2158 Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 

1 17 CFR 210.4–10. 

2 17 CFR 210. 

3 17 CFR 229.102, 17 CFR 229.801, and 17 CFR 

229.802. 

4 17 CFR 229. 

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 rulecomments@sec.gov. Please include File 

Number S7–15–08 on the subject line; 

or 

• Use the Federal e-Rulemaking 

Portal http://www.regulations.gov. 

Follow the instructions for submitting 

comments. 

Paper Comments 

• Send paper submissions in 

triplicate to Secretary, Securities and 

Exchange Commission, 100 F Street, 

NE., Washington, DC 20549–1090. 

All submissions should refer to File 

Number S7–15–08. This file number 

should be included on the subject line 

if e-mail is used. To help us process and 

review your comments more efficiently, 

please use only one method. The 

Commission will post all comments on 

the Commission’s Internet Web site 

(http://www.sec.gov/rules/ 

concept.shtml). Comments also are 

available for public inspection and 

copying in the Commission’s Public 

Reference Room, 100 F Street, NE., 

Washington, DC 20549, on official 

business days between the hours of 10 

a.m. and 3 p.m. All comments received 

will be posted without change; we do 

not edit personal identifying 

information from submissions. You 

should submit only information that 

you wish to make available publicly. 

FOR FURTHER INFORMATION CONTACT: Ray 

Be, Special Counsel, Office of Chief 

Counsel at (202) 551–3500; Dr. W. John 

Lee, Academic Petroleum Engineering 

Fellow, or Brad Skinner, Senior 

Assistant Chief Accountant, Office of 

Natural Resources and Food at (202) 

551–3740; Leslie Overton, Associate 

Chief Accountant, Office of Chief 

Accountant for the Division of 

Corporation Finance at (202) 551–3400, 

Division of Corporation Finance; or 

Mark Mahar, Associate Chief 

Accountant, Jonathan Duersch, 

Assistant Chief Accountant, or Doug 

Parker, Professional Accounting Fellow, 

Office of the Chief Accountant at (202) 

551–5300; U.S. Securities and Exchange 

Commission, 100 F Street, NE., 

Washington, DC 20549–3628. 

SUPPLEMENTARY INFORMATION: We are 

adopting amendments to Rule 4–10 1 of 

Regulation S–X 2 and Items 102, 801 and 

802 3 of Regulation S–K.4 We also are 

adding new Subpart 1200, including 

Items 1201 through 1208, to Regulation 

S–K. 

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 NonTraditional 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) 


pwalker on PROD1PC71 with RULES2
Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2159 

5Release No. 33–8935 (June 27, 2008) [73 FR 

39181]. 

6Release No. 33–8870 (Dec. 12, 2007) [72 FR 

71610]. 

7 17 CFR 210.4–10. See Release No. 33–6233 

(Sept. 25, 1980) [45 FR 63660] (adopting 

amendments to Regulation S–X, including Rule 4– 

10). The precursor to Rule 4–10 was Rule 3–18 of 

Regulation S–X, which was adopted in 1978. See 

Accounting Series Release No. 253 (Aug. 31, 1978) 

[43 FR 40688]. See also Accounting Series Release 

No. 257 (Dec. 19, 1978) [43 FR 60404] (further 

amending Rule 3–18 of Regulation S–X and revising 

the definition of proved reserves). 

8 Item 102 of Regulation S–K [17 CFR 229.102]. 

In 1982, the Commission adopted Item 102 of 

Regulation S–K. Item 102 contains the disclosure 

requirements previously located in Item 2 of 

Regulation S–K. See Release No. 33–6383 (March 

16, 1982) [47 FR 11380]. The Commission also 

‘‘recast * * * the disclosure requirements for oil 

and gas operations, formerly contained in Item 2(b) 

of Regulation S–K, as an industry guide.’’ See 

Release No. 33–6384 (Mar. 16, 1982) [47 FR 11476]. 

9The 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. 

10See, for example, Daniel Yergin and David 

Hobbs: ‘‘The Search for Reasonable Certainty in 

Reserves Disclosure,’’ Oil and Gas Journal (July 18, 

2005). 

11See, 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). 

12The 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. 

8. Item 1207 (Delivery Commitments) 

9. Item 1208 (Oil and Gas Properties, 

Wells, Operations, and Acreage) 

V. Guidance for Management’s Discussion 

and Analysis for Companies Engaged in 

Oil and Gas Producing Activities 

VI. Conforming Changes to Form 20–F 

VII. Impact of Amendments on Accounting 

Literature 

A. Consistency With FASB and IASB Rules 

B. Change in Accounting Principle or 

Estimate 

C. Differing Capitalization Thresholds 

Between Mining Activities and Oil and 

Gas Producing Activities 

VIII. Application of Interactive Data Format 

to Oil and Gas Disclosures 

IX. Implementation Date 

A. Mandatory Compliance 

B. Voluntary Early Compliance 

X. Paperwork Reduction Act 

A. Background 

B. Summary of Information Collections 

C. Revisions to PRA Burden Estimates 

D. Request for Comment 

XI. Cost-Benefit Analysis 

A. Background 

B. Description of New Rules and 

Amendments 

C. Benefits 

1. Average Price and First of the Month 

Price 

2. Probable and Possible Reserves 

3. Reserves Estimate Preparers and 

Reserves Auditors 

4. Development of Proved Undeveloped 

Reserves 

5. Disclosure Guidance 

6. Updating of Definitions Related to Oil 

and Gas Activities 

7. Harmonizing Foreign Private Issuer 

Disclosure 

D. Costs 

1. Probable and Possible Reserves 

2. Reserves Estimate Preparers and 

Reserves Auditors 

3. Consistency With IASB 

4. Change of Pricing Mechanism 

5. Disclosure of PUD Development 

6. Increased Geographic Disclosure 

7. Harmonizing Foreign Private Issuer 

Disclosure 

XII. Consideration of Burden on Competition 

and Promotion of Efficiency, 

Competition, and Capital Formation 

XIII. Final Regulatory Flexibility Analysis 

A. Reasons for, and Objectives of, the New 

Rules and Amendments 

B. Significant Issues Raised by 

Commenters 

C. Small Entities Subject to the New Rules 

and Amendments 

D. Reporting, Recordkeeping, and Other 

Compliance Requirements 

E. Agency Action to Minimize Effect on 

Small Entities 

XIV. Update to Codification of Financial 

Reporting Policies 

XV. Statutory Basis and Text of Amendments 

I. Introduction 

A. Background 

On June 26, 2008, the Commission 

issued a proposing release (Proposing 

Release) seeking public comment on 

proposed amendments to the disclosure 

requirements regarding oil and gas 

companies.5 These proposals 

encompassed issues that were 

previously addressed more generally in 

a concept release that the Commission 

issued on December 12, 2007 (Concept 

Release),6 which solicited comment on 

possible revisions to the oil and gas 

reserves disclosure requirements 

specified in Rule 4–10 of Regulation S– 

X 7 and Item 102 of Regulation S–K.8

The Proposing Release also contained 

proposals not addressed by the Concept 

Release related to the updating and 

codification of Industry Guide 2. 

We initially adopted our oil and gas 

disclosure requirements in 1978 and 

1982.9 Since that time, there have been 

significant changes in the oil and gas 

industry and markets, including 

technological advances, and changes in 

the types of projects in which oil and 

gas companies invest their capital.10

Prior to our issuance of the Concept 

Release and the Proposing Release, 

many industry participants had 

expressed concern that our disclosure 

rules are no longer in alignment with 

current industry practices and therefore 

limit their usefulness to the market and 

investors.11

B. Issuance of the Concept Release 

The Concept Release addressed the 

potential implications for the quality, 

accuracy and reliability of oil and gas 

disclosure if the Commission were to: 

• Revise the definition of ‘‘proved 

reserves’’ in our rules, in particular, the 

criteria used to assess and quantify 

resources that can be classified as 

proved reserves; and 

• Expand the categories of resources 

that may be disclosed in Commission 

filings to include resources other than 

proved reserves. 

In addition, the Concept Release 

questioned whether our revised 

disclosure rules should be modeled on 

any particular resource classification 

framework currently being used within 

the oil and gas industry. We also asked 

how any revised disclosure rules could 

be made flexible enough to address 

future technological innovation and 

changes within the oil and gas industry. 

The Concept Release sought further 

comment on whether the Commission 

should require independent third-party 

assessments of reserves estimates that a 

company includes in its filings. 

In response to the Concept Release, 

commenters submitted 80 comment 

letters.12 We received comment letters 

from a variety of industry participants 

such as accounting firms, engineering 

consulting firms, domestic and foreign 

oil and gas companies, federal 

government agencies, individuals, law 

firms, professional associations, public 

interest groups, and rating agencies. We 

considered these comments and 

addressed many of them in issuing the 

Proposing Release. 

C. Overview of the Comment Letters 

Received on the Proposing Release 

The Proposing Release sought 

significantly more detailed comment on 

issues raised in the Concept Release, as 

well as proposed amendments to the 

disclosure items in our rules and 

Industry Guide 2. In response to the 

Proposing Release, we received 65 

comment letters, again from a variety of 

constituents with interests in oil and gas 

industry disclosure. 


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2160 Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 

13See 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’’). 

14 17 CFR 210.4–10(a). 

15The 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). 

16See Rule 4–10(a)(22)(v) [17 CFR 210.4– 

10(a)(22)(v)]. 

17See letters from AngloGold, Apache, API, BHP, 

BP, Canadian Natural, CAPP, Chesapeake, Chevron, 

Devon, EIA, EnCana, Equitable, Evolution, 

ExxonMobil, Newfield, Nexen, Petrobras, PetroCanada, PWC, Questar, Repsol, Ryder Scott, Sasol, 

Shell, Southwestern, SPE, Total, and Wagner. 

18See letters from AngloGold, BHP, Equitable, 

Ryder Scott, and SPE. 

19See 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. 

20See letters from Apache, Canadian Natural, 

Devon, EnCana, Evolution, IPAA, Petro-Canada, 

Repsol, and Ryder Scott. 

Almost all commenters supported 

some form of revision to the current oil 

and gas disclosure requirements, 

particularly given the length of time that 

has elapsed since the requirements were 

initially adopted.13 Commenters 

provided significantly more detailed 

comments on the Proposing Release 

than on the Concept Release, which did 

not include specific proposed regulatory 

text. We discuss those comments in 

detail in the relevant sections of this 

release. However, in general, 

commenters focused on several key 

issues raised by the Proposing Release. 

These issues included the following: 

• The proposal to permit disclosure 

of probable and possible reserves; 

• The proposed use of average 

historical prices to represent existing 

economic conditions to determine the 

economic producibility of oil and gas 

reserves for disclosure purposes while 

continuing to use a single day year-end 

price to determine the economic 

producibility of reserves for accounting 

purposes; 

• The proposed inclusion of bitumen, 

oil shales, and other resources in the 

definition of ‘‘oil and gas producing 

activities’’; 

• The proposed provision to broaden 

the types of technology that a company 

may use to establish reserves estimates 

and categories; 

• The proposed change in the 

definition of proved undeveloped 

reserves to eliminate the ‘‘certainty’’ 

requirement; and 

• The increased detail of disclosure 

that would be required as a result of our 

proposed definition of ‘‘geographic 

location.’’ 

II. Revisions and Additions to the 

Definition Section in Rule 4–10 of 

Regulation S–X 

A. Introduction 

The revisions and additions to the 

definition section in Rule 4–10(a) of 

Regulation S–X 14 update our reserves 

definitions to reflect changes in the oil 

and gas industry and markets and new 

technologies that have occurred in the 

decades since the current rules were 

adopted. Many of the definitions are 

designed to be consistent with the 

Petroleum Resource Management 

System (PRMS).15 Among other things, 

the revisions to these definitions 

address four issues that have been of 

particular interest to companies, 

investors, and securities analysts: 

• The use of single-day year-end 

pricing to determine the economic 

producibility of reserves; 

• The exclusion of activities related 

to the extraction of bitumen and other 

‘‘non-traditional’’ resources from the 

definition of oil and gas producing 

activities; 

• The limitations regarding the types 

of technologies that an oil and gas 

company may rely upon to establish the 

levels of certainty required to classify 

reserves; and 

• The limitation in the current rules 

that permits oil and gas companies to 

disclose only their proved reserves. 

The revisions of, and additions to, the 

Rule 4–10 definitions attempt to address 

these issues without sacrificing clarity 

and comparability, which provide 

protection and transparency to 

investors. In addition, to the extent 

appropriate, we have revised our 

proposals so that the final definitions 

are more consistent with terms and 

definitions in the PRMS to improve 

compliance and understanding of our 

new rules. 

B. Pricing Mechanism for Oil and Gas 

Reserves Estimation 

1. 12-Month Average Price 

The final rules define the term 

‘‘proved oil and gas reserves’’ in part as 

‘‘those quantities of oil and gas, which, 

by analysis of geoscience and 

engineering data, can be estimated with 

reasonable certainty to be economically 

producible—from a given date forward, 

from known reservoirs, and under 

existing economic conditions, operating 

methods, and government regulations— 

prior to the time at which contracts 

providing the right to operate expire, 

unless evidence indicates that renewal 

is reasonably certain, regardless of 

whether deterministic or probabilistic 

methods are used for the estimation.’’ 

The definition states that the economic 

producibility of a reservoir must be 

based on existing economic conditions. 

It specifies that, in calculating economic 

producibility, a company must use a 12- 

month average price, calculated as the 

unweighted arithmetic average of the 

first-day-of-the-month price for each 

month within the 12-month period prior 

to the end of the reporting period, 

unless prices are defined by contractual 

arrangements, excluding escalations 

based upon future conditions.16

Most commenters supported the use 

of a 12-month average price to serve as 

a proxy for existing economic 

conditions to determine the economic 

producibility of reserves.17 Some noted 

that a 12-month average price is 

considered to reflect ‘‘current economic 

conditions’’ by PRMS.18 They noted that 

the use of an average price would 

reduce the effects of short term 

volatility 19 and seasonality,20 while 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2161 

21See letters from BHP, Canadian Natural, CAPP, 

Deloitte, Devon, IPAA, Newfield, Petro-Canada, 

Total, and Wagner. 

22See letters from Apache, BP, Chesapeake, 

Chevron, Devon, Repsol, and Shell. 

23See letters from Chesapeake, Devon, and Shell. 

24See letters from Apache, Newfield, and Repsol. 

25See letters from Canadian Natural, CAPP, 

EnCana, Nexen, Petro-Canada, and Repsol. 

26See letter from Newfield. 

27See letters from Apache and Shell. 

28See letter from CFA. 

29See letter from CFA. 

30See new Rule 4–10(a)(22)(v) of Regulation S– 

X [17 CFR 210.4–10(a)(22)(v)]. 

31Currently, companies use a single-day, yearend 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. 

32See 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. 

33See Rule 4–10. 

34See 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. 

35See letters from BP, CFA, Devon, Eni, Nexen, 

Repsol, and Wagner. 

36See letters from Apache, Canadian Natural, 

CAPP, Questar, StatoilHydro, and Wagner. 

37See letters from Canadian Natural, CAPP, 

ExxonMobil, Shell, Swift, and Wagner. 

38See 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. 

39See letters from CAPP, CFA, and Devon. 

40See letters from Apache, Chesapeake, Eni, 

Equitable, and Imperial. 

41See letters from CAPP, Devon, Eni, 

ExxonMobil, Imperial, and Wagner. 

42See letters from Apache, Audit Quality, CAPP, 

CFA, Deloitte, E&Y, Energen, Eni, ExxonMobil, 

Imperial, KPMG, Newfield, PWC, Repsol, and Total. 

43See letters from API, CAPP, and Shell. 

44See letters from API, Canadian Natural, 

EnCana, ExxonMobil, and Total. 

maintaining comparability of 

disclosures among companies.21

Seven commenters recommended the 

use of first-of-the-month prices 22

instead of the proposed use of end-ofthe-month prices because the use of 

first-of-the-month prices would provide 

companies with more time to estimate 

their reserves 23 and they thought that 

these prices better reflect the actual 

price received under typical natural gas 

contracts.24 Conversely, six commenters 

recommended the use of a 12-month 

daily average price 25 because they 

thought that a daily average price would 

be more appropriate than a monthly 

average price. These commenters noted 

that oil sales contracts often are based 

on daily averages.26 Two commenters 

expressed concern that end-of-themonth prices are not representative of 

actual prices because commodity traders 

often ‘‘clear their books’’ at the end of 

the month.27

One commenter opposed the use of 

average prices stating that, conceptually, 

the use of average prices is poor 

regulatory policy and may encourage 

the market to pressure standard setters 

to use historical average prices for 

financial instruments and other assets 

and liabilities associated with volatile 

markets.28 It noted that volatility reflects 

the underlying economics of the oil and 

gas industry.29

The objective of reserves estimation is 

to provide the public with comparable 

information about volumes, not fair 

value, of a company’s reserves available 

to enable investors to compare the 

business prospects of different 

companies. The use of a 12-month 

average historical price to determine the 

economic producibility of reserves 

quantities increases comparability 

between companies’ oil and gas reserve 

disclosures, while mitigating any 

additional variability that a single-day 

price may have on reserve estimates. 

Although oil and gas prices themselves 

are subject to market-based volatility, 

the estimation of reserves quantities 

based on any historical price 

assumption determines those reserves 

quantities as if the oil or gas already has 

been produced, even though they have 

not, and these measures do not attempt 

to portray a reflection of their fair value. 

If the objective of reserve disclosures 

were to provide fair value information, 

we believe a pricing system that 

incorporates assumptions about 

estimated future market prices and costs 

related to extraction could be a more 

appropriate basis for estimation. 

In order to provide disclosures which 

are more consistent with the objective of 

comparability, the amendments state 

that the existing economic conditions 

for determining the economic 

producibility of oil and gas reserves 

include the 12-month average price, 

calculated as the unweighted arithmetic 

average of the first-day-of-the-month 

price for each month within the 12- 

month period prior to the end of the 

reporting period.30 For example, a 

company with a reporting year end of 

December 31 would determine its 

reserves estimates for its annual report 

based on the average of the prices for oil 

or gas on the first day of every month 

from January through December. 

Therefore, the use of a 12-month average 

price provides companies with the 

ability to efficiently prepare useful 

reserve information without sacrificing 

the objective of comparability. We 

believe that the revised definition of the 

term ‘‘proved oil and gas reserves’’ will 

provide investors with improved 

reserves information thereby enhancing 

their ability to analyze the disclosures. 

2. Prices Used for Disclosure and 

Accounting Purposes 

A proposal that resulted in significant 

comment was the use of a 12-month 

average price to estimate reserves for 

disclosure purposes, but a single-day, 

year-end price for accounting 

purposes.31 All commenters addressing 

the issue of using different prices to 

determine reserves for disclosure and 

accounting opposed the proposal.32 We 

are not adopting this aspect of the 

proposal. Instead, we are revising both 

our disclosure rules and our full-cost 

accounting rules related to oil and gas 

reserves to use a single price based on 

a 12-month average.33 We also will 

continue to communicate with the 

FASB staff to align their accounting 

standards with these rules. 

Commenters pointed out that the use 

of two different prices for disclosure 

and accounting purposes could: 

• Confuse investors and other users of 

financial statements.34

• Create misleading information; 35

• Harm comparability; 36

• Decrease transparency; 37

• Increase costs and burden 

significantly; 38

• Increase the complexity of 

disclosures; 39

• Double recordkeeping burden; 40

• Require more disclosure to explain 

the differences in reserves estimates; 

and 41

• Break the connection between 

disclosures and accounting.42

Some commenters noted that the 

disclosure and accounting rules and 

guidance do not use a different pricing 

method in other situations.43 In 

addition, several commenters believed 

that changing to the use of an average 

price to estimate proved reserves would 

have a minimal impact on depreciation 

and net income.44 We believe that 

changing the rules to use a 12-month 

average price in reserves estimations is 


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45See letters from Apache, BHP, Canadian 

Natural, CAPP, CFA, Deloitte, McMoRan, Newfield, 

Nexen, Questar, Southwestern, Talisman, and Total. 

46See letters from CFA, Deloitte, Grant Thornton, 

and McMoRan. 

47See letters from CFA and Deloitte. 

48See letters from CFA, Grant Thornton, and 

McMoRan. 

49See letter from Deloitte. 

50See letters from Deloitte and McMoRan. 

51See letter from McMoRan. 

52See letter from CFA. 

53See letters from ExxonMobil and Wagner. 

54See letters from EnCana, Evolution, 

ExxonMobil, Newfield, Ryder Scott, and Total. 

55See letters from Ryder Scott and Total. 

56See letters from SPE and Total. 

57See letter from SPE. 

58See letters from Evolution, Ryder Scott, and 

Wagner. 

59See letters from Apache, API, BP, Canadian 

Natural, CAPP, EnCana, Eni, ExxonMobil, PEMEX, 

Petro-Canada, Repsol, Ryder Scott, Sasol, Shell, 

Total, van Wyk, and Wagner. 

60See letters from Apache, API, BP, Canadian 

Natural, CAPP, Devon, Eni, ExxonMobil, PEMEX, 

Petro-Canada, Repsol, Ryder Scott, Sasol, Shell, 

Total, van Wyk, and Wagner. 

61See letters from Canadian Natural, CAPP, Eni, 

Nexen, and Petro-Canada. 

62See letters from API, Canadian Natural, CAPP, 

Devon, Evolution, PEMEX, Petrobras, Ryder Scott, 

Sasol, Shell, Total, and Wagner. 

63See letters from Canadian Natural, CAPP, 

Nexen, Petrobras, Petro-Canada, Ryder Scott, Sasol, 

and Wagner. 

64See letters from API and Shell. 

65See letter from Shell. 

66See letters from API, Devon, Eni, Evolution, 

ExxonMobil, PEMEX, Petrobras, PWC, Repsol, and 

Total. 

not inconsistent with the principles and 

objectives of financial reporting in 

authoritative accounting guidance. 

With respect to accounting 

pronouncements that currently make 

reference to a single-day pricing regime 

with respect to oil and gas reserves, we 

are communicating with the FASB staff 

to align the standards used in its 

pronouncements with the 12-month 

average price used in our new rules, as 

several commenters recommended.45 As 

discussed in more detail below, we are 

adopting a compliance date that will 

provide sufficient time to coordinate 

such activities with the FASB. However, 

as we discuss our revisions with the 

FASB, we will consider whether to 

delay the compliance date further. 

3. Alternate Pricing Schemes 

Some commenters on the Proposing 

Release believed that oil and gas futures 

prices, or management’s forecast of 

future prices, would better represent the 

value of the reserves 46 and be better 

aligned with fair value of the reserves.47

They indicated that management uses 

futures prices, not historical prices, in 

its planning and day-to-day decision 

making.48 They suggested that the use of 

futures prices, combined with 

disclosure of how management made 

the estimates, would provide greater 

transparency 49 and comparability of 

disclosure.50 One noted that historical 

prices have little to do with a company’s 

future investments and values.51

Another commenter noted that 

differentials can be calculated through 

established accounting procedures 

under SFAS 157.52

However, other commenters argued 

that futures prices are not available for 

all reserves locations 53 and that 

applying differentials to prices would 

require subjective estimates and reduce 

comparability among companies.54 Two 

commenters noted that standard prices 

are not consistently available in some 

geographic regions.55 Similarly, two 

commenters were concerned that 

futures price estimates would have to be 

accompanied by estimates of future 

costs, which they thought would be very 

subjective and not comparable for 

determining future economic 

conditions.56 One commenter asserted 

that the use of future prices would 

require companies to document 

assumptions about future costs, or else 

the disclosure would be very 

inconsistent among reporting 

companies.57 Three commenters 

believed that futures prices are more 

subject to market perceptions than 

market realities and are seldom used in 

actual physical trading of oil and gas.58

We share the concerns of many of 

these commenters that determinations 

of expected future prices could require 

significant estimations which could fall 

into a wide, albeit reasonable, range. For 

example, in many situations and parts 

of the world, natural gas is sold through 

longer term contracts where observable 

market inputs are not widely available. 

As a result, there could be less 

comparability among different 

companies depending on their 

assumptions, which are inherent in 

determining futures prices. Difference in 

assumptions between companies could 

reduce the comparability of reserves 

information between those companies. 

We believe that the purpose of 

disclosing reserves estimates is to 

provide investors with information that 

is both meaningful and comparable. The 

reserves estimates in our disclosure 

rules, however, are not designed to be, 

nor are they intended to represent, an 

estimation of the fair market value of the 

reserves. Rather, the reserves 

disclosures are intended to provide 

investors with an indication of the 

relative quantity of reserves that is 

likely to be extracted in the future using 

a methodology that minimizes the use of 

non-reserves-specific variables. By 

eliminating assumptions underlying the 

pricing variable, as any historical 

pricing method would do, investors are 

able to compare reserves estimates 

where the differences are driven 

primarily by reserves-specific 

information, such as the location of the 

reserves and the grade of the underlying 

resource. We recognize that energy 

markets are continuing to develop. 

Therefore, we are not adopting a rule 

that requires companies to use futures 

prices to estimate reserves at this time. 

4. Time Period Over Which the Average 

Price Is To Be Calculated 

Numerous commenters on the 

Proposing Release recommended that 

the 12-month period used to calculate 

the average price for estimating reserves 

should not coincide with the fiscal year, 

as we proposed.59 Most of these 

commenters recommended a 12-month 

period running from the beginning of 

the fourth quarter of the prior fiscal year 

through the end of the third quarter of 

the present fiscal year. For example, for 

a company with a fiscal year end of 

December 31, the relevant 12-month 

period would span from October 1 of 

the prior year to September 30 of the 

fiscal year covered by the annual 

report.60 Several commenters suggested 

that we provide a two-month buffer 

between the end of the measurement 

period and the end of the company’s 

fiscal year so that reserves estimates 

would be based on prices from 

November 1 through October 31 by a 

company with a fiscal year ending on 

December 31.61 Commenters attributed 

the need for a buffer period to the 

accelerated filing dates for annual 

reports 62 and stated that they expected 

that the additional time would result in 

better, more accurate disclosure.63

Others noted that some agreements, like 

production sharing contracts and other 

complex concession agreements, can 

make calculations difficult.64 One 

commenter also noted that shifting the 

relevant measurement period so that it 

ends three-months prior to the fiscalyear end would align economic 

calculations with technical calculations, 

which typically occur at the end of the 

third quarter.65

As noted above, we have considered 

all of these recommendations. We are 

adopting a pricing formula based on the 

average of prices at the beginning of 

each month in the 12-month period 

prior to the end of the reporting period. 

A number of commenters believed that 

the use of first-of-the-month prices 

essentially would provide companies 

with one month more to prepare the 

reserves disclosures,66 while still 


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67See letters from Devon and ExxonMobil. 

68See Rule 4–10(a)(1)(ii)(D) [17 CFR 210.4– 

10(a)(1)(ii)(D)]. 

69Commenters noted that unconventional 

resources currently represent 45% of natural gas 

production in the U.S. See letters from American 

Clean Skies and IPAA. 

70See Rule 4–10(a)(16) [17 CFR 210.4–10(a)(16)]. 

71See 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, PetroCanada, PRA, PWC, Repsol, Ryder Scott, Sasol, 

Shell, SPE, StatoilHydro, Talisman, Total, and 

Wagner. 

72See letters from API, CAPP, CAQ, ExxonMobil, 

Imperial, PWC, Repsol, Ryder Scott, Total, and 

Wagner. 

73See letters from API, CAQ, E&Y, ExxonMobil, 

Imperial, Petro-Canada, PWC, and Total. 

74See letters from Imperial, IPAA, Repsol, and 

Total. 

75See Rule 4–10(a)(16) [17 CFR 210.4–10(a)(16)]. 

76A 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. 

77See letters from CAPP, ExxonMobil, Ryder 

Scott, Sasol, Shell, StatoilHydro, and Wagner. 

78See letters from CAPP, ExxonMobil, Shell, 

StatoilHydro, and Wagner. 

79See letter from ExxonMobil. 

80See letters from Apache, Nexen, Petrobras, and 

Ryder Scott. 

81See letters from Apache, CAQ, and Nexen. 

82See letter from Nexen. 

aligning the time period with the fiscal 

year.67 We agree with the commenters 

that such an average will provide 

companies more time to prepare more 

accurate disclosure, while still tying the 

pricing formula to the period covered by 

the annual report. 

C. Extraction of Bitumen and Other 

Non-Traditional Resources 

1. Definition of ‘‘Oil and Gas Producing 

Activities’’ 

Our current definition of ‘‘oil and gas 

producing activities’’ explicitly 

excludes sources of oil and gas from 

‘‘non-traditional’’ or ‘‘unconventional’’ 

sources, that is, sources that involve 

extraction by means other than 

‘‘traditional’’ oil and gas wells.68 These 

other sources include bitumen extracted 

from oil sands, as well as oil and gas 

extracted from coal and shales, even 

though some of these resources are 

sometimes extracted through wells, as 

opposed to mining and surface 

processing. However, such sources are 

increasingly providing energy resources 

to the world due in part to 

advancements in extraction and 

processing technology.69 Therefore, the 

rules we adopt today revise the 

definition of ‘‘oil and gas producing 

activities’’ to include such activities.70

All commenters on this issue 

supported including the extraction of 

unconventional resources as oil and gas 

producing activities.71 They believed 

that such inclusion would greatly 

improve the quality and completeness 

of the disclosures.72 Eight commenters 

noted that inclusion would better align 

disclosure with the way that companies 

view their operations.73 Some noted 

that, although the distinction was 

reasonable decades ago when traditional 

resources dominated oil and gas 

production, the reality of today is that 

such unconventional resources are 

mainstream and companies invest 

significant amounts of capital to 

develop these resources.74

The revised definition of ‘‘oil and gas 

producing activities’’ that we adopt 

today includes the extraction of the nontraditional resources described above.75

This amendment is intended to shift the 

focus of the definition of ‘‘oil and gas 

producing activities’’ to the final 

product of such activities, regardless of 

the extraction technology used. The 

amended definition states specifically 

that oil and gas producing activities 

include the extraction of saleable 

hydrocarbons, in the solid, liquid, or 

gaseous state, from oil sands, shale, 

coalbeds, or other nonrenewable natural 

resources which are intended to be 

upgraded into synthetic oil or gas, and 

activities undertaken with a view to 

such extraction.76

Currently, two types of natural 

resources pose a unique problem to 

establishing oil and gas reserves. Coal 

and, to a lesser degree, oil shale are used 

both as direct fuel and as feedstock to 

be converted into oil and gas. In 

response to our request for comment on 

how best to treat these resources, several 

commenters recommended that the 

extraction of coal 77 and oil shale 78 be 

categorized based on the final product. 

One commenter noted that investment 

decisions are based on the value and 

disposition of the final product.79 We 

agree with these commenters and have 

revised the proposal to require a 

company to include coal and oil shale 

that is intended to be converted into oil 

and gas as oil and gas reserves. The 

adopted rules also, however, prohibit a 

company from including coal and oil 

shale that is not intended to be 

converted into oil and gas as oil and gas 

reserves. 

2. Disclosure by Final Products 

We proposed that disclosure of 

reserves would be organized based on 

the pre-processed resource extracted 

from the ground. For example, under 

the proposal, a company that extracted 

bitumen and processed that bitumen 

into synthetic crude oil in its own 

processing plant would have had to base 

its reserves disclosure on the amount of 

bitumen that was economically 

producible, not taking into account the 

economics of the processing plant. This 

proposal was consistent with our 

traditional separation of ‘‘upstream’’ 

activities such as drilling and producing 

oil and gas from ‘‘downstream’’ 

activities such as refining. 

Distinguishing between traditional 

resources and unconventional resources 

can be significant to investors because 

unconventional resources often involve 

significantly different economics and 

company resources than oil and gas 

from traditional wells. 

Several commenters disagreed with 

our proposal, recommending that the 

determining factor should be the final 

product.80 They believed that a 

company should be able to consider the 

prices of self-processed resources when 

estimating oil and gas reserves because 

the economics of the processing plant 

are critical to the registrant’s evaluation 

of the economic producibility of the 

resources.81 One commenter was 

concerned that distinguishing bitumen 

or other intermediate product from 

traditional oil and gas creates a false and 

misleading sense of comparability 

because producers that upgrade bitumen 

and sell synthetic crude do not face the 

same risks and rewards as do producers 

who sell the bitumen itself.82

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 


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

84See letter from SPE. 

85See Rule 4–10(a)(22)(v) [17 CFR 210.4– 

10(a)(22)(v)]. 

86 In certain circumstances, a well may not 

penetrate the area at which the oil makes contact 

with water. In these cases, the company would not 

have information on the fluid contact and must use 

other means to estimate the lower boundary depths 

for the reservoir in which oil is located. 

87See previous Rule 4–10(a)(2)(i) [17 CFR 210.4– 

10(a)(2)(i)]. 

88See Rule 4–10(a)(22) [17 CFR 210.4–10(a)(22)]. 

See Section II.G for a more detailed discussion 

regarding this provision. 

89See letters from EIA, ExxonMobil, and Zakaib. 

90See letters from Apache, EIA, Energen, and 

SPE. 

91See letter from Evolution. 

92See letters from EnCana, ExxonMobil, 

Petrobras, and Ryder Scott. 

93Total. 

94See letters from Apache, Devon, Evolution, 

Petro-Canada, Ryder Scott, Shell, SPE, Total, and 

Wagner. 

95See letter from Wagner. 

96See letters from AAPG, SPE, and Southwestern. 

97See Rule 4–10(a)(24) [17 CFR 210.4–10(a)(24)]. 

98See letter from SPE. We note that with respect 

to oil and gas reserves, the term ‘‘classification’’ is 

extracted. However, the definition 

would continue to exclude: 

• Transporting, refining, processing 

(other than field processing of gas to 

extract liquid hydrocarbons by the 

company and the upgrading of natural 

resources extracted by the company 

other than oil or gas into synthetic oil 

or gas) or marketing oil and gas; 

• The production of natural resources 

other than oil, gas, or natural resources 

from which synthetic oil and gas can be 

extracted; and 

• The production of geothermal 

steam. 

D. Proved Oil and Gas Reserves 

We proposed to significantly revise 

the definition of ‘‘proved oil and gas 

reserves.’’ We are adopting that 

definition, substantially as proposed.83

However, as noted above, we have 

decided to base the price used to 

establish economic producibility on the 

average price during the 12-month 

period prior to the ending date of the 

period covered by the report, 

determined as an unweighted arithmetic 

average of the first-day-of-the-month 

price for each month within such 

period. 

One commenter recommended against 

using an average price to calculate 

existing economic conditions if the 

price is set by contractual 

arrangements.84 We agree that under 

such circumstances, the appropriate 

price to use for establishing economic 

producibility is the price set by those 

contractual arrangements. Therefore, we 

have revised the definition to reflect 

that situation.85

The existing definition of the term 

‘‘proved oil and gas reserves’’ 

incorporates certain specific concepts 

such as ‘‘lowest known hydrocarbons’’ 

which limit a company’s ability to claim 

proved reserves in the absence of 

information on fluid contacts in a well 

penetration,86 notwithstanding the 

existence of other engineering and 

geoscientific evidence.87 We proposed 

revisions to the definition that would 

permit the use of new reliable 

technologies to establish the reasonable 

certainty of proved reserves. The 

proposed revisions to the definition of 

‘‘proved oil and gas reserves’’ also 

included provisions for establishing 

levels of lowest known hydrocarbons 

and highest known oil through reliable 

technology other than well penetrations. 

We are adopting those revisions as 

proposed. 

We also are adopting, as proposed, 

revisions that permit a company to 

claim proved reserves beyond those 

development spacing areas that are 

immediately adjacent to developed 

spacing areas if the company can 

establish with reasonable certainty that 

these reserves are economically 

producible.88 These revisions are 

designed to permit the use of alternative 

technologies to establish proved 

reserves in lieu of requiring companies 

to use specific tests. In addition, they 

establish a uniform standard of 

reasonable certainty that applies to all 

proved reserves, regardless of location 

or distance from producing wells. 

E. Reasonable Certainty 

Both the existing definition of the 

term ‘‘proved oil and gas reserves,’’ and 

the definition of that term that we are 

adopting in this release, rely on the term 

‘‘reasonable certainty,’’ which 

previously was not defined in Rule 4– 

10. In the Proposing Release, we 

proposed to define the term ‘‘reasonable 

certainty’’ as ‘‘much more likely to be 

achieved than not’’ to avoid ambiguity 

in that term’s meaning. However, 

several commenters recommended that 

the rules mirror the PRMS definition 

more closely.89 Four commenters were 

concerned that a different definition 

from the PRMS would cause confusion. 

They recommended using the PRMS 

standard of ‘‘high degree of confidence 

that the quantities will be recovered.’’ 90

One commenter recommended that, 

because the proposed definition is new, 

the Commission should adopt a safe 

harbor, to avoid potential uncertainty 

until a court interprets the phrase.91 But 

others believed that the proposed 

definition is consistent with the PRMS 

definition.92 One commenter opined 

that the concept of estimated ultimate 

recovery (EUR) is appropriate to 

establish proved oil and gas reserves.93

We believe that the terms ‘‘high 

degree of confidence’’ from the PRMS 

and ‘‘much more likely to be achieved 

than not’’ in our proposal have the same 

meaning. Our proposed language was 

not intended to change the level of 

certainty required to establish 

reasonable certainty. However, we agree 

that the use of terminology that is 

consistent with the PRMS will assist in 

the understanding of those terms. 

Therefore, we are adopting the ‘‘high 

degree of confidence’’ standard that 

exists in the PRMS. We also are 

clarifying that having a ‘‘high degree of 

confidence’’ means that a quantity is 

‘‘much more likely to be achieved than 

not, and, as changes due to increased 

availability of geoscience (geological, 

geophysical, and geochemical), 

engineering, and economic data are 

made to estimated ultimate recovery 

(EUR) with time, reasonably certain 

EUR is much more likely to increase or 

remain constant than to decrease’’ to 

provide elaboration to the definition of 

reasonable certainty. 

We are adopting a definition of 

‘‘reasonable certainty’’ that addresses, 

and permits the use of, both 

deterministic methods and probabilistic 

methods for estimating reserves, as 

proposed. Nine commenters supported 

permitting the use of either 

deterministic methods or probabilistic 

methods.94 One commenter believed 

that each method may be more 

appropriate for different situations.95

Other commenters also supported the 

proposed alignment of the definitions of 

those terms with the definitions in the 

PRMS definitions.96 The definition that 

we are adopting states that, if 

deterministic methods are used, 

reasonable certainty means a high 

degree of confidence that the quantities 

will be recovered.97 Consistent with the 

PRMS definition, if probabilistic 

methods are used, there should be at 

least a 90% probability that the 

quantities actually recovered will equal 

or exceed the estimate. 

F. Developed and Undeveloped Oil and 

Gas Reserves 

We proposed to revise the definitions 

of the terms ‘‘proved developed oil and 

gas reserves’’ and ‘‘proved undeveloped 

oil and gas reserves.’’ One commenter 

noted that the terms ‘‘developed’’ and 

‘‘undeveloped’’ are not restricted to 

proved oil and gas reserves, but could 

apply to all classifications of reserves, 

including probable and possible 

reserves.98 We agree with that 


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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. 99See Rules 4–10(a)(6) and (31) [17 CFR 210.4– 

10(a)(6) and (31)]. 100See letters from SPE and Total. 101See previous Rule 4–10(a)(4) [17 CFR 210.4– 

10(a)(4)]. 102See Rule 4–10(a)(6) [17 CFR 210.4–10(a)(6)]. 

103As 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. 104See 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. 105See letters from American Clean Skies, 

Apache, API, Canadian Natural, CAPP, Chesapeake, 

Devon, Evolution, ExxonMobil, McMoRan, PetroCanada, Questar, Repsol, Southwestern, Shell, SPE, 

Total, and Wagner. 106See letters from Devon, EnCana, and 

Equitable. 107See letters from American Clean Skies, 

Apache, CAPP, Chesapeake, EnCana, ExxonMobil, 

Luscher, Newfield, Nexen, Petrobras, Petro-Canada, 

Ryder Scott, Shell, SPE, and Total. 108See letters from American Clean Skies, CAPP, 

Chesapeake, EnCana, ExxonMobil, Newfield, 

Nexen, Petrobras, Petro-Canada, Ryder Scott, Shell, 

and Total. 109See letter from SPE. 

110See letters from Devon, Ryder Scott, and 

Wagner. 111See Rule 4–10(a)(31) [17 CFR 210.4–10(a)(31)]. 112See Item 1203(d) [17 CFR 229.1203(d)]. 113See Rule 4–10(a)(31) [17 CFR 210.4–10(a)(31)]. 114See letter from Total. 115See letter from SPE. 116See letter from SPE. 

commenter. Although the development 

of a prospect may provide the company 

with more information and data to 

determine reserves amounts more 

accurately, companies may estimate 

proved, probable, and possible volumes 

regardless of the development stage. In 

the past, these terms were linked to the 

concept of proved reserves because our 

disclosure rules permitted the 

disclosure only of proved reserves. In 

light of our revision to allow disclosure 

of probable and possible reserves, the 

final rules define the terms ‘‘developed 

oil and gas reserves’’ and ‘‘undeveloped 

oil and gas reserves’’ to indicate that the 

development status of the reserves is 

relevant to all classifications of oil and 

gas reserves.99

1. Developed Oil and Gas Reserves 

Other than the change discussed 

above to eliminate ‘‘proved’’ from the 

term being defined, we are adopting a 

definition of ‘‘developed oil and gas 

reserves’’ substantially as proposed. We 

proposed to define the term ‘‘proved 

developed oil and gas reserves’’ as 

proved reserves that: 

• In projects that extract oil and gas 

through wells, can be expected to be 

recovered through existing wells with 

existing equipment and operating 

methods; and 

• In projects that extract oil and gas 

in other ways, can be expected to be 

recovered through extraction technology 

installed and operational at the time of 

the reserves estimate. 

Two commenters suggested that, 

consistent with the PRMS, reserves 

should be considered developed if the 

cost of any required equipment is 

relatively minor compared to the cost of 

a new well or the installed 

equipment.100 Again, we agree that 

consistency with PRMS would improve 

compliance with our rules. In addition, 

such a revision is consistent with our 

existing definition of the term ‘‘proved 

undeveloped reserves’’ which includes 

reserves on which a well exists, but a 

relatively ‘‘major’’ expenditure is 

required for recompletion.101 Therefore, 

the final rules provide that reserves also 

are developed if the cost of any required 

equipment is relatively minor compared 

to the cost of a new well.102

2. Undeveloped Oil and Gas Reserves 

In the Proposing Release, we 

proposed a significantly revised 

definition of the term ‘‘proved 

undeveloped oil and gas reserves.’’ The 

most significant aspect of the proposed 

revision was the replacement of the 

existing ‘‘certainty’’ test for areas 

beyond one offsetting drilling unit 103

from a productive well with a 

‘‘reasonable certainty’’ test. Currently, 

the definition of the term ‘‘proved 

undeveloped reserves’’ imposes a 

‘‘reasonable certainty’’ standard for 

reserves in drilling units immediately 

adjacent to the drilling unit containing 

a producing well and a ‘‘certainty’’ 

standard for reserves in drilling units 

beyond the immediately adjacent 

drilling units.104 All commenters on this 

issue supported the proposal.105 Three 

commenters noted that a single 

standard-reasonable certainty-should 

apply to all proved reserves.106 We are 

adopting this aspect of the definition as 

proposed. 

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

We also proposed to broaden the 

definition of the term ‘‘proved 

undeveloped reserves’’ to permit a 

company to include, in its undeveloped 

reserves estimates, quantities of oil that 

can be recovered through improved 

recovery projects and to expand the 

technologies that a company can use to 

establish reserves. Under the existing 

definition, a company can include such 

quantities only if techniques have been 

proved effective by actual production 

from projects in the area and in the 

same reservoir. As proposed, we are 

expanding this definition of the term 

‘‘undeveloped oil and gas reserves’’ to 

permit the use of techniques that have 

been proved effective by actual 

production from projects in the same 

reservoir or an analogous reservoir or 

‘‘by other evidence using reliable 

technology that establishes reasonable 

certainty.’’ 113

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.’’ 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 


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2166 Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 

117These 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. 

118See letters from AAPG, American Clean Skies, 

Apache, CFA, Davis Polk, Devon, EnCana, 

ExxonMobil, Petrobras, Ryder Scott, Sasol, Shell, 

SPE, Southwestern, and Wagner. 

119However, 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. 

120See letters from Chesapeake, ExxonMobil, 

Shell, and Total. 

121See letters from AAPG, Apache, EIA, 

Evolution, Ryder Scott, Shell, SPE, and Wagner. 

122See letters from Davis Polk and Sasol. 

123See letters from API, Devon, Eni, ExxonMobil, 

PEMEX, Petro-Canada, Questar, Repsol, Ryder 

Scott, Shell, Southwestern, StatoilHydro, and Total. 

124See letters from API, Devon, Evolution, 

ExxonMobil, Ryder Scott, StatoilHydro, and Total. 

125See letters from EnCana, Eni, Evolution, Ryder 

Scott, and Shell. 

126See Item 1202(a)(6) [17 CFR 229.1202(a)(6)]. 

127Currently, 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] 

128See letters from Southwestern and Wagner. 

129See Item 1202(a)(6) [17 CFR 229.1202(a)(6)]. 

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

G. Reliable Technology 

1. Definition of the Term ‘‘Reliable 

Technology’’ 

We are adopting, substantially as 

proposed, a new definition of ‘‘reliable 

technology’’ that would broaden the 

types of technologies that a company 

may use to establish reserves estimates 

and categories. All commenters on this 

topic supported the proposed 

principles-based definition for reliable 

technology.118

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. 

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. 

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. 

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

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.’’ 

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 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2167 

130See Rule 4–10(a)(18) [17 CFR 210.4–10(a)(18)]. 

131See letters from Devon, EnCana, SPE, and 

StatoilHydro. 

132See Rule 4–10(a)(17) [17 CFR 210.4–10(a)(17)]. 

133See letters from Devon, EnCana, SPE, and 

StatoilHydro. 

134See letter from Evolution. 

135See letters from API, CAQ, Grant Thornton, 

and KPMG. 

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

137See Note to Rule 4–10(a)(26) [17 CFR 210.4– 

10(a)(26)]. 

138See letter from StatoilHydro. 

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. 

H. Unproved Reserves—‘‘Probable 

Reserves’’ and ‘‘Possible Reserves’’ 

As discussed more fully in Section 

IV.B.3 of this release addressing the 

disclosure requirements of new Subpart 

1200, we are adopting the proposal to 

permit disclosure of probable and 

possible reserves. Therefore, we are 

adopting the proposed definitions of the 

terms ‘‘probable reserves’’ and ‘‘possible 

reserves’’ as proposed. 

When producing an estimate of the 

amount of oil and gas that is recoverable 

from a particular reservoir, a company 

can make three types of estimates: 

• An estimate that is reasonably 

certain; 

• An estimate that is as likely as not 

to be achieved; and 

• An estimate that might be achieved, 

but only under more favorable 

circumstances than are likely. 

These three types of estimates are 

known in the industry as (1) proved, (2) 

proved plus probable, and (3) proved 

plus probable plus possible reserves 

estimates. 

1. Probable Reserves 

We are adopting the definition of the 

term ‘‘probable reserves’’ as proposed. It 

states that ‘‘probable reserves’’ are those 

additional reserves that are less certain 

to be recovered than proved reserves but 

which, in sum with proved reserves, are 

as likely as not to be recovered.130 This 

definition provides guidance for the use 

of both deterministic and probabilistic 

methods. The definition clarifies that, 

when deterministic methods are used, it 

is as likely as not that actual remaining 

quantities recovered will equal or 

exceed the sum of estimated proved 

plus probable reserves. Similarly, when 

probabilistic methods are used, there 

must be at least a 50% probability that 

the actual quantities recovered will 

equal or exceed the proved plus 

probable reserves estimates. This 

definition was derived from the PRMS 

definition of the term ‘‘probable 

reserves.’’ Several commenters agreed 

with the proposed definition of this 

term, noting that it is roughly consistent 

with PRMS.131

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. 

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. 

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. 

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

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. 


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139See 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. 

140See Rule 4–10(a)(19) [17 CFR 210.4–10(a)(19)]. 

141See letter from Shell. 

142See letter from SPE. 

143See Rule 4–10(a)(2) [17 CFR 210.4–10(a)(2)]. 

144See Rule 4–10(a)(2) [17 CFR 210.4–10(a)(2)]. 

145See Rule 4–10(a)(4) [17 CFR 210.4–10(a)(4)]. 

146See Rule 4–10(a)(8) [17 CFR 210.4–10(a)(8)]. 

147See Rule 4–10(a)(10) [17 CFR 210.4–10(a)(10)]. 

148See Rule 4–10(a)(11) [17 CFR 210–4– 

10(a)(11)]. 

149See Rule 4–10(a)(13) [17 CFR 210.4–10(a)(13)]. 

150See Rule 4–10(a)(14) [17 CFR 210.4–10(a)(14)]. 

151See Rule 4–10(a)(28) [17 CFR 210.4–10(a)(28)]. 

152See letter from SPE. 

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

154See Section III.B.3.c. 

155See Section III.B.2.a. 

156See letter from SPE. 

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. 

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

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: 

• 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

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. 

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.’’ 

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. 

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. 

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 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2169 

157 17 CFR 210.4–10(c). 

158While 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)]. 

159The accounting guidance refers to our 

definition of proved reserves under existing Rule 4– 

10(a)(2), which currently uses a single-day, yearend price to establish reserves amounts. 160See Rule 4–10(c)(8) [17 CFR 210.4–10(c)(8)]. 

161Exchange Act Industry Guide 2 merely 

references, and therefore is identical to, Securities 

Act Industry Guide 2. 

162See revised Instructions 4 and 8 to Item 102 

[17 CFR 229.102]. 

163See revised Item 801 and 802 [17 CFR 229.801 

and 802]. 

164See revised Instruction 5 to Item 102 [17 CFR 

229.102]. Extractive enterprises include enterprises 

such as mining companies that extract resources 

from the ground. 

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. 

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

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

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 writedown 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 writedowns, 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. 

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

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 


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165See revised Instruction 3 to Item 102 [17 CFR 

229.102]. 

166 17 CFR 230.418. 

167 17 CFR 240.12b–4. 

168This 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. 

169See letters from Apache, CAPP, Devon, 

ExxonMobil, Imperial, Nexen, Repsol, Shell, and 

StatoilHydro. 

170See letters from Apache, CAPP, ExxonMobil, 

Imperial, Nexen, and Repsol. 

171See letters from ExxonMobil, Imperial, and 

Total. 

172See letters from Apache, API, BHP, Canadian 

Natural, CAPP, Devon, EnCana, Eni, Newfield, 

Nexen, Petro-Canada, Shell, StatoilHydro, and 

Total. 

173See letters from Apache, API, CAPP, Eni, 

Newfield, Petro-Canada, and Total. 

174See letter from Apache. 

175See letters from Apache, API, Canadian 

Natural, CAPP, Eni, ExxonMobil, Imperial, and 

Petro-Canada. 

176See letters from ExxonMobil and Nexen. 

177See letters from AAPG, CFA, Chesapeake, and 

E&Y. 

178See letter from Shell. 

179 17 CFR 229.102. 

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

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. 

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 nontraditional 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

• 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

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

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

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. 

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. 


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

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

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

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

184See letters from Devon and Petrobras. 

185See letter from Petro-Canada. 

186See letters from Apache and ExxonMobil. 

187See letters from Apache and ExxonMobil. 

188See Item 1202 [17 CFR 229.1202]. 

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

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

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. 

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. 

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. 

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. 

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 ....................................................................................... .................... .................... .................... .................... ....................


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

190See letters from Devon, Evolution, 

ExxonMobil, Ryder Scott, Shell, SPE, Talisman, and 

Wagner. 

191See 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. 

192See letters from CFA, Evolution, Petro-Canada, 

Ryder Scott, and Wagner. 

193See letter from Evolution. 

194See letter from EnCana. 

195See letters from API, ExxonMobil, Imperial, 

Repsol, and Total. 

196See letters from API, ExxonMobil, Imperial, 

and Repsol. 

SUMMARY OF OIL AND GAS RESERVES AS OF FISCAL-YEAR END BASED ON AVERAGE FISCAL-YEAR PRICES—Continued 

Reserves category 

Reserves 

Oil 

(mbbls) 

Natural gas 

(mmcf) 

Synthetic oil 

(mbbls) 

Synthetic 

gas 

(mmcf) 

Product A 

(measure) 

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. 

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

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

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 


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197See letters from API, ExxonMobil, and 

Imperial. 198See letters from Apache, Devon, Energen, Eni, 

and Southwestern. 199See letters from Apache, Devon, Eni, and 

Southwestern. 200See letters from Devon, Eni, and 

Southwestern. 201See letters from Apache and Total. 202See letter from Eni. 

203See Instruction 5 to Item 102 [17 CFR 

229.102]. 

204See letters from Davis Polk, Petro-Canada, 

Shearman & Sterling, SPE, and Zakaib. 

205See letter from Shearman & Sterling. 

206 Id. 

207See letter from SPE. 

208See letter from Davis Polk. 

209See letter from Davis Polk. 

210 Id. 

211See letters from Devon, ExxonMobil, Shell, 

and Total. 

212See letters from Canadian Natural, CAPP, 

CFA, Chesapeake, Deloitte, Devon, Evolution, 

ExxonMobil, McMoRan, Nexen, Petro-Canada, and 

Total. 

213See letters from Chesapeake, Deloitte, and 

McMoRan. 

214See letter from CFA. 

215See letters from Evolution and Total. 

216See letters from Canadian Natural, CAPP, 

Devon, EnCana, and ExxonMobil. 

217See letters from EnCana and Ryder Scott. 

218See letters from Apache, Petrobras, and 

Wagner. 

219See Item 303 of Regulation S–K [17 CFR 

229.303]. 

technologies may be used to support 

these estimates.197

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

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. 

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. 

However, consistent with existing 

Instruction 5, a company may continue 

to disclose such estimates of nonreserves 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. 

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. 

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. 

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 


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220See letters from Apache, API, Canadian 

Natural, CAPP, EnCana, ExxonMobil, Imperial, 

Petro-Canada, and Total. 221See letters from Apache, API, CAPP, 

Chesapeake, Devon, ExxonMobil, Imperial, Repsol, 

and Shell. 222See letters from Apache, API, BP, CAPP, 

Chesapeake, Chevron, Devon, E&Y, EnCana, 

ExxonMobil, Imperial, Petro-Canada, Repsol, and 

Southwestern. 

223See letters from BP, Canadian Natural, CAPP, 

EnCana, Petro-Canada, Ryder Scott, and Talisman. 

224See letters from EnCana and Ryder Scott. 

225See letters from Davis Polk, EIA, Petrobras, 

and Wagner. 

226See letter from Wagner. 

227See Item 1202 [17 CFR 229.1202]. 

228With 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. 

229See letters from Apache, API, Chevron, 

Energen, Eni, ExxonMobil, Newfield, Nexen, 

PEMEX, Petro-Canada, Ryder Scott, Shell, and 

Total. 

230See letters from Apache, API, ExxonMobil, 

Newfield, Nexen, PEMEX, Ryder Scott, and Total. 

231See letters from Apache, API, ExxonMobil, 

Newfield, Nexen, PEMEX, Repsol, and Total. 

232See letters from API, ExxonMobil, PEMEX, 

and Petro-Canada. 

233See letters from CFA, Devon, EnCana, 

Southwestern, and Wagner. 

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. 

SENSITIVITY OF RESERVES TO PRICES BY PRINCIPAL PRODUCT TYPE AND PRICE SCENARIO

Price case 

Proved reserves Probable reserves Possible reserves 

Oil 

Mbbls 

Gas 

mmcf 

Product A 

measure 

Oil 

mbbls 

Gas 

mmcf 

Product A 

measure 

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

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. 

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

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 


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

235See letters from API and Deloitte. 

236See letter from Deloitte. 

237See letters from AAPG, API, Chevron, Eni, 

Petro-Canada, Questar, and SPE. 

238See letters from API, Chevron, Energen, 

ExxonMobil, Newfield, Nexen, Petrobras, Ryder 

Scott, Shell, StatoilHydro, and Total. 

239See letters from ExxonMobil, Nexen, Shell, 

and StatoilHydro. 

240See Item 1202(a)(7) [17 CFR 229.1202(a)(7)]. 

241See 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. 

242See letters from API, Denbury, ExxonMobil, 

Imperial, Nexen, Shell, and Talisman. 

243See letters from AAPG, API, BP, Devon, 

ExxonMobil, Imperial, D. McBride, Newfield, D. 

Ryder, and Sasol. 

244See letters from Evolution and Petro-Canada. 

245See letter from Wagner. 

246See letter from Wagner. 

247See letters from Devon and Ryder Scott. 

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

revised the language in the rule to 

clarify this point.234

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. 

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

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. 

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

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: 

• 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 


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249See letters from Evolution and Wagner. 

250See letter from Ryder Scott. 

251See letters from Devon, Ryder Scott, and 

Talisman. 

252See letter from Talisman. 

253See SPE Reserves Auditing Standards. 

254See letters from Devon, ExxonMobil, PetroCanada, Ryder Scott, and Shell. 

255See letter from Wagner. 

256See letters from Devon and Petro-Canada. 

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

258See Item 1204 [17 CFR 229.1204]. 259See letters from API, BP, Canadian Natural, 

CAPP, Chevron, Eni, Equitable, ExxonMobil, 

Nexen, Petrobras, Repsol, Shell, and Wagner. 260See letters from API, ExxonMobil, Petrobras, 

Ryder Scott, Total, and Wagner. 261See letters from API, Canadian Natural, CAPP, 

Chevron, Eni, Equitable, ExxonMobil, Nexen, 

Petrobras, Southwestern, and Wagner. 

262See letter from Apache. 

263See letters from API, Canadian Natural, 

Chevron, ExxonMobil, Newfield, Nexen, Petrobras, 

and Ryder Scott. 

264See letter from Three Senators. 

265See letter from Three Senators. 

266See letters from Chesapeake, Devon, and 

Newfield. 

267See letters from Chesapeake, Deloitte, Devon, 

Three Senators, Talisman, and Wagner. 

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. 

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. 

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

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

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

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

Eight commenters suggested an 

alternative of disclosing (1) the quantity 

of undeveloped reserves if material, (2) 

the progress in converting PUDs, and (3) 

any material changes in the current 

year.263 Three U.S. Senators 

recommended requiring disclosure of 

development plans in addition to the 

table.264 They believed that requiring 

reporting of investments and planned 

investments in oil and gas development 

would provide investors with certainty 

about companies’ intentions to develop 

the federal lands that they have at their 

disposal.265 However, three commenters 

opposed disclosure of a company’s 

plans to drill and expected capital 

expenditures because disclosing their 

business plan may cause competitive 

harm and might expose them to 

litigation if results differ from their 

plan.266 Six commenters supported the 

proposed table.267


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268See Item 1203 [17 CFR 229.1203]. 

269See letter from Apache. 

270See letter from Apache. 

271See letters from Total and ExxonMobil. 

272See letter from ExxonMobil. 

273See letter from ExxonMobil. 

274See letters from Apache, ExxonMobil, and 

Total. 

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

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

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. 

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 


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275See letter from ExxonMobil. 

276See letters from Apache, API, and Imperial. 

277See letters from Apache and Southwestern. 

278See letter from Total. 

279See Item 1205 [17 CFR 229.1205]. 

280See Item 1206 [17 CFR 229.1206]. 

281See Item 1207 [17 CFR 229.1207]. 

282See letters from API, Chevron, ExxonMobil, 

Imperial, Shell, and Total. 

283See letters from Apache, ExxonMobil, Shell, 

and Total. 

284See letters from Apache, ExxonMobil, and 

Petro-Canada. 

285See letters from API, BP, Chevron, 

ExxonMobil, Imperial, StatoilHydro, and Total. 

286See letters from API and Imperial. 

287See Item 1208 [17 CFR 229.1208]. 

288See Item 303 of Regulation S–K [17 CFR 

229.303]. 

289See letters from Chevron, ExxonMobil, 

Petrobras, and Shell. 

290See letter from Repsol. 

291See letter from Total. 

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

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.’’ 

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. 

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. 

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

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

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: 


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292See Appendix A to Item 4.D—Oil and Gas of 

Form 20–F [17 CFR 249.220f]. 

293See letters from CAQ, Deloitte, ExxonMobil, 

KPMG, PWC, and Shell. 

294See letter from ExxonMobil. 

295See letter from ExxonMobil. 

296See letter from Total. 

297See letter from Total. 

298See letter from Ross. 

299See letters from Shell and Total. 

300See letter from ExxonMobil. 

301 Id. 

302See letter from Deloitte. 

• 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: 

Æ Changes in prices; 

Æ Technical revisions; and 

Æ Changes in the status of any 

concessions held (such as terminations, 

renewals, or changes in provisions); 

• Technologies used to establish the 

appropriate level of certainty for any 

material additions to, or increases in, 

reserves estimates, including any 

material additions or increases to 

reserves estimates that are the result of 

any of the final rules adopted in this 

release; 

• Prices and costs, including the 

impact on depreciation, depletion and 

amortization as well as the full cost 

ceiling test; 

• Performance of currently producing 

wells, including water production from 

such wells and the need to use 

enhanced recovery techniques to 

maintain production from such wells; 

• Performance of any mining-type 

activities for the production of 

hydrocarbons; 

• The company’s recent ability to 

convert proved undeveloped reserves to 

proved developed reserves, and, if 

disclosed, probable reserves to proved 

reserves and possible reserves to 

probable or proved reserves; 

• The minimum remaining terms of 

leases and concessions; 

• Material changes to any line item in 

the tables described in Items 1202 

through 1208 of Regulation S–K; 

• Potential effects of different forms 

of rights to resources, such as 

production sharing contracts, on 

operations; and 

• Geopolitical risks that apply to 

material concentrations of reserves. 

The MD&A is typically presented in a 

self-contained section of the registration 

statement or report. However, the 

disclosure requirements that comprise 

new Subpart 1200 of Regulation S–K 

will cause a substantial amount of an oil 

and gas company’s disclosure to appear 

in tabular format, providing an outline 

of much of a company’s operations. 

Because the tables will present many of 

the types of changes that management 

often discusses in its MD&A, we believe 

it may be more helpful to investors to 

locate such discussion close to the 

tables themselves. Thus, to the extent 

that any discussion or analysis of 

known trends, demands, commitments, 

uncertainties, and events that are 

reasonably likely to have a material 

effect on the company is directly 

relevant to a particular disclosure 

required by Subpart 1200, the company 

may include that discussion or analysis 

with the relevant table, with appropriate 

cross-references, rather than including it 

in its general MD&A section. 

VI. Conforming Changes to Form 20–F 

Form 20–F is the form on which 

foreign private issuers file their annual 

reports and Exchange Act registration 

statements. Currently, Form 20–F 

contains instructions that are similar to 

those in Item 102 of Regulation S–K. 

However, rather than referring to 

Industry Guide 2 for disclosures 

regarding oil and gas producing 

activities, Form 20–F contains its own 

‘‘Appendix A to Item 4.D—Oil and Gas’’ 

(Appendix A) that provides guidance for 

oil and gas disclosures for foreign 

private issuers.292 Appendix A is 

significantly shorter, and provides far 

less guidance regarding disclosures, 

than Subpart 1200 or Industry Guide 2. 

We proposed to revise Form 20–F to 

eliminate the reference to Appendix A, 

and rather refer to Subpart 1200, which 

would expand the disclosures required 

by foreign private issuers. 

Six commenters supported 

harmonizing the Form 20–F disclosures 

with Regulation S–K.293 One noted that 

the proposal would make disclosure 

more consistent and comparable among 

oil companies.294 It believed the 

proposal would put all oil companies on 

a level playing field.295 However, one 

commenter recommended that the 

Commission exempt companies 

reporting under International Financial 

Reporting Standards (IFRS).296 It also 

recommended that instead of applying 

the proposed Subpart 1200 to foreign 

private issuers, the Commission should 

revise Appendix A to Form 20–F itself, 

making appropriate limitations for 

foreign private issuers, such as 

eliminating the disclosure of wells and 

acreage.297 Another commenter was 

concerned because the proposals may 

hinder, rather than facilitate, transition 

to the use of IFRS.298

We continue to believe that Subpart 

1200 would be appropriate disclosure 

for all public companies engaged in oil 

and gas producing activities, including 

foreign private issuers. The added 

guidance in Subpart 1200 should 

promote more consistent and 

comparable disclosures among oil and 

gas companies. It is our understanding 

that many of the larger foreign private 

issuers already provide disclosure in 

their filings with the Commission 

comparable to the disclosure provided 

by domestic companies. Thus, we are 

revising Form 20–F to incorporate 

Subpart 1200 with respect to oil and gas 

disclosures and delete Appendix A to 

Item 4.D in that form. We recognize that 

this requirement may require a foreign 

private issuer to prepare two different 

reserves estimates if the rules in their 

home jurisdiction require a different 

pricing standard than the 12-month 

average that we adopt in this release. 

However, we believe the same conflict 

would have existed under our previous 

rule to the extent our pricing method 

differed from the home jurisdiction’s 

method. 

Appendix A currently allows a 

foreign private issuer to exclude 

required disclosures about reserves and 

agreements if its home country prohibits 

the disclosures. Two commenters 

suggested that the rule continue to 

provide an exception for disclosures 

about reserves and agreements that are 

prohibited by foreign laws.299 However, 

another commenter believed that a 

company taking advantage of such an 

exception should be required to disclose 

the country, the citation of the relevant 

law or regulation, and the fact that the 

disclosed estimates do not include 

amounts from the named country.300 We 

are not revising this provision. Rather, 

because these considerations still apply 

to such foreign private issuers, we are 

moving that provision from Appendix A 

and adopting it as Instruction 2 to Item 

4 of Form 20–F, as proposed.301

One commenter recommended 

clarifying that the new disclosures 

would not apply to foreign private 

issuers under the Multi-Jurisdictional 

Disclosure System (MJDS) using Form 

40—F that comply with NI 51–101 in 

Canada because those rules already are 

broadly consistent with PRMS.302 We 

agree with this commenter and believe 

that such issuers need not provide 

disclosures beyond those required in 

Canada. 

VII. Impact of Amendments on 

Accounting Literature 

A. Consistency With FASB and IASB 

Rules 

Numerous commenters recommended 

that the SEC generally coordinate its 

efforts with the IASB and FASB to 

create a cohesive whole and not adopt 


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303See letters from CAQ, CFA, Eni, Grant 

Thornton, KPMG, and PWC. 

304See letters from CAQ, Canadian Natural, 

CAPP, Deloitte, Devon, KPMG, Petrobras, PWC, 

Repsol, Shell, and StatoilHydro. 

305See letter from Deloitte. 

306See letter from Petro-Canada. 

307See letters from Apache, CAQ, Canadian 

Natural, CAPP, Deloitte, Devon, Evolution, 

ExxonMobil, Petrobras, Petro-Canada, PWC, Repsol, 

Shell, StatoilHydro, and Total. 

308See letters from Canadian Natural, Deloitte, 

Evolution, Petrobras, and Shell. 

309See letters from CAQ, Petrobras, and PWC. 

310See Rule 4–10(c) of Regulation S–X [17 CFR 

210.4–10(c)]. 

311See letter from KPMG. 

312See letter from KPMG. 

313See letter from KPMG. 

314See letters from Audit Policy, CFA, Deloitte, 

Devon, E&Y, ExxonMobil, PWC, Shell, Standard 

Advantage, StatoilHydro, and Zakaib. 

315See letters from CFA, Devon, E&Y, 

StatoilHydro, and Zakaib. 

316See letters from Audit Policy, Deloitte, Devon, 

E&Y, ExxonMobil, PWC, Shell, StatoilHydro, and 

Zakaib. 

317See letters from Audit Policy, Devon, E&Y, 

PWC, StatoilHydro, and Zakaib. 

318See letter from Zakaib. 

competing models.303 We have begun, 

and will continue, to work with both of 

these organizations to ensure a smooth 

transition to the new reporting rules. 

B. Change in Accounting Principle or 

Estimate 

In the Proposing Release, we 

expressed our view that the change from 

using single-day year-end price to an 

average price should be treated as a 

change in accounting principle, or a 

change in the method of applying an 

accounting principle, that is inseparable 

from a change in accounting estimate. 

Therefore, this change would be 

considered a change in accounting 

estimate pursuant to Statement of 

Financial Accounting Standard No. 154 

‘‘Accounting Changes and Error 

Corrections’’ (SFAS 154) and would be 

accounted for prospectively. 

Commenters believed that the change 

would be best described as: 

• A change in accounting 

estimate; 304

• A change in accounting principle 

that is inseparable from a change in 

accounting estimate; or 305

• A change in accounting estimate 

effected by a change in accounting 

principle.306

We believe that any accounting 

change resulting from the changes in 

definitions and required pricing 

assumptions in Rule 4–10, should be 

treated as a change in accounting 

principle that is inseparable from a 

change in accounting estimate, which 

does not require retroactive revision. We 

note that pursuant to AU 420.13, such 

a change requires recognition in the 

independent auditor’s report through 

the addition of an explanatory 

paragraph. 

All commenters on the issue agreed 

that adoption of the rules should not 

require retroactive revision of past 

reserves estimates.307 Some believed 

retroactive revision of reserves estimates 

would be very burdensome or 

impossible because such data was not 

maintained.308 We agree with those 

commenters and believe that no 

retroactive revisions will be necessary. 

Three commenters recommended that 

the FASB revise Statement of Financial 

Accounting Standard No. 19 (SFAS 19) 

to include unconventional resources 

currently accounted for as mining 

activities and also provide guidance that 

no retroactive revisions would be 

required in that scenario.309 We will 

continue to work with the FASB on this 

issue. 

C. Differing Capitalization Thresholds 

Between Mining Activities and Oil and 

Gas Producing Activities 

As noted elsewhere in this release, 

extraction of products such as bitumen 

now will be considered oil and gas 

producing activities, and not mining 

activities. Under current U.S. 

accounting guidance, costs associated 

with proven plus probable mining 

reserves may be capitalized for 

operations extracting products through 

mining methods, like bitumen. Under 

the new rules, bitumen extraction and 

operations that produce oil or gas 

through mining methods are included 

under oil and gas accounting rules, 

which only permit capitalization of 

costs associated with proved 

reserves.310 Moreover, the mining 

guidelines do not provide specified 

percentages for establishing levels of 

certainty for proven or probable reserves 

for mining activities. It is possible that 

these differences could result in 

changing reserves estimates for these 

resources during the transition to the 

new rules. 

One commenter believed that the 

industry would need guidance regarding 

how to transition operations that are 

disclosed and accounted for as mining 

operations to oil and gas disclosure and 

accounting.311 It noted that this issue 

would be relevant not only coincident 

with the new rules, but could be 

relevant to future events, such as a coal 

mining company that in subsequent 

years changes its operations to in situ 

coal gasification.312 That commenter 

believed that, without guidance, the 

change from mining treatment to oil and 

gas treatment could be considered a 

change in accounting principle which 

requires retroactive revision.313 We 

acknowledge this commenter’s 

concerns. With respect to resources 

formerly considered mining activities, 

we view the change from mining 

treatment to oil and gas treatment as a 

change in accounting principle that is 

inseparable from a change in accounting 

estimate, which does not require 

retroactive revision. 

VIII. Application of Interactive Data 

Format to Oil and Gas Disclosures 

In the Proposing Release, we sought 

comment on the desirability of rules 

that would permit, or require, oil and 

gas companies to present the tabular 

disclosures in Subpart 1200 in 

interactive data format in addition to the 

currently required format. Most 

commenters addressing the topic 

supported the use of XBRL for oil and 

gas disclosures.314 They believed using 

interactive data would be very helpful 

to investors and analysts.315

However, they also recommended that 

the Commission wait until a welldeveloped taxonomy exists.316 Some 

recommended that the Commission 

implement it in stages, initially with a 

voluntary program.317 One commenter 

recommended that the SEC work with 

other groups like SPE, IASB, and the 

United Nations to ensure tags ultimately 

become the industry standard.318

We agree that much of the disclosures 

regarding oil and gas companies would 

be conducive to interactive data. We 

intend to continue to work on 

developing a taxonomy for such 

disclosure. Once a well-developed 

taxonomy is created, we will address 

this issue further. We are not, however, 

adopting interactive data requirements 

in this release. We will continue to 

consider whether to require interactive 

oil and gas disclosure filings in the 

future and, if so, when such filings 

should be required based on the 

development status of an oil and gas 

disclosure taxonomy. 

IX. Implementation Date 

A. Mandatory Compliance 

We proposed to require companies to 

begin complying with the disclosure 

requirements for registration statements 

filed on or after January 1, 2010, and for 

annual reports on Forms 10–K and 20– 

F for fiscal years ending on or after 

December 31, 2009. A company may not 

apply the new rules to disclosures in 

quarterly reports prior to the first annual 

report in which the revised disclosures 

are required. 


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319See letters from Apache, Chevron, Davis Polk, 

Deloitte, ExxonMobil, KPMG, Newfield, Petrobras, 

Petro-Canada, PWC, Ryder Scott, Shell, 

Southwestern, Talisman, and Total. 

320See letters from Davis Polk, ExxonMobil, 

Shell, and StatoilHydro. 

321See letter from ExxonMobil. 

322See letter from Talisman. 

323See letters from Apache, Petrobras, PWC, and 

Total. 

324See letter from Petrobras. 

325See letter from Apache. 

326See letter from Devon. 

327See letters from Davis Polk, Devon, 

ExxonMobil, Petrobras, Ryder Scott, Shell, and 

Wagner. 

328See letter from Evolution. 

329See letter from Davis Polk. 

330 44 U.S.C. 3501 et seq. 

331 44 U.S.C. 3507(d) and 5 CFR 1320.11. 

332The paperwork burden from Regulation S–K 

and the Industry Guides is imposed through the 

forms that are subject to the disclosures in 

Regulation S–K and the Industry Guides and is 

reflected in the analysis of those forms. To avoid 

a Paperwork Reduction Act inventory reflecting 

duplicative burdens, for administrative 

convenience, we estimate the burdens imposed by 

each of Regulation S–K and the Industry Guides to 

be a total of one hour. 

333The pertinent annual reports are those on 

Forms 10–K and 20–F. 

334The disclosure requirements regarding oil and 

gas properties and activities are in Form 10–K as 

well as the annual report to security holders 

required pursuant to Rule 14a–3(b) [17 CFR 

240.14a–3(b)]. Form 10–K permits the incorporation 

by reference of information from the Rule 14a–3(b) 

annual report to security holders to satisfy the Form 

10–K disclosure requirements. The analysis that 

follows assumes that companies would either 

provide the proposed disclosure in a Form 10–K or 

incorporate the required disclosure into the Form 

10–K by reference to the Rule 14a–3(b) annual 

report to security holders if the company is subject 

to the proxy rules. This approach takes into account 

the burden from the proposed disclosure 

Continued 

Fifteen commenters agreed that a 

delayed compliance date would be 

helpful in allowing companies to 

familiarize themselves with the new 

disclosure requirements before having 

to comply with them.319 Four 

commenters supported the proposed 

January 1, 2010 compliance date of 

Securities Act filings and Exchange Act 

filings related to fiscal periods ending 

on or after December 31, 2009.320

However, one conditioned this approval 

upon the adoption of the rules before 

December 31, 2008.321 Another 

suggested one year after adoption of the 

rules.322

Four commenters believed that the 

proposed compliance date would be too 

soon.323 One recommended a 

compliance date of December 31, 2010 

to enable companies to make necessary 

changes in IT systems and data 

processing.324 Another noted the 

magnitude of the proposed changes, 

length of time to design, program and 

implement system changes, and the goal 

of getting the best possible 

disclosure.325 One commenter suggested 

delaying implementation for two years 

after adoption.326

We continue to believe that the 

proposed compliance dates are 

appropriate. However, as we discuss our 

revisions with the FASB and IASB, we 

will consider whether to delay the 

compliance date further. 

B. Voluntary Early Compliance 

Seven commenters recommended that 

early compliance not be permitted to 

maintain consistency and comparability 

of disclosure among issuers, which 

could be misleading or confusing to 

investors.327 However, one commenter 

believed that the Commission should 

permit early adoption of the new rules 

because companies with different fiscal 

year ends are not comparable 

anyway.328 One commenter suggested 

that the Commission permit companies 

to provide the new disclosures 

supplementally.329 We agree that 

voluntary compliance may make 

disclosures incomparable. Therefore, 

companies may not elect to follow the 

new disclosure rules prior to the 

effective date. 

X. Paperwork Reduction Act 

A. Background 

Our new rules and amendments 

contain ‘‘collection of information’’ 

requirements within the meaning of the 

Paperwork Reduction Act of 1995 

(‘‘PRA’’).330 We submitted the new rules 

and amendments to the Office of 

Management and Budget (OMB) for 

review in accordance with the PRA.331

OMB has approved the revisions. The 

titles for these collections of information 

are: 

(1) ‘‘Regulation S–K’’ (OMB Control 

No. 3235–0071); 332

(2) ‘‘Industry Guides’’ (OMB Control 

No. 3235–0069); 

(3) ‘‘Regulation S–X’’ (OMB Control 

No. 3235–0009); 

(4) ‘‘Form S–1’’ (OMB Control No. 

3235–0065); 

(5) ‘‘Form S–4’’ (OMB Control No. 

3235–0324); 

(6) ‘‘Form F–1’’ (OMB Control No. 

3235–0258); 

(7) ‘‘Form F–4’’ (OMB Control No. 

3235–0325); 

(8) ‘‘Form 10’’ (OMB Control No. 

3235–0064); 

(9) ‘‘Form 10–K’’ (OMB Control No. 

3235–0063); and 

(10) ‘‘Form 20–F’’ (OMB Control No. 

3235–0063). 

We adopted all of the existing 

regulations and forms pursuant to the 

Securities Act and the Exchange Act. 

These regulations and forms set forth 

the disclosure requirements for annual 

reports 333 and registration statements 

that are prepared by issuers to provide 

investors with the information they 

need to make informed investment 

decisions in registered offerings and in 

secondary market transactions. The 

industry guides supplement the existing 

regulations and forms and provide 

guidance with respect to industryspecific disclosures. 

Our amendments to these existing 

forms are intended to modernize and 

update our reserves definitions to better 

reflect changes in the oil and gas 

industry and markets and new 

technologies that have occurred in the 

decades since the current rules were 

adopted, including expanding the scope 

of permissible technologies for 

establishing certainty levels of reserves, 

reserves classifications that a company 

can disclose in a Commission filing, and 

the types of resources that can be 

included in a company’s reserves, as 

well as providing information regarding 

a company’s internal controls over 

reserves estimation and the 

qualifications of person preparing 

reserves estimates or conducting 

reserves audits. The new rules and 

amendments also are intended to codify, 

modernize, and centralize the disclosure 

items for oil and gas companies in 

Regulation S–K. Finally, the new rules 

and amendments are intended to 

harmonize oil and gas disclosures by 

foreign private issuers with disclosures 

by domestic companies. Overall, the 

new rules and amendments attempt to 

provide improved disclosure about an 

oil and gas company’s business and 

prospects without sacrificing clarity and 

comparability, which provide protection 

and transparency to investors. 

The hours and costs associated with 

preparing disclosure, filing forms, and 

retaining records constitute reporting 

and cost burdens imposed by the 

collection of information. An agency 

may not conduct or sponsor, and a 

person is not required to respond to, a 

collection of information unless it 

displays a currently valid control 

number. 

Many, but not all, of the information 

collection requirements related to 

annual reports and registration 

statements will be mandatory. There is 

no mandatory retention period for the 

information disclosed, and the 

information will be publicly available 

on the EDGAR filing system. 

B. Summary of Information Collections 

The new rules and amendments 

increase existing disclosure burdens for 

annual reports on Forms 10–K 334 and 


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requirements that are included in both Form 10–K 

and Regulation 14A or 14C. 

335For administrative convenience, the 

presentation of the totals related to the paperwork 

burden hours have been rounded to the nearest 

whole number and the cost totals have been 

rounded to the nearest thousand. 

20–F and registration statements on 

Forms 10, 20–F, S–1, S–4, F–1, and 

F–4 by creating the following new 

disclosure requirements, many of which 

were requested by industry participants: 

• Disclosure of reserves from nontraditional sources (i.e., bitumen, shale, 

coalbed methane) as oil and gas 

reserves; 

• Optional disclosure of probable and 

possible reserves; 

• Optional disclosure of oil and gas 

reserves’ sensitivity to price; 

• Disclosure of the company’s 

progress in converting proved 

undeveloped reserves into proved 

developed reserves, including those that 

are held for five years or more and an 

explanation of why they should 

continue to be considered proved; 

• Disclosure of technologies used to 

establish reserves in a company’s initial 

filing with the Commission and in 

filings which include material additions 

to reserves estimates; 

• The company’s internal controls 

over reserves estimates and the 

qualifications of the technical person 

primarily responsible for overseeing the 

preparation or audit of the reserves 

estimates; 

• If a company represents that 

disclosure is based on the authority of 

a third party that prepared the reserves 

estimates or conducted a reserves audit 

or process review, filing a report 

prepared by the third party; and 

• Disclosure based on a new 

definition of the term ‘‘by geographic 

area.’’ 

In addition, the amendments 

harmonize the disclosure requirements 

that apply to foreign private issuers with 

the disclosure requirements that apply 

to domestic issuers with respect to oil 

and gas activities. In particular, foreign 

private issuers must disclose the 

information required by Items 1205 

through 1208 of Regulation S–K 

regarding drilling activities, present 

activities, delivery commitments, wells, 

and acreage, which previously were not 

specified in Appendix A to Form 20–F. 

These disclosure items codify the 

substantive disclosures called for by 

Items 4 through 8 of Industry Guide 2, 

although much of this disclosure may 

have been disclosed by some companies 

under the more general discussions of 

business and property on that form. 

C. Revisions to PRA Burden Estimates 

For purposes of the PRA, we 

estimated, in the Proposing Release, the 

total annual increase in the paperwork 

burden for all affected companies to 

comply with our proposed collection of 

information requirements to be 

approximately 7,472 hours of in-house 

company personnel time and to be 

approximately $1,659,000 for the 

services of outside professionals.335

These estimates included the time and 

the cost of preparing and reviewing 

disclosure and filing documents. Our 

methodologies for deriving the above 

estimates are discussed below. 

Our estimates represented the burden 

for all oil and gas companies that file 

annual reports or registration statements 

with the Commission. Based on filings 

received during the Commission’s last 

fiscal year, we estimate that 241 oil and 

gas companies file annual reports and 

67 oil and gas companies file 

registration statements. Most of the 

information called for by the new 

disclosure requirements, including the 

optional disclosure items, is readily 

available to oil and gas companies and 

includes information that is regularly 

used in their internal management 

systems. These disclosures include: 

• Disclosure of reserves from nontraditional sources (i.e., bitumen, shale, 

coalbed methane) as oil and gas 

reserves; 

• Optional disclosure of probable and 

possible reserves; 

• Optional disclosure of oil and gas 

reserves’ sensitivity to price; 

• Disclosure of the company’s 

progress in converting proved 

undeveloped reserves into proved 

developed reserves, including those that 

are held for five years or more and an 

explanation of why they should 

continue to be considered proved; 

• Disclosure of technologies used to 

establish reserves in a company’s initial 

filing with the Commission and in 

filings which include material additions 

to reserves estimates; 

• The company’s internal controls 

over reserves estimates and the 

qualifications of the technical person 

primarily responsible for overseeing the 

preparation or audit of the reserves 

estimates; 

• If a company represents that 

disclosure is based on the authority of 

a third party that prepared the reserves 

estimates or conducted a reserves audit 

or process review, filing a report 

prepared by the third party; and 

• Disclosure based on a new 

definition of the term ‘‘by geographic 

area.’’ 

We estimated that, on average, each 

company would incur a burden of 35 

hours to prepare these disclosures in an 

annual report or registration statement. 

The amendments also apply several 

disclosure items to foreign private 

issuers that previously did not apply to 

them. As noted above, many of these 

disclosure items, such as drilling 

activities, wells and acreage, require the 

issuer to provide more specificity about 

its business and property. Foreign 

private issuers that do not currently 

provide such specificity would incur an 

added burden to present such 

disclosures in their filings. In the 

Proposing Release, we estimated that 

this burden would be 20 hours per 

foreign private issuer. 

We received few comments regarding 

our estimates. Several large oil 

companies, and an industry 

organization that primarily represents 

large oil companies, believed that the 

estimates were too low. They believed 

that the new rules and amendments 

would increase their burden by 10,000 

to 15,000 hours per year. However, 

these commenters included the initial 

cost to change their internal systems to 

provide the new required disclosures in 

their estimates. Based on conversations 

with these commenters, the staff 

understands that they believed that the 

ongoing burden would be 

approximately one-third of that 

estimate. For purposes of its Paperwork 

Reduction Act estimate, the staff 

considers the ongoing annual burden 

and spreads the initial transitional 

burden of compliance with new rules 

and regulations over a three-year period. 

In addition, these commenters 

indicated that the two most significant 

burdens that stemmed from the 

proposed use of different prices for 

disclosure and accounting purposes and 

the increased detail in disclosures that 

would result from the proposed 

definition of the term ‘‘geographic area’’ 

and the proposed disclosure by type of 

accumulation. It should be noted that 

these commenters have significant 

reserves spread worldwide. Some of 

these large companies have as much as 

10,000 times the amount of reserves of 

the median oil and gas company. These 

large companies likely would be more 

significantly impacted by the level of 

detailed disclosure that the proposals 

would have required compared to the 

vast majority of oil and gas companies 

in our reporting system, which do not 

have such extensive global operations. 

Therefore, we do not believe that the 

estimate provided by those large oil and 

gas companies necessarily would be 

applicable to most oil and gas 

companies. However, in response to the 

concerns that they expressed, the final 

rules do not require the use of different 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2183 

336 In connection with other recent rulemakings, 

we have had discussions with several private law 

firms to estimate an hourly rate of $400 as the 

average cost of outside professionals that assist 

issuers in preparing disclosures and conducting 

registered offerings. 

337The burden estimates for Form 10–K assume 

that the requirements are satisfied by either 

including information directly in the annual reports 

or incorporating the information by reference from 

the Rule 14a–3(b) annual report to security holders. 

prices for disclosure and full cost 

accounting purposes. We also intend to 

continue to work with the FASB to align 

the accounting standards with that 

pricing mechanism. In addition, we 

have significantly reduced the level of 

detailed geographic and product 

disclosure that the rules require. 

Finally, we are providing for a 

substantial transition period to allow 

companies to adjust their systems to 

comply with the new rules. We believe 

that these changes will help to mitigate 

the increased burden of the new rules. 

We do, however, believe that our 

initial burden estimates may have been 

too low. We are therefore adjusting our 

burden estimate to reflect an additional 

increase of 100 hours per company per 

year. In addition, we are increasing our 

burden estimate for foreign private 

issuers by an additional 150 hours per 

company per year. Consistent with 

current Office of Management and 

Budget estimates and recent 

Commission rulemakings, we estimate 

that 25% of the burden of preparation 

of registration statements on Forms S– 

1, S–4, F–1, F–4, 10, and 20–F is carried 

by the company internally and that 75% 

of the burden is carried by outside 

professionals retained by the issuer at 

an average cost of $400 per hour.336 We 

estimate that 75% of the burden of 

preparation of annual reports on Form 

10–K or Form 20–F is carried by the 

company internally and that 25% of the 

burden is carried by outside 

professionals retained by the company 

at an average cost of $400 per hour. The 

portion of the burden carried by outside 

professionals is reflected as a cost, while 

the portion of the burden carried by the 

company internally is reflected in 

hours. The following tables summarize 

the additional changes to the PRA 

estimates: 

TABLE 1—CALCULATION OF INCREMENTAL PAPERWORK REDUCTION ACT BURDEN ESTIMATES FOR EXCHANGE ACT

PERIODIC REPORTS

Form 

Annual 

responses 

Incremental 

hours/form 

Incremental 

burden 

75% Issuer 25% 

Professional 

$400 

Professional 

cost 

(A) (B) (C)=(A)*(B) (D)=(C)*0.75 (E)=(C)*0.25 (F)=(E)*$400 

10–K§ 337 .................................................. 206 100 20,600 15,450 5,150 2,060,000 

20–F ......................................................... 35 150 5,250 3,938 1,312 525,000 

Total .................................................. 241 ........................ 25,850 19,388 6,462 2,585,000 

TABLE 2—CALCULATION OF INCREMENTAL PAPERWORK REDUCTION ACT BURDEN ESTIMATES FOR SECURITIES ACT

REGISTRATION STATEMENTS AND EXCHANGE ACT REGISTRATION STATEMENTS

Form 

Annual responses Incremental 

hours/form 

Incremental 

burden 

25% 

Issuer 

75% 

Professional 

$400 

Professional 

cost 

(A) (B) (C)=(A)*(B) (D)=(C)*0.25 (E)=(C)*0.75 (F)=(E)*$400 

10 ............................................................. 5 100 500 125 375 150,000 

20–F ......................................................... 2 150 300 75 225 90,000 

S–1 ........................................................... 38 100 3,800 950 2,850 1,140,000 

S–4 ........................................................... 17 100 1,700 425 1,275 510,000 

F–1 ........................................................... 2 150 300 75 225 90,000 

F–4 ........................................................... 3 150 450 112.5 337.5 135,000 

Total .................................................. 67 ........................ 7,050 1762.5 5,287.5 2,115,000 

D. Request for Comment 

We request comment in order to 

evaluate the accuracy of our estimates of 

the burden of the revised information 

collections. Any member of the public 

may direct to us any comments 

concerning the accuracy of these burden 

estimates. Persons who desire to submit 

comments on the collection of 

information requirements should direct 

their comments to the OMB, Attention: 

Desk Officer for the Securities and 

Exchange Commission, Office of 

Information and Regulatory Affairs, 

Washington, DC 20503, and should send 

a copy of the comments to Secretary, 

Securities and Exchange Commission, 

100 F Street, NE., Washington, DC 

20549–1090, with reference to File No. 

S7–15–08. Requests for materials 

submitted to the OMB by us with regard 

to this collection of information should 

be in writing, refer to File No. S7–15– 

08, and be submitted to the Securities 

and Exchange Commission, Records 

Management Branch, 100 F Street, NE., 

Washington, DC 20549–1126. Because 

OMB is required to make a decision 

concerning the collections of 

information between 30 and 60 days 

after publication, your comments are 

best assured of having their full effect if 

OMB receives them within 30 days of 

publication. 

XI. Cost-Benefit Analysis 

A. Background 

We are adopting revisions to the oil 

and gas reserves disclosure regime of 

Regulation S–K and Regulation S–X 

under the Securities Act of 1933 and the 

Securities Exchange Act of 1934 and 

Industry Guide 2. The revisions are 

intended to modernize and update oil 

and gas disclosure. The oil and gas 

industry has experienced significant 

changes since the Commission initially 

adopted its current rules and disclosure 


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2184 Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 

regime between 1978 and 1982, 

including advancements in technology 

and changes in the types of projects in 

which oil and gas companies invest. 

The revisions also are intended to 

provide investors with improved 

disclosure about an oil and gas 

company’s business and prospects 

without sacrificing clarity and 

comparability. 

B. Description of New Rules and 

Amendments 

Currently, Industry Guide 2 specifies 

many of the disclosure guidelines for oil 

and gas companies. The Industry Guide 

calls for disclosure relating to reserves, 

production, property, and operations in 

addition to that which is required by 

Regulation S–K. Generally, the new 

rules and amendments codify and 

update the existing Industry Guide 2 

disclosures in a new Subpart 1200 of 

Regulation S–K, clarify the level of 

detail required to be disclosed, and 

require reserves disclosure in a tabular 

presentation. The changes relate 

primarily to disclosure of the following: 

• Disclosure of reserves from nontraditional sources (e.g., bitumen, shale) 

as oil and gas reserves; 

• Optional disclosure of probable and 

possible reserves; 

• Optional disclosure of oil and gas 

reserves’ sensitivity to price; 

• Disclosure of the company’s 

progress in converting proved 

undeveloped reserves into proved 

developed reserves, including those that 

are held for five years or more and an 

explanation of why they should 

continue to be considered proved; 

• Disclosure of technologies used to 

establish reserves in a company’s initial 

filing with the Commission and in 

filings which include material additions 

to reserves estimates; 

• The company’s internal controls 

over reserves estimates and the 

qualifications of the technical person 

primarily responsible for overseeing the 

preparation or audit of the reserves 

estimates; 

• If a company represents that 

disclosure is based on the authority of 

a third party that prepared the reserves 

estimates or conducted a reserves audit 

or process review, filing a report 

prepared by the third party; and 

• Disclosure based on a new 

definition of the term ‘‘by geographic 

area.’’ 

The new rules and amendments also 

make revisions and additions to the 

definitions section of Rule 4–10 of 

Regulation S–X. These revisions update 

and extend reserves definitions to 

reflect changes in the oil and gas 

industry and new technologies. In 

particular, the new and revised 

definitions: 

• Expand the definition of ‘‘oil and 

gas producing activities’’ to include the 

extraction of hydrocarbons from oil 

sands, shale, coalbeds, or other natural 

resources and activities undertaken with 

a view to such extraction; 

• Add a definition of ‘‘reasonable 

certainty’’ to provide better guidance 

regarding the meaning of that term; 

• Add a definition of ‘‘reliable 

technology’’ to permit the use of new 

technologies to establish proved 

reserves; 

• Define probable and possible 

reserves estimates; and 

• Add definitions to explain new 

terms used in the revised definitions. 

In addition, the amendments 

harmonize the disclosure requirements 

that apply to foreign private issuers with 

the disclosure requirements that apply 

to domestic issuers with respect to oil 

and gas activities. In particular, the 

amendments to Form 20–F will require 

foreign private issuers to disclose the 

information required by Items 1205 

through 1208 of Regulation S–K 

regarding drilling activities, present 

activities, delivery commitments, wells, 

and acreage, which are not currently 

specified under Appendix A to Form 

20–F, although much of this disclosure 

is often disclosed by companies under 

the more general discussions of business 

and property on that form. 

C. Benefits 

We expect that the new rules and 

amendments will increase transparency 

in disclosure by oil and gas companies 

by providing improved reporting 

standards. The revisions to the 

definitions should align our disclosure 

rules with the realities of the modern oil 

and gas markets. For example, we 

believe that the inclusion of bitumen 

and other resources from continuous 

accumulations as oil and gas producing 

activities is consistent with company 

practice to treat these operations as part 

of, rather than separate from, their 

traditional oil and gas producing 

activities. Similarly, the expansion of 

permissible technologies for 

determining certainty levels of reserves 

recognizes that companies now take 

advantage of these technological 

advances to make business decisions. 

We expect these new rules and 

amendments to improve disclosure by 

aligning the required disclosure more 

closely with the way companies 

conduct their business. 

Allowing companies to disclose 

probable and possible reserves is 

designed to improve investors’ 

understanding of a company’s unproved 

reserves. For those companies that 

already disclose such reserves on their 

Web sites, the new rules and 

amendments permit them to unify such 

disclosures into a single, filed 

document. Disclosure of these categories 

of reserves beyond proved reserves may 

foster better company valuations by 

investors, creditors, and analysts, thus 

improving capital allocation and 

reducing investment risk. Because some 

of the disclosure items are optional, the 

amount of increased transparency will 

depend on the extent to which 

companies elect to provide the 

additional disclosures permitted under 

the new rules. If companies elect not to 

provide the optional disclosure, then 

the benefits from increased transparency 

would be limited to the extent that the 

new rules improve the transparency of 

proved reserves disclosure. 

By permitting increased disclosure 

and promoting more consistency and 

comparability among disclosures, the 

new rules and amendments provide a 

mechanism for oil and gas companies to 

seek more favorable financing terms 

through more disclosure and increased 

transparency. Investors may be able to 

request such additional disclosure in 

Commission filings during negotiations 

regarding bond and debt covenants. 

Thus, we expect that, as a result of 

competing factors in the marketplace, 

the new rules and amendments will 

result in increased transparency, either 

because companies elect to voluntarily 

provide increased disclosure, or because 

investors may discount companies that 

do not do so. We believe that the 

benefits and costs of disclosing 

unproved reserves ultimately will be 

determined by market conditions, rather 

than regulatory requirements. 

We expect that permitting companies 

to disclose probable and possible 

reserves will increase market 

transparency, provide investors with 

more reserves information, and allow 

for more accurate production forecasts. 

By relating standards used in 

deterministic methods to comparable 

percentage thresholds used in 

probabilistic methods for establishing a 

given level of certainty, the new rules 

and amendments should result in 

increased standardization in reporting 

practices which would promote 

comparability of reserves across 

companies. The new rules would define 

the term ‘‘reliable technology’’ to permit 

oil and gas companies to prepare their 

reserves estimates using new types of 

technology that companies are not 

permitted to use under the current rules. 

This new definition also is designed to 

encompass new technologies as they are 

developed in the future, thereby 


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providing investors and the market with 

a more comprehensive understanding of 

a company’s estimated reserves. 

We expect that replacing the Industry 

Guide with new Regulation S–K items 

will provide greater certainty because 

the disclosure requirements would be in 

rules established by the Commission. In 

addition, we believe that disclosure of 

reserves concentrated in particular 

countries should provide better 

information to investors regarding the 

geopolitical risk to which some 

companies may be exposed. Overall, we 

believe that the amendments, as a 

whole, will provide investors with more 

information that management uses to 

make business decisions in the oil and 

gas industry. 

1. Average Price and First of the Month 

Price 

The revision to change the price used 

to calculate reserves from a year-end 

single-day price to a historical average 

price over the company’s most recently 

ended fiscal year is expected to reduce 

the effects of seasonality. In particular, 

many commenters suggested the use of 

a 12-month average price to mitigate the 

risk of a year-end price affected by 

short-term price volatility such that it 

does not reflect the true nature of a 

company investment, planning, and 

performance. Our Office of Economic 

Analysis studied the publicly-available 

pricing data and found evidence of yearend price volatility. The historical 

volatility of year-end prices is between 

16 percent and 41 percent higher than 

the volatility of annual average prices 

depending on the grade and geography 

of oil or gas prices considered. This 

difference demonstrates variability in 

oil and gas prices, likely due to seasonal 

demands, that does not reflect long term 

fundamental values, but that cannot be 

immediately corrected due to the costs 

of transportation and speed of delivery. 

Given this variability, it is likely that a 

12-month average price will yield better 

reserves estimates—that reflect 

management planning and investment 

to the extent that they discount the 

short-term component of oil and gas 

prices—than a year-end spot price. 

Many of the commenters to the 

Proposing Release supported the use of 

a historical price, even though this 

approach may be less useful in 

determining the fair value of a 

company’s reserves compared to a 

futures market price. We believe 

investors are concerned not only about 

the quantity of a company’s reserves, 

but also about the profitability of those 

reserves. We also recognize that some 

reserves will be of more value than 

others due to extraction and 

transportation costs. As a result, since 

the new rules and amendments require 

the use of a single price to estimate 

reserves and since that price may not be 

as informative of value as a futures 

price, the new rules and amendments 

also gives companies the option of 

providing a sensitivity analysis and 

reporting reserves based on additional 

price estimates. 

If companies elect to provide a 

sensitivity analysis, we expect this to 

benefit investors by allowing them to 

formulate better projections of company 

prospects that are more consistent with 

management’s planning price and prices 

higher and lower that may reasonably be 

achieved. In particular, it allows 

companies the flexibility to 

communicate how their reserves would 

change under alternative economic 

conditions, including those that they 

may believe better reflect their future 

prospects. We expect that companies 

would be more likely to adopt a 

sensitivity analysis approach if 

investors and other market participants 

determine that this information would 

reduce investment risk, or if companies 

believe such disclosure will reduce the 

cost of capital formation. The new rules 

and amendments should result in 

increased price stability in determining 

whether reserves are economically 

producible. This should mitigate 

seasonal effects, resulting in reserves 

estimates that more closely reflect those 

used by management in planning and 

investment decisions. We expect this to 

allow for more accurate company 

assessments and improve projections of 

company prospects. 

In addition to an average annual 

price, many of the commenters 

suggested that the price be computed on 

the first day of the month. Two reasons 

were given. First, beginning month 

prices would allow an additional month 

of preparation time in calculating 

reserves for financial reporting. Second, 

some commenters suggested that monthend, and in particular year-end, prices 

were subject to additional short-term 

volatility because many oil and gas 

financial contracts expire on those days, 

resulting in higher than normal trading 

activity. While the staff of the Office of 

Economic Analysis did not find 

systematic evidence of increased 

volatility around month-end or year-end 

oil and gas prices relative to other days 

in the month, we agree that additional 

preparation time is beneficial because 

reserves estimations require significant 

time and resources. An additional 

month would help reduce errors that 

might otherwise result from the 

financial reporting time constraints. 

Finally, we believe that revising the 

full cost accounting method to use the 

same pricing mechanism as the reserves 

disclosure requirements should provide 

consistency between the disclosure and 

accounting presentations. The use of a 

single pricing method should also 

minimize the incremental burden 

placed on companies as a result of the 

rule changes because they would not be 

required to prepare two separate 

estimates. 

2. Probable and Possible Reserves 

We anticipate that disclosure of 

probable and possible reserves, if 

companies elect to do so, will allow 

investors, creditors, and other users to 

better assess a company’s reserves. In 

addition, the tabular format for 

disclosing probable and possible 

reserves should reduce investor search 

costs by making it easier to locate 

reserves disclosures and facilitating 

comparability among oil and gas 

companies. 

While we recognize that many 

companies already communicate with 

investors about their unproved and 

other reserves through alternative 

means, such as company Web sites or 

press releases, some commenters 

remarked that an objective comparison 

among companies is difficult because 

different companies have defined such 

reserves classifications differently. We 

believe that permitting disclosure of this 

information in Commission filings will 

provide a more consistent means of 

comparison because disclosure in our 

filings must comply with our 

definitions. Although our new rules 

make disclosure of probable and 

possible reserves optional, and large oil 

and gas producers suggested in their 

comment letters that such disclosure 

would be of limited benefit because of 

the relative uncertainty of those 

estimates, we believe that competitive 

pressures within the industry might 

make it beneficial for large producers to 

disclose this information. Increased 

disclosure might, for example, improve 

credit quality and lower the cost of debt 

financing, or reduce the risk associated 

with business transactions between the 

company and its customers or suppliers. 

Regardless, since the disclosure 

decision is voluntary, it should occur 

only to the extent that companies find 

that the benefits justify the costs of 

doing so. 

We believe that permitting the 

disclosure of probable and possible 

reserves will benefit smaller companies, 

in particular. Larger issuers tend to 

already have large amounts of proved 

reserves. The new rules and 

amendments permit smaller companies, 


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2186 Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 

who often participate in a significant 

amount of exploratory activity, to better 

disclose their business prospects. 

Consequently, we anticipate that the 

new rules and amendments could lead 

to efficiencies in capital formation, as 

more information will be available 

regarding the prospects of smaller 

issuers. 

3. Reserves Estimate Preparers and 

Reserves Auditors 

We believe that investors would 

benefit from a greater level of assurance 

with respect to the reliability of reserve 

estimates, particularly if companies are 

allowed to disclose unproved reserves 

because unproved reserves are 

inherently less certain than proved 

reserves. We proposed disclosure 

requirements relating to whether the 

person primarily responsible for 

preparing reserves estimates or 

conducting a reserves audit, if the 

company represents that it has enlisted 

a third party to conduct a reserves audit, 

met a specified list of qualifications 

based on the Society of Petroleum 

Engineers’s reserves audit guidelines. 

However, commenters expressed 

concern that many of these 

qualifications such as membership in 

professional societies were not 

standardized worldwide. Without 

control over those standards, the 

disclosures would not be comparable. 

We agree with those commenters and, as 

suggested, have adopted a more 

principles-based disclosure 

requirement. Under the adopted rules, a 

company must disclose its internal 

controls over reserves estimations and 

disclose the qualifications of the 

primary technical person in charge of 

overseeing the reserves estimations or 

reserves audit. We believe that 

disclosure of the individual 

qualifications, rather than simple 

acknowledgement of meeting certain 

criteria, which may differ within 

countries, will provide investors with 

better information to compare 

companies and the qualifications of 

persons in charge of the reserves 

estimations and reserves audits, which 

should enable more accurate 

assessments of the quality of audit 

reports. We believe that disclosure of a 

company’s internal controls over 

reserves estimates will allow investors 

to assess whether a company has 

implemented appropriate controls 

without dictating to companies 

specified criteria for establishing those 

controls. 

Although we do not expect all 

companies to undertake a third-party 

reserves audit because our rules do not 

require such a reserves audit, third party 

participation in the estimation of 

reserves should add credibility to a 

company’s public disclosure. The 

opinion of an objective, qualified person 

on the reserves estimates is designed to 

increase the reliability of these estimates 

and investor confidence. 

4. Development of Proved Undeveloped 

Reserves 

The new rules and amendments also 

require disclosure of a company’s 

progress in developing undeveloped 

reserves and the reasons why any PUDs 

have remained undeveloped for five 

years or more. We believe that such 

disclosure supplements our 

amendments that ease the requirements 

for recognizing PUDs and thereby 

should increase the amount of PUDs 

disclosed in filings, even though the 

properties representing such proved 

reserves have not yet been developed 

and therefore do not provide the 

company with cash flow. We believe 

that the disclosure requirements will 

increase the accountability of 

companies that disclose reserves for 

extended periods of time without 

adequate justification for their failure to 

develop those reserves. 

5. Disclosure Guidance 

The release also provides guidance 

about the type of information that 

companies should consider disclosing 

in Management’s Discussion and 

Analysis, and allows companies to 

include this information with the 

relevant tables. Providing the additional 

guidance should assist companies in 

preparing their disclosure, improving 

the quality and consistency of this 

disclosure. Locating this discussion 

with the tables themselves should 

benefit investors by simplifying the 

presentation of disclosure, and 

providing insight into the information 

disclosed in the tables. 

6. Updating of Definitions Related to Oil 

and Gas Activities 

The new rules and amendments also 

update the definition of the term ‘‘oil 

and gas producing activities’’ as well as 

updating or creating new definitions for 

other terms related to such activities, 

including ‘‘proved oil and gas reserves’’ 

and ‘‘reasonable certainty.’’ We believe 

that updating these definitions will help 

companies disclose oil and gas 

operations in the same way that 

companies manage and assess those 

operations. This includes resources 

extracted from nontraditional sources 

that companies consider oil and gas 

activities, which previously were 

excluded them from the definition of 

‘‘oil and gas producing activities.’’ In 

addition, adding definitions for terms 

like ‘‘reasonable certainty’’ (which 

currently is in the definition of ‘‘proved 

oil and gas reserves,’’ but not defined) 

will provide companies with added 

guidance and assist them in providing 

consistent disclosures between 

companies. 

7. Harmonizing Foreign Private Issuer 

Disclosure 

We believe that the harmonization of 

foreign private issuer disclosure will 

help make disclosures of foreign private 

issuers more comparable with domestic 

companies. The oil and gas industry has 

changed significantly since the rules 

were adopted. Today, many companies 

have interests that span the globe. In 

addition, many of these projects are 

joint ventures between foreign private 

issuers and domestic companies. Having 

differing levels of disclosure for 

companies that may be participating in 

the same projects harms comparability 

between investment choices. The 

harmonization of foreign private issuer 

disclosure is intended to promote 

comparability among all oil companies. 

D. Costs 

We expect that the new rules and 

amendments will result in initial and 

ongoing costs to oil and gas companies. 

These burdens will vary significantly 

among companies. Based on disclosures 

in company filings, the largest oil and 

gas companies can have as much as 

10,000 times the reserves of the median 

reporting oil and gas company. As 

would be expected, companies that have 

more reserves and larger operations will 

have a correspondingly larger amount of 

information that they must disclose and, 

therefore, the burden of complying with 

our disclosure requirements would be 

greater for larger companies. 

Although we are adding a new 

subpart to Regulation S–K to set forth 

the disclosure requirements that are 

unique to oil and gas companies, the 

subpart, for the most part, codifies the 

substantive disclosure called for by 

Industry Guide 2. The disclosure 

requirements have been updated and 

clarified, and require the disclosure to 

be presented in a tabular format, where 

appropriate. 

Although many companies already 

present this information in tabular form, 

for companies that do not, this 

requirement could impose a burden on 

companies as they transition from a 

narrative to tabular disclosure format. 

We expect, however, that any increased 

preparation costs would be highest in 

the first year after adoption, but would 

decline in subsequent years as 

companies adjust to the new format. We 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2187 

think this burden is justified because 

tabular disclosure will increase 

comparability and facilitate 

understanding and analysis by 

investors. 

1. Probable and Possible Reserves 

Allowing disclosure of probable and 

possible reserves could create an 

increased risk of litigation because these 

categories of reserves estimates are less 

certain than proved reserves. Companies 

may choose not to disclose such 

reserves, in part, because of the risk of 

incurring litigation costs to defend their 

disclosures due to the increased 

uncertainty of these categories. 

Disclosure of probable and possible 

reserves may also result in revealing 

competitive information because it 

might reveal a company’s business 

strategy, such as the geographic location 

and nature of its exploration and 

discoveries. For example, if 

geographical detail can be inferred from 

estimates of unproved reserves, this 

might reveal information about the 

value of a company’s assets to 

competitors and could put the producer 

at a competitive disadvantage. We have 

reduced the level of geographical detail 

to reduce the burden on companies, 

while still providing sufficient 

information to investors regarding 

concentrations of risk, including 

political risk. 

We expect companies will incur costs 

in preparing the additional disclosures 

such as calculating and aggregating the 

reserve projections in a prescribed 

format. However, if probable and 

possible categories of reserves have 

different extraction cost structures and 

they are not disclosed separately from 

proved reserves, this could result in 

increased uncertainty in an investor’s 

assessment of a company’s prospects. 

Companies also expressed concern 

that mandatory disclosure of probable 

and possible reserves could expose 

them to increased litigation risk. We 

believe that making these disclosures 

voluntary mitigates these concerns. 

Companies unwilling to bear the added 

risk can simply opt not to provide this 

disclosure. 

2. Reserves Estimate Preparers and 

Reserves Auditors 

If a company chooses to use a third 

party to prepare or audit reserve 

estimates, it will incur costs to hire 

these outside consultants. The new 

rules and amendments do not require 

companies to hire such a person. If 

enough companies that currently do not 

use such consultants begin to hire them, 

we believe that industry wages could 

potentially increase due to increased 

demand for reserves calculating 

specialists unless that demand is 

compensated by an increase in the 

supply of such persons. If wages 

increased, then all companies, not just 

those employing third party consultants, 

would incur added costs. 

Large companies may be less likely to 

hire third parties because they tend to 

have staff to make reserves estimates. 

However, if such large companies chose 

to hire third-party consultants, third 

parties would expend significantly more 

effort on such projects than for smaller 

companies because larger companies 

have more properties to evaluate. Thus, 

we expect third-party fees, and the time 

required to conduct such projects, 

would scale upwards with the quantity 

of company reserves. 

Disclosure of unproved reserves 

without third-party certification may 

present a risk with respect to smaller oil 

and gas producers because smaller 

companies are likely to have less inhouse expertise and ability to accurately 

estimate such reserves than larger 

companies. However, we understand 

that the vast majority of smaller oil and 

gas companies already hire third parties 

to estimate their reserves or certify their 

estimates. 

3. Consistency With IASB 

Some commenters remarked that the 

International Accounting Standards 

Board is currently preparing a set of 

guidelines for oil and gas extractive 

activities, including definitions of oil 

and gas reserves, and recommended that 

the Commission align its regulations 

with those guidelines. We intend to 

monitor this initiative and work with 

the IASB, but our new rules may differ 

from the guidelines ultimately 

established by the International 

Accounting Standards Board. This 

could make it more difficult for 

investors to compare foreign and 

domestic companies. 

4. Change in Pricing Mechanism 

We do not anticipate significant costs 

with the change in pricing mechanisms 

for established reserves. Companies 

simply will apply a different price 

scenario to determine the economic 

producibility of reserves. It is possible 

that the use of a 12-month average price 

may reduce the cost of disclosure 

because it should reduce the volatility 

of reserves estimates and therefore 

reduce the need to make significant 

adjustments to those estimates on a 

yearly basis due to daily price swings. 

5. Disclosure of PUD Development 

The required disclosure of a 

company’s progress in developing PUDs 

will increase the cost of reporting. 

However, we believe that companies 

regularly track their progress in this 

arena. Until a company develops a 

property, it cannot begin to realize the 

cash flows from production and the 

actual sale of products. Thus, the 

development of reserves is of utmost 

importance to an oil and gas company’s 

business. 

6. Increased Geographic Disclosure 

The requirements to provide 

increased geographic disclosure of 

reserves and production, in certain 

circumstances, may increase the amount 

of disclosure that a company must 

present. However, because the threshold 

that we are adopting in the release is 

15% of the company’s total reserves, a 

company would be required to disclose, 

at most, reserves and production in six 

countries. Considering the relatively 

large proportion of reserves that must 

exist in a country before a company is 

required to provide country-level 

disclosure, we believe that such 

information is readily available to 

companies. As noted in the body of this 

release, we have attempted to draft this 

provision to minimize any competitive 

harm that such disclosure may cause a 

company. 

7. Harmonizing Foreign Private Issuer 

Disclosure 

The harmonization of foreign private 

issuer disclosure regarding oil and gas 

activities may increase the burden on 

foreign private issuers. However, it is 

our understanding that the large foreign 

private issuers already voluntarily 

provide disclosure comparable to the 

level required from domestic 

companies. Much of the added new 

disclosure relates to the day-to-day 

business and properties of these 

companies, including drilling activities, 

number of wells and acreage. This is 

information that is central to the 

activities of oil and gas companies, and 

therefore is readily known to these 

companies. We believe that applying 

Subpart 1200 to these companies could 

prompt more detailed disclosure 

regarding these activities, which would 

cause these companies to incur some 

cost. The provision permitting foreign 

private issuers to omit disclosures if 

prohibited from making those 

disclosures by their home jurisdiction 

could mitigate some of these costs. 


pwalker on PROD1PC71 with RULES2
2188 Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 

338 15 U.S.C. 77b(b). 

339 15 U.S.C. 78c(f). 

340 15 U.S.C. 78w(a)(2). 

341 5 U.S.C. 603. 

342See Release No. 33–8870 (Dec. 12, 2007) [72 

FR 71610]. 

XII. Consideration of Burden on 

Competition and Promotion of 

Efficiency, Competition, and Capital 

Formation 

Securities Act Section 2(b) 338 and 

Section 3(f) of the Exchange Act 339

require us, when engaging in 

rulemaking where we are required to 

consider or determine whether an action 

is necessary or appropriate in the public 

interest, to consider, in addition to the 

protection of investors, whether the 

action will promote efficiency, 

competition, and capital formation. 

Section 23(a)(2) of the Exchange Act 340

requires us, when adopting rules under 

the Exchange Act, to consider the 

impact that any new rule would have on 

competition. In addition, Section 

23(a)(2) prohibits us from adopting any 

rule that would impose a burden on 

competition not necessary or 

appropriate in furtherance of the 

purposes of the Exchange Act. 

We expect the new rules and 

amendments to increase efficiency and 

enhance capital formation, and thereby 

benefit investors, by providing the 

market with better information based on 

updated technology as well as increased 

information covering a broader range of 

reserves classifications held by a 

company and reserves found in nontraditional sources of oil and gas. Such 

increased and improved information 

should permit investors to better assess 

a company’s prospects. In particular, the 

existing prohibitions against disclosing 

reserves other than proved reserves, 

using modern technology to determine 

the certainty level of reserves, and 

including resources from nontraditional sources can lead to 

incomplete disclosures about a 

company’s actual resources and 

prospects. The new rules and 

amendments are designed to better align 

the disclosure requirements with the 

way companies make business 

decisions. 

We believe that permitting the 

disclosure of probable and possible 

reserves will benefit smaller companies, 

in particular. Larger issuers tend to 

already have large amounts of proved 

reserves. The new rules and 

amendments permit smaller companies, 

who often participate in a significant 

amount of exploratory activity, to better 

disclose their business prospects. 

Consequently, we anticipate that the 

new rules and amendments could lead 

to efficiencies in capital formation, as 

more information will be available 

regarding the prospects of smaller 

issuers. 

The effects of the new rules and 

amendments on competition are 

difficult to predict, but it is possible that 

permitting public issuers to disclose 

probable and possible reserves will lead 

to a reallocation of capital, as companies 

that previously could show few proved 

reserves will be able to disclose a 

broader range of its business prospects, 

making it easier for these issuers to raise 

capital and compete with companies 

that have large proved reserves. 

Although our new rules make disclosure 

of probable and possible reserves 

optional, and large oil and gas 

producers suggested in their comment 

letters that such disclosure would be of 

limited benefit because of the relative 

uncertainty associated with such 

reserves, we believe that competitive 

pressures within the industry might 

make it beneficial for large producers to 

disclose this information. Increased 

disclosure might, for example, improve 

credit quality and lower the cost of debt 

financing, or reduce the risk associated 

with business transactions between the 

company and its customers or suppliers. 

XIII. Final Regulatory Flexibility 

Analysis 

We have prepared this Final 

Regulatory Flexibility Analysis in 

accordance with Section 603 of the 

Regulatory Flexibility Act.341 This 

analysis relates to the modernization of 

the oil and gas disclosure requirements. 

An Initial Regulatory Flexibility 

Analysis (IRFA) was prepared in 

accordance with the Regulatory 

Flexibility Act in conjunction with the 

Proposing Release. The Proposing 

Release included, and solicited 

comment on, the IRFA. 

A. Reasons for, and Objectives of, the 

New Rules and Amendments 

The Commission adopted the current 

disclosure regime for oil and gas 

producing companies in 1978 and 1982, 

respectively. Since that time, there have 

been significant changes in the oil and 

gas industry and markets, including 

technological advances, and changes in 

the types of projects in which oil and 

gas companies invest their capital. On 

December 12, 2007, the Commission 

published a Concept Release on possible 

revisions to the disclosure requirements 

relating to oil and gas reserves.342 Prior 

to our issuance of the Concept Release, 

many industry participants had 

expressed concern that our disclosure 

rules are no longer in alignment with 

current industry practices and therefore 

have limited usefulness to the market 

and investors. 

Our new rules and amendments to 

these existing forms are intended to 

modernize and update our reserves 

definitions to reflect changes in the oil 

and gas industry and markets and new 

technologies that have occurred in the 

decades since the current rules were 

adopted, including expanding the scope 

of permissible technologies for 

establishing certainty levels of reserves, 

reserves classifications that a company 

can disclose in a Commission filing, and 

the types of resources that can be 

included in a company’s reserves, as 

well as providing information regarding 

the objectivity and qualifications of any 

third party primarily responsible for 

preparing or auditing the reserves 

estimates, if the company represents 

that it has enlisted a third party to 

conduct a reserves audit, and the 

qualifications and measures taken to 

assure the independence and objectivity 

of any employee primarily responsible 

for preparing or auditing the reserves 

estimates. The amendments also 

harmonize our full cost accounting rules 

with the changes that we are adopting 

with respect to disclosure of oil and gas 

reserves. The new rules and 

amendments also are intended to codify, 

modernize and centralize the disclosure 

items for oil and gas companies into 

Regulation S–K. Finally, the new rules 

and amendments are intended to 

harmonize oil and gas disclosures by 

foreign private issuers with disclosures 

by domestic companies. Overall, the 

new rules and amendments attempt to 

provide improved disclosure about an 

oil and gas company’s business and 

prospects without sacrificing clarity and 

comparability, which provide protection 

and transparency to investors. 

B. Significant Issues Raised by 

Commenters 

We did not receive comments 

specifically addressing the impact of the 

proposed rules and amendments on 

small entities. However, several of the 

comments related to burdens that would 

be placed on all companies affected by 

the proposals. In particular, commenters 

believed that the proposal to require the 

use of different prices for disclosure and 

accounting purposes would impose a 

significant burden on all oil and gas 

companies. We have considered those 

comments and are adopting 

amendments to our disclosure rules and 

the full cost accounting method that 

will require the use of a single price for 

both purposes. Similarly, commenters 

were concerned that certain aspects of 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2189 

343 17 CFR 230.157. 

344 17 CFR 240.0–10(a). 

the proposal, such as the new definition 

of geographic area and disclosure by 

accumulation type would increase the 

detail in the disclosures significantly. 

We agree with those commenters and 

have significantly reduced the level of 

detail required in the disclosure 

requirements. 

C. Small Entities Subject to the New 

Rules and Amendments 

The new rules and amendments affect 

small entities that are engaged in oil and 

gas producing activities, the securities 

of which are registered under Section 12 

of the Exchange Act or that are required 

to file reports under Section 15(d) of the 

Exchange Act. The new rules and 

amendments also would affect small 

entities that file, or have filed, a 

registration statement that has not yet 

become effective under the Securities 

Act and that has not been withdrawn. 

Securities Act Rule 157 343 and 

Exchange Act Rule 0–10(a) 344 define an 

issuer to be a ‘‘small business’’ or ‘‘small 

organization’’ for purposes of the 

Regulatory Flexibility Act if it had total 

assets of $5 million or less on the last 

day of its most recent fiscal year. The 

new rules and amendments affect small 

entities that are operating companies 

and engage in oil and gas producing 

activities. Based on filings in 2007, we 

estimate that there are approximately 28 

oil and gas companies that may be 

considered small entities. 

D. Reporting, Recordkeeping, and Other 

Compliance Requirements 

The new rules and amendments to 

Regulation S–K expand some existing 

disclosures, and eliminate others. In 

particular, the new disclosure 

requirements, many of which were 

requested by industry participants, 

include the following: 

• Disclosure of reserves from nontraditional sources (e.g., bitumen and 

shale) as oil and gas reserves; 

• Optional disclosure of probable and 

possible reserves; 

• Optional disclosure of oil and gas 

reserves’ sensitivity to price; 

• Disclosure of the development of 

proved undeveloped reserves, including 

those that are held for 5 years or more 

and an explanation of why they should 

continue to be considered proved; 

• Disclosure of technologies used to 

establish reserves in a company’s initial 

filing with the Commission and in 

filings which include material additions 

to reserves estimates; 

• Disclosure of the company’s 

internal controls over reserves estimates 

and the qualifications the technical 

person primarily responsible for 

overseeing the preparation or audit of 

the reserves estimates; 

• If a company represents that 

disclosure is based on the authority of 

a third party that prepared the reserves 

estimates or conducted a reserves audit 

or process review, filing a report 

prepared by the third party; and 

• Disclosure based on a new 

definition of the term ‘‘by geographic 

area.’’ 

There would be no mandatory 

retention period for the information 

disclosed, and the information disclosed 

would be made publicly available on 

the EDGAR filing system. 

E. Agency Action To Minimize Effect on 

Small Entities 

We considered different compliance 

standards for the small entities that will 

be affected by the new rules and 

amendments. In the Proposing Release, 

we solicited comment regarding the 

possibility of different standards for 

small entities. We did not receive 

comment on this particular issue. 

However, we believe that such 

differences would be inconsistent with 

the purposes of the rules. 

The new rules and amendments are 

designed to modernize the disclosure 

requirements for oil and gas companies. 

As such, we believe all oil and gas 

companies will benefit from the 

modernization of the rules. Under the 

new rules and amendments, all 

companies will be allowed to use 

modern technologies to establish 

reserves and include operations in 

unconventional resources in their oil 

and gas reserves estimates. Adopting 

differing standards for disclosure for 

small entities would significantly 

reduce the comparability between 

companies. However, the new rules and 

amendments do permit companies to 

disclose probable and possible reserves. 

We believe the removal of the 

prohibition against such reserves will 

enable companies to disclose a broader 

view of their prospects. We believe this 

will particularly benefit smaller oil and 

gas companies that may have significant 

unproved reserves in their portfolio. 

Such disclosure may assist smaller 

companies in raising capital for 

development projects in those 

properties. 

XIV. Update to Codification of 

Financial Reporting Policies 

The Commission amends the 

‘‘Codification of Financial Reporting 

Policies’’ announced in Financial 

Reporting Release No. 1 (April 15, 1982) 

[47 FR 21028] as follows: 

1. By removing the seven introductory 

paragraphs before Section 406.01, the 

last sentence of Section 406.01.c.vi., the 

first paragraph of Section 406.01.d, the 

introductory paragraph of Section 

406.02.d, and removing and reserving 

Sections 406.01.a., 406.02.a, 406.02.b., 

406.02.d.iii., and 406.02.e. 

2. By revising Section 406.01B to read 

as follows: 

The rules in Rule 4–10(b) specify that 

the application of successful efforts 

shall comply with SFAS 19. In 2008, the 

Commission published amendments to 

the definitions in Rule 4–10(a) that may 

not align completely with SFAS 19’s 

existing terminology and application. 

Further, paragraph 7 of SFAS 25 states: 

‘‘For purposes of applying this 

Statement and Statement 19, the 

definition of proved reserves, proved 

developed reserves, and proved 

undeveloped reserves shall be the 

definitions adopted by the SEC for its 

reporting purposes that are in effect on 

the date(s) as of which the reserve 

disclosures are to be made. Previous 

reported quantities shall not be revised 

retroactively if the SEC definitions are 

changed.’’ In any case, the Commission 

expects the practical application of 

SFAS 19 will remain unchanged other 

than incorporating the effects of the new 

definitions. 

3. By removing the first three 

sentences of Section 406.02.c. and in the 

fourth sentence replacing the phrase 

‘‘this sort of information’’ with 

‘‘information to assess the impact of oil 

and gas producing activities on near 

term cash flows and liquidity’’. 

4. By adding a new Section 406.03 

entitled ‘‘Transition’’ and including the 

text of the 3rd paragraph of Section 

VII.B and the last sentence of the 2nd 

paragraph of Section VII.C of this 

release. 

5. By adding a new Section 406.04 

entitled ‘‘MD&A Guidance’’ and 

including the text beginning with the 

last sentence of the 2nd paragraph of 

Section V of this release through the end 

of that Section. 

The Codification is a separate 

publication of the Commission. It will 

not be published in the Federal Register 

or Code of Federal Regulations. For 

more information on the Codification of 

Financial Reporting Policies, contact the 

Commission’s Public Reference Room at 

202–551–5850. 

XV. Statutory Basis and Text of 

Amendments 

We are adopting the amendments 

pursuant to Sections 3(b), 6, 7, 10 and 

19(a) of the Securities Act and Sections 

12, 13, 14(a), 15(d), and 23(a) of the 

Exchange Act, as amended. 


pwalker on PROD1PC71 with RULES2
2190 Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 

Text of Amendments 

List of Subjects 

17 CFR Part 210 

Accountants, Accounting, Reporting 

and recordkeeping requirements, 

Securities. 

17 CFR Parts 211, 229 and 249 

Reporting and recordkeeping 

requirements, Securities. 

■ For the reasons set out in the 

preamble, title 17, chapter II of the Code 

of Federal Regulations is amended as 

follows: 

PART 210—FORM AND CONTENT OF 

AND REQUIREMENTS FOR FINANCIAL 

STATEMENTS, SECURITIES ACT OF 

1933, SECURITIES EXCHANGE ACT 

OF 1934, PUBLIC UTILITY HOLDING 

COMPANY ACT OF 1935, INVESTMENT 

COMPANY ACT OF 1940, INVESTMENT 

ADVISERS ACT OF 1940, AND 

ENERGY POLICY AND 

CONSERVATION ACT OF 1975 

■ 1. The authority citation for part 210 

continues to read as follows: 

Authority: 15 U.S.C. 77f, 77g, 77h, 77j, 77s, 

77z–2, 77z–3, 77aa(25), 77aa(26), 78c, 78j–1, 

78l, 78m, 78n, 78o(d), 78q, 78u–5, 78w(a), 

78ll, 78mm, 80a–8, 80a–20, 80a–29, 80a–30, 

80a–31, 80a–37(a), 80b–3, 80b–11, 7202 and 

7262, unless otherwise noted. 

■ 2. Amend § 210.4–10 by: 

■ a. Redesignating the subparagraphs in 

paragraph (a) as follows: 

Old paragraph number New paragraph number 

(a)(1) ......................... (a)(16) 

(a)(2) ......................... (a)(22) 

(a)(5) ......................... (a)(23) 

(a)(6) ......................... (a)(32) 

(a)(7) ......................... (a)(21) 

(a)(8) ......................... (a)(15) 

(a)(9) ......................... (a)(27) 

(a)(10) ....................... (a)(13) 

(a)(11) ....................... (a)(9) 

(a)(12) ....................... (a)(29) 

(a)(13) ....................... (a)(30) 

(a)(14) ....................... (a)(1) 

(a)(15) ....................... (a)(12) 

(a)(16) ....................... (a)(7) 

(a)(17) ....................... (a)(20) 

■ b. Removing paragraphs (a)(3) and 

(a)(4); 

■ c. Adding new paragraphs (a)(2), 

(a)(3), (a)(4), (a)(5), (a)(6), (a)(8), (a)(10), 

(a)(11), (a)(14), (a)(17), (a)(18), (a)(19), 

(a)(24), (a)(25), (a)(26), (a)(28), (a)(31), 

and (c)(8); 

■ d. Revising newly redesignated 

paragraphs (a)(13), (a)(16), (a)(22), and 

(a)(30); and 

■ e. Removing the authority citations 

following the section. 

The additions and revisions read as 

follows: 

§ 210.4–10 Financial accounting and 

reporting for oil and gas producing 

activities pursuant to the Federal securities 

laws and the Energy Policy and 

Conservation Act of 1975. 

* * * * * 

(a) Definitions. * * * 

* * * * * 

(2) Analogous reservoir. Analogous 

reservoirs, as used in resources 

assessments, have similar rock and fluid 

properties, reservoir conditions (depth, 

temperature, and pressure) and drive 

mechanisms, but are typically at a more 

advanced stage of development than the 

reservoir of interest and thus may 

provide concepts to assist in the 

interpretation of more limited data and 

estimation of recovery. When used to 

support proved reserves, an ‘‘analogous 

reservoir’’ refers to a reservoir that 

shares the following characteristics with 

the reservoir of interest: 

(i) Same geological formation (but not 

necessarily in pressure communication 

with the reservoir of interest); 

(ii) Same environment of deposition; 

(iii) Similar geological structure; and 

(iv) Same drive mechanism. 

Instruction to paragraph (a)(2): 

Reservoir properties must, in the 

aggregate, be no more favorable in the 

analog than in the reservoir of interest. 

(3) Bitumen. Bitumen, sometimes 

referred to as natural bitumen, is 

petroleum in a solid or semi-solid state 

in natural deposits with a viscosity 

greater than 10,000 centipoise measured 

at original temperature in the deposit 

and atmospheric pressure, on a gas free 

basis. In its natural state it usually 

contains sulfur, metals, and other nonhydrocarbons. 

(4) Condensate. Condensate is a 

mixture of hydrocarbons that exists in 

the gaseous phase at original reservoir 

temperature and pressure, but that, 

when produced, is in the liquid phase 

at surface pressure and temperature. 

(5) Deterministic estimate. The 

method of estimating reserves or 

resources is called deterministic when a 

single value for each parameter (from 

the geoscience, engineering, or 

economic data) in the reserves 

calculation is used in the reserves 

estimation procedure. 

(6) Developed oil and gas reserves. 

Developed oil and gas reserves are 

reserves of any category that can be 

expected to be recovered: 

(i) Through existing wells with 

existing equipment and operating 

methods or in which the cost of the 

required equipment is relatively minor 

compared to the cost of a new well; and 

(ii) Through installed extraction 

equipment and infrastructure 

operational at the time of the reserves 

estimate if the extraction is by means 

not involving a well. 

* * * * * 

(8) Development project. A 

development project is the means by 

which petroleum resources are brought 

to the status of economically 

producible. As examples, the 

development of a single reservoir or 

field, an incremental development in a 

producing field, or the integrated 

development of a group of several fields 

and associated facilities with a common 

ownership may constitute a 

development project. 

* * * * * 

(10) Economically producible. The 

term economically producible, as it 

relates to a resource, means a resource 

which generates revenue that exceeds, 

or is reasonably expected to exceed, the 

costs of the operation. The value of the 

products that generate revenue shall be 

determined at the terminal point of oil 

and gas producing activities as defined 

in paragraph (a)(16) of this section. 

(11) Estimated ultimate recovery 

(EUR). Estimated ultimate recovery is 

the sum of reserves remaining as of a 

given date and cumulative production 

as of that date. 

* * * * * 

(13) Exploratory well. An exploratory 

well is a well drilled to find a new field 

or to find a new reservoir in a field 

previously found to be productive of oil 

or gas in another reservoir. Generally, an 

exploratory well is any well that is not 

a development well, an extension well, 

a service well, or a stratigraphic test 

well as those items are defined in this 

section. 

(14) Extension well. An extension 

well is a well drilled to extend the 

limits of a known reservoir. 

* * * * * 

(16) Oil and gas producing activities. 

(i) Oil and gas producing activities 

include: 

(A) The search for crude oil, including 

condensate and natural gas liquids, or 

natural gas (‘‘oil and gas’’) in their 

natural states and original locations; 

(B) The acquisition of property rights 

or properties for the purpose of further 

exploration or for the purpose of 

removing the oil or gas from such 

properties; 

(C) The construction, drilling, and 

production activities necessary to 

retrieve oil and gas from their natural 

reservoirs, including the acquisition, 

construction, installation, and 

maintenance of field gathering and 

storage systems, such as: 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2191 

(1) Lifting the oil and gas to the 

surface; and 

(2) Gathering, treating, and field 

processing (as in the case of processing 

gas to extract liquid hydrocarbons); and 

(D) Extraction of saleable 

hydrocarbons, in the solid, liquid, or 

gaseous state, from oil sands, shale, 

coalbeds, or other nonrenewable natural 

resources which are intended to be 

upgraded into synthetic oil or gas, and 

activities undertaken with a view to 

such extraction. 

Instruction 1 to paragraph (a)(16)(i): 

The oil and gas production function 

shall be regarded as ending at a 

‘‘terminal point’’, which is the outlet 

valve on the lease or field storage tank. 

If unusual physical or operational 

circumstances exist, it may be 

appropriate to regard the terminal point 

for the production function as: 

a. The first point at which oil, gas, or 

gas liquids, natural or synthetic, are 

delivered to a main pipeline, a common 

carrier, a refinery, or a marine terminal; 

and 

b. In the case of natural resources that 

are intended to be upgraded into 

synthetic oil or gas, if those natural 

resources are delivered to a purchaser 

prior to upgrading, the first point at 

which the natural resources are 

delivered to a main pipeline, a common 

carrier, a refinery, a marine terminal, or 

a facility which upgrades such natural 

resources into synthetic oil or gas. 

Instruction 2 to paragraph (a)(16)(i): 

For purposes of this paragraph (a)(16), 

the term saleable hydrocarbons means 

hydrocarbons that are saleable in the 

state in which the hydrocarbons are 

delivered. 

(ii) Oil and gas producing activities do 

not include: 

(A) Transporting, refining, or 

marketing oil and gas; 

(B) Processing of produced oil, gas or 

natural resources that can be upgraded 

into synthetic oil or gas by a registrant 

that does not have the legal right to 

produce or a revenue interest in such 

production; 

(C) Activities relating to the 

production of natural resources other 

than oil, gas, or natural resources from 

which synthetic oil and gas can be 

extracted; or 

(D) Production of geothermal steam. 

(17) Possible reserves. Possible 

reserves are those additional reserves 

that are less certain to be recovered than 

probable reserves. 

(i) When deterministic methods are 

used, the total quantities ultimately 

recovered from a project have a low 

probability of exceeding proved plus 

probable plus possible reserves. When 

probabilistic methods are used, there 

should be at least a 10% probability that 

the total quantities ultimately recovered 

will equal or exceed the proved plus 

probable plus possible reserves 

estimates. 

(ii) Possible reserves may be assigned 

to areas of a reservoir adjacent to 

probable reserves where data control 

and interpretations of available data are 

progressively less certain. Frequently, 

this will be in areas where geoscience 

and engineering data are unable to 

define clearly the area and vertical 

limits of commercial production from 

the reservoir by a defined project. 

(iii) Possible reserves also include 

incremental quantities associated with a 

greater percentage recovery of the 

hydrocarbons in place than the recovery 

quantities assumed for probable 

reserves. 

(iv) The proved plus probable and 

proved plus probable plus possible 

reserves estimates must be based on 

reasonable alternative technical and 

commercial interpretations within the 

reservoir or subject project that are 

clearly documented, including 

comparisons to results in successful 

similar projects. 

(v) Possible reserves may be assigned 

where geoscience and engineering data 

identify directly adjacent portions of a 

reservoir within the same accumulation 

that may be separated from proved areas 

by faults with displacement less than 

formation thickness or other geological 

discontinuities and that have not been 

penetrated by a wellbore, and the 

registrant believes that such adjacent 

portions are in communication with the 

known (proved) reservoir. Possible 

reserves may be assigned to areas that 

are structurally higher or lower than the 

proved area if these areas are in 

communication with the proved 

reservoir. 

(vi) Pursuant to paragraph (a)(22)(iii) 

of this section, where direct observation 

has defined a highest known oil (HKO) 

elevation and the potential exists for an 

associated gas cap, proved oil reserves 

should be assigned in the structurally 

higher portions of the reservoir above 

the HKO only if the higher contact can 

be established with reasonable certainty 

through reliable technology. Portions of 

the reservoir that do not meet this 

reasonable certainty criterion may be 

assigned as probable and possible oil or 

gas based on reservoir fluid properties 

and pressure gradient interpretations. 

(18) Probable reserves. Probable 

reserves are those additional reserves 

that are less certain to be recovered than 

proved reserves but which, together 

with proved reserves, are as likely as not 

to be recovered. 

(i) When deterministic methods are 

used, it is as likely as not that actual 

remaining quantities recovered will 

exceed the sum of estimated proved 

plus probable reserves. When 

probabilistic methods are used, there 

should be at least a 50% probability that 

the actual quantities recovered will 

equal or exceed the proved plus 

probable reserves estimates. 

(ii) Probable reserves may be assigned 

to areas of a reservoir adjacent to proved 

reserves where data control or 

interpretations of available data are less 

certain, even if the interpreted reservoir 

continuity of structure or productivity 

does not meet the reasonable certainty 

criterion. Probable reserves may be 

assigned to areas that are structurally 

higher than the proved area if these 

areas are in communication with the 

proved reservoir. 

(iii) Probable reserves estimates also 

include potential incremental quantities 

associated with a greater percentage 

recovery of the hydrocarbons in place 

than assumed for proved reserves. 

(iv) See also guidelines in paragraphs 

(a)(17)(iv) and (a)(17)(vi) of this section. 

(19) Probabilistic estimate. The 

method of estimation of reserves or 

resources is called probabilistic when 

the full range of values that could 

reasonably occur for each unknown 

parameter (from the geoscience and 

engineering data) is used to generate a 

full range of possible outcomes and 

their associated probabilities of 

occurrence. 

* * * * * 

(22) Proved oil and gas reserves. 

Proved oil and gas reserves are those 

quantities of oil and gas, which, by 

analysis of geoscience and engineering 

data, can be estimated with reasonable 

certainty to be economically 

producible—from a given date forward, 

from known reservoirs, and under 

existing economic conditions, operating 

methods, and government regulations— 

prior to the time at which contracts 

providing the right to operate expire, 

unless evidence indicates that renewal 

is reasonably certain, regardless of 

whether deterministic or probabilistic 

methods are used for the estimation. 

The project to extract the hydrocarbons 

must have commenced or the operator 

must be reasonably certain that it will 

commence the project within a 

reasonable time. 

(i) The area of the reservoir 

considered as proved includes: 

(A) The area identified by drilling and 

limited by fluid contacts, if any, and 

(B) Adjacent undrilled portions of the 

reservoir that can, with reasonable 

certainty, be judged to be continuous 


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with it and to contain economically 

producible oil or gas on the basis of 

available geoscience and engineering 

data. 

(ii) In the absence of data on fluid 

contacts, proved quantities in a 

reservoir are limited by the lowest 

known hydrocarbons (LKH) as seen in a 

well penetration unless geoscience, 

engineering, or performance data and 

reliable technology establishes a lower 

contact with reasonable certainty. 

(iii) Where direct observation from 

well penetrations has defined a highest 

known oil (HKO) elevation and the 

potential exists for an associated gas 

cap, proved oil reserves may be assigned 

in the structurally higher portions of the 

reservoir only if geoscience, 

engineering, or performance data and 

reliable technology establish the higher 

contact with reasonable certainty. 

(iv) Reserves which can be produced 

economically through application of 

improved recovery techniques 

(including, but not limited to, fluid 

injection) are included in the proved 

classification when: 

(A) Successful testing by a pilot 

project in an area of the reservoir with 

properties no more favorable than in the 

reservoir as a whole, the operation of an 

installed program in the reservoir or an 

analogous reservoir, or other evidence 

using reliable technology establishes the 

reasonable certainty of the engineering 

analysis on which the project or 

program was based; and 

(B) The project has been approved for 

development by all necessary parties 

and entities, including governmental 

entities. 

(v) Existing economic conditions 

include prices and costs at which 

economic producibility from a reservoir 

is to be determined. The price shall be 

the average price during the 12-month 

period prior to the ending date of the 

period covered by the report, 

determined as an unweighted arithmetic 

average of the first-day-of-the-month 

price for each month within such 

period, unless prices are defined by 

contractual arrangements, excluding 

escalations based upon future 

conditions. 

* * * * * 

(24) Reasonable certainty. If 

deterministic methods are used, 

reasonable certainty means a high 

degree of confidence that the quantities 

will be recovered. If probabilistic 

methods are used, there should be at 

least a 90% probability that the 

quantities actually recovered will equal 

or exceed the estimate. A high degree of 

confidence exists if the quantity is much 

more likely to be achieved than not, 

and, as changes due to increased 

availability of geoscience (geological, 

geophysical, and geochemical), 

engineering, and economic data are 

made to estimated ultimate recovery 

(EUR) with time, reasonably certain 

EUR is much more likely to increase or 

remain constant than to decrease. 

(25) Reliable technology. Reliable 

technology is a grouping of one or more 

technologies (including computational 

methods) that has been field tested and 

has been demonstrated to provide 

reasonably certain results with 

consistency and repeatability in the 

formation being evaluated or in an 

analogous formation. 

(26) Reserves. Reserves are estimated 

remaining quantities of oil and gas and 

related substances anticipated to be 

economically producible, as of a given 

date, by application of development 

projects to known accumulations. In 

addition, there must exist, or there must 

be a reasonable expectation that there 

will exist, the legal right to produce or 

a revenue interest in the production, 

installed means of delivering oil and gas 

or related substances to market, and all 

permits and financing required to 

implement the project. 

Note to paragraph (a)(26): Reserves 

should not be assigned to adjacent 

reservoirs isolated by major, potentially 

sealing, faults until those reservoirs are 

penetrated and evaluated as 

economically producible. Reserves 

should not be assigned to areas that are 

clearly separated from a known 

accumulation by a non-productive 

reservoir (i.e., absence of reservoir, 

structurally low reservoir, or negative 

test results). Such areas may contain 

prospective resources (i.e., potentially 

recoverable resources from 

undiscovered accumulations). 

* * * * * 

(28) Resources. Resources are 

quantities of oil and gas estimated to 

exist in naturally occurring 

accumulations. A portion of the 

resources may be estimated to be 

recoverable, and another portion may be 

considered to be unrecoverable. 

Resources include both discovered and 

undiscovered accumulations. 

* * * * * 

(30) Stratigraphic test well. A 

stratigraphic test well is a drilling effort, 

geologically directed, to obtain 

information pertaining to a specific 

geologic condition. Such wells 

customarily are drilled without the 

intent of being completed for 

hydrocarbon production. The 

classification also includes tests 

identified as core tests and all types of 

expendable holes related to 

hydrocarbon exploration. Stratigraphic 

tests are classified as ‘‘exploratory type’’ 

if not drilled in a known area or 

‘‘development type’’ if drilled in a 

known area. 

(31) Undeveloped oil and gas 

reserves. Undeveloped oil and gas 

reserves are reserves of any category that 

are expected to be recovered from new 

wells on undrilled acreage, or from 

existing wells where a relatively major 

expenditure is required for 

recompletion. 

(i) Reserves on undrilled acreage shall 

be limited to those directly offsetting 

development spacing areas that are 

reasonably certain of production when 

drilled, unless evidence using reliable 

technology exists that establishes 

reasonable certainty of economic 

producibility at greater distances. 

(ii) Undrilled locations can be 

classified as having undeveloped 

reserves only if a development plan has 

been adopted indicating that they are 

scheduled to be drilled within five 

years, unless the specific circumstances, 

justify a longer time. 

(iii) Under no circumstances shall 

estimates for undeveloped reserves be 

attributable to any acreage for which an 

application of fluid injection or other 

improved recovery technique is 

contemplated, unless such techniques 

have been proved effective by actual 

projects in the same reservoir or an 

analogous reservoir, as defined in 

paragraph (a)(2) of this section, or by 

other evidence using reliable technology 

establishing reasonable certainty. 

* * * * * 

(c) * * * 

(8) For purposes of this paragraph (c), 

the term ‘‘current price’’ shall mean the 

average price during the 12-month 

period prior to the ending date of the 

period covered by the report, 

determined as an unweighted arithmetic 

average of the first-day-of-the-month 

price for each month within such 

period, unless prices are defined by 

contractual arrangements, excluding 

escalations based upon future 

conditions. 

* * * * * 

PART 211—INTERPRETATIONS 

RELATING TO FINANCIAL REPORTING 

MATTERS 

■ 3. Amend Part 211, subpart A, by 

adding ‘‘Modernization of Oil and Gas 

Reporting,’’ Release No. FR–78 and the 

release date of December 31, 2008, to 

the list of interpretive releases. 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2193 

PART 229—STANDARD 

INSTRUCTIONS FOR FILING FORMS 

UNDER SECURITIES ACT OF 1933, 

SECURITIES EXCHANGE ACT OF 1934 

AND ENERGY POLICY AND 

CONSERVATION ACT OF 1975— 

REGULATION S–K 

■ 4. The authority citation for part 229 

continues to read in part as follows: 

Authority: 15 U.S.C. 77e, 77f, 77g, 77h, 77j, 

77k, 77s, 77z–2, 77z–3, 77aa(25), 77aa(26), 

77ddd, 77eee, 77ggg, 77hhh, 77iii, 77jjj, 

77nnn, 77sss, 78c, 78i, 78j, 78l, 78m, 78n, 

78o, 78u–5, 78w, 78ll, 78mm, 80a–8, 80a–9, 

80a–20, 80a–29, 80a–30, 80a–31(c), 80a–37, 

80a–38(a), 80a–39, 80b–11, and 7201 et seq.; 

and 18 U.S.C. 1350, unless otherwise noted. 

* * * * * 

■ 5. Amend § 229.102 by revising the 

introductory text of Instruction 3 and 

Instructions 4, 5 and 8 to read as 

follows. 

§ 229.102 (Item 102) Description of 

property. 

* * * * * 

Instructions to Item 102: * * * 

3. In the case of an extractive 

enterprise, not involved in oil and gas 

producing activities, material 

information shall be given as to 

production, reserves, locations, 

development, and the nature of the 

registrant’s interest. If individual 

properties are of major significance to 

an industry segment: 

* * * * * 

4. A registrant engaged in oil and gas 

producing activities shall provide the 

information required by Subpart 1200 of 

Regulation S–K. 

5. In the case of extractive reserves 

other than oil and gas reserves, 

estimates other than proven or probable 

reserves (and any estimated values of 

such reserves) shall not be disclosed in 

any document publicly filed with the 

Commission, unless such information is 

required to be disclosed in the 

document by foreign or state law; 

provided, however, that where such 

estimates previously have been 

provided to a person (or any of its 

affiliates) that is offering to acquire, 

merge, or consolidate with the 

registrant, or otherwise to acquire the 

registrant’s securities, such estimates 

may be included in documents relating 

to such acquisition. 

* * * * * 

8. The attention of certain issuers 

engaged in oil and gas producing 

activities is directed to the information 

called for in Securities Act Industry 

Guide 4 (referred to in § 229.801(d)). 

* * * * * 

■ 6. Amend § 229.801 by removing and 

reserving paragraph (b) and removing 

the authority citation following the 

section. 

■ 7. Amend § 229.802 by removing and 

reserving paragraph (b) and removing 

the authority citation following the 

section. 

■ 8. Add Subpart 229.1200 to read as 

follows: 

Subpart 229.1200—Disclosure by 

Registrants Engaged in Oil and Gas 

Producing Activities 

Sec. 

229.1201 (Item 1201) General instructions 

to oil and gas industry-specific 

disclosures. 

229.1202 (Item 1202) Disclosure of reserves. 

229.1203 (Item 1203) Proved undeveloped 

reserves. 

229.1204 (Item 1204) Oil and gas 

production, production prices and 

production costs. 

229.1205 (Item 1205) Drilling and other 

exploratory and development activities. 

229.1206 (Item 1206) Present activities. 

229.1207 (Item 1207) Delivery 

commitments. 

229.1208 (Item 1208) Oil and gas 

properties, wells, operations, and 

acreage. 

Subpart 229.1200—Disclosure by 

Registrants Engaged in Oil and Gas 

Producing Activities 

§ 229.1201 (Item 1201) General 

instructions to oil and gas industry-specific 

disclosures. 

(a) If oil and gas producing activities 

are material to the registrant’s or its 

subsidiaries’ business operations or 

financial position, the disclosure 

specified in this Subpart 229.1200 

should be included under appropriate 

captions (with cross references, where 

applicable, to related information 

disclosed in financial statements). 

However, limited partnerships and joint 

ventures that conduct, operate, manage, 

or report upon oil and gas drilling or 

income programs, that acquire 

properties either for drilling and 

production, or for production of oil, gas, 

or geothermal steam or water, need not 

include such disclosure. 

(b) To the extent that Items 1202 

through 1208 (§§ 229.1202–229.1208) 

call for disclosures in tabular format, as 

specified in the particular Item, a 

registrant may modify such format for 

ease of presentation, to add information 

or to combine two or more required 

tables. 

(c) The definitions in Rule 4–10(a) of 

Regulation S–X (17 CFR 210.4–10(a)) 

shall apply for purposes of this Subpart 

229.1200. 

(d) For purposes of this Subpart 

229.1200, the term by geographic area 

means, as appropriate for meaningful 

disclosure in the circumstances: 

(1) By individual country; 

(2) By groups of countries within a 

continent; or 

(3) By continent. 

§ 229.1202 (Item 1202) Disclosure of 

reserves. 

(a) Summary of oil and gas reserves at 

fiscal year end. (1) Provide the 

information specified in paragraph (a)(2) 

of this Item in tabular format as 

provided below: 

SUMMARY OF OIL AND GAS RESERVES AS OF FISCAL-YEAR END BASED ON AVERAGE FISCAL-YEAR PRICES

Reserves 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 B ........................................................ .................... .................... .................... .................... ....................

Undeveloped: ........................................................................................... .................... .................... .................... .................... ....................

Continent A ....................................................................................... .................... .................... .................... .................... ....................

Continent B ....................................................................................... .................... .................... .................... .................... ....................


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SUMMARY OF OIL AND GAS RESERVES AS OF FISCAL-YEAR END BASED ON AVERAGE FISCAL-YEAR PRICES—Continued 

Reserves category 

Reserves 

Oil 

(mbbls) 

Natural gas 

(mmcf) 

Synthetic oil 

(mbbls) 

Synthetic 

gas 

(mmcf) 

Product A 

(measure) 

Country A .......................................................................................... .................... .................... .................... .................... ....................

Country B .......................................................................................... .................... .................... .................... .................... ....................

Other Countries in Continent B ........................................................ .................... .................... .................... .................... ....................

TOTAL PROVED ....................................................................... .................... .................... .................... .................... ....................

PROBABLE .............................................................................................. .................... .................... .................... .................... ....................

Developed ......................................................................................... .................... .................... .................... .................... ....................

Undeveloped ..................................................................................... .................... .................... .................... .................... ....................

POSSIBLE ............................................................................................... .................... .................... .................... .................... ....................

Developed ......................................................................................... .................... .................... .................... .................... ....................

Undeveloped ..................................................................................... .................... .................... .................... .................... ....................

(2) Disclose, in the aggregate and by 

geographic area and for each country 

containing 15% or more of the 

registrant’s proved reserves, expressed 

on an oil-equivalent-barrels basis, 

reserves estimated using prices and 

costs under existing economic 

conditions, for the product types listed 

in paragraph (a)(4) of this Item, in the 

following categories: 

(i) Proved developed reserves; 

(ii) Proved undeveloped reserves; 

(iii) Total proved reserves; 

(iv) Probable developed reserves 

(optional); 

(v) Probable undeveloped reserves 

(optional); 

(vi) Possible developed reserves 

(optional); and 

(vii) Possible undeveloped reserves 

(optional). 

Instruction 1 to paragraph (a)(2): 

Disclose updated reserves tables as of 

the close of each fiscal year. 

Instruction 2 to paragraph (a)(2): The 

registrant is permitted, but not required, 

to disclose probable or possible reserves 

pursuant to paragraphs (a)(2)(iv) 

through (a)(2)(vii) of this Item. 

Instruction 3 to paragraph (a)(2): If 

the registrant discloses amounts of a 

product in barrels of oil equivalent, 

disclose the basis for such equivalency. 

Instruction 4 to paragraph (a)(2): A 

registrant need not provide disclosure of 

the reserves in a country containing 

15% or more of the registrant’s proved 

reserves if that country’s government 

prohibits disclosure of reserves in that 

country. In addition, a registrant need 

not provide disclosure of the reserves in 

a country containing 15% or more of the 

registrant’s proved reserves if that 

country’s government prohibits 

disclosure in a particular field and 

disclosure of reserves in that country 

would have the effect of disclosing 

reserves in particular fields. 

(3) Reported total reserves shall be 

simple arithmetic sums of all estimates 

for individual properties or fields 

within each reserves category. When 

probabilistic methods are used, reserves 

should not be aggregated 

probabilistically beyond the field or 

property level; instead, they should be 

aggregated by simple arithmetic 

summation. 

(4) Disclose separately material 

reserves of the following product types: 

(i) Oil; 

(ii) Natural gas; 

(iii) Synthetic oil; 

(iv) Synthetic gas; and 

(v) Sales products of other nonrenewable natural resources that are 

intended to be upgraded into synthetic 

oil and gas. 

(5) If the registrant discloses probable 

or possible reserves, discuss the 

uncertainty related to such reserves 

estimates. 

(6) If the registrant has not previously 

disclosed reserves estimates in a filing 

with the Commission or is disclosing 

material additions to its reserves 

estimates, the registrant shall provide a 

general discussion of the technologies 

used to establish the appropriate level of 

certainty for reserves estimates from 

material properties included in the total 

reserves disclosed. The particular 

properties do not need to be identified. 

(7) Preparation of reserves estimates 

or reserves audit. Disclose and describe 

the internal controls the registrant uses 

in its reserves estimation effort. In 

addition, disclose the qualifications of 

the technical person primarily 

responsible for overseeing the 

preparation of the reserves estimates 

and, if the registrant represents that a 

third party conducted a reserves audit, 

disclose the qualifications of the 

technical person primarily responsible 

for overseeing such reserves audit. 

(8) Third party reports. If the 

registrant represents that a third party 

prepared, or conducted a reserves audit 

of, the registrant’s reserves estimates, or 

any estimated valuation thereof, or 

conducted a process review, the 

registrant shall file a report of the third 

party as an exhibit to the relevant 

registration statement or other 

Commission filing. If the report relates 

to the preparation of, or a reserves audit 

of, the registrant’s reserves estimates, it 

must include the following disclosure, if 

applicable to the type of filing: 

(i) The purpose for which the report 

was prepared and for whom it was 

prepared; 

(ii) The effective date of the report 

and the date on which the report was 

completed; 

(iii) The proportion of the registrant’s 

total reserves covered by the report and 

the geographic area in which the 

covered reserves are located; 

(iv) The assumptions, data, methods, 

and procedures used, including the 

percentage of the registrant’s total 

reserves reviewed in connection with 

the preparation of the report, and a 

statement that such assumptions, data, 

methods, and procedures are 

appropriate for the purpose served by 

the report; 

(v) A discussion of primary economic 

assumptions; 

(vi) A discussion of the possible 

effects of regulation on the ability of the 

registrant to recover the estimated 

reserves; 

(vii) A discussion regarding the 

inherent uncertainties of reserves 

estimates; 

(viii) A statement that the third party 

has used all methods and procedures as 

it considered necessary under the 

circumstances to prepare the report; 

(ix) A brief summary of the third 

party’s conclusions with respect to the 

reserves estimates; and 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2195 

(x) The signature of the third party. 

(9) For purposes of this Item 1202, the 

term reserves audit means the process of 

reviewing certain of the pertinent facts 

interpreted and assumptions underlying 

a reserves estimate prepared by another 

party and the rendering of an opinion 

about the appropriateness of the 

methodologies employed, the adequacy 

and quality of the data relied upon, the 

depth and thoroughness of the reserves 

estimation process, the classification of 

reserves appropriate to the relevant 

definitions used, and the reasonableness 

of the estimated reserves quantities. 

(b) Reserves sensitivity analysis 

(optional). (1) The registrant may, but is 

not required to, provide the information 

specified in paragraph (b)(2) of this Item 

in tabular format as provided below: 

SENSITIVITY OF RESERVES TO PRICES BY PRINCIPAL PRODUCT TYPE AND PRICE SCENARIO

Price 

case 

Proved reserves Probable reserves Possible reserves 

Oil Gas Syn. oil Syn. 

gas Product A Oil Gas Syn. oil Syn. gas Product A Oil Gas Syn. oil Syn. gas Product A 

mbbls mmcf mbbls mmcf measure mbbls mmcf mbbls mmcf measure mbbls mmcf mbbls mmcf measure 

Scenario 

1.

Scenario 

2.

(2) The registrant may, but is not 

required to, disclose, in the aggregate, 

an estimate of reserves estimated for 

each product type based on different 

price and cost criteria, such as a range 

of prices and costs that may reasonably 

be achieved, including standardized 

futures prices or management’s own 

forecasts. 

(3) If the registrant provides 

disclosure under this paragraph (b), 

disclose the price and cost schedules 

and assumptions on which the 

disclosed values are based. 

Instruction to Item 1202: Estimates of 

oil or gas resources other than reserves, 

and any estimated values of such 

resources, shall not be disclosed in any 

document publicly filed with the 

Commission, unless such information is 

required to be disclosed in the 

document by foreign or state law; 

provided, however, that where such 

estimates previously have been 

provided to a person (or any of its 

affiliates) that is offering to acquire, 

merge, or consolidate with the registrant 

or otherwise to acquire the registrant’s 

securities, such estimate may be 

included in documents related to such 

acquisition. 

§ 229.1203 (Item 1203) Proved 

undeveloped reserves. 

(a) Disclose the total quantity of 

proved undeveloped reserves at year 

end. 

(b) Disclose material changes in 

proved undeveloped reserves that 

occurred during the year, including 

proved undeveloped reserves converted 

into proved developed reserves. 

(c) Discuss investments and progress 

made during the year to convert proved 

undeveloped reserves to proved 

developed reserves, including, but not 

limited to, capital expenditures. 

(d) Explain the reasons why material 

amounts of proved undeveloped 

reserves in individual fields or countries 

remain undeveloped for five years or 

more after disclosure as proved 

undeveloped reserves. 

§ 229.1204 (Item 1204) Oil and gas 

production, production prices and 

production costs. 

(a) For each of the last three fiscal 

years disclose production, by final 

product sold, of oil, gas, and other 

products. Disclosure shall be made by 

geographical area and for each country 

and field that contains 15% or more of 

the registrant’s total proved reserves 

expressed on an oil-equivalent-barrels 

basis unless prohibited by the country 

in which the reserves are located. 

(b) For each of the last three fiscal 

years disclose, by geographical area: 

(1) The average sales price (including 

transfers) per unit of oil, gas and other 

products produced; and 

(2) The average production cost, not 

including ad valorem and severance 

taxes, per unit of production. 

Instruction 1 to Item 1204: Generally, 

net production should include only 

production that is owned by the 

registrant and produced to its interest, 

less royalties and production due 

others. However, in special situations 

(e.g., foreign production) net production 

before any royalties may be provided, if 

more appropriate. If ‘‘net before royalty’’ 

production figures are furnished, the 

change from the usage of ‘‘net 

production’’ should be noted. 

Instruction 2 to Item 1204: Production 

of natural gas should include only 

marketable production of natural gas on 

an ‘‘as sold’’ basis. Production will 

include dry, residue, and wet gas, 

depending on whether liquids have 

been extracted before the registrant 

transfers title. Flared gas, injected gas, 

and gas consumed in operations should 

be omitted. Recovered gas-lift gas and 

reproduced gas should not be included 

until sold. Synthetic gas, when 

marketed as such, should be included in 

natural gas sales. 

Instruction 3 to Item 1204: If any 

product, such as bitumen, is sold or 

custody is transferred prior to 

conversion to synthetic oil or gas, the 

product’s production, transfer prices, 

and production costs should be 

disclosed separately from all other 

products. 

Instruction 4 to Item 1204: The 

transfer price of oil and gas (natural and 

synthetic) produced should be 

determined in accordance with SFAS 

69. 

Instruction 5 to Item 1204: The 

average production cost, not including 

ad valorem and severance taxes, per 

unit of production should be computed 

using production costs disclosed 

pursuant to SFAS 69. Units of 

production should be expressed in 

common units of production with oil, 

gas, and other products converted to a 

common unit of measure on the basis 

used in computing amortization. 

§ 229.1205 (Item 1205) Drilling and other 

exploratory and development activities. 

(a) For each of the last three fiscal 

years, by geographical area, disclose: 

(1) The number of net productive and 

dry exploratory wells drilled; and 

(2) The number of net productive and 

dry development wells drilled. 

(b) Definitions. For purposes of this 

Item 1205, the following terms shall be 

defined as follows: 

(1) A dry well is an exploratory, 

development, or extension well that 

proves to be incapable of producing 

either oil or gas in sufficient quantities 

to justify completion as an oil or gas 

well. 


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(2) A productive well is an 

exploratory, development, or extension 

well that is not a dry well. 

(3) Completion refers to installation of 

permanent equipment for production of 

oil or gas, or, in the case of a dry well, 

to reporting to the appropriate authority 

that the well has been abandoned. 

(4) The number of wells drilled refers 

to the number of wells completed at any 

time during the fiscal year, regardless of 

when drilling was initiated. 

(c) Disclose, by geographic area, for 

each of the last three years, any other 

exploratory or development activities 

conducted, including implementation of 

mining methods for purposes of oil and 

gas producing activities. 

§ 229.1206 (Item 1206) Present activities. 

(a) Disclose, by geographical area, the 

registrant’s present activities, such as 

the number of wells in the process of 

being drilled (including wells 

temporarily suspended), waterfloods in 

process of being installed, pressure 

maintenance operations, and any other 

related activities of material importance. 

(b) Provide the description of present 

activities as of a date at the end of the 

most recent fiscal year or as close to the 

date that the registrant files the 

document as reasonably possible. 

(c) Include only those wells in the 

process of being drilled at the ‘‘as of’’ 

date and express them in terms of both 

gross and net wells. 

(d) Do not include wells that the 

registrant plans to drill, but has not 

commenced drilling unless there are 

factors that make such information 

material. 

§ 229.1207 (Item 1207) Delivery 

commitments. 

(a) If the registrant is committed to 

provide a fixed and determinable 

quantity of oil or gas in the near future 

under existing contracts or agreements, 

disclose material information 

concerning the estimated availability of 

oil and gas from any principal sources, 

including the following: 

(1) The principal sources of oil and 

gas that the registrant will rely upon and 

the total amounts that the registrant 

expects to receive from each principal 

source and from all sources combined; 

(2) The total quantities of oil and gas 

that are subject to delivery 

commitments; and 

(3) The steps that the registrant has 

taken to ensure that available reserves 

and supplies are sufficient to meet such 

commitments for the next one to three 

years. 

(b) Disclose the information required 

by this Item: 

(1) In a form understandable to 

investors; and 

(2) Based upon the facts and 

circumstances of the particular 

situation, including, but not limited to: 

(i) Disclosure by geographic area; 

(ii) Significant supplies dedicated or 

contracted to the registrant; 

(iii) Any significant reserves or 

supplies subject to priorities or 

curtailments which may affect 

quantities delivered to certain classes of 

customers, such as customers receiving 

services under low priority and 

interruptible contracts; 

(iv) Any priority allocations or price 

limitations imposed by Federal or State 

regulatory agencies, as well as other 

factors beyond the registrant’s control 

that may affect the registrant’s ability to 

meet its contractual obligations (the 

registrant need not provide detailed 

discussions of price regulation); 

(v) Any other factors beyond the 

registrant’s control, such as other parties 

having control over drilling new wells, 

competition for the acquisition of 

reserves and supplies, and the 

availability of foreign reserves and 

supplies, which may affect the 

registrant’s ability to acquire additional 

reserves and supplies or to maintain or 

increase the availability of reserves and 

supplies; and 

(vi) Any impact on the registrant’s 

earnings and financing needs resulting 

from its inability to meet short-term or 

long-term contractual obligations. (See 

Items 303 and 1209 of Regulation S–K 

(§§ 229.303 and 229.1209).) 

(c) If the registrant has been unable to 

meet any significant delivery 

commitments in the last three years, 

describe the circumstances concerning 

such events and their impact on the 

registrant. 

(d) For purposes of this Item, 

available reserves are estimates of the 

amounts of oil and gas which the 

registrant can produce from current 

proved developed reserves using 

presently installed equipment under 

existing economic and operating 

conditions and an estimate of amounts 

that others can deliver to the registrant 

under long-term contracts or agreements 

on a per-day, per-month, or per-year 

basis. 

§ 229.1208 (Item 1208) Oil and gas 

properties, wells, operations, and acreage. 

(a) Disclose, as of a reasonably current 

date or as of the end of the fiscal year, 

the total gross and net productive wells, 

expressed separately for oil and gas 

(including synthetic oil and gas 

produced through wells) and the total 

gross and net developed acreage (i.e., 

acreage assignable to productive wells) 

by geographic area. 

(b) Disclose, as of a reasonably current 

date or as of the end of the fiscal year, 

the amount of undeveloped acreage, 

both leases and concessions, if any, 

expressed in both gross and net acres by 

geographic area, together with an 

indication of acreage concentrations, 

and, if material, the minimum 

remaining terms of leases and 

concessions. 

(c) Definitions. For purposes of this 

Item 1208, the following terms shall be 

defined as indicated: 

(1) A gross well or acre is a well or 

acre in which the registrant owns a 

working interest. The number of gross 

wells is the total number of wells in 

which the registrant owns a working 

interest. Count one or more completions 

in the same bore hole as one well. In a 

footnote, disclose the number of wells 

with multiple completions. If one of the 

multiple completions in a well is an oil 

completion, classify the well as an oil 

well. 

(2) A net well or acre is deemed to 

exist when the sum of fractional 

ownership working interests in gross 

wells or acres equals one. The number 

of net wells or acres is the sum of the 

fractional working interests owned in 

gross wells or acres expressed as whole 

numbers and fractions of whole 

numbers. 

(3) Productive wells include 

producing wells and wells mechanically 

capable of production. 

(4) Undeveloped acreage encompasses 

those leased acres on which wells have 

not been drilled or completed to a point 

that would permit the production of 

economic quantities of oil or gas 

regardless of whether such acreage 

contains proved reserves. Do not 

confuse undeveloped acreage with 

undrilled acreage held by production 

under the terms of the lease. 

PART 249—FORMS, SECURITIES 

EXCHANGE ACT OF 1934 

■ 9. The authority citation for part 249 

continues to read in part as follows: 

Authority: 15 U.S.C. 78a et seq. and 7201; 

and 18 U.S.C. 1350, unless otherwise noted. 

* * * * * 

■ 10. Amend Form 20–F (referenced in 

§ 249.220f) by: 

■ a. Revising ‘‘Instruction to Item 4’’ and 

the introductory text and paragraph (b) 

of ‘‘Instructions to Item 4.D’’; and 

■ b. Removing paragraph (c) of 

‘‘Instructions to Item 4.D’’ and 

‘‘Appendix A to Item 4.D—Oil and 

Gas.’’ 

The revisions read as follows: 

[Note: The text of Form 20–F does not, and 

this amendment will not, appear in the Code 

of Federal Regulations.] 


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Federal Register / Vol. 74, No. 9 / Wednesday, January 14, 2009 / Rules and Regulations 2197 

Form 20–F 

* * * * * 

Item 4. Information on the Company 

* * * * * 

Instructions to Item 4 

1. Furnish the information specified 

in any industry guide listed in Subpart 

229.800 of Regulation S–K (§ 229.801 et 

seq. of this chapter) that applies to you. 

2. If oil and gas operations are 

material to you or your subsidiaries’ 

business operations or financial 

position, provide the information 

specified in Subpart 1200 of Regulation 

S–K (§ 229.1200 et seq. of this chapter). 

* * * * * 

Instruction to Item 4.D: In the case of 

an extractive enterprise, other than an 

oil and gas producing activity: 

* * * * * 

(b) In documents that you file 

publicly with the Commission, do not 

disclose estimates of reserves unless the 

reserves are proven or probable and do 

not give estimated values of those 

reserves, unless foreign law requires you 

to disclose the information. If these 

types of estimates have already been 

provided to any person that is offering 

to acquire you, however, you may 

include the estimates in documents 

relating to the acquisition. 

* * * * * 

Dated: December 31, 2008. 

By the Commission. 

Florence E. Harmon, 

Acting Secretary. 

[FR Doc. E9–409 Filed 1–13–09; 8:45 am] 

BILLING CODE 8011–01–P 


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