Thomas R. Stauffer
International oil/finance consultant
Washington, D.C.
This article focuses on the costs of oil production in the major areas of the world, including OPEC and non-OPEC countries.
The question of production costs has become even more important since 1986, when the Saudis unilaterally undercut the oil price.
Previously, costs were less important; $30 oil could be profitably found and produced in 1980-when the price was $33. So $20 oil was quite unattractive as long as the oil price languished around $16-18/bbl.
The cost of competing, non-OPEC oil is therefore an important but uncontrollable parameter from OPEC's perspective.
Shaikh Yamani slashed oil prices in 1986 with three clearly articulated objectives:
- to reduce conservation;
- to stimulate global economic growth; and
- to discourage non-OPEC energy supplies of all kinds.
Here we address the last of those strategic objectives-squeezing out non-OPEC oil-by comparing oil production costs around the world. The analysis is framed with respect to five questions:
- How great is the variation in full costs of production within OPEC itself?
- Are the costs of OPEC and non-OPEC producers radically different?
- Are there producing areas today that are cost-constrained, meaning where E&P activity is limited by high costs in relation to expected prices?
- Has the Saudi "market share" strategy been successful in curbing non-OPEC oil development?
- Is it probable, as is often bruited, that lack of capital for new E&P projects might constrain future oil production, especially in the OPEC states?
DEFINING COSTS
Production costs are important signals of the prospectivity of areas, so analysis of those costs is the basis for assessing both future opportunities and also the likely success of OPEC's "low-price" or predatory pricing strategy.
"Cost" in this context is defined to reflect afl exploration and development outlays, including a 15% real rate of return.
The "cost" differs markedly from the more conventional figures for dollars spent divided by reserves discovered because it allows for timing effects and includes a target level of profitability. The "cost" is therefore higher.
Further, the calculations here exclude taxes and operating costs. Operating costs are excluded simply because reliable estimation is difficult.
Taxes are omitted since they are in fact flexible, rather than absolute, particularly outside North America. Taxes are often adjusted to fill the gap between price and full cost, i.e. to capture for the governments any economic rents. It is therefore more useful for purposes of comparison to look at the "costs" without taxes.
OPEC COSTS
The full costs of finding and developing new oil production differ strikingly around the world-ranging from a low of $1-2/bbl in the Persian Gulf to a high of $25 plus in North America.
The "Big Four" in the gulf - Iran, Iraq, Kuwait, and Saudi Arabia - stand out as doubly blessed and uniquely, low-cost producers: Not only are their reserves the most abundant in the world, but their production is also by far the world's cheapest.
Costs have increased over the last 20 years, but the inflated costs are still below $2/bbl. They are "the only game in town."
The simplest indicator of relative cost is the rate of flow of wells. Wells in the "Big Four" are by far the most prolific-the average flow rate in those four countries is better than 4,000 b/d (more than 100 times the U.S. average).
Wells in Saudi Arabia and Iraq yield 9,000 b/d or better (Fig. 1), and some Iranian wells both off and onshore registered 20,000 b/d.
But the disparities eve within OPEC are large: Saudi or Iranian wells can flow at 8,000-10,000 b/d, while those in Venezuela or Indonesia average less than 200 b/d. The latter yield, nonetheless, is still much higher than the average well in the Lower 48 U.S. or Canada.
Flow rates are only part of the story. Two additional factors must be weighed.
LOCATION, DEPTH
First, location is critical. A well offshore costs two to four times as much as a well to the same depth onshore, and an onshore well in Alaska costs four times what it costs in Oklahoma.
Second, well depth is important: a 12,000 ft well costs four to five times more than one at 5,000 ft.
Reflecting all three factors, full-cycle costs of finding, developing, and producing a barrel of oil, including a 15% rate of return, have been calculated for 22 OPEC and non-OPEC producers.
The range is wide.
Even within OPEC costs vary by a factor of 10 to one (Fig. 2). Costs in the older offshore areas in Abu Dhabi are now $7-10/bbl or more, and the fields developed by Adnoc and the Japanese are still more costly. Those fields, the Upper Zakum project and Bunduq, appear to cost over $20/bbl, possibly yet more.
On the other hand, costs for the "Big Four" are as little as $1/bbl and at most $2/bbl. Indeed, for those areas, since the well flow rates are so high, much of those costs are for field facilities or infrastructure.
POLITICAL CONSTRAINT
However, except for some offshore areas in Abu Dhabi and for low-value crude oils in Venezuela ' cost is not itself a barrier to new development for the OPEC countries. Where prospects exist, the limiting factor is the political will to expand operations, not costs or cash flow.
In particular, the availability of capital is not a meaningful constraint for the major OPEC areas; costs are still so low, that the financing of expansion, given the political will, is not a burden. The payback period for new wells is six months or less.
At most, 10% of annual revenues would need to be plowed back into replacing reserves or adding capacity to meet any probable growth scenario.
There is one possible exception: Iran will need much more capital to finance the gas injection schemes for reservoir repressurization. These are long overdue, and the anticipated capital needs for that undertaking alone come to about one year's gross oil export receipts, a daunting burden.
Elsewhere in OPEC, however, finance is an issue. Payout periods are much longer, as in Venezuela or Gabon, and tax policy becomes the critical question under such high-cost conditions for any private investor, while cash flow becomes a real constraint for a national oil company, such as Petroleos de Venezuela SA.
But in these areas, where financial constraints might be binding, expected incremental output is small. The effect is real but not material.
NON-OPEC COSTS
The pattern is quite different for most non-OPEC producers (Fig. 3).
Only a favored few, such as Malaysia or Oman, can expand it comparatively low full-cycle costs-circa $5/bbl.
Alaska North Slope costs are also in that range, but the constraint there is concern for the caribou, not economic costs. Otherwise costs are notably higher than in even the middle-tier of OPEC producers.
Mexico and Russia are quite different (Fig. 3). Estimated costs for Russia are theoretical. They are predicated upon Western technology and production standards, not upon reported ruble outlays or present oilfield practices.
Russia is potentially a rather low-cost producer - full costs should be less than $10/bbl and probably closer to $5-6, but - an indispensable qualifier - if and only if Russian producers gain access to better equipment, better procedures, and better management.
Here is why that calculation might be plausible: The yield to drilling in Russia is roughly 570 bbl of producible oil per meter drilled, compared with 100 bbl/m drilled in the U.S. and 130 bbl/m drilled in Canada symptomatic evidence o significantly lower costs, given that costs per mete drilled would be comparable.
The situation in Mexico is similar; the reported costs of $3-6/bbl are also normative, based upon what it would have cost U.S. companies to have developed the same fields, i.e. without including any allowance for waste, inefficiency, or peculation.
For both Mexico and Russia the geology is indeed favorable, and OPEC would need to worry about the implications for medium-term oil supply if either one were able to reorganize and streamline its producing sector. But there the constraints are political and institutional, not technical costs as such because the geology is inherently attractive.
HIGH COST AREAS
It is in North America and the North Sea where high costs are now potentially binding constraints. In both areas OPEC's "market share strategy" has begun to have an impact.
The full cost in the Lower 48 states of the U.S. is now some $25/bbl or more - which is higher than the price, even without operating costs or royalties. That high cost means that the industry is earning on average a rate of return that is much lower than 15%, probably rather closer to zero.
There are of course great differences across companies, and part of the high costs can be attributed to drilling funds operating at the margin with third-party funds.
Costs are high, though, even allowing for speculative operators, and those high costs in turn explain the rapid decline in drilling in the U.S. since oil prices peaked in 1981-82. U.S. and Canadian operators will need to retrench still further, limiting their exploration only to the very best prospects or directing their effort instead towards natural gas.
A second area is the North Sea, where new operations appear to be becoming marginal-full-cycle costs in both the U.K. and Norway are now very close to present market price: ' $13-16 on average. Since operating costs themselves average $36/bbl and must be added, the typical newer North Sea field costs over $18/bbl and barely returns 15% before taxes.
Because of these high costs, future development will hinge sensitively upon tax policy. Acceptable rates of return on new developments are possible only with generous tax treatment: remission of royalties, early expensing of exploration, and deductions for interest charges.
Margins for profit are thin, so the margin for error in fiscal policy is great, but both Norway and the U.K. have moved toward lightening the fiscal burden on smaller, now marginal fields. The 1993 U.K. tax changes clearly discriminate against new exploration; the logic behind the revisions is still opaque.
The cost-price squeeze is crucial, but the response of North Sea production and activity to today's lower prices is slow-the inertial effect. There still exists a backlog of fields that have already been discovered. These can still be developed at today's prices.
Even though high costs permit no real return to the sunk exploration outlays, the incremental rate of return on development alone is still acceptable, although the governments may see little net revenue from those fields.
CONCLUSIONS
Low prices, OPEC's 1986 policy for recapturing lost markets, were only partly successful because in most areas the fun-cycle costs of new oil production are still less than 1993's low oil prices, even allowing for a 15% rate of return to the producing companies.
Low prices have limited or jeopardized development of new oil principally only in three areas-the North Sea, U.S., and Canada.
The price reductions of 1986 have seriously cut into production potential in North America, where output is now falling. They have rendered medium-term development in the North Sea precarious.
Elsewhere, Saudi Arabia's "market share strategy," based upon a price in the high teens, has been less effective.
Oman and Malaysia can continue to expand, for example, because costs are still well below price, and prices would have to be cut much further to stymie possible developments there or in a few other non-OPEC producers. However, low paces more generally have indisputably slowed the pace of drilling because the industry's cash flow is much reduced, as is the taxable income against which drilling levels are dimensioned. This effect may have been as significant as the cost-price squeeze itself.
Thus OPEC-in particular the "Big Four" holds a commanding advantage with respect to costs, but there are still important areas where full-cycle costs are less than 1993 prices. In those areas output can be sustained even without a price increase. This is particularly the case when, as with Norway, the host government may be willing to sacrifice tax revenues in order to promote field development as a device to spur local employment.
Low prices therefore did not eliminate much non-OPEC production, but they did forestall further net increases in new non-OPEC output. Overall, non-OPEC production is essentially stagnant, whereas during the era of high prices, 19731985, non-OPEC production increased by some 10 million b/d. It may be shown further that they saved some additional loss of markets from new conservation.
Therefore, the policy did not fail, because prior to 1986 OPEC was steadily losing absolute market volumes at higher prices. That disastrous trend was summarily halted.
The policy, therefore, painful as it was to OPEC and non-OPEC producers, was a measured success, even though it only hobbled non-OPEC oil production rather than crippling it.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
