Dwight Gaddis, Horace Brock, Charles Boynton
Institute of Petroleum Accounting
Denton, Tex.
A major problem facing the U.S. petroleum industry is the higher average finding costs that now exist within the U.S. compared with the average finding costs outside the U.S.
It has been argued that federal lands and offshore areas need to be open for drilling in order to reduce average finding costs in the U.S.
Certainly, the development of a national energy policy must acknowledge the importance of finding costs.
Financial analysts for some time have acknowledged the importance of finding costs in evaluating individual energy firms. Analysts expect mergers when it is cheaper for companies to purchase reserves than find them. 1
just as industry average finding costs are a key determinant of long term market prices for oil and gas, relative finding costs are a key determinant of a company's stock market value. Division managers are now judged regularly by top management on the basis of relative finding costs.
The heavy use of finding costs data is causing its own problems, however, because there is as yet no standard for calculating and reporting those costs.
This article analyzes the strengths and weaknesses of conventional techniques for determining finding costs. Our goal is a finding costs measure that is a reliable indicator of future profitability.
FINDING COST PER BOE
Conceptually, a finding cost figure is a measurement of how much it costs a company to find a barrel of oil or 1,000 cu ft of gas.
The figure is determined by dividing the costs incurred during a specified period by the volume (barrels or Mcfs) of reserves added during the same period.
For example, if the incurred costs were $100,000 and the reserves added were 20,000 bbl, the finding cost would be $5/bbl.
In order to arrive at a uniform oil and gas measure, the incurred costs for oil and gas are generally combined, the volume (mcf) of gas reserves found is converted into equivalent barrels of oil (BOE) and the ratio expressed as "finding costs per BOE."
The finding cost per barrel equivalent reduces to a simple formula:
Total costs to 'find' the barrels equivalent barrels 'found'
KEY ISSUES
The key issues in the calculation are: (a) what costs to use, (b) what reserves to use, (c) what time period to use, (d) what mcf to BOE conversion factor to use, and (e) whether to report on a worldwide or U.S. and non-U. S. basis.
PUBLIC DATA
In computing the cost of finding reserves, the most critical concern is matching the appropriate costs to the appropriate reserves found.
Obviously, tracing costs to reserves added is easier when internal data are available because there is greater detail available about both costs and reserves, simplifying the matching of costs incurred to reserves added.
If publicly disclosed information is used, costs incurred and reserves added cannot be matched exactly.
Financial analysts, wishing to standardize company comparisons and lacking internal data, estimate finding costs solely from publicly disclosed information.
Since that information was not specifically designed for the finding costs calculations, finding costs reported by companies may differ from those calculated by analysts simply because of the data differences.
The source of such differences may be more fundamental, however, as will be discussed in the remaining sections.
PICKING COSTS, RESERVES
The costs and reserves used in the calculation are dictated by the objective at hand.
If the aim is to determine the effectiveness of a company's exploration activities, then it is illogical to include costs and reserves added by purchase or through improved recovery techniques.
Similarly, it is inconsistent to include the costs and reserves of unconsolidated affiliates since such reserves presumably do not reflect activities directly under the control of the reporting company.
Some analysts contend that finding costs end with the exploration effort and, hence, that finding costs should include only costs of unproven leaseholds and of exploration, with only "reserve additions and extensions" used as the appropriate figure for reserves added.
A second school of thought holds that since reserve revisions are not separated between those that are associated with over- or under-estimates of reserves and those associated with a company's development efforts, reserve revisions should be included in the calculation of finding costs.
Still others take a third position that development costs are appropriately included in calculating finding costs. As an example, they point to Prudhoe Bay, Alaska, where development expenditures were substantial, and dividing initial exploration expense by the reserves found would result in a deceptively low finding cost.
If development expenditures are included, reserve revisions must also be included in the calculation.
Also, because the statement of costs incurred in the supplemental footnotes, does not separate developments costs and costs related to improved recovery projects, reserves added through improved recovery should also be included.
(Still another possibility sometimes advocated is to compute a replacement cost per equivalent barrel. This calculation would include the above costs and reserves and, in addition, the costs of proved reserves purchased in place.)
LEASEHOLD, RENTALS, G&G
Leasehold costs, delay rentals, and geological and geophysical expenses may be allocated to finding costs in several ways if internal data are available.
In a survey of major oil and gas companies, the financial reporting committee of the Dallas chapter of the Council of Petroleum Accountants Societies found three basic options in use for including unproved leasehold costs:
- Include costs of leasehold acreage acquired in the year;
- Include the costs of leases decisioned or surrendered in a year; or
- Include the leasehold cost amortized and the cost of leases that prove productive during the year.
There were two basic options for allocating delay rentals and Geological and geophysical expenses:
- Include costs in the year the outcome is known, or
- Include costs in the year incurred.
An analyst working from publicly disclosed information must use the total cost of leasehold acreage acquired in the year because other information is not available.
Further, when publicly disclosed information is used in the computation, delay rentals and geological and geophysical expenses are categorized as exploration expense and thus included in the year incurred.
Exploratory drilling costs are included in the year incurred if public disclosure information is used. If finding costs are being calculated in-house, exploratory drilling costs are usually included in the year in which a well's outcome is known.
SELECTING THE TIME PERIOD
Year-by-year computations of finding costs are unreliable.
Consider this scenario: exploration is conducted on a large area in 1991, properties acquired in 1992, further exploration conducted in 1993, exploration drilling begun in 1994 and 1995, and major development undertaken in 1996 and 1997.
Although costs are reported as having been incurred throughout the seven years, reserves were added only in the sixth and seventh years, with revisions in later years.
Given such a scenario, a one-year computation would be virtually meaningless. The only solution is to use a moving average.
Financial analysts, restricted to using publicly disclosed data, generally use a moving average over a three year or five year period.
CONVERSION FACTORS
Another significant problem in calculating finding costs is the basis to be used for converting natural gas to BOE.
Most financial analysts rely on the energy content basis of 6 Mcf of gas = 1 BOE. However, oil prices have recently been near $19/bbl and gas at about $1.50/Mcf, suggesting that a ratio closer to 12:1 than 6:1 might have more economic significance.
Furthermore, finding costs comparisons do not reflect the quality of the product found. finding costs comparisons do not consider the actual BTU content of the natural gas or the gravity of the oil, nor do they compensate for the presence of impurities such as sulfur.
WORLD, U.S., NON-U.S
.Since non-U.S. finding costs are usually lower than U.S. finding costs, some analysts prefer to use those separate figures to determine the relative efficiency of a firm in each area.
Others argue that the decision to stay home or go abroad is an integral part of the search for oil and gas, and that it is worldwide finding costs on which a firm should be judged.
FINDING COST EXAMPLES
The table shows a comparison of the three year and five year moving average worldwide finding costs of selected companies based on the three previously discussed methods:
- Exploration expense and leasehold costs divided by reserve additions;
- Exploration expense and leasehold costs divided by reserve additions and revisions;
- Exploration, leasehold, and development expense divided by reserve additions, revisions, and enhanced recovery.
The figures used to calculate these data can be found in the supplemental footnotes of the companies' annual financial reports.
SPECIAL PROBLEMS
Additional questions about costs and reserves to be included in finding costs calculations must be answered.
Interest costs are not usually included in the computation because they are not separately identified in the public disclosures.
"Probable" and "possible" reserves are not included if public information is used because they are not reported. However, if the calculation is done internally, interest expense and risk-adjusted probable and possible reserves may be included in the calculation.
The level of disclosure of costs incurred in the supplemental footnotes generates several special problems in comparing the finding costs of different companies.
For example, some companies include all gas plant costs, some include none, and others allocate gas plant costs based on the percentage of the plant capacity used. Variations in the costs included in reported incurred costs can result in major differences in calculated finding costs.
A second major source of variation in incurred costs appears to relate to the decision whether to use full costs (FC) or successful efforts (SE) accounting. An unpublished preliminary study conducted at the University of North Texas' Institute of Petroleum Accounting indicates that finding costs for FC companies appear to be approximately 15% higher than for SE companies, although the reasons for this variation are not clear.
On the surface, such a difference would suggest that SE companies are more efficient than FC companies.
Another explanation, however, might be that FC companies report more overhead charges in the statement of costs incurred even though Financial Accounting Standard 69 does not provide for any accounting-method differences in the reporting of incurred costs.
CONCLUSION
The importance of finding costs is causing many in the oil and gas industry, the accounting profession, the investment banking community, and concerned U.S. government agencies to support the development of an agreed upon standard for determining and reporting finding costs.
Without an agreed upon standard, finding costs comparisons between companies and between domestic and foreign exploration and development may be meaningless.
An agreed standard would not eliminate all of the problems discussed in this article, but it would represent a major step toward comparability.
Over time, experience with an agreed standard should allow refinements that should correct many of the remaining problems and lead to the development of a useful indicator of future profitability with an acceptable level of comparability.
REFERENCE
- Energy Information Administration, Financial Aspects of the Consolidation of the U.S. Oil and Gas Industry in the 1980s, DOE/EIA-0524 (Washington, D.C.).
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
