APPRAISAL OF 20 GLOBAL EXPLORATION CONTRACTS LOCATES KEY VARIABLES THAT AFFECT PROFIT LEVELS

David A. Wood
International Petroleum Corp.
Dubai, United Arab Emirates

This is part two of an article that summarizes an economic evaluation of 20 international exploration and production contracts.

A systematic method for evaluating and comparing contract performance enables the relative importance of the key variables responsible for profit levels under the terms of a specific contract to be clearly identified.

The 20 contracts show large diversity in the post-tax profits a company can expect to receive from production controlled by them.

The first part of the article presented the specifications of model oil fields of three sizes used in the analysis, listed the objectives of the analysis, and included part of the results (OGJ, Oct. 29, p. 48).

Each contract has been assigned a letter from A to T. The countries are confidential but include six from South America, five from Africa, four from the Middle East, four from the Far East, and one from Europe.

SPIDER DIAGRAMS

An informative way to illustrate the complete sensitivity analysis of the input variables for a particular field size and contract is to plot the value of a key economic indicator for each sensitivity case run versus the percentage variation of the input parameter varied from its base case value.

The resulting diagram is referred to as a spider diagram for obvious reasons. The patterns shown on these spider diagrams vary perceptibly from contract to contract giving them a "finger print" like value.

Such diagrams can be used to establish to variations of which input variables a contract is particularly sensitive and to understand the detailed mechanism of those contracts with the most complex fiscal structures.

Fig. 3 shows spider diagrams for NPV-15% displaying the sensitivity analysis of input variables.

The spider diagram for Contract B is typical of NPV spider diagrams for the production driven contract mechanisms.

The trends are approximately symmetrical and relatively predictable. The contractor's NPV is more sensitive to oil price and production rates than costs.

Also the contract is less sensitive to operating costs, inflation rates (applied to operating and capital costs), and time of production startup than to capital costs.

The spider diagram for Contract R in Fig. 3 is a typical NPV spider diagram for a production driven contract with a low cost recovery allowance from gross production. This type of contract is very sensitive to variations in costs as well as oil prices and production rates.

Relatively small changes in costs, inflation rate, production rate, or oil price for this particular field can change the base case into a reasonably economic project or an economic disaster under the terms of this contract.

The Contract R diagram illustrates why careful planning of the expenditure levels and annual profiles versus production profiles is essential to optimize the contractor's profits under the terms of such contracts.

The Contract R diagram also illustrates how such spider diagrams can be of use during the contract negotiation phase. The dotted line shows the effect on NPV for this 50 million bbl field under Contract R but for a range of higher cost recovery allowances.

It is concluded from this analysis that obtaining even a small increase in the cost recovery allowance is worthwhile, but anything more than a 30% increase from the base case percentage allowance has little impact on the NPV.

Clearly analysis of the effects of other negotiable contract terms can be performed in a similar way using spider diagrams.

The Contract D spider diagram in Fig. 3 is typical for a taxation driven contract with one tax controlled by a periodic rate of return to the contractor.

This spider diagram is quite asymmetrical and the trends unpredictable, typical of contracts in which a rate of return is involved in the fiscal structure. There is much less overall variation involved in the sensitivity analysis of NPV for this particular field size (i.e., low standard deviation).

Plotting the NPV of each case divided by the mean or base case values for the three contracts in Fig. 3 would illustrate this point more clearly. However, spider diagrams are at their most useful when the absolute value of the economic indicator is plotted rather than a derivative.

A higher sensitivity to oil price and production rate is also apparent in the Contract D diagram.

For this field case the contract is virtually insensitive to inflation rate and the time of production start-up. Curiously both the earlier and the later production start-up times evaluated result in lower profitability for the contractor than the base case.

This indicates that a carefully planned field start-up time is required to optimize the field's profitability to the contractor.

Unlike the typical production driven contracts the earliest possible production startup does not necessarily result in optimum profits with such contracts.

The reason for the asymmetry in the capital cost variations in the Contract D diagram in Fig. 3 is that the lower costs through the project result in higher periodic rates of return to the contractor, to which the contract responds with higher tax rates (or in the case of other contracts introduces a supplementary tax).

Somewhere between 25% and 50% lower capital costs than the base case causes the contract to pass this tax threshold.

The unpredictability of the effect in variations of the input variables on contractor profits with contracts controlled in part by periodic rates of return justifies calculating a much larger number of sensitivity cases.

Once a quick look sensitivity analysis, such as the one illustrated here, is completed certain variables can be targeted for more detailed analysis. This could help to define more precisely the critical values at which significant tax breaks occur.

An iterative computer program is clearly of value for such detailed analysis. When planning a field development under one of these contracts detailed sensitivity analysis is a very useful aid.

After detailed analysis a spider diagram can appropriately look more like a can of worms.

Other contracts that can result in significantly asymmetrical spider diagrams, of the type shown in Fig. 3, are those where the production split to the contractor varies according to the contractor's periodic cumulative revenue to cumulative investment ratio (for example, contracts N, P).

However, the asymmetry is generally more predictable and less extreme than for those contracts with a rate of return control.

Only examples of spider diagrams for NPV and the 50 million bbl field are included here. However, two points worth noting for NPV spider diagrams for the 350 million bbl field are:

All contracts are significantly more sensitive to oil prices and production rates than costs;
The changes in NPV caused by varying capital costs, operating costs, and inflation rate are much more similar than for the small field sizes.

For the 15 million bbl field the spider diagrams show that NPV is almost as sensitive to changes in capital costs as to oil price.

Unlike the other contracts the rate of return controlled contracts (i.e., contracts C, D, and F) are not sensitive to significant decreases in capital costs. This is because as soon as the contractor's periodic rate of return increases in such circumstances, the contract compensates by cutting the share of profit oil to the contractor.

The poor cost recovery contracts are very sensitive to changes in both costs and prices as they are for the 50 million bbl field (Contract R, Fig. 3).

Clearly spider diagrams have many uses in detailed prospect and development project analysis as well as in comparing and understanding the fiscal mechanisms of contracts themselves.

The patterns on spider diagrams drawn for payout time and percentage of profits are different from those shown here for NPV and can be useful in certain circumstances.

DISCOUNTED PROFIT INVESTMENT RATIOS

Profit-investment ratios can be of value in the economic comparison of E&P contracts.

There are several ways to define profit and investment, so it is important to clarify the definitions applied here:

Profit is the sum of the post-tax cash flow.

Investment is the sum of all expenditures made by the contractor in the project, including exploration costs, capital investment, and operating costs.

To calculate a discounted profit-investment ratio both profit and investment are discounted at the appropriate discount rate.

It should be remembered that investments are involved in the numerator and denominator of this ratio as defined here. This ratio can also be referred to as NPV/investment or as the investment efficiency, which is essentially what it defines.

In the first element in Fig. 4 the profit-investment ratio discounted at 15% is plotted against NPV-15% for the base case input variables of the 15 million bbl field for each of the 20 E&P contracts.

This graph distinguishes those contracts in which the government, through a state oil company, contributes to investment in the project. The dashed line passes through those contracts in which the government does not contribute to costs.

This relationship shows that for a given profit investment ratio the contracts with no government participation in investment have a higher NPV. Conversely, the contracts where the government pays a substantial share of investments require less investment on the part of the contractor to yield the same profit-investment ratio than contracts where the government does not contribute to investment.

A graph of profit-investment ratio vs. investment shows this. In cases where a company has limited funds it then becomes important to maximize the profit-investment ratio.

The second element in Fig. 4 shows the same relationship for the 350 million bbl field. The NPV for the same profit investment ratio is substantially lower for those fields in which the government contributes to investment (i.e., in return for a greater share of the profits, which is larger for the larger fields).

For approximately the same profit-investment ratio this field provides the contractor with less than half the NPV under Contract than under Contract O for less than half the investment.

The effect of optional government back-ins once a field has been discovered can be evaluated using plots similar to those shown in Fig. 4.

Such analyses are sometimes of use during the phase of contract negotiation or bidding with a government, i.e., for a potential contractor to establish how different levels of government back-in effect contractor profits and break even points.

For the contracts analyzed in this study it has been assumed that where the government has an option to back-in to production that option has been excerised.

RANKING, VALUING PROSPECT PORTFOLIOS

Notwithstanding the foregoing sections it is important for the economist to appreciate that establishing favorable terms for the E&P contract is only one of the factors in determining whether a project is attractive.

There have to be prospects or fields with technical merit in the contract area, and the exploration and political risks have to be acceptable.

The oil industry has a number of well established methods for placing a fair market value on tangible assets such as producing fields or development properties, only some of which are objective and take into account all relevant factors (e.g., Garb, 1990).

The most useful methods commonly apply an economic and political risk factors to the various categories of reserves and analyze the various cash flows that can arise from them, depending on the price paid.

However, for placing a fair market value on an intangible asset, such as an exploration prospect, there is no standard practice due to the uncertainties and risks involved and the subjective ways in which the risks are often expressed.

For the purposes of justifying a drilling prospect, or for farm-in and farm-out deals, it is important to be able to place values on exploration acreage.

One of the most objective methods requires slight modifications to one method for establishing the fair market value of existing reserves, and involves the following steps:

Estimate base case reserves of prospect(s).
Calculate applicable production profile(s).
Calculate contractor cost profiles.
Make forecasts for future oil and-or gas prices.
Estimate exploration risks or changes of success.
Estimate political, economic, and environmental risks in developing reserves.
Determine the net revenue interest and paying interest of the share of the prospect being valued.
Combine above data with the applicable contract terms to generate post-tax cash flows and calculate risked economic indicators, such as expected monetary value (EMV) discounted at various percentages and discounted EMV-investment ratios. In such ratios the investment is both risk weighted and discounted.

The above is more of an art than an objective scientific procedure. The uncertainties that exist in steps 4, 5, 6, and 7 leave scope for a wide range of risked cash flows to be calculated.

There are several objectively designed schemes for estimating exploration risk based on the main elements required to trap commercial quantities of oil.

However, this is not the case for political and economic risks, which change by the day and at any time will be perceived differently by one company or nation than others.

Something that some factions of the western oil industry have yet to accept is that in some less developed countries such risks can be less than in the western world.

The uncertainties of expanding environmental restrictions and liabilities in Europe and North America will probably make this the norm rather than the exception in the years ahead.

At present it is common for the high perceived political, economic, and environmental risks of a new venture country due to a lack of first hand knowledge of that country, rather than the quality of the prospects concerned-that prevent companies entering exploration ventures in those countries.

As the industry's international exposure and experience grows, the perceived risks will become less, and more international projects will pass the required economic thresholds for participation using the above method of valuation.

The valuation method outlined above can be applied to value a portfolio of acreage and prospects each with their own reserves, costs, risks and contract terms. The only constants at any one time in such a valuation will be the discount rate used for the valuation.

Oil and gas prices will vary slightly due to fluid compositions and geographic locations of the prospects. Contract terms become one of several variables in the overall valuation.

The discount factor used to calculate the EMV to be considered as a fair market value for the acreage or prospect should be several points higher than the interest available from placing such funds on deposit at a financial institution.

A discount rate of 15-25% would be appropriate at this time.

Fig. 5 illustrates the results of a valuation for a portfolio of 60 prospects.

The risk weighted economic indicator EMV, discounted at 15%, is plotted against the ratio of EMV to risked total investment similarly discounted. These parameters can be considered as a risked weighted versions of NPV and discounted profit-investment ratio, respectively.

They combine the rewards of success at the appropriate chance of success and the costs of failure at the appropriate chance of failure.

The chances of success for exploration prospects rarely exceed 30%, and for high risk prospects are less than 5%. The average chance of success for the portfolio presented is 12% and ranges from 1-28%.

Several prospects in the portfolio studied have negative EMVs. This is not unusual as many prospects with attractive NPVs when risked are shown to be uneconomic.

Prospects with negative EMVs at the companies threshold discount rate for profitable ventures would be dropped from the portfolio. The company would elect not to drill such prospects unless required by a contract obligation in a contract area where no better prospects existed.

The large scatter shown by the prospects in Fig. 5 is due to the large number and diversity of variables involved in the risked values calculated. However, two groups of prospects can be distinguished from the main cluster:

The high cost-high reward offshore prospects. These are characterized by high EMV but relatively low EMV investment ratio indicating a relatively poor investment efficiency.
The high risk-low cost shallow depth onshore prospects. Despite very low risk factors these prospects have small positive EMVS, but very high EMV-investment ratios due to the low costs indicating a relatively high investment efficiency.

A well balanced portfolio should clearly include both the above types of prospects, and a selection of other high and low risk prospects.

A work program too heavily weighted to the high risk end of the spectrum runs a significant chance of consuming its exploration budget on dry holes.

A work program too heavily committed to high cost projects has a significant chance of consuming its exploration budget to test very few prospects (not necessarily a bad thing if some are discoveries) or of requiring large scale financing projects to develop its discoveries.

In the latter case there is also the greater chance of making sub-economic discoveries, the most frustrating of all results.

The relationship shown in Fig. 5 can be used to rank a prospect portfolio and thereby prioritize the order in which prospects should be drilled.

There are parameters that are particularly useful for highlighting the values of prospects for which, as a result of farmout deals, the net revenue interest being valued is either promoted or carried.

One of these is the EMV-risk investment ratio. In this ratio only the exploration costs (discounted) are included as risk investment.

When a net revenue interest in a prospect is fully carried this ratio is infinite. The ratio is also high for partially carried prospects.

By drilling prospects with the highest values of this ratio for given EMVs, a company maximizes the potential returns from its available risk capital.