[Federal Register Volume 73, Number 132 (Wednesday, July 9, 2008)]
[Proposed Rules]
[Pages 39526-39568]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-14944]
[[Page 39525]]
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Part IV
Securities and Exchange Commission
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17 CFR Parts 210, 229, and 249
Modernization of the Oil and Gas Reporting Requirements; Proposed Rule
Federal Register / Vol. 73, No. 132 / Wednesday, July 9, 2008 /
Proposed Rules
[[Page 39526]]
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SECURITIES AND EXCHANGE COMMISSION
17 CFR Parts 210, 229, and 249
[Release Nos. 33-8935; 34-58030; File No. S7-15-08]
RIN 3235-AK00
Modernization of the Oil and Gas Reporting Requirements
AGENCY: Securities and Exchange Commission.
ACTION: Proposed rule.
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SUMMARY: The Commission is proposing revisions to its oil and gas
reporting requirements 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 requirements,
there have been significant changes in the oil and gas industry. The
proposed amendments are designed to modernize and update the oil and
gas disclosure requirements to align them with current practices and
changes in technology. The proposed amendments would also codify
Industry Guide 2 in Regulation S-K, with several additions to, and
deletions of, current Industry Guide items. They would further
harmonize oil and gas disclosures by foreign private issuers with the
proposed disclosures for domestic issuers.
DATES: Comments should be received on or before September 8, 2008.
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 [email protected]. 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: Questions on this Proposing Release
should be directed to Ray Be, Special Counsel, Office of Rulemaking at
(202) 551-3430; Mellissa Campbell Duru, Attorney-Advisor, 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, or Jonathan Duersch, Assistant Chief Accountant, 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 proposing 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 propose to add new Subpart 1200, including Items 1201
through 1209, 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. General Overview of the Comment Letters Received on Key
Issues
II. Revisions and Additions to the Definition Section of Rule 4-10
of Regulation S-X
A. Introduction
B. Year-End Pricing
1. 12-month average price
2. Trailing year-end
3. Prices used for accounting purposes
C. Extraction of Bitumen and Other Non-Traditional Resources
D. Reasonable Certainty and Proved Oil and Gas Reserves
1. New technology
2. Probabilistic methods
3. Other revisions related to proved oil and gas reserves
E. Unproved Reserves--``Probable Reserves'' and ``Possible
Reserves''
F. Definition of ``Proved Developed Oil and Gas Reserves''
G. Definition of ``Proved Undeveloped Reserves''
1. Proposed replacement of certainty threshold
2. Proposed definitions for continuous and conventional
accumulations
3. Proposed treatment of improved recovery projects
H. Proposed Definition of Reserves
I. Other Proposed Definitions and Reorganization of Definitions
III. Proposed Amendments To Codify the Oil and Gas Disclosure
Requirements in Regulation S-K
A. Proposed Revisions to Item 102, 801, and 802 of Regulation S-
K
B. Proposed New Subpart 1200 of Regulation S-K Codifying
Industry Guide 2 Regarding Disclosures by Companies Engaged in Oil
and Gas Producing Activities
1. Overview
2. Proposed Item 1201 (General instructions to oil and gas
industry-specific disclosures)
3. Proposed Item 1202 (Disclosure of reserves)
i. Oil and gas reserves tables
ii. Optional reserves sensitivity analysis table
iii. Geographic specificity with respect to reserves disclosures
iv. Separate disclosure of conventional and continuous
accumulations
v. Preparation of reserves estimates or reserves audits
vi. Contents of third party preparer and reserves audit reports
vii. Solicitation of comments on process reviews
4. Proposed Item 1203 (Proved undeveloped reserves)
5. Proposed Item 1204 (Oil and gas production)
6. Proposed Item 1205 (Drilling and other exploratory and
development activities)
7. Proposed Item 1206 (Present activities)
8. Proposed Item 1207 (Delivery commitments)
9. Proposed Item 1208 (Oil and gas properties, wells,
operations, and acreage)
i. Enhanced description of properties disclosure requirement
ii. Wells and acreage
iii. New proposed disclosures regarding extraction techniques
and acreage
10. Proposed Item 1209 (Discussion and analysis for registrants
engaged in oil and gas activities)
IV. Proposed Conforming Changes to Form 20-F
V. Impact of Proposed Amendments on Accounting Literature
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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
D. Price Used to Determine Proved Reserves for Purposes of
Capitalizing Costs
VI. Impact of the Proposed Codification of Industry Guide 2 on Other
Industry Guides
VII. Solicitation of Comment Regarding the Application of
Interactive Data Format to Oil and Gas Disclosures
VIII. Proposed Implementation Date
IX. General Request for Comment
X. Paperwork Reduction Act
A. Background
B. Summary of Information Collections
C. Paperwork Reduction Act Burden Estimates
D. Request for Comment
XI. Cost-Benefit Analysis
A. Background
B. Description of Proposal
C. Benefits
1. Average 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. Average price
4. Consistency with IASB
5. Harmonizing foreign private issuer disclosure
E. Request for Comments
XII. Consideration of Burden on Competition and Promotion of
Efficiency, Competition, and Capital Formation
XIII. Initial Regulatory Flexibility Analysis
A. Reasons for, and Objectives of, the Proposed Action
B. Legal Basis
C. Small Entities Subject to the Proposed Amendments
D. Reporting, Recordkeeping, and Other Compliance Requirements
E. Duplicative, Overlapping, or Conflicting Federal Rules
F. Significant Alternatives
G. Solicitation of Comment
XIV. Small Business Regulatory Enforcement Fairness Act
XV. Statutory Basis and Text of Proposed Amendments
I. Introduction
A. Background
On December 12, 2007, the Commission published a Concept Release on
possible revisions to the disclosure requirements relating to oil and
gas reserves.\5\ The release solicited comment on the oil and gas
reserves disclosure requirements specified in Rule 4-10 of Regulation
S-X \6\ and Item 102 of Regulation S-K.\7\ The Commission adopted these
disclosure requirements in 1978 and 1982, respectively.\8\ 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.\9\
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.\10\
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\5\ See Release No. 33-8870 (Dec. 12, 2007) [72 FR 71610].
\6\ 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).
\7\ 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].
\8\ 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.
\9\ See, for example, Daniel Yergin and David Hobbs: ``The
Search for Reasonable Certainty in Reserves Disclosure,'' Oil and
Gas Journal (July 18, 2005).
\10\ 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 measure 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 which addressed all or some of the 15 questions that were
raised by the release.\11\ We received comment letters from a variety
of industry participants such as accounting firms, consultants,
domestic and foreign oil and gas companies, federal government
agencies, individuals, law firms, professional associations, public
interest groups, and rating agencies.
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\11\ 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. General Overview of the Comment Letters Received on Key Issues
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. Commenters diverged significantly, however, in their views
about the extent and type of revisions that we should make to our
disclosure system. For example, commenters expressed varied opinions
regarding whether we should adopt revisions that would result in a
principles-based disclosure regime rather than a rules-based disclosure
regime. Those who favored a principles-based approach noted that such
an approach would be inherently more flexible than a rules-based
approach and would allow for greater adaptability as technological
advancements and changes occur in the industry.\12\ Other commenters,
however,
[[Page 39528]]
expressed concern that a principles-based model is more subjective than
a rules-based approach and could result in less consistent and
comparable disclosure in the filings made by oil and gas companies.\13\
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\12\ See, for example, letters from BHP Biliton Petroleum
(``BHP''), John R. Etherington (``J. Etherington''), and White &
Case, LLP (``White & Case'').
\13\ See, for example, letters from Apache Corp. (``Apache''),
Moody's Investor's Service (``Moody's) and Oil Change International
and the Center for Corporate Policy (``Oil Change'').
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Virtually all of the commenters supported a revision of the
definition of proved reserves in some form or another. Most remarked
that the definition of proved reserves should be broadened to allow
unconventional resources such as oil shales and bitumen to be
classified as proved reserves.\14\ In addition, while commenters were
split on the use of a single fiscal year-end spot price to value the
reserves held by an oil and gas company, a majority advocated the use
of a different pricing standard to reduce the effects of short-term
price volatility.\15\
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\14\ See letters from American Association of Petroleum
Geologists (``AAPG''), American Clean Skies Foundation (``ACSF''),
Apache, American Petroleum Institute (``API''), Center for Audit
Quality (``Audit Quality''), BP Plc (``BP,'') Brookwood Petroleum
Advisors Ltd. (``Brookwood''), CFA Institute Centre for Financial
Market Integrity (``CFA''), Chesapeake Energy Corporation
(``Chesapeake''), China National Offshore Oil Corporation
(``CNOCC''), CIBC World Markets (``CIBC''), Denbury Resources
(``Denbury''), Department of Energy (``DOE''), Deutsche Bank, Devon
Energy Corporation (``Devon''), EnCana, Energy Information
Administration (of DOE) (``EIA''), Energy Literacy Project (``Energy
Literacy''), Eni S.p.A. (``Eni''), Ernst & Young (``E&Y''), J.
Etherington, ExxonMobil, Grant Thornton, Imperial Oil Ltd.
(``Imperial''), Independent Petroleum Association of America
(``IPAA''), Dan Kelly (``D. Kelly''), McBride, Douglas-Morningstar
Consultants (``D. McBride''), Moody's, Nexen Inc. (``Nexen''), Oil
Change, Dan Olds (``D. Olds''), Petrobras, Petro-Canada,
PriceWaterhouseCoopers (``PWC''), Robert Pinkerton (``R.
Pinkerton''), Robinson Petroleum Consulting (``Robinson''), Ross
Petroleum Ltd. (``Ross''), Derek Ryder (``D. Ryder''), Sasol Ltd
(``Sasol''), Shell International (``Shell''), Society of Petroleum
Engineers (``SPE''), Standard & Poor's (``S&P''), StatoilHydro,
Total, S.A. (``Total''), Ashish Verma (``A. Verma''), Robert Wagner
(``R. Wagner''), White & Case, and Fred Ziehe (``F. Ziehe'').
\15\ See letters from Chesapeake, Devon, and Imperial.
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There were mixed views on whether the Commission should permit
disclosure of reserves other than proved reserves in Commission
filings. Commenters supporting the inclusion of disclosures about
probable and possible reserves in Commission filings suggested that
such disclosure would allow investors to gain a more comprehensive
understanding of the resources held by an oil and gas company.\16\
Commenters opposing disclosure of probable and possible reserves
thought that disclosure about these reserves categories would be less
reliable than disclosure about proved reserves. Many of these
commenters were concerned about liability issues associated with such
disclosure and the loss of comparability of disclosure between
companies.\17\
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\16\ See, for example, letters from Chesapeake, Oil Change, D.
Olds, Ross, D. Ryder, and R. Wagner.
\17\ See, for example, letters from Hugh Anderson (``H.
Anderson''), Apache, API, ExxonMobil, Imperial, and Shell.
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Several of the comment letters addressed whether third parties
should be required to independently evaluate the reserves reported by a
company in its filings. There was a divergence in opinion on this
issue. Some commenters suggested that an evaluation requirement is
necessary to ensure the reliability of the reserves disclosure included
in companies' filings.\18\ Other commenters, however, believed that a
company's internal staff is often in the best position to accurately
evaluate the reserves of the company.\19\ Some of the commenters that
opposed a third-party evaluation requirement noted that there likely
would be practical impediments to establishing that type of
requirement, such as the lack of availability of qualified
professionals to perform the evaluations and the lack of a regulatory
or professional body to enforce universal standards that would govern
the activities of third-party reserves evaluators or auditors.\20\
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\18\ See letters from Fitch Ratings (``Fitch'') and White &
Case.
\19\ See letters from API, Denbury, ExxonMobil, Imperial, Nexen,
Shell, and Talisman Energy (``Talisman'').
\20\ See, for example, letters from the AAPG, API, Devon, and R.
Wagner.
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Finally, numerous commenters expressed support for the adoption of
an alternate resource classification system that would allow for
disclosure of a wider range of reserves and resources in Commission
filings. Most of these commenters advocated the use of the Petroleum
Resources Management System (PRMS) for this purpose.\21\ PRMS was
prepared in 2007 by the oil and gas reserves committee of the Society
of Petroleum Engineers and jointly sponsored by the World Petroleum
Council, the American Association of Petroleum Geologists and the
Society of Petroleum Evaluation Engineers.\22\ Other commenters
proposed that we consider the rules adopted by regulators in Canada or
the resource classification framework currently being created under the
auspices of the United Nations Economic Commission for Europe and the
United Nations Economic and Social Council in revising our rules.\23\
We address the public comments on specific issues in more detail in the
relevant sections below.
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\21\ See comment letters from the API, Deloitte & Touche, LLP
(``D&T''), DOE, ExxonMobil and Netherland, Sewell & Associates
(``Netherland''). The Petroleum Resources Management System
classification system defines a broad range of reserves categories,
contingent resources and prospective resources. 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).
\22\ See letters from AAPG, SPE, and the Society of Petroleum
Evaluation Engineers (``SPEE''). See also Petroleum Resources
Management System, SPE/WPC/AAPG/SPEE (2007).
\23\ See letters from Devon, Robinson, and White & Case. The
Canadian system is outlined in National Instrument 51-101,
``Standards of Disclosure for Oil and Gas Activities,'' and the
related ``Canadian Oil and Gas Evaluation Handbook.'' See http://www.albertasecurities.com/securitieslaw/Regulatory%20Instruments/5/2232/AMENDED%20NI%2051-101%20_FULL%20VERSION_.pdf. The United
Nations Economic Commission for Europe and the United Nations
Economic and Social Council are working together to establish an
international classification system to classify resources in both
the oil and gas and mining industries. See United Nations Framework
Classification System for Fossil Energy and Mineral Resources,
United Nations Economic Council For Europe (March, 2006) available
at http://www.unece.org/ie/se/pdfs/UNFC/UNFCemr.pdf.
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II. Revisions and Additions to the Definition Section in Rule 4-10 of
Regulation S-X
A. Introduction
The proposed revisions and additions to the definition section in
Rule 4-10 of Regulation S-X would 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. Among other things, the proposed revisions to these
definitions address three issues that have been of particular interest
to companies, investors, and securities analysts:
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.
In addition, the proposed revisions would change the use of single-day
year-end pricing to determine economic producibility of oil and gas
reserves. The proposed revisions of, and
[[Page 39529]]
additions to, the Rule 4-10 definitions attempt to address these issues
without sacrificing clarity and comparability, which provide protection
and transparency to investors.
Many commenters on the Concept Release suggested that we adopt the
PRMS definitions and classification system to the greatest extent
possible.\24\ They noted that PRMS is rapidly becoming the leading
standard for international petroleum resources classifications. Others
suggested that we adopt the definitions and classifications used in
Canadian National Instrument 51-101 (NI 51-101), adopted in 2003,
because they have been tested in practice as part of a regulatory
framework and because they are broadly consistent with PRMS.\25\
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\24\ See letters from API, BHP, Brookwood, CFA, China National
Offshore Oil Corporation (``CNOOC''), CIBC World Markets (``CIBC''),
D&T, Deutsche Bank, DOE, EIA, EnCana, Energy Literacy, Eni,
ExxonMobil, Netherland, Newfield Exoploration (``Newfield''), D.
Olds, Petrobras, Petro-Canada, Questar Market Resources
(``Questar''), Sasol, Shell, Leigh Ann Smothers (``L. Smothers''),
SPE, SPEE, Talisman, Total, TRACS International (``TRACS''), Ultra
Petroleum Corporation (``Ultra''), White & Case, and Geoff Zakaib
(``G. Zakaib'').
\25\ See letters from Devon, Robinson, and White & Case. NI 51-
101 constitutes the Canadian regulatory system for oil and gas
company disclosures.
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We have based many of our proposed new and revised definitions
classifications on both PRMS and NI 51-101. The language in NI 51-101
lends itself to a regulatory framework more easily than the language in
PRMS, which is primarily a management tool, and we have been guided by
the language in NI 51-101 in several instances. Although the proposed
definitions are not totally consistent with either PRMS or NI 51-101,
they are significantly more consistent with those standards than our
existing rules.
One important difference between the proposed amendments and PRMS
or NI 51-101 is that the proposed amendments would continue to require
the use of historical prices and costs used to promote comparability.
In contrast, NI 51-101 and PRMS afford a reserves estimator more
flexibility in choosing among alternative pricing schedules. While this
flexibility has its benefits, it impedes comparability of different
companies' disclosures. Another significant difference is that the
proposed amendments, like the current rules, would require reserves to
be ``economically producible,'' meaning that estimated revenues must
exceed costs, whereas other classification systems require an
extractive project to be ``commercial,'' meaning that a company's
investment evaluation guidelines must be met (for example, the
extraction project rate of return must exceed some prescribed minimum).
There are many different investment evaluation guidelines in use today.
However, we believe that our proposed criteria would provide greater
comparability among companies' disclosures so that investors can better
understand the relative merits of their different investment choices.
In addition, NI 51-101 and PRMS provide definitions of various
categories of resources beyond reserves, such as contingent and
prospective resources, whereas our proposed rules do not. Given that we
are not proposing to allow disclosure of resources that do not qualify
as reserves in Commission filings, we are not proposing definitions of
other various classifications of resources.
After considering the comments received on the Concept Release, we
are proposing to revise the definition of proved reserves. Furthermore,
as a result of those changes and also observations made by commenters,
we are proposing to revise associated definitions and the disclosures
made by issuers regarding the extent, characteristics, and location of
their reserves.
B. Year-End Pricing
1. 12-Month Average Price
Most commenters on the Concept Release recommended that we replace
our current use of a single-day, fiscal year-end spot price to
determine whether resources are economically producible based on
current economic conditions with a different test.\26\ Some believed
that reliance on a single-day spot price is subject to significant
volatility and results in frequent adjustment of reserves.\27\ These
commenters expressed the view that variations in single-day prices
provide temporary alterations in reserve quantities that are not
meaningful or may lead investors to incorrect conclusions, do not
represent the general price trend, and do not provide a meaningful
basis for determination of reserve or enterprise value.\28\
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\26\ See letters from AAPG, American Clean Skies Foundation
(``ACSF''), H. Anderson, Apache, API, BHP, BP, Brookwood, Canadian
Association of Petroleum Producers (``CAPP''), CFA, Chesapeake, CIBC
CNOOC, Davis Family Energy Partners (``Davis''), Denbury, Deutsche
Bank, Devon, EIA, EnCana, Energy Literacy, Eni, Etherington, J.,
ExxonMobil, Grant Thornton, Imperial, IPAA, Robbin Jones (``R.
Jones''), D. Kelly, Long Consultants (``Long''), D. McBride, MIT
Center for Energy and Environmental Policy Research (``MIT''),
Moody's, Netherland, Newfield, Nexen, D. Olds, Oil Change,
Petrobras, Petro-Canada, Robinson, Ross, D. Ryder, S&P, Sasol,
Shell, Southwestern, SPE, StatoilHydro, Total, TRACS, Ultra, Walter
van de Vijver (``W. van DeVijver''), R. Wagner, White & Case, and F.
Ziehe.
\27\ See letters from API, Chesapeake, CIBC, ExxonMobil,
Imperial, R. Jones, S&P, Ultra, and R. Wagner.
\28\ See letters from Chesapeake, Devon, and Imperial.
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Of those who commented on this issue, most recommended using a 12-
month average price instead of the single-day price.\29\ However,
others recommended using one of the following alternative pricing
options:
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\29\ See letters from H. Anderson, Apache, API, BHP, BP, CAPP,
Chesapeake, CIBC, CNOOC, Devon, DOE, EnCana, Eni, ExxonMobil
Imperial, IPAA, R. Jones, D. McBride, Moody's, Netherland, Nexen,
Oil Change, D. Olds, Petro-Canada, D. Ryder, Shell, StatoilHydro,
Total, TRACS, R. Wagner, and F. Ziehe.
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A futures price or the average futures price over a
specified period of time; \30\
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\30\ See letters from Apache, CFA, Chesapeake, Davis, EIA, IPAA,
Southwestern, StatoilHydro, and TRACS.
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Management's forecasted price; \31\
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\31\ See letters from AAPG, J. Etherington, Grant Thornton,
Robinson, Ross, StatoilHydro, and W. van de Vijver.
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Average price over three months; \32\
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\32\ See letter from CFA.
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Average price over two years; \33\ or
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\33\ See letter from Deutsche Bank.
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Probabilistic future pricing with ranges and explanations
for the pricing basis.\34\
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\34\ See letter from Energy Literacy.
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Each of the options above, involving historical price averages,
futures prices, futures price averages, and price forecasts developed,
or relied on, by management, has advantages and disadvantages. For
example, historical price averages provide a high level of
comparability among oil and gas companies and are relatively easy to
compute because the underlying data is readily available to companies.
However, they may not reflect the prices that a company could
reasonably expect to receive for its production in the future.
Prices based on oil and gas futures are forward-looking, and
therefore may better approximate the economic value of the reserves as
they are ultimately produced and sold. These prices, however, are not
necessarily available for all products in all geographic areas and
would require adjustments. To provide comparability of disclosures
among oil and gas companies, we likely would have to specify certain
private-sector publications for use in such pricing. Price forecasts
developed by management of an oil and gas company would provide
investors with better insight into the prices that management of the
company foresees and, therefore, the prices upon which management
[[Page 39530]]
bases its investment and operating decisions, but may provide limited
comparability between companies.
We propose to revise the definitions in Rule 4-10 of Regulation S-X
to change the price used in calculating reserves from a single-day
closing price measured on the last day of the company's fiscal year to
an average price for the 12 months prior to the end of the company's
fiscal year.\35\ This pricing standard is consistent with the PRMS's
default guidelines for the term ``current economic conditions.'' This
price would be calculated as the unweighted arithmetic average of the
closing price on the last day of each month in that 12-month period.
Using historical pricing maximizes comparability between companies,
which is the primary objective of the oil and gas disclosure. This
proposal is intended to maintain reserves disclosure comparability
while mitigating the risk that an anomalous single pricing date will
distort the proved reserves estimates. It therefore may provide a
better basis for economic producibility than single-day pricing.
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\35\ See proposed Rule 4-10(a)(24)(v).
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We recognize that use of historical pricing may not capture
management's outlook on the future as well as futures prices or
management's planning prices. As noted in detail elsewhere in this
release,\36\ in order to allow for such disclosures, we are proposing
to add a disclosure item that would specifically permit an oil and gas
company, at its option, to include a sensitivity case analysis in its
filings that would show total reserves estimates based on futures
prices, management's planning prices, or other price schedules in
addition to the pricing mechanism specifically required.\37\
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\36\ See Section III.B.3.ii of this release.
\37\ See proposed Item 1202(c).
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Request for Comment
Should the economic producibility of a company's oil and
gas reserves be based on a 12-month historical average price? Should we
consider an historical average price over a shorter period of time,
such as three, six, or nine months? Should we consider a longer period
of time, such as two years? If so, why?
Should we require a different pricing method? Should we
require the use of futures prices instead of historical prices? Is
there enough information on futures prices and appropriate
differentials for all products in all geographic areas to provide
sufficient reporting consistency and comparability?
Should the average price be calculated based on the prices
on the last day of each month during the 12-month period, as proposed?
Is there another method to calculate the price that would be more
representative of the 12-month average, such as prices on the first day
of each month? Why would such a method be preferable?
Should we require, rather than merely permit, disclosure
based on several different pricing methods? If so, which different
methods should we require?
Should we require a different price, or supplemental
disclosure, if circumstances indicate a consistent trend in prices,
such as if prices at year-end are materially above or below the average
price for that year? If so, should we specify the particular
circumstances that would trigger such disclosure, such as a 10%, 20%,
or 30% differential between the average price and the year-end price?
If so, what circumstances should we specify?
2. Trailing Year-End
Numerous commenters recommended the use of an average price over a
period ending some time before the company's fiscal year end.\38\ They
noted that, with accelerated filing deadlines, it becomes difficult for
the larger companies subject to those deadlines to make the required
calculations accurately and with the best available data.\39\ Most of
these commenters recommended that the pricing period end three months
prior to the end of the company's fiscal year (for example, a company
with a December 31, 2007 fiscal year end, would use the average
historical price for the period between October 1, 2006 and September
30, 2007 to calculate its reserves estimates).\40\ We are not proposing
such a lag in the time between the close of the pricing period and the
end of the fiscal year. However, we solicit comment on this issue.
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\38\ See letters from AAPG, API, BP, CAPP, CIBC, Deutsche Bank,
EnCana, Eni, ExxonMobil, Imperial, D. McBride, Moody's Netherland,
Nexen, D. Ryder, Shell, Total, R. Wagner, and F. Ziehe.
\39\ See letters from CAPP and Shell.
\40\ See letters from AAPG, API, BP, CAPP, CIBC, Deutsche Bank,
EnCana, Eni, ExxonMobil, Imperial, D. McBride, Moody's, Netherland,
Nexen, D. Ryder, Shell, Total, R. Wagner, and F. Ziehe.
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Request for Comment
Should the price used to determine the economic
producibility of oil and gas reserves be based on a time period other
than the fiscal year, as some commenters have suggested? If so, how
would such pricing be useful? Would the use of a pricing period other
than the fiscal year be misleading to investors?
Is a lag time between the close of the pricing period and
the end of the company's fiscal year necessary? If so, should the
pricing period close one month, two months, three months, or more
before the end of the fiscal year? Explain why a particular lag time is
preferable or necessary. Do accelerated filing deadlines for the
periodic reports of larger companies justify using a pricing period
ending before the fiscal year end?
3. Prices Used for Accounting Purposes
Notwithstanding our proposal to change the single-day, year-end
pricing for the estimation of reserves, we are not proposing to change
the prices that are used for accounting purposes. Specifically,
companies using either the successful efforts accounting method
described in Statement of Financial Accounting Standard No. 19 (SFAS
19) prescribed by the Financial Accounting Standards Board (FASB) or
the full cost accounting method, set forth in Rule 4-10(c) \41\ of
Regulation S-X, would continue to depreciate property, plant, and
equipment related to oil and gas producing activities using a units-of-
production basis over proved developed reserves or proved reserves, as
applicable, using single-day, year-end rates. In addition, companies
using the full cost accounting method would continue to use the single-
day, year-end rate for purposes of determining the limitation on
capitalized costs (i.e., the ceiling test).
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\41\ 17 CFR 210.4-10(c).
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However, to provide consistency between the reserves disclosures
required by proposed new Subpart 1200 and SFAS 69, we believe that the
information required by SFAS 69 should be prepared using the average
price as described above. This would result in two different
presentations of proved reserves using two different economic
producibility assumptions. For purposes of Subpart 1200, a company
would use a value for proved reserves based on average prices.
Conversely, for purposes of applying the successful efforts method and
the full cost accounting method, a company would use a value of proved
reserves based on a single-day, year-end price. We intend to discuss
such possible changes with FASB.
Request for Comment
Should we require companies to use the same prices for
accounting purposes as for disclosure outside of the financial
statements?
[[Page 39531]]
Is there a basis to continue to treat companies using the
full cost accounting method differently from companies using the
successful efforts accounting method? For example, should we require,
or allow, a company using the successful efforts accounting method to
use an average price but require companies using the full cost
accounting method to use a single-day, year-end price?
Should we require companies using the full cost accounting
method to use a single-day, year-end price to calculate the limitation
on capitalized costs under that accounting method, as proposed? If such
a company were to use an average price and prices are higher than the
average at year end or at the time the company issues its financial
statements, should that company be required to record an impairment
charge?
Should the disclosures required by SFAS 69 be prepared
based on different prices than the disclosures required by proposed
Section 1200?
If proved reserves, for purposes of disclosure outside of
the financial statements, other than supplemental information provided
pursuant to SFAS 69, are defined differently from reserves for purposes
of determining depreciation, should we require disclosure of that fact,
including quantification of the difference, if the effect on
depreciation is material?
What concerns would be raised by rules that require the
use of different prices for accounting and disclosure purposes? For
example, is it consistent to use an average price to estimate the
amount of reserves, but then apply a single-day price to calculate the
ceiling test under the full cost accounting method? Would companies
have sufficient time to prepare separate reserves estimates for
purposes of reserves disclosure on one hand, and calculation of
depreciation on the other? Would such a requirement impose an
unnecessary burden on companies?
Will our proposed change to the definitions of proved
reserves and proved developed reserves for accounting purposes have an
impact on current depreciation amounts or net income and to what
degree?
If we change the definitions of proved reserves and proved
developed reserves to use average pricing for accounting purposes, what
would be the impact of that change on current depreciation amounts and
on the ceiling test? Would the differences be significant?
C. Extraction of Bitumen and Other Non-Traditional Resources
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.\42\ These other
sources include bitumen extracted from oil sands, as well as oil and
gas extracted from coalbeds 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.\43\ As noted earlier, many
commenters supported such disclosure.\44\
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\42\ See 17 CFR 210.4-10(a)(1)(ii)(D).
\43\ According to one commenter, some estimates indicate that
such resources already provide 40% of the natural gas produced in
the United States. See letter from Chesapeake Energy.
\44\ See letters from AAPG, ACSF, Apache, API, Audit Quality,
BP, Brookwood, CFA, Chesapeake, CIBC, CNOOC, Denbury, Deutsche Bank,
Devon, DOE, EIA, EnCana, Energy Literacy, Eni, J. Etherington,
ExxonMobil, E&Y, Grant Thornton, Imperial, IPAA, D. Kelly, D.
McBride, Moody's, Nexen, Oil Change, D. Olds, Petrobras, Petro-
Canada, R. Pinkerton, PWC, Robinson, Ross, D. Ryder, S&P, Sasol,
Shell, SPE, StatoilHydro, Total, A. Verma, R. Wagner, White & Case,
and F. Ziehe.
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The proposed revised definition of ``oil and gas producing
activities'' would include the extraction of the non-traditional
resources described above.\45\ The proposal 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 proposed definition would state specifically that
oil and gas producing activities include the extraction of marketable
hydrocarbons, in the solid, liquid, or gaseous state, from oil sands,
shale, coalbeds \46\ or other nonrenewable natural resources which can
be upgraded into natural or synthetic oil or gas, and activities
undertaken with a view to such extraction.
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\45\ See proposed Rule 4-10(a)(16).
\46\ Although the proposed definition would encompass activities
such as extracting coalbed methane from a deposit of coal, it would
not include the extraction of the coal itself, even if the company
intends to use that coal as feedstock into processing activities
that result in oil and gas products, such as coal gasification. We
recognize that as technologies progress, it may become appropriate
to include such processes as oil and gas producing activities.
---------------------------------------------------------------------------
However, the proposed definition would continue to exclude
activities relating to:
Transporting, refining, processing (other than field
processing of gas to extract liquid hydrocarbons), or marketing oil and
gas;
The production of natural resources other than oil, gas,
or natural resources from which natural or synthetic oil and gas can be
extracted; and
The production of geothermal steam.
Consistent with historical treatment, we continue to believe that,
once a resource is extracted from the ground, it should not be
considered oil and gas reserves. Thus, the current definition of the
term ``oil and gas producing activities'' does not, and the proposed
definition would not, permit companies that only transport, process,
and/or market oil or gas to disclose, as reserves, amounts of oil or
gas received from, and extracted from the ground by, another company.
In addition, if a company extracting the resources also builds its own
processing plant on-site or near the extraction location (other than
field processing of gas to extract liquid hydrocarbons), we do not
believe it would be appropriate for that company to use the price of
its processed product to determine the economic producibility of the
unprocessed product. For example, if a company builds a bitumen
processing plant to convert raw bitumen into synthetic crude oil, its
calculation for the economic producibility of reserves from that
location should be based on the prices for the raw bitumen, as though
it were providing the bitumen to a third party processor. This will
facilitate comparability among companies.
We recognize, however, that excluding the listed activities from
the definition of ``oil and gas producing activities'' would not permit
a company to reflect the result of building its own processing plant on
the price estimates and other considerations that may be used in making
the company's business decisions. Such a processing plant can
significantly enhance the value of the upgraded product, enabling the
company to use lower costs (or higher prices) in its internal decision-
making. As noted elsewhere in this release, we are proposing to allow
companies to voluntarily present an analysis of the sensitivity of
reserves estimates based on varying prices, including the expected
product prices used by management for its own planning purposes.\47\
Such supplemental disclosure would permit companies to disclose other
pricing and cost considerations, including advantages gained by
internal processing of raw
[[Page 39532]]
products that may add value to the final product sold by the company.
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\47\ See proposed Item 1202(c).
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Request for Comment
Should we consider the extraction of bitumen from oil
sands, extraction of synthetic oil from oil shales, and production of
natural gas and synthetic oil and gas from coalbeds to be considered
oil and gas producing activities, as proposed? Are there other non-
traditional resources whose extraction should be considered oil and gas
producing activities? If so, why?
The extraction of coal raises issues because it is most
often used directly as mined fuel, although hydrocarbons can be
extracted from it. As noted above, we propose to include the extraction
of coalbed methane as an oil and gas producing activity. However, the
actual mining of coal has traditionally been viewed as a mining
activity. In most cases, extracted coal is used as feedstock for energy
production rather than refined further to extract hydrocarbons.
However, as technologies progress, certain processes to extract
hydrocarbons from extracted coal, such as coal gasification, may become
more prevalent. Applying rules to coal based on the ultimate use of the
resource could lead to different disclosure and accounting implications
for similar coal mining companies based solely on the coal's end use.
How should we address these concerns? Should all coal extraction be
considered an oil and gas producing activity? Should it all be
considered mining activity? Should the treatment be based on the end
use of the coal? Please provide a detailed explanation for your
comments.
Similar issues could arise regarding oil shales, although
to a significantly less extent, because those resources currently are
used as direct fuel only in limited applications. How should we treat
the extraction of oil shales?
If adopted, how would the proposed changes affect the
financial statements of producers of non-traditional resources and
mining producers?
D. Reasonable Certainty and Proved Oil and Gas Reserves
The current definition of the term ``proved reserves'' states that
these reserves are ``the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating
conditions.'' \48\ Although ``reasonable certainty'' is, and has been,
the standard used in the definition of proved oil and gas reserves, the
current rules do not define that term. As a result, the meaning of the
term ``reasonable certainty'' has been the subject of significant
disagreement within the industry relating to the level of probability
necessary to meet this standard. Although some believe that this
standard is clear and has established a consistent guideline for
establishing proved reserves,\49\ others do not believe that this has
been the case.\50\ To avoid ambiguity, we propose to add a definition
of the term ``reasonable certainty'' to Rule 4-10 of Regulation S-
X.\51\
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\48\ See Rule 4-10(a)(2) of Regulation S-X [17 CFR 210.4-
10(a)(2)].
\49\ See letters from R. Jones and Moody's.
\50\ See letters from D. Olds, Raymond Schutte (``R. Schutte''),
L. Smothers, R. Wagner, and Sir Philip Watts (``P. Watts'').
\51\ See proposed Rule 4-10(a)(26).
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We propose to define the term ``reasonable certainty'' as ``much
more likely to be achieved than not.'' In addition, we would clarify
that, when deterministic methods \52\ are used to estimate oil and gas
reserves, as changes due to increased availability of geoscience
(geological, geophysical, and geochemical), engineering, and economic
data are made to estimated ultimate recovery (EUR) \53\ with time,
reasonably certain EUR is much more likely to increase than to either
decrease or remain constant. The proposed definition also would explain
that, when probabilistic methods are used to estimate reserves,
reasonable certainty means that there is at least a 90% probability
that the quantities actually recovered will equal or exceed the stated
volume.\54\
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\52\ See Section II.D.2 of this release for a discussion
regarding deterministic methods and probabilistic methods.
\53\ We propose to define the term ``estimated ultimate
recovery'' as the sum of reserves remaining as of a given date plus
the cumulative production as of that date. See proposed Rule 4-
10(a)(11).
\54\ This is consistent with the PRMS definition of ``proved
reserves.''
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Request for Comment
Is the proposed definition of ``reasonable certainty'' as
``much more likely to be achieved than not'' a clear standard? Is the
standard in the proposed definition appropriate? Would a different
standard be more appropriate?
Is the proposed 90% threshold appropriate for defining
reasonable certainty when probabilistic methods are used? Should we use
another percentage value? If so, what value?
1. New Technology
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 generally must use actual production
or flow tests to meet the ``reasonable certainty'' standard necessary
to establish the proved status of its reserves. 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. Some commenters
noted that a case-by-case exemption from the flow test requirement
imposes unequal standards for establishing reasonable certainty based
on geographic location.\55\
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\55\ See letters from Petrobras, D. Ryder, and White & Case.
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In addition, we recognize that technology 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. We
propose to add a definition of the term ``reliable technology'' to Rule
4-10 of Regulation S-X to clarify the types of technology that can be
used to establish reasonable certainty. We propose to define ``reliable
technology'' as ``technology (including computational methods) that,
when applied using high quality geoscience and engineering data, is
widely accepted within the oil and gas industry, has been field tested
and has demonstrated consistency and repeatability in the formation
being evaluated or in an analogous formation. Consistent with current
industry practice, expressed in probabilistic terms, reliable
technology has been proved empirically to lead to correct conclusions
in 90% or more of its applications.'' \56\
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\56\ See proposed Rule 4-10(a)(27).
---------------------------------------------------------------------------
The proposed definition is intended to permit broader use of new
technologies to establish the proper classification for reserves and to
lessen the need for frequent updates to our reserves definitions as
technology continues to evolve. Because companies would now be able to
select the technology that it uses, we are proposing to require a
company to disclose the technology used to establish the appropriate
level of certainty for material properties in a company's first filing
with the Commission and for material additions
[[Page 39533]]
to reserves estimates in subsequent filings.\57\ Such disclosure should
identify the particular portion of the reserves estimates for which a
particular technology was used, including identification of the
geographic area, country, field or basin to the extent necessary for
investors to determine whether use of that technology was appropriate
under the circumstances.
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\57\ See proposed Item 1202(a)(4) and proposed Item 1209(a)(2).
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Request for Comment
Is our proposed definition of ``reliable technology''
appropriate? Should we change any of its proposed criteria, such as
widespread acceptance, consistency, or 90% reliability?
Is the open-ended type of definition of ``reliable
technology'' that we propose appropriate? Would permitting the company
to determine which technologies to use to determine their reserves
estimates be subject to abuse? Do investors have the capacity to
distinguish whether a particular technology is reasonable for use in a
particular situation? What are the risks associated with adoption of
such a definition?
Is the proposed disclosure of the technology used to
establish the appropriate level of certainty for material properties in
a company's first filing with the Commission and for material additions
to reserves estimates in subsequent filings appropriate? Should we
require disclosure of the technology used for all properties? Should we
require companies currently filing reports with the Commission to
disclose the technology used to establish appropriate levels of
certainty regarding their currently disclosed reserves estimates?
2. Probabilistic Methods
We propose to add definitions of the terms ``deterministic
estimate'' and ``probabilistic estimate.'' \58\ These two terms relate
to the two alternative methods by which a company may estimate its
reserves amounts. We understand that both methods are, to varying
degrees, currently used by the industry. Our proposed definitions are
consistent with industry practice. We propose to define the term
``deterministic estimate'' to mean an estimate that is based on using a
single ``most appropriate'' value for each variable in the estimation
of reserves, such as the company's determination of the oil or gas in
place in a reservoir, multiplied by the fraction of that oil or gas
that can be recovered. In addition, we propose to define 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, engineering, and economic data) is used
to generate a full range of possible outcomes and their associated
probabilities of occurrence. Although companies currently can use
either method to produce reserves estimates, we believe that these
proposed definitions will promote consistent usage of the terms
``probabilistic estimate'' and ``deterministic estimate.''
---------------------------------------------------------------------------
\58\ See proposed Rules 4-10(a)(6) 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.
---------------------------------------------------------------------------
Some of the commenters suggested that we require the use of
probabilistic estimates to establish proved reserves because these
methods are derived through extensive statistical computer calculations
using a wide range of potential values for parameters that affect the
reserves estimate, such as possible recovery factors for a particular
field or type of field, and so would be more rigorous than
deterministic methods.\59\ Conversely, the quality of an estimate
derived through deterministic methods depends more heavily on the
experience and judgment of the reserves estimator to select the most
appropriate value for those parameters. Although we recognize that
probabilistic methods can be useful in certain circumstances, requiring
the use of probabilistic estimates could significantly increase the
costs of reserves estimate preparation, without significant increases
in reliability of the results in many cases. One commenter was
concerned that companies may not have sufficient staff to calculate all
reserves estimates through probabilistic methods.\60\ Thus, the
proposed definition of ``reasonable certainty'' would continue to allow
companies to estimate reserves amounts using either deterministic or
probabilistic methods, leaving companies to determine which method is
more appropriate for their particular situations.\61\
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\59\ See letters from AAPG, EIA, Long, D. Olds, Rose, and SPE.
\60\ See letter from D. Olds.
\61\ See proposed Rule 4-10(a)(26).
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Request for Comment
Are the proposed definitions of ``deterministic estimate''
and ``probabilistic estimate'' appropriate? Should we revise either of
these definitions in any way? If so, how?
Are the statements regarding the use of deterministic and
probabilistic estimates in the proposed definition of ``reasonable
certainty'' appropriate? Should we change them in any way? If so, how?
Should an oil and gas company have the choice of using
deterministic or probabilistic methods for reserves estimation, or
should we require one method? If we were to require a single method,
which one should it be? Why? Would there be greater comparability
between companies if only one method was used?
Should we require companies to disclose whether they use
deterministic or probabilistic methods for their reserves estimates?
3. Other Revisions Related to Proved Oil and Gas Reserves
The current definition of the term ``proved oil and gas reserves''
also 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,\62\ notwithstanding the existence of other engineering and
geoscientific evidence.\63\ Consistent with our proposal to permit the
use of new technologies to establish the reasonable certainty of proved
reserves, the proposed revisions to the definition of ``proved oil and
gas reserves'' also include provisions for establishing levels of
lowest known hydrocarbons and highest known oil through reliable
technology other than well penetrations.
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\62\ 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.
\63\ See Rule 4-10(a)(2)(i) [17 CFR 210.4-10(a)(2)(i)].
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Similarly, the proposed definition would permit a company to claim
proved reserves beyond drilling units that immediately offset developed
drilling locations if the company can establish with reasonable
certainty that these reserves are economically producible.\64\ 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 would establish a uniform standard of
reasonable certainty that could be applied to all proved reserves,
regardless of location or distance from producing wells.
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\64\ See proposed Rule 4-10(a)(24)(ii). See Section II.G for a
more detailed discussion regarding this proposed revision.
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[[Page 39534]]
Finally, we propose adding a sentence to the definition that would
state that, in order for reserves to be proved, the project to extract
the hydrocarbons must have commenced or it must be reasonably certain
that the operator will commence the project within a reasonable time.
This revision is designed to prevent a company from including, in
proved reserves, projects in undeveloped areas for which it does not
have the intent to develop.
Request for Comment
Should we permit the use of technologies that do not
provide direct information on fluid contacts to establish reservoir
fluid contacts, provided that they meet the definition of ``reliable
technology,'' as proposed?
Should there be other requirements to establish that
reserves are proved? For example, for a project to be reasonably
certain of implementation, is it necessary for the issuer to
demonstrate either that it will be able to finance the project from
internal cash flow or that it has secured external financing?
E. Unproved Reserves--``Probable Reserves'' and ``Possible Reserves''
We propose to define the terms ``probable reserves'' and ``possible
reserves'' because we are proposing to permit companies to disclose
these categories of reserves estimates.\65\ 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:
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\65\ See proposed Rule 4-10(a)(18) and (17), respectively.
---------------------------------------------------------------------------
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 proved,
probable, and possible reserves estimates. By proposing to permit
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.
Some commenters on the Concept Release were concerned that
disclosing reserves categories that are less certain than proved
reserves could increase the risk of confusion and litigation.\66\
Therefore, we are proposing to make these disclosures voluntary.\67\
Numerous oil and gas companies currently 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 create increased
litigation risk. By making these disclosures voluntary, a company could
decide on its own whether to provide the market with this disclosure,
despite possible increased litigation risk. In addition, to address the
concerns regarding the uncertainty of estimates of unproved reserves,
we also are proposing to require disclosure about the person primarily
responsible for preparing the company's reserves estimates and, if
applicable, about the person primarily responsible for conducting a
reserves audit.\68\ The proposal would clarify that a ``person'' may be
a business entity or an individual. We address this proposed disclosure
in more detail in Section III.B.3.v of this release.
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\66\ See letters from Devon and Imperial.
\67\ See proposed Item 1202.
\68\ See proposed Item 1202(a)(6).
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We propose to define the term ``probable reserves'' as 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.\69\ The proposed definition would provide guidance for
the use of both deterministic and probabilistic methods. The proposed
definition would clarify 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 should be at
least a 50% probability that the actual quantities recovered will equal
or exceed the proved plus probable reserves estimates. This proposed
definition was derived from the PRMS definition of the term ``probable
reserves.''
---------------------------------------------------------------------------
\69\ See proposed Rule 4-10(a)(18).
---------------------------------------------------------------------------
Our proposed definition of ``possible reserves'' would include
those additional reserves that are less certain to be recovered than
probable reserves.\70\ It would clarify 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
should be at least a 10% probability that the actual quantities
recovered will equal or exceed the sum of proved, probable, and
possible estimates. As with the proposed definition of probable
reserves, the proposed definition of possible reserves is based on the
PRMS definition of the term ``possible reserves.''
---------------------------------------------------------------------------
\70\ See proposed Rule 4-10(a)(17).
---------------------------------------------------------------------------
Request for Comment
Should we permit a company to disclose its probable or
possible reserves, as proposed? If so, why?
Should we require, rather than permit, disclosure of
probable or possible reserves? If so why?
Should we adopt the proposed definitions of probable
reserves and possible reserves? Should we make any revisions to those
proposed definitions? If so, how should we revise them?
Are the proposed 50% and 10% probability thresholds
appropriate for estimating probable and possible reserves quantities
when a company uses probabilistic methods? Should probable reserves
have a 60% or 70% probability threshold? Should possible reserves have
a 15% or 20% probability threshold? If not, how should we modify them?
F. Definition of ``Proved Developed Oil and Gas Reserves''
As noted above, we are proposing to expand the scope of oil and gas
producing activities to include resources extracted by technologies
other than traditional oil and gas wells, such as mining processes.
Similarly, we propose to expand the definition of the term ``proved
developed oil and gas reserves'' to include extraction of resources
using technologies other than production through wells.\71\ The
proposed new definition would state that ``proved developed oil and gas
reserves'' are proved reserves that:
---------------------------------------------------------------------------
\71\ See proposed Rule 4-10(a)(22).
---------------------------------------------------------------------------
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.
Request for Comment
Should we revise the definition of proved developed oil
and gas reserves, as proposed? Should we make any other revisions to
that definition? If so, how should we revise it?
[[Page 39535]]
G. Definition of ``Proved Undeveloped Reserves''
1. Proposed Replacement of Certainty Threshold
We propose to amend the definition of the term ``proved undeveloped
reserves'' (PUDs) by replacing the requirement that productivity be
``certain'' for areas beyond the immediate area of known proved
reserves with a ``reasonably certain'' requirement.\72\ 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.\73\
---------------------------------------------------------------------------
\72\ See proposed Rule 4-10(a)(25).
\73\ See 17 CFR 210.4-10(a)(4). A drilling unit refers to the
spacing required between wells to prevent wasting resources and
optimize recovery. These units are typically determined by the local
jurisdiction.
---------------------------------------------------------------------------
Some commenters believed that requiring ``certainty'' beyond
offsetting, or adjacent, units is not appropriate.\74\ They believed
that there should be a single criterion--reasonable certainty--to
characterize all proved reserves, including proved undeveloped
reserves. Two commenters noted that the offsetting unit requirement is
a purely mathematical and arbitrary standard for ease of calculation
and does not reflect the actual geological characteristics of the
reservoir.\75\ Other commenters argued that PUDs should be determined
by the totality of the engineering and geoscience data available,
including seismic data, appropriate analogs, and assessment of
reservoir characteristics.\76\ One commenter believed that the ``one
offsetting unit'' rule is outdated and does not acknowledge new
technology.\77\
---------------------------------------------------------------------------
\74\ See letters from AAPG, API, Denbury, Devon, and DOE.
\75\ See letters from CNOOC and Ultra.
\76\ See letters from API, Devon, DOE, and ExxonMobil.
\77\ See letter from Ultra.
---------------------------------------------------------------------------
The proposed definition would permit the use of evidence gathered
from reliable technology that establishes reasonable certainty of
economic producibility at any distance from productive units (that is,
in units adjacent to the productive units as well as units beyond those
adjacent units).\78\ It would further clarify that proved reserves can
be claimed in a conventional accumulation \79\ or a continuous
accumulation in a given area beyond immediately offset drilling units
where economic producibility is reasonably certain, based on
engineering, geoscience, and economic data and reliable technology,
including actual drilling statistics in the area.\80\ However, the
proposed definition would prohibit a company from assigning proved
status to undrilled locations if a development plan has not been
adopted indicating that the locations are scheduled to be drilled
within five years, unless it discloses unusual circumstances that
justify a longer time, such as particularly complex projects in remote
areas that require more time to develop.\81\
---------------------------------------------------------------------------
\78\ See proposed Rule 4-10(a)(25)(i).
\79\ See Section II.G.2 for a discussion of continuous
accumulations and conventional accumulations.
\80\ See proposed Rule 4-10(a)(25)(i)(B).
\81\ See proposed Rule 4-10(a)(25)(ii).
---------------------------------------------------------------------------
Request for Comment
Are the proposed revisions appropriate? Would the proposed
expansion of the PUDs definition create potential for abuses?
Should we replace the current ``certainty'' threshold for
reserves in drilling units beyond immediately adjacent drilling units
with a ``reasonable certainty'' threshold as proposed?
Is it appropriate to prohibit a company from assigning
proved status to undrilled locations if the locations are not scheduled
to be drilled more than five years, absent unusual circumstances, as
proposed? Should the proposed time period be shorter or longer than
five years? Should it be three years? Should it be longer, such as
seven or ten years?
Should the proposed definition specify the types of
unusual circumstances that would justify a development schedule longer
than five years for reserves that are classified as proved undeveloped
reserves?
2. Proposed Definitions for Continuous and Conventional Accumulations
We propose to adopt definitions for the terms ``continuous
accumulations'' and ``conventional accumulations'' to assist companies
in determining the extent of PUDs associated with these two types of
accumulations.\82\ PUDs have caused estimation difficulties in the
past. The fundamental difficulty in making these estimates is
calculating the volume of a resource beyond the immediate area in which
wells have been drilled (or beyond the immediate area in which other
extraction technology has been installed and is operational) that
should be included in the proved category. The answer can be vastly
different for continuous accumulations, as opposed to conventional
accumulations. Because of this potential difference, we believe that it
is important to define these two distinct categories of accumulations
in the proposed rules.
---------------------------------------------------------------------------
\82\ See proposed Rule 4-10(a)(4) and (a)(5).
---------------------------------------------------------------------------
The proposed definition of ``continuous accumulations'' would
encompass resources that are pervasive throughout large areas, have
ill-defined boundaries, and typically lack or are unaffected by
hydrocarbon-water contacts near the base of the accumulation.\83\
Examples include, but are not limited to, accumulations of natural
bitumen (oil sands), gas hydrates, and self-sourced accumulations such
as coalbed methane, shale gas, and oil shale deposits. Typically, such
accumulations require specialized extraction technology (e.g., removal
of water from coalbed methane accumulations, large fracturing programs
for shale gas, steam, or solvents to mobilize bitumen for in-situ
recovery, and, in some cases, mining activities). Moreover, the
extracted petroleum may require significant processing prior to sale
(e.g., bitumen upgraders). This proposed definition is based on the
PRMS definition of the term ``unconventional resources.''
---------------------------------------------------------------------------
\83\ See proposed Rule 4-10(a)(4).
---------------------------------------------------------------------------
Conversely, we propose to define ``conventional accumulations'' as
discrete oil and gas resources related to localized geological
structural features or stratigraphic conditions, with the accumulation
typically bounded by a hydrocarbon-water contact near its base, and
which are significantly affected by the tendency of lighter
hydrocarbons to ``float'' or accumulate above the heavier water.\84\
This proposed definition is based on the PRMS definition of the term
``conventional resources.''
---------------------------------------------------------------------------
\84\ See proposed Rule 4-10(a)(5).
---------------------------------------------------------------------------
Request for Comment
Should we provide separate definitions of conventional and
continuous accumulations, as proposed? Would separate disclosure of
these accumulations be helpful to investors?
Should we revise our proposed definition of ``continuous
accumulations'' in any way? For example, should the proposed definition
provide examples of such accumulations? If so, how should we revise it?
Should we revise our proposed definition of ``conventional
accumulations'' in any way? If so, how should we revise it?
[[Page 39536]]
3. Proposed Treatment of Improved Recovery Projects
The proposed definition of proved undeveloped reserves also would
be broadened to permit a company to include quantities of oil that can
be recovered through improved recovery projects in its proved
undeveloped reserves estimates. Currently, a company can include such
quantities only where techniques have been proved effective by actual
production from projects in the area and in the same reservoir. The
proposed amendments would expand this definition to permit the use of
techniques that have been proved effective by actual production from
projects in an analogous reservoir in the same geologic formation in
the immediate area or by other evidence using reliable technology that
establishes reasonable certainty.\85\
---------------------------------------------------------------------------
\85\ See proposed Rule 4-10(a)(25)(iii).
---------------------------------------------------------------------------
Request for Comment
Should we expand the definition of proved undeveloped
reserves to permit the use of techniques that have been proven
effective by actual production from projects in an analogous reservoir
in the same geologic formation in the immediate area or by other
evidence using reliable technology that establishes reasonable
certainty?
H. Proposed Definition of Reserves
To add clarity to the definition of the term ``proved reserves,''
we also propose to add a definition of the term ``reserves.'' \86\ We
propose to describe more completely 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. We propose 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:
---------------------------------------------------------------------------
\86\ See proposed Rule 4-10(a)(28).
---------------------------------------------------------------------------
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 definition would clarify that reserves are classified as
proved, probable, and possible according to the degree of uncertainty
associated with the estimates. This proposed definition is based on the
PRMS definition of the term ``reserves.''
Request for Comment
Is the proposed definition of ``reserves'' appropriate?
Should we change it in any way? If so, how?
I. Other Proposed Definitions and Reorganization of Definitions
We are proposing additional definitions primarily to support and
clarify the proposed definitions of the key terms discussed above.
These supplementary definitions include:
``Analogous formation in the immediate area,'' which
appears in the definition of proved reserves; \87\
---------------------------------------------------------------------------
\87\ See proposed Rule 4-10(a)(2).
---------------------------------------------------------------------------
``Condensate'' \88\
---------------------------------------------------------------------------
\88\ See proposed Rule 4-10(a)(3).
---------------------------------------------------------------------------
``Development project'' \89\
---------------------------------------------------------------------------
\89\ See proposed Rule 4-10(a)(8).
---------------------------------------------------------------------------
``Estimated ultimate recovery,'' which appears in the
definition of proved reserves; \90\ and
---------------------------------------------------------------------------
\90\ See proposed Rule 4-10(a)(11).
---------------------------------------------------------------------------
``Resources,'' which are often confused with reserves.\91\
---------------------------------------------------------------------------
\91\ See proposed Rule 4-10(a)(30).
---------------------------------------------------------------------------
Most of these supporting terms and their proposed definitions are
based on similar terms in the PRMS. The proposed definition of
``resources'' is based on the Canadian Oil and Gas Evaluation Handbook
(COGEH).
We also are proposing to alphabetize the definitional terms in Rule
4-10(a), including existing and proposed definitions. Currently, the
terms defined in Rule 4-10(a) are organized by placing the key terms
ahead of supporting terms. The proposals would significantly increase
the number of terms defined in this section. With the proposed addition
of numerous new definitions, we believe that alphabetizing these
definitions would make specific definitions easier to find.
Request for Comment
Are these additional proposed definitions appropriate?
Should we revise them in any way?
Are there other terms that we have used in the proposal
that need to be defined? If so, which terms and how should we define
them?
Should we alphabetize the definitions, as proposed? Would
any undue confusion result from the re-ordering of existing
definitions?
III. Proposed Amendments To Codify the Oil and Gas Disclosure
Requirements in Regulation S-K
The Concept Release primarily solicited comment on certain key
definitions in the oil and gas disclosure regime, and whether oil and
gas companies should be permitted to disclose probable and possible
reserves. In this release, we are proposing, and soliciting comment on,
a broader scope of amendments. In particular, we are proposing to
update and codify Securities Act and Exchange Act Industry Guide 2:
Disclosure of Oil and Gas Operations (Industry Guide 2).\92\ Industry
Guide 2 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. We propose to codify the contents of Industry Guide 2 in
Regulation S-K.
---------------------------------------------------------------------------
\92\ Exchange Act Industry Guide 2 merely references, and
therefore is identifical to, Securities Act Industry Guide 2.
---------------------------------------------------------------------------
Included in the proposals are several new disclosure items that we
believe are necessary in light of the proposed amendments to the
definitions in Rule 4-10, such as disclosure of technology used to
determine levels of certainty because we propose to permit companies to
choose the appropriate technology for that purpose. We also are
proposing to eliminate several disclosures in Industry Guide 2 because
we believe that they are no longer necessary, such as reporting of
production through processing plant ownership. We address these
proposals in detail below.
A. Proposed Revisions to Items 102, 801, and 802 of Regulation S-K
The instructions to Item 102 of Regulation S-K, in conjunction with
Items 801 and 802 of Regulation S-K, currently reference the industry
guides. Because we are proposing to move the disclosures from Industry
Guide 2 into a new Subpart 1200 of Regulation S-K, we propose to revise
the instructions to Item 102 to reflect this change.\93\ We also
propose eliminating the references in Items 801 and 802 to Industry
Guide 2 because that industry guide will cease to exist if the
proposals described in this release are adopted.\94\
---------------------------------------------------------------------------
\93\ See proposed Instructions 4 and 8 to Item 102.
\94\ See proposed Item 801 and 802.
---------------------------------------------------------------------------
[[Page 39537]]
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 proposing to permit disclosure of probable and
possible oil and gas reserves, we would revise Instruction 5 to limit
its applicability to extractive enterprises other than oil and gas
producing activities, such as mining activities.\95\ Similarly,
Instruction 3 of Item 102, regarding production, reserves, locations,
development and the nature of the company's interests, would no longer
need to apply to oil and gas producing activities if the proposals are
adopted, so we also propose to limit that instruction to mining
activities.\96\
---------------------------------------------------------------------------
\95\ See proposed Instruction 5 to Item 102. Extractive
enterprises include enterprises such as mining companies that
extract resources from the ground.
\96\ See proposed Instruction 3 to Item 102.
---------------------------------------------------------------------------
Finally, we propose to eliminate 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 \97\ and Exchange Act 12b-4,\98\
regarding the staff's general ability to request supplemental
information.
---------------------------------------------------------------------------
\97\17 CFR 230.418.
\98\17 CFR 240.12b-4.
---------------------------------------------------------------------------
Request for Comment
Is the proposed amendment to Instruction 3, limiting it to
extractive activities other than oil and gas activities, appropriate?
Should we simply call them mining activities?
Are there any other aspects of Item 102 that we should
revise? If so, what are they and how should they be revised?
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 proposing to add a new Subpart 1200 to Regulation S-K that
would codify the disclosure requirements related to companies engaged
in oil and gas producing activities. This proposed subpart would
largely include 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, the proposed Subpart 1200 would contain the
following new disclosure requirements, many of which have been
requested by industry participants:
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 development of proved undeveloped
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 additions to
reserves estimates;
Disclosure regarding material changes due to technology,
prices, and concession conditions;
Disclosure of the objectivity and qualifications of the
business entity or individual preparing or auditing the reserves
estimates;
Filing a report prepared by the third party if a company
represents that it is relying on a third party to prepare the reserves
estimates or conduct a reserves audit; and
Disclosure based on a new definition for the term ``by
geographic area.''
We discuss each of these proposed new Items below.
2. Proposed Item 1201 (General Instructions to Oil and Gas Industry-
Specific Disclosures)
We propose to add new Item 1201 to Regulation S-K. This item would
set forth the general instructions to Subpart 1200. The proposed item
would contain three paragraphs that would:
Instruct companies for which oil and gas producing
activities are material to provide the disclosures specified in Subpart
1200;\99\
---------------------------------------------------------------------------
\99\ 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; and
State that the definitions in Rule 4-10(a) of Regulation
S-X apply to Subpart 1200.
Request for Comment
Are the proposed general instructions to Subpart 1200
clear and appropriate? Are there any other general instructions that we
should include in this proposed Item?
For disclosure items requiring tabulated information,
should we require companies to adhere to a specified tabular format,
instead of permitting companies to reorganize, supplement, or combine
the tables?
In particular, should we permit a company to disclose
reserves estimates from conventional accumulations in the same table as
it discloses its reserves estimates from continuous accumulations?
3. Proposed 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 proposing to replace this
Instruction by adding a new Item 1202 to Regulation S-K that would
contain a similar disclosure requirement regarding a company's proved
reserves.\100\ However, the proposed new Item would expand on the
requirements of Item 102 by specifically permitting the disclosure of
probable and possible reserves and permitting the disclosure of
reserves from continuous accumulations. Proposed Item 1202 would
organize reserves disclosure into the following three tables:
---------------------------------------------------------------------------
\100\ See proposed Item 1202.
---------------------------------------------------------------------------
An oil and gas reserves from conventional accumulations
table;
An oil and gas reserves from continuous accumulations
table; and
An optional sensitivity analysis table.
i. Oil and Gas Reserves Tables
Proposed Item 1202 would require disclosure, in the aggregate and
by geographic area,\101\ of reserves estimated using prices and costs
under existing economic conditions, for each product type, in the
following categories:
---------------------------------------------------------------------------
\101\ See Section II.B.3.iv for a discussion about geographic
area specificity.
---------------------------------------------------------------------------
Proved developed reserves;
Proved undeveloped reserves;
Total proved reserves;
Probable reserves (optional); and
Possible reserves (optional).
The proposed Item would provide for separate tables for reserves in
conventional accumulations \102\ and continuous accumulations.\103\
However,
[[Page 39538]]
a company may combine these two tables.\104\ If a company does so, it
must present different products in different columns. For example,
because refining and processing, other than field processing of gas to
extract liquid hydrocarbons, are not oil and gas producing activities,
we believe that a company that extracts and processes oil sands into
synthetic crude oil should report the first salable product, bitumen,
as its reserves. The activity of processing bitumen into synthetic
crude oil at a plant, even if on or near the extraction location, is a
refining process. Forms of these two proposed tables are set forth
below:
---------------------------------------------------------------------------
\102\ See proposed Item 1202(a).
\103\ See proposed Item 1202(b).
\104\ See proposed Item 1201(b).
Summary of Oil and Gas Reserves in Conventional Accumulations as of
Fiscal-Year End Based on Average Fiscal-Year Prices
------------------------------------------------------------------------
Reserves
--------------------------------------
Reserves category Natural gas
Oil (mbbls) (mmcf)
------------------------------------------------------------------------
PROVED........................... .................. .................
Developed:
Continent A.............. .................. .................
Continent B.............. .................. .................
15% Country A........ .................. .................
15% Country B........ .................. .................
10% Field A in .................. .................
Country B.
Other Fields in .................. .................
Country B.
Other Countries in .................. .................
Continent B.
Undeveloped:
Continent A.............. .................. .................
Continent B.............. .................. .................
15% Country A........ .................. .................
15% Country B........ .................. .................
10% Field A in .................. .................
Country B.
Other Fields in .................. .................
Country B.
Other Countries in
Continent B
--------------------------------------
TOTAL PROVED.........
PROBABLE.............
POSSIBLE.............
------------------------------------------------------------------------
Summary of Oil and Gas Reserves From Continuous Accumulations as of Fiscal-Year End Based on Average Fiscal-Year
Prices
----------------------------------------------------------------------------------------------------------------
Reserves
-------------------------------------------------------------------------
Reserves category Product A \105\
(measure) Product B (measure) Product C (measure)
----------------------------------------------------------------------------------------------------------------
PROVED................................
Developed:
Country A..................... ....................... .......................
Country B..................... ....................... .......................
10% Field A in Country B.. ....................... .......................
Other Fields in Country B. ....................... .......................
Undeveloped:
Country A..................... ....................... .......................
Country B..................... ....................... .......................
10% Field A in Country B.. ....................... .......................
Other Fields in Country B. ....................... .......................
TOTAL PROVED..........
PROBABLE..............
POSSIBLE..............
----------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------
\105\ The product should be based on the product that is the
result of the oil and gas producing activity, such as bitumen, which
is extracted from oil sands.
---------------------------------------------------------------------------
A company may, but would not be 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 with proved reserves. The proposal would require a company to update
such reserves tables as of the close of each fiscal year. The table
would be categorized by the products (Product A, Product B, etc.) that
are the result of oil and gas producing activities. Thus, an oil and
gas company should not disclose, as reserves, products that are not the
result of oil and gas producing activities, including refined or
processed products
[[Page 39539]]
such as synthetic crude oil.\106\ Of course, a company may provide
supplemental disclosure regarding the amount of synthetic crude oil or
other refined or processed product that may be extracted ultimately
from the product of oil and gas producing activities. The proposal
would also clarify that, if the company discloses amounts of a product
in barrels of oil equivalent, it must disclose the basis for such
equivalency.
---------------------------------------------------------------------------
\106\ Rule 4-10(a)(16)(ii) specifically excludes from oil and
gas producing activities refining and processing (other than field
processing of gas to extract liquid hydrocarbons) of oil and gas.
---------------------------------------------------------------------------
The reserves to be reported in these proposed 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.
The proposed items would require companies that previously have not
disclosed reserves estimates in a filing with the Commission to
disclose the technologies used to establish the appropriate level of
certainty for reserves estimates from material properties included in
the total reserves disclosed. However, the particular properties would
not need to be identified. Similarly, proposed Item 1209 would note
that companies should discuss the technologies used to establish the
appropriate level of certainty for material additions to, or increases
in, reserves estimates.\107\ The proposal would not require a company
to disclose the technologies used to determine levels of certainty for
reserves disclosed prior to effectiveness of the proposed amendments,
if adopted, because the current definitions limit technologies to
prescribed types, such as production or flow tests or actual
observation of oil-water contacts in the wellbore.
---------------------------------------------------------------------------
\107\ See proposed Item 1209.
---------------------------------------------------------------------------
If probable or possible reserves are disclosed, the proposed item
would also require the company to disclose the relative risks related
to such reserves estimations. Because we are proposing to permit
disclosure of probable and possible reserves, an instruction to this
proposed Item would revise 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.\108\ We continue to believe that such resources are too
speculative and may lead investors to incorrect conclusions. However,
consistent with Instruction 5, a company could disclose such estimates
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.\109\
---------------------------------------------------------------------------
\108\ See proposed Instruction 5 to Item 102.
\109\ Id.
---------------------------------------------------------------------------
Request for Comment
Should we permit companies to disclose their probable
reserves or possible reserves? Is the probable reserves category, the
possible reserves category (or both categories) too uncertain to be
included as disclosure in a company's public filings? Should we only
permit disclosure of probable reserves? What are the advantages and
disadvantages of permitting disclosure of probable and possible
reserves, from the perspective of both an oil and gas company and an
investor in an oil and gas company that chooses to provide such
disclosure? Would investors be concerned by such disclosure? Would they
understand the risks involved with probable or possible reserves?
Would the proposed disclosure requirements provide
sufficient disclosure for investors to understand how companies
classified their reserves? Should the proposed Item require more
disclosure regarding the technologies used to establish certainty
levels and assumptions made to determine the reserves estimates for
each classification?
Should companies be required to provide risk factor
disclosure regarding the relative uncertainty associated with the
estimation of probable and possible reserves?
Should we allow filers to report sums of proved and
probable reserves or sums of proved, probable, and possible reserves?
Or, to avoid misleading investors, should we allow only disclosure of
each category of reserves by itself and not in sum with others, as
proposed?
Should we require disclosure of probable or possible
reserves estimates in a company's public filings if that company
otherwise discloses such estimates outside of its filings?
Should we require all reported reserves to be simple
arithmetic sums of all estimates, as proposed? Alternatively, should we
allow probabilistic aggregation of reserves estimated probabilistically
up to the company level? If we do so, will company reserves estimated
and aggregated deterministically be comparable to company reserves
estimated and aggregated probabilistically?
Should we revise the proposed form and content of the
table? If so, how should we revise the table's form or content?
Should we eliminate the current exception regarding the
disclosure of estimates of resources in the context of 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? If so, would this create a significant imbalance in the
disclosures being made to the possible acquirer, as opposed to the
company's shareholders?
ii. Optional Reserves Sensitivity Analysis Table
Our current rules require determining whether oil or gas is
economically producible based on the price on the last day of the
fiscal year. As discussed in Section II.B.1 above, this single-day
price has been the subject of some criticism from commenters in the
past because it is sensitive to short-term price volatility and does
not account for seasonal variations in the prices of different
products. Although we are proposing to require that reserves estimates
be based on a 12-month average of historical prices, we are proposing
to permit companies to include an optional reserves sensitivity
analysis table in their filings that would show what the reserves
estimates would be if 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.
The company would be free to choose the different scenario or
scenarios, if any, that it wishes to disclose in the table. If the
company chooses to provide such disclosure, it would be required to
disclose the price and cost schedules and assumptions on which the
alternate reserves estimates are based. Similarly, companies should
remember that Item 303 of Regulation S-K (Management's Discussion and
Analysis of Financial Condition and Results of Operations) \110\
[[Page 39540]]
requires discussion of 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.
---------------------------------------------------------------------------
\110\ 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 Product A Product A Product A
Oil (mbbls) Gas (mmcf) (measure) Oil (mbbls) Gas (mmcf) (measure) Oil (mbbls) Gas (mmcf) (measure)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario 1..................... ................ ................ ................ ................ ................ ................ ................ ................ ...............
Scenario 2..................... ................ ................ ................ ................ ................ ................ ................ ................ ...............
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Request for Comments
Should we adopt such an optional reserves sensitivity
analysis table? Would such a table be beneficial to investors? Is such
a table necessary or appropriate?
Should we require a sensitivity analysis if there has been
a significant decline in prices at the end of the year? If so, should
we specify a certain percentage decline that would trigger such
disclosure?
Should we revise the proposed form and content of the
table? If so, how should we revise the table's form or content?
As noted above in this release, SFAS 69 currently uses
single-day, year-end prices to estimate reserves, while the reserves
estimates in the proposed tables would be based on 12-month average
year-end prices. If the FASB elects not to change its SFAS 69
disclosures to be based on 12-month average year-end prices, should we
require reconciliation between the proposed Item 1202 disclosures and
the SFAS 69 disclosures? What other means should we adopt to promote
comparability between these disclosures?
iii. Geographic Specificity With Respect to Reserves Disclosures
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.\111\ 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. We think that greater specificity than
simply disclosing reserves within ``groups of countries'' would benefit
investors and currently are necessary to meet the requirements of Item
102 of Regulation S-K, in cases where a particular country, sedimentary
basin, or field constitutes a significant portion of a company's
reserves, particularly if that country, sedimentary basin, or field is
subject to unique risks, such as political instability. Thus,
instructions to proposed Item 1202 would state that, in general,
disclosures need only be broken out by continent, except where:
---------------------------------------------------------------------------
\111\ 17 CFR 229.102.
---------------------------------------------------------------------------
A particular country contains 15% or more of the company's
global oil reserves or gas reserves, or
A particular sedimentary basin or field contains 10% or
more of the company's global oil reserves or gas reserves.\112\
---------------------------------------------------------------------------
\112\ See proposed Instruction to Item 1202.
---------------------------------------------------------------------------
This proposed amendment would differ from the existing guidance in SFAS
69, which would permit disclosure based on broader geographic areas. In
addition, under the proposals, a company would be permitted, but not
required, to provide more detailed disclosure, such as countries or
fields containing less than the specified percentages.
Request for Comment
Should we provide the proposed guidance about the level of
specificity required when a company discloses its oil and gas reserves
by ``geographic area''?
Are the proposed 15% and 10% thresholds appropriate?
Should either, or both, of these percentages be different? For example,
should both be 15%? Should both be 10%? Would 5% or 20% be a more
appropriate threshold for either or both?
What would be the impact to investors if companies are
permitted to omit disclosures based on the individual field or basin
due to concerns related to competitive sensitivities? Would investors
be harmed if disclosure based on the individual field or basin is
omitted due to concerns related to competitive sensitivities? Is there
a better way to provide disclosure that a company heavily dependent on
a particular field or basin may be subject to risks related to the
concentration of its reserves?
Would greater specificity cause competitive harm? Is so,
how can the rules mitigate the risk of harm?
In the event that the FASB does not amend SFAS 69, should
we require companies to supplement their SFAS 69 disclosure with
greater geographic specificity? If the FASB does not amend SFAS 69,
should we require that companies reconcile the differences between the
reserves estimates shown in the SFAS 69 disclosure with the estimates
presented in the proposed tables?
iv. Separate Disclosure of Conventional and Continuous Accumulations
Under proposed Item 1202, companies would be required to disclose
reserves from conventional accumulations separately from reserves in
continuous accumulations. Several commenters on the Concept Release
believed that it is important to disclose such reserves
separately.\113\ Although proposed Item 1201 would permit a company to
combine these two tables, it would not permit a company to combine
columns of different tables. Thus, for example, if a company decided to
combine the two tables, it would have to represent reserves in
conventional natural gas reservoirs separately from gas reserves in
coalbeds or gas shales.
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\113\ See letters from Brookwood, D. McBride, Moody's, and Oil
Change.
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[[Page 39541]]
Request for Comment
Should we require separate disclosure of conventional
accumulations and continuous accumulations, as proposed?
Should we permit combining of columns if the product of
the oil and gas producing activity is the same, such as natural gas,
regardless of whether the reserves are in conventional or continuous
accumulations?
v. Preparation of Reserves Estimates or Reserves Audits
In the Concept Release, we sought comment on whether the rules
should require a company to retain an independent third party to
prepare, or conduct a reserves audit on, the company's reserves
estimates. Most commenters urged the Commission not to adopt such a
requirement.\114\ Some believed that a company's internal staff,
particularly at larger companies, is in a better position to prepare
those estimates.\115\ In addition, commenters pointed out a potential
lack of qualified third party engineers and other professionals to
conduct the increase in work that would need to be accomplished if we
adopted such a requirement.\116\ Others were concerned about the added
costs that would be associated with such a requirement.\117\ However,
some commenters believed that the participation of an independent third
party would provide heightened assurance regarding the accuracy of the
reserves estimates.\118\
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\114\ 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.
\115\ See letters from API, Denbury, ExxonMobil, Imperial,
Nexen, Shell, and Talisman.
\116\ See letters from AAPG, API, BP, Devon, ExxonMobil,
Imperial, D. McBride, Newfield, D. Ryder, and Sasol.
\117\ See letters from Sasol and Nexen.
\118\ See letters from CIBC, EnCana, Fitch, D. Kelly, Petrobras,
Robinson, Ultra, and White & Case.
---------------------------------------------------------------------------
In light of the commenters' concerns, we are not proposing to
require an independent third party to prepare the reserves estimates or
conduct a reserves audit. However, several commenters noted that it is
important that persons preparing or auditing the reserves estimates be
objective and qualified to perform the work that they are doing.\119\
In addition, because we are proposing to broaden permissible
technologies for establishing levels of certainty of reserves, we
believe that the proper application of such technologies in particular
situations requires a heightened level of judgment. Therefore, we
propose to require disclosure regarding the qualifications of the
person primarily responsible for preparing the reserves estimates or,
if the company represents that a reserves audit was conducted,
conducting a reserves audit.\120\ In addition, we propose to require
disclosure regarding the objectivity of third parties that conduct such
service for an oil and gas company and measures taken to assure the
independence and objectivity of employees. We based these
qualifications largely on the reserves audit guidance of the Society of
Petroleum Engineers (SPE).\121\ In particular, we propose to require
the company to disclose the following information about the technical
person \122\ primarily responsible for preparing the reserves estimate
or, if the company represents that such a reserves audit was conducted,
conducting the reserves audit:
---------------------------------------------------------------------------
\119\ See letters from Brookwood, Denbury, D. McBride, Petro-
Canada, Robinson, and Total.
\120\ See proposed Item 1202(a)(6).
\121\ See Standards Pertaining to the Estimating and Auditing of
Oil and Gas Reserves Information of the SPE (SPE Reserves Auditing
Standards).
\122\ 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.
---------------------------------------------------------------------------
(1) If the person is an employee of the company,
[cir] The fact that an employee of the company had primary
responsibility for preparing the reserves estimate (but the employee
would not have to be identified); and
[cir] Measures taken to assure the independence and objectivity of
the estimate;
(2) If the person is not an employee of the company,
[cir] The identity of the person;
[cir] The nature and amount of all work that the person has
performed for the company during the past three fiscal years, other
than preparing the reserves estimate or conducting the reserves audit,
as well as all compensation and fees (in any form) paid to that person
for all such services; and
[cir] Whether the person has any other interests in the company or
other conflict of interests;
(3) Whether the person (regardless of whether an employee or third
party) primarily responsible for the estimating or auditing of
reserves:
[cir] Has a minimum of three years of practical experience in
petroleum engineering or petroleum production geology, with at least
one full year of this experience being in the estimation and evaluation
of reserves if the person was in charge of preparing the reserves
estimates;
[cir] Has a minimum of ten years of practical experience in
petroleum engineering or petroleum production geology, with at least
five years of this experience being in the estimation and evaluation of
reserves and the conducting of reserves audits if that person conducted
a reserves audit of the registrant's reserves estimates;
[cir] Has received, and is maintaining in good standing, a
registered or certified professional engineer's license or a registered
or certified professional geologist's license, or the equivalent
thereof, from an appropriate governmental authority or a recognized
self-regulating professional organization; and
[cir] Has a bachelor's or advanced degree in petroleum engineering,
geology, or other discipline of engineering or physical science, and if
so, the specific degree earned by the person; and
(4) Any memberships, in good standing, of the person (regardless of
whether an employee or third party) with a self-regulatory organization
of engineers, geologists, other geoscientists, or other professionals
whose professional practice includes reserves evaluations or reserves
audits, that:
[cir] Admits members primarily on the basis of their educational
qualifications;
[cir] Requires its members to comply with the professional
standards of competence and ethics prescribed by the organization that
are relevant to the estimation, evaluation, review, or audit of
reserves data; and
[cir] Has disciplinary powers, including the power to suspend or
expel a member.
For purposes of the proposed disclosure, the ``person'' could be
either an individual or an entity. If the person is an entity, then the
disclosures regarding technical qualifications in the paragraphs (3)
and (4) would apply to the individual within the entity who is
responsible for the technical aspects of the reserves estimation or
audit. To the extent that the person does not have all of the technical
qualifications above, the company would be required to discuss the
reasons why it believes that the person is otherwise qualified to
prepare the estimates or conduct the reserves audit, as applicable, and
any risks associated with reserves estimates not
[[Page 39542]]
prepared or audited by persons with such qualifications.\123\
---------------------------------------------------------------------------
\123\ See proposed Item 1202(a)(6)(v).
---------------------------------------------------------------------------
Request for Comments
Should we require companies to disclose whether the person
primarily responsible for preparing reserves estimates or conducting
reserves audits meets the specified qualification standards, as
proposed? Should we, instead, simply require companies to disclose such
a person's qualifications?
Should we require disclosure regarding a person's
objectivity when a company prepares its reserves estimates in-house?
Should the proposed disclosures regarding objectivity be required only
if a company hires a third party to prepare its reserve estimates or
conduct a reserves audit, as proposed?
If a company prepares its reserves estimates in-house,
should we require disclosure of any procedures that the company has
taken to preserve that person's objectivity? Should we require
disclosure of whether the internal person meets specified objectivity
criteria? For example, should we apply the some of the same criteria
that we propose to apply to third party preparers? If so, which ones?
Consistent with the SPE's auditing guidance regarding
internal auditors, should we require companies to disclose whether that
person (1) is assigned to an internal-audit group which is (a)
accountable to senior level management or the board of directors of the
company and (b) separate and independent from the operating and
investment decision making process of the company and (2) is granted
complete and unrestricted freedom to report, to one or more principal
executives or the board of directors, any substantive or procedural
irregularities of which that person becomes aware?
Should we require disclosure with other specific
independence or objectivity standards and, if so, what?
Should we revise any of the proposed provisions regarding
a person's objectivity or technical qualifications? Should the proposal
require disclosure of other criteria that would have bearing on
determining whether the person is objective or qualified?
Should a company be required to present risk factor
disclosure if its reserves estimates were not prepared by a person
meeting the objectivity and technical qualifications?
Because of the inherent uncertainty regarding estimates of
probable and possible reserves, should we require the proposed
disclosure only if a company chooses to disclose probable or possible
reserves?
Should we require that a third party prepare reserves
estimates or conduct a reserves audit if a company chooses to disclose
probable or possible reserves estimates?
Should we require the proposed disclosure only if the
company is using technologies other than those which are allowed in our
current definitions to establish levels of certainty?
vi. Contents of Third Party Preparer and Reserves Audit Reports
Currently, if the company represents that it relied on a third
party for a portion of its filing, it must obtain consent from that
third party.\124\ In order to clarify which portion of the disclosures
the third party is expertising, we propose that, if a company
represents that its estimates of reserves are based on estimates
prepared by a third party, the company must file a report of the third
party as an exhibit to the relevant registration statement or
report.\125\ The proposal would require that report to include the
following disclosure:
---------------------------------------------------------------------------
\124\ See 17 CFR 229.601(b)(23).
\125\ See proposed Item 1202(a)(7).
---------------------------------------------------------------------------
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.
Similarly, if the company represents that a third party conducted a
reserves audit of the reserves estimates, the company would be required
to file a report of the third party as an exhibit to the relevant
registration statement or report. We are not proposing that these
reports be the full ``reserves report'' that is often very detailed and
voluminous. Rather these proposed reports would summarize the scope of
work performed by, and conclusions of, the third party. The proposed
contents of these reports mirror the guidance issued by the Society of
Petroleum Evaluation Engineers regarding the preparation of such
reports.
We propose 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 thoroughness of the reserves estimation process, the
classification of reserves appropriate to the relevant definitions
used, and the reasonableness of the estimated reserves quantities.\126\
The proposed definition would state that, 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 company's reserves covered by the reserves audit. This definition
is largely derived from the SPE's reserves auditing guidelines.\127\
---------------------------------------------------------------------------
\126\ See proposed Item 1202(a)(9).
\127\ Consistent with the SPE's auditing guidelines, we note
that a ``reserves audit'' is significantly different from a
financial audit. See SPE Reserves Auditing Standards.
---------------------------------------------------------------------------
We propose to require that the report associated with such a
reserves audit must include the following disclosure, based on the
Society of Petroleum Evaluation Engineers's audit report guidelines:
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;
[[Page 39543]]
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;
A brief summary of the third party's conclusions with
respect to the reserves estimates; and
The signature of the third party.
Request for Comment
Should we require a company to file reports from third
party reserves preparers and reserves auditors containing the proposed
disclosure when the company represents that a third party prepared its
reserves estimates or conducted a reserves audit? As an alternative,
should we not require that the third party's report be filed, but that
the company must provide a description of the third party's report? If
so, should we specify that the company's description of the third
party's report should contain the information that we propose to
require in the third party's report?
Should we specify the disclosures that need to be included
in third party reports? If so, is the disclosure that we have proposed
for the reserves estimate preparer's and reserves auditor's reports
appropriate? Should these reports contain more or less information? If
they should include more information, what other information should
they include? If less, what proposed information is not necessary?
In an audit, should we specify the minimum percentage of
reserves that should be examined and determined to be reasonable? If
so, what should that percentage be? Should it be 50%, 75%, 90% or some
other percentage? If so, why?
If the company engages multiple third parties to conduct
reserves audits on different portions of its reserves, should the
definition of reserves audit be conditioned on each third party
evaluating at least 80% of the reserves covered by its reserves audit,
as proposed? Is the scope of a reserves audit defined by geographic
areas? If so, should the definition of a reserves audit be based on the
third party's evaluation of 80% of the reserves located in the
geographic areas covered by the reserves audit?
Would disclosure that a company has hired a third party to
audit only a portion of its reserves be confusing to investors? Is
there a danger that investors will not be able to ascertain the extent
of the reserves audit? Should we require that a company could not
disclose that it has conducted a reserves audit unless 80% of all of
its reserves have been evaluated by a third party or, if the company
hires multiple third parties, by all of the third parties collectively?
Is the proposed definition of ``reserves audit''
appropriate? Should we revise this proposed definition in any way?
vii. Solicitation of Comments on Process Reviews
The Society of Petroleum Engineer's reserves auditing standards
reference a third type of review, which it calls a ``process review.''
\128\ It defines 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, it notes 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 an audit of reserves. We are not proposing requiring
disclosure of whether a company has conducted a process review, as
defined by the SPE. In so doing, we note the SPE's admonition that such
reviews are not as rigorous as a reserves audit. We are not proposing
to prohibit disclosure of such process reviews because we believe that
they may be beneficial to companies and shareholders. However, in order
to help prevent confusion between the different levels of third-party
participation, companies should clearly disclose the level and scope of
work that was performed. In addition, a company should avoid using
language which may lead investors to erroneously believe that a higher
level of third-party review was performed.
---------------------------------------------------------------------------
\128\ See SPE Reserves Auditing Standards.
---------------------------------------------------------------------------
Request for Comment
Should we require disclosure of whether a company has
conducted a process review? Notwithstanding the relative lack of rigor
of a process review compared to a reserves audit, would investors find
such information useful?
The proposal does not prohibit disclosure of process
reviews. Is there a danger that the public may be confused by such
disclosure? Should we prohibit disclosure of any type of reserves-
related activity other than the preparation of the reserves estimates
or a reserves audit?
4. Proposed Item 1203 (Proved Undeveloped Reserves)
We are proposing to require disclosure of the aging of proved
undeveloped reserves (PUDs). Some of the commenters responding to the
Concept Release expressed concerns regarding companies that carry
alleged PUDs for lengthy time periods.\129\ Long holding periods of
such reserves raise the question whether the company has a bona fide
intention or the capability to develop those reserves, even though the
company has determined them to be economically producible. Several
commenters recommended that we require a company to remove PUDs that
have remained so classified for five years or longer.\130\ PRMS
guidelines indicate that five years is a benchmark for a reasonable
timeframe to initiate the development of reserves, although they
recognize that this timeframe depends on the specific circumstances.
However, others suggested that a company should be able to characterize
PUDs as such for longer than a five-year period if there are
exceptional circumstances (such as extensive offshore projects) that
justify continued inclusion of such reserves in the proved
category.\131\
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\129\ See letters from CIBC, Devon, EIA, D. McBride, Robinson,
D. Ryder, and SPE.
\130\ See letters from Devon, EIA, D. McBride, D. Olds, SPE, and
Ultra. This is consistent with PRMS guidance. See Section 2.1.3.2 of
PRMS.
\131\ See letters from Denbury, Devon, EIA, D. McBride, D. Olds,
Robinson, SPE, and StatoilHydro.
---------------------------------------------------------------------------
We propose to address these concerns through disclosure. We believe
that the need for such disclosure is heightened as a result of our
proposed amendments that would ease the requirements for recognizing
PUDs and thereby 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.
Proposed Item 1203 would require 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
[[Page 39544]]
Net investment required to convert proved undeveloped
reserves to proved developed reserves during the year.\132\
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\132\ See proposed Item 1204.
---------------------------------------------------------------------------
A form of the proposed PUDs development table is set forth below:
Conversion of Proved Undeveloped Reserves
----------------------------------------------------------------------------------------------------------------
Proved undeveloped reserves converted to
proved developed reserves Investment in conversion of
Fiscal year ------------------------------------------------ proved undeveloped reserves to
Product A proved developed reserves ($)
Oil (mbbls) Gas (mmcf) (measure)
----------------------------------------------------------------------------------------------------------------
2004......................... ..............
2005......................... ..............
2006......................... ..............
2007......................... ..............
2008......................... ..............
----------------------------------------------------------------------------------------------------------------
This table would allow investors to assess how a company is
managing its PUDs. In addition, proposed Item 1203 would require
disclosure, by product type, of any PUDs which have remained
undeveloped for five years or more and the reasons for the lack of
development. The proposed item would also require a company to disclose
its plans to develop PUDs and to further develop proved oil and gas
reserves. Finally, the company would be required to discuss any
material changes to PUDs.
Request for Comment
Should we adopt the proposed table? Alternatively, should
we simply require companies to reclassify their PUDs after five years?
Should the table require disclosure of other categories of
changes to the status of PUDs, such as acquisitions, removals, and
production? Should we add any categories?
Some of the abuse related to PUD disclosure may be related
to companies' desire to show proved reserves in light of our
prohibition on disclosure of probable reserves. Would the proposed
rules permitting disclosure of probable reserves reduce the incentive
to categorize reserves as PUDs? If so, is the proposed table necessary?
Should we require disclosure of the reasons for
maintaining PUDs that have been classified as PUDs for more than five
years, as proposed? If not, why not?
Should we require a company to disclose its plans to
develop PUDs and to further develop proved oil and gas reserves, as
proposed? If not, why not?
Should we require the company to discuss any material
changes to PUDs that are disclosed in the table? If not, why not?
5. Proposed Item 1204 (Oil and gas production)
Item 3 of Industry Guide 2 currently requires disclosure, by
geographic area, of oil and gas production. We propose codifying that
requirement in proposed Item 1204 of Regulation S-K.\133\ In addition,
the proposed Item would require such disclosure to be made in tabular
form for ease of presentation. As a practical matter, it appears that
most companies already provide this disclosure in tabular form. A form
of the proposed table is set forth below:
---------------------------------------------------------------------------
\133\ See proposed Item 1204.
Oil and Gas Production, Sales Prices, and Production Costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
Oil Gas Product A
--------------------------------------------------------------------------------------------------------------------
Location Production Production Sales price Production
Production Sales price cost ($US/ Production Sales price cost ($US/ Production ($US/ cost ($US/
(mbbls) ($US/bbl) boe) (mmcf) ($US/mcf) mcfe) (measure) measure) measure)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Geographic Area A.................. ........... ........... ........... ........... ........... ........... ........... ........... ...........
2005........................... ........... ........... ........... ........... ........... ........... ........... ........... ...........
2006........................... ........... ........... ........... ........... ........... ........... ........... ........... ...........
2007........................... ........... ........... ........... ........... ........... ........... ........... ........... ...........
Geographic Area B.................. ........... ........... ........... ........... ........... ........... ........... ........... ...........
Geographic Area C.................. ........... ........... ........... ........... ........... ........... ........... ........... ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------
The disclosure that proposed Item 1204 would require is very
similar to the disclosure called for by existing Industry Guide 2, but
would be modified in two respects. First, proposed Item 1204 would use
the definition of the term ``geographic area'' in proposed Item
1201(d), rather than use the current reference to SFAS 69, which only
requires disclosure by country or, if appropriate, groups of
countries.\134\
---------------------------------------------------------------------------
\134\ See SFAS 69.
---------------------------------------------------------------------------
In addition, we propose to eliminate existing instructions to Item
3 of Industry Guide 2 that we believe are no longer necessary. These
instructions relate to the following topics:
Separate reporting of production through processing plant
ownership;
Inclusion of only marketable production of gas on an ``as
sold'' basis, including the exclusion of flared gas, injected gas, and
gas consumed in operations;
Determination of transfer price of oil and gas; and
Means to calculate average production costs.
We believe that these instructions are no longer necessary in light
of changes in the oil and gas industry and markets and relate to issues
that are commonly understood and do not require additional instruction.
Several of these instructions have very limited application.
[[Page 39545]]
Request for Comments
Should we adopt the proposed table?
Should the disclosure be made based on the proposed
definition of ``geographic area,'' or should we continue to follow the
definition set forth in SFAS 69?
Should we eliminate the instructions listed above, as
proposed? If not, which instructions should we retain? Please explain
why those instructions continue to be useful.
6. Proposed Item 1205 (Drilling and other exploratory and development
activities)
Item 6 of Industry Guide 2 currently calls for disclosure of
drilling activities by geographic area. We propose to codify this
disclosure as Item 1205 of Regulation S-K, in tabular form.\135\ A form
of the proposed table is set forth below:
---------------------------------------------------------------------------
\135\ See proposed Item 1205.
Drilling Activities
[Geographic area]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Exploratory wells Development wells Extension wells
----------------------------------------------------------------------------------------------------------------------
Gross Net Gross Net Gross Net
--------------------------------------------------------------------------------------------------------------------------------------------------------
Oil .................. .................. .................. .................. .................. .................
Fiscal Year.................. .................. .................. .................. .................. .................. .................
Fiscal Year-1................ .................. .................. .................. .................. .................. .................
Fiscal Year-2................ .................. .................. .................. .................. .................. .................
Natural Gas .................. .................. .................. .................. .................. .................
Fiscal Year.................. .................. .................. .................. .................. .................. .................
Fiscal Year-1................ .................. .................. .................. .................. .................. .................
Fiscal Year-2................ .................. .................. .................. .................. .................. .................
Product A .................. .................. .................. .................. .................. .................
Fiscal Year.................. .................. .................. .................. .................. .................. .................
Fiscal Year-1................ .................. .................. .................. .................. .................. .................
Fiscal Year-2................ .................. .................. .................. .................. .................. .................
Suspended .................. .................. .................. .................. .................. .................
Fiscal Year.................. .................. .................. .................. .................. .................. .................
Fiscal Year-1................ .................. .................. .................. .................. .................. .................
Fiscal Year-2................ .................. .................. .................. .................. .................. .................
Dry .................. .................. .................. .................. .................. .................
Fiscal Year.................. .................. .................. .................. .................. .................. .................
Fiscal Year-1................ .................. .................. .................. .................. .................. .................
Fiscal Year-2................ .................. .................. .................. .................. .................. .................
----------------------------------------------------------------------------------------------------------------------
Total.................... .................. .................. .................. .................. .................. .................
--------------------------------------------------------------------------------------------------------------------------------------------------------
We are also proposing several revisions to the existing
disclosures. First, the existing item calls for disclosure by
geographic area. We propose to clarify that, for purposes of this item,
disclosure should be made pursuant to the definition of ``geographic
area'' set forth in proposed Item 1201(d). Second, we propose to add
two categories of wells:
Extension wells and
Suspended wells.
Currently, Industry Guide 2 only calls for disclosure of the drilling
of exploratory and development wells. However, we believe that
distinguishing between extension well drilling and exploratory drilling
is important because exploratory drilling typically is associated with
the discovery of new fields, and thus new sources of oil and gas,
rather than merely the extension of an existing field. Thus, we believe
that disclosure of extension wells should be distinct from disclosure
about exploratory wells.
Similarly, companies sometimes suspend drilling of a well before
completion. Because the definition of a dry well requires that the
company report the well as abandoned, these suspended drilling projects
are not reflected as drilling activities under the current disclosure
requirements. Although suspension of drilling does not necessarily mean
that the company has abandoned the well, such activities can consume
significant capital resources. Thus, we propose to include this
category of drilling activity in the disclosure item.
Proposed new Item 1205 would also require disclosure of any other
exploratory or development activities that the company has conducted
over the prior three years, including implementation of mining methods
for the extraction of oil or gas. We recognize that resources in
continuous accumulations often require extraction methods that differ
significantly from the extraction methods used in connection with
traditional oil or gas wells. This proposed new disclosure would
provide investors with information about an oil and gas company's full
spectrum of exploratory and development activities.
Request for Comment
Should we adopt the proposed table? Should the disclosures
be made based on the definition of ``geographic area'' in proposed Item
1201(d)?
Should we require separate disclosure about the two new
proposed categories of wells-extension wells and suspended wells? Does
distinguishing these types of wells from exploratory wells and dry
wells provide enough clarity regarding the types of exploratory or
development activities?
7. Proposed Item 1206 (Present activities)
Proposed Item 1206 would codify 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
[[Page 39546]]
(including wells temporarily suspended), waterfloods in process of
being installed, pressure maintenance operations, and any other related
activities of material importance.\136\ We are proposing no substantive
changes to the existing disclosure item except clarification that the
meaning of the term ``geographical area'' would be based on the
proposed definition of that term in proposed Item 1201(d).\137\
---------------------------------------------------------------------------
\136\ See proposed Item 1206.
\137\ See proposed Item 1206(a).
---------------------------------------------------------------------------
Request for Comment
Should the disclosure of present activities be made based
on the definition of ``geographic area'' in proposed Item 1201(d)?
Should we adopt any other changes to the disclosures
currently set forth in existing Item 7 of Industry Guide 2 that we
propose to codify in Item 1206?
8. Proposed Item 1207 (Delivery Commitments)
Proposed Item 1207 would codify 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.\138\ We are not proposing any
substantive changes to the disclosure currently called for by Item 8.
However, we are proposing a significant amount of restructuring and
rewording of the disclosure item to make it easier to understand. These
proposed changes largely involve separating embedded lists into
separate subparagraphs and general plain English revisions but are not
intended to change the substance of the disclosures.
---------------------------------------------------------------------------
\138\ See proposed Item 1207.
---------------------------------------------------------------------------
Request for Comment
Are the proposed revisions appropriate? Do the proposed
revisions make any unintended substantive changes to the existing
disclosures?
Should we adopt any substantive changes to the disclosures
currently set forth in Item 8 of Industry Guide 2 that we propose to
codify in Item 1207?
Is this disclosure requirement still necessary? Do oil and
gas companies still enter into such delivery commitments? Are they
material?
9. Proposed Item 1208 (Oil and gas properties, wells, operations, and
acreage)
Proposed Item 1208 would codify existing Items 4 and 5 of Industry
Guide 2. The proposed item also would require new disclosures not
currently called for by Industry Guide 2 that are described below.
i. Enhanced Description of Properties Disclosure Requirement
Item 102 of Regulation S-K provides a very broad, general
description of the properties and facilities that a company must
disclose in its filings. We propose to add a paragraph to Item 1208
that better illustrates the types of properties and the types of
disclosures for those properties that apply to oil and gas
companies.\139\ The proposed paragraph would require a company to do
the following:
---------------------------------------------------------------------------
\139\ See proposed Item 1208(a).
---------------------------------------------------------------------------
Identify and describe generally its material properties,
plants, facilities, and installations;
Identify the geographic area in which they are located;
Indicate whether they are located onshore or offshore; and
Describe any statutory or other mandatory relinquishments,
surrenders, back-ins, or changes in ownership.
Request for Comment
Are the proposed disclosure enhancements regarding oil and
gas properties appropriate? Would this enhanced disclosure be helpful
to investors?
Should the disclosures be made based on the definition of
``geographic area'' in proposed Item 1201(d)?
Do we need to define any of the terms in the proposed
language?
ii. Wells and Acreage
Proposed Item 1208 would require separate tabular disclosure of the
number of the registrant's producing wells, expressed in terms of both
gross wells and net wells, by geographic area.\140\ These disclosures
are currently called for by Items 4 and 5 of Industry Guide 2. This
proposed table would illustrate oil wells and gas wells in both
conventional and continuous accumulations and other wells for products
from continuous accumulations. A form of the proposed table is set
forth below:
---------------------------------------------------------------------------
\140\ See proposed Item 1208(b) and (c).
Wells
------------------------------------------------------------------------
Producing wells
Location ------------------------------------
Gross Net
------------------------------------------------------------------------
Geographic Area A: ................. ................
Oil Wells...................... ................. ................
Natural Gas Wells.............. ................. ................
Product A Wells................ ................. ................
------------------------------------
Total...................... ................. ................
========================================================================
Geographic Area B:
Oil Wells...................... ................. ................
Natural Gas Wells.............. ................. ................
Product A Wells................ ................. ................
------------------------------------
Total...................... ................. ................
------------------------------------------------------------------------
Similarly, it would require tabular disclosure, by geographic area,
of the company's total gross and net developed acres (that is, acres
spaced or assignable to productive wells) and undeveloped acres,
including leases and concessions.\141\ A form of the proposed table is
set forth below:
---------------------------------------------------------------------------
\141\ See proposed Item 1208(e) and (f).
Acreage
----------------------------------------------------------------------------------------------------------------
Developed acres Undeveloped acres
------------------------------------------------------------------------------
Gross Net Gross Net
----------------------------------------------------------------------------------------------------------------
Geographic Area A................ .................. .................. .................. .................
Geographic Area B................ .................. .................. .................. .................
Geographic Area C................ .................. .................. .................. .................
------------------------------------------------------------------------------
Total.................... .................. .................. .................. .................
----------------------------------------------------------------------------------------------------------------
[[Page 39547]]
Request for Comment
Is the proposed table appropriate? Is there a better way
to disclose such information?
Should the disclosures be made based on the definition of
``geographic area'' in proposed Item 1201(d)?
Is it necessary to disclose wells and acreage in
conventional accumulations separate from wells and acreage in
continuous accumulations, as proposed?
Is this disclosure requirement still necessary? Is
disclosure of the number of wells and acreage material? Should we
require the disclosures related to wells and acreage only if there is a
high concentration of production or reserves attributable to a few
wells or limited acreage? If so, should we specify what that
concentration would be?
iii. New Proposed Disclosures Regarding Extraction Techniques and
Acreage
As noted previously, some oil and gas resources require extraction
techniques other than traditional oil and gas wells. Because we are
adding non-traditional resources, such as bitumen, to the definition of
oil and gas producing activities, we believe that it is appropriate for
companies to describe the techniques that the company is using to
extract the resources if it is not using a well. Thus, we are proposing
to add a new requirement for companies extracting hydrocarbons through
means other than wells to provide a discussion of such operations.\142\
This disclosure requirement has been drafted broadly to allow for
unanticipated developments in extraction technologies.
---------------------------------------------------------------------------
\142\ See proposed Item 1208(d).
---------------------------------------------------------------------------
Proposed Item 1208 also would require a company to disclose, for
unproved properties:
The existence, nature (including any bonding
requirements), timing, and cost (specified or estimated) of any work
commitments; and
By geographic area, the net area of unproved property for
which the registrant expects its rights to explore, develop, and
exploit to expire within one year.\143\
---------------------------------------------------------------------------
\143\ See proposed Item 1208(g).
---------------------------------------------------------------------------
Finally, the proposed Item would continue to require disclosure of
areas of acreage concentration, and, if material, the minimum remaining
terms of leases and concessions.\144\
---------------------------------------------------------------------------
\144\ See proposed Item 1208(h).
Request for Comment
Should we require more specific disclosure regarding
extraction activities that do not involve wells? Should this proposed
item remain open-ended to permit description of unanticipated
technologies?
Is the proposed disclosure for unproved properties
appropriate? Should the proposed disclosure for unproved properties be
set forth in proposed Item 1208? Should we move such disclosure to the
reserves table in proposed Item 1202, where reserves are discussed?
10. Proposed Item 1209 (Discussion and Analysis for Registrants Engaged
in Oil and Gas Activities)
We propose to add new Item 1209, which would provide topics that a
company should address either as part of Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A) \145\
or in a separate section. First, the proposed Item would require
companies to discuss material 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:
---------------------------------------------------------------------------
\145\ See 17 CFR 229.303.
---------------------------------------------------------------------------
Changes in prices;
Technical revisions; and
Changes in the status of any concessions held (such as
terminations, renewals, or changes in provisions).
We note that SFAS 69 currently requires reconciliation of changes to
reserves estimates. This proposal is intended to supplement the SFAS 69
disclosure because SFAS 69 currently does not provide for these
categories of changes. We believe such disclosure would be helpful
because developments in the oil and gas industry and markets, including
more liquid commodities markets and expansion of interests in foreign
countries involving concessions, have made distinguishing changes
resulting from these factors more important.
The proposed Item also would require companies to discuss
technologies used to establish the appropriate level of certainty for
any material additions to, or increases in, reserves estimates.
Finally, the proposed Item would list matters that a company should
consider in discussing known trends, demands, commitments,
uncertainties, and events that are reasonably likely to have a material
effect on the company. These matters include, but are not limited to,
the following:
Prices and costs;
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 registrant'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;
Anticipated capital expenditures directed toward
conversion of proved undeveloped reserves to proved developed reserves,
and, if disclosed, probable reserves to proved reserves and possible
reserves to probable or proved reserves;
Anticipated exploratory activities, well drilling, and
production;
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; and
Potential effects of different forms of rights to
resources, such as production sharing contracts, on operations.
The MD&A is typically presented in a self-contained section of the
registration statement or report. However, the disclosure requirements
that would comprise proposed new Subpart 1200 of Regulation S-K would
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 would be able to include that discussion or analysis with
the relevant table, with appropriate cross-references, rather than
including it in its general MD&A section.\146\
---------------------------------------------------------------------------
\146\ See proposed Item 1209(b).
---------------------------------------------------------------------------
Request for Comment
Proposed Item 1209 is not intended to increase a company's
disclosure requirements, but specify disclosures already required
generally by MD&A. Is such an item helpful?
Are the proposed topics that an oil and gas company should
consider discussing as part of MD&A, whether in the main MD&A section
or in conjunction with the relevant table,
[[Page 39548]]
appropriate? Are there other topics that an oil and gas company should
consider discussing?
Should we permit such discussions in conjunction with the
relevant table as proposed? Would this aid comparability of the
disclosures? Or should we keep MD&A as a self-contained section?
IV. Proposed 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.\147\ Appendix A is significantly shorter, and provides far
less guidance regarding disclosures, than proposed Subpart 1200 or
Industry Guide 2.
---------------------------------------------------------------------------
\147\ See Appendix A to Item 4.D--Oil and Gas of Form 20-F [17
CFR 249.220f].
---------------------------------------------------------------------------
We believe that the proposed 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 proposing to revise 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.\148\ We propose to revise
the Instructions to Item 4 of Form 20-F to refer to Subpart 1200
instead of Appendix A.\149\
---------------------------------------------------------------------------
\148\ We are not proposing changes to Form 40-F, which is the
form on which Canadian companies reporting under the multi-
jurisdictional disclosure system file Exchange Act registration
statements and annual reports with the Commission, because the
disclosures regarding oil and gas activities for those companies are
not currently governed by our rules.
\149\ See proposed Instruction 2 to Item 4.
---------------------------------------------------------------------------
Thus, the proposal would continue to require the same type of
disclosure currently required by Appendix A regarding reserves and
production. In addition, the proposal would require foreign private
issuers to comply with the following disclosures currently in Industry
Guide 2 that we propose to codify in Subpart 1200 of Regulation S-K:
Drilling and other exploratory and development activities
(Item 1205);
Present activities (Item 1206);
Delivery commitments (Item 1207); and
Oil and gas properties, wells, operations, and acreage
(Item 1208).
Finally, applying the proposed Subpart 1200 on foreign private
issuers would impose the completely new disclosures that we are
proposing for domestic companies in this release, including the
following:
Reserves from non-traditional sources (i.e., bitumen,
shale, coalbed methane);
Optional disclosure of probable and possible reserves;
Optional disclosure of oil and gas reserves' sensitivity
to price;
Proved undeveloped reserves held for five years or more
and an explanation of why they should continue to be considered proved;
Technologies used to establish additions to reserves
estimates;
Material changes due to technology, prices, and concession
conditions;
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;
The qualifications and measures taken to ensure the
independence and objectivity of any employee primarily responsible for
preparing or auditing the reserves estimates; and
Filing of the report of a third party if a company
represents that it is relying on a third party to prepare the reserves
estimates or conduct a reserves audit.
Appendix A currently allows a foreign private issuer to exclude
required disclosures about reserves and agreements if its home country
prohibits the disclosures. Because these considerations still apply to
such foreign private issuers, we propose to move that provision from
Appendix A, which we propose to delete, to the Instructions to Item 4
of Form 20-F.\150\
---------------------------------------------------------------------------
\150\ Id.
---------------------------------------------------------------------------
Also, similar to our revisions to Item 102 of Regulation S-K, we
propose to limit the Instruction to Item 4.D of Form 20-F to extractive
enterprises conducting activities other than oil and gas producing
activities because Subpart 1200 would cover companies conducting oil
and gas producing activities.\151\
---------------------------------------------------------------------------
\151\ See proposed Instruction 4.D of Form 20-F.
---------------------------------------------------------------------------
Request for Comment
Should we delete Appendix A and refer to Subpart 1200 with
respect to Form 20-F, as proposed? Why? Should we expand the
requirements of Form 20-F to require more disclosure than currently
required by Appendix A, as proposed? Conversely, should we only update
Appendix A to reflect the proposed new definitions and formats for
disclosing reserves and production?
Would the proposed reference to Subpart 1200 in Form 20-F
significantly change the information currently disclosed by foreign
private issuers? If so how? Would such a change be appropriate?
Is the proposed exception for foreign laws that prohibit
disclosure about reserves and agreements appropriate? Do such laws
affect domestic companies as well? Should Subpart 1200 have a general
instruction with respect to such foreign laws?
Are the proposed revisions to Instructions to Item 4.D
appropriate with respect to foreign private issuers that have
extractive activities other than oil and gas producing activities?
V. Impact of Proposed Amendments on Accounting Literature
A. Consistency With FASB and IASB Rules
Several commenters noted that changing the definition of the term
``proved reserves'' in Rule 4-10(a) of Regulation S-X would affect both
the full cost accounting treatment of Rule 4-10(c) and the successful
efforts accounting treatment of Statement of Financial Accounting
Standard No. 19 (SFAS 19).\152\ One commenter suggested the Commission
consider the impact on the required immediate expensing of seismic
tests under SFAS 19.\153\ In addition, a revised definition could
affect the primary inputs to the standardized measure, such as static
operating conditions, year-end prices and costs and the 10% discount
rate, which would affect the full cost ceiling under the full cost
accounting treatment.\154\ These changes could also affect how costs
are expensed.\155\ Companies should clearly explain the changes in
their filings.\156\ Commenters recommended that the Commission
coordinate corresponding rule changes with the FASB and IASB to ensure
[[Page 39549]]
consistency of the rules.\157\ Some commenters remarked that the IASB
is currently considering establishing a set of guidelines for oil and
gas extractive activities, including a definition of oil and gas
reserves, and recommended that the Commission align its regulations
with those guidelines. We intend to discuss our rulemaking project with
the FASB and IASB and work with them to harmonize the rules upon
effectiveness of the proposed rules, if adopted.
---------------------------------------------------------------------------
\152\ See letters from D&T, Grant Thornton, and KPMG.
\153\ See letter from Audit Quality.
\154\ See letters from Audit Quality, KPMG, and PWC.
\155\ See letter from KPMG.
\156\ Id.
\157\ See letters from Audit Quality, CFA, KPMG, and PWC.
---------------------------------------------------------------------------
B. Change in Accounting Principle or Estimate
One commenter noted that the proposals would raise the question of
whether a change in the definition of proved reserves is a change in
accounting principle (which requires retroactive revision of past
years) or a change in an estimate caused by a change in accounting
principle under SFAS 154.\158\ The proposed change in the definition of
proved reserves and the change from using single-day year-end price to
an average price should be viewed 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.
---------------------------------------------------------------------------
\158\ See letter from Audit Quality.
---------------------------------------------------------------------------
Request for Comment
Are the proposed changes more properly characterized as a
change in accounting principle or a change in estimate under SFAS 154?
Would it be appropriate to consider the changes as a
change in accounting principle, but specify that no retroactive
revision of past years would be required?
If we required retroactive revision of past years, would
companies have the historical engineering and scientific data to make
such revisions? If not, are there alternatives to retroactive revision
that we should consider?
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 would be considered oil and gas producing activities, and not
mining activities, if we adopt the proposals. 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 proposed rules, bitumen
extraction and operations that produce oil or gas through mining
methods would be included under oil and gas accounting rules, which
only permit capitalization of costs associated with proved
reserves.\159\ 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, if adopted.
---------------------------------------------------------------------------
\159\ See Rule 4-10(c) of Regulation S-X [17 CFR 210.4-10(c)].
---------------------------------------------------------------------------
Request for Comment
How should we address these inconsistencies between oil
and gas accounting rules and mining accounting rules?
Should we permit companies that extract, through mining
methods, materials from which oil and gas can be produced to continue
to capitalize costs under mining rules, or should we require them to
capitalize costs based on oil and gas rules? Are there circumstances
involved with mining operations, different from oil and gas operations,
that justify capitalization of costs of proved plus probable reserves,
as opposed to only costs of proved reserves?
D. Price Used To Determine Proved Reserves for Purposes of Capitalizing
Costs
Statement of Financial Accounting Standard No. 19 ``Financial
Accounting and Reporting by Oil and Gas Producing Companies'' (SFAS 19)
requires the units-of-production method to be used for amortizing
acquisition costs of proved properties and development costs. As noted
above, we are not proposing to change the use of the period end price
assumption when determining reserves for accounting purposes. Changes
in the definition of reserves and the price used to determine whether
resources are reserves (i.e., whether they are economically producible)
would impact the determination of the quantity of reserves, and
therefore would impact the amount of amortization expense that is
recorded in the income statement. It is expected that, for most
companies, based on the relationship between the amount of proved
reserves and the production in a given period, the impact of such a
change on the financial statements would not be significant and would
not have a significant impact on comparability between periods.
Request for Comment
Would the effect of such changes be material or have a
material effect on historical amortization levels?
Would the effect of such changes be material or have a
material effect on comparability? Please provide any empirical evidence
to support your conclusion.
Would it be appropriate to continue to require the use of
the year-end price for purposes of determining reserves for purposes of
amortization expense while using a different price for purposes of
disclosing reserves estimates in Commission filings? This would result
in a different value associated with the use of the term ``proved
reserves'' for purposes of disclosure, as opposed to the use of that
term for purposes of accounting. Would this be confusing? Should we use
a different term? Should we otherwise clarify the two different
meanings of that term in different contexts?
VI. Impact of the Proposed Codification of Industry Guide 2 on Other
Industry Guides
There currently are six Securities Act Industry Guides:
Guide 2--Disclosure of oil and gas operations;
Guide 3--Statistical disclosure by bank holding companies;
Guide 4--Prospectuses relating to interests in oil and gas
programs;
Guide 5--Preparation of registration statements relating
to interests in real estate limited partnerships;
Guide 6--Disclosures concerning unpaid claims and claim
adjustment expenses of property-casualty insurance underwriters; and
Guide 7--Description of property by issuers engaged, or to
be engaged, in significant mining operations.
There also are four Exchange Act Industry Guides:
Guide 2--Disclosure of oil and gas operations;
Guide 3--Statistical disclosure by bank holding companies;
Guide 4--Disclosures concerning unpaid claims and claim
adjustment expenses of property-casualty underwriters; and
Guide 7--Description of property by issuers engaged, or to
be engaged, in significant mining operations.
As discussed above, the specific disclosures that relate to oil and
gas operations currently are set forth in both Securities Act and
Exchange Act
[[Page 39550]]
Industry Guide 2, as well as Securities Act Industry Guide 4. The
codification of the Industry Guide 2 disclosures that we are proposing
in this release should not have any impact on the manner in which the
other Industry Guides are applied to company disclosures. Those guides
will remain in effect in their current form and companies in the
industries to which the guides relate will continue to include
disclosure in response to the guides in their Securities Act and
Exchange Act filings. In the future, the staff plans to review and
update each of the Industry Guides; as part of the initiative to update
a particular guide, we would propose to codify it as a new subpart of
Regulation S-K.
Request for Comment
Is it appropriate to codify Industry Guide 2 separately
from the other industry guides? Should we merely amend Industry Guide 2
and codify it with all of the other industry guides when they have been
updated?