Economist's Corner

Economic Evaluation of Oil and Gas Projects

Economist’s Corner this issue hosts Dennis Smith of IHS Energy. Smith gives an introduction to commercial analysis of upstream projects, stressing the importance of various inputs, fiscal system interpretation, and presentation of economic indicators.

Kristine Petrosyan and Francesco Verre, Editors, Economist's Corner

The results of economic evaluations are one of the primary resources that are used by executives to make oil and gas investment decisions. The economic evaluation process is usually the final step in a long process of technical and financial evaluation that must be done before any investment decision is made. The economic evaluation process can be represented in these steps:

Step 1—Generating Forecasts of Key Technical and Economic Parameters

The initial step of an economic evaluation is the gathering of the technical data, which include the following:

  • An annual forecast of the oil and gas production that is expected to be generated by the project, where the project may be a single well, a field, an onshore license, an offshore block, or any other type of asset or group of assets. These forecasts are prepared by the geologists furnishing the amount of estimated oil and gas reserves and the engineers who then convert the reserves to annual production figures.
  • An annual forecast of the oil and gas prices at which the production is expected to be sold. In larger oil companies, there are usually “company approved” forecasts that must be used for all economic evaluations, especially for oil prices. By doing this, companies strive to maintain consistency among all economic evaluations. If this is not done, then sponsors of individual projects can easily manipulate the economics in their favor through more optimistic price assumptions.
  • An annual forecast of the capital expenditures that will be required to explore and develop a project. These are typically provided by engineers who have evaluated the optimum methods for developing and/or producing the oil and gas (in terms of field exploiting strategies and facilities development). For the purposes of economic evaluations, a great deal of breakdown of the capital expenditures into subcategories is usually not required, although separating them into exploration capital and development capital is typical so that the decision maker can clearly see how much capital is at risk vs. the capital that is only required once a discovery is made (development capital). Any further separation into subcategories is necessary only when the tax laws or contract terms specify different treatment of these capital subcategories for income tax or contractual issues.
  • An annual forecast of the operating expenses required to maintain the production of the oil and gas (e.g., costs associated with the maintenance of the plant). This is also typically provided by the engineers and is usually split into fixed costs that will be incurred each year and variable costs that will vary with the amount of production. The costs of transporting the oil or gas from the wellhead to the point of sale (e.g., tariffs paid for use of a pipeline system) are also usually entered here.
  • The working interest ownership also needs to be supplied because it represents the share of the project that is being evaluated.

Step 2—Modeling of the Fiscal System

Each country has a set of tax laws and/or contract terms that govern the methods by which oil and gas companies must pay a portion of their proceeds to various government agencies. Collectively, these are referred to as the fiscal system of a country. A model must be constructed that will ultimately calculate the annual after-tax cash flow that the oil company will receive over the life of the project. It is this determination of cash flow that is always the goal of an economic evaluation because, from this, many types of economic indicators may be derived to aid in the decision process. Thus, from the economic evaluation point of view, there are two fundamental types of fiscal systems.

Royalty/tax regimes. These types of systems are found in countries such as the United States, United Kingdom, Norway, and Australia and have the following common characteristics:

  • The oil company “owns” the reserves and thus receives their revenues by selling the oil and gas.
  • Out of the proceeds of the sales, the oil company must pay a royalty to the government, which is generally a specified percentage of the revenues. The oil company must then pay an income tax based on the profits of the project (i.e, the revenues less the royalties less all costs). There is a single source of cash inflow—the revenues from the sales of production—and four sources of cash outflow: royalty, capital expenditures, operating costs, and taxes.

Production-sharing contracts. The derivation of the after-tax cash flow is very different in production-sharing contracts, which are used most often, but not exclusively, in emerging markets (e.g., Angola, Indonesia, Malaysia, and China).

  • Unlike royalty/tax systems, the oil company does not “own” all of the reserves. Rather, the government may be considered the original owner.
  • The government allocates a portion of each year’s actual production (cost recovery) to be used by the oil company to recover their costs of exploration, development, and operating.
  • The value of the production remaining in a given year after cost recovery is deemed to be the profit of the project. This profit is then shared between the oil company and the government.
  • There are two sources of cash flow inflow to the oil company—cost recovery and profit share—and two sources of cash outflow: capital expenditures and the operating costs.

Step 3—Calculation of Economic Indicators

The final step in the economic evaluation process is to summarize the future cash flow projections from Step 2 into various economic indicators that will allow you to make a decision on whether to proceed with the project. One of the key concepts upon which many economic indicators are based is the time value of money.

The time value of money can best be illustrated by asking a question. Would you rather have USD 100 today or USD 100 a year from today? The answer is today and the reason is that you could take that USD 100 today, put it in the bank for 1 year, and earn interest on it. Assuming a 5% interest rate at the bank, this means that you would have USD 105 at the end of the year, which is better than the USD 100 offer.

Working this concept backwards, if there is a projection that USD 105 will be earned from a project 1 year from now and we have the same bank, then that USD 105 is only worth USD 100 today. This process of converting future cash flows into today’s value is called discounting, and the amount of equivalent value today of a future cash flow is called its present value. If each year of a future cash flow projection is converted into today’s value and then all of these present values are added together, the result is what is commonly referred to as the net present value (NPV).

The NPV is the best measure of the actual value in monetary terms of any individual project. The interest rate at the bank referenced in the preceding example is commonly called the discount rate, and it generally represents the oil company’s alternative earnings rate. There are various methods used to derive the company discount rate, but most companies have a standard one that must be used for all new projects to maintain consistency of results among multiple projects.

Besides NPV, there are three other economic indicators:

  • Rate of return is mathematically derived as the only discount rate that forces the NPV to be exactly zero. 
  • Payout (or payback) is a meaningful indicator of how long it takes a project to recoup its capital expenditures from the profits.
  • A profitability index is a measure of the earning power of each dollar of capital and is calculated by taking the total after-tax cash flow for the life of the project and dividing it by the total capital expenditures. This indicator may be done on either an undiscounted or a discounted basis.

Many other economic indicators may be used, each with its own strengths and weaknesses. When viewed together, though, they usually give a very good indication of whether or not the project should proceed.


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