Since August 2014, the price of crude oil, West Texas Intermediate (WTI) and Brent, has fallen precipitously. The reason for the decline has been debated by energy analysts from around the world; ranging from global politics to supply and demand issues. While the price of natural gas (Henry Hub) experienced some volatility in the first quarter of 2014, it remained relatively stable for most of the year before declining during the last few months of 2014. Whatever the reason for the decline, at the close of 2014 many exploration and production (E&P) companies and analysts alike were assessing the market value of reserves held. When assessing the value of reserves, a distinction must be made between the SEC reported value in the notes to the publicly traded companies’ Form 10-Ks and the Fair Market Value of such reserves.
The methodology and underlying reasoning used to value reserves may differ depending on the purpose of the valuation. For instance, the determination of Fair Value used in a purchase price accounting allocation is based on the concept of what market participants would expect to receive in order to sell the business or assets. Assumptions for capital structure, tax rates, and synergies (such as cost savings) are based on circumstances for a typical market participant. Conversely, a valuation performed in support of a merger or sale depending on its purpose, could assume a unique buyer with a specific capital structure, tax rate, and synergies. Where valuations are performed for tax purposes under the U.S. Internal Revenue Code, the term “Fair Market Value” is used.
The SEC Reported Value
The Securities and Exchange Commission (SEC) reported value is known as “PV-10”. Under PV-10, the value of reserves is defined as the present value of the estimated future oil and gas revenues, reduced by direct expenses and discounted at an annual rate of 10%. Both the pricing of future oil and natural gas, and the discount rate is standardized under this method. PV-10 is the indicated value of a company’s oil and gas reserves for disclosure in filings with the SEC. The purpose of such disclosure is to assist users of oil and gas companies’ financial statements in determining the overall financial position of the company as well as to assess the risks that may affect the issuer’s future financial position. While the SEC’s overall goal in requiring registrants to use this standardized metric was to make amounts reported by companies comparable, it can be misinterpreted as a measure of the Fair Market Value of E&P companies’ proved oil and gas reserves. Valuation experts do not believe that PV-10 necessarily represents the Fair Market Value of a company’s oil and gas reserves.
FASB Accounting Standards Codification (ASC) 932 requires disclosure of a standardized measure of discounted future cash flows relating to proved oil and gas reserves quantities for public companies. This is sometimes referred to as the standardized measure of oil and gas, or SMOG. The standardized measure of discounted future net cash flows from production of proved reserves are developed as follows:
1I Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced. These estimates are normally done by petroleum engineers based on the SEC Final Rule (as described below).
2I The estimated future cash flows are compiled by applying prices, based the SEC Final Rule, to the year-end quantities of reserves of oil and natural gas.
3I The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves, and abandonment costs, all based on year-end economic conditions.
4I Future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits, and allowances related to the company’s proved oil and natural gas reserves.
5I Future net cash flows are discounted to present value by applying a discount rate of 10% (as described earlier).
The SEC Final Rule—Modernization of Oil and Gas Reporting
For publicly traded U.S. E&P companies, oil and gas reserves reported in the notes to their annual reports filed with the SEC are determined by the “SEC Final Rule”.
On December 31, 2008, the SEC issued a final rule revising disclosure requirements relating to oil and gas reserves. The SEC Final Rule reflects the SEC’s consideration of comments received from various stakeholders in the oil and gas industry. The amendments were intended to modernize and update oil and gas disclosure requirements to align them with current industry practices and to adapt to changes in technology.1 According to the SEC, these revisions were intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves and to facilitate comparisons between companies.
Among other changes, the SEC Final Rule requires companies to estimate proved reserves using oil and natural gas prices based on the 12-month historical average of the beginning-of-month prices. Prior to the 2008 ruling the SEC rules required that a single-day, fiscal year-end spot price be used to determine economic producibility and future cash flows of oil and gas reserves. The SEC Final Rule changed this requirement to a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.2
The SEC Final Rule defines the term “proved oil and gas reserves” as “those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.”3
For simplicity, let’s focus only on oil reserves in this analysis. Before 2014, oil prices had remained relatively strong since 2011 with the beginning-of-the-month WTI spot prices averaging $96.04, $95.05, and $96.78 per barrel in 2011, 2012, and 2013, respectively. Under the SEC Final Rule, and assuming no adjustment for quality, energy content, transportation fees, or regional price differentials, the value of reserves at year-end 2014 was based on a price of $94.42 per barrel, the 12-month beginning-of-the-month average for 2014. Compare this to the closing price at December 31, 2014, of $53.27 per barrel, and it is clear to see that the SEC Final Rule does not always reflect market prices at a particular point in time.
Forward Prices vs. SEC Final Rule
A more realistic way of estimating reserves, which is more commonly used in the industry and by valuation experts, is an analysis based on oil and gas future prices. Oil and gas futures prices, or management’s forecast of future prices, better represent the value of the reserves and would be better aligned with the Fair Market Value of the reserves, as historical prices have little to do with a company’s future investments and values.4 Additionally, the use of futures price estimates should be accompanied by estimates of future costs, which can be subjective and not always comparable for determining future economic conditions. The chart below shows the 5-year forward curve for oil and natural gas as of December 31, 2014.
If the average five-year futures price at the end of 2014 was used, oil reserves would be reported based on a price of $64.97 per barrel. Comparing this price to the SEC requirements shows a difference in oil pricing of approximately 31%, assuming no adjustment for quality, energy content, transportation fees, or regional price differentials. Reserve values would actually decline by more due to the cost structure of the portfolio of reserves.
The implication of this is that depending on the characteristics of a portfolio of reserves, an oil well may be economically producible at $94.42 per barrel but not at $64.97. This is because as an oil well produces, it gets closer and closer to its economic limit (where the operating cost of the well equals the revenue). At a price of $64.97 per barrel a producing oil well would reach its economic limit much faster than it would at $94.42 per barrel. Additionally, for undeveloped locations, at a price of $64.97 per barrel an oil well may not be economically viable whereas at $94.42 per barrel it might be. As a result, reserves that would be reported or booked (captured by reserve engineering) at a price of $94.42 per barrel would not be booked at $64.97 per barrel, because they would not be economically producible. This would indicate that the reserves reported in SEC filings may not represent the true economic value or quantities of a given portfolio of reserves.
Fair Market Value
One way to estimate the Fair Market Value of oil and gas reserves, is to utilize certain risk-adjusted rates of return, commonly applied by buyers in the acquisition and divesture marketplace, to convert reserve reports into Fair Market Value amounts. This method can be seen as a form of the Income Approach but valuation experts often use multiple methods to value oil and gas reserves.
A reserve report is prepared by petroleum engineers and estimates the remaining quantities of oil and gas (reserves) expected to be recovered from existing properties. Reserve reports provide information regarding the expected future pre-tax net cash flows that would be produced from the various categories of reserves. Valuation experts generally utilize reserve reports based on New York Mercantile Exchange (NYMEX) futures prices in effect as of the valuation date through some date in the future. These prices are usually adjusted for regional and quality differentials, based on actual prices received as compared to NYMEX benchmarks.
In estimating reserves, petroleum engineers classify reserves as proved, probable, or possible. The Society of Petroleum Engineers establishes standards for each category. The category of proved reserves, occasionally called 1P reserves, is generally broken down, at a minimum, into three subcategories:
Other reserve categories include probable and possible reserves. 2P reserves are the sum of proved and probable while 3P reserves are the sum of proved, probable, and possible.
More specifically, in order to calculate the Fair Market Value of reserves, valuation experts generally applies different discount rates to each stream of Cash Flow (PDPs, PDNPs, PUDs, Probable and Possible) based on the relative riskiness of each category. It should be noted that very few publicly traded companies report probable or possible reserves (although companies in unconventional plays frequently discuss drilling location counts over and above PUD locations).To estimate the Fair Market Value of reserves, valuation experts consider these reserves categories under appropriate circumstances and facts but apply higher risk adjusted rates of return than those used for proved properties.
The decline in oil prices in late 2014 has rattled the oil and gas industry as a whole and will probably suppress exploration in the near term. Therefore, with this radical decline in prices in latter part of 2014, as of December 31, 2014 the reserve values and quantities reported on E&P companies’ SEC Form 10-Ks or other reports may not represent the Fair Market Value.
1 SEC Modernization of Oil and Gas Reporting Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08.