WORLDWIDECOMPETITION for exploration and production rights improved the fiscal terms offered by governments to international oil and gas companies in 1997.
An analysis of fiscal regimes for oil projects by Van Meurs & Associates Ltd., Calgary, showed net improvement in terms, from the company perspective, over those reported in an analysis 2 years earlier by the same company. And the 1995 Van Meurs report had noted general improvement due to an increasing supply of and diminishing demand for acreage.
A separate study by the firm showed that some countries account for the economic differences of gas discoveries relative to oil, but they remain in a small minority.
The oil studies of 1995 and 1997 based their conclusions about rising overall attractiveness to investors on one criterion: government take (GT; Figs. 1, 2). GT is the percentage a government earns of economic rent, which is gross revenues from a project less all investments and operating costs on a cash flow basis. GT is one of eight criteria the Van Meurs analysis uses to rank fiscal systems.
The 1997 analysis, Worldwide Fiscal Systems for Oil - 1997, covered 324 fiscal systems in 159 countries. Like its 1995 predecessor, the study was distributed by Barrows Inc., New York.
The analysis applies its eight criteria on a weighted basis, assigns numerical scores to individual fiscal systems, ranks the systems, then groups rankings into five star-coded categories showing varying degrees of attractiveness to investors. It also calculates a world average fiscal system.
Among the most heavily weighted criteria are the two main profitability indicators: rate of return (ROR) and net present value (NPV) per barrel. Other criteria are the ability to absorb geological risk, attractiveness of incremental investments, "bonanza economics," and degree of front-end loading.
Trends in 1997
Between the 1995 and 1997 surveys, 33 countries and regions made changes to fiscal systems or signed contracts that improved terms to international investors. In addition, eight countries introduced terms that Van Meurs assessed as "favorable" or "very favorable" to companies. Four countries introduced systems or signed contracts assessed as "average." Nine countries toughened existing terms, and five countries introduced systems with "very tough" terms.
North America`s attractiveness to investors improved between 1995 and 1997. Terms became significantly more attractive in the Gulf of Mexico and Newfoundland, and changes in Alberta enhanced the allure of oil sands projects.
A trend toward differentiation in terms noted in the 1995 analysis continued in 1997. Countries increasingly varied systems and contracts to reflect differences in factors such as geology, costs, logistical conditions, water depth, and oil gravity.
A growing number of countries, including the U.S., also offered special terms for deepwater projects.
Key assumptions
The Van Meurs analysis uses a data bank of standard oil field sizes, well productivities, well depths, oil prices, and other factors to generate cash flows with which to test fiscal terms.
Onshore field sizes and the number of wells assumed to be needed for production are 3 million bbl of reserves and 7 wells, 10 million bbl and 16 wells, 30 million bbl and 34 wells, 100 million bbl and 79 wells, 300 million bbl and 171 wells, and 1 billion bbl and 398 wells.
The offshore assumptions are 30 million bbl and 14 wells, 100 million bbl and 27 wells, 300 million bbl and 51 wells, and 1 billion bbl and 100 wells.
The analysis assumes well depths of 3 km for both onshore and offshore fields and water depths for the latter of 100 m.
Well costs are assumed to be $2.8 million for onshore exploration, $2 million for onshore development, $5.1 million for offshore exploration, and $2.7 million for offshore development.
For standard field analysis, the study uses an oil price of $20/bbl, increasing at 3%/year. To rate fiscal systems it uses prices of $15/bbl and $25/bbl, rising at 3%/year.
The study further makes standard assumptions about timing and amount of work of various phases of field life.
It applies these and a number of other assumptions to generate cash flows to which various fiscal terms can be applied for assessment of effects on profitability.
For individual assessments, the study evaluates systems on both stand-alone and incremental bases. Stand-alone analysis treats a project as the first and only work by the investor in a particular country and contract area. Incremental analysis assumes that operations are under way. The different treatment accounts for considerations such as the immediate or future availability of income streams against which to write off expenses.
Ranking criteria
To compare fiscal systems, the study first ranks systems on the basis of each of the criteria, then weights the criteria and blends rankings into a weighted total. The criteria and their weighting factors are:
- NPV discounted at 15% per barrel-30%. NPV is total cash flow discounted to reflect the cost of capital. Since NPV varies with field size and oil price, the analysis assesses NPV and other of the criteria on a weighted basis against six onshore and six offshore fields of varying size at oil prices of $15/bbl and $25/bbl.
- Weighted ROR-15%. ROR is cash flow return on total capital, a basic measure of profitability.
- Weighted maximum sustainable risk (MSR) discounted at 15%-20%. MSR is the sum of NPV plus net exploration investment divided by net exploration investment, with all values discounted at 15%. The MSR is the number of times a company can expect to recover its exploration investment and shows the maximum geological risk it can take.
- Weighted, undiscounted GT-5%. The analysis assumes that governments and companies are the only participants in economic rent. In practice, surface owners, consumers, financial institutions, and other entities sometimes share the rent. The weighting of GT is relatively low because effects of government claims are already reflected in NPV, MSR, and ROR.
- Bonanza economics-15%. This tests the possibility of earning significant income on a very large discovery. It evaluates NPV per barrel discounted at 15% for an onshore 1 billion bbl discovery at an oil price of $20/bbl.
- Net incremental cost of exploration-2.5%. The analysis tests economics of exploration investments, undiscounted, against the existence of a 30 million bbl field within a single contract or license area. It simulates the possibility of developing a sequence of modest discoveries.
- Net incremental costs of development-2.5%. This parameter tests undiscounted development costs against a 30 million bbl field.
- Front-end loading-10%. To assess timing of a government`s claim on economic rent, the analysis measures undiscounted GT during the first 10 years of a project involving a 30 million bbl field. Investors prefer systems with low front-end loading, which enable them to recover their investments as quickly as possible.
Ranking the systems
The Van Meurs study ranks fiscal systems according to each of the eight criteria, then applies the weighting factors to produce a total weighted ranking.
A specific fiscal system thus receives eight individual rankings, one for each criterion. The analysis multiplies each ranking by the weighting factor for that criterion, then adds the eight weighted rankings to produce the total.
The analysis then ranks the totals. The system with the lowest weighted total ranking is the most attractive system to investors and receives the No. 1 ranking.
The study groups the rankings on the basis of simple statistics and ranks the groups with a coding system based on numbers of stars (Table 1). Systems falling in the group coded with five stars are very favorable to investors. Four-star systems are favorable to investors; three-star systems, average; two-star systems, tough to investors; and one-star systems, very tough.
World average system
The world average fiscal system, as calculated by Van Meurs, tends to punish small oil fields.
NPV per barrel discounted at 15% for a 3 million bbl field is a negative $3.03. For a 10 million bbl field it rises to 33¢. It rises to $1.17 for a 30 million bbl field, $1.58 for a 100 million bbl field, and $1.71 for a 300 million bbl field. For a 1 billion bbl field the value slips to $1.70.
ROR rises from 0.9% for a field with reserves of 3 million bbl to 17.9% for 10 million bbl, 31% for 30 million bbl, 51.1% for 100 million bbl, 71.6% for 300 million bbl, and 101.8% for 1 billion bbl.
The analysis notes that the survey is based on very profitable fields in order to be able to assess a full range of government treatments of cash flows.
The worldwide averages for NPR and ROR show how governments damage economics of small fields. With no GT, the 3 million and 10 million bbl fields would be reasonably profitable. Fiscal systems also hurt oil field development as costs rise past $5.50/bbl or crude prices fall to $10/bbl, even when fields are very profitable in the absence of GT.
World average GT is 96.1% for a field with 3 million bbl of reserves, 67.7% for 10 million bbl, 64.2% for 30 million bbl, 63.8% for 100 million bbl, 64.7% for 300 million bbl, and 66.5% for 1 billion bbl.
For incremental costs, the world average is $6.67 million for exploration incremental to a 3 million bbl discovery and $6.57 million for development in the same case. Costs fall steadily through the various field sizes to $3.58 million for exploration and $3.80 million for development incremental to a 1 billion bbl discovery.
Widespread use of royalties and cost oil limits for production sharing create front-end loading of the world average system. GT in the first 10 years of cash flow varies from 65.3% for a 100 million bbl field to 119.3% for a 3 million bbl field.
MSR discounted at 15% increases greatly with field size in the world average system. A 3 million bbl field is uneconomic, with MSR of 0.04. A 10 million bbl field has an MSR of 1.35, which means probability of success must be at least 74%. A 30 million bbl field`s MSR is 4.69, requiring probability of success of 21% or more.
The MSRs rise rapidly after that to 17.63 for a 100 million bbl field, 55.30 for a 300 million bbl field, and 180.66 for a 1 billion bbl field.
Gas systems
In a separate 1997 study for worldwide gas systems, "World Fiscal Systems for Gas," Van Meurs & Associates concluded that governments have been slow to account for economic disadvantages of gas discoveries relative to oil fields.
The disadvantages arise when gas discoveries occur far from markets and require installation of treatment or processing plants and pipelines and because energy-equivalent prices are often lower for gas at the wellhead than they are for oil.
The Van Meurs gas study examined 258 fiscal systems for gas in 123 countries. For 246 of the systems, both oil and gas terms were available for the same area, so comparisons could be made. The study made the comparisons on the basis of GT, with oil fields ranging in size from 3 million bbl to 1 billion bbl and gas fields from 36 bcf to 12 tcf. Economics were relatively attractive both onshore and offshore.
The study weighted results to produce a single weighted GT for oil and for gas (Fig. 3). Price assumptions for oil fields ranged from $15/bbl to $25/bbl and for gas fields, $1.75/Mcf to $3.25/Mcf. Assumed field lives for gas fields were longer than those for oil fields.
In 19 fiscal systems, GTs are 10-30% lower for gas than for oil. These systems strongly stimulated gas development.
Twelve systems modestly stimulate gas development with GTs 5-10% lower for gas.
A total of 200 fiscal systems have essentially the same terms for gas and oil, with GTs within 5% of one another.
And 15 systems discourage gas development with GTs 5-12% higher for gas than for oil.
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