Reserves Disclosure Rules Revised

On Dec. 29, 2008, the U.S. Securities and Exchange Commission (SEC) announced that it was revising and updating its disclosure rules for oil and natural gas reserves.

Oil and natural gas professionals have been urging the SEC to modernize its disclosure rules for oil and natural gas reserves for many years. The principal criticism of the original rules is that they were introduced more than a quarter century ago, and were not updated regularly to remain current with industry practice and technological advancements.

The result was an increasing divergence between the information investors and the market wanted and what companies could disclose in their official SEC reports.

The vote by the bipartisan commission to adopt the amendments to the disclosure rules was unanimous, and completes a process that has taken more than a year.

It began after AAPG and the Society of Petroleum Engineers held the Interdisciplinary Reserves Conference in Washington, D.C., in June 2007 with a Concept Release issued the following December, in which the SEC solicited feedback on a host of specific questions relating to reserves disclosure.

Based on this feedback, the SEC developed a proposed rule (actually a series of amendments to the current rule) that it offered for public comment in June 2008. The SEC then used this additional feedback to develop the final amendments that the commission adopted in December 2008.

In announcing the changes to the disclosure requirements, SEC Chairman Christopher Cox said, ”These updates to the SEC rules will help ensure more meaningful and comprehensive disclosure of information that, even though it does not appear on a company’s balance sheet, is of significance to investors in making informed investment decisions.”

AAPG provided comments and feedback throughout the process, as did many of our sister societies.

In our comments, AAPG urged the SEC to adopt the principles set out in the Petroleum Resources Management System – a set of guidelines and definitions for managing petroleum resources, prepared by the Society of Petroleum Engineers Oil and Gas Reserves Committee jointly with AAPG (represented by Ken Mallon), the World Petroleum Council and the Society of Petroleum Evaluation Engineers.

In many cases the SEC agreed with this suggestion, indicating repeatedly how the new disclosure requirements conform to PRMS guidelines.

The complete final rule can be downloaded on the SEC Web site, but several major changes include:

  • Use of 12-month average price, instead of a single-day, year-end price, in determining the economically producible volume of oil and natural gas classified as “proved reserves.”
  • Inclusion of bitumen extraction and other non-traditional resources as oil and gas producing activities covered under the revised disclosure rules. The determinant of whether a particular non-traditional resource can be included as oil or natural gas reserves is based on final product. Thus, coal intended to be converted to oil and natural gas would be included, while other coal reserves would not.
  • The revised definition of “proven reserves” permits the use of new reliable technologies in determining reserve volumes and enables the booking of reserves outside traditional spacing areas, which is particularly important for resource plays.
  • The concept of “reasonable certainty” is central to the revised definition of proved reserves, and follows the PRMS. It permits the use of deterministic and probabilistic methods in meeting the standard.
  • Uses a principles-based definition of “reliable technology” that permits a broader portfolio of technologies to estimate and categorize proved reserves. Enabling the use of new technologies, once they are established as reliable, is a significant step to ensuring that these new disclosure rules will remain current.
  • The SEC will now permit (but not require) disclosure of probable and possible reserves.

“It is gratifying to see the SEC make these changes to its disclosure requirements, and I congratulate and thank the many AAPG members and members of other professional associations who helped develop and communicate the PRMS principles,” said Peter R. Rose, a former AAPG president, co-chair of the reserves conference and chair of the AAPG ad hoc committee on SEC response.

“The new disclosure rules demonstrate how scientific excellence and professional, ethical conduct in a regulatory context directly benefit society,” Rose continued. “Our challenge now, as a scientific and professional association, is to ensure that our members who are engaged in preparing and complying with these new rules can do so properly and effectively.”

The SEC has set an effective date for the new rules of Jan. 1, 2010, and companies may not adopt the new disclosure requirements any sooner.

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Washington Watch - David Curtiss

David Curtiss served as the Director of AAPG’s Geoscience and Energy Office in Washington, D.C. from 2008-11.

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Creties Jenkins is a past president of the EMD.

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Dan Smith is chair of the Governance Board.

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 Peter MacKenzie is vice chair of the Governance Board. 

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Alternative Resources, Structure, Geochemistry and Basin Modeling, Sedimentology and Stratigraphy, Geophysics, Business and Economics, Engineering, Petrophysics and Well Logs, Environmental, Geomechanics and Fracture Analysis, Compressional Systems, Salt Tectonics, Tectonics (General), Extensional Systems, Fold and Thrust Belts, Structural Analysis (Other), Basin Modeling, Source Rock, Migration, Petroleum Systems, Thermal History, Oil Seeps, Oil and Gas Analysis, Maturation, Sequence Stratigraphy, Clastics, Carbonates, Evaporites, Seismic, Gravity, Magnetic, Direct Hydrocarbon Indicators, Resource Estimates, Reserve Estimation, Risk Analysis, Economics, Reservoir Characterization, Development and Operations, Production, Structural Traps, Oil Sands, Oil Shale, Shale Gas, Coalbed Methane, Deep Basin Gas, Diagenetic Traps, Fractured Carbonate Reservoirs, Stratigraphic Traps, Subsalt Traps, Tight Gas Sands, Gas Hydrates, Coal, Uranium (Nuclear), Geothermal, Renewable Energy, Eolian Sandstones, Sheet Sand Deposits, Estuarine Deposits, Fluvial Deltaic Systems, Deep Sea / Deepwater, Lacustrine Deposits, Marine, Regressive Deposits, Transgressive Deposits, Shelf Sand Deposits, Slope, High Stand Deposits, Incised Valley Deposits, Low Stand Deposits, Conventional Sandstones, Deepwater Turbidites, Dolostones, Carbonate Reefs, (Carbonate) Shelf Sand Deposits, Carbonate Platforms, Sebkha, Lacustrine Deposits, Salt, Conventional Drilling, Directional Drilling, Infill Drilling, Coring, Hydraulic Fracturing, Primary Recovery, Secondary Recovery, Water Flooding, Gas Injection, Tertiary Recovery, Chemical Flooding Processes, Thermal Recovery Processes, Miscible Recovery, Microbial Recovery, Drive Mechanisms, Depletion Drive, Water Drive, Ground Water, Hydrology, Reclamation, Remediation, Remote Sensing, Water Resources, Monitoring, Pollution, Natural Resources, Wind Energy, Solar Energy, Hydroelectric Energy, Bioenergy, Hydrogen Energy
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Gas generation is a commonly hypothesized mechanism for the development of high-magnitude overpressure. However, overpressures developed by gas generation have been rarely measured in situ, with the main evidence for such overpressures coming from source rock microfractures, the physical necessity of overpressures for primary migration, laboratory experiments, and numerical modeling. Indeed, previous in-situ observations suggest that gas generation only creates highly localized overpressures within rich source rocks. Pore-fluid pressure data and sonic velocity–vertical effective stress plots from 30 wells reveal that overpressures in the northern Malay Basin are primarily generated by fluid expansion and are located basinwide within the Miocene 2A, 2B, and 2C source rock formations. The overpressures are predominantly associated with gas sampled in more than 83% of overpressure measurements and have a sonic-density response consistent with gas generation. The association of fluid expansion overpressures with gas, combined with the sonic-density response to overpressure and a regional geology that precludes other overpressuring mechanisms, provides convincing in-situ evidence for basinwide gas generation overpressuring. Overpressure magnitude analysis suggests that gas generation accounts for approximately one-half to two-thirds of the measured excess pore pressure in the region, with the remainder being generated by coincident disequilibrium compaction. Thus, the data herein suggest that gas generation, if acting in isolation, is producing a maximum pressure gradient of 15.3 MPa/km (0.676 psi/ft) and not lithostatic magnitudes as commonly hypothesized. The gas generation overpressures in this article are not associated with a significant porosity anomaly and represent a major drilling hazard, with traditional pore-pressure prediction techniques underestimating pressure gradients by 2.3 plusmn 1.5 MPa/km (0.1 plusmn 0.07 psi/ft).
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