Annexe 2
Regulation S-X, Rule 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
L'annexe 2 est un extrait du code de la réglementation
fédérale aux Etats-Unis. Il s'agit des règles comptables
régissant l'activité de recherche et de production des
hydrocarbures, en l'occurrence la section 10, article 4 de la
réglementation S-X.
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Annexe 2 - Code of Federal Regulations, alias S-X, article 4,
section 10
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Regulation S-X
Article 4--Rules of General Application
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
Reg. § 210.4-10.
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 [IS 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
rate-making purposes on an individual-company-cost-of-service basis may,
however, give appropriate recognition to differences arising because of the
effect of the rate-making 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.
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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.
(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
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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
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be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless
such techniques Leave 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.
(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 which 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 arc 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
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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 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.
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(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:
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(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.
(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
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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 cross 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 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.
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(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 section1; 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 section2.
(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 section3, "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:
1 Paragraph (i) was redesignated paragraph (c) by
Release No. 33-7300, effective July 15, 1996, 61 FR 30397.
2 Paragraph (i) was redesignated paragraph (c) by
Release No. 33-7300, effective July 15, 1996, 61 FR 30397
3 Paragraph (h) was removed by Release No. 33-7300,
effective July 15, 1996, 61 FR 30397
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(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.
(iii) Partnerships, joint ventures and drilling
arrangements.
(A) Except as provided in subparagraph (i)(6)(i) of this
section4, 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.
4 Paragraph (i) was redesignated paragraph (c) by
Release No. 33-7300, effective July 15, 1996, 61 FR 30397
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(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 § 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 intercompany profit under generally
accepted accounting principles.
(C) Notwithstanding the provisions of (A) and (B) above, 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 section5, 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
5 Paragraph (k) was removed by Release No. 33-6958A,
effective November 2, 1992, 57 FR 45287
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are excluded, in accordance with paragraph (i)(3) of this
section6, from the 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.
6 Paragraph (i) was redesignated paragraph (c) by
Release No. 33-7300, effective July 15, 1996, 61 FR 30397
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