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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 geotech-nical 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 geotech-nical 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 cost-of-capital approach, some authorities believe that the chosen discount rate should approximate the firm's actual long-term 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 long-term projects (which are typically associated with large-reserve opportunities) by assigning little or no value to cash flows beyond about 15 years. Instead, short-term 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 long-term, large-reserve 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 short-term 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 Cash-flow Models and Discounted Cash-flow Analysis

The cash-flow 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 cash-flow model assumes success. This scenario must be geologically reasonable using the mean-reserves case and compatible values for per-well 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 cash-flow 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 geo-technical predictions are a professional goal.

As previously stated (p. 24), discounted cash-flow (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 mean-reserves outcome. Naturally, geologic and engineering parameters such as area, well numbers, net pay thickness, HC-recovery, 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 cash-flow 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 cash-flow stream (Megill, 1988); analysts are encouraged to calculate these costs on an after-tax basis, taking depreciation and investment tax credits into account. The net income cash-flow stream (also on an after-tax basis) is influenced by production revenues (declining), net revenue interest, wellhead taxes, operating costs, and income tax provisions. For production-sharing 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 after-tax investment cash flow and after-tax income cash flow is annual after-tax 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 after-tax net cash flows for the life of the field, we derive the field's cumulative after-tax net cash flow (CNCF).

Annual net cash flows are discounted using the appropriate annual present-value factor for the selected discount rate (Table 10). By adding them for the period of the cash-flow model, we derive the key value of the cash-flow 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 present-value factor for years hence and the selected discount rate. This is, in essence, an after-tax 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 add-ins, 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 year-end 1999 still utilized multiple runs of deterministic cash-flow models.

Another problem is that each cash-flow 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 cash-flow 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” cash-flow models and decision-tree 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 large-reserve, long-term 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 long-term, stable production potential—just the kinds of fields that build companies and provide steady, reliable, low-cost production revenue streams for many years. Yet these are the kinds of long-term, steady cash flows whose value beyond about 20 years is shown to be nearly zero by conventional DCF analysis!

Table 10

Present value factors.

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 long-term cash flows and eliminating the possibility that some projects could be made to appear more attractive through biased selection of elevated price-escalation 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 short-term 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: Option-pricing Theory.

Option-pricing 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 Black-Scholes 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.

  1. 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 dis-counting those future cash flows back to the time of the decision, but price fluctuations may introduce substantial uncertainty.

  2. 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 max-min price envelope. Therefore, any price differential at the time of option-exercise 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.

  3. 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.

  4. 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 option-pricing procedure to replace conventional DCF analysis for establishing the monetary value of oil and gas ventures, especially long-term, large-reserve projects (Chorn, 1999; Dixit and Pindyck, 1994; Lehman, 1989; Mann et al., 1992; Paddock et al., 1983; Pickles and Smith, 1993).

Figure 24

Option concept applied to E&P projects. F/O = farm-out; EOR = enhanced oil recovery.

Figure 24

Option concept applied to E&P projects. F/O = farm-out; EOR = enhanced oil recovery.

Recommended Economic Measures

Once the cash-flow 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 Cash-flow Rate of Return

Discounted cash-flow 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 long-term, large-reserve 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 break-even 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 short-term 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 chance-weighted 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 mean-reserves case (Equation 3). For prospects (rather than plays), it integrates prospect reserves, DCF values, and commercial chance of success, thus allowing comparison of high-risk, high-potential prospects with low-risk 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 risk-neutral: two projects might have identical ENPVs even though one project requires a much larger initial capital investment (= dry-hole 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). 

formula

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 loss-aversion, called risk-adjusted 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). 

formula

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 longer-term 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 chance-weight all outcomes (Equation 5): 

formula
where 
formula

Exploration portfolios ranked using risked investment efficiency are optimized for the creation of value. Unfortunately, such portfolios sometimes present unac-ceptable degrees of risk, and this may require the company to surrender some attractive high-risk prospects in exchange for some less risky but smaller ventures. 

formula

Figure 25

Cumulative net present value and maximum negative net cash flow.

Figure 25

Cumulative net present value and maximum negative net cash flow.

Risk-adjusted 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 

formula

Optimum Working Interest

If the company's risk-quotient (r) is known, 7 every venture can be shown to have an optimum working 

formula
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. where 
formula

If 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 corre-spondingly 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 risk-averse 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.

5The reader is referred to books by Megill (1988), Stermole and Stermole (1990), and Wright and Thompson (1985) for detailed dis-cussions about cash-flow models and economic analysis of projects.
66To match the appropriate area, average net pay, and HC-recovery factor to the P90%, P50%, and P10% reserves cases, remember that multiplication of the product of the three P23% cases for area, pay, and HC-recovery results in the P10% reserves case, just as the product of the three P77% cases for area, pay, and HC-recovery yields the P90% reserves case. The product of the three P50% values yields the P50% reserves (Appendix B).
7Cozzolino suggested that a rough approximation of (r) was 1/annual exploration budget ($MM); thus (r) for a firm with a $50MM annual budget would be 1/50 or 0.02. Later observations and calculations by Walls (1993, personal communication) suggested that 5/annual budget was a more representative value for average oil companies, so Walls's (r) for a $50MM firm would be 0.10. Each company should be able to determine approximately what its (r) value really is, based on recent previous joint ventures and expressed share preferences for its current joint ventures.

Figures & Tables

Figure 24

Option concept applied to E&P projects. F/O = farm-out; EOR = enhanced oil recovery.

Figure 24

Option concept applied to E&P projects. F/O = farm-out; EOR = enhanced oil recovery.

Figure 25

Cumulative net present value and maximum negative net cash flow.

Figure 25

Cumulative net present value and maximum negative net cash flow.

Table 10

Present value factors.

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