Modernization of Oil and Gas Reporting

Federal RegisterJan 14, 2009

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SECURITIES AND EXCHANGE COMMISSION

17 CFR Parts 210, 211, 229, and 249

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

RIN 3235-AK00

Modernization of Oil and Gas Reporting

AGENCY:

Securities and Exchange Commission.

ACTION:

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

SUMMARY:

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

DATES:

Effective Date:

January 1, 2010.

Comment Date:

Comments on the Paperwork Reduction Act Analysis should be received on or before February 13, 2009.

ADDRESSES:

Comments may be submitted by any of the following methods:

Electronic Comments

• Use the Commission's Internet comment form (

http://www.sec.gov/rules/proposed.shtml

); or

• Send an e-mail to

rule-comments@sec.gov

. Please include File Number S7-15-08 on the subject line; or

• Use the Federal e-Rulemaking Portal

http://www.regulations.gov

. Follow the instructions for submitting comments.

Paper Comments

• Send paper submissions in triplicate to Secretary, Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-1090.

All submissions should refer to File Number S7-15-08. This file number should be included on the subject line if e-mail is used. To help us process and review your comments more efficiently, please use only one method. The Commission will post all comments on the Commission's Internet Web site (

http://www.sec.gov/rules/concept.shtml

). Comments also are available for public inspection and copying in the Commission's Public Reference Room, 100 F Street, NE., Washington, DC 20549, on official business days between the hours of 10 a.m. and 3 p.m. All comments received will be posted without change; we do not edit personal identifying information from submissions. You should submit only information that you wish to make available publicly.

FOR FURTHER INFORMATION CONTACT:

Ray Be, Special Counsel, Office of Chief Counsel at (202) 551-3500; Dr. W. John Lee, Academic Petroleum Engineering Fellow, or Brad Skinner, Senior Assistant Chief Accountant, Office of Natural Resources and Food at (202) 551-3740; Leslie Overton, Associate Chief Accountant, Office of Chief Accountant for the Division of Corporation Finance at (202) 551-3400, Division of Corporation Finance; or Mark Mahar, Associate Chief Accountant, Jonathan Duersch, Assistant Chief Accountant, or Doug Parker, Professional Accounting Fellow, Office of the Chief Accountant at (202) 551-5300; U.S. Securities and Exchange Commission, 100 F Street, NE., Washington, DC 20549-3628.

SUPPLEMENTARY INFORMATION:

We are adopting amendments to Rule 4-10

of Regulation S-X

and Items 102, 801 and 802

of Regulation S-K.

We also are adding new Subpart 1200, including Items 1201 through 1208, to Regulation S-K.

17 CFR 210.4-10.

17 CFR 210.

17 CFR 229.102, 17 CFR 229.801, and 17 CFR 229.802.

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)

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.

These proposals encompassed issues that were previously addressed more generally in a concept release that the Commission issued on December 12, 2007 (Concept Release),

which solicited comment on possible revisions to the oil and gas reserves disclosure requirements specified in Rule 4-10 of Regulation S-X

and Item 102 of Regulation S-K.

The Proposing Release also contained proposals not addressed by the Concept Release related to the updating and codification of Industry Guide 2.

Release No. 33-8935 (June 27, 2008) [73 FR 39181].

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

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).

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.

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.

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.

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.

See, for example, Daniel Yergin and David Hobbs: “The Search for Reasonable Certainty in Reserves Disclosure,” Oil and Gas Journal (July 18, 2005).

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.

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.

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.

Almost all commenters supported some form of revision to the current oil and gas disclosure requirements, particularly given the length of time that has elapsed since the requirements were initially adopted.

Commenters 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:

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

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).

Among other things, the revisions to these definitions address four issues that have been of particular interest to companies, investors, and securities analysts:

17 CFR 210.4-10(a).

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.

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.

Some noted that a 12-month average price is considered to reflect “current economic conditions” by PRMS.

They noted that the use of an average price would reduce the effects of short term volatility

and seasonality,

while

maintaining comparability of disclosures among companies.

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.

See letters from AngloGold, BHP, Equitable, Ryder Scott, and SPE.

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.

See letters from Apache, Canadian Natural, Devon, EnCana, Evolution, IPAA, Petro-Canada, Repsol, and Ryder Scott.

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

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

and they thought that these prices better reflect the actual price received under typical natural gas contracts.

Conversely, six commenters recommended the use of a 12-month daily average price

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.

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.

See letters from Apache, BP, Chesapeake, Chevron, Devon, Repsol, and Shell.

See letters from Chesapeake, Devon, and Shell.

See letters from Apache, Newfield, and Repsol.

See letters from Canadian Natural, CAPP, EnCana, Nexen, Petro-Canada, and Repsol.

See letter from Newfield.

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.

It noted that volatility reflects the underlying economics of the oil and gas industry.

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.

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.

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.

All commenters addressing the issue of using different prices to determine reserves for disclosure and accounting opposed the proposal.

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.

We also will continue to communicate with the FASB staff to align their accounting standards with these rules.

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.

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.

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.

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;

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

• Harm comparability;

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

• Decrease transparency;

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

• Increase costs and burden significantly;

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;

See letters from CAPP, CFA, and Devon.

• Double recordkeeping burden;

See letters from Apache, Chesapeake, Eni, Equitable, and Imperial.

• Require more disclosure to explain the differences in reserves estimates; and

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

• Break the connection between disclosures and accounting.

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.

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.

We believe that changing the rules to use a 12-month average price in reserves estimations is

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

See letters from API, CAPP, and Shell.

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.

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.

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

and be better aligned with fair value of the reserves.

They indicated that management uses futures prices, not historical prices, in its planning and day-to-day decision making.

They suggested that the use of futures prices, combined with disclosure of how management made the estimates, would provide greater transparency

and comparability of disclosure.

One noted that historical prices have little to do with a company's future investments and values.

Another commenter noted that differentials can be calculated through established accounting procedures under SFAS 157.

See letters from CFA, Deloitte, Grant Thornton, and McMoRan.

See letters from CFA and Deloitte.

See letters from CFA, Grant Thornton, and McMoRan.

See letter from Deloitte.

See letters from Deloitte and McMoRan.

See letter from McMoRan.

See letter from CFA.

However, other commenters argued that futures prices are not available for all reserves locations

and that applying differentials to prices would require subjective estimates and reduce comparability among companies.

Two commenters noted that standard prices are not consistently available in some geographic regions.

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.

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.

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.

See letters from ExxonMobil and Wagner.

See letters from EnCana, Evolution, ExxonMobil, Newfield, Ryder Scott, and Total.

See letters from Ryder Scott and Total.

See letters from SPE and Total.

See letter from SPE.

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.

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.

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.

Commenters attributed the need for a buffer period to the accelerated filing dates for annual reports

and stated that they expected that the additional time would result in better, more accurate disclosure.

Others noted that some agreements, like production sharing contracts and other complex concession agreements, can make calculations difficult.

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.

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.

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.

See letters from Canadian Natural, CAPP, Eni, Nexen, and Petro-Canada.

See letters from API, Canadian Natural, CAPP, Devon, Evolution, PEMEX, Petrobras, Ryder Scott, Sasol, Shell, Total, and Wagner.

See letters from Canadian Natural, CAPP, Nexen, Petrobras, Petro-Canada, Ryder Scott, Sasol, and Wagner.

See letters from API and Shell.

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,

while still

aligning the time period with the fiscal year.

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.

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

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.

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.

Therefore, the rules we adopt today revise the definition of “oil and gas producing activities” to include such activities.

See Rule 4-10(a)(1)(ii)(D) [17 CFR 210.4-10(a)(1)(ii)(D)].

Commenters noted that unconventional resources currently represent 45% of natural gas production in the U.S. See letters from American Clean Skies and IPAA.

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.

They believed that such inclusion would greatly improve the quality and completeness of the disclosures.

Eight commenters noted that inclusion would better align disclosure with the way that companies view their operations.

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.

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.

See letters from API, CAPP, CAQ, ExxonMobil, Imperial, PWC, Repsol, Ryder Scott, Total, and Wagner.

See letters from API, CAQ, E&Y, ExxonMobil, Imperial, Petro-Canada, PWC, and Total.

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.

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.

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

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

and oil shale

be categorized based on the final product. One commenter noted that investment decisions are based on the value and disposition of the final product.

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.

See letters from CAPP, ExxonMobil, Ryder Scott, Sasol, Shell, StatoilHydro, and Wagner.

See letters from CAPP, ExxonMobil, Shell, StatoilHydro, and Wagner.

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.

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.

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.

See letters from Apache, Nexen, Petrobras, and Ryder Scott.

See letters from Apache, CAQ, and Nexen.

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

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.

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.

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.

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.

See letter from SPE.

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,

notwithstanding the existence of other engineering and geoscientific evidence.

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.

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.

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.

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.

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.

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.”

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.

But others believed that the proposed definition is consistent with the PRMS definition.

One commenter opined that the concept of estimated ultimate recovery (EUR) is appropriate to establish proved oil and gas reserves.

See letters from EIA, ExxonMobil, and Zakaib.

See letters from Apache, EIA, Energen, and SPE.

See letter from Evolution.

See letters from EnCana, ExxonMobil, Petrobras, and Ryder Scott.

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.

One commenter believed that each method may be more appropriate for different situations.

Other commenters also supported the proposed alignment of the definitions of those terms with the definitions in the PRMS definitions.

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.

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.

See letters from Apache, Devon, Evolution, Petro-Canada, Ryder Scott, Shell, SPE, Total, and Wagner.

See letter from Wagner.

See letters from AAPG, SPE, and Southwestern.

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.

We agree with that

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.

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.

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.

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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

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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.”

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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

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.

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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

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.

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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

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.

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

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

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

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.

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

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

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 category

Reserves

Oil

(mbbls)

Natural gas

(mmcf)

Synthetic oil

(mbbls)

Synthetic gas

(mmcf)

Product A

(measure)

PROVED

Developed:

Continent A

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

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

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

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

Price case

Proved reserves

Oil

Mbbls

Gas

mmcf

Product A

measure

Probable reserves

Oil

mbbls

Gas

mmcf

Product A

measure

Possible reserves

Oil

mbbls

Gas

mmcf

Product A

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

revised the language in the rule to clarify this point.

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

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

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

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.

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

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

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:

• 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:

○ Changes in prices;

○ Technical revisions; and

○ 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 Sub

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