Economic Analysis of Exploration Ventures

Published:January 01, 2001
Abstract
It is essential for geoscientists to understand how the results of their technical work are used in estimating the economic value of the ventures in which they have been involved. Otherwise, they may invite incorrect use or manipulation of their professional geotechnical product. This understanding requires that they have a good working knowledge of economics and finance integrated into their geotechnical expertise.
introduction
It is essential for geoscientists to understand how the results of their technical work are used in estimating the economic value of the ventures in which they have been involved. Otherwise, they may invite incorrect use or manipulation of their professional geotechnical product. This understanding requires that they have a good working knowledge of economics and finance integrated into their geotechnical expertise.
Time Value of Money and Discount Rates
Corporations invest in petroleum exploration ventures, anticipating receipt of a series of future annual cash flows from production revenues (Megill, 1988). To assess the value of such future cash flows requires understanding of the time value of money, especially the concepts of future value, compounding, present value, and discounting.
Discounting is “compounding in reverse.” The discount rate has one use and one use only: to express the time value of money. Arbitrarily elevated discount rates are not useful screening measures nor are they a proxy for risk.
The discount rate selected by the firm should be consistent among all classes of ventures (“it's all the same money”), and it should reflect the firm's average weighted cost of capital. Part of that cost of capital consists of interest on bank loans, part is the return realized by corporate investors as dividends and stock appreciation. As an alternative to the costofcapital approach, some authorities believe that the chosen discount rate should approximate the firm's actual longterm average annual rate of return—the “corporate reinvestment rate” (Capen, 1995).
When companies deliberately choose a high discount rate—one substantially higher than their cost of capital (or average reinvestment rate), they in effect select against longterm projects (which are typically associated with largereserve opportunities) by assigning little or no value to cash flows beyond about 15 years. Instead, shortterm projects are preferentially introduced into the portfolio, projects with high earning rates, but short lives, which are difficult to replace. On the other hand, choosing a low discount rate results in portfolios containing longterm, largereserve projects. Even though they may create large values, such projects may depress the overall present value of the portfolio somewhat, although not as much as the shortterm projects will (Capen, 1984). The selection of a discount rate that is too low is not as detrimental to portfolio value as the selection of a discount rate that is too high.
Exploration Cashflow Models and Discounted Cashflow Analysis
The cashflow model of a proposed exploration venture is a quantified scenario for the exploration, discovery, development, and producing life of an oil or natural gas field.^{5} It models the complex cash flows involved in a successful venture. The cashflow model assumes success. This scenario must be geologically reasonable using the meanreserves case and compatible values for perwell ultimate production: initial production rates; percentage decline rates; numbers of wells; costs for exploration, development, and well operations; taxes and tax provisions; wellhead prices; field life; salvage costs; and expected contract terms. To have meaning, the cashflow model must be based on actual geotechnical estimates of ultimately recoverable reserves, field area, numbers and depths of wells, and existing surface conditions. This model should not be unduly optimistic (in order to sell it to management) or unduly pessimistic (in order not to be wrong). The responsible geoscientist/prospector should strive for objective realism, recognizing that unbiased geotechnical predictions are a professional goal.
As previously stated (p. 24), discounted cashflow (DCF) models for most prospects should also be run on the P10%, P50%, and P90% reserves cases, with the goal of generating a probabilistic distribution of net present values (NPV) for the venture. In other words (because NPV/BOE may vary with reserve sizes), we want to determine the mean of all NPV outcomes rather than the NPV of only the meanreserves outcome. Naturally, geologic and engineering parameters such as area, well numbers, net pay thickness, HCrecovery, reserves, well initial production (IPs), and field life must be compatible with the corresponding P10%, P50%, and P90% reserves cases. ^{6} The key result from the cashflow model is the discounted cumulative net cash flow (= “present value” or “present worth”) over the projected life of the field.
Exploration costs and development costs constitute the net investment cashflow stream (Megill, 1988); analysts are encouraged to calculate these costs on an aftertax basis, taking depreciation and investment tax credits into account. The net income cashflow stream (also on an aftertax basis) is influenced by production revenues (declining), net revenue interest, wellhead taxes, operating costs, and income tax provisions. For productionsharing contracts, further modification may be required to correctly provide for the state's share of production revenues, cost recovery, and special tax provisions. For each year, the difference between aftertax investment cash flow and aftertax income cash flow is annual aftertax net cash flow. Ordinarily, annual net cash flows are negative in the first years of a project and positive in middle and later years when the field is fully developed and wells are in their producing (but declining) lives. Sometimes a project may anticipate a second stage of investment in a field's midlife to install an enhanced oil recovery (EOR) program or additional infill drilling. By adding all the annual aftertax net cash flows for the life of the field, we derive the field's cumulative aftertax net cash flow (CNCF).
Annual net cash flows are discounted using the appropriate annual presentvalue factor for the selected discount rate (Table 10). By adding them for the period of the cashflow model, we derive the key value of the cashflow analysis: the cumulative net present value (= NPV), which is the sum of the discounted annual net cash flows for the project, using the appropriate annual presentvalue factor for years hence and the selected discount rate. This is, in essence, an aftertax profit number, incorporating investments, costs, taxes, wellhead revenues, production decline rates, operating costs, and the time value of money.
The cumulative NPV for any proposed prospect thus represents the venture compared against the perspective of the firm's present performance, i.e., How much better is this project than our present performance (or average weighted cost of capital)?
Problems with DCF Valuation of Exploratory Ventures
For more than 50 years, the petroleum industry has routinely used DCF analysis to value producing properties and exploratory ventures. One difficulty with the procedure has been that deterministic values were used, even for parameters that were known to be highly uncertain. Multiple runs using different values for some parameters gave a spread or range of possible outcomes; this process has been called “sensitivity analysis.” But no probabilistic values could be assigned to the ranges. Software addins, especially Lotus® with @Risk®, or Excel® with Crystal Ball®, utilizing Monte Carlo or Latin Hypercube simulation, now allow probabilistic expression of such parameters so that the cumulative NPV can be expressed as a probability distribution. Even so, most firms at yearend 1999 still utilized multiple runs of deterministic cashflow models.
Another problem is that each cashflow model represents only one sequence of events from project inception to abandonment, often spanning 30 years or more. It is not possible to build into one cashflow model the possibility of several alternative scenarios that might develop during the life of the field. This difficulty can now be partially addressed through a combination of “segmented” cashflow models and decisiontree analysis.
But the most fundamental difficulty with DCF analysis of exploration ventures is that the observed business behavior of most major companies indicates that they place much more intrinsic value on largereserve, longterm prospects than is consistent with their DCF valuation of such projects (Boccia, 1996). The reason, of course, has to do mostly with discounting: using prevalent discount rates of 10% to 12%, PVs of annual production cash flows beyond the first 15 or 20 years of a project's life are reduced to practically zero. But most companies specifically seek large new fields having longterm, stable production potential—just the kinds of fields that build companies and provide steady, reliable, lowcost production revenue streams for many years. Yet these are the kinds of longterm, steady cash flows whose value beyond about 20 years is shown to be nearly zero by conventional DCF analysis!
One solution to this difficulty has been to employ artificially reduced discount rates when evaluating such opportunities. Of course, the choice of the proper low discount rate is arbitrary. A better approach would be to run all DCF analyses for all candidate projects in the inventory at a low discount rate that represents the fundamental interest for the “hire of the money”—perhaps 4% to 5%—one that does not include any provision for inflation of costs or prices. By using the current mean of “real” historical oil prices, the company could compare all projects for its portfolio and rank them on that basis. This would be internally consistent, reducing the negative effect that discounting has on longterm cash flows and eliminating the possibility that some projects could be made to appear more attractive through biased selection of elevated priceescalation schedules. Use of the historical mean of real oil prices (corrected to present day for inflation) recognizes the long life of most large oil and gas fields and tends to correct for shortterm price influences. Such a simplified procedure would likely optimize the ranking of projects and would select for growth.
But the most promising solution to “the DCF problem” lies in adoption of an alternate method of valuing exploration ventures: Optionpricing Theory.
Optionpricing Theory and Valuation of Exploration Ventures
The sequence of characteristic business decisions that attend discovery, development, and operation of large oil and gas fields represents classic option behavior (Figure 24). Companies acquire leases or contract areas, then invest in additional geotechnical data to refine their risk/reward perception—which, if encouraging, leads them to exploratory drilling. If drilling is successful, the company confirms and delineates the discovered field, which, if it is judged to be economic, the company then develops and produces. Enhanced recovery projects may be added during the field's producing life, followed by abandonment when production revenues decline below operating costs. Depending on the prevailing economics, technologic developments, political trends, and contract terms, the company may choose at various decision points to invest further, to defer action, to sell part or all of their interest, or to abandon the venture. Each stage in the venture thus represents an option.
The BlackScholes model (Brealey and Myers, 1988; Bernstein, 1996) for valuing a stock option depends on four parameters: time, price differential between current price and strike price, interest rates, and variance of price. But there are four important differences between options in the stock market or commodities market and options in the oil business.
When a stock option is exercised the benefit is realized immediately, but when an oil company exercises its option by developing a property or installing new EOR procedures in an existing field, additional revenues may not be realized for one to four years. This can be handled by discounting those future cash flows back to the time of the decision, but price fluctuations may introduce substantial uncertainty.
In the case of stock options, economic benefits are realized because the current price exceeds the strike price. However, most large oil fields have lives of 20 to 100 years, and the price of oil or gas behaves as a typical fluctuating commodity, oscillating widely through a maxmin price envelope. Therefore, any price differential at the time of optionexercise will change many times, positively and negatively, during the field's life. Thus the benefit in oil and gas field options usually relates not to elevated oil prices but to improved operating profits, which result from reduced costs to find, develop, and/or operate fields. In general then, oil exploration option behavior depends on waiting for new data or technology that may lower costs and/or reduce risk, not on sustained higher oil or natural gas prices.
Calculating the variance (or standard deviation) in price of a given stock is easy. Moreover, it would be easy to calculate the historical standard deviation in the real price of crude oil (approximate 2000 estimate = ±$7.00 bbl). What is not known is the variance in prices of oil properties, such as exploration prospects or discoveries that have not yet been developed.
There is a large and continuous market for trading common stocks—any time an owner wishes to sell his or her common stock, a trade may be effected almost instantly. But sales of oil properties commonly require months of preparation, analysis, and negotiation, during which ongoing developments may cause major changes in the perceived value of the property (Lohrenz, 1988).
Most major international oil companies are now developing some form of optionpricing procedure to replace conventional DCF analysis for establishing the monetary value of oil and gas ventures, especially longterm, largereserve projects (Chorn, 1999; Dixit and Pindyck, 1994; Lehman, 1989; Mann et al., 1992; Paddock et al., 1983; Pickles and Smith, 1993).
Recommended Economic Measures
Once the cashflow model or models of the proposed venture have been run, there are many different ways to measure the venture's attractiveness (Megill, 1988, 1992). Use and diversity of these measures have evolved as companies and analysts have become increasingly sophisticated about oil and gas investments. Different companies have developed minor variations on the main measures to suit their individual needs.
However, all current and widely used industry measures depend on the fundamental expression of project value—cumulative NPV (see p. 50)—which of course assumes project success.
Discounted Cashflow Rate of Return
Discounted cashflow rate of return (DCFROR) may be expressed in two different ways: (1) the exact earning rate of the project during its full life, expressed as an annual average rate of return; or (2) that discount rate that sets the value of the cumulative net cash flow stream to be discounted, over the life of the project, at zero. DCFROR is not useful for comparing different projects. It has only one legitimate use: to serve as a minimum qualifying standard, or “hurdle rate,” which any project must clear if it is to be considered further for corporate funding. Once DCFROR has been used in this way, other economic measures should be employed to compare and rank exploratory ventures. Employment of arbitrarily elevated DCF hurdle rates does not compensate for risk; moreover, it selects against longterm, largereserve ventures.
Maximum Negative Cash Flow
Maximum negative cash flow (MNCF) is the “turnaround” point on the project's cumulative discounted net cash flow profile—that point at which the cumulative net cash flows have reached their maximum negative level and will turn back upward toward the breakeven line and increasing profitability (Figure 25). MNCF is a discounted value, and for exploratory ventures, where a new field may be developed if there is a discovery, MNCF represents the net of investments and partially offsetting production revenues. It is useful in capital budgeting and planning because it represents the amount of money that actually will be needed from the corporate treasury. In firms that have shortterm capital constraints, it may be useful for comparing and choosing projects. It also serves as a “time focus” for concerns about political risk because it represents the time of greatest economic vulnerability for project life. But the most significant use of this parameter is as a proxy for investment in investment efficiency, one of the most useful common economic measures (see this page).
Expected Net Present Value
As introduced in Equations 1 and 2, ENPV is the chanceweighted NPV of a venture, in which the product of the chance of failure and the cost of exploratory failure is subtracted from the product of the chance of success and the NPV of the meanreserves case (Equation 3). For prospects (rather than plays), it integrates prospect reserves, DCF values, and commercial chance of success, thus allowing comparison of highrisk, highpotential prospects with lowrisk prospects having only a moderate reserves potential. It is useful in portfolio analysis primarily because the sum of all project expected values is the expected value of the entire portfolio. The drawback of expected value is that it implies that the firm is riskneutral: two projects might have identical ENPVs even though one project requires a much larger initial capital investment (= dryhole cost) than the other (see p. 92). In fact, however, most firms recognize that exploration decisions commonly involve provisions against loss (= risk) as well as ENPV (Equations 6 and 7).
In its simple form, ENPV makes no provision for risk (as distinguished from chance). However, ENPV does form the basis of an expanded economic measure that considers project utility and corporate lossaversion, called riskadjusted value (RAV) (Cozzolino, 1977, 1978), which is discussed further below and on page 92.
Investment Efficiency
Investment efficiency (IE) is the most discriminating form of profit/investment ratio, in which profit is the project's NPV and the investment is maximum negative net cash flow (MCNF) (Equation 4).
Figure 25 shows the relationship of the key terms involved in investment efficiency. Investment efficiency produces the same project ranking as does another preferred measure: growth rate of return (GRR) (Capen et al., 1976), in which net cash flows are considered to be reinvested as received, at the company's real rate of return, and projected out to some preselected target year (often 10 or 12 years). For longerterm projects, annual net cash flows extending beyond the target year are discounted back and then combined with accumulated earnings. Even though generally acknowledged to be a superior economic measure, GRR has not received the wide usage of its derivative, investment efficiency (Clapp, 1995).
Another advantage of investment efficiency is that it can easily be risked—that is, it can be modified to chanceweight all outcomes (Equation 5):
whereExploration portfolios ranked using risked investment efficiency are optimized for the creation of value. Unfortunately, such portfolios sometimes present unacceptable degrees of risk, and this may require the company to surrender some attractive highrisk prospects in exchange for some less risky but smaller ventures.
Riskadjusted Value
Cozzolino's (1977, 1978) equation for RAV combines the expected value concept with principles of utility theory, which is generally acknowledged to follow an exponential form (Equation 6). Where
Optimum Working Interest
If the company's riskquotient (r) is known, ^{7} every venture can be shown to have an optimum working
interest (OWI)—i.e., that proportional share at which the RAV is greatest (MacKay, 1995). However, further work by MacKay and his colleague Ian Lerche has generated a direct method for determining OWI (Equation 7) using the concept of risk tolerance, generally represented as 1/r. whereIf a company wishes to include considerations of utility theory or risk aversion in ranking its various projects for inclusion in the annual portfolio, it can calculate OWI for each venture, then calculate ENPV and risked IE (see this page) at the predetermined share (or actual share, where the exact OWI is not available).
Considerations of OWI have two main applications in exploration. Small firms are often quite sensitive to risk because of their limited capital and the correspondingly small number of drilling ventures that are possible for them. Such firms may employ OWI calculations to ensure that participation levels in the several ventures comprising their annual portfolios are consistent and appropriate to their modest financial resources.
The second OWI application arises from the nature of annual drilling portfolios. Ideally a company would assemble an inventory of candidate prospects for ranking and selection to make up the next year's drilling portfolio, and appropriate shares of joint ventures would be determined as part of the calculations that lead to portfolio optimization. But many companies do not have the luxury of assembling a full year's supply of prospects 12 months in advance. Instead they make decisions serially on prospects that appear throughout the program year, hence they cannot predetermine the appropriate share based on portfolio considerations. Here OWI offers an alternative approach that, however, may actually function in a somewhat more riskaverse way and thus reduce portfolio value more than necessary. This topic will be revisited in Chapter 6, in the section on prospect and play portfolios.
Figures & Tables
Contents
Risk Analysis and Management of Petroleum Exploration Ventures
During the 1990s, many international petroleum companies improved their exploration performance significantly by using principles of risk analysis and portfolio management, in combination with new geotechnologies. While exploration risk cannot be eliminated, it can certainly be reduced substantially, on a portfolio scale. And the widespread adoption of standardized risk analysis methods during the 1990s brought badly needed discipline to petroleum exploration. By the mid1980s, most wellinformed major international petroleum firms that were engaged in exploration recognized that, globally, the average size of new discoveries was diminishing. Not coincidentally, the class of exploratory prospects categorized as “high risk/highpotential” was showing marked signs of underperformance. For major companies, when all such ventures, which averaged around a 10% perceived probability of success, were considered, less than 1% actually discovered profitable oil and gas reserves, and the sizes of these discoveries were generally far smaller than predicted. All in all, such exploration for new giant fields destroyed value, rather than creating it, in the 1980s and early 1990s. Consequently, exploration, as a corporate function, lost credibility. It badly needed to begin delivering on its corporate promises. It needed to become more efficient, and thereby more profitable. To optimize the allocation of exploration capital, concepts of portfolio management began to be considered.