SEC Staff Accounting Bulletin:
Codification of Staff Accounting Bulletins

Topic 12: Oil and Gas Producing Activities

1. Accounting Series Release 257 -Requirements For Financial Accounting And Reporting Practices For Oil And Gas Producing Activities

   1. Estimates of quantities of proved reserves

   2. Estimates of future net revenues

   3. Disclosure of reserve information

      1. Deleted by SAB 103

      2. Unproved properties

      3. Limited partnership 10-K reports

      4. Limited partnership registration statements

      5. Rate regulated companies

   4. Deleted by SAB 103

2. Deleted by SAB 103

3. Methods Of Accounting By Oil And Gas Producers

   1. First-time registrants

   2. Consistent use of accounting methods within a consolidated entity

4. Application Of Full Cost Method Of Accounting

   1. Treatment of income tax effects in the computation of the limitation on capitalized costs

   2. Exclusion of costs from amortization

   3. Full cost ceiling limitation

      1. Exemptions for purchased properties

      2. Use of cash flow hedges in the computation of the limitation on capitalized costs

      3. Effect of subsequent events on the computation of the limitation on capitalized costs

   4. Interaction of Statement 143 and the Full Cost Rules

      1. Impact of Statement 143 on the full cost ceiling test

      2. Impact of Statement 143 on the calculation of depreciation, depletion, and amortization

      3. Transition

5. Financial Statements Of Royalty Trusts

6. Gross Revenue Method Of Amortizing Capitalized Costs

7. Inclusion Of Methane Gas In Proved Reserves

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 quantities of proved reserves

Facts: Rule 4-10 contains definitions of proved reserves, proved developed reserves, and proved undeveloped reserves to be used in determining quantities of oil and gas reserves to be reported in filings with the Commission.

Question 1: The definition of proved reserves states that reservoirs are considered proved if "economic producibility is supported by either actual production or conclusive formation test." May oil and gas reserves be considered proved if economic producibility is supported only by core analyses and/or electric or other log interpretations?

Interpretive Response: Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test.

Question 2: In determining whether "proved undeveloped reserves" encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? The definition in Rule 4-10(a)(4) does not make this distinction between pressure maintenance activity and fluid injection undertaken for purposes of secondary recovery.

Interpretive Response: The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved.

Question 3: What volumes of natural gas liquids should be reported as net reserves, that portion recovered in a gas processing plant and allocated to the leasehold interest or the total recovered by a plant from net interest gas?

Interpretive Response: Companies should report reserves of natural gas liquids which are net to their leasehold interests, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instructions to Item 3of Securities Act Industry Guide 2 and report such reserves separately and describe the nature of the ownership.

Question 4: 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 the staff will not object to natural gas reserves and production data calculated at other pressure bases, if such other pressure bases are identified in the filing.

2. Estimates of future net revenues

Facts: Paragraphs 30-34 of Statement 69 require the disclosure of the standardized measure of discounted future net cash flows from production of proved oil and gas reserves, computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production as of the latest balance sheet date, less estimated future expenditures (based on current costs) of developing and producing the proved reserves, and assuming continuation of existing economic conditions.

Question 1: For purposes of determining reserves and estimated future net revenues, what price should be used for 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 gas which will be produced after a contract expires or has a redetermination is the current market price at the end of the fiscal year for that category of gas. This price may be increased thereafter only for additional fixed and determinable escalations, as appropriate, for that category of gas. A fixed and determinable escalation is one which is specified in amount and is not based on future events such as rates of inflation.

Question 2: What price should be applied to gas which at the end of a fiscal year is not yet subject to a gas sales contract?

Interpretive Response: The price to be used is the current market price for similarly situated gas at the end of the fiscal year provided the company can reasonably expect to sell the gas at the prevailing market price.

Question 3: To what extent should price increases announced by OPEC or by certain government agencies not yet effective at the date of the reserve report be considered in determining current prices?

Interpretive Response: Current prices should not reflect price increases announced but not yet effective at the date of the reserve valuation, i.e., the end of the fiscal year.

3. Disclosure of reserve information

a. Deleted by SAB 103

b. Unproved properties

Facts: Disclosures of reserve information are based on estimated quantities of proved reserves of oil and gas. Regulation S-K prohibits disclosure of estimated quantities of probable or possible reserves of oil and gas and any estimated value thereof in any document publicly filed with the Commission.

Question: What types of disclosures will be permitted by registrants who wish to indicate that some of their properties have value other than that attributable to proved reserves?

Interpretive Response: The Office of Engineering has, for the past several years, suggested to registrants the following form of disclosure for undeveloped lease acreage:

"In addition to proved reserves, the estimated (or appraised) value of leases or parts of leases to which proved reserves cannot be attributable is $xxx."

The registrant should describe the basis on which the estimate was made. For example, such estimated values are often based on the market demand for leasehold acreage which, in turn, is based on a number of qualitative factors such as proximity to production. If the disclosed amount is based on an appraisal, the person making the appraisal should be named.

c. Limited partnership 10-K reports

Facts: Securities Act Industry Guide 2 contains an exemption from the requirements of the Guide 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 which acquire properties either for drilling and production, or for production of oil, gas, or geothermal steam." Regulation S-X does not contain a similar exemption from the supplemental disclosure requirements of Statement 69.

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 by paragraphs 24-34 of Statement 69?

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 specified by these paragraphs of Statement 69 for partnerships which are the subject of a merger or exchange offer under which various limited partnerships are to be combined into a single entity.

d. Limited partnership registration statements

Facts: The staff requires that a registration statement relating to an offering of limited partnership interests include the most recent year-end balance sheet of the general partner. This is considered necessary for purposes of assessing the financial responsibility of the general partner.

Question: What disclosures of oil and gas reserve information must accompany the balance sheet of the general partner?

Interpretive Response: Disclosures should include oil and gas reserve information that pertains to the balance sheet, i.e., the estimated year-end quantities of proved oil and gas reserves and the estimated future net revenues and present values thereof specified by paragraphs 10-17 and 30-34, respectively, of Statement 69.

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 30-34 of Statement 69?

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. Deleted by SAB 103

B. Deleted 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 because of the position expressed in Statement 25 that successful efforts is considered preferable by the FASB for accounting changes. 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 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: If a parent company uses the successful efforts method of accounting for oil and gas producing activities, may a subsidiary of the parent use the full cost method?

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) of Rule 4-10(c)(4)(i) of Regulation S-X states 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) minimum taxes on tax preference items, and (vi) the impact of statutory (percentage) depletion.

It may often be difficult to allocate net operating loss carryforwards (NOLs) between oil and gas assets and other assets. However, to the extent that the NOLs are clearly attributable to oil and gas operations and are expected to be realized within the carryforward period, they 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 NOLs 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:
Capitalized Costs of Oil and Gas Assets			$500,000
Accumulated DD&A			(100,000)
Book basis of oil and gas assets			400,000
Related deferred income taxes			35,000
Net book basis to be recovered			$365,000
NOL carryforward*			$ 20,000
Foreign tax credit carryforward*			$ 1,000
ITC-Carryforward*		$2,000
Present value of ITC relating to future development costs		1,500	$ 3,500
Estimated preference (minimum) tax on percentage depletion in excess of cost depletion			$ 500
Tax basis of oil and gas assets			$270,000
Present value of statutory depletion attributable to future deductions			$ 10,000
Statutory tax rate (percent)			46%
Present value of future net revenues from proved oil and gas reserves			$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
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
Tax Effects:
Total of above items			$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)		x 46%
Tax payable at statutory rate		(34,960)
ITC		3,500
Foreign tax credit carryforward		1,000
Estimated preference tax		(500)
Total tax effects			(30,960)
Cost Center Ceiling			$345,040
Less: Net book basis			365,000
REQUIRED WRITE-OFF, net of tax**			($ 19,960)

* All carryforward amounts in this example represent amounts which are available for tax purposes and which related to oil and gas operations.

** For accounting purposes, the gross write-off should be recorded to adjust both the oil and gas properties account and the related deferred income taxes.

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 Interpretation 33 and Statement 34 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 1,000)
	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 December 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 income 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 were 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 spot market prices for oil and natural gas. However, prior to the balance sheet date, the company enters 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 than the estimated future cash flows indicated by use of the spot market price as of the reported balance sheet date. These arrangements qualify as cash flow hedges under the provisions of Statement 133 as amended and interpreted, 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 prices to be received after taking into account the hedging arrangements ("hedge-adjusted prices") in calculating the current price of the quantities of its 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 hedging instruments in a cash flow hedge and are accounted for as such pursuant to Statement 133 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. For example, prior to the adoption of Statement 133, hedging activities related to foreign exchange rates were addressed in Statement 52. The use of futures contracts as hedging arrangements was previously addressed in Statement 80. The guidance provided in these Statements differed from Statement 133 in the criteria used to qualify for hedge accounting. However, the staff believes that Statement 133 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 less than the current spot market price. 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 the SOP 94-6. Paragraph 14 of SOP 94-6 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 FR 60. Through this release, 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 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 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 auditors' report on the company's financial statements, assume that one of two events occurs: (1) additional reserves are proved up on properties owned at year-end, or (2) price increases become known which were not fixed and determinable at year-end. The present value of future net revenues from the additional reserves or from the increased prices 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. It is necessary to record a write down?

Interpretive Response: No. In these cases, the proving up of additional reserves on properties owned at year-end or the increase in prices 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. However, the staff cautions registrants that the process of considering subsequent price changes in the determination of whether a ceiling write-down is called for should be similar to the consideration given to other subsequent events under the auditing literature. The staff expects that the date selected for the ceiling recomputation will be consistent from period to period, and bear a logical relationship to the filing date of the affected financial statements. For example, it would seem logical that an oil and gas producing company would consistently make whatever recalculations are necessary at the date the auditors are completing their interim reviews.

The registrant's financial statements should disclose that capitalized costs exceeded the limitation thereon at year-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 or to the price increases occurring after year-end. However, such quantities and amounts 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 Statement 143¹ and the Full Cost Rules

a. Impact of Statement 143 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. Prior to adopting Statement 143, in calculating the full cost ceiling a company reduced the expected future revenues from proved oil and gas reserves by the estimated future expenditures to be incurred in developing and producing such reserves discounted using a factor specified in the rule. While expected future cash flows related to the asset retirement obligation (ARO) were included in the calculation of the ceiling test, no associated asset was recorded. Under Statement 143, a company must recognize a liability for an asset retirement obligation 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 Statement 143 are subject to the full cost ceiling limitation under Rule 4-10(c)(4) of Regulation S-X. If after adoption of Statement 143, a company were to continue calculating 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 1: After adopting Statement 143, 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: After adoption of Statement 143, 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.^2,3

Question 2: What disclosures should the company provide on the interaction of Statement 143 and the full cost rules?

Interpretive Response: In order to inform financial statement users on the interaction of Statement 143 and the full cost rules, a company following such rules is expected to provide appropriate disclosures in the financial statement footnotes and Management's Discussion and Analysis explaining in detail how the adoption of Statement 143 impacts its accounting for oil and gas operations. This disclosure is expected to address each area of accounting that is impacted or expected to be impacted and should specifically address each way that the company's application of full cost accounting has changed as a result of adoption of Statement 143. These disclosures and discussions should include, but are not limited to, how the company's calculation of the ceiling test and depreciation, depletion, and amortization are affected by the adoption of Statement 143.

b. Impact of Statement 143 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 Regulations 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;⁴ (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." Statement 143 requires that upon initial recognition of an ARO, the associated asset retirement costs be included in the capitalized costs of the company. Therefore, subsequent to the adoption of Statement 143, 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: Following the adoption of Statement 143, 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. To the extent that estimated dismantlement and abandonment costs, net of estimated salvage values, have not been included as capitalized costs in the base for computing DD&A because they have not yet been capitalized as asset retirement costs under Statement 143, compliance with Rule 4-10(c)(3) of Regulation S-X continues to require that they be included in the base for computing DD&A. 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. Transition

Question: When will registrants be expected to comply with the accounting and disclosures described in this bulletin?

Interpretive Response: All registrants are expected to apply the accounting and disclosures described in this bulletin prospectively as of the beginning of the first fiscal quarter beginning after the publication of this bulletin in the Federal Register. If a registrant files financial statements with the Commission before applying the guidance in this bulletin, disclosures similar to those described in Staff Accounting Bulletin Topic 11-M should be provided.

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 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.

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 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. Inclusion Of Methane Gas In Proved Reserves

Facts: Because of a concern over worldwide oil and gas supplies, Congress, in 1980, provided for tax incentives (credits) for the production of oil and gas from other than conventional sources. As a consequence, significant amounts of gas are now recovered from seams of coal beds. This gas is referred to as coalbed methane. It is produced using conventional drilling methods, but for various reasons, it may be more costly to produce than oil and gas recovered from customary sources and some reserves may not be economical without the tax credits.

Rule 4-10(a)(1)(i)(A) of Regulation S-X indicates that oil and gas producing activities include the search for crude oil, including condensate and natural gas liquids, or natural gas in their natural states and original locations. Rule 4-10(a)(2)(iii)(D) of Regulation S-X states that estimates of proved reserves do not include (among other things) natural gas that can be recovered from coal.⁵ In addition, the definition of proved oil and gas reserves includes a provision that the quantities of natural gas be recovered from existing reservoirs. Under these definitions, "coalbed methane" gas has generally not been included in the disclosures in Commission filings required by Statement 69. Further, coalbed methane has generally not been counted in proved oil and gas reserves for purposes of the full cost ceiling test in Rule 4-10(c)(4) since that test is based on the same definition of proved oil and gas reserves.

Question: Is it appropriate to consider coalbed methane gas within the definition of proved reserves for purposes of the disclosures relating to oil and gas producing activities and the full cost ceiling test?

Interpretive Response: Yes. The prohibition against the inclusion of gas derived from coal was meant to apply to the recovery of hydrocarbons from the processing of coal. The extraction of methane gas from coalbed seams using conventional methods was not contemplated at the time Rule 4-10(a) was developed. The staff believes that, since coalbed methane gas can be recovered from coal in its natural state and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs (net of the tax credit) and existing operating conditions.⁶ Methane gas from coalbeds (like any other hydrocarbon obtained from conventional reservoirs) that cannot be produced at a profit under current economic and operating conditions, or for which there is no market or any existing method of delivery to the market, cannot be included in the category of proved reserves.

In instances where methane gas is deemed to be economically producible only as a consequence of existing Federal tax incentives, the staff believes that additional disclosure should be provided as to the specific quantities and values of reported proved reserves that are dependent on existing U.S. tax policy together with any other information necessary to inform readers of the risks attendant with any future change to existing Federal tax policy.

Endnotes:
1.	Statement of Financial Accounting Standards No. 143 (Statement 143), Accounting for Asset Retirement Obligations, is effective for financial statements issued for fiscal years beginning after June 15, 2002.
2.	If an obligation for expected asset retirement costs has not been accrued under Statement 143 for certain asset retirement costs required to be included in the full cost ceiling calculation under Rule 4-10(c)(4), such costs should continue to be included in the full cost ceiling calculation.
3.	This approach is consistent with the guidance in paragraph 12 of Statement 143 on testing for impairment under Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. 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.
4.	The 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.
5.	Similar language appears in Statements 19 and 25.
6.	Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. (Emphasis added.)

http://www.sec.gov/interps/account/sabcodet12.htm