Rules of General Application
Source:
Sections 210.4-01 through 210.4-10 appear at 45 FR 63669, Sept. 25, 1980, unless otherwise noted.
210.4-01 — Form, order, and terminology.
(a) Financial statements should be filed in such form and order, and should use such generally accepted terminology, as will best indicate their significance and character in the light of the provisions applicable thereto. The information required with respect to any statement shall be furnished as a minimum requirement to which shall be added such further material information as is necessary to make the required statements, in the light of the circumstances under which they are made, not misleading.
(1) Financial statements filed with the Commission which are not prepared in accordance with generally accepted accounting principles will be presumed to be misleading or inaccurate, despite footnote or other disclosures, unless the Commission has otherwise provided. This article and other articles of Regulation S-X provide clarification of certain disclosures which must be included in any event, in financial statements filed with the Commission.
(2) In all filings of foreign private issuers (see § 230.405 of this chapter), except as stated otherwise in the applicable form, the financial statements may be prepared according to a comprehensive set of accounting principles, other than those generally accepted in the United States or International Financial Reporting Standards as issued by the International Accounting Standards Board, if a reconciliation to U.S. Generally Accepted Accounting Principles and the provisions of Regulation S-X of the type specified in Item 18 of Form 20-F (§ 249.220f of this chapter) is also filed as part of the financial statements. Alternatively, the financial statements may be prepared according to U.S. Generally Accepted Accounting Principles or International Financial Reporting Standards as issued by the International Accounting Standards Board.
[45 FR 63669, Sept. 25, 1980, as amended at 47 FR 54767, Dec. 6, 1982; 70 FR 20719, Apr. 21, 2005; 73 FR 953, Jan. 4, 2008; 73 FR 1009, Jan. 4, 2008; 76 FR 50119, Aug. 12, 2011; 83 FR 50148, Oct. 4, 2018]
210.4-02 — Items not material.
If the amount which would otherwise be required to be shown with respect to any item is not material, it need not be separately set forth. The combination of insignificant amounts is permitted.
210.4-03 — Inapplicable captions and omission of unrequired or inapplicable financial statements.
(a) No caption should be shown in any financial statement as to which the items and conditions are not present.
(b) Financial statements not required or inapplicable because the required matter is not present need not be filed.
(c) The reasons for the omission of any required financial statements shall be indicated.
210.4-04 — Omission of substantially identical notes.
If a note covering substantially the same subject matter is required with respect to two or more financial statements relating to the same or affiliated persons, for which separate sets of notes are presented, the required information may be shown in a note to only one of such statements: Provided, That a clear and specific reference thereto is made in each of the other statements with respect to which the note is required.
210.4-05 — 210.4-06 — [Reserved]
210.4-07 — Discount on shares.
Discount on shares, or any unamortized balance thereof, shall be shown separately as a deduction from the applicable account(s) as circumstances require.
210.4-08 — General notes to financial statements.
If applicable to the person for which the financial statements are filed, the following shall be set forth on the face of the appropriate statement or in appropriately captioned notes. The information shall be provided for each statement required to be filed, except that the information required by paragraphs (b), (c), (d), (e), and (f) of this section shall be provided as of the most recent audited balance sheet being filed and for paragraph (j) of this section as specified therein. When specific statements are presented separately, the pertinent notes shall accompany such statements unless cross-referencing is appropriate.
(a) [Reserved].
(b) Assets subject to lien. Assets mortgaged, pledged, or otherwise subject to lien, and the approximate amounts thereof, shall be designated and the obligations collateralized briefly identified.
(c) Defaults. The facts and amounts concerning any default in principal, interest, sinking fund, or redemption provisions with respect to any issue of securities or credit agreements, or any breach of covenant of a related indenture or agreement, which default or breach existed at the date of the most recent balance sheet being filed and which has not been subsequently cured, shall be stated in the notes to the financial statements. If a default or breach exists but acceleration of the obligation has been waived for a stated period of time beyond the date of the most recent balance sheet being filed, state the amount of the obligation and the period of the waiver.
(d) Preferred shares. Aggregate preferences on involuntary liquidation, if other than par or stated value, shall be shown parenthetically in the equity section of the balance sheet.
(e) Restrictions which limit the payment of dividends by the registrant.
(1) Describe the most significant restrictions on the payment of dividends by the registrant, indicating their sources, their pertinent provisions, and the amount of retained earnings or net income restricted or free of restrictions.
(2) Disclose the amount of consolidated retained earnings which represents undistributed earnings of 50 percent or less owned persons accounted for by the equity method.
(3) The disclosures in paragraphs (e)(3)(i) and (ii) of this section shall be provided when material. For purposes of this test, restricted net assets of subsidiaries shall mean that amount of the registrant's proportionate share of net assets (after intercompany eliminations) reflected in the balance sheets of its consolidated and unconsolidated subsidiaries as of the end of the most recent fiscal year which may not be transferred to the parent company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party (i.e., lender, regulatory agency, foreign government, etc.). Not all limitations on transferability of assets are considered to be restrictions for purposes of this test, which considers only specific third party restrictions on the ability of subsidiaries to transfer funds outside of the entity. For example, the presence of subsidiary debt which is secured by certain of the subsidiary's assets does not constitute a restriction under this rule. However, if there are any loan provisions prohibiting dividend payments, loans or advances to the parent by a subsidiary, these are considered restrictions for purposes of computing restricted net assets. When a loan agreement requires that a subsidiary maintain certain working capital, net tangible asset, or net asset levels, or where formal compensating arrangements exist, there is considered to be a restriction under the rule because the lender's intent is normally to preclude the transfer by dividend or otherwise of funds to the parent company. Similarly, a provision which requires that a subsidiary reinvest all of its earnings is a restriction, since this precludes loans, advances or dividends in the amount of such undistributed earnings by the entity. Where restrictions on the amount of funds which may be loaned or advanced differ from the amount restricted as to transfer in the form of cash dividends, the amount least restrictive to the subsidiary shall be used. Redeemable preferred stocks (§ 210.5-02.27) and noncontrolling interests shall be deducted in computing net assets for purposes of this test.
(i) Describe the nature of any restrictions on the ability of consolidated subsidiaries and unconsolidated subsidiaries to transfer funds to the registrant in the form of cash dividends, loans or advances (i.e., borrowing arrangements, regulatory restraints, foreign government, etc.).
(ii) Disclose separately the amounts of such restricted net assets for unconsolidated subsidiaries and consolidated subsidiaries as of the end of the most recently completed fiscal year.
(f) Significant changes in bonds, mortgages and similar debt. Any significant changes in the authorized amounts of bonds, mortgages and similar debt since the date of the latest balance sheet being filed for a particular person or group shall be stated.
(g) Summarized financial information of subsidiaries not consolidated and 50 percent or less owned persons. (1) The summarized information as to assets, liabilities and results of operations as detailed in § 210.1-02(bb) shall be presented in notes to the financial statements on an individual or group basis for:
(i) Subsidiaries not consolidated; or
(ii) For 50 percent or less owned persons accounted for by the equity method by the registrant or by a subsidiary of the registrant, if the criteria in § 210.1-02(w) for a significant subsidiary are met:
(A) Individually by any subsidiary not consolidated or any 50% or less owned person; or
(B) On an aggregated basis by any combination of such subsidiaries and persons.
(2) Summarized financial information shall be presented insofar as is practicable as of the same dates and for the same periods as the audited consolidated financial statements provided and shall include the disclosures prescribed by § 210.1-02(bb). Summarized information of subsidiaries not consolidated shall not be combined for disclosure purposes with the summarized information of 50 percent or less owned persons.
(h) Income tax expense. (1) Disclosure shall be made in the statement of comprehensive income or a note thereto, of the components of income (loss) before income tax expense (benefit) as either domestic or foreign.
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Note:
Amounts applicable to United States Federal income taxes, to foreign income taxes and the other income taxes shall be stated separately for each major component. Amounts applicable to foreign income (loss) and amounts applicable to foreign or other income taxes which are less than five percent of the total of income before taxes or the component of tax expense, respectively, need not be separately disclosed. For purposes of this rule, foreign income (loss) is defined as income (loss) generated from a registrant's foreign operations, i.e., operations that are located outside of the registrant's home country.
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(2) In the reconciliation between the amount of reported total income tax expense (benefit) and the amount computed by multiplying the income (loss) before tax by the applicable statutory Federal income tax rate, if no individual reconciling item amounts to more than five percent of the amount computed by multiplying the income before tax by the applicable statutory Federal income tax rate, and the total difference to be reconciled is less than five percent of such computed amount, no reconciliation need be provided unless it would be significant in appraising the trend of earnings. Reconciling items that are individually less than five percent of the computed amount may be aggregated in the reconciliation. Where the reporting person is a foreign entity, the income tax rate in that person's country of domicile should normally be used in making the above computation, but different rates should not be used for subsidiaries or other segments of a reporting entity. When the rate used by a reporting person is other than the United States Federal corporate income tax rate, the rate used and the basis for using such rate shall be disclosed.
(3) Paragraphs (h) (1) and (2) of this section shall be applied in the following manner to financial statements which reflect the adoption of FASB ASC Topic 740, Income Taxes.
(i) The disclosures required by paragraph (h)(1)(ii) of this section and by the parenthetical instruction at the end of paragraph (h)(1) of this section and by the introductory sentence of paragraph (h)(2) of this section shall not apply.
(ii) The instructional note between paragraphs (h) (1) and (2) of this section and the balance of the requirements of paragraphs (h) (1) and (2) of this section shall continue to apply.
(i) [Reserved]
(j) [Reserved]
(k) Related party transactions that affect the financial statements. (1) Amounts of related party transactions should be stated on the face of the balance sheet, statement of comprehensive income, or statement of cash flows.
(2) In cases where separate financial statements are presented for the registrant, certain investees, or subsidiaries, any intercompany profits or losses resulting from transactions with related parties and the effects thereof shall be disclosed.
(l) [Reserved]
(m) Repurchase and reverse repurchase agreements — (1) Repurchase agreements (assets sold under agreements to repurchase). (i) If, as of the most recent balance sheet date, the carrying amount (or market value, if higher than the carrying amount or if there is no carrying amount) of the securities or other assets sold under agreements to repurchase (repurchase agreements) exceeds 10% of total assets, disclose separately in the balance sheet the aggregate amount of liabilities incurred pursuant to repurchase agreements including accrued interest payable thereon.
(ii)(A) If, as of the most recent balance sheet date, the carrying amount (or market value, if higher than the carrying amount) of securities or other assets sold under repurchase agreements, other than securities or assets specified in paragraph (m)(1)(ii)(B) of this section, exceeds 10% of total assets, disclose in an appropriately captioned footnote containing a tabular presentation, segregated as to type of such securities or assets sold under agreements to repurchase (e.g., U.S. Treasury obligations, U.S. Government agency obligations and loans), the following information as of the balance sheet date for each such agreement or group of agreements (other than agreements involving securities or assets specified in paragraph (m)(1)(ii)(B) of this section) maturing (1) overnight; (2) term up to 30 days; (3) term of 30 to 90 days; (4) term over 90 days and (5) demand:
(i) The carrying amount and market value of the assets sold under agreement to repurchase, including accrued interest plus any cash or other assets on deposit under the repurchase agreements; and
(ii) The repurchase liability associated with such transaction or group of transactions and the interest rate(s) thereon.
(B) For purposes of paragraph (m)(1)(ii)(A) of this section only, do not include securities or other assets for which unrealized changes in market value are reported in current income or which have been obtained under reverse repurchase agreements.
(iii) If, as of the most recent balance sheet date, the amount at risk under repurchase agreements with any individual counterparty or group of related counterparties exceeds 10% of stockholders' equity (or in the case of investment companies, net asset value), disclose the name of each such counterparty or group of related counterparties, the amount at risk with each, and the weighted average maturity of the repurchase agreements with each. The amount at risk under repurchase agreements is defined as the excess of carrying amount (or market value, if higher than the carrying amount or if there is no carrying amount) of the securities or other assets sold under agreement to repurchase, including accrued interest plus any cash or other assets on deposit to secure the repurchase obligation, over the amount of the repurchase liability (adjusted for accrued interest). (Cash deposits in connection with repurchase agreements shall not be reported as unrestricted cash pursuant to rule 5-02.1.)
(2) Reverse repurchase agreements (assets purchased under agreements to resell). (i) If, as of the most recent balance sheet date, the aggregate carrying amount of “reverse repurchase agreements” (securities or other assets purchased under agreements to resell) exceeds 10% of total assets:
(A) Disclose separately such amount in the balance sheet; and
(B) Disclose in an appropriately captioned footnote:
(1) The registrant's policy with regard to taking possession of securities or other assets purchased under agreements to resell; and
(2) Whether or not there are any provisions to ensure that the market value of the underlying assets remains sufficient to protect the registrant in the event of default by the counterparty and if so, the nature of those provisions.
(ii) If, as of the most recent balance sheet date, the amount at risk under reverse repurchase agreements with any individual counterparty or group of related counterparties exceeds 10% of stockholders' equity (or in the case of investment companies, net asset value), disclose the name of each such counterparty or group of related counterparties, the amount at risk with each, and the weighted average maturity of the reverse repurchase agreements with each. The amount at risk under reverse repurchase agreements is defined as the excess of the carrying amount of the reverse repurchase agreements over the market value of assets delivered pursuant to the agreements by the counterparty to the registrant (or to a third party agent that has affirmatively agreed to act on behalf of the registrant) and not returned to the counterparty, except in exchange for their approximate market value in a separate transaction.
(n) Accounting policies for certain derivative instruments. Disclosures regarding accounting policies shall include, to the extent material, where in the statement of cash flows derivative financial instruments, and their related gains and losses, as defined by U.S. generally accepted accounting principles, are reported.
Instructions to paragraph (n): 1. For purposes of this paragraph (n), derivative financial instruments and derivative commodity instruments (collectively referred to as “derivatives”) are defined as follows:
(i) Derivative financial instruments have the same meaning as defined by generally accepted accounting principles (see, e.g., FASB ASC Master Glossary, and include futures, forwards, swaps, options, and other financial instruments with similar characteristics.
(ii) Derivative commodity instruments include, to the extent such instruments are not derivative financial instruments, commodity futures, commodity forwards, commodity swaps, commodity options, and other commodity instruments with similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial instrument. For purposes of this paragraph, settlement in cash includes settlement in cash of the net change in value of the derivative commodity instrument (e.g., net cash settlement based on changes in the price of the underlying commodity).
2. For purposes of paragraphs (n)(2), (n)(3), (n)(4), and (n)(7), the required disclosures should address separately derivatives entered into for trading purposes and derivatives entered into for purposes other than trading. For purposes of this paragraph, trading purposes means dealing and other trading activities measured at fair value with gains and losses recognized in earnings.
3. For purposes of paragraph (n)(6), anticipated transactions means transactions (other than transactions involving existing assets or liabilities or transactions necessitated by existing firm commitments) an enterprise expects, but is not obligated, to carry out in the normal course of business.
4. Registrants should provide disclosures required under paragraph (n) in filings with the Commission that include financial statements of fiscal periods ending after June 15, 1997.
[45 FR 63669, Sept. 25, 1980, as amended at 46 FR 56179, Nov. 16, 1981; 50 FR 25215, June 18, 1985; 50 FR 49532, Dec. 3, 1985; 51 FR 3770, Jan. 30, 1986; 57 FR 45293, Oct. 1, 1992; 59 FR 65636, Dec. 20, 1994; 62 FR 6063, Feb. 10, 1997; 74 FR 18615, Apr. 23, 2009; 76 FR 50119, Aug. 12, 2011; 83 FR 50148, Oct. 4, 2018]
210.4-9 — [Reserved]
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) 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.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
(7) 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.
(iv) Provide improved recovery systems.
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) 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.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12) 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.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) 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.
(16) Oil and gas producing activities. (i) Oil and gas producing 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 or for the purpose of removing the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D) Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20) 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.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
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Note to paragraph (a)(26):
Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
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(27) 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.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29) 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.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for 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 projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Successful Efforts Method
(b) A reporting entity that follows the successful efforts method shall comply with the accounting and financial reporting disclosure requirements of FASB ASC Topic 932, Extractive Activities — Oil and Gas.
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.
(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 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.
(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 § 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 a statement of comprehensive income 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 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.
(8) For purposes of this paragraph (c), the term “current price” shall mean the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
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.
[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; 74 FR 2190, Jan. 14, 2009; 76 FR 50119, Aug. 12, 2011; 83 FR 50148, Oct. 4, 2018]