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Marc Folladori, Robin L. Clarkson, and Jeff M. Dobbs, Mayer Brown LLP, Houston
EDITOR'S NOTE: This is the third of three articles by the authors that address publicly-held exploration and production companies' compliance with the oil and natural gas disclosure rules adopted by the Securities and Exchange Commission (SEC) in 2008. Because of its length, we are running the article in two parts. Find Part II in our January issue.
The new oil and natural gas disclosure rules adopted by the SEC in late 2008 had been eagerly anticipated by industry participants, intended to modernize the old rules by conforming them to current industry standards. The rules first became operational with respect to companies' annual reports with the SEC for fiscal years ended on and after Dec. 31, 2009.
In our article published in the Oil & Gas Financial Journal in December 2010, we summarized our review of 25 E&P companies' annual reports on Form 10-K filed with the SEC during 2010. Our review provided us insights on how these particular domestic issuers had interpreted and implemented the new rules. In August 2011, we completed a review of comment letters issued by the staff of the Division of Corporation Finance of the SEC during 2010 and the first half of 2011, which addressed E&P companies' disclosures in their annual reports for their fiscal year ended Dec. 31, 2009 (and in some instances, later).
Comment letters are publicly-available written correspondence from the staff sent to public companies that contain observations and questions about disclosures contained in the companies' filings. The comments in the 2010-2011 letters reflected staff views on whether and to what extent companies were complying with the new oil and gas rules. After analyzing our findings from these letters, we summarized our observations in a second article.
We noted in our second article that many staff comments had been directed toward two of the most significant changes under the new rules.
- The first was a five-year time limitation on reserves classified as proved undeveloped reserves (PUDs). For PUDs to be booked for an undrilled location, there must be a development plan adopted by the company that indicates that the undrilled location is scheduled to be drilled within five years. PUDs that remained recorded as such on the books for more than five years must be removed from the proved category. However, exceptions may be justified if the company can establish that "special circumstances" exist that warrant a longer interval before initiating development.
- The second was a broadened authorization that permitted companies to prove up their undeveloped reserves by the application of "reliable technology," meaning that companies were no longer restricted to the use of flow tests or observations of actual production. The new rules defined reliable technology as technology that has been field tested and demonstrated to provide "reasonably certain" results with consistency and repeatability in the subject formation or in an analogous formation.
During the second half of 2011 and into 2012, the staff issued comment letters to many E&P companies about disclosures in their annual reports for the fiscal year ended Dec. 31, 2010 (and in some instances, later). This second round of comments revealed a greater focus by the staff on technical details about the compliance issues raised compared to the first round of comments issued during the 2010-11 period. This was true both with familiar disclosure topics that had been areas of concentration in the 2010-11 letters, and a number of new subject areas as well. It may be that in the first round of comment letters, the staff's primary focus was on whether companies were complying with the new rules—and that for the 2011-12 period, its attention had turned more to how companies were complying.
As noted above, we observed in the 2011-12 letters many changes in not only the type and tenor of the staff's comments, but also in the types of companies commented upon by the staff.
- Whereas many comments issued in 2010-11 dealt with simple failures by companies to comply with the literal terms of many of the new rules, the level of detail of the staff's review and comments in 2011-12 was considerably more granular in many cases:
- There appeared to be more comments requesting spreadsheets and other detailed reserve engineering data, including information on the costs used in calculating the standardized measure of discounted future net cash flows; and
- There also appeared to be more financial and accounting comments dealing with items as diverse as impairment charges, non-GAAP measures, the SEC's Regulation S-X Rule 4-10 full-cost accounting definitions and the Financial Accounting Standards Board's Accounting Standards Codification disclosure requirements of Extractive Activities—Oil and Gas (Topic 932) "Oil and Gas Reserve Estimation and Disclosures" (FASB ASC Topic 932);
- There was a broader variety of comments—for example, many comments dealt with companies' hydraulic fracturing (or "fracking") activities, environmental practices and insurance coverage—topics that received considerably less attention in the 2010-11 letters;
- There appeared to be more comments relating to foreign private issuers' disclosures; and
- There appeared to be a higher incidence of comments for non-corporate entities having pass-thru tax attributes, such as royalty trusts and master limited partnerships (MLPs).
There were also numerous comments raised in the 2011-12 letters dealing with the five-year rule and reliable technology employed in proving up reserves. However, those two topics comprised, relatively speaking, a smaller percentage of the total comments than in the 2010-11 period.
Hydraulic fracturing, liabilities, insurance
Depending on the geographic and geological concentrations of their E&P activities, many companies received comments requesting information about their horizontal drilling and hydraulic fracturing operations. For example, many companies received general requests, "with a view toward ultimate disclosure," to provide the staff with information on the locations of, their acreage subject to, the percentage of their total proved reserves subject to, and the anticipated costs and funding associated with, their hydraulic fracturing activities, and whether there had been incidents, citations, or suits relating to environmental concerns and their fracing operations.
Other companies received these and additional comments requesting more focused information on their particular shale development activities – such as costs and funding (including maintenance capital expenditure data) relating to their fracing activities or specific information regarding a particular locale.
There were many comments directed to E&P producers' efforts to minimize the environmental impact of their fracing activities, including requests for additional disclosures as to steps a company had taken and had in place to ensure that (i) its drilling, casing, and cementing activities adhered to known best practices; (ii) it monitored the rate and pressure of its fracing treatment in real time; (iii) it evaluated the environmental impact of additives to its fracing fluids; and (iv) it minimized the use of water, or else disposed of water used in its operations in a way that minimized the impact to nearby surface water.
Comments also requested information about (a) actions that third-party contractors had taken to minimize environmental impact, (b) applicable state permitting requirements and insurance coverage, (c) the existence of baseline assessments of nearby water sources and whether the company had the capability to monitor for and detect the chemicals in local water supplies, and (d) the existence of remediation plans or procedures to deal with the environmental impact likely to result from a spill or a leak.
There were many questions dealing with the contents of the fluids used in hydraulic fracturing activities. For example, the staff requested reports that would detail all chemicals (in volumes and concentrations) used in companies' fracing fluid mixtures, and the total amounts of each component utilized for representative wells in each of the major areas of interest in which the companies operated.
Where companies responded only that "additional substances" made up portions of their total fluid components, the staff asked what the additional substances were and how many gallons of fracing fluid on average (not including proppants) were used for well completion, stimulation, or workover purposes.
Other comment letters asked broader questions about the financial and operational risks associated with fracing, such as underground migration of the fracing fluids, or spillage or mishandling of recovered hydraulic fracturing fluids. One company responded that it did not believe that the operational and financial risks associated with its fracing activities were material to it. In its reply, the staff asked the company to explain the basis for its opinion to this effect.
Requests for disclosures about companies' insurance coverage and potential liabilities for their fracing activities were also commonplace during the 2011-12 review period. For example, companies were asked to disclose all material information regarding possible liabilities relating to environmental contamination that could arise from their fracing operations; relevant information requested included applicable insurance policy limits and deductibles, cross-indemnification obligations of companies and their co-participants, insurance covering environmental liabilities resulting from fracing activities and the types of fracing-related risks for which companies were insured.
Other times, the staff observed that companies' "risk factors" identified in their filings should better disclose the potential liabilities and lack of insurance coverage for their fracing pollution liability. These types of disclosures relating to pollution concerns were also requested from E&P producers having deepwater or other offshore operations.
Many companies received comments in 2011-12 pointing out deficiencies in their reserve engineering disclosures. Comments in this area generally appeared to be as commonplace as they had been during the 2010-11 period. A number of comments noted only generally that the filed third-party engineers' reports did not comply with Item 1202(a)(8) of the SEC's Regulation S-K, which describes the disclosures required by the SEC to be included in third-party engineering reports.
Other comments dealt with specific deficiencies under S-K Item 1202(a)(8) and other standards – such as (i) failure to include the purpose for which the report was prepared and the location of the audited properties, (ii) failure of the third-party engineers to use the definitions in Rule 4-10(a) of Regulation S-X to determine the reserves and prepare the report, (iii) noting that the report was improperly presented in conformance with Canadian oil and gas regulations instead of SEC regulations, (iv) referencing evaluation and auditing standards promulgated by the Society of Petroleum Engineers instead of the relevant SEC disclosure rules, (v) clarifying whether the report was a "review," as opposed to an "audit" of reserves and (vi) the inclusion of references to boilerplate language that discussed every reserve methodology, whether actually used or not, instead of addressing the type of methodology actually applied in estimating the company's reserves.
Also notable in the 2011-12 period was the extent to which detailed engineering information was requested by the staff to be furnished to it as supplemental information, such as:
- One-line recaps in spreadsheet format for each property, sorted by field within each reserve category, including the dates of first booking and the estimated first production of the company's PUDs;
- Total company summary income forecast schedules for each proved reserve category with proved developed reserves (PDs) segregated into producing and non-producing categories;
- Individual income forecasts for all wells and locations in the PUD and PD categories; and
- Engineering exhibits (e.g., maps, rate/time plots, volumetric calculations, analogy well performance) for each of the three largest wells/locations in the PUD and PD categories.
Schapiro resigns from SEC, Elisse Walter to head agency
Mary Schapiro said Nov. 26 that she is stepping down as chairwoman of the Securities and Exchange Commission effective Dec. 14. President Barack Obama said he would appoint SEC Commissioner Elisse Walter as the agency's new chairwoman.
Walter assumes her new role upon Schapiro's departure. Her appointment will not require congressional approval because the Senate previously confirmed her as a commissioner.
Obama nominated Schapiro, a political independent, to head the SEC in 2009 during a critical time when economic and financial problems had shaken investor confidence in the agency, which was faulted for its lax oversight of brokerage firms like Lehman Brothers, which failed in 2008 and contributed to the worst economic downturn since the Great Depression of the 1930s. Schapiro is widely credited with restoring a measure of confidence in the regulatory agency.
Walter, a Democrat, is a longtime ally of Schapiro and will likely follow a similar policy line.
Similar comments were directed toward companies' major areas of operational concentration. For example, the staff asked EOG Resources Inc. for essentially the same information described above, but limited to "each shale play." Some letters requested further detailed information specific to characteristics of a particular field or formation.
In the case of EOG, the information requested included (i) terminal net decline rates employed in estimating proved reserves for the company's Eagle Ford and Haynesville shale plays, technical support for those estimates and the effect of decreasing or increasing the decline rates by 25% on estimated ultimate recovery (EUR) and economic well life, and (ii) incremental EUR and costs of any shale re-fracture treatments in those areas and provisions for any future treatments.
Other examples of specific engineering data requested from companies included decline parameters used in estimating EURs (initial decline rate, terminal decline, hyperbolic exponent and economic life) and maps showing analogy wells and engineering exhibits (rate/time plots, volumetric calculations and analogy well performance) used to determine EURs.
In another case, the staff requested data showing (i) the average EUR for a Haynesville Shale PUD compared to that for a Lower Cotton Valley formation PUD, estimated average drilling costs and estimated completion costs for a Haynesville well versus a Lower Cotton Valley well and the average length of time it would take for each well to produce its estimated reserves and (ii) how much in terms of future investment was included in the reserve evaluations for re-fracturing the shale wells, estimated time interval between the re-fracturings, and the basis for that estimate.
Some companies' reserve reports indicated that their estimated PUDs in certain producing fields evidenced producing lives that were longer than the staff believed justified. For example, the report for Memorial Production Partners LP indicated that the average well life of 19 PUD locations in the Cotton Valley formation was approximately 55 years. The company argued that an economic software program it had utilized justified these producing-life estimates.
The staff disagreed, responding that a software program's indication that economic production would continue for 50-plus years did not mean that it was reasonably certain that it would do so, stating in a comment letter dated Sept. 7, 2011: "[I]n relatively new developments or where new technology is being utilized, where no analogy exists for the estimated life of the producing wells, proved reserves should be limited to well lives that are more reasonably certain until such time the evidence for longer well lives is more compelling."
TO BE CONTINUED IN JANUARY 2013 OGFJ
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.