SEC looks at E&P compliance with amended disclosure rules

PART three OF A THREE-PART SERIES

Marc Folladori and Amelia Xu, Mayer Brown LLP, Houston

This is the latest in a series of articles that address publicly-held exploration and production (E&P) companies' compliance with the amended oil and natural gas disclosure rules adopted by the Securities and Exchange Commission (SEC) in late 2008.1 This is the final part of a three-part series that started with the May issue. Part two appeared in June.

Other financial and accounting comments

Consistent with the 2011-12 review period, the volume of staff comments dealing with detailed specific accounting and financial topics continued to increase. Areas of staff inquiries ranged broadly and included questions about changes in reserve values, facility costs, ceiling tests, the effects of lower natural gas prices and capitalized cost components.

Many staff comments in 2012-13 dealt with the question of how companies categorized the costs they used to calculate their standardized measures of discounted future net cash flows relating to their proved reserves under FASB ASC 932-235-50-31 through 50-36. For example, there were numerous questions about whether future estimated development costs had been correctly calculated for purposes of companies' standardized measure computations. There were numerous comments asking companies to report future estimated development costs separately from their future estimated production costs, particularly where companies' estimated future development costs appeared to be "individually significant" under FASB ASC 932-235-50-31b (PrimeEnergy Corp. (Dec. 4, 2012)). Another company had incorrectly reported $696 million of development costs as being related to drilling unproved properties. The staff pointed the company to the definition of development costs in Regulation S-X § 4-10(a)(7) as "costs incurred to obtain access to proved reserves" (Ultra Petroleum Corp. (Aug. 30, 2012 and Dec. 7, 2012)).

In the tabular presentation of changes in a company's standardized measure required by FASB ASC 932-235-50-35, the staff counseled the company that when identifying the sources of change for the table, changes in the estimated future development costs should be presented separately from changes in previously estimated development costs incurred during the period (Devon Energy Corp. (Dec. 13, 2012)). Where future development costs for a company had included not only costs for the development of its PUDs, but also costs associated with (i) sustaining the existing producing reserves and (ii) the abandonment of developed assets, the staff asked the company for additional explanation about the sustaining costs and abandonment costs and their respective amounts (ConocoPhillips (Sept. 26, 2012)). The staff requested another company to describe further the "social payment obligations" for certain Blocks offshore West Africa in a note to the company's consolidated financial statements presenting its contractual commitments (Cobalt International Energy Inc. (Sept. 13, 2012)).

There were also numerous comments in 2012-13 about companies' determination of their capitalized costs for financial accounting purposes (under the successful efforts method and the full cost method) and for purposes of the unaudited supplemental oil and gas information required to be disclosed in the notes to financial statements. The staff asked a company that reported both PDs and PUDs to revise its disclosures and report the amount of capitalized costs of its PUDs separately from the capitalized costs of its PDs. The company had characterized all costs of its proved properties as costs of developed properties (PrimeEnergy Corp. (Dec. 4, 2012)). Another company was asked why it had not complied with FASB ASC 932-235-50-18, which requires separate disclosure of property acquisition costs from exploration costs (PetroChina Co. Ltd. (Sept. 21, 2012)).

The staff requested one company to provide an explanation (required under FASB ASC 932-235-50-1) about the continued capitalization of its exploratory, or suspended, well costs (Total S.A. (Sept. 17, 2012)). Where a company described a gas gathering system in its disclosures, the staff asked whether the gathering system assets had been installed on wells in which the company had an interest. If the answer was yes, the costs of the gathering system should have been treated as development costs under full cost accounting methodologies of Regulation S-X § 4-10, , whether or not the company had established proved reserves with respect to those interests (Ultra Petroleum Corp. (Aug. 30 and Oct. 25, 2012)).

A company disclosed that it had incurred $650,000 in exploration and development costs per well in 2011. The staff asked the company for (i) a reconciliation of the drilling costs per well with the figures in the third-party reserve report and (ii) the average completed well cost for 2011, along with a comparison of projected capital costs for its estimated PUDs (Far East Energy Corp. (Sept. 25, 2012)).

In light of the continuing low natural gas prices in recent years, the staff issued many comments during 2012-13 about impairment charges and whether companies had correctly calculated the amounts to be written down. Where it appeared that the total capitalized costs of a company's properties had exceeded the sum of the company's standardized measure for those properties plus its costs of unproved properties, the staff asked whether ceiling test write-downs should be recognized (Emerald Oil Inc. (Dec. 26, 2012)). A company's ceiling test calculated as of December 31, 2011 indicated that its ceiling was $262.5 million higher than it would have been if cash flow hedges had not been in place; the staff asked the company what the amount of the ceiling test write-downs would have been had the cash flow hedges not been in place (Southwestern Energy Corp. (June 6, 2012)). Where a decline in natural gas prices had resulted in a company being very close to taking impairment charges at year-end 2011 for its proved properties, the staff compared a number of the company's key financial measures as of year-end 2011 to those as of year-end 2010. These key measures included estimated future development costs as of each of those dates, the increase in PUDs from year-end 2010 to year-end 2011 and the increase in actual costs of converting its PUDs in 2011 compared to those costs incurred in 2010. The staff requested additional details from the company regarding why an impairment charge was not deemed necessary during fiscal 2011 and how the decline in average realized natural gas prices had impacted its impairment assessment (Cabot Oil & Gas Corp. (May 23, 2012)).

Other staff requests asked for specific identification of the asset groups involved when a company performed its impairment analysis by asset groups (Hercules Offshore Inc. (Dec. 7, 2012)), and for significant assumptions the company used in its asset impairment analysis (particularly as to the classification, quantity and pricing of the reserves used to determine revenues) (CAMAC Energy Inc. (Dec. 20, 2012).

Where a company had recognized no impairment expense for fiscal 2011, the staff pressed the company about its analysis in a series of letters. The company replied that for impairment testing purposes, its shallow oil and gas segment was the appropriate, lowest level of identifiable cash flows independent of cash flows from other assets. The staff then requested whether different oil and gas fields within that segment had independent sets of identifiable cash flows, since under FASB ASC 932-360-35-8, evaluation of oil and gas producing properties was typically done on a field-by-field basis or by a logical grouping of assets if there was significant shared infrastructure. The company cited a US Geological Survey report and argued that the entire shallow gas segment constituted one geological structure, and thereby constituted a single "field." The staff disagreed, responding that the very same report had also stated that there were 68 named gas fields within the particular assessment unit (Devonian) that had encompassed the company's shallow gas segment. The company ultimately agreed to perform its future gas division impairment testing by using a grouping of strata by geographical regions (CONSOL Energy Inc. (June 8, 2012 and Sept. 10, 2012)).

The staff issued comments to one company that (i) recorded impairment charges of $12.3 million for fiscal 2012 due to a decrease in expected future natural gas prices with respect to its Midwestern proved properties, and (ii) reported a decrease in gas reserves by an amount equal to 31% of its total gas reserve quantities as of December 31, 2011. The staff requested clarification as to why the amount of the impairment charge taken was not larger when compared to the significance of the revisions and the cost bases for the properties, and why impairment was not also required for the related unproved properties and midstream assets (BreitBurn Energy Partners LP (Mar. 27, 2013)).

Comments regarding companies' goodwill and goodwill impairments increased during the 2012-13 review period. Where one company had recognized goodwill impairments of $1.7 billion and asset impairments of $1.0 billion for fiscal 2012, the staff asked the company to clearly disclose all of its asset groups that have undiscounted cash flows not substantially in excess of their carrying values (referred to as "at-risk" asset groups), including the net book value of each of those asset groups (Alpha Natural Resources Inc. (May 7, 2013)). Where a company's method for assessing impairment of goodwill and other intangible assets did not appear to be consistent with applicable financial accounting guidance, the staff requested that the company either revise the disclosures or advise the staff of the company's rationale (Questar Corp. (Sept. 28, 2012)).

Finally, there were more comments in 2012-13 asking companies about financial disclosures in their filings and press releases that are not considered by the SEC to be appropriate measures of U.S. generally accepted accounting principles (GAAP). The SEC refers to these non-appropriate financial measures as "non-GAAP financial measures." Basically, a non-GAAP financial measure is a numerical measure of a company's historical or projected financial performance that excludes amounts that are included in the most directly comparable measure calculated in accordance with GAAP, or that includes amounts that are excluded from the most directly comparable measure calculated in accordance with GAAP. The SEC's principal concern is that non-GAAP financial measures, without further explanation, allow companies to independently decide what the best measure of their performance should be, and the investing public would be misled if companies presented only that figure.

During 2012-13, non-GAAP financial measures cited by the staff included terms such as "EBITDAX," "future cash flows before income tax," "field level segment operating earnings" and "PV 10." Any disclosure of non-GAAP financial measures triggers a requirement for the disclosing company to provide a statement or table that reconciles the non-GAAP measures to the most comparable GAAP measures in the relevant disclosures (Rex Energy Corp. (Jan. 17, 2013)). One company received comments that some non-GAAP measures it had used in its annual report, such as "Adjusted EBITDA" and "Adjusted net income," were inconsistent with similar terms used elsewhere in its annual report and, importantly, that there were no reconciliations to the most comparable measures under GAAP – such as net income or net income from continuing operations (Linn Energy LLC (June 4, 2012)). Another company had adjusted its EBITDA numbers to include net cash flows from certain properties (through negotiated purchase price adjustments) prior to its ownership of those properties. The staff directed the company to revise its presentation to eliminate those adjustments (BreitBurn Energy Partners LP (June 20, 2013)).

International operations disclosure

During 2012-13, many international oil and service companies received comments unique to their international operations and areas of interest. The staff paid special attention to operations associated with countries designated by the US State Department as "state sponsors of terrorism." For example, the staff requested from different companies (i) information about the materiality of a company's contacts with Iran, Syria and Sudan in quantitative terms and whether those contacts constituted a material investment risk for investors, and (ii) information on products, equipments and services the company had provided to Cuba, Syria, Iran and Sudan (Cameron International Corp. (Dec. 11, 2012)).

Many US companies with significant non-U.S. assets and substantial earnings generated from non-US sources received comments in 2012-13 regarding the cash and cash equivalents held by their non-US subsidiaries, and whether the companies would repatriate that cash to the US Comments requested companies to disclose the amounts of cash and cash equivalents on hand located outside the US, the availability of such cash for their US operations and its impact on their liquidity, their intention or need to repatriate the funds and the effects on their income tax liabilities upon repatriation (Tidewater Inc. (Mar. 13, 2012)). Another company that had made international sales and divestitures of its foreign assets was asked to describe the factors considered by its management in concluding not to repatriate the sales proceeds held by its foreign subsidiaries, and to outline its plans for the permanent reinvestment of those proceeds (Devon Energy Corp. (Dec. 13, 2012)). Where a company disclosed that it had repatriated non-US earnings during fiscal 2012, the staff asked the company to describe the nature of the non-US earnings that had been repatriated, identify the country from which the earnings had been repatriated, explain why management had decided to take this action during fiscal 2012 and inform the staff as to any specific investment plans that had supported its conclusions (National Oilwell Varco Inc. (June 11, 2013)).

Other topics

While many other subjects were addressed by the comments issued during the 2012-13 review period, the following developments were most noteworthy:

• Hydraulic Fracturing and Related Liabilities. For producers active in shale regions, there were numerous requests from the staff during the 2011-12 period for details about their hydraulic fracturing operations. Many companies received requests to provide the staff with comprehensive information about the locations of their acreage and the percentage of their total proved reserves attributed to areas where fracking was conducted. This included environmental concerns, associated anticipated costs and whether there had been incidents, citations or lawsuits relating to their fracking activities.Overall, however, the number of staff comments on hydraulic fracturing dwindled substantially in 2012-13. The relatively few comments on this topic asked companies for additional disclosures about material operational risks associated with their fracking activities. Other letters requested enhanced disclosures about the processes involved in companies' hydraulic fracturing activities (what they entailed, etc.), and additional risk-factor disclosure that addressed the associated operational and financial risks.
• Geographic regions, fields and the 15% rule. Regulation S-K requires separate disclosures of reserves and production for each country (and each field, for production) that contains 15% or more of a company's total proved reserves (unless disclosure is prohibited by the government of the country in which the reserves are located). Thus, where a company discloses that a particular field or basin contains 15% or more of the company's total proved reserves, the company is required to provide to the staff the three-year annual production totals for that field or basin. Disclosures limited to certain states for each of the prior three fiscal years do not, by themselves, suffice (US Energy Corp. (Dec. 20, 2012) and BreitBurn Energy Partners LP (Mar. 27, 2013)).

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