Valuation of Non-U.S. Oil and Gas Properties
Authors: Gustavson J.B. 
Published: June 2014

This paper (SPE 60223) was revised for publication from paper 52957, originally presented at the 1999 SPE Hydrocarbon Economics and Evaluation Symposium held in Dallas, 20–23 March. Original manuscript received 1 February 1999. This paper has not been peer reviewed.

Valuation of non-U.S. concessions, prospects, and producing fields varies greatly from country to country because of differences in fiscal and political regimes and therefore must include quantified adjustments for these differences in the light of comparative modes of sale of other non-U.S. properties. The market for acquisitions and divestitures works by also applying such adjustments to the values derived for U.S. analogs with comparable geological, engineering, and economic risks. This paper discusses the primary types of fiscal regimes found around the world, namely, licenses with royalties and taxes, association agreements, and production-sharing contracts (PSC's). We show that discounted-cash-flow (DCF) models are readily applicable to proved reserves and present a review of a recent market transaction to demonstrate these effects. Political risk in the non-U.S. market is shown to be additive.

Introduction

For most of the 20th Century, non-U.S. oil business was the exclusive domain of industry majors. Over the last few decades, however, numerous small companies and independents have become increasingly global, which, in turn, increases the need to understand the approaches to valuing their non-U.S. properties.

Takings or expropriations are experienced where values may need to be estimated by courts or tribunals. Other instances requiring a valuation include potentially taxable transactions, such as transferring an oil or gas property across country boundaries. Sales transactions frequently take place between apparently willing and knowledgeable buyers and sellers, so the concept of fair market value should apply.

This all sounds familiar to the U.S. oilman, banker, or tax agent. However, can the same approaches to estimates of fair market value be used globally? Are there differences or pitfalls that would be important to consider when appraising non-U.S. properties? This paper shows that a resounding "yes" is the answer to both questions. It also highlights some of our own experiences in the non-U.S. appraisal arena.

U.S. Approaches

Numerous presentations have been made on the merits of conventional approaches, such as the DCF methods and comparable sales with various unit values. In addition, cost methods have seen use, particularly in the downstream sector. This paper examines the ease or difficulty with which these familiar methods can be applied worldwide. A brief review of the most common U.S. method, the DCF approach is presented first, followed by an alternative interpretation of the discount rate applied by the market.

DCF Approach.

The DCF method is best applied to producing properties or to properties where the outlook for an income stream in the near future is likely and not speculative. Simplistically, the multistep approach of valuation consists of an annual forecast of oil and gas production volumes times a prediction of prices less an estimate of operating costs. After other, but minor, adjustments, this future cash flow is discounted for both time value of money and the perceived probability of achieving exactly the predicted cash flow. Miller and Vasquez1 present arguments for their observed 6 to 8% excess of the average market discount rate over the average cost of capital. The excess is sometimes considered equivalent to growth motive, offsetting the "risk" of the oil business. It reflects the desire on the part of owners or management to make a rate of return better than the company's weighted average cost of capital (WACC). Can this 6 to 8% excess be dissected further, and can it be quantified? Most importantly, can such an understanding improve the selection of discount rates to be applied in the valuation of non-U.S. properties?

Key Variables.

We examine the oil operating company's perception of the probability that it will actually receive the predicted cash flow when purchasing a producing property. If the company were 100% sure of the cash flow as predicted by the reserve engineer, it might pay close to its cost of capital. Conversely, if an operating company were uncertain, it would pay less and target a higher rate of return.

Prediction of the DCF rate of return is based on four major parameters: production quantities, oil prices, operating costs, and discount rate. Production quantities may vary from the petroleum engineer's predictions, oil prices will fluctuate, and operating costs may likewise turn out differently than forecast. In addition, the discount rate generally used to reflect time value of money—namely, the weighted average cost of capital (WACC) for the E&P industry sector—varies with the country's economy. U.S. appraisal experience and literature provide a framework for estimates of these four parameters.

Quantity, Price, and Operating Cost.

The first three parameters have been used for prediction for almost 5 decades and applied in DCF forecasts for valuation of oil and gas properties.