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Petroleum exploration in the non-OPEC LDCs The effects of recent world developments
Petroleum exploration in the non-OPEC LDCs The effects of recent world developments
Raymond F. Mikesell The recent decline in world oil prices in terms of dollars has had an adverse effect on exploration activity in many regions of the world. I emphasize dollar prices because for consumers and producers outside the USA, the decline in world dollar prices has been approximately offset by the appreciation of the dollar in relation to other major currencies. In addition to the decline in the dollar price of oil, there has been a change in the longer-term outlook for oil prices, which may be even more important for exploration than the drop in current prices. I have the impression that much of the investment in petroleum exploration in the past has been based in considerable part on the assumption of a continuing rise in real oil prices. This may well be the case over the coming decades, but recent developments have led to uncertainties regarding the trends of real oil prices. Apart from the price outlook, the exploration budgets of petroleum companies have been adversely affected by a reduction in their cash flow, arising both from the decline in dollar prices and the fall in world demand for oil. Exploration activity has not changed uniformly among the various Keywords: Petroleum exploration; LDCs, regions of the world. It has declined drastically in the USA, but much Oil prices less so in a number of other non-OPEC regions, and in some regions it The author is the W.E. Miner Professor of has continued to expand. This article concentrates on the effects of Economics, University of Oregon, Eugene, recent world developments on exploration in non-OPEC LDCs and in OR 97403-1202, USA. particular on exploration in the oil-importing developing countries (OIDCs). Little in the way of quantitative data exists on these activities during 1982 and early 1983. It may be noted, however, that planned capital expenditures in the petroleum sector by foreign affiliates of US companies in 1983 declined significantly in South America and Africa from actual 1982 expenditures. Within the Third World, only in Southeast Asia are US company planned expenditures in 1983 significantly higher than actual expenditures in 1982.1 Discussions with 1R. Kozlow, 'Capital expenditures by petroleum company and other petroleum specialists regarding recent majority-owned foreign affiliates of US companies, 1983', Survey of Current Busi- exploration trends give the impression that multinational petroleum companies have been much less willing to negotiate contracts and ness, March 1983, pp 28-29.
The recent decline in world petroleum prices and the uncertainty with respect to future oil prices is having an adverse effect on exploration in non-OPEC LDCs, particularly in the oil-importing developing countries. The fiscal regimes of LDCs, as applied to petroleum investment, have tended to limit incentives for foreign investment, especially in countries without high reserve potential. Recent developments have exacerbated these fiscal deterrents to petroleum investment, particularly in countries where there is little likelihood of discovering large oil fields. In addition, the external debt crisis in a number of LDCs where petroleum operations are largely in the hands of government oil enterprises is likely to reduce the availability of external financing for oil exploration and development.
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undertake exploration in areas regarded as marginal, while in more promising areas the amounts these companies are willing to commit in bidding for acreage has substantially declined. According to a World Bank specialist, this is definitely the case for a number of OIDCs with which the World Bank has lending programmes for seismic and appraisal drilling, designed mainly to assist the countries in offering new acreage to petroleum companies. In appraising the effects of recent world developments on exploration it must be kept in mind that about 60% of exploration activity in the OIDCs is accounted for by national oil companies, such as Petrobras in Brazil, the Oil and Natural Gas Commission in India, Petroperu in Peru, and Yacimientos Petroliferos Fiscales (YPF) in Argentina. The exploration activities of government oil enterprises (GOEs) are determined by government policies plus the availability of financing, much of which is derived directly (or indirectly via central government foreign borrowing) from external sources. Although the drop in dollar oil prices should not significantly affect the incentives of GOEs to increase oil exploration and development, the current debt crisis experienced by a number of countries with substantial government oil programmes has undoubtedly had an impact on their exploration budgets, especially for costly offshore operations. During the 1975-1980 period, external public guaranteed financing of oil and gas projects in developing countries totalled about $25 billion; most of this financing was for government or joint government-private projects. Of this amount about 33% came from international financial institutions (mainly commercial banks); 29% from suppliers' credits for financing exports; about 16% from bilateral concessionary assistance; and about 8% from multinational public sources such as the World Bank. z Over half this financing for oil and gas projects has gone to the OIDCs. The sharp reduction in total international bank lending to developing countries during 1982 was probably accompanied by a substantial reduction in external financing for government petroleum projects, although the author has no direct data on this. Total net international commercial bank lending to 21 major LDC borrowers reached a peak of nearly $47 billion in 1981, declining to less than $38 billion in 1982, and is projected to be about $22 billion in 1983. 3 Although the current debt crisis may pass, total borrowing in real terms by the LDCs is unlikely to approach the 1981 level during the rest of the decade. It cannot be expected that loans from public international lending agencies will make up a significant portion of this decline in private international financing. World Bank lending for oil development, a portion of which went to private or joint private-government projects, declined from $462 million in fiscal year 1981 to $303 million in fiscal year 1982. The World Bank is unlikely to make large loans to GOEs since the Bank's policy has been to use its funds as a catalyst for promoting private equity and loan financing in the petroleum sectors of its members. In the remainder of this article the effects of recent world developments on exploration by multinational petroleum companies in the non-OPEC LDCs will be discussed, within the context of the contract terms currently offered by these countries. For some countries, such as 21BRDsources. Egypt and Malaysia where large fields have been discovered and 3World Financial Markets, Morgan Guaranty Trust Co, New York, February prospects are favourable, the 15% decline in the world oil price may not 1983, p 10. in itself substantially reduce the incentive to explore new acreage,
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Petroleum exploration in the non-OPEC LDCs
especially since the governments are already taking 85-90%, or more, of the net revenues. The decline in prices and the uncertainties relating to future prices and to the world demand-supply balance are likely to have a severe effect on exploration incentives in high-risk areas where the probability of finding large fields is very low. Unless the contract terms offered by these countries are substantially altered, there may be a low level of interest on the part of petroleum companies in bidding for contracts. It seems likely, in any case, that many of these countries will have little opportunity of achieving the level of exploration warranted by their estimated reserve potential.
Petroleum agreements and host country tax regimes During the post-World War II period, the traditional concession agreement that governed the operations of foreign petroleum companies was replaced by a variety of arrangements that have not only given host governments the vast bulk of net revenues, but have provided governments with a substantial degree of control over the operations of foreign petroleum companies. The following paragraphs concentrate on some of the features of these arrangements that have impaired the attractiveness of petroleum investments in the past or have reduced the efficiency of exploration and development operations. Except for the pure service contract (still used in Argentina), under which the contractor is paid a fixed amount for specific tasks such as drilling so many wells to a certain depth, the several categories of contracts (eg production-sharing contracts (PSCs), joint ventures, modern concession agreements, and so-called risk service contracts) have all tended to encompass a number of more or less common fiscal features that have rendered the categories somewhat ambiguous. For example, the original PSCs employed in Indonesia and Peru that provided for a simple division of the output after a fixed percentage cost allowance4 have been altered to include signature and production bonuses, income taxes, differential output splits based on the level of output, and a requirement to supply a portion of the contractor's share of the output to the domestic market at a fraction of the world price. The modern production-sharing contract often differs only slightly from joint venture contracts under which the contractor's share is subject to income and other taxes. The substantive features of the modern contracts that affect risk, the expected internal rate of return, and the efficiency of the development of fields include provisions for signature bonuses; a commitment of a minimum level of expenditure or exploration activity; royalties or other forms of taxation on gross output; the use of a graduated tax on gross output or net profits (excess profits tax); the use of investment tax credits; and the creditability of taxes paid to the host government against tax liabilities of the foreign investor to its home government. Some of these features involve complex effects on the three elements cited above. Although a full analysis is not possible within the space limits of this article, certain principles that have a bearing on the weaknesses of many fiscal regimes will be examined. To begin with, a brief analysis will be made of the effects of different fiscal regimes on risk and risk perception. Most investors employ the 4The original Peruvian petroleum production-sharing contracts did not pro- internal rate of return (IRR) or net present value (NPV) at an acceptable rate of return as the basis for making an investment decision vide for a cost allowance.
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~For details and an illustration, see Raymond F. Mikesell, Petroleum Company Operations and Agreements in the Developing Countries, Johns Hopkins University Press for Resources for the Future, Baltimore, USA, forthcoming. See also, Thomas R. Stauffer and John Gait, 'Effects of petroleum tax design upon exploration and development', paper presented at the 1981 Economics and Evaluation Symposium of the Society of Petroleum Engineers of the AIME, Dallas, TX, USA, 25-27 February 1981.
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or for choosing between alternative investment opportunities. Since the outcome of an investment is uncertain, the petroleum company must apply a probability coefficient in order to determine whether the project will yield an acceptable, probability-adjusted IRR, or what has been called the expected IRR. The expected or probability-adjusted IRR is the average of a number of possible IRRs, each weighted by the probability that the particular rate of return will be achieved. This is a complicated process since each of the elements determining the final IRR, such as the likelihood of discovering small fields or large fields, the operating cost per unit of output, and the future price of petroleum, will have a range of probabilities. However, knowledge of the probability coefficients for each of a number of possible outcomes of these various factors will enable the investor to estimate a probability-weighted or expected I R R on the investment. It is not always possible to estimate the probability coefficients for each possible outcome, except on a rather broad basis. For example, this situation would exist for an initial investment in seismic activity or exploratory drilling in an area about which very little is known. On the other hand, a geologist familiar with the geological structure of a region might be able to assign probability coefficients for finding oil fields of different sizes in terms of the volume of reserves. In addition to the expected IRR, an investor must take account of risk aversion, which will differ among investors in accordance with the size of the investing firm or its portfolio of ventures. A small firm with only one or two investment projects will usually be more risk averse than a very large firm with a large portfolio of investment projects. The more risk averse the investor, the higher his acceptable expected I R R is likely to be. When account is taken of risk aversion, it is possible to calculate an investor's risk-corrected expected IRR. The risk-corrected IRR is a function of the investor's coefficient of risk aversion and the variance of the rate of return. For the same expected or probability-adjusted I R R and the same coefficient of risk aversion (or risk perception of the individual investor), different fiscal regimes may yield different riskcorrected IRRs for the same investment prospect, depending upon the variance (or standard deviation) of the probability-adjusted cash flow for the two regimes. Without going into further technicalities, this situation may be illustrated by an investment prospect in which there is a low probability of discovering a large field with a relatively high net cash flow, and a much higher probability of finding a smaller field with a much lower net cash flow. If the fiscal regime is such that it would be profitable to produce the large field if discovered but not the smaller field, the variance of the probability-adjusted rate of return will be higher than would be the case under a fiscal regime that would make it profitable to produce either the smaller field or the larger field if only one is discovered. In the latter case, the risk-corrected I R R is potentially greater than in the former case in which it would only be profitable to produce the larger field. Thus the potential investor's risk-corrected I R R might be below his acceptable rate of return under the fiscal system that rendered it profitable to produce only the larger field. It can also be shown that with a fiscal regime under which it would be profitable to produce either the smaller field or the larger field, the expected present value of the government's revenue will be larger than it would be under a fiscal regime in which it would only be profitable to produce the larger field, s ENERGY POLICY March 1984
Petroleum exploration in the non-OPEC LDCs
Bonus payments and minimum expenditure requirements Signature bonuses and large investment expenditure commitments not geared to exploration results increase risk by committing the investor to a larger fixed cost for obtaining knowledge through exploration. A larger signature bonus substantially reduces the expected NPV of the lease as contrasted with the same government revenue obtained from a royalty or net profits tax that would be paid only after production was initiated. A bonus payment designed to capture a portion of the rent requires the contractor to accept the entire risk of there being any economic rent to be derived from the lease, thereby reducing the expected NPV of the investment. Also, the discounted value of the cost incurred with a bonus payment is substantially higher than the discounted value of royalty or profits taxes paid after production is initiated. Moreover, in the absence of a bonus payment or a minimum expenditure requirement, the contractor can buy an increasing amount of knowledge for each dollar spent on exploration and can make a decision to cancel the lease or contract at any time on the basis of the knowledge gained. Under certain circumstances, particularly where there is a substantial amount of knowledge regarding a tract available for lease, there may be an advantage in competitive bonus bidding for petroleum contracts. But in the case of areas for which there is little geological information and where the government is anxious to attract companies to undertake high-risk exploration in regions where no oil has been discovered, competitive bonus bidding may fail to attract prospective investors. This has proved to be the case in Guatemala. 6 Also, in the case of areas regarding which there is little knowledge, there may be little relationship between the actual economic rent from the project and the bonus. On the other hand, once several discoveries are made and a substantial amount of geological knowledge is accumulated, many more companies will be attracted and bonus bidding may have the advantage of both increasing the share of economic rent going to the government and of achieving a more efficient development of resources discovered as compared, for example, with a high royalty. The requirement that companies agree to put up a bond guaranteeing that they will spend a minimum of, say, $10 million or drill a certain number of wildcats has often discouraged companies from negotiating contracts. This was true in the case of the initial so-called risk contracts employed in Brazil. Subsequently, companies were offered a 'seismic option' which enabled them to undertake a certain amount of exploration without a large commitment for drilling. A popular form of bonus payment provides for payments on the discovery of a commercially producible field, followed by graduated payments when daily production reaches progressively higher levels. Although such arrangements reduce risk compared with a large signature bonus, they are likely to prevent the development of a marginal field or the expansion of production beyond the level that triggers a higher production bonus payment. The rationale for a sliding scale bonus is that the larger the output, the lower the cost per barrel and, therefore, the larger the proportion of the total economic rent the host government can capture. However, the existence of progressive 8Raymond F. Mikesell, Petroleum Company Operations and Agreements in the bonus obligations reduces the present value of marginal investments and may work against the most efficient development of a field. Developing Countries, ibid, Chapter VII.
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Petroleum exploration in the non-OPEC LDCs Royalties and production-sharing contracts
Royalties and PSCs reduce risk, compared with large signature bonuses, but have the disadvantage of reducing the incentive for developing marginal fields. In some countries PSCs allow the contractor to deduct a certain percentage of the output, say 40%, to cover his costs (cost oil) before sharing the remainder (profit oil) with the government. A cost oil allowance encourages the contractor to minimize costs since his cost allowance does not decline with lower actual costs. Since operating costs as a percentage of sales revenue tend to decline as output rises, the expected NPV for a given percentage cost oil allowance is higher for larger fields than for smaller ones. Although the contractor's expected NPV with a given cost oil allowance will be higher the higher the probability of finding a large field, it is less effective for increasing the expected NPV for a smaller field. Hence, a cost allowance tends to reduce the relative expected NPV of small fields. Taxes on net profits and excess profits taxes
A fiscal system based largely on taxes on net profits has the advantage of both minimizing risk and maximizing total revenue, so long as the rates of taxation are not so high as to discourage the development of marginal fields. Net profits taxes do, however, have the disadvantage of delaying government revenues, especially where the tax regimes provide for rapid capital recovery. Profits taxes, unlike royalties and bonus payments, are also creditable against the tax liabilities of the investor to the government of the parent company. Some governments have imposed so-called windfall profits taxes on petroleum producers to capture a larger share of the economic rent. Since the contractor's expected IRR depends heavily upon the possibility of discovering a large field that will yield high returns, the effect of a high windfall profits tax is to reduce substantially the expected or probability-adjusted IRR. Most windfall or excess profits taxes apply to accounting rates of profits above a certain level. Accounting profits vary widely over time and do not constitute a proper measure of economic rent, since they do not reflect full economic costs. The only proper measure of pure economic rent is the surplus over the net return to the investor that yields an IRR equal to the opportunity cost of his capital. One means of avoiding some of the difficulties of an excess profits tax on the accounting rate of return is provided by the so-called 'resource rent tax' or the D C F 'trigger tax'. This tax system was developed by Ross Garnaut and Anthony Clunies-Ross. 7 The resource rent tax is levied only on profits in any year in excess of the amount necessary to yield a specified I R R on all capital expenditures. Although there are difficulties with the resource rent tax, if host governments must apply some form of excess profits tax, the resource rent tax has certain advantages over other forms in rendering petroleum projects more attractive to a prospective investor. Accelerated depreciation of all capital expenditures has some of the same advantages. 7Ross Garnaut and Anthony Clunies-Ross, 'Uncertainty, risk and taxing of natural resource projects', Economic Journal, June 1975, p 287; see also, Raymond F. Mikesell, The World Copper Industry, Johns Hopkins University Press for Resources for the Future, Baltimore, 1979, pp 295-297.
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Evaluation of host country fiscal regimes from the standpoint of attracting foreign investment in petroleum Fiscal regimes, applied to petroleum contracts in developing countries, are usually a hotchpotch of arrangements that have not been well structured from the standpoint of either maximizing government E N E R G Y POLICY March 1984
Petroleum exploration in the non-OPEC LDCs
revenues or of providing maximum attractiveness of an investment to investors given the percentage of the government's take of the potential revenues from the project. It is true that some arrangements, such as a high signature bonus, seek to maximize early returns to the government, but they are usually at the expense of much larger revenues later on in the project so that the NPV of the government's take may be adversely affected. OIDCs with unknown or modest petroleum potential often pattern their contracts along the lines of those negotiated by countries with substantial reserves and favourable geological conditions for large field discoveries. High-risk exploration with little probability of success requires generous terms in order to provide substantial rewards for successful ventures. Moreover, since newly discovered fields in regions not producing oil are likely to be relatively small, while exploration and development costs are high, the expected NPVs before taxes may not be exceptionally high even if contract terms are quite generous. Once important discoveries are made, new contracts more favourable to the government can be negotiated on tracts in the same area. Argentina, Bolivia, Brazil, Colombia, Guatemala, India, Pakistan, Peru and Turkey, amongst others, are OIDCs that either currently or in the recent past have not offered sufficiently attractive terms to foreign investors to achieve an adequate level of exploration. Some of these countries have improved their contract terms in recent years, eg Brazil and Colombia, with a consequent rise in foreign exploration activity, but many years of potential production have already been lost at enormous cost to the countries. The shortcomings of petroleum contracts include high royalties or shares of gross output going to the government; high signature and production bonuses; commitments of large minimum expenditures on contract areas regardless of exploration results; the requirement to sell output to the government at prices well below world market prices; exorbitant income taxes, including excess profits taxes that are out of line with the degree of risk associated with unexplored areas; and tax systems that prevent foreign investors from crediting taxes paid in the host country against tax liabilities in their parent countries. In addition to the shortcomings of the fiscal arrangements, GOEs in host countries often select the most favourable acreage for themselves, an allegation that has been made in the past with respect to Argentina and Brazil. In some countries, eg Brazil, foreign petroleum companies are not permitted to operate the fields they develop. Finally, in some countries the government has forced renegotiation of contract terms to the disadvantage of the contractors after the contracts have gone into effect. This is well illustrated by the action of the Peruvian government in 1980 when it forced a renegotiation of its contracts with Occidental Petroleum and Belco Petroleum on substantially less favourable terms for the companies. A serious overall defect in the fiscal systems as applied to petroleum investments of many, if not most, developing countries is that they tend to be regressive in the sense that the government's share of net profits is substantially larger on lower quality fields (eg high cost/low volume) than on higher quality fields (low cost/high volume). This result tends to be produced by a heavy reliance on revenues from production-sharing, royalties and bonus payments, while taxes on net profits with rapid cost recovery tend to be more progressive in their effects on the govern-
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Petroleum exploration in the non-OPEC LDCs
ment's share of net profits, thereby providing greater encouragement for the development of high cost/low volume fields. A regressive tax system may result in an expected IRR for a high cost/low volume field that is unacceptable to investors, while at the same time providing a relatively high expected IRR for low cost/high volume fields, the probability of discovering the latter type of field being relatively low in any particular region. Therefore, a regressive fiscal system will tend to reduce the expected IRR for the investor and, for reasons indicated earlier, raise the acceptable risk-corrected IRR for the project. The regressivity of fiscal systems in recent concession contracts has been illustrated by Alexander Kemp and David Rose 8 by means of a simulation of the effects of fiscal systems currently applied to concession contracts in five countries - Egypt, Indonesia, Malaysia, Nigeria and Papua New Guinea (PNG) - for four hypothetical oil fields, with each hypothetical field identical for each of the five countries. The four hypothetical (new) fields are characterized as low cost/high volume, medium cost/medium volume, high cost/medium volume, and high cost/low volume. In all cases the simulations were on a project lifetime basis and were conducted on both a nominal and a real return basis, assuming constant real oil prices and real value returns. The price of oil in the base case was $33.80/bbl and the calculation of real IRR assumed that both the price of oil and capital and operating costs escalated at 9% per year. In the absence of government taxes, all four hypothetical fields yield a positive NPV at a 15% (real) rate of discount. The results of the simulations showed that in the case of Egypt and Indonesia the (real) IRRs for the low cost/high volume and medium cost/medium volume fields were significantly above the minimum acceptable rate of 15% but the IRRs for the two high-cost fields were below the minimum acceptable rate. In the case of Malaysia and Nigeria, the IRRs on the medium cost/medium volume fields were only marginally above the minimum acceptable rate of return, but in both cases the low cost/high volume fields were significantly above the minimum rate of return. For all four countries the government's take as a percentage of resources generated (total revenues minus all capital and operating costs) either rose or did not decline significantly with a decline in the quality of the fields. However, in the case of PNG, the government's take as a percentage of resources generated declined progressively from the low cost/high volume field to the high cost/low volume field, and in all four hypothetical fields the (real) IRR is significantly above the minimum acceptable rate of return. The PNG fiscal system for petroleum is characterized by a low royalty rate of 1.25% and a net profits tax, plus a resource rent tax. The Egyptian, Indonesian and Malaysian systems employ a productionsharing arrangement. The Nigerian system provides for a posted price set above the market price, and the royalty, varying from 16.6% to 20%, is based on the posted price. There are other complications in the five fiscal systems, but the results 8Alexander G. Kemp and David Rose, 'Four oil fiscal systems in need of an illustrate the general principles set forth above. Only the PNG system is overhaul', Financial Times Energy Eco- reasonably progressive, in that the total government take as a nomist, April 1982; and Alexander G. Kemp and David Rose, Investment in Oil percentage of resources generated and the real IRRs for the lower Exploration and Development: A Compa- quality fields are adequate to induce investment. It may be noted that rative Study of the Effects of Taxation, most fiscal systems employed by developing countries with respect to North Sea Study Occasional Papers, University of Aberdeen, Scotland, November petroleum investment rely far more heavily on production-sharing, royalties and bonus payments than on income taxes as is the case with 1982. 20
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PNG. This suggests that for most developing countries the fiscal systems are biased against small, high-cost fields. The foregoing observations on fiscal terms as a deterrent to exploration in developing countries are shared not only by oil industry spokesmen, but by independent observers, such as members of the World Bank staff. For example, Keith Palmer, a contract specialist in the Petroleum Projects Division of the World Bank's Energy Department, stated in a recent article that: the fiscal terms in petroleum contracts may also deter private sector exploration in some cases. In response to the large oil price increases, countries raised substantially the government's share of project revenues from royalties, taxes, production shares and so on to obtain for the state a larger share of the resource rent and to limit the 'windfall' gains made by investors. However, the structure of the fiscal terms in many cases not only limit windfall gains, but also make it unprofitable for investors to explore for small fields. 9 It should not be concluded that unattractive fiscal terms are the only deterrent to exploration and development in the n o n - O P E C LDCs. The larger integrated multinational petroleum companies are primarily (but not exclusively) interested in exploring in areas with a potential for large fields, eg in excess of 500 million barrels of oil. This is true because of their interest in producing petroleum for export to their downstream operations. 1° In most OIDCs, particularly those in which oil discoveries have not been made, the probability of discovering large fields is low. In many areas discoveries are more likely to take the form of gas than petroleum. However, multinational petroleum companies are usually not interested in discovering gas fields with reserves less than the minimum required for liquified gas export projects to become economical. In addition, there may not be a readily accessible market and pipeline facilities for natural gas in the host country.
Conclusions
9Keith Palmer, 'Private sector petroleum exploration in developing countries', Finance and Development, quarterly publication of the IMF and World Bank, March 1983, p 36. 1°It is worth noting that in Argentina the multinationals most active in exploration have refining and distributing facilities in that country.
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The shortcomings of modern petroleum contracts for attracting foreign petroleum investors are exacerbated by recent developments in the world oil market. With smaller exploration budgets resulting from reduced cash flow, petroleum companies will tend to concentrate their activities in areas with the best prospects for finding high volume/low cost fields. This will tend to work against exploration in most OIDCs and in particular against the non-oil producing developing countries. The greater uncertainty regarding future oil prices will increase the acceptable risk-corrected I R R for undertaking petroleum investments in most if not all the n o n - O P E C LDCs. Finally, the lower world demand and expected rate of growth in world demand will reduce the incentives for integrated multinationals to expand their exploration activities in the LDC oil-exporting countries to meet their downstream requirements. It is my conclusion, therefore, that the post-World War II trend of a larger and larger share of the revenue pie going to host governments must be reversed if exploration activities in the n o n - O P E C LDCs are to expand or even be maintained at current levels.
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Raymond F. Mikesell The recent decline in world oil prices in terms of dollars has had an adverse effect on exploration activity in many regions of the world. I emphasize dollar prices because for consumers and producers outside the USA, the decline in world dollar prices has been approximately offset by the appreciation of the dollar in relation to other major currencies. In addition to the decline in the dollar price of oil, there has been a change in the longer-term outlook for oil prices, which may be even more important for exploration than the drop in current prices. I have the impression that much of the investment in petroleum exploration in the past has been based in considerable part on the assumption of a continuing rise in real oil prices. This may well be the case over the coming decades, but recent developments have led to uncertainties regarding the trends of real oil prices. Apart from the price outlook, the exploration budgets of petroleum companies have been adversely affected by a reduction in their cash flow, arising both from the decline in dollar prices and the fall in world demand for oil. Exploration activity has not changed uniformly among the various Keywords: Petroleum exploration; LDCs, regions of the world. It has declined drastically in the USA, but much Oil prices less so in a number of other non-OPEC regions, and in some regions it The author is the W.E. Miner Professor of has continued to expand. This article concentrates on the effects of Economics, University of Oregon, Eugene, recent world developments on exploration in non-OPEC LDCs and in OR 97403-1202, USA. particular on exploration in the oil-importing developing countries (OIDCs). Little in the way of quantitative data exists on these activities during 1982 and early 1983. It may be noted, however, that planned capital expenditures in the petroleum sector by foreign affiliates of US companies in 1983 declined significantly in South America and Africa from actual 1982 expenditures. Within the Third World, only in Southeast Asia are US company planned expenditures in 1983 significantly higher than actual expenditures in 1982.1 Discussions with 1R. Kozlow, 'Capital expenditures by petroleum company and other petroleum specialists regarding recent majority-owned foreign affiliates of US companies, 1983', Survey of Current Busi- exploration trends give the impression that multinational petroleum companies have been much less willing to negotiate contracts and ness, March 1983, pp 28-29.
The recent decline in world petroleum prices and the uncertainty with respect to future oil prices is having an adverse effect on exploration in non-OPEC LDCs, particularly in the oil-importing developing countries. The fiscal regimes of LDCs, as applied to petroleum investment, have tended to limit incentives for foreign investment, especially in countries without high reserve potential. Recent developments have exacerbated these fiscal deterrents to petroleum investment, particularly in countries where there is little likelihood of discovering large oil fields. In addition, the external debt crisis in a number of LDCs where petroleum operations are largely in the hands of government oil enterprises is likely to reduce the availability of external financing for oil exploration and development.
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undertake exploration in areas regarded as marginal, while in more promising areas the amounts these companies are willing to commit in bidding for acreage has substantially declined. According to a World Bank specialist, this is definitely the case for a number of OIDCs with which the World Bank has lending programmes for seismic and appraisal drilling, designed mainly to assist the countries in offering new acreage to petroleum companies. In appraising the effects of recent world developments on exploration it must be kept in mind that about 60% of exploration activity in the OIDCs is accounted for by national oil companies, such as Petrobras in Brazil, the Oil and Natural Gas Commission in India, Petroperu in Peru, and Yacimientos Petroliferos Fiscales (YPF) in Argentina. The exploration activities of government oil enterprises (GOEs) are determined by government policies plus the availability of financing, much of which is derived directly (or indirectly via central government foreign borrowing) from external sources. Although the drop in dollar oil prices should not significantly affect the incentives of GOEs to increase oil exploration and development, the current debt crisis experienced by a number of countries with substantial government oil programmes has undoubtedly had an impact on their exploration budgets, especially for costly offshore operations. During the 1975-1980 period, external public guaranteed financing of oil and gas projects in developing countries totalled about $25 billion; most of this financing was for government or joint government-private projects. Of this amount about 33% came from international financial institutions (mainly commercial banks); 29% from suppliers' credits for financing exports; about 16% from bilateral concessionary assistance; and about 8% from multinational public sources such as the World Bank. z Over half this financing for oil and gas projects has gone to the OIDCs. The sharp reduction in total international bank lending to developing countries during 1982 was probably accompanied by a substantial reduction in external financing for government petroleum projects, although the author has no direct data on this. Total net international commercial bank lending to 21 major LDC borrowers reached a peak of nearly $47 billion in 1981, declining to less than $38 billion in 1982, and is projected to be about $22 billion in 1983. 3 Although the current debt crisis may pass, total borrowing in real terms by the LDCs is unlikely to approach the 1981 level during the rest of the decade. It cannot be expected that loans from public international lending agencies will make up a significant portion of this decline in private international financing. World Bank lending for oil development, a portion of which went to private or joint private-government projects, declined from $462 million in fiscal year 1981 to $303 million in fiscal year 1982. The World Bank is unlikely to make large loans to GOEs since the Bank's policy has been to use its funds as a catalyst for promoting private equity and loan financing in the petroleum sectors of its members. In the remainder of this article the effects of recent world developments on exploration by multinational petroleum companies in the non-OPEC LDCs will be discussed, within the context of the contract terms currently offered by these countries. For some countries, such as 21BRDsources. Egypt and Malaysia where large fields have been discovered and 3World Financial Markets, Morgan Guaranty Trust Co, New York, February prospects are favourable, the 15% decline in the world oil price may not 1983, p 10. in itself substantially reduce the incentive to explore new acreage,
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especially since the governments are already taking 85-90%, or more, of the net revenues. The decline in prices and the uncertainties relating to future prices and to the world demand-supply balance are likely to have a severe effect on exploration incentives in high-risk areas where the probability of finding large fields is very low. Unless the contract terms offered by these countries are substantially altered, there may be a low level of interest on the part of petroleum companies in bidding for contracts. It seems likely, in any case, that many of these countries will have little opportunity of achieving the level of exploration warranted by their estimated reserve potential.
Petroleum agreements and host country tax regimes During the post-World War II period, the traditional concession agreement that governed the operations of foreign petroleum companies was replaced by a variety of arrangements that have not only given host governments the vast bulk of net revenues, but have provided governments with a substantial degree of control over the operations of foreign petroleum companies. The following paragraphs concentrate on some of the features of these arrangements that have impaired the attractiveness of petroleum investments in the past or have reduced the efficiency of exploration and development operations. Except for the pure service contract (still used in Argentina), under which the contractor is paid a fixed amount for specific tasks such as drilling so many wells to a certain depth, the several categories of contracts (eg production-sharing contracts (PSCs), joint ventures, modern concession agreements, and so-called risk service contracts) have all tended to encompass a number of more or less common fiscal features that have rendered the categories somewhat ambiguous. For example, the original PSCs employed in Indonesia and Peru that provided for a simple division of the output after a fixed percentage cost allowance4 have been altered to include signature and production bonuses, income taxes, differential output splits based on the level of output, and a requirement to supply a portion of the contractor's share of the output to the domestic market at a fraction of the world price. The modern production-sharing contract often differs only slightly from joint venture contracts under which the contractor's share is subject to income and other taxes. The substantive features of the modern contracts that affect risk, the expected internal rate of return, and the efficiency of the development of fields include provisions for signature bonuses; a commitment of a minimum level of expenditure or exploration activity; royalties or other forms of taxation on gross output; the use of a graduated tax on gross output or net profits (excess profits tax); the use of investment tax credits; and the creditability of taxes paid to the host government against tax liabilities of the foreign investor to its home government. Some of these features involve complex effects on the three elements cited above. Although a full analysis is not possible within the space limits of this article, certain principles that have a bearing on the weaknesses of many fiscal regimes will be examined. To begin with, a brief analysis will be made of the effects of different fiscal regimes on risk and risk perception. Most investors employ the 4The original Peruvian petroleum production-sharing contracts did not pro- internal rate of return (IRR) or net present value (NPV) at an acceptable rate of return as the basis for making an investment decision vide for a cost allowance.
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Petroleum exploration in the non-OPEC LDCs
~For details and an illustration, see Raymond F. Mikesell, Petroleum Company Operations and Agreements in the Developing Countries, Johns Hopkins University Press for Resources for the Future, Baltimore, USA, forthcoming. See also, Thomas R. Stauffer and John Gait, 'Effects of petroleum tax design upon exploration and development', paper presented at the 1981 Economics and Evaluation Symposium of the Society of Petroleum Engineers of the AIME, Dallas, TX, USA, 25-27 February 1981.
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or for choosing between alternative investment opportunities. Since the outcome of an investment is uncertain, the petroleum company must apply a probability coefficient in order to determine whether the project will yield an acceptable, probability-adjusted IRR, or what has been called the expected IRR. The expected or probability-adjusted IRR is the average of a number of possible IRRs, each weighted by the probability that the particular rate of return will be achieved. This is a complicated process since each of the elements determining the final IRR, such as the likelihood of discovering small fields or large fields, the operating cost per unit of output, and the future price of petroleum, will have a range of probabilities. However, knowledge of the probability coefficients for each of a number of possible outcomes of these various factors will enable the investor to estimate a probability-weighted or expected I R R on the investment. It is not always possible to estimate the probability coefficients for each possible outcome, except on a rather broad basis. For example, this situation would exist for an initial investment in seismic activity or exploratory drilling in an area about which very little is known. On the other hand, a geologist familiar with the geological structure of a region might be able to assign probability coefficients for finding oil fields of different sizes in terms of the volume of reserves. In addition to the expected IRR, an investor must take account of risk aversion, which will differ among investors in accordance with the size of the investing firm or its portfolio of ventures. A small firm with only one or two investment projects will usually be more risk averse than a very large firm with a large portfolio of investment projects. The more risk averse the investor, the higher his acceptable expected I R R is likely to be. When account is taken of risk aversion, it is possible to calculate an investor's risk-corrected expected IRR. The risk-corrected IRR is a function of the investor's coefficient of risk aversion and the variance of the rate of return. For the same expected or probability-adjusted I R R and the same coefficient of risk aversion (or risk perception of the individual investor), different fiscal regimes may yield different riskcorrected IRRs for the same investment prospect, depending upon the variance (or standard deviation) of the probability-adjusted cash flow for the two regimes. Without going into further technicalities, this situation may be illustrated by an investment prospect in which there is a low probability of discovering a large field with a relatively high net cash flow, and a much higher probability of finding a smaller field with a much lower net cash flow. If the fiscal regime is such that it would be profitable to produce the large field if discovered but not the smaller field, the variance of the probability-adjusted rate of return will be higher than would be the case under a fiscal regime that would make it profitable to produce either the smaller field or the larger field if only one is discovered. In the latter case, the risk-corrected I R R is potentially greater than in the former case in which it would only be profitable to produce the larger field. Thus the potential investor's risk-corrected I R R might be below his acceptable rate of return under the fiscal system that rendered it profitable to produce only the larger field. It can also be shown that with a fiscal regime under which it would be profitable to produce either the smaller field or the larger field, the expected present value of the government's revenue will be larger than it would be under a fiscal regime in which it would only be profitable to produce the larger field, s ENERGY POLICY March 1984
Petroleum exploration in the non-OPEC LDCs
Bonus payments and minimum expenditure requirements Signature bonuses and large investment expenditure commitments not geared to exploration results increase risk by committing the investor to a larger fixed cost for obtaining knowledge through exploration. A larger signature bonus substantially reduces the expected NPV of the lease as contrasted with the same government revenue obtained from a royalty or net profits tax that would be paid only after production was initiated. A bonus payment designed to capture a portion of the rent requires the contractor to accept the entire risk of there being any economic rent to be derived from the lease, thereby reducing the expected NPV of the investment. Also, the discounted value of the cost incurred with a bonus payment is substantially higher than the discounted value of royalty or profits taxes paid after production is initiated. Moreover, in the absence of a bonus payment or a minimum expenditure requirement, the contractor can buy an increasing amount of knowledge for each dollar spent on exploration and can make a decision to cancel the lease or contract at any time on the basis of the knowledge gained. Under certain circumstances, particularly where there is a substantial amount of knowledge regarding a tract available for lease, there may be an advantage in competitive bonus bidding for petroleum contracts. But in the case of areas for which there is little geological information and where the government is anxious to attract companies to undertake high-risk exploration in regions where no oil has been discovered, competitive bonus bidding may fail to attract prospective investors. This has proved to be the case in Guatemala. 6 Also, in the case of areas regarding which there is little knowledge, there may be little relationship between the actual economic rent from the project and the bonus. On the other hand, once several discoveries are made and a substantial amount of geological knowledge is accumulated, many more companies will be attracted and bonus bidding may have the advantage of both increasing the share of economic rent going to the government and of achieving a more efficient development of resources discovered as compared, for example, with a high royalty. The requirement that companies agree to put up a bond guaranteeing that they will spend a minimum of, say, $10 million or drill a certain number of wildcats has often discouraged companies from negotiating contracts. This was true in the case of the initial so-called risk contracts employed in Brazil. Subsequently, companies were offered a 'seismic option' which enabled them to undertake a certain amount of exploration without a large commitment for drilling. A popular form of bonus payment provides for payments on the discovery of a commercially producible field, followed by graduated payments when daily production reaches progressively higher levels. Although such arrangements reduce risk compared with a large signature bonus, they are likely to prevent the development of a marginal field or the expansion of production beyond the level that triggers a higher production bonus payment. The rationale for a sliding scale bonus is that the larger the output, the lower the cost per barrel and, therefore, the larger the proportion of the total economic rent the host government can capture. However, the existence of progressive 8Raymond F. Mikesell, Petroleum Company Operations and Agreements in the bonus obligations reduces the present value of marginal investments and may work against the most efficient development of a field. Developing Countries, ibid, Chapter VII.
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Petroleum exploration in the non-OPEC LDCs Royalties and production-sharing contracts
Royalties and PSCs reduce risk, compared with large signature bonuses, but have the disadvantage of reducing the incentive for developing marginal fields. In some countries PSCs allow the contractor to deduct a certain percentage of the output, say 40%, to cover his costs (cost oil) before sharing the remainder (profit oil) with the government. A cost oil allowance encourages the contractor to minimize costs since his cost allowance does not decline with lower actual costs. Since operating costs as a percentage of sales revenue tend to decline as output rises, the expected NPV for a given percentage cost oil allowance is higher for larger fields than for smaller ones. Although the contractor's expected NPV with a given cost oil allowance will be higher the higher the probability of finding a large field, it is less effective for increasing the expected NPV for a smaller field. Hence, a cost allowance tends to reduce the relative expected NPV of small fields. Taxes on net profits and excess profits taxes
A fiscal system based largely on taxes on net profits has the advantage of both minimizing risk and maximizing total revenue, so long as the rates of taxation are not so high as to discourage the development of marginal fields. Net profits taxes do, however, have the disadvantage of delaying government revenues, especially where the tax regimes provide for rapid capital recovery. Profits taxes, unlike royalties and bonus payments, are also creditable against the tax liabilities of the investor to the government of the parent company. Some governments have imposed so-called windfall profits taxes on petroleum producers to capture a larger share of the economic rent. Since the contractor's expected IRR depends heavily upon the possibility of discovering a large field that will yield high returns, the effect of a high windfall profits tax is to reduce substantially the expected or probability-adjusted IRR. Most windfall or excess profits taxes apply to accounting rates of profits above a certain level. Accounting profits vary widely over time and do not constitute a proper measure of economic rent, since they do not reflect full economic costs. The only proper measure of pure economic rent is the surplus over the net return to the investor that yields an IRR equal to the opportunity cost of his capital. One means of avoiding some of the difficulties of an excess profits tax on the accounting rate of return is provided by the so-called 'resource rent tax' or the D C F 'trigger tax'. This tax system was developed by Ross Garnaut and Anthony Clunies-Ross. 7 The resource rent tax is levied only on profits in any year in excess of the amount necessary to yield a specified I R R on all capital expenditures. Although there are difficulties with the resource rent tax, if host governments must apply some form of excess profits tax, the resource rent tax has certain advantages over other forms in rendering petroleum projects more attractive to a prospective investor. Accelerated depreciation of all capital expenditures has some of the same advantages. 7Ross Garnaut and Anthony Clunies-Ross, 'Uncertainty, risk and taxing of natural resource projects', Economic Journal, June 1975, p 287; see also, Raymond F. Mikesell, The World Copper Industry, Johns Hopkins University Press for Resources for the Future, Baltimore, 1979, pp 295-297.
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Evaluation of host country fiscal regimes from the standpoint of attracting foreign investment in petroleum Fiscal regimes, applied to petroleum contracts in developing countries, are usually a hotchpotch of arrangements that have not been well structured from the standpoint of either maximizing government E N E R G Y POLICY March 1984
Petroleum exploration in the non-OPEC LDCs
revenues or of providing maximum attractiveness of an investment to investors given the percentage of the government's take of the potential revenues from the project. It is true that some arrangements, such as a high signature bonus, seek to maximize early returns to the government, but they are usually at the expense of much larger revenues later on in the project so that the NPV of the government's take may be adversely affected. OIDCs with unknown or modest petroleum potential often pattern their contracts along the lines of those negotiated by countries with substantial reserves and favourable geological conditions for large field discoveries. High-risk exploration with little probability of success requires generous terms in order to provide substantial rewards for successful ventures. Moreover, since newly discovered fields in regions not producing oil are likely to be relatively small, while exploration and development costs are high, the expected NPVs before taxes may not be exceptionally high even if contract terms are quite generous. Once important discoveries are made, new contracts more favourable to the government can be negotiated on tracts in the same area. Argentina, Bolivia, Brazil, Colombia, Guatemala, India, Pakistan, Peru and Turkey, amongst others, are OIDCs that either currently or in the recent past have not offered sufficiently attractive terms to foreign investors to achieve an adequate level of exploration. Some of these countries have improved their contract terms in recent years, eg Brazil and Colombia, with a consequent rise in foreign exploration activity, but many years of potential production have already been lost at enormous cost to the countries. The shortcomings of petroleum contracts include high royalties or shares of gross output going to the government; high signature and production bonuses; commitments of large minimum expenditures on contract areas regardless of exploration results; the requirement to sell output to the government at prices well below world market prices; exorbitant income taxes, including excess profits taxes that are out of line with the degree of risk associated with unexplored areas; and tax systems that prevent foreign investors from crediting taxes paid in the host country against tax liabilities in their parent countries. In addition to the shortcomings of the fiscal arrangements, GOEs in host countries often select the most favourable acreage for themselves, an allegation that has been made in the past with respect to Argentina and Brazil. In some countries, eg Brazil, foreign petroleum companies are not permitted to operate the fields they develop. Finally, in some countries the government has forced renegotiation of contract terms to the disadvantage of the contractors after the contracts have gone into effect. This is well illustrated by the action of the Peruvian government in 1980 when it forced a renegotiation of its contracts with Occidental Petroleum and Belco Petroleum on substantially less favourable terms for the companies. A serious overall defect in the fiscal systems as applied to petroleum investments of many, if not most, developing countries is that they tend to be regressive in the sense that the government's share of net profits is substantially larger on lower quality fields (eg high cost/low volume) than on higher quality fields (low cost/high volume). This result tends to be produced by a heavy reliance on revenues from production-sharing, royalties and bonus payments, while taxes on net profits with rapid cost recovery tend to be more progressive in their effects on the govern-
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Petroleum exploration in the non-OPEC LDCs
ment's share of net profits, thereby providing greater encouragement for the development of high cost/low volume fields. A regressive tax system may result in an expected IRR for a high cost/low volume field that is unacceptable to investors, while at the same time providing a relatively high expected IRR for low cost/high volume fields, the probability of discovering the latter type of field being relatively low in any particular region. Therefore, a regressive fiscal system will tend to reduce the expected IRR for the investor and, for reasons indicated earlier, raise the acceptable risk-corrected IRR for the project. The regressivity of fiscal systems in recent concession contracts has been illustrated by Alexander Kemp and David Rose 8 by means of a simulation of the effects of fiscal systems currently applied to concession contracts in five countries - Egypt, Indonesia, Malaysia, Nigeria and Papua New Guinea (PNG) - for four hypothetical oil fields, with each hypothetical field identical for each of the five countries. The four hypothetical (new) fields are characterized as low cost/high volume, medium cost/medium volume, high cost/medium volume, and high cost/low volume. In all cases the simulations were on a project lifetime basis and were conducted on both a nominal and a real return basis, assuming constant real oil prices and real value returns. The price of oil in the base case was $33.80/bbl and the calculation of real IRR assumed that both the price of oil and capital and operating costs escalated at 9% per year. In the absence of government taxes, all four hypothetical fields yield a positive NPV at a 15% (real) rate of discount. The results of the simulations showed that in the case of Egypt and Indonesia the (real) IRRs for the low cost/high volume and medium cost/medium volume fields were significantly above the minimum acceptable rate of 15% but the IRRs for the two high-cost fields were below the minimum acceptable rate. In the case of Malaysia and Nigeria, the IRRs on the medium cost/medium volume fields were only marginally above the minimum acceptable rate of return, but in both cases the low cost/high volume fields were significantly above the minimum rate of return. For all four countries the government's take as a percentage of resources generated (total revenues minus all capital and operating costs) either rose or did not decline significantly with a decline in the quality of the fields. However, in the case of PNG, the government's take as a percentage of resources generated declined progressively from the low cost/high volume field to the high cost/low volume field, and in all four hypothetical fields the (real) IRR is significantly above the minimum acceptable rate of return. The PNG fiscal system for petroleum is characterized by a low royalty rate of 1.25% and a net profits tax, plus a resource rent tax. The Egyptian, Indonesian and Malaysian systems employ a productionsharing arrangement. The Nigerian system provides for a posted price set above the market price, and the royalty, varying from 16.6% to 20%, is based on the posted price. There are other complications in the five fiscal systems, but the results 8Alexander G. Kemp and David Rose, 'Four oil fiscal systems in need of an illustrate the general principles set forth above. Only the PNG system is overhaul', Financial Times Energy Eco- reasonably progressive, in that the total government take as a nomist, April 1982; and Alexander G. Kemp and David Rose, Investment in Oil percentage of resources generated and the real IRRs for the lower Exploration and Development: A Compa- quality fields are adequate to induce investment. It may be noted that rative Study of the Effects of Taxation, most fiscal systems employed by developing countries with respect to North Sea Study Occasional Papers, University of Aberdeen, Scotland, November petroleum investment rely far more heavily on production-sharing, royalties and bonus payments than on income taxes as is the case with 1982. 20
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PNG. This suggests that for most developing countries the fiscal systems are biased against small, high-cost fields. The foregoing observations on fiscal terms as a deterrent to exploration in developing countries are shared not only by oil industry spokesmen, but by independent observers, such as members of the World Bank staff. For example, Keith Palmer, a contract specialist in the Petroleum Projects Division of the World Bank's Energy Department, stated in a recent article that: the fiscal terms in petroleum contracts may also deter private sector exploration in some cases. In response to the large oil price increases, countries raised substantially the government's share of project revenues from royalties, taxes, production shares and so on to obtain for the state a larger share of the resource rent and to limit the 'windfall' gains made by investors. However, the structure of the fiscal terms in many cases not only limit windfall gains, but also make it unprofitable for investors to explore for small fields. 9 It should not be concluded that unattractive fiscal terms are the only deterrent to exploration and development in the n o n - O P E C LDCs. The larger integrated multinational petroleum companies are primarily (but not exclusively) interested in exploring in areas with a potential for large fields, eg in excess of 500 million barrels of oil. This is true because of their interest in producing petroleum for export to their downstream operations. 1° In most OIDCs, particularly those in which oil discoveries have not been made, the probability of discovering large fields is low. In many areas discoveries are more likely to take the form of gas than petroleum. However, multinational petroleum companies are usually not interested in discovering gas fields with reserves less than the minimum required for liquified gas export projects to become economical. In addition, there may not be a readily accessible market and pipeline facilities for natural gas in the host country.
Conclusions
9Keith Palmer, 'Private sector petroleum exploration in developing countries', Finance and Development, quarterly publication of the IMF and World Bank, March 1983, p 36. 1°It is worth noting that in Argentina the multinationals most active in exploration have refining and distributing facilities in that country.
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The shortcomings of modern petroleum contracts for attracting foreign petroleum investors are exacerbated by recent developments in the world oil market. With smaller exploration budgets resulting from reduced cash flow, petroleum companies will tend to concentrate their activities in areas with the best prospects for finding high volume/low cost fields. This will tend to work against exploration in most OIDCs and in particular against the non-oil producing developing countries. The greater uncertainty regarding future oil prices will increase the acceptable risk-corrected I R R for undertaking petroleum investments in most if not all the n o n - O P E C LDCs. Finally, the lower world demand and expected rate of growth in world demand will reduce the incentives for integrated multinationals to expand their exploration activities in the LDC oil-exporting countries to meet their downstream requirements. It is my conclusion, therefore, that the post-World War II trend of a larger and larger share of the revenue pie going to host governments must be reversed if exploration activities in the n o n - O P E C LDCs are to expand or even be maintained at current levels.
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