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16-Mar-2016
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Feasibility of Petroleum Industry Divestiture

Walter S. Measday

Chief Economist,
Senate Antitrust &
Monopoly Subcommittee

R & D in Energy: Implications of Petroleum Industry Reorganization,
Proceedings of a Conference held at Stanford University,
September 20-21, 1976;
Institute for Energy Studies,
Stanford University.

The proceedings were divided into two halves, each half consisting of four papers followed by an edited transcript of a panel discussion. My father's paper appeared in the second half and the discussion seemed to be largely devoted to beating up on what he had said in his paper; also included in the transcript, but not part of the actual discussion, was a written critique of my father's paper by a senior Exxon economist.

I was a little miffed at first, but then I looked at the first half's panel discussion in which everyone was beating up on Paul Davidson, another economist (famous, to boot!) who favored divestiture of the petroleum industry—my father was in good company. Again, there was a written critique of Professor Davidson's paper by the Exxon economist. Regardless of the merits of the various arguments, I have to give Professor Davidson the award for the best line of the conference: "I think that you're looking at the hole and I'm looking at the doughnut!"

Two or three years ago the idea of legislatively restructuring any major U.S. industries was the private preserve of a handful of industrial organization economists. For the record, we should note that their economic philosophies should be described as 19th Century Liberal rather than 20th Century Radical. They accept more seriously than do most people the basic economic requirements for the successful functioning of a free-enterprise, capitalistic system. The area was a private preserve not because of any barriers to entry, but because the vast majority of economists saw no reason to waste their time on such an impractical subject.

For the past three Congresses, Senator Philip A. Hart has introduced an Industrial Reorganization bill, to create a commission and a special court with a broad mandate to restructure a number of basic industries. There has been no roaring groundswell of support for the measure. Indeed, it has not even come to a vote in the Senator's own Subcommittee on Antitrust and Monopoly.

The crisis atmosphere generated by the Arab oil embargo of October 1973 and the subsequent rise in petroleum prices and oil company profits served to narrow the focus of interest from the broad range of industrial activity down to the petroleum industry. Congress's instinctive reaction was to create a new regulatory bureaucracy and a comprehensive system of controls through the Emergency Petroleum Allocation Act of 1973.

Meanwhile, however, there has been a resurgence of interest in divestiture, including both functional vertical divestiture within the petroleum industry and horizontal divestiture to prevent leading petroleum companies from dominating alternative sources of energy. Still, the approach was known to be politically impractical—few people, least of all the oil company representatives, took it seriously. When Senators Philip Hart, Bayh, Abourezk, Tunney, and Packwood introduced S. 2387 on September 23, 1975, the usual question asked by lobbyists was whether the five cosponsors really thought they could get another five Senators to vote with them if the measure ever came to the floor.

Less than three weeks later a vertical divestiture amendment to a natural gas deregulation bill lost by the narrow margin of five votes, 54-45. S. 2387 was reported out of the Antitrust Subcommittee, after extensive hearings, on April 1, 1976, and out of the full Judiciary Committee on June 15. Suddenly, divestiture has become a relevant issue. The extent of its relevance can best be measured by the magnitude of the industry's effort to sway political and public opinion against the idea.

A brief description of the present structure of the industry is essential to an understanding of potential petroleum legislation. A convenient starting point is the levels of concentration in the various functions.

At the crude oil level, industry propaganda tells us that there are some 10,000 producers, which is about as good a ballpark figure as any. Entry into the industry is easy on a small scale, since the minimum requirement is a single well producing enough oil to cover royalties and operating costs. Exit, of course, is equally easy, as a number of investors in dry holes have learned to their sorrow. Nevertheless, according to the Bureau of the Census, in 1974 the eight largest companies (on a gross operator basis) accounted for 54 percent of the nation's production of crude oil and condensate, while the twenty largest produced 76 percent of the total. [1]  Further, concentration has been increasing rapidly in recent years. In 1955 the eight largest companies had only 36 percent and the twenty largest, 56 percent of the market. [2]  Note that the market share of the eight largest rose by nearly 18 percentage points, while that of the next twelve firms rose by little more than 2 percentage points.

At the refining level, concentration has been remarkably stable over the same period. From the 1954 Census of Manufactures on, the eight largest refiners have accounted for roughly 56 percent and the twenty largest for 84 percent of the industry's value of shipments.

The stability of market shares in the refining sector is noteworthy during a period of market growth, less than 7 million b/d in 1950 to nearly 17 million b/d at present. Equally noteworthy has been the relative scarcity of new entrants, despite what the industry has claimed about ease of entry into the refining sector.

Professor William Johnson, George Washington University, has presumably identified 13 substantial new entrants from 1950 to 1975 in a frequently-cited study. [3]  "Substantial" is defined to include "grassroots" new entrants (six firms) who have entered de novo and constructed at least 50,000 b/d of capacity, and firms (seven) which have entered by acquiring existing refiners whose capacities have been expanded by at least 50,000 b/d.

His grassroots entrants include three offshore refineries, one of which (Hawaiian Independent) does not serve the domestic market. One of the other two was established and both have survived primarily through the grace and favor of the federal government. Of the three firms designated as onshore grassroots entrants, two are incorrectly identified, having entered by the acquisition of existing capacity. This leaves one really new entrant, the ECOL refinery now under construction and scheduled to go onstream later this year.

There are similar errors in the identification of firms which have expanded acquired capacity by at least 50,000 b/d. At best, we can say that five companies have entered by acquisition and subsequently expanded capacity substantially, while one really new entrant will appear this year. This hardly qualifies as proof that entry into refining is an easy matter.

Little can be said about the marketing function, since data are virtually nonexistent except for gasoline retailing. What we can say with some confidence is that in the retail gasoline market, the share of the traditional 16 majors declined from something over 80 percent in 1968 to about 71 percent by 1974 for sales under their own brands. This erosion can be traced to the expansion of price-competitive non-integrated marketers and independent refiners integrating forward into marketing.

Whether this loss of major market shares would continue in a reasonably tight market is questionable. At the time Congress passed the Emergency Petroleum Allocation Act, it was evident that independents were seriously threatened with loss of supplies. A recent article in Forbes, however, suggests that in order to defuse the bomb of divestiture, "most major oil firms are artfully giving up market share in gas to the independents." [4]  The writer goes on to point out that the companies are giving up branded operations in competitive, low-margin regions: "You give something up, but what you give up you didn't really want." Whether or to what extent this does take place, gasoline marketing appears to be highly competitive. Looking solely at the retail gasoline market, it is hard to find fault with Union Oil's famous "What a way to run a monopoly!" advertisement featuring 72 marketing logos.

In short, available statistics provide a surface appearance of moderate concentration—far less, for example, than one can find in a number of other industries ranging from automobiles and computers to men's underwear and paper napkins. What concentration ratios do not provide is insight into a variety of institutional factors which effectively compound the effect of concentration.

First, of course, there is vertical integration itself. The companies which are dominant at any one level of the industry are dominant in each of the other levels. To the extent that they can exert market power at any level, they can exert it at all levels.

This is especially evident with respect to the control of crude oil. For one thing, the major companies have the financial resources to hold huge inventories of lease acreage. Shell, for example, reported leases last year in the lower 48 states alone of 8.6 million acres—nearly 13,500 square miles. The existence of thousands of small producers depends upon their ability to negotiate farmout agreements permitting them to drill upon major company acreage. Almost invariably farmout agreements give the leaseholder a perpetual call on all the oil produced on the farmout. The leaseholder, in other words, gives up the right to produce some of the oil from his lease, but retains the power to control the disposition of that oil.

Next, the system of gathering and trunk pipelines is crucial to the movement of oil from the fields to refineries. Technically, under state and federal law most of these lines are common carriers; in fact, the common carrier obligation is rarely enforced. Nearly all independent crude oil is sold at the wellhead to purchasers who own the pipelines serving particular fields. In the words of Kewanee Oil's 1974 Annual Report:

As an independent oil and gas producer, crude oil and natural gas production is sold at the wellhead to major oil pipeline companies and [Kewanee] has very little control of the price it receives for its products.

We should note that Kewanee's production is only about two percent that of Exxon or Texaco, but it is still within the 30 or 35 largest producers among those 10,000 the industry tells us about.

The companies that own the pipelines, then, to a large extent control the oil that moves through those lines and determine the allocation of that oil to non-integrated refiners. And from the I.C.C. statistics for 1973, we learn that 92 percent of the crude going into reporting lines went into lines owned individually or jointly by the sixteen majors. [5]

Third, there has not been for years a meaningful crude oil market within the United States. Most crude oil is bought and sold under exchange agreements—i.e., the buyer of "x" amount of oil for his refinery at a particular location agrees to sell an equivalent amount back to the seller at another location. [6]  Now, within an environment of vertically-integrated firms—and this condition must be emphasized—such exchanges make considerable economic sense. What they do, however, is replace a competitive market with a network of bilateral or multilateral barter transactions from which non-integrated firms can be easily excluded as first purchasers of crude and which, by their very nature, must be less efficient allocators of resources than open markets would be.

A final institutional factor is the prevalence of joint ventures through which every major company is linked to its leading competitors. Joint ventures are largely confined to production and pipelines within the United States, since the industry appears to feel that there are excessive antitrust risks in overt joint refining and marketing operations. Overseas, however, they cover the whole range of industry activity, from Aramco (Exxon, Texaco, Socal, and Mobil) to the Irish Refining Co. (Exxon, Texaco, and Royal Dutch/Shell). The standard industry argument that joint ventures provide a means for risk-sharing among the participants cannot be rebutted. On the other hand, from the social point of view, it is clear that every joint venture provides an interface among companies within which cooperative behavior may be more profitable than competitive behavior.

A classic example is the Cal-Tex Group of companies through which Texaco and Standard Oil of California have jointly operated many of their foreign assets for the past 40 years. A trade publication recently noted:

Caltex's profits accounted for 59.5% of Texaco's total profits [in 1975], up sharply from 37.3% and 26.5% in the two previous years. For Socal, the reliance on Caltex also increased, but less sharply, rising to 63.9%, from 59.3% and 40.5% of Socal's total profits in the two previous years. [7]

Surely a reasonable man is entitled to ask, "Are Texaco and Socal competitors or are they partners?" This situation is unusual only in that the Cal-Tex owners provide financial information on the group's operations. If similar information were available for all joint ventures, the major petroleum companies would find it a little difficult to maintain their image of tigerishly aggressive competition in the industry.

No discussion of the oil industry today can ignore the importance of the Organization of Petroleum Exporting Countries. Domestic production peaked in 1970 at 9.7 million b/d of crude and condensate and has been declining ever since; 1976 production will be on the order of 8.0 million b/d. Refinery crude oil runs this summer have been running close to 14 million b/d. It is clear that for the next ten years, and probably longer, we will be dependent upon crude oil and product imports from OPEC sources, and, absent government controls, OPEC crude prices will determine domestic prices.

The emergence of OPEC as a viable cartel during the past five years adds a new element to discussions of the industry. In our preoccupation with "what the Arabs did to us," we are apt to overlook the fact that OPEC has simply taken over ownership of production from the private cartel of international majors who developed their control over both production and marketing of this oil over half a century. Iran nationalized ownership of its reserves 25 years ago; Venezuela did it last January 1; Saudi Arabia and Aramco are finalizing the details of nationalization. Host government ownership of reserves is no longer a question, but a fact. The question for the next few years is control over marketing.

When participation, originally at the 25 percent level, was implemented in 1973 in the Mideast, it was expected by producers and consumers alike that national oil companies would rapidly expand their direct marketing of crude. Had these expectations been realized, OPEC pricing would probably have become more competitive in a relatively short time. There have been charges and countercharges among member nations of price cheating on direct sales at every OPEC meeting. This practice, or even the belief that it occurs, has been the principal rock upon which cartels have foundered.

Unfortunately, the trend over the past year has been in the direction of reaffirming the international majors' control over the marketing of OPEC oil. This is particularly true in the case of Saudi Arabia, which itself produces enough crude to dominate the world market price. It appears that Saudi Arabia has agreed that Petromin, the state company, will retain five percent of production for domestic use and to extend contracts entered into in 1973 and 1974; 95 percent will be marketed by the four Aramco owners.

So long as they can control the marketing of OPEC oil, the integrated majors have little reason to oppose OPEC price increases. They can pass such increases through into the prices of their own products secure in the knowledge that competitors, who are also their customers, are not getting oil any cheaper. They may, indeed, enjoy positive benefits from OPEC price increases through the enhanced values of the reserves which they still possess.

The Prudhoe Bay field alone provides an example here. Each one dollar increase in the value of a reserve barrel raises the North Slope assets of Exxon, Atlantic Richfield and Sohio/BP by a minimum of $10 billion and probably much more—the improvement in asset values is none the less real because it is off-balance sheet. A good case can be made that had it not been for the Arabs, the North Slope would have been a financial diaster, given the escalation in pipeline construction costs. As it is, a recent estimate forecasts profits in the range of $2.00 a barrel for production delivered from this area. [8]  Similarly, North Sea oil has been made profitable only through OPEC actions. There is, in short, no great divergence—now that OPEC ownership of its own reserves has been accepted—between the interests of the international majors and the interests of OPEC member nations.

Horizontal expansion of oil company operations into fuel sources other than oil and gas may be dealt with more briefly. We can concede that this represents rational corporate growth strategy at a time when the companies are losing control over their foreign reserves and secure domestic reserves are declining. Still, economic theory has stressed the importance of interindustry competition, when the products of two or more industries are actual or potential substitutes, as a check to the exercise of market power in any one of these industries.

The data in this area are sketchy, although hopefully a current study by the Federal Trade Commission will fill some of the gaps. What we do know is that eleven of the sixteen traditional major oil companies, and several smaller companies, have substantial interests in the coal industry. They appear to account for about 20 percent of current production, but they also appear to own 40 percent or more of all privately-held coal reserves. [9]  Similarly, in 1973 oil companies are said to have accounted for 28 percent of U3O8 milling output, but to have owned 50-55 percent of the uranium industry's reserves. [10]  These percentages must have increased sharply since 1973, with Exxon's milling operations growing from zero in mid-1972 to 8 percent of the market in 1975 [11], with the purchase of a controlling interest in AMAX by Standard of California, and with Atlantic Richfield's acquisition of Anaconda. We know enough, in other words, to say that oil companies, alert to the potential need for alternate fuels, are making great efforts to secure their own positions in the production of those fuels.

The question which occurs to the economist here is the impact on interfuel competition. Would Continental Oil encourage price and market competition between Consolidation Coal and its traditional oil operations? Would Union Oil push geothermal development in an area where it might cut into the market for Union's fuel oil? The question extends to the exploitation of successful R&D. According to Senator Bartlett (R., Oklahoma), 49 of 52 patents relating to coal gasification or liquefaction issued from 1964 to 1974 went to oil companies. [12]  Let us make the highly unlikely assumption that an oil company with extensive foreign investments was to achieve a technological breakthrough which could make the United States self-sufficient in energy. Would Exxon enjoy telling Sheik Yamani or would Occidental inform Col. Qadaffi that no more Saudi Arabian or Libyan oil would be lifted for the U.S. market? Or would there be some temptation to delay exploitation of the technology until "it's really needed"?

It is questions such as these which have led to legislative proposals for both vertical and horizontal divestiture. Two bills can be taken as representative. S. 2387, as reported out of the Senate Judiciary Committee, would require worldwide separation of crude oil production from refining and marketing for some 18 companies, the 16 traditional majors plus Ashland and Amerada Hess. [13]  All oil companies would effectively be required to divest their pipeline interests, with some small exceptions. The purpose of this bill is to create a crude oil market, accessible to all refiners on equal terms, and to ensure a true common carrier pipeline system for the transportation of crude and products. S. 489, introduced by Senator Abourezk, would prohibit oil companies from holding any interests in alternative sources of energy, in order to preserve interfuel competition.

Preliminary to any discussion of the feasibility of divestiture, let me assure you that—despite what the oil industry has been telling us for the past year—neither of these measures would lead to the Collapse of Western Civilization. In one glorious three-year period, for example, Congress enacted the Banking Act of 1933, separating investment from commercial banking; the Airmail Act of 1934, designed to split aircraft manufacturing from airline operation, or as some people have suggested, to keep General Motors from running the airline industry; and the Public Utility Holding Company Act of 1935. Each of these measures was greeted with the same prophecies of doom and gloom that we have been hearing from oil companies, yet somehow both the nation and the industries affected have survived and, indeed, prospered. There are ample successful precedents for legislative action to alter industry structure.

Let me dispose of a couple of additional matters concerning the feasibility of divestiture quite briefly. First, horizontal divestiture—apart from the question of capital investment—poses no problem so far as the operation of oil companies as oil companies is concerned, at least in the present state of the art. The operation of a coal mine, a nuclear fuel fabrication facility, or a plant to manufacture solar collectors makes absolutely no contribution to the production of petroleum products from crude oil. Horizontal divestiture per se would have no effect on the activities of the several industries involved. Neither is the supposed transferability of expertise much of an argument. It's hard to believe that a petroleum geologist from the University of Texas employed by Exxon is better equipped to test and evaluate coal reserves than a coal geologist out of Penn State employed by North American Coal. Union Oil has one advantage in geothermal development over the man in the street. The company's experience in oil production enables it to make a sounder choice of a drilling contractor than you or I could make.

Second, pipeline divestiture appears to be a technically simple matter. Of 102 oil pipelines reporting to the ICC in 1974, only five relatively small operations were departments of their parent companies; the remainder had their own corporate identities and financial structures [14]  and could be separated as going concerns. The industry's argument is that pipelining risks are so great that no one but the oil companies would be willing to operate lines. (Natural gas pipelining, of course, is a separate industry in itself and several non-integrated petroleum product lines—such as Williams, Kaneb, Buckeye, and Southern Pacific—operate successfully.) An Antitrust Subcommittee staff member once asked an industry executive about the risks facing the Colonial Pipeline. He replied with a smile: "Well, all the refineries around Port Arthur and Baton Rouge might shut down or all the people might move out of the New York metropolitan area." In fact, so long as there are sufficient quantities of crude or products to be moved from where they are found or refined to places where they are utilized, the pipeline system will survive with or without oil company ownership.

So far as new pipelines are concerned, the key to financing construction comes from throughput and deficiency commitments provided by potential shippers adequate to assure the cash flow required for debt service. Historically the oil companies have refused to make such commitments to non-owned lines. As the head of Cities Service expressed this position: "But as mere shippers [on independent lines] with no equity interest, we could not justify to our stockholders the assumption of long-term throughput agreements and the even greater financial risk of deficiency obligations." [15]  Were the oil companies barred from pipeline ownership, however, there is no reason to doubt that they would be willing to guarantee throughputs necessary to construct lines which would serve their interests.

The separation of crude oil production from refining and marketing in the integrated companies appears at first glance to present more difficult problems than either interfuel or pipeline divestiture. This first impression generally rests upon a misconception that there is some technical flow relationship between the production of crude oil and refining operations within an integrated company—i.e., that a company produces crude oil from its fields and then moves this oil to its refineries. This is not the way the industry operates. Typically, an integrated company produces whatever oil it can locate wherever it can find it, and then trades through exchange agreements for the oil it refines.

Thus, Exxon was unable to answer an Antitrust Subcommittee request for information on the amount of Exxon's own crude oil which is processed in Exxon refineries:

It is not possible to trace Exxon-owned feedstocks to each refinery. Exxon's crude production is often commingled with purchased crude, part of the commingled stream sold to others, and some Exxon crude is sold outright. For example, during 1974, Exxon's net crude plus condensate production was 701 M B/D. We purchased 868 M B/D from others (including royalty oil), and we sold 780 M B/D to others. [16]

In other words, Exxon operates a crude oil business, supplied in part from its own wells and in part by outside firms and distributed in part to Exxon's refineries and in part to other refiners. A former supply manager of the company (then Humble) testified in effect that company-owned refineries were treated like any other customers of this business—there was never any company policy that the Crude Department's output go to the Refining Department or that the Refining Department acquire its crude from the Crude Department. [17]

The advantage of being vertically-integrated is that a company has crude oil to sell in exchange for the crude it must acquire to meet its refining requirements. This is what the companies mean when they talk about "security of supply." It is especially important when, as suggested earlier, open crude oil markets have been replaced by a system of closed barter arrangements. Note, though, that vertical integration does not increase the security of supplies for the industry. To the extent some companies achieve security of supply, they simply transfer whatever risks exist to non-integrated refiners. Divestiture would not reduce security of supply for the industry; it would ensure that all refiners face supply risks on relatively equal terms.

If there are, as the industry has assured us time and again, at least 10,000 viable independent producing firms, then at least 99 percent of them must be demonstrating their capacity to survive without integration. Again, a majority of the firms in the refining industry have survived without integration, although their survival is now based on the grace and favor of the government. The major companies correctly point out that a number of these companies are now trying to integrate into crude production. But this effort reflects nothing more than the absence of a workable crude oil market without which they cannot survive in the future except through government intervention.

Another argument advanced by opponents of legislation is that there are efficiencies of vertical integration which would be lost with divestiture. Exxon, for example, came up with a guess—and nothing more than a guess—that efficiency losses with divestiture would cost $5 billion a year. [18]  The most succinct answer to this argument has been given by M.A. Adelman (who does not support divestiture legislation):

The industry's contention, that vertical integration helps efficiency, is unfounded. Common ownership of these activities, by one company, neither saves money nor costs any. (There are bound to be some exceptions to the rule; relatively, they are unimportant.) Most companies became integrated long ago for reasons that are now history. They have stayed integrated because there is no reason to change. [19]

A senior vice president of Exxon, a managing partner in the accounting firm, Arthur Anderson & Co., Professor Ezra Solomon, and other witnesses have testified under oath that the producing, refining, and marketing departments of Exxon are operated as fully-staffed, unitary businesses capable of functioning effectively outside the integrated corporate umbrella. [20]  In fact, several companies—notably Gulf, Sun, and Continental—are reported to have reorganized their operations in a manner which can best be described as internal divestiture through the creation of separate corporate subsidiaries at each functional level. It would be hard to find a reason for such action other than a desire to improve overall efficiency.

Finally, the very survival of independent refiners, without any of the tax benefits enjoyed by integrated companies in the past, demonstrates at the very least that they are no less efficient than integrated companies. According to the president of Ashland Oil, "I have often made the statement that if I can get within a dollar per barrel of major crude oil costs going into the refinery, we can compete with them in the marketplace." [21]  There could, in other words, be gains in efficiency if, through divestiture, the major companies were forced to improve their performance in refining and marketing to the levels already reached by non-integrated firms.

Regardless of the technical and economic feasibility of divestiture, there is the question as to whether actions of the magnitude proposed, in terms of the capital values involved, could be successfully accomplished. Raymond Gary, managing director of Morgan, Stanley pointed out to the Subcommittee that major companies subject to the provisions of S. 2387 had, at the end of 1974, total assets of $138 billion, long-term debt outstanding of $18 billion, and $72 billion in stockholders' equity. [22]

These sums are large indeed, but they are not unmanageable. Neither Mr. Gary nor any of the other financial experts who testified at Subcommittee hearings seemed to see any problems in splitting the stockholders' equity. The usual method would involve establishing functional subsidiaries, as Gulf and other companies have already done, and then selling off, or more likely, distributing to existing stockholders, the stock of the subsidiaries. While stockholders would now hold the securities of several companies in place of the original firm, their asset values would not be impaired. Historical experience with corporate spinoffs indicates, in fact, that in most cases stockholders benefit; one Wall Street analyst, for example, expressed the view that divestiture would be a bonanza for oil company investors. [23]

Mr. Gary and other industry witnesses expressed concern, however, about the management of corporate debt issued with the backing of the full faith and credit of a corporate entity which would be substantially altered by divestiture. Clearly, debt under covenants of this type might have to be refinanced. Of concern here is the effect on the embedded cost of a company's debt when securities issued in the past at, say, five percent, must be refinanced in a ten percent market. The fact is that these are the very problems to which the courts have developed solutions in thousands of cases of court-ordered divestiture, corporate reorganizations, voluntary spinoffs, even mergers.

An example of one such solution is the recent divestiture of Northwest Pipeline by El Paso, which affected 26 series of El Paso's long-term debt. [24]  By court order, each of these series was replaced by an El Paso issue and a Northwest issue bearing the same maturities as the original series but with a 1/8 percent higher interest rate "to sweeten the deal." The ratio between the two companies' debt is the proportion between the taxable basis of properties retained by El Paso and those transferred to Northwest. In other words, an investor in El Paso 5's issued in 1962 and maturing in 1982 now holds El Paso 5-1/8's and Northwest 5-1/8's, still maturing in 1982. The increase in interest rate is minor compared to the inflation in rates since 1962, while the value of the securities to investors has been enhanced.

Still the industry warns us that vertical divestiture will make it impossible for the industry to raise the capital it needs in the future. This argument generally implies that "dismemberment" will reduce our major oil companies down to units the size of the average retail station. Nothing could be farther from the truth.

Last year Exxon, with assets of $32.8 billion, was No. 1 on the Fortune "500" list of U.S. corporations ranked by assets. [25]  Suppose we take away $1.2 billion for Exxon Pipe Line Co. and divide the remaining assets according to the ratio between the net fixed assets (property, plant, and equipment) devoted to production and those to manufacturing and marketing. The new "Exxon Manufacturing and Marketing Co.", $17.7 billion in assets, would slip—by a narrow margin—to second place behind General Motors. Our "Exxon Production Co.", $15.2 billion, would show up in fourth position, behind General Motors, Exxon Manufacturing, and Ford.

Marathon Oil's assets, $2.0 billion (No. 72 in the 1975 Fortune list) can be divided in the same way. Marathon Refining and Marathon Production would be each in the top 200 companies, with assets of $889 million and $1.0 billion, respectively. In short, if the vertically divested units were well managed and still had trouble raising capital, one can only say Lord help the 99.8 percent of U.S. manufacturing corporations which are smaller.

The industry makes one last stand on the capital question. Assuming that the capital reorganization required by divestiture can be accomplished and that the new firms, once established, can secure long-term financing, there is still an interim period between the time an act is passed and the final accomplishment of divestiture. During this interval—a minimum of five years and perhaps much longer—the uncertainty of final solutions will make it impossible for the industry to go to the capital market at all at a time when the nation's energy problems require immediate action. This is a reasonable, logical, almost unanswerable argument—except that, again, it is belied by real-world experience.

Georgia-Pacific, for example, was the subject of an FTC investigation for its extensive acquisition activity. In the relatively short period between the announcement of FTC action and the spinoff of Louisiana-Pacific (pursuant to a voluntary consent settlement), the company raised nearly $500 million in debt on favorable terms. The Kennecott-Peabody divestiture case is even more dramatic. Kennecott acquired Peabody Coal in March 1968. Four months later, the FTC filed a complaint, leading to a divestiture order in 1971, upheld by the Supreme Court in 1974. Six months after the Supreme Court denied certiorari, Kennecott was able to raise $250 million in revolving credit, at the prime rate for two years, then ¼ above the prime until the last two years when it rose to ½ above the prime. Over the whole period clouded by threat, and for the past two the certainty, of divestiture of a very large part of its business, Kennecot appears to have been able to raise at least $700 million on terms at least as good as those available to most other large corporations. It would appear, therefore, that the investment community views the uncertainties of divestiture with far less concern than it does many of the other risks to which business is subject.

While this paper has been concerned with the feasibility of divestiture, which we trust has been established, the subject of the Conference is the effect of divestiture on R&D. Apart from ignorance, my reluctance to approach this topic stems mostly from an inability to see any connection between the two. The companies have assured us that they are mounting a gigantic research effort to solve our energy problems, an effort which will be completely aborted by either vertical or horizontal divestiture. (Snidely, one might wonder how their antidivestiture media expenditures compare to their R&D outlays.)

The National Science Foundation reports that the oil industry spent $504 million on R&D in 1973. [26]  This is a respectable sum—although at 0.7 percent of sales, the relative effort is well below that of many other industries. I have a vague impression that these efforts are not characteristic of all major oil companies, but are rather concentrated among a few of them. Of the 49 coal technology patents referred to earlier, for example, 19 went to Exxon, 11 to Atlantic Richfield, with the remainder scattered among five other companies. [27]

It is hard to see how divestiture would have any adverse effects on R&D outlays. Would an oil company faced with exhausting supplies of its conventional input be any less willing to look for an alternative which would keep its principal business alive if it has to buy coal rather than mining its own? Why would a refiner, vertically separated from ownership of crude oil reserves, lose its incentive to engage in research which it sees as essential to maintaining its corporate existence?

Perhaps more important, research teams are hardly likely to be dismantled just because of divestiture, at least in the present research climate. As many industrial concerns and most leading academic institutions know full well, when research funds are available from outside sources rather than internally generated, R&D itself can be a highly profitable activity. We have already entered a period in which billions of dollars of taxpayers' money is going into energy R&D, under conditions in which corporations stand to profit enormously from successful R&D while any threat of corporate losses from unsuccessful efforts is minimized. Perhaps I am naive, but I cannot believe that—with or without divestiture—oil company research departments will not push ahead at full steam to develop projects which can ensure their fair shares of these publicly-supported programs.


  1. U. S. Department of Commerce, Bureau of the Census, Annual Survey of Oil and Gas, 1974, MA-13K(74)-1, Table 1. 1974 figure for 20 firms estimated from 72.4% for 16 and 78.8% for 24 firms.

  2. Federal Trade Commission, Staff Report on Concentration Levels and Trends in the Energy Sector of the U. S. Economy, March 1974.

  3. W. A. Johnson, R. E. Messick, S. Van Vactor, F. R. Wyant, Competition in the Oil Industry, Energy Policy Research Project, George Washington University, 1976, Table 13, p. 94.

  4. "Shell Oil's Money Machine," Forbes, August 1, 1976, p. 45.

  5. Interstate Commerce Commission, Transport Statistics in the United States, 1973, Part 6, "Pipelines," Table 4. Computed from number of barrels originated in lines, excluding Lakehead, Portland, and Trans Mountain lines.

  6. Product exchanges are normally barrel-for-barrel trades. Crude exchanges involve simultaneous purchases and sales, with two important advantages until very recently: first, they helped to stabilize posted prices, and second, they were simpler to justify to IRS for percentage depletion accounting than straight commodity trades would have been.

  7. Petroleum Intelligence Weekly, March 22, 1976, p. 5.

  8. Petroleum Intelligence Weekly, June 21, 1976, p. 7.

  9. See U. S. Senate, Subcommittee on Antitrust and Monopoly, Hearings on S. 489, 94th Cong., 1st Sess., pp. 233 (testimony of Continental Oil) and 266-267 (testimony of United Mine Workers of America).

  10. Ibid., Hearings on S. 1167, Part 9, p. 467 (Exxon statement).

  11. Exxon Corp., 1975 Annual Report, p. 12.

  12. Hearings on S. 489, supra, p. 22.

  13. The standards applied are U. S. production of 100,000 b/d of crude condensate, and natural gas liquids or more, or refining or marketing volumes of 300,000-plus b/d or more.

  14. Interstate Commerce Commission, Transport Statistics in the United States, 1974, Part 6, p. 1.

  15. Hearings on S. 2387, Part 1, p. 258.

  16. Hearings on S. 1167, Part 9, p. 529.

  17. Exxon Corporation v. Wisconsin Department of Revenue, before the Wisconsin Tax Appeals Commission, reproduced in Hearings on S. 2387, Part 2, p. 1445.

  18. Hearings on S. 2387, Part 1, p. 341.

  19. Washington Post, April 30, 1976.

  20. Exxon Corporation v. Wisconsin Department of Revenue, transcript reproduced in Hearings on S. 2387, Part 2.

  21. Hearings on S. 1167, Part 8, p. 5918.

  22. Hearings on S. 2387, Part 1, p. 1978 (with Tenneco and Pennzoil data excluded).

  23. Hearings on S. 2387, Part 1, p. 494.

  24. Details provided to the author in a telephone conversation with the comptroller of Northwest Pipeline Co.

  25. Exxon Corp., 1975 Annual Report, and Fortune, "The 500 Largest U.S. Industrial Corporations," May 1976.

  26. National Science Foundation, Research in Industry, 1973.

  27. Hearings on S. 489, p. 22.

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