In response to the Concept Release, commenters submitted 80 comment letters which addressed all or some of the 15 questions that were raised by the release.\11\ We received comment letters from a variety of industry participants such as accounting firms, consultants, domestic and foreign oil and gas companies, federal government agencies, individuals, law firms, professional associations, public interest groups, and rating agencies.
\11\ The public comments we received are available for inspection in the Commission's Public Reference Room at 100 F St. NE., Washington, DC 20549 in File No. S72907. They are also available online at http://www.sec.gov/comments/s72907/ s72907.shtml.
C. General Overview of the Comment Letters Received on Key Issues

Almost all commenters supported some form of revision to the current oil and gas disclosure requirements, particularly given the length of time that has elapsed since the requirements were initially adopted. Commenters diverged significantly, however, in their views about the extent and type of revisions that we should make to our disclosure system. For example, commenters expressed varied opinions regarding whether we should adopt revisions that would result in a principlesbased disclosure regime rather than a rulesbased disclosure regime. Those who favored a principlesbased approach noted that such an approach would be inherently more flexible than a rulesbased approach and would allow for greater adaptability as technological advancements and changes occur in the industry.\12\ Other commenters, however,
[[Page 39528]]
expressed concern that a principlesbased model is more subjective than a rulesbased approach and could result in less consistent and comparable disclosure in the filings made by oil and gas companies.\13\ \12\ See, for example, letters from BHP Biliton Petroleum (``BHP''), John R. Etherington (``J. Etherington''), and White & Case, LLP (``White & Case'').
\13\ See, for example, letters from Apache Corp. (``Apache''), Moody's Investor's Service (``Moody's) and Oil Change International and the Center for Corporate Policy (``Oil Change'').

Virtually all of the commenters supported a revision of the definition of proved reserves in some form or another. Most remarked that the definition of proved reserves should be broadened to allow unconventional resources such as oil shales and bitumen to be classified as proved reserves.\14\ In addition, while commenters were split on the use of a single fiscal yearend spot price to value the reserves held by an oil and gas company, a majority advocated the use of a different pricing standard to reduce the effects of shortterm price volatility.\15\
\14\ See letters from American Association of Petroleum Geologists (``AAPG''), American Clean Skies Foundation (``ACSF''), Apache, American Petroleum Institute (``API''), Center for Audit Quality (``Audit Quality''), BP Plc (``BP,'') Brookwood Petroleum Advisors Ltd. (``Brookwood''), CFA Institute Centre for Financial Market Integrity (``CFA''), Chesapeake Energy Corporation
(``Chesapeake''), China National Offshore Oil Corporation
(``CNOCC''), CIBC World Markets (``CIBC''), Denbury Resources (``Denbury''), Department of Energy (``DOE''), Deutsche Bank, Devon Energy Corporation (``Devon''), EnCana, Energy Information Administration (of DOE) (``EIA''), Energy Literacy Project (``Energy Literacy''), Eni S.p.A. (``Eni''), Ernst & Young (``E&Y''), J. Etherington, ExxonMobil, Grant Thornton, Imperial Oil Ltd. (``Imperial''), Independent Petroleum Association of America (``IPAA''), Dan Kelly (``D. Kelly''), McBride, DouglasMorningstar Consultants (``D. McBride''), Moody's, Nexen Inc. (``Nexen''), Oil Change, Dan Olds (``D. Olds''), Petrobras, PetroCanada,
PriceWaterhouseCoopers (``PWC''), Robert Pinkerton (``R.
Pinkerton''), Robinson Petroleum Consulting (``Robinson''), Ross Petroleum Ltd. (``Ross''), Derek Ryder (``D. Ryder''), Sasol Ltd (``Sasol''), Shell International (``Shell''), Society of Petroleum Engineers (``SPE''), Standard & Poor's (``S&P''), StatoilHydro, Total, S.A. (``Total''), Ashish Verma (``A. Verma''), Robert Wagner (``R. Wagner''), White & Case, and Fred Ziehe (``F. Ziehe''). \15\ See letters from Chesapeake, Devon, and Imperial.

There were mixed views on whether the Commission should permit disclosure of reserves other than proved reserves in Commission filings. Commenters supporting the inclusion of disclosures about probable and possible reserves in Commission filings suggested that such disclosure would allow investors to gain a more comprehensive understanding of the resources held by an oil and gas company.\16\ Commenters opposing disclosure of probable and possible reserves thought that disclosure about these reserves categories would be less reliable than disclosure about proved reserves. Many of these commenters were concerned about liability issues associated with such disclosure and the loss of comparability of disclosure between companies.\17\
\16\ See, for example, letters from Chesapeake, Oil Change, D. Olds, Ross, D. Ryder, and R. Wagner.
\17\ See, for example, letters from Hugh Anderson (``H. Anderson''), Apache, API, ExxonMobil, Imperial, and Shell.

Several of the comment letters addressed whether third parties should be required to independently evaluate the reserves reported by a company in its filings. There was a divergence in opinion on this issue. Some commenters suggested that an evaluation requirement is necessary to ensure the reliability of the reserves disclosure included in companies' filings.\18\ Other commenters, however, believed that a company's internal staff is often in the best position to accurately evaluate the reserves of the company.\19\ Some of the commenters that opposed a thirdparty evaluation requirement noted that there likely would be practical impediments to establishing that type of requirement, such as the lack of availability of qualified professionals to perform the evaluations and the lack of a regulatory or professional body to enforce universal standards that would govern the activities of thirdparty reserves evaluators or auditors.\20\ \18\ See letters from Fitch Ratings (``Fitch'') and White & Case.
\19\ See letters from API, Denbury, ExxonMobil, Imperial, Nexen, Shell, and Talisman Energy (``Talisman'').
\20\ See, for example, letters from the AAPG, API, Devon, and R. Wagner.

Finally, numerous commenters expressed support for the adoption of an alternate resource classification system that would allow for disclosure of a wider range of reserves and resources in Commission filings. Most of these commenters advocated the use of the Petroleum Resources Management System (PRMS) for this purpose.\21\ PRMS was prepared in 2007 by the oil and gas reserves committee of the Society of Petroleum Engineers and jointly sponsored by the World Petroleum Council, the American Association of Petroleum Geologists and the Society of Petroleum Evaluation Engineers.\22\ Other commenters proposed that we consider the rules adopted by regulators in Canada or the resource classification framework currently being created under the auspices of the United Nations Economic Commission for Europe and the United Nations Economic and Social Council in revising our rules.\23\ We address the public comments on specific issues in more detail in the relevant sections below.
\21\ See comment letters from the API, Deloitte & Touche, LLP (``D&T''), DOE, ExxonMobil and Netherland, Sewell & Associates (``Netherland''). The Petroleum Resources Management System classification system defines a broad range of reserves categories, contingent resources and prospective resources. See Society of Petroleum Engineers, the World Petroleum Council, American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers, Petroleum Resources Management System, SPE/ WPC/AAPG/SPEE (2007).
\22\ See letters from AAPG, SPE, and the Society of Petroleum Evaluation Engineers (``SPEE''). See also Petroleum Resources Management System, SPE/WPC/AAPG/SPEE (2007).
\23\ See letters from Devon, Robinson, and White & Case. The Canadian system is outlined in National Instrument 51101,
``Standards of Disclosure for Oil and Gas Activities,'' and the related ``Canadian Oil and Gas Evaluation Handbook.'' See http:// www.albertasecurities.com/securitieslaw/Regulatory%20Instruments/5/ 2232/AMENDED%20NI%2051101%20_FULL%20VERSION_.pdf. The United Nations Economic Commission for Europe and the United Nations Economic and Social Council are working together to establish an international classification system to classify resources in both the oil and gas and mining industries. See United Nations Framework Classification System for Fossil Energy and Mineral Resources, United Nations Economic Council For Europe (March, 2006) available at http://www.unece.org/ie/se/pdfs/UNFC/UNFCemr.pdf. II. Revisions and Additions to the Definition Section in Rule 410 of Regulation SX

A. Introduction

The proposed revisions and additions to the definition section in Rule 410 of Regulation SX would update our reserves definitions to reflect changes in the oil and gas industry and markets and new technologies that have occurred in the decades since the current rules were adopted. Among other things, the proposed revisions to these definitions address three issues that have been of particular interest to companies, investors, and securities analysts:

Many commenters on the Concept Release suggested that we adopt the PRMS definitions and classification system to the greatest extent possible.\24\ They noted that PRMS is rapidly becoming the leading standard for international petroleum resources classifications. Others suggested that we adopt the definitions and classifications used in Canadian National Instrument 51101 (NI 51101), adopted in 2003, because they have been tested in practice as part of a regulatory framework and because they are broadly consistent with PRMS.\25\ \24\ See letters from API, BHP, Brookwood, CFA, China National Offshore Oil Corporation (``CNOOC''), CIBC World Markets (``CIBC''), D&T, Deutsche Bank, DOE, EIA, EnCana, Energy Literacy, Eni, ExxonMobil, Netherland, Newfield Exoploration (``Newfield''), D. Olds, Petrobras, PetroCanada, Questar Market Resources
(``Questar''), Sasol, Shell, Leigh Ann Smothers (``L. Smothers''), SPE, SPEE, Talisman, Total, TRACS International (``TRACS''), Ultra Petroleum Corporation (``Ultra''), White & Case, and Geoff Zakaib (``G. Zakaib'').
\25\ See letters from Devon, Robinson, and White & Case. NI 51 101 constitutes the Canadian regulatory system for oil and gas company disclosures.

We have based many of our proposed new and revised definitions classifications on both PRMS and NI 51101. The language in NI 51101 lends itself to a regulatory framework more easily than the language in PRMS, which is primarily a management tool, and we have been guided by the language in NI 51101 in several instances. Although the proposed definitions are not totally consistent with either PRMS or NI 51101, they are significantly more consistent with those standards than our existing rules.

One important difference between the proposed amendments and PRMS or NI 51101 is that the proposed amendments would continue to require the use of historical prices and costs used to promote comparability. In contrast, NI 51101 and PRMS afford a reserves estimator more flexibility in choosing among alternative pricing schedules. While this flexibility has its benefits, it impedes comparability of different companies' disclosures. Another significant difference is that the proposed amendments, like the current rules, would require reserves to be ``economically producible,'' meaning that estimated revenues must exceed costs, whereas other classification systems require an extractive project to be ``commercial,'' meaning that a company's investment evaluation guidelines must be met (for example, the extraction project rate of return must exceed some prescribed minimum). There are many different investment evaluation guidelines in use today. However, we believe that our proposed criteria would provide greater comparability among companies' disclosures so that investors can better understand the relative merits of their different investment choices.

In addition, NI 51101 and PRMS provide definitions of various categories of resources beyond reserves, such as contingent and prospective resources, whereas our proposed rules do not. Given that we are not proposing to allow disclosure of resources that do not qualify as reserves in Commission filings, we are not proposing definitions of other various classifications of resources.

After considering the comments received on the Concept Release, we are proposing to revise the definition of proved reserves. Furthermore, as a result of those changes and also observations made by commenters, we are proposing to revise associated definitions and the disclosures made by issuers regarding the extent, characteristics, and location of their reserves.
B. YearEnd Pricing

1. 12Month Average Price

Most commenters on the Concept Release recommended that we replace our current use of a singleday, fiscal yearend spot price to determine whether resources are economically producible based on current economic conditions with a different test.\26\ Some believed that reliance on a singleday spot price is subject to significant volatility and results in frequent adjustment of reserves.\27\ These commenters expressed the view that variations in singleday prices provide temporary alterations in reserve quantities that are not meaningful or may lead investors to incorrect conclusions, do not represent the general price trend, and do not provide a meaningful basis for determination of reserve or enterprise value.\28\ \26\ See letters from AAPG, American Clean Skies Foundation (``ACSF''), H. Anderson, Apache, API, BHP, BP, Brookwood, Canadian Association of Petroleum Producers (``CAPP''), CFA, Chesapeake, CIBC CNOOC, Davis Family Energy Partners (``Davis''), Denbury, Deutsche Bank, Devon, EIA, EnCana, Energy Literacy, Eni, Etherington, J., ExxonMobil, Grant Thornton, Imperial, IPAA, Robbin Jones (``R. Jones''), D. Kelly, Long Consultants (``Long''), D. McBride, MIT Center for Energy and Environmental Policy Research (``MIT''), Moody's, Netherland, Newfield, Nexen, D. Olds, Oil Change, Petrobras, PetroCanada, Robinson, Ross, D. Ryder, S&P, Sasol, Shell, Southwestern, SPE, StatoilHydro, Total, TRACS, Ultra, Walter van de Vijver (``W. van DeVijver''), R. Wagner, White & Case, and F. Ziehe.
\27\ See letters from API, Chesapeake, CIBC, ExxonMobil, Imperial, R. Jones, S&P, Ultra, and R. Wagner.

\28\ See letters from Chesapeake, Devon, and Imperial.

Of those who commented on this issue, most recommended using a 12 month average price instead of the singleday price.\29\ However, others recommended using one of the following alternative pricing options:
\29\ See letters from H. Anderson, Apache, API, BHP, BP, CAPP, Chesapeake, CIBC, CNOOC, Devon, DOE, EnCana, Eni, ExxonMobil Imperial, IPAA, R. Jones, D. McBride, Moody's, Netherland, Nexen, Oil Change, D. Olds, PetroCanada, D. Ryder, Shell, StatoilHydro, Total, TRACS, R. Wagner, and F. Ziehe.

\34\ See letter from Energy Literacy.

Each of the options above, involving historical price averages, futures prices, futures price averages, and price forecasts developed, or relied on, by management, has advantages and disadvantages. For example, historical price averages provide a high level of comparability among oil and gas companies and are relatively easy to compute because the underlying data is readily available to companies. However, they may not reflect the prices that a company could reasonably expect to receive for its production in the future.

Prices based on oil and gas futures are forwardlooking, and therefore may better approximate the economic value of the reserves as they are ultimately produced and sold. These prices, however, are not necessarily available for all products in all geographic areas and would require adjustments. To provide comparability of disclosures among oil and gas companies, we likely would have to specify certain privatesector publications for use in such pricing. Price forecasts developed by management of an oil and gas company would provide investors with better insight into the prices that management of the company foresees and, therefore, the prices upon which management [[Page 39530]]
bases its investment and operating decisions, but may provide limited comparability between companies.

We propose to revise the definitions in Rule 410 of Regulation SX to change the price used in calculating reserves from a singleday closing price measured on the last day of the company's fiscal year to an average price for the 12 months prior to the end of the company's fiscal year.\35\ This pricing standard is consistent with the PRMS's default guidelines for the term ``current economic conditions.'' This price would be calculated as the unweighted arithmetic average of the closing price on the last day of each month in that 12month period. Using historical pricing maximizes comparability between companies, which is the primary objective of the oil and gas disclosure. This proposal is intended to maintain reserves disclosure comparability while mitigating the risk that an anomalous single pricing date will distort the proved reserves estimates. It therefore may provide a better basis for economic producibility than singleday pricing. \35\ See proposed Rule 410(a)(24)(v).

We recognize that use of historical pricing may not capture management's outlook on the future as well as futures prices or management's planning prices. As noted in detail elsewhere in this release,\36\ in order to allow for such disclosures, we are proposing to add a disclosure item that would specifically permit an oil and gas company, at its option, to include a sensitivity case analysis in its filings that would show total reserves estimates based on futures prices, management's planning prices, or other price schedules in addition to the pricing mechanism specifically required.\37\ \36\ See Section III.B.3.ii of this release.
\37\ See proposed Item 1202(c).
Request for Comment

2. Trailing YearEnd

Numerous commenters recommended the use of an average price over a period ending some time before the company's fiscal year end.\38\ They noted that, with accelerated filing deadlines, it becomes difficult for the larger companies subject to those deadlines to make the required calculations accurately and with the best available data.\39\ Most of these commenters recommended that the pricing period end three months prior to the end of the company's fiscal year (for example, a company with a December 31, 2007 fiscal year end, would use the average historical price for the period between October 1, 2006 and September 30, 2007 to calculate its reserves estimates).\40\ We are not proposing such a lag in the time between the close of the pricing period and the end of the fiscal year. However, we solicit comment on this issue. \38\ See letters from AAPG, API, BP, CAPP, CIBC, Deutsche Bank, EnCana, Eni, ExxonMobil, Imperial, D. McBride, Moody's Netherland, Nexen, D. Ryder, Shell, Total, R. Wagner, and F. Ziehe.
\39\ See letters from CAPP and Shell.
\40\ See letters from AAPG, API, BP, CAPP, CIBC, Deutsche Bank, EnCana, Eni, ExxonMobil, Imperial, D. McBride, Moody's, Netherland, Nexen, D. Ryder, Shell, Total, R. Wagner, and F. Ziehe.
Request for Comment

3. Prices Used for Accounting Purposes

Notwithstanding our proposal to change the singleday, yearend pricing for the estimation of reserves, we are not proposing to change the prices that are used for accounting purposes. Specifically, companies using either the successful efforts accounting method described in Statement of Financial Accounting Standard No. 19 (SFAS 19) prescribed by the Financial Accounting Standards Board (FASB) or the full cost accounting method, set forth in Rule 410(c) \41\ of Regulation SX, would continue to depreciate property, plant, and equipment related to oil and gas producing activities using a unitsof production basis over proved developed reserves or proved reserves, as applicable, using singleday, yearend rates. In addition, companies using the full cost accounting method would continue to use the single day, yearend rate for purposes of determining the limitation on capitalized costs (i.e., the ceiling test).

\41\ 17 CFR 210.410(c).

However, to provide consistency between the reserves disclosures required by proposed new Subpart 1200 and SFAS 69, we believe that the information required by SFAS 69 should be prepared using the average price as described above. This would result in two different presentations of proved reserves using two different economic producibility assumptions. For purposes of Subpart 1200, a company would use a value for proved reserves based on average prices. Conversely, for purposes of applying the successful efforts method and the full cost accounting method, a company would use a value of proved reserves based on a singleday, yearend price. We intend to discuss such possible changes with FASB.
Request for Comment

Our current definition of ``oil and gas producing activities'' explicitly excludes sources of oil and gas from ``nontraditional'' or ``unconventional'' sources, that is, sources that involve extraction by means other than ``traditional'' oil and gas wells.\42\ These other sources include bitumen extracted from oil sands, as well as oil and gas extracted from coalbeds and shales, even though some of these resources are sometimes extracted through wells, as opposed to mining and surface processing. However, such sources are increasingly providing energy resources to the world due in part to advancements in extraction and processing technology.\43\ As noted earlier, many commenters supported such disclosure.\44\
\42\ See 17 CFR 210.410(a)(1)(ii)(D).
\43\ According to one commenter, some estimates indicate that such resources already provide 40% of the natural gas produced in the United States. See letter from Chesapeake Energy.
\44\ See letters from AAPG, ACSF, Apache, API, Audit Quality, BP, Brookwood, CFA, Chesapeake, CIBC, CNOOC, Denbury, Deutsche Bank, Devon, DOE, EIA, EnCana, Energy Literacy, Eni, J. Etherington, ExxonMobil, E&Y, Grant Thornton, Imperial, IPAA, D. Kelly, D. McBride, Moody's, Nexen, Oil Change, D. Olds, Petrobras, Petro Canada, R. Pinkerton, PWC, Robinson, Ross, D. Ryder, S&P, Sasol, Shell, SPE, StatoilHydro, Total, A. Verma, R. Wagner, White & Case, and F. Ziehe.

The proposed revised definition of ``oil and gas producing activities'' would include the extraction of the nontraditional resources described above.\45\ The proposal is intended to shift the focus of the definition of oil and gas producing activities to the final product of such activities, regardless of the extraction technology used. The proposed definition would state specifically that oil and gas producing activities include the extraction of marketable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds \46\ or other nonrenewable natural resources which can be upgraded into natural or synthetic oil or gas, and activities undertaken with a view to such extraction.
\45\ See proposed Rule 410(a)(16).
\46\ Although the proposed definition would encompass activities such as extracting coalbed methane from a deposit of coal, it would not include the extraction of the coal itself, even if the company intends to use that coal as feedstock into processing activities that result in oil and gas products, such as coal gasification. We recognize that as technologies progress, it may become appropriate to include such processes as oil and gas producing activities.

However, the proposed definition would continue to exclude activities relating to:

Consistent with historical treatment, we continue to believe that, once a resource is extracted from the ground, it should not be considered oil and gas reserves. Thus, the current definition of the term ``oil and gas producing activities'' does not, and the proposed definition would not, permit companies that only transport, process, and/or market oil or gas to disclose, as reserves, amounts of oil or gas received from, and extracted from the ground by, another company. In addition, if a company extracting the resources also builds its own processing plant onsite or near the extraction location (other than field processing of gas to extract liquid hydrocarbons), we do not believe it would be appropriate for that company to use the price of its processed product to determine the economic producibility of the unprocessed product. For example, if a company builds a bitumen processing plant to convert raw bitumen into synthetic crude oil, its calculation for the economic producibility of reserves from that location should be based on the prices for the raw bitumen, as though it were providing the bitumen to a third party processor. This will facilitate comparability among companies.

We recognize, however, that excluding the listed activities from the definition of ``oil and gas producing activities'' would not permit a company to reflect the result of building its own processing plant on the price estimates and other considerations that may be used in making the company's business decisions. Such a processing plant can significantly enhance the value of the upgraded product, enabling the company to use lower costs (or higher prices) in its internal decision making. As noted elsewhere in this release, we are proposing to allow companies to voluntarily present an analysis of the sensitivity of reserves estimates based on varying prices, including the expected product prices used by management for its own planning purposes.\47\ Such supplemental disclosure would permit companies to disclose other pricing and cost considerations, including advantages gained by internal processing of raw
[[Page 39532]]
products that may add value to the final product sold by the company. \47\ See proposed Item 1202(c).
Request for Comment

D. Reasonable Certainty and Proved Oil and Gas Reserves

The current definition of the term ``proved reserves'' states that these reserves are ``the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.'' \48\ Although ``reasonable certainty'' is, and has been, the standard used in the definition of proved oil and gas reserves, the current rules do not define that term. As a result, the meaning of the term ``reasonable certainty'' has been the subject of significant disagreement within the industry relating to the level of probability necessary to meet this standard. Although some believe that this standard is clear and has established a consistent guideline for establishing proved reserves,\49\ others do not believe that this has been the case.\50\ To avoid ambiguity, we propose to add a definition of the term ``reasonable certainty'' to Rule 410 of Regulation S X.\51\
\48\ See Rule 410(a)(2) of Regulation SX [17 CFR 210.4
10(a)(2)].
\49\ See letters from R. Jones and Moody's.
\50\ See letters from D. Olds, Raymond Schutte (``R. Schutte''), L. Smothers, R. Wagner, and Sir Philip Watts (``P. Watts''). \51\ See proposed Rule 410(a)(26).

We propose to define the term ``reasonable certainty'' as ``much more likely to be achieved than not.'' In addition, we would clarify that, when deterministic methods \52\ are used to estimate oil and gas reserves, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) \53\ with time, reasonably certain EUR is much more likely to increase than to either decrease or remain constant. The proposed definition also would explain that, when probabilistic methods are used to estimate reserves, reasonable certainty means that there is at least a 90% probability that the quantities actually recovered will equal or exceed the stated volume.\54\
\52\ See Section II.D.2 of this release for a discussion regarding deterministic methods and probabilistic methods.
\53\ We propose to define the term ``estimated ultimate recovery'' as the sum of reserves remaining as of a given date plus the cumulative production as of that date. See proposed Rule 4 10(a)(11).
\54\ This is consistent with the PRMS definition of ``proved reserves.''
Request for Comment

1. New Technology

The current rules limit the use of alternative technologies as the basis for determining a company's reserves disclosures. For example, under the current rules, a company generally must use actual production or flow tests to meet the ``reasonable certainty'' standard necessary to establish the proved status of its reserves. However, in the past, the Commission's staff has recognized that flow tests can be impractical in certain areas, such as the Gulf of Mexico, where environmental restrictions effectively prohibit these types of tests. The staff has not objected to disclosure of reserves estimates for these restricted areas using alternative technologies. Some commenters noted that a casebycase exemption from the flow test requirement imposes unequal standards for establishing reasonable certainty based on geographic location.\55\
\55\ See letters from Petrobras, D. Ryder, and White & Case.

In addition, we recognize that technology will continue to develop, improving the quality of information that can be obtained from existing tests and creating entirely new tests that we cannot yet envision. We propose to add a definition of the term ``reliable technology'' to Rule 410 of Regulation SX to clarify the types of technology that can be used to establish reasonable certainty. We propose to define ``reliable technology'' as ``technology (including computational methods) that, when applied using high quality geoscience and engineering data, is widely accepted within the oil and gas industry, has been field tested and has demonstrated consistency and repeatability in the formation being evaluated or in an analogous formation. Consistent with current industry practice, expressed in probabilistic terms, reliable technology has been proved empirically to lead to correct conclusions in 90% or more of its applications.'' \56\

\56\ See proposed Rule 410(a)(27).

The proposed definition is intended to permit broader use of new technologies to establish the proper classification for reserves and to lessen the need for frequent updates to our reserves definitions as technology continues to evolve. Because companies would now be able to select the technology that it uses, we are proposing to require a company to disclose the technology used to establish the appropriate level of certainty for material properties in a company's first filing with the Commission and for material additions
[[Page 39533]]
to reserves estimates in subsequent filings.\57\ Such disclosure should identify the particular portion of the reserves estimates for which a particular technology was used, including identification of the geographic area, country, field or basin to the extent necessary for investors to determine whether use of that technology was appropriate under the circumstances.
\57\ See proposed Item 1202(a)(4) and proposed Item 1209(a)(2). Request for Comment

We propose to add definitions of the terms ``deterministic estimate'' and ``probabilistic estimate.'' \58\ These two terms relate to the two alternative methods by which a company may estimate its reserves amounts. We understand that both methods are, to varying degrees, currently used by the industry. Our proposed definitions are consistent with industry practice. We propose to define the term ``deterministic estimate'' to mean an estimate that is based on using a single ``most appropriate'' value for each variable in the estimation of reserves, such as the company's determination of the oil or gas in place in a reservoir, multiplied by the fraction of that oil or gas that can be recovered. In addition, we propose to define the term ``probabilistic estimate'' as an estimate that is obtained when the full range of values that could reasonably occur from each unknown parameter (from the geoscience, engineering, and economic data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. Although companies currently can use either method to produce reserves estimates, we believe that these proposed definitions will promote consistent usage of the terms ``probabilistic estimate'' and ``deterministic estimate.''
\58\ See proposed Rules 410(a)(6) and (a)(19). These
definitions are based on the Canadian Oil and Gas Evaluation Handbook (COGEH). This handbook was developed by the Calgary Chapter of the Society of Petroleum Evaluation Engineers and the Petroleum Society of CIM to establish standards to be used within the Canadian oil and gas industry in evaluating oil and gas reserves and resources.

Some of the commenters suggested that we require the use of probabilistic estimates to establish proved reserves because these methods are derived through extensive statistical computer calculations using a wide range of potential values for parameters that affect the reserves estimate, such as possible recovery factors for a particular field or type of field, and so would be more rigorous than deterministic methods.\59\ Conversely, the quality of an estimate derived through deterministic methods depends more heavily on the experience and judgment of the reserves estimator to select the most appropriate value for those parameters. Although we recognize that probabilistic methods can be useful in certain circumstances, requiring the use of probabilistic estimates could significantly increase the costs of reserves estimate preparation, without significant increases in reliability of the results in many cases. One commenter was concerned that companies may not have sufficient staff to calculate all reserves estimates through probabilistic methods.\60\ Thus, the proposed definition of ``reasonable certainty'' would continue to allow companies to estimate reserves amounts using either deterministic or probabilistic methods, leaving companies to determine which method is more appropriate for their particular situations.\61\
\59\ See letters from AAPG, EIA, Long, D. Olds, Rose, and SPE. \60\ See letter from D. Olds.
\61\ See proposed Rule 410(a)(26).
Request for Comment

The current definition of the term ``proved oil and gas reserves'' also incorporates certain specific concepts such as ``lowest known hydrocarbons'' which limit a company's ability to claim proved reserves in the absence of information on fluid contacts in a well
penetration,\62\ notwithstanding the existence of other engineering and geoscientific evidence.\63\ Consistent with our proposal to permit the use of new technologies to establish the reasonable certainty of proved reserves, the proposed revisions to the definition of ``proved oil and gas reserves'' also include provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations.
\62\ In certain circumstances, a well may not penetrate the area at which the oil makes contact with water. In these cases, the company would not have information on the fluid contact and must use other means to estimate the lower boundary depths for the reservoir in which oil is located.

\63\ See Rule 410(a)(2)(i) [17 CFR 210.410(a)(2)(i)].

Similarly, the proposed definition would permit a company to claim proved reserves beyond drilling units that immediately offset developed drilling locations if the company can establish with reasonable certainty that these reserves are economically producible.\64\ These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they would establish a uniform standard of reasonable certainty that could be applied to all proved reserves, regardless of location or distance from producing wells.
\64\ See proposed Rule 410(a)(24)(ii). See Section II.G for a more detailed discussion regarding this proposed revision.

[[Page 39534]]

Finally, we propose adding a sentence to the definition that would state that, in order for reserves to be proved, the project to extract the hydrocarbons must have commenced or it must be reasonably certain that the operator will commence the project within a reasonable time. This revision is designed to prevent a company from including, in proved reserves, projects in undeveloped areas for which it does not have the intent to develop.
Request for Comment

We propose to define the terms ``probable reserves'' and ``possible reserves'' because we are proposing to permit companies to disclose these categories of reserves estimates.\65\ When producing an estimate of the amount of oil and gas that is recoverable from a particular reservoir, a company can make three types of estimates:
\65\ See proposed Rule 410(a)(18) and (17), respectively.

Some commenters on the Concept Release were concerned that disclosing reserves categories that are less certain than proved reserves could increase the risk of confusion and litigation.\66\ Therefore, we are proposing to make these disclosures voluntary.\67\ Numerous oil and gas companies currently disclose unproved reserves on their Web sites and in press releases. This practice does not appear to have created confusion in the market. However, we understand commenters' concerns that probable and possible reserves estimates are less certain than proved reserves estimates and so may create increased litigation risk. By making these disclosures voluntary, a company could decide on its own whether to provide the market with this disclosure, despite possible increased litigation risk. In addition, to address the concerns regarding the uncertainty of estimates of unproved reserves, we also are proposing to require disclosure about the person primarily responsible for preparing the company's reserves estimates and, if applicable, about the person primarily responsible for conducting a reserves audit.\68\ The proposal would clarify that a ``person'' may be a business entity or an individual. We address this proposed disclosure in more detail in Section III.B.3.v of this release.
\66\ See letters from Devon and Imperial.
\67\ See proposed Item 1202.

\68\ See proposed Item 1202(a)(6).

We propose to define the term ``probable reserves'' as those additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.\69\ The proposed definition would provide guidance for the use of both deterministic and probabilistic methods. The proposed definition would clarify that, when deterministic methods are used, it is as likely as not that actual remaining quantities recovered will equal or exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. This proposed definition was derived from the PRMS definition of the term ``probable reserves.''

\69\ See proposed Rule 410(a)(18).

Our proposed definition of ``possible reserves'' would include those additional reserves that are less certain to be recovered than probable reserves.\70\ It would clarify that, when deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable, and possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the sum of proved, probable, and possible estimates. As with the proposed definition of probable reserves, the proposed definition of possible reserves is based on the PRMS definition of the term ``possible reserves.''
\70\ See proposed Rule 410(a)(17).
Request for Comment

As noted above, we are proposing to expand the scope of oil and gas producing activities to include resources extracted by technologies other than traditional oil and gas wells, such as mining processes. Similarly, we propose to expand the definition of the term ``proved developed oil and gas reserves'' to include extraction of resources using technologies other than production through wells.\71\ The proposed new definition would state that ``proved developed oil and gas reserves'' are proved reserves that:
\71\ See proposed Rule 410(a)(22).

FOR FURTHER INFORMATION CONTACT Questions on this Proposing Release should be directed to Ray Be, Special Counsel, Office of Rulemaking at (202) 5513430; Mellissa Campbell Duru, AttorneyAdvisor, Dr. W. John Lee, Academic Petroleum Engineering Fellow, or Brad Skinner, Senior Assistant Chief Accountant, Office of Natural Resources and Food at (202) 5513740; Leslie Overton, Associate Chief Accountant, Office of Chief Accountant for the Division of Corporation Finance at (202) 551 3400, Division of Corporation Finance; or Mark Mahar, Associate Chief Accountant, or Jonathan Duersch, Assistant Chief Accountant, Office of the Chief Accountant at (202) 5515300; U.S. Securities and Exchange Commission, 100 F Street, NE., Washington, DC 205493628.