Helmut Merklein
Pre-1960 concession agreements gave way to production-sharing contracts that eventually came to dominate international exploration-production agreements, even though strongly resisted by the Western petroleum industry when first introduced in Indonesia. Political-economic conditions prevailing at the time no longer supported concession agreements, whether the international oil community liked it or not, and they practically vanished from the world scene. The production-sharing contracts that replaced them provided the incentive for heavy investments in risky oil ventures while allowing host governments to retain better control over their oil resources, and they offered greater flexibility in designing contractual formulations that gave the governments access to increasing amounts of windfall profits, which is what the tug-of-war between international oil companies and host governments is all about.
This article discusses the forces set in motion through the recent rise in crude-oil prices, focusing on Iraq, to set the stage for a discussion of other oil-producing countries and their current and expected attitudes towards production sharing versus service contracts.
RESERVES AND PRODUCTION POTENTIAL
The Iraqi Oil Ministry currently carries a reserve base of 115 Bbbl on its books. While these reserves are uncontested, there is considerable disagreement as to what that means in terms of production potential.
To cut through the confusion, it is helpful to differentiate between what may be called a country’s absolute production potential, and its realistic production potential. By absolute production potential is meant the production rate that would be achieved if all of a country’s reserves could be developed and placed onstream at the same time. In terms of practical applicability, the idea of developing and producing a country’s entire reserve base at once is technically impossible and financially absurd for most countries, especially for a country like Iraq, which has among the world’s highest reserves but a relatively underdeveloped, partially destroyed, and heavily deteriorated petroleum infrastructure. But the concept is important, as it serves as a reference point characterizing the strength of its developable oil potential.
Under normal operating conditions, and taking into consideration life-prolonging efforts in producing fields such as work-overs, well stimulations, and secondary and tertiary recovery projects, as well as deliberate under-production in most fields during the early production-plateau years, the average decline rate of producing fields runs around 5-6% per year. That is about half of the unrestricted decline rate of roughly 10% that would be experienced worldwide in the absence of production plateaus, workovers, etc. That unrestricted decline rate, applied to Iraq’s reserves of 115 Bbbl translates into an absolute production potential in excess of 30 million bopd. If that sounds far-fetched, consider that the US produced 5.1 million bopd in 2006 from a reserve base of 21 Bbbl. That corresponds to 8.9% of its reserves, which is about as much as can be expected from a highly competitive petroleum industry of a technologically advanced country operating hundreds of oil fields approaching abandonment.
Similarly, Prudhoe Bay Field in Alaska, with its original reserve of 10 Bbbl, produced 2 million bopd, or right at 10% of its absolute capacity at the time. This was a case where the field had been almost fully developed while the 800-mi Alyeska pipeline was under construction, so that almost all of the field came online at once. All in all, Prudhoe Bay produced in excess of at 1.5 million bopd for 14 years, and more than 1 million bopd five years after that.
Compare this with the East Baghdad Field in Central Iraq, which is equivalent in size to the US Prudhoe Bay Field at 11 Bbbl. That field produces only 50,000 bopd. Labeled a “good prospect” when found in 1975, it turned into a giant field by the time it was fully appraised. Yet it never produced more than 50,000 barrels per day after being placed on production in 1982 even though, by US standards, it should be producing around 1.5 MMBPD.
Extrapolate the capacity of the East Baghdad Field to expand Iraqi production, and it becomes clear that Iraq has the potential to raise production to just about any level that the world market can absorb. The Iraqi Oil Ministry believes that oil production can be restored to, and beyond, earlier OPEC quotas, and history is on its side. As shown in Fig. 1, Iraq actually did produce well above its highest ever OPEC quota in 1979, delivering an average of 3.48 million bopd for an entire year, and it again approached the 3-million mark in 1989 and in 2000.
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Fig. 1. Iraqi crude production and OPEC quotas.
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So much for Iraq’s productive capacity. That leaves the question of how quickly that capacity can be developed. The historical evidence depicted in Fig. 1 shows that Iraq was able to raise production by 920,000 barrels per day in the one-year interval of 1978-1979, and by 990,000 bopd in 1997-1998.
Given the credibility of its 115-Bbbl reserve and its historically proven ability to substantially raise production at record speed, the plans of the Iraqi Oil Ministry to nearly double production to 4.5 million bopd in five years is conservative. Focusing on oilfield development only and leaving out infrastructure rehabilitation, western consultants generally are more optimistic. After all, during the three-year interval 2005-2008, a period when sabotage and fighting were still under way and when the intensive reserve-development phase of today had not yet begun, production was raised by 550,000 bopd. Today, with a clear commitment to seek international assistance in a much calmer environment, the production of 4.5 million bopd in two years, and 6.0 million bopd in the coming 5-10 years is an achievable policy goal.
Apart from a resolution of internal political issues, the only technical question that remains is, under what contractual conditions and at what price. To understand the pricing issue, the concept of rents or windfall profits that are potentially associated with oil production must be understood.
Windfall profits appear in oil production primarily for one of two reasons: unexpected increases in oil prices or discoveries of oil fields that turn out to be significantly larger than anticipated. The world is witnessing at this very moment the largest and most rapid increase in crude oil prices in the history of petroleum production. From a macroeconomic perspective, this involves a shift of wealth from oil importing nations to oil exporting nations, through the intermediate action of inflation that robs consumers in oil importing nations of purchasing power. For the corporate oil producer, these windfalls provide profits far beyond risk-adjusted competitive levels because the oil from a given field is produced at the same rate and in the same quantities as before, but that production now generates substantially more revenues without further investments.
PSCs AND WINDFALL PROFITS
To quantify windfall profits, computer calculations were conducted to examine the effect of different price increases from a base of $25/bbl, which corresponds roughly to the average Europe Brent spot price of $23.75 over the period of 1979-2004. The specific objective was to determine what happens if an oil company signs a Production-Sharing Contract (PSC) on a 100-million-barrel oil field at a time when oil prices are $25/bbl, under various subsequent price scenarios, where the increase in oil prices occurs during exploration operations, before the field is placed onstream, and remains at the higher level throughout the field’s productive life. The results of these calculations are shown in Table 1.
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TABLE 1. Windfalls as crude oil prices rise. Higher price over field life
Click table to enlarge.
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The top row in Table 1 lists the various prices under investigation, where the red cells identify the cases discussed in some detail below. The base case results are shown in the $25 column on the far left. As that column illustrates, at a price of $25/bbl, a 100-million barrel field will produce cumulative gross revenues of $2.5 billion. After deducting capital cost entitlements, production costs and the signature bonus, and applying the model’s 50/50 split and 30% production tax on gross corporate profits, the cumulative revenue accruing to the government is $1.20 billion. This compares to oil company after-tax profits of $650 million, or an internal rate of return of 24.5%.
The base-case windfalls listed in the Table 1 are zero, i.e., the $25 base case yields no rent. Doubling the price of crude oil from $25 to $50 will double the field’s gross revenue, but in the face of unchanged production costs, the net revenue is more than doubled (not shown). After splitting the net revenue in accordance with contractual provisions, the government revenue rises from $1.20 to $2.83 billion, while the oil company after-tax profit increases from $650 million to $1.52 billion. The increase in corporate after-tax profits from the base case are windfall profits that escape capture. At $870 million, they exceed the rent-free profits the oil company had counted on when it submitted its proposal. The bottom cell in the $50-column shows that the internal rate of return of the oil company nearly tripled to 71.8% in the face of doubled crude oil prices.
The $70 case was considered the extreme case a short two years ago, before spot prices rose to $140 in June of 2008. At $70/bbl, oil company profits rise from the $650 base case to $2.22 billion, for a windfall of $1.57 billion and a rate of return of nearly 103%. A price increase to $125/bbl raises the oil company’s after-tax profits to $4.15 billion, its windfall to $3.5 billion, and its internal rate of return to 167%. The $150 case raises windfall profits and the internal rate of return into the stratosphere.
More realistic results are obtained when price increases are spread out over the 20-year life of the field. Calculations were made for oil prices rising to 50, 70, 100, and $125/bbl, in accordance with the schedule shown in Table 2. For example, in the $50 case, the $25-base price had risen to $35 by the time the field was placed onstream, with subsequent price increases to $40 in the sixth year of production, to $45 in the eleventh year, and to $50 in year 16. The results of these calculations are shown in Table 3.
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TABLE 2. Staggered price increases
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As can be seen, the $50 staggered price scenario produces oil company windfalls of $510 million and boosts the rate of return to 45.5%. At $70, the windfalls rise to $850 million, pushing the rate of return to 55.4%. The corresponding windfalls in the $100 and $125 case are $1.30 billion and $1.68 billion, producing rates of return of 65.5% and 74.2%, respectively. The model that produced these calculations did not take into consideration protective triggers that shift revenues in favor of host governments when certain agreed-upon milestones are reached.
Ideally, actual negotiations should be based on a specific host-government-designed exploration and production contract and a computer program to back it up. This keeps the initiative in the government’s hands and it avoids the burden the government would face in having to develop new computer models for every variation offered by oil companies over a prolonged period of negotiations. For the purpose of this discussion, if one assumes that the various protective clauses capture half the windfalls that price-induced changes would generate, a simple extrapolation of the results in Table 3 suggests that the oil company windfall would be on the order of $425 million and its rate of return would rise from the 24.5% to roughly 40% in the $70 staggered-price-increase case.
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TABLE 3. Windfalls as Crude oil prices rise. Staggered price increases over field life.
Click to enlarge table.
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The preceding calculations cover a minor (by middle Eastern standards) 100-million-barrel field. Applied to a country’s entire uncommitted reserve base, the amounts at stake are truly staggering. No wonder governments are seeking alternatives to PSCs. In the case of Iraq, it is a little surprising that the US government failed to see the draw-backs of these contracts and kept pushing them (and privatization in a region where national oil companies are universal) in its discussions with the Iraqi government.
SERVICE CONTRACTS AND OTHER OPTIONS
In Iraq, there has been strong opposition to PSCs in Parliament and some reluctance in adopting them within the Oil Ministry. A Power Point Presentation published by the Ministry titled “The New Structure of the Iraqi Oil Industry” proposes to give the improved service contract first preference over PSCs. One would expect that this message has been reinforced in face-to-face discussions with the 41 prospective bidders for long-term contracts that are scheduled for finalization in 2009. Surely, observers and players in the petroleum industry will be watching with keen interest how many of these 41 respondents will opt for service contracts.
The five two-year Technical Support Agreements (now reduced to 12 months) that were designed to develop 500,000 bopd by putting the development of five existing oil fields on a fast track also point in the no-PSC direction. Originally intended for signature at the start of 2008, negotiations on the technical support agreements had not been completed by the end of June, and both sides show signs of frustration. Having lost six months in “fast track” contract negotiations, Minister Al-Shahristani seems prepared to consider alternative options.
SHORT TERM OPTIONS
Taking it for granted that the production sharing option is not on the table and that the term of the technical support agreements is limited to 12 months, three alternative options appear to be available. They are: risk service contracts, no-risk contracts, and pursuing oilfield development through the Iraq National Oil Company.
Risk service contracts. Generally, in a risk service contract, the contractor bears the risk for the investment. The central issue regarding risk service contracts revolves around the method of payment. If the oil to be used to reimburse the contractor is specified in volumes, the contract retains its vulnerability to price-induced windfall losses. The exception would be to use oil as a means of payment for agreed-upon fixed dollar fees, valued at market prices as of the transaction date.
These contracts can be quite lucrative. Their advantage is that they engage both the technical expertise and financial resources of the contractor. They are particularly well suited in cases where the investment risk is low and the host government lacks the resources to finance its own development. Proven but undeveloped fields in developing countries would be likely targets for such contracts, now that the $100-plus price of crude oil has improved the economic viability of such fields, as would be the Iraqi producing fields here under discussion.
If negotiations on the five fields now under consideration fail, the proposed Iraqi technical support agreements in their current or in altered forms could be offered to the full set of the 41 eligible oil companies. The advantage of this alternative is that the companies now on the list have been pre-cleared, which permits almost immediate implementation. If time permits another round of reviews, large oil field service companies capable of securing funding for a $500 million oil production development project from known giant oil fields could be included. Names like Halliburton, Baker-Hughes, Schlumberger and Weatherford International come to mind. Funding would likely use significant equity participation by the contractors, with outside commercial or institutional debt infusion, which the service companies may or may not be in the position to provide, as per their internal corporate policies.
No-risk service contracts. These are contracts in which the resource owner, the Government of Iraq, bears the risk of the project. This would require that the Government of Iraq pledge its reserves against the loans that the contractors would need to implement their projects. Such an arrangement would permit the inclusion of well-established independents who have the required expertise but lack the needed funding capability.
The five fields under consideration are all producing on-shore fields where independent producers have excelled for decades. They are familiar with conventional and horizontal drilling techniques, well completions and recompletions, and artificial lift technologies, secondary oil recovery, and similar methods used to stimulate production from ageing, declining or underperforming fields.
The Oil Ministry has taken great care in selecting established oil companies with Iraqi experience as its first choice for partners in its technical support program. The Ministry’s aversion to risk-taking under the circumstances is understandable. Yet if an agreement cannot be forged because the international oil companies cannot bring themselves to accept what to them must appear to be a revolutionary turn to untested or undesirable financial arrangements, it may be well to remember that the production-sharing contract that they adhere to now was passionately opposed by them some four decades ago, when a tiny independent producer no one had ever heard of, the Independent Indonesian American Oil Company, developed and signed the very production-sharing contract that dominates the industry today.
Development through the Iraq National Oil Company. If it were not for the urgency to develop immediate and massive funding for the reconstruction of the Iraqi economy, there would have been no need for short-term technical support agreements. Of course, one could make the argument that the most recent price increase has lessened the pressure for outside funding. The average price of crude oil was $72/bbl in 2007, when the plans for the five oil field projects to be quick-started were drawn up. By mid-2008, these prices are running in the $130-40 range. The associated windfalls, if fully captured by the Iraqis, would easily provide the needed reconstruction funds now, instead of 18 months or two years down the road, as per the original intent of the short-term agreements.
LONG TERM CONTRACTS
On the assumption that the Oil Ministry meant it when it stipulated that the new structure of the Iraqi oil industry proposes to give the improved service contract first preference over PSCs, what are the long-term options beyond the 12-month technical support agreements?
This section briefly describes two long-term options. The risk utility service contract, and the option for Iraq to pursue upstream oil activities on its own.
The risk utility service contract. If a long-term cooperative route is chosen, with multinational oil companies undertaking heavy investments, there is a type of contract that truly captures all of the rent while providing desired rates of return. This is what one may call a utility service agreement, in which a freely and competitively negotiated internal rate of return is the bidding, trigger and target variable, rather than one of the many trigger variables discussed earlier that are generally used for contractual adjustments elsewhere, in favor of host governments. In the utility service contract, adjustments are made by compensatory revenue payments, up or down, to make sure the agreed-upon rate of return is maintained. Anything beyond that rate belongs to the host country.
Utility contracts are commonplace in the US and in Canada where they have been used for decades in the electric and natural gas distribution and transmission sectors as regulatory tools to control excess profits by setting prices at levels designed to achieve quasi-competitive target rates of return. But there is a difference between the US utility contracts and those discussed here in connection with Iraqi oil production. The regulation of Iraqi production operations, where prices are set extraneously in competitive world markets, would require adjustments of recent revenue payments to oil companies to achieve the contractual rates of return.
This is a novel concept in the petroleum industry that will probably not be particularly appreciated by international oil companies. But then, the introduction of production sharing agreements by Indonesia in the 1960’s was also novel and fiercely opposed by international oil companies, only to become the standard today. Standards evolve, and beneficiaries of existing standards will always be opposed to the development of new ones, especially when their winning position is at risk.
The utility service contract proposed here has its pro’s and con’s. From an oil company point of view, the upside is that it protects against losses if prices collapse. The downside, or so the companies would have you believe, is the need for an exceedingly detailed accounting procedure. That, however, is a flawed argument, since detailed accounting is required in any event, for tax purposes and for the determination of profit oil in production sharing or other types of contracts. Moreover, accounting expenses are routinely charged against oil production, so that the host government in effect reimburses the oil company for these costs.
In the end, if the utility contracts are such a good deal, why are they not widely used in the international oil business? They are not in use because most host countries are not in a strong enough bargaining position to impose them. Not so in Iraq, which holds all the cards, since it could, but does not have to, engage the cooperation of multinational oil companies. In fact, working with multinationals in up-stream operations, even under a utility service contract, is a second-best solution, compared to going it alone. Iraq’s natural inclination should be to develop its oil reserves on its own.
Iraq NOC pursues oilfield developments unilaterally. There has been talk of privatizing the Iraqi oil industry in order to attract foreign capital and speed up recovery. That policy makes sense for all energy sectors, except the oil exploration and production sector. Oil production service industries (drilling, logging, seismic, well stimulation, etc.) and other oil-related industries (refineries, pipelines, marketing facilities, distribution networks, etc.) could and probably should be privatized in whole or in part. Iraq needs a vibrant oil industry characterized by a competitive environment that has the capacity for rapid technological development, and that responds quickly to changing circumstances.
However, privatization does not make sense for the oil exploration and production sector of a country that in a few years will be the fourth largest oil producer in the world, after Saudi Arabia, Russia and the United States.
The one thing that sets oil production apart from other industrial activities, including down-stream oil activities, is that it is in oil production where rents accrue-huge rents. These rents, like all rents or windfalls, belong in principle to the resource owner, the people of Iraq. However, they will not accrue to the people, unless a mechanism can be devised to capture them. The obvious way for the Iraqis to remain in control of their oil wealth and to capture all of the oil-related rents is to leave the Iraq National Oil Company intact and to put it in charge of all upstream operations. If so, can they on their own attract the funds that will be needed to restore production to or beyond pre-war levels? The answer is yes, because essentially no exploration and not much new development is needed, and the funds that will be required are dwarfed by the wealth represented by already proven but undeveloped reserves.
The five technical support agreements offered by the Oil Minister have a combined price tag of $2.5 billion. Assuming a net revenue of $100/bbl, the loan required for the development of 500,000 bopd of productive capacity would be a minute fraction of one percent of the value of Iraq’s proven reserve base, 0.022% to be exact. Pledging $2.5 billion against that base would be like securing a $250 loan with a fully paid-for readily sellable asset of $1.2 million. With that kind of collateral, there will be no shortage of commercial or governmental (bilateral or multilateral) credit institutions eager to supply the capital needed to rehabilitate oil production in Iraq, provided of course that peace and tranquility reigns in the country. The payout on the $2.5 billion investment would be a matter of months, once production is under way.
Given the fact that Iraq has the proven reserve base from which to proceed and that the investment required to get Iraq production back on par is minimal, the question is whether the country has the technical know-how and the financial wherewithal to do it on their own. As to the technical know-how, the Iraqis have been producing oil for the last 36 years, i.e., since they assumed control of their petroleum industry in 1972. They are quite capable of boosting production without the help from international oil companies. They have the experience, they have a lot of practical know-how, and they are known to be inventive and flexible. Moreover, it is widely acknowledged that the deterioration of the oil infrastructure is more a reflection of severe decade-long budgetary constraints imposed during the Saddam Hussein regime and wanton destruction thereafter, rather than a lack of know-how.
Whatever the Iraqis don’t have by way of technological advances, they can acquire through outsourcing in the open market, much like the multinationals do when they turn to seismic firms for exploration, drilling firms for drilling, logging firms for geological reservoir delineations, and reservoir engineering firms for reserve definitions and production optimization.
Minister Al-Shahristani said as much this past April, when he grew impatient with the oil companies’ slow response to the technical support agreements pointing out that “June is a bit late. If they are not ready by then we might not really require technical service contracts... we may drop them if they are not signed soon.”
FINAL OBSERVATIONS
Time and space do not permit to deal with some significant issues that need to be resolved, if Iraq is to gain the trust of foreign partners. The greatest risk by far associated with the establishment (or, in the Iraqi case, continuation) and use of a National Oil Company is political interference, well-meaning, misguided or fraudulent. Labor practices are among the most prominent of well-meaning but grievously costly errors. Errant workers at all levels must be subject to corporate discipline, including the ultimate corporate penalty, dismissal.
The risk of misguided political interference covers the imposition of political criteria on corporate decision-making, at times for the noblest of causes. Using the corporation as an employer of last resort to “fix” otherwise intractable unemployment problems, allocating capital funds for local economic stimulation, developing marginal fields in ethnically deprived areas while higher prospectivity projects are available elsewhere, these and many similar practices are things that profit-driven corporations will avoid. Finally, the risks associated with fraud and corruption are likely to be more prevalent in national companies and are a realistic danger to guard against through appropriate corporate oversight, especially when salaries are deliberately kept low as they are in many countries that are trying to avoid structural salary imbalances.
Ideally, a national corporation needs to be run like a private corporation. That includes the development and enforcement of strict ethical standards, freedom to contract with corporate and financial entities, and reasonable criteria in setting their own budget, subject of course to enlightened governmental oversight through an independent Board or Commission that conducts general and targeted audits through independent accounting firms of international stature.
To achieve the near-autonomous corporate structure advocated here for the Iraq National Petroleum Company, the Petroleum Ministry should limit itself to what Ministries are meant to do: monitoring and guiding national petroleum policy and submitting legislative proposals to Parliament and enforcing the laws that emerge from it. The Petroleum Ministry should not be actively involved in any of the National Oil Company’s day-to-day operational activities. The stakes are simply too high to ignore this fundamental axiom of separation of powers. 
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