posted by it, all freight tariffs, rules, notices,
concurrences, movement agreements, divisions, authorities, powers of
attorney, or other instruments whatsoever, including supplements or
amendments thereto, filed with the Federal Energy Regulatory Commission
by the ------ (corporate name of old carrier) prior to ------ (date) in
so far as said instruments apply from, to, at, or via the following
points ------ (naming them).
(2) If, on the transferred portion, there is a junction point which
will remain a point on the old line as well as being established as a
point on the new line, a note or reference mark may be provided in
connection with the name of such point and explained substantially as
follows:
This adoption notice does not have the effect of eliminating ------
as a point on ------ (corporate name of old carrier), but has the effect
of establishing said point also as a point on ------ (corporate name of
adopting carrier).
(3) In addition to the adoption notice in paragraph (j)(2) of this
section the old carrier shall immediately file, under proper concurrence
from the adopting carrier, a supplement to each of the tariffs covered
by the adoption notice reading as follows:
Effective ------ (here insert date shown in the adoption notice),
this tariff or as amended, in so far as it contains rates, rules, and/or
regulations applying from, to, at, or via the following points ------
(naming them), became the tariff of the ------ (corporate name of
adopting carrier as per adoption notice FERC No. ------ of ------
(corporate name of adopting carrier).
(4) Such supplements must contain no other matter, must bear
reference to this section, and may be issued without regard to the
provisions of paragraph (e) of this section.
(5) Rates applying locally between points on the transferred portion
shall as quickly as possible be transferred to tariffs of the adopting
carrier. In all instances where rates are transferred from tariffs of
the old carrier to tariffs of the adopting carrier, the adopting carrier
shall establish the rates in its tariffs and the old carrier shall
cancel the corresponding rates from its tariffs effective on the same
date with a reference to the FERC number of the adopting carrier for
rates applying thereafter.
(6) Tariffs issued by other carriers or agents, in which the pipeline
absorbed, taken over, or operated in part by another carrier is named as
a participating carrier, shall be amended on statutory notice, to add
the new carrier as a participating carrier by the first subsequent
supplement. Such supplement shall also contain the following provision:
The ------ (corporate name of adopting carrier) by its adoption
notice FERC No. ------ , having taken over tariffs, etc., of the ------
(corporate name of old carrier) in so far as they contain rates,
charges, rules, or regulations applying from, to, at, or via the
following points ------ (naming them), the ------ (corporate name of
adopting carrier) is hereby substituted for the ------ (corporate name
of old carrier) wherever the latter appears in this tariff in connection
with said points and rates.
(7) Similar adoption notice numbered in the FERC series of the
carrier must immediately be filed by a receiver when he assumes
possession and control of part of a carrier's lines. When the
receivership is terminated, the carrier taking over the properties shall
file an adoption notice and shall also file supplements as prescribed in
this section if a change in the name of the carrier has been made.
(8) Notices of adoption should be filed with the Commission
immediately, and if possible, on or before the date shown therein.
Copies must be sent to each agent or carrier to which power of attorney
or concurrence has been given. The notice must refer to this rule and
its effective date must be the date (as shown in body of notice) on
which the change in name or operation occurs. If prior approval of such
change is necessary, reference must also be made to the order of the
Commission.
(k) Suspension of tariff schedules. (1) Upon receipt of an order
suspending any tariff or portion thereof, the carrier or agent who filed
such tariff shall immediately file with the Commission a supplement, not
bearing an effective date, which shall contain a reproduction of the
pertinent portions of the Commission's order of suspension (including
the paragraph prohibiting changes in the suspended matter), followed by
a statement that by reason of the Commission's order (i) the use and
application of the suspended publication or portions thereof (which must
be identified with certainty) is either indefinitely deferred or
deferred for the period prescribed in the Commission's suspension order
and (ii) the schedules which were to be changed by the suspended
publication (which schedules must also be identified with certainty)
will remain in effect and will not be changed so long as effectiveness
of the suspended matter is deferred (if deferred only for the term of
the Commission's order, the date must be specified), except by order or
special permission of the Commission.
(2) If the responsible carrier or publishing agent has elected to
file a supplement deferring the suspended matter only for the period
prescribed by the Commission's order, and if prior to the expiration of
that order, the Commission formally or informally requests that a
further deferment be made, the carrier or publishing agent may, under
the authority of this section, issue a supplement effecting such further
deferment. Where suspended matter has previously been deferred under
the authority of this section, the carrier or publishing agent may, when
requested by the Commission and prior to the date to which the matter is
postponed, issue a supplement under the authority of this section,
further postponing the effective date of the matter originally
suspended. Supplements issued should be filed on statutory notice if
practicable, and otherwise on shorter notice, but the notice shall be as
long as time will reasonably permit and in no event less than one day.
Where the effectiveness of matter originally suspended by the Commission
has been voluntarily postponed beyond the term of the Commission's
order, no change during the period of such voluntary postponement may be
made in the tariff matter which was originally held in force by the
Commission's suspension order, except by order or special permission of
the Commission.
(3) Where, following the entry of a report and order in an
investigation and suspension proceeding, a further order is entered in
such proceeding postponing the effective date or requirement of the
original order, the carrier or publishing agent, under authority of this
section, may issue a supplement effecting such further deferment of the
suspended schedule, and may also issue a supplement to announce
postponement of the effective date of a cancellation or vacation
supplement or notice filed following the entry of such report and order,
to and including a date immediately preceding the effective date fixed
in the further order effecting the postponement. Further, where
pursuant to the provisions of section 17(8) of the Interstate Commerce
Act, the filing of an application for rehearing, reargument, or
reconsideration stays the order fixing the effective date of a
requirement or other action in an investigation and suspension
proceeding, as evidenced by notice of the Commission to the parties, the
carrier or publishing agent, under authority of this section, may issue
a supplement effecting further deferment of the schedule under
suspension or under voluntary postponement, and may also issue a
supplement to announce postponement of the effective date of a
cancellation or vacation supplement or notice that was filed following
the entry of the report and order in such investigation and suspension
proceeding. (Postponement should be to the last day of the suspension
period prescribed in the suspension order, except where the responsible
carrier or publishing agent elects to defer the use of the suspended
schedule beyond the statutory period of suspension, in which event
postponement should be until the date upon which the supplement
announcing such postponement is canceled.) Supplements issued should be
filed on statutory notice if practicable, and otherwise on shorter
notice, but the notice shall be as long as time will reasonably permit
and in no event less than one day.
(4) When the Commission has suspended a supplement in whole or in
part, it sometimes occurs that prior to the filing of the supplement
announcing suspension, a later supplement has been filed which purports
to reissue the suspended matter. In such instances the suspension
supplement required by this section shall also (i) specifically cancel
from the later supplement such reissued matter, and (ii) amend the
cancellation notice on the title page of said supplement so as to except
the suspended matter from the cancellation. Tardiness in filing
supplements announcing suspension may result in the rejection by the
Commission of the supplement which cancels the suspended matter.
(5) When the Commission suspends an entire tariff, the previous
tariff and effective supplements are continued in effect and will remain
in force during the period of suspension or until lawfully canceled or
reissued. Except as to loose-leaf tariffs and tariffs of less than five
pages, supplements containing additions and/or changes in rates or other
provisions which were not sought to be changed by the suspended tariff
may be filed to the previous tariff without regard to the volume of
supplemental matter which the effective supplements in the aggregate may
contain. If the volume of supplemental matter permitted by paragraph
(e) of this section has been exceeded under authority of this paragraph,
and the Commission orders the cancellation of the suspended tariff, the
volume of supplemental matter must be brought within the requirements of
paragraph (e) of this section by schedule filed within 90 days, or such
tariff must be reissued in accordance with the following: If consisting
of less than 100 pages, by schedule filed within 90 days, and if
consisting of 100 or more pages, by schedule filed within 120 days, from
date upon which the suspended tariff is canceled.
(6) When the Commission suspends an entire supplement, the supplement
will not be counted in the number of supplements nor in the volume of
supplemental matter permitted by paragraph (e) of this section; nor in
the event of suspension of a portion of a supplement will that
supplement be so counted after all matter therein except the suspended
portions has been reissued in or canceled by a subsequent supplement.
Such subsequent supplement shall cancel the supplement containing the
suspended matter ''except portions under suspension in Docket No. IS
------ , viz (identifying the suspended portion by item and page
number).''
(7) When a tariff (not a supplement), any portion of which is under
suspension, is canceled, the new tariff may either (i) cancel the
previous tariff ''except portions under suspension in Docket No. IS
------ , viz, (identifying the suspended matter and the matter held in
force by the suspension order by item and page number),'' or (ii) cancel
the previous tariff entirely and bring forward without change the matter
held in force by the order of suspension, followed immediately by the
matter under suspension. The matter held in force by the order of
suspension must be identified as such and shown as expiring with the
date to which the suspended matter has been postponed. The suspended
matter immediately following must likewise be identified as such and
shown as effective on the day following the expiration of the matter
held in force by the order of suspension.
(8) When an order of suspension relates to a portion of a new tariff
or a supplement thereto, intended to supersede completely a readily
identifiable item (or other unit) in the prior tariff, such matter as is
continued in effect by the order of suspension may be published (see
Note following paragraph (k)(9) of this section) in the supplement
announcing suspension. When so published the following notation must be
provided in connection therewith, either as a note or in the form of a
reference mark:
The matter subject to this (note or reference mark as the case may
be) is reissued from tariff FERC ------ and is continued in effect by
the terms of the order of suspension in Docket No. IS ------ , and
unless it is sooner canceled, changed, or extended, will expire with
------ . (The date to be shown will be the date to which the suspended
matter has been postponed.)
(9) When an order suspends a particular rate or rates or a portion of
matter in an item (or other unit) in a new tariff and the matter
remaining in effect in a prior tariff thereby becomes an integral part
of such item (or other unit) of the new tariff, the entire item (or
other unit) of the new tariff may be republished in the supplement
announcing the suspension, provided there is shown in such item (or
other unit), (i) the matter continued in effect by reason of the order
of suspension, (ii) the suspended matter, and (iii) all other provisions
of the item (or other unit) without change and appropriately indicated
as reissued from the new tariff (see Note following this paragraph).
The matter held in force by the order of suspension must be identified
as such and shown as expiring with the date to which the suspended
matter has been postponed. The suspended matter immediately following
must likewise be identified as such and shown as effective on the day
following the expiration of the matter held in force by the order of
suspension. When the effective date of suspended matter has been
indefinitely postponed, that fact must be stated by appropriate
language.
Note: The form of publication permitted by the two paragraphs
preceding may be used only when it permits complete cancellation of the
tariff containing the matter continued in effect by the order of
suspension. It may not be used in loose-leaf tariffs nor where the
application of matter continued in effect depends in whole or in part
upon other provisions, such as point grouping, rate bases, rules or
regulations, which differ from those in the new tariff and which cannot
be brought forward in the supplement announcing suspension.
(10) When a revised (not an original) loose-leaf page, a portion of
which is under suspension, is reissued, the new revised page shall (i)
include the matter continued in effect by reason of the order of
suspension, (ii) cancel the page previously containing such matter, and
(iii) cancel the loose-leaf page containing the suspended matter
''except portions under suspension in Docket No. IS ------ , viz.
(identifying the suspended portion by item and page number).''
(11) Neither a suspended tariff provision nor a provision held in
force by reason of an order of suspension may be changed or canceled
except by order or permission of the Commission.
(12) When the Commission vacates an order of suspension, or when
suspended matter has been voluntarily postponed beyond the term of the
Commission's order, and the Commission finds the suspended matter
justified, a supplement may be filed making the suspended or postponed
matter effective on one day's notice unless the Commission directs
otherwise.
(13) When an order which suspended a tariff in its entirety is
vacated and/or the Commission formally finds that the suspended tariff
is justified, the vacating supplement filed under authority of this
section may also include as reissues any changes or additions which in
the interim have been made in the tariff which was held in force by the
order of suspension. If by special permission a new tariff has been
filed during the period of suspension, canceling the tariff proposed to
be canceled by the suspended tariff, any changes or additions published
in the new tariff which are not included in the suspended tariff may
likewise be included in the vacating supplement as reissued items, but
in such cases the vacating supplement must also cancel the new tariff.
No other matter may be included in vacating supplements. When reissued
matter is published in a vacating supplement, the vacation notice must
be printed in not less than 10-point type, either on the title page or
immediately preceding the particular tariff matter to which the notice
applies.
(14) When a tariff has been canceled except portions under suspension
by a new tariff and the Commission vacates its suspension order and/or
formally finds the suspended matter justified after the new tariff has
become effective, a supplement may be filed to the new tariff on not
less than one day's notice (unless the Commission directs otherwise),
republishing and establishing the suspended matter and canceling the
matter which was effective during the period of suspension, together
with the matter under suspension in the former issue. When the
Commission vacates its suspension order and/or formally finds the
suspended matter justified before the new tariff becomes effective, a
vacating supplement as provided in this section should be filed to the
old tariff, and a supplement should also be filed to the new tariff on
not less than one day's notice (unless the Commission directs
otherwise), establishing therein the matter which was under suspension
in the old tariff. A supplement common to both tariffs as authorized by
paragraph (h) of this section may be issued for this purpose.
(15) When the Commission suspends matter in a tariff or a supplement
thereto and thereafter orders its cancellation, the cancellation shall
become effective upon not less than one day's notice (unless the
Commission directs otherwise), by supplement to or reissue of the
tariff. When the Commission orders suspended matter canceled and the
final date for compliance is subsequent to the date to which the matter
has been postponed, carriers should endeavor to make the cancellation in
time to prevent the rates or other provisions which have been found not
justified from becoming effective. If this is not done and the
suspended matter becomes temporarily effective, it is necessary when
cancellation is effected to republish and reestablish the matter which
was continued in force by reason of the order of suspension.
(16) Every suspension, vacation, and cancellation supplement issued
under authority of this section must bear on its title page the
following notation:
Issued under authority of 18 CFR 341.9(k) and in compliance with
order of the Federal Energy Regulatory Commission in Docket No. IS
------ of (date).
Postponement supplements issued under authority of this section must
show on the title page:
Issued upon ------ day's notice under authority of 18 CFR 341.9(k).
(17) Supplements issued under authority of this section will not be
counted in the number of effective supplements, or the volume of
supplemental matter, permitted under paragraph (e) of this section, but
must be listed among the effective supplements as required by paragraph
(c) of this section.
(18) The provisions of this section relating to suspension,
postponement, vacation, and cancellation supplements will also govern in
connection with tariffs issued in loose-leaf form, except that such
supplements must not contain any other matter. All changes made in
loose-leaf tariffs must be published on revised pages. (See paragraph
(e) of this section.)
(l) (Reserved)
(m) Additional supplement to establish rates under rule or order of
Commission. Except as to loose-leaf tariffs and tariffs of less than
five pages, one additional supplement may be issued to any tariff
without regard to the requirements of paragraph (e) of this section for
the purpose of establishing rates or other provisions in compliance with
an order or formal decision of the Commission and/or to establish rates
under authority of 341.56 or 341.57. The next regular supplement filed
must bring the number of effective supplements within the requirements
of paragraph (e) of this section. Only one such supplement may be in
effect at any time and, except as provided in 341.14(f), may contain no
other matter. It must be designated on its title page as ''Issued under
authority of 18 CFR 341.9(m).''
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
12901 and 12906, Mar. 30, 1984)
18 CFR 341.10 Terminal and special services; distance and mileage
rates.
(a) Terminal and special services. Each carrier or its agent shall
publish, post, and file tariffs which shall contain in clear, plain, and
specific form and terms all the rules governing and rates and charges
for demurrage, lighterage, wharfage, and other terminal services,
storage transfer, weighing, diversion, reconsignment, heat, elevation,
odorization, coloration, filtration, loading and unloading, gathering,
terminalling, in-line transfers, storage, batching, blending,
commingling, etc., and other transit services, absorptions, allowances,
and all other charges and rules which in any way increase or decrease
the amount to be paid on any shipment, or which increase or decrease the
value of the service to the shipper. Tariffs authorizing such services,
or providing charges therefor or for the absorption of such charges,
must clearly show their application in connection with volume moving
under any quantity rates.
(b) Method of publication. Subject to the provisions of paragraphs
(c), (f) of this section, the application of the several services and/or
the charges covered by paragraph (a) of this section in connection with
line-haul rates lawfully on file with the Commission must be provided
for in one of the three following ways:
(1) By including in the tariff which contains the rate upon which
charges are finally to be assessed the specific authority for the extra
service, the rules or regulations under which such extra service is to
be performed, and the charge, if any, therefor; (2) by specific
reference, in the tariff which contains the rate upon which charges are
finally to be assessed, to the FERC number of a separate publication
containing the authority for such service and the charge, if any,
therefor; or (3) by including in the tariff which contains the rate
upon which charges are finally to be assessed a clause providing that
shipments made under the rates contained therein are entitled to the
following services (here name specifically the services which will be
permitted in connection with such rate (tariff) and are subject to the
charges therefor, if any, of participating carriers performing the
services ''as per tariffs lawfully on file with the Federal Energy
Regulatory Commission.''
(c) Intermediate transfer. A joint through rate from a point on the
line of one carrier to a point on the line of another carrier includes
transfer services at intermediate interchange points, and no part of
such charges may be added to the joint rate on shipments handled through
and not stopped for special services at such intermediate interchange
points. Carriers performing intermediate transfer services in
connection with joint rates should be shown as participating carriers in
the joint rate; but if this is not done, the carrier performing the
transfer service must have on file with the Commission a tariff naming
its charges for the intermediate transfer service and the line-haul
carriers parties to the joint rate must file tariffs providing for the
payment of all such charges to the transferring line.
All tariffs containing joint rates must contain the following
provision:
The joint rates published herein include all charges for transfer
services at intermediate interchange points on shipments handled through
and not stopped for special services at such intermediate interchange
points.
(d) Transfer charges. (1) Any carrier performing a transfer or
terminal service, even though its line be located wholly within one
State, must publish, post, and file in accordance with the law and the
Commission's regulations a tariff containing its transfer charges upon
or for movements on interstate shipments; and this must be done
regardless of absorption provisions published in connecting lines'
tariffs. Such transfer tariff must name the points at which shipments
will be received or delivered or must clearly define such limits.
(2) All of the transfer charges of a carrier must be published in one
tariff except as indicated in (d)(2)(i), (ii), and (iii) of this
section.
(i) When a carrier divides its line and publishes separate FERC
series of tariffs for the different portions thereof, separate tariffs
of transfer charges must be published for each.
(ii) When a carrier publishes a separate FERC series to provide rates
and charges on a single commodity or group of commodities, for example,
gasoline and diesel, it may publish a separate tariff covering all of
its transfer charges on that commodity or group of commodities.
(iii) Carriers may publish separate tariffs of transfer charges
applicable at important points on their lines, Provided, That such
points are indexed in the general transfer tariff and reference is made
therein to the FERC number of the separate tariffs published for such
points.
(3) Provisions, if any, for the absorption of connecting-line
transfer charges may be included in the tariff of rates or in the
transfer tariffs described in this section, or such provisions must be
included in a single separate publication or in a single separate
publication in each FERC series of tariffs. (See paragraph (f) of this
section.)
(4) Nothing in this section shall be construed as prohibiting two or
more carriers employing a joint agent for the publication of a
consolidated transfer tariff at a particular point, which tariff must
contain all of the transfer charges and absorption provisions of the
carriers parties to the tariff at that point. In such cases the general
transfer tariff (or tariffs) of each carrier must index the point
covered by the joint agency publication and must show reference by FERC
number to the joint agency publication.
(e) Transfer and other terminal charges added to rate. A carrier's
charges for transfer or other terminal services (except as otherwise
provided in paragraph (c) of this section) must be added to the
line-haul tariff charges unless such transfer charges are absorbed, in
whole or in part, in the manner provided by paragraph (f) of this
section.
(f) Transfer charges absorbed. Line-haul carriers may absorb charges
for transfer or other terminal services performed at point of origin,
point of destination, or (except as otherwise provided in paragraph (c)
of this section) at an intermediate point, provided, the line-haul
carriers publish and file a tariff which shows that such transferring
charges as published in tariffs of the transferring carrier (naming it)
lawfully on file with the Federal Energy Regulatory Commission will be
absorbed in their entirety. Line-haul carriers may also absorb
transferring charges in part or in a specified amount. In such cases
the tariff containing the absorption provision shall state that such
charges are published in tariffs of the transferring carrier (naming it)
lawfully on file with the Federal Energy Regulatory Commission and shall
also state that charges not absorbed will be in addition to the
line-haul rate.
(g) Distance rates may be used when no other rates provided. (1) A
carrier or an agent acting for two or more carriers may file tariffs
containing distance or mileage commodity rates. Except as otherwise
provided in 341.7 and 341.27, distance or mileage commodity rates may
be used only when no specific through commodity rates from and to the
same points are provided. Except as otherwise provided in 341.7 and
341.27, distance or mileage commodity rates will apply.
(2) Tariffs containing distance or mileage rates must clearly and
definitely show the application of the rates, must contain an
alphabetical list of points between which the rates apply and must also
show in proper arrangement the specific distances between such points,
or may make reference by FERC number to a separate tariff for such list
of points and distances. (See paragraph (h) of this section.)
(3) Each tariff that contains only distance or mileage commodity
rates must bear on its title page the following rule:
The distance or mileage commodity rates shown herein may be used only
when no specific through commodity rates from and to the same points
have been provided on the same shipment.
(4) If distance or mileage rates without alternative application are
published in a tariff which also contains specific rates, the notation
for commodity rates, prescribed by this paragraph must be shown
immediately in connection with such distance or mileage rates.
(5) If distance or mileage rates have alternative application, the
notations prescribed in this paragraph must be qualified by the
prefatory words, ''Except to the extent alternative application of rates
is provided.''
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12902, Mar. 30, 1984; 49 FR 44629, Nov. 8, 1984)
18 CFR 341.11 Index of tariffs.
(a) Each carrier shall publish as a tariff, under FERC number, a
complete index of all effective tariffs to which it is a party either as
initial or delivering carrier. Such index shall be arranged in sections
as indicated below, and shall show as to each tariff: (1) FERC number,
(2) full or abbreviated name of issuing carrier, tariff publishing
bureau, or agent, (3) type of tariff or description of the traffic upon
which it applies, (4) where tariff applies from, (5) where tariff
applies to, and (6) whether tariff contains other than all-pipeline
rates. The information required by items (3), (4), and (5) shall be
stated in sufficient detail to show clearly the application of the
tariff. Additionally, the index may show as to each tariff the
carrier's own number, the index number, and the issuing carrier's (or
agent's or tariff publishing bureau's) number.
First section: A list of all tariffs as to which the carrier is an
initial carrier, entered in the following order: Specific commodity
tariffs, general commodity tariffs, and miscellaneous schedules such as
rules and regulations, loading/unloading, transfers, etc. Specific
commodity tariffs shall be entered alphabetically under the names of
commodities or principal commodities. Tariffs applying to different
groups of the same commodity shall be grouped together; for example,
''Petroleum, crude, Petroleum, product,'' etc. Each group of specific
commodity tariffs and tariffs grouped under the respective heads of
general commodity tariffs, shall be entered by alphabetical arrangement
of the points or territory from or to which they apply, in either the
''From'' or ''To'' column. Miscellaneous schedules shall be entered in
alphabetical order.
Second section: A list of all tariffs under which the carrier is a
delivering carrier arranged alphabetically by names of issuing carriers,
or agents, with the items arranged by commodities under each of such
carriers or agents, as prescribed for the first section. If carrier so
desires, lists of tariffs under which it is an intermediate carrier may
be included in this section provided those tariffs under which it is a
delivering carrier or an intermediate carrier or both are indicated.
Third section: A complete list of the numbers of effective tariffs
of its own FERC series arranged in numerical order.
(b) Supplements to tariffs should not be included in indexes. Where
supplements have the effect of changing the application of the original
tariff, the descriptions of such tariff in the index should be amended
accordingly. If carriers so desire, lists of their intrastate tariffs,
official tariffs, etc., may appear in this publication. In connection
with intrastate tariffs which do not bear FERC numbers the reference
mark prescribed in 341.4(m) must be used with explanation ''Rates in
this tariff do not apply on interstate shipments.'' All intrastate
tariffs which bear FERC numbers must be properly shown in the index.
(c) A group of family lines may unite in the publication and filing
by a connecting trunk line of a joint index of the tariffs of such
family lines, provided the application of the tariffs as to each line is
plainly indicated and such lines are shown as parties to the joint index
under concurrence.
(d) The index must be kept current by supplements which need not be
issued more frequently than quarterly. The index must be reissued every
four years. Supplements must be numbered consecutively, must be
constructed in accordance with specifications for the index itself and
must show additions, changes and cancellations made in index itself or
in prior supplements, by reference to the page or index number of the
entry changed or canceled. Supplements may be issued without regard to
volume of supplemental matter permitted by 341.9(e), but not more than
five supplements may be in effect at any time.
(e) Each index must bear on its title page these notations: ''This
index contains list of tariffs in effect on (date of issue of index)''
to which in proper circumstances may be added ''or which have been filed
to become effective at a later date as shown within''; also ''This
index will be reissued on or before ------ 19 -- , and all changes will
be reflected in supplements issued quarterly.''
(f) Each supplement to an index must bear on its title page the
notation, ''Supplements Nos. ------ and ------ contain all changes from
original index that are in effect on date hereof''; to which may be
added ''or which have been filed to become effective at a later date as
shown within.''
(g) The title page of each index and of each supplement must bear
date of issue but must not bear an effective date. The rule requiring
thirty days' notice does not apply to these indexes and their
supplements.
(32 FR 20510, Dec. 20, 1967, as amended at 42 FR 36462, July 15,
1977. Redesignated and amended at 49 FR 12899 and 12902, Mar. 30, 1984)
18 CFR 341.12 Restoration and discontinuance of water service.
Tariffs containing pipeline-and-water rates applicable via routes
upon which it is necessary to close navigation during a portion of each
year, must provide for the restoration and discontinuance of service
over such routes in the manner prescribed in paragraphs (a) to (e) of
this section.
(a) Notation on title page. The following notation shall appear
either (1) on the title page of the pipeline tariff, (2) amongst the
rules governing the application of rates, or (3) immediately in
conjunction with the rates to which the notation applies:
Transportation service in connection with (here insert name of water
carrier or carriers specified in the tariff) is subject to restoration
and discontinuance as indicated on page ------ .
When the foregoing notation is published in the tariff amongst the
rules governing the application of rates, reference thereto must be made
in the table of contents of the tariff, and the words ''as follows''
must be substituted for ''as indicated on page ------ .''
(b) When definite dates of service cannot be determined. (1) When
definite dates for restoration and discontinuance of transportation
service for each season of navigation cannot be determined the following
rule must be published in the tariff under the heading of ''Application
of rates'':
Shipments will be accepted by carriers parties to this tariff during
the period from ------ (here show date approximately 30 days prior to
the first sailing from port of transshipment) to ------ (here insert
date which will allow sufficient time for shipment to reach the port of
transshipment prior to the last sailing) of each year, for
transportation on the vessels of the ------ (here insert name of water
carrier or carriers named in the tariff). Shipments also will be
accepted from the latter date until the date announced by supplements to
this tariff, subject to the condition that all freight left on hand at
the port of transshipment after the closing of navigation for lack of
space on vessels sailing after the arrival of such freight, and all
freight reaching the port of transshipment after the last sailing of
each season of navigation, will be forwarded via all-pipeline routes and
be subject to the tariff rates applicable via such all-pipeline routes
in effect on date of shipment from the point of origin of the shipment.
In such cases shipping receipts, bills of lading and way-bills must bear
notation to that effect. Supplements announcing the final date upon
which shipments will be accepted for transportation, under this tariff
and effective supplements thereto, will be filed with the Federal Energy
Regulatory Commission and posted at points from which the rates apply
not less than 1 day in advance of such date.
Note: In applying the provisions of the preceding paragraph, the
date on which final instructions are received for transportation via the
water line will be considered the date of acceptance of the shipment for
transportation by that line. The rate to be applied on shipments moved
via the water line will be the rate in effect on the date shipments are
received for transportation at points of origin.
(2) The dates for restoration and discontinuance of service as set
forth in this paragraph shall be shown in boldface type.
(c) When definite dates of service can be determined. When definite
dates for restoration and discontinuance of transportation service for
each season of navigation can be determined the following rule must be
published in the tariff under the heading of ''Application of rates'':
Shipments will be accepted by carriers parties to this tariff, during
the period from ------ (here show date approximately 30 days to the
first sailing from port of transshipment) to ------ (here show date
which will allow sufficient time for shipment to reach the port of
transshipment prior to the last sailing) of each year, for
transportation on the vessels of the ------ (here insert name of water
carrier or carriers named in the tariff). Shipments also will be
accepted from the latter date until ------ (here insert final date upon
which shipments will be accepted for transportation under the tariff and
effective supplements thereto), subject to the condition that all
freight left on hand at the port of transshipment after the closing of
navigation for lack of space on vessels sailing after the arrival of
such freight, and all freight reaching the port of transshipment after
the last sailing of each season of navigation, will be forwarded via
all-pipeline routes and be subject to the tariff rates applicable via
such all-pipeline routes in effect on date of shipment from the point of
origin of the shipment. In such cases shipping receipts, bills of
lading, and way-bills must bear notation to that effect.
No supplement will be issued to this tariff announcing the date of
discontinuance of transportation service.
Note: In applying the provisions of the preceding paragraph, the
date on which final instructions are received for transportation via the
water line will be considered the date of acceptance of the shipment for
transportation by that line. The rate to be applied on shipments moved
via the water line will be the rate in effect on the date shipments are
received for transportation at points of origin.
The dates for restoration and discontinuance of service as set forth
in this section shall be shown in boldface type.
(d) Contents of supplements. Supplements announcing discontinuance
of transportation service under this section may be filed with the
Federal Energy Regulatory Commission and posted at points from which the
rates apply on not less than 1 day's notice by noting thereon reference
to this section. Only one such supplement may be in effect at any time;
it may not contain other matter and may be issued without regard to the
requirements of 341.9(e).
(e) Tariffs may be reissued. Tariffs containing pipeline-and-water
rates may be reissued or amended at any time in the regular manner, but
tariffs containing the clause prescribed by paragraph (b) of this
section which are made effective subsequent to the date of actual
discontinuance of service must contain a statement that service was
discontinued on ------ as per supplement No. ------ to FERC No. ------
(former tariff) and that supplement announcing discontinuance of service
for that season will not be filed.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12902, Mar. 30, 1984)
Cross Reference: For regulations of the Federal Maritime Commission
relating to tariffs of common carriers by water in interstate commerce,
see 46 CFR Part 550.
18 CFR 341.13 Filing tariffs.
(a) Authority to file. Tariffs shall be published and filed by
carriers either directly or through duly authorized tariff-publishing
agents. When filed directly by a carrier the concurrence (or power of
attorney as authorized in 341.18(f)), and when filed by an agent the
power of attorney, of every carrier participating therein must be filed
or on file with the Commission. (See 341.17 to 341.20, inclusive.)
(b) Agent will file under own FERC number. A tariff publishing agent
must file tariffs under his or its own single series of FERC numbers and
not in the series of any of his principals. If the agent is a
corporation or an unincorporated association (see 341.17(a)) having
jurisdiction over two or more tariff publishing organizations, bureaus,
or committees, the tariffs issued through each such tariff publishing
organization may bear a separate series of FERC numbers.
(c) Filing by issuing carrier or agent. Tariffs must be filed by the
issuing carrier or agent, and such filing will constitute filing for all
carriers parties thereto. Such tariffs must be posted at offices of
carriers participating therein in the manner required by law.
(d) Exchange of publications. The agent or the carrier that issues a
joint tariff publication shall at once send copies thereof to each and
every carrier that is named as party thereto.
(e) Conflict between tariffs; avoidance. A carrier that grants
authority to an agent or to another carrier to publish and file certain
of its rates must not in its own issues publish rates which duplicate or
conflict with those which are published by such authorized agent or
other carrier.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
12903, and 12906, Mar. 30, 1984)
Cross Reference: For provisions concerning powers of attorney and
concurrences, see 341.17 to 341.26 inclusive.
18 CFR 341.14 Statutory notice; additional procedure in filing
tariffs.
(a) Period of notice. The act requires that all changes in rates, or
in rules that affect rates, shall be filed with the Commission at least
30 days before the date upon which they are to become effective unless
otherwise authorized by the Commission. Manifestly it is impossible for
the Commission to check the items in tariffs to determine whether or not
statutory notice has been given. Therefore, except as otherwise
authorized by the Commission, 30 days' notice to the public and to the
Commission must be given as to every tariff publication filed with the
Commission, regardless of whether or not changes are effected thereby.
(See 341.3(h), 341.9(d)).
(b) Filing of tariffs and receipt by Commission not relief of
carriers from liability. The law affirmatively imposes upon each
carrier the duty of filing with the Commission all of its tariffs and
amendments thereto in the manner prescribed in the law or in any rule
which may be promulgated by the Commission. A penalty is provided for
failure so to do, or for using any rate which is not contained in its
lawfully published and filed tariffs. The receipt and filing of a
tariff or supplement by the Commission does not relieve carriers from
liability for violation of the act or of regulations issued thereunder.
(c) Interstate shipments. Rates for through shipments are often made
by adding together two or more rates. All rates used in making
combination through rates for interstate shipments, including rates
between points in one State, must be filed with the Commission and
posted at points and can only be changed as to such traffic in
accordance with the terms of the act.
(d) Delivery free of charges. No tariff, revised page, or supplement
will be received by the Commission unless it is delivered to it free
from all charges including claims for postage.
(e) Rejection of tariffs and notices of revocation. (1) Any tariff
or schedule, tendered for filing, which fails to give lawful notice of
changes in rates, charges or other provisions which it proposes to
establish, or which fails to meet the requirements of the regulations
contained in this chapter, or violates any order of the Commission or of
a court, is subject to rejection by the Commission. When a tariff or
schedule is rejected, the Commission, acting through a designated
administrative officer, will inform the carrier or the agent who
tendered it for filing, in writing, of the reasons for rejection, and
will return the rejected tariff or schedule to such carrier or agent.
(2) The number assigned to a tariff or schedule which has been
rejected may not again be used. The rejected tariff or schedule may not
be referred to in any subsequent tariff or schedule as having been
canceled, amended or withdrawn, but the tariff or schedule which is
published in its stead must bear the following notation: ''Issued in
lieu of (here identify the rejected schedule or tariff), rejected by the
Commission.''
(3) A notice of the revocation, complete or partial, of a concurrence
or power of attorney which, if it were to become effective, would
require the establishment of rates, fares, or charges in violation of an
order of the Commission or of a court, or of the regulations in this
chapter, may be rejected in the same manner as a tariff or schedule and
any such notice of revocation which would require the establishment of
rates, fares, or charges of doubtful lawfulness may be suspended.
(f) Promulgation of rates prescribed in decisions of Commission. (1)
Rates prescribed by the Commission in its decisions and orders in formal
cases shall be promulgated by the carriers against which such orders are
entered, in duly published, filed, and posted tariffs, revised pages or
supplements, and notice shall be sent to the Commission that its
decision (or order) in Docket No. ------ , has been complied with in
item ------ , page -- of ------ tariff, FERC No. ------ or supplement
No. ------ to ------ tariff, FERC No.
------ .
(2) Unless otherwise specified in the decision or order in the case,
such tariff or supplement must be made effective upon statutory notice
to the Commission and to the public. Whether made effective on less
than statutory notice under special authority granted in the decision or
order in the case, or upon statutory notice, when an entire tariff or
supplement is issued in compliance with a decision or order, such tariff
or supplement shall bear on its title page the notation ''In compliance
with decision (or order) of Federal Energy Regulatory Commission in
Docket No. ------ .'' (Whenever possible, the volume and page number of
the report of the Federal Energy Regulatory Commission should be shown.)
(3) If the decision or order of the Commission affects only portions
of the tariff or supplements, the above notice shall be shown in
connection with each portion so affected.
(4) In establishing rates, rules or regulations effective on less
than thirty days notice under authority of a decision or order of the
Commission in a formal case, the carrier or carriers parties of the
record, or that are lawful parties to a joint tariff in which the rates,
rules, or other regulations that are prescribed are published by some
carrier that is a party to the record, may include change or changes in
commodity or commodities that are grouped with that or those which are
specified in the decision or order; and may include adjustment at other
points in order to conform rates to the provisions of the fourth section
of the act, or to preserve established grouping or relation of points;
and may also include adjustment of rates to same points on other
commodities for the purpose of maintaining established relation of rates
between commodities; Provided, All changes made under authority of this
section shall be effected by reductions in rates or charges.
(5) If a carrier that is not a party to the record or to the joint
tariff desires to make on less than statutory notice the same changes
that are made under the decision or order by carrier that is party to
the same it must secure special permission so to do. (See also
341.9(m).)
(g) Explanation of missing numbers required. Tariffs bearing FERC
numbers and supplements are required to be numbered consecutively. If,
for any reason, this is not done, the tariff or supplement which is not
numbered in sequence with the publication last filed must be accompanied
by a memorandum explaining why consecutive numbers were not used.
(h) Number of copies; address. Two copies of each tariff,
supplement, revised page, or other schedule of rates or regulations,
shall be filed with the Commission, both copies to be filed together
under one letter of transmittal (see 341.29). They must be addressed to
the ''Federal Energy Regulatory Commission, Washington, D.C. 20426,''
with the envelope marked as containing ''Tariffs.''
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12903, Mar. 30, 1984)
341.15 -- 341.16 (Reserved)
18 CFR 341.17 Tariffs issued through an agent.
(a) If a carrier desires to issue a tariff or tariffs through an
agent it may do so by filing with the Commission an appropriate power of
attorney to the designated agent. Agents may be either natural persons,
corporations, or unincorporated associations whose articles of
association (or other form of agreement) have been approved by the
Commission in a proceeding pursuant to the provisions of section 5a,
part I, of the Interstate Commerce Act. An officer or employee of an
incorporated tariff-publishing agent may not act as an agent in his
individual capacity for the publication of tariffs.
(b) When an association or corporation has been appointed an issuing
agent the executive head thereof shall at once notify the Commission of
the name of the individual who is to be responsible for the actual
compilation and filing of each FERC series of tariffs issued by the
agent. There may be only one issuing officer for each such series of
tariffs, and the same individual may not act as issuing officer for more
than one series without the special permission of the Commission. When
an issuing officer is replaced the Commission shall be immediately
notified in like manner of his successor.
(c) When a natural person is authorized by power of attorney to act
as a tariff-publishing agent, such instrument shall designate another
natural person to act as alternate agent in the event of the death or
disability of the principal agent. On or before the date of filing of
the first tariff or supplement by the alternate agent under the
authority granted in the instrument, such alternate agent shall notify
the Commission in writing that death or disability of the principal
agent has occurred and that he, the alternate agent, will thereafter act
until the appointment of a new principal agent. The term ''disability''
as used in the instrument means resignation, permanent transfer to other
duties, or other permanent absence of the principal agent. After an
alternate agent has once exercised the authority granted by the
instrument, the principal agent may not thereafter act under that
instrument.
18 CFR 341.18 Powers of attorney.
(a) Publishing agents. (1) A power of attorney shall be used by a
carrier to give to a publishing agent, but not to another carrier,
authority to publish and file freight rate tariffs and supplements for
it, except that a carrier may give a power of attorney to another
carrier in the circumstances and subject to the conditions stated in
paragraph (f) of this section. Powers of attorney given to publishing
agents may be either unlimited or limited, and in the case of
corporations or unincorporated associations comprised of more than one
bureau, committee or regional organization, the power of attorney may
consist of multiple instruments, such instruments to define separately
the authority to be exercised by each component bureau, committee or
regional organization.
(2) A carrier may not have in effect at the same time an unlimited
power of attorney and a limited power of attorney in favor of the same
agent for use by the same bureau, committee, or regional organization.
(b) Unlimited power of attorney form. (1) An unlimited power of
attorney, when given to a publishing agent, authorizes the agent to file
any freight tariff in which the carrier giving the power is a
participating carrier. Form FA1 confers unlimited authority to publish
local rates and charges for the carrier issuing the power and to publish
joint rates and charges for such carrier and such other carriers as have
issued the necessary authority.
(2) The following form of power of attorney, FA1, shall be used to
give such unlimited powers:
FA1 No. --
Cancels ------ No. --
(Name of carrier)
(Mail address)
(Date)
Know All Men by These Presents:
That the (full and correct name of carrier) has made, constituted,
and appointed, and by these presents does make, constitute, and appoint
(name of principal agent) its true and lawful attorney and agent, to
file in its name, place, and stead, (1) for it alone, and (2) for it
jointly with other carriers (through its (name of bureau, committee, or
regional organization, if any)) tariffs and supplements thereto, as
required of common carriers by existing laws and regulations established
thereunder. And does hereby give and grant unto its said attorney and
agent full and unlimited power and authority to do and perform all and
every act and thing above specified as fully, to all intents and
purposes, as if the same were done and performed by the undersigned
carrier itself, and does hereby assume full responsibility for the acts
and failures to act of said attorney and agent.
And, further, that the undersigned carrier does hereby make and
appoint (name of alternate agent) alternate attorney and agent to do and
perform the same acts and exercise the same authority herein granted to
the principal agent in the event and only in the event of the death or
disability of the above-named principal agent.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name of Agent)
(Address)
(c) Limited power of attorney form. (1) A power of attorney may be
limited in any appropriate manner provided the limitations are
specifically and unambiguously expressed in the instrument. For
example, the agent may be authorized to publish only local rates, only
joint rates, only rates and charges on specified commodities or in a
specified territory, or only specified tariffs or types of tariffs.
(2) The following power of attorney, Form FA2, shall be used to give
such limited authority:
FA2 No. --
Cancels ------ No. --
(Name of carrier)
(Mail address)
(Date)
Know All Men by These Presents:
That the (full and correct name of carrier) has made, constituted,
and appointed, and by these presents does make, constitute and appoint
(name of principal agent) its true and lawful attorney and agent, to
file in its name, place, and stead, (1) for it alone, and (2) for it
jointly with other carriers (through its (name of bureau, committee, or
regional organization, if any)), tariffs and supplements thereto and
successive reissues thereof, as required of common carriers by existing
laws and regulations established thereunder, but only as hereinafter
specified:
And does hereby give and grant unto its said attorney and agent full
power and authority to do and perform all and every act and thing above
specified as fully, to all intents and purposes, as if the same were
done and performed by the undersigned carrier itself, and does hereby
assume full responsibility for the acts and failures to act of said
attorney and agent.
And, further, that the undersigned carrier does hereby make and
appoint (name of alternate agent) alternate attorney and agent to do and
perform the same acts and exercise the same authority herein granted to
the principal agent in the event and only in the event of the death or
disability of the above named principal agent.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name of Agent)
(Address)
(d) Manner of execution. (1) In the blank space for the name of the
carrier in Forms FA1, FA2, and FA3, there must be shown, if the carrier
is an individual, the individual name followed by the trade name, if
any. If the carrier is a partnership, the correct names of all partners
must be given, followed by the trade name, if any. If the carrier is a
corporation, the correct corporate name must be used.
(2) If the carrier is an individual, the power of attorney must be
signed by the individual; if a partnership, the power of attorney must
be signed individually by each partner. If the carrier is a
corporation, the power of attorney must be signed by the president, a
vice-president or any other authorized official of the carrier.
However, before the signature of an employee other than the president or
a vice-president on a power of attorney will be recognized by the
Commission, the carrier must file with the Commission, over the
signature of the president or a vice-president, a statement reciting
that the individual is authorized to sign powers of attorney. The
statement must include a specimen signature of the individual or
individuals so designated. The authority to sign powers of attorney may
be conferred in the manner described, on more than one official of the
carriers. If the carrier is being operated by trustees or receivers the
power of attorney must be signed by each trustee or receiver
individually or by his or their designee. Trustees or receivers may
invest others with the authority to sign in the same manner as the
president or vice-president of a corporation may confer the authority on
subordinate officials.
(3) If the agent appointed by either FA1 or FA2 is a corporation or
an unincorporated association the last full paragraph of the form shall
be omitted.
(e) Joint agents. If an agent does not hold the requisite authority
to publish a particular tariff the authority to do so may be obtained by
pooling the authority held by him with that held by one or more other
agents, and the tariff may be published jointly by both or all such
agents in the FERC series of each. For example, if one agent has
authority to publish rates only from territory A to territory B, and
another agent has authority to publish rates only from territory B to
territory A, the rates may be published in a single tariff on a
''between'' basis and filed with the Commission as a joint tariff of
both agents under the FERC series of each.
(f) Carrier acting for another carrier. (1) A power of attorney may
be given by small carriers to large carriers with which they connect, or
by subsidiary to parent carriers, authorizing the large or parent
carriers to publish tariffs, to give and receive concurrences, and to
give powers of attorney to agents, all in behalf of the small or
subsidiary carrier. The authority granted may be unlimited, as in the
form which follows (Form FA3), or it may be limited in any appropriate
manner, provided the limitations are specifically and unambiguously
expressed in the instrument. When an FA3 form of power of attorney has
been given, the granting carrier may not thereafter do in its own behalf
anything which it has authorized the grantee carrier to do in its stead.
Concurrences and powers of attorney given by the grantee carrier will,
however, be deemed to be given on its own behalf only, unless the
instrument expressly recites that it is given or is also given, in
behalf of the granting carrier. An FA3 form of power of attorney will
be construed as authorizing the grantee carrier to give a concurrence to
itself in behalf of the granting carrier.
(2) The following form of power of attorney, Form FA3, shall be used
by a carrier to give authority to another carrier. When the authority
is to be limited in any way, the form should be altered to the extent
necessary.
FA3 No. --
Cancels ------ No. --
(Name of carrier)
(Mail address)
(Date)
Know All Men by These Presents:
That the (name of granting carrier) has made, constituted, and
appointed, and by these presents does make, constitute, and appoint
(name of grantee carrier) its true and lawful attorney and agent (1) to
issue in its name, place and stead powers of attorney to
tariff-publishing agents, (2) to give and receive in its name, place and
stead concurrences in tariffs of other carriers, and (3) to publish and
file, or cause to be published and filed, tariffs and supplements
thereto and successive reissues thereof, in which the undersigned
carrier is a participant, all as required of common carriers by existing
laws and regulations established thereunder. And the undersigned
carrier does hereby give and grant unto its said attorney and agent,
full, sole and exclusive power and authority to do and perform all and
every act and thing above specified for and on behalf of the undersigned
carrier as fully, to all intents and purposes, as if the same were done
and performed by the undersigned carrier itself and does hereby assume
full responsibility for the acts and failures to act of its attorney and
agent.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name and Title of Officer)
(Name of Carrier)
(Address)
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
12903, Mar. 30, 1984)
18 CFR 341.19 Concurrences.
(a) A carrier desiring to become a participant in a tariff or tariffs
issued by another carrier (not by an agent) may do so by filing with the
Commission a limited or unlimited concurrence (except as provided in
341.18(f)) in one of the four following forms. In Forms FC2 and FC4 the
limitations must be specifically and unambiguously expressed.
(1) Form FC1 which follows is unlimited and covers all tariffs
applying on traffic moving from, to, via or at points on the line of the
carrier giving the concurrence:
FC1 No. --
Cancels ------ No. --
(Name of carrier)
(Mail address)
(Date)
To the Federal Energy Regulatory Commission, Washington, D.C. 20426.
This is to certify that (name of carrier issuing concurrence) assents
to and concurs in all tariffs and supplements thereto, filed by (name of
carrier to which concurrence is given) in which the undersigned carrier
is shown as a participant, and the undersigned carrier hereby makes
itself a party thereto and bound thereby insofar as such tariffs apply
from, to, via or at points on its lines, until this authority is revoked
by formal notice of revocation filed with the Federal Energy Regulatory
Commission and sent to the carrier to which this concurrence is given.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name and Title of Officer)
(Name of Carrier)
(Address)
(2) Form FC2 covers tariffs applying on limited but affirmatively
specified traffic moving from, to, via or at points on the line of the
carrier giving the concurrence. The form follows:
FC2 No. --
Cancels ------ No. --
(Name of carrier)
(Mail address)
(Date)
To the Federal Energy Regulatory Commission, Washington, D.C. 20426.
This is to certify that (name of carrier issuing concurrence) assents
to and concurs in all tariffs and supplements thereto, filed by (name of
carrier to which concurrence is given) in which the undersigned carrier
is shown as a participant, but only to the extent that such tariffs
apply:
(Here affirmatively state the limitations, such as designating the
commodities to which, the points to and/or from and/or at which, the
limited territory within which, or the specific publication(s) or series
of tariffs to which, the concurrence shall be applicable.)
And the undersigned carrier hereby makes itself a party thereto and
bound thereby insofar as such tariffs apply from, to, via or at points
on its lines, until this authority is revoked by formal notice of
revocation filed with the Federal Energy Regulatory Commission and sent
to the carrier to which this concurrence is given.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name and Title of Officer)
(Name of Carrier)
(Address)
(3) Form FC3 is restricted to tariffs applying on traffic moving to
points on or via the line of the carrier giving the concurrence but is
not otherwise limited. The form follows:
FC3 No. --
Cancels ------ No. --
(Name of carrier)
(Mail address)
(Date)
To the Federal Energy Regulatory Commission, Washington, D.C. 20426.
This is to certify that (name of carrier issuing concurrence) assents
to and concurs in all tariffs or supplements thereto filed by the (name
of carrier to which concurrence is given) in which the undersigned
carrier is shown as a participant, and hereby makes itself a party
thereto and bound thereby, insofar as such tariffs or supplements
contain rates or other provisions applying via its lines and to, but not
from or at, points thereon, until this authority is revoked by formal
notice of revocation filed with the Federal Energy Regulatory Commission
and sent to the carrier to which this concurrence is given.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name and Title of Officer)
(Name of Carrier)
(Address)
(4) Form FC4 which follows covers freight tariffs applying on limited
but affirmatively specified traffic moving to points on or via the line
of the carrier giving the concurrence.
FC4 No. --
Cancels ------ No. --
(Name of carrier)
(Mail address)
(Date)
To the Federal Energy Regulatory Commission, Washington, D.C. 20426.
This is to certify that (name of carrier issuing concurrence) assents
to and concurs in all tariffs or supplements thereto filed by (name of
carrier to which concurrence is given) in which the undersigned carrier
is shown as a participant, but only to the extent that such tariffs
apply:
(Here affirmatively state the limitations, such as designating the
commodities to which, the points to or the lines over which the limited
territory within which, or the specific publication(s) or series of
tariffs to which, the concurrence shall be applicable.)
And the undersigned carrier hereby makes itself a party to such
tariffs and bound thereby insofar as such tariffs or supplements contain
rates or other provisions applying via its lines and to, but not from or
at, points thereon, until this authority is revoked by formal notice of
revocation filed with the Federal Energy Regulatory Commission and sent
to the carrier to which this concurrence is given.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name and Title of Officer)
(Name of Carrier)
(Address)
(b) Concurrences shall be personally signed by any official of the
issuing carrier.
(c) If a carrier has been authorized by power of attorney to issue
concurrences in behalf of one or more small or subsidiary carriers (see
341.18(f)), the carrier holding such authority may by a single
instrument issue a concurrence in its own behalf and in behalf of any or
all of such subsidiary carriers.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12903, Mar. 30, 1984)
18 CFR 341.20 Filing of powers of attorney and concurrences.
(a) If a power of attorney or concurrence is issued subsequent to the
date of the filing of the tariff with the Commission the original
instrument shall be forwarded directly to the Commission with a copy to
the issuing agent or carrier, but if it is issued prior to or
concurrently with the issuance of the tariff, the original instrument
may either be forwarded directly to the Commission, or it may be sent to
the carrier or agent issuing the tariff and be transmitted by it or him
to the Commission with the tariff. (For exceptions see 341.22 and
341.23(a).)
(b) Powers of attorney, concurrences, amendments thereto and
revocation notices shall be printed or typed on paper of good quality, 8
1/2 11 inches, and must show the date on which they are issued. Each
power of attorney and concurrence shall bear a form and serial number,
the serial numbers to run consecutively for each form of instrument.
Concurrences issued by a carrier jointly in its own behalf and in behalf
of one or more other carriers (see 341.18(f)) may, if desired, be
issued under a separate series of numbers. The form and serial numbers
shall be shown on the upper right-hand corner and immediately thereunder
shall be shown the form and number of the power of attorney or
concurrence, if any, which is canceled thereby. If the instrument to be
canceled contains more authority or is broader in scope than the new
instrument, such new instrument must in addition to the date of issue,
bear an effective date at least 60 days after the date on which it is
received by the Commission. When the new instrument is the same or
broader in scope than the instrument which it cancels, it becomes
effective when filed with the Commission. The instrument shall also
show, in the lower left-hand corner, the name, title and address of the
person to whom the duplicate is sent.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12903, Mar. 30, 1984)
18 CFR 341.21 Certificate stating correct name of carrier to be filed.
When a corporate or partnership carrier files its first tariff, power
of attorney or concurrence, it shall also file a certificate stating the
precisely correct name of the carrier as it appears in the charter or
articles of incorporation, or in the articles of co-partnership, as the
case may be. If, for example, the article ''The'' is a part of the
carrier's name, if the conjunction ''and'' appears therein as ''&'', or
if the word ''Company'' is abbreviated to ''Co.'', the certificate must
so indicate.
18 CFR 341.22 Transfer of authority from one agent to another agent.
(a) When it is desired to transfer authority from one agent to
another agent superseding the former agent as to all such agent's
effective tariffs, the transfer shall be accomplished by filing a new
power of attorney naming the agent (and alternate when the new agent is
a natural person) thereafter to serve, which shall specifically cancel
the previous instrument or instruments, by including the following in
the power of attorney to the new agent:
This power of attorney cancels the following power(s) of attorney:
(b) Under all other conditions the power of attorney must be revoked
in accordance with 341.26(b).
(c) The originals of such powers of attorney shall not be sent
immediately to the Commission, but shall be forwarded to the new agent,
who, after all the necessary instruments shall have been secured, shall
file all of the originals with the Commission at one time. The new
agent may file no tariffs with the Commission until the powers of
attorney from all of the carriers shown therein as participants have
been so filed.
18 CFR 341.23 Procedure when one publishing agent succeeds another.
(a) When powers of attorney have been issued to a natural person and
his alternate, and death or disability of either the principal agent or
the alternate occurs, new powers of attorney shall be filed with the
Commission within 180 days, canceling the previous instruments and
designating the new agent (and also his alternate if the new agent is a
natural person) thereafter to serve. If the filing of the new
instruments is occasioned by the death or disability of the former
alternate, the new instruments may, if desired, continue the former
principal agent and designate a new alternate only. Likewise if death
or disability of the principal agent has occurred it is permissible to
continue the former alternate agent in the new instruments and designate
a new principal agent only. As soon as the instruments appointing the
new agent are filed the alternate agent who in the interim has acted may
no longer do so. The new powers of attorney shall not be forwarded
directly to the Commission, but shall be collected by the new agent and
forwarded to the Commission together, as provided in 341.22. The new
agent may not file a tariff for any carrier until that carrier's power
of attorney to him is on file with the Commission.
(b) In the first amendment to each tariff issued by the alternate
agent after the death or disability of the principal agent, there shall
be shown a statement reading substantially as follows: ''On and after
(show here the date on which the principal agent ceased to act) this
publication shall be considered as the issue of ------ , Alternate
Agent.''
(c) A new agent, on or after the filing of his or its authorities,
shall include in the next supplement to each of the effective tariffs
previously taken over by the alternate agent a statement reading
substantially as follows: ''On and after (show here the date on which
the new authorities are filed with this Commission) this publication
shall be considered as the issue of ------ , Agent.''
18 CFR 341.24 FERC numbers of tariffs issued by a new agent or
alternate agent.
Tariffs issued by a new agent may be, and those issued by an
alternate agent must be, numbered in the FERC series of the former
agent. If it is desired to number the tariffs of a new agent in a
different FERC series, this may be done as to new or reissued tariffs,
but amendments (supplements or revised pages) to tariffs issued by the
former agent must be continued in the original series.
18 CFR 341.25 Powers of attorney and concurrences in special
situations.
(a) Joint concurrences. If joint concurrences are issued in behalf
of two or more carriers by the same Officer, all concurrences in each
series must be issued on behalf of all such carriers, except as to
concurrences interchanged between those carriers. If concurrences in a
single series are issued separately for different carriers, separate
files in that series must be maintained for each carrier, and
concurrences of each carrier must be issued in consecutive numerical
order as required by 341.20(b).
(b) When operation discontinued or taken over by another carrier.
Powers of attorney and concurrences issued in favor of a carrier which
has discontinued operations should be revoked within 120 days after such
discontinuance. If its operations have been taken over by another
carrier all effective powers of attorney and concurrences should be
canceled within 120 days either by new issues or revocation notices.
Note: 341.25(b) applies, among other situations, when an
incorporated carrier is placed in the hands of trustees or receivers and
is thereafter reorganized. When trustees or receivers are appointed
they normally assume, and the corporation discontinues, operations; and
thereafter, following reorganization, operations again pass from the
receivers or trustees to the reorganized corporation.
(c) Forms for joint intermodal pipeline tariffs. Powers of attorney
and concurrences authorizing the publication of joint intermodal
pipeline tariffs and supplements shall be issued on the standard FA and
FC Forms described in 341.18 and 341.19. Such powers of attorney and
concurrences must bear the following notation in the upper portion of
the document: ''Joint Intermodal Pipeline Power of Attorney'' or
''Joint Intermodal Pipeline Concurrence.''
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12903, Mar. 30, 1984; 49 FR 44629, Nov. 8, 1984)
18 CFR 341.26 Amendment and revocation of powers of attorney and
concurrences.
(a) Amendments. (1) A power of attorney on Forms FA2 or FA3 or a
concurrence on Forms FC2 or FC4 may be amended by issuing an ''Amendment
to Power of Attorney,'' or ''Amendment to Concurrence,'' respectively.
However, only four amendments to any one power of attorney or
concurrence will be permitted. The amendment must specify with
particularity the exact change in the scope of the powers or the
authority conferred, by appropriate reference by number to the power of
attorney or concurrence affected, by identification by FERC and agent's
or carrier's number of the tariff or tariffs affected, and by a detailed
description of the traffic or territory affected.
(2) If an amendment to a power of attorney or to a concurrence
reduces the scope of the original instrument, such amendment must bear
in addition to the date of issue, an ''effective'' date at least 60 days
after the date on which it is received by the Commission. If the
amendment adds to or increases the scope of the original power of
attorney or concurrence, no notice is required, and it becomes effective
when filed with the Commission. (See paragraph (e) of this section.)
(3) The form of an ''Amendment to Power of Attorney'' is as follows:
Amendment No. --
To FA No. --
(Name of carrier)
(Mail address)
(Date)
Know All Men by These Presents:
Effective -------------- (date), the undersigned hereby amends the
above-numbered power of attorney, in the following respects:
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name of Agent or Carrier)
(Address)
(4) The form of an ''Amendment to Concurrence'' is as follows:
Amendment No. --
To FC -- No. --
(Name of carrier)
(Mail address)
(Date)
To the Federal Energy Regulatory Commission, Washington, D.C. 20426.
The undersigned hereby amends FC -- No. -- in the following
respects:
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name of Carrier)
(Address)
(b) Revocations. A power of attorney or a concurrence may be revoked
upon not less than 60 days' notice by filing a Notice of Revocation with
the Commission and serving at the same time a copy thereof on the agent,
in the case of powers of attorney on Forms FA1 and FA2, or on the
carrier, in the case of concurrences or powers of attorney on FA3, in
whose favor the instrument was executed. Such notice shall not bear a
separate serial number, but shall specify the form and number of the
power of attorney, or the form and number of the concurrence, to be
revoked, shall name the agent, and alternate agent, if any, or the
carrier in whose favor the instrument was executed, and shall specify a
date upon which revocation is to become effective. (See paragraph (e)
of this section.)
(c) Corresponding revision of tariff. When a power of attorney or
concurrence is revoked corresponding revision of the tariff or tariffs
must be made not later than the effective date stated in the notice of
revocation. If the tariff or tariffs are not so amended the rates and
other provisions therein remain effective and must be protected by the
carrier or carriers responsible for their continued maintenance.
(d) Form for revocations. Revocation notices shall be in one of the
following forms, as appropriate:
(Name of carrier)
(Mail address)
(Date)
Know All Men by These Presents:
Effective -------------- (date), power of attorney FA ---------- No.
---------- , issued by
(Name of carrier issuing power of attorney) in favor of
(Name of carrier, or agent (an alternate), if any) is hereby canceled
and revoked.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name of Agent or Carrier)
(Address)
(Concurrence)
(Name of carrier)
(Mail address)
(Date)
To the Federal Energy Regulatory Commission, Washington, D.C. 20426.
Effective -------------- (Date) concurrence FC -------------- No.
-------------- , issued by
(Name of carrier issuing concurrence) in favor of
(Name of carrier)
is hereby canceled and revoked.
(Name of carrier)
By
Its
(Title)
Duplicate mailed to:
(Name of Carrier)
(Address)
(e) Manner of execution. (1) An amendment to, or a revocation of a
power of attorney shall be executed in the same manner as powers of
attorney, and a statement of the kind specified in 341.18(d) shall be
filed with the Commission to designate persons authorized to sign such
amendments or revocations. The statement filed in accordance with
341.18(d) may include in the one instrument designations and specimen
signatures of persons authorized to sign powers of attorney, amendments
to powers of attorney, and revocations of powers of attorney.
(2) An amendment to, or a revocation of a concurrence shall be
executed in the same manner as concurrences. (See 341.19(b).)
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
Mar. 30, 1984; 49 FR 44629, Nov. 8, 1984)
18 CFR 341.27 Intermediate application of rates.
Tariffs may provide for the application of commodity rates from or to
intermediate points by incorporating in such tariffs the appropriate one
or more of the rules set forth below, subject to the limitations of this
section.
(a) Intermediate rules to be used only where routing is provided.
Effective on and after June 10, 1959, an intermediate point rule may not
be published so as to result in establishing from (or to, as the case
may be) an intermediate point, a rate from (or to) a more distant point
unless the tariff contains specific routing instructions showing
definitely in accordance with the plan listed in paragraph (k)(1)(i) of
341.4 the routes through the intermediate point over which the rate from
(or to) the more distant point applies.
(b) Intermediate point commodity rate rules -- (1) From intermediate
points. Subject to the provisions of notes 1, 2 and 3, in this
paragraph from any point of origin from which a commodity rate on a
given article to a given destination and via a given route is not named
in this tariff, which point is intermediate to a point from which a
commodity rate on said article is published in this tariff via a route
through the intermediate point over which such commodity rate applies to
the same destination, apply from such intermediate point to such
destination and via such route the commodity rate in this tariff on said
article from the next point beyond from which a commodity rate is
published herein on that article to the same destination via the same
route.
Note 1: When by reason of branch or diverging lines there are two or
more ''next beyond'' points, apply the rate from the next point beyond
(in this tariff) which on that article to the same destination via the
same route results in the lowest charge.
Note 2: If the intermediate point is located between two points from
which commodity rates on the same article via the same route are
published in this tariff, apply via that route from the intermediate
point the rate from the next point in either direction which results in
the higher charge. In applying this note, if there are two or more next
beyond points due to branch or diverging lines, eliminate all such next
beyond points except the point from which the lowest charge is
applicable.
Note 3: If there is in any other tariff a commodity rate on the same
article from the intermediate origin point applicable over the same
route to the same destination, the provisions of this rule are not
applicable from such intermediate origin point.
(2) To intermediate points. Subject to the provisions of notes 1, 2,
and 3, in this subparagraph, to any point of destination to which a
commodity rate on a given article from a given point of origin and via a
given route is not named in this tariff, which point is intermediate to
a point to which a commodity rate on said article is published in this
tariff via a route through the intermediate point over which such
commodity rate applies from the same point of origin, apply to such
intermediate point from such point of origin and via such route the
commodity rate in this tariff on said article to the next point beyond
to which a commodity rate is published herein on that article from the
same point of origin via the same route.
Note 1: When by reason of branch or diverging lines, there are two
or more ''next beyond'' points, apply the rate to the next point beyond
(in this tariff) which on that article from the same point of origin via
the same route results in the lowest charge.
Note 2: If the intermediate point is located between two points to
which commodity rates on the same article via the same route are
published in this tariff, apply via that route to the intermediate point
the rate to the next point in either direction which results in the
higher charge. In applying this note, if there are two or more next
beyond points due to branch or diverging lines, eliminate all such next
beyond points except the point to which the lowest charge is applicable.
Note 3: If there is in any other tariff a commodity rate on the same
article to the intermediate destination point applicable over the same
route from the same point of origin the provisions of this rule are not
applicable to such intermediate destination point.
(c) ''From'' and ''to'' rules may apply in connection with same rate.
When the rules providing application from and to intermediate points
are both shown in connection with any commodity rate, they establish
commodity rates from intermediate points of origin to intermediate
points of destination on such commodities. Concurrences are not posted
at offices and their provisions are not published in tariffs. Unless
otherwise provided in the tariff intermediate application rules
establish rates from (or to) intermediate points on the lines of
carriers parties to the tariff without regard to the concurrence forms
and numbers under authority of which carriers are shown as participating
carriers.
(d) Application of rules may be restricted. Tariffs may by
appropriate application published in connection with one or more of such
rules, provide that they apply only in connection with the rates or
routes making reference thereto, or may provide for the nonapplication
of such rule or rules to particular rates or routes.
(e) Wording of rules not to vary. The wording of the above rules may
not be varied, except that (1) in tariffs containing alternative
sections the rules may be modified by substituting the words ''in this
section'' for the words ''in this tariff'' wherever they appear. If
this is done such rules must be published in each section of tariff in
which they are to apply and may not be published elsewhere in the
tariff; or (2) when it is desired to alternate the rates in any section
of a tariff with the rates made only by use of an intermediate point
rule applicable in connection with rates in another section, such
intermediate rule must be published in a separate section and must be
modified by changing the words ''this tariff'' to read ''Section No.
------ '' (here insert number of the section which contains the points
and rates in connection with which the intermediate rule is to be used).
The provisions of this paragraph do not waive the requirements of
341.7(b).
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12903, Mar. 30, 1984)
18 CFR 341.28 Tariff notations in connection with fourth section
orders.
(a) When relief from long-and-short haul provision is granted. (1)
When the Commission has issued an order granting to a carrier authority
to depart from the provisions of the amended fourth section of the Act
and to charge higher rates for shorter than for longer distances over
the same line or route, the title page of each tariff or supplement
issued and filed under such authority must bear the following notation:
This tariff (or supplement) contains rates that are higher for
shorter than longer distances over the same route. Such departure from
the terms of the amended fourth section of the Interstate Commerce Act
is permitted by authority of Federal Energy Regulatory Commission fourth
section order (or orders), as indicated in individual items herein.
(2) In connection with the item or items containing the rates as to
which such authority has been granted, specific authority has been
granted, specific reference to the Commission's fourth section order
number and date must be given, except that in instances where all of the
rates in the tariff or supplement are covered by one fourth section
order references to the number and date thereof may be shown on the
title page. When a general fourth section order is referred to, the
particular section thereof granting such authority must be shown in
addition to the order number.
(b) When relief from aggregate of intermediate provision is granted.
(1) When the Commission has issued an order granting to a carrier
authority to depart from the provisions of the amended fourth section of
the Act and to charge rates higher than the aggregate of the
intermediate rates subject to the Act, the title page of each tariff or
supplement issued and filed under such authority must bear the following
notation:
This tariff (or supplement), contains rates that exceed the
aggregates of the intermediate rates subject to the Interstate Commerce
Act. Such departure from the terms of the amended fourth section of the
Act is permitted by authority of Federal Energy Regulatory Commission
Fourth section order (or orders), as indicated in individual items
herein.
(2) In connection with the item or items containing the rates as to
which such authority has been granted, specific reference to the
Commission's fourth section order number and date must be given, except
that in instances where all of the rates in the tariff or supplement are
covered by one fourth section order, reference to the number and date
thereof may be shown on the title page. When a general fourth section
order is referred to, the particular section thereof granting such
authority must be shown in addition to the order number.
(c) When relief is denied. When the Commission has denied authority
to carriers to continue existing departures from the provisions of the
amended fourth section of the Act, but has not prescribed specific rates
in lieu of those existing, and it becomes necessary for carriers to
publish and file rates in full conformity with the provisions of that
section, the rates so filed have not been approved by the Commission.
Tariffs or supplements in which they are published should not indicate
that they are prescribed by, or are in compliance with an order of the
Commission. If desired, however, a clause reading substantially as
follows may be shown:
Issued to bring rates into conformity with the provisions of the
fourth section of the Interstate Commerce Act following the issuance by
the Federal Energy Regulatory Commission of its fourth section order No.
---- of ------ (date), denying carrier's application.
(d) Fourth section not waived. Nothing in this section may be
construed as waiving any of the provisions of the amended fourth section
of the Interstate Commerce Act.
(49 FR 12903, Mar. 30, 1984)
18 CFR 341.29 Letter of transmittal.
(a) All tariffs and supplements filed with the Commission shall be
accompanied by a letter of transmittal of one sheet 8 1/2 by 11 inches
in size, in form substantially as follows:
(Post-office address)
-------------------- , 19 -- .
Transmittal No.
To the Federal Energy Regulatory Commission, Washington, D.C., 20426.
Accompanying schedule is sent you for filing in compliance with the
requirements of the Interstate Commerce Act, issued by ------ and
bearing FERC No. ------ ; Supp. No. ------ to FERC No. ------ ;
revised page to FERC No. ------ ; effective ------ , 19 ------ ; and
is concurred in by all carriers named therein as participants under
continuing concurrences or authorizations now on file with the Federal
Energy Regulatory Commission, except the following-named carriers, whose
concurrences are attached hereto:
..................................
.......... (Sig.)
..................................
........ (Title)
(b) A separate letter may accompany each schedule, or the form may be
modified to provide for filing under one letter as many schedules as can
be conveniently entered.
Note: If receipt for accompanying schedule is desired the letter of
transmittal must be sent in duplicate, and one copy showing the date of
receipt by the Commission will be returned to the sender.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
12904, Mar. 30, 1984)
18 CFR 341.30 Transmission of publications to subscribers.
(a) Except as otherwise authorized in paragraphs (b) and (d) of this
section, one copy of each new tariff, supplement, and loose-leaf page
must be transmitted to each (subscriber) thereto by first-class mail (or
other means requested in writing by subscriber) not later than the time
the copies for official filing are transmitted to the Commission. The
letter of transmittal accompanying the copies to the Commission must
contain the following certification:
I hereby certify that I have on or before this day sent one copy of
each publication listed hereon to each subscriber thereto by first-class
mail, or by other means of transmission agreed upon in writing by the
subscriber.
Signature of person
transmitting publication(s)
Date
(b) If a new tariff or supplement is filed which in its entirety is
published under an authority from this Commission to publish and file
without notice or on notice of less than ten days, or if a new
loose-leaf page is filed which contains a provision published under an
authority from this Commission to publish and file without notice or on
notice of less than ten days, paragraph (a) of this section need not be
complied with as to such publication if it cannot be or compliance would
cause excessive delay, but one copy of such publication must be
transmitted to each subscriber thereto by first-class mail (or other
means requested in writing by subscriber) within five calendar days,
starting with the calendar day following that on which the copies for
official filing are transmitted to the Commission, and the letter of
transmittal to the Commission must contain the following certification:
I hereby certify that I will within five calendar days after today
send one copy of each publication listed hereon to each subscriber
thereto by first-class mail, or by other means of transmission agreed
upon in writing by the subscriber.
Signature of person
transmitting publication(s)
Date
Included in this exception are supplements issued for the purpose of
announcing suspensions made by the Commission, publications (published
in the name of a carrier only) announcing adoptions.
(c) When copies of different publications are transmitted to the
Commission at the same time, some copies of which have been transmitted
to subscribers in compliance with paragraph (a) of this section and some
copies of which will be transmitted to subscribers in compliance with
paragraph (b) of this section, two letters of transmittal must accompany
the copies to the Commission, one complying with paragraph (a) of this
section and the other complying with paragraph (b) of this section.
(d) If there are no subscribers to any publication listed on a letter
of transmittal accompanying the copies for official filing to the
Commission, the letter of transmittal must contain the following
certification:
I hereby certify that there are no subscribers to the publication(s)
listed hereon.
Signature of person
transmitting publication(s)
Date
If copies of different publications are transmitted to the Commission
at the same time, some of which are subscribed to and some of which are
not, only the provisions of paragraphs (a) or (b) of this section, or
both, as the case may be, need be complied with.
(e) Expedited service (when transmitting one copy of each
publication) must be provided to each subscriber requesting it. The
cost of this service may be passed on to the subscriber.
(f) Carriers and agents shall furnish without delay one copy of any
of their tariff publications, effective or published but not yet
effective, to any person upon reasonable request therefor at a
reasonable charge not to exceed that assessed a subscriber.
(g) As used herein, the term ''subscriber'' means a party who
voluntarily or upon reasonable request is furnished at least one copy of
a particular tariff and amendments thereto (including reissues thereof)
by the publishing carrier or agent. The term does not, however, pertain
to requests for a copy or copies of a tariff without a request for
future amendments thereto.
(40 FR 7654, Feb. 21, 1975, as amended at 40 FR 25678, June 18, 1975.
Redesignated and amended at 49 FR 12899 and 12904, Mar. 30, 1984)
341.31 -- 341.50 (Reserved)
18 CFR 341.51 Movement of shipments refused by consignees.
(a) Subject to the limitations in this section, rules (1) providing
that shipments which are refused by consignee may be reconsigned and
forwarded to a new destination under application of the through rate
from point of origin to final destination, either with or without the
exaction of a reconsignment charge, or (2) providing for the return of
shipments (or portions of shipments) refused by consignee to point of
origin at free or reduced rates, are permissible.
(b) Such rules must provide that if reconsignment or forwarding to a
new destination is permitted, the through rate to be applied shall be
that in effect from point of origin to final destination through the
point of reconsignment or reforwarding, and if return to point of origin
is permitted such return must be made over the route over which the
shipment moved to the original destination. Such rules must be
published in tariffs and must be so worded and applied as to be free
from unjust discrimination and to avoid abuse or improper practices
thereunder. The practice of forwarding to a new destination or
redeeming at reduced rates volumes that have been delivered into the
possession of consignees and have been altered is neither proper nor
free from unjust discrimination.
(c) Where a shipment is refused and is left on the hands of the
carrier, it is believed that the carrier, when it recognizes its
responsibility for the value of the shipment and the transportation
charges on same, may haul it for itself to such point on its own lines
as offers the best opportunities or facilities for disposing of it to
advantage, just as it may haul product of its own.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899,
12904, Mar. 30, 1984)
18 CFR 341.52 Responsibilities of carriers under tariffs.
(a) The Commission's tariff regulations require that the carrier or
agent that issues a joint tariff shall, before issuing same, have
secured definite and affirmative authority from every carrier shown
therein as a participant, and shall show in connection with the name of
each participating carrier the form and number of the instrument by
authority of which that carrier is made a party to the tariff.
A carrier has no means of preventing another carrier from naming it
as a party to a joint tariff without proper authority so to do, or of
preventing another carrier from exceeding the authority conferred by a
limited concurrence. It can not, however, be bound by such unauthorized
act and it is its obvious duty to refuse to recognize or apply any such
unlawful issue. It should also at once call the attention of the
Commission and of the one that issued the tariff to such erroneous
action.
(b) If one or more carriers are, without proper authority, so shown
as participating in any tariff and other carriers are lawfully shown as
parties thereto, the use of the publication is unlawful as to the
carriers that are named as parties thereto without proper authority and
lawful as to those that are parties to it under proper authority. The
carrier over whose line shipments are sent under a joint tariff is bound
by the terms of that tariff if it has lawfully concurred therein, and,
if it has not lawfully concurred therein, may not accept earnings in
accordance therewith, but must demand for the service performed its
lawful earnings according to its lawful tariffs.
(c) Responsibility and liability for the unlawful incorporation of
any carrier in a tariff, or for exceeding the authority conferred by a
limited concurrence, will rest wholly upon the carrier that issued the
tariff.
18 CFR 341.53 Withdrawal of filed tariffs not permitted.
On occasion the Commission is requested to return to carriers tariff
publications which have been forwarded to the Commission for filing or
which have been received by the Commission in the ordinary course of
business. Such requests are usually based on the desire to substitute
some corrected or changed publication for the one that has been filed.
To surrender publications duly filed and permit the substitution of
others would involve falsification of the records, which cannot be
permitted. Tariff publications received for filing will not be returned
unless rejected because of failure to give lawful notice of changes.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12904, Mar. 30, 1984)
18 CFR 341.54 Changes in rates.
Section 6(3) of the Act, as amended, provides that:
No change shall be made in the rates, fares, and charges or joint
rates, fares, and charges which have been filed and published by any
common carrier in compliance with the requirements of this section,
except after 30 days' notice to the Commission and to the public
published as aforesaid, which shall plainly state the changes proposed
to be made in the schedule then in force and the time when the changed
rates, fares, or charges will go into effect; and the proposed changes
shall be shown by printing new schedules, or shall be plainly indicated
upon the schedules in force at the time and kept open to public
inspection.
(a) Effectiveness; notice of change. This provision plainly refers
to rates which have already become effective, and also applies the term
''proposed changes'' to rates which have not become effective. It
follows that after notice of a change in rates has been published and
filed the new rates must be allowed to go into effect, and cannot be
changed, withdrawn, or canceled for at least 30 days after the date when
the rates have become effective except as otherwise specifically
authorized by rule, decision, or order of the Commission. A tariff may
provide that it will expire with a date specified therein and which is
at least 30 days subsequent to the date upon which it becomes effective,
or a tariff may contain a notation that certain rates therein stated
will expire with a date specified which is at least 30 days subsequent
to the date upon which such rates become effective, and this will be
legal notice of the cancellation or withdrawal of such tariff or of such
rates. A provision in a tariff or supplement that the same or any part
thereof will expire with a given date is not a guaranty that the tariff,
or supplement, or such part thereof, will remain effective until and
including that date. Such provision must be understood to mean that the
tariff, or supplement, or specified part thereof, will expire with the
date named unless sooner canceled, changed, or extended in lawful way.
(See 341.3(g).)
(b) Commission may allow exception. Carriers must comply fully with
the requirements of the law respecting the publication, filing, and
taking effect of proposed rates, unless upon application and for good
cause shown, the Commission, in the exercise of authority conferred upon
it, shall allow rates to be changed or withdrawn upon less than 30 days'
notice, or by formal order otherwise modify such requirements. No rule
decision, or order of the Commission is authority to change rates or
issue tariffs on less than statutory notice unless so specifically
provided in the rule, decision, or order. (See 341.14(f).)
(49 FR 12904, Mar. 30, 1984)
18 CFR 341.55 Legal rate.
(a) Rate named from origin to destination only legal rate. When a
rate, whether local or joint, from point of origin to destination, has
been established via a route, it becomes the only legal rate for through
transportation via that route, whether it is greater or less than the
aggregate of intermediate rates.
(b) Combination rate. (1) If no rate is named from point of origin
to destination of a shipment via the route of movement, the lowest
combination of rates applicable via the route of movement is the legal
rate.
(2) A combination rate for a through shipment must be treated as a
unit from point of origin to final destination, and the rate applied
must be the combination of the factors in effect on the date the
shipment was accepted for transportation at point of origin. All of the
conditions applicable to each factor in such combination rate for
through shipment in effect on the date the shipment was accepted for
transportation at point of origin must be observed and can not be varied
as to that shipment during the period of its transportation to final
destination.
(c) Back-haul unnecessary. If, in applying combination rates on a
through shipment, the shipment moves from a point of origin (or to a
point of destination) intermediate to a base point upon which the lowest
combination makes, or moves via a junction point which the lowest
combination makes, or moves via a junction point with connecting or
branch line intermediate to the base point upon which the lowest
combination makes, such combination must be applied; and it is not
necessary to haul the shipment to such base point and back again through
(or to) such intermediate point of origin (or destination), or such
intermediate junction point: Provided, (1) That the rates used in such
combination are applicable over the route the shipment would have moved
had it been hauled to the base point and back again over the same route;
and (2) That compliance with routing instructions will permit movement
to the base point and back again over the same route.
Note: This section does not authorize equalizing via one route the
combination of rates applicable over another route and does not confer
any authority to depart from the provisions of the fourth section of the
Act, which prohibits higher charges for shorter than for longer
distances over the same route and higher charges than the aggregate of
the intermediate rates over the same route. It must also be understood
that in a case where the lowest combination of rates makes on a base
point as to which the point of origin or of destination is directly
intermediate, a specific rate to or from such point that is higher than
such combination is included in the Commission's ruling that a through
rate that is higher than the combination of intermediate rates between
the same points is prima facie unreasonable. It must be further
understood that in applying the lowest combination authorized in this
section the Commission expresses no opinion as to the reasonableness of
a rate so constructed.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12904, Mar. 30, 1984)
18 CFR 341.56 Reduction of rate to equal the aggregate of the
intermediate rates.
(a) Section 4 of the Act, as amended, prohibits the charging of any
greater compensation as a through rate than the aggregate of the
intermediate rates that are subject to the Act. The Commission has
frequently held that through rates which are in excess of the sum of the
intermediate rates between the same points via the same route are prima
facie unreasonable. The Commission has no authority to change or fix a
rate except after full hearing. It is believed to be proper for the
Commission to say that if called upon to formally pass upon a case of
this nature it would be its policy to consider a rate which is higher
than the aggregate of the intermediate rates between the same points via
the same route as prima facie unreasonable and that the burden of proof
would be upon the carrier to defend such unreasonable rate.
(b) Where a rate is in effect by a given route from point of origin
to destination which is higher than the aggregate of intermediate rates
from and to the same points, by the same or another route, such higher
rate may, on not less than 1 day's notice to the public and the
Commission, be reduced to the actual aggregate of such intermediate
rates. Such reduced rate must be published in a supplement to or a
reissue of the tariff in which the rate so reduced appears. Any tariff
or supplement containing a rate reduced under authority of this section
must bear on its title page, or in connection with such item, the
notation ''Issued on 1 day's notice under authority of 18 CFR 341.56.
The rate (or rates) hereby reduced appears in ------ Tariff, FERC ------
, item (or page) ------ , and the factors to and from ------ (here
insert point or points on which combination makes) used in making the
new rate (or rates) are found in ------ , Tariff, FERC No. ------ ,
item (or page) ------ , and ------ Tariff, FERC No. ------ , item (or
page) ------ .''
(c)(1) In order to facilitate the publication of rates which will be
in accord with the aggregate of intermediates provision of the fourth
section of the act the following rule may be incorporated in tariffs:
Carriers have endeavored to publish herein rates which do not exceed
the aggregate of the intermediate rates between points between which
there is an actual movement of traffic, but if there should be in this
tariff any rate which is in excess of the aggregate of intermediates, or
if through subsequent change in an intermediate factor any rate in this
tariff becomes higher than the aggregate of intermediates in violation
of the provisions of the fourth section of the Act, carriers will reduce
such rates to the aggregate of the intermediate rates on 1 day's notice
under authority of 18 CFR 341.56. On any commodity between points
between which there is a movement or a prospective movement of that
commodity. The publication of such reduced rate will be made within 30
days after such unlawful rate comes to carrier's notice.
Carriers, parties to this tariff, whose rate over the route of
movement is higher than the aggregate of the intermediates over that
route, further agree that on any shipment on which the higher rate named
in this tariff for that route has been charged, application will be made
promptly to the Federal Energy Regulatory Commission for authority to
award reparation on the basis of the aggregate of intermediates in
effect on date of shipment. (See note.)
Note: Carriers or shippers who discover combinations which result in
lower charges than the rates named herein, should promptly report such
cases to the publishing agent of his tariff, showing the through rate
and the item or page where it is found together with the separate
factors which make up the combination, giving tariff reference by item
or page, where possible, for each.
(2) In placing this rule in tariffs carriers must strictly adhere to
the wording of the rule as no modification thereof will be permitted.
(3) The failure to publish and file reduced rates as provided in this
part, within 30 days from the date that said rates are brought to the
attention of the carriers parties thereto, or any of them, or their
agents, will be considered by the Commission as sufficient ground for
the issuance of an order prohibiting its use in connection with such
carrier or carriers. A promise to publish certain rates, when published
in a tariff, becomes the rule of the carriers parties to the tariff and
therefore when a carrier or agent has been called upon to reduce rates
under authority of the above rule it will not be necessary for such
carrier or agent to secure any additional authority from the carriers
parties to the tariff for the publication of the reduced rates and any
delay on that account may cause carriers, to incur the penalties
provided for violations of the fourth and sixth sections of the Act in
addition to losing the right to use the rule in tariffs.
(49 FR 12904, Mar. 30, 1984)
18 CFR 341.57 Newly constructed pipelines.
(a) Rates from, to, or via newly constructed lines. Charges
applicable at, and rates, charges, rules or regulations applicable from,
to, or via points on newly constructed pipelines including loops,
branches and extensions of existing pipelines may be established in the
first instance on not less than 10 days' notice. Such rates when
established may be changed only in accordance with the act, except that
where, by reason of the establishment of local rates between points on a
newly constructed line as defined in this section, combination through
rates have become effective between points on said line and points on
other lines of the same or other carriers, such combination through
rates may, within 60 days after the effective date of the local rates
between points on said newly constructed line, be displaced on not less
than 10 days' notice by other rates, through or combination, which
produce lower charges than such combination rates.
(b) Tariff notation when rates established in first instance. A
tariff or supplement establishing rates, charges, rules, or regulations
in the first instance under authority of this section must contain the
following notation on its title page, except that if only a portion of
the rates, charges, rules, or regulations in such publications are
established under authority of the rule the notation must be shown in
connection with such rates, charges rules, or regulations:
Issued on 10 days' notice, authority 18 CFR 341.57. Rates established
in the first instance (from, to, between, via, or at, as case may be)
points on pipeline.
(c) Tariff notation for subsequent publications. A tariff or
supplement which changes combination rates from, to, or via points on a
newly constructed line as provided in paragraph (a) of this section must
contain the following notation on its title page, except that if only a
portion of the rates, charges, rules, or regulations in such publication
are established under authority of the rule, the notation must be shown
in connection with such rates, charges, rules, or regulations:
Issued on 10 days' notice, authority 18 CFR 341.57. Rates established
(from, to, between, via, or at, as case may be) points on pipeline.
Local rates first established (from, to, between, via, or at, as the
case may be) such points in -------- FERC No. -------- effective
-------- (date).
(d) Rates established may not be reduced by similar rates. When a
commodity rate has been established from, to, via, or between points on
a newly constructed line, a different commodity rate from, to, via, or
between the same points may not be established at a later date under
authority of this section; but commodity rates may be established under
authority of this section within the 60-day period prescribed herein.
Interested carriers and publishing agents should be notified as much in
advance of the opening of a newly constructed line as is possible in
order that rates may be established which will give carriers and
shippers fullest possible use of such newly constructed lines.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12905, Mar. 30, 1984)
18 CFR 341.58 Applications under section 6 for authority to make
changes in tariffs.
(a) Rates changed on less than statutory notice. Section 6 of the
Act authorizes the Commission in its discretion and for good cause
shown, to permit changes in rates on a notice of less than 30 days. The
Commission will exercise this authority only in cases where actual
emergency and real merit are shown. Desire to meet the rates of a
competing carrier which has given the full statutory notice of change in
rates will not of itself be regarded as good cause for allowing changes
in rates on a notice of less than 30 days. Clerical or typographical
errors in tariffs constitute good cause for the exercise of this
authority, but every application based thereon must plainly specify the
omissions or mistakes together with a full statement of the
circumstances attending such omission or error and must be presented
with reasonable promptness after issuance of the defective tariff.
(b) Authority necessary to make applications. Applications for
permission to establish rates, rules, or regulations on less than
statutory notice, or for waiver of the provisions of this part must be
made by the agent or carrier that holds authority to file the proposed
changes. If the application requests permission to make changes in
joint tariffs it must state that it is filed for and on behalf of all
carriers parties to the proposed change.
(c) Permission will not issue to modify formal orders. Frequently
carriers file sixth section applications requesting authority to make
changes on short notice when a formal order of the Commission required
publication on 30 days notice. Such requests in effect are requests for
modification of the formal order and should be filed as petitions on the
formal docket for modification of the order and not as applications
under sixth section.
(d) Partial use of permission prohibited. Instances have occurred
where carriers or their agents have not used the full authority extended
by special permissions. When passing upon sixth section applications
the Commission gives consideration to all of the facts and circumstances
set forth in the application and if approved the special permission is
issued with the understanding that all of its terms are to be complied
with and that all the authority dealing with the same subject matter
will be used. Therefore, if all related matter authorized by special
permissions will not be established and more limited authority is
desired a new application complying with the provisions of this section
in all respects and making reference to the previous authority must be
filed.
(e) Applications, form and number. Applications (including
amendments thereto and exhibits made a part thereof) for permission to
change rates, rules, or regulations, on less than statutory notice or
for waiver of the provisions of this part shall be made with fourteen
copies in conformance with Rule 2004 of Commission's Rules of Practice
and Procedure, shall be addressed to the Federal Energy Regulatory
Commission, and shall be sent to the Secretary, Federal Energy
Regulatory Commission, Washington, D.C. 20426. Such applications shall
be made on paper 8 1/2 by 11 inches, shall be in the following form,
shall give the information required by that form, shall be numbered
consecutively and must bear the signature of the president, vice
president, traffic manager, assistant traffic manager, general freight
agent, or a duly authorized attorney and agent, specifying title.
(Name of carrier in full)
-------------------- , 19 ---- .
(Place and date)
To the Federal Energy Regulatory Commission, Washington, D.C. 20426:
The ---------- (Name of carrier), by ---------- (Name of officer) its
---------- (Title of officer) does hereby respectfully petition the
Federal Energy Regulatory Commission that it be permitted, under section
6 of the Interstate Commerce Act, as amended, to put in force the
following rates (or rules or regulations) to become effective ----------
days after the filing thereof with the Federal Energy Regulatory
Commission
(State fully, either specifically or by reference to an accompanying
exhibit, the rates (or rules or regulations) which it is desired to put
into effect, the commodities upon which they are to apply and the points
of origin and destination. If permission is sought to establish a rule
or regulation the exact wording of the proposed rule or regulations must
be shown)
Your petitioner further represents that the said rates (or rules or
regulations) above mentioned will be published in Tariff FERC No. ----
(or in a consecutively numbered supplement to FERC No. ---- ), and will
supersede and take the place of the rates (or rules or regulations) on
like traffic from and to the points above named which are set forth in
Tariff FERC No. ---- (or supplement) on file with the commission.
(Here state, either specifically or by reference to an accompanying
exhibit, the present rates, rules, or regulations, together with the
FERC numbers in which published and the effect of the proposed change)
(State names of all carriers publishing rates on the commodity or
commodities covered by the application between the same or related
points and the FERC numbers of tariffs containing such rates)
(State whether or not the proposed rates or rules or regulations,
including the request to establish on less than statutory notice have
been called to the attention of such carriers and their views thereon)
(State the basis on which the proposed rates are constructed, if the
application seeks less than statutory notice)
(State the relationship existing between points of origin and
destination covered by the application, and any point or points of
origin or destination not covered by said application, if the
application seeks less than statutory notice)
(State what relationship, if any, the rates on the commodity or
commodities covered by the application bear to rates on other
commodities if the application seeks less than statutory notice)
And your petitioner further bases such request upon the following
facts, which present certain special circumstances and conditions
justifying the request herein made:
(State fully all other circumstances and conditions which are relied
upon as justifying the application and which may aid the commission in
determining the question presented. If short notice is requested, state
why the change was not established upon statutory notice)
(Corporate name of carrier)
By
(Name and title of officer)
Subscribed and sworn to before me this ------ day of
-------------------- , 19 -- .
(Only the original need be executed)
Notary Public
When an application is made by an agent, appropriate change should be
made in the introductory and closing paragraphs of the form.
(32 FR 20510, Dec. 20, 1967. Redesignated and amended at 49 FR 12899
and 12905, Mar. 30, 1984)
18 CFR 341.59 Diversion or reconsignment privileges and rules.
(a)(1) Frequently a shipper desires to forward a shipment to a
certain point and have the privilege of changing the destination or
consignee while shipment is in transit or after it arrives at
destination to which originally consigned, and to forward it under the
through rate from point of origin to final destination which generally
is lower than the combination of intermediate rates.
(2) Such services are of value to the shipper. If they are granted,
carriers' tariffs shall so state in terms that are not open to
misconstruction, and shall also state clearly the conditions under which
they may be used and the charges that will be made therefor.
(b) Some carriers do not consider a change of consignee which does
not involve a change of destination as a reconsignment, while others do
consider it a reconsignment and charge for it as such. The Commission
holds the view that when not specifically qualified in tariffs, the
terms ''reconsignment'' or ''diversion'' include changes in destination,
routing, consignor or consignee. If carrier wishes to distinguish
between such changes in its privileges or charges it must so specify in
its tariff rules.
341.60 (Reserved)
18 CFR 341.61 Demurrage on interstate shipments.
(a) The act requires that carriers shall publish, post and file
tariffs containing terminal or other charges and all rules or
regulations which in any wise change, affect, or determine the value of
the service rendered to the shipper or consignee. Such terminal charges
include demurrage charges.
(b) Demurrage rules and charges applicable to interstate shipments
are governed by the act and therefore are within the jurisdiction of the
Federal Energy Regulatory Commission and not within the jurisdiction of
State authorities.
(c) Demurrage rules and charges published and filed must be observed
as strictly as transportation rules and charges. Such charges are
controlled by the tariffs in effect contemporaneously with the accrual
of the service, and therefore are subject to such changes as may be made
in the applicable tariffs during the period of accrual.
Cross Reference: For regulations concerning posting tariffs at
points, see 49 CFR Part 1312.
341.62 -- 341.63 (Reserved)
18 CFR 341.64 In absence of routes, rates apply via lines parties to
tariffs.
If a tariff contains no routing direction the joint rates shown
therein are applicable between the points specified via the lines of any
and all carriers that are parties to the tariff; and shipper must not
be required to pay higher charges than those stated in the tariff
because the carriers have not agreed divisions of the rates via the
junction through which the shipment moves. If agent of carrier bills or
sends shipment via a route or junction point that is covered by the
tariff but via which no division of the rate applies, it is for the
carriers to agree between themselves upon the division of the rate.
341.65 -- 341.66 (Reserved)
18 CFR 341.67 Export and import traffic -- ocean carriers.
(a) Ocean carriers not subject to Act. Common carriers by water, or
conferences of such carriers, engaged in the foreign commerce of the
United States, as defined in the Shipping Act, 1916, that operate
between ports of the United States and foreign countries are not subject
to the terms of the Interstate Commerce Act or to the jurisdiction of
the Federal Energy Regulatory Commission.
(b) Through routes and joint rates. (1) A common carrier by pipeline
subject to the Interstate Commerce Act (hereinafter referred to in this
section as the domestic carrier), may establish a through route and
joint rate with a vessel-operating common carrier by water engaged in
the foreign commerce of the United States (hereinafter referred to in
this section as the ocean carrier) as defined in the Shipping Act, 1916,
for the transportation of property between any place in the United
States and any place in a foreign country. Every tariff naming such a
through route and joint rate shall be filed with this Commission. The
tariff may be filed in the name of the ocean carrier, a conference of
ocean carriers, the domestic carrier or the duly appointed tariff
publishing agent of such carriers.
(2) The tariff shall be constructed, filed, and posted in conformity
with the Interstate Commerce Act, and, except as otherwise specifically
authorized, with the regulations in Parts 341 and 343 of this chapter.
The tariff shall be printed in the English language, include the names
of all participating carriers, a description of the services to be
performed by each participating carrier, a statement of the joint rate,
and a clear and definite statement of the division, rate, or charge to
be received by the domestic carrier for its share of the revenue
covering a through shipment or aggregate of shipments under the tariff.
The division, rate, or charge accruing to the domestic carrier must be
shown in terms of lawful money of the United States. If shipments are
to be permitted to be aggregated which are rated under more than one
tariff published by the carrier or for its account, each tariff so
affected must contain a specific rule, providing for the aggregation in
connection with the statement of the domestic carrier's divisions and
identifying by FERC designation each of the other tariffs. A tariff
filed in the name of a conference need not show ''Agent'' after the name
of the conference unless the conference publishes as an agent. Where
the volumes to be loaded or unloaded into or from the facilities by the
domestic carrier, the tariff must clearly state that the joint rate
includes this service or must provide a separate charge to apply when
said service is provided.
(3) Rates or charges may be stated to apply in a unit other than a
United States unit provided the unit is defined in the tariff where
used. The International System of Units (SI) (the metric system) may be
used and need not be defined. A rate or charge applying on a unit of
measurement other than weight may be published, but if the tariff also
includes a rate or charge applying on a unit of weight on the same
traffic, the charges on the weight basis must alternate with the charges
on the measurement basis other than weight. In every case the tariff
shall provide a definite method for determining the measurement of the
shipment and the applicable charges. ''Cargo, N.O.S.'' may be provided
as a commodity description provided the term is clearly defined in the
tariff where used. Tariffs governing the application of the rate tariff
need not show a carrier as a participant when none of the provisions
therein apply for such carrier's account.
(4) Allowances, cargo administrative charges, or reductions shall not
be provided for payment to shippers or other parties for services
performed by or facilities furnished by other than the carriers parties
to the through transportation unless (i) such carriers by tariff
publication hold themselves out to perform such services and furnish
such facilities, (ii) such carriers are able to perform such services
and furnish such facilities upon reasonable demand, and (iii) the
performance of such services and furnishing of such facilities are
included in the through joint rate or charge. This subparagraph does
not apply where such provisions do not affect the division, rate, or
charge accruing to the domestic carrier or the services performed by
such carrier.
(5) A domestic carrier desiring to become a participant in a tariff
filed in the name of a conference of ocean carriers, which conference
does not publish as an agent, must give to its connecting ocean carrier
participating in such conference tariffs a concurrence in tariffs issued
and filed by the ocean carrier or the conference, or both. A limited
concurrence may provide for only those limitations authorized in 341.19
of this chapter. The concurrence forms prescribed by 341.19 shall be
modified to show that the authority extends to amendments to the
tariff(s) and extends to tariffs filed in the name of the conference,
and to show the types of tariffs such as tariffs (containing joint
pipeline-ocean rates) in which the domestic carrier desires to
participate. Powers of attorney must not be executed unless the
conference publishes as an agent.
(6) The following changes may be published to become effective upon a
specified date not prior to the date filed with the Commission in
Washington, D.C., provided the division, rate, or charge accruing to the
domestic carrier or a provision governing or affecting such division,
rate, or charge does not change.
(i) A change in a published rate, charge, rule, regulation, or other
provision which results in a reduction or in no change in charges. This
includes a change in a rate or charge which results in lessening or
canceling a proposed (published but not yet effective) increase.
(ii) The establishment of a rate on a specific commodity not
previously named in a tariff which results in a reduction or in no
change in charges. The tariff must contain a cargo, N.O.S. rate or
similar general cargo rate, which rate would otherwise be applicable to
the specific commodity. The specific commodity rate must be equal to or
lower than the cargo, N.O.S. or general cargo rate.
(iii) Except as otherwise provided in this paragraph, no new or
initial rate, charge, rule, regulation, or other provision and no new
point of origin or destination may be published upon less than 30 days'
notice. In no case may the establishment of or a change in a division,
rate, or charge accruing to the domestic carrier or a provision
governing or affecting such division, rate, or charge become effective
upon less than 30 days' notice.
(7) If a tariff includes charges for terminal services, canal tolls,
or additional charges not under the control of the carrier or
conference, which carrier merely acts as a collection agent for the
charges, and the agency making such charges to the carrier increases the
charges without notice or without adequate notice to the carrier or
conference, such charges may be increased in the tariff by specific
publication effective upon a specified date not prior to the date filed
with the Commission, in Washington, D.C., whether included in the joint
rate or separately stated. If the change occurs in the division, rate,
or charge accruing to the domestic carrier, the amendment must contain a
statement explaining the change.
(8) Every change made under authority of 341.67(b) (6) or (7) must
be shown in an amendment (a supplement if the tariff is in bound form or
a loose-leaf page if the tariff is in loose-leaf form) to the tariff.
The rates, charges, rules, regulations, or other provisions authorized
to be changed thereunder may be changed without their having been
effective for 30 days prior to the effective date of the change.
(9) The regulations in 341.9(k) -- Suspension of Tariff Schedules --
shall govern only when the operation of the division, rate, or charge
accruing to the domestic carrier or any provision governing the
division, rate, or charge or the service performed by such carrier is
suspended by an order of this Commission.
(10) The following reference marks may be used in the exact form
shown for the purposes indicated and may not be used for any other
purpose:
(R) to denote reductions.
(A) to denote increases.
(C) to denote changes in wording which result in neither increases
nor reductions in charges.
An explanation of these reference marks must be provided in the
tariff in which used.
(c) Port combination basis. Domestic and ocean carriers may enter
into joint rate arrangements, as authorized by paragraph (b) of this
section, and domestic carriers may at the same time maintain in effect
rates applicable only from and to the ports, usable in combination with
ocean carriers' independently established rates. Publication of such
rates by the domestic carrier shall be subject to the following:
(1) The domestic carriers shall file their rates to the ports and
from the ports, and such rates must be the same for all, regardless of
which ocean carrier may be designated by the shipper, except as
otherwise provided by section 28 of the Merchant Marine Act (41 Stat.
988, 46 U.S.C. 884).
(2) When the domestic carriers publish rates which are indicated to
apply only on export or import traffic, the tariffs containing such
rates shall specify by inclusion or exclusion the countries to or from
which traffic subject to such rates shall move, regardless of whether
such countries are, or are not, adjacent to the United States. Tariffs
shall also specify whether or not properly destined to or from which
traffic subject to such the Commonwealth of Puerto Rico, Guam, Hawaii,
or the Canal Zone is subject to such rates. In the absence of a
statement in tariffs limiting the application of export or import rates,
such rates will apply on traffic destined to or coming from them.
(3) As a matter of convenience to the public, the domestic carriers
may also publish as information in their tariffs the ocean carriers'
rates or charges that will apply to or from a foreign country in
connection with the domestic carriers' rates. When this is done, the
ocean carriers' rates or charges are in no manner subject to the
jurisdiction of this Commission, but the rates of the domestic carriers
applying to or from the ports are subject to all provisions of the
Interstate Commerce Act and to this Commission's regulations.
(d) Through export and import billing. Export and import shipments
may be forwarded under through billing. Through bills of lading must
clearly separate the liability of the carriers included therein, where
different, and must show (1) the tariff rates or charges of the domestic
carriers to or from the port or (2) the joint rates or charges when such
rates or charges are established and are named in tariffs on file with
this Commission as provided in paragraph (b) of this section. The name
of the domestic carrier shall appear in a prominent place on the face of
the bill of lading when that carrier originates the shipment. Tariffs
which provide for the use of a specified kind of bill of lading shall
reproduce all of the terms and conditions thereof.
Cross Reference: For regulations governing the posting of tariffs of
common carriers by pipeline see Part 343.
(49 U.S.C. 10762)
(41 FR 9352, Mar. 4, 1976, as amended at 46 FR 14352, Feb. 27, 1981.
Redesignated and amended at 49 FR 12899 and 12906, Mar. 30, 1984)
18 CFR 341.67 PART 342 -- LONG-AND-SHORT-HAUL AND
AGGREGATE-OF-INTERMEDIATE RATES -- PIPELINES
Sec.
342.21 Disposition of fractions.
342.61 Relief for departures in rates on transit shipments.
342.65 Filing schedules simultaneously with applications.
342.75 Applications, preparation and filing, conformity with rules.
342.76 (Reserved)
342.77 Long-and-short-haul and aggregate of intermediate applications
separate.
342.78 Number of copies, form, general specifications and
requirements, signatures, and verification.
342.79 Matters to be shown in the application.
342.80 Additional information required.
342.81 Additional matters to be shown.
342.82 Miscellaneous provisions.
342.83 Acceptance of applications.
342.84 Applications for relief previously denied.
342.85 Changes and additions.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (Supp. V 1981), Interstate Commerce Act, 49 U.S.C. 1-27
(1976); E.O. 12009. 3 CFR Part 142 (1978).
Source: 49 FR 12906, Mar. 30, 1984, unless otherwise noted.
18 CFR 342.21 Disposition of fractions.
(a) Applying the rule de minimis, all carriers are hereby authorized,
in the making up of through rates on the aggregate of the intermediate
rates, to disregard fractions of a cent less than .5 retaining the half
cent in the rate when it is even .5, and making the rate in even cents
when the fraction is more than .5.
(b) Tariffs need contain no reference to this order. The Commission
does not hereby approve any rates that may be filed under this
authority, all such rates being subject to complaint, investigation, and
correction if in conflict with any other provision of the Act.
18 CFR 342.61 Relief for departures in rates on transit shipments.
In those instances in which fourth-section orders have been or may be
entered granting carriers relief from the provisions of section 4 of the
Act to maintain lower rates for the transportation of like kind of
property for longer than for shorter distances the same relief shall
also apply when the said rates, with or without the addition of lawfully
established charges to cover the cost of transit, are applied on transit
shipments. This section shall not be construed as authorizing
fourth-section departures which might result from the establishment of
transit privileges at some points and not at other points on the route
of movement, nor as approving any transit arrangements that may be
established under this permission, all such arrangements being subject
to complaint, investigation, and correction if in conflict with any
other provision of the Act.
18 CFR 342.65 Filing schedules simultaneously with applications.
(a) Section 4(1) of the Interstate Commerce Act (49 U.S.C. 4(1)) has
been amended by the Transportation Act of 1940, now effective, so as to
eliminate the so-called equidistant clause and to provide:
That tariffs proposing rates subject to the provisions of this
paragraph may be filed when application is made to the Commission under
the provisions hereof, and in the event such application is approved,
the Commission shall permit such tariffs to become effective upon one
day's notice.
(b) Heretofore, the practice of carriers has been to file
applications for, and to obtain, fourth-section relief of either a
temporary or continuing character before publishing and filing rates
which would without relief contravene the fourth section. The new
proviso is construed as intended to shorten the period intervening
between carrier's determination to publish rates and their effective
date so that if relief is granted, the time now intervening between the
filing of the application and its granting will be eliminated, but is
not intended to set aside the 30 days' notice requirement of section 6
or to abridge the rights of interested persons to seek suspension under
section 15(7). To facilitate administration of the new proviso and at
the same time to avoid interference with other sections of the Act, the
following procedure has been adopted:
(1) Insofar as possible, fourth section applications filed under the
proviso will be acted upon before the effective date of the tariffs.
(2) In cases where it is found possible to pass upon applications
before the effective date of the tariffs, if relief is granted, such
relief will be made effective not with issuance of the order but on the
same date as the effective date of the tariffs.
(3) In cases where action upon the application has not been taken
prior to the effective date of the schedules, or where the relief sought
has been denied in whole or in part, the present intention is to suspend
the tariffs in order to avoid the unauthorized fourth-section departures
which otherwise would result.
(4) Where rates were suspended solely because of failure to act upon
the fourth-section application and where the necessary relief is
subsequently granted, the present intention is promptly to vacate the
order of suspension, the vacating order to be effective with issuance.
(c) Pending modification of the Commission's Rules of Practice,
carriers that file applications for relief from the provisions of
section 4 with respect to rates or charges included in schedules filed
concurrently with such applications, should include in the applications
a complete statement of the tariffs and supplements containing such
rates or charges in substantially the following form:
The rates (charges) as to which relief is prayed herein have been
published and filed to become effective ------ (date) in ------ (name of
agent or carriers). Tariff, FERC ------ (No.) (supplement number to
tariff should be shown if published therein).
(d) Tariffs and supplements filed under the above provision should
show on the title page thereof a statement that they contain rates or
charges, as the case may be, that contravene the long-and-short-haul (or
aggregate-of-intermediates) provision of section 4, and should give
specific reference to an item or page of the tariff or supplement on
which shall be prominently displayed a complete and specific list of
items and pages on which such rates are found, with specific number and
date reference to the application for relief with respect to such rates
or charges.
(e) When appropriate fourth section relief has been granted before
the effective date of tariffs or supplements, and such tariffs or
supplements become effective, number reference to the order granting
such relief need be given only when the next supplement or reissue is
filed.
(f) Many outstanding orders granting relief from the
long-and-short-haul provision of section 4 contain conditions designed
to give effect to the equidistant clause. The present intention is not
to eliminate such conditions in the absence of petitions for reopening
of proceedings in which such orders were entered as it is believed that
in some cases retention of such conditions may be warranted
notwithstanding the repeal of the equidistant clause and in others some
substitute limitation may be necessary.
Note: See previous notice in this matter, 5 FR 3758, Sept. 25,
1940.
18 CFR 342.75 Applications, preparation and filing, conformity with
rules.
Any common carrier subject to the Act may apply to this Commission,
under section 4(1) of the Act, for such authorization as it is empowered
to grant thereunder. Such application must conform to the requirements
hereinafter provided.
342.76 (Reserved)
18 CFR 342.77 Long-and-short-haul and aggregate of intermediate
applications separate.
Separate applications shall be filed for relief from the
long-and-short-haul provision, and for relief from the
aggregate-of-intermediates provision of section 4 of the Act.
18 CFR 342.78 Number of copies, form, general specifications and
requirements, signatures, and verification.
(a) Applications shall be substantially in the form shown below, and
five copies of each, including all exhibits and maps must be furnished.
Commission's No. ----
Carrier's No. ----
The ------ Company, by ------ , its ------ (Official title), hereby
petitions the Federal Energy Regulatory Commission (FERC) for authority
to establish rates or charges hereinafter set forth without observing
the long-and-short-haul (or aggregate-of-intermediates) provision of
section 4(1) of the Interstate Commerce Act. (If rates, etc., are to
apply over the lines of more than one carrier, the application should
show that it is made for and on behalf of all such carriers, naming
them, or if made for or on behalf of all carriers parties to a
particular tariff, reference may be made by FERC No. to such tariff for
the names of such carriers.)
I. (State fully the rates, charges, etc., which it is desired to
establish, with complete reference to the tariffs in which published and
the effective date thereof, the routes over and the commodities upon
which they are to apply, and name, or descriptions of the points of
origin and destination. See Note A following.)
II. (State fully names or description of intermediate points at which
it is desired to maintain higher rates etc., and rates etc., at such
points or a sufficient number of such points to illustrate the
situation, including the first and last higher-rated and the
highest-rated intermediate points. Distances between all points shown
should be included in this statement. In applications for relief from
the aggregate-of-intermediates provision, set forth typical examples of
the higher through rates or charges, and the intermediate rates or
charges that in the aggregate are less than the through rates etc. See
Note A, following. Also show FERC Nos. of tariffs, and supplements
thereto, containing the rates and distances stated.)
III. This application is based upon the following facts which present
all of the circumstances and conditions relied upon by your applicant in
justification of the relief herein prayed: (Make a complete and
accurate statement as to the necessity for the proposed changes, and all
of the circumstances and conditions relied upon as justifying the relief
prayed. See Note A, following.)
IV. (Give specific reference to any proceeding pending before or
determined by the Commission, by docket number, and report citation, if
any, which may have any bearing upon, or be in any way related to the
rates, etc., sought to be established or maintained. If none, state that
fact.)
------------ Company (Corporate title of applicant)
By (Personal signature of officer)
Title of officer
Note A: When more convenient this information may be given in an
exhibit or exhibits, and here referred to: ''As stated in exhibit ----
attached to and made a part hereof.'' Information required under each
numbered section, as above, should be shown in a separate exhibit.
Exhibits should conform to the following requirements:
Generally. Exhibits of a documentary character may have a maximum
width of 22 inches by 12 1/2 inches in height. Whenever practicable the
sheets of each exhibit and the lines of each sheet should be numbered.
If the exhibit consists of five or more sheets, the first sheet or
title-page should be confined to a brief statement of what the exhibit
purports to show, with reference by sheet and line to illustrative or
typical examples contained therein. The exhibit should bear an
identifying number, letter, or short title which will readily
distinguish it from other exhibits offered. It is desirable that,
whenever practicable, rate comparisons and other evidence should be
condensed into tables. Exhibits should not be argumentative, should be
limited to statements of fact, and be relevant and material to the
issue.
Reference to tariff authority, routes, and distances. All exhibits
showing rates, charges, or other tariff or schedule provision must, by
appropriate Federal Energy Regulatory Commission number reference,
indicate the tariff or schedule authority therefor, and if distances are
shown must also show the authority therefor and, by lines, highways, or
waterways, and junction points, the routes over which the distances are
computed; except that the routes over which the distances are computed
need not be shown when such distances are specifically published in a
tariff or schedule lawfully on file with the Commission, or definitely
ascertainable from a tariff or schedule on file with the Commission
showing rates prescribed by the Commission and based on short-lined
distances, or short highway distances, provided the exhibit makes
specific reference to such tariff or schedule as provided by this rule.
(b) Applications shall be on opaque, unglazed, durable paper not
exceeding 8 1/2 by 11 inches. To permit the binding in covers of
uniform size, margins of at least 1 1/2 and 1 inch, respectively, shall
be allowed on the left and right margins. Binding shall be on the left
margin. Reproduction may be by printing, multilithing, mimeographing,
or any other process, provided the copies are clear and permanently
legible. Whiteline blue prints which cannot be reproduced by
photography are not desirable. If directly typewritten, or if in
facsimile reproduction of typewriting, the impression must be on one
side of the paper and must be double spaced, except that long quotations
shall be single spaced and indented. If printed, nothing less than
10-point type shall be used, except that 8-point type may be used in
footnotes.
(c) The original copy of the application must be over the personal
signature of an executive officer, a responsible traffic officer, or a
duly authorized attorney or agent, specifying his title, and sworn to
before a notary public or other officer authorized by law to administer
oaths. Verification shall be in the manner shown below:
State of ------ ss:
County of ------
------ (Name of affiant), being duly sworn, deposes and says:
That he is the ------ (title of affiant) of the ------ (Name of
applicant); that he is authorized by said applicant to sign and file
with the Federal Energy Regulatory Commission this application and
exhibits attached hereto, and to verify the facts and statements
contained in said application and exhibits; that he has carefully
examined all of such statements contained in said application and
exhibits; and that the same are true and correct to the best of his
knowledge, information, and belief.
Subscribed and sworn to before me, a ------ in and for the State and
County above, this ------ day of ------ , 19 -- .
(SEAL) My commission expires ------ .
18 CFR 342.79 Matters to be shown in the application.
(a) The information required in this section and in 342.80 and
342.81, and 342.82, according to the grounds upon which relief is
sought, shall be shown in the application when Commission action is
desired on the presentation made therein, without hearing. When a
hearing is desired and applicants propose to justify at the hearing the
relief desired, the information specified in this section shall be
included in the application, and the information required in 342.80,
342.81 and 342.82 may, instead, be introduced at the hearing. It should
be understood, however, that where the information included in the
application does not fully justify the relief sought, or for other good
cause, the application may be assigned for hearing at the Commission's
discretion. The application shall show:
(b) The names of the carrier or carriers for, or on behalf of which
it is made, or, if made on behalf of all carriers parties to a
particular tariff, the application may refer to such tariff by the
Federal Energy Regulatory Commission number (hereinafter abbreviated
FERC No.).
(c) The FERC No. of all tariffs in which rates or charges referred
to in the application or exhibits are published.
(d) The rates or charges proposed to be established; the basis or
bases therefor; the commodities on which they are to apply; the points
of origin and destination; and the routes between such points over
which the rates or charges will apply. (Direct routes only with respect
to applications for long-and-short-haul relief). When relief is desired
from or to ''related'' points or ''group'' points, the points or groups
shall be indicated in the map hereafter required to be furnished, or
defined by reference to tariff publications providing the grouping.
(e) If long-and-short-haul relief is sought, the intermediate points
at which it is proposed to maintain rates or charges higher than those
proposed from or to more distant points and the rates or charges at such
points. If relief from the aggregate-of-intermediate provision of
section 4 is sought, the intermediate rates or charges that, in the
aggregate, are less than the through rates or charges.
(f) A complete and accurate statement of the grounds relied upon as
justification for the relief prayed.
(g) Applications for relief from the provisions of section 4 with
respect to rates or charges included in schedules filed before the
necessary relief has been obtained shall include in the opening or
second paragraph a complete statement of the tariffs and supplements
containing such rates or charges in substantially the following form:
The rates (charges) as to which relief is prayed herein have been
published and filed to become effective ------ (Date) in ---- (Name of
agent or carriers) tariff FERC ---- (Number). (Supplement number should
be shown if published in a supplement).
18 CFR 342.80 Additional information required.
(a) Long-and-short-haul relief. Applications should show:
(1) That, where proposed rates are depressed to meet competition, the
competitive rates they are being established to meet are not within the
control of applicant carriers, and any other facts tending to show that
such rates should not be observed as maxima at intermediate points.
(2) That the lower rates for longer than for shorter hauls over the
same line or route are reasonably compensatory.
The following information is considered pertinent in a showing as to
the reasonably compensatory nature of rates:
(i) Statement of ton-mile and per barrel-mile earnings under the
competitive rates. When a general adjustment is involved covering rates
between numerous competitive points and applicable or to be applied by
numerous routes, it will be sufficient, ordinarily, to give
representative examples of rates throughout the territory yielding the
lowest earnings for the longest and shortest hauls involved.
(ii) Statement of ton-mile and barrel-mile expenses of petitioning
carriers on the traffic involved, or other evidence showing that the
proposed rates will be reasonably compensatory.
(3) A statement of rates at representative intermediate points at
which rates exceed or would exceed the rates at more distant points
under the proposed adjustment, including rates at the first and last
higher-rated intermediate points and the distances from and to such
intermediate points. This information need not be shown where the rates
at the more distant points are constructed on the basis of a mileage
scale and the rates at the intermediate points reflect the same mileage
scale.
(4) That the higher rates for the shorter than for the longer hauls
over the same line or route are reasonable. (The usual facts tending to
show the reasonableness of rates should be presented).
(5) Whether there is a complaint pending as to the reasonableness of
the rates at the intermediate points on the applicant line or route.
(6) In the event the rates proposed to be superseded by subsequent
revisions are maintained under the authority of outstanding
fourth-section orders, reference to such orders shall be furnished.
(7) Where the proposed adjustment is in any way related to a prior
adjustment as to which relief has been authorized, that is, the addition
of origins, destinations, commodities, etc., or involves rates for the
return movement of commodities as to which relief for initial hauls has
been authorized, reference to orders authorizing such relief shall be
furnished.
(b) Aggregate-of-intermediates relief. Applications should show:
(1) The origins and destinations from and to which it is proposed to
continue, or to establish and maintain through rates or charges which
exceed the aggregate-of-intermediate rates or charges, together with the
intermediate rates or charges that, in the aggregate, are less than the
through rates or charges.
(2) That the intermediate rates or charges which, in the aggregate,
are lower than the through rates or charges, are depressed by
competitive conditions that do not affect the through rates, or charges;
and the same information with respect to the conditions alleged as
affecting the intermediate rates as that required in applications for
long-and-short-haul relief with respect to similar conditions when
alleged as grounds for maintaining lower rates for longer than for
shorter distances.
(3) That the through rates or charges that would exceed the
aggregate-of-intermediate rates or charges are reasonable. (The usual
facts tending to show the reasonableness of rates should be presented).
18 CFR 342.81 Additional matters to be shown.
(a) Applications based on water competitions. (1) The name of the
competing water line or lines actually in operation between the water
points and whether said water line or lines, in the transportation of
the traffic involved, are subject to the Interstate Commerce Act.
(2) A detailed statement of the charges over the water line or lines,
including marine insurance, wharfage, handling, shrinkage, and all other
applicable incidental charges. Where such charges are named in tariffs
on file with the Interstate Commerce Commission, reference should be
made to such tariffs by ICC number.
(3) Whether facilities for loading into and unloading from barges or
ships are available.
(4) The minimum tender that may be made to the water carrier or
carriers, and whether shippers and receivers are equipped to handle such
amounts.
(5) If the season of navigation is restricted, and, if so, that
available storage will permit the handling by water of receivers' needs
during the season of navigation.
(6) The cost of installation, maintenance, etc., of loading,
unloading, and storage facilities which must be constructed or installed
before water transportation is feasible.
(7) Evidence supporting water costs and accessorial charges which are
not published in tariffs on file with the Interstate Commerce
Commission.
(8) Certification that a copy of the application has been served upon
the competing water line or lines named in paragraph (a)(1) hereof. The
service and certification shall conform with the requirements of
385.203 of this chapter.
(b) Applications based on motor carrier competition. The charges
over the competing motor line or lines, including all incidental
charges, and if interstate common contract carrier or carriers,
reference to the applicable tariffs by ICC numbers.
(c) Applications based on market competition. (1) The names of the
producing or receiving points whose competition is to be met.
(2) The short line or route and distances, or the class rate
distances if the latter are normally used for rate making purposes, from
the various producing points to the common market and tariff authority
for the distances.
(3) The rates from the competitive producing points with reference by
ICC No. to the tariffs naming the rates and whether they conform to the
provisions of section 4 of the act. If relief has been granted or
application is pending as to such rates, give reference to the ICC No.
of the application or order.
(4) Whether similar competition is to be met at intermediate points.
(d) Applications based on weak financial condition or high operating
costs of the applicant line. Financial statistics and operating
conditions.
18 CFR 342.82 Miscellaneous provisions.
(a) In addition to the above, applications should show any other
conditions or circumstances relied upon as constituting a special case
within the meaning of section 4(1) of the Act.
(b) Applications should contain a map, made a part thereof, showing
the relative location of lines or routes, the competitive points, and
representative intermediate points at which higher rates are to be
charged, or representative points from or to which it is proposed to
maintain through rates or charges which exceed the aggregate of
intermediates.
18 CFR 342.83 Acceptance of applications.
In any case when, upon inspection, the Commission is of the opinion
that an application does not sufficiently set forth required material or
is otherwise deficient, the Commission may decline to accept the
application for filing and may return it unfiled, or the Commission may
accept it for filing and advise the person tendering it of the
deficiencies and require that such deficiencies be corrected.
18 CFR 342.84 Applications for relief previously denied.
If the Commission denies an application, and the carrier presents a
new application based upon new or additional facts in justification of
the proposed rates or charges, such facts should be clearly indicated as
such, and the modified application must refer specifically to the
previous application and the number of the order by which it was denied.
18 CFR 342.85 Changes and additions.
Copies of any amendment to the application, or any additional
information furnished to the Commission in connection therewith,
including notices of any changes in the effective date of the rates or
charges as set forth in compliance with 342.79(g), shall be served by
applicant upon all parties served with a copy of the application and
upon all parties protesting the application. The service and
certification thereof shall conform with the requirements of 385.203 of
this chapter.
18 CFR 342.85 PART 343 -- POSTING TARIFFS OF COMMON CARRIER PIPELINES
Sec.
343.0 Application-posting of tariffs defined.
343.1 Location of complete public files of tariffs.
343.2 Time of posting.
343.3 Tariff files to be accessible to the public.
343.4 Notice required to be posted.
343.5 Check-up on files of tariffs.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (Supp. V 1981); Interstate Commerce Act, 49 U.S.C. 1-27
(1976); E.O. 12009, 3 CFR Part 142 (1978).
Source: 49 FR 12910, Mar. 30, 1984, unless otherwise noted.
18 CFR 342.85 Tariffs of Common Carriers by Pipeline and Tariffs Containing Joint Intermodal Pipeline Rates
18 CFR 343.0 Application-posting of tariffs defined.
(a) The regulations in this part shall also govern the posting (by
carriers subject to the jurisdiction of the Federal Energy Regulatory
Commission) of any tariff containing a through route and joint rate over
the lines of a common carrier by pipeline subject to the Interstate
Commerce Act, on the one hand, and a vessel-operating common carrier by
water engaged in the foreign commerce of the United States, as defined
in the Shipping Act, 1916, on the other hand, and all other tariffs
governing the application of the rate tariff, for the transportation of
property between any place in the United States and any place in a
foreign country. The carrier subject to the jurisdiction of this
Commission receiving shipments at a port for delivery to points in the
United States under joint through rate and route arrangements shall post
at its office at such port the tariffs naming such rates and its
governing tariffs.
(b) The term ''post'' as used in this part means the maintenance of a
file of tariffs in the custody of an agent of the carrier in a complete,
accessible, and usable form, and keeping such file of tariffs available
to the public upon request during ordinary business hours. The term
''tariff'' as used in this part includes tariff supplements or
amendments.
18 CFR 343.1 Location of complete public files of tariffs.
Each common carrier by pipeline shall post at its principal office a
complete set of all tariffs which it issued or to which it is a party,
together with an index thereto.
18 CFR 343.2 Time of posting.
Each tariff must be posted at least 30 days before its effective
date, excepting those as to which the Commission has authorized a
shorter period of notice to the public. Each carrier shall require the
agent at every office at which tariffs are posted to write or stamp on
each tariff the date on which it was posted.
18 CFR 343.3 Tariff files to be accessible to the public.
Each file of tariffs shall be in charge of an agent of the carrier.
Each carrier shall require and instruct such agent to afford inquirers
an opportunity to examine any of such tariffs without asking the
inquirer to assign any reason therefor, and, upon request, to lend
assistance to seekers of information therefrom with all promptness
possible and consistent with proper performance of other duties.
18 CFR 343.4 Notice required to be posted.
Each carrier shall also cause to be displayed continuously in a
conspicuous public place at each office at which tariffs are required to
be posted, a notice printed in large type reading as follows:
With only such exceptions as have been authorized by the Federal
Energy Regulatory Commission, all tariffs which contain rates and
charges applying from or at this location are on file, in this office,
together with an index of all of this company's tariffs. The tariffs
and index may be inspected by any person upon application and without
the assignment of any reason for such inspection. The agent on duty in
this office will lend any assistance desired in securing information
therefrom.
If request is made for a tariff naming rates from this location, the
posting of which has been discountinued because of nonuse, the agent
will arrange to have it reposted within 20 days and thereafter keep it
posted.
In addition a complete file of all of this company's tariffs, with
indexes thereof, is maintained and kept available for public inspection
at:
(Here indicate the place or places where complete tariff files are
maintained, including the street address and, where appropriate, the
room number.)
18 CFR 343.5 Check-up on files of tariffs.
Each carrier shall place in effect a system of supervision that will
insure the continued maintenance in proper and readily accessible form
of tariff files required at each office where complete files are
maintained. Such offices must be furnished at least once a year with a
list of all of the tariffs which should be in their files. Upon receipt
of the list the agent or employee in charge will immediately check the
tariffs on hand against the list, and report any deficiencies. Evidence
of improper maintenance of files at any office may incur the
prescription of detailed instructions to the carrier by the Commission
necessary to insure compliance with the regulations.
18 CFR 343.5 PART 344 -- FILING QUOTATIONS FOR GOVERNMENT SHIPMENTS AT
REDUCED RATES
Sec.
344.1 Applicability.
344.2 Manner of submitting quotations.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (Supp. V 1981); Interstate Commerce Act, 49 U.S.C. 1-27
(1976); E.O. 12009, 3 CFR Part 142 (1978).
18 CFR 344.1 Applicability.
The provisions of this part shall apply to copies of quotations or
tenders made by all pipeline common carriers to the United States
Government, or any agency or department thereof, for the transportation,
storage or handling of property at reduced rates as permitted by section
22 of the Interstate Commerce Act, as amended, except quotations or
tenders which, as indicated by the United States Government or any
department or agency thereof to any carrier or carriers, involves
information the disclosure of which would endanger the national
security.
(49 FR 12910, Mar. 30, 1984)
18 CFR 344.2 Manner of submitting quotations.
(a) General. Copies of all quotations or tenders by common carriers
to which this part applies, concerning rates or charges for the
transportation, storage, or handling of property, at reduced rates,
including quotations or tenders for retroactive application whether
negotiated or renegotiated after the services have been performed, which
are submitted to the Federal Energy Regulatory Commission on and after
the effective date of this part in conformity with the provisions of
paragraph (2) of section 22 of the Interstate Commerce Act (49 U.S.C.
22) shall conform to the provisions of paragraphs (b), (c), (d), (e),
(f) and (g) of this section.
(b) Copies to be submitted concurrently with submittal to government
agencies. Exact copies of the quotation or tender shall be submitted to
the Commission concurrently with the submittal of the quotation or
tender to the Federal department or agency for whose account the
quotation or tender is offered or the proposed services are to be
rendered.
(c) Filing in duplicate required. All quotations or tenders shall be
filed in duplicate, one copy of which will be maintained at the
Washington office of this Commission for public inspection. One of such
copies shall be signed and both shall clearly indicate the name and
official title of the officer executing the document.
(d) Filing procedure. Both copies of the quotations or tenders shall
be filed together with a letter of transmittal which clearly indicates
that they are being filed in accordance with the requirements of section
22, as amended. They must be addressed to the ''Federal Energy
Regulatory Commission, Washington, D.C. 20426,'' with the envelope
marked as containing ''Section 22 Quotations'', and delivered free of
all charges. If receipt for the accompanying documents is desired, the
letter of tramsmittal must be sent in duplicate, and one copy showing
date of receipt by the Commission will be returned to the sender.
(e) Numbering. The copies of quotations or tenders which are filed
with this Commission by each carrier or agent shall be numbered
consecutively in a series maintained by such carrier or agent beginning
with the number ''1''.
(f) Quotation or tender superseding prior one. A quotation or tender
which supersedes a prior quotation or tender shall, by a statement shown
immediately under the number of the new document, cancel the prior
document by number.
(g) Amendments or supplements to quotations or tenders. When
amendments or supplements are filed to quotations or tenders issued
prior to August 31, 1957, copies of the original quotations or tenders,
and any prior amendments thereto, must be filed with the amendments or
supplements.
(49 FR 12910, Mar. 30, 1984)
18 CFR 344.2 PART 345 -- SECTION 5a APPLICATIONS
Sec.
345.1 Form and contents of application.
345.2 Required exhibits.
345.3 Procedure.
345.4 New parties to an agreement.
345.5 Public notice.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (Supp. V 1981); Interstate Commerce Act, 49 U.S.C. 1-27
(1976); E.O. 12009, 3 CFR Part 142 (1978).
Source: 49 FR 12911, Mar. 30, 1984, unless otherwise noted.
18 CFR 344.2 Applications for Authority to Establish or Control Agreements Between or Among Carriers
18 CFR 345.1 Form and contents of application.
The application and supporting exhibits shall conform to Rule 203 of
the general rules of practice ( 385.203 of this chapter) and shall show,
in the order indicated, with the following paragraph designations, the
following information:
(a) Full and correct name and business address (street and number,
city and ZIP Code, county and State) of the carrier applicant or
applicants (hereinafter called applicant); whether applicant is a
corporation, individual, or partnership; if a corporation, the
government, State or territory under the laws of which the applicant was
organized and received its present charter, and if a partnership, the
names of the partners and the date of formation of the partnership.
(b) Full and correct name and business address (city and State) of
each carrier on whose behalf the application is filed and whether it is
a corporation, individual, or partnership.
(c) If the agreement of which approval is sought pertains to a
conference, bureau, committee, or other organization, a complete
description of such organization, including any subunits, and of its or
their functions and methods of operation, together with a description of
the territorial scope of such operations; and, if such organization has
a working or other arrangement or relationship with any other
organization, a complete description of such arrangement or
relationship. If the agreement is of any other character, a precise
statement of its nature and scope and the mode of procedure thereunder.
(d) The facts and circumstances relied upon to establish that the
agreement will be in furtherance of the national transportation policy
declared in the Interstate Commerce Act, as amended.
(e) The name, title, and post office address of counsel, officer, or
other person to whom correspondence in regard to the application is to
be addressed.
18 CFR 345.2 Required exhibits.
There shall be filed with and made a part of each orginal
application, and each copy, the following exhibits:
(a) As Exhibit 1, a true copy of the agreement.
(b) As Exhibit 2, if the agreement pertains to a conference, bureau,
committee, or other organization, a copy of the constitution, by-laws,
or other documents or writings, specifying the organization's powers,
duties, and procedures, unless incorporated in the agreement filed as
Exhibit 1.
(c) As Exhibit 3, if the agreement relates to a conference, bureau,
committee, or other organization, an organization chart.
(d) As Exhibit 4, if the agreement relates to a conference, bureau,
committee, or other organization, a schedule of its charges to members
or, where expenses are divided among the members, a statement, showing
how the expenses are divided.
(e) As Exhibit 5, opinion of counsel for applicant that the
application made meets the requirements of law as set forth in section
5a of the Interstate Commerce Act, as amended, and will be legally
authorized if approved by the Commission, with specific reference to any
specially pertinent provisions of articles of incorporation or
association.
18 CFR 345.3 Procedure.
The following procedure shall govern the execution, filing, and
disposition of the applications:
(a) The orginal application shall be made under oath and shall be
signed in ink by applicant, if an individual; by all partners, if a
partnership; and if a corporation, by an executive officer having
knowledge of the matters therein contained; and shall show, among other
things, that the affiant is duly authorized to verify and file the
application.
(b) The original application and supporting papers and twenty copies
thereof for the use of the Commission shall be filed with the Secretary
of the Federal Energy Regulatory Commission, Washington, D.C. 20426.
Each copy shall bear the dates and signatures that appear in the
original and shall be complete in itself, but the signatures in the
copies may be stamped or typed, and the officer's seal may be omitted.
(c) A copy of the application shall be served by applicant by
first-class mail upon the regulatory body having jurisdiction as to
rates, fares, or charges of each State, territory, or district embraced
within the scope of the agreement, and the original application filed
with the Commission shall include a certificate naming the bodies upon
whom the application has been so served.
(d) A public notice will be issued by the Commission and filed with
the Director of the Federal Register stating the fact that an
application has been filed under these rules and indicate how a hearing
on such application may be obtained.
(e) A protest against the granting of an application should be filed
in accordance with Rule 1403 of the general rules of practice ( 385.1403
of this chapter).
(f) To the extent that matters of procedure are not covered by these
special rules, the Commission's general rules of practice shall apply.
18 CFR 345.4 New parties to an agreement.
Where a carrier becomes a party to an agreement which has been
approved by the Commission, such approval will extend and be applicable
to such carrier upon the filing with the Commission by the carrier or
its authorized agent of a verified statement that it has become a party
to the agreement, which statement shall show the information required by
345.1(b): Provided (a) That such carrier is not, under the agreement,
to act with carriers of a different class, within the meaning of section
5a(4) of the Interstate Commerce Act, except as the agreement relates to
transportation under joint rates or over through routes, and (b) that no
change is made in the agreement except the addition of such carrier.
18 CFR 345.5 Public notice.
When independent action is announced and tariff publication is to be
made by a publishing agent operating pursuant to an agreement under
section 5a of the Interstate Commerce Act, notification thereof will be
given by the agent to the same extent and in the same manner that the
agent gives notice of actions proposed under procedures for collective
consideration of the parties to the agreement; and no other joint or
collective procedures under the agreement are thereby invoked.
18 CFR 345.5 PART 347 -- COMPETITIVE BIDS OIL PIPELINE
Sec.
347.1 Specifications, form of proposal and contract; publication of
request for bids; variation from the generally applicable procedure.
347.2 Opening of bids; bonds; form and contents of bids.
347.3 Considerations for acceptance of bids; rejection;
readvertising for new bids.
347.4 Statement of the transaction.
347.5 Examination.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (Supp. V 1981); Interstate Commerce Act, 49 U.S.C. 1-27
(1976) E.O. 12009, 3 CFR Part 142 (1978).
Source: 49 FR 12912, Mar. 30, 1984, unless otherwise noted.
18 CFR 347.1 Specifications, form of proposal and contract;
publication of request for bids; variation from the generally
applicable procedure.
(a) When any pipeline, subject to the Interstate Commerce Act, is
required by section 10 of the Clayton Antitrust Act (38 Stat. 734; 15
U.S.C. 20) to call for bids for securities, supplies, or other articles
of commerce, or for the construction or maintenance of any kind or part
of its carrier property such carrier shall prepare specifications, form
of proposals and contract, setting forth clearly and so far as
applicable in each case in detail a description or descriptions of the
matters and things for which bids are requested, the terms, times and
conditions of delivery and payment, the place or places where delivery
or performance is to be made, the character, amount, and terms of
securities offered or sought, and a full description of the supplies or
other ariticles required or offered for sale, hypothecation, or
purchase, and shall make and attach to such specifications such maps,
drawings, and illustrations and state such other substantial facts or
conditions as are or may be necessary to a full understanding of the
premises and procedure by bidders. Such specifications, drawings and
illustrations in each case shall be kept open at the principal office or
offices of the carrier for full examination, free of charges, by persons
desiring to examine the same with a view to bidding, and, upon request,
such carrier shall furnish to any person or persons desiring the same
true and accurate copies of such specifications, maps, drawings and
illustrations; Provided, That the pipeline may make a charge for such
copies so furnished, the charge not to exceed the reasonable cost of
making and forwarding the copies requested.
(b) The pipeline shall publish in each case a request for bids in at
least two daily newspapers of general circulation, at least two
publications in each week for two weeks, the first publication to be at
least two weeks immediately preceding the day when the bids are to be
submitted; one such newspaper shall be published or shall be of general
circulation in the city or town where the principal operating officer of
the carrier is located and the other newspaper shall be published in one
other of the following cities nearest to the operating or financial
office of the carrier or the place where the contract is to be
performed; namely: New York, N.Y., Boston, Mass., Chicago, Ill., St.
Louis, Mo., Atlanta, Ga., San Francisco, Calif., and Portland, Oreg.;
and a printed copy of the published notice in each case shall be posted
in plain view, for two weeks immediately preceding the day on which bids
are to be received, on a bulletin board, designated for that purpose, in
a public and conspicuous place in the building where the principal
operating office of the carrier is located.
(1) Such published notices shall describe in general but intelligible
terms the proposed contract, giving its serial number, and the special
matter or things for which bids are requested, and the date and time at
or before which the bids must be submitted, and the person by whom and
the office at which the bids submitted will be recieved and opened as
provided in this part. The carrier may in said notice reserve the right
to reject, any and all bids and may, at its option, require each bidder
to tender a bond in a reasonable sum to be therein named, with
sufficient surety or sureties conditioned upon the faithful and prompt
performance of the terms of the contract.
(c) Upon application, a pipeline owned or operated by any state or by
an agency of one or more states or a wholly-owned subsidiary corporation
thereof, may be authorized by the Commission to employ a competitive
bidding procedure or precedures varying from the generally applicable
procedure provided by this regulation upon the following showing: (1)
That the applicant carrier is owned or operated by a state or by an
agency of one or more states, or is a wholly-owned subsidiary
corporation thereof: (2) a detailed statement of the procedure for
which authorization is requested and the variations thereof from the
generally applicable procedure provided by this regulation and the
purpose or reason for such variation; and (3) that the generally
applicable procedure provided by this regulation imposes on the carrier
an unreasonable burden or interferes with obtaining by the carrier of
the most favorable bid.
18 CFR 347.2 Opening of bids; bonds; form and contents of bids.
(a) Every bid to receive consideration shall be submitted at the
place and at or before the hour specified in the notice for the receipt
of bids. The time specified may be any hour from 10:00 a.m. until 3:00
p.m of any business day, and the bids shall be opened after the
specified hour and before six o'clock on the day and at place and by the
person or persons designated in the notice. Each bidder may attend in
person or by a duly authorized representative at the opening of the
bids, and shall be afforded an opportunity to do so and to examine each
bid. The bids shall forthwith be tabulated in conformity with the form
of proposal prepared and a copy of such tabulation shall be promptly
furnished to any bidder or his authorized representative upon
application therefor.
(b) When required by the notice, each bid shall be accompanied by
tender of a bond in the amount specified in the notice with sufficient
surety or sureties conditioned upon the faithful and prompt performance
of the proposed contract. A bond shall be required only in cases where
the notice for bids expressly calls for a bond.
(c) Each bid shall be enclosed with accompanying papers in a plain
envelope securely sealed bearing no indication of the name of the bidder
or the amount of the bid, and shall be marked ''Bid under proposed
contract No. ------ ,'' and shall be addressed to the officer of the
carrier designated in the notice to receive the name.
(d) Each bid shall state the name and address of the bidder and, if
the bidder be a corporation, the names and addresses of the officers,
directors and general manager thereof and of the purchasing or selling
officer or agent in that transaction and, if the bidder is a firm,
partnership or association, the bid shall give the names and addresses
of each member thereof, and of the manager, purchasing or selling
officer or agent in that transaction.
18 CFR 347.3 Considerations for acceptance of bids; rejection;
readvertising for new bids.
(a) After receiving and opening bids as aforesaid, the carrier
receiving the same shall within 48 hours in cases where the sale or
purchase of securities is the undertaking, and within 21 days where bids
are for supplies, equipment, other articles of commerce and for
construction or maintenance work, accept the most favorable bid
considering (1) the lowest price or prices for the supplies, equipment,
and other articles of commerce, and for the construction or maintenance
work, described in the advertisement, and the highest price or prices
offered for any securities or property, so described, for sale by the
carrier, and (2) the ability and reliability of the bidder, financial
and otherwise, to deliver the property or to perform the work or
transaction, or to pay for the securities, described in the
advertisement, giving due consideration to any bond or security tendered
by the bidder.
(b) If the right be reserved in the notice, all bids may be rejected
and the pipeline may readvertise for bids. The pipeline shall notify
the successful bidder of the acceptance of his or its bid, and the
bidder shall within 10 days execute the required contract, and, if
required by the notice, execute a good and sufficient bond for the
faithful and prompt performance of the contract. In case the successful
bidder shall neglect or fail within said time to execute the contract or
bond as aforesaid the carrier may within 5 days award the contract to
the next most favorable bidder, ascertained as herein provided for
determining the most favorable bidder. If neither the most favorable
bidder nor the next most favorable bidder shall execute a contract and
qualify as aforesaid, the carrier shall readvertise for new bids.
18 CFR 347.4 Statement of the transaction.
Each pipeline after having made and executed a contract as and in the
manner above specified shall within 30 days after the execution of such
contract file with the Federal Energy Regulatory Commission a statement
of the transaction giving, (a) a copy of the published notice; (b) the
names of all bidders, and, if the bidder be a corporation, the names and
addresses of the officers, directors and general managers thereof and of
the purchasing or selling officer or agent in that transaction, or if
the bidder be a partnership or firm, the names and addresses of the
members of the firm, the general manager and purchasing or selling agent
thereof, and the total amount of each bid; (c) the name of the bidder
to whom the contract was awarded together with a copy of the contract;
and (d) if any other than the lowest or the highest bid, as the case may
be, is accepted as being most favorable to the carrier, the reasons for
such acceptance. The statement shall be made in typewriting, in
pamphlet form on pages not less than 8 by 10 1/2 inches in size nor
greater than 9 1/2 by 12 inches, in size, bound on the longer edge of
the page, the paper to be of durable quality fit for permanent record.
18 CFR 347.5 Examination.
In the case of each bid so taken as aforesaid, the pipeline shall
preserve and keep open for examination by the Federal Energy Regulatory
Commission or any duly authorized examiner thereof, (a) a copy of the
resolution or order of the Board of Directors, Executive Committee, or
officers of the said common carrier specifying the purposes and terms of
the contract for which the bids were invited; (b) a copy of the
specifications, maps, drawings, and illustrations upon which bids were
made; (c) copies of the notices published, sworn to by or on behalf of
the publisher of each paper, respectively, giving the dates and times of
publication; (d) the original bids received, designating the bid
accepted and giving a statement of the reasons for accepting the same;
(e) a copy of the contract entered into between the carrier and the
accepted bidder, together with a copy of the bonds if any; (f)
references by number of volume and page to the records of proceedings of
the stockholders, directors, or executive committee of the pipeline.
The files in each transaction shall be securely fastened together and
given the contract number and each document therein shall be numbered
consecutively and at the conclusion there shall be a sworn statement by
the president, a vice president, or the general manager of the pipeline,
stating that the files in No. ------ contain true and complete records
and statements of all the negotiations had in connection with the
contract therein set forth. Carriers subject to the requirements of
section 10 of the Clayton Antitrust Act, 15 U.S.C. 20, may destroy such
contracts or other records required thereby 10 years after the
expiration thereof, without permission of the Commission: Provided,
There is no litigation pending involving these records: And further
provided, That the carrier has informed the Commission of its intended
action at least 2 weeks prior to the date the records are to be
destroyed.
18 CFR 347.5 SUBCHAPTER Q -- ACCOUNTS UNDER THE INTERSTATE COMMERCE ACT
18 CFR 347.5 PART 351 -- FINANCIAL STATEMENTS RELEASED BY CARRIERS
Authority: Department of Energy Organization Act, (42 U.S.C. 7101 et
seq.) E.O. 12009, 42 FR 46267, Interstate Commerce Act, as amended, (49
U.S.C. 1 et seq).
18 CFR 351.1 Financial statements released by carriers.
Carriers desiring to do so may prepare and publish financial
statements in reports to stockholders and others, except in reports to
this Commission, based on generally accepted accounting principles for
which there is authoritative support, provided that any variance from
this Commission's prescribed accounting rules contained in such
statements is clearly disclosed in footnotes to the statements.
(Order 119, 46 FR 9044, Jan. 28, 1981)
18 CFR 351.1 Pt. 352
18 CFR 351.1 PART 352 -- UNIFORM SYSTEMS OF ACCOUNTS PRESCRIBED FOR OIL
PIPELINE COMPANIES SUBJECT TO THE PROVISIONS OF THE INTERSTATE COMMERCE
ACT
Definitions.
General Instructions
1-1 Classification of accounts.
1-2 Records.
1-3 Accounting period.
1-4 Accounting method.
1-5 Delayed items.
1-6 Extraordinary, unusual or infrequent items, prior period
adjustments, discontinued operations and accounting changes.
1-7 Items in texts of accounts.
1-8 Depreciation accounting -- Carrier property.
1-9 Depreciation accounting -- Noncarrier property.
1-10 Amortization of intangibles.
1-11 Interpretation of rules.
1-12 Accounting for income taxes.
1-13 Transactions with affiliated companies.
1-14 Charges to be just and reasonable.
1-15 Accounting for marketable equity securities owned.
1-16 Accounting for inaccurate reporting of income taxes on income
from continuing operations which occurred prior to reporting year 1979.
Instructions for Balance Sheet Accounts
2-1 Current assets.
2-2 Investments and special funds.
2-3 Tangible property.
2-4 Other assets and deferred charges.
2-5 Current liabilities.
2-6 Noncurrent liabilities.
2-7 Contingent assets and liabilities.
Instructions for Carrier Property Accounts
3-1 Property acquired.
3-2 Minimum rule.
3-3 Cost of property constructed.
3-4 Additions.
3-5 Improvements.
3-6 Replacements.
3-7 Retirements.
3-8 Salvage.
3-9 Relocation of line.
3-10 Property contributed.
3-11 Acquisition by merger, consolidation or purchase.
3-12 Reorganizations.
3-13 Disposition of former Account 193, Acquisition Adjustment.
3-14 Accounting units of property.
Instructions for Operating Revenues and Operating Expenses
4-1 Detail of accounts.
4-2 Operating revenues.
4-3 Operating expenses.
4-4 Expense classification.
4-5 Expense distribution.
Balance Sheet Accounts
10 Cash.
10-5 Special deposits.
11 Temporary investments.
12 Notes receivable.
13 Receivables from affiliated companies.
14 Accounts receivable.
15 Interest and dividends receivable.
16 Oil inventory.
17 Material and supplies.
18 Prepayments.
19 Other current assets.
19-5 Deferred income tax charges.
20 Investments in affiliated companies.
21 Other investments.
22 Sinking and other funds.
23 Reductions in security values -- Credit.
24 Allowance for net unrealized loss on noncurrent marketable equity
securities -- Credit.
30 Carrier property.
31 Accrued depreciation -- Carrier property.
32 Accrued amortization -- Carrier property.
33 Operating oil supply.
34 Noncarrier property.
35 Accrued depreciation -- Noncarrier property.
40 Organization costs and other intangibles.
41 Accrued amortization of intangibles.
43 Miscellaneous other assets.
44 Other deferred charges.
45 Accumulated deferred income tax charges.
50 Notes payable.
51 Payables to affiliated companies.
52 Accounts payable.
53 Salaries and wages payable.
54 Interest payable.
55 Dividends payable.
56 Taxes payable.
57 Long-term debt payable within one year.
58 Other current liabilities.
59 Deferred income tax credits.
60 Long-term debt payable after one year.
61 Unamortized premium on long-term debt.
62 Unamortized discount and interest on long-term debt.
63 Other noncurrent liabilities.
64 Accumulated deferred income tax credits.
70 Capital stock.
71 Premiums on capital stock.
72 Capital stock subscriptions.
73 Additional paid-in capital.
74 Appropriated retained income.
75 Unappropriated retained income.
75.5 Net unrealized loss on noncurrent marketable equity securities.
76 Treasury stock.
Carrier Property Accounts
101, 151, 171 Land.
102, 152 Right of way.
103, 153 Line pipe.
104, 154 Line pipe fittings.
105, 155 Pipeline construction.
106, 156, 176 Buildings.
107, 157 Boilers.
108, 158 Pumping equipment.
109, 159, 179 Machine tools and machinery.
110, 160 Other station equipment.
111, 161 Oil tanks.
112, 162 Delivery facilities.
113, 163, 183 Communication systems.
114, 164, 184 Office furniture and equipment.
115, 165, 185 Vehicles and other work equipment.
116, 166, 186 Other property.
187 Construction work in progress.
Operating Revenues
200 Gathering revenues.
210 Trunk revenues.
220 Delivery revenues.
230 Allowance oil revenue.
240 Storage and demurrage revenue.
250 Rental revenue.
260 Incidental revenue.
Operating Expenses
18 CFR 351.1 Operations
300 Salaries and wages.
310 Supplies and expenses.
320 Outside services.
330 Operating fuel and power.
340 Oil losses and shortages.
18 CFR 351.1 Maintenance
400 Salaries and wages.
410 Supplies and expenses.
420 Outside services.
430 Maintenance materials.
18 CFR 351.1 General
500 Salaries and wages.
510 Supplies and expenses.
520 Outside services.
530 Rentals.
540 Depreciation and amortization.
550 Pensions and benefits.
560 Insurance.
570 Casualty and other losses.
580 Pipeline taxes.
Income Accounts
18 CFR 351.1 Ordinary Items
600 Operating revenues.
620 Income (net) from noncarrier property.
630 Interest and dividend income.
640 Miscellaneous income.
645 Unusual or infrequent items (credit).
610 Operating expenses.
650 Interest expense.
660 Miscellaneous income charges.
665 Unusual or infrequent items (debit).
670 Income taxes on income from continuing operations.
671 Provision for deferred taxes.
675 Income (loss) from operations of discontinued segments.
676 Gain (loss) on disposal of discontinued segments.
680 Extraordinary items (net).
695 Income taxes on extraordinary items.
696 Provision for deferred taxes -- extraordinary items.
697 Cumulative effect on changes in accounting principles.
Retained Income Accounts
700 Net balance transferred from income.
705 Prior period adjustments to beginning retained income account.
710 Other credits to retained income.
720 Other debits to retained income.
740 Appropriations of retained income.
750 Dividend appropriations of retained income.
797 Form of balance sheet statement.
798 Form of income statement.
799 Form of unappropriated retained income statement.
Authority: Sec. 12, 20, 24 Stat. 383, as amended, 49 U.S.C. 12, 20.
Source: 32 FR 20241, Dec. 20, 1967, unless otherwise noted.
Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981.
18 CFR 351.1 List of Instructions and Accounts
Definitions. Definitions of terms used in this system of accounts:
1. Accounts means the accounts prescribed in this system of accounts.
2. Actually issued, as applied to securities issued or assumed by the
carrier, means those which have been sold to bona fide purchasers or
holders for a valuable consideration, those issued in exchange for other
securities or other property, and those issued as dividends on stock;
and the purchasers or holders secured them free from control by the
carrier.
3. Actually outstanding, as applied to securities issued or assumed
by the carrier, means those which have been actually issued and are
neither retired nor held by or for the carrier.
4. Additions means facilities, equipment, and structures added to
existing property exclusive of replacements.
5. Affiliated companies means companies or persons that directly, or
indirectly through one or more intermediairies, control, or are
controlled by, or are under common control with, the accounting carrier.
6. Amortization means the gradual extinguishment of an amount in an
account by distributing such amount over a fixed period, over the life
of the asset or liability to which it applies, or over the period during
which it is anticipated the benefit will be realized.
7. Book cost means the amount at which assets are recorded in the
accounts without deduction of related provisions for accrued
depreciation, amortization, or for other purposes.
8. Carrier means a common carrier by pipeline subject to the
Interstate Commerce Act.
9. Commission means the Federal Energy Regulatory Commission.
10. Control (including the terms controlling, controlled by, and
under common control with) means the possession, directly or indirectly,
of the power to direct or cause the direction of the management and
policies of a company, whether such power is exercised through one or
more intermediary companies, or alone, or in conjunction with, or
pursuant to an agreement, and whether such power is established through
a majority or minority ownership or voting of securities, common
directors, officers or stockholders, voting trusts, holding trusts,
associated companies, contract or any other direct or indirect means.
When there is doubt about an existence of control in any particular
situation, the carrier shall report all pertinent facts to the
Commission for determination.
11. Cost means the amount of money actually paid for property or
services or the current cash value of the consideration given when it is
other than money.
12. Cost of removal means cost of demolishing, dismantling, tearing
down, or otherwise removing property including costs of handling and
transportation.
13. Date of retirement means the date that property is withdrawn from
service.
14. Debt expense means all expense in connection with the issuance
and sale of evidences of debt, such as fees for drafting mortgages and
trusts; fees and taxes for issuing or recording evidences of debt;
cost of engraving and printing bonds, certificates of indebtedness, and
other evidences of debt; fees paid to trustees; specific costs of
obtaining governmental authority; fees for legal services; fees and
commissions paid underwriters, brokers, and salesmen for marketing
evidences of debt; fees and expenses of listing on exchanges; and
other like costs.
15. Depreciation means the loss in service value not restored by
current maintenance and incurred in connection with the consumption or
prospective retirement of property in the course of service from causes
against which the carrier is not protected by insurance, and the effect
of which can be forecast with a reasonable approach to accuracy.
16. Discount, as applied to securities issued or assumed by the
carrier, means the excess of the par or face value of the securities
plus interest or dividends accrued at the date of the sale over the cash
value of the consideration received from their sale.
17. Group plan means the plan under which depreciation charges are
computed on the book cost of all property included in each depreciable
account by application of a composite rate of depreciation based on the
weighted average service lives of such property.
18. Improvements means alterations or changes in structural design of
property which result in increased service life or efficiency.
19. Minor items of property means the associated parts or items of
which units of property are composed.
20. Net salvage value means salvage value of property retired less
the cost of removal.
21. Nominally issued, as applied to securities issued or assumed by
the carrier, means those which have been signed, certified, or otherwise
executed, and placed with the proper officer for sale and delivery, or
pledged, or otherwise placed in some special fund of the accounting
company.
22. Nominally outstanding, as applied to securities issued or assumed
by the carrier, means those which, after being actually issued, have
been reacquired by or for the accounting company under such
circumstances which require them to be considered as held alive and not
retired and canceled.
23. Premium, as applied to securities issued or assumed by the
carrier, means the excess of the cash value of the consideration
received from their sale over the sum of their par (stated value of
no-par stocks) or face value and interest or dividends accrued at the
date of sale.
24. Property retired means units of property which have been removed,
sold, abandoned, destroyed, or which for any cause have been withdrawn
from service; also, minor items of property not replaced.
25. Replacement means the substitution of a part or of a complete
unit of property with a new part or unit.
26. Salvage value means the amount received or estimated to be
received for property retired less any expenses incurred in connection
with the sale or preparing the property for sale; or, if retained, the
value at which the recovered material is chargeable to the material and
supplies account or other appropriate account.
27. Service life means the period between the date that property is
placed in service and the date of its retirement.
28. Service value means the book cost less the actual or estimated
net salvage value of property.
29. Straight-line method, as applied to depreciation and amortization
accounting, means the plan under which the service value of property is
charged to expense and credited to the related accrued depreciation or
amortization account through equal monthly charges during the service
life of the property.
30. (a) Income taxes means taxes based on income determined under
provisions of the United States Internal Revenue Code and foreign, state
and other taxes (including franchise taxes) based on income.
(b) Income tax expense means the amount of income taxes (whether or
not currently payable or refundable) allocable to a period in the
determination of net income.
(c) Pretax accounting income means income or loss for a period,
exclusive of related income tax expense.
(d) Taxable income means the excess of revenues over deductions or
the excess of deductions over revenues to be reported for income tax
purposes for a period.
(e) Timing differences means differences between the periods in which
transactions affect taxable income and the periods in which they enter
into the determination of pretax accounting income. Timing differences
originate in one or more subsequent periods. Some timing differences
reduce income taxes that would otherwise be payable currently; others
increase income taxes that would otherwise be payable currently.
(f) Permanent differences means differences between taxable income
and pretax accounting income arising from transactions that, under
applicable tax laws and regulations, will not be offset by corresponding
differences or ''turn around'' in other periods.
(g) Tax effects means differentials in income taxes of a period
attributable to (1) revenue or expense transactions which enter into the
determination of pretax accounting income in one period and into the
determination of taxable income in another period, (2) deductions or
credits that may be carried backward or forward for income tax purposes
and (3) adjustments of prior periods and direct entries to other
stockholders' equity accounts which enter into the determination of
taxable income in a period but which do not enter into the determination
of pretax accounting income of that period. A permanent difference does
not result in a ''tax effect'' as that term is used in this definition.
(h) Deferred taxes means tax effects which are deferred for
allocation to income tax expense of future periods.
(i) Interperiod tax allocation means the process of apportioning
income taxes among periods.
(j) Tax allocation within a period means the process of apportioning
income tax expense applicable to a given period between income before
extraordinary items and of associating the income tax effects of
adjustments of prior periods and direct entries to other stockholders'
equity accounts with these items.
31. (a) Investor means a business entity that holds an investment in
voting stock of another company.
(b) Investee means a corporation that issued voting stock held by an
investor.
(c) Corporate joint venture is a company owned and operated by a
small group of businesses as a separate and specific business or project
for the mutual benefit of the members of the group.
(d) Dividends, unless otherwise specified, means dividends paid or
payable in cash, other assets, or another class of stock and does not
include stock dividends or stock splits.
(e) Earnings or losses of an investee and financial position of an
investee refer to net income (or net loss) and financial position of an
investee determined in accordance with generally accepted accounting
principles.
(f) Undistributed earnings of an investee means net income less
dividends declared whether received or not.
(g) Date of acquisition is the date on which the investor assumes the
rights of ownership. Ordinarily this is the date assets are received
and other assets are given or securities issued.
32. (a) Segment of a business refers to a component of an entity
whose activities represent a separate major line of business or class of
customer. A segment may be in the form of a subsidiary, a division, or
a department, and in some cases a joint venture or other nonsubsidiary
investee, provided that its assets, results of operations, and
activities can be clearly distinguished, physically and operationally
and for financial reporting purposes, from the other assets, results of
operations, and activities of the entity. The fact that the results of
operations of the segment being sold or abandoned cannot be separately
identified strongly suggests that the transaction should not be
classified as a segment of business.
(b) Measurement date means the date on which the management having
authority to approve the action commits itself to a formal plan to
dispose of a segment of the business, whether by abandonment or sale.
The measurement date for disposals requiring Commission approval shall
be the service date of the Order authorizing the disposal.
(c) Disposal date refers to the date of closing the sale if the
disposal is by sale or the date that operations cease if the disposal is
by abandonment.
33. Compensating balance means the portion of any demand deposit (or
any time deposit or certificate of deposit) maintained by a carrier (or
by any person on behalf of the carrier) which constitutes support for
existing borrowing arrangements of the carrier (or any person) with a
lending institution. Such arrangements include both outstanding
borrowings and the assurance of future credit availability. (The
compensating balance requirement should be adjusted by the amount of
float unless such adjustment would cause the compensating balance to be
greater than the cash balance per carrier's books. The float adjustment
is made by subtracting the float from the compensating balance
requirement if the collected bank ledger balance exceeds the cash
balance per carrier's books or by adding the float to the compensating
balance requirement if the collected bank ledger balance is less than
the cash balance per carrier's books.)
34. Float means deposits and withdrawals in transit which constitute
a difference between the collected bank ledger balance and the cash
balance per carrier's books.
35. (a) Equity security encompasses any instrument representing
ownership shares (e.g., common, preferred, and other capital stock), or
the right to acquire (e.g., warrants, rights, and call options) or
dispose of (e.g., put options) ownership shares in an enterprise at
fixed or determinable prices. The term does not encompass preferred
stock that by its terms either must be redeemed by the issuing
enterprise or is redeemable at the option of the investor, nor does it
include treasury stock or convertible bonds.
(b) Marketable, as applied to an equity security, means an equity
security as to which sales prices or bid and ask prices are currently
available on a national securities exchange (i.e., those registered with
the Securities and Exchange Commission) or in the over-the-counter
market. In the over-the-counter market, an equity security shall be
considered marketable when a quotation is publicly reported by the
National Association of Securities Dealers Automatic Quotations System
or by the National Quotations Bureau, Inc. (Provided, in the later
case, That quotations are available from at least three dealers.) Equity
securities traded in foreign markets shall be considered marketable when
such markets are of a breadth and scope comparable to those referred to
above. This definition is not met by restricted stock (securities for
which sale is restricted by a governmental or contractual requirement
except where such requirement terminates within one year or where the
holder has the power to cause the requirement to be met within one
year). Any portion of the stock which can reasonably be expected to
qualify for sale within one year, such as may be the case under Rule 144
or similar rules of the Securities and Exchange Commission, is not
considered restricted.
(c) Market value refers to the aggregate of the market price of a
single share or unit times the number of shares or units of each
marketable equity security in the portfolio. When an entity has taken
positions involving short sales, sales of calls, and purchases of puts
for marketable equity securities and the same securities are included in
the portfolio, those contracts shall be taken into consideration in the
determination of market value of the marketable equity securities.
(d) Cost, as applied to a marketable equity security, refers to the
original cost unless a new cost basis has been assigned based on
recognition of an impairment of value that was deemed other than
temporary or as the result of a transfer between current and noncurrent
classifications. In such cases, the new cost basis assigned shall be
considered cost.
(32 FR 20241, Dec. 20, 1967, as amended at 37 FR 17713, Aug. 31,
1972; 39 FR 33343, Sept. 17, 1974; 39 FR 34043, Sept. 23, 1974; 40 FR
53247, Nov. 17, 1975; 41 FR 9158, Mar. 3, 1976; 42 FR 33297, June 30,
1977. Redesignated and amended by Order 119, 46 FR 9044, Jan. 28, 1981)
18 CFR 351.1 General Instructions
1-1 Classification of accounts. Accounts are prescribed to record
the cost of property used in transportation and related operations and
for revenues, expenses, taxes, rents, and other items of income for such
operations. Separate accounts are prescribed for cost of property not
used in transportation operations and for income and expenses pertaining
thereto; for other investments and related income; for extraordinary
and prior period items, including applicable income taxes; and for
assets and liabilities.
In addition, stockholders' equity accounts, designed to segregate
directly contributed capital from appropriated and unappropriated
retained income, are provided. Retained income accounts form the
connecting link between the income account and the equity section of the
balance sheet. They are provided to record the transfer of net income
or loss for the year; certain capital transactions; and, when
authorized by the Commission, other items.
1-2 Records. (a) Carriers shall keep their accounts and records in
accordance with the prescribed accounts. In addition, clearing
accounts, temporary accounts, and subdivisions of any account may be
kept provided the integrity of the prescribed accounts is not impaired.
Each carrier shall keep its books of account, and all other books,
records and memoranda which support the entries in such books of
account, so as to be able to furnish readily full information as to any
item included in any account. Each entry shall be supported by such
detailed information as will permit ready identification, analysis, and
verification of all facts relevant thereto.
(b) The books and records referred to herein include not only
accounting records in a limited technical sense, but all records, such
as minute books, stock books, reports, correspondence, memorandums,
etc., which may be useful in developing the history of or facts
regarding any transaction.
(c) No carrier shall destroy any books, records, memoranda, etc.,
which support entries to its accounts unless destruction is permitted by
the regulations governing preservation of records, Part 356 of this
chapter.
(49 U.S.C. 5b, 304, 320, 904, 913, 917, 1003, 1012)
(32 FR 20241, Dec. 20, 1967, as amended at 40 FR 50384, Oct. 29,
1975. Redesignated and amended by Order 119, 46 FR 9044, Jan. 28, 1981)
1-3 Accounting period. (a) Each carrier shall keep its books on a
monthly basis so that all transactions, as nearly as may be ascertained,
shall be entered in the accounts not later than 60 days after the last
day of the period for which the accounts are stated, except that the
time within which the final entries for the year ending December 31
shall be made may be extended to such date in the following March as
shall not interfere with the preparation and filing of the annual
report.
(b) Changes shall not be made in the accounts for periods covered by
reports that have been filed with the Commission unless the changes have
first been authorized by the Commission.
1-4 Accounting method. (a) This system of accounts shall be kept by
the accrual method of accounting. The basis used for accruing income
and expense items each month shall be consistently applied and any
change in such basis or any unusual accruals involving material amounts
shall be promptly reported to the Commission.
(b) When the amount of any transaction cannot be accurately
determined in time for inclusion in the applicable month's accounts, an
estimated amount shall be entered in the proper accounts. Appropriate
adjustments shall be made as soon as the actual amounts become known or
at the time a substantial change is indicated. Carriers are not
required to anticipate minor items which do not appreciably affect the
accounts.
1-5 Delayed items. Ordinary delayed items and adjustments arising
during the current year which are applicable to prior years shall be
included in the same account which would have been charged or credited
if the item had been taken up or the adjustments made in the year to
which it pertained. When the amount of a delayed item or adjustment is
relatively so large that its inclusion in net income for a single month
would seriously distort the accounts for the month (but not for the
year), such amount may be distributed in equal monthly charges or
credits, as the case may be, to the remaining months of the calendar
year. See instruction 1-6 for instructions covering extraordinary and
prior period items of a nonrecurring nature.
1-6 Extraordinary, unusual or infrequent items, prior period
adjustments, discontinued operations and accounting changes. (a)
Extraordinary Items. All items of profit and loss recognized during the
year are includible in ordinary income unless evidence clearly supports
their classification as extraordinary items. Extraordinary items are
characterized by both their unusual nature and infrequent occurrence
taking into account the environment in which the firm operates; they
must also meet the materiality standard.
Unusual means the event or transaction must possess a high degree of
abnormality and be of a type clearly unrelated to, or only incidentally
related to the ordinary and typical activities of the entity.
Infrequent occurrence means the event or transaction shall be of a
type not reasonably expected to recur in the foreseeable future.
(b) Unusual or Infrequent Items. Material events unusual in nature
or infrequent in occurrence but not both, thus not meeting both criteria
for classification as extraordinary, shall be includible in the accounts
provided as separate components of income/expense from continuing
operations. Such items are not to be reported net of income taxes.
(c) Discontinued Operations. The results of continuing operations
shall be reported separately from discontinued operations and any gain
or loss resulting from disposal of a segment of a business (see
definition 32(a)) shall be reported in conjunction with the related
results of discontinued operations and not as an extraordinary item.
The disposal of a segment of a business shall be distinguished from
other disposals of assets incident to the evolution of the entity's
business, such as the disposal of part of a line of business, the
shifting of production or marketing activities for a particular line of
business from one location to another, the phasing out of a product line
or class of service, and other changes occasioned by technological
improvements. If a loss is expected from the proposed sale or
abandonment of a segment, the estimated loss shall be provided for at
the measurement date (see definition 32(b)). If a gain is expected, it
shall be recognized when realized, which ordinarily is the disposal date
(see definition 32(c)).
(d) Prior Period Adjustments. Adjustments occurring in the current
accounting period, relating to events or transactions which occurred in
a prior period the accounting effects of which could not be determined
with reasonable assurance at that time, shall be reported as prior
period adjustments. A prior period adjustment, after income tax effect,
should be reported by restating the beginning balance of retained income
of the current year and correspondingly adjusting related prior year
balances presented for comparative purposes. Such adjustments shall not
be considered prior period unless:
(1) They can be specifically identified with and directly related to
the business activities of particular prior periods, and (2) are not
attributable to economic events occurring subsequent to the date of the
financial statements for the prior period, and (3) depend primarily on
determinations by persons other than management, and (4) were not
susceptible of reasonable estimation prior to such determination, and
(5) they are material. If an adjustment does not meet such criteria, it
shall be separately disclosed as to year of origin, nature, and amount
and classified in the current period in the same manner as the original
item. If the adjustment is the correction of an error, it shall be
reported as a prior period adjustment.
(e) Accounting Changes. A change in accounting principle or
accounting entity should be referred to this Commission for approval.
The cumulative effect of a change in accounting principle should
ordinarily be reflected in the account provided for in determining net
income; in certain cases accounting changes may be reflected as prior
period adjustments. Changes in accounting estimates should ordinarily
be reflected prospectively.
(f) Materiality. As a general standard an item shall be considered
material when it exceeds 10 percent of annual income (loss) before
extraordinary items. An item may also be considered in relation to the
trend of annual earnings before extraordinary items or other appropriate
criteria. Items shall be considered individually and not in the
aggregate in determining materiality. However, the effects of a series
of related transactions arising from a single specific and identifiable
event or plan of action shall be aggregated to determine materiality.
(g) Commission Approval and accountant's letter. Items shall be
included in the accounts provided for extraordinary items, unusual or
infrequent items, discontinued operations, prior period adjustments and
cumulative effect of changes in accounting principles only upon approval
of the Commission. If the carrier retains the service of an independent
accountant, a request for using these accounts shall be accompanied by a
letter from the independent accountant approving or otherwise commenting
on the request.
Note: The carrier may refer to generally accepted accounting
principles for further guidance in applying instruction 1-6.
(40 FR 53248, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
1-7 Items in texts of accounts. Items appearing in instructions and
in the texts of various accounts are merely representative and are not
intended to cover all of the items includible therein.
1-8 Depreciation accounting -- Carrier property.
(a) Method. Monthly depreciation charges shall be made by the
straight-line method to operating expenses in conformity with the group
plan of accounting applicable to all carrier property except property
included in accounts 101, 151, 171, Land, and 187, Construction Work in
Progress.
(b) Rates. (1) Separate composite annual percentage rates will be
prescribed for each depreciable account except that the Commission may
authorize the use of component rates upon specific request from a
carrier. Carriers becoming subject to this system of accounts and
carriers acquiring property for which no rates have been previously
prescribed shall file, within six months, composite annual percentage
rates applicable to the book cost of each class of depreciable carrier
property as will distribute the service value, by the straight-line
method, in equal annual charges to operating expenses during the service
life of the property. These rates shall be used by the carrier until
the rates prescribed by the Commission become effective. Such rates
shall, for each primary account comprised of more than one class of
property, produce a depreciation charge equal to the sum of the amounts
that would otherwise be chargeable for each of the various classes of
property included in the account. Carriers shall base these percentage
rates on estimated service values and service lives developed from
engineering and other studies. The rates filed shall be accompanied by
a statement showing the bases and the methods employed in the rate
determination.
(2) Carriers shall be prepared at any time upon the direction of the
Commission to compute and submit revised percentage rate studies. When
a carrier believes that any rate prescribed by the Commission is no
longer applicable, it shall submit the rate which it believes should be
established supported by full particulars for consideration by the
Commission.
(3) A carrier shall keep records of property and property retirements
that will reflect the service life of property which has been retired,
or will permit the determination of service life indications by
mortality, turnover, or other appropriate methods; and also such
records as will reflect the percentage of net salvage value for property
retired from each class of depreciable carrier property.
(c) Charges. In computing monthly charges, the annual percentage
rates shall be applied to the depreciation base as of the first of each
month and the result divided by twelve.
(d) Retirements. Except as provided in paragraph (e) of this
section, upon the retirement of depreciable property the service value
shall be charged in its entirety to account 31, Accrued Depreciation --
Carrier Property. Any amounts of insurance recovered from casualty
losses involving depreciable property retired shall be credited thereto.
(e) Special accounting authority. (1) When circumstances indicate
that newly acquired property should be subject to amortization, or that
the prescribed depreciation rates based on the service lives of certain
property are no longer applicable, because the source of traffic will be
exhausted before the end of the physical service life, the carrier shall
submit to the Commission for approval amortization or depreciation rates
based on the estimated remaining service life of the property
accompanied by full information justifying the request.
(2) A carrier may request, or the Commission may direct, that special
accounting be applied in situations causing undue inflation or deflation
of depreciation reserves, such as premature or unusual retirements or
sales of depreciable property, or related insurance recoveries. A
carrier's request for special accounting shall contain full particulars
concerning the situation, including the basis for its proposal.
Alternative accounting techniques shall be applied to the extent
approved or directed by the Commission.
1-9 Depreciation accounting -- Noncarrier property. Monthly
depreciation charges for all depreciable property recorded in account
34, Noncarrier Property, shall be made to account 620, Income from
Noncarrier Property, with concurrent credits to account 35, Accrued
Depreciation -- Noncarrier Property. The depreciation charges shall be
such as to distribute the service values equitably over the service life
of the property.
1-10 Amortization of intangibles. Monthly charges shall be made to
account 540, Depreciation and Amortization, to amortize the cost of
fixed life intangibles such as permits, patents and franchises which are
directly related to pipeline operations. Monthly charges shall be made
to account 660, Miscellaneous Income Charges, to amortize the cost of
intangibles such as goodwill which are not directly associated with
pipeline operations. The amortization charges shall be such as to
distribute the cost by the straight-line method in equal annual charges
over the life or expected period of benefit.
1-11 Interpretation of rules. To maintain uniformity of accounting,
carriers shall submit questions of doubtful interpretation to the
Commission for consideration and decision.
1-12 Accounting for income taxes. (a) The interperiod tax allocation
method of accounting shall be applied where material timing differences
(see definition 30(e)) occur between pretax accounting income and
taxable income. Carriers may elect, as provided by the Revenue Act of
1971, to account for the investment tax credit by either the flow
through method or the deferred method of accounting. See paragraphs (d)
and (e) below. All income taxes (Federal, State, and other) currently
accruable for income tax return purposes shall be charged to account
670, Income taxes on income from continuing operations, and account 695,
Income taxes on extraordinary items, as applicable.
(b) Under the interperiod tax allocation method of accounting the tax
effect of timing differences (see definitions 30 (g) and (e))
originating in the current accounting period are allocated to income tax
expense of future periods when the timing differences reverse. Similar
timing differences originating and reversing in the current accounting
period should be combined into groups and the current tax rates applied
to determine the tax effect of each group. A carrier shall not apply
other than current tax rates in determining the tax effect of reversing
differences except upon approval of the Commission. When determining
the amount of deferred taxes, rather than computing State and other
taxes individually by jurisdiction, the Federal income tax rate may be
increased by a percent equivalent to the effect of taxes imposed by the
jurisdictions.
(c) The future tax benefits of loss carryforwards shall normally be
recognized in the year in which such loss is applied to reduce taxes.
Only in those unusual instances when realization is assured beyond any
reasonable doubt should the future tax benefits of loss carryforwards be
recognized in the year of loss. The tax effects of any realizable loss
carrybacks shall be recognized in the determination of net income (loss)
of the loss periods; appropriate adjustments of existing net deferred
tax credits may also be necessary in the loss period.
(d) Carriers electing to account for the investment tax credit by the
flow through method shall credit account 670, Income taxes on income
from continuing operations, or account 695, Income taxes on
extraordinary items, as applicable, and charge to account 56, Taxes
payable, with the amount of investment tax credit utilized in the
current accounting period. When the flow through method is followed for
the investment tax credit, account 671, Provision for deferred taxes,
shall reflect the difference between the tax payable (after recognition
of allowable investment tax credit) based on taxable income and tax
expense (with full recognition of investment tax credit that would be
allowable based on accounting income) based on accounting income.
(e) Carriers electing to account for the investment tax credit by the
deferred method shall concurrently with making the entries prescribed in
(d) above charge account 671, ''Provision for deferred taxes'' or
account 696, ''Provision for deferred taxes -- extraordinary items,'' as
applicable, and shall credit account 64, Accumulated deferred income tax
credits with the investment tax credit utilized as a reduction of the
current year's tax liability but deferred for accounting purposes. The
investment tax credit so deferred shall be amortized by credits to
account 671, ''Provision for deferred taxes''.
Note A: Any change in practice of accounting for the investment tax
credit shall be reported promptly to the Commission. Carriers desiring
to clear deferred investment tax credits because of a change from the
deferral method to the flow through method shall submit the proposed
journal entry to the Commission for consideration and advice.
Note B: The carrier shall follow generally accepted accounting
principles where an interpretation of the accounting rules for income
taxes is needed or obtain an interpretation from its public accountant
or the Commission.
(Interstate Commerce Act, 49 U.S.C. 20 (1976), Department of Energy
Organization Act, 42 U.S.C. 7155, 7172(b), 7295(a) (Supp. I 1977); E.
O. 12009, 42 FR 46267 (1977); Federal Energy Regulatory Commission,
Order No. 1, 42 FR 55450 (1977))
(39 FR 33344, Sept. 17, 1974, as amended at 40 FR 53247, Nov. 17,
1975; 44 FR 72161, Dec. 13, 1979. Redesignated by Order 119, 46 FR
9044, Jan. 28, 1981)
1-13 Transactions with affiliated companies. (a) The records and
supporting data of all transactions with affiliated companies shall be
maintained in a separate file. The types of transactions referred to in
this paragraph are for management services or any other type of services
rendered, sale or use of facilities or any other type of assets or
property. The file shall be maintained so as to enable the carrier, to
furnish accurate information with supporting documentation about
particular transactions within 15 days of the request. We do not intend
the file to include data relating to ordinary carrier operations (e.g.
lawful tariff charges).
(b) Each bill rendered by an affiliated company shall state
specifically the basis used for determining charges, unless the file
contains other information to support the specific basis for charges.
(c) Punched cards, magnetic tapes, discs, or other machine-sensible
device used for recording, consolidating, and summarizing accounting
transactions and records with a carrier's electronic or automatic data
processing system may constitute a file within the meaning of this
instruction.
(d) The carrier shall record, as the cost of assets or services
received from an affiliated supplier, the invoice price (plus any
incidental costs related to those transactions) in those cases where the
invoice price can be determined from a prevailing price list of the
affiliated supplier available to the general public in the normal course
of business. If no such price list exists, the charges shall be
recorded at the lower of their cost to the originating affiliated
supplier (less all applicable valuation reserves in case of asset
sales), or their estimated fair market value determined on the basis of
a representative study of similar competitive and arm's-length or
bargained transactions.
Any difference between actual transaction price and the above, as
well as charges that are not transportation related, shall be considered
of a financing nature and shall be recorded, accordingly, as
nonoperating charges or credits. (See Instruction 1-14).
(e) Nothing contained herein shall be construed as restraining the
carrier from subdividing accounts (see Instruction 1-2(a)) for the
purpose of recording separately transactions with affiliated companies.
(40 FR 44562, Sept. 29, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
1-14 Charges to be just and reasonable. All charges to the accounts
prescribed in this system of accounts for carrier property, operating
revenues, operating and maintenance expenses, and other carrier
expenses, shall be just, reasonable and not exceed amounts necessary to
the honest and efficient operations and management of carrier business.
Payments shall not exceed the fair market value of goods and services
acquired in an arm's-length transaction. Any payments in excess of such
just and reasonable charges shall be included in account 660,
Miscellaneous Income Charges.
(40 FR 44562, Sept. 29, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
1-15 Accounting for marketable equity securities owned. (a) Accounts
11 ''Temporary investments,'' 20 ''Investments in affiliated
companies,'' and 21 ''Other investments'' shall be maintained in such a
manner as to reflect the marketable equity securities' portion (see
definition 35) and other securities or investments.
(b) For the purpose of determining net ledger value, the marketable
equity securities in account 11 shall be considered the current
portfolio and the marketable equity securities in accounts 20 and 21
(combined) shall be considered the noncurrent portfolio. The net ledger
value of each portfolio shall be the lower of its aggregate cost or
market value. (See definition 35.) The amount by which aggregate cost
exceeds market value shall be accounted for as the valuation allowance.
Account 11 ''Temporary investments'' shall be subdivided to include the
valuation allowance for the marketable equity securities included
therein. Account 24 ''Allowance for net unrealized loss on noncurrent
marketable equity securities -- Credit'' is the valuation allowance for
the marketable equity securities included in accounts 20 ''Investments
in affiliated companies'' and 21 ''Other investments.'' Marketable
equity securities accounted for by the equity method shall not be
combined with other marketable equity securities when determining
aggregate cost and market value.
(c) Realized gains and losses (the difference between net proceeds
from sale and cost) shall be included in income of the period in which
they occur. Changes in the valuation allowance for marketable equity
securities included in account 11 shall be charged to account 660
''Miscellaneous income charges'' or credited to account 640
''Miscellaneous income'' as appropriate, with a contra entry to the
valuation allowance contained within account 11. Changes in the
valuation allowance for marketable equity securities included in
accounts 20 and 21 shall be recorded in equity account 75.5 ''Net
unrealized loss on noncurrent marketable equity securities'' with a
contra entry to valuation account 24.
(d) If there is a change in the classification of a marketable equity
security between current and noncurrent, the security shall be
transferred at the lower of its cost or market value at date of
transfer. If market value is less than cost, the market value shall
become the new cost basis, and the difference shall be accounted for as
if it were a realized loss and included in the determination of net
income.
(e) For long investments in marketable equity securities, when the
decline in market value below cost is judged to be other than temporary,
the cost basis of the individual security shall be written down to a new
cost basis. The amount of the write-down shall be accounted for as a
realized loss by a charge to account 660 ''Miscellaneous income
charges'' and a credit to account 23, ''Reduction in security values --
Credit.'' The new cost basis shall not be changed for subsequent
recoveries in value.
(42 FR 33297, June 30, 1977. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
1-16 Accounting for inaccurate reporting of income taxes on income
from continuing operations which occurred prior to reporting year 1979.
To the extent that any oil pipeline company, required to file annual
reports with the Commission, did not correctly report State or other
income taxes on continuing operations for the 1976, 1977, and 1978
reporting years, such company is ordered to disclose the amount of the
accounting change in the space for notes and remarks provided in its
1979 Annual Report Form P, Schedule 300-A, of the Commission.
(Interstate Commerce Act, 49 U.S.C. 20 (1976), Department of Energy
Organization Act, 42 U.S.C. 7155, 7172(b), 7295(a) (Supp. I 1977); E.
O. 12009, 42 FR 46267 (1977); Federal Energy Regulatory Commission,
Order No. 1, 42 FR 55450 (1977))
(44 FR 72161, Dec. 13, 1979. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
18 CFR 351.1 Instructions for Balance Sheet Accounts
2-1 Current assets. In the group of accounts designated as current
assets shall be included cash and other assets or resources commonly
identified as those which are reasonably expected to be realized in cash
or sold or consumed within a one-year period. There shall not be
included any amount the collection of which is not reasonably assured by
the known financial condition of the debtor or otherwise. Items of
current character but of doubtful value shall be written down or written
off to account 510, Supplies and Expenses, or to account 660,
Miscellaneous Income Charges, as appropriate.
2-2 Investments and special funds. (a) This group of accounts shall
include the cost of long-term investments in securities other than those
of the accounting carrier, investment advances, sinking and other funds,
cash value of life insurance policies, and other items of similar
nature.
(b) Investment in securities shall be recorded at cost at time of
acquisition excluding amounts paid for accrued interest and dividends.
When securities with a fixed maturity date are purchased at a discount
or premium, such discount or premium shall be amortized over the
remaining life of the securities by periodical debits or credits to the
account in which the cost of the securities is recorded with
corresponding credits or debits to interest income. If the amount of
the discount or premium is minor, the investment may be maintained at
actual cost without adjustment, and the amount of discount or premium
recorded in the interest income account at the time the securities
mature.
(c)(1) For financial statement purposes the carrier shall follow the
principles of equity accounting for (1) all investments in corporate
joint ventures (see definition 31(c)), and (2) all investments in voting
stock of affiliated companies giving the carrier the ability to
significantly influence the operating and financial policies of an
investee (see definition 31(b)). For purposes of this instruction an
investment of 20 percent or more of the outstanding voting stock of an
investee will indicate the ability to exercise significant influence
over an investee in the absence of evidence to the contrary.
(2) Since the equity method is not to be effected by entries in the
books of accounts but is to apply only in financial reports to the
Commission, the carrier shall establish worksheet or memorandum
accounts. Three basic worksheet or memorandum accounts are needed:
(a) An investment account to include (1) equity in the undistributed
earnings or losses of the investee since the date of acquisition (see
definition 31(g)); (2) accumulated amortization of the difference
between cost and net assets at date of acquisition (see (c)(3) below);
and other adjustments for disposition or writedown of investments.
(b) An income account to include (1) the investor's share of the
investee's undistributed profits or losses for each reporting period
subsequent to acquisition of the investment except that in the year of
acquisition such amount shall be determined from the date of
acquisition; (2) amortization for the reporting period of the
difference between cost and net assets at date of acquisition. This
account shall be closed at year-end to the retained income memorandum
account discussed in paragraph (c) below.
(c) A retained income account to include (1) equity in the
undistributed earnings or losses of the investee since the date of
acquisition; (2) accumulated amortization of the difference between
cost and net assets acquired at date of acquisition (see (c)(3) below).
(d) Other memorandum accounts will be needed for such adjustments as
gains and losses on disposition of investments, recognition of
impairments in value, the investor's share of extraordinary and prior
period items reported in the investee's financial statements (see
instruction 1-6), and provision for deferred taxes where it is
reasonable to assume that undistributed earnings of an investee will be
transferred to the investor in a taxable distribution. These memorandum
accounts shall be closed at year-end to the retained income memorandum
account discussed in paragraph (c) above.
(3) The carrier shall retain the following information for each
investee in support of the worksheet or memorandum accounts:
(a) Original cost of investment.
(b) Equity in net assets of investee at date of acquisition.
(c) Allocation of difference between cost and equity in net assets,
namely, to specific assets of investee or to goodwill.
(d) Accumulated amortization of difference between cost and equity in
net assets.
(e) Unamortized balance of difference between cost and equity in net
assets.
(f) Equity in undistributed earnings/losses for each year since date
of acquisition.
(g) Dividends received since date of acquisition if determinable.
(h) Proceeds from sale of investments.
(4) Any difference between the investor's cost and its share of the
net assets of the investee at date of acquisition shall be allocated to
specific assets of the investee to the extent the difference is
attributable to them. When the difference is allocated to depreciable
or amortizable assets, depreciation and amortization (through the
investment and income memorandum accounts) should absorb the difference
over the remaining life of the related assets. If the difference is not
related to specific accounts, it should be considered goodwill and
amortized over a reasonable period not to exceed 40 years. For
investments made prior to November 1, 1970, amortization of goodwill is
not required in the absence of evidence that the goodwill has a limited
term of existence.
(5) The financial statements of the investee that are used for equity
accounting should be timely. If the accounting year of the investee
differs from that of the investor then the most recent available
financial statements may be used. The lag in reporting should be
consistent from period to period.
(6) Material profits or losses on transactions between the investor
and investee shall be eliminated until realized by either company as if
the two were consolidated.
(7) A transaction of the investee of a capital nature that affects
the investor's share of the investee's stockholder's equity should be
reported in the financial statements as if the two were consolidated.
(8) The investor shall deduct any dividends applicable to outstanding
cumulative preferred stock whether or not declared, and any other
dividends declared when computing its share of undistributed earnings or
losses.
(9) The investor shall suspend application of the equity method when
the investment (including the investment memorandum account) together
with any net advances made to the investee is reduced to zero.
Additional losses shall not be provided for unless the investor has
guaranteed obligations of the investee or is otherwise committed to
provide further financial support for the investee. If the investee
subsequently reports net income the investor shall resume applying the
equity method at such time as its share of that net income equals the
share of net losses not recognized during the period of suspension.
(10) When the investor's voting stock interest falls below the level
of ownership described in paragraph (c)(1) of this instruction, the
investment no longer qualifies for the equity method. Should dividends
received on the investment in subsequent periods exceed the investor's
share of earnings for such periods, the investment memorandum and income
memorandum accounts shall be reduced by the excess amount.
(11) When the level of ownership of an investment increases to that
described in paragraph (c)(1) of this instruction, the equity method
shall be applied. The memorandum accounts for the investment, income
(for current year's equity in undistributed earnings less amortization),
and retained income (for prior years' equity in undistributed earnings
less amortization) shall be adjusted retroactively on a step-by-step
basis determining the equity in net assets at date of acquisition,
amortization adjustment, and equity in undistributed earnings or losses
at each level of ownership. Where small purchases are made over a
period of time and then a purchase is made which qualifies the
investment for the equity method, the date of latest purchase may be
used as date of acquisition. In those situations where the information
needed to apply the equity method is not determinable, the date of
acquisition may be considered as January 1, 1974.
(12) Information having significance with respect to the investor's
ownership in investees shall be disclosed in notes to financial
statements of annual reports filed with the Commission in accordance
with generally accepted accounting principles.
Note A: The carrier shall follow generally accepted accounting
principles where an interpretation of the rules for equity accounting is
needed or obtain an interpretation from its public accountant or the
Commission.
(32 FR 20241, Dec. 20, 1967, as amended at 39 FR 34043, Sept. 23,
1974. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
2-3 Tangible property. The cost of property owned that is devoted to
transportation service shall be recorded in account 30, Carrier
Property, and in account 33, Operating Oil Supply. This includes
carrier's investment in jointly-owned transportation property in which
it has an undivided ownership interest. The cost of other property not
directly associated with pipeline operations shall be included in
account 34, Noncarrier Property. Property used in both carrier and
noncarrier services shall be classified in account 30 or account 34
according to its dominant use.
2-4 Other assets and deferred charges. Account 40, Organization
Costs and Other Intangibles, is prescribed for organization costs and
other intangible assets, such as patents and franchises. These
intangible assets shall be recorded at cost. Accounts are also
prescribed for assets not otherwise provided for and for charges
applicable to future periods.
2-5 Current liabilities. In this group of accounts shall be included
obligations which are payable on demand or mature or become due within
one year from the date of the balance sheet.
2-6 Noncurrent liabilities. Includible under this category of
account are those obligations which are not due to be liquidated within
one year from the date of the balance sheet. Estimates of future fire
losses or other contingencies shall not be accounted for as current
expenses or recorded as liabilities. Such contingencies may be provided
for by appropriations of retained income, the losses to be recognized in
income when sustained.
2-7 Contingent assets and liabilities. Contingent assets and
liabilities shall not be shown in the balance sheet but shall be
explained in detail in a footnote or in a supplementary statement.
Contingent assets are those which may be a possible source of value to
the carrier dependent upon the fulfillment of conditions regarded as
uncertain. Contingent liabilities are those which may under certain
conditions become obligations of the carrier but which are neither
direct nor assumed liabilities at the date of the balance sheet.
18 CFR 351.1 Instructions for Carrier Property Accounts
3-1 Property acquired. (a) In general the carrier property accounts
shall be charged with the cost of property purchased or constructed and
with the cost of additions and improvements. However, the acquisition
of properties comprising a distinct operating system, or an integral
portion thereof, when the purchase price exceeds $250,000, shall be
accounted for in accordance with the provisions set forth in instruction
3-11.
(b) The cost of purchased property is the net price paid on a cash
basis, or if other than money is given, the current value of that
consideration. Cost includes the purchase price; sales, use, and
excise taxes, and ad valorem taxes during periods of construction;
transportation charges; insurance in transit; installation charges;
and expenditures for testing and final preparation for use.
(c) Property acquired from an affiliated company through purchase or
transfer shall be recorded together with the related accrued
depreciation and liabilities assumed, if any, in the appropriate
property accounts at the same amount that it was recorded on the books
of the affiliate. When the purchase price exceeds the net book value of
the property acquired, the difference shall be charged to retained
income. When the purchase price is less than the net book value, the
difference shall be credited to account 73, Additional Paid-in Capital.
This does not apply to small miscellaneous purchases or transfers.
(d) The purchase of a proportionate share of a pipeline system or
facility owned in undivided interests shall be recorded at the amount
that the percentage of interest acquired bears to the whole. Any excess
of deficiency of purchase price over the amount so recorded shall be
debited to account 44, Other Deferred Charges, or credited to account
63, Other Noncurrent Liabilities, as appropriate, and amortized in equal
periodic amounts over the remaining service life of the system or
facility through income.
3-2 Minimum rule. (a) To avoid undue refinement in accounting,
carriers shall charge to operating expenses acquisitions of property
(other than land) including additions and improvements costing less than
$500. Expenditures made under a general plan shall not be parceled to
meet the minimum nor shall unrelated items be combined to avoid the
minimum.
(b) An amount of less than $500 may be adopted for purposes of this
rule provided the carrier first notifies the Commission of the amount it
proposes to adopt and thereafter makes no change in the amount unless
authorized to do so by the Commission.
3-3 Cost of property constructed. The cost of constructing property
chargeable to the carrier property accounts shall include direct and
other costs as described hereunder:
(1) Cost of labor includes the amount paid for labor performed by the
carrier's own employees and officers. This includes payroll taxes,
vacation pay, pensions, holiday pay and traveling and other incidental
expenses of employees. No charge shall be made to these accounts for
pay and expenses of officers and employees who merely render services
incidentally in connection with extensions, additions or replacements.
(2) Cost of material and supplies includes the purchase price (less
purchase and trade discounts) of material and supplies, including small
tools, at the point of free delivery; costs of inspection and loading
borne by the carrier; transportation charges; sales, use and excise
taxes; and when applicable a proportionate share of stores expenses.
In calculating the cost of material and supplies used, proper allowance
shall be made for the value of unused portions and other salvage, for
the value of the material recovered from temporary scaffolding,
cofferdams and other temporary structures used in construction: and for
the value of small tools recovered and used for other purposes.
(3)(i) Cost of special machine service includes the cost of labor
expended and of materials and supplies consumed in maintaining and
operating vehicles, equipment, and other machines used in construction
work; and rents paid for the use of such machines.
(ii) When machines are purchased primarily for a construction
project, their cost shall be charged to account 187, Construction Work
in Progress. Upon completion of the construction project, account 187
shall be credited with amounts received for machines sold or the book
cost (less a fair allowance for depreciation during the construction
period) of machines retained for use in carrier service. The net book
cost shall be included in the appropriate carrier property accounts.
(iii) The cost of repairs to vehicles and other work equipment and of
machine tools and machinery which are used both in construction and
maintenance work shall be apportioned equitably to the work in
connection with which the equipment is used.
(4) Cost of transportation includes the amounts paid to other
companies or individuals for the transportation of employees, material
and supplies, special machine outfits, appliances, and tools in
connection with construction and also the cost of hauling performed by
the carrier's own forces and facilities. The cost of the transportation
of construction material to the point where material is received by the
carrier shall be included, so far as practicable, as a part of the cost
of such material.
(5) Cost of contract work includes amounts paid for construction work
performed under contract by other companies, firms, or individuals, and
cost incident to the award of the contract.
(6) Cost of protection includes expenditures for protection in
connection with construction. This includes the cost of protection
against fires, cost of detecting and prosecuting incendiaries, amounts
paid to municipal corporations and others for fire protection, cost of
protecting property of others from damages, and analogous items.
(7) Cost of injuries and damages includes expenditures for injuries
to persons or damage to property when incident to construction projects,
and shall be included in the cost of the related construction work. It
also includes that portion of premiums paid for insuring property prior
to the completion or coming into service of the property insured.
Insurance recovered for compensation paid for injuries to persons
incident to construction shall be credited to the accounts to which such
compensation is charged. Any insurance recovered for damages to
property incident to construction shall be credited to the accounts
chargeable with the expenditures necessary for restoring the damaged
property. The cost of injuries and damages in connection with the
removal of old structures which are encumbrances on newly acquired lands
shall be included in the cost of land, or rights of way.
(8) Cost of privileges and permits includes compensation for
temporary privileges, such as the use of private or public property or
of streets, in connection with construction work.
(9) Taxes include taxes on property during construction and before
the facilities are completed and ready for service. This includes taxes
on land held under a definite plan for its use in pipeline service for
the period prior to the completion of pipeline facilities thereon and
other taxes separately assessed on property during construction, or
assessed under conditions which permit separate identification or
allocation of the amount chargeable to construction.
(10) Rent includes payments for use of facilities, such as motor
vehicles, special tools or machines, and quarters used for construction
work.
(11)(i) Interest during construction includes interest expense on
bonds, notes and other interest bearing debt incurred in the
construction of carrier property (less interest, if any, earned on funds
temporarily invested) after such funds become available for use and
before the receipt or the completion or coming into service of the
property. The interest shall be included in the accounts charged with
the cost of the property to which related.
(ii) There shall be deducted from such interest charges a proportion
of premium on securities sold. There shall be added a proportion of
discount and expense on funded debt issued for the acquisition or
construction of carrier property. The amount of premium and discount
and expense thus related shall be determined by the ratio which the
period between the date the proceeds from the securities issued become
available and the receipt, completion, or coming into service of the
property bears to the entire life of the securities issued.
(12) Cost of disposing of excavated material shall be included in the
cost of construction except that when such material is used for filling,
the cost of loading, hauling, and dumping shall be equitably apportioned
between the work for which removal is made and the work for which the
material is used.
3-4 Additions. Cost of additions to existing property shall be
included in the appropriate primary property accounts except as provided
in the minimum rule.
3-5 Improvements. Costs of improvements, subject to the minimum
rule, shall be accounted for as follows:
(a) The cost of items replaced shall be retired and the cost of the
improvement shall be charged to the appropriate property account except
that the related labor expense shall be charged to the maintenance
expense account.
(b) If the improvement does not involve a replacement, the cost of
the improvement shall be charged to the appropriate property account.
3-6 Replacements. Replacements are substitutions of a part or of a
complete unit of property with a new part or unit. Costs of
replacements shall be accounted for as follows:
(a) In replacing a complete unit of property, the old unit shall be
retired and the cost of the replacement recorded in the appropriate
primary property account, subject to the minimum rule.
(b) In replacing a minor item without improvement, the cost of such
replacement shall be charged to the maintenance expense account.
3-7 Retirements. The retirement of carrier property shall be
accounted for as follows:
(a) Land. The book cost of land retired shall be removed from the
property accounts. Gain or loss on the sale of land shall be recorded
in account 640, Miscellaneous Income, or account 660, Miscellaneous
Income Charges.
(b) Property. (1) The book cost of units of property retired and of
minor items of property retired and not replaced shall be written out of
the property account as of date of retirement, and the service value
shall be charged to account 31, Accrued Depreciation -- Carrier
Property.
(2) In case of casualty loss, insurance proceeds recovered shall be
credited to account 31, Accrued Depreciation -- Carrier Property, in an
amount not to exceed the book cost of the property involved. Any excess
amount shall be credited to account 640, Miscellaneous Income.
(3) Carrier property no longer used nor held for carrier operations
but used or intended for use in noncarrier operations shall be
transferred, along with the amount of past accrued depreciation,
estimated if necessary, to noncarrier property.
(32 FR 20241, Dec. 20, 1967, as amended at 40 FR 53248, Nov. 17,
1975. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
3-8 Salvage. (a) When retired property is salvaged for material or
parts which are to be reused by the carrier, the salvage shall be priced
at current second-hand value, not to exceed original cost, and charged
to account 17, Material and Supplies, or other appropriate account.
(b) When retired property is held without being dismantled, the
estimated value of the salvage less the estimated cost of salvaging
shall be included in account 19, Other Current Assets, if to be
recovered within a year, otherwise, in account 43, Miscellaneous Other
Assets.
3-9 Relocation of line. (a) If a line is relocated in the same
gathering field serving the same lease or purpose, all of the relocating
expenses whether or not a unit of property is involved shall be charged
to maintenance expense, provided that the same size pipe is used in such
relocation. Resulting increases or decreases in the length of the line
shall be accounted for as additions or retirements of property.
(b) In accounting for relocation of trunk lines involving units of
property, the replaced property shall be retired and the cost of the new
property included in the appropriate primary property accounts. When
public improvement projects are involved, the cost of the new property
shall be (1) the book cost less depreciation or amortization of the
replaced property, less the net salvage value recovered, plus (2) costs
incurred by the carrier, less any amounts contributed by governmental
agencies or others.
3-10 Property contributed. (a) The value of contributions or
property received from others including governmental agencies shall not
be recorded in the property accounts; however, memorandum entries
should be made in the records of the carrier describing the property
received, the value thereof, and all other pertinent information related
thereto.
(b) Property contributed by an affiliate shall be recorded in the
property accounts together with the related accrued depreciation at the
same amounts that were recorded on the books of the affiliate provided,
however, that the amount of contribution made by non-carrier affiliates
shall not exceed the fair value of the property received.
3-11 Acquisition by merger, consolidation or purchase. Accounting
for property acquired by business combination of two or more
corporations, or the acquisition of properties comprising a distinct
operating system, or integral portion thereof as specified in section
3-1, shall depend on whether there has been (1) a merger or
consolidation in a ''pooling of interests'' or (2) a ''purchase.'' A
''pooling of interests'' may exist when holders of all or substantially
all of the ownership interests, usually common stock, in the constituent
corporations or entities become the owners of a surviving corporation or
a new corporation which owns the assets and business of the constituent
corporations or entities directly or through one or more subsidiaries.
However, when the stockholders of one of the constituent corporations
obtain 90 percent or more of the voting interest in the combined
enterprise; or when there is a plan or firm intention and understanding
to retire a substantial part of the capital stock issued to the owners
of one or more of the constituent corporations or substantial changes in
ownership which occurred shortly before or planned to occur shortly
after the combination, the combination may be considered a ''purchase.''
(a) Accounting under a ''pooling in interest.'' (1) In accounting for
a ''pooling of interests,'' no new basis of accountability arises. The
assets and liabilities of the constituent companies or entities and the
related accrued depreciation and amortization accounts along with the
retained income or deficit accounts shall be carried forward, adjusted,
if necessary, to conform with the accounting rules of the Commission.
(2) When the total par value or stated value of no-par capital stock
of the succeeding corporation is greater than that of the constituent
corporations, the excess shall be charged first to the amount in account
73, Additional Paid-in Capital, that is not otherwise restricted, and
the Balance to account 75, Unappropriated Retained Income.
(3) When the par value or stated value of no-par capital stock of the
succeeding corporation is less than that of the constituent
corporations, the difference shall be credited to account 73, Additional
Paid-in Capital.
(b) Accounting under a ''purchase.'' In accounting for a
''purchase,'' the assets shall be recorded on the books of the acquiring
carrier at cost as of the date of acquisition or, if other than money is
given, at the fair value of such consideration. Liabilities assumed
shall be recorded in the appropriate accounts according to the
accounting rules of the Commission.
(c) Approval of accounting. (1) Tentative journal entries recording
the acquisition of pipeline properties shall be submitted to the
Commission for consideration and approval. The entries shall give a
complete description of the property purchased and the basis upon which
the amounts of the entries have been determined. Any portion of the
purchase price attributable to intangible property shall be separately
recorded as hereinafter provided in account 40, Organization Costs and
Other Intangibles.
(2) When the costs of individual or groups of transportation property
are not specified in the agreement or in supporting documents, or when
separate costs are not provided for the physical property and the
intangible property, the total purchase price shall be equitably
apportioned among the appropriate property or other accounts, based on
the percentage relationship between the purchase price and the original
cost of property shown in the valuation records of the Commission or the
fair market value of the properties. The portion of the total price
assignable to the physical property shall be supported by independent
appraisal or such other information as the Commission may consider
appropriate. In no event shall amounts recorded for physical properties
and other assets acquired exceed the total purchase price.
(3)(a) Where the purchase price is in excess of amounts recorded for
the net assets acquired, such excess shall be included in account 40,
Organization Costs and Other Intangibles.
(b) The excess of the purchase price over amounts includable in the
primary carrier property accounts shall be amortized through account
660, ''Miscellaneous income charges,'' or otherwise disposed of, as the
Commission may approve or direct.
(32 FR 20241, Dec. 20, 1967, as amended by 35 FR 13992, Sept. 3,
1970; 37 FR 17713, Aug. 31, 1972. Redesignated by Order 119, 46 FR
9044, Jan. 28, 1981)
3-12 Reorganizations. When a carrier is involved in receivership or
bankruptcy so as to effect a reorganization, all accounting relating to
the plan of reorganization shall be submitted to this Commission for
consideration and approval.
3-13 Disposition of former Account 193, Acquisition Adjustment.
Amounts included in former account 193, Acquisition Adjustment,
attributable to mergers, consolidations, reorganizations, and purchases
of property shall be cleared from that account as the Commission may
authorize or direct upon submission of proposal for distribution of the
amounts therein.
3-14 Accounting units of property. (a) This list of units is
established for the purpose of designating the items of property, the
cost of which shall be written out of the property accounts when the
property is retired and replaced.
(b) When property is retired and not replaced the cost thereof shall
be written out of the accounts whether or not designated a unit of
property.
(c) A carrier desiring to include in any account an appropriate unit
not now specified therein may, upon approval of the Commission, make
such authorized addition to this list of units.
A section of right of way.
1,500 feet of pipe 6 inches in diameter or larger contained in a
continuous section.
3,000 feet of pipe of less than 6 inches in diameter contained in a
continuous section.
Fittings for pipe lines 6 inches or more in diameter contained in a
continuous section of 1,500 feet of line pipe.
Fittings for pipe lines less than 6 inches in diameter contained in a
continuous section of 3,000 feet of line pipe.
The construction cost pertaining to a unit of line pipe.
A complete building.
An entire roof with or without supporting members.
A complete fire escape.
A complete heating system.
An elevator complete with operating mechanism.
A complete boiler.
A complete engine with or without foundation.
A complete pump with or without foundation.
A power-transmission system.
A machine tool.
A foundation special to a machine.
A motor, generator, steam engine, pump, ventilating fan, or other
similar equipment.
A coal-handling system.
An ash-handling system.
A furnace.
A boiler.
Each complete item of property, the book cost of which was charged to
the carrier property account.
A complete oil tank with or without grade and fire walls.
A fire wall.
A tank grade.
A motor, generator, engine, pump, or similar equipment.
A delivery-pipe system.
A complete wharf.
A section of wharf.
A pile cluster or dolphin.
A complete loading or unloading rack.
A complete railroad siding.
A complete switchboard.
A continuous section of 1 mile of aerial wire.
A section of 1,000 feet of aerial cable.
A section of 500 feet of submarine cable.
A section of 500 feet of conduit.
A continuous section of 35 poles.
A case of equipment, such as loading coil or autotransformer.
A transmitting set.
A receiving set.
An antenna, complete, or without supports.
Each complete item of furniture or equipment the book cost of which
was charged to the carrier property account, such as: A desk, chair,
table, davenport, typewriter, computing machine; a section of bookcase,
filing cabinet; rug, carpet, or other floor covering for one room.
Each complete item of equipment the original cost of which was
charged to the carrier property account, such as: A passenger
automobile or truck with or without body; a tractor; a pole derrick,
power winch, earthboring machine, or trailer.
Each complete item of property the book cost of which was charged to
the carrier property account.
(32 FR 20241, Dec. 20, 1967. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
18 CFR 351.1 Instructions for Operating Revenues and Operating Expenses
4-1 Detail of accounts. The carrier shall keep the prescribed
accounts with sufficient particularity to permit the reporting of
operating revenues and expenses for crude oil lines and for product
lines separately, and to permit the allocation of operating expenses by
service functions (see 4-3 Operating Expenses).
4-2 Operating revenues. The operating revenue accounts are designed
to show the amount of money which the carrier becomes entitled to
receive or which accrues to its benefit for transportation and services
incidental thereto.
4-3 Operating expenses. The operating expense accounts are designed
to show the costs of pipeline operations by service functions. The
expenses of pipeline operations are to be allocated to the following
functions:
(a) Gathering. This includes the gathering and collection of oil,
oil products and other commodities from oil field, refinery, or other
source (other than carrier's own terminal and delivery facilities), and
transmission to point of connection to meters, working or storage tanks,
or intake side of the manifold at the trunk line receiving site or
station, or at a terminal.
(b) Trunk. This includes the trunk line transportation of crude oil,
oil products and other commodities from origin or receiving station to
point of connection with other carriers, consignee facilities at
destination, or to the discharge side of the manifold or connection to
working or storage tanks at the destination station.
(c) Delivery. This includes the receiving, storage, and delivering
at terminal and delivery facilities of crude oil, oil products and other
commodities from or to railroads, motor carriers, water carriers, and
others prior or subsequent to movement by pipeline.
4-4 Expense classification. The primary expense accounts are to be
reported under the following classifications:
(a) Operations expense. This group of accounts includes all costs
directly associated with the operation of facilities devoted to pipeline
operations including scheduling, dispatching, movement, and delivery of
crude oil, oil products and other commodities.
(b) Maintenance expense. This group of accounts includes all costs
directly associated with repairs and maintenance of property devoted to
pipeline operations.
(c) General expense. This group of accounts includes general and
administrative expense and all other expenses not directly allocable to
operations and maintenance expenses.
4-5 Expense distribution. The several classes of expenses shall be
directly allocated to applicable service functions to the fullest
possible extent. Expenses common to two or more functions and system
expenses shall be equitably apportioned to the service functions. The
basis for apportionment and the underlying records in support thereof
shall be readily available for inspection by the Commission's examiners.
18 CFR 351.1 Balance Sheet Accounts
10 Cash.
This account shall include money, checks, sight drafts and sight
bills of exchange, money in banks or in other depositories subject to
withdrawal on demand, and other similar items. The amount of checks and
sight drafts transmitted to payees which are unpaid at the close of the
accounting period shall be credited to this account.
Note: Compensating balances (see Definition 33) under an agreement
which legally restricts the use of such funds shall not be included in
this account. Such balances shall be included in account 10-5 ''Special
deposits'' or account 22 ''Sinking and other funds.''
(49 U.S.C. 304, 913, 1012)
(32 FR 20241, Dec. 20, 1967, as amended at 41 FR 9158, Mar. 3, 1976.
Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
10-5 Special deposits.
This account shall include cash deposits, either placed in hands of
trustees or under the direct control of the reporting company, which are
restricted for specific purposes. Examples are those deposits made for
the payment of dividends and interest due within one year, the
liquidation of other current liabilities, to guarantee fulfillment of
current contract obligations, to meet specific operating requirements,
or compensating balances (see Definition 33) under an agreement which
legally restricts the use of such funds and which constitute support for
short-term borrowing arrangements. Sub-accounts may be set up, if
necessary to account for special deposits for specific purposes.
Note: Deposits available for general company purposes shall be
included in account 10 ''Cash.''
(49 U.S.C. 304, 913, 1012)
(41 FR 9158, Mar. 3, 1976. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
11 Temporary investments.
This account shall include the cost of securities and other
collectible obligations acquired for the purpose of temporarily
investing cash, such as United States Treasury certificates, marketable
securities, time drafts receivable, demand loans, time loans, time
deposits with banks and trust companies, and other similar investments
of a temporary character.
This account shall be subdivided to reflect the marketable equity
securities' portion (and its corresponding valuation allowance) and
other temporary investments (See Instruction 1-15).
(32 FR 20241, Dec. 20, 1967, as amended at 42 FR 33298, June 30,
1977. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
12 Notes receivable.
This account shall include the book cost, not includible elsewhere,
of all collectible obligations in the form of notes receivable,
contracts receivable, and similar evidences (except interest coupons) of
money receivable on demand or within a time not exceeding one year from
date of the balance sheet. Notes receivable from affiliates shall be
included in account 13, Receivables from Affiliated Companies.
13 Receivables from affiliated companies.
This account shall include amounts receivable due and accrued from
affiliated companies subject to settlement within one year from date of
the balance sheet. This includes receivables for items such as revenue
for services rendered, material furnished, rent, interest and dividends,
advances and notes.
14 Accounts receivable.
This account shall include amounts receivable due and accrued from
other than affiliates which are subject to settlement within one year
from date of the balance sheet. This includes items such as revenue for
services rendered, material furnished, rent, accounts of officers and
employees, miscellaneous accounts with others.
15 Interest and dividends receivable.
(a) This account shall include the amount of interest due and accrued
as of the date of the balance sheet on all interest-bearing obligations
held by the carrier. This account shall also include the amount of
dividends declared on stocks owned.
(b) Interest and dividends receivable from affiliated companies or on
the carrier's own securities shall not be included in this account.
16 Oil inventory.
(a) This account shall include the cost of oil purchased and the
value of oil acquired through tariff allowances and operating gains.
Amounts paid preceding carriers for transportation, customs duties, or
similar charges shall be charged to account 230, Allowance Oil Revenue.
Additions to inventory from tariff allowances shall be credited to
revenue at current value. Additions resulting from operating gains
shall be credited against operating oil losses and shortages.
(b) The cost or value of oil owned by the carrier and used to
maintain lines and working tanks in condition for transportation
operations shall be included in account 33, Operating Oil Supply.
17 Material and supplies.
(a) This account shall include the cost, including sales, use and
excise taxes and transportation costs to point of delivery, less
purchase and trade discounts, of all unapplied material and supplies,
such as line pipe, line pipe fittings, fuel, tools, and other pipeline
supplies. The value of items being manufactured by the carrier and the
fair value of salvaged material shall also be included herein.
(b) Carriers shall take annual inventories of material and supplies
and shall make the adjustments necessary to reconcile the books to the
inventory figures. To the extent practicable, adjustments shall be made
directly to the same accounts to which such material and supplies were
charged during the period. Differences that cannot be directly
allocated shall be equitably apportioned among the accounts to which
material was charged since the last inventory.
18 Prepayments.
This account shall include the amount of expenses paid in advance of
accrual such as insurance, rent, and taxes, the benefits of which are to
be realized in subsequent periods. Monthly transfers shall be made to
the appropriate expense or other accounts for the expired portion of the
prepayments applicable to that month.
19 Other current assets.
This account shall include such items as estimated tax refunds
receivable, legally enforceable, balances due on subscriptions to
capital stock, temporary guaranty and other deposits, and all other
current assets due within one year which are not includible in the other
current asset accounts.
19-5 Deferred income tax charges.
(a) This account shall include the portion of deferred income tax
charges and credits relating to current assets and liabilities, when the
balance is a net debit.
(b) A net credit balance shall be included in account 59, Deferred
income tax credits.
(39 FR 33344, Sept. 17, 1974. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
20 Investments in affiliated companies.
This account shall include the cost of investments in securities
(other than securities held in special funds) and investment advances
made to affiliated companies. Separate records shall be maintained to
show the securities pledged and the following classes of investments in
each affiliated company:
(a) Stocks.
(b) Bonds.
(c) Other secured obligations.
(d) Unsecured notes.
(e) Investment advances.
21 Other investments.
This account shall include the cost of investments in securities of
(other than securities held in special funds) and advances made to other
than affiliated companies. Separate records shall be maintained to show
the securities pledged and the following classes of investments in each
nonaffiliated company:
(a) Stocks.
(b) Bonds.
(c) Other secured obligations.
(d) Unsecured notes.
(e) Investment advances.
22 Sinking and other funds.
(a) This account shall include cash and cost of investment in
securities and other assets, trusteed or otherwise restricted, that have
been segregated in distinct funds for purposes of redeeming outstanding
obligations; purchasing or replacing assets; paying pensions, relief,
hospitalization, and other similar items. This account shall also
include the cash value of life insurance policies on the lives of
employees and officers to the extent that the carrier is the beneficiary
of such policies. Separate subsidiary records shall be maintained for
each distinct fund.
(b) Securities issued or assumed by the accounting company shall be
recorded at par or stated value.
(c) This account shall include compensating balances (see Definition
34) under an agreement which legally restricts the use of such funds and
which constitute support for long-term borrowing arrangements.
(49 U.S.C. 304, 913, 1012)
(32 FR 20241, Dec. 20, 1967, as amended at 41 FR 9158, Mar. 3, 1976.
Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
23 Reductions in security values -- Credit.
This account shall include provisions for losses in value of
securities held as investments in affiliated or other companies, and
including securities in funds. Concurrent charges shall be made to
account 660, Miscellaneous Income Charges.
(32 FR 20241, Dec. 20, 1967, as amended at 40 FR 53248, Nov. 17,
1975. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
24 Allowance for net unrealized loss on noncurrent marketable equity
securities -- Credit.
This account shall reflect the amount by which aggregate cost exceeds
market value for the noncurrent marketable equity securities found in
accounts 20 and 21. This account shall be debited or credited so that
the balance at the balance sheet date shall reflect such difference.
(Refer to Instruction 1-15.)
This account shall not include amounts by which aggregate cost
exceeds market value if such differences are judged to be other than
temporary. (Such differences should be charged to account 23.)
(42 FR 33298, June 30, 1977. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
30 Carrier property.
This account shall include the cost of tangible property used in
carrier service, or held for such use within a reasonable time under a
definite plan for pipeline operations. Separate primary accounts are
prescribed for each class of carrier property.
31 Accrued depreciation -- Carrier property.
This account shall be credited with amounts charged to operating
expenses or other accounts representing the loss in service value of
depreciable carrier property. The service value of depreciable property
retired shall be charged to this account. It shall also include other
entries as may be authorized by the Commission. Detail of this account
shall be maintained by primary property accounts.
32 Accrued amortization -- Carrier property.
This account shall be credited with amounts charged to operating
expenses or other accounts representing the loss in service value of
carrier property subject to amortization accounting as authorized by the
Commission. Upon the retirement of property subject to amortization
this account shall be charged with the amount included herein applicable
to the specific property at the time the property is retired.
Subsidiary records shall be maintained for each group of property items
under a separate amortization authorization.
33 Operating oil supply.
This account shall include the cost of oil purchased and the value of
oil added through tariff allowances and operating gains which is used to
maintain lines and tanks in working condition. Additions to operating
supply from tariff allowances shall be credited to revenue at current
value. Additions resulting from operating gains shall be credited
against operating oil losses and shortages.
34 Noncarrier property.
This account shall include the cost of tangible property not used in
carrier pipeline operations.
35 Accrued depreciation -- Noncarrier property.
This account shall be credited with amounts charged to income,
representing the loss in service value of depreciable noncarrier
property.
40 Organization costs and other intangibles.
This account shall include the cost of intangible assets such as
organizing the carrier, patents, permits, franchises, and goodwill.
Organization costs include the legal expense, taxes, fees, stationery
and printing, original capital stock expense and costs of economic
feasibility studies made prior to initial operation of the carrier.
Separate subsidiary records shall be maintained for each class of
intangible asset.
41 Accrued amortization of intangibles.
This account shall be credited with the amounts charged to operating
expenses or income representing the expired cost of intangible property.
When the period of benefit of intangible property is fully expired, or
assets are retired to which the intangible relates, this account shall
be charged with the amount herein applicable to the specific property.
43 Miscellaneous other assets.
This account shall include such items as accounts receivable, utility
deposits, guaranty deposits and other similar assets which are not
expected to be realized or returned to the carrier within one year from
date of the balance sheet. The estimated net salvage value of retired
carrier property held without being dismantled shall be included in this
account.
44 Other deferred charges.
This account shall include items that cannot be disposed of until
further information is received and items of a deferred nature, not
provided for elsewhere, to be amortized to expense or other accounts in
future periods. This includes such items as engineering surveys and
studies and debt expense.
45 Accumulated deferred income tax charges.
This account shall include the amount of deferred taxes (see
definition 30(h)) determined in accordance with instruction 1-12 and the
text of account 64, Accumulated deferred income tax credits, when the
balance is a net debit.
(39 FR 33344, Sept. 17, 1974. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
50 Notes payable.
This account shall include outstanding obligations in the form of
notes, and other similar evidences of indebtedness payable on demand or
within one year from the date of issue except those payable to
affiliated companies.
Note: This account shall not include obligations due within one year
which are intended to be refinanced on a long-term basis. Long-term
refinancing of short-term obligations means; (1) replacement with
long-term obligations or equity securities, or (2) renewal, extension,
or replacement with short-term obligations for an uninterrupted period
extending beyond one year from the balance sheet date.
The intention to refinance on a long-term basis shall be supported by
the ability to refinance. Evidence of this ability includes either;
(1) the actual issuance of a long-term obligation or equity securities
for the purpose of refinancing the short-term obligation, after the
balance sheet date but before the balance sheet is issued, or (2) before
the balance sheet is issued, the existence of a financing agreement
which is long-term and based on terms readily determinable with no
existing violations of its provisions, and with a lender which is
financially capable of honoring the agreement.
(49 U.S.C. 304, 913, 1012)
(32 FR 20241, Dec. 20, 1967, as amended at 41 FR 9163, Mar. 3, 1976.
Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
51 Payables to affiliated companies.
This account shall include amounts payable due and accrued to
affiliated companies (except interest and dividends) subject to
settlement within one year from date of the balance sheet, and for which
arrangements for long-term refinancing have not been made (See Note
following account 50, ''Notes Payable''). This includes payables for
items such as services and material received, rent, advances and notes.
(49 U.S.C. 304, 913, 1012)
(41 FR 9163, Mar. 3, 1976. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
52 Accounts payable.
This account shall include amounts payable due and accrued (except
those to affiliated companies) subject to settlement within one year
from the date of the balance sheet. This includes payables for items
such as joint revenue, material and supplies, services received, rents,
claims, taxes collected from employees and others for account of taxing
entities, and other similar items.
53 Salaries and wages payable.
This account shall include salaries and wages payable due and accrued
including vacation pay and unclaimed salaries and wages as of the
balance sheet date. Unclaimed salaries and wages outstanding for more
than one year may be written off to income unless the amount unclaimed
escheats to the state.
54 Interest payable.
This account shall include interest accrued or payable on all
obligations.
55 Dividends payable.
This account shall include the amount of dividends (other than stock
dividends) declared but unpaid as of the date of the balance sheet.
56 Taxes payable.
This account shall include all Federal, state, and local taxes
(except taxes withheld from employees) accrued and payable, estimated if
necessary, as of the balance sheet date. Prepaid taxes shall be shown
as current assets in account 18, Prepayments. Subsidiary records shall
be maintained to allow analyses of this account by matured and unmatured
taxes and by type of tax and taxing entity.
57 Long-term debt payable within one year.
This account shall include the amount of long-term debt which will
mature and become payable within one year from date of the balance sheet
for which arrangements for long-term refinancing have not been made (See
note following account 50, ''Notes Payable'').
(49 U.S.C. 304, 913, 1012)
(41 FR 9163, Mar. 3, 1976. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
58 Other current liabilities.
This account shall include all other current liabilities not provided
for elsewhere that are payable within one year from date of balance
sheet.
59 Deferred income tax credits.
(a) This account shall include the portion of deferred income tax
charges and credits relating to current assets and liabilities, when the
balance is a net credit.
(b) A net debit balance shall be included in account 19-5, Deferred
income tax charges.
(39 FR 33344, Sept. 17, 1974. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
60 Long-term debt payable after one year.
This account shall include the total par value of the carrier's
outstanding obligations maturing more than one year from the date of the
balance sheet, including obligations due within one year which are
expected to be refinanced on a long-term basis (See note following
account 52, ''Accounts payable''). This account shall be divided to
show the face value of (1) debt issued and actually outstanding, and (2)
debt ''nominally issued'' and ''nominally outstanding''. These accounts
shall be further divided by the following classes of debt: mortgage
bonds, collateral trusts, income bonds, miscellaneous obligations and
nonnegotiable debt to affiliated companies.
(49 U.S.C. 304, 913, 1012)
(41 FR 9163, Mar. 3, 1976. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
61 Unamortized premium on long-term debt.
This account shall include the premium received and not yet amortized
on the issuance of long-term debt. The amount of premium received on
each issue of bonds, mortgages, notes, and other long-term debt shall be
amortized over the life of the debt by credit to interest expense.
Note: Issue costs related to long-term debt (debt expense) shall be
included in account 44. Other deferred charges, and amortized over the
life of the debt by charge to account 660, Miscellaneous income charges.
(32 FR 20241, Dec. 20, 1967, as amended at 41 FR 52467, Nov. 30,
1976. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
62 Unamortized discount and interest on long-term debt.
This account shall include the amount of discount on long-term debt,
and the amount of interest expressly provided for and included in the
face amount of obligations issued or assumed and not amortized as of the
balance sheet date. The amount of discount or interest applicable to
each issue of debt obligation shall be amortized over the life of the
respective debt by charge to interest expense.
Note: Issue costs related to long-term debt (debt expense) shall be
included in account 44, Other deferred charges, and amortized over the
life of the debt by charge to account 660, Miscellaneous income charges.
(41 FR 52467, Nov. 30, 1976. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
63 Other noncurrent liabilities.
(a) This account shall include such items as deferred revenue from
rents or leases that will not be realizable as income within one year,
and the liability for amounts contributed by employees or others for
pensions, savings, and similar items. This account shall also include
the amount accrued for pensions in which the employees have a vested
right and which are administered by the carrier.
(32 FR 20241, Dec. 20, 1967, as amended at 39 FR 33344, Sept. 17,
1974. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
64 Accumulated deferred income tax credits.
(a) This account shall be credited (charged) with amounts
concurrently charged (credited) to account 671, Provision for deferred
taxes and account 696, Provision for deferred taxes -- extraordinary
items, representing the net tax effect of material timing differences
(see definitions 30 (g) and (e)) originating and reversing in the
current accounting period.
(b) This account shall be credited with the amount of investment tax
credit utilized in the current year for income tax purposes but deferred
for accounting purposes (see instruction 1-12).
(c) This account shall be concurrently debited with amounts credited
to account 671, Provision for deferred taxes representing amortization
of amounts for investment tax credits deferred in prior accounting
periods.
(d) This account shall be maintained in such a manner as to show
separately: (1) The unamortized balance of deferred income taxes and
deferred investment tax credit separately as of the beginning and as of
the end of each year entries are made affecting the account balance, (2)
the current years net credit or charges applicable to timing differences
and deferred investment tax credits.
Note A: The portion of deferred charges and credits relating to
current assets and liabilities should likewise be classified as current
and included in account 19-5, Deferred income tax charges, or account
59, Deferred income tax credits, as appropriate.
Note B: This account shall include a net credit balance only. A net
debit balance shall be recorded in account 45, Accumulated deferred
income tax charges.
(39 FR 33344, Sept. 17, 1974, as amended at 40 FR 53248, Nov. 17,
1975. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
70 Capital stock.
(a) This account shall include the par value of par value stock,
stated value of no-par stock, and the amount received for no-par stock
without stated value, which have been issued to bona fide purchasers and
have not been reacquired and cancelled, also shares of stock nominally
issued. When other than cash is received for no-par value stock, the
fair market value of the consideration shall be entered in this account.
(b) This account shall be divided so as to show separately each class
of stock issued, subdivided between (1) issued and outstanding, and (2)
nominally issued and nominally outstanding.
(c) When an issue of capital stock or any part thereof is reacquired,
either by purchase or donation, and is retired or cancelled, the par
value shall be charged to this account. Any excess of reacquisition
cost over par value shall be allocated between account 73, Additional
Paid-in-Capital and 720, Other Debits to Retained Income. Any excess of
par value over reacquisition cost shall be credited to account 73,
Additional Paid-in-Capital.
(d) When an issue of capital stock or any part thereof is reacquired,
either by purchase or donation, and is not retired or cancelled, nor
properly includible in sinking or other funds, the reacquisition cost
shall be charged to account 76, Treasury Stock.
(e) When treasury stock is resold, account 76, Treasury Stock, shall
be credited with the cost paid for it. Gains shall be credited to
account 73, Additional Paid-in-Capital. Losses shall be charged to
account 73, Additional Paid-in-Capital to the extent that previous net
gains from sales or retirements of the same class of stock are included
therein; otherwise, to account 720, Other Debits to Retained Income.
(40 FR 44562, Sept. 29, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
71 Premiums on capital stock.
This account shall include the excess of the actual cash value of the
consideration received at the time of the original sale over the par or
stated value of the stock issued.
72 Capital stock subscriptions.
This account shall include the full amount of the par value, stated
value, or price agreed upon for no-par stock which has been subscribed
under a legally binding purchase agreement. The difference between the
par value or stated value, plus any premiums or the amount agreed upon
for no-par stock, and the down payment or installments received, shall
be recorded as a current asset in account 19, Other Current Assets.
Appropriate subaccounts shall be kept to record separately the
transactions for each class and series of stock involved.
73 Additional paid-in capital.
This account shall include gains from purchase and resale of
reacquired stock. Credits attributable to reductions in the par or
stated value of capital stock may be included in this account only when
approved by the Commission. Separate subaccounts shall be maintained
for each class and series of stock. Also include herein contributions
to capital made by stockholders and others.
74 Appropriated retained income.
This account shall include retained income which has been
appropriated and set aside under contractual or legal requirements and
for other specific purposes, such as the retirement of bonded
indebtedness, contingencies, redemption of preferred capital stock;
fire losses; plant replacement and additions; miscellaneous employee
benefits; and similar items. Appropriations shall be released when
their respective purposes have been served. Separate subaccounts shall
be maintained for each specific purpose for which retained income is
appropriated.
75 Unappropriated retained income.
(a) This account shall include retained income which has not been
appropriated or set aside for specific purposes. There shall be no
transfers to or from account 73, Additional Paid-in Capital, to this
account unless so authorized by the Commission.
(b) The balance of accounts 700 to 750, inclusive, shall be closed to
this account at the end of each calendar year.
(32 FR 20241, Dec. 20, 1967, as amended at 34 FR 15483, Oct. 4, 1969;
37 FR 17714, Aug. 31, 1972. Redesignated by Order 119, 46 FR 9044, Jan.
28, 1981)
75.5 Net unrealized loss on noncurrent marketable equity securities.
This account shall include the accumulated changes in account 24 to
the extent that these changes represent a net unrealized loss (aggregate
cost exceeds market value).
(42 FR 33298, June 30, 1977. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
76 Treasury stock.
(a) This account shall include in subdivisions for each class the
reacquisition cost of capital stock which has been actually issued or
assumed by the carrier, then reacquired, and is neither retired nor
cancelled, nor properly includible in sinking or other funds.
(b) This account shall be maintained to reflect separately securities
pledged or unpledged.
(c) This account shall be shown on the Balance Sheet as a deduction
in arriving at Stockholders' Equity.
Note A: The accounting for the reacquisition of capital stock and
resale thereof shall be in accordance with balance sheet account 70,
paragraphs (c) through (e).
(40 FR 44562, Sept. 29, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
18 CFR 351.1 Carrier Property Accounts
The following table lists the prescribed primary property accounts
and indicates those accounts which contain similar items of property for
which a single text is provided. The accounts are to be kept separately
for crude oil lines and for product lines.
101, 151, 171 Land.
(a) This account shall include the cost of land held in fee and used
in pipeline operations. Land not used in carrier service shall be
recorded in account 34, Noncarrier Property. Irregular parcels of land
without commercial value acquired with rights of way shall not be
transferred to account 34 solely to make right of way boundries regular.
(b) The cost of land and buildings acquired together shall be
equitably separated and recorded. When land is acquired with buildings,
structures, or other encumbrances that must be removed before the land
is usable, demolition cost, less salvage, shall be added to the book
cost of the land. Net proceeds from the sale of timber, minerals and
improvements which were part of the land cost when purchased by the
carrier, shall be credited to this account up to the amount of the
purchase price allocated as their cost. Any excess shall be credited to
account 640, Miscellaneous Income.
(c) Costs of filing, clearing, grading or leveling land, when such
work is not directly associated with construction or a definite plan for
construction, shall be charged to this account.
(d) All direct or incidental costs associated with the acquisition of
the land and any taxes and public assessments assumed at the time of
purchase, shall be included in this account.
(e) Special assessments for public improvements and also costs borne
by the carrier for public improvements constructed by it shall be
included in this account.
(32 FR 20241, Dec. 20, 1967, as amended at 40 FR 53248, Nov. 17,
1975. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
102, 152 Right of way.
This account shall include the cost of obtaining rights of way used
in pipeline operations. Periodic rents paid for the use of a right of
way shall be charged to operating rents. Costs of filling, clearing,
grading or leveling of a right of way when such work is not directly
associated with construction or a definite plan for construction, shall
be charged to this account.
103, 153 Line pipe.
This account shall include the cost of all line pipe actually laid in
pipe lines devoted to transportation service.
104, 154 Line pipe fittings.
This account shall include the cost of the line pipe fittings,
including manifolds, used in pipe lines devoted to transportation
service.
105, 155 Pipeline construction.
(a) This account shall include all the costs of constructing pipe
lines except the cost of line pipe and fittings provided for in accounts
103, 153, Line Pipe, and 104, 154, Line Pipe Fittings.
(b) Includible shall be the cost of labor and materials such as
casing and vent pipe, pipe coatings of all kinds, river weights, support
structures, sand bags, valve boxes, cathodic protection devices, mile
posts, right-of-way markers, excavating and backfilling, pipeline pits,
and the cost of damages paid for the destruction of crops, timber, and
other property during construction. The cost of reopening the trenches
for repairs, or installation of casing, coating or cathodic protection,
and the necessary backfilling shall be charged to maintenance expense.
106, 156, 176 Buildings.
This account shall include the cost of all buildings including the
foundations, fixtures, and appurtenances thereto. This includes such
items as architects' fees, sidewalks, driveways, fences, permanent water
rights, grading and preparing grounds before and after construction,
utility lines and other service piping. Cost of restoring grounds after
repair work shall be charged to maintenance expense.
107, 157 Boilers.
This account shall include the cost of boilers, including accessories
and attachments such as injectors, water gages, steam gages and
fittings, and the cost of special boiler foundations and installations.
108, 158 Pumping equipment.
This account shall include the cost of engines, motors, pumps, and
all other pumping equipment, and the cost of special foundations and
installation.
109, 159, 179 Machine tools and machinery.
This account shall include the cost of machine tools and machinery,
including the cost of their special foundations and installation.
110, 160 Other station equipment.
This account shall include the cost of all station equipment not
provided for elsewhere, such as electric light, gas, and refrigeration
equipment, manifolds, and miscellaneous equipment and fittings. It
shall also include the carrier's investment in tracks if located at and
used in connection with a station.
111, 161 Oil tanks.
This account shall include the cost of oil tanks, including grades,
roofs, fire banks, steam coils, swing pipes, inlet valves, and outlet
valves.
112, 162 Delivery facilities.
This account shall include the cost of facilities for receiving or
delivering oil and oil products from or to water carriers, railroads,
motor carriers, and others, such as delivery racks, wharves (including
buildings thereon), docks, and slips, including piling, pile protection,
cribs, cofferdams, walls, and other necessary devices and apparatus for
the operation or protection of such property. It shall also include the
cost of engines, pumps, and boilers at loading racks and on wharves, the
construction of oil-pipe lines between oil tanks and delivery
facilities, and the carrier's investment in tracks if located at and
used in connection with delivery facilities.
113, 163, 183 Communication systems.
This account shall include the cost of telegraph, wireless,
telephone, and radio equipment.
114, 164, 184 Office furniture and equipment.
This account shall include the cost of all office furniture,
equipment and fixtures, including such items as safes, desks, chairs,
typewriters, accounting machines, cabinets, file cabinets, floor
coverings, portable air conditioners, drinking fountains, and other
similar items that are not an integral part of a building.
115, 165, 185 Vehicles and other work equipment.
This account shall include the cost of motor and other vehicles,
motor and other portable work equipment, garage equipment, and portable
tools and machines such as drills, hoists, jacks, power mowers, stocks
and dies, laying tongs, vises, air compressors, welding machines, valve
reseating machines, pipe-cleaning machines, and concrete mixers, not
specifically provided for in other accounts.
116, 166, 186 Other property.
This account shall include the cost of property used in pipeline
operations not provided for elsewhere.
187 Construction work in progress.
This account shall include the cost of carrier property under
construction and the cost of land acquired for such construction as of
the date of the balance sheet. It includes interest and taxes during
construction, material and supplies delivered to the construction site,
and other expenditures that will eventually be part of the cost of the
completed property. When construction work is completed, the cost
included in this account shall be transferred to the appropriate primary
property accounts. Subsidiary records shall be maintained for each
construction project. When part of a project under construction is
completed and put into service, the costs applicable to that portion
shall be transferred to the appropriate property account.
18 CFR 351.1 Operating Revenues
200 Gathering revenues.
This account shall include revenues on the basis of tariff charges
for the gathering or collection of crude oil, oil products and other
commodities.
210 Trunk revenues.
This account shall include revenues on the basis of tariff charges
for trunk line transportation of crude oil, oil products or other
commodities.
220 Delivery revenues.
This account shall include revenues on the basis of tariff charges
for receiving, delivering, unloading and loading fees at carrier
terminal and delivery facilities.
230 Allowance oil revenue.
(a) This account shall include the current value of oil acquired
through tariff allowances taken into inventory or retained in the line
for operating oil supply, and the selling price of such oil sold not
previously recorded in inventory or operating oil supply.
(b) Profits and losses on sales of allowance oil from inventory or
operating supply shall be included in this account.
240 Storage and demurrage revenue.
This account shall include revenues on the basis of tariff charges
for the storage of oil; also demurrage charges incident to failure of
consignees to receive shipments promptly.
250 Rental revenue.
This account shall include the revenues from renting or subrenting
property, the cost of which is included in the accounts for investment
in carrier property.
260 Incidental revenue.
This account shall include revenues incidental to carrier operations
and not includible in other revenue accounts.
18 CFR 351.1 Operating Expenses
18 CFR 351.1 Operations
300 Salaries and wages.
This account shall include the salaries and wages (including pay for
holidays, vacations, sick leave, and similar payroll disbursements) of
supervisory and other personnel directly engaged in transportation
operations.
310 Supplies and expenses.
This account shall include the cost of supplies consumed and expended
in operations, including the expenses of aircraft and vehicle operation;
travel and other expenses of operating employees; and other related
expenses of operations.
320 Outside services.
This account shall include the cost of operating services provided by
other than company forces under contract, agreement or other
arrangement. The cost of services performed by affiliated companies
shall be segregated within the account.
330 Operating fuel and power.
This account shall include the cost of fuel and power consumed and
expended in operations. The cost of normal utilities services shall be
included herein when such costs are directly allocable to operations.
340 Oil losses and shortages.
(a) This account shall include the cost of settlements with shippers
for oil lost or undelivered due to operating causes during the course of
transportation.
(b) The value of oil gains from operations shall be credited to this
account at current value at time of determination of gain and charged to
oil inventory or operating supply.
18 CFR 351.1 Maintenance
400 Salaries and wages.
This account shall include the salaries and wages (including pay for
holidays, vacations, sick leave, and similar payroll disbursements) of
supervisory and other personnel directly engaged in the maintenance and
repair of transportation property.
410 Supplies and expenses.
This account shall include the cost of supplies consumed and expended
in support of the maintenance activity, including the expenses of
operating aircraft, vehicles, and work equipment; travel and other
expenses of maintenance employees; and other related maintenance
expense.
420 Outside services.
This account shall include the cost of maintenance services provided
by other than company forces under contract agreement or other
arrangement. The cost of services performed by affiliated companies
shall be segregated within the account.
430 Maintenance materials.
This account shall include the cost of materials applied in the
repair and maintenance of transportation property. The salvage value of
materials recovered in maintenance work shall be credited to this
account.
18 CFR 351.1 General
500 Salaries and wages.
This account shall include the salaries and wages (including pay for
holidays, vacations, sick leave, and similar payroll disbursements) of
executives and general officers, general office personnel, and of other
employees whose wages cannot be directly allocated to operations or
maintenance.
510 Supplies and expenses.
This account shall include the cost of supplies consumed and expended
for administration and general services, including the expenses of
aircraft and vehicles used for general purposes; travel and other
expenses of general employees and officers; utilities services; and
all other incidental general expenses.
520 Outside services.
This account shall include the cost of management and general and
administrative services provided by other than company forces under
contract, agreement or other arrangement. The cost of services
performed by affiliated companies shall be segregated within the
account.
530 Rentals.
This account shall include the cost of renting property used in
carrier transportation service, such as a complete pipeline or segment
thereof, office space, land and buildings, and other equipment and
facilities.
540 Depreciation and amortization.
This account shall include charges for the depreciation and
amortization of transportation property. Charges for the amortization
of fixed term intangibles relating to common carrier operations shall
also be included herein.
550 Pensions and benefits.
This account shall include the cost to the carrier of annuities and
pensions for active or retired employees, their beneficiaries or
designees. Contributions to health or welfare funds or payment for
similar benefits to or on behalf of employees shall be included herein.
Premiums, to the extent borne by the carrier, for group life, health,
accident and other beneficial insurance for employees shall also be
included in this account.
560 Insurance.
(a) This account shall include the cost of commercial insurance to
protect the carrier against losses and damages in its pipeline
operations such as injuries to or deaths of employees and other persons,
damages to or destruction of carrier property or the property of others,
and other business risks and hazards pertaining to transportation
operations.
(b) The carrier shall not accrue amounts for the purpose of
estimating risk of loss or damage to its property from fire, theft, or
similar loss contingencies not covered by commercial insurance.
Note: Insurance or other reimbursement for loss or damage shall be
credited to the same account charged with the loss or expense.
(49 U.S.C. 304, 913, 1012)
(32 FR 20241, Dec. 20, 1967, as amended at 41 FR 32597, Aug. 4, 1976.
Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
570 Casualty and other losses.
(a) This account shall include the amount of expense sustained by the
carrier on account of loss or damage to oil or other commodity entrusted
to it for transportation or storage resulting from fire, flood, or other
casualty.
(b) Expenses on account of damage and destruction to property of
others from all causes; and the expense of repairing damages to
transportation property caused by casualty shall also be included
herein.
(c) This account shall also include expenses incurred on account of
injury to or death of employees or other persons including related
medical, hospital and funeral expenses.
Note: The cost of oil lost or undelivered through operating causes
shall be charged to account 340, Oil Losses and Shortages.
580 Pipeline taxes.
(a) This account shall include accruals for taxes of all kinds,
excepting income taxes (see definition 30(a)), relating to carrier
property, operations, privileges and licenses.
(b) The detail of this account shall show separately the amounts
levied by the Federal government and by each state.
(32 FR 20241, Dec. 20, 1967, as amended at 39 FR 33345, Sept. 17,
1974. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
18 CFR 351.1 Income Accounts
18 CFR 351.1 Ordinary Items
18 CFR 351.1 Credit
600 Operating revenues.
This account shall include the total revenues included in the
operating revenue accounts for the calendar year.
620 Income (net) from noncarrier property.
(a) This account shall include all noncarrier revenues and expenses
from property carried in account 34, Noncarrier Property.
(b) All expenses related to noncarrier property, such as operation
and maintenance expenses, depreciation, taxes (except Federal income
taxes) and similar expenses, are includible herein.
630 Interest and dividend income.
(a) This account shall include interest accruing to the carrier on
securities of others, loans, notes and advances, deposits, and all other
interest bearing assets. Also include the amount of amortized premium
or discount related to such assets.
(b) This account shall also include the amount of dividends declared
on stocks of others owned by the carrier.
(c) Income shall not be included in this account unless receipt
thereof is reasonably assured.
640 Miscellaneous income.
(a) This account shall include income not provided for elsewhere
creditable to income accounts for the current year, such as unclaimed
wages written off, profit on sales of land and noncarrier, property,
profit on sales of investment securities, profit from company bonds
reacquired, and decreases in the valuation allowance (contained within
account 11) for the marketable equity securities included in current
assets.
(b) Gains from extinguishment of debt shall be aggregated and, if
material, credited to account 680, Extraordinary Items, upon approval by
the Commission.
(32 FR 20241, Dec. 20, 1967, as amended at 40 FR 53248, Nov. 17,
1975; 42 FR 33298, June 30, 1977. Redesignated by Order 119, 46 FR
9044, Jan. 28, 1981)
645 Unusual or infrequent items (credit).
Included in this account shall be material items unusual in nature or
infrequent in occurrence, but not both, accounted for in the current
year in accordance with the text of instruction 1-6, upon approval by
the Commission.
(40 FR 53248, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
18 CFR 351.1 Debit
610 Operating expenses.
This account shall include the total expenses included in the
operating expense accounts for the calendar year.
650 Interest expense.
This account shall include interest expense on all classes of debt
except interest pertaining to construction of property. This account
shall also include the amortization of long-term debt premium and
discount. Charges for interest on carrier debt obligations previously
issued and now held by or for the carrier shall not be recorded in this
account.
660 Miscellaneous income charges.
(a) This account shall include income charges not provided for
elsewhere chargeable to income accounts for the current year, such as
amortization of debt expense, losses on sale or disposition of land and
noncarrier property, losses on sales or reductions in value of
investment securities (including increases in the valuation allowance
within account 11 for the marketable equity securities included in
current assets), bad debts, losses on company bonds reacquired, taxes
(other than Federal income taxes) on investment securities, trust
management expenses, amortization of intangibles which are not
restricted to a fixed term, and the difference between the premium and
the added cash surrender value of life insurance on officers and
employees when the carrier is beneficiary.
(b) Losses from extinguishment of debt shall be aggregated and, if
material, charged to account 680, Extraordinary Items, upon approval by
the Commission.
(32 FR 20241, Dec. 20, 1967, as amended at 37 FR 17714, Aug. 31,
1972; 40 FR 53248, Nov. 17, 1975; 42 FR 33298, June 30, 1977.
Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
665 Unusual or infrequent items (debit).
Included in this account shall be material items unusual in nature or
infrequent in occurrence, but not both, accounted for in the current
year in accordance with the text of instruction 1-6, upon approval by
the Commission.
(40 FR 53248, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
670 Income taxes on income from continuing operations.
(a) This account shall be debited with the monthly accruals for all
income taxes which are estimated to be payable and which are applicable
to ordinary income (see instruction 1-12). See the texts of account
695, Income Taxes on Extraordinary Items, account 710, Other Credits to
Retained Income, and account 720, Other Debits to Retained Income, for
recording other income tax consequences.
(b) Details pertaining to the tax consequences of other unusual and
significant items, and also cases where tax consequences are
disproportionate to related amounts included in income accounts, shall
be submitted to the Commission for consideration and decision as to
proper accounting.
(Interstate Commerce Act, 49 U.S.C. 20 (1976), Department of Energy
Organization Act, 42 U.S.C. 7155, 7172(b), 7295(a) (Supp. I 1977); E.
O. 12009, 42 FR 46267 (1977); Federal Energy Regulatory Commission,
Order No. 1, 42 FR 55450 (1977))
(32 FR 20241, Dec. 20, 1967, as amended at 39 FR 33345, Sept. 17,
1974; 40 FR 53248, Nov. 17, 1975; 44 FR 72161, Dec. 13, 1979.
Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
671 Provision for deferred taxes.
(a) This account shall include the net tax effect of all material
timing differences (see definitions 30 (g) and (e)) originating and
reversing in the current accounting period, and the future tax benefits
of loss carryforwards recognized in accordance with instruction 1-12(c).
(b) This account shall include credits for the amortization of the
investment tax credit if the carrier elected to use the deferred method
of accounting for the investment tax credit. (See instruction 1-12(d)).
(39 FR 33345, Sept. 17, 1974. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
18 CFR 351.1 Discontinued Operations
675 Income (loss) from operations of discontinued segments.
This account shall include the results of operations of a segment of
a business (see definition 32(a)), after giving effect to income tax
consequences that has been or will be discontinued in accordance with
the text of instruction 1-6, upon approval by the Commission.
(40 FR 53249, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
676 Gain (loss) on disposal of discontinued segments.
This account shall include the gain or loss from the disposal of a
segment of a business, after giving effect to income tax consequences,
in accordance with the text of instruction 1-6, upon approval by the
Commission.
(40 FR 53249, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
18 CFR 351.1 Extraordinary Items and Accounting Changes
680 Extraordinary items (net).
(a) This account shall include extraordinary items accounted for
during the current accounting year in accordance with the text of
instruction 1-6, upon submission of a letter from the carrier's
independent accountants, approving or otherwise commenting on the item
and upon approval by the Commission.
(b) This account shall be maintained in a manner sufficient to
identify the nature and gross amount of each debit and credit.
(c) Federal income tax consequences of charges and credits to this
account shall be recorded in account 695, Income Taxes on Extraordinary
Items, or account 696. Provision for Deferred Taxes -- Extraordinary
Items, as applicable.
(40 FR 53249, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
695 Income taxes on extraordinary items.
This account shall include the estimated income tax consequences
(debit or credit) assignable to the aggregate of items of both taxable
income and deductions from taxable income which for accounting purposes
are classified extraordinary, and are recorded in account 680,
Extraordinary Items (Net). The tax effect of any timing differences
caused by recognizing an item in the account provided for extraordinary
items in different periods in determining accounting income and taxable
income shall be included in acount 696, Provision for Deferred Taxes --
Extraordinary Items.
(40 FR 53249, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
696 Provision for deferred taxes -- extraordinary items.
This account shall include debits or credits for the current
accounting period for income taxes deferred currently, or for
amortization of income taxes deferred in prior accounting periods
applicable to items of revenue or expense included in account 680,
Extraordinary Items (Net) (See instruction 1-12).
(40 FR 53249, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
697 Cumulative effect of changes in accounting principles.
This account shall include the cumulative effect of changing to a new
accounting principle, after giving effect to income tax consequences, in
accordance with instruction 1-6, upon approval by the Commission.
(40 FR 53249, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
18 CFR 351.1 Retained Income Accounts
700 Net balance transferred from income.
This account shall include net income (or deficit) for the calendar
year.
705 Prior period adjustments to beginning retained income account.
This account shall include adjustments after giving income tax
effect, in accordance with the text of instruction 1-6, to the balance
in the retained income account at the beginning of the calendar year,
upon approval by the Commission.
(40 FR 53249, Nov. 17, 1975. Redesignated by Order 119, 46 FR 9044,
Jan. 28, 1981)
710 Other credits to retained income.
This account shall include other credit adjustments, net of assigned
Federal income taxes, not provided for elsewhere in this system but only
after such inclusion has been authorized by the Commission.
720 Other debits to retained income.
This account shall include losses from resale of reacquired capital
stock, and charges which reduce or write off discount on capital stock
issued by the company, but only to the extent that such charges exceed
credit balances in account 73, Additional Paid-In Capital, for shares
reacquired. This account shall also include other debit adjustments,
net of assigned Federal income taxes, not provided for elsewhere in this
system of accounts, but only after such inclusion has been authorized by
the Commission.
740 Appropriations of retained income.
This account shall include appropriations made from retained income
during the calendar year. Appropriations charged to this account shall
be credited to account 74, Appropriated Retained Income.
750 Dividend appropriations of retained income.
This account shall include the amount of dividends declared during
the calendar year on all classes of outstanding capital stock. Stock
reacquired and owned by the carrier shall not be subject to dividends.
Subsidiary records shall be kept to show separately the dividends
declared on each type and class of capital stock. When dividends are
paid in other than money, complete detail of each transaction shall be
maintained.
18 CFR 351.1 797 Form of Balance Sheet Statement
10 Cash.
10.5 Special deposits.
11 Temporary Investments.
12 Notes Receivable.
13 Receivables from Affiliated Companies.
14 Accounts Receivable.
15 Interest and Dividends Receivable.
16 Oil Inventory.
17 Material and Supplies.
18 Prepayments.
19 Other Current Assets.
19-5 Deferred Income Tax Charges.
Total current assets.
20 Investments in Affiliated Companies.
21 Other Investments.
22 Sinking and Other Funds.
23 Reductions in Security Values -- Credit.
24 Allowance for Net Unrealized Loss on Noncurrent Marketable Equity
Securities -- Credit.
Total investments and special funds.
30 Carrier Property.
31 Accrued Depreciation -- Carrier Property.
32 Accrued Amortization -- Carrier Property.
33 Operating Oil Supply.
34 Noncarrier Property.
35 Accrued Depreciation -- Noncarrier Property.
Total tangible property.
40 Organization Costs and Other Intangibles.
41 Accrued Amortization of Intangibles.
43 Miscellaneous Other Assets.
44 Other Deferred Charges.
45 Accumulated deferred income tax charges.
Total other assets and deferred charges.
Total Assets.
50 Notes Payable.
51 Payables to Affiliated Companies.
52 Accounts Payable.
53 Salaries and Wages Payable.
54 Interest Payable.
55 Dividends Payable.
56 Taxes Payable.
57 Long-Term Debt Payable Within One Year.
58 Other Current Liabilities.
59 Deferred income tax credits.
Total current liabilities.
60 Long-Term Debt Payable After One Year.
61 Unamortized Premium on Long-Term Debt.
62 Unamortized Discount and Interest on Long-term Debt.
63 Other Noncurrent Liabilities.
64 Accumulated deferred income tax credits.
Total noncurrent liabilities.
Total Liabilities.
70 Capital Stock.
71 Premiums on Capital Stock.
72 Capital Stock Subscriptions.
73 Additional Paid-In Capital.
74 Appropriated Retained Income.
75 Unappropriated Retained Income.
75-5 Unrealized Loss on Noncarrier Marketable Equity Securities.
Total Stockholders' Equity.
Total Liabilities and Stockholders' Equity.
76 Treasury stock.
Total Stockholders' Equity.
18 CFR 351.1 798 Form of Income Statement
600 Operating Revenues.
610 Operating Expenses.
Net carrier operating income.
620 Income (Net) from Noncarrier Property.
630 Interest and Dividend Income (dividends from other than
affiliates).
640 Miscellaneous Income.
645 Unusual or Infrequent Items (Credit).
650 Interest Expense.
660 Miscellaneous Income Charges.
Income from affiliated companies.
Dividends. Equity in undistributed earnings. (losses)
Total other income and deductions.
665 Unusual or Infrequent Items (Debit).
670 Federal Income Taxes on Income from Continuing Operations.
671 Provision for deferred taxes.
675 Income (Loss) from Operations of Discontinued Segments. (Less
Applicable Income Taxes of $ ---- ).
676 Gain (Loss) from Disposition of Discontinued Segments (Less
Applicable Income Taxes of $ ---- ).
Income (Loss) before Extraordinary Items.
680 Extraordinary items (net).
695 Income Taxes on Extraordinary Items.
696 Provision for Deferred Taxes -- Extraordinary Items.
697 Cumulative Effect of Changes in Accounting Principles (Less
Applicable Income Taxes of $ ---- ).
Net Income (Loss).
18 CFR 351.1 799 Form of Unappropriated Retained Income Statement
75 Unappropriated retained income (beginning of year).
700 Net balance transferred from income.
705 Prior Period Adjustments to Beginning Retained Income Account.
710 Other credits to retained income.
720 Other debits to retained income.
740 Appropriations of retained income.
750 Dividend appropriations of retained income.
75 Unappropriated retained income (end of year).
(32 FR 20241, Dec. 20, 1967, as amended at 37 FR 17714, Aug. 31,
1972; 39 FR 33345, Sept. 17, 1974; 39 FR 34044, Sept. 23, 1974; 40 FR
53249, Nov. 17, 1975; 41 FR 52467, Nov. 30, 1976; 42 FR 33298, June
30, 1977. Redesignated by Order 119, 46 FR 9044, Jan. 28, 1981)
18 CFR 351.1 SUBCHAPTER R -- APPROVED FORMS, INTERSTATE COMMERCE ACT
18 CFR 351.1 PART 356 -- PRESERVATION OF RECORDS
Sec.
356.1 Applicability.
356.2 Purpose.
356.3 Designation of supervisory official.
356.4 Availability of records.
356.5 Protection and storage of records.
356.6 Preservation of records.
356.7 Destruction of records.
356.8 Photographic copies.
356.9 Companies going out of business.
356.10 Waiver of requirements of these regulations.
356.11 Schedule of records and periods of retention.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (1982): Interstate Commerce Act, 49 U.S.C. 1-27 (1976); E.O.
12009, 3 CFR 142 (1978).
Source: Order 119, 46 FR 9044, Jan. 28, 1981, unless otherwise
noted.
18 CFR 356.1 Applicability.
Before destroying any operating, accounting, or financial papers,
records, books, blanks, tickets, stubs, correspondence, reports, or
documents the pipeline companies and persons subject to the provisions
of the Interstate Commerce Act shall comply with the regulations in this
part. This part applies to the preservation of accounts, records, and
memoranda of traffic associations, demurrage and car service bureaus,
weighing and inspection bureaus, and other joint activities maintained
by or on behalf of companies listed in the above paragraph of this
subpart.
18 CFR 356.2 Purpose.
The regulations in this part prescribe the minimum length of time
records shall be preserved, after which they may be destroyed. Mention
of a record imposes no requirement that such a record be maintained if
the information recorded is not requested by provisions of the
Interstate Commerce Act or this Commission, or if its purpose is
otherwise being adequately served. The provisions of this part shall
not be construed as excusing compliance with the lawful requirements of
any other governmental body, Federal or State, prescribing longer
retention periods for any category of records.
18 CFR 356.3 Designation of supervisory official.
(a) Each company subject to the provision of this part shall appoint
an officer or other responsible employee to supervise the preservation
and authorized destruction of records. Such appointment shall be by
formal corporate act of the Board of Directors or its executive
committee or, if the company is not incorporated, by formal designation
of the owners.
(1) Designation may be made by title only, rather than by name and
title, and thus obviate the necessity for a new resolution or order each
time a successor is appointed.
(b) If the property of the company is in the hands of a trustee,
executor, administrator, or assignee, the officer or other responsible
employee supervising the preservation and destruction of records shall
be designated by such trustee, executor, administrator, or assignee.
(c) Authority to supervise the destruction of company records
maintained by an association, joint bureau, etc. may be delegated to
the manager or other chief officer.
(d) A company, at its option, may by a formal act of appointment
delegate to a bank, trust company, or similar institution having custody
of its records in the normal course of business, the authority to
destroy such records upon compliance with the requirements of
regulations in this part.
(e) Copies of the resolution or orders of appointment need not be
filed with the Commission but shall be available for inspection by the
Commission's duly authorized representatives.
18 CFR 356.4 Availability of records.
At each office where records are kept or stored, such records as are
herein required to be preserved shall be so arranged and filed so that
they may be readily identified and made available to representatives of
the Commission.
18 CFR 356.5 Protection and storage of records.
The company shall protect records subject to the regulations in this
part from fires, floods, and other hazards and safeguard the records
from unnecessary exposure to deterioration from excessive humidity,
dryness, or lack of ventilation.
18 CFR 356.6 Preservation of records.
(a) All records listed in 356.11 may be preserved in either
hard-copy paperstock or nonerasable microfilm (see 356.8). However, a
paperstock or microfilm record need not be created to satisfy the
requirements of this part if the particular records are initially
prepared on nonerasable media such as punched cards, magnetic tapes and
disks. The records maintained in nonreadable media and the underlying
data used in their preparation shall be preserved for the periods
prescribed in 356.11. In no case shall a paperstock or microfilm record
be destroyed after transfer to nonreadable media before expiration of
the prescribed periods of retention without Commission approval (see
356.7).
(b) Each nonreadable form of media shall be accompanied by a
statement clearly indicating the type of data included in the media and
certifying that the information contained therein is complete and
accurate. This statement shall be executed by a person having personal
knowledge of the facts contained in the records. The records shall be
indexed and retained in such a manner as will render them readily
accessible, and the company shall have facilities available to locate,
identify and reproduce the records on paper similar in size to the
orginal without loss of clarity.
18 CFR 356.7 Destruction of records.
(a) General authority. Records described in these regulations may be
destroyed after having been preserved for the prescribed periods.
(b) Special authority. Special authority is required before records
described in these regulations may be destroyed prior to the end of the
prescribed retention periods. Applications for special authority must
describe in detail the nature and purpose of the records in question and
the reasons continued retention is no longer considered necessary (see
356.10).
(c) Method of destruction These regulations require that records be
preserved for specified periods. Upon expiration of these periods,
records may be destroyed in any manner if the company so elects.
Precaution should be taken, however, to shred or otherwise destroy the
legibility of any records, the content of which is forbidden by law to
be divulged to unauthorized persons.
(d) Premature destruction or loss of records. When records are
destroyed or lost before the expiration of the prescribed retention
periods, a statement shall be prepared listing, as accurately as
possible, the records destroyed or lost and describing the circumstances
under which they were destroyed or lost. The statement shall be
certified by an officer of the carrier and filed with the officer having
supervision over preservation of records. A copy of the statement shall
also be filed with the Secretary's Office of this Commission within
ninety (90) days from the discovery of the premature destruction or
loss.
18 CFR 356.8 Photographic copies.
(a) Any record may be transferred to nonerasable microfilm (including
microfiche, computer output microfilm, and aperture cards) at any time.
Records so maintained on microfilm shall satisfy the mimimum
requirements listed in paragraphs (b) through (f) of this section.
(b) The microfilm used shall be of a quality that can be easily read
and that reproduction in paperstock can be similar in size of an
original without loss of clarity of detail during the periods the
records are required to be retained in 356.11.
(c) Microfilm records shall be indexed and retained in such a manner
as will render them readily accessible, and the company shall have
facilities available to locate, identify and read the microfilm and
reproduce in paper form.
(d) Any significant characteristic, feature, or other attribute which
microfilm will not preserve shall be clearly indicated at the beginning
of each roll of film or series of microfilm records if applicable to all
records on the roll or series, or on the individual record, as
appropriate.
(e) The printed side of printed forms need not be microfilmed for
each record if nothing has been added to the printed matter common to
all such forms, but an identified specimen of the form shall be on the
film for reference.
(f) Each roll of film or series of microfilm records shall include a
microfilm of a certificate stating that the photographs are direct and
facsimile reproductions of the original records and they have been made
in accordance with prescribed regulations. Such a certificate shall be
executed by a person having personal knowledge of the facts covered
therein. Where the microfilm is computer output microfilm the
certificate shall state that the information is complete and accurate.
18 CFR 356.9 Companies going out of business.
The records referred to in these regulations may be destroyed after
business is discontinued and the company is completely liquidated. The
records may not be destroyed until dissolution is final and all
transactions are completed. When a company is merged with another
company under jurisdiction of the Commission, the successor company
shall preserve records of the merged company in accordance with these
regulations.
18 CFR 356.10 Waiver of requirements of these regulations.
A waiver from any provision of these regulations may be made by the
Commission upon its own initiative or upon submission of a written
request by the company. Each request for waiver shall demonstrate that
unusual circumstances warrant a departure from prescribed retention
periods, procedures, or techniques, or that compliance with such
prescribed requirements would impose an unreasonable burden on the
company.
18 CFR 356.11 Schedule of records and periods of retention.
The following schedule shows periods that designated records shall be
preserved. The descriptions specified under the various general
headings are for convenient reference and identification, and are
intended to apply to the items named regardless of where records are
filed and regardless of departmental organization. Records other than
those listed below may be destroyed at the option of the company:
Provided, Such records used in place of those listed are preserved for
the periods prescribed for the records used for substantially similar
purposes.
(Order 119, 46 FR 9044, Jan. 28, 1981, as amended by Order 335, 48 FR
44484, Sept. 29, 1983; 48 FR 55121, Dec. 9, 1983; 49 FR 44629, Nov. 8,
1984)
18 CFR 356.11 PART 357 -- ANNUAL SPECIAL OR PERIODIC REPORTS: CARRIERS
SUBJECT TO PART I OF THE INTERSTATE COMMERCE ACT
Sec.
357.1 Common carriers.
357.2 FERC Form No. 6, Annual Report of Oil Pipeline Companies.
357.3 FERC Form No. 73, Oil Pipeline Data for Depreciation Analysis.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (1982); Interstate Commerce Act, 49 U.S.C. 1-27 (1976); E.O.
12009, 3 CFR Part 142 (1978).
18 CFR 357.1 Common carriers.
All common carriers by pipeline subject to the provisions of Part I
of Interstate Commerce Act, as amended, are hereby required hereinafter
to file in the office of the Commission on or before the 31st day of
March in each year, reports covering the period of 12 months ending with
the 31st day of December preceding said date, giving the particulars
heretofore called for in the annual reports required by the Commission
of said carriers.
(Order 119, 46 FR 9051, Jan. 28, 1981)
18 CFR 357.2 FERC Form No. 6, Annual Report of Oil Pipeline Companies.
Every carrier by pipeline subject to the provisions of section 20 of
the Interstate Commerce Act must file with the Commission copies of FERC
Form No. 6, ''Annual Report of Oil Pipeline Companies'' pursuant to the
General Instructions set out in that form. This report must be filed on
or before March 31st of each year for the previous calendar year,
beginning with the year ending December 31, 1982.
(Order 260, 47 FR 42331, Sept. 27, 1982)
18 CFR 357.3 FERC Form No. 73, Oil Pipeline Data for Depreciation
Analysis.
(a) Who must file. Any oil pipeline company directed by the
Commission to file service life data during an investigation of its book
depreciation rates.
(b) When to submit. Service life data is reported to the Commission
by an oil pipeline company ony during a depreciation rate investigation.
(c) What to submit. The format and data which must be submitted are
prescribed in FERC Form No. 73, Oil Pipeline Data for Depreciation
Analysis, available for review at the Commission's Public Reference
Section, Room 1000, 825 North Capitol Street, NE., Washington, DC 20426.
(Order 456, 51 FR 35509, Oct. 6, 1986)
18 CFR 357.3 SUBCHAPTER S -- VALUATION, INTERSTATE COMMERCE ACT
Note: Forms prescribed in Parts 360 through 362 are available upon
request from the Office of the Secretary, Federal Energy Regulatory
Commission, 825 North Capitol Street, NE., Washington DC 20426.
18 CFR 357.3 PART 360 -- REPORTING OF DATA FOR INITIAL PIPELINE
VALUATION
Sec.
360.1 Regulations prescribed.
360.2 Data to be filed.
360.3 Responsibility for filing data.
360.4 Copies required.
360.5 Carrier and noncarrier property defined.
360.6 Original cost defined.
360.7 Reporting overhead expenditures.
360.8 Reporting cost of organization.
360.9 Valuation sections.
360.10 Auxiliary documents.
360.11 Assembling and numbering forms.
360.12 Amendments and deviations.
360.100 ACV Form No. 5 -- Inventory of Property Other Than Land and
Rights-of-Way.
360.101 ACV Form No. 6 -- Inventory of Land and Rights-of-Way.
360.102 ACV Form No. 7 -- Summary of Original Cost of Inventory.
360.103 ACV Form No. 8 -- Cost Data for Equipment and Tanks.
360.104 ACV Form No. 9 -- Cost Data for Pipeline Construction.
360.105 Maps.
360.106 Plot plans.
360.107 Sketches.
360.108 Photographs.
360.109 Special notes.
360.110 Identification of aids, gifts, grants or donations.
360.111 Reconciliations.
360.112 Corporate history and development of fixed physical property.
Authority: Department of Energy Organization Act, 42 U.S.C.
7101-7352 (1982); Interstate Commerce Act, 49 U.S.C. 1-27 (1976); E.O.
12009, 3 CFR 142 (1978).
Source: 32 FR 20475, Dec. 20, 1967. Redesignated and amended by
Order 119, 46 FR 9051, Jan. 28, 1981, unless otherwise noted.
18 CFR 357.3 General
18 CFR 360.1 Regulations prescribed.
Each common carrier by pipeline, subject to the provisions of the
Interstate Commerce Act, for which an initial valuation is to be found
by the Commission is required to comply with regulations in this Part
pertaining to the preparation and filing of data with the Commission for
its consideration in finding such initial valuation. The data to be
filed shall be reported separately by ownership and use, by states, and
by primary property accounts, as hereinafter prescribed.
18 CFR 360.2 Data to be filed.
(a) Except as may be otherwise directed by the Commission, the
following data shall be filed:
ACV Form No. 5 -- Inventory of Property Other than Land and
Rights-of-Way.
ACV Form No. 6 -- Inventory of Land and Rights-of-Way.
ACV Form No. 7 -- Summary of Original Cost of Inventory.
ACV Form No. 8 -- Cost Data for Equipment and Tanks.
ACV Form No. 9 -- Cost Data for Pipeline Construction.
Maps.
Plot plans.
Sketches.
Photographs.
Special notes.
Identification of aids, gifts, grants or donations.
Reconciliations.
Corporate history and development of fixed physical property.
(b) All worksheets and other underlying support of data filed shall
be retained by carriers in such manner that they may be readily
verified.
(32 FR 20475, Dec. 20, 1967. Redesignated and amended by Order 119,
46 FR 9051, Jan. 28, 1981; 49 FR 44629, Nov. 8, 1984)
18 CFR 360.3 Responsibility for filing data.
It shall be the responsibility of the carrier for which an initial
valuation is to be found by the Commission to file the data prescribed
by this order. This responsibility shall apply whether property
included in the initial inventory is wholly or jointly owned and used,
wholly or jointly owned but not used, or wholly or jointly used but not
owned, or whether such property is a part of a ''system'' or otherwise.
As used in these regulations, the term ''agent operator'' refers only to
a carrier for which an initial valuation is to be found by the
Commission.
18 CFR 360.4 Copies required.
The data referred to in 360.2 shall be filed with the Commission in
an original only, and one copy shall be retained by carriers. However,
copies of ACV Forms prepared by other than the filing carrier may be
filed in lieu of originals.
18 CFR 360.5 Carrier and noncarrier property defined.
Carrier property is that which is used exclusively for common-carrier
purposes. Noncarrier property is that which is used exclusively for
purposes other than those of a common carrier. Property held in
anticipation of an indefinite future use, and property which is owned by
a common carrier and is leased to other than a common carrier shall be
reported as noncarrier property. Classification of property under this
definition shall be consistent with the classification of property for
accounting purposes.
18 CFR 360.6 Original cost defined.
(a) Original cost means the actual cost of construction or
acquisition of property to the first person or corporation dedicating
such property to public use. Interpretive examples of this definition
follow:
(1) Where an entire property, or portion thereof, is acquired from
another common carrier by purchase, merger, consolidation, or
reorganization, the cost of the property, estimated if not known, to the
vendor shall be construed to be the original cost of the property
acquired.
(2) Where property which has not been previously dedicated to public
use is acquired, the cost of acquisition to the vendee shall be regarded
as the original cost of the property acquired.
(3) Where the actual cost of property acquired by lease from a
noncarrier and placed in public use by a carrier is not obtainable, the
estimated cost of such property, as of the date of the lease, shall be
used as the original cost.
(b) Where estimated original cost is used it shall be prorated among
the primary accounts on an equitable basis, and a notation shall be made
that estimates were used, together with an explanation of the method
employed in arriving at such estimates.
18 CFR 360.7 Reporting overhead expenditures.
To assure against the double inclusion of overhead in the
determination by the Commission of the cost of reproduction new of the
inventory of carrier property, overhead expenditures shall be reported
separately under the caption ''Overhead,'' in complete detail for each
account for each valuation section, and shall be reported on ACV Form
No. 5 and on ACV Form No. 6 immediately following the last original
cost amount stated on these forms in accordance with 360.100 and
360.101. The term overhead, as used in these regulations, shall be
construed as consisting of those expenditures incurred in connection
with the construction or acquisition of property which were applicable
to a period prior to the date that the property to which they relate was
placed in operation. Examples of such expenditures are interest during
construction, engineering cost, taxes on physical property, etc.
18 CFR 360.8 Reporting cost of organization.
Cost of organization shall be reported, in complete detail by
category of expenditure, on a separate ACV Form No. 5 which shall be
headed ''Account No. 40 Cost of Organization.'' The total of amounts
shown shall be reported on ACV Form No. 7 in accordance with
instructions appearing in 360.102.
(32 FR 20475, Dec. 20, 1967. Redesignated and amended by Order 119,
46 FR 9051, Jan. 28, 1981; 49 FR 44629, Nov. 8, 1984)
18 CFR 360.9 Valuation sections.
A valuation section is a geographical segregation of property within
a state, and in no case may a valuation section extend beyond a state
line. Separate valuation sections shall be established within each
state for each group of property identified in the Uniform System of
Accounts for Pipe Line Companies as ''Gathering Lines,'' ''Trunk
Lines,'' and ''General.'' Valuation sections so established shall be
numbered and shall bear the corresponding identifying suffix G for
gathering line property, T Crude or T Prods. for trunkline property,
and Gen. for property classified as general. Jointly owning or jointly
using carriers, and carriers wholly using property owned by others,
shall assign their own valuation section numbers to property so owned or
used. Mobile property servicing more than one valuation section of a
state shall not be assigned to a valuation section but shall be reported
as ''Unallocated'' for the state served. Mobile property servicing more
than one state shall not be assigned to a valuation section but shall be
reported as ''Unallocated'' for the carrier as a whole without state
identity. Valuation section numbers and unallocated designations shall
be decided by each carrier, subject to the approval of the Commission.
18 CFR 360.10 Auxiliary documents.
The following documents referred to in these regulations will be
supplied by the Valuation Branch, Office of Pipeline and Producer
Regulation:
1947 Period Guide Prices and Annual and Period Indices.
Schedule of Element Codes and Guide Service Lives for Oil Pipeline
Property.
ACV Forms No. 5, No. 6, No. 7, No. 8, and No. 9.
(32 FR 20475, Dec. 20, 1967. Redesignated and amended by Order 119,
46 FR 9051, Jan. 28, 1981; 49 FR 44629, Nov. 8, 1984)
18 CFR 360.11 Assembling and numbering forms.
Related ACV Forms No. 5, 6, and 7 shall be associated, with ACV
Forms No. 5 and 6 following ACV Form No. 7. ACV Forms No. 8 and 9
shall then be placed behind ACV Forms No. 5, 6, and 7. All ACV Forms
thus assembled shall then be consecutively numbered in the upper
right-hand corner. There shall also be shown in the upper right-hand
corner of the ACV Form numbered 1 the total number of ACV Forms filed.
18 CFR 360.12 Amendments and deviations.
Only those amendments to or deviations from the regulations
prescribed by this Order as may be directed by the Commission are
authorized.
(32 FR 20475, Dec. 20, 1967. Redesignated and amended by Order 119,
46 FR 9051, Jan. 28, 1981; 49 FR 44629, Nov. 8, 1984)
18 CFR 360.12 Preparation of Data
18 CFR 360.100 ACV Form No. 5 -- Inventory of Property Other Than Land
and Rights-of-Way.
(a) This is a multipurpose form designed to meet the needs of both
the carriers and the Commission. Columns 1 through 7 shall be used by
carriers to document the inventory. The remaining columns will be
completed by the Commission.
(b) A separate ACV Form No. 5 shall be filed bearing the following
statement which shall be signed by a responsible officer of the carrier,
or agent, filing the data prescribed by these regulations:
The data filed pursuant to Valuation Order No. 29 have been
carefully examined by the undersigned who declares that such data have
been prepared in accordance with regulations set out in said Order.
(Signature)
(Title)
(Date)
(c) A pipeline mileage statement shall be presented on ACV Form No.
5, in the following format, on Sheet No. 1 of each valuation section,
summarizing the pipeline footage included in the inventory. The gross
and screwage shown on the statement shall represent the pipe footage
reported on ACV Forms No. 5 documenting the inventory:
(d) Inventory data to be shown on ACV Form No. 5 shall be reported
in summary form by kind of property within each account. By summary
reporting is meant the grouping of property units having characteristics
common to all such units. An example of summary reporting appears in
paragraph (e) of this section.
(e) The number of units to be reported in column 6 of ACV Form No. 5
shall be governed by the applicability to such units of the identifying
data shown in columns 1 through 5. Taking steel pipe as an example, the
units of pipe to be reported in column 6 must be of the same
construction, that is, either plain end or screw end, lap weld, electric
weld, seamless, etc., and they must have the same diameter and weight in
pounds per foot (all these identifications will appear in column 1);
they must have been dedicated to public use in the same year (column 2);
they must be includible in the same element code (column 3); they must
have the same guide life years (column 4); and they will have a common
unit of property, linear feet (column 5).
(f) ACV Form No. 5 shall be prepared by typewriter without
interlineation as follows:
(1) Enter the date assigned for the valuation of the property on the
line provided in the caption of the form.
(2) Carrier Property Noncarrier Property. Place an X in the
appropriate block to identify the property being reported.
(3) Account No. ---- . Enter the appropriate primary account
number. When ACV Form No. 5 is used to report noncarrier property, the
primary property account numbers used to report carrier property shall
also be employed to facilitate the identification of such property.
(4) State ------ Val. Sec. ------ . Identify the state and the
valuation section in which the property is located. Enter
''Unallocated'' when appropriate.
(5) Sheet No. ---- of ---- Sheets. The use of this line shall be
restricted to identifying the sheets relating to the valuation section
or Unallocated, as appropriate.
(6) Report Filed by ------ Property Owned by ------ Property Used by
------ . Identify, respectively, the carrier or agent filing the
report, the owner of the property, and the carrier using the property.
When the form is used to report jointly owned or jointly used property,
enter an asterisk (*) on the Property Owned by ------ and Property Used
by ------ lines of Sheet No. 1 of each valuation section, or
Unallocated, and below, in the body of the form, the identity of both
the owning and the using carriers and the percentage of their respective
owning and using interest. Enter an asterisk on these two lines on all
remaining sheets to indicate that the identity of the owning and using
carriers is set out on Sheet No. 1.
(7) Columns 1 and 5. The property description and unit of property
to be shown in these columns shall conform with those appearing in the
1947 Period Guide Prices and Annual and Period Indices. Where property
descriptions do not appear in that document or where, in the view of the
carrier, they are inadequate, they shall be shown in column 1 in
sufficient detail to clearly describe the property being reported.
Identify, in column 1, property representing public improvement
projects, and show the total cost of the project, the identity of the
participants, and the percentage of participation, in addition to the
description of the property. Identify also in column 1 property
included in the inventory, other than land and rights-of-way, which was
acquired by aid, gift, grant or donation from private parties. See
paragraph (11)(vii) below for instructions covering the reporting of
original cost for public improvement projects and for aids, gifts,
grants or donations received from private parties. Except for service
pipe, show in column 1 the screwage included in the gross linear footage
reported in column 6 for pipe in accounts 103, 153, 110, 160, 112 and
162.
(8) Column 2. Show the year the property was dedicated to public
use. Where the year, or years, of construction or installation differ
from the year of dedication to public use show the former in column 1,
together with the number of units constructed or installed during such
years.
(9) Columns 3 and 4. The data to be entered in these columns shall
be taken from the Schedule of Element Codes and Guide Service Lives for
Oil Pipeline Property. Guide life years shall not be shown for property
reported under accounts 104, 105, 154, and 155, or for property reported
under element code 124 of accounts 111 and 161. Use guide lives other
than those shown in the Schedule of Element Codes and Guide Service
Lives for Oil Pipeline Property only when specifically authorized by the
Valuation Branch.
(10) Column 6. Enter the total number of units of property referred
to in columns 1 through 5. See example of summary reporting appearing
in (e) of this section. Where the unit reported in column 5 is ''Lot''
make no entry in this column.
(11) Column 7. Report, to the nearest dollar, in this column, in the
manner directed in (i) through (v) below, the original cost, exclusive
of overhead which shall be reported in accordance with 360.7, of the
property identified in Columns 1 through 6. With the exception of
cathodic protection reported separately under element code 24, include
the cost of cathodic protection with the cost of the property reported:
(i) Report a single total for the entire valuation section for each
of the following accounts: 103, 104, 109, 114, 153, 154, 159, 164, 179,
and 184.
(ii) Report a single total for the entire valuation section for each
of the following element codes: 26, 128, 150, 154, 156, 174, 176, 178,
and each element code assigned to other accounts when such element codes
are used to identify property reported under accounts 116, 166 and 186.
(iii) Enter a single total for the entire valuation section for each
of the following portions of element codes: cathodic protection
reported under element code 24; the installation of oil lines in
stations reported under element code 24; ordinary casing installations
at railroad or highway crossings reported under element code 24; with
the exception of river crossings, pipeline bridges and unusual
construction jobs, all other pipeline construction reported under
element code 24 not enumerated in this paragraph: oil pipe in place
reported under element code 96; fittings in place reported under
element code 96; service pipe in place reported under element code 98;
fittings in place reported under element code 98; the miscellaneous
portion of element code 124; oil pipe in place reported under element
code 130; and fittings in place reported under element code 130. When
reporting clearing and grubbing under element code 24 include only those
expenditures for areas where it is necessary to remove trees and heavy
brush, and not for the entire right-of-way prior-to-ditching grading.
(iv) Enter a separate total for the following:
Accounts 105 and 155. Each river crossing, pipeline bridge, or each
unusual construction job such as one involving long stretches of solid
rock or swamp areas or an unusual casing installation, reported under
element code 24; and each type of coating reported under element code
28.
Accounts 106, 156, and 176. Each building, station ground or bridge.
Include communication system buildings and grounds.
Accounts 107, 108, 157, and 158. Each unit, or group of units,
reported in accordance with paragraph (10) above.
Accounts 110, 112, 160, and 162. All of the property for each
station reported under each of the element codes 100, 102, 132, 134,
136, 138, and 140.
Accounts 111 and 161. Each unit, or group of units, reported in
accordance with paragraph (10) above. Exclude the miscellaneous portion
of element code 124 and all of element code 128.
(v) Report the original cost of each unit of property, or each group
of those units of property which are identical, which has not been
specifically identified in paragraphs (i) through (iv) above, or for
which a description and unit price has not been provided in the 1947
Period Guide Prices and Annual and Period Indices.
(vi) The following chart, presenting graphically the reporting
requirements set out in paragraphs (i) through (v) above, is provided
for ready reference. Portions of prescribed elements, only, have been
identified in the column captioned ''Element -- Subtitle.''
(vii) In reporting original cost in accordance with paragraphs (i)
through (vi) above include for property acquired by aid, gift, grant or
donation from private parties, identified in column 1 in accordance with
paragraph (7) above, the cost of such property, or the appraised value
where the cost cannot be determined; in the case of property identified
as a public improvement project in column 1 in accordance with paragraph
(7) above, include only the cost borne by the carrier.
(12) When ACV Form No. 5 has been completed for each account, show
the total of all amounts entered in column 7. In the case of jointly
owned or jointly used property apply the owning or using percentages,
shown on Sheet No. 1, to the total and identify the results by each
jointly owning or jointly using carrier.
(g) ACV Forms No. 5 prepared by agent operators for ''system''
property as a whole, together with related ACV Forms No. 5 showing the
proportionate share of the original cost of such property applicable to
each jointly owning or jointly using carrier, shall be filed with the
Commission for review and completion.
(h) Following review and completion by the Commission of ACV Forms
No. 5 filed by agent operators in accordance with paragraph (g) of this
section, agent operators will be supplied with photocopies of all ACV
Forms No. 5 for ''system'' property as a whole, and with photocopies of
all ACV Forms No. 5 showing proportionate shares of original cost on
which corrections are made by the Commission. Agent operators shall
then provide each jointly owning or jointly using carrier with two
copies of its ''proportionate share'' ACV Forms No. 5, one to be
retained and one to be filed with the Commission.
(i) Following their review and completion by the Commission ACV Forms
No. 5 will be made available for required photocopying by wholly owning
or wholly using carriers.
(32 FR 20475, Dec. 20, 1967. Redesignated and amended by Order 119,
46 FR 9051, Jan. 28, 1981; 49 FR 44629, Nov. 8, 1984)