Annexe 3
SEC Staff Accounting Bulletin
Topic 12: Oil and Gas Producing
Activities
Les Staff Accounting Bulletin (SAB) sont des publications de
la SEC aux Etats-Unis visant à apporter des réponses et des
clarifications concernant l'application de la réglementation
fédérale. L'annexe 3 est une reproduction du Topic 12 traitant
des règles comptables applicables aux activités de recherche et
de production des hydrocarbures.
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
SEC Staff Accounting Bulletin:
Codification of Staff Accounting
Bulletins
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
2. Estimates of future net revenues
3. Disclosure of reserve information
a. Deleted by SAB 103
b. Unproved properties
c. Limited partnership 10-K reports
d. Limited partnership registration statements
e. Rate regulated companies
4. Deleted by SAB 103
B. Deleted by SAB 103
C. Methods Of Accounting By Oil And Gas Producers
1. First-time registrants
2. Consistent use of accounting methods within a consolidated
entity
D. 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
a. Exemptions for purchased properties
b. Use of cash flow hedges in the computation of the
limitation on capitalized costs
c. Effect of subsequent events on the computation of the
limitation on capitalized costs
E. Financial Statements Of Royalty Trusts
F. Gross Revenue Method Of Amortizing Capitalized Costs
G. 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
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Annexe 3 - SAB Topic 12: 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.
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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."
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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 10K 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
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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)?
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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.
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Assumptions:
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Capitalized Costs of Oil and Gas Assets
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$500,000
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Accumulated DD&A
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(100,000)
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Book basis of oil and gas assets
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400,000
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Related deferred income taxes
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35,000
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Net book basis to be recovered
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$365,000
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NOL carryforward*
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$ 20,000
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Foreign tax credit carryforward*
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$ 1,000
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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ITC-Carryforward*
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$2,000
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Present value of ITC relating to future development costs
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1,500
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$ 3,500
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Estimated preference (minimum) tax on percentage depletion in
excess of cost depletion
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$ 500
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Tax basis of oil and gas assets
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$270,000
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Present value of statutory depletion attributable to future
deductions
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$ 10,000
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Statutory tax rate (percent)
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46%
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Present value of future net revenues from proved oil and gas
reserves
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$272,000
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Cost of properties not being amortized
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$ 55,000
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Lower of cost or estimated fair value of unproved properties
included in costs being amortized
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$ 49,000
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CALCULATION
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Present value of future net revenue
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$272,000
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Cost of properties not being amortized
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55,000
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Lower of cost or estimated fair value of unproved properties
included in costs being amortized
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49,000
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Tax Effects:
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Total of above items
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$376,000
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Less: Tax basis of properties
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(270,000)
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Statutory depletion
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(10,000)
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NOL carryforward
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(20,000)
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(300,000)
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Future taxable income
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76,000
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Tax rate (percent)
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x 46%
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Tax payable at statutory rate
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(34,960)
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ITC
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3,500
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Foreign tax credit carryforward
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1,000
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Estimated preference tax
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(500)
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Total tax effects
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(30,960)
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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Cost Center Ceiling
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$345,040
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Less: Net book basis
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365,000
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REQUIRED WRITE-OFF, net of tax**
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($ 19,960)
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* 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:
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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(Amounts in 1,000)
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Other
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Purchased
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Proved
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Unproved
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Total
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Reserves
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Properties
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Properties
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Present value of estimated future net revenues
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$14,100
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8,600
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5,500
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$16,300
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9,800
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5,500
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1,000
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Cost, net of amortization
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$2,300
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___
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2,000
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300
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Related deferred taxes
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Income tax effects related to properties
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$2,500
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___
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2,500
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Comparison of capitalized
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Including
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Excluding
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costs with limitation on
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Purchased
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Purchased
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capitalized costs at December
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Reserves
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Reserves
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31, 20x1:
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Capitalized costs, net of amortization
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$16,300
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$6,500
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Related deferred taxes
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(2,300)
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(2,300)
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Net book cost
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14,000
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4,200
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Present value of estimated future net revenues
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14,100
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$5,500
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Lower of cost or market of unproved properties
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1,000
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1,000
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Income tax effects related to properties
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(2,500)
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(2,500)
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Limitation on capitalized costs
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12,600
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4,000
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Excess of capitalized costs over limitation on Capitalized costs,
net of tax
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$1,400
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$200
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* 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.
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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
writedown 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
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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
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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 yearend. 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 yearend 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.
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.
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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.1 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 410(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
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Annexe 3 - SAB Topic 12: Oil and Gas Producing Activities
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.2 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. Similar language appears in Statements 19 and 25.
2. 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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