Middle East Economic Survey

VOL. LIII

No 7   

15-Feb-2010

Production Sharing Contracts – A Dying Breed?

By Helmut A Merklein

Dr Merklein is a consultant in oil and gas policies. He was Assistant Secretary of International Affairs and Energy Security at the US Department of Energy and Administrator of the Energy Information Administration (EIA) from 1984 to 1990. As head of the EIA, Dr Merklein was in effect the government’s chief energy analyst. Prior to joining the Reagan Administration, he was Professor of Petroleum Engineering at Texas A&M University. He can be contacted at helmut.merklein@ verizon.net. A version of this article was also submitted to Iraq Oil Report.

This paper was originally intended to analyze the production sharing contracts (PSCs) developed and implemented by the Kurdish Region Government (KRG). Given the scarcity of contract information in the public domain, it evolved instead into a generic probe of PSCs. Applying a PSC computer program to a proxy field, it provides answers to three controversial issues:

• Do PSCs provide adequate protection to host governments against windfall losses to oil companies?

• Are PSCs going the way concession agreements went in the early 1960s?

• Is there such a thing as a windfall-free oil exploration/production contract and, if so, what role could it assume in the Iraqi oil industry?

The answers, in short, are that: (1) no, PSCs, even multi-tiered PSCs, do not provide adequate protection against windfall losses; (2) PSCs will stick around for some time to come, especially in financially weak countries and/or in high risk and technologically difficult areas such as extreme deepwater reservoirs; and (3) yes, there is a windfall-free contract that, if nothing else, should be developed by all oil-producing governments, including Iraq, as the ultimate windfall yardstick.

This is strictly an economic/financial analysis. As such, it steers clear of any political or legal opinion. Instead, the paper develops government takes, oil company profits, and oil company internal rates of return of PSCs under a variety of oil pricing conditions. It does not endorse or reject PSCs. To the extent that it exhumes certain shortfalls in PSCs, it simply points them out and lets it go at that, leaving the reader to draw his or her own conclusion.

Introduction

Not all governments of petroleum exporting countries have the reserve base and potential financial clout to stand up to international oil companies (IOCs). Iraq does. At 115bn barrels of recoverable reserves, Iraq is going to be among the three largest petroleum exporters in the world. While the country has had its problems in securing funding for the development of its petroleum industry, that kind of reserve base can’t help but attract the capital funds it needs to do the job.

This is the story of unrecognized and missed (and, following the 12 December 2009 auction, partially restored) opportunities, the story of petroleum exploration/production contracts, of one-tranche and multi-tranche PSCs, of windfall profits and rents, and of windfall-free contracts whose potential for retaining the petroleum wealth in the host country has not been fully recognized. Missing in this narrative for lack of data is a discussion of the Iraqi Ministry of Oil service contract that, on the face of it, appears to hold considerable promise.

One of the most difficult tasks facing an analyst in the performance of his work is to explain a complex system to an informed audience that nevertheless is not familiar with the analyst’s field of specialization. Going too deep means losing the audience. Going too shallow means generating the impression of inadequately treating the issues at hand. This paper is a compromise. It introduces the never before addressed concepts of conventional and hidden windfalls from oil and gas exploration/production contracts in easily accessible terms, ie at a seemingly superficial level. Yet the results presented here are based on a fairly sophisticated computer model.

Oil and gas exploration/production contracts are certainly among the most complex contracts around. They attempt to find a satisfactory middle ground in negotiations between investors, more often than not foreign investors, who would like to get their hands on as much oil as possible, and host governments, who would like to keep most of it for themselves. To make things worse, these negotiations take place in a multi-country legal environment beset by erratic economic behavior, especially as regards oil prices.

This is a summary presentation dealing with the advantages and disadvantages of PSCs. The focus of the discussion will be on a one-tranche PSC and a three-tranche PSC that uses the R-factor as a means of controlling the collection of windfall profits (rents). A third petroleum contract, here called a Rate of Return or Utility-Service contract, will be contrasted with the two PSC versions. To be noted is the inclusion in the three-tranche model of some of the contract provisions as published by the KRG for their PSCs.

The methodology used in this comparative analysis was to apply all three contracts to a 110mn barrels field and to determine which of them would best protect the host government in holding on to windfalls that would otherwise be captured by oil companies. The analysis assumes that the price of crude oil rises from a base case level of $25/B to $50/B after the contract has been signed but before production has begun. Cumulative oil company profits, oil company internal rates of returns (IRRs), and host government takes accruing under various simulated conditions are discussed. Partial results of one sample run using a one-tranche PSC are presented in Figure 1. Its simplified three-graph pattern has also been adopted for a utility-service contract in Figure 2 and a three-tranche PSC in Figure 4.

In the computer model used here, only oil production and sales are taken into consideration. This implies that associated and non-associated gas will be collected and sold under different contracts to either the producing oil company or to third parties under conditions unrelated to the oil operations. Expansion of the program to include gas production is possible, but requires additional work.

The Field

Prior to its adaptation to Iraqi onshore fields, the original computer program used here was designed years ago for a non-Iraqi 110mn barrels shallow offshore field near the coast. Production was assumed to come from 24 producing wells on two platforms. First production began in year three after contract signing. Production would reach a brief plateau of nearly 29,000 b/d (10.5mn barrels/year) in the third year of production operations. A 10% annual decline from that plateau was assumed to set in two years later. Total capital exploration and development cost for the project was $336.5mn. Unit operating costs were $2.50/B in the first year of production, and assumed to rise at 3.0% per year thereafter.

The terms of the contracts used here are as follows:

• 20-year contract duration, set to coincide with the productive life of the field.

• A small non-recoverable exploration bonus (or signature bonus) of $1.0mn.

• A 10.0% royalty.

• A 40.0% set-aside of after-royalty revenue, for capital recovery.

• A 70.0% split of profit oil in favor of the government in the one-tranche case.

• Variable splits of profit oil in the three-tranche case, triggered by appropriate R-factors.

• A constant 25.0% internal rate of return in the utility-service contract.

• A 0% corporate income tax in deference to a US/host government bilateral tax agreement.

The costs and prices used in the model are low by today’s standards, but they were realistic when a first version of the underlying computer model was developed. The important thing is that the costs and prices are historically correct and internally consistent. The model can easily accommodate any oil price scenario to fit any specific onshore or offshore area or field where current cost data are available.

Using a low crude oil price for the base case that is then compared to higher price scenarios appears to exaggerate oil company windfalls, but this is not the case. Measured in dollars or in percentage increases, crude oil prices have actually risen by more than $25/B and certainly by more than 100% in the recent past. In addition, we are talking 20 years into the future in the face of rapidly growing oil demands by developing countries, especially in Asia and Latin America. Moreover, doubling the base case crude oil price of $25/B as was done here produces roughly the same increase in gross revenue as a 42% increase from a $60/B base price to $85/B, so the assumption regarding price movements is not out of line in the present context.

The full model, not presented here, focuses on annual government takes, oil company after-tax profits, and oil company internal rates of return, which are the three most important objectives of oil and gas exploration/production contracts. These target variables can be calculated under various simulated conditions. In this paper, the principal focus is on rising crude oil prices, but the impact of other factors can easily be calculated and simultaneously contrasted and plotted with pre-determined base-case scenarios. These other factors include the following: changes in bonuses; different types of bonuses (non-recoverable, recoverable as capital expenditures, recoverable as operating costs); drilling costs; operating costs; royalties; cost set-asides for capital recovery (or, alternatively, recovery through depreciation); government share of profit oil; and corporate income taxes and/or other taxes or fees.

Results of specific computer runs are presented in graphic and/or tabular form with brief discussions of what they mean to the host government. The government’s overall objective is, or should be, the capture of all windfalls, or at least most of them, while allowing sufficient incentives for oil companies to bid on and engage in exploration and production operations.

Windfalls

In oil and gas operations, windfalls are defined as profits that accrue to oil companies gratuitously, ie profits that fall in their laps for which they have not made any specific investment. No additional wells have been drilled, no enhanced recovery projects have been undertaken, no individual well stimulations or other operational improvements have been brought to bear on the oil field. Yet, when crude oil prices rise, profits to oil companies escalate at rates that exceed by far the profit potential of any other non-resource-producing industry.

Rising crude oil prices are the dominant reason for the generation of windfalls, but there are others as well. If crude oil prices in a fully developed oil field double, so does the total revenue from the field, even though production operations go on as before. With operational efforts and costs remaining unchanged, all of the revenue increase is available for distribution to stakeholders in the oil field, meaning the resource owner (generally the host government in foreign operations) and the oil company or companies. Windfalls are what oil contract negotiations are all about. There is no argument about the need to recover investments and operating costs, or to provide for a reasonable internal rate of return on investments. The bread and crumb analogy is solely about windfalls. Theoretically the resource owner, the host government, would and should capture all windfalls. In practice the windfalls are divided between the investor-operator and the host government based on the terms of the governing exploration/production agreement.

Conventional And Hidden Windfalls

The One-Tranche PSC is a contract that provides for a fixed split of the pre-tax profit oil between the host government and the oil company. The center panel in Figure 1 below shows that the oil company after-tax profit in our proxy field rose from an anticipated level of $538mn at contract signing to $1,280mn as the price of crude oil doubled. The difference of the two numbers, $742mn, is what is generally referred to as the windfall. We have opted to call this difference in profits the oil company’s conventional windfall, which is the windfall the company would have received under the underlying contract without regard to alternative opportunities. As will be seen later, this is by far not the entire price-induced windfall at stake.

Panel C in Figure 1 conveys a sense of the magnitude of the price impact on the overall gross revenue. Panel H shows what the government take and the oil company after-tax profit would have been before the price increase, and what they would be after it. Panel F shows the impact of the price increase on the oil company’s internal rate of return. These and other relevant numbers are reproduced in Table 1 for the reader’s convenience. They cover only the $25/B base case and the final $50/B reference case.

Table 1: One-Tranche PSC

The two significant discussion topics here are the increase the oil company’s IRR from 28.3% to 63.7%, and the rise in oil company after-tax profits that give rise to ‘conventional windfalls’. As mentioned. these windfalls do not reflect the totality of rents that accrue to the oil company. They are only the windfalls that are generated by this particular contract, under conditions as they existed at contract signing. Other contracts such as the three-tranche PSC, to be discussed later, and other starting conditions generate different windfalls, some more, some less.

Suppose the underlying contract was lopsided, favoring the oil company over the host government in its original contract terms. If that is the case, additional hidden windfalls exist that escape recognition and capture. If those hidden windfalls could be found and added to the conventional windfalls described here, we would come up with what I call the oil company’s total windfall.

If a zero-windfall contract could be identified and compared with the one-tranche PSC here under consideration, the oil company’s total windfall could be assessed. It so happens that there is such a contract that produces zero windfalls. That is the rate-of-return or utility-service contract, which is commonly used in the energy industry outside the oil industry, especially pipelines and the electric sector.

The Utility-Service Contract, see Figure 2, uses the internal rate of return as the profit allocation mechanism between the host government and the oil company. If oil companies could be persuaded to bid on the internal rate of return they want to achieve in a project, they could be expected to bid close to their opportunity costs, with due regard to their assessment of technical and country risks they would expect to encounter. Of course, they would want to bid higher, but competitive pressure in an open and transparent procurement would work against that.

Suppose a utility-service contract is put up for auction of a fully developed oil field and oil companies submit offers that range from a low IRR of 25% with several other offers not too far above and one or two complete outliers. That would be an indication that, for the field under consideration, 25% is the winning company’s opportunity cost. Under the terms of this contract, the oil company would receive year-after-year profits that would build up to and then stabilize at an internal rate of return of 25%, as bid on by the company. The contract would provide for adjustments in the distribution of profits, raising the oil company’s share as oil prices went down and vice versa. Royalty and tax formulations would remain unchanged, meaning that there still is a chance of failure for the oil company, as in any contract, if production does not occur as expected. This utility service contract, indexed to the oil company’s desired internal rate of return, provides zero windfalls. This is why the utility-service contract is used here as the zero-windfall reference contract. The principal results of a utility-service contract under the stipulated $25/B and $50/B scenarios are summarized in Table 2.

Figure 1: One-Tranche PSC (Simplified Presentation)

110mn barrel field, government profit share of 70%, royalty of 10% and zero profit tax due to bilateral tax agreement.

Figure 2: Utility-Service Contract (Simplified Presentation)

110mn barrel field, target IRR of 25%, royalty 10%, zero profit tax due to bilateral tax agreement.

Table 2: Utility-Service Contract

As Table 2 shows, the IRRs are not affected by price changes in this case. They remain at 25%, by design. Instead, respective government and oil company shares are adjusted to achieve the target rates of return. This implies, of course, changes in government take and in oil company profits. At a price of $25/B over the life of the field, it would take a government share of 70.3% to achieve the target rate of return under the utility-service contract. However, as the price of crude oil doubles, the adjusted government share would rise to 93.9%.

More intriguing is the fact that the project’s profitability remains unchanged, as expressed in identical IRRs before and after the stipulated price changes, while the oil company profits decline from $442 mn to $261mn, generating what appears to be a negative oil company windfall of $181mn. This ‘negative windfall’ reflects compensatory adjustments from oil companies to the host government in the face of rising crude oil prices. Under the terms of the utility-service contract, these adjustments serve to stabilize the IRR at its contractual target level. The reduction in oil company profits at a constant target IRR is the result of shifting massive sums of money forward, which is clearly depicted in the third panel of Figure 2. It takes less money to produce a given rate of return, all other things being the same, if the bulk of the collection occurs earlier.

Just how meaningless oil company profits (as opposed to IRRs) are as a gauge of profitability can be seen in the following example. If you financed an investment of $100 that yields $15.00/ year over 20 years (zero salvage value), your profit would be $200 and your IRR 16.7%. If you had the option of getting dividends at the rate of $27.00 for the first 10 years and $3.00/year thereafter, your profit would still be $200, but your IRR would rise to 34.7%, ie it would more than double. If another option yielded $3.00 for the first 10 years and $27.00 thereafter, your profit would still remain $200, but your IRR would be 9.1%. Same profit, vastly different IRRs, brought on solely by the time value of money.

Whether or not the use of the IRR is an acceptable standard as a profit allocation tool can and will be debated. However, it is the only standard that takes into consideration the time value of money, which plays a significant role in the profitability of oil exploration/production contracts.

As to the value of the IRR used here, 25%, this paper deals with Iraqi oil fields, many of which are already under production. These are fields where the geological structure has been identified through seismic surveys, the presence of oil has been confirmed by exploration wells, and productivity has been established through production tests. In short, many of the Iraqi oil fields have none of the geological-technical risks that are so characteristic for virgin areas. The only risks they have are political, and these are not inconsiderable. In any event, a 25% IRR does not appear to be unreasonable. If such a contract were to be offered at some time in the future, the minimum IRR threshold acceptable to oil companies would emerge soon enough. As will be seen later, that minimum IRR is a vital gauge for the companies’ opportunity costs against which the host government must measure its own opportunity cost to come to a rational decision on any exploration/production contract.

The problem is that contract negotiations generally deal with proposals on the table, rather than alternative contracts. This means that consideration is only given to windfalls that might be generated through price changes (or otherwise) under the contract at hand. With alternative contracts off limits, hidden windfalls are completely out of the line of vision. They are never given any consideration, and for most analysts they probably don’t exist.

Conventional, Hidden And Total Windfalls Under The One-Tranche PSC

Use of the utility-service contract as the zero-windfall reference contract, in comparison with the one-tranche PSC discussed above, leads to the concept of total windfalls. To reiterate, if the price of crude oil had remained at $25/B over the life of the field, there would have been no increase in oil company profits in the PSC, which would have remained at $538mn (Table 2). If the price had risen to $50/B and remained there for the life of the field, the one-tranche contract would have generated a profit of $1,280mn, with appropriate profit values in between. These profits are plotted in Figure 3.

The higher curve in Figure 3 represents the one-tranche-PSC curve for oil company profits. At $25/B, that contract produces zero conventional windfall. The oil company would earn the exact profit of $538mn it had in mind when it submitted its bid for a target IRR of 28.3%. It may have hoped for windfalls, but it would surely not bid below its opportunity cost under conditions as they exist at contract signing. However, at $50/B, that contract creates a conventional windfall of $742mn (from the $50/B price profit of $1,280mn minus the base case profit of $538mn).

The lower curve depicting the no-windfall utility-service contract shows reduced profits for a target profitability (IRR) of 25%. If the interested parties had signed a utility-service contract instead of their one-tranche PSC, the $25/B base price would have yielded an oil company profit of $442mn as opposed to the $538mn it would have gotten under the one-tranche PSC. The difference, $96mn, is the amount of money the host government would have lost under the one-tranche PSC. That lost amount of money is the oil company’s hidden windfall.

Figure 3: Conventional, Hidden And Total Oil Company Windfalls (One-Tranche PSC)

At $50/B, the conventional windfall of $742mn plus the hidden windfall of $277mn ($538mn minus $261mn) produces what I have opted to call the oil company’s total windfall of $1,019mn. That is the reality government negotiators face when they meet oil companies across the table. To be noted is the fact that the hidden windfall is not static. It would have steadily risen with rising oil prices from $96mn at a price of $25/B to $277mn at $50/B.

The Three-Tranche PSC (Figure 4) is a contract that provides for variable splits of the pre-tax profit oil between the host government and the oil company, as determined by the so-called R-Factor. The R-Factor is defined as the ratio of cumulative oil company receipts to cumulative expenses, as from the effective contract date. The three tranches under this contract provide for increasing percentages in government shares as revenues rise. The splits in favor of the host government in the contract used here are 60%, 70% and 80%, respectively, for R <1, 1 to =<2, and >2. The purpose of the R-factors is to mitigate the effect of rising oil company windfalls as crude oil prices rise. While R-factors reduce some of the oil company windfalls, they still leave substantial windfalls for the companies to reap.

As shown in the simplified Figure 4 below, when the price of crude oil rises from $25/B to $50/B, government take rises from $1,497mn to $3,792mn. At the same time, corporate profits rise from $573mn to $1,028mn, for a conventional windfall of $455mn, pushing the oil company’s IRR from 31.6% to 67.2%. Conventional, hidden and total windfalls, are developed in the discussion that follows.

Conventional, Hidden And Total Windfalls Under The Three-Tranche PSC

Again, the utility-service contract was used here as the zero-windfall reference contract and compared with the three-tranche PSC described above. Listed in Table 3 below are data from the base case and the $50/B excursion relevant to the discussion at hand.

Table 3: Three-Tranche PSC

There would have been no increase in oil company profits if the price of crude oil had remained constant at $25/B over the life of the field. If the price had risen to $50/B and remained there for the life of the field, the three-tranche contract would have generated a profit of $1,028mn, with appropriate profit values in between. These profits are plotted in Figure 5.

The upper curve in Figure 5 represents the three-tranche PSC curve for oil company profits. As discussed, that contract produces zero conventional windfalls at the $25/B base case. However, at $50/B, the three-tranche PSC creates a conventional windfall of $455mn (from the $50/B price profit of $1,028mn minus the base case profit of $573mn).

The base case utility-service contract in the three-tranche case is identical to the one used in the one-tranche case in Figure 3. If the interested parties had signed a utility-service contract instead of their three-tranche PSC, the $25/B base price would have yielded an oil company profit of $442mn as opposed to the $573mn it would have gotten under the three-tranche PSC. The difference, $131mn, is the amount of money lost by the host government under the three-tranche PSC. That lost amount of money is the oil company’s hidden windfall at base case conditions.

Figure 4: Three-Tranche PSC (Simplified Presentation)

110mn barrel field, government profit share of 60%, 70% and 90%, respectively, for R <1, 1< =<2, >2. Royalty 10%, zero profit tax due to bilateral tax agreement.

Figure 5: Conventional, Hidden And Total Oil Company Windfalls (Three-Tranche PSC)

At $50/B, the conventional windfall of $455mn plus the hidden windfall of $312mn (from $573mn minus $261mn) produces the oil company’s total windfall of $767mn.

Oil Company Profits

The preceding discussion shows that, indeed, the three-tranche PSC captures some of the windfalls that would have gone to oil companies under a similar unprotected one-tranche contract – nearly half of them in the cases here under deliberation. However, the utility-service contract does much better. It catches all windfalls. This is shown in Figure 6, where oil company profits of the one-tranche PSC and the three-tranche PSC are plotted against the utility-service contract (zero-windfall contract) used in this analysis.

To summarize the astonishing results of the doubled oil price scenario in Figure 6, the competitive 25% rate of return applied to this 110mn barrel field, after stripping of all windfalls, produces an after-tax profit to the oil companies of $261mn. That is roughly one fifth (20.4%) of what the oil companies would have gotten under a one-tranche PSC, and a quarter (25.4%) of what they would have received under the three-tranche PSC. A well-run national oil company will be running at, or even below, the lower zero-windfall curve in Figure 6, depending on the IRR that the government grants it. However, a poorly run and corrupt national oil company may well perform worse than the higher one-tranche curve. If nothing else, this shows why it is so important for oil-producing governments to undertake a serious analysis of going it alone.

The importance of the utility-service contract is threefold:

• It has potential for use as a model contract in actual bidding rounds in some applications, notably fully explored and/or developed oil fields of substantial size. Whether or not the utility-service contract will ever be used for that purpose remains to be seen but, in addition…

• It is an important analytical tool that should always be kept handy in a producing country’s toolbox. Use of this contract as an analytical tools is the only way for a producing country to assess hidden windfalls, which permits it to analyze and come to a rational decision between competing oil company proposals, especially for PSCs which do have substantial inherent windfalls, and...

• It is equally important for oil producing countries that have the potential of going it alone, as does Iraq, since it permits them to weigh its cost against their own national opportunity cost and thus to come to a rational decision regarding the threshold IRR where they would be better served by a national oil company.

Since the utility-service contract specifies the internal rate of return as the variable that determines oil company profits, it is, by definition, absolutely rent-free as long as the contract was awarded under transparent and competitive conditions. How such contracts, which are widely used in the western world outside the oil exploration/production industry, actually function has been discussed elsewhere. Hence this is not the place to repeat the argument. (See, for example, H A Merklein, ‘Iraq Contract Options’, MEES, 9 March 2009 or e-mail the author for an electronic copy).

Figure 6: Oil Company Profits

Conclusion

In view of the scarcity of publicly available data, what started out as a specific attempt to analyze the multiple-tranche KRG PSC evolved into a generic comparison of one- and three-tranche PSCs with the zero-windfall utility-service contract. The overall objective was to focus on windfalls inherent in exploration/production contracts, and on how to minimize or, if possible, eliminate them. Several of the KRG features of their published contract were used to make this work more meaningful within the Iraqi context. That said, no claim is made here that the study is a direct analysis of the KRG PSC.

The principal conclusions from this study are:

• All PSCs will provide substantial windfalls to oil companies as crude oil prices rise.

• Price induced windfalls accruing to oil companies under PSCs can be reduced, but never eliminated, through the appropriate use of R-factors and similar techniques.

• PSCs can be configured to essentially eliminate windfalls for one crude oil price, but they can never be designed to yield meaningful results over a range of prices.

• Windfalls should and can be avoided if the host government has a sufficiently large reserve base, technological background, and financial strength to stand up to the oil companies, which Iraq does.

• The Iraqi Ministry of Oil has been right, therefore, in insisting on service contracts.

• If acceptance by oil companies has been difficult, that only reflects the companies’ unwillingness to abandon a technique that has served them well, at the expense of host governments.

Considering the above, one wonders why US government advisors pushed so hard on PSCs. This is clearly not the type of contract to use on very large and fully developed oil fields. Recommending PSCs in preference to (or at the exclusion of) service contracts, operations by national oil companies, or other arrangements seems to have been misplaced.

Even though the second Iraqi licensing round has been successfully concluded and the oil ministry has made its point that PSCs are not the way to go in Iraq, the preceding analysis should still be of value to the ministry as it faces questions regarding the merit of its service contracts vs PSCs. The work should also prove helpful in convincing political authorities, especially the Iraqi Parliament, of the soundness of the ministry’s approach. An analysis of the Ministry of Oil’s service contract and its comparison with PSCs and with the zero-windfall or utility-service contract that served as the reference contract in this article would be particularly useful in this debate. With reference to Figure 5, there will almost surely be no conventional windfalls in the ministry’s service contracts, and probably sharply reduced hidden windfalls.

Will the recent events in Iraq bring on the demise of the PSC in the rest of the world? Probably not, at least not in the short run. But they will raise new questions that were largely ignored in the past. They will lead to the realization that there are workable alternatives to PSCs and that some of these alternatives will be considerably more favorable to host governments. As mentioned, in the case of proven reservoirs with large reserves, relatively easy access through standard technologies, and acceptable political risks, the PSC is likely to give way to service contracts, to utility service contracts, or to exploration/production operations through host government national oil companies. Future winning competitors in public auctions offering licenses for these kinds of fields will not be the large international oil companies. The new entrants will increasingly be independent producers and domestic and foreign national oil companies, which are already entering into competition with the majors and which oftentimes have additional non-profit objectives in mind such as securing future oil supplies for their national economies. The Chinese companies are an example of aggressively competitive players in the petroleum industry, but there are others including, for example, the national oil companies of Angola, Malaysia, India, Indonesia, Russia, Turkey, and Vietnam that participated in the two 2009 auctions in Iraq.