Marc Folladori, Robin L. Clarkson, and Jeff M. Dobbs, Mayer Brown LLP, Houston
EDITOR'S NOTE: This is the second part of a two-part article. Part I, published in December, analyzed a second round of comment letters issued by the staff of the Division of Corporation Finance of the SEC addressing E&P companies' disclosures in 10-K reports—specifically how the companies were complying. Topics covered in Part I included hydraulic fracturing, liabilities, and insurance, as well as engineering information.
The staff continued to request justification for PUDs that remained on the books for more than five years, or that would not be developed in five years. Where companies responded arguing justification of this treatment with respect to certain fields or areas, the staff often pressed their case harder.
For example, where a company had contended that PUDs scheduled to be developed in year six were located in areas where the company had "demonstrated a track record of continuous development activity" that had extended beyond the term of its development plan, the staff requested data showing the number of locations scheduled for development after five years from booking and the PUD reserves attributed to them, as well as detailed information regarding the company's three largest Haynesville shale locations.
The staff questioned one company about its disclosures that its management had curtailed its drilling program for cost-reduction purposes and how that decision may have changed the company's intentions to develop its large inventory of undeveloped well locations within five years. In response to the company's answer that it continued to have the ability and intention to develop all of its PUD reserves in five years, the staff asked the company to provide it with data regarding the PUDs' drilling schedules, well cost capital and capital for facilities.
There were also many comments regarding the five-year rule in 2011-2012 that were similar to those issued in 2010-2011, including:
- Requests for justification for material amounts of PUDs associated with locations in individual fields that appeared would remain undeveloped for more than five years;
- Where the company was not the operator, an explanation of how the company was getting appropriate assurances that its PUDs would be converted to PDs in five years or less;
- Pointing out that the company's recent actual rates of conversion of PUDs to PDs would not support its estimate that all PUDs would be fully converted to PDs in five years; and
Providing support for the company's project development plans that would justify PUDs remaining on the books beyond five years.
The staff continued to request more disclosure about technologies and methods companies used to establish the appropriate level of certainty for the economic producibility of their added reserves as required under Item 1202(a)(6) of Regulation S-K. This was especially the case where there had been a large annual increase in estimated reserve quantities. Thus, where a company disclosed that it had added 411.7 bcfe in proved reserves through extensions and discoveries, the staff asked for expanded disclosures to discuss the technologies used that had contributed to those particular additions.
Changes in estimates, revisions of proved reserves and trends
Item 1203 of Regulation S-K requires disclosures of material changes in PUD quantities that occurred during the fiscal year, including conversions of PUDs to PDs, and investments and progress (such as capital expenditures) made during the year to convert PUDs to PDs. As was the case during the 2010-11 review period, numerous companies received comments concerning these requirements during the 2011-12 period. Companies disclosing material changes to their PUD estimates were requested to provide additional information as to revisions, acquisitions, divestments, discoveries and extensions in order to better explain the reasons for the changes. Where only conversion information was provided, disclosures were requested about removals and other reasons for the material changes. If improved recovery techniques utilized by the company had accounted for a portion of the material changes, additional disclosures about the techniques were requested. Detailed explanations were also requested as to (i) pertinent development activities performed and costs incurred to convert PUDs to PDs, (ii) capital expended to develop the PUDs, (iii) reasons for increases of natural gas liquid (NGL) reserves by 50%, gas reserves by 11% and oil reserves by 71% and (iv) capital expenditures for two wells drilled in Gabon that had resulted in conversion to proved developed status of 1.9 Mbbls of previously undeveloped oil reserves.
Companies reporting under the successful efforts method of accounting received comments requesting enhanced disclosures about changes in net quantities of their proved reserves during the year and the sources of those changes under FASB ASC 932-235-50-5. Where a company had recorded revisions representing approximately 23% of its proved reserves as of the end of the prior fiscal year, additional disclosures were required to explain the causal factors underlying the changes. Companies were requested to provide information as to major discoveries or other favorable events that caused an increase in proved reserves, as well as downward revisions due to (i) production performance (coupled with an explanation of the circumstances of the reduction and the steps taken to avoid further net negative revisions) or (ii) decisions made to cease developing reserves associated with certain locations for the near future, along with disclosure of the reasons for this change in the company's development plan. Where a company had disclosed "a reserve replacement rate of 736% for the year," the staff asked for an enhanced discussion on how the ratio was calculated and the uncertainties involved in realizing actual production and cash flows from the added reserves.
Acquisitions of properties during the year drew comments and questions. For example, where a company had purchased Permian Basin oil properties and attributed 155 BCFe of estimated proved reserves to undeveloped properties in that area, the staff asked the company for (i) its basis for that estimate, (ii) how many producing wells were on the properties, (iii) their production rates at the time of purchase and (iv) certain pertinent reservoir information. In another comment letter, the staff requested more detailed disclosures about certain properties purchased during the prior year, whether the purchases were related to certain sales of properties during that year and the amounts attributed to each property acquired and sold under the respective purchase and sale agreements.
Production and development
During 2011-12, there appeared to be more questions from the staff dealing with companies' production disclosures, particularly under Item 1204 of Regulation S-K, which requires disclosures of (i) production, by category (oil, gas and other products) by geographic area and for each country and field that contains 15% or more of the company's total proved reserves, (ii) average sales (or transfer) prices and (iii) average production cost per unit of production. The staff questioned whether companies had incorrectly excluded ad valorem and severance taxes in their calculations of average production cost and whether the average production cost had been properly calculated under appropriate accounting guidance.
Many companies received comments about their present activities and trends in their development activities. Item 1206 of Regulation S-K requires disclosures of a company'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 other related material activities. Where crude oil appeared to represent a decreasing portion of total proved reserves, the staff asked whether the company expected this trend to continue, and requested a description of risks associated with the trend and its reasonably possible impact on the company's financial results, financial condition or liquidity in the future. One company had provided a forecast that indicated significant increases in its production attributed to its ongoing drilling program and existing waterflood projects. he staff requested from this company more recent average net production data and a description of how the company's historical drilling activity and waterflood projects had impacted its production within the past year. Other comment letters requested enhanced disclosures about depletion rates, recoveries from infill wells, drilling plans for (and economic risks posed by) marginal proved undeveloped wells in Louisiana and Texas and support for a company's statement that average drilling and completion costs for its Eagle Ford Shale wells had ranged between $5.5 million and $8.1 million per well.
International operations disclosure
During the 2011-2012 period, many international oil companies received comments unique to their international operations and areas of interest. For example, the staff requested from different companies (i) disclosures on the failure of a company to maintain control-of-well insurance for its Brazilian operations and potential consequences of its liability insurance coverage limits, (ii) information on the end dates and fulfillment of minimum exploration obligations under a production sharing contract with the Indian government, (iii) information on capital at risk, contractual oil prices and cost recovery and profit apportionment of derived revenues for particular fields in Iraq and (iv) information on companies' contacts with Iran, Syria and the Sudan. The staff also requested information about the nature and details of prohibitions (by law or contractual) imposed on disclosing information about a company's reserves in Angola and Qatar, and whether any governments of countries where 15% or more of the company's total reserves were located had prohibited the disclosure of reserves in their countries.
Financial and accounting comments
It appeared that in 2011-2012, there were more staff comments than in the prior period relating to detailed specific accounting and financial issues. The staff asked companies whether certain financial disclosures – such as "EBITDAX," "future cash flows before income tax" and "present value of estimated future net revenues of proved undeveloped reserves, discounted at 10%" – were "non-GAAP" measures. The SEC considers a non-GAAP financial measure to be a numerical measure of financial performance that excludes amounts that are included in (or includes amounts that are excluded from) the most directly comparable measure in a financial statement prepared in accordance with generally accepted accounting principles; if a non-GAAP financial measure is disclosed, the disclosure must also include a reconciliation of the non-GAAP measure to the comparable GAAP measure.
There were also numerous comments about companies' compliance with the requirements of the successful efforts method and FASB ASC Topic 932, or the full cost method of accounting and Rule 4-10 of Regulation S-X — topics of inquiry included questions about cost centers, ceiling tests, lower natural gas prices, costs contributed by joint operating agreement partners, capitalized costs and depletion calculations.
There were many comments issued during the 2011-2012 period on impairment, perhaps reflecting the lower range of natural gas spot prices received by producers in 2010 and 2011. These included requests for enhanced information about actual impairment charges taken, whether impairment testing had taken place during the 12 months prior to the sale of certain properties and assumptions used in a company's impairment analysis. Where the staff disagreed with a company's contention that its PUDs were reasonably certain of economic producibility, it directed the company to reconsider the accounting implications associated with revising its total proved reserves, including depletion expense and impairment testing.
Consistent with the theme in the 2011-2012 review period of more detailed comments, the staff asked many companies how they treated certain costs in accounting for and evaluating their reserves. Comments included:
• Requests for an explanation of a company's procedures used to recognize its capital well costs and its saltwater disposal operating costs in its reserve evaluation;
• Questions of why overhead costs were not attributed to a company's properties, and why the company believed that their omission was the correct treatment;
• Requests for supplemental information supporting the company's development costs to be expended in relation to proved reserves at Sept. 30, 2011;
• Explanation of the relationship between the number of suspended exploration wells related to a company's U.S. operations and suspended well costs incurred during the prior fiscal year;
• Questions of whether income tax expenditures were included in the company's calculation of the standardized measure of discounted future net cash flows; and
• An observation that an omission of pre-paid drilling costs that had been paid before the date of a company's reserve report meant that the company's proved reserves may have been overstated.
While many staff comments issued in the 2011-2012 period dealt with new topics, there were also many comments related to topics that had been dealt with during the prior period.
• Expiration of minimum terms of leases and concessions. Where leases for 31.8% of a company's gross acreage were scheduled to expire in 2013, the staff asked for additional disclosures about those leases. Noting that leases for 29,000 of 39,000 net acres in the Eagle Ford Shale area would expire within the next three years, the staff asked for disclosure of the company's PUD reserves that it had attributed to the expiring acreage.
• Geographic regions, fields and the 15% rule. The staff continued to find issues with companies' efforts to comply with Item 1202(a)(2) and Item 1204(a) of Regulation S-K, which require separate disclosures of production totals and proved reserves by geographical areas and with respect to each field and country that contains 15% or more of a company's total proved reserves (unless those disclosures are prohibited by the country in which the reserves are located).
• Internal Controls and Persons Overseeing Reserve Estimation. As was the case in 2010-11, the staff asked for more description as required under Regulation S-K Item 1202(a)(7) of (i) the internal controls that companies used in their reserves estimation process and (ii) the qualifications of the company's technical person primarily responsible for overseeing the preparation of the reserve estimates. Where a company had described a close working relationship between its reservoir management group and its third party engineering firm on technical matters throughout its reserves estimation process, the staff requested expanded disclosures about the company's internal controls and the qualifications of the technical person primarily responsible for overseeing the reserves audit.
• Prices. The staff issued numerous comments requesting information on prices used in companies' reserves evaluation assumptions. An engineer's reserve report stating that prices were based on the continuation of prices in effect as of December 31, 2010 was deficient because the new rules require the use of the average of first-day-of-the-month prices for each month during the fiscal year. Other comments were raised about (i) whether prices used to determine reserve quantities were before or after adjustments from posted prices for differences in location and quality, (ii) whether net book values of a company's properties would have exceeded their undiscounted future net cash flows if revenues had been determined based on actual prices as of the estimation dates or un-escalated forward prices for subsequent years, (iii) hypothetical assumptions used for prices in future years and (iv) whether transfer pricing explained the difference between the 2010 average price for natural gas in Brazil as shown in an average production price table and the higher price applied by the third party engineer in its reserve report.
• Natural gas liquids. With prices for and production of NGLs increasing during 2011, the latest review period saw numerous comments from the staff requesting that companies separate the disclosures that combined their NGL quantities with their crude oil totals.
• Delivery commitments. As was the case in 2010-11, the staff continued to issue comments requesting information required under Item 1207 of Regulation S-K to disclose the sources and availability of oil and gas that the company would rely upon to fulfill its contractual obligations to deliver a fixed and determinable quantity of oil or gas in the near future.
• Miscellaneous. During 2011-12, the staff addressed numerous other disclosure items, mostly fact-specific as to the individual companies. Topics included: inconsistencies in company disclosures within the same document; Regulation S-K Item 1206(d)'s prohibition on disclosing wells that the company plans to drill but has not commenced drilling (unless there are factors that make that information material); volumetric production payments; contractual restrictions on drilling horizontal wells; production marketing contracts and derivatives contracts covering 50%-80% of the company's production; providing appropriate maps of core areas of interest in the disclosure documents; continuous drilling commitments; disallowance under FASB ASC Topic 932 of the inclusion of reserves for two investee entities accounted for under the cost method; separating costs of natural gas sold from affiliated and unaffiliated parties in the operating results table; risks of ethane remaining in the natural gas stream as being non-compliant with pipeline regulatory specifications; and disclosures of synthetic oil reserves.
About the authors
Marc Folladori has been a merger and acquisition and securities attorney in Texas since 1974 and has extensive experience representing energy companies and firms engaged in energy investment and finance. He is co-leader of Mayer Brown's Global Energy Industry group.
Robin Clarkson is an associate in the Houston office of Mayer Brown's Corporate & Securities practice. She concentrates her practice on M&A, securities offerings, corporate governance, and general corporate matters.
Jeff Dobbs is an associate in the Houston office of Mayer Brown's Corporate & Securities practice. His practice focuses on M&A, securities offerings, corporate governance, and general corporate matters.