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SEC Staff Accounting Bulletin: |
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.
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.
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.
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.
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.) |
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