Staff Accounting Bulletin No. 113

SECURITIES AND EXCHANGE COMMISSION 17 CFR Part 211 [Release No. SAB 113] Staff Accounting Bulletin No. 113 AGENCY: Securities and Exchange Commission. ACTION: Publication of staff accounting bulletin. SUMMARY: This Staff Accounting Bulletin (SAB) revises or rescinds portions of the interpretive guidance included in the section of the Staff Accounting Bulletin Series titled ‘‘Topic 12: Oil and Gas Producing Activities’’ (Topic 12) and revises a technical reference in ‘‘Topic 3: Senior Securities’’ (Topic 3). This update is intended to make the relevant interpretive guidance consistent with

current authoritative accounting and auditing guidance and Commission rules and regulations. The principal changes involve revision or removal of material due to recent Commission rulemaking. Specifically, the staff is updating the Series in order to bring existing guidance into conformity with the contents of Financial Reporting Release No. 78 (Release No. 33–8995), Modernization of Oil and Gas Reporting, issued December 31, 2008 (FR–78), and, in the case of the technical amendment to SAB Topic 3, Financial Reporting Release No. 79 (Release Nos. 33–9026; 34–59775), Technical Amendments to Rules, Forms, Schedules and Codification of Financial Reporting Policies (FR–79), issued April 15, 2009. This SAB also updates related interpretive responses and examples in Topic 12. The staff expects registrants to apply the updated guidance in this SAB related to Topic 12 on a prospective basis in conjunction with the application of FR–78 and retroactively for the technical amendment to Topic 3 in conjunction with the effective date of FR–79. FR–78 is effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10–K and 20–F for fiscal years ending on or after December 31, 2009. FR–79 is effective as of April 23, 2009. DATES: Effective Date: November 4, 2009. FOR FURTHER INFORMATION CONTACT:
Jonathan W. Duersch, Assistant Chief Accountant, Office of the Chief Accountant, at (202) 551–3719, Doug Parker, Professional Accounting Fellow, Office of the Chief Accountant, at (202) 551–5316 or Leslie A. Overton, Associate Chief Accountant, Division of Corporation Finance, at (202) 551–3518, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549. SUPPLEMENTARY INFORMATION: The statements in staff accounting bulletins are not rules or interpretations of the Commission, nor are they published as bearing the Commission’s official approval. They represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws. Dated: October 29, 2009. Elizabeth M. Murphy, Secretary.
PART 211—[AMENDED]

• Accordingly, Part 211 of Title 17 of
  the Code of Federal Regulations is amended by adding Staff Accounting Bulletin No. 113 to the table found in Subpart B. Staff Accounting Bulletin No. 113 This staff accounting bulletin revises or rescinds portions of the interpretive guidance in Topic 12, ‘‘Oil and Gas Producing Activities,’’ included in the Staff Accounting Bulletin Series, in order to make the relevant interpretive guidance consistent with current authoritative accounting and auditing guidance and Financial Reporting Release No. 78 (Release No. 33–8995), Modernization of Oil and Gas Reporting, issued December 31, 2008 (2008 Oil & Gas Release). This SAB also updates related interpretive responses and examples. This SAB also includes an amendment to Topic 3 ‘‘Senior Securities,’’ for a technical reference revision to conform to Financial Reporting Release No. 79 (Release Nos. 33–9026; 34–59775), Technical Amendments to Rules, Forms, Schedules and Codification of Financial Reporting Policies, issued April 15, 2009. The following describes the changes made to the Staff Accounting Bulletin Series that are presented at the end of this release:
  Topic 3: Senior Securities Topic 3.C, the introductory facts are amended to replace the reference ‘‘Rule 5–02.28 of Regulation S–X’’ with ‘‘Rule 5–02.27 of Regulation S–X’’ to conform to paragraph numbering amendments made by FR–79. Topic 12: Oil and Gas Producing Activities a. Topic 12 is amended to update authoritative accounting literature references to the FASB’s Accounting Standards Codification (FASB ASC) throughout. b. Topic 12.A.1, the introductory facts have been amended, and questions 1, 2, and 3 are removed, leaving question 4 in place (without a numerical designation). Questions 1 and 2 are no longer applicable to the amended definition of ‘‘reliable technology’’ in Rule 4–10 of Regulation S–X. Question 3 is removed to conform to Instruction 1 of Item 1204 of Regulation S–K, which no longer addresses reserves attributable to production from processing plant ownership as previously included in Instruction B of Item 3 of former Industry Guide 2.
  c. Topic 12.A.2, the facts and the
  interpretive response to question 1 are amended to conform to changes made by the 2008 Oil & Gas Release by replacing the use of a year-end price when determining reserve quantities with the use of the average price during the 12-month period prior to the ending date of the period covered by the balance sheet, determined as the unweighted arithmetic average of the first-day-of-the-month market price within such period for that oil and gas (the average price). Questions 2 and 3 are removed because the average price is applied in all cases where contractual prices do not exist as specified under Rule 4–10(a)(22) of Regulation S–X. d. Topic 12.A.3.b is removed to conform to the 2008 Oil & Gas Release which permits the disclosure of probable and possible reserve quantities but does not provide a basis to present estimated values attributed to those reserve quantities. e. Topic 12.A.3.c, the facts are amended to remove references to Industry Guide 2, which has been replaced by amendments to Regulation S–K and to remove unnecessary references to Regulation S–X and Financial Accounting Standards Board (FASB) Statement No. 69. The interpretive response is amended to replace the term ‘‘merger’’ with the term ‘‘business combination’’ and replace the term ‘‘combined’’ with the term ‘‘consolidated or combined’’. f. Topic 12.A.3.d is removed to conform to the Commission’s rules and regulations which do not require (and the Division of Corporation Finance no longer requests) a balance sheet of the general partner to be included in a registration statement for an offering of limited partnership interests. g. Topic 12.C.1, the facts are amended to remove a reference to FASB Statement No. 25, which is not included in the FASB ASC. In addition, non￾substantive editorial changes are made to Topic 12.C.2. h. Topic 12.D.1, non-substantive editorial changes are made to question 1 and question 2 is amended to simplify the illustrative example in the interpretive response and thereby promote a clearer understanding of the calculation using the ‘‘shortcut’’ method for determining the tax effects in computing the full cost ceiling limitation and the resulting gross write￾off attributed to the full cost pool.
  i. Topic 12.D.3.b is amended to
  conform to changes made by the 2008 Oil & Gas Release by replacing the use of a year-end spot price when determining reserve quantities with the use of the average price during the 12- month period prior to the ending date of the period covered by the balance sheet, determined as the unweighted arithmetic average of the first-day-of￾the-month market price within such period for that oil and gas. Additionally,

the interpretive response is amended to remove unnecessary references to guidance in FASB Statements 52 and 80, which is now provided in FASB ASC Topic 815, Derivatives and Hedging, and to add a reference to Financial Reporting Release No. 72 (Release Nos. 33–8350; 34–48960), Commission Guidance Regarding Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is more recent guidance pertinent to Management’s Discussion and Analysis disclosures. j. Topic 12.D.3.c is amended to conform to changes made by the 2008 Oil & Gas Release by removing the provision to apply a recovery of oil and gas prices subsequent to period-end, when assessing whether a write-off computed under the full cost ceiling limitation should be recognized. As stated in the 2008 Oil & Gas Release, this guidance is no longer necessary because use of the average price would effectively eliminate anomalies caused by the single-day period-end price. k. Topic 12.D.4, Footnote 1 is removed to eliminate unnecessary references specifically related to the adoption of FASB Statement 143, which is now referenced to FASB ASC Subtopic 410–20, Asset Retirement and Environmental Obligations—Asset Retirement Obligations. Footnotes previously numbered 2, 3 and 4 are renumbered 1, 2 and 3, respectively.
l. Topic 12.D.4.a, question 1 and the
facts and interpretive response related to question 1 are amended and question 2 is removed to eliminate unnecessary references and guidance specifically related to the adoption of FASB Statement 143. m. Topic 12.D.4.b, the facts, question and interpretive response are amended to eliminate unnecessary references and guidance specifically related to the adoption of FASB Statement 143. n. Topic 12.D.4.c is removed to eliminate unnecessary transition guidance specifically related to the adoption of FASB Statement 143. o. Topic 12.F, Footnote 4 is added to reference the definition of current prices used in Rule 4–10(c) of Regulation S–X, which was amended to conform to the 2008 Oil & Gas Release. As amended, Rule 4–10(c)(8) of Regulation S–X defines current price as 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. p. Topic 12.G and Footnotes 5 and 6 are removed to conform to changes made by the 2008 Oil & Gas Release. This conforming change reflects the fact that, under amended Rule 4–10(a)(16) the definition of ‘‘oil and gas producing activities’’ includes the extraction of natural gas from coal beds. Note: The text of SAB 113 will not appear in the Code of Federal Regulations.

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TOPIC 3: SENIOR SECURITIES

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C. Redeemable Preferred Stock
Facts: Rule 5–02.27 of Regulation S–X states that redeemable preferred stocks are not to be included in amounts reported as stockholders’ equity, and that their redemption amounts are to be shown on the face of the balance sheet. However, the Commission’s rules and regulations do not address the carrying amount at which redeemable preferred stock should be reported, or how changes in its carrying amount should be treated in calculations of earnings per share and the ratio of earnings to combined fixed charges and preferred stock dividends.

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TOPIC 12: OIL AND GAS PRODUCING ACTIVITIES A. Accounting Series Release 257— Requirements for Financial Accounting and Reporting Practices for Oil and Gas Producing Activities

1. Estimates of Reserve Quantities
   Facts: Rule 4–10 of Regulation S–X contains definitions of possible reserves, probable reserves, and proved and developed oil and gas reserves to be used in determining quantities of oil and gas reserves to be reported in filings with the Commission. Question: What pressure base should be used for reporting gas and production, 14.73 psia or the pressure base specified by the state? Interpretive Response: The reporting instructions to the Department of Energy’s Form EIA–28 specify that natural gas reserves are to be reported at
   14.73 psia and 60 degrees F. There is no
   pressure base specified in Regulation S– X or S–K. At the present time staff will not object to natural gas reserves and production data calculated at other pressure bases, if such pressure bases are identified in the filing.
2. Estimates of Future Net Revenues
   Facts: U.S. GAAP requires the disclosure of the standardized measure of discounted future net cash flows from production of proved oil and gas reserves. Question: For purposes of determining reserves and estimated future net revenues, what price should be used for oil and gas which will be produced after an existing contract expires or after the redetermination date in a contract? Interpretive Response: The price to be used for oil and gas which will be produced after a contract expires or has a redetermination is the average price during the 12-month period prior to the ending date of the period covered by the balance sheet, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period for that oil and gas. This average price, which should be based on the first-day-of-the￾month market prices, may be increased thereafter only for additional fixed and determinable escalations, as appropriate. A fixed and determinable escalation is one which is specified in amount and is not based on future events such as rates of inflation.
3. Disclosure of Reserve Information
   a. Removed by SAB 103 b. Removed by SAB 113
   c. Limited Partnership 10–K Reports
   Facts: Item 1201(a) of Regulation S–K contains an exemption from the requirements to disclose certain information relating to oil and gas operations for ‘‘limited partnerships or joint ventures that conduct, operate, manage, or report upon oil and gas drilling income programs that acquire properties either for drilling and production, or for production of oil, gas, or geothermal steam. * * * Limited partnership agreements often contain buy-out provisions under which the general partner agrees to purchase limited partnership interests that are offered for sale, based upon a specified valuation formula. Because of these arrangements, the requirements for disclosure of reserve value information may be of little significance to the limited partners. Question: Must the financial statements of limited partnerships included in reports on Form 10–K contain the disclosures of estimated future net revenues, present values and changes therein, and supplemental summary of oil and gas activities specified in paragraphs 23 through 36 of FASB Accounting Standards Codification (FASB ASC) Section 932– 235–50, Extractive Activities—Oil and Gas—Notes to Financial Statements— Disclosure?

Interpretive Response: The staff will not take exception to the omission of these disclosures in a limited partnership Form 10–K if reserve value information is available to the limited partners pursuant to the partnership agreement (even though the valuations may be computed differently and may be as of a date other than year end). However, the staff will require all of the information listed in paragraphs 23 through 36 of FASB ASC Section 932– 235–50 for partnerships which are the subject of a business combination or exchange offer under which various limited partnerships are to be consolidated or combined into a single entity. d. Removed by SAB 113 e. Rate Regulated Companies Question: If a company has cost-of￾service oil and gas producing properties, how should they be treated in the supplemental disclosures of reserve quantities and related future net revenues provided pursuant to paragraphs 29 through 36 of FASB ASC
Section 932–235–50, Extractive
Activities—Oil and Gas—Notes to Financial Statements—Disclosure? Interpretive Response: Rule 4–10 provides that registrants may give effect to differences arising from the ratemaking process for cost-of-service oil and gas properties. Accordingly, in these circumstances, the staff believes that the company’s supplemental reserve quantity disclosures should indicate separately the quantities associated with properties subject to cost-of-service ratemaking, and that it is appropriate to exclude those quantities from the future net revenue disclosures. The company should also disclose the nature and impact of its cost-of-service ratemaking, including the unamortized cost included in the balance sheet.
4. Removed by SAB 103
B. Removed by SAB 103
C. Methods of Accounting by Oil and
Gas Producers
1. First-Time Registrants
Facts: In ASR 300, the Commission announced that it would allow registrants to change methods of accounting for oil and gas producing activities so long as such changes were in accordance with GAAP. Accordingly, the Commission stated that changes from the full cost method to the successful efforts method would not require a preferability letter. Changes to full cost, however, would require justification by the company making the change and filing of a preferability letter from the company’s independent accountants. Question: How does this policy apply to a nonpublic company which changes its accounting method in connection with a forthcoming public offering or initial registration under either the 1933 Act or 1934 Act? Interpretive Response: The Commission’s policy that first-time registrants may change their previous accounting methods without filing a preferability letter is applicable. Therefore, such a company may change to the full cost method without filing a preferability letter.
2. Consistent Use of Accounting
Methods Within a Consolidated Entity Facts: Rule 4–10(c) of Regulation S–X states in part that ‘‘[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 * * *’’ Question 1: May a subsidiary of the parent use the full cost method if the parent company uses the successful efforts method of accounting for oil and gas producing activities? Interpretive Response: No. The use of different methods of accounting in the consolidated financial statements by a parent company and its subsidiary would be inconsistent with the full cost requirement that a parent and its subsidiaries all use the same method of accounting. The staff’s general policy is that an enterprise should account for all its like operations in the same manner. However, Rule 4–10 of Regulation S–X provides that oil and gas companies with cost-of-service oil and gas properties may give effect to any differences resulting from the ratemaking process, including regulatory requirements that a certain accounting method be used for the cost￾of-service properties. Question 2: Must the method of accounting (full cost or successful efforts) followed by a registrant for its oil and gas producing activities also be followed by any fifty percent or less owned companies in which the registrant carries its investment on the equity method (equity investees)? Interpretive Response: No. Conformity of accounting methods between a registrant and its equity investees, although desirable, may not be practicable and thus is not required. However, if a registrant proportionately consolidates its equity investees, it will be necessary to present them all on the same basis of accounting. D. Application of Full Cost Method of Accounting
1. Treatment of Income Tax Effects in
the Computation of the Limitation on Capitalized Costs Facts: Item (D) in Rule 4–10(c)(4)(i) of Regulation S–X provides that the income tax effects related to the properties involved should be deducted in computing the full cost ceiling. Question 1: What specific types of income tax effects should be considered in computing the income tax effects to be deducted from estimated future net revenues? Interpretive Response: The rule refers to income tax effects generally. Thus, the computation should take into account (i) the tax basis of oil and gas properties, (ii) net operating loss carryforwards, (iii) foreign tax credit carryforwards, (iv) investment tax credits, (v) alternative minimum taxes on tax preference items, and (vi) the impact of statutory (percentage) depletion. It may often be difficult to allocate a net operating loss (NOL) carryforward between oil and gas assets and other assets. However, to the extent that the NOL is clearly attributable to oil and gas operations and is expected to be realized within the carryforward period, it should be added to tax basis. Similarly, to the extent that investment tax credit (ITC) carryforwards and foreign tax credit carryforwards are attributable to oil and gas operations and are expected to be realized within the carryforward period, they should be considered as a deduction from the tax effect otherwise computed. Consideration of NOL and ITC or foreign tax credit carryforwards should not, of course, reduce the total tax effect below zero. Question 2: How should the tax effect be computed considering the various factors discussed above? Interpretive Response: Theoretically, taxable income and tax could be determined on a year-by-year basis and the present value of the related tax computed. However, the ‘‘shortcut’’ method illustrated below is also acceptable. ASSUMPTIONS:
Cost of proved properties being amortized .................................................................. .......................... $396,000 ..........................
Lower of cost or estimated fair value of unproved properties to be amortized ........ .......................... 49,000 ..........................

Cost of properties not being amortized ........................................................................ .......................... 55,000 ..........................
Capitalized costs of oil and gas assets ......................................................................... .......................... 500,000 ..........................
Accumulated DD&A ...................................................................................................... .......................... (100,000 ) ..........................
Book basis of oil and gas assets ............................................................................. .......................... .......................... $400,000
Excess of book basis over tax basis ($270,000) of oil and gas assets ......................... .......................... $(130,000 ) ..........................
NOL carryforward* ........................................................................................................ .......................... 20,000 ..........................
.......................... (110,000 ) ..........................
Statutory tax rate (percent) ........................................................................................... .......................... × 46% ..........................
.......................... (50,600 ) ..........................
Foreign tax credit carryforward* .................................................................................. .......................... 1,000 ..........................
ITC carryforward* .......................................................................................................... .......................... 2,000 ..........................
Related net deferred income tax liability ..................................................................... .......................... .......................... (47,600 ) Net book basis to be recovered .............................................................................. .......................... .......................... $352,400 Other Assumptions:
Present value of ITC relating to future development costs ......................................... .......................... $1,500 ..........................
Present value of statutory depletion attributable to future deductions ..................... .......................... $10,000 ..........................
Estimated preference (minimum) tax on percentage depletion in excess of cost de￾pletion ......................................................................................................................... .......................... $500 ..........................
Present value of future net revenue from proved oil and gas reserves ...................... .......................... $272,000 ..........................
CALCULATION:
Present value of future net revenue ............................................................................. .......................... $272,000 ..........................
Cost of properties not being amortized ........................................................................ .......................... 55,000 ..........................
Lower of cost or estimated fair value of unproved properties included in costs
being amortized .......................................................................................................... .......................... 49,000 ..........................
Total ceiling limitation before tax effects ............................................................. .......................... .......................... $376,000 Tax Effects:
Total ceiling limitation before tax effects .................................................................... .......................... $376,000 ..........................
Less: Tax basis of properties ......................................................................................... $(270,000) .......................... ..........................
Statutory depletion ................................................................................................. (10,000 ) .......................... ..........................
NOL carryforward ................................................................................................... (20,000 ) .......................... ..........................
.......................... (300,000 ) ..........................
Future taxable income ................................................................................................... .......................... 76,000 ..........................
Tax rate (percent) ........................................................................................................... .......................... × 46% ..........................
Tax at statutory rate ....................................................................................................... .......................... (34,960 ) ..........................
ITC (future development costs and carryforward) ...................................................... .......................... 3,500 ..........................
Foreign tax credit carryforward .................................................................................... .......................... 1,000 ..........................
Estimated preference tax ............................................................................................... .......................... (500 ) ..........................
Net tax effects ......................................................................................................... .......................... .......................... (30,960 ) Cost Center Ceiling ................................................................................................. .......................... .......................... $345,040 Less: Net book basis to be recovered ............................................................................ .......................... .......................... 352,400 REQUIRED WRITE-OFF, net of tax .......................................................................... .......................... .......................... $(7,360 ) *All carryforward amounts in this example represent amounts which are available for tax purposes and which relate to oil and gas oper￾ations. For accounting purposes, the gross write-off should be recorded to adjust both the oil and gas properties account and the related de￾ferred income taxes. CALCULATION OF GROSS PRE-TAX WRITE-OFF:
Required write-off, net of tax ............................................................................................ ........................ ........................ $(7,360 ) Divided by (100% minus the statutory rate of 46%) ...................................................... ........................ ........................ 54% Gross pre-tax write-off ................................................................................................ ........................ ........................ $(13,630 )
Related Journal Entries DR CR ..........................
Full cost ceiling impairment .................................................................................................... $13,630 ........................ ..........................
Oil and gas assets ...................................................................................................................... ........................ $13,630 ..........................
Deferred income tax liability ................................................................................................... $6,270 ........................ ..........................
Deferred income tax benefit ..................................................................................................... ........................ $6,270 ..........................

2. Exclusion of Costs From Amortization
   Facts: Rule 4–10(c)(3)(ii) indicates that the costs of acquiring and evaluating unproved properties may be excluded from capitalized costs to be amortized if the costs are unusually significant in relation to aggregate costs to be amortized. Costs of major development projects may also be incurred prior to ascertaining the quantities of proved reserves attributable to such properties. Question: At what point should amortization of previously excluded costs commence—when proved reserves have been established or when those reserves become marketable? For instance, a determination of proved reserves may be made before completion of an extraction plant necessary to process sour crude or a pipeline necessary to market the reserves. May the costs continue to be excluded from amortization until the plant or pipeline is in service? Interpretive Response: No. The proved reserves and the costs allocable to such reserves should 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 are established. Once the determination of proved reserves has been made, there is no justification for continued exclusion from the full cost pool, regardless of whether other factors prevent immediate marketing. Moreover, at the same time that the costs are transferred into the amortization base, it is also necessary in accordance with FASB ASC Subtopic 932–835, Extractive Activities—Oil and Gas—Interest and FASB ASC Subtopic 835–20, Interest— Capitalization of Interest, to terminate capitalization of interest on such properties. In this regard, registrants are reminded of their responsibilities not to delay recognizing reserves as proved once they have met the engineering standards.
3. Full Cost Ceiling Limitation
   a. Exemptions for Purchased Properties Facts: During 20x1, a registrant purchases proved oil and gas reserves in place (‘‘the purchased reserves’’) in an arm’s-length transaction for the sum of $9.8 million. Primarily because the registrant expects oil and gas prices to escalate, it paid $1.2 million more for the purchased reserves than the ‘‘Present Value of Estimated Future Net Revenues’’ computed as defined in Rule 4–10(c)(4)(i)(A) of Regulation S–X. An analysis of the registrant’s full cost center in which the purchased reserves are located at December 31, 20x1 is as follows:
   [Amounts in thousands] Total Purchased reserves Other proved properties Unproved properties
   Present value of estimated future net revenues ............................................. $14,100 8,600 5,500 ........................
   Cost, net of amortization ................................................................................. 16,300 9,800 5,500 1,000 Related deferred taxes .................................................................................... 2,300 ........................ 2,000 300
   Income tax effects related to properties .......................................................... 2,500 ........................ 2,500 ........................
   Comparison of capitalized costs with limitation on capitalized costs at De￾cember 31, 20x1: Including purchased reserves Excluding purchased reserves Capitalized costs, net of amortization. ............................................................. ........................ $16,300 $6,500 Related deferred taxes .................................................................................... ........................ (2,300) (2,300) Net book cost ................................................................................................... ........................ 14,000 4,200 Present value of estimated future net revenues ............................................. ........................ 14,100 5,500 Lower of cost or market of unproved properties ............................................. ........................ 1,000 1,000 Income tax effects related to properties .......................................................... ........................ (2,500) (2,500) Limitation on capitalized costs ......................................................................... ........................ 12,600 4,000 Excess of capitalized costs over limitation on capitalized costs, net of tax* .. ........................ 1,400 200

• For accounting purposes, the gross write-off should be recorded to adjust both the oil and gas properties account and the related deferred in￾come taxes.
  Question: Is it necessary for the registrant to write down the carrying value of its full cost center at December 31, 20x1 by $1,400,000? Interpretive Response: Although the net carrying value of the full cost center exceeds the cost center’s limitation on capitalized costs, the text of ASR 258 provides that a registrant may request an exemption from the rule if as a result of a major purchase of proved properties, a write down would be required even though the registrant believes the fair value of the properties in a cost center clearly exceeds the unamortized costs. Therefore, to the extent that the excess carrying value relates to the purchased reserves, the registrant may seek a temporary waiver of the full-cost ceiling limitation from the staff of the Commission. Registrants requesting a waiver should be prepared to demonstrate that the additional value exists beyond reasonable doubt. To the extent that the excess costs relate to properties other than the purchased reserves, however, a write-off should be recorded in the current period. In order to determine the portion of the total excess carrying value which is attributable to properties other than the purchased reserves, it is necessary to perform the ceiling computation on a ‘‘with and without’’ basis as shown in the example above. Thus in this case, the registrant must record a write-down of $200,000 applicable to other reserves. An additional $1,200,000 write-down would be necessary unless a waiver was obtained. b. Use of Cash Flow Hedges in the Computation of the Limitation on Capitalized Costs Facts: Rule 4–10(c)(4) of Regulation S–X provides, in pertinent part, that

capitalized costs, net of accumulated depreciation and amortization, and deferred income taxes, should not exceed an amount equal to the sum of components that include 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. As of the reported balance sheet date, capitalized costs of an oil and gas producing company exceed the full cost limitation calculated under the above￾described rule based on current prices, as defined in Rule 4–10(c)(8) of Regulation S–X, for oil and natural gas. However, prior to the balance sheet date, the company entered into certain hedging arrangements for a portion of its future natural gas and oil production, thereby enabling the company to receive future cash flows that are higher or lower than the estimated future cash flows indicated by use of the average price during the 12-month period prior to the balance sheet date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These arrangements qualify as cash flow hedges under the provisions of FASB ASC Topic 815, Derivatives and Hedging, and are documented, designated, and accounted for as such under the criteria of that standard. Question: Under these circumstances, must the company use the higher or lower prices to be received after taking into account the hedging arrangements (‘‘hedge-adjusted prices’’) in calculating the estimated cash flows from future production of oil and gas reserves covered by the hedges as of the reported balance sheet date? Interpretive Response: Yes. Derivative contracts that qualify as a hedging instrument in a cash flow hedge and are accounted for as such pursuant to FASB ASC Topic 815 represent the type of contractual arrangements for which consideration of price changes should be given under the existing rule. While the SEC staff has objected to previous proposals to consider various hedging techniques as being equivalent to the contractual arrangements permitted under the existing rules, the staff’s objection was based on concerns that the lack of clear, consistent guidance in the accounting literature would lead to inconsistent application in practice. However, the staff believes that FASB ASC Topic 815 and related guidance (including a more systematic approach to documentation) provides sufficient guidance so that comparable financial reporting in comparable factual circumstances should result. This interpretive response reflects the SEC staff’s view that, assuming compliance with the prerequisite accounting requirements, hedge￾adjusted prices represent the best measure of estimated cash flows from future production of the affected oil and gas reserves to use in calculating the ceiling limitation.
Nonetheless, the staff expects that oil and gas producing companies subject to the full cost rules will clearly indicate the effects of using cash flow hedges in calculating ceiling limitations within their financial statement footnotes. The staff further expects that disclosures will indicate the portion of future oil and gas production being hedged. The dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation also should be disclosed. The use of hedge-adjusted prices should be consistently applied in all reporting periods, including periods in which the hedge-adjusted price is more or less than the average price during the 12-month period prior to the balance sheet date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. Oil and gas producers whose computation of the ceiling limitation includes hedge￾adjusted prices because of the use of cash flow hedges also should consider the disclosure requirements under FASB ASC Section 275–10–50, Risks and Uncertainties—Overall-Disclosure. Paragraph 9 of FASB ASC Section 275– 10–50 calls for disclosure when it is at least reasonably possible that the effects of cash flow hedges on capitalized costs on the reported balance sheet date will change in the near term due to one or more confirming events, such as potential future changes in commodity prices. In addition, the use of cash flow hedges in calculating the ceiling limitation may represent a type of critical accounting policy that oil and gas producers should consider disclosing consistent with the cautionary advice provided in Financial Reporting Release No. 60 (Release Nos. 33–8040; 34–45149), Cautionary Advice Regarding Disclosure about Critical Accounting Policies (December 12, 2001), and Financial Reporting Release No. 72 (Release Nos. 33–8350; 34– 48960), Commission Guidance Regarding Management’s Discussion and Analysis of Financial Condition and Results of Operations (December 29, 2003). Through these releases, the Commission has encouraged companies to include, within their MD&A disclosures, full explanations, in plain English, of the judgments and uncertainties affecting the application of critical accounting policies, and the likelihood that materially different amounts would be reported under different conditions or using different assumptions. The staff’s guidance on this issue would apply to calculations of ceiling limitations both in interim and annual reporting periods.
c. Effect of Subsequent Events on the
Computation of the Limitation on Capitalized Costs Facts: Rule 4–10(c)(4)(ii) of Regulation S–X provides that an excess of unamortized capitalized costs within a cost center over the related cost ceiling shall be charged to expense in the period the excess occurs. Question: Assume that at the date of the company’s fiscal year-end, its capitalized costs of oil and gas producing properties exceed the limitation prescribed by Rule 4–10(c)(4) of Regulation S–X. Thus, a write-down is indicated. Subsequent to year-end but before the date of the auditor’s report on the company’s financial statements, assume that additional reserves are proved up (excluding the effect of increased oil and gas prices subsequent to year-end) on properties owned at year-end. The present value of future net revenues from the additional reserves is sufficiently large that if the full cost ceiling limitation were recomputed giving effect to those factors as of year-end, the ceiling would more than cover the costs. Is it necessary to record a write-down? Interpretive Response: No. In this case, the proving up of additional reserves on properties owned at year￾end indicates that the capitalized costs were not in fact impaired at year-end. However, for purposes of the revised computation of the ‘‘ceiling,’’ the net book costs capitalized as of year-end should be increased by the amount of any additional costs incurred subsequent to year-end to prove the additional reserves or by any related costs previously excluded from amortization. While the fact pattern described herein relates to annual periods, the guidance on the effects of subsequent events applies equally to interim period calculations of the ceiling limitation. The registrant’s financial statements should disclose that capitalized costs exceeded the limitation thereon at year￾WReier-Aviles on DSKGBLS3C1PROD with RULES

1 If an obligation for expected asset retirement costs has not been accrued under FASB ASC Subtopic 410–20 for certain asset retirement costs required to be included in the full cost ceiling calculation under Rule 4–10(c)(4) of Regulation S– X, such costs should continue to be included in the full cost ceiling calculation. 2This approach is consistent with the guidance in FASB ASC Subtopic 410–20 on testing for impairment under FASB ASC Section 360–10–35 Property, Plant, and Equipment—Overall— Subsequent Measurement. Under that guidance, the asset tested should include capitalized asset retirement costs. The estimated cash flows related to the associated ARO that has been recognized in the financial statements are to be excluded from both the undiscounted cash flows used to test for recoverability and the discounted cash flows used to measure the asset’s fair value. 3The reference to ‘‘cost of properties described in paragraph (ii) below’’ relates to the costs of investments in unproved properties and major development projects, as defined. end and should explain why the excess was not charged against earnings. In addition, the registrant’s supplemental disclosures of estimated proved reserve quantities and related future net revenues and costs should not give effect to the reserves proved up or the cost incurred after year-end. However, such quantities may be disclosed separately, with appropriate explanations. Registrants should be aware that oil and gas reserves related to properties acquired after year-end would not justify avoiding a write-off indicated as of year-end. Similarly, the effects of cash flow hedging arrangements entered into after year-end cannot be factored into the calculation of the ceiling limitation at year-end. Such acquisitions and financial arrangements do not confirm situations existing at year-end.
4. Interaction of FASB ASC Subtopic
410–20 Asset Retirement and Environmental Obligations—Asset Retirement Obligations—and the Full Cost Rules a. Impact of FASB ASC Subtopic 410– 20 on the Full Cost Ceiling Test Facts: A company following the full cost method of accounting under Rule 4–10(c) of Regulation S–X must periodically calculate a limitation on capitalized costs, i.e., the full cost ceiling. Under FASB ASC Subtopic 410–20, Asset Retirement and Environmental Obligations—Asset Retirement Obligations, a company must recognize a liability for an asset retirement obligation (ARO) at fair value in the period in which the obligation is incurred, if a reasonable estimate of fair value can be made. The company also must initially capitalize the associated asset retirement costs by increasing long-lived oil and gas assets by the same amount as the liability. Any asset retirement costs capitalized pursuant to FASB ASC Subtopic 410–20 are subject to the full cost ceiling limitation under Rule 4–10(c)(4) of Regulation S–X. If a company were to calculate the full cost ceiling by reducing expected future net revenues by the cash flows required to settle the ARO, then the effect would be to ‘‘double-count’’ such costs in the ceiling test. The assets that must be recovered would be increased while the future net revenues available to recover the assets continue to be reduced by the amount of the ARO settlement cash flows. Question: How should a company compute the full cost ceiling to avoid double-counting the expected future cash outflows associated with asset retirement costs? Interpretive Response: The future cash outflows associated with settling AROs that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.12 b. Impact of FASB ASC Subtopic 410– 20 on the Calculation of Depreciation, Depletion, and Amortization Facts: Regarding the base for depreciation, depletion, and amortization (DD&A) of proved reserves, Rule 4–10(c)(3)(i) of Regulation S–X states that ‘‘[c]osts to be amortized shall include (A) all capitalized costs, less accumulated amortization, other than the cost of properties described in paragraph (ii) below; 3 (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.’’ FASB ASC Subtopic 410–20 requires that upon initial recognition of an ARO, the associated asset retirement costs be included in the capitalized costs of the company. Therefore, the estimated dismantlement and abandonment costs described in (C) above may be included in the capitalized costs described in (A) above, at least to the extent that an ARO has been incurred as a result of acquisition, exploration and development activities to date. Future development activities on proved reserves may result in additional asset retirement obligations when
such activities are performed and the associated asset retirement costs will be capitalized at that time. Question: Should the costs to be amortized under Rule 4–10(c)(3) of Regulation S–X include an amount for estimated dismantlement and abandonment costs, net of estimated salvage values, that are expected to result from future development activities? Interpretive Response: Yes. Companies should estimate the amount of dismantlement and abandonment costs that will be incurred as a result of future development activities on proved reserves and include those amounts in the costs to be amortized.
c. Removed by SAB 113
E. Financial Statements of Royalty Trusts Facts: Several oil and gas exploration and production companies have created ‘‘royalty trusts.’’ Typically, the creating company conveys a net profits interest in certain of its oil and gas properties to the newly created trust and then distributes units in the trust to its shareholders. The trust is a passive entity which is prohibited from entering into or engaging in any business or commercial activity of any kind and from acquiring any oil and gas lease, royalty or other mineral interest. The function of the trust is to serve as an agent to distribute the income from the net profits interest. The amount to be periodically distributed to the unitholders is defined in the trust agreement and is typically determined based on the cash received from the net profits interest less expenses of the trustee. Royalty trusts have typically reported their earnings on the basis of cash distributions to unitholders. The net profits interest paid to the trust for any month is based on production from a preceding month; therefore, the method of accounting followed by the trust for the net profits interest income is different from the creating company’s method of accounting for the related revenue. Question: Will the staff accept a statement of distributable income which reflects the amounts to be distributed for the period in question under the terms of the trust agreement in lieu of a statement of income prepared under GAAP? Interpretive Response: Yes. Although financial statements filed with the Commission are normally required to be prepared in accordance with GAAP, the Commission’s rules provide that other presentations may be acceptable in unusual situations. Since the operations of a royalty trust are limited to the distribution of income from the net profits interests contributed to it, the staff believes that the item of primary importance to the reader of the financial statements of the royalty trust is the amount of the cash distributions to the unitholders for the period reported. Should there be any change in the

4Rule 4–10(c)(8) of Regulation S–X defines current price as 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. nature of the trust’s operations due to revisions in the tax laws or other factors, the staff’s interpretation would be reexamined. A note to the financial statements should disclose the method used in determining distributable income and should also describe how distributable income as reported differs from income determined on the basis of GAAP. F. Gross Revenue Method of Amortizing Capitalized Costs Facts: Rule 4–10(c)(3)(iii) of Regulation S–X states in part:
‘‘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.’’ 4 Question: May entities using the full cost method of accounting for oil and gas producing activities compute amortization based on the gross revenue method described in the above rule when substantial production is not subject to pricing regulation? Interpretive Response: Yes. Under the existing rules for cost amortization adopted in ASR 258, the use of the gross revenue method of amortization was permitted in those circumstances where, because of the effect of existing pricing regulations, the use of the units of production method would result in an amortization provision that would be inconsistent with the current sales prices being received. While the effect of regulation on gas prices has lessened, factors other than price regulation (such as changes in typical contract lengths and methods of marketing natural gas) have caused oil and gas prices to be disproportionate to their relative energy content. The staff therefore believes that it may be more appropriate for registrants to compute amortization based on the gross revenue method whenever oil and gas sales prices are disproportionate to their relative energy content to the extent that the use of the units of production method would result in an improper matching of the costs of oil and gas production against the related revenue received. The method should be consistently applied and appropriately disclosed within the financial statements. G. Removed by SAB 113 [FR Doc. E9–26525 Filed 11–3–09; 8:45 am] BILLING CODE 8011–01–P