World oil production & prices 1947–2000

The Quarterly Review of Economics and Finance 42 (2002) 169 –191

World oil production & prices 1947–2000 M.A. Adelman*,1 Massachusetts Institute of Technology, Center for Energy and Environmental Policy Research, Cambridge, MA 02139-4307, USA Received 21 August 2001; accepted 15 January 2002

1. Introduction The price of crude oil, inflation-adjusted, should in theory be stable. It was stable and declining before 1970 (Fig. 1). Since then, it has been highly unstable. With the price reversal came a production reversal. The lowest-cost output in the world, that of the OPEC nations, had been growing the most rapidly. Now it actually fell (Fig. 2) and never regained the peak.2 For lower-cost output to fall or stagnate, while higher-cost output rises, is like water flowing uphill. Some special explanation is needed for the two reversals, in price and output. At no time has crude oil been scarce. During every price rise, including the latest, there has been excess productive capacity. A cartel has repeatedly, but clumsily, limited output and raised prices. Collusion requires agreement beforehand, and policing afterward. Any coalition—military, political, market, and so forth—must cope with free riders, who would reap the benefit while the other members bear the burden. The members of this cartel have poor information, short time horizons, high discount rates, and large budget and balance-of-payment deficits. Hence their price-output management is awkward, sticky, and slow. They overshoot and undershoot. Buyers and sellers try to anticipate cartel actions, which amplifies price changes. The latest upheaval started in 1996. The price in early 2001 is around $25, about 50% above the 1986 –1996 average. I think the price will decline, and remain unstable, but the cartel will last.

* Corresponding author. E-mail address: [email protected] (M.A. Adelman). 1062-9769/02/$ – see front matter © 2002 Board of Trustees of the University of Illinois. All rights reserved. PII: S 1 0 6 2 - 9 7 6 9 ( 0 2 ) 0 0 1 2 9 - 1

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Fig. 1. World crude oil price; 1947–2000.

2. Oil prices in a competitive market In a mature oil industry, prices should be relatively stable. Oil is no feast-or-famine product. It is perishable, and its consumers are very diversified, so consumption closely follows gross national product. Oil production is flexible too, if not controlled by a government or a monopoly. Under competition, oil output responds promptly to excess supply and weak prices. Fixed

Fig. 2. World output, 1947–1999.

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cost is unimportant. Industry marginal cost is close to price because of the natural decline rate in every well. Worldwide, production declines at roughly 7%, less in the Middle East, more elsewhere. At (say) 10% decline, in fourteen years a well’s output drops by three-fourths, raising the operating cost per unit by a factor of four. When operating cost has risen to equal the price, engineering handbooks call it “the economic limit.” Production ceases no matter how much is left in the ground; in this country, roughly two-thirds of the original deposit. Even outside North America, Eastern Europe, and China, there are 87,000 oil wells in the world, including 5,000 in the Middle East (World Oil, 2000, p. 30). At any moment, many wells’ unit operating costs have risen to approach equality with the price. If output is in excess, these high-cost wells’ production is soon curtailed, easing any price decline. At the other extreme: when capacity is fully used and excessive demand pushes up marginal costs, prices rise, as has recently happened in North American natural gas. But since 1970, every oil price increase has been triggered by the OPEC3 nations’ deliberate action in cutting output or in declining to use current capacity to expand it. Before 1971, prices were stable because output was flexible. The few companies who then supplied most of the world governed output by shutting in their higher-cost sources. But after 1970, prices fluctuated widely. Even in the relatively stable decade 1986 –1997, oil prices were more volatile than other primary commodities, mostly metals (Plourde & Watkins, 1998). The oil price is high and unstable because the competitive thermostat has been disconnected. Producers no longer set output independently of each other, with higher-cost output disappearing by individual operator’s choices. Instead, a cartel of low-cost producer nations restrain their output to support the price. Since cooperation is usually difficult, reluctant, and slow, members’ output overshoots or undershoots the demand. Prices are volatile not because of methods of production or consumption, but because of the clumsy cartel.

3. Brief price history There was no world crude oil price before World War II. Most production and consumption was within the United States. Outside, there were few market transactions. Nearly all oil stayed within the integrated companies, transferred among affiliates: from producing to transport to refining-marketing affiliate. Only refined products were sold at arms-length to ultimate consumers. Wartime devastation and the Soviet threat led to the Marshall Plan, which in 1948 mandated a competitive market price for crude oil sold out of the Persian Gulf to Europe. The U.S.A. had just become an oil importer (although its imports were restricted until 1971). The required single f.o.b. Persian Gulf price meant that all would pay the lowest price charged to the most distant buyers, in the U.S.A. This involved a very large cut in the price to European and other buyers.4 The original prices “posted” at the Persian Gulf were soon discounted. Refined-product prices were subject to some competition and the lower product prices reflected back to crude prices. The few independent refiners bargained for better prices. By the mid-1950s it was

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said: “only fools and affiliates pay posted prices.” It is too bad that posted prices continue to be officially reprinted, and analyzed as if they were real data, not artifacts. Fig. 1 is based, before 1960, on isolated observations of arms-length sales. But the prices are close to the average annual realizations for Venezuelan crude oil (heavier hence cheaper). For 1960 –1972, the price estimates are better, because of two new data sources. One of them is a trade-publication series of Saudi Arabian Light spot prices. These agree well with f.o.b. Persian Gulf “netbacks,” calculated by subtracting refining and transport margins from the other new series, of European (“Rotterdam”) product prices. In 1973–74, prices were confused and often misstated. Our series is calculated from the monthly data on taxes paid to the Persian Gulf producer nations. After 1974, the price is the average f.o.b. spot price charged each month for imports into the U.S.A., as compiled by the Department of Energy. It checks closely with some shorter series, such as WTI or Brent or the OPEC “market basket.”

4. Resource constraints revealed by costs and competitive prices Even before the 20th century, when the industry was miniscule by our standards, there were fears that the supply of crude oil would dwindle or disappear. Pennsylvania oil output peaked in 1891. In the new century, some places dwindled, but world output expanded more than a hundred fold. The fears remain. A popular question has always been: “When will the oil give out?” A one-word answer—never—is correct, but does not take us far. The question ignores the economics of any industry: comparative cost. For any mineral, the cheapest sources are used first, then successively dearer ones. The worst-case scenario is: cost keeps rising and the market price with it. Consumption/production falls, finally stops when the mineral becomes so costly to extract that consumers will no longer pay for it. How much was in the ground, at the start or at the end, cannot be known and does not matter. (See below, “The types of ‘Reserves’ ”.) The worst-case scenario arrived long ago for coal in Europe, where production has dwindled and would be even less without subsidies. Huge amounts of coal remaining underground are worthless for lack of demand. A mineral industry runs out of customers before it can run out of mineral. The worst-case scenario is only one of many. There is a never ending struggle of depletion against increasing knowledge: of the Earth, and of ways to find and extract minerals from it. The net effect on cost and price can in theory go either way. In fact, in the 20th century, for nearly all minerals, greater knowledge loosened resource constraints. Costs fell, and competitive prices with them. A competitive market price converges with marginal cost, that is, the sum of outlays needed to find and develop and extract an additional unit. Long term resource exhaustion would be visible as a long-run cost and price increase. As better resources were used up, the continued shift to higher-cost sources and methods would raise marginal costs and price. Changes in the competitive price register changes in resource scarcity, whether the impulse comes from the side of supply or demand or both. But changes in a noncompetitive price do not measure scarcity.

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5. Competition reflects growing resource plenty 1947–1970 The price decline in 1947–1970 was not sought or desired by any oil producer interest. The integrated multinational companies did not want lower profits and the political backlash against cheap oil imports. They hurt coal in Europe and domestic crude oil in the U.S.A. But competition forced each company to export: if it didn’t, another would. Moreover, each host government pressured its local companies to increase production, at their neighbors’ expense. (The story of governments wanting lower output, to conserve limited resources, was invented later, and discarded still later.) Thus the companies and governments competed among themselves to promote higher output and lower prices. As Adam Smith would say, the end was no part of their intention. In 1947–70, the annual drain on the resource increased by a factor of more than five, yet the real price fell about 70%. Yet investment and capacity surged. In the Middle East, the annual return on new investment was several hundred percentage. In 1972, Saudi Arabian output was programmed to increase in a decade from the then-current 7 million barrels daily (mbd) to over 21 mbd. There was no hint of a rising cost of expansion. Moreover, the finding-developing-producing costs in the new higher-cost areas were below the price. New finds in the North Sea, Mexico, and the Alaska North Slope were already committed to development by 1972, at then-current prices.

6. The reversal in output and prices There were no signs of growing resource scarcity before 1970, and the price increases of the 1970s were made amid obvious collusion, and despite excess capacity. Somehow these price increases were almost everywhere viewed as resulting from greater scarcity, and promising still-greater future scarcity. Price forecasts ranged, on the scale of Fig. 1, far above $100 per barrel. The CIA predicted that world oil output would peak in 1980, for lack of reserves. In 1982, an impressive multiauthor survey predicted that prices would rise, yet non-OPEC output would decline because of limited resources. But prices fell and non-OPEC output rose. In 1972, the Council on Foreign Relations journal published an influential article warning that “this time the wolf is here,” and later papers to the same effect. In 2001, a study sponsored by the Council sees the consuming countries in crisis because they have had no energy policy (Council on Foreign Relations, 2001). A three volume study from the Center for Strategic and International Studies on the “Geopolitics of Energy” predicts increasing dependence on Persian Gulf nations, who by 2020 AD “will have to expand oil production by almost 80% . . . to satisfy world demand” (Fialka, 2001). It sounds urgent. But in 1974, Persian Gulf exports were 21.6 mbd; in 1997, 15.9 mbd (OPEC, various).5 Socrates said that the unexamined life is not worth living. But an unexamined premise is safe from analysis or criticism. In the 1970s there was not even a rush to judgment, but instant judgment: resource scarcity had raised oil prices and would raise them more; the sudden rise in 1970 –1980 had been long waiting to happen. Hence the extravagant price

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forecasts. The 1970 price was unsustainable for lack of reserves (Gately, 1984). Yet the meaning of reserves was never explained. (See below, “The types of ‘reserves’ ”).

7. Higher prices and oil consumption The violent price increases in the 1970s contributed to a worldwide recession, then to slower world economic growth, which slowed the growth in oil use. Quite distinct was the effect of the price elasticity of demand on oil use per unit of income. For every barrel of oil used in the U.S.A. per dollar of GDP in 1974, only half a barrel is used today. The relation between economic activity and oil is still there; the slope is lower. The price elasticity effect was not visible until 1978. It acted slowly, through investment by firms and households changing their consumption patterns. When prices fell back after 1980, there was little apparent effect on consumption. The original price effect was still underway. World consumption stagnated in 1973–1979, but growth resumed after 1980, at a lower rate. In Europe and Japan higher excise taxes, especially on gasoline, raised consumer prices and hence lowered demand. Thereby higher taxes pre-empted some of the crude oil price increases, transferring revenues from producer to consumer countries. The OPEC countries strongly, and rationally, oppose oil product taxes. OPEC governments once claimed that above-competitive prices merely compensated them for quicker use of their limited resources. They would have preferred, they said, a lower rate of consumption. Some economists echoed the assumption of lower time preference. But the OPEC nations have “for years” demanded compensation for the delay in using up of those resources by any possible agreements against global warming (see Revkin, 2000a, 2000b, and The Economist, 2000).

8. The Organization of Petroleum Exporting Countries (OPEC) 8.1. The Texas Railroad Commission OPEC has often been compared with the TRC. But TRC output control was far more efficient. First, Texas accounted for two-thirds of the U.S.A., an isolated market before 1971, when import controls were abolished. (OPEC once accounted for about the same portion of the world market, but no longer.) Second, the TRC had sovereign power over all Texas producers. Any output allocation was fully effective in a month. Third, the Commission had timely and accurate inventory data. When stocks went too “high” or too “low,” the TRC soon changed output to stabilize inventories and hold or change the price. Thus the TRC could make frequent small course corrections to reflect new data or perceptions. OPEC cannot. It is ill informed on inventories. Its actions require prior consent of its members— of all, in theory, and of several at least in practice. Pent-up forces tend to be violent, OPEC’s price changes included.

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8.2. A brief history of OPEC Through 1959, the multinational producing companies continued to discount actual market prices, but left the posted prices unchanged. Their taxes per barrel, based on posted not real prices, were also unchanged. But in 1959–60, the companies also cut posted prices, thereby also reducing their taxes levied on them. Several producer countries reacted to form OPEC. For the next ten years, market prices continued to decline, but not the companies’ posted prices. Thus the OPEC countries succeeded in making the tax an absolute amount per barrel, regardless of the market price. The excise tax was a price floor, like any per-unit cost. A higher excise tax can be covered by a higher price. In 1971–1973, the OPEC countries actually raised the excise tax several times, and each time the companies raised prices. In October 1973, before the outbreak of war, the OPEC nations had already announced that they would soon enact another, and larger, tax increase. But when war broke out in October 1973, all Arab oil producers except Iraq declared an “embargo” against the U.S.A. and Holland. It was a mere gesture, which had no effect. (I had predicted this months earlier; see The Economist, 1973). But they also cut output, which was no gesture. The cutback lasted only two months. Its amount was less than what had been added to OECD inventories during early 1973. Thus the market was better supplied at year-end than at the beginning. But the cutback had scared buyers into wanting to build inventories against a sudden unforeseen dearth. In academic jargon, prices rose because of an abrupt rightward shift of the short-run demand curve. Volatility upward is followed, under competition, by volatility down. In previous cutbacks, in 1956 and 1967, the fall succeeded the rise so promptly that nothing is seen in the annual statistics. This time, however, the OPEC countries continued to make further tax and price increases in 1974. They also cut output, despite large and growing overcapacity. In 1975–1978 they again cut output and raised taxes and prices; but worldwide inflation soon offset these smaller price increases. In 1979 – 80, the market was again jittery when the revolution in Iran reduced output. When the other OPEC nations, especially Saudi Arabia, declined to expand production to replace lost Iranian output, prices again exploded. OPEC held production below the amount demanded, despite continuing excess capacity. In 1979 –1981 as in 1974 –1978, there were also later production cutbacks to place a higher floor under prices. Every price increase, from 1973 through 2001, followed a deliberate output cut or refusal to increase output. Throughout there was excess OPEC capacity.6 One cannot reconcile this history with any hypothesis of increasing scarcity raising oil prices. By 1981, the OPEC nations had raised prices too far, ultimately reducing their net revenues. In my opinion they have recently made the same mistake, on a smaller scale. (See below, “The latest price cycle”). 8.3. The new market conditions in the 1980s By 1981 the market had greatly changed. Production in the Middle East and Venezuela had been almost completely nationalized. The governments were no longer tax collectors.

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Fig. 3. World price, 1996 –2000, undeflated.

They could no longer raise excise taxes and let the integrated companies raise crude oil and refined-product prices down the chain. They had lost the buffer of the integrated companies, who now became crude oil buyers in search of better prices. Buying and selling oil soon resembled that in other bulk commodities. Contracts were now traded for spot and future deliveries at public exchanges. Most oil moved under term contracts, which saved transaction costs. But contract prices closely followed the spot and futures markets. These new markets were efficient in price discovery; the cartel determined output and price. In 1982– 85, OPEC began to fix sales prices directly, and members agreed to hold the line against the probing by old and new customers. The backup to the agreement was that Saudi Arabia would absorb all of the OPEC cutback. So they did: by mid-1985, Saudi exports approached zero. The Kingdom repudiated its role as OPEC producer of last resort. Prices plunged until a new production agreement stabilized the market in August 1986. Over the next ten years, oil prices still were more volatile than other commodities, but the fluctuations were far less than they had been since 1973.

9. The latest price cycle Excess supply and weak prices again forced the cartel to act together. In 1996 –1998, warm winters and East Asia recession kept consumption growing slowly, as non-OPEC production grew a little more. To balance the amount supplied with the amount demanded, the OPEC nations needed to make a small output cut. It took them three years. Production exceeded consumption, and inventories built up, one cannot tell how much because data are poor. Experts have debated those “missing barrels.” The price fell by over half from early 1997 through early 1999 (Fig. 3). Finally in March 1999, OPEC (supported by Norway and Mexico) agreed on concerted production cuts and made them.

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Just before the cuts, “Saudis leave no doubt $18-$20 is their goal.” (Petroleum Intelligence Weekly, 1999). In early 2001, the Saudi objective was “between $25 and $30 a barrel” (Banerjee, 2001). Since 1974 several US Presidents, including Mr. Bush, have asked Saudi Arabia for lower prices, with no result (Keto, 2000). The reason is clear. We have no hold or leverage over any producer nations. We must for our own sake protect them against the likes of Saddam Hussein. They owe us nothing for protection, and will give us nothing. I do not know whether $25 is a target or only a floor. Assuming OPEC will stay near $25, the price rise is from about $17 per barrel in 1986 –1996 (omitting 1991), or by about 50%. These higher oil prices will not damage the world economy nearly as much as in the 1970s. But price elasticity of demand may be working faster now. In 1999 and 2000 oil consumption barely increased despite the boom. But OPEC decisions seem to be and I think are systematically biased. They charge prices higher than private profit-maximizers would, and higher than suits their long run interests.

10. OPEC in permanent crisis OPEC has no power of its own. It is an organization and forum, within which members must from time to time assemble a coalition to hold or reduce output and support prices, or to share out a consumption increase. Such coalitions have formed, lasted a few years, vanished, and reformed as needed. Over the years, OPEC has not been a single cartel but a succession of cartels, each somewhat different in composition and program. In the recent price cycle, nearly all members have joined in the output reductions, and largely observed them. Prices are volatile because collusion has replaced competition. In a competitive market, supply is matched to demand by high-cost output soon being reduced by individual actions. But to attain an upside-down result—less low-cost output—requires prior agreement on who cuts how much. The group must share out the perceived market among cooperating producers. They rightly fear cheating. It is a zero-sum game, and agreement is slow and clumsy. Cooperation needs attention and maintenance. As demand and supply change, some members attract more buyers at the expense of others. New market-sharing deals must be made to accommodate these changes. 10.1. The importance of being sovereign No private firms are as free to pursue profit as the cartel members. In no industrial country could private companies cooperate to raise the price of a widely-used product by 1300%. They would fear to damage interests more numerous and powerful than they. But OPEC states do not account to anyone. The benefit of a higher price is immediate: higher revenues. The penalty is delayed: loss of sales. Hence any cartel decision to raise prices involves a trade-off. The more sellers discount future events, the greater and quicker the price increases. OPEC members have shorter horizons and higher implicit discount rates than do private individuals and firms.

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First, member incomes and assets are not diversified. Government revenues, and the foreign exchange to pay for imports, are nearly all from oil exports. Second, discount rates are higher because of political risks from local or regional instability. Every OPEC nation has suffered from one or both in the last decade. Third, as we will see shortly, OPEC governments are in financial straits. Therefore, as compared with a group of private owners in the same market position, their higher discount rates give more weight to the quick gains of higher prices, and less weight to the future sales losses. Undiversified and strapped for cash, they cannot wait. Hence they will raise price more and faster than would a group of private owners.7 The OPEC nations’ judgment as sellers is biased by their fiscal needs. Budget deficits and balance-of-payments deficits are of course not identical, but in practice are closely linked. In 1974, OPEC ran a huge foreign-exchange surplus. By 1978, the members were again in deficit. In 1980, they had an even larger surplus, were again in deficit in 1982, and have stayed there. In 1981, the Saudi state had about $160 billions in foreign assets, but recently its debts have been estimated at $150 billions (Pope, 2000). Recently the Saudis were reported as awaiting the first budget surplus since 1982, but a later report mentions a deficit of over $20 billions (Pope, 2000; Herrick, 2001). The OPEC countries have been unable to establish self-sustaining nonoil industries, and have invested large amounts with low or negative returns. Projects once created must be maintained. Thus higher oil revenues have increased oil dependence. Iraq is a striking case in point.8 10.2. The OPEC market share trap A single monopolist, who is the whole industry, trades off a higher price against lower industry sales. OPEC, with only part of the market, trades off the higher price against a lower market share. The OPEC market share is not measured by its production, but by its exports. Oil products sold locally at below-market prices are simply a dividend to the local population. They earn no foreign currency, and are not linked to the world market through the world price. In fact, higher world oil prices mean more revenues, and more local consumption. OPEC countries today consume 18% of their output. The fraction keeps rising. Iran uses nearly 30%. Locally refined gasoline is so cheap it is smuggled out of the country, replaced by expensive imported fuel. The government of Iran dares not defy local opinion by raising gasoline prices. To see OPEC’s current situation: in December 2000, just before its most recent output cut: world liquids production was 79.1 mbd, OPEC 30.4 mbd (Petroleum Market Intelligence, monthly issues). Subtracting OPEC home use (5.56 mbd): worldwide sales were 73.5, and OPEC sales 24.5, or one-third. In January and March, OPEC reduced production by a total of 2.5 mbd. The OPEC cut was 3.4% worldwide, but 10.0% of OPEC’s own production. This is small not negligible. OPEC’s market share is now down to (22/71), or 31%. No wonder they hope to restore the cutbacks soon. Saudi Arabia is nearly one third of OPEC. If all other members cheat, a condition approached in 1985, the latest output cut would cost the Saudis not 10% but over a third of their exports. They will probably not tolerate this.

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Adaptation to sales loss cannot be smooth except by chance. Prediction of the total amount demanded is very imprecise. If a prediction is too high or low, OPEC must arrange cutbacks or increases by its members. The political problem of getting members to agree to changed quotas is an additional reason for delay and error. 10.3. Inventory buildup and draw down The more that buyers try to anticipate OPEC actions, the more uncertain are inventory changes. Buyers hold inventories for profit. Their investment earns a “convenience yield.” This corresponds to what Keynes calls the transactions motive for holding cash. But when buyers fear damage from sudden dearth, there is also a precautionary motive;9 which may be joined to a speculative motive, to profit by buying sooner. When the uncertainties of OPEC price-output behavior are great, oil markets behave like financial markets, subject to panics, bubbles, and self-fulfilling swings (Kindleberger, 2000). Speculators aim at profits, not by guessing right on the effects of supply and demand, but on guessing what others will guess, rightly or wrongly. OPEC behavior makes oil markets act like financial markets, because it generates more uncertainty to speculate on. Inadequate inventory data make matters worse. Indeed even output data leave much to be desired, since the expropriations in the 1970s. Summing up: the OPEC cartel is (or OPEC cartels are) more powerful than any private group could be. They raise prices more quickly. But they must act in ignorance, and can only know in hindsight—if then—when they have gone too far. When they raised prices too far by 1980, it took years to find out. I think they have put themselves in danger again. (Non-OPEC producers are discussed below). As we saw earlier, higher prices in 1970 were assumed to be inevitable because oil reserves were inadequate. Oil reserves are frequently mentioned. Sweeping conclusions are drawn from unrevealed premises. In 1986, the firm of Petroconsultants (PC) had predicted stable Soviet output, but in other non-OPEC areas a decline was “imminent and unstoppable . . . well before” 1990. These remarkably bad forecasts were based on their “analysis of reserves.” (Oil & Gas Journal, 1986). In fact, Soviet output fell, and other non-OPEC rose. A 1989 prediction was for world output to peak that year or next (Campbell, 1989). In fact, it has kept rising. More recently the PC experts Campbell and Laherrere predict that limited reserves will cause oil production to peak in 2010 (Campbell & Laherrere, 1998; see also Ker, 1998). They do not mention their past gross errors. PC reserve data are conveniently proprietary. There is no support for their current alarms.10 10.4. The types of “reserves” Proved reserves have been estimated in the U.S.A. since 1918. Since World War II, governments and trade journals have published similar estimates for all other countries. The quality has much deteriorated. Since 1998, outside North America and the North Sea, the entries for most areas are worthless.11 Estimates of proved reserves are an integral part of the development process. Rational

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investors considering new oil wells need reliable estimates of what they will get for their money. Petroleum engineers estimate the up-front investment, and the wells’ flow rate, diminishing over time. The area under the production curve is the proved reserve. Multiplying by the assumed price per barrel gives the wells’ annual cash flows. Discounting each year’s flow gives its present value. Adding up the annual values gives the current value of the reserve, which can be compared with the needed investment. The decision, whether to drill and complete, requires reliable estimates of proved reserves. It is worth spending money to reduce the errors enough for engineers, bankers, managers, and investors to bet on the estimates. As reservoirs are worked, more is learned about them and the local geology, and the reserves are updated. Proved reserves are peer-reviewed estimates of future output, given current knowledge and cost. Since 1975 the U. S. Securities & Exchange Commission (SEC) has required companies to report only proved reserves as in-ground assets. SEC never set standards for reserve reporting. They accepted a category then sixty years old. Like other real (nonfinancial) assets, proved developed reserves are widely bought and sold, priced per-barrel. An old rule of thumb is that a proved developed reserve barrel is worth about one-third of the current wellhead price, or one-half of the wellhead price net of operating costs, taxes and royalties (see footnote 13). There is of course great variation around any such average. The using-up of proved reserves is a production cost, like the using-up of any other type of inventory. A proved developed reserve is a real (nonfinancial) asset. A proved undeveloped reserve is a real option, whose exercise price is the development investment. If it will not provide an adequate return, the option is unused, and there is no investment. Thus the market price of oil includes the market value of the in-ground resource used up in production. Many believe that minerals have some “intrinsic” value which markets fail to capture.12 But they have not explained this “intrinsic” value. Only broad conclusions can be drawn from Table 1. In 1944, world proved reserves were 51 billion barrels. In 1945–1998, 605 billion barrels were removed, leaving 1,035 billion. The world industry invested to create gross additions of 1,771 billion barrels, or 35 times the original holdings. The purpose of production capital expenditures is to create additional proved reserves. As with any inventory, proved reserves increased not despite interim production, but because of it. Probable, possible, speculative, and undiscovered “reserves,” unlike proved reserves, do not result from development plans, and are not supported by development cost data. Opinions vary of how to use them. A well-known geologist (Lewis H. Weeks) regarded them as ordinal: if one area had much larger probable-possible reserves, it was a much better place to look for new oil. The various types of nonproved reserves have no value per barrel, and cannot be sold per barrel. They are not comparable with or additive to proved reserves. They are estimated future output from facilities not yet in being, whose costs will reflect future geology and engineering. Anyone who adds nonproved to proved reserves, and from the total predicts future output, implicitly claims to know future science and technology. The late lamented John Lohrenz long protested against what he called (X-x) estimation, where X was original “reserves,” and x was the amount produced until (X-x) was zero

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Table 1 World production and gross reserve additions, 1944 –1998 (billions of barrels) Geographical region OPEC Cumulative production Gross reserve additions Reserves at end NON OPEC Cumulative production Gross reserve additions Reserves at end Total World Cumulative production Gross reserve additions Reserves at end

1944

1945–1960

1961–1970

1971–1980

1981–1990

1990–1998

Cum

— — 22

26 219 215

55 252 412

103 127 436

62 392 766

74 108 800

320 1098 800

— — 29

51 98 76

64 187 200

102 113 211

142 164 233

107 109 235

466 671 235

— — 51

77 318 291

119 439 611

205 242 648

204 555 999

181 217 1035

786 1771 1035

Notes: This table understates production and reserve additions. It includes only crude oil. Worldwide, about 8 percent of refined products today are from liquids derived from natural gas. Recently, improved technology has made direct gas-to-liquids conversion cheap enough for more widespread use. Thus a growing portion of liquids production will be from gas reserves, not oil reserves. Improving technology keeps changing the origin of the crude oils charged into the world’s refineries. Until 1950, crude oil produced offshore was “unconventional,” as was, until recently, very-heavy oil from bitumens and tar sands. The proportions of these sources depend on comparative costs, which will keep changing. To limit “conventional” crude oil from “unconventional” is to elevate convention above reason. Sources: Frey and Ide (1946) for column 1, the remaining columns from Oil & Gas Journal, end-of-year issue. It has not been updated because estimates are no longer being updated by the nations furnishing nearly all the data.

(Lohrenz, 1992). The (X-x) estimates are precise, satisfying, and wrong. They allow for using up in-ground oil, but not for its replacement under conditions of increasing knowledge. In time they prove to be too low, and are recalculated (Lynch, 1996). 10.5. Mineral depletion theory It is widely assumed that there is some limited amount of each mineral in the ground. Once it is extracted, exploitation and production must end. But mineral industries have stubbornly expanded. One accommodation was to assume that the total stock had not—yet— been properly measured. Another solution was first put forth by Gordon (1967), and by Adelman in 1970: there was no limited stock. Since the whole earth is finite, any subset must be finite, but this truism is no measure of the subset. A mineral stock at any moment reflects current knowledge—science and technology— hence current costs. As knowledge and cost change, so must the stock, mostly up sometimes down. Both sides properly use the Hotelling theory, which like any sound theory demonstrates the consequences of a given assumption. If the stock is fixed, then as some of it disappears, the remainder must become more valuable. The unit value must increase at a rate linked to the rate of interest, which states the return gained by holding the asset instead of selling it. Some recognized that market prices had not escalated, and tried to rescue the premise by postulating an initial discovery period. Once it ended, unit value had to rise.13 Their opponents (including myself) cited the failure as a reason for denying the premise.

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There is agreement that the value of a mineral unit, in-ground or above ground, is what it will fetch in a free market. Now, if mineral values in-ground are expected to increase at the rate of interest, a mineral unit in-ground should be worth the same as one above ground, net of extraction cost.14 But in the U.S.A., in 41 years, the wellhead price was in almost every year at least two standard deviations above the in-ground value. Moreover, there was no persistent change in the ratio (Adelman, De Silva & Koehn, 1991; Table 2). A more recent study of in-ground values reaches the same conclusion (Adelman & Watkins, 1997). Thus another deduction from the premise of a fixed stock fails, giving another reason for rejecting the premise. As for “probable, possible, and speculative reserves,” no such check is possible because they have no unit price. 10.6. Trends in finding new oil It is widely feared, and often repeated, that oil discoveries have long been decreasing. In fact, nobody knows. The number of new fields found in any year is trivial, because the definition of a field is arbitrary. The alleged contents of new-found fields are estimates of what will eventually be developed and extracted, given future knowledge. For example, how much was found in the Middle East before 1945? We can make the test because for 1944 its reserves were estimated by a special expert committee at 16 billion proved plus 5 probable. By 1975, those same fields, excluding later discoveries, had already produced 42 billion barrels and had another 76 billions in proved reserves. Thus the “discoveries” of pre-1945 grew more than 7.4 (118/16) times to reflect growing knowledge over 30 years. Unfortunately, reserves by fields were no longer published after 1975. The discrepancy kept increasing, we know not how much. But even if we knew discoveries each year, we could not match them with any definite amounts of money spent. The French call exploration recherche´ , and the reward for research is knowledge. Oil is like drugs, where companies spend heavily on research, but do not calculate the research cost of the drug. Manufacturing drugs must be profitable enough to make research spending worth while. Oil development must be profitable enough to make finding effort worth while. We cannot match a set of finding expenditures with a set of results. Most discovery funds are spent with no return. Exploration wells are mostly dry holes. But some small outlays bring big returns. The trick is to find a few good leads to pay for many bad. Moreover, the discovery is always a mixture of oil and gas. Talk of “oil equivalent” only adds confusion. “There is no such thing” (Browne, 1998). I see no way around the logical impasse: with no match between finding expenditures and results, “finding costs” are error. “Finding costs per barrel of oil equivalent” compound the error. Since discoveries and finding costs per unit cannot be measured directly, we must resort to indirect measures. If development costs are known, a newly discovered barrel is worth the cost saved by not developing an additional barrel. Since the incremental development raises costs, I have suggested a quadratic function to estimate what is saved at the limit by not developing another barrel. Ordinal measures are probably more useful. If discoveries were dwindling over time, the

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newly found oil deposits would be getting smaller, deeper, more remote, and harder to reach. Therefore the cost of their development must be increasing. Thus changes over time in development unit cost are a proxy for changes in discovery unit cost, or at least of the direction of change. Another approach is to examine changes in the market value of the option: proved developed reserve value minus development cost.15 Option value equals the pure discovery value, that is, what a barrel is worth before development investment. If discoveries were dwindling, the value of what already exists would be rising. This did not happen in the U.S.A. before 1973, nor after 1979. The interim increase was the result of higher prices by restriction of output. The empirical estimates by Watkins and Streifel (1998) for all producing countries over a long time period fail to show any general trend. The authors emphasize that these studies are seriously hampered by data deficiencies. In recent decades, it is generally believed, development productivity has increased. Great improvements in seismic techniques have resulted from vastly greater computing power to “see” the rock layers in the earth, even through the barrier of underground salt sheets. Another major change is directional drilling, itself only one aspect of continuous measurement while drilling (MWD). It is like a driver able to guide himself by looking out continuously through the windshield, instead of finding out the hard way by hitting a bank or going into a ditch. Also important has been the ability to drill offshore in much deeper water, and/or to install wells on the sea floor, rather than building huge platform structures. Because of these and other advances, a unit of drilling time brings more wells, or proved reserves added. These facts are impressive, but do not add themselves up. The chairman of Conoco E&P Europe has stated: “the industry has cut the worldwide cost of finding and developing a barrel of crude from over $20 at the start of the 1980s to below $5 today” (Petroleum Intelligence Weekly, 2000). We do not know how this estimate is derived, nor on what data it is based. It looks to me like a real tendency, much exaggerated. All we really know is that data are scarce, and getting scarcer. Worldwide production capital expenditures estimates shrank after 1985 and ceased after 1987. Estimated U.S.A. capital expenditures, which could also be used as a starting point for the rest of the world, were stopped in 1991. The annual AAPG (American Association of Petroleum Geologists) survey of oil development, in the U.S.A. and worldwide, ceased soon afterward. Nearly all producing countries ceased to publish reserves by fields after 1977, and production by fields after 1981. The Department of Energy has made estimates of unit “finding costs” which are often absurd on their face, when they exceed the current unit market values of reserves. Since 1975, if my unpublished work is correct, an average rig-year has generated increasing amounts of capacity and proved reserves. But we do not know what has been paid for the observed greater efficiencies. In the U.S.A., after 1972 there was a big jump in the ratio of indirect to direct drilling outlays. Much of the change was due to the wastes of a frantic boom. But in 1991, just when the numbers would begin to be most useful, their publication stopped.16 Be that as it may, if development cost has really declined, the resource has become more not less plentiful. Thus there is no supporting evidence for decreasing oil and gas discoveries. Such evidence

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as exists tends to disprove it. But this cannot prove that oil may not become more scarce in the 21st century. In fact, there are more important problems. World oil supply is subject to closer constraints, which we now address.

11. Government and an investment-intensive industry Oil production depends on continued investment in adding proved reserves. In the 20th century, the investment environment was often difficult. The problems, still unresolved, are created by two basic conditions. Outside the U.S.A., and offshore even in the U.S.A., governments own the subsoil resources. (This is fortunate; private ownership of subsoil fluid hydrocarbons is wasteful and increases price volatility.) Investment requires their prior agreement, whether as investors-producers, or as landlords setting terms of investment. Second, rents in oil and gas production, that is, profits exceeding the minimum acceptable return on investment, are very uncertain in advance and often very large in retrospect. This follows logically from what was said above on unknown finding costs. But uncertainty generates conflict, which may disturb or prevent investment. There are conflicting national claims to some areas, especially offshore. Colombia and Venezuela claim the Gulf of Venezuela. In the East China Sea and South China Sea, small islands, some of them mere uninhabited rocks, confer jurisdiction over lands under the surrounding seas. These undersea areas contain deformations (“structures”), indicating possible oil and gas. Only drilling can prove or disprove these prospects. Ownership of these islands and jurisdiction over the surrounding seas is disputed by various governments. Discovery investment by anyone is too risky. If China takes control over the East and South China Seas, which it seems to be attempting, that would reduce one dimension of the problem. Within or outside a national unit, there may be competing overlapping claims. In general, any group whose prior consent is needed for an investment may claim all the rents— or more than all. If oil must be pipelined out of the producing area, anyone who sits on the line’s right of way can veto the whole project until he is paid off. In the Caspian area, we cannot tell how many of these mutual deadlocks will ever be resolved; certainly not all. Possibly the most important barrier lies in the terms which are acceptable both to the sovereign, and to the investors who may explore, develop, and produce. It is difficult to design an effective tax system to capture the rents. Any system must be imperfect. But few tax systems are even designed to capture the rents. They are at best inefficient and lessen investment. At worst they preclude it. In the U.S.A., rights to exploit offshore lands are sold at auction by sealed competitive bids. Since 1950, these sales have brought in about $60 billion. On average, returns to successful bidders seem to have been no higher than in industries generally. Returns on the individual tracts have of course ranged from large positive to large negative. A government adopting such a system accepts uncertainty in any given tract, and makes a bet on all tracts taken together. For such a bet to work, there must be enough bidders to ensure competition. This has been true in world oil since the 1950s. Yet sealed competitive bids are rarely used. The uncertainty of investment is magnified by distrust of oil companies and investors,

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especially of foreigners. Investment is widely viewed as a zero-sum game, where one party’s profit must be another’s loss. Governments are terrified even to appear to be even handed toward the foreigner. If the gap between government and investor is unbridgeable, and there is no investment, both sides lose. Or a rich discovery means a dissatisfied landlord-sovereign, who wishes he had held out for more. If he now demands more, it chills the prospect of entry by others. Government-investor tension will continue to dominate the world industry. It cannot be ended, but it can be mitigated. If government and public opinion can accept that oil is not a “limited nonrenewable” stock, that its future value need not be greater than its present value, and may be less, they are more likely to make and keep bargains. Then the conflicts are less likely to go to extremes. But higher prices always strengthen the delusion that oil in the ground must be worth more than any amount of money in the bank, and make deals less likely. It is happening again now. 11.1. State enterprises In recent decades, socialism has died as a fighting faith. The tide has run strongly toward private enterprise, even for industries (like electricity and gas distribution) where the number of sellers can never be large. Yet most crude oil is produced today by state enterprises. They are often overstaffed, sloppy, and corrupt, but above all lack rational investment objectives. A state company invests not only for profit but for supposed national objectives, like making jobs, looking up-to-date, and helping friends, or their friends. The state enterprise does things it is unqualified to do, or some which consume wealth rather than create it. Refined product prices are fixed low, raising consumption and requiring heavy refining-marketing investment. Furthermore, the cash stream to be tapped is not the net profit from oil operations, but the gross revenues. The state enterprise must compete for government funds with all other uses, and their beneficiaries’ political clout. Contrary to what is often heard, the amounts needed for production investment in the OPEC nations are very small. In 1975–1987, upstream capital expenditures were 1 to 2% of OPEC oil revenues. They are unlikely to exceed 10% today, although as usual current data are lacking. But the absolute amounts are large, and tempt any insider who wants funds for any purpose. Investment and even maintenance can be deferred. State companies have been starved of funds, and forced to disinvest then wastefully overinvest. The managers’ judgment on price is distorted by the governments’ fiscal needs, and domestic pressures for expenditures. An additional dollar on the price means billions more in annual revenues, with many urgent places to spend the money. Governments have long known that foreign companies could supply scarce money and engineering-management expertise. Almost as soon as the Persian Gulf companies were nationalized, in the 1970s and 1980s, there were reports that some expropriating governments would make room for foreign company cooperation. Reports of oil production investment plans have multiplied in recent years. Little has been done. Saudi Arabia has blown hot and cold; Kuwait has been taking years even to consider a very limited involvement. Sanctions against Iran are now largely nonoperative, but there is little investment there as long as its “buy-back” system requires a short investment period

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and a fixed low profit ceiling. Venezuela’s limited “opening” in 1997 brought in a larger than expected $2.2 billion in bonus payments, but no more will be considered. (However, heavy oil projects, suspended when prices dropped, have been restarted.) The constitution of Mexico forbids foreign investment in oil or gas production. Even disregarding the greater efficiencies which foreign companies would bring, and coherent investment objectives, the asset oil is worth more to a private owner than to a government. The market value of an asset compensates the investor for risks that cannot be diversified away. As noted earlier, individual and corporate investors are diversified; governments owning oil are not. Thus both parties would benefit in a swap of the nation’s oil rights for the investors’ money. “Loss of sovereignty” was important before World War II. The few private companies in the world market (seven Anglo Americans and one French) had monopoly power in getting concessions. Industry growth and the end of colonialism increased the number of possible bidders. In 1948 –1950 the oil producing countries made good their claim to the power to tax away as much as they wished of the profits earned on oil. In the 1950s, new companies entered Libya and Venezuela. The list is much longer today, as shown by new companies in new areas, and recent bidders in Venezuela, or would-be bidders in Kuwait or Iran. Sovereignty has since 1950 been a nonissue. A state can get the largest value from its subsoil by selling to local or foreign firms the right to locate, develop, and sell off the oil underneath. But there must be, and today there is, enough competition to assure a nation getting the full market value of those rights. But there is a powerful feeling that sovereignty requires government not only to own the hydrocarbons, and to get the best possible price, but itself to produce and sell them. It is not only sentiment. A state company can transfer some of its monopoly as contracts, jobs, perks, and salaries above market levels, to local personnel: a gain to them, a burden to the local economy. Possibly the worst investment climate is in the Former Soviet Union. The state industry was privatized to persons skilled in maneuvering to seize wealth, not investing to create it. Foreign companies saw great promise for new investment in discovery and development. But local interests found the competition unwelcome. Investment was aborted by local barriers, excessive and capricious taxes, and no system of law to enforce contracts and property rights. But several successor republics may be better than one. If Kazakhstan does better than Russia, it offers an example to them and others.

12. The next century 12.1. The short and long run OPEC will do its considerable best to hold or raise the price, with $25 as a floor not a target. They will find the task easier because policy in the consuming nations is still ruled by the irrational fear that OPEC may not produce “enough for our needs.” OPEC will produce the amount which serves them. If it pays them to reduce output, they will. If they wish to hold

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the price line, and one or two member countries are shut down by revolution or war, the others will gladly supply. OPEC will not soon vanish; neither will its problems. They must relearn two forgotten lessons of 1970 – 86. First, elasticity of demand for oil is low, not zero. As in the past, a higher price will lower oil use in relation to GDP, and has probably already begun to. Second, price-fixing is like singing and mountain climbing: it is easier to go up than to come down. It is a never-ending job to restrict low-cost output. The higher the price today, the greater the stimulus to lower demand and more non-OPEC supply, and the more likely is a lower price later. 12.2. Energy and oil consumption It will keep changing. Coal may be helped by new subsidies, but it will be hurt more by measures against atmospheric carbon dioxide. Natural gas is increasingly free of control in Europe and Asia, as it has been in North America. Its growth will displace oil. Gas deposits now isolated and unused will be exploited for out-shipment in pipelines, in tankers as LNG and as light products from the newly proved gas-to-liquids conversion. For the next ten years, fuel cells will stay unimportant. If hybrid (part-electric) cars are successful, they will cut into the most price-inelastic use of oil: automotive transport. Congestion, pollution, and the threat of global warming will also reduce demand. To this end, higher oil product taxes should be consuming countries’ first choice: they would transfer more revenues from producing to consuming states. But consumers resent taxes, and prefer inefficient command-and-control methods. Given also the effects of higher prices, consumption will not grow at the forecast 2% per year. In the world oil market, the key role will be that of the non-OPEC producers. If they expand enough to keep OPEC below its current market share, the price will probably go below the 1986 –1996 range. If their production increase is so slow as to let the OPEC market share rise, prices will hold. Non-OPEC producers are underachievers who would profit by more investment. The question is how far and fast they will approach their potential. Given current costs, or what little we know of them, non-OPEC production could be profitably expanded. Their cost of expansion was below the price after 1986, and the margin is much wider today. If costs have come down in the past two decades, there can be continued and perhaps faster non-OPEC expansion. But in the early 21st century, regulation and taxation will be more important than the cost of mineral under depletion and increasing knowledge. In some non-OPEC countries, impediments to investment will never be removed. Mexico is particularly interesting. Proved reserves decreased in 2000, and this will be blamed on limited resources. Yet the profit on investment in new reserves and capacity is very high.17 Foreign investment would expand it. But Petroleos Mexicanos stays in the public sector, starved for investment funds. The public views Pemex as a national cash cow. It seems strange and unnatural to raise taxes and “take” money from the public in order to “give” funds to Pemex. Similarly, in Venezuela the government has said more than once that it will cut investment in oil to do more social spending.

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I may be mistaken in assuming some removal of some of the non-OPEC achievement gap. If this pushes the OPEC share of world sales below 25%, it will be hard for OPEC to hold the line. Adding new members might help short-term, but would make agreement more difficult. Be this as it may, the critical variable is non-OPEC investment and output. World production could top out permanently in this century, for the same reason as the temporary peak in the 1970s: not limited resources but governments demanding more than the traffic will bear. At the other extreme: a long-run competitive price would be more stable. Low-cost producing countries would cease to restrict output. They would serve their individual interests and remove barriers to investment, starting with state ownership. Of course, this would raise their fraction of world output, and tempt them into reforming OPEC, and again making the price high and unstable. In any case, resource “optimism” and “pessimism” have no meaning. Make the “optimistic” assumption that fuel resources are renewable. A rising marginal fuel cost would still mean less fuel and more discomfort. In England from 1550 to 1650 the price of the renewable resource firewood quadrupled. Some even took refuge across the sea. “All England, nay all Europe, hath not such great fires as we have in New England.” Scarcity—rising marginal cost—may arrive one day in world oil. We could recognize it and take measures, if there were a competitive market to register scarcity. In that respect, they were better off in 1550.

Notes 1. Professor of Economics Emeritus, MIT, Cambridge, Mass., USA. The paper draws extensively upon The Economics of Petroleum Supply: Selected Papers 1962–1993 (MIT Press 1993); and The Genie Out of the Bottle: World Oil Since 1970 (MIT Press 1995). The final draft was completed during June 2001. I am grateful for the comments and suggestions of Shane Streifel. 2. The figure includes crude oil only, for which data are available for the whole period. Today an additional 10% of output is from natural gas liquids; in the U.S.A., about 33%. The percentages of oil drawn from natural gas reserves are increasing. 3. Current members: Algeria, Indonesia, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, United Arab Emirates, Venezuela. 4. Absent the Marshall Plan, when would a world crude oil price have emerged? My own guess is: not very soon. Lower oil prices damaged the (mostly nationalized) coal industry in Europe, and domestic oil in the U.S.A. 5. A cabinet-level report issued May 19, 2001 has made it official: the U.S.A. is in a long term “energy crisis.” There is no such thing, but there are four current problems, all mutually independent. If any three disappeared, the fourth would be no less. (1) Investment in natural gas production is guided by expected demand. Actual consumption has been higher than expected. While investment catches up, supply is scarce, and marginal costs and prices are up. Nobody is curtailing production to raise the price. There is no “crisis” when the market registers a temporary scarcity; that is

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7.

8.

9.

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what a market is for. (2) There is an electricity shortage because investment has been restricted or stopped for years, especially on the West Coast. The guiding principle of NIMBY (Not In My Back Yard) works, one locality taken at a time, but not in all localities taken together for years on end. To make the NIMBY shortage more dramatic and devastating, California has enacted a curious “deregulation” which caps the prices charged to consumers by utilities, and frees up wholesale prices the utilities pay. Undoing this legal mess will take longer than increasing the gas supply. (3) There are sporadic shortages of gasoline, because of varying local air-quality regulations, and an investment lag similar to natural gas but less serious. (4) Finally, there is the worldwide crude oil price surge, resulting not from any kind of shortage, but from deliberate output cuts by a cartel, with the usual cartel objective: to raise and hold the price level against the threat of competitive price cutting. There has never been any noncartel excess capacity. A competitive producer has no reason to hold back production. There is no straightforward relation between cartel excess capacity and prices. When OPEC had massive excess capacity, in 1973– 80, prices rose 10-fold. In 1981–1998, when excess capacity was lower, and declining, prices actually fell. In early 1999, the excess, largely in Saudi Arabia and Kuwait, was modest. But the production cuts themselves took more capacity out of production, to raise and maintain prices. It was long assumed, especially in the US government, that the oil states had long horizons and low discount rates; or did not seek higher revenues, only tried to cover their “revenue requirements.” Iraq national product has been reported down by as much as 90% since sanctions. Some of this is the shift into “black” unreported activities, but most of the apparent decrease was real. Iraq was a relatively developed Persian Gulf oil economy. Without oil exports, there was not much left. A taxicab operator drives say one mile, charges $2, and uses up one-tenth of a gallon of gasoline, costing say 20 cents. For lack of fuel, he would lose the other $1.80 of revenue. Insurance against such a loss by storing more gasoline, even paying higher prices for it, makes good sense. We can only mention here the well-known prediction of M. King Hubbert that U.S.A. output would decrease after 1970. He was right, but his reasons were unclear. Hubbert based the forecast on a bell-shaped curve of production over time. Most manufacturing industries, with no resource constraints, follow such a curve anyway, as customers and factors are competed away. Short-term marginal costs turned up at the same time, see Adelman (1998). Hubbert spoke out of great knowledge of a very large sample in an intensively explored area. All of us know more than we can articulate, let alone prove. Perhaps he did. But a similar conclusion about the whole world, relatively little explored, has no authority. Outside North America and the North Sea, most countries, accounting for the great bulk of reserves, show identical reserves for 1999 and 1998. This means that the gross reserve additions were precisely equal to production. It would be an unlikely coincidence in any one country, and is quite impossible for several or many. The job has simply not been done.

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12. “The modern economy is a fire-breathing vampire of petroleum which is slowly cooking our planet . . . . Unless the prices of energy and natural resources reflect the cost of consuming limited ”natural capital,“ the true price of prosperity is deferred to the debit column of the future. It is a category [sic] failure of modern economics that these costs are not reflected in the costs of production” Bode (1999). 13. See for example, Dasgupta and Heal (1979). 14. It is easily proved that if V ⫽ in-ground value, P ⫽ current wellhead price, a ⫽ the production decline rate, i ⫽ the interest rate, and g ⫽ the rate of increase of the wellhead price (all in percentage per year), then V ⫽ Pa/(a⫹i-g). If it be assumed or proved that g ⫽ i, then P ⫽ V. 15. Direct observations of discovery values are rare. In Saudi Arabia, in 1975, a contract between the government and the then-Aramco for undiscovered oil assigned it a value of about 2 cents. 16. In 1992, I published a brief note, Adelman (1992), suggesting that gas prices were not about to increase, despite growing demand, because investment requirements to develop new gas reserves were not increasing. In fact, gas prices fell during the 1990s. There are no data from which to estimate the cost of later reserve-additions. At the 1990 decline rate, about 10.2%, by 2000 AD 64% of the 1990 proved reserves had been used up. 17. Pemex has stated that production was static for lack of funds. More investment would increase reserves and production because “the return on those investments is exceptionally high.” (Secretariat of Public Education and Culture, 1993, p. 55). Later the Director General estimated costs at $2.50 per barrel, which he compared with a price of $13 for heavy crudes. See Friedland (1999).

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