Section

[Code of Federal Regulations]
[Title 17, Volume 2]
[Revised as of April 1, 2001]
From the U.S. Government Printing Office via GPO Access
[CITE: 17CFR210.4-10]

[Page 256-263]

TITLE 17--COMMODITY AND SECURITIES EXCHANGES

CHAPTER II--SECURITIES AND EXCHANGE COMMISSION

PART 210--FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL STATEMENTS,

Sec. 210.4-10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and
Conservation Act of 1975.

This section prescribes financial accounting and reporting standards
for registrants with the Commission engaged in oil and gas producing
activities in filings under the Federal securities laws and for the
preparation of accounts by persons engaged, in whole or in part, in the
production of crude oil or natural gas in the United States, pursuant to
section 503 of the Energy Policy and Conservation Act of 1975 (42 U.S.C.
6383) (EPCA) and section 11(c) of the Energy Supply and Environmental
Coordination Act of 1974 (15 U.S.C. 796) (ESECA), as amended by section
505 of EPCA. The application of this section to those oil and gas
producing operations of companies regulated for ratemaking purposes on
an individual-company-cost-of-service basis may, however, give
appropriate recognition to differences arising because of the effect of
the ratemaking process.

Exemption. Any person exempted by the Department of Energy from any
record-keeping or reporting requirements pursuant to section 11(c) of
ESECA, as amended, is similarly exempted from the related provisions of
this section in the preparation of accounts pursuant to EPCA. This
exemption does not affect the applicability of this section to filings
pursuant to the Federal securities laws.

Definitions

(a) Definitions. The following definitions apply to the terms listed
below as they are used in this section:
(1) Oil and gas producing activities. (i) Such activities include:
(A) The search for crude oil, including condensate and natural gas
liquids, or natural gas (oil and gas) in their natural states and
original locations.
(B) The acquisition of property rights or properties for the purpose
of further exploration and/or for the purpose of removing the oil or gas
from existing reservoirs on those properties.
(C) The construction, drilling and production activities necessary
to retrieve oil and gas from its natural reservoirs, and the
acquisition, construction, installation, and maintenance of field
gathering and storage systems--including lifting the oil and gas to the
surface and gathering, treating, field processing (as in the case of
processing gas to extract liquid hydrocarbons) and field storage. For
purposes of this section, the oil and gas production function shall
normally be regarded as terminating at the outlet valve on the lease or
field storage tank; if unusual physical or operational circumstances
exist, it may be appropriate to regard the production functions as
terminating at the first point at which oil, gas, or gas liquids are
delivered to a main pipeline, a common carrier, a refinery, or a marine
terminal.
(ii) Oil and gas producing activities do not include:
(A) The transporting, refining and marketing of oil and gas.

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(B) Activities relating to the production of natural resources other
than oil and gas.
(C) The production of geothermal steam or the extraction of
hydrocarbons as a by-product of the production of geothermal steam or
associated geothermal resources as defined in the Geothermal Steam Act
of 1970.
(D) The extraction of hydrocarbons from shale, tar sands, or coal.
(2) Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes
in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil and/or oil-water contacts,
if any, and (B) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically productive on the basis
of available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are included
in the proved classification when successful testing by a pilot project,
or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program was
based.
(iii) Estimates of proved reserves do not include the following: (A)
Oil that may become available from known reservoirs but is classified
separately as indicated additional reserves; (B) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics,
or economic factors; (C) crude oil, natural gas, and natural gas
liquids, that may occur in undrilled prospects; and (D) crude oil,
natural gas, and natural gas liquids, that may be recovered from oil
shales, coal, gilsonite and other such sources.
(3) Proved developed oil and gas reserves. Proved developed oil and
gas reserves are reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a pilot project or after
the operation of an installed program has confirmed through production
response that increased recovery will be achieved.
(4) Proved undeveloped reserves. Proved undeveloped oil and gas
reserves are reserves that are expected to be recovered from new wells
on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should
estimates for proved undeveloped reserves be attributable to any acreage
for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same reservoir.
(5) Proved properties. Properties with proved reserves.
(6) Unproved properties. Properties with no proved reserves.
(7) Proved area. The part of a property to which proved reserves
have been specifically attributed.

[[Page 258]]

(8) Field. An area consisting of a single reservoir or multiple
reservoirs all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition. There may be two or
more reservoirs in a field that are separated vertically by intervening
impervious, strata, or laterally by local geologic barriers, or by both.
Reservoirs that are associated by being in overlapping or adjacent
fields may be treated as a single or common operational field. The
geological terms structural feature and stratigraphic condition are
intended to identify localized geological features as opposed to the
broader terms of basins, trends, provinces, plays, areas-of-interest,
etc.
(9) Reservoir. A porous and permeable underground formation
containing a natural accumulation of producible oil and/or gas that is
confined by impermeable rock or water barriers and is individual and
separate from other reservoirs.
(10) Exploratory well. A well drilled to find and produce oil or gas
in an unproved area, to find a new reservoir in a field previously found
to be productive of oil or gas in another reservoir, or to extend a
known reservoir. Generally, an exploratory well is any well that is not
a development well, a service well, or a stratigraphic test well as
those items are defined below.
(11) Development well. A well drilled within the proved area of an
oil or gas reservoir to the depth of a stratigraphic horizon known to be
productive.
(12) Service well. A well drilled or completed for the purpose of
supporting production in an existing field. Specific purposes of service
wells include gas injection, water injection, steam injection, air
injection, salt-water disposal, water supply for injection, observation,
or injection for in-situ combustion.
(13) Stratigraphic test well. A drilling effort, geologically
directed, to obtain information pertaining to a specific geologic
condition. Such wells customarily are drilled without the intention of
being completed for hydrocarbon production. This classification also
includes tests identified as core tests and all types of expendable
holes related to hydrocarbon exploration. Stratigraphic test wells are
classified as (i) exploratory-type, if not drilled in a proved area, or
(ii) development-type, if drilled in a proved area.
(14) Acquisition of properties. Costs incurred to purchase, lease or
otherwise acquire a property, including costs of lease bonuses and
options to purchase or lease properties, the portion of costs applicable
to minerals when land including mineral rights is purchased in fee,
brokers' fees, recording fees, legal costs, and other costs incurred in
acquiring properties.
(15) Exploration costs. Costs incurred in identifying areas that may
warrant examination and in examining specific areas that are considered
to have prospects of containing oil and gas reserves, including costs of
drilling exploratory wells and exploratory-type stratigraphic test
wells. Exploration costs may be incurred both before acquiring the
related property (sometimes referred to in part as prospecting costs)
and after acquiring the property. Principal types of exploration costs,
which include depreciation and applicable operating costs of support
equipment and facilities and other costs of exploration activities, are:
(i) Costs of topographical, geographical and geophysical studies,
rights of access to properties to conduct those studies, and salaries
and other expenses of geologists, geophysical crews, and others
conducting those studies. Collectively, these are sometimes referred to
as geological and geophysical or G&G costs.
(ii) Costs of carrying and retaining undeveloped properties, such as
delay rentals, ad valorem taxes on properties, legal costs for title
defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.
(16) Development costs. Costs incurred to obtain access to proved
reserves and to provide facilities for extracting, treating, gathering
and storing the oil and gas. More specifically, development costs,
including depreciation and applicable operating costs of support

[[Page 259]]

equipment and facilities and other costs of development activities, are
costs incurred to:
(i) Gain access to and prepare well locations for drilling,
including surveying well locations for the purpose of determining
specific development drilling sites, clearing ground, draining, road
building, and relocating public roads, gas lines, and power lines, to
the extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type
stratigraphic test wells, and service wells, including the costs of
platforms and of well equipment such as casing, tubing, pumping
equipment, and the wellhead assembly.
(iii) Acquire, construct, and install production facilities such as
lease flow lines, separators, treaters, heaters, manifolds, measuring
devices, and production storage tanks, natural gas cycling and
processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.
(17) Production costs. (i) Costs incurred to operate and maintain
wells and related equipment and facilities, including depreciation and
applicable operating costs of support equipment and facilities and other
costs of operating and maintaining those wells and related equipment and
facilities. They become part of the cost of oil and gas produced.
Examples of production costs (sometimes called lifting costs) are:
(A) Costs of labor to operate the wells and related equipment and
facilities.
(B) Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in
operating the wells and related equipment and facilities.
(D) Property taxes and insurance applicable to proved properties and
wells and related equipment and facilities.
(E) Severance taxes.
(ii) Some support equipment or facilities may serve two or more oil
and gas producing activities and may also serve transportation,
refining, and marketing activities. To the extent that the support
equipment and facilities are used in oil and gas producing activities,
their depreciation and applicable operating costs become exploration,
development or production costs, as appropriate. Depreciation,
depletion, and amortization of capitalized acquisition, exploration, and
development costs are not production costs but also become part of the
cost of oil and gas produced along with production (lifting) costs
identified above.

Successful Efforts Method

(b) A reporting entity that follows the successful efforts method
shall comply with the accounting and financial reporting disclosure
requirements of Statement of Financial Accounting Standards No. 19, as
amended.

Full Cost Method

(c) Application of the full cost method of accounting. A reporting
entity that follows the full cost method shall apply that method to all
of its operations and to the operations of its subsidiaries, as follows:
(1) Determination of cost centers. Cost centers shall be established
on a country-by-country basis.
(2) Costs to be capitalized. All costs associated with property
acquisition, exploration, and development activities (as defined in
paragraph (a) of this section) shall be capitalized within the
appropriate cost center. Any internal costs that are capitalized shall
be limited to those costs that can be directly identified with
acquisition, exploration, and development activities undertaken by the
reporting entity for its own account, and shall not include any costs
related to production, general corporate overhead, or similar
activities.
(3) Amortization of capitalized costs. Capitalized costs within a
cost center shall be amortized on the unit-of-production basis using
proved oil and gas reserves, as follows:
(i) Costs to be amortized shall include (A) all capitalized costs,
less accumulated amortization, other than the cost of properties
described in paragraph (ii) below; (B) the estimated future expenditures
(based on current costs) to be incurred in developing proved reserves;
and (C) estimated dismantlement and abandonment costs, net of estimated
salvage values.

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(ii) The cost of investments in unproved properties and major
development projects may be excluded from capitalized costs to be
amortized, subject to the following:
(A) All costs directly associated with the acquisition and
evaluation of unproved properties may be excluded from the amortization
computation until it is determined whether or not proved reserves can be
assigned to the properties, subject to the following conditions:
(1) Until such a determination is made, the properties shall be
assessed at least annually to ascertain whether impairment has occurred.
Unevaluated properties whose costs are individually significant shall be
assessed individually. Where it is not practicable to individually
assess the amount of impairment of properties for which costs are not
individually significant, such properties may be grouped for purposes of
assessing impairment. Impairment may be estimated by applying factors
based on historical experience and other data such as primary lease
terms of the properties, average holding periods of unproved properties,
and geographic and geologic data to groupings of individually
insignificant properties and projects. The amount of impairment assessed
under either of these methods shall be added to the costs to be
amortized.
(2) The costs of drilling exploratory dry holes shall be included in
the amortization base immediately upon determination that the well is
dry.
(3) If geological and geophysical costs cannot be directly
associated with specific unevaluated properties, they shall be included
in the amortization base as incurred. Upon complete evaluation of a
property, the total remaining excluded cost (net of any impairment)
shall be included in the full cost amortization base.
(B) Certain costs may be excluded from amortization when incurred in
connection with major development projects expected to entail
significant costs to ascertain the quantities of proved reserves
attributable to the properties under development (e.g., the installation
of an offshore drilling platform from which development wells are to be
drilled, the installation of improved recovery programs, and similar
major projects undertaken in the expectation of significant additions to
proved reserves). The amounts which may be excluded are applicable
portions of (1) the costs that relate to the major development project
and have not previously been included in the amortization base, and (2)
the estimated future expenditures associated with the development
project. The excluded portion of any common costs associated with the
development project should be based, as is most appropriate in the
circumstances, on a comparison of either (i) existing proved reserves to
total proved reserves expected to be established upon completion of the
project, or (ii) the number of wells to which proved reserves have been
assigned and total number of wells expected to be drilled. Such costs
may be excluded from costs to be amortized until the earlier
determination of whether additional reserves are proved or impairment
occurs.
(C) Excluded costs and the proved reserves related to such costs
shall be transferred into the amortization base on an ongoing (well-by-
well or property-by-property) basis as the project is evaluated and
proved reserves established or impairment determined. Once proved
reserves are established, there is no further justification for
continued exclusion from the full cost amortization base even if other
factors prevent immediate production or marketing.
(iii) Amortization shall be computed on the basis of physical units,
with oil and gas converted to a common unit of measure on the basis of
their approximate relative energy content, unless economic circumstances
(related to the effects of regulated prices) indicate that use of units
of revenue is a more appropriate basis of computing amortization. In the
latter case, amortization shall be computed on the basis of current
gross revenues (excluding royalty payments and net profits
disbursements) from production in relation to future gross revenues,
based on current prices (including consideration of changes in existing
prices provided only by contractual arrangements), from estimated
production of proved oil and gas reserves. The effect of a significant
price increase during the year

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on estimated future gross revenues shall be reflected in the
amortization provision only for the period after the price increase
occurs.
(iv) In some cases it may be more appropriate to depreciate natural
gas cycling and processing plants by a method other than the unit-of-
production method.
(v) Amortization computations shall be made on a consolidated basis,
including investees accounted for on a proportionate consolidation
basis. Investees accounted for on the equity method shall be treated
separately.
(4) Limitation on capitalized costs. (i) For each cost center,
capitalized costs, less accumulated amortization and related deferred
income taxes, shall not exceed an amount (the cost center ceiling) equal
to the sum of:
(A) The present value of estimated future net revenues computed by
applying current prices of oil and gas reserves (with consideration of
price changes only to the extent provided by contractual arrangements)
to estimated future production of proved oil and gas reserves as of the
date of the latest balance sheet presented, less estimated future
expenditures (based on current costs) to be incurred in developing and
producing the proved reserves computed using a discount factor of ten
percent and assuming continuation of existing economic conditions; plus
(B) the cost of properties not being amortized pursuant to paragraph
(i)(3)(ii) of this section; plus
(C) the lower of cost or estimated fair value of unproven properties
included in the costs being amortized; less
(D) income tax effects related to differences between the book and
tax basis of the properties referred to in paragraphs (i)(4)(i) (B) and
(C) of this section.
(ii) If unamortized costs capitalized within a cost center, less
related deferred income taxes, exceed the cost center ceiling, the
excess shall be charged to expense and separately disclosed during the
period in which the excess occurs. Amounts thus required to be written
off shall not be reinstated for any subsequent increase in the cost
center ceiling.
(5) Production costs. All costs relating to production activities,
including workover costs incurred solely to maintain or increase levels
of production from an existing completion interval, shall be charged to
expense as incurred.
(6) Other transactions. The provisions of paragraph (h) of this
section, ``Mineral property conveyances and related transactions if the
successful efforts method of accounting is followed,'' shall apply also
to those reporting entities following the full cost method except as
follows:
(i) Sales and abandonments of oil and gas properties. Sales of oil
and gas properties, whether or not being amortized currently, shall be
accounted for as adjustments of capitalized costs, with no gain or loss
recognized, unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves of oil and
gas attributable to a cost center. For instance, a significant
alteration would not ordinarily be expected to occur for sales involving
less than 25 percent of the reserve quantities of a given cost center.
If gain or loss is recognized on such a sale, total capitalization costs
within the cost center shall be allocated between the reserves sold and
reserves retained on the same basis used to compute amortization, unless
there are substantial economic differences between the properties sold
and those retained, in which case capitalized costs shall be allocated
on the basis of the relative fair values of the properties. Abandonments
of oil and gas properties shall be accounted for as adjustments of
capitalized costs; that is, the cost of abandoned properties shall be
charged to the full cost center and amortized (subject to the limitation
on capitalized costs in paragraph (b) of this section).
(ii) Purchases of reserves. Purchases of oil and gas reserves in
place ordinarily shall be accounted for as additional capitalized costs
within the applicable cost center; however, significant purchases of
production payments or properties with lives substantially shorter than
the composite productive life of the cost center shall be accounted for
separately.

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(iii) Partnerships, joint ventures and drilling arrangements. (A)
Except as provided in paragraph (i)(6)(i) of this section, all
consideration received from sales or transfers of properties in
connection with partnerships, joint venture operations, or various other
forms of drilling arrangements involving oil and gas exploration and
development activities (e.g., carried interest, turnkey wells,
management fees, etc.) shall be credited to the full cost account,
except to the extent of amounts that represent reimbursement of
organization, offering, general and administrative expenses, etc., that
are identifiable with the transaction, if such amounts are currently
incurred and charged to expense.
(B) Where a registrant organizes and manages a limited partnership
involved only in the purchase of proved developed properties and
subsequent distribution of income from such properties, management fee
income may be recognized provided the properties involved do not require
aggregate development expenditures in connection with production of
existing proved reserves in excess of 10% of the partnership's recorded
cost of such properties. Any income not recognized as a result of this
limitation would be credited to the full cost account and recognized
through a lower amortization provision as reserves are produced.
(iv) Other services. No income shall be recognized in connection
with contractual services performed (e.g. drilling, well service, or
equipment supply services, etc.) in connection with properties in which
the registrant or an affiliate (as defined in Sec. 210.1-02(b)) holds an
ownership or other economic interest, except as follows:
(A) Where the registrant acquires an interest in the properties in
connection with the service contract, income may be recognized to the
extent the cash consideration received exceeds the related contract
costs plus the registrant's share of costs incurred and estimated to be
incurred in connection with the properties. Ownership interests acquired
within one year of the date of such a contract are considered to be
acquired in connection with the service for purposes of applying this
rule. The amount of any guarantees or similar arrangements undertaken as
part of this contract should be considered as part of the costs related
to the properties for purposes of applying this rule.
(B) Where the registrant acquired an interest in the properties at
least one year before the date of the service contract through
transactions unrelated to the service contract, and that interest is
unaffected by the service contract, income from such contract may be
recognized subject to the general provisions for elimination of inter-
company profit under generally accepted accounting principles.
(C) Notwithstanding the provisions of paragraphs (i)(6)(iv) (A) and
(B) of this section, no income may be recognized for contractual
services performed on behalf of investors in oil and gas producing
activities managed by the registrant or an affiliate. Furthermore, no
income may be recognized for contractual services to the extent that the
consideration received for such services represents an interest in the
underlying property.
(D) Any income not recognized as a result of these rules would be
credited to the full cost account and recognized through a lower
amortization provision as reserves are produced.
(7) Disclosures. Reporting entities that follow the full cost method
of accounting shall disclose all of the information required by
paragraph (k) of this section, with each cost center considered as a
separate geographic area, except that reasonable groupings may be made
of cost centers that are not significant in the aggregate. In addition:
(i) For each cost center for each year that an income statement is
required, disclose the total amount of amortization expense (per
equivalent physical unit of production if amortization is computed on
the basis of physical units or per dollar of gross revenue from
production if amortization is computed on the basis of gross revenue).
(ii) State separately on the face of the balance sheet the aggregate
of the capitalized costs of unproved properties and major development
projects that are excluded, in accordance with paragraph (i)(3) of this
section, from the

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capitalized costs being amortized. Provide a description in the notes to
the financial statements of the current status of the significant
properties or projects involved, including the anticipated timing of the
inclusion of the costs in the amortization computation. Present a table
that shows, by category of cost, (A) the total costs excluded as of the
most recent fiscal year; and (B) the amounts of such excluded costs,
incurred (1) in each of the three most recent fiscal years and (2) in
the aggregate for any earlier fiscal years in which the costs were
incurred. Categories of cost to be disclosed include acquisition costs,
exploration costs, development costs in the case of significant
development projects and capitalized interest.

Income Taxes

(d) Income taxes. Comprehensive interperiod income tax allocation by
a method which complies with generally accepted accounting principles
shall be followed for intangible drilling and development costs and
other costs incurred that enter into the determination of taxable income
and pretax accounting income in different periods.

(Secs. 6, 7, 8, 10, and 19(a) (15 U.S.C. 77f, 77g, 77h, 77j, 77s) of the
Securities Act of 1933; secs. 12, 13, 15(d) and 23(a) (15 U.S.C. 78l,
78m, 78o(d), 78w), of the Securities Exchange Act of 1934; secs. 5(b),
14, and 20(a) (15 U.S.C. 79e, 79n, 79t) of the Public Utility Holding
Company Act of 1935; secs. 8, 30, 31(c) and 38(a) (15 U.S.C. 80a-8, 80a-
29, 80a-30(c), 80a-37(a)) of the Investment Company Act of 1940; sec.
503 (42 U.S.C. 6383) of the Energy Policy and Conservation Act of 1975;
secs. 5, 6, 7, 8, 10, 19(a) and Schedule A e(25) and (26) (15 U.S.C.
77e, 77f, 77g, 77h, 77j, 77s(a) and 77aa (25) and (26)) of the
Securities Act of 1933; secs. 12, 13, 14, 15(d) and 23(a) (15 U.S.C.
78l, 78m, 78n, 78o(d), 78w(a)) of the Securities Exchange Act of 1934;
secs. 5(b), 14 and 20(a) (15 U.S.C. 79e(b), 79n, 79t(a)) of the Public
Utility Holding Company Act of 1935 and sec. 503 (42 U.S.C. 6383) of the
Energy Policy and Conservation Act of 1975)

[43 FR 60405, Dec. 27, 1978, as amended at 43 FR 60417, Dec. 27, 1978;
44 FR 57036, 57038, Oct. 9, 1979; 45 FR 27749, Apr. 24, 1980.
Redesignated and amended at 45 FR 63669, Sept. 25, 1980; 47 FR 57913,
Dec. 29, 1982; 48 FR 44200, Sept. 28, 1983; 49 FR 18473, May 1, 1984; 57
FR 45293, Oct. 1, 1992; 61 FR 30401, June 14, 1996]

Commercial and Industrial Companies