[Federal Register Volume 74, Number 9 (Wednesday, January 14, 2009)]
[Rules and Regulations]
[Pages 2158-2197]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-409]



[[Page 2157]]

-----------------------------------------------------------------------

Part II





Securities and Exchange Commission





-----------------------------------------------------------------------



17 CFR Parts 210, 211 et al.



Modernization of Oil and Gas Reporting; Final Rule

  Federal Register / Vol. 74 , No. 9 / Wednesday, January 14, 2009 / 
Rules and Regulations  

[[Page 2158]]


-----------------------------------------------------------------------

SECURITIES AND EXCHANGE COMMISSION

17 CFR Parts 210, 211, 229, and 249

[Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08]
RIN 3235-AK00


Modernization of Oil and Gas Reporting

AGENCY: Securities and Exchange Commission.

ACTION: Final rule; interpretation; request for comment on Paperwork 
Reduction Act burden estimates.

-----------------------------------------------------------------------

SUMMARY: The Commission is adopting revisions to its oil and gas 
reporting disclosures which exist in their current form in Regulation 
S-K and Regulation S-X under the Securities Act of 1933 and the 
Securities Exchange Act of 1934, as well as Industry Guide 2. The 
revisions are intended to provide investors with a more meaningful and 
comprehensive understanding of oil and gas reserves, which should help 
investors evaluate the relative value of oil and gas companies. In the 
three decades that have passed since adoption of these disclosure 
items, there have been significant changes in the oil and gas industry. 
The amendments are designed to modernize and update the oil and gas 
disclosure requirements to align them with current practices and 
changes in technology. The amendments concurrently align the full cost 
accounting rules with the revised disclosures. The amendments also 
codify and revise Industry Guide 2 in Regulation S-K. In addition, they 
harmonize oil and gas disclosures by foreign private issuers with the 
disclosures for domestic issuers.

DATES: Effective Date: January 1, 2010.
    Comment Date: Comments on the Paperwork Reduction Act Analysis 
should be received on or before February 13, 2009.

ADDRESSES: Comments may be submitted by any of the following methods:

Electronic Comments

     Use the Commission's Internet comment form (http://www.sec.gov/rules/proposed.shtml); or
     Send an e-mail to [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: Ray Be, Special Counsel, Office of 
Chief Counsel at (202) 551-3500; Dr. W. John Lee, Academic Petroleum 
Engineering Fellow, or Brad Skinner, Senior Assistant Chief Accountant, 
Office of Natural Resources and Food at (202) 551-3740; Leslie Overton, 
Associate Chief Accountant, Office of Chief Accountant for the Division 
of Corporation Finance at (202) 551-3400, Division of Corporation 
Finance; or Mark Mahar, Associate Chief Accountant, Jonathan Duersch, 
Assistant Chief Accountant, or Doug Parker, Professional Accounting 
Fellow, Office of the Chief Accountant at (202) 551-5300; U.S. 
Securities and Exchange Commission, 100 F Street, NE., Washington, DC 
20549-3628.

SUPPLEMENTARY INFORMATION: We are adopting amendments to Rule 4-10 \1\ 
of Regulation S-X \2\ and Items 102, 801 and 802 \3\ of Regulation S-
K.\4\ We also are adding new Subpart 1200, including Items 1201 through 
1208, to Regulation S-K.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

Table of Contents

I. Introduction
    A. Background
    B. Issuance of the Concept Release
    C. Overview of the Comment Letters Received on the Proposing 
Release
II. Revisions and Additions to the Definition Section in Rule 4-10 
of Regulation S-X
    A. Introduction
    B. Pricing Mechanism for Oil and Gas Reserves Estimation
    1. 12-Month Average Price
    2. Prices Used for Disclosure and Accounting Purposes
    3. Alternate Pricing Schemes
    4. Time Period Over Which the Average Price Is To Be Calculated
    C. Extraction of Bitumen and Other Non-Traditional Resources
    1. Definition of ``Oil and Gas Producing Activities''
    2. Disclosure by Final Products
    D. Proved Oil and Gas Reserves
    E. Reasonable Certainty
    F. Developed and Undeveloped Oil and Gas Reserves
    1. Developed Oil and Gas Reserves
    2. Undeveloped Oil and Gas Reserves
    G. Reliable Technology
    1. Definition of the Term ``Reliable Technology''
    2. Disclosure of Technologies Used
    H. Unproved Reserves--``Probable Reserves'' and ``Possible 
Reserves''
    1. Probable Reserves
    2. Possible Reserves
    I. Reserves
    J. Other Supporting Terms and Definitions
    1. Deterministic Estimate
    2. Probabilistic Estimate
    3. Analogous Reservoir
    4. Definitions of Other Terms
    5. Proposed Terms and Definitions Not Adopted
    K. Alphabetization of the Definitions Section of Rule 4-10
III. Revisions to Full Cost Accounting and Staff Accounting Bulletin
IV. Updating and Codification of the Oil and Gas Disclosure 
Requirements in Regulation S-K
    A. Revisions to Items 102, 801, and 802 of Regulation S-K
    B. Proposed New Subpart 1200 to Regulation S-K Codifying 
Industry Guide 2 Regarding Disclosures by Companies Engaged in Oil 
and Gas Producing Activities
    1. Overview
    2. Item 1201 (General Instructions to Oil and Gas Industry-
Specific Disclosures)
    a. Geographic Area
    b. Tabular Disclosure
    3. Item 1202 (Disclosure of Reserves)
    a. Oil and Gas Reserves Tables
    i. Disclosure by Final Product Sold
    ii. Aggregation
    iii. Optional Disclosure of Probable and Possible Reserves
    iv. Resources Not Considered Reserves
    b. Optional Reserves Sensitivity Analysis Table
    c. Separate Disclosure of Conventional and Continuous 
Accumulations
    d. Preparation of Reserves Estimates or Reserves Audits
    e. Reserve Audits and the Contents of Third Party Reports
    f. Process Reviews
    4. Item 1203 (Proved Undeveloped Reserves)
    5. Item 1204 (Oil and Gas Production)
    6. Item 1205 (Drilling and Other Exploratory and Development 
Activities)
    7. Item 1206 (Present Activities)

[[Page 2159]]

    8. Item 1207 (Delivery Commitments)
    9. Item 1208 (Oil and Gas Properties, Wells, Operations, and 
Acreage)
V. Guidance for Management's Discussion and Analysis for Companies 
Engaged in Oil and Gas Producing Activities
VI. Conforming Changes to Form 20-F
VII. Impact of Amendments on Accounting Literature
    A. Consistency With FASB and IASB Rules
    B. Change in Accounting Principle or Estimate
    C. Differing Capitalization Thresholds Between Mining Activities 
and Oil and Gas Producing Activities
VIII. Application of Interactive Data Format to Oil and Gas 
Disclosures
IX. Implementation Date
    A. Mandatory Compliance
    B. Voluntary Early Compliance
X. Paperwork Reduction Act
    A. Background
    B. Summary of Information Collections
    C. Revisions to PRA Burden Estimates
    D. Request for Comment
XI. Cost-Benefit Analysis
    A. Background
    B. Description of New Rules and Amendments
    C. Benefits
    1. Average Price and First of the Month Price
    2. Probable and Possible Reserves
    3. Reserves Estimate Preparers and Reserves Auditors
    4. Development of Proved Undeveloped Reserves
    5. Disclosure Guidance
    6. Updating of Definitions Related to Oil and Gas Activities
    7. Harmonizing Foreign Private Issuer Disclosure
    D. Costs
    1. Probable and Possible Reserves
    2. Reserves Estimate Preparers and Reserves Auditors
    3. Consistency With IASB
    4. Change of Pricing Mechanism
    5. Disclosure of PUD Development
    6. Increased Geographic Disclosure
    7. Harmonizing Foreign Private Issuer Disclosure
XII. Consideration of Burden on Competition and Promotion of 
Efficiency, Competition, and Capital Formation
XIII. Final Regulatory Flexibility Analysis
    A. Reasons for, and Objectives of, the New Rules and Amendments
    B. Significant Issues Raised by Commenters
    C. Small Entities Subject to the New Rules and Amendments
    D. Reporting, Recordkeeping, and Other Compliance Requirements
    E. Agency Action to Minimize Effect on Small Entities
XIV. Update to Codification of Financial Reporting Policies
XV. Statutory Basis and Text of Amendments

I. Introduction

A. Background

    On June 26, 2008, the Commission issued a proposing release 
(Proposing Release) seeking public comment on proposed amendments to 
the disclosure requirements regarding oil and gas companies.\5\ These 
proposals encompassed issues that were previously addressed more 
generally in a concept release that the Commission issued on December 
12, 2007 (Concept Release),\6\ which solicited comment on possible 
revisions to the oil and gas reserves disclosure requirements specified 
in Rule 4-10 of Regulation S-X \7\ and Item 102 of Regulation S-K.\8\ 
The Proposing Release also contained proposals not addressed by the 
Concept Release related to the updating and codification of Industry 
Guide 2.
---------------------------------------------------------------------------

    \5\ Release No. 33-8935 (June 27, 2008) [73 FR 39181].
    \6\ Release No. 33-8870 (Dec. 12, 2007) [72 FR 71610].
    \7\ 17 CFR 210.4-10. See Release No. 33-6233 (Sept. 25, 1980) 
[45 FR 63660] (adopting amendments to Regulation S-X, including Rule 
4-10). The precursor to Rule 4-10 was Rule 3-18 of Regulation S-X, 
which was adopted in 1978. See Accounting Series Release No. 253 
(Aug. 31, 1978) [43 FR 40688]. See also Accounting Series Release 
No. 257 (Dec. 19, 1978) [43 FR 60404] (further amending Rule 3-18 of 
Regulation S-X and revising the definition of proved reserves).
    \8\ Item 102 of Regulation S-K [17 CFR 229.102]. In 1982, the 
Commission adopted Item 102 of Regulation S-K. Item 102 contains the 
disclosure requirements previously located in Item 2 of Regulation 
S-K. See Release No. 33-6383 (March 16, 1982) [47 FR 11380]. The 
Commission also ``recast * * * the disclosure requirements for oil 
and gas operations, formerly contained in Item 2(b) of Regulation S-
K, as an industry guide.'' See Release No. 33-6384 (Mar. 16, 1982) 
[47 FR 11476].
---------------------------------------------------------------------------

    We initially adopted our oil and gas disclosure requirements in 
1978 and 1982.\9\ Since that time, there have been significant changes 
in the oil and gas industry and markets, including technological 
advances, and changes in the types of projects in which oil and gas 
companies invest their capital.\10\ Prior to our issuance of the 
Concept Release and the Proposing Release, many industry participants 
had expressed concern that our disclosure rules are no longer in 
alignment with current industry practices and therefore limit their 
usefulness to the market and investors.\11\
---------------------------------------------------------------------------

    \9\ The disclosure requirements were introduced pursuant to a 
directive in the Energy Policy and Conservation Act of 1975 (the 
``EPCA''). The EPCA directed the Commission to ``take such steps as 
may be necessary to assure the development and observance of 
accounting practices to be followed in the preparation of accounts 
by persons engaged, in whole or in part, in the production of crude 
oil or natural gas in the United States.'' See 42 U.S.C. 6201-6422.
    \10\ See, for example, Daniel Yergin and David Hobbs: ``The 
Search for Reasonable Certainty in Reserves Disclosure,'' Oil and 
Gas Journal (July 18, 2005).
    \11\ See, for example, Greg Courturier, ``Standard & Poor's 
Urges SEC to Change Disclosure Rules,'' International Oil Daily 
(Dec. 3, 2007); Steve Levine, ``Tracking the Numbers: Oil Firms Want 
SEC to Loosen Reserves Rules,'' Wall Street Journal Online (Feb. 7, 
2006); Christopher Hope, ``Oil Majors Back Attack on SEC Rules,'' 
The Daily Telegraph (London) (Feb. 24, 2005); Barrie McKenna, 
``Rules undervalue reserves report says: Volumes buried in Canada's 
oil sands not counted by SEC's measure,'' The Globe & Mail (Canada) 
(Feb. 24, 2005); and ``Deloitte Calls on Regulators to Update Rules 
for Oil and Gas Reserves Reporting,'' Business Wire Inc. (Feb. 9, 
2005).
---------------------------------------------------------------------------

B. Issuance of the Concept Release

    The Concept Release addressed the potential implications for the 
quality, accuracy and reliability of oil and gas disclosure if the 
Commission were to:
     Revise the definition of ``proved reserves'' in our rules, 
in particular, the criteria used to assess and quantify resources that 
can be classified as proved reserves; and
     Expand the categories of resources that may be disclosed 
in Commission filings to include resources other than proved reserves.

In addition, the Concept Release questioned whether our revised 
disclosure rules should be modeled on any particular resource 
classification framework currently being used within the oil and gas 
industry. We also asked how any revised disclosure rules could be made 
flexible enough to address future technological innovation and changes 
within the oil and gas industry. The Concept Release sought further 
comment on whether the Commission should require independent third-
party assessments of reserves estimates that a company includes in its 
filings.
    In response to the Concept Release, commenters submitted 80 comment 
letters.\12\ We received comment letters from a variety of industry 
participants such as accounting firms, engineering consulting firms, 
domestic and foreign oil and gas companies, federal government 
agencies, individuals, law firms, professional associations, public 
interest groups, and rating agencies. We considered these comments and 
addressed many of them in issuing the Proposing Release.
---------------------------------------------------------------------------

    \12\ The public comments we received are available for 
inspection in the Commission's Public Reference Room at 100 F St., 
NE., Washington, DC 20549 in File No. S7-29-07. They are also 
available on-line at http://www.sec.gov/comments/s7-29-07/s72907.shtml.
---------------------------------------------------------------------------

C. Overview of the Comment Letters Received on the Proposing Release

    The Proposing Release sought significantly more detailed comment on 
issues raised in the Concept Release, as well as proposed amendments to 
the disclosure items in our rules and Industry Guide 2. In response to 
the Proposing Release, we received 65 comment letters, again from a 
variety of constituents with interests in oil and gas industry 
disclosure.

[[Page 2160]]

    Almost all commenters supported some form of revision to the 
current oil and gas disclosure requirements, particularly given the 
length of time that has elapsed since the requirements were initially 
adopted.\13\ Commenters provided significantly more detailed comments 
on the Proposing Release than on the Concept Release, which did not 
include specific proposed regulatory text. We discuss those comments in 
detail in the relevant sections of this release. However, in general, 
commenters focused on several key issues raised by the Proposing 
Release. These issues included the following:
---------------------------------------------------------------------------

    \13\ See letters from American Association of Petroleum 
Geologists (``AAPG''), American Clean Skies Foundation (``American 
Clean Skies''), American Petroleum Institute (``API''), AngloGold 
Ashanti Ltd. (``AngloGold''), Apache Corporation (``Apache''), BHP 
Billiton Petroleum (``BHP''), BP Plc. (``BP''), Brookwood Petroleum 
Advisors, Ltd. (``Brookwood''), Canadian Association of Petroleum 
Producers (``CAPP''), Canadian Natural Resources Ltd. (``Canadian 
Natural''), Center for Audit Quality (``CAQ''), Center for Corporate 
Policy (``CCP''), CFA Institute Centre for Financial Market 
Integrity (``CFA''), Chesapeake Energy Corporation (``Chesapeake''), 
Chevron Corporation (``Chevron''), Coeur d'Alene Mines Corporation 
(``Coeur''), Cunningham, Peter (``Cunningham''), Davis, Polk & 
Wardwell (``Davis Polk''), Deloitte & Touche (``Deloitte''), Devon 
Energy Corporation (``Devon''), EnCana Corporation (``EnCana''), 
Energen Corporation (``Energen''), Energy Information Administration 
(of DOE) (``EIA''), Eni S.p.A. (``Eni''), Equitable Resources, Inc. 
(``Equitable''), Ernst & Young (``E&Y''), Evolution Petroleum 
Corporation (``Evolution''), ExxonMobil Corporation 
(``ExxonMobil''), Federal Energy Regulatory Commission (``FERC''), 
Graff Consulting Group LLC (``Graff Consulting''), Grant Thornton 
(``Grant Thornton''), Imperial Oil Ltd. (``Imperial''), Independent 
Petroleum Association of America (``IPAA''), KPMG (``KPMG''), 
Luscher, Brian (``Luscher''), Magoto, Joseph (``Magoto''), McMoRan 
Exploration Co. (``McMoRan''), Newfield Exploration Company 
(``Newfield''), Nexen, Inc. (``Nexen''), Peabody Energy Corporation 
(``Peabody''), Petro-Canada (``Petro-Canada''), Petroleo Brasileiro 
S.A. (``Petrobras''), Petroleos Mexicanos (``PEMEX''), PRA 
International Ltd. (``PRA''), PriceWaterhouseCoopers (``PWC''), 
Questar Market Resources (``Questar''), RepsolYPF, S.A. 
(``Repsol''), Ross Petroleum Ltd. (``Ross''), Ryder Scott Company, 
L.P. (``Ryder Scott''), Sasol Ltd. (``Sasol''), Senator Robert 
Menendez, Senator Russell D. Feingold, and Senator Bernard Sanders, 
U.S. Senate (``Three Senators''), Shearman & Sterling (``Shearman & 
Sterling''), Shell International B.V. (``Shell''), Society of 
Exploration Geophysicists (``SEG''), Society of Petroleum Engineers 
(``SPE''), Society of Petroleum Evaluation Engineers (``SPEE''), 
Southwestern Energy Production Company (``Southwestern''), Standard 
Advantage (``Standard Advantage''), StatoilHydro (``StatoilHydro''), 
Swift Energy Company (``Swift''), Talisman Energy Inc. 
(``Talisman''), Total, S.A. (``Total''), van Wyk, Mike (``van 
Wyk''), Wagner, Robert (``Wagner''), Zakaib, Geoff (``Zakaib'').
---------------------------------------------------------------------------

     The proposal to permit disclosure of probable and possible 
reserves;
     The proposed use of average historical prices to represent 
existing economic conditions to determine the economic producibility of 
oil and gas reserves for disclosure purposes while continuing to use a 
single day year-end price to determine the economic producibility of 
reserves for accounting purposes;
     The proposed inclusion of bitumen, oil shales, and other 
resources in the definition of ``oil and gas producing activities'';
     The proposed provision to broaden the types of technology 
that a company may use to establish reserves estimates and categories;
     The proposed change in the definition of proved 
undeveloped reserves to eliminate the ``certainty'' requirement; and
     The increased detail of disclosure that would be required 
as a result of our proposed definition of ``geographic location.''

II. Revisions and Additions to the Definition Section in Rule 4-10 of 
Regulation S-X

A. Introduction

    The revisions and additions to the definition section in Rule 4-
10(a) of Regulation S-X \14\ update our reserves definitions to reflect 
changes in the oil and gas industry and markets and new technologies 
that have occurred in the decades since the current rules were adopted. 
Many of the definitions are designed to be consistent with the 
Petroleum Resource Management System (PRMS).\15\ Among other things, 
the revisions to these definitions address four issues that have been 
of particular interest to companies, investors, and securities 
analysts:
---------------------------------------------------------------------------

    \14\ 17 CFR 210.4-10(a).
    \15\ The Petroleum Resources Management System is a widely 
accepted standard for the management of petroleum resources 
developed by several industry organizations. See Society of 
Petroleum Engineers, the World Petroleum Council, American 
Association of Petroleum Geologists, and the Society of Petroleum 
Evaluation Engineers, Petroleum Resources Management System, SPE/
WPC/AAPG/SPEE (2007).
---------------------------------------------------------------------------

     The use of single-day year-end pricing to determine the 
economic producibility of reserves;
     The exclusion of activities related to the extraction of 
bitumen and other ``non-traditional'' resources from the definition of 
oil and gas producing activities;
     The limitations regarding the types of technologies that 
an oil and gas company may rely upon to establish the levels of 
certainty required to classify reserves; and
     The limitation in the current rules that permits oil and 
gas companies to disclose only their proved reserves.

The revisions of, and additions to, the Rule 4-10 definitions attempt 
to address these issues without sacrificing clarity and comparability, 
which provide protection and transparency to investors. In addition, to 
the extent appropriate, we have revised our proposals so that the final 
definitions are more consistent with terms and definitions in the PRMS 
to improve compliance and understanding of our new rules.

B. Pricing Mechanism for Oil and Gas Reserves Estimation

1. 12-Month Average Price
    The final rules define the term ``proved oil and gas reserves'' in 
part as ``those quantities of oil and gas, which, by analysis of 
geoscience and engineering data, can be estimated with reasonable 
certainty to be economically producible--from a given date forward, 
from known reservoirs, and under existing economic conditions, 
operating methods, and government regulations--prior to the time at 
which contracts providing the right to operate expire, unless evidence 
indicates that renewal is reasonably certain, regardless of whether 
deterministic or probabilistic methods are used for the estimation.'' 
The definition states that the economic producibility of a reservoir 
must be based on existing economic conditions. It specifies that, in 
calculating economic producibility, a company must use a 12-month 
average price, calculated as the unweighted arithmetic average of the 
first-day-of-the-month price for each month within the 12-month period 
prior to the end of the reporting period, unless prices are defined by 
contractual arrangements, excluding escalations based upon future 
conditions.\16\
---------------------------------------------------------------------------

    \16\ See Rule 4-10(a)(22)(v) [17 CFR 210.4-10(a)(22)(v)].
---------------------------------------------------------------------------

    Most commenters supported the use of a 12-month average price to 
serve as a proxy for existing economic conditions to determine the 
economic producibility of reserves.\17\ Some noted that a 12-month 
average price is considered to reflect ``current economic conditions'' 
by PRMS.\18\ They noted that the use of an average price would reduce 
the effects of short term volatility \19\ and seasonality,\20\ while

[[Page 2161]]

maintaining comparability of disclosures among companies.\21\
---------------------------------------------------------------------------

    \17\ See letters from AngloGold, Apache, API, BHP, BP, Canadian 
Natural, CAPP, Chesapeake, Chevron, Devon, EIA, EnCana, Equitable, 
Evolution, ExxonMobil, Newfield, Nexen, Petrobras, Petro-Canada, 
PWC, Questar, Repsol, Ryder Scott, Sasol, Shell, Southwestern, SPE, 
Total, and Wagner.
    \18\ See letters from AngloGold, BHP, Equitable, Ryder Scott, 
and SPE.
    \19\ See letters from Apache, API, BHP, BP, Canadian Natural, 
CAPP, Chesapeake, EIA, EnCana, Equitable, Evolution, ExxonMobil, 
Imperial, IPAA, Newfield, Petrobras, Petro-Canada, Repsol, Ryder 
Scott, SPE, Total, and Wagner.
    \20\ See letters from Apache, Canadian Natural, Devon, EnCana, 
Evolution, IPAA, Petro-Canada, Repsol, and Ryder Scott.
    \21\ See letters from BHP, Canadian Natural, CAPP, Deloitte, 
Devon, IPAA, Newfield, Petro-Canada, Total, and Wagner.
---------------------------------------------------------------------------

    Seven commenters recommended the use of first-of-the-month prices 
\22\ instead of the proposed use of end-of-the-month prices because the 
use of first-of-the-month prices would provide companies with more time 
to estimate their reserves \23\ and they thought that these prices 
better reflect the actual price received under typical natural gas 
contracts.\24\ Conversely, six commenters recommended the use of a 12-
month daily average price \25\ because they thought that a daily 
average price would be more appropriate than a monthly average price. 
These commenters noted that oil sales contracts often are based on 
daily averages.\26\ Two commenters expressed concern that end-of-the-
month prices are not representative of actual prices because commodity 
traders often ``clear their books'' at the end of the month.\27\
---------------------------------------------------------------------------

    \22\ See letters from Apache, BP, Chesapeake, Chevron, Devon, 
Repsol, and Shell.
    \23\ See letters from Chesapeake, Devon, and Shell.
    \24\ See letters from Apache, Newfield, and Repsol.
    \25\ See letters from Canadian Natural, CAPP, EnCana, Nexen, 
Petro-Canada, and Repsol.
    \26\ See letter from Newfield.
    \27\ See letters from Apache and Shell.
---------------------------------------------------------------------------

    One commenter opposed the use of average prices stating that, 
conceptually, the use of average prices is poor regulatory policy and 
may encourage the market to pressure standard setters to use historical 
average prices for financial instruments and other assets and 
liabilities associated with volatile markets.\28\ It noted that 
volatility reflects the underlying economics of the oil and gas 
industry.\29\
---------------------------------------------------------------------------

    \28\ See letter from CFA.
    \29\ See letter from CFA.
---------------------------------------------------------------------------

    The objective of reserves estimation is to provide the public with 
comparable information about volumes, not fair value, of a company's 
reserves available to enable investors to compare the business 
prospects of different companies. The use of a 12-month average 
historical price to determine the economic producibility of reserves 
quantities increases comparability between companies' oil and gas 
reserve disclosures, while mitigating any additional variability that a 
single-day price may have on reserve estimates. Although oil and gas 
prices themselves are subject to market-based volatility, the 
estimation of reserves quantities based on any historical price 
assumption determines those reserves quantities as if the oil or gas 
already has been produced, even though they have not, and these 
measures do not attempt to portray a reflection of their fair value. If 
the objective of reserve disclosures were to provide fair value 
information, we believe a pricing system that incorporates assumptions 
about estimated future market prices and costs related to extraction 
could be a more appropriate basis for estimation.
    In order to provide disclosures which are more consistent with the 
objective of comparability, the amendments state that the existing 
economic conditions for determining the economic producibility of oil 
and gas reserves include the 12-month average price, calculated as the 
unweighted arithmetic average of the first-day-of-the-month price for 
each month within the 12-month period prior to the end of the reporting 
period.\30\ For example, a company with a reporting year end of 
December 31 would determine its reserves estimates for its annual 
report based on the average of the prices for oil or gas on the first 
day of every month from January through December. Therefore, the use of 
a 12-month average price provides companies with the ability to 
efficiently prepare useful reserve information without sacrificing the 
objective of comparability. We believe that the revised definition of 
the term ``proved oil and gas reserves'' will provide investors with 
improved reserves information thereby enhancing their ability to 
analyze the disclosures.
---------------------------------------------------------------------------

    \30\ See new Rule 4-10(a)(22)(v) of Regulation S-X [17 CFR 
210.4-10(a)(22)(v)].
---------------------------------------------------------------------------

2. Prices Used for Disclosure and Accounting Purposes
    A proposal that resulted in significant comment was the use of a 
12-month average price to estimate reserves for disclosure purposes, 
but a single-day, year-end price for accounting purposes.\31\ All 
commenters addressing the issue of using different prices to determine 
reserves for disclosure and accounting opposed the proposal.\32\ We are 
not adopting this aspect of the proposal. Instead, we are revising both 
our disclosure rules and our full-cost accounting rules related to oil 
and gas reserves to use a single price based on a 12-month average.\33\ 
We also will continue to communicate with the FASB staff to align their 
accounting standards with these rules.
---------------------------------------------------------------------------

    \31\ Currently, companies use a single-day, year-end price to 
determine the quantity of its proved reserves. From an accounting 
perspective, the quantity of those reserves, while not included on 
the balance sheet, is used to determine the depreciation, depletion 
and amortization of certain capitalized costs included on the 
balance sheet. If the final rule retained a single-day, year-end 
price for determining reserves for accounting purposes (i.e. , for 
determining depreciation, depletion and amortization), then 
companies would effectively be required to calculate reserves twice, 
using two different pricing assumptions--once for disclosure 
purposes and once for accounting purposes. Similarly, under the full 
cost rules, the full cost ceiling test, as described in Section III 
of this release, would have similar implications.
    \32\ See letters from Apache, API, Audit Quality, BHP, BP, 
Canadian Natural, CAPP, CFA, Chesapeake, Chevron, Deloitte, Devon, 
E&Y, EnCana, Energen, Eni, Equitable, Evolution, ExxonMobil, Grant 
Thornton, Imperial, KPMG, McMoRan, Newfield, Nexen, PEMEX, 
Petrobras, Petro-Canada, PWC, Questar, Repsol, Ross, Ryder Scott, 
Sasol, Shell, Southwestern, SPEE, StatoilHydro, Swift, Talisman, 
Total, and Wagner.
    \33\ See Rule 4-10.
---------------------------------------------------------------------------

    Commenters pointed out that the use of two different prices for 
disclosure and accounting purposes could:
     Confuse investors and other users of financial 
statements.\34\
---------------------------------------------------------------------------

    \34\ See letters from Audit Quality, BHP, Canadian Natural, 
CAPP, Chesapeake, Deloitte, Devon, Evolution, ExxonMobil, Imperial, 
Newfield, Nexen, Petrobras, Petro-Canada, PWC, Questar, Repsol, 
Ryder Scott, Shell, Swift, Talisman, Total, and Wagner.
---------------------------------------------------------------------------

     Create misleading information; \35\
---------------------------------------------------------------------------

    \35\ See letters from BP, CFA, Devon, Eni, Nexen, Repsol, and 
Wagner.
---------------------------------------------------------------------------

     Harm comparability; \36\
---------------------------------------------------------------------------

    \36\ See letters from Apache, Canadian Natural, CAPP, Questar, 
StatoilHydro, and Wagner.
---------------------------------------------------------------------------

     Decrease transparency; \37\
---------------------------------------------------------------------------

    \37\ See letters from Canadian Natural, CAPP, ExxonMobil, Shell, 
Swift, and Wagner.
---------------------------------------------------------------------------

     Increase costs and burden significantly; \38\
---------------------------------------------------------------------------

    \38\ See letters from Apache, Audit Quality, BHP, Canadian 
Natural, CAPP, Chevron, Deloitte, Devon, Eni, Equitable, Evolution, 
ExxonMobil, Imperial, McMoRan, Newfield, Nexen, Petrobras, Questar, 
Petro-Canada, PWC, Ryder Scott, Shell, Swift, Total, and Wagner.
---------------------------------------------------------------------------

     Increase the complexity of disclosures; \39\
---------------------------------------------------------------------------

    \39\ See letters from CAPP, CFA, and Devon.
---------------------------------------------------------------------------

     Double recordkeeping burden; \40\
---------------------------------------------------------------------------

    \40\ See letters from Apache, Chesapeake, Eni, Equitable, and 
Imperial.
---------------------------------------------------------------------------

     Require more disclosure to explain the differences in 
reserves estimates; and \41\
---------------------------------------------------------------------------

    \41\ See letters from CAPP, Devon, Eni, ExxonMobil, Imperial, 
and Wagner.
---------------------------------------------------------------------------

     Break the connection between disclosures and 
accounting.\42\
---------------------------------------------------------------------------

    \42\ See letters from Apache, Audit Quality, CAPP, CFA, 
Deloitte, E&Y, Energen, Eni, ExxonMobil, Imperial, KPMG, Newfield, 
PWC, Repsol, and Total.
---------------------------------------------------------------------------

    Some commenters noted that the disclosure and accounting rules and 
guidance do not use a different pricing method in other situations.\43\ 
In addition, several commenters believed that changing to the use of an 
average price to estimate proved reserves would have a minimal impact 
on depreciation and net income.\44\ We believe that changing the rules 
to use a 12-month average price in reserves estimations is

[[Page 2162]]

not inconsistent with the principles and objectives of financial 
reporting in authoritative accounting guidance.
---------------------------------------------------------------------------

    \43\ See letters from API, CAPP, and Shell.
    \44\ See letters from API, Canadian Natural, EnCana, ExxonMobil, 
and Total.
---------------------------------------------------------------------------

    With respect to accounting pronouncements that currently make 
reference to a single-day pricing regime with respect to oil and gas 
reserves, we are communicating with the FASB staff to align the 
standards used in its pronouncements with the 12-month average price 
used in our new rules, as several commenters recommended.\45\ As 
discussed in more detail below, we are adopting a compliance date that 
will provide sufficient time to coordinate such activities with the 
FASB. However, as we discuss our revisions with the FASB, we will 
consider whether to delay the compliance date further.
---------------------------------------------------------------------------

    \45\ See letters from Apache, BHP, Canadian Natural, CAPP, CFA, 
Deloitte, McMoRan, Newfield, Nexen, Questar, Southwestern, Talisman, 
and Total.
---------------------------------------------------------------------------

3. Alternate Pricing Schemes
    Some commenters on the Proposing Release believed that oil and gas 
futures prices, or management's forecast of future prices, would better 
represent the value of the reserves \46\ and be better aligned with 
fair value of the reserves.\47\ They indicated that management uses 
futures prices, not historical prices, in its planning and day-to-day 
decision making.\48\ They suggested that the use of futures prices, 
combined with disclosure of how management made the estimates, would 
provide greater transparency \49\ and comparability of disclosure.\50\ 
One noted that historical prices have little to do with a company's 
future investments and values.\51\ Another commenter noted that 
differentials can be calculated through established accounting 
procedures under SFAS 157.\52\
---------------------------------------------------------------------------

    \46\ See letters from CFA, Deloitte, Grant Thornton, and 
McMoRan.
    \47\ See letters from CFA and Deloitte.
    \48\ See letters from CFA, Grant Thornton, and McMoRan.
    \49\ See letter from Deloitte.
    \50\ See letters from Deloitte and McMoRan.
    \51\ See letter from McMoRan.
    \52\ See letter from CFA.
---------------------------------------------------------------------------

    However, other commenters argued that futures prices are not 
available for all reserves locations \53\ and that applying 
differentials to prices would require subjective estimates and reduce 
comparability among companies.\54\ Two commenters noted that standard 
prices are not consistently available in some geographic regions.\55\ 
Similarly, two commenters were concerned that futures price estimates 
would have to be accompanied by estimates of future costs, which they 
thought would be very subjective and not comparable for determining 
future economic conditions.\56\ One commenter asserted that the use of 
future prices would require companies to document assumptions about 
future costs, or else the disclosure would be very inconsistent among 
reporting companies.\57\ Three commenters believed that futures prices 
are more subject to market perceptions than market realities and are 
seldom used in actual physical trading of oil and gas.\58\
---------------------------------------------------------------------------

    \53\ See letters from ExxonMobil and Wagner.
    \54\ See letters from EnCana, Evolution, ExxonMobil, Newfield, 
Ryder Scott, and Total.
    \55\ See letters from Ryder Scott and Total.
    \56\ See letters from SPE and Total.
    \57\ See letter from SPE.
    \58\ See letters from Evolution, Ryder Scott, and Wagner.
---------------------------------------------------------------------------

    We share the concerns of many of these commenters that 
determinations of expected future prices could require significant 
estimations which could fall into a wide, albeit reasonable, range. For 
example, in many situations and parts of the world, natural gas is sold 
through longer term contracts where observable market inputs are not 
widely available. As a result, there could be less comparability among 
different companies depending on their assumptions, which are inherent 
in determining futures prices. Difference in assumptions between 
companies could reduce the comparability of reserves information 
between those companies.
    We believe that the purpose of disclosing reserves estimates is to 
provide investors with information that is both meaningful and 
comparable. The reserves estimates in our disclosure rules, however, 
are not designed to be, nor are they intended to represent, an 
estimation of the fair market value of the reserves. Rather, the 
reserves disclosures are intended to provide investors with an 
indication of the relative quantity of reserves that is likely to be 
extracted in the future using a methodology that minimizes the use of 
non-reserves-specific variables. By eliminating assumptions underlying 
the pricing variable, as any historical pricing method would do, 
investors are able to compare reserves estimates where the differences 
are driven primarily by reserves-specific information, such as the 
location of the reserves and the grade of the underlying resource. We 
recognize that energy markets are continuing to develop. Therefore, we 
are not adopting a rule that requires companies to use futures prices 
to estimate reserves at this time.
4. Time Period Over Which the Average Price Is To Be Calculated
    Numerous commenters on the Proposing Release recommended that the 
12-month period used to calculate the average price for estimating 
reserves should not coincide with the fiscal year, as we proposed.\59\ 
Most of these commenters recommended a 12-month period running from the 
beginning of the fourth quarter of the prior fiscal year through the 
end of the third quarter of the present fiscal year. For example, for a 
company with a fiscal year end of December 31, the relevant 12-month 
period would span from October 1 of the prior year to September 30 of 
the fiscal year covered by the annual report.\60\ Several commenters 
suggested that we provide a two-month buffer between the end of the 
measurement period and the end of the company's fiscal year so that 
reserves estimates would be based on prices from November 1 through 
October 31 by a company with a fiscal year ending on December 31.\61\ 
Commenters attributed the need for a buffer period to the accelerated 
filing dates for annual reports \62\ and stated that they expected that 
the additional time would result in better, more accurate 
disclosure.\63\ Others noted that some agreements, like production 
sharing contracts and other complex concession agreements, can make 
calculations difficult.\64\ One commenter also noted that shifting the 
relevant measurement period so that it ends three-months prior to the 
fiscal-year end would align economic calculations with technical 
calculations, which typically occur at the end of the third 
quarter.\65\
---------------------------------------------------------------------------

    \59\ See letters from Apache, API, BP, Canadian Natural, CAPP, 
EnCana, Eni, ExxonMobil, PEMEX, Petro-Canada, Repsol, Ryder Scott, 
Sasol, Shell, Total, van Wyk, and Wagner.
    \60\ See letters from Apache, API, BP, Canadian Natural, CAPP, 
Devon, Eni, ExxonMobil, PEMEX, Petro-Canada, Repsol, Ryder Scott, 
Sasol, Shell, Total, van Wyk, and Wagner.
    \61\ See letters from Canadian Natural, CAPP, Eni, Nexen, and 
Petro-Canada.
    \62\ See letters from API, Canadian Natural, CAPP, Devon, 
Evolution, PEMEX, Petrobras, Ryder Scott, Sasol, Shell, Total, and 
Wagner.
    \63\ See letters from Canadian Natural, CAPP, Nexen, Petrobras, 
Petro-Canada, Ryder Scott, Sasol, and Wagner.
    \64\ See letters from API and Shell.
    \65\ See letter from Shell.
---------------------------------------------------------------------------

    As noted above, we have considered all of these recommendations. We 
are adopting a pricing formula based on the average of prices at the 
beginning of each month in the 12-month period prior to the end of the 
reporting period. A number of commenters believed that the use of 
first-of-the-month prices essentially would provide companies with one 
month more to prepare the reserves disclosures,\66\ while still

[[Page 2163]]

aligning the time period with the fiscal year.\67\ We agree with the 
commenters that such an average will provide companies more time to 
prepare more accurate disclosure, while still tying the pricing formula 
to the period covered by the annual report.
---------------------------------------------------------------------------

    \66\ See letters from API, Devon, Eni, Evolution, ExxonMobil, 
PEMEX, Petrobras, PWC, Repsol, and Total.
    \67\ See letters from Devon and ExxonMobil.
---------------------------------------------------------------------------

C. Extraction of Bitumen and Other Non-Traditional Resources

1. Definition of ``Oil and Gas Producing Activities''
    Our current definition of ``oil and gas producing activities'' 
explicitly excludes sources of oil and gas from ``non-traditional'' or 
``unconventional'' sources, that is, sources that involve extraction by 
means other than ``traditional'' oil and gas wells.\68\ These other 
sources include bitumen extracted from oil sands, as well as oil and 
gas extracted from coal and shales, even though some of these resources 
are sometimes extracted through wells, as opposed to mining and surface 
processing. However, such sources are increasingly providing energy 
resources to the world due in part to advancements in extraction and 
processing technology.\69\ Therefore, the rules we adopt today revise 
the definition of ``oil and gas producing activities'' to include such 
activities.\70\
---------------------------------------------------------------------------

    \68\ See Rule 4-10(a)(1)(ii)(D) [17 CFR 210.4-10(a)(1)(ii)(D)].
    \69\ Commenters noted that unconventional resources currently 
represent 45% of natural gas production in the U.S. See letters from 
American Clean Skies and IPAA.
    \70\ See Rule 4-10(a)(16) [17 CFR 210.4-10(a)(16)].
---------------------------------------------------------------------------

    All commenters on this issue supported including the extraction of 
unconventional resources as oil and gas producing activities.\71\ They 
believed that such inclusion would greatly improve the quality and 
completeness of the disclosures.\72\ Eight commenters noted that 
inclusion would better align disclosure with the way that companies 
view their operations.\73\ Some noted that, although the distinction 
was reasonable decades ago when traditional resources dominated oil and 
gas production, the reality of today is that such unconventional 
resources are mainstream and companies invest significant amounts of 
capital to develop these resources.\74\
---------------------------------------------------------------------------

    \71\ See letters from American Clean Skies, Apache, API, 
Canadian Natural, CAPP, CAQ, CFA, Davis Polk, Devon, E&Y, EnCana, 
ExxonMobil, FERC, Imperial, IPAA, KPMG, Nexen, Petrobras, Petro-
Canada, PRA, PWC, Repsol, Ryder Scott, Sasol, Shell, SPE, 
StatoilHydro, Talisman, Total, and Wagner.
    \72\ See letters from API, CAPP, CAQ, ExxonMobil, Imperial, PWC, 
Repsol, Ryder Scott, Total, and Wagner.
    \73\ See letters from API, CAQ, E&Y, ExxonMobil, Imperial, 
Petro-Canada, PWC, and Total.
    \74\ See letters from Imperial, IPAA, Repsol, and Total.
---------------------------------------------------------------------------

    The revised definition of ``oil and gas producing activities'' that 
we adopt today includes the extraction of the non-traditional resources 
described above.\75\ This amendment is intended to shift the focus of 
the definition of ``oil and gas producing activities'' to the final 
product of such activities, regardless of the extraction technology 
used. The amended definition states specifically that oil and gas 
producing activities include the extraction of saleable hydrocarbons, 
in the solid, liquid, or gaseous state, from oil sands, shale, 
coalbeds, or other nonrenewable natural resources which are intended to 
be upgraded into synthetic oil or gas, and activities undertaken with a 
view to such extraction.\76\
---------------------------------------------------------------------------

    \75\ See Rule 4-10(a)(16) [17 CFR 210.4-10(a)(16)].
    \76\ A hydrocarbon product is saleable if it is in a state in 
which it can be sold even if there is no ready market for that 
hydrocarbon product in the geographic location of the project. The 
absence of a market does not preclude the activity from being 
considered an oil and gas producing activity. However, in order to 
claim reserves for that hydrocarbon product from a particular 
location, there must be a market, or a reasonable expectation of a 
market, for that product.
---------------------------------------------------------------------------

    Currently, two types of natural resources pose a unique problem to 
establishing oil and gas reserves. Coal and, to a lesser degree, oil 
shale are used both as direct fuel and as feedstock to be converted 
into oil and gas. In response to our request for comment on how best to 
treat these resources, several commenters recommended that the 
extraction of coal \77\ and oil shale \78\ be categorized based on the 
final product. One commenter noted that investment decisions are based 
on the value and disposition of the final product.\79\ We agree with 
these commenters and have revised the proposal to require a company to 
include coal and oil shale that is intended to be converted into oil 
and gas as oil and gas reserves. The adopted rules also, however, 
prohibit a company from including coal and oil shale that is not 
intended to be converted into oil and gas as oil and gas reserves.
---------------------------------------------------------------------------

    \77\ See letters from CAPP, ExxonMobil, Ryder Scott, Sasol, 
Shell, StatoilHydro, and Wagner.
    \78\ See letters from CAPP, ExxonMobil, Shell, StatoilHydro, and 
Wagner.
    \79\ See letter from ExxonMobil.
---------------------------------------------------------------------------

2. Disclosure by Final Products
    We proposed that disclosure of reserves would be organized based on 
the pre-processed resource extracted from the ground. For example, 
under the proposal, a company that extracted bitumen and processed that 
bitumen into synthetic crude oil in its own processing plant would have 
had to base its reserves disclosure on the amount of bitumen that was 
economically producible, not taking into account the economics of the 
processing plant. This proposal was consistent with our traditional 
separation of ``upstream'' activities such as drilling and producing 
oil and gas from ``downstream'' activities such as refining. 
Distinguishing between traditional resources and unconventional 
resources can be significant to investors because unconventional 
resources often involve significantly different economics and company 
resources than oil and gas from traditional wells.
    Several commenters disagreed with our proposal, recommending that 
the determining factor should be the final product.\80\ They believed 
that a company should be able to consider the prices of self-processed 
resources when estimating oil and gas reserves because the economics of 
the processing plant are critical to the registrant's evaluation of the 
economic producibility of the resources.\81\ One commenter was 
concerned that distinguishing bitumen or other intermediate product 
from traditional oil and gas creates a false and misleading sense of 
comparability because producers that upgrade bitumen and sell synthetic 
crude do not face the same risks and rewards as do producers who sell 
the bitumen itself.\82\
---------------------------------------------------------------------------

    \80\ See letters from Apache, Nexen, Petrobras, and Ryder Scott.
    \81\ See letters from Apache, CAQ, and Nexen.
    \82\ See letter from Nexen.
---------------------------------------------------------------------------

    We are persuaded by these commenters. However, we believe that the 
distinction between a company's traditional and unconventional 
activities is an important one from an investor's perspective because 
many of the unconventional activities are costlier and, therefore, have 
a much higher threshold of economic producibility. Therefore, we are 
revising the proposed table in Item 1202 to require separation of 
reserves based on final product, but distinguishing between final 
products that are traditional oil or gas from final products of 
synthetic oil or gas. We believe that with this separate disclosure, 
investors will be able to identify resources in projects that produce 
synthetic oil or gas that may be more sensitive to economic conditions 
from other resources.
    In addition, as proposed, we are amending the definition of ``oil 
and gas producing activities'' to include activities relating to the 
processing or upgrading of natural resources from which synthetic oil 
or gas can be

[[Page 2164]]

extracted. However, the definition would continue to exclude:
     Transporting, refining, processing (other than field 
processing of gas to extract liquid hydrocarbons by the company and the 
upgrading of natural resources extracted by the company other than oil 
or gas into synthetic oil or gas) or marketing oil and gas;
     The production of natural resources other than oil, gas, 
or natural resources from which synthetic oil and gas can be extracted; 
and
     The production of geothermal steam.

D. Proved Oil and Gas Reserves

    We proposed to significantly revise the definition of ``proved oil 
and gas reserves.'' We are adopting that definition, substantially as 
proposed.\83\ However, as noted above, we have decided to base the 
price used to establish economic producibility on the average price 
during the 12-month period prior to the ending date of the period 
covered by the report, determined as an unweighted arithmetic average 
of the first-day-of-the-month price for each month within such period.
---------------------------------------------------------------------------

    \83\ See Rule 4-10(a)(22) [17 CFR 210.4-10(a)(22)].
---------------------------------------------------------------------------

    One commenter recommended against using an average price to 
calculate existing economic conditions if the price is set by 
contractual arrangements.\84\ We agree that under such circumstances, 
the appropriate price to use for establishing economic producibility is 
the price set by those contractual arrangements. Therefore, we have 
revised the definition to reflect that situation.\85\
---------------------------------------------------------------------------

    \84\ See letter from SPE.
    \85\ See Rule 4-10(a)(22)(v) [17 CFR 210.4-10(a)(22)(v)].
---------------------------------------------------------------------------

    The existing definition of the term ``proved oil and gas reserves'' 
incorporates certain specific concepts such as ``lowest known 
hydrocarbons'' which limit a company's ability to claim proved reserves 
in the absence of information on fluid contacts in a well 
penetration,\86\ notwithstanding the existence of other engineering and 
geoscientific evidence.\87\ We proposed revisions to the definition 
that would permit the use of new reliable technologies to establish the 
reasonable certainty of proved reserves. The proposed revisions to the 
definition of ``proved oil and gas reserves'' also included provisions 
for establishing levels of lowest known hydrocarbons and highest known 
oil through reliable technology other than well penetrations. We are 
adopting those revisions as proposed.
---------------------------------------------------------------------------

    \86\ In certain circumstances, a well may not penetrate the area 
at which the oil makes contact with water. In these cases, the 
company would not have information on the fluid contact and must use 
other means to estimate the lower boundary depths for the reservoir 
in which oil is located.
    \87\ See previous Rule 4-10(a)(2)(i) [17 CFR 210.4-10(a)(2)(i)].
---------------------------------------------------------------------------

    We also are adopting, as proposed, revisions that permit a company 
to claim proved reserves beyond those development spacing areas that 
are immediately adjacent to developed spacing areas if the company can 
establish with reasonable certainty that these reserves are 
economically producible.\88\ These revisions are designed to permit the 
use of alternative technologies to establish proved reserves in lieu of 
requiring companies to use specific tests. In addition, they establish 
a uniform standard of reasonable certainty that applies to all proved 
reserves, regardless of location or distance from producing wells.
---------------------------------------------------------------------------

    \88\ See Rule 4-10(a)(22) [17 CFR 210.4-10(a)(22)]. See Section 
II.G for a more detailed discussion regarding this provision.
---------------------------------------------------------------------------

E. Reasonable Certainty

    Both the existing definition of the term ``proved oil and gas 
reserves,'' and the definition of that term that we are adopting in 
this release, rely on the term ``reasonable certainty,'' which 
previously was not defined in Rule 4-10. In the Proposing Release, we 
proposed to define the term ``reasonable certainty'' as ``much more 
likely to be achieved than not'' to avoid ambiguity in that term's 
meaning. However, several commenters recommended that the rules mirror 
the PRMS definition more closely.\89\ Four commenters were concerned 
that a different definition from the PRMS would cause confusion. They 
recommended using the PRMS standard of ``high degree of confidence that 
the quantities will be recovered.'' \90\ One commenter recommended 
that, because the proposed definition is new, the Commission should 
adopt a safe harbor, to avoid potential uncertainty until a court 
interprets the phrase.\91\ But others believed that the proposed 
definition is consistent with the PRMS definition.\92\ One commenter 
opined that the concept of estimated ultimate recovery (EUR) is 
appropriate to establish proved oil and gas reserves.\93\
---------------------------------------------------------------------------

    \89\ See letters from EIA, ExxonMobil, and Zakaib.
    \90\ See letters from Apache, EIA, Energen, and SPE.
    \91\ See letter from Evolution.
    \92\ See letters from EnCana, ExxonMobil, Petrobras, and Ryder 
Scott.
    \93\ Total.
---------------------------------------------------------------------------

    We believe that the terms ``high degree of confidence'' from the 
PRMS and ``much more likely to be achieved than not'' in our proposal 
have the same meaning. Our proposed language was not intended to change 
the level of certainty required to establish reasonable certainty. 
However, we agree that the use of terminology that is consistent with 
the PRMS will assist in the understanding of those terms. Therefore, we 
are adopting the ``high degree of confidence'' standard that exists in 
the PRMS. We also are clarifying that having a ``high degree of 
confidence'' means that a quantity is ``much more likely to be achieved 
than not, and, as changes due to increased availability of geoscience 
(geological, geophysical, and geochemical), engineering, and economic 
data are made to estimated ultimate recovery (EUR) with time, 
reasonably certain EUR is much more likely to increase or remain 
constant than to decrease'' to provide elaboration to the definition of 
reasonable certainty.
    We are adopting a definition of ``reasonable certainty'' that 
addresses, and permits the use of, both deterministic methods and 
probabilistic methods for estimating reserves, as proposed. Nine 
commenters supported permitting the use of either deterministic methods 
or probabilistic methods.\94\ One commenter believed that each method 
may be more appropriate for different situations.\95\ Other commenters 
also supported the proposed alignment of the definitions of those terms 
with the definitions in the PRMS definitions.\96\ The definition that 
we are adopting states that, if deterministic methods are used, 
reasonable certainty means a high degree of confidence that the 
quantities will be recovered.\97\ Consistent with the PRMS definition, 
if probabilistic methods are used, there should be at least a 90% 
probability that the quantities actually recovered will equal or exceed 
the estimate.
---------------------------------------------------------------------------

    \94\ See letters from Apache, Devon, Evolution, Petro-Canada, 
Ryder Scott, Shell, SPE, Total, and Wagner.
    \95\ See letter from Wagner.
    \96\ See letters from AAPG, SPE, and Southwestern.
    \97\ See Rule 4-10(a)(24) [17 CFR 210.4-10(a)(24)].
---------------------------------------------------------------------------

F. Developed and Undeveloped Oil and Gas Reserves

    We proposed to revise the definitions of the terms ``proved 
developed oil and gas reserves'' and ``proved undeveloped oil and gas 
reserves.'' One commenter noted that the terms ``developed'' and 
``undeveloped'' are not restricted to proved oil and gas reserves, but 
could apply to all classifications of reserves, including probable and 
possible reserves.\98\ We agree with that

[[Page 2165]]

commenter. Although the development of a prospect may provide the 
company with more information and data to determine reserves amounts 
more accurately, companies may estimate proved, probable, and possible 
volumes regardless of the development stage. In the past, these terms 
were linked to the concept of proved reserves because our disclosure 
rules permitted the disclosure only of proved reserves. In light of our 
revision to allow disclosure of probable and possible reserves, the 
final rules define the terms ``developed oil and gas reserves'' and 
``undeveloped oil and gas reserves'' to indicate that the development 
status of the reserves is relevant to all classifications of oil and 
gas reserves.\99\
---------------------------------------------------------------------------

    \98\ See letter from SPE. We note that with respect to oil and 
gas reserves, the term ``classification'' is used to indicate the 
level of certainty that estimated amounts will be recovered. Thus, 
although the terms ``developed'' and ``undeveloped'' may be 
considered means in which to generically ``classify'' reserves, for 
clarity, we use that term to be consistent with industry usage.
    \99\ See Rules 4-10(a)(6) and (31) [17 CFR 210.4-10(a)(6) and 
(31)].
---------------------------------------------------------------------------

1. Developed Oil and Gas Reserves
    Other than the change discussed above to eliminate ``proved'' from 
the term being defined, we are adopting a definition of ``developed oil 
and gas reserves'' substantially as proposed. We proposed to define the 
term ``proved developed oil and gas reserves'' as proved reserves that:
     In projects that extract oil and gas through wells, can be 
expected to be recovered through existing wells with existing equipment 
and operating methods; and
     In projects that extract oil and gas in other ways, can be 
expected to be recovered through extraction technology installed and 
operational at the time of the reserves estimate.
    Two commenters suggested that, consistent with the PRMS, reserves 
should be considered developed if the cost of any required equipment is 
relatively minor compared to the cost of a new well or the installed 
equipment.\100\ Again, we agree that consistency with PRMS would 
improve compliance with our rules. In addition, such a revision is 
consistent with our existing definition of the term ``proved 
undeveloped reserves'' which includes reserves on which a well exists, 
but a relatively ``major'' expenditure is required for 
recompletion.\101\ Therefore, the final rules provide that reserves 
also are developed if the cost of any required equipment is relatively 
minor compared to the cost of a new well.\102\
---------------------------------------------------------------------------

    \100\ See letters from SPE and Total.
    \101\ See previous Rule 4-10(a)(4) [17 CFR 210.4-10(a)(4)].
    \102\ See Rule 4-10(a)(6) [17 CFR 210.4-10(a)(6)].
---------------------------------------------------------------------------

2. Undeveloped Oil and Gas Reserves
    In the Proposing Release, we proposed a significantly revised 
definition of the term ``proved undeveloped oil and gas reserves.'' The 
most significant aspect of the proposed revision was the replacement of 
the existing ``certainty'' test for areas beyond one offsetting 
drilling unit \103\ from a productive well with a ``reasonable 
certainty'' test. Currently, the definition of the term ``proved 
undeveloped reserves'' imposes a ``reasonable certainty'' standard for 
reserves in drilling units immediately adjacent to the drilling unit 
containing a producing well and a ``certainty'' standard for reserves 
in drilling units beyond the immediately adjacent drilling units.\104\ 
All commenters on this issue supported the proposal.\105\ Three 
commenters noted that a single standard-reasonable certainty-should 
apply to all proved reserves.\106\ We are adopting this aspect of the 
definition as proposed.
---------------------------------------------------------------------------

    \103\ As noted later in this section of the release, we are 
replacing the term ``drilling unit'' with the term ``development 
spacing area'' in the final rules. However, for purposes of 
discussing the proposal and the existing rules, we continue to use 
the term ``drilling unit'' because that is the term used in the 
proposal and the existing rules.
    \104\ See previous Rule 4-10(a)(4) [17 CFR 210.4-10(a)(4)]. A 
drilling unit refers to the spacing between wells required by some 
local jurisdictions to prevent wasting resources and optimize 
recovery.
    \105\ See letters from American Clean Skies, Apache, API, 
Canadian Natural, CAPP, Chesapeake, Devon, Evolution, ExxonMobil, 
McMoRan, Petro-Canada, Questar, Repsol, Southwestern, Shell, SPE, 
Total, and Wagner.
    \106\ See letters from Devon, EnCana, and Equitable.
---------------------------------------------------------------------------

    Many commenters opposed the proposed language that would have 
imposed a five-year limit on maintaining undeveloped reserves unless 
``unusual'' circumstances existed.\107\ They asserted that large 
projects, projects in remote areas, and projects in continuous 
accumulations, such as oil sands, typically take more than five years 
to develop, but they do not view such projects as ``unusual.'' \108\ 
One commenter noted that the proposed rule is not consistent with the 
PRMS, which uses the term ``specific circumstances,'' rather than 
``unusual circumstances.'' \109\ Other commenters suggested that we 
require the company to explain why it has not developed any undeveloped 
reserves for more than five years.\110\ The intent of the proposal was 
not to exclude projects that typically take more than five years to 
develop from being considered reserves. We agree that the rule should 
allow the recognition of reserves in projects that are expected to run 
more than five years, regardless of whether ``unusual'' circumstances 
exist. Therefore, we have revised the rule to replace the term 
``unusual'' with the term ``specific.'' \111\ We note that, as 
proposed, Item 1203 of Regulation S-K would require disclosure 
regarding why such undeveloped reserves have not been developed.\112\
---------------------------------------------------------------------------

    \107\ See letters from American Clean Skies, Apache, CAPP, 
Chesapeake, EnCana, ExxonMobil, Luscher, Newfield, Nexen, Petrobras, 
Petro-Canada, Ryder Scott, Shell, SPE, and Total.
    \108\ See letters from American Clean Skies, CAPP, Chesapeake, 
EnCana, ExxonMobil, Newfield, Nexen, Petrobras, Petro-Canada, Ryder 
Scott, Shell, and Total.
    \109\ See letter from SPE.
    \110\ See letters from Devon, Ryder Scott, and Wagner.
    \111\ See Rule 4-10(a)(31) [17 CFR 210.4-10(a)(31)].
    \112\ See Item 1203(d) [17 CFR 229.1203(d)].
---------------------------------------------------------------------------

    We also proposed to broaden the definition of the term ``proved 
undeveloped reserves'' to permit a company to include, in its 
undeveloped reserves estimates, quantities of oil that can be recovered 
through improved recovery projects and to expand the technologies that 
a company can use to establish reserves. Under the existing definition, 
a company can include such quantities only if techniques have been 
proved effective by actual production from projects in the area and in 
the same reservoir. As proposed, we are expanding this definition of 
the term ``undeveloped oil and gas reserves'' to permit the use of 
techniques that have been proved effective by actual production from 
projects in the same reservoir or an analogous reservoir or ``by other 
evidence using reliable technology that establishes reasonable 
certainty.'' \113\
---------------------------------------------------------------------------

    \113\ See Rule 4-10(a)(31) [17 CFR 210.4-10(a)(31)].
---------------------------------------------------------------------------

    We also are making other, less substantive revisions to the 
definition of ``undeveloped oil and gas reserves.'' First, commenters 
suggested that we use the term ``development spacing'' \114\ or 
``drainage areas'' \115\ instead of ``drilling units'' because the term 
``drilling units'' is only relevant in jurisdictions that establish 
such units. They noted that many foreign jurisdictions do not establish 
such units. We concur with those commenters and have replaced the term 
``drilling units'' with the term ``development spacing areas.''
---------------------------------------------------------------------------

    \114\ See letter from Total.
    \115\ See letter from SPE.
---------------------------------------------------------------------------

    One commenter also noted that the PRMS guidance on the use of 
analogs for improved recovery projects does not limit such use to 
``within the immediate area'' and recommended that we delete this 
phrase from the definition.\116\ Again, we agree that consistency with 
PRMS would be beneficial in this instance and have deleted that phrase

[[Page 2166]]

from the definition. We also have eliminated two paragraphs of the 
proposed definition because they were largely repetitive of other 
aspects of the definition and were unnecessary.\117\
---------------------------------------------------------------------------

    \116\ See letter from SPE.
    \117\ These paragraphs would have clarified (1) in a 
conventional accumulation, offsetting productive units must lie 
within an area in which economic producibility has been established 
by reliable technology to be reasonably certain and (2) proved 
reserves can be claimed in a conventional or continuous accumulation 
in a given area in which engineering, geoscience, and economic data, 
including actual drilling statistics in the area, and reliable 
technology show that, with reasonable certainty, economic 
producibility exists beyond immediately offsetting drilling units. 
We do not believe that these statements, based on the terms 
``conventional accumulation'' and ``continuous accumulation'' which 
are no longer being defined continue to serve a helpful purpose. See 
Section II.J.5 of this release.
---------------------------------------------------------------------------

G. Reliable Technology

1. Definition of the Term ``Reliable Technology''
    We are adopting, substantially as proposed, a new definition of 
``reliable technology'' that would broaden the types of technologies 
that a company may use to establish reserves estimates and categories. 
All commenters on this topic supported the proposed principles-based 
definition for reliable technology.\118\
---------------------------------------------------------------------------

    \118\ See letters from AAPG, American Clean Skies, Apache, CFA, 
Davis Polk, Devon, EnCana, ExxonMobil, Petrobras, Ryder Scott, 
Sasol, Shell, SPE, Southwestern, and Wagner.
---------------------------------------------------------------------------

    The current rules limit the use of alternative technologies as the 
basis for determining a company's reserves disclosures. For example, 
under the current rules, a company must use actual production or flow 
tests to meet the ``reasonable certainty'' standard necessary to 
establish the proved status of its reserves.\119\ Similarly, the 
current rules provide bright line tests for determining fluid contacts, 
such as lowest known hydrocarbons and highest known oil, which 
establish the volume of the hydrocarbons in place.
---------------------------------------------------------------------------

    \119\ However, in the past, the Commission's staff has 
recognized that flow tests can be impractical in certain areas, such 
as the Gulf of Mexico, where environmental restrictions effectively 
prohibit these types of tests. The staff has not objected to 
disclosure of reserves estimates for these restricted areas using 
alternative technologies.
---------------------------------------------------------------------------

    We recognize that technologies have developed, and will continue to 
develop, improving the quality of information that can be obtained from 
existing tests and creating entirely new tests that we cannot yet 
envision. Thus, the new definition of the term ``reliable technology'' 
permits the use of technology (including computational methods) that 
has been field tested and has demonstrated consistency and 
repeatability in the formation being evaluated or in an analogous 
formation. This new standard will permit the use of a new technology or 
a combination of technologies once a company can establish and document 
the reliability of that technology or combination of technologies.
    We are adopting certain revisions to our proposed definition of the 
term ``reliable technology.'' The proposal also would have required 
reliable technology to be ``widely accepted.'' However, some commenters 
were concerned that this requirement would exclude proprietary 
technologies that companies develop internally that have proven to be 
reliable.\120\ We concur with these commenters and have removed the 
``widely accepted'' requirement from the final rule.
---------------------------------------------------------------------------

    \120\ See letters from Chesapeake, ExxonMobil, Shell, and Total.
---------------------------------------------------------------------------

    We also proposed to define the term ``reliable technology,'' 
expressed in probabilistic terms, as technology that has been proven 
empirically to lead to correct conclusions in 90% or more of its 
applications. Several commenters expressed concern that this proposed 
90% threshold would be difficult to verify and support on an ongoing 
basis.\121\ We agree that a bright line test would be difficult to 
apply to a particular technology or mix of technologies to determine 
their reliability. Therefore, we are not adopting the 90% threshold as 
part of the definition.
---------------------------------------------------------------------------

    \121\ See letters from AAPG, Apache, EIA, Evolution, Ryder 
Scott, Shell, SPE, and Wagner.
---------------------------------------------------------------------------

2. Disclosure of Technologies Used
    The proposal would have required a company to disclose the 
technology used to establish reserves estimates and categories for 
material properties in a company's first filing with the Commission and 
for material additions to reserves estimates in subsequent filings 
because, under the proposal, a company would be able to select the 
technology or mix of technologies that it uses to establish reserves. 
Two commenters supported the proposal because they believed that 
disclosure of the technologies used is reasonable if the definition of 
``reliable technology'' is principles-based.\122\ However, many other 
commenters were concerned that the proposed requirement to disclose the 
technologies used to establish levels of certainty for reserves 
estimates would lead to very complex, technical disclosures that would 
have little meaning to investors.\123\ Others were concerned that 
disclosure of the technology, or the mix of technologies, might cause 
competitive harm.\124\
---------------------------------------------------------------------------

    \122\ See letters from Davis Polk and Sasol.
    \123\ See letters from API, Devon, Eni, ExxonMobil, PEMEX, 
Petro-Canada, Questar, Repsol, Ryder Scott, Shell, Southwestern, 
StatoilHydro, and Total.
    \124\ See letters from API, Devon, Evolution, ExxonMobil, Ryder 
Scott, StatoilHydro, and Total.
---------------------------------------------------------------------------

    As an alternative, some commenters recommended that the rule 
require a more general overview of the technologies used.\125\ We are 
clarifying that the required disclosure would be limited to a concise 
summary of the technology or technologies used to create the 
estimate.\126\ A company would not be required to disclose proprietary 
technologies, or a proprietary mix of technologies, at a level of 
specificity that would cause competitive harm. Rather, the disclosure 
may be more general. For example, a company may disclose that it used a 
combination of seismic data and interpretation, wireline formation 
tests, geophysical logs, and core data to calculate the reserves 
estimate. As noted, however, the Commission's staff, as part of the 
review and comment process, may continue to request companies to 
provide supplemental data, consistent with current practice,\127\ 
which, under the new rules, may include information sufficient to 
support a company's conclusion that a technology or mix of technologies 
used to establish reserves meets the definition of ``reliable 
technology.''
---------------------------------------------------------------------------

    \125\ See letters from EnCana, Eni, Evolution, Ryder Scott, and 
Shell.
    \126\ See Item 1202(a)(6) [17 CFR 229.1202(a)(6)].
    \127\ Currently, the Commission's staff requests supplemental 
data pursuant to Instruction 4 to Item 102 of Regulation S-K [17 CFR 
229.102], Rule 418 [17 CFR 230.418], and Rule 12b-4 [17 CFR 240.12b-
4]
---------------------------------------------------------------------------

    Two commenters supported the proposal to limit the disclosures to 
technologies used to establish reserves in a company's first filing 
with the Commission and material additions to reserves.\128\ We are 
adopting this limitation as proposed.\129\ If the company has not 
previously disclosed reserves estimates in a filing with the Commission 
or is disclosing material additions to its reserves estimates, the 
company must disclose the technologies used to establish the 
appropriate level of certainty for reserves estimates from material 
properties included in the total reserves disclosed and the particular 
properties do not need to be identified. We believe that requiring such 
disclosure when reserves, or material additions to reserves, are 
reported for the first time will discourage the use of questionable 
technologies to establish reserves. However, we do not believe it is 
necessary to require a company to disclose the technology or 
technologies

[[Page 2167]]

relied upon to establish reserves previously disclosed under our rules 
because the permitted technologies have been limited to those permitted 
by our existing rule. In addition, we believe that ongoing disclosure 
of the technologies used to establish all of a company's reserves would 
become unnecessarily cumbersome.
---------------------------------------------------------------------------

    \128\ See letters from Southwestern and Wagner.
    \129\ See Item 1202(a)(6) [17 CFR 229.1202(a)(6)].
---------------------------------------------------------------------------

H. Unproved Reserves--``Probable Reserves'' and ``Possible Reserves''

    As discussed more fully in Section IV.B.3 of this release 
addressing the disclosure requirements of new Subpart 1200, we are 
adopting the proposal to permit disclosure of probable and possible 
reserves. Therefore, we are adopting the proposed definitions of the 
terms ``probable reserves'' and ``possible reserves'' as proposed.
    When producing an estimate of the amount of oil and gas that is 
recoverable from a particular reservoir, a company can make three types 
of estimates:
     An estimate that is reasonably certain;
     An estimate that is as likely as not to be achieved; and
     An estimate that might be achieved, but only under more 
favorable circumstances than are likely.

These three types of estimates are known in the industry as (1) proved, 
(2) proved plus probable, and (3) proved plus probable plus possible 
reserves estimates.
1. Probable Reserves
    We are adopting the definition of the term ``probable reserves'' as 
proposed. It states that ``probable reserves'' are those additional 
reserves that are less certain to be recovered than proved reserves but 
which, in sum with proved reserves, are as likely as not to be 
recovered.\130\ This definition provides guidance for the use of both 
deterministic and probabilistic methods. The definition clarifies that, 
when deterministic methods are used, it is as likely as not that actual 
remaining quantities recovered will equal or exceed the sum of 
estimated proved plus probable reserves. Similarly, when probabilistic 
methods are used, there must be at least a 50% probability that the 
actual quantities recovered will equal or exceed the proved plus 
probable reserves estimates. This definition was derived from the PRMS 
definition of the term ``probable reserves.'' Several commenters agreed 
with the proposed definition of this term, noting that it is roughly 
consistent with PRMS.\131\
---------------------------------------------------------------------------

    \130\ See Rule 4-10(a)(18) [17 CFR 210.4-10(a)(18)].
    \131\ See letters from Devon, EnCana, SPE, and StatoilHydro.
---------------------------------------------------------------------------

2. Possible Reserves
    We also are adopting the definition of the term ``possible 
reserves'' as proposed. The new definition states that possible 
reserves include those additional reserves that are less certain to be 
recovered than probable reserves.\132\ It clarifies that, when 
deterministic methods are used, the total quantities ultimately 
recovered from a project have a low probability to exceed the sum of 
proved, probable, and possible reserves. When probabilistic methods are 
used, there must be at least a 10% probability that the actual 
quantities recovered will equal or exceed the sum of proved, probable, 
and possible estimates. Several commenters noted that our proposed 
definition of the term ``possible reserves'' was consistent with PRMS, 
which also uses a 10% threshold.\133\ One commenter recommended that 
the threshold for ``possible reserves'' should be a 25% likelihood of 
recovery because that percentage would be more meaningful than 
10%.\134\ We believe that a definition consistent with the PRMS will 
provide the most certainty and clarity for companies and investors.
---------------------------------------------------------------------------

    \132\ See Rule 4-10(a)(17) [17 CFR 210.4-10(a)(17)].
    \133\ See letters from Devon, EnCana, SPE, and StatoilHydro.
    \134\ See letter from Evolution.
---------------------------------------------------------------------------

I. Reserves

    We proposed to add a definition of the term ``reserves'' to our 
rules. The proposed definition would have described the criteria that 
an accumulation of oil, gas, or related substances must satisfy to be 
considered reserves (of any classification), including non-technical 
criteria such as legal rights. Specifically, we proposed to define 
reserves as the estimated remaining quantities of oil and gas and 
related substances anticipated to be recoverable, as of a given date, 
by application of development projects to known accumulations based on:
     Analysis of geoscience and engineering data;
     The use of reliable technology;
     The legal right to produce;
     Installed means of delivering the oil, gas, or related 
substances to markets, or the permits, financing, and the appropriate 
level of certainty (reasonable certainty, as likely as not, or possible 
but unlikely) to do so; and
     Economic producibility at current prices and costs.

The proposed definition also would have clarified that reserves are 
classified as proved, probable, and possible according to the degree of 
uncertainty associated with the estimates. We are not adopting the 
definition as proposed. Four commenters recommended clarification that 
the term ``legal right to produce'' extends beyond the initial term of 
an oil and gas concession if there is a reasonable expectation that the 
concession will be renewed, consistent with the PRMS and current staff 
position.\135\ We are adopting a definition of the term ``reserves'' 
that more closely parallels the PRMS definition of that term.
---------------------------------------------------------------------------

    \135\ See letters from API, CAQ, Grant Thornton, and KPMG.
---------------------------------------------------------------------------

    Our final rules define the term ``reserves'' as the estimated 
remaining quantities of oil and gas and related substances anticipated 
to be economically producible, as of a given date, by application of 
development projects to known accumulations.\136\ In addition, there 
must exist, or there must be a reasonable expectation that there will 
exist, the legal right to produce or a revenue interest in the 
production of oil and gas, installed means of delivering oil and gas or 
related substances to market, and all permits and financing required to 
implement the project.
---------------------------------------------------------------------------

    \136\ See Rule 4-10(a)(26) [17 CFR 210.4-10(a)(26)].
---------------------------------------------------------------------------

    A note to the definition clarifies that reserves should not be 
assigned to adjacent reservoirs isolated by major, potentially sealing, 
faults until those reservoirs are penetrated and evaluated as 
economically producible and that reserves should not be assigned to 
areas that are clearly separated from a known accumulation by a non-
productive reservoir (i.e., absence of reservoir, structurally low 
reservoir, or negative test results). Such areas may contain 
prospective resources (i.e., potentially recoverable resources from 
undiscovered accumulations).\137\
---------------------------------------------------------------------------

    \137\ See Note to Rule 4-10(a)(26) [17 CFR 210.4-10(a)(26)].
---------------------------------------------------------------------------

    One notable difference between our final definition of ``reserves'' 
and the PRMS definition is that our definition is based on ``economic 
producibility'' rather than ``commerciality.'' One commenter believed 
that reserves must be ``commercial,'' as stated in the PRMS 
definition.\138\ However, commerciality introduces a subjective aspect 
to the price used to establish existing economic conditions by 
factoring in the rate of return required by a particular company before 
it will commit resources to the project. This rate of return will vary 
among companies, reducing the comparability among disclosures. 
Therefore, the adopted definition of the term ``reserves'' relies on 
economic producibility, as proposed.
---------------------------------------------------------------------------

    \138\ See letter from StatoilHydro.

---------------------------------------------------------------------------

[[Page 2168]]

J. Other Supporting Terms and Definitions

    We also proposed to define several other terms primarily to support 
and clarify the definitions of the key terms. We are adopting most of 
those supporting definitions as discussed in further detail below.
1. Deterministic Estimate
    A company can derive two different types of reserves estimates 
depending on the method used to calculate the estimates. These two 
types of estimates are known as ``deterministic estimates'' and 
``probabilistic estimates.'' \139\ In the Proposing Release, we 
proposed to define the term ``deterministic estimate'' as an estimate 
based on a single value for each parameter (from the geoscience, 
engineering, or economic data) in the reserves calculation that is used 
in the reserves estimation procedure. We are adopting that definition 
as proposed.
---------------------------------------------------------------------------

    \139\ See Rules 4-10(a)(5) and (a)(19) [17 CFR 210.4-10(a)(5) 
and (a)(19)]. These definitions are based on the Canadian Oil and 
Gas Evaluation Handbook (COGEH). This handbook was developed by the 
Calgary Chapter of the Society of Petroleum Evaluation Engineers and 
the Petroleum Society of CIM to establish standards to be used 
within the Canadian oil and gas industry in evaluating oil and gas 
reserves and resources.
---------------------------------------------------------------------------

2. Probabilistic Estimate
    We are adopting a new definition of the term ``probabilistic 
estimate'' substantially as proposed. The new rule defines the term 
``probabilistic estimate'' as an estimate that is obtained when the 
full range of values that could reasonably occur from each unknown 
parameter (from the geoscience and engineering data) is used to 
generate a full range of possible outcomes and their associated 
probabilities of occurrence.\140\ In response to a comment received, 
however, we revised the definition so that it does not include the 
application of a range of values with respect to economic conditions 
because those conditions, such as prices and costs, are based on 
historical data, and therefore are an established value, rather than a 
range of estimated values.\141\
---------------------------------------------------------------------------

    \140\ See Rule 4-10(a)(19) [17 CFR 210.4-10(a)(19)].
    \141\ See letter from Shell.
---------------------------------------------------------------------------

3. Analogous Reservoir
    We proposed a definition of the term ``analogous formation in the 
immediate area.'' As noted above, we received comment indicating that 
the use of appropriate analogs should not be limited to the immediate 
area in which the reserves are being estimated.\142\ Therefore, we have 
changed the defined term to ``analogous reservoir.'' \143\ In addition, 
based on commenters' remarks, we are defining the term ``analogous 
reservoir'' in a manner that is more consistent with the PRMS, which 
addresses more specifically the types of reservoirs that may be used as 
analogues. The new definition of the term ``analogous reservoir'' 
states that analogous reservoirs, as used in resources assessments, 
have similar rock and fluid properties, reservoir conditions (depth, 
temperature, and pressure) and drive mechanisms, but are typically at a 
more advanced stage of development than the reservoir of interest and 
thus may provide concepts to assist in the interpretation of more 
limited data and estimation of recovery.\144\ When used to support 
proved reserves, an ``analogous reservoir'' refers to a reservoir that 
shares the following characteristics with the reservoir of interest:
---------------------------------------------------------------------------

    \142\ See letter from SPE.
    \143\ See Rule 4-10(a)(2) [17 CFR 210.4-10(a)(2)].
    \144\ See Rule 4-10(a)(2) [17 CFR 210.4-10(a)(2)].
---------------------------------------------------------------------------

     Same geological formation (but not necessarily in pressure 
communication with the reservoir of interest);
     Same environment of deposition;
     Similar geological structure; and
     Same drive mechanism.

As proposed, the new definition includes an instruction that clarifies 
that reservoir properties must, in the aggregate, be no more favorable 
in the analog than in the reservoir of interest. The new definition 
also clarifies that, although an analogous reservoir must be in the 
same geological formation as the reservoir of interest, it need not be 
in pressure communication with the reservoir of interest.
4. Definitions of Other Terms
    We received no comment with regard to several of the proposed 
supporting definitions. We are adopting those definitions substantially 
as proposed without material changes. They include the following terms:
     ``Condensate''; \145\
     ``Development project''; \146\
     ``Economically producible''; \147\
     ``Estimated ultimate recovery,'' \148\
     ``Exploratory well''; \149\
     ``Extension well''; \150\ and
     ``Resources.'' \151\
---------------------------------------------------------------------------

    \145\ See Rule 4-10(a)(4) [17 CFR 210.4-10(a)(4)].
    \146\ See Rule 4-10(a)(8) [17 CFR 210.4-10(a)(8)].
    \147\ See Rule 4-10(a)(10) [17 CFR 210.4-10(a)(10)].
    \148\ See Rule 4-10(a)(11) [17 CFR 210-4-10(a)(11)].
    \149\ See Rule 4-10(a)(13) [17 CFR 210.4-10(a)(13)].
    \150\ See Rule 4-10(a)(14) [17 CFR 210.4-10(a)(14)].
    \151\ See Rule 4-10(a)(28) [17 CFR 210.4-10(a)(28)].
---------------------------------------------------------------------------

    Most of these supporting terms and their definitions are based on 
similar terms in the PRMS. The definition of ``resources'' is based on 
the Canadian Oil and Gas Evaluation Handbook (COGEH).
    In the Proposing Release, we solicited comment on whether we should 
adopt any other supporting definitions. One commenter submitted an 
appendix to its letter containing numerous other terms that it thought 
we should adopt.\152\ We have decided not to adopt those additional 
definitions because we feel that they are unnecessary at this time. 
However, we have decided to adopt a definition for the term 
``bitumen.'' We believe that providing a definition for this term will 
lead to more consistency among disclosures because there currently are 
several competing definitions of that term used in the industry.
---------------------------------------------------------------------------

    \152\ See letter from SPE.
---------------------------------------------------------------------------

    We are defining the term ``bitumen'' as ``petroleum in a solid or 
semi-solid state in natural deposits. In its natural state, it usually 
contains sulfur, metals, and other non-hydrocarbons. Bitumen has a 
viscosity greater than 10,000 centipoise measured at original 
temperature in the deposit and atmospheric pressure, on a gas free 
basis.'' \153\ This definition is similar to the PRMS definition of 
``natural bitumen.''
---------------------------------------------------------------------------

    \153\ See Rule 4-10(a)(3) [17 CFR 210.4-10(a)(3)].
---------------------------------------------------------------------------

5. Proposed Terms and Definitions Not Adopted
    We proposed definitions for the terms ``continuous accumulations'' 
and ``conventional accumulations'' to assist companies in disclosing 
segregated reserves based on these two types of accumulations. As noted 
elsewhere in this release, the final rules do not require disclosure 
based on the type of accumulation in which the reserves are found.\154\ 
Therefore, there is no need to define these terms and we are not 
adopting the proposed definitions.
---------------------------------------------------------------------------

    \154\ See Section III.B.3.c.
---------------------------------------------------------------------------

    Similarly, we proposed a definition for the term ``sedimentary 
basin'' because it would have been part of our definition of the term 
``by geographic area.'' As noted elsewhere in this release, we have 
substantially revised the definition of the term ``by geographic area'' 
\155\ and the term ``sedimentary basin'' is no longer needed, so we are 
not adopting this proposed term and definition.
---------------------------------------------------------------------------

    \155\ See Section III.B.2.a.
---------------------------------------------------------------------------

    As noted above, one commenter recommended that we adopt a large 
glossary of terms and definitions that correspond with the PRMS 
definitions.\156\ Rather than defining an extensive glossary of terms 
in our rules

[[Page 2169]]

and attempting to constantly update those definitions, we advise 
companies to look to definitions that are commonly accepted within the 
oil and gas industry to the extent such definitions are not in, or 
inconsistent with, our rules.
---------------------------------------------------------------------------

    \156\ See letter from SPE.
---------------------------------------------------------------------------

K. Alphabetization of the Definitions Section of Rule 4-10

    We are alphabetizing the definitional terms in Rule 4-10(a) because 
we are adding a significant number of defined terms to this section.

III. Revisions to Full Cost Accounting and Staff Accounting Bulletin

    As we noted in Section II.B.2 of this release, commenters 
unanimously opposed our proposal to use different prices for disclosure 
and accounting purposes. We agree with those commenters and are 
revising our proposal to use a 12-month average price for accounting 
purposes. These revisions primarily will appear under the full cost 
accounting method described in Rule 4-10(c) \157\ of Regulation S-X. 
The full cost accounting method permits certain oil and gas extraction 
costs to accumulate on a company's balance sheet subject to a 
limitation test or a ``ceiling'' as described in Rule 4-10(c)(3)(4). 
Like reserve disclosures, these capitalized costs and the related 
limitation test are not fair value based measurements. Rather the 
capitalized costs represent the accumulated historical acquisition, 
exploration and development costs (net of any previously recorded 
depletion, amortization or ceiling test write downs) incurred for oil 
and gas producing activities, limited to a standardized mathematical 
calculation (the full cost ceiling) adopted over 25 years ago. Costs 
that do not exceed the limitation are deferred and amortized over time. 
The limitation test calculation on capitalized costs is not designed or 
intended to represent a fair valuation of the related oil and gas 
assets.\158\
---------------------------------------------------------------------------

    \157\ 17 CFR 210.4-10(c).
    \158\ While not intended to represent fair value, costs that are 
written down because they exceed the ceiling limitation are 
accounted for in the same manner as impairments recognized under 
accounting generally. That is, once the asset is written down, it 
becomes the new historical cost basis and cannot be reinstated for 
subsequent increases in the ceiling. See Rule 4-10(c)(4)(i) of 
Regulation S-X [17 CFR 210-4-10(c)(4)(i)].
---------------------------------------------------------------------------

    Similar to the single-day, year-end pricing used under the 
successful efforts method,\159\ the application of the full cost method 
of accounting in Rule 4-10(c) has used ``current prices,'' interpreted 
as single-day, year-end prices, as the basis for calculating the 
limitation on costs that may be capitalized under the full cost method. 
In order to further the objective of providing comparable oil and gas 
reserve quantities, our final rule clarifies that the term ``current 
prices'' as used in Rule 4-10(c) is consistent with the 12-month 
average price as calculated in Rule 4-10(a)(22)(v).\160\
---------------------------------------------------------------------------

    \159\ The accounting guidance refers to our definition of proved 
reserves under existing Rule 4-10(a)(2), which currently uses a 
single-day, year-end price to establish reserves amounts.
    \160\ See Rule 4-10(c)(8) [17 CFR 210.4-10(c)(8)].
---------------------------------------------------------------------------

    However, since these calculations are not designed to result in a 
calculation of fair value and since the change to the full cost 
accounting method would effectively eliminate the anomalies caused by 
the single-day, year-end price currently used in the limitation test, 
the SEC staff will eliminate portions of Staff Accounting Bulletin 
(SAB) Topic 12:D.3.c that permit consideration of the impact of price 
increases subsequent to the period end on the ceiling limitation test.
    The combination of adopting a 12-month average pricing mechanism 
and eliminating portions of SAB Topic 12:D.3.c could have the effect of 
requiring a company using the full cost accounting method to record a 
ceiling test write-down in income during periods of rising oil and gas 
prices. In that situation, it is possible that using a 12-month average 
price in the ceiling test calculation might result in a write-down that 
would not otherwise have been required had the full cost company been 
permitted to use the single-day, year-end price. Conversely, it is also 
possible that in periods of declining oil and gas prices, the 
application of this rule could result in the deferral of ceiling test 
write-downs. In that situation, it is possible that using a 12-month 
average price in the ceiling limitation test calculation might not 
result in a write-down in situations where a write down would have 
otherwise been required had the full cost company been required to use 
a single-day, year-end price in its ceiling limitation test 
calculation.
    Because the application of the ceiling limitation test is not a 
fair-value-based calculation but rather a limit on the amount of 
certain oil and gas related exploration costs that can be capitalized, 
portions of which would have resulted in write-downs in prior periods 
under other methods of accounting, we believe the benefits of using a 
single pricing mechanism justify the potential changes to the timing of 
those ceiling test write-downs or amortizations amounts. However, as 
discussed in Section V of this release, we believe that the company 
should discuss such situations, if material, particularly when pricing 
trends indicate the possibility of future write-downs, in Management's 
Discussion and Analysis and, where appropriate, the notes to the 
financial statements.

IV. Update and Codification of the Oil and Gas Disclosure Requirements 
in Regulation S-K

    The Proposing Release proposed to update and codify Securities Act 
and Exchange Act Industry Guide 2: Disclosure of Oil and Gas Operations 
(Industry Guide 2).\161\ Industry Guide 2 currently sets forth most of 
the disclosures that an oil and gas company provides regarding its 
reserves, production, property, and operations. Regulation S-K 
references Industry Guide 2 in Instruction 8 to Item 102 (Description 
of Property), Item 801 (Securities Act Industry Guides), and Item 802 
(Exchange Act Industry Guides). However, Industry Guide 2 itself does 
not appear in Regulation S-K or in the Code of Federal Regulations. The 
rules that we adopt today codify the contents of Industry Guide 2 in a 
new Subpart 1200 of Regulation S-K.
---------------------------------------------------------------------------

    \161\ Exchange Act Industry Guide 2 merely references, and 
therefore is identical to, Securities Act Industry Guide 2.
---------------------------------------------------------------------------

A. Revisions to Items 102, 801, and 802 of Regulation S-K

    The instructions to Item 102 of Regulation S-K, as well as Items 
801 and 802 of Regulation S-K, currently reference the industry guides. 
Because we are codifying the Industry Guide 2 disclosures in a new 
Subpart 1200 of Regulation S-K, we are revising the instructions to 
Item 102 to reflect this change.\162\ We also are eliminating the 
references in Items 801 and 802 to Industry Guide 2 because that 
industry guide will cease to exist upon effectiveness of the amendments 
we adopt today.\163\
---------------------------------------------------------------------------

    \162\ See revised Instructions 4 and 8 to Item 102 [17 CFR 
229.102].
    \163\ See revised Item 801 and 802 [17 CFR 229.801 and 802].
---------------------------------------------------------------------------

    In addition, Instruction 5 to Item 102 of Regulation S-K currently 
prohibits the disclosure of reserves other than proved oil and gas 
reserves. Because we are adopting rules to permit disclosure of 
probable and possible oil and gas reserves, we are revising Instruction 
5 to limit its applicability to extractive enterprises other than oil 
and gas producing activities, such as mining activities.\164\ 
Similarly, Instruction 3 of

[[Page 2170]]

Item 102, regarding production, reserves, locations, development and 
the nature of the company's interests, will no longer apply to oil and 
gas producing activities, so we also are limiting that instruction to 
mining activities.\165\
---------------------------------------------------------------------------

    \164\ See revised Instruction 5 to Item 102 [17 CFR 229.102]. 
Extractive enterprises include enterprises such as mining companies 
that extract resources from the ground.
    \165\ See revised Instruction 3 to Item 102 [17 CFR 229.102].
---------------------------------------------------------------------------

    Finally, we are eliminating Instruction 4 to Item 102 regarding the 
ability of the Commission's staff to request supplemental information, 
including reserves reports. This instruction is duplicative of 
Securities Act Rule 418 \166\ and Exchange Act 12b-4,\167\ regarding 
the staff's general ability to request supplemental information.
---------------------------------------------------------------------------

    \166\ 17 CFR 230.418.
    \167\ 17 CFR 240.12b-4.
---------------------------------------------------------------------------

B. Proposed New Subpart 1200 to Regulation S-K Codifying Industry Guide 
2 Regarding Disclosures by Companies Engaged in Oil and Gas Producing 
Activities

1. Overview
    We are adding a new Subpart 1200 to Regulation S-K that codifies 
the disclosure requirements related to companies engaged in oil and gas 
producing activities. This new subpart largely includes the existing 
requirements of Industry Guide 2. However, we have revised these 
requirements to update them, provide better clarity with respect to the 
level of detail required in oil and gas disclosures, including the 
geographic areas by which disclosures need to be made, and provide 
formats for tabular presentation of these disclosures. In addition, 
Subpart 1200 contains the following new disclosure requirements, many 
of which have been requested by industry participants:
     Disclosure of reserves from non-traditional sources (e.g., 
bitumen, shale, coal) as oil and gas reserves;
     Optional disclosure of probable and possible reserves;
     Optional disclosure of oil and gas reserves' sensitivity 
to price;
     Disclosure of the development of proved undeveloped 
reserves;
     Disclosure of technologies used to establish additions to 
reserves estimates;
     Disclosure of a company's internal controls over reserves 
estimation and the qualifications of the business entity or individual 
preparing or auditing the reserves estimates; and
     Disclosure based on a new definition of the term ``by 
geographic area.''
    We discuss each of these proposed new Items below.
2. Item 1201 (General Instructions to Oil and Gas Industry-Specific 
Disclosures)
    We are adding new Item 1201 to Regulation S-K. This item sets forth 
the general instructions to Subpart 1200. The new item contains three 
paragraphs that perform the following tasks:
     Instruct companies for which oil and gas producing 
activities are material to provide the disclosures specified in Subpart 
1200; \168\
---------------------------------------------------------------------------

    \168\ This paragraph would maintain the existing exclusion in 
Industry Guide 2 for limited partnerships and joint ventures that 
conduct, operate, manage, or report upon oil and gas drilling or 
income programs, that acquire properties either for drilling and 
production, or for production of oil, gas, or geothermal steam or 
water.
---------------------------------------------------------------------------

     Clarify that, although a company must present specified 
Subpart 1200 information in tabular form, the company may modify the 
format of the table for ease of presentation, to add additional 
information or to combine two or more required tables;
     State that the definitions in Rule 4-10(a) of Regulation 
S-X apply to Subpart 1200; and
     Define the term ``by geographic area.''
a. Geographic Area
    We received significant comments regarding the proposed definition 
of the term ``by geographic area.'' We proposed to require disclosure 
by continent, country containing 15% of more of the company's reserves, 
and sedimentary basin or field containing 10% or more of the company's 
reserves. Several commenters were concerned that the proposed 
definition would add too much detail to the disclosures, particularly 
at the basin or field level.\169\ They were concerned that this amount 
of detail would make disclosures too complex and incoherent.\170\ They 
were particularly concerned with the extension of this standard to 
disclosures other than reserves, such as production, wells, and 
acreage.\171\ Commenters also believed that the disclosures, in 
particular by field, could cause competitive harm in future property 
sales transactions, unitization agreements, and other asset 
transfers.\172\
---------------------------------------------------------------------------

    \169\ See letters from Apache, CAPP, Devon, ExxonMobil, 
Imperial, Nexen, Repsol, Shell, and StatoilHydro.
    \170\ See letters from Apache, CAPP, ExxonMobil, Imperial, 
Nexen, and Repsol.
    \171\ See letters from ExxonMobil, Imperial, and Total.
    \172\ See letters from Apache, API, BHP, Canadian Natural, CAPP, 
Devon, EnCana, Eni, Newfield, Nexen, Petro-Canada, Shell, 
StatoilHydro, and Total.
---------------------------------------------------------------------------

    Some commenters also believed that some of these disclosures may be 
prohibited by foreign governments.\173\ One commenter noted that 
separate determination of field or basin reserves within a larger 
production sharing agreement may not be possible due to concession-wide 
cost sharing terms.\174\ Eight commenters recommended that the 
determination of appropriate geographic disclosure should remain with 
management, consistent with Statement of Financial Accounting Standard 
No. 69 (SFAS 69).\175\ However, two commenters indicated that a 
country-by-country breakdown would be adequate.\176\
---------------------------------------------------------------------------

    \173\ See letters from Apache, API, CAPP, Eni, Newfield, Petro-
Canada, and Total.
    \174\ See letter from Apache.
    \175\ See letters from Apache, API, Canadian Natural, CAPP, Eni, 
ExxonMobil, Imperial, and Petro-Canada.
    \176\ See letters from ExxonMobil and Nexen.
---------------------------------------------------------------------------

    Four commenters supported the proposed percentage thresholds for 
geographic disclosure, stating that they would increase understanding 
of the total energy supply, leading to better decisions by policy 
makers.\177\ One commenter supported the 15% threshold for 
countries.\178\
---------------------------------------------------------------------------

    \177\ See letters from AAPG, CFA, Chesapeake, and E&Y.
    \178\ See letter from Shell.
---------------------------------------------------------------------------

    As we noted in the Proposing Release, there have been differing 
interpretations among oil and gas companies as to the level of 
specificity required when a company is breaking out its reserves 
disclosures based on geographic area as required by Instruction 3 of 
Item 102 of Regulation S-K.\179\ Some companies currently broadly 
organize their reserves only by hemisphere or continent. SFAS 69 
requires reserves disclosure to be separately disclosed for the 
company's home country and foreign geographic areas. It defines 
``foreign geographic areas'' as ``individual countries or groups of 
countries as appropriate for meaningful disclosure in the 
circumstances.'' Since SFAS 69 was issued, the operations of oil and 
gas companies have become much more diversified globally. For many 
large U.S. oil and gas producers, the majority of reserves are now 
overseas, with material amounts in individual countries and even 
individual fields or basins.
---------------------------------------------------------------------------

    \179\ 17 CFR 229.102.
---------------------------------------------------------------------------

    We think that greater specificity than simply disclosing reserves 
within ``groups of countries'' would benefit investors and, in certain 
cases, may be necessary to meet the requirements of Item 102 of 
Regulation S-K. Some countries in which many of these companies operate 
and may have significant reserves are subject to unique risks, such as 
political instability.

[[Page 2171]]

However, we recognize that disclosure that is too detailed may detract 
from the overall disclosure. Thus, we have revised the definition of 
the term ``by geographic area'' to mean, as appropriate for meaningful 
disclosure under a company's particular circumstances:
    (1) By individual country;
    (2) By groups of countries within a continent; or
    (3) By continent.\180\
---------------------------------------------------------------------------

    \180\ See Item 1201(d) [17 CFR 229.1201(d)].
---------------------------------------------------------------------------

    This definition is substantially the same as the definition 
currently provided in SFAS 69. However, as proposed, we are adopting 
specific percentage thresholds to the geographic breakdowns of reserves 
estimates and production. With respect to production, the final rules 
require disclosure of production in each country or field containing 
15% or more of the company's proved reserves unless prohibited by the 
country in which the reserves are located. We are raising the proposed 
10% threshold for field disclosure of production to 15% to make the 
threshold consistent. However, rather than requiring disclosure based 
on a percentage of the amount of the company's reserves of an 
individual product, as proposed, the final rules require disclosure 
based on a percentage of a company's total global oil and gas proved 
reserves, based on barrels of oil equivalent.\181\
---------------------------------------------------------------------------

    \181\ See Item 1204(a) [17 CFR 229.1204(a)].
---------------------------------------------------------------------------

    With respect to reserves estimates, the final rules require 
disclosure of reserves in countries containing more than 15% of the 
company's proved reserves. As with the production disclosure, this 15% 
threshold would be based on the company's total global oil and gas 
proved reserves, rather than on individual products, as proposed.\182\ 
A registrant need not provide disclosure of the reserves in a country 
containing 15% or more of the registrant's proved reserves if that 
country's government prohibits disclosure of reserves in that country.
---------------------------------------------------------------------------

    \182\ See Item 1202(a)(2) [17 CFR 229.1202(a)(2)].
---------------------------------------------------------------------------

    We are not adopting the requirement that we proposed to disclose 
reserves by sedimentary basin or field. We share commenters' concerns 
that there is potential for competitive harm from such disclosure in 
future property sales transactions, unitization agreements, and other 
asset transfers. Moreover, we recognize that there may be situations in 
which a particular field may encompass a significant portion of a 
company's reserves in a foreign country. To avoid compelling a company 
to provide, in effect, field disclosure, the rule does not require 
disclosure of reserves in a country containing 15% of the company's 
reserves if that country prohibits disclosure of reserves in a 
particular field and disclosure of reserves in that country would have 
the effect of disclosing reserves in particular fields.\183\ For 
example, if a company has 25% of its reserves in Country A and Country 
A's government prohibits disclosure of reserves by field within Country 
A, if almost all of that company's reserves in Country A are located in 
a single field, the company would not be required to specify the amount 
of its reserves located in Country A.
---------------------------------------------------------------------------

    \183\ See Instruction 4 to Item 1202(a)(2).
---------------------------------------------------------------------------

b. Tabular Disclosure
    We proposed to require much of the reserves disclosures and other 
disclosures in Industry Guide 2 to be presented in tabular format. Two 
commenters encouraged using a standardized table for reserves 
disclosure.\184\ Another believed that companies should be able to 
reorganize, supplement, or combine tables for better presentation of 
the company's strategy.\185\ However, two commenters believed that the 
rules should not propose a specified tabular format in general.\186\ 
These commenters believed that companies should have the flexibility to 
present data in a format that is most relevant and meaningful to 
investors, whether it is tabular or narrative.\187\ We continue to 
believe that in certain circumstances, the required disclosures lend 
themselves to a tabular disclosure format. We believe that 
standardizing such tables will improve the readability and 
comparability of disclosures among companies. However, in response to 
comments received, we have made several revisions to the individual 
disclosure items, including whether the disclosure item must be 
presented in tabular format. We discuss each below.
---------------------------------------------------------------------------

    \184\ See letters from Devon and Petrobras.
    \185\ See letter from Petro-Canada.
    \186\ See letters from Apache and ExxonMobil.
    \187\ See letters from Apache and ExxonMobil.
---------------------------------------------------------------------------

3. Item 1202 (Disclosure of Reserves)
    Existing Instruction 3 to Item 102 of Regulation S-K requires 
disclosure of an extractive enterprise's proved reserves. With respect 
to oil and gas producing companies, we are replacing this Instruction 
by adding a new Item 1202 to Regulation S-K that contains a similar 
disclosure requirement regarding a company's proved reserves.\188\ 
However, new Item 1202 expands on the requirements of Item 102 by 
specifically permitting the disclosure of probable and possible 
reserves and permitting the disclosure of reserves from non-traditional 
sources. In addition, because we are no longer distinguishing between 
types of accumulations, the item contains only one table with separate 
columns for different final products, specifically, oil, gas, synthetic 
oil, synthetic gas, and other natural resources sold by the company.
---------------------------------------------------------------------------

    \188\ See Item 1202 [17 CFR 229.1202].
---------------------------------------------------------------------------

a. Oil and Gas Reserves Tables
    New Item 1202 requires disclosure, in the aggregate and by 
geographic area, of reserves estimates using prices and costs under 
existing economic conditions, for each product type, in the following 
categories:
     Proved developed reserves;
     Proved undeveloped reserves;
     Total proved reserves;
     Probable developed reserves (optional);
     Probable undeveloped reserves (optional);
     Possible developed reserves (optional); and
     Possible undeveloped reserves (optional).
    A form of this table is set forth below:

            Summary of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices
----------------------------------------------------------------------------------------------------------------
                                                                             Reserves
                                                ----------------------------------------------------------------
               Reserves category                                            Synthetic
                                                     Oil      Natural gas      oil       Synthetic    Product A
                                                   (mbbls)       (mmcf)      (mbbls)    gas  (mmcf)   (measure)
----------------------------------------------------------------------------------------------------------------
PROVED
Developed:
    Continent A................................  ...........  ...........  ...........  ...........  ...........

[[Page 2172]]

 
    Continent B................................  ...........  ...........  ...........  ...........  ...........
    Country A..................................  ...........  ...........  ...........  ...........  ...........
    Country B..................................  ...........  ...........  ...........  ...........  ...........
    Other Countries in Continent...............  ...........  ...........  ...........  ...........  ...........
Undeveloped:
    Continent A................................  ...........  ...........  ...........  ...........  ...........
    Continent B................................  ...........  ...........  ...........  ...........  ...........
    Country A..................................  ...........  ...........  ...........  ...........  ...........
    Country B..................................  ...........  ...........  ...........  ...........  ...........
    Other Countries in Continent B.............  ...........  ...........  ...........  ...........  ...........
                                                ----------------------------------------------------------------
        TOTAL PROVED...........................  ...........  ...........  ...........  ...........  ...........
PROBABLE
    Developed..................................  ...........  ...........  ...........  ...........  ...........
    Undeveloped................................  ...........  ...........  ...........  ...........  ...........
POSSIBLE
    Developed..................................  ...........  ...........  ...........  ...........  ...........
    Undeveloped................................  ...........  ...........  ...........  ...........  ...........
----------------------------------------------------------------------------------------------------------------

i. Disclosure by Final Product Sold
    The table requires disclosure by final product sold by the company, 
specifically, oil, gas, synthetic oil, synthetic gas, or other natural 
resource. Thus, if the company processes a natural resource that it has 
extracted, such as bitumen, into synthetic oil or gas prior to selling 
the product, it may include such reserves under the synthetic oil or 
gas columns. As noted below, we have revised the proposal that would 
have required disclosure by type of accumulation. In addition, in 
response to commenters, we have revised the definition of ``oil and gas 
producing activities'' so that a company can use the price of that 
synthetic oil or gas to determine the economic producibility of the 
reserves because the economics of the processing activity are relevant 
to the determination of whether to extract the underlying 
resource.\189\
    However, if a company extracts a resource other than oil or gas, 
such as bitumen, and sells the product without processing it into 
synthetic oil or gas, it must disclose reserves of that other natural 
resource. Although that company's extractive activities would be 
considered an oil and gas producing activity under the definition of 
that term, such a company would not benefit from the economics of 
processing of that resource because the price that determines whether 
such a company extracts the resource is the price of the unprocessed 
resource and therefore the company may not establish reserves estimates 
based on the price of the upgraded product. Similarly, if the company 
does not itself extract the natural resource, but purchases the natural 
resource for processing or is paid to process the natural resource, it 
may not claim reserves either of the resource or of the processed 
product.
---------------------------------------------------------------------------

    \189\ See Section II.C.2 of this release.
---------------------------------------------------------------------------

ii. Aggregation
    As proposed, the reserves to be reported in these tables would be 
aggregations (to the company total level) of reserves determined for 
individual wells, reservoirs, properties, fields, or projects. 
Regardless of whether the reserves were determined using deterministic 
or probabilistic methods, the reported reserves should be simple 
arithmetic sums of all estimates at the well, reservoir, property, 
field, or project level within each reserves category. Eight commenters 
agreed that aggregation should not be permitted beyond the field, 
property or project level, consistent with PRMS.\190\
---------------------------------------------------------------------------

    \190\ See letters from Devon, Evolution, ExxonMobil, Ryder 
Scott, Shell, SPE, Talisman, and Wagner.
---------------------------------------------------------------------------

iii. Optional Disclosure of Probable and Possible Reserves
    A company may, but is not required to, disclose probable or 
possible reserves in these tables. If a company discloses probable or 
possible reserves, it must provide the same level of geographic detail 
as it must with respect to proved reserves and must state whether the 
reserves are developed or undeveloped. In addition, Item 1202 requires 
the company to disclose the relative uncertainty associated with these 
classifications of reserves estimations. By permitting disclosure of 
all three of these classifications of reserves, our objective is to 
enable companies to provide investors with more insight into the 
potential reserves base that managements of companies may use as their 
basis for decisions to invest in resource development.
    Most commenters addressing this issue supported permitting the 
disclosure of probable and possible reserves in filed documents.\191\ 
They believed that such disclosure would provide a more complete 
picture of a company's full portfolio of opportunities.\192\ One 
commenter noted that this information often is already available on 
company Web sites and in press releases.\193\ However, several 
commenters supporting the proposal cautioned that there could be 
significant variability among disclosures.\194\
---------------------------------------------------------------------------

    \191\ See letters from CFA, Chesapeake, Deloitte, EnCana, 
Evolution, McMoRan, Newfield, Petrobras, Petro-Canada, Questar, 
Ryder Scott, Sasol, Ryder Scott, Shell, SPE, Three Senators, Wagner, 
and Zakaib.
    \192\ See letters from CFA, Evolution, Petro-Canada, Ryder 
Scott, and Wagner.
    \193\ See letter from Evolution.
    \194\ See letter from EnCana.
---------------------------------------------------------------------------

    Other commenters expressed concern about disclosure of unproved 
reserves, but conceded that voluntary disclosure would be 
acceptable.\195\ These commenters were concerned that such disclosure 
may confuse investors and expose companies to increased litigation 
because of the inherent uncertainty associated with probable and 
possible reserves.\196\ They noted that various

[[Page 2173]]

technologies may be used to support these estimates.\197\
---------------------------------------------------------------------------

    \195\ See letters from API, ExxonMobil, Imperial, Repsol, and 
Total.
    \196\ See letters from API, ExxonMobil, Imperial, and Repsol.
    \197\ See letters from API, ExxonMobil, and Imperial.
---------------------------------------------------------------------------

    Several commenters opposed permitting disclosure of probable and 
possible reserves in Commission filings for similar reasons.\198\ 
Again, they were concerned that the inherent uncertainty associated 
with such reserves estimates may lead to investor confusion and 
misunderstanding.\199\ They believed that the broad range of 
technologies and methods used by companies to support these estimates 
would lead to inconsistent disclosure among companies.\200\
---------------------------------------------------------------------------

    \198\ See letters from Apache, Devon, Energen, Eni, and 
Southwestern.
    \199\ See letters from Apache, Devon, Eni, and Southwestern.
    \200\ See letters from Devon, Eni, and Southwestern.
---------------------------------------------------------------------------

    We note that numerous oil and gas companies already disclose 
unproved reserves on their Web sites and in press releases. This 
practice does not appear to have created confusion in the market. 
However, we understand commenters' concerns that probable and possible 
reserves estimates are less certain than proved reserves estimates and 
so may increase litigation risk. By making these disclosures voluntary, 
a company could exercise its own discretion as to whether to provide 
the market with this disclosure.
    Some commenters were concerned that voluntary disclosure by some 
companies may raise confusion as to why other companies do not disclose 
these classifications of reserves.\201\ One commenter was concerned 
that voluntary disclosure may increase market pressure on all companies 
to disclose probable and possible reserves estimates.\202\ Considering 
the fact that many companies already make these disclosures public, we 
do not believe that this is an adequate reason for prohibiting from 
filings disclosure that may be helpful to investors.
---------------------------------------------------------------------------

    \201\ See letters from Apache and Total.
    \202\ See letter from Eni.
---------------------------------------------------------------------------

iv. Resources Not Considered Reserves
    Because we are permitting disclosure of probable and possible 
reserves, we are revising existing Instruction 5 to Item 102 of 
Regulation S-K to continue to prohibit disclosure of estimates of oil 
or gas resources other than reserves, and any estimated values of such 
resources, in any document publicly filed with the Commission, unless 
such information is required to be disclosed in the document by foreign 
or state law.\203\ Five commenters recommended that the rules permit 
disclosure of all categories of resources, including those that do not 
qualify as reserves.\204\ One commenter believed that the prohibition 
against disclosing all resources deprives public markets of significant 
information without meaningfully enhancing investor protection and 
ultimately may harm the efficiency and development of U.S. markets and 
U.S. companies raising capital.\205\ That commenter also thought such a 
restriction could also encourage companies to form outside of the 
U.S.\206\ Another commenter believed that the uncertainty of resource 
estimates is best communicated by reporting the full range of 
estimates.\207\ In addition, another commenter believed that clear 
disclosure would allay concerns about investor misunderstanding of 
estimates of resources that do not qualify as reserves.\208\ That 
commenter noted that excluding resources that are not reserves is 
inconsistent with international standards and the fact that these 
resources are disclosed in the U.S. on Web sites and in press 
releases.\209\ We continue to be concerned that such resources are too 
speculative and may lead investors to incorrect conclusions. Therefore, 
we are adopting the proposal to prohibit disclosure of resources other 
than reserves.
---------------------------------------------------------------------------

    \203\ See Instruction 5 to Item 102 [17 CFR 229.102].
    \204\ See letters from Davis Polk, Petro-Canada, Shearman & 
Sterling, SPE, and Zakaib.
    \205\ See letter from Shearman & Sterling.
    \206\ Id.
    \207\ See letter from SPE.
    \208\ See letter from Davis Polk.
    \209\ See letter from Davis Polk.
---------------------------------------------------------------------------

    However, consistent with existing Instruction 5, a company may 
continue to disclose such estimates of non-reserves resources in a 
Commission filing related to an acquisition, merger, or consolidation 
if the company previously provided those estimates to a person that is 
offering to acquire, merge, or consolidate with the company or 
otherwise to acquire the company's securities.\210\ Several commenters 
recommended that the Commission maintain this exception so that the 
company's shareholders would not be at an informational disadvantage 
compared to the counterparty when assessing a merger.\211\ We agree 
with these commenters and have retained the exception in the revised 
Instruction 5 adopted today.
---------------------------------------------------------------------------

    \210\ Id.
    \211\ See letters from Devon, ExxonMobil, Shell, and Total.
---------------------------------------------------------------------------

b. Optional Reserves Sensitivity Analysis Table
    The rules that we are adopting require a company to determine 
whether its oil or gas resources are economically producible based on a 
12-month average price. We also proposed, and are adopting, an optional 
reserves sensitivity table. This table would permit companies to 
disclose additional information to investors, such as the sensitivity 
that oil and gas reserves have to price fluctuations. If a company 
chooses to provide such disclosure, it may choose the different 
scenario or scenarios, if any, that it wishes to disclose in the table, 
provided that it also discloses the price and cost schedules and 
assumptions on which the alternate reserves estimates are based.
    Twelve commenters supported permitting such sensitivity 
analyses.\212\ Some believed that this would provide investors with a 
better view of management's analysis of future prices.\213\ One 
recommended providing a set price change of 10% for the sensitivity 
analysis.\214\ Two other commenters believed that different 
circumstances may require different types of sensitivity analyses, both 
with respect to the range of prices used and the format of the 
presentation.\215\ We agree that the appropriate range for a 
sensitivity analysis may vary depending on the situation, and 
therefore, as proposed, we are not specifying a range of prices to be 
used.
---------------------------------------------------------------------------

    \212\ See letters from Canadian Natural, CAPP, CFA, Chesapeake, 
Deloitte, Devon, Evolution, ExxonMobil, McMoRan, Nexen, Petro-
Canada, and Total.
    \213\ See letters from Chesapeake, Deloitte, and McMoRan.
    \214\ See letter from CFA.
    \215\ See letters from Evolution and Total.
---------------------------------------------------------------------------

    However, five commenters specifically opposed requiring such an 
analysis.\216\ They believed that such a requirement would cause 
confusion and harm comparability.\217\ Three commenters opposed such a 
sensitivity analysis because using different prices could mislead 
investors.\218\ We are adopting this table, as proposed, as a voluntary 
disclosure rather than a requirement. However, as proposed, the table 
would require disclosure of the assumptions behind varying estimates. 
We believe this disclosure will mitigate any investor confusion.
---------------------------------------------------------------------------

    \216\ See letters from Canadian Natural, CAPP, Devon, EnCana, 
and ExxonMobil.
    \217\ See letters from EnCana and Ryder Scott.
    \218\ See letters from Apache, Petrobras, and Wagner.
---------------------------------------------------------------------------

    In addition, we remind companies that Item 303 of Regulation S-K 
(Management's Discussion and Analysis of Financial Condition and 
Results of Operations) \219\ requires discussion of

[[Page 2174]]

known trends and uncertainties, which may include changes to prices and 
costs. A form of this optional reserves sensitivity analysis table is 
set forth below.
---------------------------------------------------------------------------

    \219\ See Item 303 of Regulation S-K [17 CFR 229.303].

                                     Sensitivity of Reserves to Prices by Principal Product Type and Price Scenario
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                         Proved reserves             Probable reserves            Possible reserves
                                                                  --------------------------------------------------------------------------------------
                            Price case                               Oil     Gas    Product A     Oil     Gas    Product A     Oil     Gas    Product A
                                                                    Mbbls   mmcf     measure     mbbls   mmcf     measure     mbbls   mmcf     measure
--------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario 1.......................................................  ......  ......  ...........  ......  ......  ...........  ......  ......  ...........
Scenario 2.......................................................  ......  ......  ...........  ......  ......  ...........  ......  ......  ...........
--------------------------------------------------------------------------------------------------------------------------------------------------------

c. Separate Disclosure of Conventional and Continuous Accumulations
    Under the proposal, new Item 1202 would have required companies to 
disclose reserves from conventional accumulations separately from 
reserves in continuous accumulations. Nine commenters recommended 
disclosure based on the final product.\220\ These commenters opposed 
segregating disclosure based on the type of accumulation that is 
involved.\221\ They believed that such disclosure would be too complex 
and detailed and of little use to investors.\222\ In addition, seven 
commenters pointed out that separation may be impossible because some 
fields contain both conventional and continuous accumulations.\223\ 
This would make allocation of costs arbitrary.\224\ However, four 
commenters supported the definitions and separate disclosure by type of 
accumulation.\225\ One commenter believed that such disclosure would 
allow investors to assess the impact of unconventional sources on 
reserves.\226\
---------------------------------------------------------------------------

    \220\ See letters from Apache, API, Canadian Natural, CAPP, 
EnCana, ExxonMobil, Imperial, Petro-Canada, and Total.
    \221\ See letters from Apache, API, CAPP, Chesapeake, Devon, 
ExxonMobil, Imperial, Repsol, and Shell.
    \222\ See letters from Apache, API, BP, CAPP, Chesapeake, 
Chevron, Devon, E&Y, EnCana, ExxonMobil, Imperial, Petro-Canada, 
Repsol, and Southwestern.
    \223\ See letters from BP, Canadian Natural, CAPP, EnCana, 
Petro-Canada, Ryder Scott, and Talisman.
    \224\ See letters from EnCana and Ryder Scott.
    \225\ See letters from Davis Polk, EIA, Petrobras, and Wagner.
    \226\ See letter from Wagner.
---------------------------------------------------------------------------

    Although we agree conceptually that the focus of reserves 
disclosure should be on the final product, we also recognize that the 
production of oil and gas from varying sources can have significantly 
different economics. Extraction of oil and gas from continuous 
accumulations can be much more labor and resource intensive than 
extraction of oil and gas from traditional wells. They often require 
greater ongoing efforts and expense after the initial extraction 
equipment is in place, making such operations more sensitive to price 
fluctuations.
    We agree with the commenters that disclosure based on the end 
product sold would provide a more effective basis for distinguishing 
reserves that disclosure based on the type of accumulation in which the 
reserves are held. Therefore, we have revised the disclosure to be 
based on the end product that is sold by the company.\227\ However, 
with respect to the end product, new Item 1202 makes a distinction 
between oil and gas, on the one hand, and synthetic oil and gas, on the 
other. Synthetic products require processing of the raw resource 
material, either while it is still in the ground (``in situ'') or after 
it is extracted, before it can be used as refinery feedstock or as 
natural gas. Such processes currently include bitumen upgrading as well 
as coal liquefaction and gasification. However, resources from some 
continuous accumulations, such as coalbed methane, do not require such 
processing and therefore are not associated with the same level of 
ongoing costs once a well has been drilled because the in-ground 
resource is already oil or gas (in the case of coalbed methane, the in-
ground resource is methane, trapped in a coalbed). Thus, coalbed 
methane would not be considered a synthetic product.
---------------------------------------------------------------------------

    \227\ See Item 1202 [17 CFR 229.1202].
---------------------------------------------------------------------------

d. Preparation of Reserves Estimates or Reserves Audits
    In the Proposing Release, we proposed to require a company to 
disclose whether or not the technical person \228\ primarily 
responsible for preparing the reserves estimate possessed certain 
specified qualifications and was subject to a list of controls for 
maintaining objectivity. Most commenters addressing the issue opposed 
this proposed requirement.\229\ However, many of these commenters 
appeared to believe that the disclosure requirement would pertain to 
every person involved with the estimation process.\230\ If adopted, 
they noted that such disclosure would be voluminous, adding unnecessary 
complexity to disclosures.\231\ Four commenters suggested that we 
clarify that the disclosure is limited to the chief technical person 
who oversees the company's overall reserves estimation process,\232\ 
which was the intent of the proposal. Five commenters supported this 
disclosure because it helps users understand the objectivity and 
quality of reserves estimates.\233\
---------------------------------------------------------------------------

    \228\ With regard to the objectivity of a technical person, the 
``person'' could be an individual or an entity, as appropriate. 
However, with regard to the qualifications of a person, the 
disclosure would relate to the individual who is primarily 
responsible for the technical aspects of the reserves estimation or 
audit. Thus, this individual is not necessarily the individual 
generally overseeing the estimation or audit, but the individual who 
is primarily responsible for the actual calculations and estimation 
or audit.
    \229\ See letters from Apache, API, Chevron, Energen, Eni, 
ExxonMobil, Newfield, Nexen, PEMEX, Petro-Canada, Ryder Scott, 
Shell, and Total.
    \230\ See letters from Apache, API, ExxonMobil, Newfield, Nexen, 
PEMEX, Ryder Scott, and Total.
    \231\ See letters from Apache, API, ExxonMobil, Newfield, Nexen, 
PEMEX, Repsol, and Total.
    \232\ See letters from API, ExxonMobil, PEMEX, and Petro-Canada.
    \233\ See letters from CFA, Devon, EnCana, Southwestern, and 
Wagner.
---------------------------------------------------------------------------

    It was our intent to limit the disclosure to the technical person 
primarily responsible for overseeing the reserves estimates. However, 
there may have been confusion with respect to this point based on a 
footnote which stated that we sought disclosure about the person who 
``is primarily responsible for the actual calculations and estimation 
or audit.'' By that term, we did not intend to include any person 
making ``actual calculations.'' We recognize that, ultimately, the 
reserves estimates are overseen by top management, which may or may not 
have reserves estimation expertise. The focus of the final rule is the 
primary technical person responsible for overseeing the preparation of 
the reserves estimation process. We have

[[Page 2175]]

revised the language in the rule to clarify this point.\234\
---------------------------------------------------------------------------

    \234\ See Item 1202(a)(7) [17 CFR 229.1202(a)(7)].
---------------------------------------------------------------------------

    Two commenters noted that it was inconsistent to require such 
precise disclosure about reserves experts, but not other experts.\235\ 
One of those commenters recommended that the rule require expert 
language, including clear disclosure of which portion of the reserves 
estimate the third party is expertising and filed consents.\236\ The 
concept of an expert under the Securities Act is different from the 
disclosures that we seek regarding the qualifications and objectivity 
of persons responsible for the preparation or audit of oil and gas 
reserves. Under the Securities Act, disclosure must be made when the 
company represents that disclosure is based on the authority of an 
expert. Although the Securities Act concept of experts will continue to 
be relevant when the reserves disclosures are in, or incorporated into, 
a Securities Act filing and the company represents that disclosure is 
based on the authority of an expert, the new rules requiring disclosure 
about the reserves preparer or auditor in a company's Exchange Act 
reports are intended to help investors determine whether reserves 
estimates, which are highly technical, have been prepared by a 
qualified, objective person, regardless of whether that person is an 
employee of the company.
---------------------------------------------------------------------------

    \235\ See letters from API and Deloitte.
    \236\ See letter from Deloitte.
---------------------------------------------------------------------------

    However, we agree with commenters that a prescribed list of 
qualifications and objectivity requirements may be too rigid for all 
situations. With respect to technical qualifications, several 
commenters noted that licensing requirements can vary greatly among 
jurisdictions.\237\ Commenters also believed that disclosure of a 
person's objectivity was unnecessary because management is required to 
install appropriate internal controls to ensure the reliability of 
reserves estimates.\238\ In fact, some commenters recommended that we 
limit the disclosure to a description of a company's internal controls, 
including the company's technical assessment routine, management and 
board review and approval processes, the internal audit process, the 
extent to which the company uses external parties to estimate or audit 
reserves estimates, and a summary description of the qualifications of 
the company's typical reserves estimators.\239\ We are following these 
commenters' recommendations and adopting a rule that requires a company 
to provide a general discussion of the internal controls that it uses 
to assure objectivity in the reserves estimation process and disclosure 
of the qualifications of the technical person primarily responsible for 
preparing the reserves estimates or conducting the reserves audit if 
the company discloses that such a reserves audit has been performed, 
regardless of whether the technical person is an employee or an outside 
third party.\240\
---------------------------------------------------------------------------

    \237\ See letters from AAPG, API, Chevron, Eni, Petro-Canada, 
Questar, and SPE.
    \238\ See letters from API, Chevron, Energen, ExxonMobil, 
Newfield, Nexen, Petrobras, Ryder Scott, Shell, StatoilHydro, and 
Total.
    \239\ See letters from ExxonMobil, Nexen, Shell, and 
StatoilHydro.
    \240\ See Item 1202(a)(7) [17 CFR 229.1202(a)(7)].
---------------------------------------------------------------------------

    We did not propose, but sought comment on, whether the rules should 
require a company to retain an independent third party to prepare, or 
conduct a reserves audit of, the company's reserves estimates. Most 
commenters urged the Commission not to adopt such a requirement.\241\ 
They believed that a company's internal staff, particularly at larger 
companies, is generally in a better position to prepare those estimates 
\242\ and that there is a potential lack of qualified third party 
engineers and other professionals available to conduct the increased 
work that would result from such a requirement.\243\ We agree with 
these commenters and are not adopting a requirement that an independent 
third party prepare, or conduct a reserves audit of, the company's 
reserves estimates.
---------------------------------------------------------------------------

    \241\ See letters from API, BHP, BP, CFA, CNOOC, Denbury, Devon, 
Eni, Energy Literacy, ExxonMobil, Imperial, R. Jones, D. McBride, 
Newfield, Nexen, Petro-Canada, Ross, D. Ryder, Sasol, Shell, 
Talisman, Total, and W. van de Vijver.
    \242\ See letters from API, Denbury, ExxonMobil, Imperial, 
Nexen, Shell, and Talisman.
    \243\ See letters from AAPG, API, BP, Devon, ExxonMobil, 
Imperial, D. McBride, Newfield, D. Ryder, and Sasol.
---------------------------------------------------------------------------

e. Reserve Audits and The Contents of Third-Party Reports
    In the Proposing Release, we proposed that, if a company represents 
that its estimates of reserves are prepared or audited by a third 
party, the company must file a report of the third party as an exhibit 
to the relevant registration statement or report. Two commenters 
believed that a company description of the third party's report would 
be sufficient because the reports can contain sensitive 
information.\244\ However, another commenter was concerned that not 
filing the report may lead to mischaracterizations by the company.\245\ 
This commenter supported the filing of a report by the third party 
reserves estimator or auditor, but believed that the Commission should 
determine the contents of such a report.\246\ Two commenters supported 
the filing of the report ``letter'' as an exhibit, but not the full 
reserves report because it may contain proprietary information.\247\
---------------------------------------------------------------------------

    \244\ See letters from Evolution and Petro-Canada.
    \245\ See letter from Wagner.
    \246\ See letter from Wagner.
    \247\ See letters from Devon and Ryder Scott.
---------------------------------------------------------------------------

    As proposed, we are adopting a new rule to require that if the 
company represents that a third party prepared the reserves estimate or 
conducted a reserves audit of the reserves estimates, the company must 
file a report of the third party as an exhibit to the relevant 
registration statement or report.\248\ These reports need not be the 
full ``reserves report,'' which is often very detailed and voluminous. 
Rather, these reports could be shorter form reports that summarize the 
scope of work performed by, and conclusions of, the third party. These 
reports must include the following disclosure, based on the Society of 
Petroleum Evaluation Engineers's audit report guidelines:
---------------------------------------------------------------------------

    \248\ See Item 1202(a)(8) [17 CFR 229.1202(a)(8)].
---------------------------------------------------------------------------

     The purpose for which the report is being prepared and for 
whom it is prepared;
     The effective date of the report and the date on which the 
report was completed;
     The proportion of the company's total reserves covered by 
the report and the geographic area in which the covered reserves are 
located;
     The assumptions, data, methods, and procedures used to 
conduct the reserves audit, including the percentage of company's total 
reserves reviewed in connection with the preparation of the report, and 
a statement that such assumptions, data, methods, and procedures are 
appropriate for the purpose served by the report;
     A discussion of primary economic assumptions;
     A discussion of the possible effects of regulation on the 
ability of the registrant to recover the estimated reserves;
     A discussion regarding the inherent risks and 
uncertainties of reserves estimates;
     A statement that the third party has used all methods and 
procedures as it considered necessary under the circumstances to 
prepare the report; and
     The signature of the third party.

In addition, if the report is related to a reserves audit, it must 
contain a brief summary of the third party's conclusions with respect 
to the reserves estimates. Finally, if the disclosures are

[[Page 2176]]

made in, or incorporated into, a Securities Act registration statement, 
the company must file a consent of the third party as an exhibit to the 
filing.
    In the Proposing Release, we proposed to define the term ``reserves 
audit'' as ``the process of reviewing certain of the pertinent facts 
interpreted and assumptions made that have resulted in an estimate of 
reserves prepared by others and the rendering of an opinion about the 
appropriateness of the methodologies employed, the adequacy and quality 
of the data relied upon, the depth and thoroughness of the reserves 
estimation process, the classification of reserves appropriate to the 
relevant definitions used, and the reasonableness of the estimated 
reserves quantities. In order to disclose that a `reserves audit' has 
been conducted, the report resulting from this review must represent an 
examination of at least 80% of the portion of the registrant's reserves 
covered by the reserves audit.'' We are substantively adopting the 
first sentence of this definition as proposed.
    However, in response to comments received, we are not adopting the 
proposed second sentence of the definition of the term ``reserves 
audit.'' Two commenters supported the proposed 80% threshold regarding 
the proportion of reserves that a reserves auditor must review in order 
for the company to characterize that auditor's work as a ``reserves 
audit.'' \249\ Another commenter believed that the 80% threshold was 
appropriate for preparing reserves estimates.\250\ But three commenters 
believed that an audit should simply disclose the percentage that was 
audited.\251\ One of these noted that it has its reserves audit 
performed on a rolling basis.\252\ We believe that disclosure of the 
work done in the required third-party report makes a bright-line 
percentage test unnecessary. If a company conducts its reserves audit 
on a rolling basis, it is appropriate for its shareholders to be aware 
of that fact. Therefore, we are not adopting the proposed 80% 
threshold. We believe that disclosure of the scope of the review will 
enable investors to assess the significance to attribute to a reserves 
audit.
---------------------------------------------------------------------------

    \249\ See letters from Evolution and Wagner.
    \250\ See letter from Ryder Scott.
    \251\ See letters from Devon, Ryder Scott, and Talisman.
    \252\ See letter from Talisman.
---------------------------------------------------------------------------

f. Process Reviews
    In the Proposing Release, we solicited comment regarding whether we 
should permit a company to disclose that it has hired a third party to 
perform a process review under the Society of Petroleum Engineers' 
(SPE's) reserves auditing standards.\253\ Those standards define a 
process review as an investigation by a person who is qualified by 
experience and training equivalent to that of a reserves auditor to 
address the adequacy and effectiveness of an entity's internal 
processes and controls relative to reserves estimation. However, those 
standards also note that a process review should not include an opinion 
relative to the reasonableness of the reserves quantities and should be 
limited to the processes and control system reviewed. The SPE's 
standards state that, although such reviews may provide value to the 
entity, an external or internal process review is not of sufficient 
rigor to establish appropriate classifications and quantities of 
reserves and should not be represented to the public as being 
equivalent to a reserves audit.
---------------------------------------------------------------------------

    \253\ See SPE Reserves Auditing Standards.
---------------------------------------------------------------------------

    Five commenters believed that internal process reviews are helpful 
in promoting accuracy and effectiveness, so companies should be 
permitted to disclose them.\254\ However, one commenter was concerned 
that, although a process review can be helpful for a company, 
disclosure may give investors a false sense of security.\255\ Two 
commenters suggested that, if a company discloses that it performed a 
process review, it should clearly disclose what a process review 
is.\256\
---------------------------------------------------------------------------

    \254\ See letters from Devon, ExxonMobil, Petro-Canada, Ryder 
Scott, and Shell.
    \255\ See letter from Wagner.
    \256\ See letters from Devon and Petro-Canada.
---------------------------------------------------------------------------

    We agree that a process review can be helpful to the company and 
ultimately to investors. However, we also agree that if a company 
discloses that it has hired a third party to perform a process review, 
it must clearly disclose the details surrounding that process review. 
As such, the new rules treat a process review similar to a reserves 
audit. If the company discloses that it has hired a third party to 
conduct a process review, it must file a report of the third party as 
an exhibit to the relevant registration statement or report and, if the 
disclosures are made in, or incorporated into, a Securities Act 
registration statement, the company must file a consent of the third 
party as an exhibit to the filing.\257\
---------------------------------------------------------------------------

    \257\ See Item 1202(a)(8) [17 CFR 229.1202(a)(8)].
---------------------------------------------------------------------------

4. Item 1203 (Proved Undeveloped Reserves)
    We proposed requiring tabular disclosure of the aging of proved 
undeveloped reserves (PUDs). Proposed Item 1203 would have required an 
oil and gas company to prepare a table showing, for each of the last 
five fiscal years and by product type, proved reserves estimated using 
current prices and costs in the following categories:
     Proved undeveloped reserves converted to proved developed 
reserves during the year; and
     Net investment required to convert proved undeveloped 
reserves to proved developed reserves during the year.\258\
---------------------------------------------------------------------------

    \258\ See Item 1204 [17 CFR 229.1204].
---------------------------------------------------------------------------

    Numerous commenters were concerned that the proposed five-year 
table would be too complex for investors to understand.\259\ They 
expressed concern that the proposed table may mislead investors by not 
clearly attributing costs to the year in which the corresponding PUDs 
are converted because much of the costs may have been spent in previous 
years.\260\ In addition, commenters noted that maintenance of such data 
would be costly \261\ and that companies currently do not always 
capture this type of information because management does not use it to 
run the business.\262\
---------------------------------------------------------------------------

    \259\ See letters from API, BP, Canadian Natural, CAPP, Chevron, 
Eni, Equitable, ExxonMobil, Nexen, Petrobras, Repsol, Shell, and 
Wagner.
    \260\ See letters from API, ExxonMobil, Petrobras, Ryder Scott, 
Total, and Wagner.
    \261\ See letters from API, Canadian Natural, CAPP, Chevron, 
Eni, Equitable, ExxonMobil, Nexen, Petrobras, Southwestern, and 
Wagner.
    \262\ See letter from Apache.
---------------------------------------------------------------------------

    Eight commenters suggested an alternative of disclosing (1) the 
quantity of undeveloped reserves if material, (2) the progress in 
converting PUDs, and (3) any material changes in the current year.\263\ 
Three U.S. Senators recommended requiring disclosure of development 
plans in addition to the table.\264\ They believed that requiring 
reporting of investments and planned investments in oil and gas 
development would provide investors with certainty about companies' 
intentions to develop the federal lands that they have at their 
disposal.\265\ However, three commenters opposed disclosure of a 
company's plans to drill and expected capital expenditures because 
disclosing their business plan may cause competitive harm and might 
expose them to litigation if results differ from their plan.\266\ Six 
commenters supported the proposed table.\267\
---------------------------------------------------------------------------

    \263\ See letters from API, Canadian Natural, Chevron, 
ExxonMobil, Newfield, Nexen, Petrobras, and Ryder Scott.
    \264\ See letter from Three Senators.
    \265\ See letter from Three Senators.
    \266\ See letters from Chesapeake, Devon, and Newfield.
    \267\ See letters from Chesapeake, Deloitte, Devon, Three 
Senators, Talisman, and Wagner.

---------------------------------------------------------------------------

[[Page 2177]]

    We recognize the concern that the PUD table that we proposed may be 
confusing to investors because it would not attribute capital 
expenditures to the corresponding reserves as they are developed. As an 
alternative to the proposed table, we are adopting rules that require a 
company to disclose the following in narrative form:
     The total quantity of PUDs at year end;
     Any material changes in PUDs that occurred during the 
year, including PUDs converted into proved developed reserves;
     Investments and progress made during the year to convert 
PUDs to proved developed oil and gas reserves; and
     An explanation of the reasons why material concentrations 
of PUDs in individual fields or countries have remained undeveloped for 
five years or more after disclosure as PUDs.\268\
---------------------------------------------------------------------------

    \268\ See Item 1203 [17 CFR 229.1203].
---------------------------------------------------------------------------

    These disclosures would have been required under the proposal, but 
much of it would have been presented in tabular format. We believe that 
a narrative approach to these disclosures will provide companies with a 
better vehicle to explain the status of their PUDs and their track 
record for developing such reserves. Rather than requiring forward-
looking information about a company's plans to develop reserves that 
may lead to exaggeration of a company's capability to actually convert 
such reserves, we believe that disclosure of a company's verifiable, 
established track record of converting such reserves, including its 
ability to obtain financing for such activities, would be a better 
indication of the likelihood of that company's success in developing 
reserves in the future. Specific required disclosure regarding a 
company's failure to develop material concentrations of PUDs for five 
or more years should address commenters' concerns that the company may 
have no intention to develop such reserves.
5. Item 1204 (Oil and Gas Production)
    We proposed to codify the Industry Guide 2 disclosure regarding oil 
and gas production as Item 1204 of Regulation S-K, in tabular form and 
with greater detail. One commenter did not believe that separating 
production, sales price and production costs based on whether they were 
related oil wells or gas wells would be valuable to investors.\269\ It 
believed that companies do not use this information to manage their 
business and do not maintain systems to capture this information on 
that basis, so tracking such data would require costly changes to their 
systems.\270\ Two commenters also believed that it would not be 
possible to separate production cost by product because many units 
extract different products.\271\ One commenter also recommended that 
production not be segregated by type of accumulation.\272\
---------------------------------------------------------------------------

    \269\ See letter from Apache.
    \270\ See letter from Apache.
    \271\ See letters from Total and ExxonMobil.
    \272\ See letter from ExxonMobil.
---------------------------------------------------------------------------

    We have decided not to adopt Item 1204 as proposed. Rather, we are 
codifying the existing Industry Guide 2 disclosure item with several 
revisions. Consistent with the Industry Guide 2 disclosure item, the 
Item 1204, as adopted, requires disclosure, for each of the prior three 
fiscal years, of production, by final product sold, of oil, gas, and 
other products. In addition, for the same time period, the company must 
disclose, by geographical area:
     The average sales price (including transfers) per unit of 
oil, gas and other products produced; and
     The average production cost, not including ad valorem and 
severance taxes, per unit of production.
    However, unlike the Industry Guide disclosure item, this disclosure 
must be made by geographical area and for each country and field 
containing 15% or more of the registrant's proved reserves, expressed 
on an oil-equivalent-barrels basis.
    Similarly, we are codifying the instructions to the Industry Guide 
2 item. One commenter recommended that we maintain some of the existing 
instructions from the Industry Guide.\273\ The first instruction 
codified from the Industry Guide clarifies that net production should 
include only production that is owned by the registrant and produced to 
its interest, less royalties and production due others. However, in 
special situations (e.g., foreign production), net production before 
any royalties may be provided, if more appropriate. If ``net before 
royalty'' production figures are furnished, the change from the usage 
of ``net production'' should be noted.
---------------------------------------------------------------------------

    \273\ See letter from ExxonMobil.
---------------------------------------------------------------------------

    The second instruction, which is also from the Industry Guide, 
states that production of natural gas should include only marketable 
production of natural gas on an ``as sold'' basis. Production will 
include dry, residue, and wet gas, depending on whether liquids have 
been extracted before the registrant transfers title. Flared gas, 
injected gas, and gas consumed in operations should be omitted. 
Recovered gas-lift gas and reproduced gas should not be included until 
sold. Synthetic gas, when marketed as such, should be included in 
natural gas sales.
    We are adding a third instruction that was not in the Industry 
Guide. This instruction states that, if any product, such as bitumen, 
is sold or custody is transferred prior to conversion to synthetic oil 
or gas, the product's production, transfer prices, and production costs 
should be disclosed separately from all other products. This 
instruction is necessary because the existing Industry Guide 2 
disclosure requirement only required separate disclosure based on 
whether the end product was oil or gas. This instruction merely 
clarifies that disclosures under this item must be based on the end 
product, which may not be oil or gas because the amendments will permit 
the disclosure of reserves of other end products, such as bitumen.
    The fourth instruction codified from the Industry Guide states that 
the transfer price of oil and gas (natural and synthetic) produced 
should be determined in accordance with SFAS 69. And the fifth 
instruction codified from the Industry Guide clarifies that the average 
production cost per unit of production should be computed using 
production costs disclosed pursuant to SFAS 69. Units of production 
should be expressed in common units of production with oil, gas, and 
other products converted to a common unit of measure on the basis used 
in computing amortization. This instruction also adds products from 
unconventional sources to the existing disclosure Item in Industry 
Guide 2.
6. Item 1205 (Drilling and Other Exploratory and Development 
Activities)
    We proposed to codify the Industry Guide 2 disclosure item 
regarding drilling activities as Item 1205 of Regulation S-K, in 
tabular form, with several revisions to that Industry Guide 2 
disclosure item, including applying a new definition of the term 
``geographic area'' and adding two categories of wells:
     Extension wells; and
     Suspended wells.
    Three commenters believed that the disclosures required under this 
proposed Item would become too detailed.\274\ One of these commenters 
also believed that the number of wells being drilled does not provide 
an accurate picture of a company's drilling

[[Page 2178]]

activities because of the increased usage of horizontal wells.\275\
    Some commenters also did not believe that creating new categories 
for extension wells and suspended wells would be meaningful.\276\ They 
noted the burden of the added detail would exceed the value of the 
information to investors.\277\ One pointed out that determining whether 
a well constitutes an extension well would be difficult because of 
multipurpose drilling.\278\
---------------------------------------------------------------------------

    \274\ See letters from Apache, ExxonMobil, and Total.
    \275\ See letter from ExxonMobil.
    \276\ See letters from Apache, API, and Imperial.
    \277\ See letters from Apache and Southwestern.
    \278\ See letter from Total.
---------------------------------------------------------------------------

    After considering the above comments, we have decided not to adopt 
all of the proposed revisions to the existing Industry Guide 2 
disclosure. We recognize that, for some companies that use advanced 
drilling techniques, the proposed disclosure may not be a good 
indicator of the extent of their exploratory and development 
activities, although we believe that this disclosure is still important 
for many companies. Therefore, we have decided to codify the existing 
disclosures found in Industry Guide 2 related to drilling activities 
without revision and to not require tabular disclosure.\279\ However, 
as proposed, we are adding a new provision to this Item that requires 
companies to discuss their exploratory and development activities 
regarding oil and gas resources that are extracted by mining techniques 
because we are now including such resources under the definition of 
``oil and gas producing activities.''
---------------------------------------------------------------------------

    \279\ See Item 1205 [17 CFR 229.1205].
---------------------------------------------------------------------------

7. Item 1206 (Present Activities)
    Item 1206 codifies existing Item 7 of Industry Guide 2, which calls 
for disclosure of present activities, including the number of wells in 
the process of being drilled (including wells temporarily suspended), 
waterfloods in process of being installed, pressure maintenance 
operations, and any other related activities of material 
importance.\280\ We are adopting Item 1206 substantially as proposed.
---------------------------------------------------------------------------

    \280\ See Item 1206 [17 CFR 229.1206].
---------------------------------------------------------------------------

8. Item 1207 (Delivery Commitments)
    Item 1207 codifies existing Item 8 of Industry Guide 2, which calls 
for disclosure of arrangements under which the company is required to 
deliver specified amounts of oil or gas and how the company intends to 
meet such commitments.\281\ We are not adopting any substantive changes 
to the disclosure currently called for by Item 8 of Industry Guide 2. 
However, we are restructuring and rewording the disclosure item to make 
it easier to understand, including separating embedded lists into 
separate subparagraphs and making general plain English revisions. As 
proposed, these revisions are not intended to change the substance of 
the disclosures.
---------------------------------------------------------------------------

    \281\ See Item 1207 [17 CFR 229.1207].
---------------------------------------------------------------------------

9. Item 1208 (Oil and Gas Properties, Wells, Operations, and Acreage)
    We proposed to codify disclosure about oil and gas properties, 
wells, operations, and acreage as Item 1208 of Regulation S-K, in 
tabular form, as well as make several revisions to the existing 
disclosures, including applying a new definition of the term 
``geographic area'' and adding language that better illustrates the 
types of properties and the types of disclosures for those properties, 
including the following:
     Identification and description generally of the company's 
material properties, plants, facilities, and installations;
     Identification of the geographic area in which they are 
located;
     Indication of whether they are located onshore or 
offshore; and
     Description of any statutory or other mandatory 
relinquishments, surrenders, back-ins, or changes in ownership.
    Six commenters believed that it is not necessary to enhance this 
section from Industry Guide 2 because the requirements are already 
covered by Item 102 of Regulation S-K.\282\ Commenters were 
particularly concerned with the segmentation of this disclosure by 
product, by type of accumulation, and by geographic location.\283\ They 
believed that this level of detail would not be helpful to investors 
and would impose added costs on companies because they currently do not 
collect this detailed information.\284\ Moreover, seven commenters 
thought that the well count disclosure is no longer meaningful because 
of technologies such as horizontal drilling.\285\ They thought that, in 
light of these new technologies, well count disclosure could be 
misleading.\286\
    As with the case of drilling activities, we agree that the proposed 
added detail could make the disclosures too cumbersome. In addition, 
such disclosure may be of less importance to many companies because of 
new drilling technology. Therefore, we are merely codifying the 
existing Industry Guide 2 disclosure, without revision.\287\
---------------------------------------------------------------------------

    \282\ See letters from API, Chevron, ExxonMobil, Imperial, 
Shell, and Total.
    \283\ See letters from Apache, ExxonMobil, Shell, and Total.
    \284\ See letters from Apache, ExxonMobil, and Petro-Canada.
    \285\ See letters from API, BP, Chevron, ExxonMobil, Imperial, 
StatoilHydro, and Total.
    \286\ See letters from API and Imperial.
    \287\ See Item 1208 [17 CFR 229.1208].
---------------------------------------------------------------------------

V. Guidance for Management's Discussion and Analysis for Companies 
Engaged in Oil and Gas Producing Activities

    We proposed to add a new Item 1209, which would have specified 
topics that a company should address either as part of its Management's 
Discussion and Analysis of Financial Condition and Results of 
Operations (MD&A) or in a separate section.\288\ Four commenters were 
concerned that, although the proposed Item was intended to provide more 
guidance regarding the disclosures required, it would effectively 
require companies to address all of the issues listed in the Item.\289\ 
One recommended that, instead of a detailed list, the requirement 
should clarify that companies should address ``material changes due to 
technology, prices, concession conditions, commercial terms, known 
trends, demands, commitments, uncertainties and any events that are 
reasonably likely to have a material effect on reserves estimates and 
financial condition.'' \290\ Similarly, another commenter recommended 
that the Commission clarify that the Item is limited to material 
impacts.\291\
---------------------------------------------------------------------------

    \288\ See Item 303 of Regulation S-K [17 CFR 229.303].
    \289\ See letters from Chevron, ExxonMobil, Petrobras, and 
Shell.
    \290\ See letter from Repsol.
    \291\ See letter from Total.
---------------------------------------------------------------------------

    We are not adopting the proposed Item as part of Regulation S-K 
because it is intended to be guidance, rather than a specific 
disclosure Item. We agree that, if companies were to discuss every 
issue provided in the list, the disclosure would be too long and 
detailed to be of much use to most investors. Important issues could be 
hidden amid unnecessary detail. However, we believe that added guidance 
would be beneficial to companies regarding the issues that the 
Commission's staff commented upon in its review of the MD&A section of 
filings made by oil and gas companies.
    To begin, a fundamental premise of MD&A is that the information 
provided should be related to issues that are material to a company. 
Although we discuss a list of topics that a company might need to 
discuss, a company need only discuss a topic if it constitutes, 
involves, or indicates known trends, demands, commitments, 
uncertainties, and events that are reasonably likely to have a material 
effect on the company. These topics include:

[[Page 2179]]

     Changes in proved reserves and, if disclosed, probable and 
possible reserves, and the sources to which such changes are 
attributable, including changes made due to:
    [cir] Changes in prices;
    [cir] Technical revisions; and
    [cir] Changes in the status of any concessions held (such as 
terminations, renewals, or changes in provisions);
     Technologies used to establish the appropriate level of 
certainty for any material additions to, or increases in, reserves 
estimates, including any material additions or increases to reserves 
estimates that are the result of any of the final rules adopted in this 
release;
     Prices and costs, including the impact on depreciation, 
depletion and amortization as well as the full cost ceiling test;
     Performance of currently producing wells, including water 
production from such wells and the need to use enhanced recovery 
techniques to maintain production from such wells;
     Performance of any mining-type activities for the 
production of hydrocarbons;
     The company's recent ability to convert proved undeveloped 
reserves to proved developed reserves, and, if disclosed, probable 
reserves to proved reserves and possible reserves to probable or proved 
reserves;
     The minimum remaining terms of leases and concessions;
     Material changes to any line item in the tables described 
in Items 1202 through 1208 of Regulation S-K;
     Potential effects of different forms of rights to 
resources, such as production sharing contracts, on operations; and
     Geopolitical risks that apply to material concentrations 
of reserves.
    The MD&A is typically presented in a self-contained section of the 
registration statement or report. However, the disclosure requirements 
that comprise new Subpart 1200 of Regulation S-K will cause a 
substantial amount of an oil and gas company's disclosure to appear in 
tabular format, providing an outline of much of a company's operations. 
Because the tables will present many of the types of changes that 
management often discusses in its MD&A, we believe it may be more 
helpful to investors to locate such discussion close to the tables 
themselves. Thus, to the extent that any discussion or analysis of 
known trends, demands, commitments, uncertainties, and events that are 
reasonably likely to have a material effect on the company is directly 
relevant to a particular disclosure required by Subpart 1200, the 
company may include that discussion or analysis with the relevant 
table, with appropriate cross-references, rather than including it in 
its general MD&A section.

VI. Conforming Changes to Form 20-F

    Form 20-F is the form on which foreign private issuers file their 
annual reports and Exchange Act registration statements. Currently, 
Form 20-F contains instructions that are similar to those in Item 102 
of Regulation S-K. However, rather than referring to Industry Guide 2 
for disclosures regarding oil and gas producing activities, Form 20-F 
contains its own ``Appendix A to Item 4.D--Oil and Gas'' (Appendix A) 
that provides guidance for oil and gas disclosures for foreign private 
issuers.\292\ Appendix A is significantly shorter, and provides far 
less guidance regarding disclosures, than Subpart 1200 or Industry 
Guide 2. We proposed to revise Form 20-F to eliminate the reference to 
Appendix A, and rather refer to Subpart 1200, which would expand the 
disclosures required by foreign private issuers.
---------------------------------------------------------------------------

    \292\ See Appendix A to Item 4.D--Oil and Gas of Form 20-F [17 
CFR 249.220f].
---------------------------------------------------------------------------

    Six commenters supported harmonizing the Form 20-F disclosures with 
Regulation S-K.\293\ One noted that the proposal would make disclosure 
more consistent and comparable among oil companies.\294\ It believed 
the proposal would put all oil companies on a level playing field.\295\ 
However, one commenter recommended that the Commission exempt companies 
reporting under International Financial Reporting Standards 
(IFRS).\296\ It also recommended that instead of applying the proposed 
Subpart 1200 to foreign private issuers, the Commission should revise 
Appendix A to Form 20-F itself, making appropriate limitations for 
foreign private issuers, such as eliminating the disclosure of wells 
and acreage.\297\ Another commenter was concerned because the proposals 
may hinder, rather than facilitate, transition to the use of IFRS.\298\
---------------------------------------------------------------------------

    \293\ See letters from CAQ, Deloitte, ExxonMobil, KPMG, PWC, and 
Shell.
    \294\ See letter from ExxonMobil.
    \295\ See letter from ExxonMobil.
    \296\ See letter from Total.
    \297\ See letter from Total.
    \298\ See letter from Ross.
---------------------------------------------------------------------------

    We continue to believe that Subpart 1200 would be appropriate 
disclosure for all public companies engaged in oil and gas producing 
activities, including foreign private issuers. The added guidance in 
Subpart 1200 should promote more consistent and comparable disclosures 
among oil and gas companies. It is our understanding that many of the 
larger foreign private issuers already provide disclosure in their 
filings with the Commission comparable to the disclosure provided by 
domestic companies. Thus, we are revising Form 20-F to incorporate 
Subpart 1200 with respect to oil and gas disclosures and delete 
Appendix A to Item 4.D in that form. We recognize that this requirement 
may require a foreign private issuer to prepare two different reserves 
estimates if the rules in their home jurisdiction require a different 
pricing standard than the 12-month average that we adopt in this 
release. However, we believe the same conflict would have existed under 
our previous rule to the extent our pricing method differed from the 
home jurisdiction's method.
    Appendix A currently allows a foreign private issuer to exclude 
required disclosures about reserves and agreements if its home country 
prohibits the disclosures. Two commenters suggested that the rule 
continue to provide an exception for disclosures about reserves and 
agreements that are prohibited by foreign laws.\299\ However, another 
commenter believed that a company taking advantage of such an exception 
should be required to disclose the country, the citation of the 
relevant law or regulation, and the fact that the disclosed estimates 
do not include amounts from the named country.\300\ We are not revising 
this provision. Rather, because these considerations still apply to 
such foreign private issuers, we are moving that provision from 
Appendix A and adopting it as Instruction 2 to Item 4 of Form 20-F, as 
proposed.\301\
---------------------------------------------------------------------------

    \299\ See letters from Shell and Total.
    \300\ See letter from ExxonMobil.
    \301\ Id.
---------------------------------------------------------------------------

    One commenter recommended clarifying that the new disclosures would 
not apply to foreign private issuers under the Multi-Jurisdictional 
Disclosure System (MJDS) using Form 40--F that comply with NI 51-101 in 
Canada because those rules already are broadly consistent with 
PRMS.\302\ We agree with this commenter and believe that such issuers 
need not provide disclosures beyond those required in Canada.
---------------------------------------------------------------------------

    \302\ See letter from Deloitte.
---------------------------------------------------------------------------

VII. Impact of Amendments on Accounting Literature

A. Consistency With FASB and IASB Rules

    Numerous commenters recommended that the SEC generally coordinate 
its efforts with the IASB and FASB to create a cohesive whole and not 
adopt

[[Page 2180]]

competing models.\303\ We have begun, and will continue, to work with 
both of these organizations to ensure a smooth transition to the new 
reporting rules.
---------------------------------------------------------------------------

    \303\ See letters from CAQ, CFA, Eni, Grant Thornton, KPMG, and 
PWC.
---------------------------------------------------------------------------

B. Change in Accounting Principle or Estimate

    In the Proposing Release, we expressed our view that the change 
from using single-day year-end price to an average price should be 
treated as a change in accounting principle, or a change in the method 
of applying an accounting principle, that is inseparable from a change 
in accounting estimate. Therefore, this change would be considered a 
change in accounting estimate pursuant to Statement of Financial 
Accounting Standard No. 154 ``Accounting Changes and Error 
Corrections'' (SFAS 154) and would be accounted for prospectively.
    Commenters believed that the change would be best described as:
     A change in accounting estimate; \304\
---------------------------------------------------------------------------

    \304\ See letters from CAQ, Canadian Natural, CAPP, Deloitte, 
Devon, KPMG, Petrobras, PWC, Repsol, Shell, and StatoilHydro.
---------------------------------------------------------------------------

     A change in accounting principle that is inseparable from 
a change in accounting estimate; or \305\
---------------------------------------------------------------------------

    \305\ See letter from Deloitte.
---------------------------------------------------------------------------

     A change in accounting estimate effected by a change in 
accounting principle.\306\
---------------------------------------------------------------------------

    \306\ See letter from Petro-Canada.
---------------------------------------------------------------------------

    We believe that any accounting change resulting from the changes in 
definitions and required pricing assumptions in Rule 4-10, should be 
treated as a change in accounting principle that is inseparable from a 
change in accounting estimate, which does not require retroactive 
revision. We note that pursuant to AU 420.13, such a change requires 
recognition in the independent auditor's report through the addition of 
an explanatory paragraph.
    All commenters on the issue agreed that adoption of the rules 
should not require retroactive revision of past reserves 
estimates.\307\ Some believed retroactive revision of reserves 
estimates would be very burdensome or impossible because such data was 
not maintained.\308\ We agree with those commenters and believe that no 
retroactive revisions will be necessary.
---------------------------------------------------------------------------

    \307\ See letters from Apache, CAQ, Canadian Natural, CAPP, 
Deloitte, Devon, Evolution, ExxonMobil, Petrobras, Petro-Canada, 
PWC, Repsol, Shell, StatoilHydro, and Total.
    \308\ See letters from Canadian Natural, Deloitte, Evolution, 
Petrobras, and Shell.
---------------------------------------------------------------------------

    Three commenters recommended that the FASB revise Statement of 
Financial Accounting Standard No. 19 (SFAS 19) to include 
unconventional resources currently accounted for as mining activities 
and also provide guidance that no retroactive revisions would be 
required in that scenario.\309\ We will continue to work with the FASB 
on this issue.
---------------------------------------------------------------------------

    \309\ See letters from CAQ, Petrobras, and PWC.
---------------------------------------------------------------------------

C. Differing Capitalization Thresholds Between Mining Activities and 
Oil and Gas Producing Activities

    As noted elsewhere in this release, extraction of products such as 
bitumen now will be considered oil and gas producing activities, and 
not mining activities. Under current U.S. accounting guidance, costs 
associated with proven plus probable mining reserves may be capitalized 
for operations extracting products through mining methods, like 
bitumen. Under the new rules, bitumen extraction and operations that 
produce oil or gas through mining methods are included under oil and 
gas accounting rules, which only permit capitalization of costs 
associated with proved reserves.\310\ Moreover, the mining guidelines 
do not provide specified percentages for establishing levels of 
certainty for proven or probable reserves for mining activities. It is 
possible that these differences could result in changing reserves 
estimates for these resources during the transition to the new rules.
---------------------------------------------------------------------------

    \310\ See Rule 4-10(c) of Regulation S-X [17 CFR 210.4-10(c)].
---------------------------------------------------------------------------

    One commenter believed that the industry would need guidance 
regarding how to transition operations that are disclosed and accounted 
for as mining operations to oil and gas disclosure and accounting.\311\ 
It noted that this issue would be relevant not only coincident with the 
new rules, but could be relevant to future events, such as a coal 
mining company that in subsequent years changes its operations to in 
situ coal gasification.\312\ That commenter believed that, without 
guidance, the change from mining treatment to oil and gas treatment 
could be considered a change in accounting principle which requires 
retroactive revision.\313\ We acknowledge this commenter's concerns. 
With respect to resources formerly considered mining activities, we 
view the change from mining treatment to oil and gas treatment as a 
change in accounting principle that is inseparable from a change in 
accounting estimate, which does not require retroactive revision.
---------------------------------------------------------------------------

    \311\ See letter from KPMG.
    \312\ See letter from KPMG.
    \313\ See letter from KPMG.
---------------------------------------------------------------------------

VIII. Application of Interactive Data Format to Oil and Gas Disclosures

    In the Proposing Release, we sought comment on the desirability of 
rules that would permit, or require, oil and gas companies to present 
the tabular disclosures in Subpart 1200 in interactive data format in 
addition to the currently required format. Most commenters addressing 
the topic supported the use of XBRL for oil and gas disclosures.\314\ 
They believed using interactive data would be very helpful to investors 
and analysts.\315\
---------------------------------------------------------------------------

    \314\ See letters from Audit Policy, CFA, Deloitte, Devon, E&Y, 
ExxonMobil, PWC, Shell, Standard Advantage, StatoilHydro, and 
Zakaib.
    \315\ See letters from CFA, Devon, E&Y, StatoilHydro, and 
Zakaib.
---------------------------------------------------------------------------

    However, they also recommended that the Commission wait until a 
well-developed taxonomy exists.\316\ Some recommended that the 
Commission implement it in stages, initially with a voluntary 
program.\317\ One commenter recommended that the SEC work with other 
groups like SPE, IASB, and the United Nations to ensure tags ultimately 
become the industry standard.\318\
---------------------------------------------------------------------------

    \316\ See letters from Audit Policy, Deloitte, Devon, E&Y, 
ExxonMobil, PWC, Shell, StatoilHydro, and Zakaib.
    \317\ See letters from Audit Policy, Devon, E&Y, PWC, 
StatoilHydro, and Zakaib.
    \318\ See letter from Zakaib.
---------------------------------------------------------------------------

    We agree that much of the disclosures regarding oil and gas 
companies would be conducive to interactive data. We intend to continue 
to work on developing a taxonomy for such disclosure. Once a well-
developed taxonomy is created, we will address this issue further. We 
are not, however, adopting interactive data requirements in this 
release. We will continue to consider whether to require interactive 
oil and gas disclosure filings in the future and, if so, when such 
filings should be required based on the development status of an oil 
and gas disclosure taxonomy.

IX. Implementation Date

A. Mandatory Compliance

    We proposed to require companies to begin complying with the 
disclosure requirements for registration statements filed on or after 
January 1, 2010, and for annual reports on Forms 10-K and 20-F for 
fiscal years ending on or after December 31, 2009. A company may not 
apply the new rules to disclosures in quarterly reports prior to the 
first annual report in which the revised disclosures are required.

[[Page 2181]]

    Fifteen commenters agreed that a delayed compliance date would be 
helpful in allowing companies to familiarize themselves with the new 
disclosure requirements before having to comply with them.\319\ Four 
commenters supported the proposed January 1, 2010 compliance date of 
Securities Act filings and Exchange Act filings related to fiscal 
periods ending on or after December 31, 2009.\320\ However, one 
conditioned this approval upon the adoption of the rules before 
December 31, 2008.\321\ Another suggested one year after adoption of 
the rules.\322\
---------------------------------------------------------------------------

    \319\ See letters from Apache, Chevron, Davis Polk, Deloitte, 
ExxonMobil, KPMG, Newfield, Petrobras, Petro-Canada, PWC, Ryder 
Scott, Shell, Southwestern, Talisman, and Total.
    \320\ See letters from Davis Polk, ExxonMobil, Shell, and 
StatoilHydro.
    \321\ See letter from ExxonMobil.
    \322\ See letter from Talisman.
---------------------------------------------------------------------------

    Four commenters believed that the proposed compliance date would be 
too soon.\323\ One recommended a compliance date of December 31, 2010 
to enable companies to make necessary changes in IT systems and data 
processing.\324\ Another noted the magnitude of the proposed changes, 
length of time to design, program and implement system changes, and the 
goal of getting the best possible disclosure.\325\ One commenter 
suggested delaying implementation for two years after adoption.\326\
---------------------------------------------------------------------------

    \323\ See letters from Apache, Petrobras, PWC, and Total.
    \324\ See letter from Petrobras.
    \325\ See letter from Apache.
    \326\ See letter from Devon.
---------------------------------------------------------------------------

    We continue to believe that the proposed compliance dates are 
appropriate. However, as we discuss our revisions with the FASB and 
IASB, we will consider whether to delay the compliance date further.

B. Voluntary Early Compliance

    Seven commenters recommended that early compliance not be permitted 
to maintain consistency and comparability of disclosure among issuers, 
which could be misleading or confusing to investors.\327\ However, one 
commenter believed that the Commission should permit early adoption of 
the new rules because companies with different fiscal year ends are not 
comparable anyway.\328\ One commenter suggested that the Commission 
permit companies to provide the new disclosures supplementally.\329\ We 
agree that voluntary compliance may make disclosures incomparable. 
Therefore, companies may not elect to follow the new disclosure rules 
prior to the effective date.
---------------------------------------------------------------------------

    \327\ See letters from Davis Polk, Devon, ExxonMobil, Petrobras, 
Ryder Scott, Shell, and Wagner.
    \328\ See letter from Evolution.
    \329\ See letter from Davis Polk.
---------------------------------------------------------------------------

X. Paperwork Reduction Act

A. Background

    Our new rules and amendments contain ``collection of information'' 
requirements within the meaning of the Paperwork Reduction Act of 1995 
(``PRA'').\330\ We submitted the new rules and amendments to the Office 
of Management and Budget (OMB) for review in accordance with the 
PRA.\331\ OMB has approved the revisions. The titles for these 
collections of information are:
---------------------------------------------------------------------------

    \330\ 44 U.S.C. 3501 et seq.
    \331\ 44 U.S.C. 3507(d) and 5 CFR 1320.11.
---------------------------------------------------------------------------

    (1) ``Regulation S-K'' (OMB Control No. 3235-0071); \332\
---------------------------------------------------------------------------

    \332\ The paperwork burden from Regulation S-K and the Industry 
Guides is imposed through the forms that are subject to the 
disclosures in Regulation S-K and the Industry Guides and is 
reflected in the analysis of those forms. To avoid a Paperwork 
Reduction Act inventory reflecting duplicative burdens, for 
administrative convenience, we estimate the burdens imposed by each 
of Regulation S-K and the Industry Guides to be a total of one hour.
---------------------------------------------------------------------------

    (2) ``Industry Guides'' (OMB Control No. 3235-0069);
    (3) ``Regulation S-X'' (OMB Control No. 3235-0009);
    (4) ``Form S-1'' (OMB Control No. 3235-0065);
    (5) ``Form S-4'' (OMB Control No. 3235-0324);
    (6) ``Form F-1'' (OMB Control No. 3235-0258);
    (7) ``Form F-4'' (OMB Control No. 3235-0325);
    (8) ``Form 10'' (OMB Control No. 3235-0064);
    (9) ``Form 10-K'' (OMB Control No. 3235-0063); and
    (10) ``Form 20-F'' (OMB Control No. 3235-0063).
    We adopted all of the existing regulations and forms pursuant to 
the Securities Act and the Exchange Act. These regulations and forms 
set forth the disclosure requirements for annual reports \333\ and 
registration statements that are prepared by issuers to provide 
investors with the information they need to make informed investment 
decisions in registered offerings and in secondary market transactions. 
The industry guides supplement the existing regulations and forms and 
provide guidance with respect to industry-specific disclosures.
---------------------------------------------------------------------------

    \333\ The pertinent annual reports are those on Forms 10-K and 
20-F.
---------------------------------------------------------------------------

    Our amendments to these existing forms are intended to modernize 
and update our reserves definitions to better reflect changes in the 
oil and gas industry and markets and new technologies that have 
occurred in the decades since the current rules were adopted, including 
expanding the scope of permissible technologies for establishing 
certainty levels of reserves, reserves classifications that a company 
can disclose in a Commission filing, and the types of resources that 
can be included in a company's reserves, as well as providing 
information regarding a company's internal controls over reserves 
estimation and the qualifications of person preparing reserves 
estimates or conducting reserves audits. The new rules and amendments 
also are intended to codify, modernize, and centralize the disclosure 
items for oil and gas companies in Regulation S-K. Finally, the new 
rules and amendments are intended to harmonize oil and gas disclosures 
by foreign private issuers with disclosures by domestic companies. 
Overall, the new rules and amendments attempt to provide improved 
disclosure about an oil and gas company's business and prospects 
without sacrificing clarity and comparability, which provide protection 
and transparency to investors.
    The hours and costs associated with preparing disclosure, filing 
forms, and retaining records constitute reporting and cost burdens 
imposed by the collection of information. An agency may not conduct or 
sponsor, and a person is not required to respond to, a collection of 
information unless it displays a currently valid control number.
    Many, but not all, of the information collection requirements 
related to annual reports and registration statements will be 
mandatory. There is no mandatory retention period for the information 
disclosed, and the information will be publicly available on the EDGAR 
filing system.

B. Summary of Information Collections

    The new rules and amendments increase existing disclosure burdens 
for annual reports on Forms 10-K \334\ and

[[Page 2182]]

20-F and registration statements on Forms 10, 20-F, S-1, S-4, F-1, and 
F-4 by creating the following new disclosure requirements, many of 
which were requested by industry participants:
---------------------------------------------------------------------------

    \334\ The disclosure requirements regarding oil and gas 
properties and activities are in Form 10-K as well as the annual 
report to security holders required pursuant to Rule 14a-3(b) [17 
CFR 240.14a-3(b)]. Form 10-K permits the incorporation by reference 
of information from the Rule 14a-3(b) annual report to security 
holders to satisfy the Form 10-K disclosure requirements. The 
analysis that follows assumes that companies would either provide 
the proposed disclosure in a Form 10-K or incorporate the required 
disclosure into the Form 10-K by reference to the Rule 14a-3(b) 
annual report to security holders if the company is subject to the 
proxy rules. This approach takes into account the burden from the 
proposed disclosure requirements that are included in both Form 10-K 
and Regulation 14A or 14C.
---------------------------------------------------------------------------

     Disclosure of reserves from non-traditional sources (i.e., 
bitumen, shale, coalbed methane) as oil and gas reserves;
     Optional disclosure of probable and possible reserves;
     Optional disclosure of oil and gas reserves' sensitivity 
to price;
     Disclosure of the company's progress in converting proved 
undeveloped reserves into proved developed reserves, including those 
that are held for five years or more and an explanation of why they 
should continue to be considered proved;
     Disclosure of technologies used to establish reserves in a 
company's initial filing with the Commission and in filings which 
include material additions to reserves estimates;
     The company's internal controls over reserves estimates 
and the qualifications of the technical person primarily responsible 
for overseeing the preparation or audit of the reserves estimates;
     If a company represents that disclosure is based on the 
authority of a third party that prepared the reserves estimates or 
conducted a reserves audit or process review, filing a report prepared 
by the third party; and
     Disclosure based on a new definition of the term ``by 
geographic area.''
    In addition, the amendments harmonize the disclosure requirements 
that apply to foreign private issuers with the disclosure requirements 
that apply to domestic issuers with respect to oil and gas activities. 
In particular, foreign private issuers must disclose the information 
required by Items 1205 through 1208 of Regulation S-K regarding 
drilling activities, present activities, delivery commitments, wells, 
and acreage, which previously were not specified in Appendix A to Form 
20-F. These disclosure items codify the substantive disclosures called 
for by Items 4 through 8 of Industry Guide 2, although much of this 
disclosure may have been disclosed by some companies under the more 
general discussions of business and property on that form.

C. Revisions to PRA Burden Estimates

    For purposes of the PRA, we estimated, in the Proposing Release, 
the total annual increase in the paperwork burden for all affected 
companies to comply with our proposed collection of information 
requirements to be approximately 7,472 hours of in-house company 
personnel time and to be approximately $1,659,000 for the services of 
outside professionals.\335\ These estimates included the time and the 
cost of preparing and reviewing disclosure and filing documents. Our 
methodologies for deriving the above estimates are discussed below.
---------------------------------------------------------------------------

    \335\ For administrative convenience, the presentation of the 
totals related to the paperwork burden hours have been rounded to 
the nearest whole number and the cost totals have been rounded to 
the nearest thousand.
---------------------------------------------------------------------------

    Our estimates represented the burden for all oil and gas companies 
that file annual reports or registration statements with the 
Commission. Based on filings received during the Commission's last 
fiscal year, we estimate that 241 oil and gas companies file annual 
reports and 67 oil and gas companies file registration statements. Most 
of the information called for by the new disclosure requirements, 
including the optional disclosure items, is readily available to oil 
and gas companies and includes information that is regularly used in 
their internal management systems. These disclosures include:
     Disclosure of reserves from non-traditional sources (i.e., 
bitumen, shale, coalbed methane) as oil and gas reserves;
     Optional disclosure of probable and possible reserves;
     Optional disclosure of oil and gas reserves' sensitivity 
to price;
     Disclosure of the company's progress in converting proved 
undeveloped reserves into proved developed reserves, including those 
that are held for five years or more and an explanation of why they 
should continue to be considered proved;
     Disclosure of technologies used to establish reserves in a 
company's initial filing with the Commission and in filings which 
include material additions to reserves estimates;
     The company's internal controls over reserves estimates 
and the qualifications of the technical person primarily responsible 
for overseeing the preparation or audit of the reserves estimates;
     If a company represents that disclosure is based on the 
authority of a third party that prepared the reserves estimates or 
conducted a reserves audit or process review, filing a report prepared 
by the third party; and
     Disclosure based on a new definition of the term ``by 
geographic area.''

We estimated that, on average, each company would incur a burden of 35 
hours to prepare these disclosures in an annual report or registration 
statement.
    The amendments also apply several disclosure items to foreign 
private issuers that previously did not apply to them. As noted above, 
many of these disclosure items, such as drilling activities, wells and 
acreage, require the issuer to provide more specificity about its 
business and property. Foreign private issuers that do not currently 
provide such specificity would incur an added burden to present such 
disclosures in their filings. In the Proposing Release, we estimated 
that this burden would be 20 hours per foreign private issuer.
    We received few comments regarding our estimates. Several large oil 
companies, and an industry organization that primarily represents large 
oil companies, believed that the estimates were too low. They believed 
that the new rules and amendments would increase their burden by 10,000 
to 15,000 hours per year. However, these commenters included the 
initial cost to change their internal systems to provide the new 
required disclosures in their estimates. Based on conversations with 
these commenters, the staff understands that they believed that the 
ongoing burden would be approximately one-third of that estimate. For 
purposes of its Paperwork Reduction Act estimate, the staff considers 
the ongoing annual burden and spreads the initial transitional burden 
of compliance with new rules and regulations over a three-year period.
    In addition, these commenters indicated that the two most 
significant burdens that stemmed from the proposed use of different 
prices for disclosure and accounting purposes and the increased detail 
in disclosures that would result from the proposed definition of the 
term ``geographic area'' and the proposed disclosure by type of 
accumulation. It should be noted that these commenters have significant 
reserves spread worldwide. Some of these large companies have as much 
as 10,000 times the amount of reserves of the median oil and gas 
company. These large companies likely would be more significantly 
impacted by the level of detailed disclosure that the proposals would 
have required compared to the vast majority of oil and gas companies in 
our reporting system, which do not have such extensive global 
operations. Therefore, we do not believe that the estimate provided by 
those large oil and gas companies necessarily would be applicable to 
most oil and gas companies. However, in response to the concerns that 
they expressed, the final rules do not require the use of different

[[Page 2183]]

prices for disclosure and full cost accounting purposes. We also intend 
to continue to work with the FASB to align the accounting standards 
with that pricing mechanism. In addition, we have significantly reduced 
the level of detailed geographic and product disclosure that the rules 
require. Finally, we are providing for a substantial transition period 
to allow companies to adjust their systems to comply with the new 
rules. We believe that these changes will help to mitigate the 
increased burden of the new rules.
    We do, however, believe that our initial burden estimates may have 
been too low. We are therefore adjusting our burden estimate to reflect 
an additional increase of 100 hours per company per year. In addition, 
we are increasing our burden estimate for foreign private issuers by an 
additional 150 hours per company per year. Consistent with current 
Office of Management and Budget estimates and recent Commission 
rulemakings, we estimate that 25% of the burden of preparation of 
registration statements on Forms S-1, S-4, F-1, F-4, 10, and 20-F is 
carried by the company internally and that 75% of the burden is carried 
by outside professionals retained by the issuer at an average cost of 
$400 per hour.\336\ We estimate that 75% of the burden of preparation 
of annual reports on Form 10-K or Form 20-F is carried by the company 
internally and that 25% of the burden is carried by outside 
professionals retained by the company at an average cost of $400 per 
hour. The portion of the burden carried by outside professionals is 
reflected as a cost, while the portion of the burden carried by the 
company internally is reflected in hours. The following tables 
summarize the additional changes to the PRA estimates:
---------------------------------------------------------------------------

    \336\ In connection with other recent rulemakings, we have had 
discussions with several private law firms to estimate an hourly 
rate of $400 as the average cost of outside professionals that 
assist issuers in preparing disclosures and conducting registered 
offerings.

                     Table 1--Calculation of Incremental Paperwork Reduction Act Burden Estimates for Exchange Act Periodic Reports
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Annual        Incremental     Incremental     75% Issuer          25%            $400
                                                             responses      hours/form        burden     ----------------  Professional    Professional
                          Form                           ------------------------------------------------                ----------------      cost
                                                                                                           (D)=(C)*0.75                  ---------------
                                                                (A)             (B)         (C)=(A)*(B)                    (E)=(C)*0.25    (F)=(E)*$400
--------------------------------------------------------------------------------------------------------------------------------------------------------
10-KSec.   \337\........................................             206             100          20,600          15,450           5,150       2,060,000
20-F....................................................              35             150           5,250           3,938           1,312         525,000
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................             241  ..............          25,850          19,388           6,462       2,585,000
--------------------------------------------------------------------------------------------------------------------------------------------------------


  Table 2--Calculation of Incremental Paperwork Reduction Act Burden Estimates for Securities Act Registration Statements and Exchange Act Registration
                                                                       Statements
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Annual        Incremental     Incremental     25% Issuer          75%            $400
                                                             responses      hours/form        burden     ----------------  Professional    Professional
                          Form                           ------------------------------------------------                ----------------      cost
                                                                                                           (D)=(C)*0.25                  ---------------
                                                                (A)             (B)         (C)=(A)*(B)                    (E)=(C)*0.75    (F)=(E)*$400
--------------------------------------------------------------------------------------------------------------------------------------------------------
10......................................................               5             100             500             125             375         150,000
20-F....................................................               2             150             300              75             225          90,000
S-1.....................................................              38             100           3,800             950           2,850       1,140,000
S-4.....................................................              17             100           1,700             425           1,275         510,000
F-1.....................................................               2             150             300              75             225          90,000
F-4.....................................................               3             150             450           112.5           337.5         135,000
                                                         -----------------------------------------------------------------------------------------------
    Total...............................................              67  ..............           7,050          1762.5         5,287.5       2,115,000
--------------------------------------------------------------------------------------------------------------------------------------------------------

D. Request for Comment

    We request comment in order to evaluate the accuracy of our 
estimates of the burden of the revised information collections. Any 
member of the public may direct to us any comments concerning the 
accuracy of these burden estimates. Persons who desire to submit 
comments on the collection of information requirements should direct 
their comments to the OMB, Attention: Desk Officer for the Securities 
and Exchange Commission, Office of Information and Regulatory Affairs, 
Washington, DC 20503, and should send a copy of the comments to 
Secretary, Securities and Exchange Commission, 100 F Street, NE., 
Washington, DC 20549-1090, with reference to File No. S7-15-08. 
Requests for materials submitted to the OMB by us with regard to this 
collection of information should be in writing, refer to File No. S7-
15-08, and be submitted to the Securities and Exchange Commission, 
Records Management Branch, 100 F Street, NE., Washington, DC 20549-
1126. Because OMB is required to make a decision concerning the 
collections of information between 30 and 60 days after publication, 
your comments are best assured of having their full effect if OMB 
receives them within 30 days of publication.
---------------------------------------------------------------------------

    \337\ The burden estimates for Form 10-K assume that the 
requirements are satisfied by either including information directly 
in the annual reports or incorporating the information by reference 
from the Rule 14a-3(b) annual report to security holders.
---------------------------------------------------------------------------

XI. Cost-Benefit Analysis

A. Background

    We are adopting revisions to the oil and gas reserves disclosure 
regime of Regulation S-K and Regulation S-X under the Securities Act of 
1933 and the Securities Exchange Act of 1934 and Industry Guide 2. The 
revisions are intended to modernize and update oil and gas disclosure. 
The oil and gas industry has experienced significant changes since the 
Commission initially adopted its current rules and disclosure

[[Page 2184]]

regime between 1978 and 1982, including advancements in technology and 
changes in the types of projects in which oil and gas companies invest. 
The revisions also are intended to provide investors with improved 
disclosure about an oil and gas company's business and prospects 
without sacrificing clarity and comparability.

B. Description of New Rules and Amendments

    Currently, Industry Guide 2 specifies many of the disclosure 
guidelines for oil and gas companies. The Industry Guide calls for 
disclosure relating to reserves, production, property, and operations 
in addition to that which is required by Regulation S-K. Generally, the 
new rules and amendments codify and update the existing Industry Guide 
2 disclosures in a new Subpart 1200 of Regulation S-K, clarify the 
level of detail required to be disclosed, and require reserves 
disclosure in a tabular presentation. The changes relate primarily to 
disclosure of the following:
     Disclosure of reserves from non-traditional sources (e.g., 
bitumen, shale) as oil and gas reserves;
     Optional disclosure of probable and possible reserves;
     Optional disclosure of oil and gas reserves' sensitivity 
to price;
     Disclosure of the company's progress in converting proved 
undeveloped reserves into proved developed reserves, including those 
that are held for five years or more and an explanation of why they 
should continue to be considered proved;
     Disclosure of technologies used to establish reserves in a 
company's initial filing with the Commission and in filings which 
include material additions to reserves estimates;
     The company's internal controls over reserves estimates 
and the qualifications of the technical person primarily responsible 
for overseeing the preparation or audit of the reserves estimates;
     If a company represents that disclosure is based on the 
authority of a third party that prepared the reserves estimates or 
conducted a reserves audit or process review, filing a report prepared 
by the third party; and
     Disclosure based on a new definition of the term ``by 
geographic area.''
    The new rules and amendments also make revisions and additions to 
the definitions section of Rule 4-10 of Regulation S-X. These revisions 
update and extend reserves definitions to reflect changes in the oil 
and gas industry and new technologies. In particular, the new and 
revised definitions:
     Expand the definition of ``oil and gas producing 
activities'' to include the extraction of hydrocarbons from oil sands, 
shale, coalbeds, or other natural resources and activities undertaken 
with a view to such extraction;
     Add a definition of ``reasonable certainty'' to provide 
better guidance regarding the meaning of that term;
     Add a definition of ``reliable technology'' to permit the 
use of new technologies to establish proved reserves;
     Define probable and possible reserves estimates; and
     Add definitions to explain new terms used in the revised 
definitions.
    In addition, the amendments harmonize the disclosure requirements 
that apply to foreign private issuers with the disclosure requirements 
that apply to domestic issuers with respect to oil and gas activities. 
In particular, the amendments to Form 20-F will require foreign private 
issuers to disclose the information required by Items 1205 through 1208 
of Regulation S-K regarding drilling activities, present activities, 
delivery commitments, wells, and acreage, which are not currently 
specified under Appendix A to Form 20-F, although much of this 
disclosure is often disclosed by companies under the more general 
discussions of business and property on that form.

C. Benefits

    We expect that the new rules and amendments will increase 
transparency in disclosure by oil and gas companies by providing 
improved reporting standards. The revisions to the definitions should 
align our disclosure rules with the realities of the modern oil and gas 
markets. For example, we believe that the inclusion of bitumen and 
other resources from continuous accumulations as oil and gas producing 
activities is consistent with company practice to treat these 
operations as part of, rather than separate from, their traditional oil 
and gas producing activities. Similarly, the expansion of permissible 
technologies for determining certainty levels of reserves recognizes 
that companies now take advantage of these technological advances to 
make business decisions. We expect these new rules and amendments to 
improve disclosure by aligning the required disclosure more closely 
with the way companies conduct their business.
    Allowing companies to disclose probable and possible reserves is 
designed to improve investors' understanding of a company's unproved 
reserves. For those companies that already disclose such reserves on 
their Web sites, the new rules and amendments permit them to unify such 
disclosures into a single, filed document. Disclosure of these 
categories of reserves beyond proved reserves may foster better company 
valuations by investors, creditors, and analysts, thus improving 
capital allocation and reducing investment risk. Because some of the 
disclosure items are optional, the amount of increased transparency 
will depend on the extent to which companies elect to provide the 
additional disclosures permitted under the new rules. If companies 
elect not to provide the optional disclosure, then the benefits from 
increased transparency would be limited to the extent that the new 
rules improve the transparency of proved reserves disclosure.
    By permitting increased disclosure and promoting more consistency 
and comparability among disclosures, the new rules and amendments 
provide a mechanism for oil and gas companies to seek more favorable 
financing terms through more disclosure and increased transparency. 
Investors may be able to request such additional disclosure in 
Commission filings during negotiations regarding bond and debt 
covenants. Thus, we expect that, as a result of competing factors in 
the marketplace, the new rules and amendments will result in increased 
transparency, either because companies elect to voluntarily provide 
increased disclosure, or because investors may discount companies that 
do not do so. We believe that the benefits and costs of disclosing 
unproved reserves ultimately will be determined by market conditions, 
rather than regulatory requirements.
    We expect that permitting companies to disclose probable and 
possible reserves will increase market transparency, provide investors 
with more reserves information, and allow for more accurate production 
forecasts. By relating standards used in deterministic methods to 
comparable percentage thresholds used in probabilistic methods for 
establishing a given level of certainty, the new rules and amendments 
should result in increased standardization in reporting practices which 
would promote comparability of reserves across companies. The new rules 
would define the term ``reliable technology'' to permit oil and gas 
companies to prepare their reserves estimates using new types of 
technology that companies are not permitted to use under the current 
rules. This new definition also is designed to encompass new 
technologies as they are developed in the future, thereby

[[Page 2185]]

providing investors and the market with a more comprehensive 
understanding of a company's estimated reserves.
    We expect that replacing the Industry Guide with new Regulation S-K 
items will provide greater certainty because the disclosure 
requirements would be in rules established by the Commission. In 
addition, we believe that disclosure of reserves concentrated in 
particular countries should provide better information to investors 
regarding the geopolitical risk to which some companies may be exposed. 
Overall, we believe that the amendments, as a whole, will provide 
investors with more information that management uses to make business 
decisions in the oil and gas industry.
1. Average Price and First of the Month Price
    The revision to change the price used to calculate reserves from a 
year-end single-day price to a historical average price over the 
company's most recently ended fiscal year is expected to reduce the 
effects of seasonality. In particular, many commenters suggested the 
use of a 12-month average price to mitigate the risk of a year-end 
price affected by short-term price volatility such that it does not 
reflect the true nature of a company investment, planning, and 
performance. Our Office of Economic Analysis studied the publicly-
available pricing data and found evidence of year-end price volatility. 
The historical volatility of year-end prices is between 16 percent and 
41 percent higher than the volatility of annual average prices 
depending on the grade and geography of oil or gas prices considered. 
This difference demonstrates variability in oil and gas prices, likely 
due to seasonal demands, that does not reflect long term fundamental 
values, but that cannot be immediately corrected due to the costs of 
transportation and speed of delivery. Given this variability, it is 
likely that a 12-month average price will yield better reserves 
estimates--that reflect management planning and investment to the 
extent that they discount the short-term component of oil and gas 
prices--than a year-end spot price.
    Many of the commenters to the Proposing Release supported the use 
of a historical price, even though this approach may be less useful in 
determining the fair value of a company's reserves compared to a 
futures market price. We believe investors are concerned not only about 
the quantity of a company's reserves, but also about the profitability 
of those reserves. We also recognize that some reserves will be of more 
value than others due to extraction and transportation costs. As a 
result, since the new rules and amendments require the use of a single 
price to estimate reserves and since that price may not be as 
informative of value as a futures price, the new rules and amendments 
also gives companies the option of providing a sensitivity analysis and 
reporting reserves based on additional price estimates.
    If companies elect to provide a sensitivity analysis, we expect 
this to benefit investors by allowing them to formulate better 
projections of company prospects that are more consistent with 
management's planning price and prices higher and lower that may 
reasonably be achieved. In particular, it allows companies the 
flexibility to communicate how their reserves would change under 
alternative economic conditions, including those that they may believe 
better reflect their future prospects. We expect that companies would 
be more likely to adopt a sensitivity analysis approach if investors 
and other market participants determine that this information would 
reduce investment risk, or if companies believe such disclosure will 
reduce the cost of capital formation. The new rules and amendments 
should result in increased price stability in determining whether 
reserves are economically producible. This should mitigate seasonal 
effects, resulting in reserves estimates that more closely reflect 
those used by management in planning and investment decisions. We 
expect this to allow for more accurate company assessments and improve 
projections of company prospects.
    In addition to an average annual price, many of the commenters 
suggested that the price be computed on the first day of the month. Two 
reasons were given. First, beginning month prices would allow an 
additional month of preparation time in calculating reserves for 
financial reporting. Second, some commenters suggested that month-end, 
and in particular year-end, prices were subject to additional short-
term volatility because many oil and gas financial contracts expire on 
those days, resulting in higher than normal trading activity. While the 
staff of the Office of Economic Analysis did not find systematic 
evidence of increased volatility around month-end or year-end oil and 
gas prices relative to other days in the month, we agree that 
additional preparation time is beneficial because reserves estimations 
require significant time and resources. An additional month would help 
reduce errors that might otherwise result from the financial reporting 
time constraints.
    Finally, we believe that revising the full cost accounting method 
to use the same pricing mechanism as the reserves disclosure 
requirements should provide consistency between the disclosure and 
accounting presentations. The use of a single pricing method should 
also minimize the incremental burden placed on companies as a result of 
the rule changes because they would not be required to prepare two 
separate estimates.
2. Probable and Possible Reserves
    We anticipate that disclosure of probable and possible reserves, if 
companies elect to do so, will allow investors, creditors, and other 
users to better assess a company's reserves. In addition, the tabular 
format for disclosing probable and possible reserves should reduce 
investor search costs by making it easier to locate reserves 
disclosures and facilitating comparability among oil and gas companies.
    While we recognize that many companies already communicate with 
investors about their unproved and other reserves through alternative 
means, such as company Web sites or press releases, some commenters 
remarked that an objective comparison among companies is difficult 
because different companies have defined such reserves classifications 
differently. We believe that permitting disclosure of this information 
in Commission filings will provide a more consistent means of 
comparison because disclosure in our filings must comply with our 
definitions. Although our new rules make disclosure of probable and 
possible reserves optional, and large oil and gas producers suggested 
in their comment letters that such disclosure would be of limited 
benefit because of the relative uncertainty of those estimates, we 
believe that competitive pressures within the industry might make it 
beneficial for large producers to disclose this information. Increased 
disclosure might, for example, improve credit quality and lower the 
cost of debt financing, or reduce the risk associated with business 
transactions between the company and its customers or suppliers. 
Regardless, since the disclosure decision is voluntary, it should occur 
only to the extent that companies find that the benefits justify the 
costs of doing so.
    We believe that permitting the disclosure of probable and possible 
reserves will benefit smaller companies, in particular. Larger issuers 
tend to already have large amounts of proved reserves. The new rules 
and amendments permit smaller companies,

[[Page 2186]]

who often participate in a significant amount of exploratory activity, 
to better disclose their business prospects. Consequently, we 
anticipate that the new rules and amendments could lead to efficiencies 
in capital formation, as more information will be available regarding 
the prospects of smaller issuers.
3. Reserves Estimate Preparers and Reserves Auditors
    We believe that investors would benefit from a greater level of 
assurance with respect to the reliability of reserve estimates, 
particularly if companies are allowed to disclose unproved reserves 
because unproved reserves are inherently less certain than proved 
reserves. We proposed disclosure requirements relating to whether the 
person primarily responsible for preparing reserves estimates or 
conducting a reserves audit, if the company represents that it has 
enlisted a third party to conduct a reserves audit, met a specified 
list of qualifications based on the Society of Petroleum Engineers's 
reserves audit guidelines. However, commenters expressed concern that 
many of these qualifications such as membership in professional 
societies were not standardized worldwide. Without control over those 
standards, the disclosures would not be comparable. We agree with those 
commenters and, as suggested, have adopted a more principles-based 
disclosure requirement. Under the adopted rules, a company must 
disclose its internal controls over reserves estimations and disclose 
the qualifications of the primary technical person in charge of 
overseeing the reserves estimations or reserves audit. We believe that 
disclosure of the individual qualifications, rather than simple 
acknowledgement of meeting certain criteria, which may differ within 
countries, will provide investors with better information to compare 
companies and the qualifications of persons in charge of the reserves 
estimations and reserves audits, which should enable more accurate 
assessments of the quality of audit reports. We believe that disclosure 
of a company's internal controls over reserves estimates will allow 
investors to assess whether a company has implemented appropriate 
controls without dictating to companies specified criteria for 
establishing those controls.
    Although we do not expect all companies to undertake a third-party 
reserves audit because our rules do not require such a reserves audit, 
third party participation in the estimation of reserves should add 
credibility to a company's public disclosure. The opinion of an 
objective, qualified person on the reserves estimates is designed to 
increase the reliability of these estimates and investor confidence.
4. Development of Proved Undeveloped Reserves
    The new rules and amendments also require disclosure of a company's 
progress in developing undeveloped reserves and the reasons why any 
PUDs have remained undeveloped for five years or more. We believe that 
such disclosure supplements our amendments that ease the requirements 
for recognizing PUDs and thereby should increase the amount of PUDs 
disclosed in filings, even though the properties representing such 
proved reserves have not yet been developed and therefore do not 
provide the company with cash flow. We believe that the disclosure 
requirements will increase the accountability of companies that 
disclose reserves for extended periods of time without adequate 
justification for their failure to develop those reserves.
5. Disclosure Guidance
    The release also provides guidance about the type of information 
that companies should consider disclosing in Management's Discussion 
and Analysis, and allows companies to include this information with the 
relevant tables. Providing the additional guidance should assist 
companies in preparing their disclosure, improving the quality and 
consistency of this disclosure. Locating this discussion with the 
tables themselves should benefit investors by simplifying the 
presentation of disclosure, and providing insight into the information 
disclosed in the tables.
6. Updating of Definitions Related to Oil and Gas Activities
    The new rules and amendments also update the definition of the term 
``oil and gas producing activities'' as well as updating or creating 
new definitions for other terms related to such activities, including 
``proved oil and gas reserves'' and ``reasonable certainty.'' We 
believe that updating these definitions will help companies disclose 
oil and gas operations in the same way that companies manage and assess 
those operations. This includes resources extracted from nontraditional 
sources that companies consider oil and gas activities, which 
previously were excluded them from the definition of ``oil and gas 
producing activities.'' In addition, adding definitions for terms like 
``reasonable certainty'' (which currently is in the definition of 
``proved oil and gas reserves,'' but not defined) will provide 
companies with added guidance and assist them in providing consistent 
disclosures between companies.
7. Harmonizing Foreign Private Issuer Disclosure
    We believe that the harmonization of foreign private issuer 
disclosure will help make disclosures of foreign private issuers more 
comparable with domestic companies. The oil and gas industry has 
changed significantly since the rules were adopted. Today, many 
companies have interests that span the globe. In addition, many of 
these projects are joint ventures between foreign private issuers and 
domestic companies. Having differing levels of disclosure for companies 
that may be participating in the same projects harms comparability 
between investment choices. The harmonization of foreign private issuer 
disclosure is intended to promote comparability among all oil 
companies.

D. Costs

    We expect that the new rules and amendments will result in initial 
and ongoing costs to oil and gas companies. These burdens will vary 
significantly among companies. Based on disclosures in company filings, 
the largest oil and gas companies can have as much as 10,000 times the 
reserves of the median reporting oil and gas company. As would be 
expected, companies that have more reserves and larger operations will 
have a correspondingly larger amount of information that they must 
disclose and, therefore, the burden of complying with our disclosure 
requirements would be greater for larger companies.
    Although we are adding a new subpart to Regulation S-K to set forth 
the disclosure requirements that are unique to oil and gas companies, 
the subpart, for the most part, codifies the substantive disclosure 
called for by Industry Guide 2. The disclosure requirements have been 
updated and clarified, and require the disclosure to be presented in a 
tabular format, where appropriate.
     Although many companies already present this information in 
tabular form, for companies that do not, this requirement could impose 
a burden on companies as they transition from a narrative to tabular 
disclosure format. We expect, however, that any increased preparation 
costs would be highest in the first year after adoption, but would 
decline in subsequent years as companies adjust to the new format. We

[[Page 2187]]

think this burden is justified because tabular disclosure will increase 
comparability and facilitate understanding and analysis by investors.
1. Probable and Possible Reserves
    Allowing disclosure of probable and possible reserves could create 
an increased risk of litigation because these categories of reserves 
estimates are less certain than proved reserves. Companies may choose 
not to disclose such reserves, in part, because of the risk of 
incurring litigation costs to defend their disclosures due to the 
increased uncertainty of these categories. Disclosure of probable and 
possible reserves may also result in revealing competitive information 
because it might reveal a company's business strategy, such as the 
geographic location and nature of its exploration and discoveries. For 
example, if geographical detail can be inferred from estimates of 
unproved reserves, this might reveal information about the value of a 
company's assets to competitors and could put the producer at a 
competitive disadvantage. We have reduced the level of geographical 
detail to reduce the burden on companies, while still providing 
sufficient information to investors regarding concentrations of risk, 
including political risk.
    We expect companies will incur costs in preparing the additional 
disclosures such as calculating and aggregating the reserve projections 
in a prescribed format. However, if probable and possible categories of 
reserves have different extraction cost structures and they are not 
disclosed separately from proved reserves, this could result in 
increased uncertainty in an investor's assessment of a company's 
prospects.
    Companies also expressed concern that mandatory disclosure of 
probable and possible reserves could expose them to increased 
litigation risk. We believe that making these disclosures voluntary 
mitigates these concerns. Companies unwilling to bear the added risk 
can simply opt not to provide this disclosure.
2. Reserves Estimate Preparers and Reserves Auditors
    If a company chooses to use a third party to prepare or audit 
reserve estimates, it will incur costs to hire these outside 
consultants. The new rules and amendments do not require companies to 
hire such a person. If enough companies that currently do not use such 
consultants begin to hire them, we believe that industry wages could 
potentially increase due to increased demand for reserves calculating 
specialists unless that demand is compensated by an increase in the 
supply of such persons. If wages increased, then all companies, not 
just those employing third party consultants, would incur added costs.
    Large companies may be less likely to hire third parties because 
they tend to have staff to make reserves estimates. However, if such 
large companies chose to hire third-party consultants, third parties 
would expend significantly more effort on such projects than for 
smaller companies because larger companies have more properties to 
evaluate. Thus, we expect third-party fees, and the time required to 
conduct such projects, would scale upwards with the quantity of company 
reserves.
    Disclosure of unproved reserves without third-party certification 
may present a risk with respect to smaller oil and gas producers 
because smaller companies are likely to have less in-house expertise 
and ability to accurately estimate such reserves than larger companies. 
However, we understand that the vast majority of smaller oil and gas 
companies already hire third parties to estimate their reserves or 
certify their estimates.
3. Consistency With IASB
    Some commenters remarked that the International Accounting 
Standards Board is currently preparing a set of guidelines for oil and 
gas extractive activities, including definitions of oil and gas 
reserves, and recommended that the Commission align its regulations 
with those guidelines. We intend to monitor this initiative and work 
with the IASB, but our new rules may differ from the guidelines 
ultimately established by the International Accounting Standards Board. 
This could make it more difficult for investors to compare foreign and 
domestic companies.
4. Change in Pricing Mechanism
    We do not anticipate significant costs with the change in pricing 
mechanisms for established reserves. Companies simply will apply a 
different price scenario to determine the economic producibility of 
reserves. It is possible that the use of a 12-month average price may 
reduce the cost of disclosure because it should reduce the volatility 
of reserves estimates and therefore reduce the need to make significant 
adjustments to those estimates on a yearly basis due to daily price 
swings.
5. Disclosure of PUD Development
    The required disclosure of a company's progress in developing PUDs 
will increase the cost of reporting. However, we believe that companies 
regularly track their progress in this arena. Until a company develops 
a property, it cannot begin to realize the cash flows from production 
and the actual sale of products. Thus, the development of reserves is 
of utmost importance to an oil and gas company's business.
6. Increased Geographic Disclosure
    The requirements to provide increased geographic disclosure of 
reserves and production, in certain circumstances, may increase the 
amount of disclosure that a company must present. However, because the 
threshold that we are adopting in the release is 15% of the company's 
total reserves, a company would be required to disclose, at most, 
reserves and production in six countries. Considering the relatively 
large proportion of reserves that must exist in a country before a 
company is required to provide country-level disclosure, we believe 
that such information is readily available to companies. As noted in 
the body of this release, we have attempted to draft this provision to 
minimize any competitive harm that such disclosure may cause a company.
7. Harmonizing Foreign Private Issuer Disclosure
    The harmonization of foreign private issuer disclosure regarding 
oil and gas activities may increase the burden on foreign private 
issuers. However, it is our understanding that the large foreign 
private issuers already voluntarily provide disclosure comparable to 
the level required from domestic companies. Much of the added new 
disclosure relates to the day-to-day business and properties of these 
companies, including drilling activities, number of wells and acreage. 
This is information that is central to the activities of oil and gas 
companies, and therefore is readily known to these companies. We 
believe that applying Subpart 1200 to these companies could prompt more 
detailed disclosure regarding these activities, which would cause these 
companies to incur some cost. The provision permitting foreign private 
issuers to omit disclosures if prohibited from making those disclosures 
by their home jurisdiction could mitigate some of these costs.

[[Page 2188]]

XII. Consideration of Burden on Competition and Promotion of 
Efficiency, Competition, and Capital Formation

    Securities Act Section 2(b) \338\ and Section 3(f) of the Exchange 
Act \339\ require us, when engaging in rulemaking where we are required 
to consider or determine whether an action is necessary or appropriate 
in the public interest, to consider, in addition to the protection of 
investors, whether the action will promote efficiency, competition, and 
capital formation. Section 23(a)(2) of the Exchange Act \340\ requires 
us, when adopting rules under the Exchange Act, to consider the impact 
that any new rule would have on competition. In addition, Section 
23(a)(2) prohibits us from adopting any rule that would impose a burden 
on competition not necessary or appropriate in furtherance of the 
purposes of the Exchange Act.
---------------------------------------------------------------------------

    \338\ 15 U.S.C. 77b(b).
    \339\ 15 U.S.C. 78c(f).
    \340\ 15 U.S.C. 78w(a)(2).
---------------------------------------------------------------------------

    We expect the new rules and amendments to increase efficiency and 
enhance capital formation, and thereby benefit investors, by providing 
the market with better information based on updated technology as well 
as increased information covering a broader range of reserves 
classifications held by a company and reserves found in non-traditional 
sources of oil and gas. Such increased and improved information should 
permit investors to better assess a company's prospects. In particular, 
the existing prohibitions against disclosing reserves other than proved 
reserves, using modern technology to determine the certainty level of 
reserves, and including resources from non-traditional sources can lead 
to incomplete disclosures about a company's actual resources and 
prospects. The new rules and amendments are designed to better align 
the disclosure requirements with the way companies make business 
decisions.
    We believe that permitting the disclosure of probable and possible 
reserves will benefit smaller companies, in particular. Larger issuers 
tend to already have large amounts of proved reserves. The new rules 
and amendments permit smaller companies, who often participate in a 
significant amount of exploratory activity, to better disclose their 
business prospects. Consequently, we anticipate that the new rules and 
amendments could lead to efficiencies in capital formation, as more 
information will be available regarding the prospects of smaller 
issuers.
    The effects of the new rules and amendments on competition are 
difficult to predict, but it is possible that permitting public issuers 
to disclose probable and possible reserves will lead to a reallocation 
of capital, as companies that previously could show few proved reserves 
will be able to disclose a broader range of its business prospects, 
making it easier for these issuers to raise capital and compete with 
companies that have large proved reserves. Although our new rules make 
disclosure of probable and possible reserves optional, and large oil 
and gas producers suggested in their comment letters that such 
disclosure would be of limited benefit because of the relative 
uncertainty associated with such reserves, we believe that competitive 
pressures within the industry might make it beneficial for large 
producers to disclose this information. Increased disclosure might, for 
example, improve credit quality and lower the cost of debt financing, 
or reduce the risk associated with business transactions between the 
company and its customers or suppliers.

XIII. Final Regulatory Flexibility Analysis

    We have prepared this Final Regulatory Flexibility Analysis in 
accordance with Section 603 of the Regulatory Flexibility Act.\341\ 
This analysis relates to the modernization of the oil and gas 
disclosure requirements. An Initial Regulatory Flexibility Analysis 
(IRFA) was prepared in accordance with the Regulatory Flexibility Act 
in conjunction with the Proposing Release. The Proposing Release 
included, and solicited comment on, the IRFA.
---------------------------------------------------------------------------

    \341\ 5 U.S.C. 603.
---------------------------------------------------------------------------

A. Reasons for, and Objectives of, the New Rules and Amendments

    The Commission adopted the current disclosure regime for oil and 
gas producing companies in 1978 and 1982, respectively. Since that 
time, there have been significant changes in the oil and gas industry 
and markets, including technological advances, and changes in the types 
of projects in which oil and gas companies invest their capital. On 
December 12, 2007, the Commission published a Concept Release on 
possible revisions to the disclosure requirements relating to oil and 
gas reserves.\342\ Prior to our issuance of the Concept Release, many 
industry participants had expressed concern that our disclosure rules 
are no longer in alignment with current industry practices and 
therefore have limited usefulness to the market and investors.
---------------------------------------------------------------------------

    \342\ See Release No. 33-8870 (Dec. 12, 2007) [72 FR 71610].
---------------------------------------------------------------------------

    Our new rules and amendments to these existing forms are intended 
to modernize and update our reserves definitions to reflect changes in 
the oil and gas industry and markets and new technologies that have 
occurred in the decades since the current rules were adopted, including 
expanding the scope of permissible technologies for establishing 
certainty levels of reserves, reserves classifications that a company 
can disclose in a Commission filing, and the types of resources that 
can be included in a company's reserves, as well as providing 
information regarding the objectivity and qualifications of any third 
party primarily responsible for preparing or auditing the reserves 
estimates, if the company represents that it has enlisted a third party 
to conduct a reserves audit, and the qualifications and measures taken 
to assure the independence and objectivity of any employee primarily 
responsible for preparing or auditing the reserves estimates. The 
amendments also harmonize our full cost accounting rules with the 
changes that we are adopting with respect to disclosure of oil and gas 
reserves. The new rules and amendments also are intended to codify, 
modernize and centralize the disclosure items for oil and gas companies 
into Regulation S-K. Finally, the new rules and amendments are intended 
to harmonize oil and gas disclosures by foreign private issuers with 
disclosures by domestic companies. Overall, the new rules and 
amendments attempt to provide improved disclosure about an oil and gas 
company's business and prospects without sacrificing clarity and 
comparability, which provide protection and transparency to investors.

B. Significant Issues Raised by Commenters

    We did not receive comments specifically addressing the impact of 
the proposed rules and amendments on small entities. However, several 
of the comments related to burdens that would be placed on all 
companies affected by the proposals. In particular, commenters believed 
that the proposal to require the use of different prices for disclosure 
and accounting purposes would impose a significant burden on all oil 
and gas companies. We have considered those comments and are adopting 
amendments to our disclosure rules and the full cost accounting method 
that will require the use of a single price for both purposes. 
Similarly, commenters were concerned that certain aspects of

[[Page 2189]]

the proposal, such as the new definition of geographic area and 
disclosure by accumulation type would increase the detail in the 
disclosures significantly. We agree with those commenters and have 
significantly reduced the level of detail required in the disclosure 
requirements.

C. Small Entities Subject to the New Rules and Amendments

    The new rules and amendments affect small entities that are engaged 
in oil and gas producing activities, the securities of which are 
registered under Section 12 of the Exchange Act or that are required to 
file reports under Section 15(d) of the Exchange Act. The new rules and 
amendments also would affect small entities that file, or have filed, a 
registration statement that has not yet become effective under the 
Securities Act and that has not been withdrawn. Securities Act Rule 157 
\343\ and Exchange Act Rule 0-10(a) \344\ define an issuer to be a 
``small business'' or ``small organization'' for purposes of the 
Regulatory Flexibility Act if it had total assets of $5 million or less 
on the last day of its most recent fiscal year. The new rules and 
amendments affect small entities that are operating companies and 
engage in oil and gas producing activities. Based on filings in 2007, 
we estimate that there are approximately 28 oil and gas companies that 
may be considered small entities.
---------------------------------------------------------------------------

    \343\ 17 CFR 230.157.
    \344\ 17 CFR 240.0-10(a).
---------------------------------------------------------------------------

D. Reporting, Recordkeeping, and Other Compliance Requirements

    The new rules and amendments to Regulation S-K expand some existing 
disclosures, and eliminate others. In particular, the new disclosure 
requirements, many of which were requested by industry participants, 
include the following:
     Disclosure of reserves from non-traditional sources (e.g., 
bitumen and shale) as oil and gas reserves;
     Optional disclosure of probable and possible reserves;
     Optional disclosure of oil and gas reserves' sensitivity 
to price;
     Disclosure of the development of proved undeveloped 
reserves, including those that are held for 5 years or more and an 
explanation of why they should continue to be considered proved;
     Disclosure of technologies used to establish reserves in a 
company's initial filing with the Commission and in filings which 
include material additions to reserves estimates;
     Disclosure of the company's internal controls over 
reserves estimates and the qualifications the technical person 
primarily responsible for overseeing the preparation or audit of the 
reserves estimates;
     If a company represents that disclosure is based on the 
authority of a third party that prepared the reserves estimates or 
conducted a reserves audit or process review, filing a report prepared 
by the third party; and
     Disclosure based on a new definition of the term ``by 
geographic area.''
    There would be no mandatory retention period for the information 
disclosed, and the information disclosed would be made publicly 
available on the EDGAR filing system.

E. Agency Action To Minimize Effect on Small Entities

    We considered different compliance standards for the small entities 
that will be affected by the new rules and amendments. In the Proposing 
Release, we solicited comment regarding the possibility of different 
standards for small entities. We did not receive comment on this 
particular issue. However, we believe that such differences would be 
inconsistent with the purposes of the rules.
    The new rules and amendments are designed to modernize the 
disclosure requirements for oil and gas companies. As such, we believe 
all oil and gas companies will benefit from the modernization of the 
rules. Under the new rules and amendments, all companies will be 
allowed to use modern technologies to establish reserves and include 
operations in unconventional resources in their oil and gas reserves 
estimates. Adopting differing standards for disclosure for small 
entities would significantly reduce the comparability between 
companies. However, the new rules and amendments do permit companies to 
disclose probable and possible reserves. We believe the removal of the 
prohibition against such reserves will enable companies to disclose a 
broader view of their prospects. We believe this will particularly 
benefit smaller oil and gas companies that may have significant 
unproved reserves in their portfolio. Such disclosure may assist 
smaller companies in raising capital for development projects in those 
properties.

XIV. Update to Codification of Financial Reporting Policies

    The Commission amends the ``Codification of Financial Reporting 
Policies'' announced in Financial Reporting Release No. 1 (April 15, 
1982) [47 FR 21028] as follows:
    1. By removing the seven introductory paragraphs before Section 
406.01, the last sentence of Section 406.01.c.vi., the first paragraph 
of Section 406.01.d, the introductory paragraph of Section 406.02.d, 
and removing and reserving Sections 406.01.a., 406.02.a, 406.02.b., 
406.02.d.iii., and 406.02.e.
    2. By revising Section 406.01B to read as follows:
    The rules in Rule 4-10(b) specify that the application of 
successful efforts shall comply with SFAS 19. In 2008, the Commission 
published amendments to the definitions in Rule 4-10(a) that may not 
align completely with SFAS 19's existing terminology and application. 
Further, paragraph 7 of SFAS 25 states: ``For purposes of applying this 
Statement and Statement 19, the definition of proved reserves, proved 
developed reserves, and proved undeveloped reserves shall be the 
definitions adopted by the SEC for its reporting purposes that are in 
effect on the date(s) as of which the reserve disclosures are to be 
made. Previous reported quantities shall not be revised retroactively 
if the SEC definitions are changed.'' In any case, the Commission 
expects the practical application of SFAS 19 will remain unchanged 
other than incorporating the effects of the new definitions.
    3. By removing the first three sentences of Section 406.02.c. and 
in the fourth sentence replacing the phrase ``this sort of 
information'' with ``information to assess the impact of oil and gas 
producing activities on near term cash flows and liquidity''.
    4. By adding a new Section 406.03 entitled ``Transition'' and 
including the text of the 3rd paragraph of Section VII.B and the last 
sentence of the 2nd paragraph of Section VII.C of this release.
    5. By adding a new Section 406.04 entitled ``MD&A Guidance'' and 
including the text beginning with the last sentence of the 2nd 
paragraph of Section V of this release through the end of that Section.
    The Codification is a separate publication of the Commission. It 
will not be published in the Federal Register or Code of Federal 
Regulations. For more information on the Codification of Financial 
Reporting Policies, contact the Commission's Public Reference Room at 
202-551-5850.

XV. Statutory Basis and Text of Amendments

    We are adopting the amendments pursuant to Sections 3(b), 6, 7, 10 
and 19(a) of the Securities Act and Sections 12, 13, 14(a), 15(d), and 
23(a) of the Exchange Act, as amended.

[[Page 2190]]

Text of Amendments

List of Subjects

17 CFR Part 210

    Accountants, Accounting, Reporting and recordkeeping requirements, 
Securities.

17 CFR Parts 211, 229 and 249

    Reporting and recordkeeping requirements, Securities.

0
For the reasons set out in the preamble, title 17, chapter II of the 
Code of Federal Regulations is amended as follows:

PART 210--FORM AND CONTENT OF AND REQUIREMENTS FOR FINANCIAL 
STATEMENTS, SECURITIES ACT OF 1933, SECURITIES EXCHANGE ACT OF 
1934, PUBLIC UTILITY HOLDING COMPANY ACT OF 1935, INVESTMENT 
COMPANY ACT OF 1940, INVESTMENT ADVISERS ACT OF 1940, AND ENERGY 
POLICY AND CONSERVATION ACT OF 1975

0
1. The authority citation for part 210 continues to read as follows:

    Authority: 15 U.S.C. 77f, 77g, 77h, 77j, 77s, 77z-2, 77z-3, 
77aa(25), 77aa(26), 78c, 78j-1, 78l, 78m, 78n, 78o(d), 78q, 78u-5, 
78w(a), 78ll, 78mm, 80a-8, 80a-20, 80a-29, 80a-30, 80a-31, 80a-
37(a), 80b-3, 80b-11, 7202 and 7262, unless otherwise noted.


0
2. Amend Sec.  210.4-10 by:
0
a. Redesignating the subparagraphs in paragraph (a) as follows:

------------------------------------------------------------------------
           Old paragraph number                 New paragraph number
------------------------------------------------------------------------
(a)(1)....................................   (a)(16)
 (a)(2)...................................   (a)(22)
 (a)(5)...................................   (a)(23)
 (a)(6)...................................   (a)(32)
 (a)(7)...................................   (a)(21)
 (a)(8)...................................   (a)(15)
 (a)(9)...................................   (a)(27)
 (a)(10)..................................   (a)(13)
 (a)(11)..................................   (a)(9)
 (a)(12)..................................   (a)(29)
 (a)(13)..................................   (a)(30)
 (a)(14)..................................   (a)(1)
 (a)(15)..................................   (a)(12)
 (a)(16)..................................   (a)(7)
 (a)(17)..................................   (a)(20)
------------------------------------------------------------------------

0
b. Removing paragraphs (a)(3) and (a)(4);
0
c. Adding new paragraphs (a)(2), (a)(3), (a)(4), (a)(5), (a)(6), 
(a)(8), (a)(10), (a)(11), (a)(14), (a)(17), (a)(18), (a)(19), (a)(24), 
(a)(25), (a)(26), (a)(28), (a)(31), and (c)(8);
0
d. Revising newly redesignated paragraphs (a)(13), (a)(16), (a)(22), 
and (a)(30); and
0
e. Removing the authority citations following the section.
    The additions and revisions read as follows:


Sec.  210.4-10  Financial accounting and reporting for oil and gas 
producing activities pursuant to the Federal securities laws and the 
Energy Policy and Conservation Act of 1975.

* * * * *
    (a) Definitions. * * *
* * * * *
    (2) Analogous reservoir. Analogous reservoirs, as used in resources 
assessments, have similar rock and fluid properties, reservoir 
conditions (depth, temperature, and pressure) and drive mechanisms, but 
are typically at a more advanced stage of development than the 
reservoir of interest and thus may provide concepts to assist in the 
interpretation of more limited data and estimation of recovery. When 
used to support proved reserves, an ``analogous reservoir'' refers to a 
reservoir that shares the following characteristics with the reservoir 
of interest:
    (i) Same geological formation (but not necessarily in pressure 
communication with the reservoir of interest);
    (ii) Same environment of deposition;
    (iii) Similar geological structure; and
    (iv) Same drive mechanism.
     Instruction to paragraph (a)(2): Reservoir properties must, in the 
aggregate, be no more favorable in the analog than in the reservoir of 
interest.
    (3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is 
petroleum in a solid or semi-solid state in natural deposits with a 
viscosity greater than 10,000 centipoise measured at original 
temperature in the deposit and atmospheric pressure, on a gas free 
basis. In its natural state it usually contains sulfur, metals, and 
other non-hydrocarbons.
    (4) Condensate. Condensate is a mixture of hydrocarbons that exists 
in the gaseous phase at original reservoir temperature and pressure, 
but that, when produced, is in the liquid phase at surface pressure and 
temperature.
    (5) Deterministic estimate. The method of estimating reserves or 
resources is called deterministic when a single value for each 
parameter (from the geoscience, engineering, or economic data) in the 
reserves calculation is used in the reserves estimation procedure.
    (6) Developed oil and gas reserves. Developed oil and gas reserves 
are reserves of any category that can be expected to be recovered:
    (i) Through existing wells with existing equipment and operating 
methods or in which the cost of the required equipment is relatively 
minor compared to the cost of a new well; and
    (ii) Through installed extraction equipment and infrastructure 
operational at the time of the reserves estimate if the extraction is 
by means not involving a well.
* * * * *
    (8) Development project. A development project is the means by 
which petroleum resources are brought to the status of economically 
producible. As examples, the development of a single reservoir or 
field, an incremental development in a producing field, or the 
integrated development of a group of several fields and associated 
facilities with a common ownership may constitute a development 
project.
* * * * *
    (10) Economically producible. The term economically producible, as 
it relates to a resource, means a resource which generates revenue that 
exceeds, or is reasonably expected to exceed, the costs of the 
operation. The value of the products that generate revenue shall be 
determined at the terminal point of oil and gas producing activities as 
defined in paragraph (a)(16) of this section.
    (11) Estimated ultimate recovery (EUR). Estimated ultimate recovery 
is the sum of reserves remaining as of a given date and cumulative 
production as of that date.
* * * * *
    (13) Exploratory well. An exploratory well is a well drilled to 
find a new field or to find a new reservoir in a field previously found 
to be productive of oil or gas in another reservoir. Generally, an 
exploratory well is any well that is not a development well, an 
extension well, a service well, or a stratigraphic test well as those 
items are defined in this section.
    (14) Extension well. An extension well is a well drilled to extend 
the limits of a known reservoir.
* * * * *
    (16) Oil and gas producing activities. (i) Oil and gas producing 
activities include:
    (A) The search for crude oil, including condensate and natural gas 
liquids, or natural gas (``oil and gas'') in their natural states and 
original locations;
    (B) The acquisition of property rights or properties for the 
purpose of further exploration or for the purpose of removing the oil 
or gas from such properties;
    (C) The construction, drilling, and production activities necessary 
to retrieve oil and gas from their natural reservoirs, including the 
acquisition, construction, installation, and maintenance of field 
gathering and storage systems, such as:

[[Page 2191]]

    (1) Lifting the oil and gas to the surface; and
    (2) Gathering, treating, and field processing (as in the case of 
processing gas to extract liquid hydrocarbons); and
    (D) Extraction of saleable hydrocarbons, in the solid, liquid, or 
gaseous state, from oil sands, shale, coalbeds, or other nonrenewable 
natural resources which are intended to be upgraded into synthetic oil 
or gas, and activities undertaken with a view to such extraction.
     Instruction 1 to paragraph (a)(16)(i): The oil and gas production 
function shall be regarded as ending at a ``terminal point'', which is 
the outlet valve on the lease or field storage tank. If unusual 
physical or operational circumstances exist, it may be appropriate to 
regard the terminal point for the production function as:
    a. The first point at which oil, gas, or gas liquids, natural or 
synthetic, are delivered to a main pipeline, a common carrier, a 
refinery, or a marine terminal; and
    b. In the case of natural resources that are intended to be 
upgraded into synthetic oil or gas, if those natural resources are 
delivered to a purchaser prior to upgrading, the first point at which 
the natural resources are delivered to a main pipeline, a common 
carrier, a refinery, a marine terminal, or a facility which upgrades 
such natural resources into synthetic oil or gas.
     Instruction 2 to paragraph (a)(16)(i): For purposes of this 
paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons 
that are saleable in the state in which the hydrocarbons are delivered.
    (ii) Oil and gas producing activities do not include:
    (A) Transporting, refining, or marketing oil and gas;
    (B) Processing of produced oil, gas or natural resources that can 
be upgraded into synthetic oil or gas by a registrant that does not 
have the legal right to produce or a revenue interest in such 
production;
    (C) Activities relating to the production of natural resources 
other than oil, gas, or natural resources from which synthetic oil and 
gas can be extracted; or
    (D) Production of geothermal steam.
    (17) Possible reserves. Possible reserves are those additional 
reserves that are less certain to be recovered than probable reserves.
    (i) When deterministic methods are used, the total quantities 
ultimately recovered from a project have a low probability of exceeding 
proved plus probable plus possible reserves. When probabilistic methods 
are used, there should be at least a 10% probability that the total 
quantities ultimately recovered will equal or exceed the proved plus 
probable plus possible reserves estimates.
    (ii) Possible reserves may be assigned to areas of a reservoir 
adjacent to probable reserves where data control and interpretations of 
available data are progressively less certain. Frequently, this will be 
in areas where geoscience and engineering data are unable to define 
clearly the area and vertical limits of commercial production from the 
reservoir by a defined project.
    (iii) Possible reserves also include incremental quantities 
associated with a greater percentage recovery of the hydrocarbons in 
place than the recovery quantities assumed for probable reserves.
    (iv) The proved plus probable and proved plus probable plus 
possible reserves estimates must be based on reasonable alternative 
technical and commercial interpretations within the reservoir or 
subject project that are clearly documented, including comparisons to 
results in successful similar projects.
    (v) Possible reserves may be assigned where geoscience and 
engineering data identify directly adjacent portions of a reservoir 
within the same accumulation that may be separated from proved areas by 
faults with displacement less than formation thickness or other 
geological discontinuities and that have not been penetrated by a 
wellbore, and the registrant believes that such adjacent portions are 
in communication with the known (proved) reservoir. Possible reserves 
may be assigned to areas that are structurally higher or lower than the 
proved area if these areas are in communication with the proved 
reservoir.
    (vi) Pursuant to paragraph (a)(22)(iii) of this section, where 
direct observation has defined a highest known oil (HKO) elevation and 
the potential exists for an associated gas cap, proved oil reserves 
should be assigned in the structurally higher portions of the reservoir 
above the HKO only if the higher contact can be established with 
reasonable certainty through reliable technology. Portions of the 
reservoir that do not meet this reasonable certainty criterion may be 
assigned as probable and possible oil or gas based on reservoir fluid 
properties and pressure gradient interpretations.
    (18) Probable reserves. Probable reserves are those additional 
reserves that are less certain to be recovered than proved reserves but 
which, together with proved reserves, are as likely as not to be 
recovered.
    (i) When deterministic methods are used, it is as likely as not 
that actual remaining quantities recovered will exceed the sum of 
estimated proved plus probable reserves. When probabilistic methods are 
used, there should be at least a 50% probability that the actual 
quantities recovered will equal or exceed the proved plus probable 
reserves estimates.
    (ii) Probable reserves may be assigned to areas of a reservoir 
adjacent to proved reserves where data control or interpretations of 
available data are less certain, even if the interpreted reservoir 
continuity of structure or productivity does not meet the reasonable 
certainty criterion. Probable reserves may be assigned to areas that 
are structurally higher than the proved area if these areas are in 
communication with the proved reservoir.
    (iii) Probable reserves estimates also include potential 
incremental quantities associated with a greater percentage recovery of 
the hydrocarbons in place than assumed for proved reserves.
    (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) 
of this section.
    (19) Probabilistic estimate. The method of estimation of reserves 
or resources is called probabilistic when the full range of values that 
could reasonably occur for each unknown parameter (from the geoscience 
and engineering data) is used to generate a full range of possible 
outcomes and their associated probabilities of occurrence.
* * * * *
    (22) Proved oil and gas reserves. Proved oil and gas reserves are 
those quantities of oil and gas, which, by analysis of geoscience and 
engineering data, can be estimated with reasonable certainty to be 
economically producible--from a given date forward, from known 
reservoirs, and under existing economic conditions, operating methods, 
and government regulations--prior to the time at which contracts 
providing the right to operate expire, unless evidence indicates that 
renewal is reasonably certain, regardless of whether deterministic or 
probabilistic methods are used for the estimation. The project to 
extract the hydrocarbons must have commenced or the operator must be 
reasonably certain that it will commence the project within a 
reasonable time.
    (i) The area of the reservoir considered as proved includes:
    (A) The area identified by drilling and limited by fluid contacts, 
if any, and
    (B) Adjacent undrilled portions of the reservoir that can, with 
reasonable certainty, be judged to be continuous

[[Page 2192]]

with it and to contain economically producible oil or gas on the basis 
of available geoscience and engineering data.
    (ii) In the absence of data on fluid contacts, proved quantities in 
a reservoir are limited by the lowest known hydrocarbons (LKH) as seen 
in a well penetration unless geoscience, engineering, or performance 
data and reliable technology establishes a lower contact with 
reasonable certainty.
    (iii) Where direct observation from well penetrations has defined a 
highest known oil (HKO) elevation and the potential exists for an 
associated gas cap, proved oil reserves may be assigned in the 
structurally higher portions of the reservoir only if geoscience, 
engineering, or performance data and reliable technology establish the 
higher contact with reasonable certainty.
    (iv) Reserves which can be produced economically through 
application of improved recovery techniques (including, but not limited 
to, fluid injection) are included in the proved classification when:
    (A) Successful testing by a pilot project in an area of the 
reservoir with properties no more favorable than in the reservoir as a 
whole, the operation of an installed program in the reservoir or an 
analogous reservoir, or other evidence using reliable technology 
establishes the reasonable certainty of the engineering analysis on 
which the project or program was based; and
    (B) The project has been approved for development by all necessary 
parties and entities, including governmental entities.
    (v) Existing economic conditions include prices and costs at which 
economic producibility from a reservoir is to be determined. The price 
shall be the average price during the 12-month period prior to the 
ending date of the period covered by the report, determined as an 
unweighted arithmetic average of the first-day-of-the-month price for 
each month within such period, unless prices are defined by contractual 
arrangements, excluding escalations based upon future conditions.
* * * * *
    (24) Reasonable certainty. If deterministic methods are used, 
reasonable certainty means a high degree of confidence that the 
quantities will be recovered. If probabilistic methods are used, there 
should be at least a 90% probability that the quantities actually 
recovered will equal or exceed the estimate. A high degree of 
confidence exists if the quantity is much more likely to be achieved 
than not, and, as changes due to increased availability of geoscience 
(geological, geophysical, and geochemical), engineering, and economic 
data are made to estimated ultimate recovery (EUR) with time, 
reasonably certain EUR is much more likely to increase or remain 
constant than to decrease.
    (25) Reliable technology. Reliable technology is a grouping of one 
or more technologies (including computational methods) that has been 
field tested and has been demonstrated to provide reasonably certain 
results with consistency and repeatability in the formation being 
evaluated or in an analogous formation.
    (26) Reserves. Reserves are estimated remaining quantities of oil 
and gas and related substances anticipated to be economically 
producible, as of a given date, by application of development projects 
to known accumulations. In addition, there must exist, or there must be 
a reasonable expectation that there will exist, the legal right to 
produce or a revenue interest in the production, installed means of 
delivering oil and gas or related substances to market, and all permits 
and financing required to implement the project.
    Note to paragraph (a)(26): Reserves should not be assigned to 
adjacent reservoirs isolated by major, potentially sealing, faults 
until those reservoirs are penetrated and evaluated as economically 
producible. Reserves should not be assigned to areas that are clearly 
separated from a known accumulation by a non-productive reservoir 
(i.e., absence of reservoir, structurally low reservoir, or negative 
test results). Such areas may contain prospective resources (i.e., 
potentially recoverable resources from undiscovered accumulations).
* * * * *
    (28) Resources. Resources are quantities of oil and gas estimated 
to exist in naturally occurring accumulations. A portion of the 
resources may be estimated to be recoverable, and another portion may 
be considered to be unrecoverable. Resources include both discovered 
and undiscovered accumulations.
* * * * *
    (30) Stratigraphic test well. A stratigraphic test well is a 
drilling effort, geologically directed, to obtain information 
pertaining to a specific geologic condition. Such wells customarily are 
drilled without the intent of being completed for hydrocarbon 
production. The classification also includes tests identified as core 
tests and all types of expendable holes related to hydrocarbon 
exploration. Stratigraphic tests are classified as ``exploratory type'' 
if not drilled in a known area or ``development type'' if drilled in a 
known area.
    (31) Undeveloped oil and gas reserves. Undeveloped oil and gas 
reserves are reserves of any category that are expected to be recovered 
from new wells on undrilled acreage, or from existing wells where a 
relatively major expenditure is required for recompletion.
    (i) Reserves on undrilled acreage shall be limited to those 
directly offsetting development spacing areas that are reasonably 
certain of production when drilled, unless evidence using reliable 
technology exists that establishes reasonable certainty of economic 
producibility at greater distances.
    (ii) Undrilled locations can be classified as having undeveloped 
reserves only if a development plan has been adopted indicating that 
they are scheduled to be drilled within five years, unless the specific 
circumstances, justify a longer time.
    (iii) Under no circumstances shall estimates for undeveloped 
reserves be attributable to any acreage for which an application of 
fluid injection or other improved recovery technique is contemplated, 
unless such techniques have been proved effective by actual projects in 
the same reservoir or an analogous reservoir, as defined in paragraph 
(a)(2) of this section, or by other evidence using reliable technology 
establishing reasonable certainty.
* * * * *
    (c) * * *
    (8) For purposes of this paragraph (c), the term ``current price'' 
shall mean the average price during the 12-month period prior to the 
ending date of the period covered by the report, determined as an 
unweighted arithmetic average of the first-day-of-the-month price for 
each month within such period, unless prices are defined by contractual 
arrangements, excluding escalations based upon future conditions.
* * * * *

PART 211--INTERPRETATIONS RELATING TO FINANCIAL REPORTING MATTERS

0
3. Amend Part 211, subpart A, by adding ``Modernization of Oil and Gas 
Reporting,'' Release No. FR-78 and the release date of December 31, 
2008, to the list of interpretive releases.

[[Page 2193]]

PART 229--STANDARD INSTRUCTIONS FOR FILING FORMS UNDER SECURITIES 
ACT OF 1933, SECURITIES EXCHANGE ACT OF 1934 AND ENERGY POLICY AND 
CONSERVATION ACT OF 1975--REGULATION S-K

0
4. The authority citation for part 229 continues to read in part as 
follows:

    Authority: 15 U.S.C. 77e, 77f, 77g, 77h, 77j, 77k, 77s, 77z-2, 
77z-3, 77aa(25), 77aa(26), 77ddd, 77eee, 77ggg, 77hhh, 77iii, 77jjj, 
77nnn, 77sss, 78c, 78i, 78j, 78l, 78m, 78n, 78o, 78u-5, 78w, 78ll, 
78mm, 80a-8, 80a-9, 80a-20, 80a-29, 80a-30, 80a-31(c), 80a-37, 80a-
38(a), 80a-39, 80b-11, and 7201 et seq.; and 18 U.S.C. 1350, unless 
otherwise noted.
* * * * *

0
5. Amend Sec.  229.102 by revising the introductory text of Instruction 
3 and Instructions 4, 5 and 8 to read as follows.


Sec.  229.102  (Item 102) Description of property.

* * * * *
    Instructions to Item 102: * * *
    3. In the case of an extractive enterprise, not involved in oil and 
gas producing activities, material information shall be given as to 
production, reserves, locations, development, and the nature of the 
registrant's interest. If individual properties are of major 
significance to an industry segment:
* * * * *
    4. A registrant engaged in oil and gas producing activities shall 
provide the information required by Subpart 1200 of Regulation S-K.
    5. In the case of extractive reserves other than oil and gas 
reserves, estimates other than proven or probable reserves (and any 
estimated values of such reserves) shall not be disclosed in any 
document publicly filed with the Commission, unless such information is 
required to be disclosed in the document by foreign or state law; 
provided, however, that where such estimates previously have been 
provided to a person (or any of its affiliates) that is offering to 
acquire, merge, or consolidate with the registrant, or otherwise to 
acquire the registrant's securities, such estimates may be included in 
documents relating to such acquisition.
* * * * *
    8. The attention of certain issuers engaged in oil and gas 
producing activities is directed to the information called for in 
Securities Act Industry Guide 4 (referred to in Sec.  229.801(d)).
* * * * *

0
6. Amend Sec.  229.801 by removing and reserving paragraph (b) and 
removing the authority citation following the section.

0
7. Amend Sec.  229.802 by removing and reserving paragraph (b) and 
removing the authority citation following the section.

0
8. Add Subpart 229.1200 to read as follows:
Subpart 229.1200--Disclosure by Registrants Engaged in Oil and Gas 
Producing Activities
Sec.
229.1201 (Item 1201) General instructions to oil and gas industry-
specific disclosures.
229.1202 (Item 1202) Disclosure of reserves.
229.1203 (Item 1203) Proved undeveloped reserves.
229.1204 (Item 1204) Oil and gas production, production prices and 
production costs.
229.1205 (Item 1205) Drilling and other exploratory and development 
activities.
229.1206 (Item 1206) Present activities.
229.1207 (Item 1207) Delivery commitments.
229.1208 (Item 1208) Oil and gas properties, wells, operations, and 
acreage.

Subpart 229.1200--Disclosure by Registrants Engaged in Oil and Gas 
Producing Activities


Sec.  229.1201  (Item 1201) General instructions to oil and gas 
industry-specific disclosures.

    (a) If oil and gas producing activities are material to the 
registrant's or its subsidiaries' business operations or financial 
position, the disclosure specified in this Subpart 229.1200 should be 
included under appropriate captions (with cross references, where 
applicable, to related information disclosed in financial statements). 
However, limited partnerships and joint ventures that conduct, operate, 
manage, or report upon oil and gas drilling or income programs, that 
acquire properties either for drilling and production, or for 
production of oil, gas, or geothermal steam or water, need not include 
such disclosure.
    (b) To the extent that Items 1202 through 1208 (Sec. Sec.  
229.1202-229.1208) call for disclosures in tabular format, as specified 
in the particular Item, a registrant may modify such format for ease of 
presentation, to add information or to combine two or more required 
tables.
    (c) The definitions in Rule 4-10(a) of Regulation S-X (17 CFR 
210.4-10(a)) shall apply for purposes of this Subpart 229.1200.
    (d) For purposes of this Subpart 229.1200, the term by geographic 
area means, as appropriate for meaningful disclosure in the 
circumstances:
    (1) By individual country;
    (2) By groups of countries within a continent; or
    (3) By continent.


Sec.  229.1202  (Item 1202) Disclosure of reserves.

    (a) Summary of oil and gas reserves at fiscal year end. (1) Provide 
the information specified in paragraph (a)(2) of this Item in tabular 
format as provided below:

            Summary of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices
----------------------------------------------------------------------------------------------------------------
                                                                             Reserves
                                                ----------------------------------------------------------------
               Reserves category                                            Synthetic
                                                     Oil      Natural gas      oil       Synthetic    Product A
                                                   (mbbls)       (mmcf)      (mbbls)    gas  (mmcf)   (measure)
----------------------------------------------------------------------------------------------------------------
PROVED                                           ...........  ...........  ...........  ...........  ...........
Developed:                                       ...........  ...........  ...........  ...........  ...........
    Continent A................................  ...........  ...........  ...........  ...........  ...........
    Continent B................................  ...........  ...........  ...........  ...........  ...........
    Country A..................................  ...........  ...........  ...........  ...........  ...........
    Country B..................................  ...........  ...........  ...........  ...........  ...........
    Other Countries in Continent B.............  ...........  ...........  ...........  ...........  ...........
Undeveloped:                                     ...........  ...........  ...........  ...........  ...........
    Continent A................................  ...........  ...........  ...........  ...........  ...........
    Continent B................................  ...........  ...........  ...........  ...........  ...........

[[Page 2194]]

 
    Country A..................................  ...........  ...........  ...........  ...........  ...........
    Country B..................................  ...........  ...........  ...........  ...........  ...........
    Other Countries in Continent B.............  ...........  ...........  ...........  ...........  ...........
                                                ----------------------------------------------------------------
        TOTAL PROVED...........................  ...........  ...........  ...........  ...........  ...........
----------------------------------------------------------------------------------------------------------------
PROBABLE                                         ...........  ...........  ...........  ...........  ...........
    Developed..................................  ...........  ...........  ...........  ...........  ...........
    Undeveloped................................  ...........  ...........  ...........  ...........  ...........
POSSIBLE                                         ...........  ...........  ...........  ...........  ...........
    Developed..................................  ...........  ...........  ...........  ...........  ...........
    Undeveloped................................  ...........  ...........  ...........  ...........  ...........
----------------------------------------------------------------------------------------------------------------

    (2) Disclose, in the aggregate and by geographic area and for each 
country containing 15% or more of the registrant's proved reserves, 
expressed on an oil-equivalent-barrels basis, reserves estimated using 
prices and costs under existing economic conditions, for the product 
types listed in paragraph (a)(4) of this Item, in the following 
categories:
    (i) Proved developed reserves;
    (ii) Proved undeveloped reserves;
    (iii) Total proved reserves;
    (iv) Probable developed reserves (optional);
    (v) Probable undeveloped reserves (optional);
    (vi) Possible developed reserves (optional); and
    (vii) Possible undeveloped reserves (optional).
    Instruction 1 to paragraph (a)(2): Disclose updated reserves tables 
as of the close of each fiscal year.
    Instruction 2 to paragraph (a)(2): The registrant is permitted, but 
not required, to disclose probable or possible reserves pursuant to 
paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.
    Instruction 3 to paragraph (a)(2): If the registrant discloses 
amounts of a product in barrels of oil equivalent, disclose the basis 
for such equivalency.
    Instruction 4 to paragraph (a)(2): A registrant need not provide 
disclosure of the reserves in a country containing 15% or more of the 
registrant's proved reserves if that country's government prohibits 
disclosure of reserves in that country. In addition, a registrant need 
not provide disclosure of the reserves in a country containing 15% or 
more of the registrant's proved reserves if that country's government 
prohibits disclosure in a particular field and disclosure of reserves 
in that country would have the effect of disclosing reserves in 
particular fields.
    (3) Reported total reserves shall be simple arithmetic sums of all 
estimates for individual properties or fields within each reserves 
category. When probabilistic methods are used, reserves should not be 
aggregated probabilistically beyond the field or property level; 
instead, they should be aggregated by simple arithmetic summation.
    (4) Disclose separately material reserves of the following product 
types:
    (i) Oil;
    (ii) Natural gas;
    (iii) Synthetic oil;
    (iv) Synthetic gas; and
    (v) Sales products of other non-renewable natural resources that 
are intended to be upgraded into synthetic oil and gas.
    (5) If the registrant discloses probable or possible reserves, 
discuss the uncertainty related to such reserves estimates.
    (6) If the registrant has not previously disclosed reserves 
estimates in a filing with the Commission or is disclosing material 
additions to its reserves estimates, the registrant shall provide a 
general discussion of the technologies used to establish the 
appropriate level of certainty for reserves estimates from material 
properties included in the total reserves disclosed. The particular 
properties do not need to be identified.
    (7) Preparation of reserves estimates or reserves audit. Disclose 
and describe the internal controls the registrant uses in its reserves 
estimation effort. In addition, disclose the qualifications of the 
technical person primarily responsible for overseeing the preparation 
of the reserves estimates and, if the registrant represents that a 
third party conducted a reserves audit, disclose the qualifications of 
the technical person primarily responsible for overseeing such reserves 
audit.
    (8) Third party reports. If the registrant represents that a third 
party prepared, or conducted a reserves audit of, the registrant's 
reserves estimates, or any estimated valuation thereof, or conducted a 
process review, the registrant shall file a report of the third party 
as an exhibit to the relevant registration statement or other 
Commission filing. If the report relates to the preparation of, or a 
reserves audit of, the registrant's reserves estimates, it must include 
the following disclosure, if applicable to the type of filing:
    (i) The purpose for which the report was prepared and for whom it 
was prepared;
    (ii) The effective date of the report and the date on which the 
report was completed;
    (iii) The proportion of the registrant's total reserves covered by 
the report and the geographic area in which the covered reserves are 
located;
    (iv) The assumptions, data, methods, and procedures used, including 
the percentage of the registrant's total reserves reviewed in 
connection with the preparation of the report, and a statement that 
such assumptions, data, methods, and procedures are appropriate for the 
purpose served by the report;
    (v) A discussion of primary economic assumptions;
    (vi) A discussion of the possible effects of regulation on the 
ability of the registrant to recover the estimated reserves;
    (vii) A discussion regarding the inherent uncertainties of reserves 
estimates;
    (viii) A statement that the third party has used all methods and 
procedures as it considered necessary under the circumstances to 
prepare the report;
    (ix) A brief summary of the third party's conclusions with respect 
to the reserves estimates; and

[[Page 2195]]

    (x) The signature of the third party.
    (9) For purposes of this Item 1202, the term reserves audit means 
the process of reviewing certain of the pertinent facts interpreted and 
assumptions underlying a reserves estimate prepared by another party 
and the rendering of an opinion about the appropriateness of the 
methodologies employed, the adequacy and quality of the data relied 
upon, the depth and thoroughness of the reserves estimation process, 
the classification of reserves appropriate to the relevant definitions 
used, and the reasonableness of the estimated reserves quantities.
    (b) Reserves sensitivity analysis (optional). (1) The registrant 
may, but is not required to, provide the information specified in 
paragraph (b)(2) of this Item in tabular format as provided below:

                                                         Sensitivity of Reserves to Prices by Principal Product Type and Price Scenario
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    Proved reserves                               Probable reserves                              Possible reserves
                                                    --------------------------------------------------------------------------------------------------------------------------------------------
                                                       Oil      Gas      Syn.     Syn.   Product A    Oil      Gas      Syn.     Syn.   Product A    Oil      Gas      Syn.     Syn.   Product A
                     Price case                     ------------------   oil      gas   -----------------------------   oil      gas   -----------------------------   oil      gas   ----------
                                                                      ------------------                             ------------------                             ------------------
                                                      mbbls     mmcf    mbbls     mmcf    measure    mbbls     mmcf    mbbls     mmcf    measure    mbbls     mmcf    mbbls     mmcf    measure
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario 1.........................................
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Scenario 2.........................................
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    (2) The registrant may, but is not required to, disclose, in the 
aggregate, an estimate of reserves estimated for each product type 
based on different price and cost criteria, such as a range of prices 
and costs that may reasonably be achieved, including standardized 
futures prices or management's own forecasts.
    (3) If the registrant provides disclosure under this paragraph (b), 
disclose the price and cost schedules and assumptions on which the 
disclosed values are based.
    Instruction to Item 1202: Estimates of oil or gas resources other 
than reserves, and any estimated values of such resources, shall not be 
disclosed in any document publicly filed with the Commission, unless 
such information is required to be disclosed in the document by foreign 
or state law; provided, however, that where such estimates previously 
have been provided to a person (or any of its affiliates) that is 
offering to acquire, merge, or consolidate with the registrant or 
otherwise to acquire the registrant's securities, such estimate may be 
included in documents related to such acquisition.


Sec.  229.1203  (Item 1203) Proved undeveloped reserves.

    (a) Disclose the total quantity of proved undeveloped reserves at 
year end.
    (b) Disclose material changes in proved undeveloped reserves that 
occurred during the year, including proved undeveloped reserves 
converted into proved developed reserves.
    (c) Discuss investments and progress made during the year to 
convert proved undeveloped reserves to proved developed reserves, 
including, but not limited to, capital expenditures.
    (d) Explain the reasons why material amounts of proved undeveloped 
reserves in individual fields or countries remain undeveloped for five 
years or more after disclosure as proved undeveloped reserves.


Sec.  229.1204  (Item 1204) Oil and gas production, production prices 
and production costs.

    (a) For each of the last three fiscal years disclose production, by 
final product sold, of oil, gas, and other products. Disclosure shall 
be made by geographical area and for each country and field that 
contains 15% or more of the registrant's total proved reserves 
expressed on an oil-equivalent-barrels basis unless prohibited by the 
country in which the reserves are located.
    (b) For each of the last three fiscal years disclose, by 
geographical area:
    (1) The average sales price (including transfers) per unit of oil, 
gas and other products produced; and
    (2) The average production cost, not including ad valorem and 
severance taxes, per unit of production.
    Instruction 1 to Item 1204: Generally, net production should 
include only production that is owned by the registrant and produced to 
its interest, less royalties and production due others. However, in 
special situations (e.g., foreign production) net production before any 
royalties may be provided, if more appropriate. If ``net before 
royalty'' production figures are furnished, the change from the usage 
of ``net production'' should be noted.
    Instruction 2 to Item 1204: Production of natural gas should 
include only marketable production of natural gas on an ``as sold'' 
basis. Production will include dry, residue, and wet gas, depending on 
whether liquids have been extracted before the registrant transfers 
title. Flared gas, injected gas, and gas consumed in operations should 
be omitted. Recovered gas-lift gas and reproduced gas should not be 
included until sold. Synthetic gas, when marketed as such, should be 
included in natural gas sales.
    Instruction 3 to Item 1204: If any product, such as bitumen, is 
sold or custody is transferred prior to conversion to synthetic oil or 
gas, the product's production, transfer prices, and production costs 
should be disclosed separately from all other products.
    Instruction 4 to Item 1204: The transfer price of oil and gas 
(natural and synthetic) produced should be determined in accordance 
with SFAS 69.
    Instruction 5 to Item 1204: The average production cost, not 
including ad valorem and severance taxes, per unit of production should 
be computed using production costs disclosed pursuant to SFAS 69. Units 
of production should be expressed in common units of production with 
oil, gas, and other products converted to a common unit of measure on 
the basis used in computing amortization.


Sec.  229.1205  (Item 1205) Drilling and other exploratory and 
development activities.

    (a) For each of the last three fiscal years, by geographical area, 
disclose:
    (1) The number of net productive and dry exploratory wells drilled; 
and
    (2) The number of net productive and dry development wells drilled.
    (b) Definitions. For purposes of this Item 1205, the following 
terms shall be defined as follows:
    (1) A dry well is an exploratory, development, or extension well 
that proves to be incapable of producing either oil or gas in 
sufficient quantities to justify completion as an oil or gas well.

[[Page 2196]]

    (2) A productive well is an exploratory, development, or extension 
well that is not a dry well.
    (3) Completion refers to installation of permanent equipment for 
production of oil or gas, or, in the case of a dry well, to reporting 
to the appropriate authority that the well has been abandoned.
    (4) The number of wells drilled refers to the number of wells 
completed at any time during the fiscal year, regardless of when 
drilling was initiated.
    (c) Disclose, by geographic area, for each of the last three years, 
any other exploratory or development activities conducted, including 
implementation of mining methods for purposes of oil and gas producing 
activities.


Sec.  229.1206  (Item 1206) Present activities.

    (a) Disclose, by geographical area, the registrant's present 
activities, such as the number of wells in the process of being drilled 
(including wells temporarily suspended), waterfloods in process of 
being installed, pressure maintenance operations, and any other related 
activities of material importance.
    (b) Provide the description of present activities as of a date at 
the end of the most recent fiscal year or as close to the date that the 
registrant files the document as reasonably possible.
    (c) Include only those wells in the process of being drilled at the 
``as of'' date and express them in terms of both gross and net wells.
    (d) Do not include wells that the registrant plans to drill, but 
has not commenced drilling unless there are factors that make such 
information material.


Sec.  229.1207  (Item 1207) Delivery commitments.

    (a) If the registrant is committed to provide a fixed and 
determinable quantity of oil or gas in the near future under existing 
contracts or agreements, disclose material information concerning the 
estimated availability of oil and gas from any principal sources, 
including the following:
    (1) The principal sources of oil and gas that the registrant will 
rely upon and the total amounts that the registrant expects to receive 
from each principal source and from all sources combined;
    (2) The total quantities of oil and gas that are subject to 
delivery commitments; and
    (3) The steps that the registrant has taken to ensure that 
available reserves and supplies are sufficient to meet such commitments 
for the next one to three years.
    (b) Disclose the information required by this Item:
    (1) In a form understandable to investors; and
    (2) Based upon the facts and circumstances of the particular 
situation, including, but not limited to:
    (i) Disclosure by geographic area;
    (ii) Significant supplies dedicated or contracted to the 
registrant;
    (iii) Any significant reserves or supplies subject to priorities or 
curtailments which may affect quantities delivered to certain classes 
of customers, such as customers receiving services under low priority 
and interruptible contracts;
    (iv) Any priority allocations or price limitations imposed by 
Federal or State regulatory agencies, as well as other factors beyond 
the registrant's control that may affect the registrant's ability to 
meet its contractual obligations (the registrant need not provide 
detailed discussions of price regulation);
    (v) Any other factors beyond the registrant's control, such as 
other parties having control over drilling new wells, competition for 
the acquisition of reserves and supplies, and the availability of 
foreign reserves and supplies, which may affect the registrant's 
ability to acquire additional reserves and supplies or to maintain or 
increase the availability of reserves and supplies; and
    (vi) Any impact on the registrant's earnings and financing needs 
resulting from its inability to meet short-term or long-term 
contractual obligations. (See Items 303 and 1209 of Regulation S-K 
(Sec. Sec.  229.303 and 229.1209).)
    (c) If the registrant has been unable to meet any significant 
delivery commitments in the last three years, describe the 
circumstances concerning such events and their impact on the 
registrant.
    (d) For purposes of this Item, available reserves are estimates of 
the amounts of oil and gas which the registrant can produce from 
current proved developed reserves using presently installed equipment 
under existing economic and operating conditions and an estimate of 
amounts that others can deliver to the registrant under long-term 
contracts or agreements on a per-day, per-month, or per-year basis.


Sec.  229.1208  (Item 1208) Oil and gas properties, wells, operations, 
and acreage.

    (a) Disclose, as of a reasonably current date or as of the end of 
the fiscal year, the total gross and net productive wells, expressed 
separately for oil and gas (including synthetic oil and gas produced 
through wells) and the total gross and net developed acreage (i.e., 
acreage assignable to productive wells) by geographic area.
    (b) Disclose, as of a reasonably current date or as of the end of 
the fiscal year, the amount of undeveloped acreage, both leases and 
concessions, if any, expressed in both gross and net acres by 
geographic area, together with an indication of acreage concentrations, 
and, if material, the minimum remaining terms of leases and 
concessions.
    (c) Definitions. For purposes of this Item 1208, the following 
terms shall be defined as indicated:
    (1) A gross well or acre is a well or acre in which the registrant 
owns a working interest. The number of gross wells is the total number 
of wells in which the registrant owns a working interest. Count one or 
more completions in the same bore hole as one well. In a footnote, 
disclose the number of wells with multiple completions. If one of the 
multiple completions in a well is an oil completion, classify the well 
as an oil well.
    (2) A net well or acre is deemed to exist when the sum of 
fractional ownership working interests in gross wells or acres equals 
one. The number of net wells or acres is the sum of the fractional 
working interests owned in gross wells or acres expressed as whole 
numbers and fractions of whole numbers.
    (3) Productive wells include producing wells and wells mechanically 
capable of production.
    (4) Undeveloped acreage encompasses those leased acres on which 
wells have not been drilled or completed to a point that would permit 
the production of economic quantities of oil or gas regardless of 
whether such acreage contains proved reserves. Do not confuse 
undeveloped acreage with undrilled acreage held by production under the 
terms of the lease.

PART 249--FORMS, SECURITIES EXCHANGE ACT OF 1934

0
9. The authority citation for part 249 continues to read in part as 
follows:

    Authority: 15 U.S.C. 78a et seq. and 7201; and 18 U.S.C. 1350, 
unless otherwise noted.
* * * * *

0
10. Amend Form 20-F (referenced in Sec.  249.220f) by:
0
a. Revising ``Instruction to Item 4'' and the introductory text and 
paragraph (b) of ``Instructions to Item 4.D''; and
0
b. Removing paragraph (c) of ``Instructions to Item 4.D'' and 
``Appendix A to Item 4.D--Oil and Gas.''
    The revisions read as follows:

    [Note:
    The text of Form 20-F does not, and this amendment will not, 
appear in the Code of Federal Regulations.]


[[Page 2197]]



Form 20-F

* * * * *

Item 4. Information on the Company

* * * * *

Instructions to Item 4

    1. Furnish the information specified in any industry guide listed 
in Subpart 229.800 of Regulation S-K (Sec.  229.801 et seq. of this 
chapter) that applies to you.
    2. If oil and gas operations are material to you or your 
subsidiaries' business operations or financial position, provide the 
information specified in Subpart 1200 of Regulation S-K (Sec.  229.1200 
et seq. of this chapter).
* * * * *
    Instruction to Item 4.D: In the case of an extractive enterprise, 
other than an oil and gas producing activity:
* * * * *
    (b) In documents that you file publicly with the Commission, do not 
disclose estimates of reserves unless the reserves are proven or 
probable and do not give estimated values of those reserves, unless 
foreign law requires you to disclose the information. If these types of 
estimates have already been provided to any person that is offering to 
acquire you, however, you may include the estimates in documents 
relating to the acquisition.
* * * * *

    Dated: December 31, 2008.

    By the Commission.
Florence E. Harmon,
Acting Secretary.
 [FR Doc. E9-409 Filed 1-13-09; 8:45 am]
BILLING CODE 8011-01-P