[Federal Register: January 14, 2009 (Volume 74, Number 9)]
[Rules and Regulations]
[Page 2157-2197]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr14ja09-15]
[[Page 2157]]
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Part II
Securities and Exchange Commission
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17 CFR Parts 210, 211 et al.
Modernization of Oil and Gas Reporting; Final Rule
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SECURITIES AND EXCHANGE COMMISSION
17 CFR Parts 210, 211, 229, and 249
[Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08]
RIN 3235-AK00
Modernization of Oil and Gas Reporting
AGENCY: Securities and Exchange Commission.
ACTION: Final rule; interpretation; request for comment on Paperwork
Reduction Act burden estimates.
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SUMMARY: The Commission is adopting revisions to its oil and gas
reporting disclosures which exist in their current form in Regulation
S-K and Regulation S-X under the Securities Act of 1933 and the
Securities Exchange Act of 1934, as well as Industry Guide 2. The
revisions are intended to provide investors with a more meaningful and
comprehensive understanding of oil and gas reserves, which should help
investors evaluate the relative value of oil and gas companies. In the
three decades that have passed since adoption of these disclosure
items, there have been significant changes in the oil and gas industry.
The amendments are designed to modernize and update the oil and gas
disclosure requirements to align them with current practices and
changes in technology. The amendments concurrently align the full cost
accounting rules with the revised disclosures. The amendments also
codify and revise Industry Guide 2 in Regulation S-K. In addition, they
harmonize oil and gas disclosures by foreign private issuers with the
disclosures for domestic issuers.
DATES: Effective Date: January 1, 2010.
Comment Date: Comments on the Paperwork Reduction Act Analysis
should be received on or before February 13, 2009.
ADDRESSES: Comments may be submitted by any of the following methods:
Electronic Comments
Use the Commission's Internet comment form (http://
www.sec.gov/rules/proposed.shtml); or
Send an e-mail to rule-comments@sec.gov. Please include
File Number S7-15-08 on the subject line; or
Use the Federal e-Rulemaking Portal http://
www.regulations.gov. Follow the instructions for submitting comments.
Paper Comments
Send paper submissions in triplicate to Secretary,
Securities and Exchange Commission, 100 F Street, NE., Washington, DC
20549-1090.
All submissions should refer to File Number S7-15-08. This file number
should be included on the subject line if e-mail is used. To help us
process and review your comments more efficiently, please use only one
method. The Commission will post all comments on the Commission's
Internet Web site (http://www.sec.gov/rules/concept.shtml). Comments
also are available for public inspection and copying in the
Commission's Public Reference Room, 100 F Street, NE., Washington, DC
20549, on official business days between the hours of 10 a.m. and 3
p.m. All comments received will be posted without change; we do not
edit personal identifying information from submissions. You should
submit only information that you wish to make available publicly.
FOR FURTHER INFORMATION CONTACT: Ray Be, Special Counsel, Office of
Chief Counsel at (202) 551-3500; Dr. W. John Lee, Academic Petroleum
Engineering Fellow, or Brad Skinner, Senior Assistant Chief Accountant,
Office of Natural Resources and Food at (202) 551-3740; Leslie Overton,
Associate Chief Accountant, Office of Chief Accountant for the Division
of Corporation Finance at (202) 551-3400, Division of Corporation
Finance; or Mark Mahar, Associate Chief Accountant, Jonathan Duersch,
Assistant Chief Accountant, or Doug Parker, Professional Accounting
Fellow, Office of the Chief Accountant at (202) 551-5300; U.S.
Securities and Exchange Commission, 100 F Street, NE., Washington, DC
20549-3628.
SUPPLEMENTARY INFORMATION: We are adopting amendments to Rule 4-10 \1\
of Regulation S-X \2\ and Items 102, 801 and 802 \3\ of Regulation S-
K.\4\ We also are adding new Subpart 1200, including Items 1201 through
1208, to Regulation S-K.
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\1\ 17 CFR 210.4-10.
\2\ 17 CFR 210.
\3\ 17 CFR 229.102, 17 CFR 229.801, and 17 CFR 229.802.
\4\ 17 CFR 229.
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Table of Contents
I. Introduction
A. Background
B. Issuance of the Concept Release
C. Overview of the Comment Letters Received on the Proposing
Release
II. Revisions and Additions to the Definition Section in Rule 4-10
of Regulation S-X
A. Introduction
B. Pricing Mechanism for Oil and Gas Reserves Estimation
1. 12-Month Average Price
2. Prices Used for Disclosure and Accounting Purposes
3. Alternate Pricing Schemes
4. Time Period Over Which the Average Price Is To Be Calculated
C. Extraction of Bitumen and Other Non-Traditional Resources
1. Definition of ``Oil and Gas Producing Activities''
2. Disclosure by Final Products
D. Proved Oil and Gas Reserves
E. Reasonable Certainty
F. Developed and Undeveloped Oil and Gas Reserves
1. Developed Oil and Gas Reserves
2. Undeveloped Oil and Gas Reserves
G. Reliable Technology
1. Definition of the Term ``Reliable Technology''
2. Disclosure of Technologies Used
H. Unproved Reserves--``Probable Reserves'' and ``Possible
Reserves''
1. Probable Reserves
2. Possible Reserves
I. Reserves
J. Other Supporting Terms and Definitions
1. Deterministic Estimate
2. Probabilistic Estimate
3. Analogous Reservoir
4. Definitions of Other Terms
5. Proposed Terms and Definitions Not Adopted
K. Alphabetization of the Definitions Section of Rule 4-10
III. Revisions to Full Cost Accounting and Staff Accounting Bulletin
IV. Updating and Codification of the Oil and Gas Disclosure
Requirements in Regulation S-K
A. Revisions to Items 102, 801, and 802 of Regulation S-K
B. Proposed New Subpart 1200 to Regulation S-K Codifying
Industry Guide 2 Regarding Disclosures by Companies Engaged in Oil
and Gas Producing Activities
1. Overview
2. Item 1201 (General Instructions to Oil and Gas Industry-
Specific Disclosures)
a. Geographic Area
b. Tabular Disclosure
3. Item 1202 (Disclosure of Reserves)
a. Oil and Gas Reserves Tables
i. Disclosure by Final Product Sold
ii. Aggregation
iii. Optional Disclosure of Probable and Possible Reserves
iv. Resources Not Considered Reserves
b. Optional Reserves Sensitivity Analysis Table
c. Separate Disclosure of Conventional and Continuous
Accumulations
d. Preparation of Reserves Estimates or Reserves Audits
e. Reserve Audits and the Contents of Third Party Reports
f. Process Reviews
4. Item 1203 (Proved Undeveloped Reserves)
5. Item 1204 (Oil and Gas Production)
6. Item 1205 (Drilling and Other Exploratory and Development
Activities)
7. Item 1206 (Present Activities)
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8. Item 1207 (Delivery Commitments)
9. Item 1208 (Oil and Gas Properties, Wells, Operations, and
Acreage)
V. Guidance for Management's Discussion and Analysis for Companies
Engaged in Oil and Gas Producing Activities
VI. Conforming Changes to Form 20-F
VII. Impact of Amendments on Accounting Literature
A. Consistency With FASB and IASB Rules
B. Change in Accounting Principle or Estimate
C. Differing Capitalization Thresholds Between Mining Activities
and Oil and Gas Producing Activities
VIII. Application of Interactive Data Format to Oil and Gas
Disclosures
IX. Implementation Date
A. Mandatory Compliance
B. Voluntary Early Compliance
X. Paperwork Reduction Act
A. Background
B. Summary of Information Collections
C. Revisions to PRA Burden Estimates
D. Request for Comment
XI. Cost-Benefit Analysis
A. Background
B. Description of New Rules and Amendments
C. Benefits
1. Average Price and First of the Month Price
2. Probable and Possible Reserves
3. Reserves Estimate Preparers and Reserves Auditors
4. Development of Proved Undeveloped Reserves
5. Disclosure Guidance
6. Updating of Definitions Related to Oil and Gas Activities
7. Harmonizing Foreign Private Issuer Disclosure
D. Costs
1. Probable and Possible Reserves
2. Reserves Estimate Preparers and Reserves Auditors
3. Consistency With IASB
4. Change of Pricing Mechanism
5. Disclosure of PUD Development
6. Increased Geographic Disclosure
7. Harmonizing Foreign Private Issuer Disclosure
XII. Consideration of Burden on Competition and Promotion of
Efficiency, Competition, and Capital Formation
XIII. Final Regulatory Flexibility Analysis
A. Reasons for, and Objectives of, the New Rules and Amendments
B. Significant Issues Raised by Commenters
C. Small Entities Subject to the New Rules and Amendments
D. Reporting, Recordkeeping, and Other Compliance Requirements
E. Agency Action to Minimize Effect on Small Entities
XIV. Update to Codification of Financial Reporting Policies
XV. Statutory Basis and Text of Amendments
I. Introduction
A. Background
On June 26, 2008, the Commission issued a proposing release
(Proposing Release) seeking public comment on proposed amendments to
the disclosure requirements regarding oil and gas companies.\5\ These
proposals encompassed issues that were previously addressed more
generally in a concept release that the Commission issued on December
12, 2007 (Concept Release),\6\ which solicited comment on possible
revisions to the oil and gas reserves disclosure requirements specified
in Rule 4-10 of Regulation S-X \7\ and Item 102 of Regulation S-K.\8\
The Proposing Release also contained proposals not addressed by the
Concept Release related to the updating and codification of Industry
Guide 2.
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\5\ Release No. 33-8935 (June 27, 2008) [73 FR 39181].
\6\ Release No. 33-8870 (Dec. 12, 2007) [72 FR 71610].
\7\ 17 CFR 210.4-10. See Release No. 33-6233 (Sept. 25, 1980)
[45 FR 63660] (adopting amendments to Regulation S-X, including Rule
4-10). The precursor to Rule 4-10 was Rule 3-18 of Regulation S-X,
which was adopted in 1978. See Accounting Series Release No. 253
(Aug. 31, 1978) [43 FR 40688]. See also Accounting Series Release
No. 257 (Dec. 19, 1978) [43 FR 60404] (further amending Rule 3-18 of
Regulation S-X and revising the definition of proved reserves).
\8\ Item 102 of Regulation S-K [17 CFR 229.102]. In 1982, the
Commission adopted Item 102 of Regulation S-K. Item 102 contains the
disclosure requirements previously located in Item 2 of Regulation
S-K. See Release No. 33-6383 (March 16, 1982) [47 FR 11380]. The
Commission also ``recast * * * the disclosure requirements for oil
and gas operations, formerly contained in Item 2(b) of Regulation S-
K, as an industry guide.'' See Release No. 33-6384 (Mar. 16, 1982)
[47 FR 11476].
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We initially adopted our oil and gas disclosure requirements in
1978 and 1982.\9\ Since that time, there have been significant changes
in the oil and gas industry and markets, including technological
advances, and changes in the types of projects in which oil and gas
companies invest their capital.\10\ Prior to our issuance of the
Concept Release and the Proposing Release, many industry participants
had expressed concern that our disclosure rules are no longer in
alignment with current industry practices and therefore limit their
usefulness to the market and investors.\11\
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\9\ The disclosure requirements were introduced pursuant to a
directive in the Energy Policy and Conservation Act of 1975 (the
``EPCA''). The EPCA directed the Commission to ``take such steps as
may be necessary to assure the development and observance of
accounting practices to be followed in the preparation of accounts
by persons engaged, in whole or in part, in the production of crude
oil or natural gas in the United States.'' See 42 U.S.C. 6201-6422.
\10\ See, for example, Daniel Yergin and David Hobbs: ``The
Search for Reasonable Certainty in Reserves Disclosure,'' Oil and
Gas Journal (July 18, 2005).
\11\ See, for example, Greg Courturier, ``Standard & Poor's
Urges SEC to Change Disclosure Rules,'' International Oil Daily
(Dec. 3, 2007); Steve Levine, ``Tracking the Numbers: Oil Firms Want
SEC to Loosen Reserves Rules,'' Wall Street Journal Online (Feb. 7,
2006); Christopher Hope, ``Oil Majors Back Attack on SEC Rules,''
The Daily Telegraph (London) (Feb. 24, 2005); Barrie McKenna,
``Rules undervalue reserves report says: Volumes buried in Canada's
oil sands not counted by SEC's measure,'' The Globe & Mail (Canada)
(Feb. 24, 2005); and ``Deloitte Calls on Regulators to Update Rules
for Oil and Gas Reserves Reporting,'' Business Wire Inc. (Feb. 9,
2005).
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B. Issuance of the Concept Release
The Concept Release addressed the potential implications for the
quality, accuracy and reliability of oil and gas disclosure if the
Commission were to:
Revise the definition of ``proved reserves'' in our rules,
in particular, the criteria used to assess and quantify resources that
can be classified as proved reserves; and
Expand the categories of resources that may be disclosed
in Commission filings to include resources other than proved reserves.
In addition, the Concept Release questioned whether our revised
disclosure rules should be modeled on any particular resource
classification framework currently being used within the oil and gas
industry. We also asked how any revised disclosure rules could be made
flexible enough to address future technological innovation and changes
within the oil and gas industry. The Concept Release sought further
comment on whether the Commission should require independent third-
party assessments of reserves estimates that a company includes in its
filings.
In response to the Concept Release, commenters submitted 80 comment
letters.\12\ We received comment letters from a variety of industry
participants such as accounting firms, engineering consulting firms,
domestic and foreign oil and gas companies, federal government
agencies, individuals, law firms, professional associations, public
interest groups, and rating agencies. We considered these comments and
addressed many of them in issuing the Proposing Release.
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\12\ The public comments we received are available for
inspection in the Commission's Public Reference Room at 100 F St.,
NE., Washington, DC 20549 in File No. S7-29-07. They are also
available on-line at http://www.sec.gov/comments/s7-29-07/
s72907.shtml.
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C. Overview of the Comment Letters Received on the Proposing Release
The Proposing Release sought significantly more detailed comment on
issues raised in the Concept Release, as well as proposed amendments to
the disclosure items in our rules and Industry Guide 2. In response to
the Proposing Release, we received 65 comment letters, again from a
variety of constituents with interests in oil and gas industry
disclosure.
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Almost all commenters supported some form of revision to the
current oil and gas disclosure requirements, particularly given the
length of time that has elapsed since the requirements were initially
adopted.\13\ Commenters provided significantly more detailed comments
on the Proposing Release than on the Concept Release, which did not
include specific proposed regulatory text. We discuss those comments in
detail in the relevant sections of this release. However, in general,
commenters focused on several key issues raised by the Proposing
Release. These issues included the following:
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\13\ See letters from American Association of Petroleum
Geologists (``AAPG''), American Clean Skies Foundation (``American
Clean Skies''), American Petroleum Institute (``API''), AngloGold
Ashanti Ltd. (``AngloGold''), Apache Corporation (``Apache''), BHP
Billiton Petroleum (``BHP''), BP Plc. (``BP''), Brookwood Petroleum
Advisors, Ltd. (``Brookwood''), Canadian Association of Petroleum
Producers (``CAPP''), Canadian Natural Resources Ltd. (``Canadian
Natural''), Center for Audit Quality (``CAQ''), Center for Corporate
Policy (``CCP''), CFA Institute Centre for Financial Market
Integrity (``CFA''), Chesapeake Energy Corporation (``Chesapeake''),
Chevron Corporation (``Chevron''), Coeur d'Alene Mines Corporation
(``Coeur''), Cunningham, Peter (``Cunningham''), Davis, Polk &
Wardwell (``Davis Polk''), Deloitte & Touche (``Deloitte''), Devon
Energy Corporation (``Devon''), EnCana Corporation (``EnCana''),
Energen Corporation (``Energen''), Energy Information Administration
(of DOE) (``EIA''), Eni S.p.A. (``Eni''), Equitable Resources, Inc.
(``Equitable''), Ernst & Young (``E&Y''), Evolution Petroleum
Corporation (``Evolution''), ExxonMobil Corporation
(``ExxonMobil''), Federal Energy Regulatory Commission (``FERC''),
Graff Consulting Group LLC (``Graff Consulting''), Grant Thornton
(``Grant Thornton''), Imperial Oil Ltd. (``Imperial''), Independent
Petroleum Association of America (``IPAA''), KPMG (``KPMG''),
Luscher, Brian (``Luscher''), Magoto, Joseph (``Magoto''), McMoRan
Exploration Co. (``McMoRan''), Newfield Exploration Company
(``Newfield''), Nexen, Inc. (``Nexen''), Peabody Energy Corporation
(``Peabody''), Petro-Canada (``Petro-Canada''), Petroleo Brasileiro
S.A. (``Petrobras''), Petroleos Mexicanos (``PEMEX''), PRA
International Ltd. (``PRA''), PriceWaterhouseCoopers (``PWC''),
Questar Market Resources (``Questar''), RepsolYPF, S.A.
(``Repsol''), Ross Petroleum Ltd. (``Ross''), Ryder Scott Company,
L.P. (``Ryder Scott''), Sasol Ltd. (``Sasol''), Senator Robert
Menendez, Senator Russell D. Feingold, and Senator Bernard Sanders,
U.S. Senate (``Three Senators''), Shearman & Sterling (``Shearman &
Sterling''), Shell International B.V. (``Shell''), Society of
Exploration Geophysicists (``SEG''), Society of Petroleum Engineers
(``SPE''), Society of Petroleum Evaluation Engineers (``SPEE''),
Southwestern Energy Production Company (``Southwestern''), Standard
Advantage (``Standard Advantage''), StatoilHydro (``StatoilHydro''),
Swift Energy Company (``Swift''), Talisman Energy Inc.
(``Talisman''), Total, S.A. (``Total''), van Wyk, Mike (``van
Wyk''), Wagner, Robert (``Wagner''), Zakaib, Geoff (``Zakaib'').
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The proposal to permit disclosure of probable and possible
reserves;
The proposed use of average historical prices to represent
existing economic conditions to determine the economic producibility of
oil and gas reserves for disclosure purposes while continuing to use a
single day year-end price to determine the economic producibility of
reserves for accounting purposes;
The proposed inclusion of bitumen, oil shales, and other
resources in the definition of ``oil and gas producing activities'';
The proposed provision to broaden the types of technology
that a company may use to establish reserves estimates and categories;
The proposed change in the definition of proved
undeveloped reserves to eliminate the ``certainty'' requirement; and
The increased detail of disclosure that would be required
as a result of our proposed definition of ``geographic location.''
II. Revisions and Additions to the Definition Section in Rule 4-10 of
Regulation S-X
A. Introduction
The revisions and additions to the definition section in Rule 4-
10(a) of Regulation S-X \14\ update our reserves definitions to reflect
changes in the oil and gas industry and markets and new technologies
that have occurred in the decades since the current rules were adopted.
Many of the definitions are designed to be consistent with the
Petroleum Resource Management System (PRMS).\15\ Among other things,
the revisions to these definitions address four issues that have been
of particular interest to companies, investors, and securities
analysts:
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\14\ 17 CFR 210.4-10(a).
\15\ The Petroleum Resources Management System is a widely
accepted standard for the management of petroleum resources
developed by several industry organizations. See Society of
Petroleum Engineers, the World Petroleum Council, American
Association of Petroleum Geologists, and the Society of Petroleum
Evaluation Engineers, Petroleum Resources Management System, SPE/
WPC/AAPG/SPEE (2007).
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The use of single-day year-end pricing to determine the
economic producibility of reserves;
The exclusion of activities related to the extraction of
bitumen and other ``non-traditional'' resources from the definition of
oil and gas producing activities;
The limitations regarding the types of technologies that
an oil and gas company may rely upon to establish the levels of
certainty required to classify reserves; and
The limitation in the current rules that permits oil and
gas companies to disclose only their proved reserves.
The revisions of, and additions to, the Rule 4-10 definitions attempt
to address these issues without sacrificing clarity and comparability,
which provide protection and transparency to investors. In addition, to
the extent appropriate, we have revised our proposals so that the final
definitions are more consistent with terms and definitions in the PRMS
to improve compliance and understanding of our new rules.
B. Pricing Mechanism for Oil and Gas Reserves Estimation
1. 12-Month Average Price
The final rules define the term ``proved oil and gas reserves'' in
part as ``those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible--from a given date forward,
from known reservoirs, and under existing economic conditions,
operating methods, and government regulations--prior to the time at
which contracts providing the right to operate expire, unless evidence
indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation.''
The definition states that the economic producibility of a reservoir
must be based on existing economic conditions. It specifies that, in
calculating economic producibility, a company must use a 12-month
average price, calculated as the unweighted arithmetic average of the
first-day-of-the-month price for each month within the 12-month period
prior to the end of the reporting period, unless prices are defined by
contractual arrangements, excluding escalations based upon future
conditions.\16\
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\16\ See Rule 4-10(a)(22)(v) [17 CFR 210.4-10(a)(22)(v)].
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Most commenters supported the use of a 12-month average price to
serve as a proxy for existing economic conditions to determine the
economic producibility of reserves.\17\ Some noted that a 12-month
average price is considered to reflect ``current economic conditions''
by PRMS.\18\ They noted that the use of an average price would reduce
the effects of short term volatility \19\ and seasonality,\20\ while
[[Page 2161]]
maintaining comparability of disclosures among companies.\21\
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\17\ See letters from AngloGold, Apache, API, BHP, BP, Canadian
Natural, CAPP, Chesapeake, Chevron, Devon, EIA, EnCana, Equitable,
Evolution, ExxonMobil, Newfield, Nexen, Petrobras, Petro-Canada,
PWC, Questar, Repsol, Ryder Scott, Sasol, Shell, Southwestern, SPE,
Total, and Wagner.
\18\ See letters from AngloGold, BHP, Equitable, Ryder Scott,
and SPE.
\19\ See letters from Apache, API, BHP, BP, Canadian Natural,
CAPP, Chesapeake, EIA, EnCana, Equitable, Evolution, ExxonMobil,
Imperial, IPAA, Newfield, Petrobras, Petro-Canada, Repsol, Ryder
Scott, SPE, Total, and Wagner.
\20\ See letters from Apache, Canadian Natural, Devon, EnCana,
Evolution, IPAA, Petro-Canada, Repsol, and Ryder Scott.
\21\ See letters from BHP, Canadian Natural, CAPP, Deloitte,
Devon, IPAA, Newfield, Petro-Canada, Total, and Wagner.
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Seven commenters recommended the use of first-of-the-month prices
\22\ instead of the proposed use of end-of-the-month prices because the
use of first-of-the-month prices would provide companies with more time
to estimate their reserves \23\ and they thought that these prices
better reflect the actual price received under typical natural gas
contracts.\24\ Conversely, six commenters recommended the use of a 12-
month daily average price \25\ because they thought that a daily
average price would be more appropriate than a monthly average price.
These commenters noted that oil sales contracts often are based on
daily averages.\26\ Two commenters expressed concern that end-of-the-
month prices are not representative of actual prices because commodity
traders often ``clear their books'' at the end of the month.\27\
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\22\ See letters from Apache, BP, Chesapeake, Chevron, Devon,
Repsol, and Shell.
\23\ See letters from Chesapeake, Devon, and Shell.
\24\ See letters from Apache, Newfield, and Repsol.
\25\ See letters from Canadian Natural, CAPP, EnCana, Nexen,
Petro-Canada, and Repsol.
\26\ See letter from Newfield.
\27\ See letters from Apache and Shell.
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One commenter opposed the use of average prices stating that,
conceptually, the use of average prices is poor regulatory policy and
may encourage the market to pressure standard setters to use historical
average prices for financial instruments and other assets and
liabilities associated with volatile markets.\28\ It noted that
volatility reflects the underlying economics of the oil and gas
industry.\29\
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\28\ See letter from CFA.
\29\ See letter from CFA.
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The objective of reserves estimation is to provide the public with
comparable information about volumes, not fair value, of a company's
reserves available to enable investors to compare the business
prospects of different companies. The use of a 12-month average
historical price to determine the economic producibility of reserves
quantities increases comparability between companies' oil and gas
reserve disclosures, while mitigating any additional variability that a
single-day price may have on reserve estimates. Although oil and gas
prices themselves are subject to market-based volatility, the
estimation of reserves quantities based on any historical price
assumption determines those reserves quantities as if the oil or gas
already has been produced, even though they have not, and these
measures do not attempt to portray a reflection of their fair value. If
the objective of reserve disclosures were to provide fair value
information, we believe a pricing system that incorporates assumptions
about estimated future market prices and costs related to extraction
could be a more appropriate basis for estimation.
In order to provide disclosures which are more consistent with the
objective of comparability, the amendments state that the existing
economic conditions for determining the economic producibility of oil
and gas reserves include the 12-month average price, calculated as the
unweighted arithmetic average of the first-day-of-the-month price for
each month within the 12-month period prior to the end of the reporting
period.\30\ For example, a company with a reporting year end of
December 31 would determine its reserves estimates for its annual
report based on the average of the prices for oil or gas on the first
day of every month from January through December. Therefore, the use of
a 12-month average price provides companies with the ability to
efficiently prepare useful reserve information without sacrificing the
objective of comparability. We believe that the revised definition of
the term ``proved oil and gas reserves'' will provide investors with
improved reserves information thereby enhancing their ability to
analyze the disclosures.
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\30\ See new Rule 4-10(a)(22)(v) of Regulation S-X [17 CFR
210.4-10(a)(22)(v)].
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2. Prices Used for Disclosure and Accounting Purposes
A proposal that resulted in significant comment was the use of a
12-month average price to estimate reserves for disclosure purposes,
but a single-day, year-end price for accounting purposes.\31\ All
commenters addressing the issue of using different prices to determine
reserves for disclosure and accounting opposed the proposal.\32\ We are
not adopting this aspect of the proposal. Instead, we are revising both
our disclosure rules and our full-cost accounting rules related to oil
and gas reserves to use a single price based on a 12-month average.\33\
We also will continue to communicate with the FASB staff to align their
accounting standards with these rules.
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\31\ Currently, companies use a single-day, year-end price to
determine the quantity of its proved reserves. From an accounting
perspective, the quantity of those reserves, while not included on
the balance sheet, is used to determine the depreciation, depletion
and amortization of certain capitalized costs included on the
balance sheet. If the final rule retained a single-day, year-end
price for determining reserves for accounting purposes (i.e. , for
determining depreciation, depletion and amortization), then
companies would effectively be required to calculate reserves twice,
using two different pricing assumptions--once for disclosure
purposes and once for accounting purposes. Similarly, under the full
cost rules, the full cost ceiling test, as described in Section III
of this release, would have similar implications.
\32\ See letters from Apache, API, Audit Quality, BHP, BP,
Canadian Natural, CAPP, CFA, Chesapeake, Chevron, Deloitte, Devon,
E&Y, EnCana, Energen, Eni, Equitable, Evolution, ExxonMobil, Grant
Thornton, Imperial, KPMG, McMoRan, Newfield, Nexen, PEMEX,
Petrobras, Petro-Canada, PWC, Questar, Repsol, Ross, Ryder Scott,
Sasol, Shell, Southwestern, SPEE, StatoilHydro, Swift, Talisman,
Total, and Wagner.
\33\ See Rule 4-10.
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Commenters pointed out that the use of two different prices for
disclosure and accounting purposes could:
Confuse investors and other users of financial
statements.\34\
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\34\ See letters from Audit Quality, BHP, Canadian Natural,
CAPP, Chesapeake, Deloitte, Devon, Evolution, ExxonMobil, Imperial,
Newfield, Nexen, Petrobras, Petro-Canada, PWC, Questar, Repsol,
Ryder Scott, Shell, Swift, Talisman, Total, and Wagner.
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Create misleading information; \35\
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\35\ See letters from BP, CFA, Devon, Eni, Nexen, Repsol, and
Wagner.
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Harm comparability; \36\
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\36\ See letters from Apache, Canadian Natural, CAPP, Questar,
StatoilHydro, and Wagner.
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Decrease transparency; \37\
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\37\ See letters from Canadian Natural, CAPP, ExxonMobil, Shell,
Swift, and Wagner.
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Increase costs and burden significantly; \38\
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\38\ See letters from Apache, Audit Quality, BHP, Canadian
Natural, CAPP, Chevron, Deloitte, Devon, Eni, Equitable, Evolution,
ExxonMobil, Imperial, McMoRan, Newfield, Nexen, Petrobras, Questar,
Petro-Canada, PWC, Ryder Scott, Shell, Swift, Total, and Wagner.
---------------------------------------------------------------------------
Increase the complexity of disclosures; \39\
---------------------------------------------------------------------------
\39\ See letters from CAPP, CFA, and Devon.
---------------------------------------------------------------------------
Double recordkeeping burden; \40\
---------------------------------------------------------------------------
\40\ See letters from Apache, Chesapeake, Eni, Equitable, and
Imperial.
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Require more disclosure to explain the differences in
reserves estimates; and \41\
---------------------------------------------------------------------------
\41\ See letters from CAPP, Devon, Eni, ExxonMobil, Imperial,
and Wagner.
---------------------------------------------------------------------------
Break the connection between disclosures and
accounting.\42\
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\42\ See letters from Apache, Audit Quality, CAPP, CFA,
Deloitte, E&Y, Energen, Eni, ExxonMobil, Imperial, KPMG, Newfield,
PWC, Repsol, and Total.
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Some commenters noted that the disclosure and accounting rules and
guidance do not use a different pricing method in other situations.\43\
In addition, several commenters believed that changing to the use of an
average price to estimate proved reserves would have a minimal impact
on depreciation and net income.\44\ We believe that changing the rules
to use a 12-month average price in reserves estimations is
[[Page 2162]]
not inconsistent with the principles and objectives of financial
reporting in authoritative accounting guidance.
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\43\ See letters from API, CAPP, and Shell.
\44\ See letters from API, Canadian Natural, EnCana, ExxonMobil,
and Total.
---------------------------------------------------------------------------
With respect to accounting pronouncements that currently make
reference to a single-day pricing regime with respect to oil and gas
reserves, we are communicating with the FASB staff to align the
standards used in its pronouncements with the 12-month average price
used in our new rules, as several commenters recommended.\45\ As
discussed in more detail below, we are adopting a compliance date that
will provide sufficient time to coordinate such activities with the
FASB. However, as we discuss our revisions with the FASB, we will
consider whether to delay the compliance date further.
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\45\ See letters from Apache, BHP, Canadian Natural, CAPP, CFA,
Deloitte, McMoRan, Newfield, Nexen, Questar, Southwestern, Talisman,
and Total.
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3. Alternate Pricing Schemes
Some commenters on the Proposing Release believed that oil and gas
futures prices, or management's forecast of future prices, would better
represent the value of the reserves \46\ and be better aligned with
fair value of the reserves.\47\ They indicated that management uses
futures prices, not historical prices, in its planning and day-to-day
decision making.\48\ They suggested that the use of futures prices,
combined with disclosure of how management made the estimates, would
provide greater transparency \49\ and comparability of disclosure.\50\
One noted that historical prices have little to do with a company's
future investments and values.\51\ Another commenter noted that
differentials can be calculated through established accounting
procedures under SFAS 157.\52\
---------------------------------------------------------------------------
\46\ See letters from CFA, Deloitte, Grant Thornton, and
McMoRan.
\47\ See letters from CFA and Deloitte.
\48\ See letters from CFA, Grant Thornton, and McMoRan.
\49\ See letter from Deloitte.
\50\ See letters from Deloitte and McMoRan.
\51\ See letter from McMoRan.
\52\ See letter from CFA.
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However, other commenters argued that futures prices are not
available for all reserves locations \53\ and that applying
differentials to prices would require subjective estimates and reduce
comparability among companies.\54\ Two commenters noted that standard
prices are not consistently available in some geographic regions.\55\
Similarly, two commenters were concerned that futures price estimates
would have to be accompanied by estimates of future costs, which they
thought would be very subjective and not comparable for determining
future economic conditions.\56\ One commenter asserted that the use of
future prices would require companies to document assumptions about
future costs, or else the disclosure would be very inconsistent among
reporting companies.\57\ Three commenters believed that futures prices
are more subject to market perceptions than market realities and are
seldom used in actual physical trading of oil and gas.\58\
---------------------------------------------------------------------------
\53\ See letters from ExxonMobil and Wagner.
\54\ See letters from EnCana, Evolution, ExxonMobil, Newfield,
Ryder Scott, and Total.
\55\ See letters from Ryder Scott and Total.
\56\ See letters from SPE and Total.
\57\ See letter from SPE.
\58\ See letters from Evolution, Ryder Scott, and Wagner.
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We share the concerns of many of these commenters that
determinations of expected future prices could require significant
estimations which could fall into a wide, albeit reasonable, range. For
example, in many situations and parts of the world, natural gas is sold
through longer term contracts where observable market inputs are not
widely available. As a result, there could be less comparability among
different companies depending on their assumptions, which are inherent
in determining futures prices. Difference in assumptions between
companies could reduce the comparability of reserves information
between those companies.
We believe that the purpose of disclosing reserves estimates is to
provide investors with information that is both meaningful and
comparable. The reserves estimates in our disclosure rules, however,
are not designed to be, nor are they intended to represent, an
estimation of the fair market value of the reserves. Rather, the
reserves disclosures are intended to provide investors with an
indication of the relative quantity of reserves that is likely to be
extracted in the future using a methodology that minimizes the use of
non-reserves-specific variables. By eliminating assumptions underlying
the pricing variable, as any historical pricing method would do,
investors are able to compare reserves estimates where the differences
are driven primarily by reserves-specific information, such as the
location of the reserves and the grade of the underlying resource. We
recognize that energy markets are continuing to develop. Therefore, we
are not adopting a rule that requires companies to use futures prices
to estimate reserves at this time.
4. Time Period Over Which the Average Price Is To Be Calculated
Numerous commenters on the Proposing Release recommended that the
12-month period used to calculate the average price for estimating
reserves should not coincide with the fiscal year, as we proposed.\59\
Most of these commenters recommended a 12-month period running from the
beginning of the fourth quarter of the prior fiscal year through the
end of the third quarter of the present fiscal year. For example, for a
company with a fiscal year end of December 31, the relevant 12-month
period would span from October 1 of the prior year to September 30 of
the fiscal year covered by the annual report.\60\ Several commenters
suggested that we provide a two-month buffer between the end of the
measurement period and the end of the company's fiscal year so that
reserves estimates would be based on prices from November 1 through
October 31 by a company with a fiscal year ending on December 31.\61\
Commenters attributed the need for a buffer period to the accelerated
filing dates for annual reports \62\ and stated that they expected that
the additional time would result in better, more accurate
disclosure.\63\ Others noted that some agreements, like production
sharing contracts and other complex concession agreements, can make
calculations difficult.\64\ One commenter also noted that shifting the
relevant measurement period so that it ends three-months prior to the
fiscal-year end would align economic calculations with technical
calculations, which typically occur at the end of the third
quarter.\65\
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\59\ See letters from Apache, API, BP, Canadian Natural, CAPP,
EnCana, Eni, ExxonMobil, PEMEX, Petro-Canada, Repsol, Ryder Scott,
Sasol, Shell, Total, van Wyk, and Wagner.
\60\ See letters from Apache, API, BP, Canadian Natural, CAPP,
Devon, Eni, ExxonMobil, PEMEX, Petro-Canada, Repsol, Ryder Scott,
Sasol, Shell, Total, van Wyk, and Wagner.
\61\ See letters from Canadian Natural, CAPP, Eni, Nexen, and
Petro-Canada.
\62\ See letters from API, Canadian Natural, CAPP, Devon,
Evolution, PEMEX, Petrobras, Ryder Scott, Sasol, Shell, Total, and
Wagner.
\63\ See letters from Canadian Natural, CAPP, Nexen, Petrobras,
Petro-Canada, Ryder Scott, Sasol, and Wagner.
\64\ See letters from API and Shell.
\65\ See letter from Shell.
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As noted above, we have considered all of these recommendations. We
are adopting a pricing formula based on the average of prices at the
beginning of each month in the 12-month period prior to the end of the
reporting period. A number of commenters believed that the use of
first-of-the-month prices essentially would provide companies with one
month more to prepare the reserves disclosures,\66\ while still
[[Page 2163]]
aligning the time period with the fiscal year.\67\ We agree with the
commenters that such an average will provide companies more time to
prepare more accurate disclosure, while still tying the pricing formula
to the period covered by the annual report.
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\66\ See letters from API, Devon, Eni, Evolution, ExxonMobil,
PEMEX, Petrobras, PWC, Repsol, and Total.
\67\ See letters from Devon and ExxonMobil.
---------------------------------------------------------------------------
C. Extraction of Bitumen and Other Non-Traditional Resources
1. Definition of ``Oil and Gas Producing Activities''
Our current definition of ``oil and gas producing activities''
explicitly excludes sources of oil and gas from ``non-traditional'' or
``unconventional'' sources, that is, sources that involve extraction by
means other than ``traditional'' oil and gas wells.\68\ These other
sources include bitumen extracted from oil sands, as well as oil and
gas extracted from coal and shales, even though some of these resources
are sometimes extracted through wells, as opposed to mining and surface
processing. However, such sources are increasingly providing energy
resources to the world due in part to advancements in extraction and
processing technology.\69\ Therefore, the rules we adopt today revise
the definition of ``oil and gas producing activities'' to include such
activities.\70\
---------------------------------------------------------------------------
\68\ See Rule 4-10(a)(1)(ii)(D) [17 CFR 210.4-10(a)(1)(ii)(D)].
\69\ Commenters noted that unconventional resources currently
represent 45% of natural gas production in the U.S. See letters from
American Clean Skies and IPAA.
\70\ See Rule 4-10(a)(16) [17 CFR 210.4-10(a)(16)].
---------------------------------------------------------------------------
All commenters on this issue supported including the extraction of
unconventional resources as oil and gas producing activities.\71\ They
believed that such inclusion would greatly improve the quality and
completeness of the disclosures.\72\ Eight commenters noted that
inclusion would better align disclosure with the way that companies
view their operations.\73\ Some noted that, although the distinction
was reasonable decades ago when traditional resources dominated oil and
gas production, the reality of today is that such unconventional
resources are mainstream and companies invest significant amounts of
capital to develop these resources.\74\
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\71\ See letters from American Clean Skies, Apache, API,
Canadian Natural, CAPP, CAQ, CFA, Davis Polk, Devon, E&Y, EnCana,
ExxonMobil, FERC, Imperial, IPAA, KPMG, Nexen, Petrobras, Petro-
Canada, PRA, PWC, Repsol, Ryder Scott, Sasol, Shell, SPE,
StatoilHydro, Talisman, Total, and Wagner.
\72\ See letters from API, CAPP, CAQ, ExxonMobil, Imperial, PWC,
Repsol, Ryder Scott, Total, and Wagner.
\73\ See letters from API, CAQ, E&Y, ExxonMobil, Imperial,
Petro-Canada, PWC, and Total.
\74\ See letters from Imperial, IPAA, Repsol, and Total.
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The revised definition of ``oil and gas producing activities'' that
we adopt today includes the extraction of the non-traditional resources
described above.\75\ This amendment is intended to shift the focus of
the definition of ``oil and gas producing activities'' to the final
product of such activities, regardless of the extraction technology
used. The amended definition states specifically that oil and gas
producing activities include the extraction of saleable hydrocarbons,
in the solid, liquid, or gaseous state, from oil sands, shale,
coalbeds, or other nonrenewable natural resources which are intended to
be upgraded into synthetic oil or gas, and activities undertaken with a
view to such extraction.\76\
---------------------------------------------------------------------------
\75\ See Rule 4-10(a)(16) [17 CFR 210.4-10(a)(16)].
\76\ A hydrocarbon product is saleable if it is in a state in
which it can be sold even if there is no ready market for that
hydrocarbon product in the geographic location of the project. The
absence of a market does not preclude the activity from being
considered an oil and gas producing activity. However, in order to
claim reserves for that hydrocarbon product from a particular
location, there must be a market, or a reasonable expectation of a
market, for that product.
---------------------------------------------------------------------------
Currently, two types of natural resources pose a unique problem to
establishing oil and gas reserves. Coal and, to a lesser degree, oil
shale are used both as direct fuel and as feedstock to be converted
into oil and gas. In response to our request for comment on how best to
treat these resources, several commenters recommended that the
extraction of coal \77\ and oil shale \78\ be categorized based on the
final product. One commenter noted that investment decisions are based
on the value and disposition of the final product.\79\ We agree with
these commenters and have revised the proposal to require a company to
include coal and oil shale that is intended to be converted into oil
and gas as oil and gas reserves. The adopted rules also, however,
prohibit a company from including coal and oil shale that is not
intended to be converted into oil and gas as oil and gas reserves.
---------------------------------------------------------------------------
\77\ See letters from CAPP, ExxonMobil, Ryder Scott, Sasol,
Shell, StatoilHydro, and Wagner.
\78\ See letters from CAPP, ExxonMobil, Shell, StatoilHydro, and
Wagner.
\79\ See letter from ExxonMobil.
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2. Disclosure by Final Products
We proposed that disclosure of reserves would be organized based on
the pre-processed resource extracted from the ground. For example,
under the proposal, a company that extracted bitumen and processed that
bitumen into synthetic crude oil in its own processing plant would have
had to base its reserves disclosure on the amount of bitumen that was
economically producible, not taking into account the economics of the
processing plant. This proposal was consistent with our traditional
separation of ``upstream'' activities such as drilling and producing
oil and gas from ``downstream'' activities such as refining.
Distinguishing between traditional resources and unconventional
resources can be significant to investors because unconventional
resources often involve significantly different economics and company
resources than oil and gas from traditional wells.
Several commenters disagreed with our proposal, recommending that
the determining factor should be the final product.\80\ They believed
that a company should be able to consider the prices of self-processed
resources when estimating oil and gas reserves because the economics of
the processing plant are critical to the registrant's evaluation of the
economic producibility of the resources.\81\ One commenter was
concerned that distinguishing bitumen or other intermediate product
from traditional oil and gas creates a false and misleading sense of
comparability because producers that upgrade bitumen and sell synthetic
crude do not face the same risks and rewards as do producers who sell
the bitumen itself.\82\
---------------------------------------------------------------------------
\80\ See letters from Apache, Nexen, Petrobras, and Ryder Scott.
\81\ See letters from Apache, CAQ, and Nexen.
\82\ See letter from Nexen.
---------------------------------------------------------------------------
We are persuaded by these commenters. However, we believe that the
distinction between a company's traditional and unconventional
activities is an important one from an investor's perspective because
many of the unconventional activities are costlier and, therefore, have
a much higher threshold of economic producibility. Therefore, we are
revising the proposed table in Item 1202 to require separation of
reserves based on final product, but distinguishing between final
products that are traditional oil or gas from final products of
synthetic oil or gas. We believe that with this separate disclosure,
investors will be able to identify resources in projects that produce
synthetic oil or gas that may be more sensitive to economic conditions
from other resources.
In addition, as proposed, we are amending the definition of ``oil
and gas producing activities'' to include activities relating to the
processing or upgrading of natural resources from which synthetic oil
or gas can be
[[Page 2164]]
extracted. However, the definition would continue to exclude:
Transporting, refining, processing (other than field
processing of gas to extract liquid hydrocarbons by the company and the
upgrading of natural resources extracted by the company other than oil
or gas into synthetic oil or gas) or marketing oil and gas;
The production of natural resources other than oil, gas,
or natural resources from which synthetic oil and gas can be extracted;
and
The production of geothermal steam.
D. Proved Oil and Gas Reserves
We proposed to significantly revise the definition of ``proved oil
and gas reserves.'' We are adopting that definition, substantially as
proposed.\83\ However, as noted above, we have decided to base the
price used to establish economic producibility on the average price
during the 12-month period prior to the ending date of the period
covered by the report, determined as an unweighted arithmetic average
of the first-day-of-the-month price for each month within such period.
---------------------------------------------------------------------------
\83\ See Rule 4-10(a)(22) [17 CFR 210.4-10(a)(22)].
---------------------------------------------------------------------------
One commenter recommended against using an average price to
calculate existing economic conditions if the price is set by
contractual arrangements.\84\ We agree that under such circumstances,
the appropriate price to use for establishing economic producibility is
the price set by those contractual arrangements. Therefore, we have
revised the definition to reflect that situation.\85\
---------------------------------------------------------------------------
\84\ See letter from SPE.
\85\ See Rule 4-10(a)(22)(v) [17 CFR 210.4-10(a)(22)(v)].
---------------------------------------------------------------------------
The existing definition of the term ``proved oil and gas reserves''
incorporates certain specific concepts such as ``lowest known
hydrocarbons'' which limit a company's ability to claim proved reserves
in the absence of information on fluid contacts in a well
penetration,\86\ notwithstanding the existence of other engineering and
geoscientific evidence.\87\ We proposed revisions to the definition
that would permit the use of new reliable technologies to establish the
reasonable certainty of proved reserves. The proposed revisions to the
definition of ``proved oil and gas reserves'' also included provisions
for establishing levels of lowest known hydrocarbons and highest known
oil through reliable technology other than well penetrations. We are
adopting those revisions as proposed.
---------------------------------------------------------------------------
\86\ In certain circumstances, a well may not penetrate the area
at which the oil makes contact with water. In these cases, the
company would not have information on the fluid contact and must use
other means to estimate the lower boundary depths for the reservoir
in which oil is located.
\87\ See previous Rule 4-10(a)(2)(i) [17 CFR 210.4-10(a)(2)(i)].
---------------------------------------------------------------------------
We also are adopting, as proposed, revisions that permit a company
to claim proved reserves beyond those development spacing areas that
are immediately adjacent to developed spacing areas if the company can
establish with reasonable certainty that these reserves are
economically producible.\88\ These revisions are designed to permit the
use of alternative technologies to establish proved reserves in lieu of
requiring companies to use specific tests. In addition, they establish
a uniform standard of reasonable certainty that applies to all proved
reserves, regardless of location or distance from producing wells.
---------------------------------------------------------------------------
\88\ See Rule 4-10(a)(22) [17 CFR 210.4-10(a)(22)]. See Section
II.G for a more detailed discussion regarding this provision.
---------------------------------------------------------------------------
E. Reasonable Certainty
Both the existing definition of the term ``proved oil and gas
reserves,'' and the definition of that term that we are adopting in
this release, rely on the term ``reasonable certainty,'' which
previously was not defined in Rule 4-10. In the Proposing Release, we
proposed to define the term ``reasonable certainty'' as ``much more
likely to be achieved than not'' to avoid ambiguity in that term's
meaning. However, several commenters recommended that the rules mirror
the PRMS definition more closely.\89\ Four commenters were concerned
that a different definition from the PRMS would cause confusion. They
recommended using the PRMS standard of ``high degree of confidence that
the quantities will be recovered.'' \90\ One commenter recommended
that, because the proposed definition is new, the Commission should
adopt a safe harbor, to avoid potential uncertainty until a court
interprets the phrase.\91\ But others believed that the proposed
definition is consistent with the PRMS definition.\92\ One commenter
opined that the concept of estimated ultimate recovery (EUR) is
appropriate to establish proved oil and gas reserves.\93\
---------------------------------------------------------------------------
\89\ See letters from EIA, ExxonMobil, and Zakaib.
\90\ See letters from Apache, EIA, Energen, and SPE.
\91\ See letter from Evolution.
\92\ See letters from EnCana, ExxonMobil, Petrobras, and Ryder
Scott.
\93\ Total.
---------------------------------------------------------------------------
We believe that the terms ``high degree of confidence'' from the
PRMS and ``much more likely to be achieved than not'' in our proposal
have the same meaning. Our proposed language was not intended to change
the level of certainty required to establish reasonable certainty.
However, we agree that the use of terminology that is consistent with
the PRMS will assist in the understanding of those terms. Therefore, we
are adopting the ``high degree of confidence'' standard that exists in
the PRMS. We also are clarifying that having a ``high degree of
confidence'' means that a quantity is ``much more likely to be achieved
than not, and, as changes due to increased availability of geoscience
(geological, geophysical, and geochemical), engineering, and economic
data are made to estimated ultimate recovery (EUR) with time,
reasonably certain EUR is much more likely to increase or remain
constant than to decrease'' to provide elaboration to the definition of
reasonable certainty.
We are adopting a definition of ``reasonable certainty'' that
addresses, and permits the use of, both deterministic methods and
probabilistic methods for estimating reserves, as proposed. Nine
commenters supported permitting the use of either deterministic methods
or probabilistic methods.\94\ One commenter believed that each method
may be more appropriate for different situations.\95\ Other commenters
also supported the proposed alignment of the definitions of those terms
with the definitions in the PRMS definitions.\96\ The definition that
we are adopting states that, if deterministic methods are used,
reasonable certainty means a high degree of confidence that the
quantities will be recovered.\97\ Consistent with the PRMS definition,
if probabilistic methods are used, there should be at least a 90%
probability that the quantities actually recovered will equal or exceed
the estimate.
---------------------------------------------------------------------------
\94\ See letters from Apache, Devon, Evolution, Petro-Canada,
Ryder Scott, Shell, SPE, Total, and Wagner.
\95\ See letter from Wagner.
\96\ See letters from AAPG, SPE, and Southwestern.
\97\ See Rule 4-10(a)(24) [17 CFR 210.4-10(a)(24)].
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F. Developed and Undeveloped Oil and Gas Reserves
We proposed to revise the definitions of the terms ``proved
developed oil and gas reserves'' and ``proved undeveloped oil and gas
reserves.'' One commenter noted that the terms ``developed'' and
``undeveloped'' are not restricted to proved oil and gas reserves, but
could apply to all classifications of reserves, including probable and
possible reserves.\98\ We agree with that
[[Page 2165]]
commenter. Although the development of a prospect may provide the
company with more information and data to determine reserves amounts
more accurately, companies may estimate proved, probable, and possible
volumes regardless of the development stage. In the past, these terms
were linked to the concept of proved reserves because our disclosure
rules permitted the disclosure only of proved reserves. In light of our
revision to allow disclosure of probable and possible reserves, the
final rules define the terms ``developed oil and gas reserves'' and
``undeveloped oil and gas reserves'' to indicate that the development
status of the reserves is relevant to all classifications of oil and
gas reserves.\99\
---------------------------------------------------------------------------
\98\ See letter from SPE. We note that with respect to oil and
gas reserves, the term ``classification'' is used to indicate the
level of certainty that estimated amounts will be recovered. Thus,
although the terms ``developed'' and ``undeveloped'' may be
considered means in which to generically ``classify'' reserves, for
clarity, we use that term to be consistent with industry usage.
\99\ See Rules 4-10(a)(6) and (31) [17 CFR 210.4-10(a)(6) and
(31)].
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1. Developed Oil and Gas Reserves
Other than the change discussed above to eliminate ``proved'' from
the term being defined, we are adopting a definition of ``developed oil
and gas reserves'' substantially as proposed. We proposed to define the
term ``proved developed oil and gas reserves'' as proved reserves that:
In projects that extract oil and gas through wells, can be
expected to be recovered through existing wells with existing equipment
and operating methods; and
In projects that extract oil and gas in other ways, can be
expected to be recovered through extraction technology installed and
operational at the time of the reserves estimate.
Two commenters suggested that, consistent with the PRMS, reserves
should be considered developed if the cost of any required equipment is
relatively minor compared to the cost of a new well or the installed
equipment.\100\ Again, we agree that consistency with PRMS would
improve compliance with our rules. In addition, such a revision is
consistent with our existing definition of the term ``proved
undeveloped reserves'' which includes reserves on which a well exists,
but a relatively ``major'' expenditure is required for
recompletion.\101\ Therefore, the final rules provide that reserves
also are developed if the cost of any required equipment is relatively
minor compared to the cost of a new well.\102\
---------------------------------------------------------------------------
\100\ See letters from SPE and Total.
\101\ See previous Rule 4-10(a)(4) [17 CFR 210.4-10(a)(4)].
\102\ See Rule 4-10(a)(6) [17 CFR 210.4-10(a)(6)].
---------------------------------------------------------------------------
2. Undeveloped Oil and Gas Reserves
In the Proposing Release, we proposed a significantly revised
definition of the term ``proved undeveloped oil and gas reserves.'' The
most significant aspect of the proposed revision was the replacement of
the existing ``certainty'' test for areas beyond one offsetting
drilling unit \103\ from a productive well with a ``reasonable
certainty'' test. Currently, the definition of the term ``proved
undeveloped reserves'' imposes a ``reasonable certainty'' standard for
reserves in drilling units immediately adjacent to the drilling unit
containing a producing well and a ``certainty'' standard for reserves
in drilling units beyond the immediately adjacent drilling units.\104\
All commenters on this issue supported the proposal.\105\ Three
commenters noted that a single standard-reasonable certainty-should
apply to all proved reserves.\106\ We are adopting this aspect of the
definition as proposed.
---------------------------------------------------------------------------
\103\ As noted later in this section of the release, we are
replacing the term ``drilling unit'' with the term ``development
spacing area'' in the final rules. However, for purposes of
discussing the proposal and the existing rules, we continue to use
the term ``drilling unit'' because that is the term used in the
proposal and the existing rules.
\104\ See previous Rule 4-10(a)(4) [17 CFR 210.4-10(a)(4)]. A
drilling unit refers to the spacing between wells required by some
local jurisdictions to prevent wasting resources and optimize
recovery.
\105\ See letters from American Clean Skies, Apache, API,
Canadian Natural, CAPP, Chesapeake, Devon, Evolution, ExxonMobil,
McMoRan, Petro-Canada, Questar, Repsol, Southwestern, Shell, SPE,
Total, and Wagner.
\106\ See letters from Devon, EnCana, and Equitable.
---------------------------------------------------------------------------
Many commenters opposed the proposed language that would have
imposed a five-year limit on maintaining undeveloped reserves unless
``unusual'' circumstances existed.\107\ They asserted that large
projects, projects in remote areas, and projects in continuous
accumulations, such as oil sands, typically take more than five years
to develop, but they do not view such projects as ``unusual.'' \108\
One commenter noted that the proposed rule is not consistent with the
PRMS, which uses the term ``specific circumstances,'' rather than
``unusual circumstances.'' \109\ Other commenters suggested that we
require the company to explain why it has not developed any undeveloped
reserves for more than five years.\110\ The intent of the proposal was
not to exclude projects that typically take more than five years to
develop from being considered reserves. We agree that the rule should
allow the recognition of reserves in projects that are expected to run
more than five years, regardless of whether ``unusual'' circumstances
exist. Therefore, we have revised the rule to replace the term
``unusual'' with the term ``specific.'' \111\ We note that, as
proposed, Item 1203 of Regulation S-K would require disclosure
regarding why such undeveloped reserves have not been developed.\112\
---------------------------------------------------------------------------
\107\ See letters from American Clean Skies, Apache, CAPP,
Chesapeake, EnCana, ExxonMobil, Luscher, Newfield, Nexen, Petrobras,
Petro-Canada, Ryder Scott, Shell, SPE, and Total.
\108\ See letters from American Clean Skies, CAPP, Chesapeake,
EnCana, ExxonMobil, Newfield, Nexen, Petrobras, Petro-Canada, Ryder
Scott, Shell, and Total.
\109\ See letter from SPE.
\110\ See letters from Devon, Ryder Scott, and Wagner.
\111\ See Rule 4-10(a)(31) [17 CFR 210.4-10(a)(31)].
\112\ See Item 1203(d) [17 CFR 229.1203(d)].
---------------------------------------------------------------------------
We also proposed to broaden the definition of the term ``proved
undeveloped reserves'' to permit a company to include, in its
undeveloped reserves estimates, quantities of oil that can be recovered
through improved recovery projects and to expand the technologies that
a company can use to establish reserves. Under the existing definition,
a company can include such quantities only if techniques have been
proved effective by actual production from projects in the area and in
the same reservoir. As proposed, we are expanding this definition of
the term ``undeveloped oil and gas reserves'' to permit the use of
techniques that have been proved effective by actual production from
projects in the same reservoir or an analogous reservoir or ``by other
evidence using reliable technology that establishes reasonable
certainty.'' \113\
---------------------------------------------------------------------------
\113\ See Rule 4-10(a)(31) [17 CFR 210.4-10(a)(31)].
---------------------------------------------------------------------------
We also are making other, less substantive revisions to the
definition of ``undeveloped oil and gas reserves.'' First, commenters
suggested that we use the term ``development spacing'' \114\ or
``drainage areas'' \115\ instead of ``drilling units'' because the term
``drilling units'' is only relevant in jurisdictions that establish
such units. They noted that many foreign jurisdictions do not establish
such units. We concur with those commenters and have replaced the term
``drilling units'' with the term ``development spacing areas.''
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\114\ See letter from Total.
\115\ See letter from SPE.
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One commenter also noted that the PRMS guidance on the use of
analogs for improved recovery projects does not limit such use to
``within the immediate area'' and recommended that we delete this
phrase from the definition.\116\ Again, we agree that consistency with
PRMS would be beneficial in this instance and have deleted that phrase
[[Page 2166]]
from the definition. We also have eliminated two paragraphs of the
proposed definition because they were largely repetitive of other
aspects of the definition and were unnecessary.\117\
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\116\ See letter from SPE.
\117\ These paragraphs would have clarified (1) in a
conventional accumulation, offsetting productive units must lie
within an area in which economic producibility has been established
by reliable technology to be reasonably certain and (2) proved
reserves can be claimed in a conventional or continuous accumulation
in a given area in which engineering, geoscience, and economic data,
including actual drilling statistics in the area, and reliable
technology show that, with reasonable certainty, economic
producibility exists beyond immediately offsetting drilling units.
We do not believe that these statements, based on the terms
``conventional accumulation'' and ``continuous accumulation'' which
are no longer being defined continue to serve a helpful purpose. See
Section II.J.5 of this release.
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G. Reliable Technology
1. Definition of the Term ``Reliable Technology''
We are adopting, substantially as proposed, a new definition of
``reliable technology'' that would broaden the types of technologies
that a company may use to establish reserves estimates and categories.
All commenters on this topic supported the proposed principles-based
definition for reliable technology.\118\
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\118\ See letters from AAPG, American Clean Skies, Apache, CFA,
Davis Polk, Devon, EnCana, ExxonMobil, Petrobras, Ryder Scott,
Sasol, Shell, SPE, Southwestern, and Wagner.
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The current rules limit the use of alternative technologies as the
basis for determining a company's reserves disclosures. For example,
under the current rules, a company must use actual production or flow
tests to meet the ``reasonable certainty'' standard necessary to
establish the proved status of its reserves.\119\ Similarly, the
current rules provide bright line tests for determining fluid contacts,
such as lowest known hydrocarbons and highest known oil, which
establish the volume of the hydrocarbons in place.
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\119\ However, in the past, the Commission's staff has
recognized that flow tests can be impractical in certain areas, such
as the Gulf of Mexico, where environmental restrictions effectively
prohibit these types of tests. The staff has not objected to
disclosure of reserves estimates for these restricted areas using
alternative technologies.
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We recognize that technologies have developed, and will continue to
develop, improving the quality of information that can be obtained from
existing tests and creating entirely new tests that we cannot yet
envision. Thus, the new definition of the term ``reliable technology''
permits the use of technology (including computational methods) that
has been field tested and has demonstrated consistency and
repeatability in the formation being evaluated or in an analogous
formation. This new standard will permit the use of a new technology or
a combination of technologies once a company can establish and document
the reliability of that technology or combination of technologies.
We are adopting certain revisions to our proposed definition of the
term ``reliable technology.'' The proposal also would have required
reliable technology to be ``widely accepted.'' However, some commenters
were concerned that this requirement would exclude proprietary
technologies that companies develop internally that have proven to be
reliable.\120\ We concur with these commenters and have removed the
``widely accepted'' requirement from the final rule.
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\120\ See letters from Chesapeake, ExxonMobil, Shell, and Total.
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We also proposed to define the term ``reliable technology,''
expressed in probabilistic terms, as technology that has been proven
empirically to lead to correct conclusions in 90% or more of its
applications. Several commenters expressed concern that this proposed
90% threshold would be difficult to verify and support on an ongoing
basis.\121\ We agree that a bright line test would be difficult to
apply to a particular technology or mix of technologies to determine
their reliability. Therefore, we are not adopting the 90% threshold as
part of the definition.
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\121\ See letters from AAPG, Apache, EIA, Evolution, Ryder
Scott, Shell, SPE, and Wagner.
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2. Disclosure of Technologies Used
The proposal would have required a company to disclose the
technology used to establish reserves estimates and categories for
material properties in a company's first filing with the Commission and
for material additions to reserves estimates in subsequent filings
because, under the proposal, a company would be able to select the
technology or mix of technologies that it uses to establish reserves.
Two commenters supported the proposal because they believed that
disclosure of the technologies used is reasonable if the definition of
``reliable technology'' is principles-based.\122\ However, many other
commenters were concerned that the proposed requirement to disclose the
technologies used to establish levels of certainty for reserves
estimates would lead to very complex, technical disclosures that would
have little meaning to investors.\123\ Others were concerned that
disclosure of the technology, or the mix of technologies, might cause
competitive harm.\124\
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\122\ See letters from Davis Polk and Sasol.
\123\ See letters from API, Devon, Eni, ExxonMobil, PEMEX,
Petro-Canada, Questar, Repsol, Ryder Scott, Shell, Southwestern,
StatoilHydro, and Total.
\124\ See letters from API, Devon, Evolution, ExxonMobil, Ryder
Scott, StatoilHydro, and Total.
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As an alternative, some commenters recommended that the rule
require a more general overview of the technologies used.\125\ We are
clarifying that the required disclosure would be limited to a concise
summary of the technology or technologies used to create the
estimate.\126\ A company would not be required to disclose proprietary
technologies, or a proprietary mix of technologies, at a level of
specificity that would cause competitive harm. Rather, the disclosure
may be more general. For example, a company may disclose that it used a
combination of seismic data and interpretation, wireline formation
tests, geophysical logs, and core data to calculate the reserves
estimate. As noted, however, the Commission's staff, as part of the
review and comment process, may continue to request companies to
provide supplemental data, consistent with current practice,\127\
which, under the new rules, may include information sufficient to
support a company's conclusion that a technology or mix of technologies
used to establish reserves meets the definition of ``reliable
technology.''
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\125\ See letters from EnCana, Eni, Evolution, Ryder Scott, and
Shell.
\126\ See Item 1202(a)(6) [17 CFR 229.1202(a)(6)].
\127\ Currently, the Commission's staff requests supplemental
data pursuant to Instruction 4 to Item 102 of Regulation S-K [17 CFR
229.102], Rule 418 [17 CFR 230.418], and Rule 12b-4 [17 CFR 240.12b-
4]
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Two commenters supported the proposal to limit the disclosures to
technologies used to establish reserves in a company's first filing
with the Commission and material additions to reserves.\128\ We are
adopting this limitation as proposed.\129\ If the company has not
previously disclosed reserves estimates in a filing with the Commission
or is disclosing material additions to its reserves estimates, the
company must disclose the technologies used to establish the
appropriate level of certainty for reserves estimates from material
properties included in the total reserves disclosed and the particular
properties do not need to be identified. We believe that requiring such
disclosure when reserves, or material additions to reserves, are
reported for the first time will discourage the use of questionable
technologies to establish reserves. However, we do not believe it is
necessary to require a company to disclose the technology or
technologies
[[Page 2167]]
relied upon to establish reserves previously disclosed under our rules
because the permitted technologies have been limited to those permitted
by our existing rule. In addition, we believe that ongoing disclosure
of the technologies used to establish all of a company's reserves would
become unnecessarily cumbersome.
---------------------------------------------------------------------------
\128\ See letters from Southwestern and Wagner.
\129\ See Item 1202(a)(6) [17 CFR 229.1202(a)(6)].
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H. Unproved Reserves--``Probable Reserves'' and ``Possible Reserves''
As discussed more fully in Section IV.B.3 of this release
addressing the disclosure requirements of new Subpart 1200, we are
adopting the proposal to permit disclosure of probable and possible
reserves. Therefore, we are adopting the proposed definitions of the
terms ``probable reserves'' and ``possible reserves'' as proposed.
When producing an estimate of the amount of oil and gas that is
recoverable from a particular reservoir, a company can make three types
of estimates:
An estimate that is reasonably certain;
An estimate that is as likely as not to be achieved; and
An estimate that might be achieved, but only under more
favorable circumstances than are likely.
These three types of estimates are known in the industry as (1) proved,
(2) proved plus probable, and (3) proved plus probable plus possible
reserves estimates.
1. Probable Reserves
We are adopting the definition of the term ``probable reserves'' as
proposed. It states that ``probable reserves'' are those additional
reserves that are less certain to be recovered than proved reserves but
which, in sum with proved reserves, are as likely as not to be
recovered.\130\ This definition provides guidance for the use of both
deterministic and probabilistic methods. The definition clarifies that,
when deterministic methods are used, it is as likely as not that actual
remaining quantities recovered will equal or exceed the sum of
estimated proved plus probable reserves. Similarly, when probabilistic
methods are used, there must be at least a 50% probability that the
actual quantities recovered will equal or exceed the proved plus
probable reserves estimates. This definition was derived from the PRMS
definition of the term ``probable reserves.'' Several commenters agreed
with the proposed definition of this term, noting that it is roughly
consistent with PRMS.\131\
---------------------------------------------------------------------------
\130\ See Rule 4-10(a)(18) [17 CFR 210.4-10(a)(18)].
\131\ See letters from Devon, EnCana, SPE, and StatoilHydro.
---------------------------------------------------------------------------
2. Possible Reserves
We also are adopting the definition of the term ``possible
reserves'' as proposed. The new definition states that possible
reserves include those additional reserves that are less certain to be
recovered than probable reserves.\132\ It clarifies that, when
deterministic methods are used, the total quantities ultimately
recovered from a project have a low probability to exceed the sum of
proved, probable, and possible reserves. When probabilistic methods are
used, there must be at least a 10% probability that the actual
quantities recovered will equal or exceed the sum of proved, probable,
and possible estimates. Several commenters noted that our proposed
definition of the term ``possible reserves'' was consistent with PRMS,
which also uses a 10% threshold.\133\ One commenter recommended that
the threshold for ``possible reserves'' should be a 25% likelihood of
recovery because that percentage would be more meaningful than
10%.\134\ We believe that a definition consistent with the PRMS will
provide the most certainty and clarity for companies and investors.
---------------------------------------------------------------------------
\132\ See Rule 4-10(a)(17) [17 CFR 210.4-10(a)(17)].
\133\ See letters from Devon, EnCana, SPE, and StatoilHydro.
\134\ See letter from Evolution.
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I. Reserves
We proposed to add a definition of the term ``reserves'' to our
rules. The proposed definition would have described the criteria that
an accumulation of oil, gas, or related substances must satisfy to be
considered reserves (of any classification), including non-technical
criteria such as legal rights. Specifically, we proposed to define
reserves as the estimated remaining quantities of oil and gas and
related substances anticipated to be recoverable, as of a given date,
by application of development projects to known accumulations based on:
Analysis of geoscience and engineering data;
The use of reliable technology;
The legal right to produce;
Installed means of delivering the oil, gas, or related
substances to markets, or the permits, financing, and the appropriate
level of certainty (reasonable certainty, as likely as not, or possible
but unlikely) to do so; and
Economic producibility at current prices and costs.
The proposed definition also would have clarified that reserves are
classified as proved, probable, and possible according to the degree of
uncertainty associated with the estimates. We are not adopting the
definition as proposed. Four commenters recommended clarification that
the term ``legal right to produce'' extends beyond the initial term of
an oil and gas concession if there is a reasonable expectation that the
concession will be renewed, consistent with the PRMS and current staff
position.\135\ We are adopting a definition of the term ``reserves''
that more closely parallels the PRMS definition of that term.
---------------------------------------------------------------------------
\135\ See letters from API, CAQ, Grant Thornton, and KPMG.
---------------------------------------------------------------------------
Our final rules define the term ``reserves'' as the estimated
remaining quantities of oil and gas and related substances anticipated
to be economically producible, as of a given date, by application of
development projects to known accumulations.\136\ In addition, there
must exist, or there must be a reasonable expectation that there will
exist, the legal right to produce or a revenue interest in the
production of oil and gas, installed means of delivering oil and gas or
related substances to market, and all permits and financing required to
implement the project.
---------------------------------------------------------------------------
\136\ See Rule 4-10(a)(26) [17 CFR 210.4-10(a)(26)].
---------------------------------------------------------------------------
A note to the definition clarifies that reserves should not be
assigned to adjacent reservoirs isolated by major, potentially sealing,
faults until those reservoirs are penetrated and evaluated as
economically producible and that reserves should not be assigned to
areas that are clearly separated from a known accumulation by a non-
productive reservoir (i.e., absence of reservoir, structurally low
reservoir, or negative test results). Such areas may contain
prospective resources (i.e., potentially recoverable resources from
undiscovered accumulations).\137\
---------------------------------------------------------------------------
\137\ See Note to Rule 4-10(a)(26) [17 CFR 210.4-10(a)(26)].
---------------------------------------------------------------------------
One notable difference between our final definition of ``reserves''
and the PRMS definition is that our definition is based on ``economic
producibility'' rather than ``commerciality.'' One commenter believed
that reserves must be ``commercial,'' as stated in the PRMS
definition.\138\ However, commerciality introduces a subjective aspect
to the price used to establish existing economic conditions by
factoring in the rate of return required by a particular company before
it will commit resources to the project. This rate of return will vary
among companies, reducing the comparability among disclosures.
Therefore, the adopted definition of the term ``reserves'' relies on
economic producibility, as proposed.
---------------------------------------------------------------------------
\138\ See letter from StatoilHydro.
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[[Page 2168]]
J. Other Supporting Terms and Definitions
We also proposed to define several other terms primarily to support
and clarify the definitions of the key terms. We are adopting most of
those supporting definitions as discussed in further detail below.
1. Deterministic Estimate
A company can derive two different types of reserves estimates
depending on the method used to calculate the estimates. These two
types of estimates are known as ``deterministic estimates'' and
``probabilistic estimates.'' \139\ In the Proposing Release, we
proposed to define the term ``deterministic estimate'' as an estimate
based on a single value for each parameter (from the geoscience,
engineering, or economic data) in the reserves calculation that is used
in the reserves estimation procedure. We are adopting that definition
as proposed.
---------------------------------------------------------------------------
\139\ See Rules 4-10(a)(5) and (a)(19) [17 CFR 210.4-10(a)(5)
and (a)(19)]. These definitions are based on the Canadian Oil and
Gas Evaluation Handbook (COGEH). This handbook was developed by the
Calgary Chapter of the Society of Petroleum Evaluation Engineers and
the Petroleum Society of CIM to establish standards to be used
within the Canadian oil and gas industry in evaluating oil and gas
reserves and resources.
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2. Probabilistic Estimate
We are adopting a new definition of the term ``probabilistic
estimate'' substantially as proposed. The new rule defines the term
``probabilistic estimate'' as an estimate that is obtained when the
full range of values that could reasonably occur from each unknown
parameter (from the geoscience and engineering data) is used to
generate a full range of possible outcomes and their associated
probabilities of occurrence.\140\ In response to a comment received,
however, we revised the definition so that it does not include the
application of a range of values with respect to economic conditions
because those conditions, such as prices and costs, are based on
historical data, and therefore are an established value, rather than a
range of estimated values.\141\
---------------------------------------------------------------------------
\140\ See Rule 4-10(a)(19) [17 CFR 210.4-10(a)(19)].
\141\ See letter from Shell.
---------------------------------------------------------------------------
3. Analogous Reservoir
We proposed a definition of the term ``analogous formation in the
immediate area.'' As noted above, we received comment indicating that
the use of appropriate analogs should not be limited to the immediate
area in which the reserves are being estimated.\142\ Therefore, we have
changed the defined term to ``analogous reservoir.'' \143\ In addition,
based on commenters' remarks, we are defining the term ``analogous
reservoir'' in a manner that is more consistent with the PRMS, which
addresses more specifically the types of reservoirs that may be used as
analogues. The new definition of the term ``analogous reservoir''
states that analogous reservoirs, as used in resources assessments,
have similar rock and fluid properties, reservoir conditions (depth,
temperature, and pressure) and drive mechanisms, but are typically at a
more advanced stage of development than the reservoir of interest and
thus may provide concepts to assist in the interpretation of more
limited data and estimation of recovery.\144\ When used to support
proved reserves, an ``analogous reservoir'' refers to a reservoir that
shares the following characteristics with the reservoir of interest:
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\142\ See letter from SPE.
\143\ See Rule 4-10(a)(2) [17 CFR 210.4-10(a)(2)].
\144\ See Rule 4-10(a)(2) [17 CFR 210.4-10(a)(2)].
---------------------------------------------------------------------------
Same geological formation (but not necessarily in pressure
communication with the reservoir of interest);
Same environment of deposition;
Similar geological structure; and
Same drive mechanism.
As proposed, the new definition includes an instruction that clarifies
that reservoir properties must, in the aggregate, be no more favorable
in the analog than in the reservoir of interest. The new definition
also clarifies that, although an analogous reservoir must be in the
same geological formation as the reservoir of interest, it need not be
in pressure communication with the reservoir of interest.
4. Definitions of Other Terms
We received no comment with regard to several of the proposed
supporting definitions. We are adopting those definitions substantially
as proposed without material changes. They include the following terms:
``Condensate''; \145\
``Development project''; \146\
``Economically producible''; \147\
``Estimated ultimate recovery,'' \148\
``Exploratory well''; \149\
``Extension well''; \150\ and
``Resources.'' \151\
---------------------------------------------------------------------------
\145\ See Rule 4-10(a)(4) [17 CFR 210.4-10(a)(4)].
\146\ See Rule 4-10(a)(8) [17 CFR 210.4-10(a)(8)].
\147\ See Rule 4-10(a)(10) [17 CFR 210.4-10(a)(10)].
\148\ See Rule 4-10(a)(11) [17 CFR 210-4-10(a)(11)].
\149\ See Rule 4-10(a)(13) [17 CFR 210.4-10(a)(13)].
\150\ See Rule 4-10(a)(14) [17 CFR 210.4-10(a)(14)].
\151\ See Rule 4-10(a)(28) [17 CFR 210.4-10(a)(28)].
---------------------------------------------------------------------------
Most of these supporting terms and their definitions are based on
similar terms in the PRMS. The definition of ``resources'' is based on
the Canadian Oil and Gas Evaluation Handbook (COGEH).
In the Proposing Release, we solicited comment on whether we should
adopt any other supporting definitions. One commenter submitted an
appendix to its letter containing numerous other terms that it thought
we should adopt.\152\ We have decided not to adopt those additional
definitions because we feel that they are unnecessary at this time.
However, we have decided to adopt a definition for the term
``bitumen.'' We believe that providing a definition for this term will
lead to more consistency among disclosures because there currently are
several competing definitions of that term used in the industry.
---------------------------------------------------------------------------
\152\ See letter from SPE.
---------------------------------------------------------------------------
We are defining the term ``bitumen'' as ``petroleum in a solid or
semi-solid state in natural deposits. In its natural state, it usually
contains sulfur, metals, and other non-hydrocarbons. Bitumen has a
viscosity greater than 10,000 centipoise measured at original
temperature in the deposit and atmospheric pressure, on a gas free
basis.'' \153\ This definition is similar to the PRMS definition of
``natural bitumen.''
---------------------------------------------------------------------------
\153\ See Rule 4-10(a)(3) [17 CFR 210.4-10(a)(3)].
---------------------------------------------------------------------------
5. Proposed Terms and Definitions Not Adopted
We proposed definitions for the terms ``continuous accumulations''
and ``conventional accumulations'' to assist companies in disclosing
segregated reserves based on these two types of accumulations. As noted
elsewhere in this release, the final rules do not require disclosure
based on the type of accumulation in which the reserves are found.\154\
Therefore, there is no need to define these terms and we are not
adopting the proposed definitions.
---------------------------------------------------------------------------
\154\ See Section III.B.3.c.
---------------------------------------------------------------------------
Similarly, we proposed a definition for the term ``sedimentary
basin'' because it would have been part of our definition of the term
``by geographic area.'' As noted elsewhere in this release, we have
substantially revised the definition of the term ``by geographic area''
\155\ and the term ``sedimentary basin'' is no longer needed, so we are
not adopting this proposed term and definition.
---------------------------------------------------------------------------
\155\ See Section III.B.2.a.
---------------------------------------------------------------------------
As noted above, one commenter recommended that we adopt a large
glossary of terms and definitions that correspond with the PRMS
definitions.\156\ Rather than defining an extensive glossary of terms
in our rules
[[Page 2169]]
and attempting to constantly update those definitions, we advise
companies to look to definitions that are commonly accepted within the
oil and gas industry to the extent such definitions are not in, or
inconsistent with, our rules.
---------------------------------------------------------------------------
\156\ See letter from SPE.
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K. Alphabetization of the Definitions Section of Rule 4-10
We are alphabetizing the definitional terms in Rule 4-10(a) because
we are adding a significant number of defined terms to this section.
III. Revisions to Full Cost Accounting and Staff Accounting Bulletin
As we noted in Section II.B.2 of this release, commenters
unanimously opposed our proposal to use different prices for disclosure
and accounting purposes. We agree with those commenters and are
revising our proposal to use a 12-month average price for accounting
purposes. These revisions primarily will appear under the full cost
accounting method described in Rule 4-10(c) \157\ of Regulation S-X.
The full cost accounting method permits certain oil and gas extraction
costs to accumulate on a company's balance sheet subject to a
limitation test or a ``ceiling'' as described in Rule 4-10(c)(3)(4).
Like reserve disclosures, these capitalized costs and the related
limitation test are not fair value based measurements. Rather the
capitalized costs represent the accumulated historical acquisition,
exploration and development costs (net of any previously recorded
depletion, amortization or ceiling test write downs) incurred for oil
and gas producing activities, limited to a standardized mathematical
calculation (the full cost ceiling) adopted over 25 years ago. Costs
that do not exceed the limitation are deferred and amortized over time.
The limitation test calculation on capitalized costs is not designed or
intended to represent a fair valuation of the related oil and gas
assets.\158\
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\157\ 17 CFR 210.4-10(c).
\158\ While not intended to represent fair value, costs that are
written down because they exceed the ceiling limitation are
accounted for in the same manner as impairments recognized under
accounting generally. That is, once the asset is written down, it
becomes the new historical cost basis and cannot be reinstated for
subsequent increases in the ceiling. See Rule 4-10(c)(4)(i) of
Regulation S-X [17 CFR 210-4-10(c)(4)(i)].
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Similar to the single-day, year-end pricing used under the
successful efforts method,\159\ the application of the full cost method
of accounting in Rule 4-10(c) has used ``current prices,'' interpreted
as single-day, year-end prices, as the basis for calculating the
limitation on costs that may be capitalized under the full cost method.
In order to further the objective of providing comparable oil and gas
reserve quantities, our final rule clarifies that the term ``current
prices'' as used in Rule 4-10(c) is consistent with the 12-month
average price as calculated in Rule 4-10(a)(22)(v).\160\
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\159\ The accounting guidance refers to our definition of proved
reserves under existing Rule 4-10(a)(2), which currently uses a
single-day, year-end price to establish reserves amounts.
\160\ See Rule 4-10(c)(8) [17 CFR 210.4-10(c)(8)].
---------------------------------------------------------------------------
However, since these calculations are not designed to result in a
calculation of fair value and since the change to the full cost
accounting method would effectively eliminate the anomalies caused by
the single-day, year-end price currently used in the limitation test,
the SEC staff will eliminate portions of Staff Accounting Bulletin
(SAB) Topic 12:D.3.c that permit consideration of the impact of price
increases subsequent to the period end on the ceiling limitation test.
The combination of adopting a 12-month average pricing mechanism
and eliminating portions of SAB Topic 12:D.3.c could have the effect of
requiring a company using the full cost accounting method to record a
ceiling test write-down in income during periods of rising oil and gas
prices. In that situation, it is possible that using a 12-month average
price in the ceiling test calculation might result in a write-down that
would not otherwise have been required had the full cost company been
permitted to use the single-day, year-end price. Conversely, it is also
possible that in periods of declining oil and gas prices, the
application of this rule could result in the deferral of ceiling test
write-downs. In that situation, it is possible that using a 12-month
average price in the ceiling limitation test calculation might not
result in a write-down in situations where a write down would have
otherwise been required had the full cost company been required to use
a single-day, year-end price in its ceiling limitation test
calculation.
Because the application of the ceiling limitation test is not a
fair-value-based calculation but rather a limit on the amount of
certain oil and gas related exploration costs that can be capitalized,
portions of which would have resulted in write-downs in prior periods
under other methods of accounting, we believe the benefits of using a
single pricing mechanism justify the potential changes to the timing of
those ceiling test write-downs or amortizations amounts. However, as
discussed in Section V of this release, we believe that the company
should discuss such situations, if material, particularly when pricing
trends indicate the possibility of future write-downs, in Management's
Discussion and Analysis and, where appropriate, the notes to the
financial statements.
IV. Update and Codification of the Oil and Gas Disclosure Requirements
in Regulation S-K
The Proposing Release proposed to update and codify Securities Act
and Exchange Act Industry Guide 2: Disclosure of Oil and Gas Operations
(Industry Guide 2).\161\ Industry Guide 2 currently sets forth most of
the disclosures that an oil and gas company provides regarding its
reserves, production, property, and operations. Regulation S-K
references Industry Guide 2 in Instruction 8 to Item 102 (Description
of Property), Item 801 (Securities Act Industry Guides), and Item 802
(Exchange Act Industry Guides). However, Industry Guide 2 itself does
not appear in Regulation S-K or in the Code of Federal Regulations. The
rules that we adopt today codify the contents of Industry Guide 2 in a
new Subpart 1200 of Regulation S-K.
---------------------------------------------------------------------------
\161\ Exchange Act Industry Guide 2 merely references, and
therefore is identical to, Securities Act Industry Guide 2.
---------------------------------------------------------------------------
A. Revisions to Items 102, 801, and 802 of Regulation S-K
The instructions to Item 102 of Regulation S-K, as well as Items
801 and 802 of Regulation S-K, currently reference the industry guides.
Because we are codifying the Industry Guide 2 disclosures in a new
Subpart 1200 of Regulation S-K, we are revising the instructions to
Item 102 to reflect this change.\162\ We also are eliminating the
references in Items 801 and 802 to Industry Guide 2 because that
industry guide will cease to exist upon effectiveness of the amendments
we adopt today.\163\
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\162\ See revised Instructions 4 and 8 to Item 102 [17 CFR
229.102].
\163\ See revised Item 801 and 802 [17 CFR 229.801 and 802].
---------------------------------------------------------------------------
In addition, Instruction 5 to Item 102 of Regulation S-K currently
prohibits the disclosure of reserves other than proved oil and gas
reserves. Because we are adopting rules to permit disclosure of
probable and possible oil and gas reserves, we are revising Instruction
5 to limit its applicability to extractive enterprises other than oil
and gas producing activities, such as mining activities.\164\
Similarly, Instruction 3 of
[[Page 2170]]
Item 102, regarding production, reserves, locations, development and
the nature of the company's interests, will no longer apply to oil and
gas producing activities, so we also are limiting that instruction to
mining activities.\165\
---------------------------------------------------------------------------
\164\ See revised Instruction 5 to Item 102 [17 CFR 229.102].
Extractive enterprises include enterprises such as mining companies
that extract resources from the ground.
\165\ See revised Instruction 3 to Item 102 [17 CFR 229.102].
---------------------------------------------------------------------------
Finally, we are eliminating Instruction 4 to Item 102 regarding the
ability of the Commission's staff to request supplemental information,
including reserves reports. This instruction is duplicative of
Securities Act Rule 418 \166\ and Exchange Act 12b-4,\167\ regarding
the staff's general ability to request supplemental information.
---------------------------------------------------------------------------
\166\ 17 CFR 230.418.
\167\ 17 CFR 240.12b-4.
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B. Proposed New Subpart 1200 to Regulation S-K Codifying Industry Guide
2 Regarding Disclosures by Companies Engaged in Oil and Gas Producing
Activities
1. Overview
We are adding a new Subpart 1200 to Regulation S-K that codifies
the disclosure requirements related to companies engaged in oil and gas
producing activities. This new subpart largely includes the existing
requirements of Industry Guide 2. However, we have revised these
requirements to update them, provide better clarity with respect to the
level of detail required in oil and gas disclosures, including the
geographic areas by which disclosures need to be made, and provide
formats for tabular presentation of these disclosures. In addition,
Subpart 1200 contains the following new disclosure requirements, many
of which have been requested by industry participants:
Disclosure of reserves from non-traditional sources (e.g.,
bitumen, shale, coal) as oil and gas reserves;
Optional disclosure of probable and possible reserves;
Optional disclosure of oil and gas reserves' sensitivity
to price;
Disclosure of the development of proved undeveloped
reserves;
Disclosure of technologies used to establish additions to
reserves estimates;
Disclosure of a company's internal controls over reserves
estimation and the qualifications of the business entity or individual
preparing or auditing the reserves estimates; and
Disclosure based on a new definition of the term ``by
geographic area.''
We discuss each of these proposed new Items below.
2. Item 1201 (General Instructions to Oil and Gas Industry-Specific
Disclosures)
We are adding new Item 1201 to Regulation S-K. This item sets forth
the general instructions to Subpart 1200. The new item contains three
paragraphs that perform the following tasks:
Instruct companies for which oil and gas producing
activities are material to provide the disclosures specified in Subpart
1200; \168\
---------------------------------------------------------------------------
\168\ This paragraph would maintain the existing exclusion in
Industry Guide 2 for limited partnerships and joint ventures that
conduct, operate, manage, or report upon oil and gas drilling or
income programs, that acquire properties either for drilling and
production, or for production of oil, gas, or geothermal steam or
water.
---------------------------------------------------------------------------
Clarify that, although a company must present specified
Subpart 1200 information in tabular form, the company may modify the
format of the table for ease of presentation, to add additional
information or to combine two or more required tables;
State that the definitions in Rule 4-10(a) of Regulation
S-X apply to Subpart 1200; and
Define the term ``by geographic area.''
a. Geographic Area
We received significant comments regarding the proposed definition
of the term ``by geographic area.'' We proposed to require disclosure
by continent, country containing 15% of more of the company's reserves,
and sedimentary basin or field containing 10% or more of the company's
reserves. Several commenters were concerned that the proposed
definition would add too much detail to the disclosures, particularly
at the basin or field level.\169\ They were concerned that this amount
of detail would make disclosures too complex and incoherent.\170\ They
were particularly concerned with the extension of this standard to
disclosures other than reserves, such as production, wells, and
acreage.\171\ Commenters also believed that the disclosures, in
particular by field, could cause competitive harm in future property
sales transactions, unitization agreements, and other asset
transfers.\172\
---------------------------------------------------------------------------
\169\ See letters from Apache, CAPP, Devon, ExxonMobil,
Imperial, Nexen, Repsol, Shell, and StatoilHydro.
\170\ See letters from Apache, CAPP, ExxonMobil, Imperial,
Nexen, and Repsol.
\171\ See letters from ExxonMobil, Imperial, and Total.
\172\ See letters from Apache, API, BHP, Canadian Natural, CAPP,
Devon, EnCana, Eni, Newfield, Nexen, Petro-Canada, Shell,
StatoilHydro, and Total.
---------------------------------------------------------------------------
Some commenters also believed that some of these disclosures may be
prohibited by foreign governments.\173\ One commenter noted that
separate determination of field or basin reserves within a larger
production sharing agreement may not be possible due to concession-wide
cost sharing terms.\174\ Eight commenters recommended that the
determination of appropriate geographic disclosure should remain with
management, consistent with Statement of Financial Accounting Standard
No. 69 (SFAS 69).\175\ However, two commenters indicated that a
country-by-country breakdown would be adequate.\176\
---------------------------------------------------------------------------
\173\ See letters from Apache, API, CAPP, Eni, Newfield, Petro-
Canada, and Total.
\174\ See letter from Apache.
\175\ See letters from Apache, API, Canadian Natural, CAPP, Eni,
ExxonMobil, Imperial, and Petro-Canada.
\176\ See letters from ExxonMobil and Nexen.
---------------------------------------------------------------------------
Four commenters supported the proposed percentage thresholds for
geographic disclosure, stating that they would increase understanding
of the total energy supply, leading to better decisions by policy
makers.\177\ One commenter supported the 15% threshold for
countries.\178\
---------------------------------------------------------------------------
\177\ See letters from AAPG, CFA, Chesapeake, and E&Y.
\178\ See letter from Shell.
---------------------------------------------------------------------------
As we noted in the Proposing Release, there have been differing
interpretations among oil and gas companies as to the level of
specificity required when a company is breaking out its reserves
disclosures based on geographic area as required by Instruction 3 of
Item 102 of Regulation S-K.\179\ Some companies currently broadly
organize their reserves only by hemisphere or continent. SFAS 69
requires reserves disclosure to be separately disclosed for the
company's home country and foreign geographic areas. It defines
``foreign geographic areas'' as ``individual countries or groups of
countries as appropriate for meaningful disclosure in the
circumstances.'' Since SFAS 69 was issued, the operations of oil and
gas companies have become much more diversified globally. For many
large U.S. oil and gas producers, the majority of reserves are now
overseas, with material amounts in individual countries and even
individual fields or basins.
---------------------------------------------------------------------------
\179\ 17 CFR 229.102.
---------------------------------------------------------------------------
We think that greater specificity than simply disclosing reserves
within ``groups of countries'' would benefit investors and, in certain
cases, may be necessary to meet the requirements of Item 102 of
Regulation S-K. Some countries in which many of these companies operate
and may have significant reserves are subject to unique risks, such as
political instability.
[[Page 2171]]
However, we recognize that disclosure that is too detailed may detract
from the overall disclosure. Thus, we have revised the definition of
the term ``by geographic area'' to mean, as appropriate for meaningful
disclosure under a company's particular circumstances:
(1) By individual country;
(2) By groups of countries within a continent; or
(3) By continent.\180\
---------------------------------------------------------------------------
\180\ See Item 1201(d) [17 CFR 229.1201(d)].
---------------------------------------------------------------------------
This definition is substantially the same as the definition
currently provided in SFAS 69. However, as proposed, we are adopting
specific percentage thresholds to the geographic breakdowns of reserves
estimates and production. With respect to production, the final rules
require disclosure of production in each country or field containing
15% or more of the company's proved reserves unless prohibited by the
country in which the reserves are located. We are raising the proposed
10% threshold for field disclosure of production to 15% to make the
threshold consistent. However, rather than requiring disclosure based
on a percentage of the amount of the company's reserves of an
individual product, as proposed, the final rules require disclosure
based on a percentage of a company's total global oil and gas proved
reserves, based on barrels of oil equivalent.\181\
---------------------------------------------------------------------------
\181\ See Item 1204(a) [17 CFR 229.1204(a)].
---------------------------------------------------------------------------
With respect to reserves estimates, the final rules require
disclosure of reserves in countries containing more than 15% of the
company's proved reserves. As with the production disclosure, this 15%
threshold would be based on the company's total global oil and gas
proved reserves, rather than on individual products, as proposed.\182\
A registrant need not provide disclosure of the reserves in a country
containing 15% or more of the registrant's proved reserves if that
country's government prohibits disclosure of reserves in that country.
---------------------------------------------------------------------------
\182\ See Item 1202(a)(2) [17 CFR 229.1202(a)(2)].
---------------------------------------------------------------------------
We are not adopting the requirement that we proposed to disclose
reserves by sedimentary basin or field. We share commenters' concerns
that there is potential for competitive harm from such disclosure in
future property sales transactions, unitization agreements, and other
asset transfers. Moreover, we recognize that there may be situations in
which a particular field may encompass a significant portion of a
company's reserves in a foreign country. To avoid compelling a company
to provide, in effect, field disclosure, the rule does not require
disclosure of reserves in a country containing 15% of the company's
reserves if that country prohibits disclosure of reserves in a
particular field and disclosure of reserves in that country would have
the effect of disclosing reserves in particular fields.\183\ For
example, if a company has 25% of its reserves in Country A and Country
A's government prohibits disclosure of reserves by field within Country
A, if almost all of that company's reserves in Country A are located in
a single field, the company would not be required to specify the amount
of its reserves located in Country A.
---------------------------------------------------------------------------
\183\ See Instruction 4 to Item 1202(a)(2).
---------------------------------------------------------------------------
b. Tabular Disclosure
We proposed to require much of the reserves disclosures and other
disclosures in Industry Guide 2 to be presented in tabular format. Two
commenters encouraged using a standardized table for reserves
disclosure.\184\ Another believed that companies should be able to
reorganize, supplement, or combine tables for better presentation of
the company's strategy.\185\ However, two commenters believed that the
rules should not propose a specified tabular format in general.\186\
These commenters believed that companies should have the flexibility to
present data in a format that is most relevant and meaningful to
investors, whether it is tabular or narrative.\187\ We continue to
believe that in certain circumstances, the required disclosures lend
themselves to a tabular disclosure format. We believe that
standardizing such tables will improve the readability and
comparability of disclosures among companies. However, in response to
comments received, we have made several revisions to the individual
disclosure items, including whether the disclosure item must be
presented in tabular format. We discuss each below.
---------------------------------------------------------------------------
\184\ See letters from Devon and Petrobras.
\185\ See letter from Petro-Canada.
\186\ See letters from Apache and ExxonMobil.
\187\ See letters from Apache and ExxonMobil.
---------------------------------------------------------------------------
3. Item 1202 (Disclosure of Reserves)
Existing Instruction 3 to Item 102 of Regulation S-K requires
disclosure of an extractive enterprise's proved reserves. With respect
to oil and gas producing companies, we are replacing this Instruction
by adding a new Item 1202 to Regulation S-K that contains a similar
disclosure requirement regarding a company's proved reserves.\188\
However, new Item 1202 expands on the requirements of Item 102 by
specifically permitting the disclosure of probable and possible
reserves and permitting the disclosure of reserves from non-traditional
sources. In addition, because we are no longer distinguishing between
types of accumulations, the item contains only one table with separate
columns for different final products, specifically, oil, gas, synthetic
oil, synthetic gas, and other natural resources sold by the company.
---------------------------------------------------------------------------
\188\ See Item 1202 [17 CFR 229.1202].
---------------------------------------------------------------------------
a. Oil and Gas Reserves Tables
New Item 1202 requires disclosure, in the aggregate and by
geographic area, of reserves estimates using prices and costs under
existing economic conditions, for each product type, in the following
categories:
Proved developed reserves;
Proved undeveloped reserves;
Total proved reserves;
Probable developed reserves (optional);
Probable undeveloped reserves (optional);
Possible developed reserves (optional); and
Possible undeveloped reserves (optional).
A form of this table is set forth below:
Summary of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices
----------------------------------------------------------------------------------------------------------------
Reserves
----------------------------------------------------------------
Reserves category Synthetic
Oil Natural gas oil Synthetic Product A
(mbbls) (mmcf) (mbbls) gas (mmcf) (measure)
----------------------------------------------------------------------------------------------------------------
PROVED
Developed:
Continent A................................ ........... ........... ........... ........... ...........
[[Page 2172]]
Continent B................................ ........... ........... ........... ........... ...........
Country A.................................. ........... ........... ........... ........... ...........
Country B.................................. ........... ........... ........... ........... ...........
Other Countries in Continent............... ........... ........... ........... ........... ...........
Undeveloped:
Continent A................................ ........... ........... ........... ........... ...........
Continent B................................ ........... ........... ........... ........... ...........
Country A.................................. ........... ........... ........... ........... ...........
Country B.................................. ........... ........... ........... ........... ...........
Other Countries in Continent B............. ........... ........... ........... ........... ...........
----------------------------------------------------------------
TOTAL PROVED........................... ........... ........... ........... ........... ...........
PROBABLE
Developed.................................. ........... ........... ........... ........... ...........
Undeveloped................................ ........... ........... ........... ........... ...........
POSSIBLE
Developed.................................. ........... ........... ........... ........... ...........
Undeveloped................................ ........... ........... ........... ........... ...........
----------------------------------------------------------------------------------------------------------------
i. Disclosure by Final Product Sold
The table requires disclosure by final product sold by the company,
specifically, oil, gas, synthetic oil, synthetic gas, or other natural
resource. Thus, if the company processes a natural resource that it has
extracted, such as bitumen, into synthetic oil or gas prior to selling
the product, it may include such reserves under the synthetic oil or
gas columns. As noted below, we have revised the proposal that would
have required disclosure by type of accumulation. In addition, in
response to commenters, we have revised the definition of ``oil and gas
producing activities'' so that a company can use the price of that
synthetic oil or gas to determine the economic producibility of the
reserves because the economics of the processing activity are relevant
to the determination of whether to extract the underlying
resource.\189\
However, if a company extracts a resource other than oil or gas,
such as bitumen, and sells the product without processing it into
synthetic oil or gas, it must disclose reserves of that other natural
resource. Although that company's extractive activities would be
considered an oil and gas producing activity under the definition of
that term, such a company would not benefit from the economics of
processing of that resource because the price that determines whether
such a company extracts the resource is the price of the unprocessed
resource and therefore the company may not establish reserves estimates
based on the price of the upgraded product. Similarly, if the company
does not itself extract the natural resource, but purchases the natural
resource for processing or is paid to process the natural resource, it
may not claim reserves either of the resource or of the processed
product.
---------------------------------------------------------------------------
\189\ See Section II.C.2 of this release.
---------------------------------------------------------------------------
ii. Aggregation
As proposed, the reserves to be reported in these tables would be
aggregations (to the company total level) of reserves determined for
individual wells, reservoirs, properties, fields, or projects.
Regardless of whether the reserves were determined using deterministic
or probabilistic methods, the reported reserves should be simple
arithmetic sums of all estimates at the well, reservoir, property,
field, or project level within each reserves category. Eight commenters
agreed that aggregation should not be permitted beyond the field,
property or project level, consistent with PRMS.\190\
---------------------------------------------------------------------------
\190\ See letters from Devon, Evolution, ExxonMobil, Ryder
Scott, Shell, SPE, Talisman, and Wagner.
---------------------------------------------------------------------------
iii. Optional Disclosure of Probable and Possible Reserves
A company may, but is not required to, disclose probable or
possible reserves in these tables. If a company discloses probable or
possible reserves, it must provide the same level of geographic detail
as it must with respect to proved reserves and must state whether the
reserves are developed or undeveloped. In addition, Item 1202 requires
the company to disclose the relative uncertainty associated with these
classifications of reserves estimations. By permitting disclosure of
all three of these classifications of reserves, our objective is to
enable companies to provide investors with more insight into the
potential reserves base that managements of companies may use as their
basis for decisions to invest in resource development.
Most commenters addressing this issue supported permitting the
disclosure of probable and possible reserves in filed documents.\191\
They believed that such disclosure would provide a more complete
picture of a company's full portfolio of opportunities.\192\ One
commenter noted that this information often is already available on
company Web sites and in press releases.\193\ However, several
commenters supporting the proposal cautioned that there could be
significant variability among disclosures.\194\
---------------------------------------------------------------------------
\191\ See letters from CFA, Chesapeake, Deloitte, EnCana,
Evolution, McMoRan, Newfield, Petrobras, Petro-Canada, Questar,
Ryder Scott, Sasol, Ryder Scott, Shell, SPE, Three Senators, Wagner,
and Zakaib.
\192\ See letters from CFA, Evolution, Petro-Canada, Ryder
Scott, and Wagner.
\193\ See letter from Evolution.
\194\ See letter from EnCana.
---------------------------------------------------------------------------
Other commenters expressed concern about disclosure of unproved
reserves, but conceded that voluntary disclosure would be
acceptable.\195\ These commenters were concerned that such disclosure
may confuse investors and expose companies to increased litigation
because of the inherent uncertainty associated with probable and
possible reserves.\196\ They noted that various
[[Page 2173]]
technologies may be used to support these estimates.\197\
---------------------------------------------------------------------------
\195\ See letters from API, ExxonMobil, Imperial, Repsol, and
Total.
\196\ See letters from API, ExxonMobil, Imperial, and Repsol.
\197\ See letters from API, ExxonMobil, and Imperial.
---------------------------------------------------------------------------
Several commenters opposed permitting disclosure of probable and
possible reserves in Commission filings for similar reasons.\198\
Again, they were concerned that the inherent uncertainty associated
with such reserves estimates may lead to investor confusion and
misunderstanding.\199\ They believed that the broad range of
technologies and methods used by companies to support these estimates
would lead to inconsistent disclosure among companies.\200\
---------------------------------------------------------------------------
\198\ See letters from Apache, Devon, Energen, Eni, and
Southwestern.
\199\ See letters from Apache, Devon, Eni, and Southwestern.
\200\ See letters from Devon, Eni, and Southwestern.
---------------------------------------------------------------------------
We note that numerous oil and gas companies already disclose
unproved reserves on their Web sites and in press releases. This
practice does not appear to have created confusion in the market.
However, we understand commenters' concerns that probable and possible
reserves estimates are less certain than proved reserves estimates and
so may increase litigation risk. By making these disclosures voluntary,
a company could exercise its own discretion as to whether to provide
the market with this disclosure.
Some commenters were concerned that voluntary disclosure by some
companies may raise confusion as to why other companies do not disclose
these classifications of reserves.\201\ One commenter was concerned
that voluntary disclosure may increase market pressure on all companies
to disclose probable and possible reserves estimates.\202\ Considering
the fact that many companies already make these disclosures public, we
do not believe that this is an adequate reason for prohibiting from
filings disclosure that may be helpful to investors.
---------------------------------------------------------------------------
\201\ See letters from Apache and Total.
\202\ See letter from Eni.
---------------------------------------------------------------------------
iv. Resources Not Considered Reserves
Because we are permitting disclosure of probable and possible
reserves, we are revising existing Instruction 5 to Item 102 of
Regulation S-K to continue to prohibit disclosure of estimates of oil
or gas resources other than reserves, and any estimated values of such
resources, in any document publicly filed with the Commission, unless
such information is required to be disclosed in the document by foreign
or state law.\203\ Five commenters recommended that the rules permit
disclosure of all categories of resources, including those that do not
qualify as reserves.\204\ One commenter believed that the prohibition
against disclosing all resources deprives public markets of significant
information without meaningfully enhancing investor protection and
ultimately may harm the efficiency and development of U.S. markets and
U.S. companies raising capital.\205\ That commenter also thought such a
restriction could also encourage companies to form outside of the
U.S.\206\ Another commenter believed that the uncertainty of resource
estimates is best communicated by reporting the full range of
estimates.\207\ In addition, another commenter believed that clear
disclosure would allay concerns about investor misunderstanding of
estimates of resources that do not qualify as reserves.\208\ That
commenter noted that excluding resources that are not reserves is
inconsistent with international standards and the fact that these
resources are disclosed in the U.S. on Web sites and in press
releases.\209\ We continue to be concerned that such resources are too
speculative and may lead investors to incorrect conclusions. Therefore,
we are adopting the proposal to prohibit disclosure of resources other
than reserves.
---------------------------------------------------------------------------
\203\ See Instruction 5 to Item 102 [17 CFR 229.102].
\204\ See letters from Davis Polk, Petro-Canada, Shearman &
Sterling, SPE, and Zakaib.
\205\ See letter from Shearman & Sterling.
\206\ Id.
\207\ See letter from SPE.
\208\ See letter from Davis Polk.
\209\ See letter from Davis Polk.
---------------------------------------------------------------------------
However, consistent with existing Instruction 5, a company may
continue to disclose such estimates of non-reserves resources in a
Commission filing related to an acquisition, merger, or consolidation
if the company previously provided those estimates to a person that is
offering to acquire, merge, or consolidate with the company or
otherwise to acquire the company's securities.\210\ Several commenters
recommended that the Commission maintain this exception so that the
company's shareholders would not be at an informational disadvantage
compared to the counterparty when assessing a merger.\211\ We agree
with these commenters and have retained the exception in the revised
Instruction 5 adopted today.
---------------------------------------------------------------------------
\210\ Id.
\211\ See letters from Devon, ExxonMobil, Shell, and Total.
---------------------------------------------------------------------------
b. Optional Reserves Sensitivity Analysis Table
The rules that we are adopting require a company to determine
whether its oil or gas resources are economically producible based on a
12-month average price. We also proposed, and are adopting, an optional
reserves sensitivity table. This table would permit companies to
disclose additional information to investors, such as the sensitivity
that oil and gas reserves have to price fluctuations. If a company
chooses to provide such disclosure, it may choose the different
scenario or scenarios, if any, that it wishes to disclose in the table,
provided that it also discloses the price and cost schedules and
assumptions on which the alternate reserves estimates are based.
Twelve commenters supported permitting such sensitivity
analyses.\212\ Some believed that this would provide investors with a
better view of management's analysis of future prices.\213\ One
recommended providing a set price change of 10% for the sensitivity
analysis.\214\ Two other commenters believed that different
circumstances may require different types of sensitivity analyses, both
with respect to the range of prices used and the format of the
presentation.\215\ We agree that the appropriate range for a
sensitivity analysis may vary depending on the situation, and
therefore, as proposed, we are not specifying a range of prices to be
used.
---------------------------------------------------------------------------
\212\ See letters from Canadian Natural, CAPP, CFA, Chesapeake,
Deloitte, Devon, Evolution, ExxonMobil, McMoRan, Nexen, Petro-
Canada, and Total.
\213\ See letters from Chesapeake, Deloitte, and McMoRan.
\214\ See letter from CFA.
\215\ See letters from Evolution and Total.
---------------------------------------------------------------------------
However, five commenters specifically opposed requiring such an
analysis.\216\ They believed that such a requirement would cause
confusion and harm comparability.\217\ Three commenters opposed such a
sensitivity analysis because using different prices could mislead
investors.\218\ We are adopting this table, as proposed, as a voluntary
disclosure rather than a requirement. However, as proposed, the table
would require disclosure of the assumptions behind varying estimates.
We believe this disclosure will mitigate any investor confusion.
---------------------------------------------------------------------------
\216\ See letters from Canadian Natural, CAPP, Devon, EnCana,
and ExxonMobil.
\217\ See letters from EnCana and Ryder Scott.
\218\ See letters from Apache, Petrobras, and Wagner.
---------------------------------------------------------------------------
In addition, we remind companies that Item 303 of Regulation S-K
(Management's Discussion and Analysis of Financial Condition and
Results of Operations) \219\ requires discussion of
[[Page 2174]]
known trends and uncertainties, which may include changes to prices and
costs. A form of this optional reserves sensitivity analysis table is
set forth below.
---------------------------------------------------------------------------
\219\ See Item 303 of Regulation S-K [17 CFR 229.303].
Sensitivity of Reserves to Prices by Principal Product Type and Price Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
Proved reserves Probable reserves Possible reserves
--------------------------------------------------------------------------------------
Price case Oil Gas Product A Oil Gas Product A Oil Gas Product A
Mbbls mmcf measure mbbls mmcf measure mbbls mmcf measure
--------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario 1....................................................... ...... ...... ........... ...... ...... ........... ...... ...... ...........
Scenario 2....................................................... ...... ...... ........... ...... ...... ........... ...... ...... ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------
c. Separate Disclosure of Conventional and Continuous Accumulations
Under the proposal, new Item 1202 would have required companies to
disclose reserves from conventional accumulations separately from
reserves in continuous accumulations. Nine commenters recommended
disclosure based on the final product.\220\ These commenters opposed
segregating disclosure based on the type of accumulation that is
involved.\221\ They believed that such disclosure would be too complex
and detailed and of little use to investors.\222\ In addition, seven
commenters pointed out that separation may be impossible because some
fields contain both conventional and continuous accumulations.\223\
This would make allocation of costs arbitrary.\224\ However, four
commenters supported the definitions and separate disclosure by type of
accumulation.\225\ One commenter believed that such disclosure would
allow investors to assess the impact of unconventional sources on
reserves.\226\
---------------------------------------------------------------------------
\220\ See letters from Apache, API, Canadian Natural, CAPP,
EnCana, ExxonMobil, Imperial, Petro-Canada, and Total.
\221\ See letters from Apache, API, CAPP, Chesapeake, Devon,
ExxonMobil, Imperial, Repsol, and Shell.
\222\ See letters from Apache, API, BP, CAPP, Chesapeake,
Chevron, Devon, E&Y, EnCana, ExxonMobil, Imperial, Petro-Canada,
Repsol, and Southwestern.
\223\ See letters from BP, Canadian Natural, CAPP, EnCana,
Petro-Canada, Ryder Scott, and Talisman.
\224\ See letters from EnCana and Ryder Scott.
\225\ See letters from Davis Polk, EIA, Petrobras, and Wagner.
\226\ See letter from Wagner.
---------------------------------------------------------------------------
Although we agree conceptually that the focus of reserves
disclosure should be on the final product, we also recognize that the
production of oil and gas from varying sources can have significantly
different economics. Extraction of oil and gas from continuous
accumulations can be much more labor and resource intensive than
extraction of oil and gas from traditional wells. They often require
greater ongoing efforts and expense after the initial extraction
equipment is in place, making such operations more sensitive to price
fluctuations.
We agree with the commenters that disclosure based on the end
product sold would provide a more effective basis for distinguishing
reserves that disclosure based on the type of accumulation in which the
reserves are held. Therefore, we have revised the disclosure to be
based on the end product that is sold by the company.\227\ However,
with respect to the end product, new Item 1202 makes a distinction
between oil and gas, on the one hand, and synthetic oil and gas, on the
other. Synthetic products require processing of the raw resource
material, either while it is still in the ground (``in situ'') or after
it is extracted, before it can be used as refinery feedstock or as
natural gas. Such processes currently include bitumen upgrading as well
as coal liquefaction and gasification. However, resources from some
continuous accumulations, such as coalbed methane, do not require such
processing and therefore are not associated with the same level of
ongoing costs once a well has been drilled because the in-ground
resource is already oil or gas (in the case of coalbed methane, the in-
ground resource is methane, trapped in a coalbed). Thus, coalbed
methane would not be considered a synthetic product.
---------------------------------------------------------------------------
\227\ See Item 1202 [17 CFR 229.1202].
---------------------------------------------------------------------------
d. Preparation of Reserves Estimates or Reserves Audits
In the Proposing Release, we proposed to require a company to
disclose whether or not the technical person \228\ primarily
responsible for preparing the reserves estimate possessed certain
specified qualifications and was subject to a list of controls for
maintaining objectivity. Most commenters addressing the issue opposed
this proposed requirement.\229\ However, many of these commenters
appeared to believe that the disclosure requirement would pertain to
every person involved with the estimation process.\230\ If adopted,
they noted that such disclosure would be voluminous, adding unnecessary
complexity to disclosures.\231\ Four commenters suggested that we
clarify that the disclosure is limited to the chief technical person
who oversees the company's overall reserves estimation process,\232\
which was the intent of the proposal. Five commenters supported this
disclosure because it helps users understand the objectivity and
quality of reserves estimates.\233\
---------------------------------------------------------------------------
\228\ With regard to the objectivity of a technical person, the
``person'' could be an individual or an entity, as appropriate.
However, with regard to the qualifications of a person, the
disclosure would relate to the individual who is primarily
responsible for the technical aspects of the reserves estimation or
audit. Thus, this individual is not necessarily the individual
generally overseeing the estimation or audit, but the individual who
is primarily responsible for the actual calculations and estimation
or audit.
\229\ See letters from Apache, API, Chevron, Energen, Eni,
ExxonMobil, Newfield, Nexen, PEMEX, Petro-Canada, Ryder Scott,
Shell, and Total.
\230\ See letters from Apache, API, ExxonMobil, Newfield, Nexen,
PEMEX, Ryder Scott, and Total.
\231\ See letters from Apache, API, ExxonMobil, Newfield, Nexen,
PEMEX, Repsol, and Total.
\232\ See letters from API, ExxonMobil, PEMEX, and Petro-Canada.
\233\ See letters from CFA, Devon, EnCana, Southwestern, and
Wagner.
---------------------------------------------------------------------------
It was our intent to limit the disclosure to the technical person
primarily responsible for overseeing the reserves estimates. However,
there may have been confusion with respect to this point based on a
footnote which stated that we sought disclosure about the person who
``is primarily responsible for the actual calculations and estimation
or audit.'' By that term, we did not intend to include any person
making ``actual calculations.'' We recognize that, ultimately, the
reserves estimates are overseen by top management, which may or may not
have reserves estimation expertise. The focus of the final rule is the
primary technical person responsible for overseeing the preparation of
the reserves estimation process. We have
[[Page 2175]]
revised the language in the rule to clarify this point.\234\
---------------------------------------------------------------------------
\234\ See Item 1202(a)(7) [17 CFR 229.1202(a)(7)].
---------------------------------------------------------------------------
Two commenters noted that it was inconsistent to require such
precise disclosure about reserves experts, but not other experts.\235\
One of those commenters recommended that the rule require expert
language, including clear disclosure of which portion of the reserves
estimate the third party is expertising and filed consents.\236\ The
concept of an expert under the Securities Act is different from the
disclosures that we seek regarding the qualifications and objectivity
of persons responsible for the preparation or audit of oil and gas
reserves. Under the Securities Act, disclosure must be made when the
company represents that disclosure is based on the authority of an
expert. Although the Securities Act concept of experts will continue to
be relevant when the reserves disclosures are in, or incorporated into,
a Securities Act filing and the company represents that disclosure is
based on the authority of an expert, the new rules requiring disclosure
about the reserves preparer or auditor in a company's Exchange Act
reports are intended to help investors determine whether reserves
estimates, which are highly technical, have been prepared by a
qualified, objective person, regardless of whether that person is an
employee of the company.
---------------------------------------------------------------------------
\235\ See letters from API and Deloitte.
\236\ See letter from Deloitte.
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However, we agree with commenters that a prescribed list of
qualifications and objectivity requirements may be too rigid for all
situations. With respect to technical qualifications, several
commenters noted that licensing requirements can vary greatly among
jurisdictions.\237\ Commenters also believed that disclosure of a
person's objectivity was unnecessary because management is required to
install appropriate internal controls to ensure the reliability of
reserves estimates.\238\ In fact, some commenters recommended that we
limit the disclosure to a description of a company's internal controls,
including the company's technical assessment routine, management and
board review and approval processes, the internal audit process, the
extent to which the company uses external parties to estimate or audit
reserves estimates, and a summary description of the qualifications of
the company's typical reserves estimators.\239\ We are following these
commenters' recommendations and adopting a rule that requires a company
to provide a general discussion of the internal controls that it uses
to assure objectivity in the reserves estimation process and disclosure
of the qualifications of the technical person primarily responsible for
preparing the reserves estimates or conducting the reserves audit if
the company discloses that such a reserves audit has been performed,
regardless of whether the technical person is an employee or an outside
third party.\240\
---------------------------------------------------------------------------
\237\ See letters from AAPG, API, Chevron, Eni, Petro-Canada,
Questar, and SPE.
\238\ See letters from API, Chevron, Energen, ExxonMobil,
Newfield, Nexen, Petrobras, Ryder Scott, Shell, StatoilHydro, and
Total.
\239\ See letters from ExxonMobil, Nexen, Shell, and
StatoilHydro.
\240\ See Item 1202(a)(7) [17 CFR 229.1202(a)(7)].
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We did not propose, but sought comment on, whether the rules should
require a company to retain an independent third party to prepare, or
conduct a reserves audit of, the company's reserves estimates. Most
commenters urged the Commission not to adopt such a requirement.\241\
They believed that a company's internal staff, particularly at larger
companies, is generally in a better position to prepare those estimates
\242\ and that there is a potential lack of qualified third party
engineers and other professionals available to conduct the increased
work that would result from such a requirement.\243\ We agree with
these commenters and are not adopting a requirement that an independent
third party prepare, or conduct a reserves audit of, the company's
reserves estimates.
---------------------------------------------------------------------------
\241\ See letters from API, BHP, BP, CFA, CNOOC, Denbury, Devon,
Eni, Energy Literacy, ExxonMobil, Imperial, R. Jones, D. McBride,
Newfield, Nexen, Petro-Canada, Ross, D. Ryder, Sasol, Shell,
Talisman, Total, and W. van de Vijver.
\242\ See letters from API, Denbury, ExxonMobil, Imperial,
Nexen, Shell, and Talisman.
\243\ See letters from AAPG, API, BP, Devon, ExxonMobil,
Imperial, D. McBride, Newfield, D. Ryder, and Sasol.
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e. Reserve Audits and The Contents of Third-Party Reports
In the Proposing Release, we proposed that, if a company represents
that its estimates of reserves are prepared or audited by a third
party, the company must file a report of the third party as an exhibit
to the relevant registration statement or report. Two commenters
believed that a company description of the third party's report would
be sufficient because the reports can contain sensitive
information.\244\ However, another commenter was concerned that not
filing the report may lead to mischaracterizations by the company.\245\
This commenter supported the filing of a report by the third party
reserves estimator or auditor, but believed that the Commission should
determine the contents of such a report.\246\ Two commenters supported
the filing of the report ``letter'' as an exhibit, but not the full
reserves report because it may contain proprietary information.\247\
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\244\ See letters from Evolution and Petro-Canada.
\245\ See letter from Wagner.
\246\ See letter from Wagner.
\247\ See letters from Devon and Ryder Scott.
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As proposed, we are adopting a new rule to require that if the
company represents that a third party prepared the reserves estimate or
conducted a reserves audit of the reserves estimates, the company must
file a report of the third party as an exhibit to the relevant
registration statement or report.\248\ These reports need not be the
full ``reserves report,'' which is often very detailed and voluminous.
Rather, these reports could be shorter form reports that summarize the
scope of work performed by, and conclusions of, the third party. These
reports must include the following disclosure, based on the Society of
Petroleum Evaluation Engineers's audit report guidelines:
---------------------------------------------------------------------------
\248\ See Item 1202(a)(8) [17 CFR 229.1202(a)(8)].
---------------------------------------------------------------------------
The purpose for which the report is being prepared and for
whom it is prepared;
The effective date of the report and the date on which the
report was completed;
The proportion of the company's total reserves covered by
the report and the geographic area in which the covered reserves are
located;
The assumptions, data, methods, and procedures used to
conduct the reserves audit, including the percentage of company's total
reserves reviewed in connection with the preparation of the report, and
a statement that such assumptions, data, methods, and procedures are
appropriate for the purpose served by the report;
A discussion of primary economic assumptions;
A discussion of the possible effects of regulation on the
ability of the registrant to recover the estimated reserves;
A discussion regarding the inherent risks and
uncertainties of reserves estimates;
A statement that the third party has used all methods and
procedures as it considered necessary under the circumstances to
prepare the report; and
The signature of the third party.
In addition, if the report is related to a reserves audit, it must
contain a brief summary of the third party's conclusions with respect
to the reserves estimates. Finally, if the disclosures are
[[Page 2176]]
made in, or incorporated into, a Securities Act registration statement,
the company must file a consent of the third party as an exhibit to the
filing.
In the Proposing Release, we proposed to define the term ``reserves
audit'' as ``the process of reviewing certain of the pertinent facts
interpreted and assumptions made that have resulted in an estimate of
reserves prepared by others and the rendering of an opinion about the
appropriateness of the methodologies employed, the adequacy and quality
of the data relied upon, the depth and thoroughness of the reserves
estimation process, the classification of reserves appropriate to the
relevant definitions used, and the reasonableness of the estimated
reserves quantities. In order to disclose that a `reserves audit' has
been conducted, the report resulting from this review must represent an
examination of at least 80% of the portion of the registrant's reserves
covered by the reserves audit.'' We are substantively adopting the
first sentence of this definition as proposed.
However, in response to comments received, we are not adopting the
proposed second sentence of the definition of the term ``reserves
audit.'' Two commenters supported the proposed 80% threshold regarding
the proportion of reserves that a reserves auditor must review in order
for the company to characterize that auditor's work as a ``reserves
audit.'' \249\ Another commenter believed that the 80% threshold was
appropriate for preparing reserves estimates.\250\ But three commenters
believed that an audit should simply disclose the percentage that was
audited.\251\ One of these noted that it has its reserves audit
performed on a rolling basis.\252\ We believe that disclosure of the
work done in the required third-party report makes a bright-line
percentage test unnecessary. If a company conducts its reserves audit
on a rolling basis, it is appropriate for its shareholders to be aware
of that fact. Therefore, we are not adopting the proposed 80%
threshold. We believe that disclosure of the scope of the review will
enable investors to assess the significance to attribute to a reserves
audit.
---------------------------------------------------------------------------
\249\ See letters from Evolution and Wagner.
\250\ See letter from Ryder Scott.
\251\ See letters from Devon, Ryder Scott, and Talisman.
\252\ See letter from Talisman.
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f. Process Reviews
In the Proposing Release, we solicited comment regarding whether we
should permit a company to disclose that it has hired a third party to
perform a process review under the Society of Petroleum Engineers'
(SPE's) reserves auditing standards.\253\ Those standards define a
process review as an investigation by a person who is qualified by
experience and training equivalent to that of a reserves auditor to
address the adequacy and effectiveness of an entity's internal
processes and controls relative to reserves estimation. However, those
standards also note that a process review should not include an opinion
relative to the reasonableness of the reserves quantities and should be
limited to the processes and control system reviewed. The SPE's
standards state that, although such reviews may provide value to the
entity, an external or internal process review is not of sufficient
rigor to establish appropriate classifications and quantities of
reserves and should not be represented to the public as being
equivalent to a reserves audit.
---------------------------------------------------------------------------
\253\ See SPE Reserves Auditing Standards.
---------------------------------------------------------------------------
Five commenters believed that internal process reviews are helpful
in promoting accuracy and effectiveness, so companies should be
permitted to disclose them.\254\ However, one commenter was concerned
that, although a process review can be helpful for a company,
disclosure may give investors a false sense of security.\255\ Two
commenters suggested that, if a company discloses that it performed a
process review, it should clearly disclose what a process review
is.\256\
---------------------------------------------------------------------------
\254\ See letters from Devon, ExxonMobil, Petro-Canada, Ryder
Scott, and Shell.
\255\ See letter from Wagner.
\256\ See letters from Devon and Petro-Canada.
---------------------------------------------------------------------------
We agree that a process review can be helpful to the company and
ultimately to investors. However, we also agree that if a company
discloses that it has hired a third party to perform a process review,
it must clearly disclose the details surrounding that process review.
As such, the new rules treat a process review similar to a reserves
audit. If the company discloses that it has hired a third party to
conduct a process review, it must file a report of the third party as
an exhibit to the relevant registration statement or report and, if the
disclosures are made in, or incorporated into, a Securities Act
registration statement, the company must file a consent of the third
party as an exhibit to the filing.\257\
---------------------------------------------------------------------------
\257\ See Item 1202(a)(8) [17 CFR 229.1202(a)(8)].
---------------------------------------------------------------------------
4. Item 1203 (Proved Undeveloped Reserves)
We proposed requiring tabular disclosure of the aging of proved
undeveloped reserves (PUDs). Proposed Item 1203 would have required an
oil and gas company to prepare a table showing, for each of the last
five fiscal years and by product type, proved reserves estimated using
current prices and costs in the following categories:
Proved undeveloped reserves converted to proved developed
reserves during the year; and
Net investment required to convert proved undeveloped
reserves to proved developed reserves during the year.\258\
---------------------------------------------------------------------------
\258\ See Item 1204 [17 CFR 229.1204].
---------------------------------------------------------------------------
Numerous commenters were concerned that the proposed five-year
table would be too complex for investors to understand.\259\ They
expressed concern that the proposed table may mislead investors by not
clearly attributing costs to the year in which the corresponding PUDs
are converted because much of the costs may have been spent in previous
years.\260\ In addition, commenters noted that maintenance of such data
would be costly \261\ and that companies currently do not always
capture this type of information because management does not use it to
run the business.\262\
---------------------------------------------------------------------------
\259\ See letters from API, BP, Canadian Natural, CAPP, Chevron,
Eni, Equitable, ExxonMobil, Nexen, Petrobras, Repsol, Shell, and
Wagner.
\260\ See letters from API, ExxonMobil, Petrobras, Ryder Scott,
Total, and Wagner.
\261\ See letters from API, Canadian Natural, CAPP, Chevron,
Eni, Equitable, ExxonMobil, Nexen, Petrobras, Southwestern, and
Wagner.
\262\ See letter from Apache.
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Eight commenters suggested an alternative of disclosing (1) the
quantity of undeveloped reserves if material, (2) the progress in
converting PUDs, and (3) any material changes in the current year.\263\
Three U.S. Senators recommended requiring disclosure of development
plans in addition to the table.\264\ They believed that requiring
reporting of investments and planned investments in oil and gas
development would provide investors with certainty about companies'
intentions to develop the federal lands that they have at their
disposal.\265\ However, three commenters opposed disclosure of a
company's plans to drill and expected capital expenditures because
disclosing their business plan may cause competitive harm and might
expose them to litigation if results differ from their plan.\266\ Six
commenters supported the proposed table.\267\
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\263\ See letters from API, Canadian Natural, Chevron,
ExxonMobil, Newfield, Nexen, Petrobras, and Ryder Scott.
\264\ See letter from Three Senators.
\265\ See letter from Three Senators.
\266\ See letters from Chesapeake, Devon, and Newfield.
\267\ See letters from Chesapeake, Deloitte, Devon, Three
Senators, Talisman, and Wagner.
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[[Page 2177]]
We recognize the concern that the PUD table that we proposed may be
confusing to investors because it would not attribute capital
expenditures to the corresponding reserves as they are developed. As an
alternative to the proposed table, we are adopting rules that require a
company to disclose the following in narrative form:
The total quantity of PUDs at year end;
Any material changes in PUDs that occurred during the
year, including PUDs converted into proved developed reserves;
Investments and progress made during the year to convert
PUDs to proved developed oil and gas reserves; and
An explanation of the reasons why material concentrations
of PUDs in individual fields or countries have remained undeveloped for
five years or more after disclosure as PUDs.\268\
---------------------------------------------------------------------------
\268\ See Item 1203 [17 CFR 229.1203].
---------------------------------------------------------------------------
These disclosures would have been required under the proposal, but
much of it would have been presented in tabular format. We believe that
a narrative approach to these disclosures will provide companies with a
better vehicle to explain the status of their PUDs and their track
record for developing such reserves. Rather than requiring forward-
looking information about a company's plans to develop reserves that
may lead to exaggeration of a company's capability to actually convert
such reserves, we believe that disclosure of a company's verifiable,
established track record of converting such reserves, including its
ability to obtain financing for such activities, would be a better
indication of the likelihood of that company's success in developing
reserves in the future. Specific required disclosure regarding a
company's failure to develop material concentrations of PUDs for five
or more years should address commenters' concerns that the company may
have no intention to develop such reserves.
5. Item 1204 (Oil and Gas Production)
We proposed to codify the Industry Guide 2 disclosure regarding oil
and gas production as Item 1204 of Regulation S-K, in tabular form and
with greater detail. One commenter did not believe that separating
production, sales price and production costs based on whether they were
related oil wells or gas wells would be valuable to investors.\269\ It
believed that companies do not use this information to manage their
business and do not maintain systems to capture this information on
that basis, so tracking such data would require costly changes to their
systems.\270\ Two commenters also believed that it would not be
possible to separate production cost by product because many units
extract different products.\271\ One commenter also recommended that
production not be segregated by type of accumulation.\272\
---------------------------------------------------------------------------
\269\ See letter from Apache.
\270\ See letter from Apache.
\271\ See letters from Total and ExxonMobil.
\272\ See letter from ExxonMobil.
---------------------------------------------------------------------------
We have decided not to adopt Item 1204 as proposed. Rather, we are
codifying the existing Industry Guide 2 disclosure item with several
revisions. Consistent with the Industry Guide 2 disclosure item, the
Item 1204, as adopted, requires disclosure, for each of the prior three
fiscal years, of production, by final product sold, of oil, gas, and
other products. In addition, for the same time period, the company must
disclose, by geographical area:
The average sales price (including transfers) per unit of
oil, gas and other products produced; and
The average production cost, not including ad valorem and
severance taxes, per unit of production.
However, unlike the Industry Guide disclosure item, this disclosure
must be made by geographical area and for each country and field
containing 15% or more of the registrant's proved reserves, expressed
on an oil-equivalent-barrels basis.
Similarly, we are codifying the instructions to the Industry Guide
2 item. One commenter recommended that we maintain some of the existing
instructions from the Industry Guide.\273\ The first instruction
codified from the Industry Guide clarifies that net production should
include only production that is owned by the registrant and produced to
its interest, less royalties and production due others. However, in
special situations (e.g., foreign production), net production before
any royalties may be provided, if more appropriate. If ``net before
royalty'' production figures are furnished, the change from the usage
of ``net production'' should be noted.
---------------------------------------------------------------------------
\273\ See letter from ExxonMobil.
---------------------------------------------------------------------------
The second instruction, which is also from the Industry Guide,
states that production of natural gas should include only marketable
production of natural gas on an ``as sold'' basis. Production will
include dry, residue, and wet gas, depending on whether liquids have
been extracted before the registrant transfers title. Flared gas,
injected gas, and gas consumed in operations should be omitted.
Recovered gas-lift gas and reproduced gas should not be included until
sold. Synthetic gas, when marketed as such, should be included in
natural gas sales.
We are adding a third instruction that was not in the Industry
Guide. This instruction states that, if any product, such as bitumen,
is sold or custody is transferred prior to conversion to synthetic oil
or gas, the product's production, transfer prices, and production costs
should be disclosed separately from all other products. This
instruction is necessary because the existing Industry Guide 2
disclosure requirement only required separate disclosure based on
whether the end product was oil or gas. This instruction merely
clarifies that disclosures under this item must be based on the end
product, which may not be oil or gas because the amendments will permit
the disclosure of reserves of other end products, such as bitumen.
The fourth instruction codified from the Industry Guide states that
the transfer price of oil and gas (natural and synthetic) produced
should be determined in accordance with SFAS 69. And the fifth
instruction codified from the Industry Guide clarifies that the average
production cost per unit of production should be computed using
production costs disclosed pursuant to SFAS 69. Units of production
should be expressed in common units of production with oil, gas, and
other products converted to a common unit of measure on the basis used
in computing amortization. This instruction also adds products from
unconventional sources to the existing disclosure Item in Industry
Guide 2.
6. Item 1205 (Drilling and Other Exploratory and Development
Activities)
We proposed to codify the Industry Guide 2 disclosure item
regarding drilling activities as Item 1205 of Regulation S-K, in
tabular form, with several revisions to that Industry Guide 2
disclosure item, including applying a new definition of the term
``geographic area'' and adding two categories of wells:
Extension wells; and
Suspended wells.
Three commenters believed that the disclosures required under this
proposed Item would become too detailed.\274\ One of these commenters
also believed that the number of wells being drilled does not provide
an accurate picture of a company's drilling
[[Page 2178]]
activities because of the increased usage of horizontal wells.\275\
Some commenters also did not believe that creating new categories
for extension wells and suspended wells would be meaningful.\276\ They
noted the burden of the added detail would exceed the value of the
information to investors.\277\ One pointed out that determining whether
a well constitutes an extension well would be difficult because of
multipurpose drilling.\278\
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\274\ See letters from Apache, ExxonMobil, and Total.
\275\ See letter from ExxonMobil.
\276\ See letters from Apache, API, and Imperial.
\277\ See letters from Apache and Southwestern.
\278\ See letter from Total.
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After considering the above comments, we have decided not to adopt
all of the proposed revisions to the existing Industry Guide 2
disclosure. We recognize that, for some companies that use advanced
drilling techniques, the proposed disclosure may not be a good
indicator of the extent of their exploratory and development
activities, although we believe that this disclosure is still important
for many companies. Therefore, we have decided to codify the existing
disclosures found in Industry Guide 2 related to drilling activities
without revision and to not require tabular disclosure.\279\ However,
as proposed, we are adding a new provision to this Item that requires
companies to discuss their exploratory and development activities
regarding oil and gas resources that are extracted by mining techniques
because we are now including such resources under the definition of
``oil and gas producing activities.''
---------------------------------------------------------------------------
\279\ See Item 1205 [17 CFR 229.1205].
---------------------------------------------------------------------------
7. Item 1206 (Present Activities)
Item 1206 codifies existing Item 7 of Industry Guide 2, which calls
for disclosure of present activities, including the number of wells in
the process of being drilled (including wells temporarily suspended),
waterfloods in process of being installed, pressure maintenance
operations, and any other related activities of material
importance.\280\ We are adopting Item 1206 substantially as proposed.
---------------------------------------------------------------------------
\280\ See Item 1206 [17 CFR 229.1206].
---------------------------------------------------------------------------
8. Item 1207 (Delivery Commitments)
Item 1207 codifies existing Item 8 of Industry Guide 2, which calls
for disclosure of arrangements under which the company is required to
deliver specified amounts of oil or gas and how the company intends to
meet such commitments.\281\ We are not adopting any substantive changes
to the disclosure currently called for by Item 8 of Industry Guide 2.
However, we are restructuring and rewording the disclosure item to make
it easier to understand, including separating embedded lists into
separate subparagraphs and making general plain English revisions. As
proposed, these revisions are not intended to change the substance of
the disclosures.
---------------------------------------------------------------------------
\281\ See Item 1207 [17 CFR 229.1207].
---------------------------------------------------------------------------
9. Item 1208 (Oil and Gas Properties, Wells, Operations, and Acreage)
We proposed to codify disclosure about oil and gas properties,
wells, operations, and acreage as Item 1208 of Regulation S-K, in
tabular form, as well as make several revisions to the existing
disclosures, including applying a new definition of the term
``geographic area'' and adding language that better illustrates the
types of properties and the types of disclosures for those properties,
including the following:
Identification and description generally of the company's
material properties, plants, facilities, and installations;
Identification of the geographic area in which they are
located;
Indication of whether they are located onshore or
offshore; and
Description of any statutory or other mandatory
relinquishments, surrenders, back-ins, or changes in ownership.
Six commenters believed that it is not necessary to enhance this
section from Industry Guide 2 because the requirements are already
covered by Item 102 of Regulation S-K.\282\ Commenters were
particularly concerned with the segmentation of this disclosure by
product, by type of accumulation, and by geographic location.\283\ They
believed that this level of detail would not be helpful to investors
and would impose added costs on companies because they currently do not
collect this detailed information.\284\ Moreover, seven commenters
thought that the well count disclosure is no longer meaningful because
of technologies such as horizontal drilling.\285\ They thought that, in
light of these new technologies, well count disclosure could be
misleading.\286\
As with the case of drilling activities, we agree that the proposed
added detail could make the disclosures too cumbersome. In addition,
such disclosure may be of less importance to many companies because of
new drilling technology. Therefore, we are merely codifying the
existing Industry Guide 2 disclosure, without revision.\287\
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\282\ See letters from API, Chevron, ExxonMobil, Imperial,
Shell, and Total.
\283\ See letters from Apache, ExxonMobil, Shell, and Total.
\284\ See letters from Apache, ExxonMobil, and Petro-Canada.
\285\ See letters from API, BP, Chevron, ExxonMobil, Imperial,
StatoilHydro, and Total.
\286\ See letters from API and Imperial.
\287\ See Item 1208 [17 CFR 229.1208].
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V. Guidance for Management's Discussion and Analysis for Companies
Engaged in Oil and Gas Producing Activities
We proposed to add a new Item 1209, which would have specified
topics that a company should address either as part of its Management's
Discussion and Analysis of Financial Condition and Results of
Operations (MD&A) or in a separate section.\288\ Four commenters were
concerned that, although the proposed Item was intended to provide more
guidance regarding the disclosures required, it would effectively
require companies to address all of the issues listed in the Item.\289\
One recommended that, instead of a detailed list, the requirement
should clarify that companies should address ``material changes due to
technology, prices, concession conditions, commercial terms, known
trends, demands, commitments, uncertainties and any events that are
reasonably likely to have a material effect on reserves estimates and
financial condition.'' \290\ Similarly, another commenter recommended
that the Commission clarify that the Item is limited to material
impacts.\291\
---------------------------------------------------------------------------
\288\ See Item 303 of Regulation S-K [17 CFR 229.303].
\289\ See letters from Chevron, ExxonMobil, Petrobras, and
Shell.
\290\ See letter from Repsol.
\291\ See letter from Total.
---------------------------------------------------------------------------
We are not adopting the proposed Item as part of Regulation S-K
because it is intended to be guidance, rather than a specific
disclosure Item. We agree that, if companies were to discuss every
issue provided in the list, the disclosure would be too long and
detailed to be of much use to most investors. Important issues could be
hidden amid unnecessary detail. However, we believe that added guidance
would be beneficial to companies regarding the issues that the
Commission's staff commented upon in its review of the MD&A section of
filings made by oil and gas companies.
To begin, a fundamental premise of MD&A is that the information
provided should be related to issues that are material to a company.
Although we discuss a list of topics that a company might need to
discuss, a company need only discuss a topic if it constitutes,
involves, or indicates known trends, demands, commitments,
uncertainties, and events that are reasonably likely to have a material
effect on the company. These topics include:
[[Page 2179]]
Changes in proved reserves and, if disclosed, probable and
possible reserves, and the sources to which such changes are
attributable, including changes made due to:
[cir] Changes in prices;
[cir] Technical revisions; and
[cir] Changes in the status of any concessions held (such as
terminations, renewals, or changes in provisions);
Technologies used to establish the appropriate level of
certainty for any material additions to, or increases in, reserves
estimates, including any material additions or increases to reserves
estimates that are the result of any of the final rules adopted in this
release;
Prices and costs, including the impact on depreciation,
depletion and amortization as well as the full cost ceiling test;
Performance of currently producing wells, including water
production from such wells and the need to use enhanced recovery
techniques to maintain production from such wells;
Performance of any mining-type activities for the
production of hydrocarbons;
The company's recent ability to convert proved undeveloped
reserves to proved developed reserves, and, if disclosed, probable
reserves to proved reserves and possible reserves to probable or proved
reserves;
The minimum remaining terms of leases and concessions;
Material changes to any line item in the tables described
in Items 1202 through 1208 of Regulation S-K;
Potential effects of different forms of rights to
resources, such as production sharing contracts, on operations; and
Geopolitical risks that apply to material concentrations
of reserves.
The MD&A is typically presented in a self-contained section of the
registration statement or report. However, the disclosure requirements
that comprise new Subpart 1200 of Regulation S-K will cause a
substantial amount of an oil and gas company's disclosure to appear in
tabular format, providing an outline of much of a company's operations.
Because the tables will present many of the types of changes that
management often discusses in its MD&A, we believe it may be more
helpful to investors to locate such discussion close to the tables
themselves. Thus, to the extent that any discussion or analysis of
known trends, demands, commitments, uncertainties, and events that are
reasonably likely to have a material effect on the company is directly
relevant to a particular disclosure required by Subpart 1200, the
company may include that discussion or analysis with the relevant
table, with appropriate cross-references, rather than including it in
its general MD&A section.
VI. Conforming Changes to Form 20-F
Form 20-F is the form on which foreign private issuers file their
annual reports and Exchange Act registration statements. Currently,
Form 20-F contains instructions that are similar to those in Item 102
of Regulation S-K. However, rather than referring to Industry Guide 2
for disclosures regarding oil and gas producing activities, Form 20-F
contains its own ``Appendix A to Item 4.D--Oil and Gas'' (Appendix A)
that provides guidance for oil and gas disclosures for foreign private
issuers.\292\ Appendix A is significantly shorter, and provides far
less guidance regarding disclosures, than Subpart 1200 or Industry
Guide 2. We proposed to revise Form 20-F to eliminate the reference to
Appendix A, and rather refer to Subpart 1200, which would expand the
disclosures required by foreign private issuers.
---------------------------------------------------------------------------
\292\ See Appendix A to Item 4.D--Oil and Gas of Form 20-F [17
CFR 249.220f].
---------------------------------------------------------------------------
Six commenters supported harmonizing the Form 20-F disclosures with
Regulation S-K.\293\ One noted that the proposal would make disclosure
more consistent and comparable among oil companies.\294\ It believed
the proposal would put all oil companies on a level playing field.\295\
However, one commenter recommended that the Commission exempt companies
reporting under International Financial Reporting Standards
(IFRS).\296\ It also recommended that instead of applying the proposed
Subpart 1200 to foreign private issuers, the Commission should revise
Appendix A to Form 20-F itself, making appropriate limitations for
foreign private issuers, such as eliminating the disclosure of wells
and acreage.\297\ Another commenter was concerned because the proposals
may hinder, rather than facilitate, transition to the use of IFRS.\298\
---------------------------------------------------------------------------
\293\ See letters from CAQ, Deloitte, ExxonMobil, KPMG, PWC, and
Shell.
\294\ See letter from ExxonMobil.
\295\ See letter from ExxonMobil.
\296\ See letter from Total.
\297\ See letter from Total.
\298\ See letter from Ross.
---------------------------------------------------------------------------
We continue to believe that Subpart 1200 would be appropriate
disclosure for all public companies engaged in oil and gas producing
activities, including foreign private issuers. The added guidance in
Subpart 1200 should promote more consistent and comparable disclosures
among oil and gas companies. It is our understanding that many of the
larger foreign private issuers already provide disclosure in their
filings with the Commission comparable to the disclosure provided by
domestic companies. Thus, we are revising Form 20-F to incorporate
Subpart 1200 with respect to oil and gas disclosures and delete
Appendix A to Item 4.D in that form. We recognize that this requirement
may require a foreign private issuer to prepare two different reserves
estimates if the rules in their home jurisdiction require a different
pricing standard than the 12-month average that we adopt in this
release. However, we believe the same conflict would have existed under
our previous rule to the extent our pricing method differed from the
home jurisdiction's method.
Appendix A currently allows a foreign private issuer to exclude
required disclosures about reserves and agreements if its home country
prohibits the disclosures. Two commenters suggested that the rule
continue to provide an exception for disclosures about reserves and
agreements that are prohibited by foreign laws.\299\ However, another
commenter believed that a company taking advantage of such an exception
should be required to disclose the country, the citation of the
relevant law or regulation, and the fact that the disclosed estimates
do not include amounts from the named country.\300\ We are not revising
this provision. Rather, because these considerations still apply to
such foreign private issuers, we are moving that provision from
Appendix A and adopting it as Instruction 2 to Item 4 of Form 20-F, as
proposed.\301\
---------------------------------------------------------------------------
\299\ See letters from Shell and Total.
\300\ See letter from ExxonMobil.
\301\ Id.
---------------------------------------------------------------------------
One commenter recommended clarifying that the new disclosures would
not apply to foreign private issuers under the Multi-Jurisdictional
Disclosure System (MJDS) using Form 40--F that comply with NI 51-101 in
Canada because those rules already are broadly consistent with
PRMS.\302\ We agree with this commenter and believe that such issuers
need not provide disclosures beyond those required in Canada.
---------------------------------------------------------------------------
\302\ See letter from Deloitte.
---------------------------------------------------------------------------
VII. Impact of Amendments on Accounting Literature
A. Consistency With FASB and IASB Rules
Numerous commenters recommended that the SEC generally coordinate
its efforts with the IASB and FASB to create a cohesive whole and not
adopt
[[Page 2180]]
competing models.\303\ We have begun, and will continue, to work with
both of these organizations to ensure a smooth transition to the new
reporting rules.
---------------------------------------------------------------------------
\303\ See letters from CAQ, CFA, Eni, Grant Thornton, KPMG, and
PWC.
---------------------------------------------------------------------------
B. Change in Accounting Principle or Estimate
In the Proposing Release, we expressed our view that the change
from using single-day year-end price to an average price should be
treated as a change in accounting principle, or a change in the method
of applying an accounting principle, that is inseparable from a change
in accounting estimate. Therefore, this change would be considered a
change in accounting estimate pursuant to Statement of Financial
Accounting Standard No. 154 ``Accounting Changes and Error
Corrections'' (SFAS 154) and would be accounted for prospectively.
Commenters believed that the change would be best described as:
A change in accounting estimate; \304\
---------------------------------------------------------------------------
\304\ See letters from CAQ, Canadian Natural, CAPP, Deloitte,
Devon, KPMG, Petrobras, PWC, Repsol, Shell, and StatoilHydro.
---------------------------------------------------------------------------
A change in accounting principle that is inseparable from
a change in accounting estimate; or \305\
---------------------------------------------------------------------------
\305\ See letter from Deloitte.
---------------------------------------------------------------------------
A change in accounting estimate effected by a change in
accounting principle.\306\
---------------------------------------------------------------------------
\306\ See letter from Petro-Canada.
---------------------------------------------------------------------------
We believe that any accounting change resulting from the changes in
definitions and required pricing assumptions in Rule 4-10, should be
treated as a change in accounting principle that is inseparable from a
change in accounting estimate, which does not require retroactive
revision. We note that pursuant to AU 420.13, such a change requires
recognition in the independent auditor's report through the addition of
an explanatory paragraph.
All commenters on the issue agreed that adoption of the rules
should not require retroactive revision of past reserves
estimates.\307\ Some believed retroactive revision of reserves
estimates would be very burdensome or impossible because such data was
not maintained.\308\ We agree with those commenters and believe that no
retroactive revisions will be necessary.
---------------------------------------------------------------------------
\307\ See letters from Apache, CAQ, Canadian Natural, CAPP,
Deloitte, Devon, Evolution, ExxonMobil, Petrobras, Petro-Canada,
PWC, Repsol, Shell, StatoilHydro, and Total.
\308\ See letters from Canadian Natural, Deloitte, Evolution,
Petrobras, and Shell.
---------------------------------------------------------------------------
Three commenters recommended that the FASB revise Statement of
Financial Accounting Standard No. 19 (SFAS 19) to include
unconventional resources currently accounted for as mining activities
and also provide guidance that no retroactive revisions would be
required in that scenario.\309\ We will continue to work with the FASB
on this issue.
---------------------------------------------------------------------------
\309\ See letters from CAQ, Petrobras, and PWC.
---------------------------------------------------------------------------
C. Differing Capitalization Thresholds Between Mining Activities and
Oil and Gas Producing Activities
As noted elsewhere in this release, extraction of products such as
bitumen now will be considered oil and gas producing activities, and
not mining activities. Under current U.S. accounting guidance, costs
associated with proven plus probable mining reserves may be capitalized
for operations extracting products through mining methods, like
bitumen. Under the new rules, bitumen extraction and operations that
produce oil or gas through mining methods are included under oil and
gas accounting rules, which only permit capitalization of costs
associated with proved reserves.\310\ Moreover, the mining guidelines
do not provide specified percentages for establishing levels of
certainty for proven or probable reserves for mining activities. It is
possible that these differences could result in changing reserves
estimates for these resources during the transition to the new rules.
---------------------------------------------------------------------------
\310\ See Rule 4-10(c) of Regulation S-X [17 CFR 210.4-10(c)].
---------------------------------------------------------------------------
One commenter believed that the industry would need guidance
regarding how to transition operations that are disclosed and accounted
for as mining operations to oil and gas disclosure and accounting.\311\
It noted that this issue would be relevant not only coincident with the
new rules, but could be relevant to future events, such as a coal
mining company that in subsequent years changes its operations to in
situ coal gasification.\312\ That commenter believed that, without
guidance, the change from mining treatment to oil and gas treatment
could be considered a change in accounting principle which requires
retroactive revision.\313\ We acknowledge this commenter's concerns.
With respect to resources formerly considered mining activities, we
view the change from mining treatment to oil and gas treatment as a
change in accounting principle that is inseparable from a change in
accounting estimate, which does not require retroactive revision.
---------------------------------------------------------------------------
\311\ See letter from KPMG.
\312\ See letter from KPMG.
\313\ See letter from KPMG.
---------------------------------------------------------------------------
VIII. Application of Interactive Data Format to Oil and Gas Disclosures
In the Proposing Release, we sought comment on the desirability of
rules that would permit, or require, oil and gas companies to present
the tabular disclosures in Subpart 1200 in interactive data format in
addition to the currently required format. Most commenters addressing
the topic supported the use of XBRL for oil and gas disclosures.\314\
They believed using interactive data would be very helpful to investors
and analysts.\315\
---------------------------------------------------------------------------
\314\ See letters from Audit Policy, CFA, Deloitte, Devon, E&Y,
ExxonMobil, PWC, Shell, Standard Advantage, StatoilHydro, and
Zakaib.
\315\ See letters from CFA, Devon, E&Y, StatoilHydro, and
Zakaib.
---------------------------------------------------------------------------
However, they also recommended that the Commission wait until a
well-developed taxonomy exists.\316\ Some recommended that the
Commission implement it in stages, initially with a voluntary
program.\317\ One commenter recommended that the SEC work with other
groups like SPE, IASB, and the United Nations to ensure tags ultimately
become the industry standard.\318\
---------------------------------------------------------------------------
\316\ See letters from Audit Policy, Deloitte, Devon, E&Y,
ExxonMobil, PWC, Shell, StatoilHydro, and Zakaib.
\317\ See letters from Audit Policy, Devon, E&Y, PWC,
StatoilHydro, and Zakaib.
\318\ See letter from Zakaib.
---------------------------------------------------------------------------
We agree that much of the disclosures regarding oil and gas
companies would be conducive to interactive data. We intend to continue
to work on developing a taxonomy for such disclosure. Once a well-
developed taxonomy is created, we will address this issue further. We
are not, however, adopting interactive data requirements in this
release. We will continue to consider whether to require interactive
oil and gas disclosure filings in the future and, if so, when such
filings should be required based on the development status of an oil
and gas disclosure taxonomy.
IX. Implementation Date
A. Mandatory Compliance
We proposed to require companies to begin complying with the
disclosure requirements for registration statements filed on or after
January 1, 2010, and for annual reports on Forms 10-K and 20-F for
fiscal years ending on or after December 31, 2009. A company may not
apply the new rules to disclosures in quarterly reports prior to the
first annual report in which the revised disclosures are required.
[[Page 2181]]
Fifteen commenters agreed that a delayed compliance date would be
helpful in allowing companies to familiarize themselves with the new
disclosure requirements before having to comply with them.\319\ Four
commenters supported the proposed January 1, 2010 compliance date of
Securities Act filings and Exchange Act filings related to fiscal
periods ending on or after December 31, 2009.\320\ However, one
conditioned this approval upon the adoption of the rules before
December 31, 2008.\321\ Another suggested one year after adoption of
the rules.\322\
---------------------------------------------------------------------------
\319\ See letters from Apache, Chevron, Davis Polk, Deloitte,
ExxonMobil, KPMG, Newfield, Petrobras, Petro-Canada, PWC, Ryder
Scott, Shell, Southwestern, Talisman, and Total.
\320\ See letters from Davis Polk, ExxonMobil, Shell, and
StatoilHydro.
\321\ See letter from ExxonMobil.
\322\ See letter from Talisman.
---------------------------------------------------------------------------
Four commenters believed that the proposed compliance date would be
too soon.\323\ One recommended a compliance date of December 31, 2010
to enable companies to make necessary changes in IT systems and data
processing.\324\ Another noted the magnitude of the proposed changes,
length of time to design, program and implement system changes, and the
goal of getting the best possible disclosure.\325\ One commenter
suggested delaying implementation for two years after adoption.\326\
---------------------------------------------------------------------------
\323\ See letters from Apache, Petrobras, PWC, and Total.
\324\ See letter from Petrobras.
\325\ See letter from Apache.
\326\ See letter from Devon.
---------------------------------------------------------------------------
We continue to believe that the proposed compliance dates are
appropriate. However, as we discuss our revisions with the FASB and
IASB, we will consider whether to delay the compliance date further.
B. Voluntary Early Compliance
Seven commenters recommended that early compliance not be permitted
to maintain consistency and comparability of disclosure among issuers,
which could be misleading or confusing to investors.\327\ However, one
commenter believed that the Commission should permit early adoption of
the new rules because companies with different fiscal year ends are not
comparable anyway.\328\ One commenter suggested that the Commission
permit companies to provide the new disclosures supplementally.\329\ We
agree that voluntary compliance may make disclosures incomparable.
Therefore, companies may not elect to follow the new disclosure rules
prior to the effective date.
---------------------------------------------------------------------------
\327\ See letters from Davis Polk, Devon, ExxonMobil, Petrobras,
Ryder Scott, Shell, and Wagner.
\328\ See letter from Evolution.
\329\ See letter from Davis Polk.
---------------------------------------------------------------------------
X. Paperwork Reduction Act
A. Background
Our new rules and amendments contain ``collection of information''
requirements within the meaning of the Paperwork Reduction Act of 1995
(``PRA'').\330\ We submitted the new rules and amendments to the Office
of Management and Budget (OMB) for review in accordance with the
PRA.\331\ OMB has approved the revisions. The titles for these
collections of information are:
---------------------------------------------------------------------------
\330\ 44 U.S.C. 3501 et seq.
\331\ 44 U.S.C. 3507(d) and 5 CFR 1320.11.
---------------------------------------------------------------------------
(1) ``Regulation S-K'' (OMB Control No. 3235-0071); \332\
---------------------------------------------------------------------------
\332\ The paperwork burden from Regulation S-K and the Industry
Guides is imposed through the forms that are subject to the
disclosures in Regulation S-K and the Industry Guides and is
reflected in the analysis of those forms. To avoid a Paperwork
Reduction Act inventory reflecting duplicative burdens, for
administrative convenience, we estimate the burdens imposed by each
of Regulation S-K and the Industry Guides to be a total of one hour.
---------------------------------------------------------------------------
(2) ``Industry Guides'' (OMB Control No. 3235-0069);
(3) ``Regulation S-X'' (OMB Control No. 3235-0009);
(4) ``Form S-1'' (OMB Control No. 3235-0065);
(5) ``Form S-4'' (OMB Control No. 3235-0324);
(6) ``Form F-1'' (OMB Control No. 3235-0258);
(7) ``Form F-4'' (OMB Control No. 3235-0325);
(8) ``Form 10'' (OMB Control No. 3235-0064);
(9) ``Form 10-K'' (OMB Control No. 3235-0063); and
(10) ``Form 20-F'' (OMB Control No. 3235-0063).
We adopted all of the existing regulations and forms pursuant to
the Securities Act and the Exchange Act. These regulations and forms
set forth the disclosure requirements for annual reports \333\ and
registration statements that are prepared by issuers to provide
investors with the information they need to make informed investment
decisions in registered offerings and in secondary market transactions.
The industry guides supplement the existing regulations and forms and
provide guidance with respect to industry-specific disclosures.
---------------------------------------------------------------------------
\333\ The pertinent annual reports are those on Forms 10-K and
20-F.
---------------------------------------------------------------------------
Our amendments to these existing forms are intended to modernize
and update our reserves definitions to better reflect changes in the
oil and gas industry and markets and new technologies that have
occurred in the decades since the current rules were adopted, including
expanding the scope of permissible technologies for establishing
certainty levels of reserves, reserves classifications that a company
can disclose in a Commission filing, and the types of resources that
can be included in a company's reserves, as well as providing
information regarding a company's internal controls over reserves
estimation and the qualifications of person preparing reserves
estimates or conducting reserves audits. The new rules and amendments
also are intended to codify, modernize, and centralize the disclosure
items for oil and gas companies in Regulation S-K. Finally, the new
rules and amendments are intended to harmonize oil and gas disclosures
by foreign private issuers with disclosures by domestic companies.
Overall, the new rules and amendments attempt to provide improved
disclosure about an oil and gas company's business and prospects
without sacrificing clarity and comparability, which provide protection
and transparency to investors.
The hours and costs associated with preparing disclosure, filing
forms, and retaining records constitute reporting and cost burdens
imposed by the collection of information. An agency may not conduct or
sponsor, and a person is not required to respond to, a collection of
information unless it displays a currently valid control number.
Many, but not all, of the information collection requirements
related to annual reports and registration statements will be
mandatory. There is no mandatory retention period for the information
disclosed, and the information will be publicly available on the EDGAR
filing system.
B. Summary of Information Collections
The new rules and amendments increase existing disclosure burdens
for annual reports on Forms 10-K \334\ and
[[Page 2182]]
20-F and registration statements on Forms 10, 20-F, S-1, S-4, F-1, and
F-4 by creating the following new disclosure requirements, many of
which were requested by industry participants:
---------------------------------------------------------------------------
\334\ The disclosure requirements regarding oil and gas
properties and activities are in Form 10-K as well as the annual
report to security holders required pursuant to Rule 14a-3(b) [17
CFR 240.14a-3(b)]. Form 10-K permits the incorporation by reference
of information from the Rule 14a-3(b) annual report to security
holders to satisfy the Form 10-K disclosure requirements. The
analysis that follows assumes that companies would either provide
the proposed disclosure in a Form 10-K or incorporate the required
disclosure into the Form 10-K by reference to the Rule 14a-3(b)
annual report to security holders if the company is subject to the
proxy rules. This approach takes into account the burden from the
proposed disclosure requirements that are included in both Form 10-K
and Regulation 14A or 14C.
---------------------------------------------------------------------------
Disclosure of reserves from non-traditional sources (i.e.,
bitumen, shale, coalbed methane) as oil and gas reserves;
Optional disclosure of probable and possible reserves;
Optional disclosure of oil and gas reserves' sensitivity
to price;
Disclosure of the company's progress in converting proved
undeveloped reserves into proved developed reserves, including those
that are held for five years or more and an explanation of why they
should continue to be considered proved;
Disclosure of technologies used to establish reserves in a
company's initial filing with the Commission and in filings which
include material additions to reserves estimates;
The company's internal controls over reserves estimates
and the qualifications of the technical person primarily responsible
for overseeing the preparation or audit of the reserves estimates;
If a company represents that disclosure is based on the
authority of a third party that prepared the reserves estimates or
conducted a reserves audit or process review, filing a report prepared
by the third party; and
Disclosure based on a new definition of the term ``by
geographic area.''
In addition, the amendments harmonize the disclosure requirements
that apply to foreign private issuers with the disclosure requirements
that apply to domestic issuers with respect to oil and gas activities.
In particular, foreign private issuers must disclose the information
required by Items 1205 through 1208 of Regulation S-K regarding
drilling activities, present activities, delivery commitments, wells,
and acreage, which previously were not specified in Appendix A to Form
20-F. These disclosure items codify the substantive disclosures called
for by Items 4 through 8 of Industry Guide 2, although much of this
disclosure may have been disclosed by some companies under the more
general discussions of business and property on that form.
C. Revisions to PRA Burden Estimates
For purposes of the PRA, we estimated, in the Proposing Release,
the total annual increase in the paperwork burden for all affected
companies to comply with our proposed collection of information
requirements to be approximately 7,472 hours of in-house company
personnel time and to be approximately $1,659,000 for the services of
outside professionals.\335\ These estimates included the time and the
cost of preparing and reviewing disclosure and filing documents. Our
methodologies for deriving the above estimates are discussed below.
---------------------------------------------------------------------------
\335\ For administrative convenience, the presentation of the
totals related to the paperwork burden hours have been rounded to
the nearest whole number and the cost totals have been rounded to
the nearest thousand.
---------------------------------------------------------------------------
Our estimates represented the burden for all oil and gas companies
that file annual reports or registration statements with the
Commission. Based on filings received during the Commission's last
fiscal year, we estimate that 241 oil and gas companies file annual
reports and 67 oil and gas companies file registration statements. Most
of the information called for by the new disclosure requirements,
including the optional disclosure items, is readily available to oil
and gas companies and includes information that is regularly used in
their internal management systems. These disclosures include:
Disclosure of reserves from non-traditional sources (i.e.,
bitumen, shale, coalbed methane) as oil and gas reserves;
Optional disclosure of probable and possible reserves;
Optional disclosure of oil and gas reserves' sensitivity
to price;
Disclosure of the company's progress in converting proved
undeveloped reserves into proved developed reserves, including those
that are held for five years or more and an explanation of why they
should continue to be considered proved;
Disclosure of technologies used to establish reserves in a
company's initial filing with the Commission and in filings which
include material additions to reserves estimates;
The company's internal controls over reserves estimates
and the qualifications of the technical person primarily responsible
for overseeing the preparation or audit of the reserves estimates;
If a company represents that disclosure is based on the
authority of a third party that prepared the reserves estimates or
conducted a reserves audit or process review, filing a report prepared
by the third party; and
Disclosure based on a new definition of the term ``by
geographic area.''
We estimated that, on average, each company would incur a burden of 35
hours to prepare these disclosures in an annual report or registration
statement.
The amendments also apply several disclosure items to foreign
private issuers that previously did not apply to them. As noted above,
many of these disclosure items, such as drilling activities, wells and
acreage, require the issuer to provide more specificity about its
business and property. Foreign private issuers that do not currently
provide such specificity would incur an added burden to present such
disclosures in their filings. In the Proposing Release, we estimated
that this burden would be 20 hours per foreign private issuer.
We received few comments regarding our estimates. Several large oil
companies, and an industry organization that primarily represents large
oil companies, believed that the estimates were too low. They believed
that the new rules and amendments would increase their burden by 10,000
to 15,000 hours per year. However, these commenters included the
initial cost to change their internal systems to provide the new
required disclosures in their estimates. Based on conversations with
these commenters, the staff understands that they believed that the
ongoing burden would be approximately one-third of that estimate. For
purposes of its Paperwork Reduction Act estimate, the staff considers
the ongoing annual burden and spreads the initial transitional burden
of compliance with new rules and regulations over a three-year period.
In addition, these commenters indicated that the two most
significant burdens that stemmed from the proposed use of different
prices for disclosure and accounting purposes and the increased detail
in disclosures that would result from the proposed definition of the
term ``geographic area'' and the proposed disclosure by type of
accumulation. It should be noted that these commenters have significant
reserves spread worldwide. Some of these large companies have as much
as 10,000 times the amount of reserves of the median oil and gas
company. These large companies likely would be more significantly
impacted by the level of detailed disclosure that the proposals would
have required compared to the vast majority of oil and gas companies in
our reporting system, which do not have such extensive global
operations. Therefore, we do not believe that the estimate provided by
those large oil and gas companies necessarily would be applicable to
most oil and gas companies. However, in response to the concerns that
they expressed, the final rules do not require the use of different
[[Page 2183]]
prices for disclosure and full cost accounting purposes. We also intend
to continue to work with the FASB to align the accounting standards
with that pricing mechanism. In addition, we have significantly reduced
the level of detailed geographic and product disclosure that the rules
require. Finally, we are providing for a substantial transition period
to allow companies to adjust their systems to comply with the new
rules. We believe that these changes will help to mitigate the
increased burden of the new rules.
We do, however, believe that our initial burden estimates may have
been too low. We are therefore adjusting our burden estimate to reflect
an additional increase of 100 hours per company per year. In addition,
we are increasing our burden estimate for foreign private issuers by an
additional 150 hours per company per year. Consistent with current
Office of Management and Budget estimates and recent Commission
rulemakings, we estimate that 25% of the burden of preparation of
registration statements on Forms S-1, S-4, F-1, F-4, 10, and 20-F is
carried by the company internally and that 75% of the burden is carried
by outside professionals retained by the issuer at an average cost of
$400 per hour.\336\ We estimate that 75% of the burden of preparation
of annual reports on Form 10-K or Form 20-F is carried by the company
internally and that 25% of the burden is carried by outside
professionals retained by the company at an average cost of $400 per
hour. The portion of the burden carried by outside professionals is
reflected as a cost, while the portion of the burden carried by the
company internally is reflected in hours. The following tables
summarize the additional changes to the PRA estimates:
---------------------------------------------------------------------------
\336\ In connection with other recent rulemakings, we have had
discussions with several private law firms to estimate an hourly
rate of $400 as the average cost of outside professionals that
assist issuers in preparing disclosures and conducting registered
offerings.
Table 1--Calculation of Incremental Paperwork Reduction Act Burden Estimates for Exchange Act Periodic Reports
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual Incremental Incremental 75% Issuer 25% $400
responses hours/form burden ---------------- Professional Professional
Form ------------------------------------------------ ---------------- cost
(D)=(C)*0.75 ---------------
(A) (B) (C)=(A)*(B) (E)=(C)*0.25 (F)=(E)*$400
--------------------------------------------------------------------------------------------------------------------------------------------------------
10-KSec. \337\........................................ 206 100 20,600 15,450 5,150 2,060,000
20-F.................................................... 35 150 5,250 3,938 1,312 525,000
-----------------------------------------------------------------------------------------------
Total............................................... 241 .............. 25,850 19,388 6,462 2,585,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table 2--Calculation of Incremental Paperwork Reduction Act Burden Estimates for Securities Act Registration Statements and Exchange Act Registration
Statements
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual Incremental Incremental 25% Issuer 75% $400
responses hours/form burden ---------------- Professional Professional
Form ------------------------------------------------ ---------------- cost
(D)=(C)*0.25 ---------------
(A) (B) (C)=(A)*(B) (E)=(C)*0.75 (F)=(E)*$400
--------------------------------------------------------------------------------------------------------------------------------------------------------
10...................................................... 5 100 500 125 375 150,000
20-F.................................................... 2 150 300 75 225 90,000
S-1..................................................... 38 100 3,800 950 2,850 1,140,000
S-4..................................................... 17 100 1,700 425 1,275 510,000
F-1..................................................... 2 150 300 75 225 90,000
F-4..................................................... 3 150 450 112.5 337.5 135,000
-----------------------------------------------------------------------------------------------
Total............................................... 67 .............. 7,050 1762.5 5,287.5 2,115,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
D. Request for Comment
We request comment in order to evaluate the accuracy of our
estimates of the burden of the revised information collections. Any
member of the public may direct to us any comments concerning the
accuracy of these burden estimates. Persons who desire to submit
comments on the collection of information requirements should direct
their comments to the OMB, Attention: Desk Officer for the Securities
and Exchange Commission, Office of Information and Regulatory Affairs,
Washington, DC 20503, and should send a copy of the comments to
Secretary, Securities and Exchange Commission, 100 F Street, NE.,
Washington, DC 20549-1090, with reference to File No. S7-15-08.
Requests for materials submitted to the OMB by us with regard to this
collection of information should be in writing, refer to File No. S7-
15-08, and be submitted to the Securities and Exchange Commission,
Records Management Branch, 100 F Street, NE., Washington, DC 20549-
1126. Because OMB is required to make a decision concerning the
collections of information between 30 and 60 days after publication,
your comments are best assured of having their full effect if OMB
receives them within 30 days of publication.
---------------------------------------------------------------------------
\337\ The burden estimates for Form 10-K assume that the
requirements are satisfied by either including information directly
in the annual reports or incorporating the information by reference
from the Rule 14a-3(b) annual report to security holders.
---------------------------------------------------------------------------
XI. Cost-Benefit Analysis
A. Background
We are adopting revisions to the oil and gas reserves disclosure
regime of Regulation S-K and Regulation S-X under the Securities Act of
1933 and the Securities Exchange Act of 1934 and Industry Guide 2. The
revisions are intended to modernize and update oil and gas disclosure.
The oil and gas industry has experienced significant changes since the
Commission initially adopted its current rules and disclosure
[[Page 2184]]
regime between 1978 and 1982, including advancements in technology and
changes in the types of projects in which oil and gas companies invest.
The revisions also are intended to provide investors with improved
disclosure about an oil and gas company's business and prospects
without sacrificing clarity and comparability.
B. Description of New Rules and Amendments
Currently, Industry Guide 2 specifies many of the disclosure
guidelines for oil and gas companies. The Industry Guide calls for
disclosure relating to reserves, production, property, and operations
in addition to that which is required by Regulation S-K. Generally, the
new rules and amendments codify and update the existing Industry Guide
2 disclosures in a new Subpart 1200 of Regulation S-K, clarify the
level of detail required to be disclosed, and require reserves
disclosure in a tabular presentation. The changes relate primarily to
disclosure of the following:
Disclosure of reserves from non-traditional sources (e.g.,
bitumen, shale) as oil and gas reserves;
Optional disclosure of probable and possible reserves;
Optional disclosure of oil and gas reserves' sensitivity
to price;
Disclosure of the company's progress in converting proved
undeveloped reserves into proved developed reserves, including those
that are held for five years or more and an explanation of why they
should continue to be considered proved;
Disclosure of technologies used to establish reserves in a
company's initial filing with the Commission and in filings which
include material additions to reserves estimates;
The company's internal controls over reserves estimates
and the qualifications of the technical person primarily responsible
for overseeing the preparation or audit of the reserves estimates;
If a company represents that disclosure is based on the
authority of a third party that prepared the reserves estimates or
conducted a reserves audit or process review, filing a report prepared
by the third party; and
Disclosure based on a new definition of the term ``by
geographic area.''
The new rules and amendments also make revisions and additions to
the definitions section of Rule 4-10 of Regulation S-X. These revisions
update and extend reserves definitions to reflect changes in the oil
and gas industry and new technologies. In particular, the new and
revised definitions:
Expand the definition of ``oil and gas producing
activities'' to include the extraction of hydrocarbons from oil sands,
shale, coalbeds, or other natural resources and activities undertaken
with a view to such extraction;
Add a definition of ``reasonable certainty'' to provide
better guidance regarding the meaning of that term;
Add a definition of ``reliable technology'' to permit the
use of new technologies to establish proved reserves;
Define probable and possible reserves estimates; and
Add definitions to explain new terms used in the revised
definitions.
In addition, the amendments harmonize the disclosure requirements
that apply to foreign private issuers with the disclosure requirements
that apply to domestic issuers with respect to oil and gas activities.
In particular, the amendments to Form 20-F will require foreign private
issuers to disclose the information required by Items 1205 through 1208
of Regulation S-K regarding drilling activities, present activities,
delivery commitments, wells, and acreage, which are not currently
specified under Appendix A to Form 20-F, although much of this
disclosure is often disclosed by companies under the more general
discussions of business and property on that form.
C. Benefits
We expect that the new rules and amendments will increase
transparency in disclosure by oil and gas companies by providing
improved reporting standards. The revisions to the definitions should
align our disclosure rules with the realities of the modern oil and gas
markets. For example, we believe that the inclusion of bitumen and
other resources from continuous accumulations as oil and gas producing
activities is consistent with company practice to treat these
operations as part of, rather than separate from, their traditional oil
and gas producing activities. Similarly, the expansion of permissible
technologies for determining certainty levels of reserves recognizes
that companies now take advantage of these technological advances to
make business decisions. We expect these new rules and amendments to
improve disclosure by aligning the required disclosure more closely
with the way companies conduct their business.
Allowing companies to disclose probable and possible reserves is
designed to improve investors' understanding of a company's unproved
reserves. For those companies that already disclose such reserves on
their Web sites, the new rules and amendments permit them to unify such
disclosures into a single, filed document. Disclosure of these
categories of reserves beyond proved reserves may foster better company
valuations by investors, creditors, and analysts, thus improving
capital allocation and reducing investment risk. Because some of the
disclosure items are optional, the amount of increased transparency
will depend on the extent to which companies elect to provide the
additional disclosures permitted under the new rules. If companies
elect not to provide the optional disclosure, then the benefits from
increased transparency would be limited to the extent that the new
rules improve the transparency of proved reserves disclosure.
By permitting increased disclosure and promoting more consistency
and comparability among disclosures, the new rules and amendments
provide a mechanism for oil and gas companies to seek more favorable
financing terms through more disclosure and increased transparency.
Investors may be able to request such additional disclosure in
Commission filings during negotiations regarding bond and debt
covenants. Thus, we expect that, as a result of competing factors in
the marketplace, the new rules and amendments will result in increased
transparency, either because companies elect to voluntarily provide
increased disclosure, or because investors may discount companies that
do not do so. We believe that the benefits and costs of disclosing
unproved reserves ultimately will be determined by market conditions,
rather than regulatory requirements.
We expect that permitting companies to disclose probable and
possible reserves will increase market transparency, provide investors
with more reserves information, and allow for more accurate production
forecasts. By relating standards used in deterministic methods to
comparable percentage thresholds used in probabilistic methods for
establishing a given level of certainty, the new rules and amendments
should result in increased standardization in reporting practices which
would promote comparability of reserves across companies. The new rules
would define the term ``reliable technology'' to permit oil and gas
companies to prepare their reserves estimates using new types of
technology that companies are not permitted to use under the current
rules. This new definition also is designed to encompass new
technologies as they are developed in the future, thereby
[[Page 2185]]
providing investors and the market with a more comprehensive
understanding of a company's estimated reserves.
We expect that replacing the Industry Guide with new Regulation S-K
items will provide greater certainty because the disclosure
requirements would be in rules established by the Commission. In
addition, we believe that disclosure of reserves concentrated in
particular countries should provide better information to investors
regarding the geopolitical risk to which some companies may be exposed.
Overall, we believe that the amendments, as a whole, will provide
investors with more information that management uses to make business
decisions in the oil and gas industry.
1. Average Price and First of the Month Price
The revision to change the price used to calculate reserves from a
year-end single-day price to a historical average price over the
company's most recently ended fiscal year is expected to reduce the
effects of seasonality. In particular, many commenters suggested the
use of a 12-month average price to mitigate the risk of a year-end
price affected by short-term price volatility such that it does not
reflect the true nature of a company investment, planning, and
performance. Our Office of Economic Analysis studied the publicly-
available pricing data and found evidence of year-end price volatility.
The historical volatility of year-end prices is between 16 percent and
41 percent higher than the volatility of annual average prices
depending on the grade and geography of oil or gas prices considered.
This difference demonstrates variability in oil and gas prices, likely
due to seasonal demands, that does not reflect long term fundamental
values, but that cannot be immediately corrected due to the costs of
transportation and speed of delivery. Given this variability, it is
likely that a 12-month average price will yield better reserves
estimates--that reflect management planning and investment to the
extent that they discount the short-term component of oil and gas
prices--than a year-end spot price.
Many of the commenters to the Proposing Release supported the use
of a historical price, even though this approach may be less useful in
determining the fair value of a company's reserves compared to a
futures market price. We believe investors are concerned not only about
the quantity of a company's reserves, but also about the profitability
of those reserves. We also recognize that some reserves will be of more
value than others due to extraction and transportation costs. As a
result, since the new rules and amendments require the use of a single
price to estimate reserves and since that price may not be as
informative of value as a futures price, the new rules and amendments
also gives companies the option of providing a sensitivity analysis and
reporting reserves based on additional price estimates.
If companies elect to provide a sensitivity analysis, we expect
this to benefit investors by allowing them to formulate better
projections of company prospects that are more consistent with
management's planning price and prices higher and lower that may
reasonably be achieved. In particular, it allows companies the
flexibility to communicate how their reserves would change under
alternative economic conditions, including those that they may believe
better reflect their future prospects. We expect that companies would
be more likely to adopt a sensitivity analysis approach if investors
and other market participants determine that this information would
reduce investment risk, or if companies believe such disclosure will
reduce the cost of capital formation. The new rules and amendments
should result in increased price stability in determining whether
reserves are economically producible. This should mitigate seasonal
effects, resulting in reserves estimates that more closely reflect
those used by management in planning and investment decisions. We
expect this to allow for more accurate company assessments and improve
projections of company prospects.
In addition to an average annual price, many of the commenters
suggested that the price be computed on the first day of the month. Two
reasons were given. First, beginning month prices would allow an
additional month of preparation time in calculating reserves for
financial reporting. Second, some commenters suggested that month-end,
and in particular year-end, prices were subject to additional short-
term volatility because many oil and gas financial contracts expire on
those days, resulting in higher than normal trading activity. While the
staff of the Office of Economic Analysis did not find systematic
evidence of increased volatility around month-end or year-end oil and
gas prices relative to other days in the month, we agree that
additional preparation time is beneficial because reserves estimations
require significant time and resources. An additional month would help
reduce errors that might otherwise result from the financial reporting
time constraints.
Finally, we believe that revising the full cost accounting method
to use the same pricing mechanism as the reserves disclosure
requirements should provide consistency between the disclosure and
accounting presentations. The use of a single pricing method should
also minimize the incremental burden placed on companies as a result of
the rule changes because they would not be required to prepare two
separate estimates.
2. Probable and Possible Reserves
We anticipate that disclosure of probable and possible reserves, if
companies elect to do so, will allow investors, creditors, and other
users to better assess a company's reserves. In addition, the tabular
format for disclosing probable and possible reserves should reduce
investor search costs by making it easier to locate reserves
disclosures and facilitating comparability among oil and gas companies.
While we recognize that many companies already communicate with
investors about their unproved and other reserves through alternative
means, such as company Web sites or press releases, some commenters
remarked that an objective comparison among companies is difficult
because different companies have defined such reserves classifications
differently. We believe that permitting disclosure of this information
in Commission filings will provide a more consistent means of
comparison because disclosure in our filings must comply with our
definitions. Although our new rules make disclosure of probable and
possible reserves optional, and large oil and gas producers suggested
in their comment letters that such disclosure would be of limited
benefit because of the relative uncertainty of those estimates, we
believe that competitive pressures within the industry might make it
beneficial for large producers to disclose this information. Increased
disclosure might, for example, improve credit quality and lower the
cost of debt financing, or reduce the risk associated with business
transactions between the company and its customers or suppliers.
Regardless, since the disclosure decision is voluntary, it should occur
only to the extent that companies find that the benefits justify the
costs of doing so.
We believe that permitting the disclosure of probable and possible
reserves will benefit smaller companies, in particular. Larger issuers
tend to already have large amounts of proved reserves. The new rules
and amendments permit smaller companies,
[[Page 2186]]
who often participate in a significant amount of exploratory activity,
to better disclose their business prospects. Consequently, we
anticipate that the new rules and amendments could lead to efficiencies
in capital formation, as more information will be available regarding
the prospects of smaller issuers.
3. Reserves Estimate Preparers and Reserves Auditors
We believe that investors would benefit from a greater level of
assurance with respect to the reliability of reserve estimates,
particularly if companies are allowed to disclose unproved reserves
because unproved reserves are inherently less certain than proved
reserves. We proposed disclosure requirements relating to whether the
person primarily responsible for preparing reserves estimates or
conducting a reserves audit, if the company represents that it has
enlisted a third party to conduct a reserves audit, met a specified
list of qualifications based on the Society of Petroleum Engineers's
reserves audit guidelines. However, commenters expressed concern that
many of these qualifications such as membership in professional
societies were not standardized worldwide. Without control over those
standards, the disclosures would not be comparable. We agree with those
commenters and, as suggested, have adopted a more principles-based
disclosure requirement. Under the adopted rules, a company must
disclose its internal controls over reserves estimations and disclose
the qualifications of the primary technical person in charge of
overseeing the reserves estimations or reserves audit. We believe that
disclosure of the individual qualifications, rather than simple
acknowledgement of meeting certain criteria, which may differ within
countries, will provide investors with better information to compare
companies and the qualifications of persons in charge of the reserves
estimations and reserves audits, which should enable more accurate
assessments of the quality of audit reports. We believe that disclosure
of a company's internal controls over reserves estimates will allow
investors to assess whether a company has implemented appropriate
controls without dictating to companies specified criteria for
establishing those controls.
Although we do not expect all companies to undertake a third-party
reserves audit because our rules do not require such a reserves audit,
third party participation in the estimation of reserves should add
credibility to a company's public disclosure. The opinion of an
objective, qualified person on the reserves estimates is designed to
increase the reliability of these estimates and investor confidence.
4. Development of Proved Undeveloped Reserves
The new rules and amendments also require disclosure of a company's
progress in developing undeveloped reserves and the reasons why any
PUDs have remained undeveloped for five years or more. We believe that
such disclosure supplements our amendments that ease the requirements
for recognizing PUDs and thereby should increase the amount of PUDs
disclosed in filings, even though the properties representing such
proved reserves have not yet been developed and therefore do not
provide the company with cash flow. We believe that the disclosure
requirements will increase the accountability of companies that
disclose reserves for extended periods of time without adequate
justification for their failure to develop those reserves.
5. Disclosure Guidance
The release also provides guidance about the type of information
that companies should consider disclosing in Management's Discussion
and Analysis, and allows companies to include this information with the
relevant tables. Providing the additional guidance should assist
companies in preparing their disclosure, improving the quality and
consistency of this disclosure. Locating this discussion with the
tables themselves should benefit investors by simplifying the
presentation of disclosure, and providing insight into the information
disclosed in the tables.
6. Updating of Definitions Related to Oil and Gas Activities
The new rules and amendments also update the definition of the term
``oil and gas producing activities'' as well as updating or creating
new definitions for other terms related to such activities, including
``proved oil and gas reserves'' and ``reasonable certainty.'' We
believe that updating these definitions will help companies disclose
oil and gas operations in the same way that companies manage and assess
those operations. This includes resources extracted from nontraditional
sources that companies consider oil and gas activities, which
previously were excluded them from the definition of ``oil and gas
producing activities.'' In addition, adding definitions for terms like
``reasonable certainty'' (which currently is in the definition of
``proved oil and gas reserves,'' but not defined) will provide
companies with added guidance and assist them in providing consistent
disclosures between companies.
7. Harmonizing Foreign Private Issuer Disclosure
We believe that the harmonization of foreign private issuer
disclosure will help make disclosures of foreign private issuers more
comparable with domestic companies. The oil and gas industry has
changed significantly since the rules were adopted. Today, many
companies have interests that span the globe. In addition, many of
these projects are joint ventures between foreign private issuers and
domestic companies. Having differing levels of disclosure for companies
that may be participating in the same projects harms comparability
between investment choices. The harmonization of foreign private issuer
disclosure is intended to promote comparability among all oil
companies.
D. Costs
We expect that the new rules and amendments will result in initial
and ongoing costs to oil and gas companies. These burdens will vary
significantly among companies. Based on disclosures in company filings,
the largest oil and gas companies can have as much as 10,000 times the
reserves of the median reporting oil and gas company. As would be
expected, companies that have more reserves and larger operations will
have a correspondingly larger amount of information that they must
disclose and, therefore, the burden of complying with our disclosure
requirements would be greater for larger companies.
Although we are adding a new subpart to Regulation S-K to set forth
the disclosure requirements that are unique to oil and gas companies,
the subpart, for the most part, codifies the substantive disclosure
called for by Industry Guide 2. The disclosure requirements have been
updated and clarified, and require the disclosure to be presented in a
tabular format, where appropriate.
Although many companies already present this information in
tabular form, for companies that do not, this requirement could impose
a burden on companies as they transition from a narrative to tabular
disclosure format. We expect, however, that any increased preparation
costs would be highest in the first year after adoption, but would
decline in subsequent years as companies adjust to the new format. We
[[Page 2187]]
think this burden is justified because tabular disclosure will increase
comparability and facilitate understanding and analysis by investors.
1. Probable and Possible Reserves
Allowing disclosure of probable and possible reserves could create
an increased risk of litigation because these categories of reserves
estimates are less certain than proved reserves. Companies may choose
not to disclose such reserves, in part, because of the risk of
incurring litigation costs to defend their disclosures due to the
increased uncertainty of these categories. Disclosure of probable and
possible reserves may also result in revealing competitive information
because it might reveal a company's business strategy, such as the
geographic location and nature of its exploration and discoveries. For
example, if geographical detail can be inferred from estimates of
unproved reserves, this might reveal information about the value of a
company's assets to competitors and could put the producer at a
competitive disadvantage. We have reduced the level of geographical
detail to reduce the burden on companies, while still providing
sufficient information to investors regarding concentrations of risk,
including political risk.
We expect companies will incur costs in preparing the additional
disclosures such as calculating and aggregating the reserve projections
in a prescribed format. However, if probable and possible categories of
reserves have different extraction cost structures and they are not
disclosed separately from proved reserves, this could result in
increased uncertainty in an investor's assessment of a company's
prospects.
Companies also expressed concern that mandatory disclosure of
probable and possible reserves could expose them to increased
litigation risk. We believe that making these disclosures voluntary
mitigates these concerns. Companies unwilling to bear the added risk
can simply opt not to provide this disclosure.
2. Reserves Estimate Preparers and Reserves Auditors
If a company chooses to use a third party to prepare or audit
reserve estimates, it will incur costs to hire these outside
consultants. The new rules and amendments do not require companies to
hire such a person. If enough companies that currently do not use such
consultants begin to hire them, we believe that industry wages could
potentially increase due to increased demand for reserves calculating
specialists unless that demand is compensated by an increase in the
supply of such persons. If wages increased, then all companies, not
just those employing third party consultants, would incur added costs.
Large companies may be less likely to hire third parties because
they tend to have staff to make reserves estimates. However, if such
large companies chose to hire third-party consultants, third parties
would expend significantly more effort on such projects than for
smaller companies because larger companies have more properties to
evaluate. Thus, we expect third-party fees, and the time required to
conduct such projects, would scale upwards with the quantity of company
reserves.
Disclosure of unproved reserves without third-party certification
may present a risk with respect to smaller oil and gas producers
because smaller companies are likely to have less in-house expertise
and ability to accurately estimate such reserves than larger companies.
However, we understand that the vast majority of smaller oil and gas
companies already hire third parties to estimate their reserves or
certify their estimates.
3. Consistency With IASB
Some commenters remarked that the International Accounting
Standards Board is currently preparing a set of guidelines for oil and
gas extractive activities, including definitions of oil and gas
reserves, and recommended that the Commission align its regulations
with those guidelines. We intend to monitor this initiative and work
with the IASB, but our new rules may differ from the guidelines
ultimately established by the International Accounting Standards Board.
This could make it more difficult for investors to compare foreign and
domestic companies.
4. Change in Pricing Mechanism
We do not anticipate significant costs with the change in pricing
mechanisms for established reserves. Companies simply will apply a
different price scenario to determine the economic producibility of
reserves. It is possible that the use of a 12-month average price may
reduce the cost of disclosure because it should reduce the volatility
of reserves estimates and therefore reduce the need to make significant
adjustments to those estimates on a yearly basis due to daily price
swings.
5. Disclosure of PUD Development
The required disclosure of a company's progress in developing PUDs
will increase the cost of reporting. However, we believe that companies
regularly track their progress in this arena. Until a company develops
a property, it cannot begin to realize the cash flows from production
and the actual sale of products. Thus, the development of reserves is
of utmost importance to an oil and gas company's business.
6. Increased Geographic Disclosure
The requirements to provide increased geographic disclosure of
reserves and production, in certain circumstances, may increase the
amount of disclosure that a company must present. However, because the
threshold that we are adopting in the release is 15% of the company's
total reserves, a company would be required to disclose, at most,
reserves and production in six countries. Considering the relatively
large proportion of reserves that must exist in a country before a
company is required to provide country-level disclosure, we believe
that such information is readily available to companies. As noted in
the body of this release, we have attempted to draft this provision to
minimize any competitive harm that such disclosure may cause a company.
7. Harmonizing Foreign Private Issuer Disclosure
The harmonization of foreign private issuer disclosure regarding
oil and gas activities may increase the burden on foreign private
issuers. However, it is our understanding that the large foreign
private issuers already voluntarily provide disclosure comparable to
the level required from domestic companies. Much of the added new
disclosure relates to the day-to-day business and properties of these
companies, including drilling activities, number of wells and acreage.
This is information that is central to the activities of oil and gas
companies, and therefore is readily known to these companies. We
believe that applying Subpart 1200 to these companies could prompt more
detailed disclosure regarding these activities, which would cause these
companies to incur some cost. The provision permitting foreign private
issuers to omit disclosures if prohibited from making those disclosures
by their home jurisdiction could mitigate some of these costs.
[[Page 2188]]
XII. Consideration of Burden on Competition and Promotion of
Efficiency, Competition, and Capital Formation
Securities Act Section 2(b) \338\ and Section 3(f) of the Exchange
Act \339\ require us, when engaging in rulemaking where we are required
to consider or determine whether an action is necessary or appropriate
in the public interest, to consider, in addition to the protection of
investors, whether the action will promote efficiency, competition, and
capital formation. Section 23(a)(2) of the Exchange Act \340\ requires
us, when adopting rules under the Exchange Act, to consider the impact
that any new rule would have on competition. In addition, Section
23(a)(2) prohibits us from adopting any rule that would impose a burden
on competition not necessary or appropriate in furtherance of the
purposes of the Exchange Act.
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\338\ 15 U.S.C. 77b(b).
\339\ 15 U.S.C. 78c(f).
\340\ 15 U.S.C. 78w(a)(2).
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We expect the new rules and amendments to increase efficiency and
enhance capital formation, and thereby benefit investors, by providing
the market with better information based on updated technology as well
as increased information covering a broader range of reserves
classifications held by a company and reserves found in non-traditional
sources of oil and gas. Such increased and improved information should
permit investors to better assess a company's prospects. In particular,
the existing prohibitions against disclosing reserves other than proved
reserves, using modern technology to determine the certainty level of
reserves, and including resources from non-traditional sources can lead
to incomplete disclosures about a company's actual resources and
prospects. The new rules and amendments are designed to better align
the disclosure requirements with the way companies make business
decisions.
We believe that permitting the disclosure of probable and possible
reserves will benefit smaller companies, in particular. Larger issuers
tend to already have large amounts of proved reserves. The new rules
and amendments permit smaller companies, who often participate in a
significant amount of exploratory activity, to better disclose their
business prospects. Consequently, we anticipate that the new rules and
amendments could lead to efficiencies in capital formation, as more
information will be available regarding the prospects of smaller
issuers.
The effects of the new rules and amendments on competition are
difficult to predict, but it is possible that permitting public issuers
to disclose probable and possible reserves will lead to a reallocation
of capital, as companies that previously could show few proved reserves
will be able to disclose a broader range of its business prospects,
making it easier for these issuers to raise capital and compete with
companies that have large proved reserves. Although our new rules make
disclosure of probable and possible reserves optional, and large oil
and gas producers suggested in their comment letters that such
disclosure would be of limited benefit because of the relative
uncertainty associated with such reserves, we believe that competitive
pressures within the industry might make it beneficial for large
producers to disclose this information. Increased disclosure might, for
example, improve credit quality and lower the cost of debt financing,
or reduce the risk associated with business transactions between the
company and its customers or suppliers.
XIII. Final Regulatory Flexibility Analysis
We have prepared this Final Regulatory Flexibility Analysis in
accordance with Section 603 of the Regulatory Flexibility Act.\341\
This analysis relates to the modernization of the oil and gas
disclosure requirements. An Initial Regulatory Flexibility Analysis
(IRFA) was prepared in accordance with the Regulatory Flexibility Act
in conjunction with the Proposing Release. The Proposing Release
included, and solicited comment on, the IRFA.
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\341\ 5 U.S.C. 603.
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A. Reasons for, and Objectives of, the New Rules and Amendments
The Commission adopted the current disclosure regime for oil and
gas producing companies in 1978 and 1982, respectively. Since that
time, there have been significant changes in the oil and gas industry
and markets, including technological advances, and changes in the types
of projects in which oil and gas companies invest their capital. On
December 12, 2007, the Commission published a Concept Release on
possible revisions to the disclosure requirements relating to oil and
gas reserves.\342\ Prior to our issuance of the Concept Release, many
industry participants had expressed concern that our disclosure rules
are no longer in alignment with current industry practices and
therefore have limited usefulness to the market and investors.
---------------------------------------------------------------------------
\342\ See Release No. 33-8870 (Dec. 12, 2007) [72 FR 71610].
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Our new rules and amendments to these existing forms are intended
to modernize and update our reserves definitions to reflect changes in
the oil and gas industry and markets and new technologies that have
occurred in the decades since the current rules were adopted, including
expanding the scope of permissible technologies for establishing
certainty levels of reserves, reserves classifications that a company
can disclose in a Commission filing, and the types of resources that
can be included in a company's reserves, as well as providing
information regarding the objectivity and qualifications of any third
party primarily responsible for preparing or auditing the reserves
estimates, if the company represents that it has enlisted a third party
to conduct a reserves audit, and the qualifications and measures taken
to assure the independence and objectivity of any employee primarily
responsible for preparing or auditing the reserves estimates. The
amendments also harmonize our full cost accounting rules with the
changes that we are adopting with respect to disclosure of oil and gas
reserves. The new rules and amendments also are intended to codify,
modernize and centralize the disclosure items for oil and gas companies
into Regulation S-K. Finally, the new rules and amendments are intended
to harmonize oil and gas disclosures by foreign private issuers with
disclosures by domestic companies. Overall, the new rules and
amendments attempt to provide improved disclosure about an oil and gas
company's business and prospects without sacrificing clarity and
comparability, which provide protection and transparency to investors.
B. Significant Issues Raised by Commenters
We did not receive comments specifically addressing the impact of
the proposed rules and amendments on small entities. However, several
of the comments related to burdens that would be placed on all
companies affected by the proposals. In particular, commenters believed
that the proposal to require the use of different prices for disclosure
and accounting purposes would impose a significant burden on all oil
and gas companies. We have considered those comments and are adopting
amendments to our disclosure rules and the full cost accounting method
that will require the use of a single price for both purposes.
Similarly, commenters were concerned that certain aspects of
[[Page 2189]]
the proposal, such as the new definition of geographic area and
disclosure by accumulation type would increase the detail in the
disclosures significantly. We agree with those commenters and have
significantly reduced the level of detail required in the disclosure
requirements.
C. Small Entities Subject to the New Rules and Amendments
The new rules and amendments affect small entities that are engaged
in oil and gas producing activities, the securities of which are
registered under Section 12 of the Exchange Act or that are required to
file reports under Section 15(d) of the Exchange Act. The new rules and
amendments also would affect small entities that file, or have filed, a
registration statement that has not yet become effective under the
Securities Act and that has not been withdrawn. Securities Act Rule 157
\343\ and Exchange Act Rule 0-10(a) \344\ define an issuer to be a
``small business'' or ``small organization'' for purposes of the
Regulatory Flexibility Act if it had total assets of $5 million or less
on the last day of its most recent fiscal year. The new rules and
amendments affect small entities that are operating companies and
engage in oil and gas producing activities. Based on filings in 2007,
we estimate that there are approximately 28 oil and gas companies that
may be considered small entities.
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\343\ 17 CFR 230.157.
\344\ 17 CFR 240.0-10(a).
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D. Reporting, Recordkeeping, and Other Compliance Requirements
The new rules and amendments to Regulation S-K expand some existing
disclosures, and eliminate others. In particular, the new disclosure
requirements, many of which were requested by industry participants,
include the following:
Disclosure of reserves from non-traditional sources (e.g.,
bitumen and shale) as oil and gas reserves;
Optional disclosure of probable and possible reserves;
Optional disclosure of oil and gas reserves' sensitivity
to price;
Disclosure of the development of proved undeveloped
reserves, including those that are held for 5 years or more and an
explanation of why they should continue to be considered proved;
Disclosure of technologies used to establish reserves in a
company's initial filing with the Commission and in filings which
include material additions to reserves estimates;
Disclosure of the company's internal controls over
reserves estimates and the qualifications the technical person
primarily responsible for overseeing the preparation or audit of the
reserves estimates;
If a company represents that disclosure is based on the
authority of a third party that prepared the reserves estimates or
conducted a reserves audit or process review, filing a report prepared
by the third party; and
Disclosure based on a new definition of the term ``by
geographic area.''
There would be no mandatory retention period for the information
disclosed, and the information disclosed would be made publicly
available on the EDGAR filing system.
E. Agency Action To Minimize Effect on Small Entities
We considered different compliance standards for the small entities
that will be affected by the new rules and amendments. In the Proposing
Release, we solicited comment regarding the possibility of different
standards for small entities. We did not receive comment on this
particular issue. However, we believe that such differences would be
inconsistent with the purposes of the rules.
The new rules and amendments are designed to modernize the
disclosure requirements for oil and gas companies. As such, we believe
all oil and gas companies will benefit from the modernization of the
rules. Under the new rules and amendments, all companies will be
allowed to use modern technologies to establish reserves and include
operations in unconventional resources in their oil and gas reserves
estimates. Adopting differing standards for disclosure for small
entities would significantly reduce the comparability between
companies. However, the new rules and amendments do permit companies to
disclose probable and possible reserves. We believe the removal of the
prohibition against such reserves will enable companies to disclose a
broader view of their prospects. We believe this will particularly
benefit smaller oil and gas companies that may have significant
unproved reserves in their portfolio. Such disclosure may assist
smaller companies in raising capital for development projects in those
properties.
XIV. Update to Codification of Financial Reporting Policies
The Commission amends the ``Codification of Financial Reporting
Policies'' announced in Financial Reporting Release No. 1 (April 15,
1982) [47 FR 21028] as follows:
1. By removing the seven introductory paragraphs before Section
406.01, the last sentence of Section 406.01.c.vi., the first paragraph
of Section 406.01.d, the introductory paragraph of Section 406.02.d,
and removing and reserving Sections 406.01.a., 406.02.a, 406.02.b.,
406.02.d.iii., and 406.02.e.
2. By revising Section 406.01B to read as follows:
The rules in Rule 4-10(b) specify that the application of
successful efforts shall comply with SFAS 19. In 2008, the Commission
published amendments to the definitions in Rule 4-10(a) that may not
align completely with SFAS 19's existing terminology and application.
Further, paragraph 7 of SFAS 25 states: ``For purposes of applying this
Statement and Statement 19, the definition of proved reserves, proved
developed reserves, and proved undeveloped reserves shall be the
definitions adopted by the SEC for its reporting purposes that are in
effect on the date(s) as of which the reserve disclosures are to be
made. Previous reported quantities shall not be revised retroactively
if the SEC definitions are changed.'' In any case, the Commission
expects the practical application of SFAS 19 will remain unchanged
other than incorporating the effects of the new definitions.
3. By removing the first three sentences of Section 406.02.c. and
in the fourth sentence replacing the phrase ``this sort of
information'' with ``information to assess the impact of oil and gas
producing activities on near term cash flows and liquidity''.
4. By adding a new Section 406.03 entitled ``Transition'' and
including the text of the 3rd paragraph of Section VII.B and the last
sentence of the 2nd paragraph of Section VII.C of this release.
5. By adding a new Section 406.04 entitled ``MD&A Guidance'' and
including the text beginning with the last sentence of the 2nd
paragraph of Section V of this release through the end of that Section.
The Codification is a separate publication of the Commission. It
will not be published in the Federal Register or Code of Federal
Regulations. For more information on the Codification of Financial
Reporting Policies, contact the Commission's Public Reference Room at
202-551-5850.
XV. Statutory Basis and Text of Amendments
We are adopting the amendments pursuant to Sections 3(b), 6, 7, 10
and 19(a) of the Securities Act and Sections 12, 13, 14(a), 15(d), and
23(a) of the Exchange Act, as amended.
[[Page 2190]]
Text of Amendments
List of Subjects
17 CFR Part 210
Accountants, Accounting, Reporting and recordkeeping requirements,
Securities.
17 CFR Parts 211, 229 and 249
Reporting and recordkeeping requirements, Securities.
0
For the reasons set out in the preamble, title 17, chapter II of the
Code of Federal Regulations is amended as follows:
PART 210--FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL
STATEMENTS, SECURITIES ACT OF 1933, SECURITIES EXCHANGE ACT OF
1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT
COMPANY ACT OF 1940, INVESTMENT ADVISERS ACT OF 1940, AND ENERGY
POLICY AND CONSERVATION ACT OF 1975
0
1. The authority citation for part 210 continues to read as follows:
Authority: 15 U.S.C. 77f, 77g, 77h, 77j, 77s, 77z-2, 77z-3,
77aa(25), 77aa(26), 78c, 78j-1, 78l, 78m, 78n, 78o(d), 78q, 78u-5,
78w(a), 78ll, 78mm, 80a-8, 80a-20, 80a-29, 80a-30, 80a-31, 80a-
37(a), 80b-3, 80b-11, 7202 and 7262, unless otherwise noted.
0
2. Amend Sec. 210.4-10 by:
0
a. Redesignating the subparagraphs in paragraph (a) as follows:
------------------------------------------------------------------------
Old paragraph number New paragraph number
------------------------------------------------------------------------
(a)(1).................................... (a)(16)
(a)(2)................................... (a)(22)
(a)(5)................................... (a)(23)
(a)(6)................................... (a)(32)
(a)(7)................................... (a)(21)
(a)(8)................................... (a)(15)
(a)(9)................................... (a)(27)
(a)(10).................................. (a)(13)
(a)(11).................................. (a)(9)
(a)(12).................................. (a)(29)
(a)(13).................................. (a)(30)
(a)(14).................................. (a)(1)
(a)(15).................................. (a)(12)
(a)(16).................................. (a)(7)
(a)(17).................................. (a)(20)
------------------------------------------------------------------------
0
b. Removing paragraphs (a)(3) and (a)(4);
0
c. Adding new paragraphs (a)(2), (a)(3), (a)(4), (a)(5), (a)(6),
(a)(8), (a)(10), (a)(11), (a)(14), (a)(17), (a)(18), (a)(19), (a)(24),
(a)(25), (a)(26), (a)(28), (a)(31), and (c)(8);
0
d. Revising newly redesignated paragraphs (a)(13), (a)(16), (a)(22),
and (a)(30); and
0
e. Removing the authority citations following the section.
The additions and revisions read as follows:
Sec. 210.4-10 Financial accounting and reporting for oil and gas
producing activities pursuant to the Federal securities laws and the
Energy Policy and Conservation Act of 1975.
* * * * *
(a) Definitions. * * *
* * * * *
(2) Analogous reservoir. Analogous reservoirs, as used in resources
assessments, have similar rock and fluid properties, reservoir
conditions (depth, temperature, and pressure) and drive mechanisms, but
are typically at a more advanced stage of development than the
reservoir of interest and thus may provide concepts to assist in the
interpretation of more limited data and estimation of recovery. When
used to support proved reserves, an ``analogous reservoir'' refers to a
reservoir that shares the following characteristics with the reservoir
of interest:
(i) Same geological formation (but not necessarily in pressure
communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the
aggregate, be no more favorable in the analog than in the reservoir of
interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is
petroleum in a solid or semi-solid state in natural deposits with a
viscosity greater than 10,000 centipoise measured at original
temperature in the deposit and atmospheric pressure, on a gas free
basis. In its natural state it usually contains sulfur, metals, and
other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists
in the gaseous phase at original reservoir temperature and pressure,
but that, when produced, is in the liquid phase at surface pressure and
temperature.
(5) Deterministic estimate. The method of estimating reserves or
resources is called deterministic when a single value for each
parameter (from the geoscience, engineering, or economic data) in the
reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves
are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating
methods or in which the cost of the required equipment is relatively
minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure
operational at the time of the reserves estimate if the extraction is
by means not involving a well.
* * * * *
(8) Development project. A development project is the means by
which petroleum resources are brought to the status of economically
producible. As examples, the development of a single reservoir or
field, an incremental development in a producing field, or the
integrated development of a group of several fields and associated
facilities with a common ownership may constitute a development
project.
* * * * *
(10) Economically producible. The term economically producible, as
it relates to a resource, means a resource which generates revenue that
exceeds, or is reasonably expected to exceed, the costs of the
operation. The value of the products that generate revenue shall be
determined at the terminal point of oil and gas producing activities as
defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery
is the sum of reserves remaining as of a given date and cumulative
production as of that date.
* * * * *
(13) Exploratory well. An exploratory well is a well drilled to
find a new field or to find a new reservoir in a field previously found
to be productive of oil or gas in another reservoir. Generally, an
exploratory well is any well that is not a development well, an
extension well, a service well, or a stratigraphic test well as those
items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend
the limits of a known reservoir.
* * * * *
(16) Oil and gas producing activities. (i) Oil and gas producing
activities include:
(A) The search for crude oil, including condensate and natural gas
liquids, or natural gas (``oil and gas'') in their natural states and
original locations;
(B) The acquisition of property rights or properties for the
purpose of further exploration or for the purpose of removing the oil
or gas from such properties;
(C) The construction, drilling, and production activities necessary
to retrieve oil and gas from their natural reservoirs, including the
acquisition, construction, installation, and maintenance of field
gathering and storage systems, such as:
[[Page 2191]]
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of
processing gas to extract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or
gaseous state, from oil sands, shale, coalbeds, or other nonrenewable
natural resources which are intended to be upgraded into synthetic oil
or gas, and activities undertaken with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production
function shall be regarded as ending at a ``terminal point'', which is
the outlet valve on the lease or field storage tank. If unusual
physical or operational circumstances exist, it may be appropriate to
regard the terminal point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or
synthetic, are delivered to a main pipeline, a common carrier, a
refinery, or a marine terminal; and
b. In the case of natural resources that are intended to be
upgraded into synthetic oil or gas, if those natural resources are
delivered to a purchaser prior to upgrading, the first point at which
the natural resources are delivered to a main pipeline, a common
carrier, a refinery, a marine terminal, or a facility which upgrades
such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this
paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons
that are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas or natural resources that can
be upgraded into synthetic oil or gas by a registrant that does not
have the legal right to produce or a revenue interest in such
production;
(C) Activities relating to the production of natural resources
other than oil, gas, or natural resources from which synthetic oil and
gas can be extracted; or
(D) Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional
reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities
ultimately recovered from a project have a low probability of exceeding
proved plus probable plus possible reserves. When probabilistic methods
are used, there should be at least a 10% probability that the total
quantities ultimately recovered will equal or exceed the proved plus
probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir
adjacent to probable reserves where data control and interpretations of
available data are progressively less certain. Frequently, this will be
in areas where geoscience and engineering data are unable to define
clearly the area and vertical limits of commercial production from the
reservoir by a defined project.
(iii) Possible reserves also include incremental quantities
associated with a greater percentage recovery of the hydrocarbons in
place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus
possible reserves estimates must be based on reasonable alternative
technical and commercial interpretations within the reservoir or
subject project that are clearly documented, including comparisons to
results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and
engineering data identify directly adjacent portions of a reservoir
within the same accumulation that may be separated from proved areas by
faults with displacement less than formation thickness or other
geological discontinuities and that have not been penetrated by a
wellbore, and the registrant believes that such adjacent portions are
in communication with the known (proved) reservoir. Possible reserves
may be assigned to areas that are structurally higher or lower than the
proved area if these areas are in communication with the proved
reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where
direct observation has defined a highest known oil (HKO) elevation and
the potential exists for an associated gas cap, proved oil reserves
should be assigned in the structurally higher portions of the reservoir
above the HKO only if the higher contact can be established with
reasonable certainty through reliable technology. Portions of the
reservoir that do not meet this reasonable certainty criterion may be
assigned as probable and possible oil or gas based on reservoir fluid
properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional
reserves that are less certain to be recovered than proved reserves but
which, together with proved reserves, are as likely as not to be
recovered.
(i) When deterministic methods are used, it is as likely as not
that actual remaining quantities recovered will exceed the sum of
estimated proved plus probable reserves. When probabilistic methods are
used, there should be at least a 50% probability that the actual
quantities recovered will equal or exceed the proved plus probable
reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir
adjacent to proved reserves where data control or interpretations of
available data are less certain, even if the interpreted reservoir
continuity of structure or productivity does not meet the reasonable
certainty criterion. Probable reserves may be assigned to areas that
are structurally higher than the proved area if these areas are in
communication with the proved reservoir.
(iii) Probable reserves estimates also include potential
incremental quantities associated with a greater percentage recovery of
the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi)
of this section.
(19) Probabilistic estimate. The method of estimation of reserves
or resources is called probabilistic when the full range of values that
could reasonably occur for each unknown parameter (from the geoscience
and engineering data) is used to generate a full range of possible
outcomes and their associated probabilities of occurrence.
* * * * *
(22) Proved oil and gas reserves. Proved oil and gas reserves are
those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be
economically producible--from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods,
and government regulations--prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that
renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for the estimation. The project to
extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a
reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts,
if any, and
(B) Adjacent undrilled portions of the reservoir that can, with
reasonable certainty, be judged to be continuous
[[Page 2192]]
with it and to contain economically producible oil or gas on the basis
of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in
a reservoir are limited by the lowest known hydrocarbons (LKH) as seen
in a well penetration unless geoscience, engineering, or performance
data and reliable technology establishes a lower contact with
reasonable certainty.
(iii) Where direct observation from well penetrations has defined a
highest known oil (HKO) elevation and the potential exists for an
associated gas cap, proved oil reserves may be assigned in the
structurally higher portions of the reservoir only if geoscience,
engineering, or performance data and reliable technology establish the
higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through
application of improved recovery techniques (including, but not limited
to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the
reservoir with properties no more favorable than in the reservoir as a
whole, the operation of an installed program in the reservoir or an
analogous reservoir, or other evidence using reliable technology
establishes the reasonable certainty of the engineering analysis on
which the project or program was based; and
(B) The project has been approved for development by all necessary
parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which
economic producibility from a reservoir is to be determined. The price
shall be the average price during the 12-month period prior to the
ending date of the period covered by the report, determined as an
unweighted arithmetic average of the first-day-of-the-month price for
each month within such period, unless prices are defined by contractual
arrangements, excluding escalations based upon future conditions.
* * * * *
(24) Reasonable certainty. If deterministic methods are used,
reasonable certainty means a high degree of confidence that the
quantities will be recovered. If probabilistic methods are used, there
should be at least a 90% probability that the quantities actually
recovered will equal or exceed the estimate. A high degree of
confidence exists if the quantity is much more likely to be achieved
than not, and, as changes due to increased availability of geoscience
(geological, geophysical, and geochemical), engineering, and economic
data are made to estimated ultimate recovery (EUR) with time,
reasonably certain EUR is much more likely to increase or remain
constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one
or more technologies (including computational methods) that has been
field tested and has been demonstrated to provide reasonably certain
results with consistency and repeatability in the formation being
evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil
and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects
to known accumulations. In addition, there must exist, or there must be
a reasonable expectation that there will exist, the legal right to
produce or a revenue interest in the production, installed means of
delivering oil and gas or related substances to market, and all permits
and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to
adjacent reservoirs isolated by major, potentially sealing, faults
until those reservoirs are penetrated and evaluated as economically
producible. Reserves should not be assigned to areas that are clearly
separated from a known accumulation by a non-productive reservoir
(i.e., absence of reservoir, structurally low reservoir, or negative
test results). Such areas may contain prospective resources (i.e.,
potentially recoverable resources from undiscovered accumulations).
* * * * *
(28) Resources. Resources are quantities of oil and gas estimated
to exist in naturally occurring accumulations. A portion of the
resources may be estimated to be recoverable, and another portion may
be considered to be unrecoverable. Resources include both discovered
and undiscovered accumulations.
* * * * *
(30) Stratigraphic test well. A stratigraphic test well is a
drilling effort, geologically directed, to obtain information
pertaining to a specific geologic condition. Such wells customarily are
drilled without the intent of being completed for hydrocarbon
production. The classification also includes tests identified as core
tests and all types of expendable holes related to hydrocarbon
exploration. Stratigraphic tests are classified as ``exploratory type''
if not drilled in a known area or ``development type'' if drilled in a
known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas
reserves are reserves of any category that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those
directly offsetting development spacing areas that are reasonably
certain of production when drilled, unless evidence using reliable
technology exists that establishes reasonable certainty of economic
producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped
reserves only if a development plan has been adopted indicating that
they are scheduled to be drilled within five years, unless the specific
circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped
reserves be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual projects in
the same reservoir or an analogous reservoir, as defined in paragraph
(a)(2) of this section, or by other evidence using reliable technology
establishing reasonable certainty.
* * * * *
(c) * * *
(8) For purposes of this paragraph (c), the term ``current price''
shall mean the average price during the 12-month period prior to the
ending date of the period covered by the report, determined as an
unweighted arithmetic average of the first-day-of-the-month price for
each month within such period, unless prices are defined by contractual
arrangements, excluding escalations based upon future conditions.
* * * * *
PART 211--INTERPRETATIONS RELATING TO FINANCIAL REPORTING MATTERS
0
3. Amend Part 211, subpart A, by adding ``Modernization of Oil and Gas
Reporting,'' Release No. FR-78 and the release date of December 31,
2008, to the list of interpretive releases.
[[Page 2193]]
PART 229--STANDARD INSTRUCTIONS FOR FILING FORMS UNDER SECURITIES
ACT OF 1933, SECURITIES EXCHANGE ACT OF 1934 AND ENERGY POLICY AND
CONSERVATION ACT OF 1975--REGULATION S-K
0
4. The authority citation for part 229 continues to read in part as
follows:
Authority: 15 U.S.C. 77e, 77f, 77g, 77h, 77j, 77k, 77s, 77z-2,
77z-3, 77aa(25), 77aa(26), 77ddd, 77eee, 77ggg, 77hhh, 77iii, 77jjj,
77nnn, 77sss, 78c, 78i, 78j, 78l, 78m, 78n, 78o, 78u-5, 78w, 78ll,
78mm, 80a-8, 80a-9, 80a-20, 80a-29, 80a-30, 80a-31(c), 80a-37, 80a-
38(a), 80a-39, 80b-11, and 7201 et seq.; and 18 U.S.C. 1350, unless
otherwise noted.
* * * * *
0
5. Amend Sec. 229.102 by revising the introductory text of Instruction
3 and Instructions 4, 5 and 8 to read as follows.
Sec. 229.102 (Item 102) Description of property.
* * * * *
Instructions to Item 102: * * *
3. In the case of an extractive enterprise, not involved in oil and
gas producing activities, material information shall be given as to
production, reserves, locations, development, and the nature of the
registrant's interest. If individual properties are of major
significance to an industry segment:
* * * * *
4. A registrant engaged in oil and gas producing activities shall
provide the information required by Subpart 1200 of Regulation S-K.
5. In the case of extractive reserves other than oil and gas
reserves, estimates other than proven or probable reserves (and any
estimated values of such reserves) shall not be disclosed in any
document publicly filed with the Commission, unless such information is
required to be disclosed in the document by foreign or state law;
provided, however, that where such estimates previously have been
provided to a person (or any of its affiliates) that is offering to
acquire, merge, or consolidate with the registrant, or otherwise to
acquire the registrant's securities, such estimates may be included in
documents relating to such acquisition.
* * * * *
8. The attention of certain issuers engaged in oil and gas
producing activities is directed to the information called for in
Securities Act Industry Guide 4 (referred to in Sec. 229.801(d)).
* * * * *
0
6. Amend Sec. 229.801 by removing and reserving paragraph (b) and
removing the authority citation following the section.
0
7. Amend Sec. 229.802 by removing and reserving paragraph (b) and
removing the authority citation following the section.
0
8. Add Subpart 229.1200 to read as follows:
Subpart 229.1200--Disclosure by Registrants Engaged in Oil and Gas
Producing Activities
Sec.
229.1201 (Item 1201) General instructions to oil and gas industry-
specific disclosures.
229.1202 (Item 1202) Disclosure of reserves.
229.1203 (Item 1203) Proved undeveloped reserves.
229.1204 (Item 1204) Oil and gas production, production prices and
production costs.
229.1205 (Item 1205) Drilling and other exploratory and development
activities.
229.1206 (Item 1206) Present activities.
229.1207 (Item 1207) Delivery commitments.
229.1208 (Item 1208) Oil and gas properties, wells, operations, and
acreage.
Subpart 229.1200--Disclosure by Registrants Engaged in Oil and Gas
Producing Activities
Sec. 229.1201 (Item 1201) General instructions to oil and gas
industry-specific disclosures.
(a) If oil and gas producing activities are material to the
registrant's or its subsidiaries' business operations or financial
position, the disclosure specified in this Subpart 229.1200 should be
included under appropriate captions (with cross references, where
applicable, to related information disclosed in financial statements).
However, limited partnerships and joint ventures that conduct, operate,
manage, or report upon oil and gas drilling or income programs, that
acquire properties either for drilling and production, or for
production of oil, gas, or geothermal steam or water, need not include
such disclosure.
(b) To the extent that Items 1202 through 1208 (Sec. Sec.
229.1202-229.1208) call for disclosures in tabular format, as specified
in the particular Item, a registrant may modify such format for ease of
presentation, to add information or to combine two or more required
tables.
(c) The definitions in Rule 4-10(a) of Regulation S-X (17 CFR
210.4-10(a)) shall apply for purposes of this Subpart 229.1200.
(d) For purposes of this Subpart 229.1200, the term by geographic
area means, as appropriate for meaningful disclosure in the
circumstances:
(1) By individual country;
(2) By groups of countries within a continent; or
(3) By continent.
Sec. 229.1202 (Item 1202) Disclosure of reserves.
(a) Summary of oil and gas reserves at fiscal year end. (1) Provide
the information specified in paragraph (a)(2) of this Item in tabular
format as provided below:
Summary of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices
----------------------------------------------------------------------------------------------------------------
Reserves
----------------------------------------------------------------
Reserves category Synthetic
Oil Natural gas oil Synthetic Product A
(mbbls) (mmcf) (mbbls) gas (mmcf) (measure)
----------------------------------------------------------------------------------------------------------------
PROVED ........... ........... ........... ........... ...........
Developed: ........... ........... ........... ........... ...........
Continent A................................ ........... ........... ........... ........... ...........
Continent B................................ ........... ........... ........... ........... ...........
Country A.................................. ........... ........... ........... ........... ...........
Country B.................................. ........... ........... ........... ........... ...........
Other Countries in Continent B............. ........... ........... ........... ........... ...........
Undeveloped: ........... ........... ........... ........... ...........
Continent A................................ ........... ........... ........... ........... ...........
Continent B................................ ........... ........... ........... ........... ...........
[[Page 2194]]
Country A.................................. ........... ........... ........... ........... ...........
Country B.................................. ........... ........... ........... ........... ...........
Other Countries in Continent B............. ........... ........... ........... ........... ...........
----------------------------------------------------------------
TOTAL PROVED........................... ........... ........... ........... ........... ...........
----------------------------------------------------------------------------------------------------------------
PROBABLE ........... ........... ........... ........... ...........
Developed.................................. ........... ........... ........... ........... ...........
Undeveloped................................ ........... ........... ........... ........... ...........
POSSIBLE ........... ........... ........... ........... ...........
Developed.................................. ........... ........... ........... ........... ...........
Undeveloped................................ ........... ........... ........... ........... ...........
----------------------------------------------------------------------------------------------------------------
(2) Disclose, in the aggregate and by geographic area and for each
country containing 15% or more of the registrant's proved reserves,
expressed on an oil-equivalent-barrels basis, reserves estimated using
prices and costs under existing economic conditions, for the product
types listed in paragraph (a)(4) of this Item, in the following
categories:
(i) Proved developed reserves;
(ii) Proved undeveloped reserves;
(iii) Total proved reserves;
(iv) Probable developed reserves (optional);
(v) Probable undeveloped reserves (optional);
(vi) Possible developed reserves (optional); and
(vii) Possible undeveloped reserves (optional).
Instruction 1 to paragraph (a)(2): Disclose updated reserves tables
as of the close of each fiscal year.
Instruction 2 to paragraph (a)(2): The registrant is permitted, but
not required, to disclose probable or possible reserves pursuant to
paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.
Instruction 3 to paragraph (a)(2): If the registrant discloses
amounts of a product in barrels of oil equivalent, disclose the basis
for such equivalency.
Instruction 4 to paragraph (a)(2): A registrant need not provide
disclosure of the reserves in a country containing 15% or more of the
registrant's proved reserves if that country's government prohibits
disclosure of reserves in that country. In addition, a registrant need
not provide disclosure of the reserves in a country containing 15% or
more of the registrant's proved reserves if that country's government
prohibits disclosure in a particular field and disclosure of reserves
in that country would have the effect of disclosing reserves in
particular fields.
(3) Reported total reserves shall be simple arithmetic sums of all
estimates for individual properties or fields within each reserves
category. When probabilistic methods are used, reserves should not be
aggregated probabilistically beyond the field or property level;
instead, they should be aggregated by simple arithmetic summation.
(4) Disclose separately material reserves of the following product
types:
(i) Oil;
(ii) Natural gas;
(iii) Synthetic oil;
(iv) Synthetic gas; and
(v) Sales products of other non-renewable natural resources that
are intended to be upgraded into synthetic oil and gas.
(5) If the registrant discloses probable or possible reserves,
discuss the uncertainty related to such reserves estimates.
(6) If the registrant has not previously disclosed reserves
estimates in a filing with the Commission or is disclosing material
additions to its reserves estimates, the registrant shall provide a
general discussion of the technologies used to establish the
appropriate level of certainty for reserves estimates from material
properties included in the total reserves disclosed. The particular
properties do not need to be identified.
(7) Preparation of reserves estimates or reserves audit. Disclose
and describe the internal controls the registrant uses in its reserves
estimation effort. In addition, disclose the qualifications of the
technical person primarily responsible for overseeing the preparation
of the reserves estimates and, if the registrant represents that a
third party conducted a reserves audit, disclose the qualifications of
the technical person primarily responsible for overseeing such reserves
audit.
(8) Third party reports. If the registrant represents that a third
party prepared, or conducted a reserves audit of, the registrant's
reserves estimates, or any estimated valuation thereof, or conducted a
process review, the registrant shall file a report of the third party
as an exhibit to the relevant registration statement or other
Commission filing. If the report relates to the preparation of, or a
reserves audit of, the registrant's reserves estimates, it must include
the following disclosure, if applicable to the type of filing:
(i) The purpose for which the report was prepared and for whom it
was prepared;
(ii) The effective date of the report and the date on which the
report was completed;
(iii) The proportion of the registrant's total reserves covered by
the report and the geographic area in which the covered reserves are
located;
(iv) The assumptions, data, methods, and procedures used, including
the percentage of the registrant's total reserves reviewed in
connection with the preparation of the report, and a statement that
such assumptions, data, methods, and procedures are appropriate for the
purpose served by the report;
(v) A discussion of primary economic assumptions;
(vi) A discussion of the possible effects of regulation on the
ability of the registrant to recover the estimated reserves;
(vii) A discussion regarding the inherent uncertainties of reserves
estimates;
(viii) A statement that the third party has used all methods and
procedures as it considered necessary under the circumstances to
prepare the report;
(ix) A brief summary of the third party's conclusions with respect
to the reserves estimates; and
[[Page 2195]]
(x) The signature of the third party.
(9) For purposes of this Item 1202, the term reserves audit means
the process of reviewing certain of the pertinent facts interpreted and
assumptions underlying a reserves estimate prepared by another party
and the rendering of an opinion about the appropriateness of the
methodologies employed, the adequacy and quality of the data relied
upon, the depth and thoroughness of the reserves estimation process,
the classification of reserves appropriate to the relevant definitions
used, and the reasonableness of the estimated reserves quantities.
(b) Reserves sensitivity analysis (optional). (1) The registrant
may, but is not required to, provide the information specified in
paragraph (b)(2) of this Item in tabular format as provided below:
Sensitivity of Reserves to Prices by Principal Product Type and Price Scenario
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Proved reserves Probable reserves Possible reserves
--------------------------------------------------------------------------------------------------------------------------------------------
Oil Gas Syn. Syn. Product A Oil Gas Syn. Syn. Product A Oil Gas Syn. Syn. Product A
Price case ------------------ oil gas ----------------------------- oil gas ----------------------------- oil gas ----------
------------------ ------------------ ------------------
mbbls mmcf mbbls mmcf measure mbbls mmcf mbbls mmcf measure mbbls mmcf mbbls mmcf measure
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario 1.........................................
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario 2.........................................
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(2) The registrant may, but is not required to, disclose, in the
aggregate, an estimate of reserves estimated for each product type
based on different price and cost criteria, such as a range of prices
and costs that may reasonably be achieved, including standardized
futures prices or management's own forecasts.
(3) If the registrant provides disclosure under this paragraph (b),
disclose the price and cost schedules and assumptions on which the
disclosed values are based.
Instruction to Item 1202: Estimates of oil or gas resources other
than reserves, and any estimated values of such resources, shall not be
disclosed in any document publicly filed with the Commission, unless
such information is required to be disclosed in the document by foreign
or state law; provided, however, that where such estimates previously
have been provided to a person (or any of its affiliates) that is
offering to acquire, merge, or consolidate with the registrant or
otherwise to acquire the registrant's securities, such estimate may be
included in documents related to such acquisition.
Sec. 229.1203 (Item 1203) Proved undeveloped reserves.
(a) Disclose the total quantity of proved undeveloped reserves at
year end.
(b) Disclose material changes in proved undeveloped reserves that
occurred during the year, including proved undeveloped reserves
converted into proved developed reserves.
(c) Discuss investments and progress made during the year to
convert proved undeveloped reserves to proved developed reserves,
including, but not limited to, capital expenditures.
(d) Explain the reasons why material amounts of proved undeveloped
reserves in individual fields or countries remain undeveloped for five
years or more after disclosure as proved undeveloped reserves.
Sec. 229.1204 (Item 1204) Oil and gas production, production prices
and production costs.
(a) For each of the last three fiscal years disclose production, by
final product sold, of oil, gas, and other products. Disclosure shall
be made by geographical area and for each country and field that
contains 15% or more of the registrant's total proved reserves
expressed on an oil-equivalent-barrels basis unless prohibited by the
country in which the reserves are located.
(b) For each of the last three fiscal years disclose, by
geographical area:
(1) The average sales price (including transfers) per unit of oil,
gas and other products produced; and
(2) The average production cost, not including ad valorem and
severance taxes, per unit of production.
Instruction 1 to Item 1204: Generally, net production should
include only production that is owned by the registrant and produced to
its interest, less royalties and production due others. However, in
special situations (e.g., foreign production) net production before any
royalties may be provided, if more appropriate. If ``net before
royalty'' production figures are furnished, the change from the usage
of ``net production'' should be noted.
Instruction 2 to Item 1204: Production of natural gas should
include only marketable production of natural gas on an ``as sold''
basis. Production will include dry, residue, and wet gas, depending on
whether liquids have been extracted before the registrant transfers
title. Flared gas, injected gas, and gas consumed in operations should
be omitted. Recovered gas-lift gas and reproduced gas should not be
included until sold. Synthetic gas, when marketed as such, should be
included in natural gas sales.
Instruction 3 to Item 1204: If any product, such as bitumen, is
sold or custody is transferred prior to conversion to synthetic oil or
gas, the product's production, transfer prices, and production costs
should be disclosed separately from all other products.
Instruction 4 to Item 1204: The transfer price of oil and gas
(natural and synthetic) produced should be determined in accordance
with SFAS 69.
Instruction 5 to Item 1204: The average production cost, not
including ad valorem and severance taxes, per unit of production should
be computed using production costs disclosed pursuant to SFAS 69. Units
of production should be expressed in common units of production with
oil, gas, and other products converted to a common unit of measure on
the basis used in computing amortization.
Sec. 229.1205 (Item 1205) Drilling and other exploratory and
development activities.
(a) For each of the last three fiscal years, by geographical area,
disclose:
(1) The number of net productive and dry exploratory wells drilled;
and
(2) The number of net productive and dry development wells drilled.
(b) Definitions. For purposes of this Item 1205, the following
terms shall be defined as follows:
(1) A dry well is an exploratory, development, or extension well
that proves to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
[[Page 2196]]
(2) A productive well is an exploratory, development, or extension
well that is not a dry well.
(3) Completion refers to installation of permanent equipment for
production of oil or gas, or, in the case of a dry well, to reporting
to the appropriate authority that the well has been abandoned.
(4) The number of wells drilled refers to the number of wells
completed at any time during the fiscal year, regardless of when
drilling was initiated.
(c) Disclose, by geographic area, for each of the last three years,
any other exploratory or development activities conducted, including
implementation of mining methods for purposes of oil and gas producing
activities.
Sec. 229.1206 (Item 1206) Present activities.
(a) Disclose, by geographical area, the registrant's present
activities, such as the number of wells in the process of being drilled
(including wells temporarily suspended), waterfloods in process of
being installed, pressure maintenance operations, and any other related
activities of material importance.
(b) Provide the description of present activities as of a date at
the end of the most recent fiscal year or as close to the date that the
registrant files the document as reasonably possible.
(c) Include only those wells in the process of being drilled at the
``as of'' date and express them in terms of both gross and net wells.
(d) Do not include wells that the registrant plans to drill, but
has not commenced drilling unless there are factors that make such
information material.
Sec. 229.1207 (Item 1207) Delivery commitments.
(a) If the registrant is committed to provide a fixed and
determinable quantity of oil or gas in the near future under existing
contracts or agreements, disclose material information concerning the
estimated availability of oil and gas from any principal sources,
including the following:
(1) The principal sources of oil and gas that the registrant will
rely upon and the total amounts that the registrant expects to receive
from each principal source and from all sources combined;
(2) The total quantities of oil and gas that are subject to
delivery commitments; and
(3) The steps that the registrant has taken to ensure that
available reserves and supplies are sufficient to meet such commitments
for the next one to three years.
(b) Disclose the information required by this Item:
(1) In a form understandable to investors; and
(2) Based upon the facts and circumstances of the particular
situation, including, but not limited to:
(i) Disclosure by geographic area;
(ii) Significant supplies dedicated or contracted to the
registrant;
(iii) Any significant reserves or supplies subject to priorities or
curtailments which may affect quantities delivered to certain classes
of customers, such as customers receiving services under low priority
and interruptible contracts;
(iv) Any priority allocations or price limitations imposed by
Federal or State regulatory agencies, as well as other factors beyond
the registrant's control that may affect the registrant's ability to
meet its contractual obligations (the registrant need not provide
detailed discussions of price regulation);
(v) Any other factors beyond the registrant's control, such as
other parties having control over drilling new wells, competition for
the acquisition of reserves and supplies, and the availability of
foreign reserves and supplies, which may affect the registrant's
ability to acquire additional reserves and supplies or to maintain or
increase the availability of reserves and supplies; and
(vi) Any impact on the registrant's earnings and financing needs
resulting from its inability to meet short-term or long-term
contractual obligations. (See Items 303 and 1209 of Regulation S-K
(Sec. Sec. 229.303 and 229.1209).)
(c) If the registrant has been unable to meet any significant
delivery commitments in the last three years, describe the
circumstances concerning such events and their impact on the
registrant.
(d) For purposes of this Item, available reserves are estimates of
the amounts of oil and gas which the registrant can produce from
current proved developed reserves using presently installed equipment
under existing economic and operating conditions and an estimate of
amounts that others can deliver to the registrant under long-term
contracts or agreements on a per-day, per-month, or per-year basis.
Sec. 229.1208 (Item 1208) Oil and gas properties, wells, operations,
and acreage.
(a) Disclose, as of a reasonably current date or as of the end of
the fiscal year, the total gross and net productive wells, expressed
separately for oil and gas (including synthetic oil and gas produced
through wells) and the total gross and net developed acreage (i.e.,
acreage assignable to productive wells) by geographic area.
(b) Disclose, as of a reasonably current date or as of the end of
the fiscal year, the amount of undeveloped acreage, both leases and
concessions, if any, expressed in both gross and net acres by
geographic area, together with an indication of acreage concentrations,
and, if material, the minimum remaining terms of leases and
concessions.
(c) Definitions. For purposes of this Item 1208, the following
terms shall be defined as indicated:
(1) A gross well or acre is a well or acre in which the registrant
owns a working interest. The number of gross wells is the total number
of wells in which the registrant owns a working interest. Count one or
more completions in the same bore hole as one well. In a footnote,
disclose the number of wells with multiple completions. If one of the
multiple completions in a well is an oil completion, classify the well
as an oil well.
(2) A net well or acre is deemed to exist when the sum of
fractional ownership working interests in gross wells or acres equals
one. The number of net wells or acres is the sum of the fractional
working interests owned in gross wells or acres expressed as whole
numbers and fractions of whole numbers.
(3) Productive wells include producing wells and wells mechanically
capable of production.
(4) Undeveloped acreage encompasses those leased acres on which
wells have not been drilled or completed to a point that would permit
the production of economic quantities of oil or gas regardless of
whether such acreage contains proved reserves. Do not confuse
undeveloped acreage with undrilled acreage held by production under the
terms of the lease.
PART 249--FORMS, SECURITIES EXCHANGE ACT OF 1934
0
9. The authority citation for part 249 continues to read in part as
follows:
Authority: 15 U.S.C. 78a et seq. and 7201; and 18 U.S.C. 1350,
unless otherwise noted.
* * * * *
0
10. Amend Form 20-F (referenced in Sec. 249.220f) by:
0
a. Revising ``Instruction to Item 4'' and the introductory text and
paragraph (b) of ``Instructions to Item 4.D''; and
0
b. Removing paragraph (c) of ``Instructions to Item 4.D'' and
``Appendix A to Item 4.D--Oil and Gas.''
The revisions read as follows:
[Note:
The text of Form 20-F does not, and this amendment will not,
appear in the Code of Federal Regulations.]
[[Page 2197]]
Form 20-F
* * * * *
Item 4. Information on the Company
* * * * *
Instructions to Item 4
1. Furnish the information specified in any industry guide listed
in Subpart 229.800 of Regulation S-K (Sec. 229.801 et seq. of this
chapter) that applies to you.
2. If oil and gas operations are material to you or your
subsidiaries' business operations or financial position, provide the
information specified in Subpart 1200 of Regulation S-K (Sec. 229.1200
et seq. of this chapter).
* * * * *
Instruction to Item 4.D: In the case of an extractive enterprise,
other than an oil and gas producing activity:
* * * * *
(b) In documents that you file publicly with the Commission, do not
disclose estimates of reserves unless the reserves are proven or
probable and do not give estimated values of those reserves, unless
foreign law requires you to disclose the information. If these types of
estimates have already been provided to any person that is offering to
acquire you, however, you may include the estimates in documents
relating to the acquisition.
* * * * *
Dated: December 31, 2008.
By the Commission.
Florence E. Harmon,
Acting Secretary.
[FR Doc. E9-409 Filed 1-13-09; 8:45 am]
BILLING CODE 8011-01-P