Lacking full comprehension of the implications behind assumptions applied in reserves valuations can result in sub-optimal decision-making for lenders and shareholders alike. Learn the factors necessary for an objective evaluation of oil & gas properties.
Valuing O&G properties requires a specialized skill set, including precise knowledge of ad valorem, severance, federal taxes, special treatment for intangible drilling and development costs, political and property-specific risks and more. Often, exploration and production (E&P) companies employ their own professionals to value reserves. But in certain circumstances — such as the valuation of complicated corporate transactions and complex properties — companies may be wiser to consider an independent appraiser who specializes in the field.
Here’s a bit of insight into the key factors for valuing oil and gas properties:
Pricing and differentials
E&P companies, because they operate within a commodity business, can’t control the prices they receive. Market supply and demand dictates what producers will earn when selling their products.
Considering expected future prices, commonly known as a price deck, is critical to developing cash-flow forecasts specific to O&G properties. The two common practices in selecting a price deck for commodities include the NYMEX futures curve and estimated normalized pricing, based on various published estimates.
The primary advantage of utilizing the futures curve at the date of valuation includes its objectivity since the curve represents the expectations of market participants at a given point in time. However, applying this approach presents certain drawbacks, including the potential for overreactions to political or economic events, and the failure to adopt a long-term pricing perspective.
In general, the futures curve only provides a reliable indicator of market-participant expectations during the first five years beyond the valuation date, due to limited trading activity during the latter years of the curve. For longer-term pricing perspectives, the most common method of estimating prices includes adding an inflation factor to the fifth-year estimated futures price for the sixth and subsequent years of the cash-flow forecast.
An alternative approach — developing pricing forecasts by considering published, third-party estimates — offers certain advantages, such as eliminating the emotion often associated with the futures curve and ready acceptance by major E&P companies. However, a limited number of third-party sources publish pricing forecasts beyond a two- to three-year time frame, leaving an analyst to apply judgment to produce subsequent years for the long-term forecast. In addition, dated third-party sources of pricing forecasts can be of limited use during a period of rapidly changing prices.
Regardless of the method for developing a price deck, differentials are commonly applied. A price differential represents the difference between published market prices and the price actually received when a producer sells a commodity. In practice, realized prices for a commodity often differ from posted prices due to quality, transportation, proximity to market and more. Depending on the nature of these factors, differentials can be positive or negative.
Essentially, applying a risk-adjustment factor reduces a property’s volumes or cash flows to capture uncertainties linked with realizing less-than-proved reserve categories. As reserve reports for O&G properties commonly reflect gross-production volumes, it’s typical to apply adjustments based on the degree of certainty.
The Society of Petroleum Evaluation Engineers (SPEE) publishes an annual survey to obtain opinions from U.S. and Canadian analysts regarding many parameters used to evaluate O&G properties, one of which includes adjustment factors applied against various reserve categories. The most recent survey, published in June 2014, indicate analysts commonly apply adjustment factors ranging from 80- to 100-percent good (0- to 20-percent discount) for proved reserves, 50-percent good for probable reserves, and 10-percent good (90-percent discount) for possible reserves.
For properties where a risk-adjustment factor is applied, practitioners commonly use a uniform discount rate to these risk-adjusted volumes or cash flows. For valuations that don’t apply a risk-adjustment factor, the uncertainties associated with realizing less-than-proved reserve categories are best captured by using a premium to the initially calculated discount rate.
As outlined in the June 2014 SPEE survey, applied O&G discount rates, in practice, range from 4.96 percent to 29.24 percent, with an average of 17.1 percent. Similarly, the 2014 Property Value Study published by the Texas Comptroller of Public Accounts concludes reasonable discount rates for E&P properties ranging from 17.09 percent to 24.66 percent. Regardless of the specific source, the discount-rate development methodology should consider the inherent industry risks, as well as the specific risks associated with the unique property valued.
While reserve reports consider severance and ad valorem taxes, petroleum-engineering firm reports typically present the annual cash flows of an O&G property on a pretax basis. Therefore, the analysis of O&G properties should include appropriate adjustments for the relevant tax regime in which each property is located.
In certain countries, various forms of government taxation, or government take, can represent more than 90 percent of profits. However, in the U.S. and Canada, government take for oil-producing properties averaged 51 percent and 54 percent, respectively, according to recent editions of OECD Economic Surveys.
Intangible drilling costs represent one specialized area of the U.S. tax code, designed to encourage investment in O&G properties. Specifically, an investor in an O&G property can write off intangible drilling costs as a current business expense, rather than capitalizing them, provided the costs meet qualifying criteria.
*original post appeared on an M&A forum