INTERNATIONAL PETROLEUM AGREEMENTS—2: Embargo of '73 launched era of mutual adjustment

In the low-price environment of the 1980s and 1990s, many host countries adopted policies to promote E&P
investments in their territories by offering more-attractive terms and conditions to foreign investors.

For international petroleum agreements (IPAs), oil scarcity led to the demand by many oil-producing countries for the newer production sharing and risk service agreements or for a new concession agreement with so-called OPEC terms (OGJ, Sept. 7, 2009, p. 22). These terms consisted of high royalty rates (up to 20%) and taxation rates (up to 85%), coupled with majority state participation schemes.

In some cases, the new demands led to nationalization by the host country (HC).

State interest

One of the key objectives of OPEC and other producing countries in the early 1970s, prior to the 1973 oil embargo, was to obtain a high state participating interest in the existing concession agreements.

Minority state participation was already in force in several countries. Kuwait, for example, had negotiated a 15% participation rate in a concession with Aminoil in 1948 and a 20% participation option in case of discovery in a 1961 concession agreement. Other countries with minority state participation at that time were Iran, Egypt, Congo, Gabon, Algeria, and Nigeria.

The New York agreement of Oct. 5, 1972, signed between OPEC and a group of international oil companies (IOCs), provided for a 25% HC participation to begin on January 1973, increasing by steps to 51% in 1982. Indeed, a movement towards state majority participation or full nationalization took place in the 1970s in several major exporting countries. Among those countries were:

When HCs nationalized the oil industries, they usually entered into technical services agreements with the former foreign concessionaire for the provision of expertise or consulting services without any direct access to the production by the IOCs. For example, Kuwait, Qatar, Saudi Arabia, and Venezuela followed this course.

In OPEC countries where the concessionaires were not fully nationalized, such as Oman and the UAE), the concession agreements continued but were amended to achieve majority HC participation and increased taxes on the IOCs.

Most oil-producing countries followed this trend, even Western countries where petroleum reserves were found. For example, Norway created its own national oil company, Statoil, in 1972, which was granted an option for majority state participation in the event of commercial discovery.

Privatization of NOCs

In the 1980s, another "oil shock" occurred, but this time it was the shock of sharply falling oil prices. In 1986, the price of crude oil fell to about $8/bbl.

In this low-price environment, many HC governments sought to privatize their state-owned oil companies, led by governments in the Organization for Economic Cooperation and Development (OECD) countries. Privatization was first observed in the UK with British Petroleum, British Gas, and British National Oil Co., then in France with Elf and Total, Italy with Eni, Spain with Repsol/Hispanoil, and Canada with Petro-Canada.

The movement then spread to developing countries. For example, Argentina privatized its national oil company (NOC) in 1993, which was taken over by Repsol in 1999. Brazil partially privatized Petrobras, which, though still a state-controlled company, lost its 45-year monopoly over exploration and production (E&P) in 1998.

In Norway, Statoil was also partially privatized, but as in Brazil it remains a state-controlled company. In addition, Norway created a separate entity, Petoro, which is fully owned by the state for the purpose of independently managing Norwegian HC participation interests, known as the state's direct financial interests.

Following the break-up of the Soviet Union in 1991 and the creation of the Russian Federation and the Commonwealth of Independent States, the Russian Ministry of Fuels was reorganized to create many local state-owned companies, some of which were privatized. A similar movement toward minority privatization of NOCs is now occurring in China.

In tandem with the privatization of NOCs through the sale of shares to international investors, many countries opened E&P acreage to IOCs. This opening is another way for the HC to "privatize" domestic oil operations by entering into international petroleum agreements (IPAs) with IOCs. China, Russia, Azerbaijan, Kazakhstan, Turkmenistan, Romania, Ukraine, Hungary, and Poland have followed this course.

The same trend occurred on a large scale in Latin America, with licensing rounds open to foreign investors in Argentina, Bolivia, Brazil, Colombia, and Ecuador.

Venezuela also decided in the 1990s to reopen its E&P sector to IOCs, through the signing of 32 risk service contracts (contratos operativos) resulting from three licensing rounds organized between 1991 and 1997, as well as the signing of other types of agreements. These contracts included projects to reactivate mature fields under "operations contracts," to explore eight exploration blocks, and to develop extra-heavy oil reserves in the Orinoco Belt through four "strategic alliances" with IOCs.

Since 1995, Iran has signed over 20 risk service agreements with IOCs, the first with Total in 1995. Algeria, Angola, and Nigeria all increased the awards of blocks to IOCs.

However, four countries with major reserves and resources of interest to the IOCs remain closed to foreign direct investment:

• Mexico, except for operations under "multiple-service contracts" signed with Pemex for increasing gas production in selected areas.
• Kuwait, where the award of risk service agreements called "operations services agreements" has been under consideration for a long time.
• Saudi Arabia, except for natural gas development where Saudi Aramco's monopoly was ended by the signing of four "upstream agreements" with IOCs, awarding the IOCs a license for the exploration, development, and production (including transport of gas and related products) of gas from nonassociated gas reservoirs.
• Iraq, with the exception of a few PSAs and service contracts. However, Iraq is expected to promulgate a new petroleum law providing for IPAs with foreign companies and has begun negotiating agreements.

Easing terms

In the low-price environment of the 1980s and 1990s, many HCs, with the exception of the largest exporters, adopted policies to promote E&P investments in their territories by offering more-attractive terms and conditions to foreign investors and to interest these investors in more-costly ventures, such as deep offshore areas, deeper reservoirs, heavy oil, or natural gas.

As a striking example, the UK marginal government take, which peaked at over 90% in 1982, was gradually reduced to 65% for "old" fields developed before 1993 and reduced to a mere 30% for new fields developed after 1993. The UK government's objective was to maximize the benefits to the nation through the development of local industry and manpower rather than simply looking for tax revenues.

The easing of fiscal terms in the UK and some other producing countries was noticed by other countries that were engaged in assessing their legislation and contract terms prior to organizing licensing rounds or preparing negotiations with IOCs.

The trend toward more favorable terms for private investors was implemented through new policies adopted by oil-importing countries which had domestic petroleum sources that supplemented imports from abroad. These new policies were designed to foster domestic E&P activities through reductions or waivers in royalty rates, lower HC participation, or lower income tax rates. The host countries and IOCs also mutually agreed to negotiate and adjust, usually at the IOCs' request, the terms of IPAs entered into before 1986 in the era of higher prices.

HCs wanted to encourage new investments, which would have been only marginally profitable under the original IPAs after prices dropped. Indeed, in the 1990s, many HCs were competing with each other to attract foreign capital in a period of reduced investments in E&P. This competition led to growing opportunities for investors to gain access to newly opened areas.

In addition to the award of E&P contracts to explore new fields, more countries provided incentives to invest in existing fields by offering agreements to extend the producing life of older fields, to carry out enhanced oil recovery projects, or to develop natural gas discoveries.

Also, since 1980, HCs and IOCs have focused more attention on the environmental and social issues related to petroleum exploration and exploitation activities. This new priority came to the fore, first, in the Western oil-producing countries of the OECD, which enacted extensive legislation to control air and water pollution, hazardous wastes, and land use, especially in sensitive coastal areas and in the Alaskan Arctic and the North Sea. These issues are now of increasing importance to all countries where petroleum development occurs.

NOC diversification

In the last decade, many NOCs that once operated only in their home countries have diversified into upstream investments abroad, taking advantage of E&P acreage openings in certain countries.

The move to invest abroad in the 1990s was taken in particular by Statoil; Petronas (Malaysia); Petrobras (Brazil); Kufpec (Kuwait); China National Petroleum Corp. and Sinopec (China); Oil & National Gas Corp. (India); Petro-Vietnam; Sonatrach (Algeria); the new Russian companies such as Lukoil, Gazprom, and Rosneft; and Iranian companies (such as Petropars).

The strategic objectives of these "going abroad" NOCs are to be recognized as global oil and gas companies that can perform according to the good practices of the industry, to become more efficient in their home operations, and to earn profits against investment criteria similar to those used by the Western IOCs.

Some NOCs from oil-importing countries like China and India may be willing to accept a higher degree of risk or lower profitability in order to gain access to production that can meet their countries' growing energy demands.

Changes after 2000

At the turn of the 21st century, rising oil prices and profits have caused an opposite trend to the preceding softening of the terms in E&P contracts.

With little surplus producing capacity available anywhere in the world until very recently, host countries took advantage of the new high-price environment to slow the licensing of new acreage. In particular, several OPEC countries refused to give access to the most promising exploration areas or to already producing fields.

At the same time, IOCs had surplus funds to invest from their own higher cash flows but faced a relative lack of attractive new opportunities in E&P. Therefore, spurred on by competition from NOCs going international, IOCs were forced to offer better terms in the post-2000 licensing rounds in countries like Libya and Angola, where acreage was opened to foreign investors. Thus, Libya, after the lifting of US sanctions against it in 2004, organized two successful licensing rounds in 2005 for production sharing agreements which attracted many IOCs and NOCs ready to offer highly advantageous terms to the country.

Many countries, including OECD countries, have recently introduced additional taxes on their own domestic production. For example, in 2002, the UK government introduced an additional income tax of 10%, rising to 20% in 2006, which led to a revised marginal government take of 75% (in "old" fields) and 50% (in "new" fields).

The state of Alaska adopted a new profit-based petroleum production tax in 2006 to replace royalty payments in the concession agreements.

Some major oil-exporting countries, such as Venezuela, Bolivia, and Ecuador, radically changed some of the conditions and terms under which foreign investors operated.

Will this trend to impose harsher tax rates and terms on investors in the petroleum business continue? Or will the IPAs and related petroleum legislation and regulations be robust enough to self-adjust to price volatility, so that there is a fair sharing of profits between HCs and investors over long-term business cycles?

Such flexibility is a key challenge in designing and negotiating IPAs because price volatility is likely to remain a notable feature of global oil and gas markets.

Mutual adjustment

Early IPAs were the result of a certain political, economic, and technical climate. When these original factors gave way to new conditions, the IPAs and their terms were modified accordingly.

In this context, the bargaining power between HCs and IOCs is one of mutual adjustment in which each party acts to further its own best interests when it is in a stronger overall position and yields to necessity when in a weaker position.

Nevertheless, the evolution in IPAs since World War II has been decidedly lopsided in favor of developing countries. Once freed from colonial rule, these countries have successfully asserted their sovereignty over their natural resources, especially in an era of relative scarcity in petroleum supplies and high oil prices, like the 1970s.

From the mid-1980s to the turn of the 21st Century, relatively low oil prices led to the privatization of some national oil companies and the opening of acreage once closed to IOCs, as bargaining power shifted in favor of IOCs (except in the largest oil exporting countries of OPEC). With the oil price hikes through mid-2008, HCs were again in the driver's seat, able to capture a higher share of the profits.

All IPAs share many basic features and can be made to achieve the same economic results. In fact, at least 80% of the contents of most IPAs consist of the same clauses, irrespective of their label. The real issue is how production, profits, and the control of operations will be split between the risk-taking investor and the state as owner of the subsoil. All IPAs still aim, just as in Col. Drake's days, at the same goal: to make petroleum exploration and exploitation possible.

Acknowledgment

This article is adapted from International Petroleum Exploration and Exploitation Agreements, Second Edition, published by Barrows Co. Inc., New York. It contains contributions by Prof. Owen L. Anderson, R. Doak Bishop, and John P. Bowman.

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