Contractual arrangements for the exploitation of natural gas in developing countries

Contractual arrangements for the

,

In this paper we discuss contracts used in the exploration and development of gas reserves in developing countries. Natural gas has several features that distinguish it from oil. Most importantly, gas pipelines are relatively expen- sive and have large economies of scale. Additionally, for most countries gas must be sold on internal markets, usually to state monopsony buyers. The foreign oil company must therefore become involved in a close and long- term relationship with the relevant state agencies. The paper discusses the nature of the bilateral relationship between oil company and state during a gas project. Long-term development contracts and the clauses that deal with this relationship are discussed. In addition contract terms to encourage exploration, including concession terms, are reviewed. Finally, we conclude with a discussion of optimal contract forms and likely requirements for future gas projects.

At the time of writing the author was with the Oxford Institute for Energy Studies and St Catherine’s College, Oxford, UK. He now works as a consultant for the Euro- pean Commission.

The author would like to acknowledge the numerous conversations with staff of transnational oil companies, and several multilateral development agencies, including the World Bank, the IFC, the Technical Assistance Group of the Commonwealth Secretariat, and the United Nations Centre for Transnational Corporations. Naturally any errors and omissions remain those of the author. ‘United Nations Centre on Transnational

continued on page 160

exploit&ion of natural gas in developing countries

Christopher Hurst

The history of petroleum agreements between foreign oil companies and Third World governments is long and varied. The early concession terms in the first half of this century essentially established the concession area as a ‘state within a state’. Some of the main features of the original concessions were, for example:’

0 large concession areas with no relinquishment provisions; 0 long concession periods of up to 99 years; 0 no state participation in management; 0 exclusive right granted to the company to all facets of petroleum

activities; 0 contractual provisions guaranteed for the duration of the conces-

sion; and 0 government revenues generated by a royalty of 12.5% on produc-

tion tonnage.

Under these conditions it was not surprising that conflicts arose with the growth of national self determination within host countries. As the state became increasingly involved in petroleum exploitation, national oil companies were formed to oversee the activities of foreign companies. Concession terms were steadily reduced until in the mid-1950s typical agreements contained shorter exploration periods of five to six years with renewal rights, a shorter exploitation period of 25 to 30 years, minimum exploration expenditures, and the required training of national personnel.2 The importance of the national oil company continued to stengthen during the 1960s and 197Os, and in some countries, notably the major oil exporters, the state began to take on a fully active and controlling role. In these cases the foreign oil company was reduced to a contractee, undertaking specified tasks for a fixed fee.3

In this paper we discuss contracts used today in the exploration and development of gas reserves in developing countries. Although reserves of natural gas in these countries (outside the high income oil importers) are large (some 30 trillion m3), the utilization of gas appears relatively less than than in industrialized nations. In addition, most exploration

0301-4207/88/030159-14$03.00 0 1988 Butterworth & Co (Publishers) Ltd 159

Nalural gas contracts in developing countries

continued from page 159 Corporations, Main features and Trends in Petroleum and Mining Agreements, ST/ CTC/48), UNCTC, New York, 1983. *Ibid, p 2. 3A summary of worldwide concession contracts for oil is given in G.H. Barrows, World Wide Concession Contracts and Petroleum Legislation, Pennwell, Tulsa, USA, 1983. 40PEC, Annual Statistical Bulletin, Vienna, 1986, Table 35. ‘In new markets large technical innovation rents may be captured. During 1971 to 1975 the real rate of return on equity for US mining (including oil) companies was an average of 9.3% per annum, compared with 5.8% for all manufacturing companies During 1976 to 1980 these figures were 6.3% and 5.7% respectively. It is interesting to note that during this period the real rates of return on equity for US broadcasting (where monopoly rents exist for limited access) were higher than those from mining (8.6% for 1971 to 1975 and 115% for 1976 to 1980). Based on data in Fortune magazine, various issues, 1978 80.

160

work has been undertaken in either developed countries or major oil exporters, and much of the Third World is relatively unexplored. Of a total of 3 548 active rigs operating outside centrally planned economies in 198.5, 2 272 were in use in North America, while 292 were in OPEC countries. The non-OPEC countries of Asia and Africa accounted for only 162 and 105 active rigs respectively.J Moreover, exploration has been particularly scarce in gas prone areas, and even if a gas field is struck, appraisal wells are often not drilled and reservoir data not collected. Some industry sources also claim that cases exist where oil companies have declared a gas find to be a dry hole in order to avoid becoming involved in negotiations over gas development.

A reluctance by foreign oil companies to become involved in gas in developing countries is not irrational - the exploitation of gas has several problems that do not occur to the same degree with oil. At the heart of the problem is the high cost of transporting gas: a gas pipeline may cost four or five times an equivalent oil pipeline (delivering the same quantity of energy). There are also large economies of scale so that certain minimum volumes of gas must be available in order to make gas transmission competitive.

Furthermore, the option of exporting liquid natural gas (LNG) during the medium term is not viable in most countries. Consequently most gas production will have to be sold on internal markets, usually to state monopsony buyers. The foreign oil company must therefore become involved in a close and long-term relationship with the relevant state agencies.

This paper discusses contract terms that may assist in the exploitation of gas. The first part explains the nature of the bilateral relationship between oil company and state during a gas project. Long-term development contracts and the clauses that deal with this relationship are discussed. Contract terms to encourage exloration, including concession terms, are reviewed. Finally we conclude with a discussion of optimal contract forms, and likely requirements for future gas projects.

The lack of competition during gas development projects

Whatever the specified contractual relationship between a foreign oil company and the host government, the object of a contract is to allocate the investment of resources (including capital, technical and managerial skills, natural resources etc), the risks associated with the planned investment and the resulting profits.

In this context it is commonly held that mining projects are distinguished from other industries by the high risks involved in the discovery and extraction of natural resources and by the possibility of high resource rents. Although the truth of this statement would depend upon the size of the portfolio and the level of maturity of markets for manufactured products, companies involved in mining do often exhibit higher rates of return than average.’

In a situation of perfect competition between oil companies, for example through competitive bidding for the right to operate in a country, any resource rents would be captured by the government. In a monopolistic or oligopolistic environment the share of the rent between the two parties, oil company and government, is determined by their relative bargaining strengths. Oligopolies can be formed only if a limited number of companies have the necessary technical skills or can control

RESOURCES POLICY September 1988

6E.T. Penrose, The Theory and Growth of the Firm, Basil Blackwell, Oxford, UK, 1959, for example, argues that the supply of investment in the Middle East in 1959 was monopolistic, as only a few companies had the necessary financial and technical resources. There is an extensive literature on the relationships between government and investors including, R.G. Garnaut and A. Clunies Ross, ‘Uncertainty risk aversion and the taxing of natural resource proiects’, Economic Journal, Vol 85, No 338, june 1975fR.G. Garnaut and A. Clunies Floss, ‘The neutrality of the resource rent tax’, Economic Record, Vol 55, No 150, September 1979; M. Gillis et al, Tax and lnvestmenf Policies for Hard Minerals: Public and Multinational Enter- prise in Indonesia, Ballinger, Cambridge, MA, 1980; H. Hughes, ‘Economic rents: the distribution of gains from mineral exploitation and mineral development policy’, World Development, Vol3, Nos 11 and 12, 175; R.F. Mikesell, W.H. Bartsch and J.N. Bahram, eds, Foreign investment in the Petroleum and Mineral Industries: Case Studies of Investor-Host Country Rela- tions, The Johns Hopkins University Press, Baltimore, 1971. ‘R. Garnaut and A. Clunies Ross, Taxation of Mineral Rents, Clarendon Press, Ox- ford, 1983, p 79.

Natural gas contracts in developing countries

access to markets (eg control refineries in the case of crude oil). Perhaps more importantly, the large risky investments required for petroleum exploration also limit its feasibility to companies with large capital resources that can spread risks over many projects.6 Although the petroleum industry today has a large number of players this does not preclude the formation of bilateral monopolies. As Garnaut and Clunies Ross note ,’

Even when the investor has no monopolistic control of technology or access to markets, the bargaining model of government-investor relations may be applicable if the government is constrained for other reasons from dealing with other companies. This situation arises most commonly when a company has undertaken exploration and discovered a mineral deposit before the settlement of the terms of conditions of rent charges.

Although most exploration contracts will be very specific in stating the liabilities of the foreign oil company should oil be discovered, they are usually extremely vague on gas terms. A typical approach is to include a statement that in the event of a gas find, both parties (ie the company and the government) will in good faith negotiate a mutually satisfactory programme of development. This vagueness in the past has ensured that the terms of development of gas will be determined in an uncompetitive bilateral environment.

In the negotiation to determine the wellhead price of gas the government position is made complex by a lack of information regarding the economics of the development project. Although mineral extraction does often contain pure resource rents, a large component of what may otherwise appear excessively high returns may in fact be quasirents ie they are required if the project is to proceed. These may, for example, be required to cover the uncertainties associated with the investment. The true economic cost of supplying gas is consequently composed not only of the cost of equity investments charged at a ‘riskless’ rate of return, bank charges for loans, the cost of labour and other operating and maintenance costs, but additionally quasirents or risk premiums to cover geological risk (eg the technical uncertainty of finding, developing and operating a gas field), market risks (eg the uncertainty over the rate at which markets will develop and their profitability) and political risks (most notably contract defaults by the government) associated with operating in a foreign country. Figure 1 illustrates the components of the price of gas after a successful negotiation. The difference between the total supply cost and the economic value of the product, any ratio between producer strengths.

the pure resource rent, can be shared in and purchaser subject to bargaining

The stability of contracts

Because the bilateral nature of gas development remains through the life of a project, the relationship between oil company and government can be viewed as a dynamic game, the solution to which will depend on how the relative bargaining strengths change over time and on how individual economic positions change. Any contract will be renegotiated if any one of the two players feels the terms have become unreasonable, and indeed it is in the interest of both parties not to force the other into a position where they take drastic unilateral actions; in the extreme they ‘walk away’ from the project.

RESOURCES POLICY September 1988 161

Natural gas contracts in developing counwies

Economic value

Figure 1. The components of the gas

price.

‘In the words of Machiavelli, ‘a prudent ruler cannot, and should not, honour his word when it places him at a disadvantage and when the reasons for which he made his promise no longer exist’ (The Prince, Penguin, 1979, pp 99-100). See Ft. Bos- son and B. Varon, The Mining industry and the Developing Countries, Oxford Uni- versity Press for the World Bank, Oxford, UK, 1977.

Before exploration, the position of the oil company depends upon the level of competition from other oil companies. After a gas find its position would depend upon the extent to which it is prepared to write off sunk exploration costs. Once the oil company begins to develop the field, and increasing sums are invested, the balance of power swings towards the government. Upon the completion of the project, the host government, as a sovereign state, has a strong position and can, if it so desires, nationalize the local operating company.’ The main constraints on this are twofold. It may not have the technical expertise to operate the gas field, or the operating costs may become excessively high due to lack of management skills. Second, the position of the government in negotiations with other corporations is strongly influenced by the general perception of the political risk associated with the country. At a time of reduced availability of commercial bank loans, governments in need of foreign capital flows may strongly desire to attract foreign direct investment. They may, therefore, be very sensitive to international opinion regarding their treatment of foreign investors. None the less, in the short run, the government is in a strong bargaining position.

As contracts incorporating some flexibility are more likely to remain in operation it is perhaps better for individual agreements to be negotiated between governments and oil companies, rather than the government enacting rigid petroleum legislation (with the possibility of lengthy parliamentary ratification of changes). On the other hand, a system of general legislation can assist the government by providing an

162 RESOURCES POLICY September 1988

Negotiated price

Competitive economic price

I Risk neutral price

Government’s share of pure resource rent

Oil company share of pure resource rent (ie a monopoly rent)

Political risk premia

Market risk premia

Geological risk premia

Bank loan charges

Return on equity at a ‘riskless’ rate

Cost of labour Other operating and maintenance charges

‘Numerous renegotiations have taken place, including, for example, the price indexation clause on Bolivian exports to Argentina. The contract for LNG sales between Sonatrach of Algeria and Distri- gas of the USA was renegotiated five times between 1978 and 1984. “UNCTC, Trends and Issues in Foregin Direct Investment, United Nations Centre on Transnational Corporations, ST/CTC/59, New York, 1985. Table 111.4. “Industrialized (ie low political risk) countries are not ncessarily efficient at captur- ing resource rents. In Holland, for example, a large portion of the rent from the develooment of the Groninqeno oas field went to NAM (a ShelVEsso consortium) (J.D. Davis, Blue Gold: The Political Eco- nomy of Natural Gas, World Industry Stu- dies 3, George Allen and Unwin, London, 1984. DD 160-161). In some parts of FR Germany (those ‘that were historically under Prussian control) a royalty of only about 17% is charged on domestic gas production (ibid, p 167). ‘2C, Hurst, ‘Financino natural oas projects in developing countrTes’, in T.-Walde; ed, Petroleum Investment Policies in Develop- ing Countries, Graham and Trotman for the United Nations Department of Technical Cooperation for Development, London, 1988. 13Since bank loans to the oil company must be repaid whether the project suc- ceeds or fails (for example, through default by the government) it is appropriate to include debt in the calculation of returns. This would not be the case for non-


initial framework which has been invested with legal sanction. Neither course is mutually exclusive, of course, and a combination of petroleum laws for the terms that are non-negotiable and individually negotiated agreements may be the most desirable approach. Model contracts will also be helpful in negotiations provided that they are sufficiently loosely defined to allow negotiations to proceed.

Although the vast majority of contract disputes are settled by direct negotiations between the parties,” the option of submitting disputes to binding third party arbitration may help provide a sense of security for foreign investors. Several organizations including the International Centre for Settlement of Investment Disputes and the United Nations Commission on International Trade Law will provide arbitrators. Oil companies often prefer this option because it is cheaper than pursuing disputes through the legal system. Indeed the expense of an international law suit can be prohibitive for both the oil company and government.

The political risks of unilateral actions by the governments of developing countries, excepting a radical change of government, is often no more than for developed ones. The UK, for example, changed its North Sea basic tax rate several times from a rate of 45% in 1978 to 75% in 1982. Usually the uncertainties of foreign exchange depreciation and convertibility are more real: the rates of return on US direct investment in developing countries fell from 24.3% in 1980 to 10.0% in 1983. In Latin America the rates of return for the same years were 18.8% and 2.2% respectively, much of this caused by widespread devaluations.”

Clearly a government can, over time, establish a track record of a stable government for oil company activity; but this is somewhat of a long-run option. In the nearer term governments may have to recognize that they must compete with other countries (eg a more ‘stable’ country) and other activities (such as oil export projects) where risk premiums are smaller or where the potential of the oil company taking monopoly rents is high.”

The involvement of other third parties in a gas project can help reduce perceptions of political risk by oil companies. The most important potential candidates here are multilateral development banks. Financing of gas infrastructure by these banks, and to much a lesser extent sectoral adjustment loans, provide a security to the foreign investor that the government will not take unilateral actions against their interests. Loans by commercial banks can play a similar role; however, funds from this source are very limited at the current time.‘*

Long-term development contracts

As a result of the long-term bilateral relationship needed for a gas development project, contracts are also usually long-term agreements specifying the volume of gas to be delivered and the payments made in compensation. In addition, many aspects of contracts deal with attempting to reduce unilateral actions by one of the players, and to adapt to the changing economic environment. The contracts used for the developing gas fields can be grouped in two main categories which we will now discuss.

The service contract recourse loans, where risks may be taken by the lender and will be reflected in the Here the company is paid on a cost plus basis with an agreed rate of

interest rate. return on equity or on discounted cash flow.‘” When the level of capital



‘?f large proven reserves exist this may be of little relevance. The Pakistani gas industry worked successfully for more than 20 years under a cost plus approach before supply shortages occurred. Shortages did eventually develop, however. 15H.G. Broadman and M.A. Toman, ‘Non- price provisions in long-term natural gas contracts’, Land Economics, Vol 62, No 2, p 111-118, May 1986.

164

investment used to calculate profits is based on the actual (LY post) expenses necessary to develop the gas field, all project risks are borne by the government, and the oil company only has to take the political risk perceived to exist in the country in question. This is a pure service contract. A variation is the risk service contract where the company is guaranteed a service contract for development if gas is found, but where geological risks are taken by the oil company. Similar geological risks are taken if the contract is based on (ex arztr) tenders before exploration begins. This would imply the oil company taking market risks with respect to the magnitude of future sales (and whether development actually takes place). Such a contract form is less suitable for gas than oil because of the higher market risks of this fuel.

There are several problems with service contracts, however. First, if the payment to the oil company is based on actual costs, there are incentives for the company to be inefficient and overspend. As a result, there are large demands on the government to supervise and check the expenditures of the contracted company. Second, the project risks may be an excessive burden for many countries. Third, there are problems with determining a mutually satisfactory rate of return on investment. Service contracts have been used successfully to develop large low cost gas fields (eg the Sui field in Pakistan); however, the returns typically offered have not been sufficient to attract investment for additional exloration. One interpretation of this is that the rate of return has been large enough to cover the political risk of the incremental development cost of a gas field, given sunk exploration costs (usually spent looking for oil), but not the total political risk of a complete venture.”

Market based pricing

The second category is one of market based pricing. Here the price of gas is set relative to the cost of substitute fuels. As profits will be increased if costs are reduced there is an incentive for the oil company to be efficient under this contract form. The geological risks are taken by the oil company; but the government must usually take some of the market risk by contractually guaranteeing minimum sales. As these guarantees become stronger this approach becomes more like a service contract as returns become less uncertain.

Several different types of market guarantee can be given. The key elements include:”

0

l

Take or pay provisions. These clauses assure the supplier of gas minimum payments regardless of actual offtake. The minimum quantities covered are often a large proportion eg 80% of the contracted volume which can be specified hourly, daily or annually. Gas which is not taken in one period, but not paid for, can sometimes be taken in addition to contract requirements in later periods free of charge (so-called ‘make up’ gas). Take or pay requirements can also be expressed in terms of reserve size if there is some uncertainty about these. Buyer protection provisions. These clauses limit the liability of purchasers by allowing them to break the above provisions if market conditions make the gas unsaleable at its contract price (ie ‘market oil’ clauses). In the USA it has been common for purchasers tied by contracts not containing this protection to claim force mujeure in the event of increased competition from substitute fuels.



“Examples in the literature include ibid, H.G. Broadman, ‘Elements of market power in the natural gas pipeline industry’, The Energy Journal, Vol7, No 1, January 1986, pp 119-138; M.E. Caines and D.A. Nor- man, ‘Analysis of take-or-pay provisions in natural aas contracts’, Discussion Paper 029, American Petroleum Institute, Washington, DC, 1983; R.G. Hubbard and R.J. Weiner, ‘Regulation and bilateral monopoly: long term contracting in natural gas’, Working Paper E-84-l 1, Energy and Environmental Policy Centre, Harvard Uni- versitv. USA. December 1984: S.E. Mar- ston and K.J’. Cracker, ‘Efficient adaption in long-term contracts: take-or-pay provisions for natural gas’, American Economic Review, Vol 75, No 7, 1985, pp 1083 1093. 170p tit, Ref 15 and op tit, Ref 16, Caines and Norman. “From both deregulation of the wellhead gas price and the oil price collapse. The changes in the US gas markets are discussed by M.A. Toman, ‘The outlook for “spot” trade in natural gas’, Public Utilities Fortnight/y, 10 July 1986, pp 2832Jand P.R. Carpenter, H.D. Jacoby and ‘A.W.

of small arouo baraainino see O.E. Wil- liamson, ‘?ransacti& cosieconomics: the governance of contractual relations’, Jour- nal of Law and Economics, Vol 22, Octo- ber 1979, ~~233-261 and O.E. William- son, Markets and Hierarchies, Free Press, New York, 1975.

There are many reasons postulated for the existence of long-term contracts, and particularly take or pay clauses.” A traditional argument for their adoption in the USA is that they are a means of circumventing regulation. When prices are fixed by the state to be below the willingness to pay of purchasers, then competition for supply will include non-price terms - the higher the take or pay the more attractive the contract to the producer.

However, take or pay clauses existed in US gas contracts before price regulation in 1954. They also exist in unregulated markets (such as coal) in the USA, and elsewhere (eg LNG contracts). Indeed, if the gas market were to continue in a state of excess demand, the offer of a minimum purchase guarantee causes little penalty to purchasers as they will desire as much gas as the producer can provide. Equally non-price guarantees are of little incremental value to the seller in this setting.

An alternative interpretation of take or pay clauses if that they provide a method of sharing market risks, with any dramatic fluctua- tions in demand being distributed between seller and buyer.” If this is the underlying reason for introducing non-price clauses it must be said that they have not fulfilled this goal very satisfactorily in the USA in the 198Os, as many transmission companies are today fighting both bankruptcy and take or pay obligations through arguments of force majeure. Ix

Another argument for non-price provisions depends upon market uncertainty of a different kind. As we have discussed, it is common for a bilateral monopoly to exist between purchaser and producer and in this situation take or pay clauses are a method of attenuating opportunistic behaviour.lY This remains a form of minimizing market risks for individual sellers, even if they are risk neutral to uncertainty in final markets. Such logic would appear to be supported by the fact that take or pay contracts exist even when the gas price is fully indexed against current price of competing fuels. Under these circumstances, the market risks for purchasers associated with volume uncertainty are minimized, as gas consumers will always find gas use cost-effective. The remaining volume uncertainty is associated with the possibility of opportunistic behaviour by the purchaser. As transnational oil companies in developing countries often base their internal economic appraisal of projects on minimum guaranteed sales rather than the full contracted volume it would appear that fears of future unilateral actions by purchasers are very real.

Take or pay clauses based upon reserves mean that any uncertainty over field size and the deliverability of gas is borne by the purchaser. If take or pay clauses do not include the possibility of a shortfall in reserves, an inability to supply gas for geological reasons would usually lead the gas supplier to claim force majeure and demand contract renegotiation (this happened with Unocal’s operation of the Erawan field in Thailand). The difficulty with this route is that attempting to avoid contract obligations through force majeure can be very conten- tious and there is an attraction in having the take or pay liability linked explicitly to reserves.

Long-term sales contracts also include clauses that specify the payments to be made by the purchaser for the gas received. In an attempt to account for changes in the economy over the period of the contract, the price for gas is usually linked to several economic indices. The most important of these indices is the price of crude oil or of oil


Natural gas contracts in developing counrries

products, under the assumption that these give an estimate of the value of the gas. However, the gas price is typically not directly proportional to changes in the oil price, but is given by a weighted function:

Pg = c.P,.(aPo + bPI)

where Pg is the gas price, P,, is a base price, P, is the price of an appropriate crude oil or product, PI is a price index of other commodities and a, b and c are constants.

The gas price can be linked to a variety of different oil prices. The official or spot prices of a particular type of crude can be used, as can a particular type of oil product at a particular location. It is also possible to link the price to a basket of different oil commodities.

With indexation formulae including general inflation indices (such as the WPI) the gas price may deviate widely from the oil price after a period of time. During periods of rising oil prices this acts to the advantage of the purchaser; however, should the oil price fall, the gas producer is then cushioned by a relatively smaller drop in gas price. As a result of this the price of gas in many contracts is now above that for oil. Figure 2 shows the change in gas prices for LNG shipments to Japan and natural gas exports to Western Europe. In the case of Indonesian- Japanese trade, the gas price has also been increased through the use of official prices greatly above spot prices. This has been the subject of intense negotiation and Pertamina has agreed to repay a portion of Japanese payments for 1986. The new agreement is based on a new lower official price (of $17.65/bbl for benchmark Minas crude) with an agreement to review Indonesian crude markers if a significant gap occurs between official and market prices.

A similar discrepancy between the gas price and the indexed oil price

I

1975 ' 1976 ' 1977 ' 1978 ' 1979 ’ 1980 ’ 1981 ’ 1982 ' 1983 ' 1984 ' 1985 ' 1986 <Q

1Q 2Q 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1986

LNG (Japan) 1.7 1.8 2.1 2.4 2.8 5.1 5.8 5.8 5.2 5.0 5.0 5.0 4.2

Natural gas (Western Europe) 1.0 1.4 1.7 1.9 2.1 3.2 4.6 4.6 4.3 3.9 3.8 4.0 3.6

Crude oil 2.1 2.2 2.4 2.4 3.2 5.7 6.4 6.0 5.3 5.0 4.8 4.3 2.5

Figure 2. Average price of natural gas exports and crude oil 1975-86 in US$/mmbtu.

Source: Petroleum Economist, 1986, p 437



can occur if long time lags are included in indexation clauses. This was the case with the Thai gas purchase contract between PTT and Unocal, where the gas price was indexed to the price of medium fuel oil at Singapore with an l&month time lag. Again this gave an advantage to PTT when the fuel oil price was rising, but led to a serious anomaly after the oil price collapse of 1986. In this case an interim deduction in the wellhead price of gas was agreed by Unocal.

In most countries gas will predominantly substitute for fuel oil use by bulk users. Consequently, if a market based price is to be followed it is appropriate that the gas price should be linked to the price of this oil product eg the average spot price over a period of time in a nearby major trading centre. In fact the true economic value to a country of fuel oil is the cif border price for an importing country and the fob price for an exporter. In order to track oil prices accurately, the gas indexation clause should be directly proportional to the appropriate fuel oil price and time lags should not exceed more than a few months. The base price in index clauses remains to be negotiated and must be greater than production costs (including quasirents).

It should be noted that the final profits of the oil company also depend upon the fiscal regime in existence, including royalty payments, and any production sharing agreements. Equally important is the interaction between the tax system of the host country of the project and the home country of the company, and the extent to which tax payments can be credited or deducted. However, in this paper we focus on the contractual arrangements before taxes are applied; most of the comments apply regardless of the subsequent fiscal system used. The implications of different fiscal regimes are discussed in more detail by Garnaut and Clunies Ross, and Hurst.*”

Problems with exploration contracts

So far we have focused mainly on projects for gas development assuming a gas field exists. In many countries, however, additional exploration and field delineation is required to determine gas reserves more accurately. Although the final goal of such exploration activities is, of course, a successful development project, the future is substantial- ly more uncertain at this early stage of a gas project. Exploration contracts in virgin areas also need to address the possibility of a gas strike. As we have observed, most exploration contracts are extremely vague about gas development terms. This approach is far from satisfactory for an oil company exploring in a gas prone area: the returns from the discovery of gas are only learnt after the oil company has sunk exploration costs and taken geological risks.

“‘Op tit, Ref 7 and C. Hurst ‘Taxes on oil and gas’, mimeo, Oxford institute for Ener- gy Studies, Oxford, UK, 1987.

We could expect that some predetermination of gas development clauses would help the progress of gas exploration by reducing uncertainty for investors. However, the view of the oil company regarding gas clauses depends upon its strategy with regard to this fuel. If it is genuinely interested in gas projects then explicit statements of intent by the government should be welcomed. For the oil company interested exclusively in oil, then additional gas clauses may be either positive or negative depending upon the extent to which they oblige the company to invest in gas and the extent to which they influence oil operations. Consequently one company’s best contract may be another’s worst.



“Egypt has included a similar compensation option in its gas exploration clause The justification was based on a somewhat different policy goal, that of building up a national reserve’ of gas. A portion of gas reserves were put towards this national reserve with the option of relinquishment and compensation of expenditures. Oil companies, however, do not wish to re- ceive just their expenditures, and have chosen to keep the title to gas reserves, presumably in the hope of selling gas within Eavot (which alreadv has some oas

“~. .

infrastructure) at some later date. - **lJNCTC. Natural Gas Clauses in Pet- roleum A&eemenfs, United Nations Cen- tre on Transnational Corporations, New York, 1987, p 34.

Assuming the scenario that oil companies would invest in gas exploration if some of the market uncertainties could be reduced, it is

still far from easy for the government to give meaningful contract terms until after gas has been found. The problem is the high cost and inflexibility of gas transmission. Even if the government promises that it will peg the price of gas to that of the substitute, and that the substitute is priced economically, the net back value of the gas at the wellhead remains highly sensitive to the quantity of gas sold.

The guarantee of competitive pricing or of guaranteeing gas markets (eg the conversion of a power station) could be worthless unless sufficiently large volumes of gas are found to reduce average gas pipeline costs. This, of course, varies from country to country and with the proximity of exploration concessions to potential consumers. For a country with an established gas industry where additional gas reserves are required to keep pace with demand, indications of the terms under which gas will be priced should have value. Even in this situation perhaps the best guarantee that could be made with a market pricing approach would be similar to that of the recent proposal of Pakistan: ie gas would be priced at a proportion of the fuel oil price (which in this case happened to be 66%) less a deduction to account for transmission and regional demand factors.

However, such guarantees may be of little concrete value to the oil company. Even with the best will by the government to fulfil its promises, the situation could still arise where two different oil companies each find gas fields of sufficient size to meet demand in the near future. Only one field, the one of lower average cost, should be developed, the other being left dormant until such time as new demand is generated.

The result of this inherent market uncertainty is a classic chicken and egg situation: prices and production levels cannot be set until the size of reserves and production costs are known, but exploration will not be undertaken until this information is available and a return can be estimated. Countries with limited gas infrastructure, and limited oil prospects, have had, and will continue to have, a difficult time attracting oil companies.

What can a government do to improve exploration contract terms under these conditions? One approach is to institute methods of compensating oil companies during any waiting period after a gas find while a gas utilization plan is developed, or while other gas fields, required to meet the threshold volumes for pipelines investments, are discovered. This could include straight compensation of exploration costs (possibly accumulated at an interest rate), although there may be some disagreement as to whether only the exploration costs associated directly with the gas field, or the exploration expenditure in the entire concession (assuming no other successful wells), should be reimbursed.21

Another option is for the government to take over development of gas fields when long lead times are expected, but to allow the company to buy back into the project on guaranteed terms at some future date. It would also be possible to give special finder’s fee to companies finding gas up to some critical threshold. Such a finder’s fee could be a deferred royalty of, say, 5% the value of the gas when it is developed. This is a similar concept to the overriding royalty that is frequently applied in North America.22


Natural gas contractS in developing countries

The general problem with compensation schemes is ensuring that companies do not overspend on exploration (ie to limit payments to a competitive market level), as there is the potential for the government being required to pay large sums to explorers. This type of contract is really a form of service contract, with an option of a market pricing contract if economic reserves are found. The geological risks are then divided between the government (which takes exploration risks) and the company (which takes development risks). This combination has some attractions if the government can absorb exploration risks and monitor exploration expenditures.

Concession terms relating to gas

At a more concrete level, the government can change concession terms to allow time for appraisal of gas fields and an assessment of commercial viability. Usually no differentiation is made between oil and gas in concessions, which typically include:2”

0 A primary exploration period of between three to eight years (eg six years in Peru, four in Tunisia and eight in Thailand), with the right to extension for additional periods ranging from one to five years which can be renewed two or three times. The duration of the exploitation period typically varies from fifteen years (eg Brazil) to thirty years (eg Egypt and Indonesia) from the date of signature, although some run to as much as forty years (eg Chad) or fifty years (eg Tunisia) from commercial discovery. The trend has been towards shorter concession periods and it is likely that exploitation periods of longer than twenty-five years will become less common. In order to increase the rate of exploration, it is also probable that host countries will try to reduce the automatic granting of extensions to the primary exploration period.

l In the absence of a commercial discovery, relinquishment provisions typically covering 50% of the original area at the end of the primary term, with often an additional 25% up for renewals of two to five years. As host countries attempt to increase the rate of activity by oil companies, it is becoming increasingly common for relinquishment obligations to be included in the primary exploration period (eg 25% at the end of the second year and another 25% at the end of the fourth).

‘30p tit, Fief 1, p 40.

These shorter and shorter exploration periods have become less and less applicable to gas, with its much longer stage of commercial assessment. It would seem reasonable, in the event of a gas discovery, for the oil company be given a period after field delineation and evaluation to decide if the field warrants commercial development (say one to two years) and then an additional period in which to prepare development (say two years). It would also appear unfair that the gas field should have to be relinquished because of a lack of markets. No loss to the state occurs by the company holding the field until a market can be generated, while the company is assured of some income from the field if it ever becomes economic. Unfortunately, in some cases it may be difficult for the government to determine whether the lack of development is really due to economic reasons, or whether it is a result of an unreasonable negotiating stance by the company. One option may be to provide for the possibility of renewal of the predevelopment



preparation period subject to government approval. This approach is followed in the Arctic regions of Canada where the problem of achieving threshold volumes is particularly acute. Here the holding period is determined by the government, and can be essentially indefinite.24

The exploitation period should also be linked to the time when deliveries have begun. This will usually be required in order to cover the large capital investments required in gas development. The trend of reduction in the size of concession areas is also less satisfactory for gas where larger threshold volumes are necessary and where the discovery of several adjoining fields may be necessary to meet initial minimum volumes.

The optimal distribution of profits

240p tit, Ref 22, p 33. However some control is necessary to prevent companies simply holding inventories of concessions for long-term strategic goals. 25A discussion of the management of gas markets is given in World Bank, Managing Gas hdusity Development, Energy be- partment Paper No 29, Washington, DC, August 1985. 26C.R. Blitzer. D.R. Lessard and J.L. Pad- dock, ‘Risk-bearing and the choice of contract forms for oil exploration and development’, The Energy Journal, Vol 5, No 1, January 1984. “An analogous literature exists on efficient labour contracts; see J. Green and C.M. Kahn, ‘Wage employment contracts’, Quarterly Journal of Economics Vol 98 (supplement), 1983, pp 173-188.

i R.E. Hall

and D.M. Lilien, ‘Efficient wag bargains under uncertain supply and demand’, American Economic Review, Vol 69, De- cember 1979, pp 868-879.

Contracts between transnational companies and a state play a major role in determining the overall relationship between the parties. Other factors of importance include the fiscal regime implemented, the financial package used and the political and economic environment of the country in question. For the planned project this relationship determines the allocation of contributions, risks and profits between the participants; but as many factors are not explicitly defined, the individual perception of the final allocation may well be different.

The total magnitude of resource rent generated by a project depends upon the size of the risk premiums that must be paid to the different agents. This must, of course, depend upon the magnitude of the risks taken, and this varies with different types of contract. It is also important to note that the premium necessary to cover risk is different for the different economic players. Oil companies, for example, are able to spread geological risk by having large portfolios of other exploration activities. For the government market risks are much smaller as the price of substitutes can be regulated.25 Political risk (ie fears over expropriation, contract stability, civil disobedience, war, currency convertibility) does not exist; however, there may be risk aversion by the civil servants and politicians (whose careers may be at stake) required to back the project. Other factors that determine the risk aversion of the government include, for example, the size of the economy, the relative contributions to GNP of the energy producing and consuming sectors, the dependency on imported oil and the extent to which oil price risks can be transferred to others (eg through long-term contracts, through buying shares in foreign oil producing companies, or by an oil exporter issuing petrobonds).2h Because of the different views of uncertainty, it is possible to conceive of the concept of Pareto efficient contracts with an efficient allocation of risk.27

Figure 3 shows schematically one possible example of how the supply cost of gas could break down in a particular country for a selection of contracts. Here we have assumed a large degree of risk aversion by the government and that the lack of experience of the national oil company could increase is riskless costs. Because of this the self-sufficient strategy is not feasible.

In this example, both the pure service and risk service contracts are feasible, the pure service contract leaving a larger pure rent margin as the reduced geological risk premium (of the oil company relative to the government) is more than removed by the increased market risk



Economic value of the gas

Figure 3. Components of the supply price of gas under different contracts.


Government geological risk premia (with national company as operator)

Government risk neutral cost

Oil company market risk premia

Oil company geological risk premia

Government geological risk premia (with foreign company as operator)

I company Oi political risk premia





Oil company risk neutral cost

I

Government risk premia associated with its expenditures (eg in infrastructure)

Self- sufficient national oil company

Risk- Pure- service service contract contract

Market based contract (MBC)

MBC with finance by multilateral banks

premium of the oil company. The market pricing contract implies a further increase in the pure rent that is available as the possibility of a large pay off reduces the oil company risk premiums.*s The contract when gas infrastructure is financed by a multilateral finance institution clearly produces most rent as the perceptions of political risks by the oil company are drastically reduced.

The efficiency ranking of contracts will, of course, be project specific, although we would generally expect a pure service contract to be more optimal than the risk service variety because of a high company market risk premium. For those countries where these risks are within the bounds of acceptability, a market based approach (linked to an appropriate fiscal regime) is desirable for development projects. These countries would typically be stable middle income countries where there is already oil company involvement and where ideally there is some gas infrastructure. If developing countries arrive at the situation where they

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in developing countries

“The calculation of a risk premium depends upon potential gains as well as losses: the possibility of high returns acts as a compensation for losses. H.G. Broadman, An Econometric Analysis of the Determinants of Explofaation for Petroleum Outside North America, Resources for the Future, Washington, DC, 1985, has attempted an econometric analysis of the factors determining oil company investment, implicitly giving the relative magni- tudes of the risk premiums. His analysis concludes that exploratory drilling in non- producing countries depends predominantly on geological factors, while contractual arrangements and taxes are most important in non-USA producing countries. However, political risk is very difficult to measure and the index used is question- able. The regression equation for exploration activity in non-oil producing LDCs (where we would expect political risk to be most important) also has an p of a mere 3%.

can absorb the risks of gas exploration and development, and their national oil companies gain a sufficient level of competence to supervise contractors, then service contracts are a viable option. In some cases this may be the most efficient approach (ie the overall risk premium is minimized) and it is likely that in the future more oil companies will be prepared to undertake this type of activity. State equity holdings in joint ventures may also be used to share risk, and have the advantage that they defend national interests and act as a vehicle for technology transfer.

For the low income oil important countries where there are no existing gas consumers even the most liberal market based terms for gas development are unlikely to attract much investment. In this situation service contracts financed by concessional bilateral and multilateral funds are needed. Without these it is improbable that any significant activity will take place.

In any country where minerals are owned by the state it is inevitable that private oil companies and the government will be in conflict because of their opposing economic objectives. As we have discussed, this clash of goals between developing country governments and foreign oil companies for gas projects must often be solved in an uncompetitive environment. The more the government can promulgate the terms it intends to use, the more negotiations on the development contract can be brought forward into a competitive arena. Of course many of the final terms cannot be determined until after a gas field is found. None the less, by clearly stating the planned approach the government can reduce unnecessary uncertainties for the oil company. Concession terms should also be adjusted to allow for the longer development planning required for gas by giving periods for commercial assessment and for preparing development plans. The oil company should also be allowed, subject to government veto, to retain the title to gas fields indefinitely until markets are generated.

For the next decade the development of gas reserves will be highly influenced by the policy of multilateral development banks. With investment of their non-concessional funds in gas infrastructure, then transnational oil companies may be drawn into market based development contracts. Where appropriate these banks should also use their concessional funds to finance service activities in low income countries. The financing of structural adjustment is an attempt to encourage private direct investment in the long term through the adaption of economic conditions; however, more direct involvement is necessary to reduce the high risks associated with gas.


Documents

Contractual arrangements for the exploitation of natural gas in developing countries