Oil and gas disclosure rules

Financial and accounting comments

Costs and Prices. Since 2012, it appears that the staff has engaged in a more granular review of E&P companies' financial and accounting disclosures. Many staff comments during the 2013-14 review period dealt with how companies' determined their costs for financial accounting purposes - whether under the successful efforts method or the full cost method - as well as for purposes of calculating the SM and other data required under Regulations S-X and S-K.

A more frequent comment during 2013-14 was whether, in computing net operating income in connection with companies' SM determination, abandonment costs had been taken into account in their future development costs (Petron Energy II Inc. (Feb. 21, 2014); Santa Maria Energy Corp. (Jan. 16, 2014); Enduro Royalty Trust (Dec. 30, 2013); Southwestern Energy Co. (Sept. 25, 2013); EV Energy Partners LP (Sept. 11, 2013); EOG Resources Inc. (Aug. 29, 2013)). The staff often referred these companies to a form of letter sent in 2004 to chief financial officers of E&P companies that expressed staff views that estimated cash outflows associated with oil and gas assets' expected abandonment were asset retirement cost obligations that should be included when determining the standardized measure ("Sample Letter Sent to Oil and Gas Producers" (Feb. 24, 2004) at http://www.sec.gov/divisions/corpfin/guidance/oilgasletter.htm).

There were also numerous comments about property acquisition, drilling and development costs applied for purposes of calculating companies' standardized measure and their capitalized cost ceiling or impairment tests. Companies were often criticized that their treatment of these costs did not conform to applicable accounting guidance, which resulted in questions regarding uncertainties regarding their PUDs and other reserves (Gastar Exploration Ltd. (Sept. 12, 2013); RSP Permian Inc. (Dec. 4, 2013)). Where the staff noted that at year-end 2013, a company's standardized measure was more than its net capitalized oil and gas assets subject to depreciation, it requested the company to provide it with a summary, broken down by cost center, of its ceiling test calculations, and a reconciliation of the sums used in that calculation to its balance sheet or standardized measure, as appropriate (Triangle Petroleum Corp. (Jan. 30, 2014)).

Correspondence between the staff and one company during 2013-14 illustrates issues companies have had in conforming their accounting methods to staff guidance. Devon Energy Corp. did not include certain general and administrative costs in calculating its capitalized costs for ceiling test purposes because it did not consider them to be well-level expenditures. However, it did include them in connection with determining its results of operations and for purposes of its SM. The staff questioned Devon's authority for this disparity in treatment. Devon argued that its treatment for the G&A expenses in question (which it referred to as "production support costs") was proper and based on the same accounting treatment that it employed in its joint operating agreement accounting procedures. After much back-and-forth, Devon finally agreed with the staff's contentions. However, one day later, Devon decided to reverse its decision (see Devon Energy Corp. (Feb. 7, 2014); response letters (Feb. 26 and 27, 2014)).

Companies' treatment of transportation costs received additional attention during 2013-14. The staff asked one company how its oil & gas transportation costs had been incorporated into its historical and projected (for purposes of its SM determination) production costs, or into its average sales price per unit of production, pointing out that transportation costs should be reflected in either the prices the company is paid or the costs it incurs (RSP Permian Inc. (Nov. 4, 2013)). In EP Energy Corp. (Oct. 2, 2013), the staff asked a company to explain how its transportation costs had been incorporated in its estimated proved reserves, associated future net income and the standardized measure. Where the disclosures had been unclear, the staff asked whether companies' oil and gas prices as reported had been inclusive of certain adjustments, such as differentials for transportation, quality, gravity or btu content (Santa Maria Energy (Jan. 16, 2013); FX Energy Inc. (Jan. 10, 2014)).

In addition to costs, there were also comments addressing how companies determined their average sales price per unit of production as required under Regulation S-K Item 1204(b). One company, in determining its average sales price per unit of production, had wrongfully taken into account the impact of hedges. The staff pointed out that average sales price determinations should exclude hedges' impact (Vanguard Natural Resources LLC (Sept. 10, 2013)).

As the case with prior review periods, the staff continued to ask companies about the potential for ceiling test write-downs (e.g., Forest Oil Corp. (Apr. 9, 2014)) and their property cost amortization practices (see EOG Resources Inc. (Aug. 29, 2013)).

MLPs and Distributable Cash Flow. During the 2013-14 review period, the staff directed many comments to E&P master limited partnerships and their calculations of projected "Distributable Cash Flow," to indicate to investors the expected continued stability of their distributions for the future. A key element of the formula for determining estimated Distributable Cash Flow is "maintenance capital expenditures," a concept used to describe the level of capital expenditures required to maintain an MLP's operating assets, operating cash flow or operating capacity, and to quantify the extent to which the MLP's productive capacity, in terms of production and total reserves, must be maintained from period to period. One company defined maintenance capital expenditures as "the estimated amount of capital required to hold production flat on a long-term basis." The staff asked this company how it calculated those expenditures, including whether they represented actual or budgeted expenditures, and requested a clarification of the targets, in terms of production or proved reserves, that were intended to be achieved (Legacy Reserves LP (Sept. 4, 2013 and Oct. 31, 2013)). Another letter asked a company to revise its calculation of maintenance capital expenditures and how they differed from its other capital expenditures; the company was also asked about the underlying assumptions used in its determination, including how it chose its wells, formed expectations about their production profiles and took into account the impact of derivatives related to production to be sold (Atlas Resource Partners LP (Aug. 9 and Oct. 30, 2013)). The enhanced disclosures were intended to convey a better understanding of why maintenance capital expenditures were a meaningful sum to investors, and the extent of their correlation with changes in reserves and production (Linn Energy LLC (April 25, 2013, made publicly available in June 2014)).

Derivatives. Accounting treatment of companies' commodity derivative instruments was a popular topic for the staff during the second half of calendar 2013. Where a company had incorrectly disclosed in its market risk disclosures that changes in the fair value of its derivatives not qualifying as cash flow hedges were recorded in gas and oil sales, the staff asked the company to revise its statement to indicate that changes in the fair value of its derivatives were recorded in the company's income statement line item "gain (loss) on derivatives," and asked the company to confirm that its hedge ineffectiveness was recorded in gas and oil sales rather than as a component of the gain or loss on derivatives (Southwestern Energy Co. (Sept. 25, 2013)).

E&P companies that did not choose to designate, or were unable to qualify, their commodity derivative instruments as cash flow hedges recorded changes in the fair value of those instruments in their current earnings. Many of these companies had presented their changes in fair value of their derivatives in their income statements in two components − (i) realized gains and losses and (ii) unrealized gains and losses. Proceeds and accrued receivables on settled positions were generally shown as realized gains or losses, while the periodic changes in fair value of derivatives were shown as unrealized gains or losses. The staff contended that presenting these amounts separately on the face of the income statement did not conform to accepted accounting guidance, which does not differentiate between realized and unrealized sums for purposes of showing fair value gain (loss) on derivatives (see Linn Energy LLC (May 28, 2013); EXCO Resources Inc. (Sept. 11, 2013); Range Resources Corp. (Sept. 19, 2013 and Jan. 27, 2014)). Companies argued that the bifurcated presentation provided more clarity and transparency to investors by showing both cash and non-cash effects on derivatives fair value changes. The staff cited previous (albeit obscure) authority for their position from the SEC website: Transcript - Speech by G. Faucette, 31st AICPA National Conference on Current SEC Developments (Dec. 11, 2003) at http://www.sec.gov/news/speech/spch121103gaf.htm. There, the staff indicated its view that the presentation of unrealized gains (losses) in one income statement line with a reclassification of realized gains and losses to another line was essentially a form of "synthetic instrument accounting" − the practice of integrating two or more transactions into a single transaction for purposes of recording gains, losses and income - which had been discredited by the accounting profession. See Santa Maria Energy Corp (Jan. 16, 2014); Gastar Exploration Ltd. (Sept. 12 and Oct. 21, 2013); QR Energy LP (Sept. 24, 2013); Antero Resources Corp. (Aug. 16 and Sept. 19, 2013); Equal Energy Ltd. (Aug. 27, 2013); Penn West Petroleum Ltd. (Aug. 23, 2013); WPX Energy Inc. (Aug. 23, 2013).

In July 2013, Linn Energy LLC and its affiliate, LinnCo LLC disclosed that the SEC staff had commenced a private inquiry, requesting documents and communications potentially relevant to, among other things, the companies' disclosures related to hedging strategy.

Engineering information

A consistently disappointing area in terms of companies' and engineering firms' compliance with the amended oil and gas disclosure rules has been the continuing failure by many to observe all of the requirements of the SEC's reserve engineering disclosures - especially regarding third-party engineers' reports filed as exhibits to the filings. Numerous comments addressed engineers' reports simply failing to meet all the requirements of Item 1202(a)(8) of Regulation S-K, which requires specific disclosures in the report about the engineers' role in connection with the preparation of the report or the preparation (or audit) of the company's reserves estimates (see Daybreak Oil and Gas Inc. (Feb. 20, 2014); Red Mountain Resources Inc. (Mar. 26, 2014); Lucas Energy Inc. (Mar. 18, 2014)). One report had omitted to include numerous items required by Item 1202(a)(8), such as a statement regarding the purpose for which the report was prepared, the date on which the report was completed (in addition to its effective date), the proportion of the company's total proved reserves covered by the report and, as part of the report's primary economic assumptions, the realized prices by product type for the reserves covered by the report (EPL Oil & Gas Inc. (Dec. 19, 2013).

Also troubling was continuing instances of inconsistencies between information and data contained in the engineers' reserve report and that contained in the forepart of the filing. For example, a number of engineers' reports had included summary presentations of estimated probable reserves, while the forepart of the filing had not included any references to probable reserve estimates. To remedy the inconsistencies, the staff generally asked the company either to file a revised engineering report, deleting the references to probable reserves, or else amend the entire filing to include probable reserves estimates wherever required (Petron Energy II Inc. (Feb. 21, 2014); Sundance Energy Australia Ltd. (Jan. 15, 2014); Equal Energy Ltd. (Nov. 14, 2013); FX Energy Inc. (Sept. 26, 2013)). Another letter pointed out that certain pricing assumptions used by a company in calculating its standardized measure as disclosed in the forepart of the filing were not the same as the pricing assumptions used by the engineers as contained in the engineers' report (Gastar Exploration Ltd. (Sept. 12, 2013)).

As in prior periods, the staff commented frequently that companies' filings failed to include required disclosures addressing the qualifications of the technical persons primarily responsible for overseeing the reserves estimates' preparation and primarily responsible for overseeing the reserves audit (if one was conducted by independent engineers) (Parsley Energy Inc. (Feb. 3, 2014); Santa Maria Energy Corp. (Jan. 16, 2014); Rex Energy Corp.(Dec. 30, 2013); Lucas Energy Inc. (Mar. 18, 2014); EPL Oil & Gas Inc. (Dec. 19, 2013); FX Energy, Inc. (Sep. 20, 2013 and Jan. 10, 2014); Endeavour International Corp. (Sept. 19, 2013); Imperial Oil Ltd. (Sept. 11, 2013); Cabot Oil & Gas Corp. (Aug. 29, 2013)).

Particularly in the case of IPOs (which generally involve first-time registrants unfamiliar to the staff), the staff made many staff requests for detailed engineering data as supplemental information that would support the companies' estimated reserves. For example, in Antero Resources Corp. (Aug. 16, 2013), the staff asked for technical data to support the company's booking of probable reserves attributable to locations within a 3-mile radius of existing production in the Marcellus and Utica shale areas. The questions included whether any of the company's estimated proved developed producing reserves in those formations had been deterministic estimates − and if so, to what extent had those estimates been based on one or more types of curves for the subject formation or else supported by other methods, such as volumetric calculations, reservoir simulation or probabilistic methods. Also, the company was requested to provide the staff with summary information as of June 30, 2013 in spreadsheet format, of the gross estimated ultimate recoverable quantities in bcfe, the average btu content and the total lateral length of completion for each proved, probable and possible location in such formations, along with rate/time plots for each of the three largest proved developed producing wells and each of the three largest PUD locations in each formation. In Matador Resources Co. (Dec. 27, 2013), the staff asked the company to provide a schedule by each of its operating areas (e.g., Eagle Ford, Haynesville, Cotton Valley, etc.) that would show initial booking dates for its PUDs, the investments and progress that it made by year and the remaining investments and timeline in order to complete the conversion of its PUDs to developed reserves.

About the authors

Marc Folladori has been an M&A and securities attorney in Texas since 1974, and has extensive experience representing energy companies and firms engaged in energy investment and finance. Before his retirement from Mayer Brown LLP in 2014, he served as the head of the firm's Global Energy Practice. The author wishes to acknowledge the research and other contributions in connection with this article made by Amelia Xu while she was an associate at Mayer Brown LLP during 2014.