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It’s not your father’s oil industry anymore
The Quarterly Review of Economics and Finance 42 (2002) 273–284
It’s not your father’s oil industry anymore Roger M. Olien* Humanities & Fine Arts Department, University of Texas Permian Basin, Odessa, TX 79762, USA Received 21 August 2001; accepted 15 January 2002
1. Introduction Once again, America is engaged in prolonged dispute over the creation of a national energy policy. Dating from the decade before World War I, the topic has revived with every real or imagined crisis of supply of crude oil during the 1910s, of refined products during the 1970s, and of natural gas in California in 2001. Solutions to perceived problems have included restriction of consumption, voluntary and incentive-based conservation, incentives for producers, expansion of territory open to exploration, and various forms of national control or ownership. As time has passed, especially during the past twenty years, however, many policy advocates merely dust off familiar remedies, having lost track of the sweeping changes that have transformed the petroleum industry in the United States. In many instances, policy proposals are useless at best because they address vanished realities, ignoring significant aspects of the energy industries as they function in 2001. Step one in policy advocacy, thus, must be to recognize that “it’s not your father’s oil industry anymore.”1 The major elements in the recent transformation are price volatility and a general decline in the value of production, particularly of crude oil in the upstream sector. Oil prices declined from $39 per barrel in 1981 to $12 (nominal) in 1986, followed by a run-up that reached $33 (nominal) in 1989 and a drop to $20 a year later; thereafter it rose to $20 in 1996 and fell again, stabilizing briefly at $10 per barrel in 1998 before it shot back up to $34 in March of 2000. Restated in real (2000) dollars, the swings moved from $73 per barrel in 1980 to a low of $10 in 1998.2 The progressive deregulation of natural gas, beginning with the US Natural Gas Policy Act of 1978, revolutionized the sale and marketing of natural gas, producing occasional
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“bubbles,” excess supply, and in tandem with environmental regulation, encouraged increased consumption of it. Recently, these changes and seasonal demand produced a steady increase in the price of gas, from $4.26 per thousand cubic feet at the well head in September 2000 to $6.35 in December, and $8.06 in January. Thereafter, the price declined to $5.15 in March. In the short-term, at least, natural gas became the hydrocarbon of choice for producers, leading to additional drilling in the Delaware Basin of Texas and to additional searches for natural gas in offshore areas.3 Price volatility and the increased value of natural gas led explorationists to seek the latter and to reenter existing fields to drill additional wells. The sharp swings in oil prices and the decline of reserves in the lower 48 states encouraged larger producers to seek more substantial reserves abroad and in the deep waters (in 1,000 feet of water or more) in the US sector of the Gulf of Mexico, shedding declining properties to the independents, exploitationists who worked to squeeze additional oil from mature fields. In declining markets, with weakening competitive positions, some of the larger companies had to lower costs. While Mobil paid $3.67 per barrel to replace reserves during the early 1990s, replacement costs for Amoco and BP respectively were $5.45 and $6.10. BP’s response to cost problems was to pull out of exploration in the Lower 48 in 1991, while other companies rationalized but kept core assets.4 The independent US wildcatter, once the typical small explorationist who drilled in geological frontier areas, now struggles to keep domestic stripper wells pumping, while larger producers take geological risks in frontier areas. In the downstream sector, massive shifts of ownership and operation stemmed from federal regulation, the changing prices of crude oil and natural gas and the emergence of large-scale competition in the production of basic petrochemicals. By 2001, the American refining industry was smaller than it had been twenty years earlier and the major players in the US petrochemical industry had shifted to the production of specialized chemicals, a part of that industry that has always been highly responsive to demand cycles and even more capital intensive than basic chemicals. The stakes got higher and the odds got longer. One of the most visible changes in the petroleum industry is that there are fewer players. Every major swing in the price of oil, gas, and refined products drove mergers and acquisitions, restructuring and reconfiguration of major firms, implementation of new costsaving technologies, and cuts in work forces. Perhaps the most obvious evidence of change has been the disappearance of the “seven sisters,” the multinational, multidivisional corporations that were long dominant in national and international trade. Of the seven, Exxon, Chevron, Shell, British Petroleum, Mobil, Gulf, and Texaco, only the first four-named still exist as they did in 1980. Chevron acquired Gulf and Texaco, and Mobil merged with Exxon. The “sisters” had seemed as immutable as the Soviet Union, but Gulf succumbed because of poor performance and Texaco and Mobil were acquired/merged as other giant corporations sought economies of and scale enhanced asset bases. John D. Rockefeller’s original Standard Oil Company of Ohio (SOHIO) and Amoco(Standard Oil of Indiana) were both acquired by British Petroleum, which had acquired Sinclair’s down stream assets—principally 10,000 gasoline stations and two refineries—when ARCO bought Sinclair in 1968.5 Big oil has gotten bigger. Second-tier companies, such as Phillips, Marathon, Conoco, Occidental, and Kerr-McGee
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also went through major transformations, launching aggressive acquisitions campaigns. For example, after Conoco was spun off by DuPont Company in 1999, it made extensive buys in the Permian Basin and Canada, making it the tenth largest investor-owned oil and gas company in the United States. Kerr-McGee increased its presence in offshore US areas and in foreign regions, as did Phillips. From time to time all of them, like the larger companies cut payrolls as prices plunged. Phillips, for example slashed its workforce by about 10% during the dark days of 1986.6 As usual with large mergers, payrolls were cut as redundant positions were eliminated. Thus, after Chevron bought Gulf in 1984, the combined global work force was cut from 79,000 to 61,000 within four years.7 Mergers, however, accounted for fewer lost jobs than the widespread reorganization of companies, as they scrambled to maintain financial performance standards during downturns. Initially, the slow down in exploration led to cuts in geophysical and geological staffs. During the late 1980s, for example, US unemployment rates among geologists ranged from 28% in Midland to 34% in Denver and 39% in Oklahoma City.8 By the end of 1991, employment in the North American industry had fallen to 350,000 from its 1982 peak of 754,500 people. The service sector was hardest hit as nearly two-thirds of the jobs were eliminated. As a result, at the present time the industry faces shortages or potential shortages in many job categories. This problem will probably become more acute because within most companies there is a significant age-disconnect because there are relatively few workers between the ages of 35 and 50. Margaret Carriere, vice president of human resources of Halliburton, estimates that the industry could lose 60% of its “top talent” by 2007. Shortages are especially critical in petroleum engineering, which now finds it difficult to attract students because of the cyclic nature of the industry and its history of cutbacks.9 The consolidations in exploration and production were mirrored by changes in the service sector of the petroleum industry. During the 1980s, the downturn led to failure of even large companies, such as Western. Other diversified companies sold petroleum industry-related assets. Thus, Fluor sold its oil and gas operations to Houston Industries which was later acquired by Schlumberger, which also bought Western Geophysical in 2000. By the end of 2000, Halliburton, the other giant among service companies, had acquired M. W. Kellogg, the dominant engineering firm, and Dresser, the leader in production services, among other companies.10 Consolidations were massive in the drilling and equipment sectors. Thus Baker International merged with Hughes Tool in 1986 to become Baker/Hughes. The price downturn of 1998 placed Reading & Bates Corporation in a weak debt position and it was acquired by Falcon Drilling, which also bought Cliff’s Drilling Company. The relative lag in day rates, in turn, undermined the financial position of R & B Falcon, which was acquired by another product of recent mergers, Transocean Sedco Forex, Inc, in the early months of 2001. In midyear, Pride International, Inc., and Marine Drilling Companies, Inc., also merged, creating a company with 10,000 employees.11 As the real value of oil declined, companies commonly sought economies through elimination of layers of management. Unocal, for example, trimmed supervisory levels from
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six to eight, cutting its workforce by 2%.12 During the next decade British Petroleum removed layers of management by reorganizing Amoco, which had already cut 8500 jobs between 1988 and 1992, eliminating 59 of the 86 head office committees, firing 160 of 540 managers in Cleveland’s SOHIO headquarters, trimming 3800 jobs by 1994.13 With fewer management tiers, some companies reorganized work by creating interdisciplinary teams in exploration and production and out-sourced work, saving time and money by delayering and wage and benefit costs by contracting out accounting and other office work. In response to low and volatile prices, producers also re-examined properties during the 1980s, shedding some and acquiring others, a process that continues. In 1990, Chevron sold nearly two-thirds of its US oil and gas properties and bought Tenneco’s Gulf of Mexico holdings.14 When Santa Fe Energy spun off Monterey Resources in 1997, Texaco made the buy to boost its production in California, where it continued to refine crude oil.15 Mobil sold its interests in 27 Permian Basin fields to Titan Resources, a large Midland-based company in 1997. More recently, in 1997, Kerr-McGee sold large working interests in five offshore blocks to the Offshore Oil and Gas Corporation, a Houston-based subsidiary of the China National Offshore Oil Company.16 Buying, selling and swapping, always fast-paced in the petroleum industry, now move at the speed of corporate jets and computers. Some companies reorganized their operations to encourage effective adaptation to rapidly changing conditions and related opportunities. ARCO, the most successful at strategic reorganization, created ARCO Permian to manages and expand its assets in its largest concentration in the Lower 48, then spun off Vastar to do the same with off-shore properties. ARCO Permian proved to be highly entrepreneurial and cost effective. Vastar, specializing in shallow water, complex geological formations and problematic reservoirs, built a 71% success rate and drilled 40 wells on the Outer Continental Shelf in 2000 alone.17 Both ARCO Permian and Vastar were acquired by BP Amoco, through its purchase of ARCO. In the mature regions, large companies commonly combined operations in newly-formed firms. Thus Amoco and Shell combined Permian Basin assets into Altura Energy and Mobil and Shell formed Aera Energy to combine their exploration and production operations in California in 1997.18 Other US companies did spin-offs. Panhandle Eastern, largely a gas transmission company, spun off Anadarko, a production company, which acquired additional assets and became a significant player among medium-sized companies. The company became a regular participant in Gulf of Mexico projects, holding 37.5% of Phillips’s important Mahogany field. In 1999, it purchased a 50% working interest in 82 blocks held by Texaco in the Gulf of Mexico. With its purchase of Union Pacific Resources, Anadarko was the largest independent oil producer in the world.19 Sale of properties and company acquisitions created some large new US independents, including Parker and Parsley (which merged with Mesa Petroleum to form Pioneer in 1999), and Apache Corporation. The latter, on the scene in a relatively small way since the 1950s, moved to acquire properties from Hadson Energy Resources in Australia and other companies, then worked to offset mounting production costs by acquiring additional holdings, buying offshore US leases from Shell Offshore, Occidental, and Petsec, along with Canadian assets purchased from Phillips, Shell Canada, and Fletcher Challenge Energy. As part of its
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growth, the enlarged company bought holdings in Egypt along with sizable assets in the Permian Basin. With nearly $7.5 billion in assets, Apache achieved economies of scale in operations and became one of the world’s largest independent oil and gas exploration and production companies. During August and September of 2001, Devon Energy acquired Mitchell Energy of Houston, and Canadian properties, to become the largest independent in the world, as determined by oil and gas reserves.20 Trading properties was hardly new to the oil industry, but the direction of it was novel, as most of the larger producers invested in foreign and offshore US exploration and production, producing a massive shift in the ownership of the declining on-shore reserves. The repositioning of the large multinational companies is clearly reflected in the control of oil production in Texas. By January 2001, familiar names, Exxon/Mobil, Texaco, Chevron, ARCO, Conoco, and Phillips were present on the list of 100 largest producers, but there were notable changes since 1980 because of mergers, acquisitions and divestitures. The number one producer, long Exxon, was replaced by Occidental Permian, which produced 14% of the crude oil in Texas during that year. More notable, Texas, a mature geological province with declining production, had become the preserve of small producers. For example, the tenth largest Texas producer, Pure Resources, a Midland company, accounted for 1.9% of Texas crude. The 30th largest, Henry Petroleum of Midland sold 0.59% of total production in the state from February 2000 through January, 2001. The changes in the list of producers reflects shifting ownership patterns, the general decline of production to the point that the typical Texas oil well is far from a gusher—it now produces less than ten barrels per day and must be pumped to do even that.21 For anyone who had missed the results of the sweeping nationalizations by nationallyowned companies during the 1970s, R. Dobie Langenkamp, a deputy assistant secretary of the Department of Energy from 1976 – 81 and 1997–98, pointed out that the nationallyowned companies were, in fact, the largest oil companies in the world, displacing the surviving Four Sisters. In 1970, for example, Exxon produced 80% of its own crude. Ten years later, the number had fallen to 44%. By 2001, determined by reserves base, oil owned in the ground, Exxon/Mobil was the world’s 12th largest oil company, following the Brazilian national company, Petroleous Brasileiro (Petrobras) and just ahead of Russia’s largest oil producer, Lukoil. The second largest US company, Chevron, was 20th worldwide, following Pertamina, of Indonesia, and Dubai Petroleum, among others. The combined reserves of the top ten US oil companies amounted to less than those of Pemex (Mexico) and comprised less than four percentage of the reserves held by the ten biggest. The Saudi Oil Company dwarfed them all.22 The largest oil companies, faced with declining and increasingly costly onshore US production, ventured into the North Sea after the Ekofisk discovery in the Norwegian sector and into Alaska beginning in 1976, searching for larger plays. When Minerals Management Service, US Department of the Interior, instituted area-wide leasing in 1984, it was possible for companies to acquire enough contiguous leases to make billion dollar commitments in deepwater regions in the Gulf of Mexico. Improvements in 3-D seismography and the more rapid processing of data, and improvements in drilling and production technologies, have progressively supported exploration in ever deeper water. By 2001, investment in deepwater projects absorbs 40% of the capital invested in offshore exploration and development, with
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the large companies setting the trends. The high costs of activity in that arena has meant that seven companies, BP/Amoco, Shell, Exxon/Mobil, Chevron, Total/Elf, Petrobras, and Texaco have located more than three-quarters of the deepwater reserves. Shell, in particular, has advanced capital and technology to push the depth drilling record beyond 7,500 feet with major discoveries in the Mississippi Canyon in the US sector of the Gulf of Mexico.23 With the increasing investment and involvement of privately held companies in Russia and other component states of the former Soviet Union, new dimensions of political risk—largely exporting profits from operations— came into play as Chevron, Exxon/Mobil and other companies heavily invested in Caspian Sea-area plays.24 Other regions in Asia, offshore West Africa, Canada, South America, and Australia also saw large-scale searches for new reserves by the larger companies. All of these costly and risky investments in exploration have been conducted as joint ventures, producing a crazy-quilt of alliances of large and medium-sized firms. In the Kashagan field of Kazakstan, for example, shareholders include Exxon/Mobil, TotalFinaElf, BP Amoco, Statoil, Phillips, ENI and several smaller companies. In the Tengiz offshore field, Chevron holds a half interest with the balance divided between Exxon/Mobil and the Kazakstan government.25 Joint ventures of course, had been common before then. Aramco and CalTex were familiar models. Moreover, the practice of sharing risk in exploration with partners had been around for almost as long as there has been an American oil industry. In recent years, however, the practice has become standard practice because of the increase in costs and risk in the context of volatile prices. Thus both Shell and Exxon/Mobil have partners in deepwater Gulf of Mexico ventures, including Shell’s grand Mississippi Canyon plays and Exxon/Mobil’s Crazy Horse development. In its Ram-Powell field, Shell partnered with Amoco and Exxon. In its Ursa field, located in 4,000 feet of water, 130 miles southeast of New Orleans, Shell had a 45% stake, with BP at 23% and Conoco and Exxon both with 16% of the 400-million barrel field. In the giant Mars field, where development costs exceeded $1 billion, Shell partnered with BP. Most recently, Shell and Exxon/Mobil have combined to built a $159 million pipeline to deepwater fields.26 Over time, as risks and costs have increased, joint ventures, always common, have become the norm among larger companies. More extraordinary changes have occurred in the downstream sector of the American petroleum industry in response to price volatility and new standards of financial performance. The conventional observation that fully integrated companies were less vulnerable to short-term fluctuations of prices of raw materials and finished goods was discredited with the large crude price drops in 1982 and 1986, as refineries found the values of their feedstocks and inventories plummeting.27 The common assumption had been that when feed stocks were cheap, refiners and petrochemical producers were more profitable; conversely, when feed stocks were more costly, the advantage went to producers. Ideally, a company that operated in all phases of the petroleum industry thus enjoyed some protection from the effects of volatile markets. Over the medium-term, it would have balanced. For the large companies it did, over the medium term. But in the meantime, the expiration of the US federal import entitlements program deprived marginal refiners of income and the lag of product prices behind feedstock costs wiped out most small refiners. Between 1981 and 1985, more than 100 simply shut down; most of them found no bidders. In raw numbers,
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they comprised one-third of all of the refiners who had been in business during the earlier year.28 Since 1995, 24 additional refineries—many of them small independents– have shut down.29 Some of the closed operations were too small to realize economies of scale, or to afford the added cost of compliance with federal environmental regulation. Even large operations, such as the Unocal refinery in Beaumont, Texas closed because it was uneconomical for the company to invest in additional plant installations required to lower emissions through reformulation.30 Amoco also closed its refinery in Casper, Wyoming because adaptation to meet environmental standards was uneconomical. Since 1970, the US has lost nearly one-third of its refining capacity.31 Surviving US refiners coped with cost-price and financial performance pressures. When prices of feed stocks rose, refined product prices typically rose less rapidly, leaving net revenues flat and discouraging additional investment in refineries. Returns improved only as the industry got smaller, raising plant utilization rates to about 90% in 1998, for the first time in twenty years. As a result, the capacity of refiners to respond to seasonal demand for gasoline and heating oil diminished, a situation that has produced area shortages of special formula products.32 With the rise of imported refined products, a trend from the 1980s, American refiners were usually hard pressed to maintain minimally satisfactory rates of return on investment in plant. In the past, this implicit acceptance of definitionaly mediocre financial performance was acceptable because oil fared at least as well as other leading industries. In the context of financial markets during the 1980s and 1990s, however, past practice was inadequate. Simply put, investor-owned oil companies found it difficult to defend levels of performance inferior to lead industries to institutional and foreign investors, increasingly powerful in securities markets. When electronics, telecommunications, e-commerce, and even real estate investment trusts were out-performing them, oil companies simply had to do better to attract and hold investment capital. As their control of reserves declined, from the 1970s onward, they found it necessary to try other common remedies for inadequate financial performance. During the cash-rich days of the late 1970s and early 1980s, oil companies pursued diversification strategies to offset cyclical declines in petroleum and to share technologies. The best known examples at the time were Exxon’s purchase of Reliance Electric, based on assumed mutual technology transfers from the oil company’s research and development activity with the office systems company. Farther afield, Mobil, a leading retailer among oil companies, purchased ailing Montgomery Ward.33 Less well known diversifications included heavy investments in real estate, as with Mitchell Energy’s Woodlands project north of Houston, and narrower diversifications into other energy areas such as shale oil extraction, geothermal power generation, and nuclear projects. Though many of the diversified purchases, notably Exxon’s and Mobil’s, have been sold or closed, changes in regulations and markets continue to encourage near-process diversification. Recently, Shell purchased 50% of Integen, a power-generating subsidiary of Bechtel Corporation.34 From the 1980s onward, downstream US properties have also been swapped, sold, and brought into joint ventures as companies reacted to costs of meeting environmental regulation, rising costs and volatile prices. Some of the sales were logical outcomes of redundant acquisitions. Thus Chevron sold old Gulf Oil refineries, including the giant Port Arthur,
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Texas plant to Clark Refining & Marketing and the Philadelphia refinery to Sun.35 Similarly, Unocal sold West Coast refining, marketing, and transportation acquired in its acquisition of Pure Oil to Tosco, already a large independent refiner.36 The petrochemical industry, always hyper-competitive and fast-moving, underwent similar changes. During the 1970s, US companies enjoyed competitive advantages over foreign competitors because of federal regulation of interstate natural gas prices. Those who used by-products of oil refining benefited from long-term contracts for federally regulated “old” oil, frozen at $5.25 per barrel.37 With the removal of price regulations during the Carter administration, these advantages were lost; foreign competitors moved into the production of basic chemicals as nationally-owned oil and gas production companies sold feed stocks to their refiners and petrochemical operations at prices below world market levels.38 Petrochemicals were also hit with mandatory investments to meet US federal pollution standards. The leading trade periodical, Hydrocarbon Processing, estimated the 20-year cost of environmental compliance to 2000 at $50 billion in year 2000 dollars.39 Emissions and water disposal were especially costly problems along the Texas Gulf Coast. Citing compliance costs, Cities Service withdrew from petrochemicals in 1982, when industry operating margins were -1.3%, down from 3.5% the year before.40 The petrochemical section of the industry had always been the most highly responsive to changes in the general economy, declining during downturns as specialty chemical installations and finished goods producers cut orders. The global industry also suffered perennially from excess capacity in basic chemicals, where processes enjoyed relatively little protection from patents and technology could be purchased “off the shelf” by any company with sufficient capital. In 1993, even after adjustments in production had been made, the US industry operated at only 70% of capacity, a critically low level in capital-intensive, continuous-process manufacturing.41 Whenever the cost of feedstocks rose in the United States, companies had to invest in efficiency-boosting improvements to hold competitive position with lower cost processors in the Middle East and Asia. By 1986, the production of basic petrochemicals was declining sharply in the US in the face of these challenges, and major producers were investing in the production of specialty products, where they enjoyed technological superiority.42 Some producers chose not to make the conversion. American Hoechst, for example, sold its polystyrene plants to Huntsman Financial Corporation, the leading producer of that product in the United States. Hoechst merged its remaining petrochemical plants with Celanese in 1987, the year after the sale.43 As the process of divesting proceeded in petrochemicals, even large companies withdrew: Texaco also abandoned petrochemical production in Texas, selling its Gulf Coast operations to Huntsman.44 All of the larger companies reassessed their investments in exploration, production, refining, petrochemicals, and distribution, producing an extended series of divestiture that restructured the downstream sector of the industry. Both Tosco and Valero, a San Antonio company, became large-scale refiners as they acquired properties shed by large companies. Thus Exxon/Mobil sold its west coast refinery and retail assets to Valero, which had acquired Mobil’s Paulsboro refinery earlier. In 2001, Valero, which began as a part of LoVaca Gathering Company, a natural gas subsidiary of Coastal Corporation, acquired Ultramar Diamond Shamrock to become the second-largest refiner in the US, after Exxon/Mobil. Exxon/Mobil also sold 1,740 retail outlets in the northeast and mid-Atlantic to Tosco, which
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went on to acquire BP’s West Coast refinery.45 Texaco reassessed its “sell in all of the 50” retailing policy and withdrew from parts of the Upper Middle West and Northern Rockies in 1980.46 In refining as in domestic production, the large oil companies abandoned the traditional model of vertical integration, leaving large parts of the field to aggressive independents. The dominant financial strategy, asset/portfolio management, also led the large companies to lower their exposure to the risk of lower performance in downstream activities by entering into alliances across the country. Thus, Texaco formed Star Enterprises in partnership with Saudi Refining to operate refineries in Delaware, Louisiana and Texas and to market in 26 states.47 Shell entered joint ventures with Texaco, creating Equilon and Motiva in the downstream sector.48 In petrochemicals, alliances were also common with even industry giant Shell joining with Himont Chemicals to form Montell Corporation to produce chemicals in fifteen plants and Union Carbide forming an alliance with Kuwait Petroleum. Within the industry, Exxon and Union Carbide, Dow and British Petroleum combined in ventures and all of the large producers sought alliances with large foreign national oil companies.49 Capital intensity, fast-moving technology, and movements in US utilization rates between 70 and 96%, varying by year and product, all transformed a major American industry. By 2001, the model of functional integration, from exploration to production, transportation, refining, and marketing, long the dominant model for large and medium-sized oil companies, had undergone major change. The original Standard Oil model, described as normative in oil and other industries by Alfred D. Chandler, Jr., and other scholars had been displaced by asset management strategies, alliances, partnerships, and divestitures. One of the trends that appeared during the 1980s continued thereafter as foreign, nationally-owned oil companies bought increasingly large access to the US market. Mexico (Pemex), Venezuela (PDVSA), Saudi Arabia (Aramco), and other countries became partners and owners of refineries. Union, for example, sold a 50% stake in its Chicago refinery to Venezuela, which had already taken over Champlin Refining during the 1980s. In 1992, Pemex obtained a 50% interest in Shell’s Deer Park, Texas refinery, which was capable of processing heavy Mayan crude.50 Lukoil recently bid for 1300 US service stations.51 The foreign nationals have also taken a strong interest in exploration in the Gulf of Mexico, reflected in the Houston offices maintained by Norway’s Statoil and other companies. In 2000, Exxon/Mobil and Italy’s Agip Petroleum Exploration (ENI) formed an alliance to develop up to 259 blocks in the Gulf of Mexico over a five-year period.52 Clearly the increasing presence of non-US and noninvestor-owned companies reflects the sea change in the world petroleum industry. The continued volatile economics of oil and gas, reorganization, down-sizing, and globalization of the petroleum industry now pose special challenges for would-be US regulators. The loss of refinery capacity and the increasing importation of refined products will keep domestic supplies and margins thin. Further regulation will make domestic refining and petrochemical operations even less profitable, leading to further reductions in capacity and increased reliance on foreign refiners. In exploration and production, withholding potential domestic areas from exploitation will reinforce the foreign activity of large privately-owned companies and strengthen the market positions of the noninvestor-owned foreign producers, whose refineries would gain market advantages over US refiners, while doing little to lessen
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industrial emissions around the world. Capping natural gas prices, similarly, will discourage exploration, lower domestic production, weakening feed stock supplies of American chemical companies and, thereby, enhancing the competitive positions of foreign processors to the disadvantage of American workers, consumers, and investors. Globalization has placed the creation of an effective and equitable energy policy beyond our reach, when we try to enact it through restrictive law and regulation. The principal reality of 2001 is that it’s not your father’s oil industry anymore, unless your father is a Saudi, a Brazilian, a Mexican, an Angolan, an Indonesian . . . . Regulations that do not take full account of this reality will certainly worsen the conditions they are intended to remedy.
Notes 1. For my view of policy gyrations to 1945 see Roger M. Olien and Diana Davids Olien, Oil and Ideology: The Cultural Creation of the American Petroleum Industry (Chapel Hill: The University of North Carolina Press, 2000). 2. Stephen P. A. Brown and Mine Y. Yuecel, “Oil Prices and the Economy,” Southwest Economy (Federal Reserve Bank of Dallas), July/August 2000, 2. 3. Energy Information Agency, “Monthly Gas Report, March, 2000,” 9 –11; an overview of regulatory changes is provided by Arlon R. Tussing and Bob Tippee, in The Natural Gas Industry: Evolution, Structure, and Economics, Second edition, (Tulsa, OK: PennWell Books, 1995). 4. Petroleum Economist, November 1991, 35. 5. On BP see James Bamberg, British Petroleum and Global Oil, 1950 –1975: The Challenge of Nationalism (Cambridge, UK: Cambridge University Press, 2000), 273– 6. 6. Wall Street Journal, May 30, 2001, 12. 7. Petroleum Economist, November 1989, 362. 8. Oil and Gas Journal, November 13, 1989, 28, 36. 9. Midland Reporter-Telegram, May 3, 2001. 10. Petroleum Economist, November 1985, 422. Perry A. Fischer, “Western and Geco Merge,” World Oil, July 2000, 25. 11. St. Paul Pioneer Press, May 25, 2001. 12. Oil and Gas Journal, March 6, 1989, 23; May 15, 1989, 14. 13. Oil and Gas Journal, May 11, 1992, 26; July 13, 1992, 19; May 16, 1994. 14. Oil and Gas Journal, May 11, 1992, 26; Petroleum Economist, December 1995, 15. 15. Petroleum Economist, October 1997, 59. 16. Petroleum Economist, December 1997, 44. 17. Jeane M. Perdue, “Shallow Waters: The ‘Other’ Gulf,” Hart’s E & P, April 2000, 69; Petroleum Economist, November 1999, 57; World Oil, July 2000, 31. 18. Petroleum Economist, January 1997, 54. 19. Petroleum Economist, May 1995, 57; November 1999, 43. 20. Petroleum Economist, December 1993, 51; United States Securities and Exchange Commission, Form 10-K: Apache Corporation, for the fiscal year ended December
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21. 22.
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24. 25. 26. 27. 28. 29. 30.
31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41. 42. 43. 44. 45. 46. 47. 48.
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31, 2000, 24 –5; Apache Corporation, 2000 Annual Report, 2; Dallas Morning News, September 6, 2001. Railroad Commission of Texas, “Texas Largest Oil Producers, February 2000 through January, 2001,” Computer Report (OLN261), March 21, 2001, 1–2. Donald O. Croll, “The Majors in Transition,” Petroleum Economist, May 1980, 189; R. Dobie Langenkampf, “U.S. ‘Big Oil’ Companies: Getting Smaller in the Real World,” Houston Chronicle, December 31, 2000, C-1. M. Liliana Riahi, “Deepwater Exploration in the Gulf of Mexico,” Hart’s Petroleum Engineer International, April 1998, 63, 64 –5; “Deepwater Dilemma,” Hart’s E & P, April 2000, 84 –5; World Oil, March 2000, 3. “Fifty Years of the Oil Industry,” Petroleum Economist, September 1983, 326. Wall Street Journal, March 21, 2001. Petroleum Economist, October 1993, 65; September, 19995, 80; August 1996, 49, October 1997, 60; Midland Reporter-Telegram, May 27, 2001. G. M. Intille, “How Refineries Inventories Threaten Profitability,” Hydrocarbon Processing, July 1986, 92. Houston Chronicle, June 2, 1985. Dallas Morning News, June 15, 2001. Hydrocarbon Processing, June 1988, 13; December 1989, 69; Houston Post, July 21, 1991; Texas Comptroller of Public Accounts, Forces of Change, Volume II, Part I (Austin, November 1993), 27. Oil and Gas Journal, July 13, 1992, 19 Hydrocarbon Processing, November 1994, 29; March 1996, 25; March, 1998, 31. Petroleum Economist, February 1987, 2. Oil and Gas Journal, April 2000, 68. Petroleum Economist, December 1995, 15. Petroleum Economist, May 1992, 40; January, 1993, 41; March 1994, 48; May 1994, 60; February 1997, 52. Houston Chronicle, January 15, 1975; March 10, 1977. Dallas Morning News, April 19, 1985. Hydrocarbon Processing, December 1990, 58 – 60. Houston Chronicle, July 25, 1982; January 6, 1984, 16A. Houston Chronicle, March 29, 1993. Houston Chronicle, May 20, 1984. Hydrocarbon Processing, February 1986, 8; May 1986, 26; August 1986, 19; April 1987, 25, 31; May 1987, 431; May 1988, 29. Petroleum Economist, July 1997, 50. Petroleum Economist, January 1993, 41; October 1993, 64; January 1997, 54; April 2000, 68; Midland Reporter-Telegram, May 20, 2001. Petroleum Economist, May 1979, 205. Oil and Gas Journal, September 28, 1992, 104; Petroleum Economist, September 1997, 124. Oil and Gas Journal, December 21, 1998, 31.
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49. 50. 51. 52.
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Hydrocarbon Processing, March 1996, 27;March 1998, 25, 27, 29. Petroleum Economist, July 1988, 250; January 1989, 38; September 1992, 46. Petroleum Economist, January 1982, 39. Langenkamp, “U.S. ‘Big Oil’ Companies.” Petroleum Economist, June 1997; World Oil, July 2000, 31.
It’s not your father’s oil industry anymore Roger M. Olien* Humanities & Fine Arts Department, University of Texas Permian Basin, Odessa, TX 79762, USA Received 21 August 2001; accepted 15 January 2002
1. Introduction Once again, America is engaged in prolonged dispute over the creation of a national energy policy. Dating from the decade before World War I, the topic has revived with every real or imagined crisis of supply of crude oil during the 1910s, of refined products during the 1970s, and of natural gas in California in 2001. Solutions to perceived problems have included restriction of consumption, voluntary and incentive-based conservation, incentives for producers, expansion of territory open to exploration, and various forms of national control or ownership. As time has passed, especially during the past twenty years, however, many policy advocates merely dust off familiar remedies, having lost track of the sweeping changes that have transformed the petroleum industry in the United States. In many instances, policy proposals are useless at best because they address vanished realities, ignoring significant aspects of the energy industries as they function in 2001. Step one in policy advocacy, thus, must be to recognize that “it’s not your father’s oil industry anymore.”1 The major elements in the recent transformation are price volatility and a general decline in the value of production, particularly of crude oil in the upstream sector. Oil prices declined from $39 per barrel in 1981 to $12 (nominal) in 1986, followed by a run-up that reached $33 (nominal) in 1989 and a drop to $20 a year later; thereafter it rose to $20 in 1996 and fell again, stabilizing briefly at $10 per barrel in 1998 before it shot back up to $34 in March of 2000. Restated in real (2000) dollars, the swings moved from $73 per barrel in 1980 to a low of $10 in 1998.2 The progressive deregulation of natural gas, beginning with the US Natural Gas Policy Act of 1978, revolutionized the sale and marketing of natural gas, producing occasional
* Corresponding author. E-mail address: [email protected] (R.M. Olien). 1062-9769/02/$ – 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 3 4 - 5
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“bubbles,” excess supply, and in tandem with environmental regulation, encouraged increased consumption of it. Recently, these changes and seasonal demand produced a steady increase in the price of gas, from $4.26 per thousand cubic feet at the well head in September 2000 to $6.35 in December, and $8.06 in January. Thereafter, the price declined to $5.15 in March. In the short-term, at least, natural gas became the hydrocarbon of choice for producers, leading to additional drilling in the Delaware Basin of Texas and to additional searches for natural gas in offshore areas.3 Price volatility and the increased value of natural gas led explorationists to seek the latter and to reenter existing fields to drill additional wells. The sharp swings in oil prices and the decline of reserves in the lower 48 states encouraged larger producers to seek more substantial reserves abroad and in the deep waters (in 1,000 feet of water or more) in the US sector of the Gulf of Mexico, shedding declining properties to the independents, exploitationists who worked to squeeze additional oil from mature fields. In declining markets, with weakening competitive positions, some of the larger companies had to lower costs. While Mobil paid $3.67 per barrel to replace reserves during the early 1990s, replacement costs for Amoco and BP respectively were $5.45 and $6.10. BP’s response to cost problems was to pull out of exploration in the Lower 48 in 1991, while other companies rationalized but kept core assets.4 The independent US wildcatter, once the typical small explorationist who drilled in geological frontier areas, now struggles to keep domestic stripper wells pumping, while larger producers take geological risks in frontier areas. In the downstream sector, massive shifts of ownership and operation stemmed from federal regulation, the changing prices of crude oil and natural gas and the emergence of large-scale competition in the production of basic petrochemicals. By 2001, the American refining industry was smaller than it had been twenty years earlier and the major players in the US petrochemical industry had shifted to the production of specialized chemicals, a part of that industry that has always been highly responsive to demand cycles and even more capital intensive than basic chemicals. The stakes got higher and the odds got longer. One of the most visible changes in the petroleum industry is that there are fewer players. Every major swing in the price of oil, gas, and refined products drove mergers and acquisitions, restructuring and reconfiguration of major firms, implementation of new costsaving technologies, and cuts in work forces. Perhaps the most obvious evidence of change has been the disappearance of the “seven sisters,” the multinational, multidivisional corporations that were long dominant in national and international trade. Of the seven, Exxon, Chevron, Shell, British Petroleum, Mobil, Gulf, and Texaco, only the first four-named still exist as they did in 1980. Chevron acquired Gulf and Texaco, and Mobil merged with Exxon. The “sisters” had seemed as immutable as the Soviet Union, but Gulf succumbed because of poor performance and Texaco and Mobil were acquired/merged as other giant corporations sought economies of and scale enhanced asset bases. John D. Rockefeller’s original Standard Oil Company of Ohio (SOHIO) and Amoco(Standard Oil of Indiana) were both acquired by British Petroleum, which had acquired Sinclair’s down stream assets—principally 10,000 gasoline stations and two refineries—when ARCO bought Sinclair in 1968.5 Big oil has gotten bigger. Second-tier companies, such as Phillips, Marathon, Conoco, Occidental, and Kerr-McGee
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also went through major transformations, launching aggressive acquisitions campaigns. For example, after Conoco was spun off by DuPont Company in 1999, it made extensive buys in the Permian Basin and Canada, making it the tenth largest investor-owned oil and gas company in the United States. Kerr-McGee increased its presence in offshore US areas and in foreign regions, as did Phillips. From time to time all of them, like the larger companies cut payrolls as prices plunged. Phillips, for example slashed its workforce by about 10% during the dark days of 1986.6 As usual with large mergers, payrolls were cut as redundant positions were eliminated. Thus, after Chevron bought Gulf in 1984, the combined global work force was cut from 79,000 to 61,000 within four years.7 Mergers, however, accounted for fewer lost jobs than the widespread reorganization of companies, as they scrambled to maintain financial performance standards during downturns. Initially, the slow down in exploration led to cuts in geophysical and geological staffs. During the late 1980s, for example, US unemployment rates among geologists ranged from 28% in Midland to 34% in Denver and 39% in Oklahoma City.8 By the end of 1991, employment in the North American industry had fallen to 350,000 from its 1982 peak of 754,500 people. The service sector was hardest hit as nearly two-thirds of the jobs were eliminated. As a result, at the present time the industry faces shortages or potential shortages in many job categories. This problem will probably become more acute because within most companies there is a significant age-disconnect because there are relatively few workers between the ages of 35 and 50. Margaret Carriere, vice president of human resources of Halliburton, estimates that the industry could lose 60% of its “top talent” by 2007. Shortages are especially critical in petroleum engineering, which now finds it difficult to attract students because of the cyclic nature of the industry and its history of cutbacks.9 The consolidations in exploration and production were mirrored by changes in the service sector of the petroleum industry. During the 1980s, the downturn led to failure of even large companies, such as Western. Other diversified companies sold petroleum industry-related assets. Thus, Fluor sold its oil and gas operations to Houston Industries which was later acquired by Schlumberger, which also bought Western Geophysical in 2000. By the end of 2000, Halliburton, the other giant among service companies, had acquired M. W. Kellogg, the dominant engineering firm, and Dresser, the leader in production services, among other companies.10 Consolidations were massive in the drilling and equipment sectors. Thus Baker International merged with Hughes Tool in 1986 to become Baker/Hughes. The price downturn of 1998 placed Reading & Bates Corporation in a weak debt position and it was acquired by Falcon Drilling, which also bought Cliff’s Drilling Company. The relative lag in day rates, in turn, undermined the financial position of R & B Falcon, which was acquired by another product of recent mergers, Transocean Sedco Forex, Inc, in the early months of 2001. In midyear, Pride International, Inc., and Marine Drilling Companies, Inc., also merged, creating a company with 10,000 employees.11 As the real value of oil declined, companies commonly sought economies through elimination of layers of management. Unocal, for example, trimmed supervisory levels from
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six to eight, cutting its workforce by 2%.12 During the next decade British Petroleum removed layers of management by reorganizing Amoco, which had already cut 8500 jobs between 1988 and 1992, eliminating 59 of the 86 head office committees, firing 160 of 540 managers in Cleveland’s SOHIO headquarters, trimming 3800 jobs by 1994.13 With fewer management tiers, some companies reorganized work by creating interdisciplinary teams in exploration and production and out-sourced work, saving time and money by delayering and wage and benefit costs by contracting out accounting and other office work. In response to low and volatile prices, producers also re-examined properties during the 1980s, shedding some and acquiring others, a process that continues. In 1990, Chevron sold nearly two-thirds of its US oil and gas properties and bought Tenneco’s Gulf of Mexico holdings.14 When Santa Fe Energy spun off Monterey Resources in 1997, Texaco made the buy to boost its production in California, where it continued to refine crude oil.15 Mobil sold its interests in 27 Permian Basin fields to Titan Resources, a large Midland-based company in 1997. More recently, in 1997, Kerr-McGee sold large working interests in five offshore blocks to the Offshore Oil and Gas Corporation, a Houston-based subsidiary of the China National Offshore Oil Company.16 Buying, selling and swapping, always fast-paced in the petroleum industry, now move at the speed of corporate jets and computers. Some companies reorganized their operations to encourage effective adaptation to rapidly changing conditions and related opportunities. ARCO, the most successful at strategic reorganization, created ARCO Permian to manages and expand its assets in its largest concentration in the Lower 48, then spun off Vastar to do the same with off-shore properties. ARCO Permian proved to be highly entrepreneurial and cost effective. Vastar, specializing in shallow water, complex geological formations and problematic reservoirs, built a 71% success rate and drilled 40 wells on the Outer Continental Shelf in 2000 alone.17 Both ARCO Permian and Vastar were acquired by BP Amoco, through its purchase of ARCO. In the mature regions, large companies commonly combined operations in newly-formed firms. Thus Amoco and Shell combined Permian Basin assets into Altura Energy and Mobil and Shell formed Aera Energy to combine their exploration and production operations in California in 1997.18 Other US companies did spin-offs. Panhandle Eastern, largely a gas transmission company, spun off Anadarko, a production company, which acquired additional assets and became a significant player among medium-sized companies. The company became a regular participant in Gulf of Mexico projects, holding 37.5% of Phillips’s important Mahogany field. In 1999, it purchased a 50% working interest in 82 blocks held by Texaco in the Gulf of Mexico. With its purchase of Union Pacific Resources, Anadarko was the largest independent oil producer in the world.19 Sale of properties and company acquisitions created some large new US independents, including Parker and Parsley (which merged with Mesa Petroleum to form Pioneer in 1999), and Apache Corporation. The latter, on the scene in a relatively small way since the 1950s, moved to acquire properties from Hadson Energy Resources in Australia and other companies, then worked to offset mounting production costs by acquiring additional holdings, buying offshore US leases from Shell Offshore, Occidental, and Petsec, along with Canadian assets purchased from Phillips, Shell Canada, and Fletcher Challenge Energy. As part of its
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growth, the enlarged company bought holdings in Egypt along with sizable assets in the Permian Basin. With nearly $7.5 billion in assets, Apache achieved economies of scale in operations and became one of the world’s largest independent oil and gas exploration and production companies. During August and September of 2001, Devon Energy acquired Mitchell Energy of Houston, and Canadian properties, to become the largest independent in the world, as determined by oil and gas reserves.20 Trading properties was hardly new to the oil industry, but the direction of it was novel, as most of the larger producers invested in foreign and offshore US exploration and production, producing a massive shift in the ownership of the declining on-shore reserves. The repositioning of the large multinational companies is clearly reflected in the control of oil production in Texas. By January 2001, familiar names, Exxon/Mobil, Texaco, Chevron, ARCO, Conoco, and Phillips were present on the list of 100 largest producers, but there were notable changes since 1980 because of mergers, acquisitions and divestitures. The number one producer, long Exxon, was replaced by Occidental Permian, which produced 14% of the crude oil in Texas during that year. More notable, Texas, a mature geological province with declining production, had become the preserve of small producers. For example, the tenth largest Texas producer, Pure Resources, a Midland company, accounted for 1.9% of Texas crude. The 30th largest, Henry Petroleum of Midland sold 0.59% of total production in the state from February 2000 through January, 2001. The changes in the list of producers reflects shifting ownership patterns, the general decline of production to the point that the typical Texas oil well is far from a gusher—it now produces less than ten barrels per day and must be pumped to do even that.21 For anyone who had missed the results of the sweeping nationalizations by nationallyowned companies during the 1970s, R. Dobie Langenkamp, a deputy assistant secretary of the Department of Energy from 1976 – 81 and 1997–98, pointed out that the nationallyowned companies were, in fact, the largest oil companies in the world, displacing the surviving Four Sisters. In 1970, for example, Exxon produced 80% of its own crude. Ten years later, the number had fallen to 44%. By 2001, determined by reserves base, oil owned in the ground, Exxon/Mobil was the world’s 12th largest oil company, following the Brazilian national company, Petroleous Brasileiro (Petrobras) and just ahead of Russia’s largest oil producer, Lukoil. The second largest US company, Chevron, was 20th worldwide, following Pertamina, of Indonesia, and Dubai Petroleum, among others. The combined reserves of the top ten US oil companies amounted to less than those of Pemex (Mexico) and comprised less than four percentage of the reserves held by the ten biggest. The Saudi Oil Company dwarfed them all.22 The largest oil companies, faced with declining and increasingly costly onshore US production, ventured into the North Sea after the Ekofisk discovery in the Norwegian sector and into Alaska beginning in 1976, searching for larger plays. When Minerals Management Service, US Department of the Interior, instituted area-wide leasing in 1984, it was possible for companies to acquire enough contiguous leases to make billion dollar commitments in deepwater regions in the Gulf of Mexico. Improvements in 3-D seismography and the more rapid processing of data, and improvements in drilling and production technologies, have progressively supported exploration in ever deeper water. By 2001, investment in deepwater projects absorbs 40% of the capital invested in offshore exploration and development, with
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the large companies setting the trends. The high costs of activity in that arena has meant that seven companies, BP/Amoco, Shell, Exxon/Mobil, Chevron, Total/Elf, Petrobras, and Texaco have located more than three-quarters of the deepwater reserves. Shell, in particular, has advanced capital and technology to push the depth drilling record beyond 7,500 feet with major discoveries in the Mississippi Canyon in the US sector of the Gulf of Mexico.23 With the increasing investment and involvement of privately held companies in Russia and other component states of the former Soviet Union, new dimensions of political risk—largely exporting profits from operations— came into play as Chevron, Exxon/Mobil and other companies heavily invested in Caspian Sea-area plays.24 Other regions in Asia, offshore West Africa, Canada, South America, and Australia also saw large-scale searches for new reserves by the larger companies. All of these costly and risky investments in exploration have been conducted as joint ventures, producing a crazy-quilt of alliances of large and medium-sized firms. In the Kashagan field of Kazakstan, for example, shareholders include Exxon/Mobil, TotalFinaElf, BP Amoco, Statoil, Phillips, ENI and several smaller companies. In the Tengiz offshore field, Chevron holds a half interest with the balance divided between Exxon/Mobil and the Kazakstan government.25 Joint ventures of course, had been common before then. Aramco and CalTex were familiar models. Moreover, the practice of sharing risk in exploration with partners had been around for almost as long as there has been an American oil industry. In recent years, however, the practice has become standard practice because of the increase in costs and risk in the context of volatile prices. Thus both Shell and Exxon/Mobil have partners in deepwater Gulf of Mexico ventures, including Shell’s grand Mississippi Canyon plays and Exxon/Mobil’s Crazy Horse development. In its Ram-Powell field, Shell partnered with Amoco and Exxon. In its Ursa field, located in 4,000 feet of water, 130 miles southeast of New Orleans, Shell had a 45% stake, with BP at 23% and Conoco and Exxon both with 16% of the 400-million barrel field. In the giant Mars field, where development costs exceeded $1 billion, Shell partnered with BP. Most recently, Shell and Exxon/Mobil have combined to built a $159 million pipeline to deepwater fields.26 Over time, as risks and costs have increased, joint ventures, always common, have become the norm among larger companies. More extraordinary changes have occurred in the downstream sector of the American petroleum industry in response to price volatility and new standards of financial performance. The conventional observation that fully integrated companies were less vulnerable to short-term fluctuations of prices of raw materials and finished goods was discredited with the large crude price drops in 1982 and 1986, as refineries found the values of their feedstocks and inventories plummeting.27 The common assumption had been that when feed stocks were cheap, refiners and petrochemical producers were more profitable; conversely, when feed stocks were more costly, the advantage went to producers. Ideally, a company that operated in all phases of the petroleum industry thus enjoyed some protection from the effects of volatile markets. Over the medium-term, it would have balanced. For the large companies it did, over the medium term. But in the meantime, the expiration of the US federal import entitlements program deprived marginal refiners of income and the lag of product prices behind feedstock costs wiped out most small refiners. Between 1981 and 1985, more than 100 simply shut down; most of them found no bidders. In raw numbers,
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they comprised one-third of all of the refiners who had been in business during the earlier year.28 Since 1995, 24 additional refineries—many of them small independents– have shut down.29 Some of the closed operations were too small to realize economies of scale, or to afford the added cost of compliance with federal environmental regulation. Even large operations, such as the Unocal refinery in Beaumont, Texas closed because it was uneconomical for the company to invest in additional plant installations required to lower emissions through reformulation.30 Amoco also closed its refinery in Casper, Wyoming because adaptation to meet environmental standards was uneconomical. Since 1970, the US has lost nearly one-third of its refining capacity.31 Surviving US refiners coped with cost-price and financial performance pressures. When prices of feed stocks rose, refined product prices typically rose less rapidly, leaving net revenues flat and discouraging additional investment in refineries. Returns improved only as the industry got smaller, raising plant utilization rates to about 90% in 1998, for the first time in twenty years. As a result, the capacity of refiners to respond to seasonal demand for gasoline and heating oil diminished, a situation that has produced area shortages of special formula products.32 With the rise of imported refined products, a trend from the 1980s, American refiners were usually hard pressed to maintain minimally satisfactory rates of return on investment in plant. In the past, this implicit acceptance of definitionaly mediocre financial performance was acceptable because oil fared at least as well as other leading industries. In the context of financial markets during the 1980s and 1990s, however, past practice was inadequate. Simply put, investor-owned oil companies found it difficult to defend levels of performance inferior to lead industries to institutional and foreign investors, increasingly powerful in securities markets. When electronics, telecommunications, e-commerce, and even real estate investment trusts were out-performing them, oil companies simply had to do better to attract and hold investment capital. As their control of reserves declined, from the 1970s onward, they found it necessary to try other common remedies for inadequate financial performance. During the cash-rich days of the late 1970s and early 1980s, oil companies pursued diversification strategies to offset cyclical declines in petroleum and to share technologies. The best known examples at the time were Exxon’s purchase of Reliance Electric, based on assumed mutual technology transfers from the oil company’s research and development activity with the office systems company. Farther afield, Mobil, a leading retailer among oil companies, purchased ailing Montgomery Ward.33 Less well known diversifications included heavy investments in real estate, as with Mitchell Energy’s Woodlands project north of Houston, and narrower diversifications into other energy areas such as shale oil extraction, geothermal power generation, and nuclear projects. Though many of the diversified purchases, notably Exxon’s and Mobil’s, have been sold or closed, changes in regulations and markets continue to encourage near-process diversification. Recently, Shell purchased 50% of Integen, a power-generating subsidiary of Bechtel Corporation.34 From the 1980s onward, downstream US properties have also been swapped, sold, and brought into joint ventures as companies reacted to costs of meeting environmental regulation, rising costs and volatile prices. Some of the sales were logical outcomes of redundant acquisitions. Thus Chevron sold old Gulf Oil refineries, including the giant Port Arthur,
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Texas plant to Clark Refining & Marketing and the Philadelphia refinery to Sun.35 Similarly, Unocal sold West Coast refining, marketing, and transportation acquired in its acquisition of Pure Oil to Tosco, already a large independent refiner.36 The petrochemical industry, always hyper-competitive and fast-moving, underwent similar changes. During the 1970s, US companies enjoyed competitive advantages over foreign competitors because of federal regulation of interstate natural gas prices. Those who used by-products of oil refining benefited from long-term contracts for federally regulated “old” oil, frozen at $5.25 per barrel.37 With the removal of price regulations during the Carter administration, these advantages were lost; foreign competitors moved into the production of basic chemicals as nationally-owned oil and gas production companies sold feed stocks to their refiners and petrochemical operations at prices below world market levels.38 Petrochemicals were also hit with mandatory investments to meet US federal pollution standards. The leading trade periodical, Hydrocarbon Processing, estimated the 20-year cost of environmental compliance to 2000 at $50 billion in year 2000 dollars.39 Emissions and water disposal were especially costly problems along the Texas Gulf Coast. Citing compliance costs, Cities Service withdrew from petrochemicals in 1982, when industry operating margins were -1.3%, down from 3.5% the year before.40 The petrochemical section of the industry had always been the most highly responsive to changes in the general economy, declining during downturns as specialty chemical installations and finished goods producers cut orders. The global industry also suffered perennially from excess capacity in basic chemicals, where processes enjoyed relatively little protection from patents and technology could be purchased “off the shelf” by any company with sufficient capital. In 1993, even after adjustments in production had been made, the US industry operated at only 70% of capacity, a critically low level in capital-intensive, continuous-process manufacturing.41 Whenever the cost of feedstocks rose in the United States, companies had to invest in efficiency-boosting improvements to hold competitive position with lower cost processors in the Middle East and Asia. By 1986, the production of basic petrochemicals was declining sharply in the US in the face of these challenges, and major producers were investing in the production of specialty products, where they enjoyed technological superiority.42 Some producers chose not to make the conversion. American Hoechst, for example, sold its polystyrene plants to Huntsman Financial Corporation, the leading producer of that product in the United States. Hoechst merged its remaining petrochemical plants with Celanese in 1987, the year after the sale.43 As the process of divesting proceeded in petrochemicals, even large companies withdrew: Texaco also abandoned petrochemical production in Texas, selling its Gulf Coast operations to Huntsman.44 All of the larger companies reassessed their investments in exploration, production, refining, petrochemicals, and distribution, producing an extended series of divestiture that restructured the downstream sector of the industry. Both Tosco and Valero, a San Antonio company, became large-scale refiners as they acquired properties shed by large companies. Thus Exxon/Mobil sold its west coast refinery and retail assets to Valero, which had acquired Mobil’s Paulsboro refinery earlier. In 2001, Valero, which began as a part of LoVaca Gathering Company, a natural gas subsidiary of Coastal Corporation, acquired Ultramar Diamond Shamrock to become the second-largest refiner in the US, after Exxon/Mobil. Exxon/Mobil also sold 1,740 retail outlets in the northeast and mid-Atlantic to Tosco, which
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went on to acquire BP’s West Coast refinery.45 Texaco reassessed its “sell in all of the 50” retailing policy and withdrew from parts of the Upper Middle West and Northern Rockies in 1980.46 In refining as in domestic production, the large oil companies abandoned the traditional model of vertical integration, leaving large parts of the field to aggressive independents. The dominant financial strategy, asset/portfolio management, also led the large companies to lower their exposure to the risk of lower performance in downstream activities by entering into alliances across the country. Thus, Texaco formed Star Enterprises in partnership with Saudi Refining to operate refineries in Delaware, Louisiana and Texas and to market in 26 states.47 Shell entered joint ventures with Texaco, creating Equilon and Motiva in the downstream sector.48 In petrochemicals, alliances were also common with even industry giant Shell joining with Himont Chemicals to form Montell Corporation to produce chemicals in fifteen plants and Union Carbide forming an alliance with Kuwait Petroleum. Within the industry, Exxon and Union Carbide, Dow and British Petroleum combined in ventures and all of the large producers sought alliances with large foreign national oil companies.49 Capital intensity, fast-moving technology, and movements in US utilization rates between 70 and 96%, varying by year and product, all transformed a major American industry. By 2001, the model of functional integration, from exploration to production, transportation, refining, and marketing, long the dominant model for large and medium-sized oil companies, had undergone major change. The original Standard Oil model, described as normative in oil and other industries by Alfred D. Chandler, Jr., and other scholars had been displaced by asset management strategies, alliances, partnerships, and divestitures. One of the trends that appeared during the 1980s continued thereafter as foreign, nationally-owned oil companies bought increasingly large access to the US market. Mexico (Pemex), Venezuela (PDVSA), Saudi Arabia (Aramco), and other countries became partners and owners of refineries. Union, for example, sold a 50% stake in its Chicago refinery to Venezuela, which had already taken over Champlin Refining during the 1980s. In 1992, Pemex obtained a 50% interest in Shell’s Deer Park, Texas refinery, which was capable of processing heavy Mayan crude.50 Lukoil recently bid for 1300 US service stations.51 The foreign nationals have also taken a strong interest in exploration in the Gulf of Mexico, reflected in the Houston offices maintained by Norway’s Statoil and other companies. In 2000, Exxon/Mobil and Italy’s Agip Petroleum Exploration (ENI) formed an alliance to develop up to 259 blocks in the Gulf of Mexico over a five-year period.52 Clearly the increasing presence of non-US and noninvestor-owned companies reflects the sea change in the world petroleum industry. The continued volatile economics of oil and gas, reorganization, down-sizing, and globalization of the petroleum industry now pose special challenges for would-be US regulators. The loss of refinery capacity and the increasing importation of refined products will keep domestic supplies and margins thin. Further regulation will make domestic refining and petrochemical operations even less profitable, leading to further reductions in capacity and increased reliance on foreign refiners. In exploration and production, withholding potential domestic areas from exploitation will reinforce the foreign activity of large privately-owned companies and strengthen the market positions of the noninvestor-owned foreign producers, whose refineries would gain market advantages over US refiners, while doing little to lessen
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industrial emissions around the world. Capping natural gas prices, similarly, will discourage exploration, lower domestic production, weakening feed stock supplies of American chemical companies and, thereby, enhancing the competitive positions of foreign processors to the disadvantage of American workers, consumers, and investors. Globalization has placed the creation of an effective and equitable energy policy beyond our reach, when we try to enact it through restrictive law and regulation. The principal reality of 2001 is that it’s not your father’s oil industry anymore, unless your father is a Saudi, a Brazilian, a Mexican, an Angolan, an Indonesian . . . . Regulations that do not take full account of this reality will certainly worsen the conditions they are intended to remedy.
Notes 1. For my view of policy gyrations to 1945 see Roger M. Olien and Diana Davids Olien, Oil and Ideology: The Cultural Creation of the American Petroleum Industry (Chapel Hill: The University of North Carolina Press, 2000). 2. Stephen P. A. Brown and Mine Y. Yuecel, “Oil Prices and the Economy,” Southwest Economy (Federal Reserve Bank of Dallas), July/August 2000, 2. 3. Energy Information Agency, “Monthly Gas Report, March, 2000,” 9 –11; an overview of regulatory changes is provided by Arlon R. Tussing and Bob Tippee, in The Natural Gas Industry: Evolution, Structure, and Economics, Second edition, (Tulsa, OK: PennWell Books, 1995). 4. Petroleum Economist, November 1991, 35. 5. On BP see James Bamberg, British Petroleum and Global Oil, 1950 –1975: The Challenge of Nationalism (Cambridge, UK: Cambridge University Press, 2000), 273– 6. 6. Wall Street Journal, May 30, 2001, 12. 7. Petroleum Economist, November 1989, 362. 8. Oil and Gas Journal, November 13, 1989, 28, 36. 9. Midland Reporter-Telegram, May 3, 2001. 10. Petroleum Economist, November 1985, 422. Perry A. Fischer, “Western and Geco Merge,” World Oil, July 2000, 25. 11. St. Paul Pioneer Press, May 25, 2001. 12. Oil and Gas Journal, March 6, 1989, 23; May 15, 1989, 14. 13. Oil and Gas Journal, May 11, 1992, 26; July 13, 1992, 19; May 16, 1994. 14. Oil and Gas Journal, May 11, 1992, 26; Petroleum Economist, December 1995, 15. 15. Petroleum Economist, October 1997, 59. 16. Petroleum Economist, December 1997, 44. 17. Jeane M. Perdue, “Shallow Waters: The ‘Other’ Gulf,” Hart’s E & P, April 2000, 69; Petroleum Economist, November 1999, 57; World Oil, July 2000, 31. 18. Petroleum Economist, January 1997, 54. 19. Petroleum Economist, May 1995, 57; November 1999, 43. 20. Petroleum Economist, December 1993, 51; United States Securities and Exchange Commission, Form 10-K: Apache Corporation, for the fiscal year ended December
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21. 22.
23.
24. 25. 26. 27. 28. 29. 30.
31. 32. 33. 34. 35. 36. 37. 38. 39. 40. 41. 42. 43. 44. 45. 46. 47. 48.
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31, 2000, 24 –5; Apache Corporation, 2000 Annual Report, 2; Dallas Morning News, September 6, 2001. Railroad Commission of Texas, “Texas Largest Oil Producers, February 2000 through January, 2001,” Computer Report (OLN261), March 21, 2001, 1–2. Donald O. Croll, “The Majors in Transition,” Petroleum Economist, May 1980, 189; R. Dobie Langenkampf, “U.S. ‘Big Oil’ Companies: Getting Smaller in the Real World,” Houston Chronicle, December 31, 2000, C-1. M. Liliana Riahi, “Deepwater Exploration in the Gulf of Mexico,” Hart’s Petroleum Engineer International, April 1998, 63, 64 –5; “Deepwater Dilemma,” Hart’s E & P, April 2000, 84 –5; World Oil, March 2000, 3. “Fifty Years of the Oil Industry,” Petroleum Economist, September 1983, 326. Wall Street Journal, March 21, 2001. Petroleum Economist, October 1993, 65; September, 19995, 80; August 1996, 49, October 1997, 60; Midland Reporter-Telegram, May 27, 2001. G. M. Intille, “How Refineries Inventories Threaten Profitability,” Hydrocarbon Processing, July 1986, 92. Houston Chronicle, June 2, 1985. Dallas Morning News, June 15, 2001. Hydrocarbon Processing, June 1988, 13; December 1989, 69; Houston Post, July 21, 1991; Texas Comptroller of Public Accounts, Forces of Change, Volume II, Part I (Austin, November 1993), 27. Oil and Gas Journal, July 13, 1992, 19 Hydrocarbon Processing, November 1994, 29; March 1996, 25; March, 1998, 31. Petroleum Economist, February 1987, 2. Oil and Gas Journal, April 2000, 68. Petroleum Economist, December 1995, 15. Petroleum Economist, May 1992, 40; January, 1993, 41; March 1994, 48; May 1994, 60; February 1997, 52. Houston Chronicle, January 15, 1975; March 10, 1977. Dallas Morning News, April 19, 1985. Hydrocarbon Processing, December 1990, 58 – 60. Houston Chronicle, July 25, 1982; January 6, 1984, 16A. Houston Chronicle, March 29, 1993. Houston Chronicle, May 20, 1984. Hydrocarbon Processing, February 1986, 8; May 1986, 26; August 1986, 19; April 1987, 25, 31; May 1987, 431; May 1988, 29. Petroleum Economist, July 1997, 50. Petroleum Economist, January 1993, 41; October 1993, 64; January 1997, 54; April 2000, 68; Midland Reporter-Telegram, May 20, 2001. Petroleum Economist, May 1979, 205. Oil and Gas Journal, September 28, 1992, 104; Petroleum Economist, September 1997, 124. Oil and Gas Journal, December 21, 1998, 31.
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49. 50. 51. 52.
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Hydrocarbon Processing, March 1996, 27;March 1998, 25, 27, 29. Petroleum Economist, July 1988, 250; January 1989, 38; September 1992, 46. Petroleum Economist, January 1982, 39. Langenkamp, “U.S. ‘Big Oil’ Companies.” Petroleum Economist, June 1997; World Oil, July 2000, 31.