Reserves disclosures must balance formality with natural complexity

Surprise cuts to hydrocarbon reserves reported by large, publicly traded oil and gas producers draw new attention to an old challenge: reconciling natural complexity with accounting's formality.

The changes also underscore the powerful financial implications of reserves disclosures.

Stock markets punished Royal Dutch/Shell Group after the company on Jan. 9 announced it was reducing its estimate of oil and gas reserves by 20%. El Paso Corp. came in for similar treatment after it announced on Feb. 17 a negative reserves adjustment amounting to 41%.

American depositary receipts (ADRs) of Royal Dutch Petroleum Co. slumped 11% on the New York Stock Exchange after the adjustment. ADRs of Shell Transport & Trading Co. PLC fell 13%. El Paso's share price on the NYSE appeared, at this writing, to have steadied at about 11% below its level before the reserves announcement.

Obviously and with good reason, market values of oil and gas companies strongly reflect the reserves evaluations attached to financial reports. Reserves indicate both past exploratory success and potential revenue from future production.

Imbedded in reserves disclosures, however, is a large and inescapable margin of error that frustrates correlation with dollar values. The financial values attached to reserves disclosures—based on discounted future net cash flow—can imply a degree of precision unattainable in the calculations, beginning with volumetric estimates of recoverable oil and gas.

A parallel difficulty arises because reserves estimates for specific companies change frequently as, for example, oil and gas prices change and as companies gain knowledge about geology and subsurface dynamics of their discoveries through drilling, geophysical surveys, and production. Adjustments are not unusual.

Extraordinary adjustments

The Shell and El Paso changes, however, far exceed sizes that the Securities and Exchange Commission, which oversees reserves disclosures, considers ordinary.

Statutes specify no margin of tolerance for adjustments. But at a forum last October of the Society of Petroleum Evaluation Engineers, SEC engineer Jim Murphy said a 10% difference between originally reported reserves and estimates after revisions is enough to raise alarm. Indeed, Shell reported on Feb. 19 that the SEC had notified it of a formal investigation into its big reserves change.

Whether the Shell and El Paso adjustments represent isolated episodes or the beginning of a trend remains to be seen. After the 2002 Sarbanes-Oxley Act's crackdown on corporate governance, hard looks by managers and investors at an inherently hazy area of financial reporting are natural. So may be calls on the SEC to make reserves disclosures less hazy to begin with.

Yet a regulatory fix that helps more than hurts may be easier to request than to deliver. Clear as it is that markets calibrate expectations about the financial performances of oil and gas producers to reserves reports, the nature of reserves assessment confounds the exercise.

Unlike revenues and expenses, reserves values aren't measurements; they're estimates. They depend heavily on interpretation of data collected at often widely dispersed points in natural systems that are complex, irregularly distributed in the subsurface, and fluid. To make matters worse, the estimates depend partly on notoriously changeable prices of oil and natural gas.

These difficulties have long bedeviled regulation of reserves disclosures in the US. They're major reasons the disclosures appear in isolated sections of company financial reports. The history of reserves regulation and a review of current controversies about them show the extent to which reserves data can help with—and help confuse—company evaluations.

Two methods

The SEC's current prescription for reserves disclosures evolved during debate in the 1960s and 1970s over two accounting methods used by oil and gas producers. At first, attempts to reconcile differences between full-cost (FC) and successful-efforts (SE) accounting didn't involve reserves. But that would quickly change.

One of two main differences between the methods is their treatment of the costs of unsuccessful exploratory wells. Under the SE method, a company charges exploratory dry-hole costs to expense in the accounting period during which a well is determined to be unsuccessful. An FC company includes such costs, along with others associated with exploration, in an asset account and writes them down over a number of years.

The other main difference between the accounting methods is the assignment of cost centers. SE companies bundle costs around specific wells or leases. Cost centers for FC companies are whole companies or, for international operators, countries.

Until 1957, when the former Belco Petroleum Co. began using the full-cost method in anticipation of an initial public offering of stock, all producers used SE accounting. The FC method came into favor, especially with young, small companies needing to raise capital, because it stabilized earnings over multiple periods and enabled small firms to expand reported assets rapidly by drilling.

By the late 1960s, about half of all US producers used FC accounting. The FC share is much smaller now, confined mainly to small companies specializing in production.

El Paso, a large, diverse company using the FC method for its production activities, is an interesting exception. Under a ceiling test required of FC companies, El Paso had to take a $1 billion charge against fourth-quarter earnings when it cut its reserves on Feb. 17. SE companies, because they carry comparatively lower reserves-related assets on their balance sheets, usually don't face cuts that drastic when they lower reserves estimates. Shell, an SE company, thus took an $86 million charge for an energy-equivalent reserves cut four times as large as El Paso's.

In fact, many FC companies switched to SE accounting after plummeting crude oil prices in the late 1980s forced them to slash reserves estimates and report huge impairments to earnings.

Long dispute

Each accounting method has sound arguments on its behalf. But the duality frustrates financial comparison of SE with FC companies. It's been subject to dispute at least since 1964, when the American Institute of Certified Public Accountants commissioned Accounting Research Study (ARS) No. 11, which in 1969 recommended the SE method for all producers.

But FC accounting wasn't ready to die. Aspects of the method received support from the Accounting Principles Board (APB) and the old Federal Power Commission, which in 1971 required FC accounting for producers of natural gas.

The debate gained an important dimension in 1974, when a committee of oil and gas companies asserted that FC accounting best served the needs of financial decision-makers when combined with information about reserves. And it gained urgency in 1975, when a section of the Energy Policy and Conservation Act, passed in response to the Arab oil embargo of 1973-74, directed the SEC to resolve the differences by rule or to make clear its reliance on findings of the Financial Accounting Standards Board (FASB).

Even with that statutory pressure, the issue took years to settle. The FASB, successor to the APB, in December 1977 issued Financial Accounting Standard (FAS) 19 requiring use of the SE method and, for the first time, disclosure of reserves estimates.

FC accounting still didn't die.

The following August, the SEC's Accounting Series Release (ASR) 253 permitted use of either of the accounting methods. But the SEC adopted the FAS 19 requirement for reserves disclosure with Release 33-5969, calling for a 3-year experiment with something called reserves recognition accounting (RRA). In February 1979, the FASB, with FAS 25, rescinded its ban on FC accounting.

RRA required companies to report in unaudited areas of financial reports their volumetric estimates of oil and gas reserves along with estimates of values of those reserves.

As an effort to replace disparate accounting methods based on historic costs with a single, value-based approach, RRA failed. In February 1981, the SEC issued ASR 289 disallowing RRA in primary financial statements. Reserves data, it decided, were too changeable and too subject to interpretation for full integration into basic financial reports.

Acknowledging the importance of reserves information to investors, however, the SEC called on the FASB to establish requirements for reserves in discrete sections of oil and gas company financial statements. FASB complied in November 1982 with FAS 69. Requirements and definitions outlined there form the basis of SEC Regulation S-X, Section 210.4-10, governing reserves disclosures today.

Important features of the requirements are reliance on estimates only of proved reserves and standard estimates of discounted future net cash flows based on production forecasts, current oil and gas prices, and a 10% discount factor.

Reserves and accounting

Recognition of the importance of reserves data to the financial evaluation of oil and gas producers thus emerged from an unsuccessful struggle to unify accounting methods. But along with it came the question of compatibility of reserves estimates with basic financial metrics.

The FASB clearly defined the issue and took a strong position on it in an appendix to FAS 19:

"The board does not agree with the view, expressed by some, that mineral reserve information is not accounting information and, if disclosed at all, should not be included in financial statements. Those who take that position argue that while reserve information may indeed be important, it is too subjective, too frequently revised, too unreliable, too 'soft' to be reported in financial statements. In the board's judgment, however, certain reserve information has the qualities of verifiability, reliability, freedom from bias, comparability, and the like to a sufficiently reasonable degree to warrant its inclusion in financial statements."

By disallowing RRA as a replacement for SE and FC accounting after 3 years of experimentation, of course, the SEC rejected the FAS 19 view. The format of the current requirement, with reserves disclosures separate from basic financial reports, represents a compromise acknowledging both the importance and the imprecision of the data.

The FASB, moreover, felt obliged in FAS 69 to issue a warning to users about the method it selected for translating estimated reserves volumes into dollar evaluations. In an explanation of its decision to adopt a standardized measure of discounted net cash flows based on current prices, it wrote: "The board is concernedUthat users of financial statements understand that [the standardized measure] is neither fair market value nor the present value of future cash flows. It is a rough surrogate for such measures, a tool to allow for a reasonable comparison of mineral reserves and changes through the use of a standardized method that recognizes qualitative, quantitative, geographic, and temporal characteristics. Absent such a tool, there is no reasonable basis for comparing these most important assets and activities; values are not determinable, and quantities are not comparable. In addition, the standardized measure provides users with a common base upon which they can prepare their own estimates of future cash flows."

Now, therefore, the FASB and SEC deal with the problems of reserves assessment by concentrating on proved reserves—the category with the least degree of uncertainty—and requiring that all companies follow the same formula for deriving financial values. They in effect provide analysts a carefully crafted lens through which to examine reserves data. But they rely on people using the lens to understand that the requirements of standardization distort the view, that the underlying data remain plagued by variability, and that any effort to increase precision means ignoring information—such as reserves other than "proved," strictly defined—that may have value.

Current issues

It was largely the regulatory focus on proved reserves, for example, that led to Shell's big adjustment in January, which the company called a "recategorization" affecting a total of 3.9 billion boe. It moved 400 million boe from the proved to probable category and 3.5 billion boe from proved to a category for discoveries under appraisal called "scope for recovery" (see figure).