Oil and gas disclosure rules

PUDs attributable to locations more than one offset away

Disclosures of significant additions to companies' PUDs during the year continued to draw requests for expanded disclosures about those additions, particularly with regard to companies active in shale plays. Item 1202(a)(6) of Regulation S-K provides that (i) for an IPO, or (ii) whenever a company discloses material additions to its reserve estimates, the company must provide a general discussion of the technologies used to establish the appropriate level of certainty for its reserves. In 2013-14, this rule was particularly relevant for companies having reserves additions attributable to PUD locations that were more than one offset location away from a currently-producing well. Where one company disclosed that the significant additions to its reserves in 2012 were related to its drilling activity in the Dimrock field in Pennsylvania, the staff asked whether the additional reserves were supported by reliable technologies and whether they included locations that were more than one offset location from an existing producing well (Cabot Oil & Gas (Aug. 29, 2013)). In Halcon Resources (Dec. 30, 2013), the staff asked the company to quantify the total number of PUD locations and associated net reserves added during fiscal 2012 that were more than one offset away from an existing producing well, and whether any of the wells drilled to date that were more than one offset away from a producing well at the time of their drilling were later found not to be economically producible. In an IPO, the staff scrutinized how the company had attributed PUDs to its locations in the Marcellus Shale and requested additional information on its methodology used to establish reasonable certainty of economic producibilty at distances greater than a direct offset away from a producing well (Antero Resources (July 12 2013)).

Changes in proved reserves

One of the substantive areas that drew the most comments from the staff during the 2013-14 review period was disclosures of material changes from year to year in companies' proved reserves. FASB ASC 932-235-50-4 requires disclosure of the net quantities of a company's PDs and PUDs as of the beginning and end of each fiscal year. In addition, FASB ASC 932-235-50-5 requires a tabular presentation of the specific causes of the changes in net quantities of proved reserves during the year. Changes identified as resulting from specific causes must be disclosed separately, along with an appropriate explanation of significant changes. These specific causes are: (i) revisions of prior estimates; (ii) reserves added by improved recovery methods; (iii) purchases and sales of minerals in place; (iv) extensions and discoveries; (v) production and (vi) conversions to developed reserves (Sanchez Energy (Dec. 24, 2013); Lucas Energy (Mar. 18, 2014)).

The staff observed that it appeared a company had combined two specific causes of its changes in its proved reserves (i.e., an increase resulting from drilling and from reservoir performance) into one line item in the summary of changes (a "Revision in estimate"). The staff informed the company to disaggregate the single item and show separately the changes in reserves caused by each of the specific causal agents (Kosmos Energy (June 12, 2014)).

Additionally, Item 1203(b) of Regulation S-K requires disclosure of material changes in PUDs that occur during a year, including PUDs converted into PDs. The disclosures should be accompanied by a discussion of the investments and progress (including capital expenditures) made by the company during the year to convert its PUDs to PDs.

Revisions to prior reserve estimates were often the catalyst for comments. In many cases, the staff remarked that insufficient explanation had been given about companies' reasons for their revisions. If revisions had been disclosed as resulting from "well performance" issues, the staff asked for clarification to describe the reasons for the performance revisions; for example, were the revisions merely concentrated in just a few wells or else spread across all proved reserves (Southwestern Energy (Sept. 25, 2013))?

A company disclosed additions to its PUDs for fiscal 2012 partially as a result of restoring to PUD status certain of its reserves that had been previously downgraded to "probable" status due to the five-year rule (WPX Energy (Aug. 23, 2013)). In response to staff questions, including those about management's drilling plans, the company explained that the restoration of these reserves to PUD status was because of changes in its drilling plans and the passage of time. The staff then requested additional information describing the circumstances that had led to the initial reclassification of the reserves from PUDs to probable reserves, and an explanation of how those circumstances had later changed to the degree that it would warrant a finding to support their restoration to PUDs. Assuming that the reserves had been moved from PUD status to probable status in the prior period due to economic considerations, the staff asked for an explanation of how company management had concluded that as of year-end 2012, the expected rate of return for those reserves would be sufficient to restore them to PUDs. The staff also requested that the company discuss the proportion of the restored PUDs associated with locations scheduled to be drilled during 2013 that had actually been drilled during 2013 to the date of the company's response (WPX Energy (Dec. 3, 2013)).

Similarly, where a company reclassified certain reserves as PUDs that had previously been downgraded from PUDs to probable status due to a decline in natural gas prices, the staff requested the company to provide justification for its decision to upgrade, along with a development schedule and an investment plan for the next five years that addressed whether the company had the ability to complete its development plan at current costs (Matador Resources (Dec. 27, 2013)). The staff requested another company to provide it with a detailed explanation about its development plan, which would address the development rate assumptions it had considered in light of a deterioration in the economic environment, rig cancellations and ceiling test write-downs (Hyperdynamics (Feb. 7, 2014)).

Other reserves comments

Non-reserves resources. Under an instruction to Regulation S-K Item 1202, estimates of oil or gas resources other than reserves estimates, and any estimated values of those resources, may not be disclosed in any document publicly filed with the SEC unless that information is required to be disclosed in the document by foreign or state law. In Unit Corp. (Sept. 19, 2013), the staff asked the company to explain its basis for including disclosures of its net and gross quantities of potential reserves, citing the instruction. Another company owned properties in the Cook Inlet region of Alaska; the company referenced in its most recent annual report positive statements about the region from a publicly available report of the US Geologic Survey. The report included a 2011 Cook Inlet region assessment that attributed to the region "estimated mean undiscovered technically recoverable reserves of 599 million bbls of oil and 19 tcf of natural gas." The staff pointed out the instruction's general prohibition against disclosing resources other than reserves, and asked the company to remove the language from its filing (Miller Energy Resources (Feb. 21, 2014)).

Mineral interests. Where a company owned mineral interests covering substantial acreage in properties operated by a third party, the staff inquired the company about the PUDs booked with respect to that acreage and how the company could establish the reasonable certainty of the scheduled recovery of those PUDs, since the company had no control over the PUDs' development other than under any development provisions in the relevant lease agreement (Viper Energy Partners (May 22, 2014)).

Net profits interests and production payments. The 2013-14 review period featured comments about conveyances by companies of net profits interests (NPIs) and production payments, and whether they had continued to book proved reserves attributable to the interests that had been conveyed. In RSP Permian Inc. (Nov. 4, 2013), the staff asked the company whether any reserves attributed to certain NPIs that the company had conveyed to a third party in 2011 were included in its disclosed proved reserves estimates for year-end 2012 and at June 30, 2013. The company responded that it had correctly included in its estimates the net cash flows and reserves associated with the NPIs, because the total cumulative revenues credited to the NPIs had not yet exceeded the cumulative direct operating expenses and capital expenditures charged against the cumulative revenues.

In Endeavour International (Sept. 19, 2013), the staff noted the company's sale during 2013 of a monetary production payment for $107.5 million, and requested a detailed explanation of the transaction, including addressing whether the oil and gas quantities associated with the production payment would be included as part of the company's year-end 2013 disclosed proved reserves. The company replied that the transaction was classified as a monetary (and not volumetric) production payment. As such, the company's obligation under the production payment was to repay specified dollar amounts, and not to repay in a specified quantity of future production. Citing relevant accounting literature, the company asserted that all reserves estimates and production data with respect to the monetary production payment would be reported with those of the company; therefore, the associated oil and gas quantities would be included in its proved reserves disclosures at December 31, 2013.

Probable and possible reserves. Finally, there appeared to be more disclosures of estimated unproved reserves - probable and possible reserves − contained in filings for 2013-14. Where estimated unproved reserves disclosures appeared in filings, companies often failed to include disclosures of all matters required by Regulation S-K with respect to probable and possible reserves. Probable and possible reserve estimates disclosures must include much of the same categories of information as are applicable to proved reserves under Regulation S-K Item 1202. These requirements include summary tabular information showing both developed and undeveloped probable and possible reserves, categorized as either developed or undeveloped, classified by final product sold (oil, natural gas, NGLs, synthetic oil, etc.) and in the same geographic detail as is required for proved reserves. The staff noted one company's failure to disclose its probable and possible reserves as developed or undeveloped as required by Regulation S-K Item 1202(a) (Sanchez Energy (Dec. 24, 2013)).

Where companies disclose probable and possible reserves, Regulation S-K Item 1202 mandates that they also discuss the uncertainty related to estimates of probable and possible reserves (Antero Resources (Aug. 16, 2013)). The staff has stated, for example, that companies should address the degree of certainty regarding the underlying cash flows for probable and possible reserves (and their associated risks) and discuss the assumptions used by management in their calculation. Because the categories of proved, probable and possible reserves estimates each have different risk profiles due to the disparities in their respective levels of certainty, it is not appropriate for a company to add the individual categories together and then present the sum as one total reserves estimate (Dune Energy Inc. (Aug. 5, 2013 and Sept. 6, 2013)).

NGLs as separate product type

One of the most recurring comments since 2012 has been that companies should report their natural gas liquid (NGLs) reserves and production volumes separately from the reserves and prodfuction data of their other hydrocarbons. FASB ASC 932-235-50-4 provides that if a company's NGL reserve quantities are significant, then information regarding its NGL reserves must be disclosed separately and not aggregated with its crude oil quantities. Also, Regulation S-K Item 1202(a) requires disclosure of production volumes broken down by "final product sold" for each of the three prior fiscal years. Item 1204(b) mandates disclosure, broken down by geographical area, of (1) the average sales price per unit of oil, gas and other products produced and (2) the average production cost, not including ad valorem and severance taxes, per unit of production. The staff has made it very clear in its comments that it considers NGLs to be a "separate product type" for disclosure purposes given the generally wide price differentials between NGLs and crude oil.

Staff guidance as to whether NGL reserve quantities are "significant" is not clear (Southwestern Energy (July 10, 2014)). Companies contending that their NGL reserve quantities were not significant have generally lost their arguments (Enduro Royalty Trust (Dec. 30, 2013); Rex Energy (Dec. 30, 2013)). However, one company, contending that Regulation S-K Item 1202(a)(4) only requires separate disclosures of "material reserves" by product type, argued that its NGL reserves and production were not material. The company represented in its response that its NGLs represented only approximately 4% of its total estimated proved reserves, 7% of its total estimated liquid reserves, 3% of its total production and less than 2% of its total oil and gas revenues for fiscal 2012. The staff appeared to concede the point, although the company did confirm in its response that it would disclose separately information required for NGLs under Items 1202 and 1204 of Regulation S-K for any annual period after 2012 in which NGLs were material to its estimated proved reserves and/or production (EPL Oil & Gas (Dec. 19, 2013); response letter (Jan. 21, 2014)).

Under an instruction to Regulation S-K Item 1204, reported volumes of natural gas produced should include only the marketable production of natural gas on an "as sold" basis, and gas consumed in operations should be omitted from the production quantities. Thus, where a wide difference existed between a company's disclosed historical average natural gas price ($3.67/Mcfg) and its gas price used for purposes of its proved reserves determination ($5.03/Mcfg), the staff inquired whether ethane rejection by the gas processor had produced any significant effect that resulted in such a variance (Viper Energy Partners (March 21, 2014)).

About the author

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.