333.8 Un3fi9r 1975 cop. 2 The Library of the M DEC 1 0 1975 at Urbana-Champaign REPORT TO THE FEDERAL TRADE COMMISSION ON FEDERAL ENERGY LAND POLICY: EFFICIENCY, REVENUE, AND COMPETITION UNIVERSITY OF ILLINOIS LIBRARY URBANA-CHAMPAIGM booksws BUREAU OF COMPETITION BUREAU OF ECONOMICS October, 1975 The Federal Trade Commission has not adopted this staff report. # € « REPORT TO THE FEDERAL TRADE COMMISSION ON FEDERAL ENERGY LAND POLICY: EFFICIENCY, REVENUE, AND COMPETITION BUREAU OF COMPETITION BUREAU OF ECONOMICS October, 1975 t % ACKNOWLEDGEMENTS 3 3 Q^bY) This is a staff report to the Federal Trade Commission, Owen M. Johnson, Jr., Director, Bureau of Competition and F. M. Scherer, Director, Bureau of Economics. This study is the product of many authors. Because so many persons were involved, it is difficult to identify all the individual contributors. Nevertheless, the chapters and their principal authors are: Chapter 1 - Introduction Philip Jaynes and David Garvin Chapter 2 - History of Public Land Mineral Policy James Olson Chapter 3 - Economic Theory and Alternative Leasing Policies Charles Stone Chapter 4 - Policy Goals Philip Jaynes and David Garvin Chapter 5 - Leasing Methods Ernest Pantos Chapter 6 - Offshore Oil and Gas Ernest Pantos Chapter 7 - Onshore Oil and Gas Calvin Roush Chapter 8 - Oil Shale Douglas Webbink, Lawrence Leiken and Charles Stone Chapter 9 - Coal Martha Brand and Arnold Baker Chapter 10 - Uranium Land Policies Sheldon C. Hofferman and John Haring Chapter 11 - Geothermal Energy John King and Philip Jaynes Chapter 12 - Conclusions F. M. Scherer, Harry A. Garfield II, and Calvin Roush In the Bureau of Competition, research and editing assistance was provided by Michele Crown, Patricia Granfield, Margaret Hamer, Judy Karger, Lawrence Smith, and Shirley Rockenbaugh. In the Bureau of Economics, Addie Williams provided statistical assistance and George Pascoe provided computer support. Douglas Webbink reviewed early drafts. Bess Townsend provided the final editing. The Federal Trade Commission has not adopted this staff report. FEDERAL ENERGY LAND POLICY: EFFICIENCY, REVENUE, AND COMPETITION General Summary The Federal Government owns a substantial fraction of U. S. energy resources, including a small amount of onshore oil and gas; much larger amounts of offshore oil and gas plus coal and uranium; about half the geothermal resources; and vast amounts of oil shale. Historically, the Government has chosen not to develop the resources itself, but has transferred them to private entitites through one of two methods, mining claims or mineral leasing. This study discusses for each major energy resource the impact of Federal policy on the rate of resource development, efficiency, market structure and competition, and the receipt of fair market value by the Government. Chapter 2 summarizes the history of Federal mineral land transfer policy. Early legislation culminating in the Mining Act of 1872 emphasized rapid development of the West by transferring public lands to private use at nominal cost through a claim location and patent system. In later years, legislative emphasis turned toward conserva¬ tion, preventing monopoly, and receipt of revenue by the Federal Government. The Mineral Lands Leasing Act of 1920 placed deposits of coal, phosphate, sodium, potassium, oil, gas, and oil shale under a leasing system rather than a claim system. Later acts, including the Continental Shelf Lands Act of 1953 and the Geothermal Steam Act of 1970, favored leasing for additional energy resources. The only energy resource still subject to a location system rather than a leasing program in 1975 is uranium. In chapter 3, some fundamental economic principles are developed to analyze energy resource market perform¬ ance. Initially, the notion of economic efficiency in a static framework is explored. It is shown that in a competitive market, bonus bidding leads to efficient resource allocation and also secures for the Government the economic rents anticipated from resource development. Market behavior and economic efficiency are then analyzed for situations in which resources are exhaustible and current production -l decisions affect future production possibilities. A final section describes the effects of uncertainty con¬ cerning future supply and demand conditions and identifies the circumstances under which bonus bidding may nevertheless be the preferred method of leasing. The various goals which have been proposed for Govern¬ ment energy land transfer policy are considered in chapter 4. Following an analysis of goal conflicts, emphasis is placed upon capture by the Government of economic rent or "fair market value," efficiency, environmental protection, the promotion of competition, and increased energy self- sufficiency . The relative advantages of various competitive and noncompetitive leasing systems are analyzed in chapter 5. Competitive leasing is found to be preferable, since it is more likely to lead to economically efficient production and the receipt of fair market value by the Government. The relative merits of sealed bidding versus oral auction are considered. Cash bonus bidding, royalty bidding, profit share bidding, rental bidding, work commit¬ ment bidding and their variants are analyzed as pure systems, and combination systems as well as alternative Government enterprise approaches are examined. Chapter 6 is the first of six chapters devoted to specific energy resource land policies. Offshore oil and gas production is becoming increasingly important. In 1974, 16 percent of U. S. gas production and 11 per¬ cent of oil production came from the Outer Continental Shelf. With the exception of one competitive royalty bid sale, all lease sales have entailed competitive bonus bidding. This permitted the Government to receive an approx¬ imation to fair market value, but it also created substantial capital and risk barriers to entry by small firms, and it encouraged the formation of possibly anticompetitive joint ventures. Leading firm concentration of OCS produc¬ tion is substantially higher than total U. S. oil and gas production, and the largest U. S. oil companies play a dominant role. In recent years the Department of the Interior has leased fewer OCS tracts than business firms would have preferred, but now it plans to increase greatly its rate of leasing. Federal onshore oil and gas lands account for only a small fraction of total U. S. reserves and production. Chapter 7 reveals that both competitive and noncompetitive leasing systems are used. But the vast majority of leases have been issued noncompetitively under the simultaneous filing system, which is essentially a lottery. While the Government has probably received fair market value on lands made available through competitive bonus bidding, it has not done so on leases under the simultaneous filing system. Production concentration on Federal onshore oil and gas tracts does appear to be slightly lower than overall national concentration. The rate of leasing has been determined by market demand, with leasehold pro¬ duction subject to State prorationing regulations. The Federal Government owns about 80 percent of the Nation's high grade oil shale reserves, which means that it can strongly affect the future development of the shale oil industry. The first four Federal oil shale tracts were leased under a new program in 1974. Whether oil shale production is technologically and economically feasible is not yet known, but it clearly would not be viable at pre-Arab Oil Embargo prices. Therefore, developing the technology and conducting commercial- scale tests are desirable before oil shale leasing can be viewed as a means of raising revenue for the Government. Keeping access to key patents and technological know-how open is also an important policy concern. The capital costs of a shale oil venture are high, and most of the proto¬ type lease winners are major oil companies, many of which have formed joint ventures. Coal is the most abundant of all U. S. energy resources. The Federal Government owns at least 60 percent of western coal reserves and 40 percent of total U. S. coal resources, principally in seven Western States. Through 1971, the Department of the Interior had only leased a small fraction of its coal lands, and since then it has had a moratorium on new coal land leasing. Prior to the moratorium, the Government permitted industry to determine the timing, location, and size of lease sales. About half of the coal lands were leased under the preference right system and the other half using competitive bonus bids plus a fixed royalty. In the competitive lease sales, over half the tracts received only a single bid. Total payments to the Government from all bonus bids, rentals, and royalties have been nominal compared to the market value of the coal. Thus far Federal coal leasing has accounted for only a small proportion of U. S. pro¬ duction. Only 5 of the 20 largest U. S. coal producers were among the 20 largest Federal leaseholders in 1973. With future growth in demand for coal, the Federal coal reserves will become much more important. -iii- The Federal Government owns over half of the known high quality uranium lands. However, unlike other energy resources. Federal uranium-bearing land has been trans¬ ferred into private development through a claim staking and patent system rather than a leasing system. As a re¬ sult, Chapter 10 reveals, the Government has received only token payments. The claim system increases the costs of acquiring land blocks of economic size and leads to conflicting land ownership claims. Because claims are filed in county land offices, the Department of the Interior does not have aggregated company ownership records. It is known that concentration in the ownership of uranium reserves is very high, but it is not clear to what extent this is a result of existing Federal land policies. In 1974, there was only one commercially operating geothermal generating plant in the United States. It generated about 0.1 percent of the Nation's electricity. The Federal Government controls slightly more than one- half of U. S. geothermal resources. As with oil shale, there is substantial uncertainty concerning the technologi¬ cal and economic feasibility of developing geothermal energy, but even under the most optimistic projections, it will only account for a small fraction of electricity generation by the year 2000. An active Government leasing program for geothermal resources began only in 1974. The first two years' bidding indicates that there is growing interest, although many tracts received no bid or only one bid. The majority of the winning bidders have been oil companies. Concluding chapter 12 observes that recent worldwide energy price developments have greatly increased the value of the Federal Government's energy resource lands. Methods such as claim staking, preference right leasing, and simultaneous filing, under which land is transferred to the private sector at nominal fees, have as a result be¬ come increasingly inappropriate because they fail to obtain for the public the fair market value of its energy resources. Their abolition is recommended. As high energy prices have encouraged the probing of new resource frontiers, there has also been a sharp increase in the geologic and technological uncertainty confronting energy resource development investors. Substantial uncertainty and high resource values interact to exacerbate risk aversion. Under the bonus bid system traditionally used for competitive leasing, this in turn precipitates important dilemmas. Intensified exploration for new resource deposits may as a consequence be achieved -IV- only at an appreciable sacrifice of Government leasing revenues. And the high cost and risk of bonus bids discourage independent exploration and development by smaller firms, thereby lessening competition. A new two-stage competitive bidding approach is proposed to cope more effectively with the economic and technological challenges of a dear-energy era. Under it, entities seeking to explore Federal mineral lands would have to make no front-end payments, and the assignment of exploration rights would be separated from the granting of development and production rights. When an economi¬ cally attractive resource deposit has been discovered, development rights would be awarded through orthodox competitive bonus bidding. The discoverer of such a deposit would be rewarded with a "discovery bonus share" — that is, a share of the development rights bonus bid which acts as a handicap against non-discoverer bidders or which is retained by the discoverer if another firm nevertheless wins the development rights. Companies seeking explora¬ tion rights would either obtain them freely, in which case the discovery bonus share would be set administratively, or through competitive bidding with respect to the value of the subsequently applicable discovery bonus share. In all cases, relevant geologic data would be made public before tracts on which energy resource deposits have been discovered are put out for bonus bidding. Participants in the high-stakes bidding stage would therefore have good knowledge of what they were bidding on. Numerous variations are possible to adapt the two-stage competitive bidding approach to diverse energy resource conditions. As a possible alternative to the two-stage approach, increased experimentation with royalty bidding in areas of high geologic uncertainty is proposed. Other specific recommendations include the following: For the Outer Continental Shelf, small companies should be allowed to spread bonus bids over a five-year period, and a ban on joint ventures among the largest corporations should be seriously considered. For onshore oil and gas leases, no Federal lands should be subject to State prorationing, and unitization of pools should be fostered. For oil shale leasing, the Government should encourage rapid development and testing of alternative technologies, and only enough land to meet that goal should be leased. A guaranteed shale oil purchase commitment may be desirable, but the Government should also take steps to ensure that no company or group acquires patents or technological know¬ how sufficient to block entry by other firms. For uranium, the leasing approach recommended represents a substantial -v- departure from past claim staking practice. This plus the rapidly growing demand for uranium suggest the advisability of careful experimentation with selected leasing techniques. As with oil shale, the principal goal in geothermal leasing ought to be geologic exploration and the development of new, economically efficient technologies before numerous unexplored geothermal tracts are trans¬ ferred to the private sector. In coal, the moratorium on leasing Federal lands should be ended, and competitive methods -- either bonus bidding or a two-stage approach — should be substituted for the preference right system. A final major recommendation is that, in order to make better-informed energy and leasing policy decisions, the Federal Government should collect and publish detailed data on the locations and geological characteristics of federally-owned energy resources and on the distribution of private sector rights to those resources. TABLE OF CONTENTS Chapter 1 - INTRODUCTION. 1 The Timing of Resource Development. 7 Efficiency Consequences. 11 Impact on Market Structure and Competition. 12 Obtaining Economic Rent for Government Lands. 14 The Central Questions. 16 Chapter 2 - HISTORY OF PUBLIC LAND MINERAL POLICY. 19 Introduction and Overview. 19 Prelude to a Policy. 22 Early Mineral Land Action. 2 2 The California Gold Rush. 26 Triumph of the Miner. 31 The 1866 and 1870 Acts. 31 The Act of May 10, 1872. 38 The Turn Toward Leasing. 4 0 The Struggle for a Leasing Policy: 1872-1920. 40 1. Coal Lands. 41 2. Oil Lands. 4 6 The Mineral Lands Leasing Act of 1920. 49 1. Prelude. 4 9 2. Passage of the 1920 Act. 53 i The Limits of Coverage. 68 Where Are the Public Mineral Lands?. 68 Limitation on the Disposal of Public Lands... 71 The Outer Continental Shelf Lands. 7 4 AEC Leasing on Federal Lands. 7 8 Geothermal Leasing. 80 Conflict Over Multiple Use. 81 The Continuing Debate. 86 Chapter 3 - ECONOMIC THEORY AND ALTERNATIVE LEASING POLICIES. 89 Introduction. 89 Static Efficiency. 95 Production Costs and the Supply of Energy Resources. 95 The Supply Curve and the Social Cost of Production.103 Consumer Tastes and the Demand for Energy Resources.106 The Efficient Level of Production.112 The Distribution of Economic Welfare.114 Market Failure.124 1. Imperfect Competition.124 2. Externalities.129 Resource Transfer Policy in a Static World...131 1. Claiming and Noncompetitive Leasing.132 li 2. Bonus Payments.133 3. Supply Restrictions.134 4. Summary and Conclusions.135 The Efficient Allocation of Exhaustible Energy Resources.136 Resource Exhaustibility.136 The Production Decision of an Industrial Producer.141 The Competitive Market Timing of Resource Development.14 5 Government Ownership and Resource Develop¬ ment Timing.153 The Market Interest Rate, the Government Discount Rate, and the Social Discount Rate.167 Leasing Policy for Exhaustible Resources.... 177 The Effects of Uncertainty on Market Behavior and Economic Efficiency.182 Uncertainty in Energy Resource Development..182 Private Risk and Social Risk.186 Decision-Making Under Uncertainty.193 Uncertainty and Market Behavior.195 Social Risk and Efficient Resource Development.2 02 iii Chapter 4 - POLICY GOALS.210 Alternative Leasing Policy Objectives.212 Chapter 5 - LEASING METHODS.221 Competition vs. Noncompetitive Systems.222 Nationalization.225 Full Nationalization of Exploration and Production.226 Full Nationalization of Exploration.228 Partial Nationalization of Exploration and Production.230 Competitive Bidding Mechanisms.233 Oral Auctions.234 Sealed Bidding.237 Sealed Bid Followed by Oral Auction.240 Refusal Prices.241 Summary.243 Alternative Bidding Systems.245 Cash Bonus Bidding.246 1. Receipt of Fair Market Value.246 2. Economic Efficiency.250 3. Energy Self-sufficiency.252 4. Defferred Bonus Bidding Variants .... 254 IV Rental Bidding.257 1. Receipt of Fair Market Value.257 2. Economic Efficiency.259 3. Energy Self-sufficiency.262 Royalty Bidding.263 1. Receipt of Fair Market Value.263 2. Economic Efficiency.266 3. Energy Self-sufficiency.278 4. Royalty Bidding with a Declining Royalty Base.278 Profit Share Bidding.2 82 1. Receipt of Fair Market Value.283 2. Economic Efficiency.289 3. Energy Self-sufficiency.295 Work Commitment Bidding.2 96 1. Receipt of Fair Market Value.296 2. Economic Efficiency.297 3. Energy Self-sufficiency.298 Combination System.299 Conclusion.302 v Chapter 6 - ONSHORE OIL AND GAS.303 Importance of Federally-owned Resources.303 Production from Federal OCS Leases.304 Past and Present Leasing Policies.306 The Outer Continental Shelf Lands Act and Its Administration...306 The Geological Survey.308 1. Selection of Lands for Lease.309 2. Size and Timing of Lease Sales.313 3. Size of Tracts Offered for Lease....319 4. Method of Lease Allocation.320 5. Terms of Lease.325 6. Drilling and Production Require¬ ments .327 Economic and Technological Conditions of the Industry.333 General.333 Offshore Technology.336 Costs.337 Risks.340 1. Discovery Risk.340 2. Other Risks.349 Economic Evaluation of Past and Present Leasing Policies.351 The Time Pattern of Resource Development.351 Economic Efficiency.354 1. Selection of Lands for Lease.354 2. Size and Timing of Lease Sales.355 3. Size of Tracts.359 4. Allocation of Leases.360 5. Terms of Leases.363 6. Drilling and Production Requirements... 365 Competitive Impact.366 1. Concentration of Winning Bids.369 2. Concentration of Oil and Gas Production on the OCS.37 5 3. Joint Ventures.385 4. Reducing the Anticompetitive Impact of OCS Leasing Policy.390 Collecting the Fair Market Value of Leases.397 Summary.419 Chapter 7 - ONSHORE OIL AND GAS.425 Importance of Federally-owned Resources.425 Leasing Policies and Procedures.429 Economic and Technological Conditions of the Industry.434 Time Pattern of Resource Development.435 Tract Sizes.440 Vll Allocation of Leases.448 Competitive Impact.4 51 Obtaining the Fair Market Value.453 Competitive Leasing.453 Noncompetitive Leasing.455 Summary and Conclusions.466 Chapter 8 - OIL SHALE.469 Importance of Federally-owned Resources.469 Past and Present Leasing Policies.473 The Prototype Oil Shale Leasing Program.477 Economic and Technological Conditions of the Industry.480 Uncertainty and Risks.482 1. Discovery and Resource Risks.482 2. Technological Risks.484 3. Market Risks.491 Leasing Acquisition Costs.495 Age and Structure of the Industry.498 1. Age of the Industry.498 2. Industry Structure and Concentra¬ tion of Resource Ownership.499 3. Barriers to Entry.502 Economies of Scale.514 Externalities.515 Evaluation of Present Leasing Policies.517 Developing a New Technology.517 Time Pattern of Resource Development.520 Economic Efficiency.525 viii Competitive Impact.528 Attaining Fair Market Value.535 Summary.539 Chapter 9 - COAL.541 The Importance of Federally-owned Coal.541 Economic and Technological Conditions of the Coal Industry.551 Risk and Uncertainty in Coal Exploration and Development.560 Barriers to Entry.569 Past and Present Leasing Policies.576 Federal Agencies in Charge of Administering the Federal Coal Leasing Program.577 The Mineral Lands Leasing Act of 1920.581 1. Coal Prospecting Permits and Preference Right Leases.580 2. Competitive Coal Leases.588 3. Other Provisions Applying to all Leases.592 The Moratorium.599 An Evaluation of Federal Coal Leasing Policies.603 Resource Allocation.604 1. Lease Timing.604 2. Location of Leases.609 3. Lease Size.610 4. Type of Lease.612 ix 5. Coal Production.614 6. The Moratorium.624 7. Summary.6 25 Competition.626 1. Competition for Federal Coal Leases...626 2. Impact of Federal Coal Leasing on Market Structure and Competition.629 Fair Market Value.636 1. Legislation History and Statutory Basis.636 2. Definition of Fair Market Value.638 3. Revenue Received for Federal Coal Leases.639 Summary and Conclusions.647 Chapter 10 - URANIUM LAND POLICIES.650 Introduction.650 Public Ownership of Uranium Lands.654 The Location-Patent.657 Weakness of the Location-Patent System.661 Evaluation of the Claim System's Effect . 674 Impact on Rate of Development.675 Returns to the Government.679 Environmental Impact.681 Effects on Competition.683 Summary.685 Chapter 11 - GEOTHERMAL ENERGY.687 Introduction.687 x Dry Steam Generation.689 Hot Water Technologies.690 1. Flashed Steam Process.691 2. Heat Exchange Process (Binary Circle).692 3. Total Flow Process.693 Hot Dry Rock Technology.693 The Geothermal Leasing Program.694 1. Leasing Terms.696 2. Royalty and Rental Payment.698 3. Diligent Exploration.701 4. Noncompetitive Leases.704 5. Lease by Competitive Bid.705 Problems of Implementation of the Leasing Program.709 Competition.712 Environmental Problems.„.713 Economies of Geothermal Energy Utilization.714 The Location and Extraction of Geothermal Heat.714 Construction of Power Plants and Trans¬ mission Lines.716 Cost Competitiveness of Electricity Produced from Geothermal Energy.718 Summary and Conclusions.723 xi Chapter 12 - CONCLUSIONS. 725 The Dimensions of Government Leasing Policy. 7 26 A Proposed Two-stage Bidding Approach. 7 33 Further Uncertainty-Reducing Measures. 744 Specific Energy Resource Sector Recommendations. 746 Offshore Oil and Gas. 746 Onshore Oil and Gas. 7 51 Oil Shale. 753 Coal. 758 Uranium. 760 Geothermal Resources. 763 The Need for a Reliable Reporting System. 7 67 Xll Chapter 1 INTRODUCTION Substantial energy reserves are under Government con¬ trol on federally-owned land. These include small reserves of onshore oil; substantially greater reserves of coal, uranium, and offshore oil; and massive amounts of oil shale. Through the leasing or granting of Federal lands, the Government periodically feeds these energy resources into the marketplace. Fully one-third of the Nation's land area is owned by the. Federal Government. In addition, the Government con¬ trols the Outer Continental Shelf—those submerged lands lying three or more miles offshore. Both areas are rich in energy resources, with considerable production to date. They are likely to play an even larger role in the future. Table 1.1 shows the proportion of total U.S. resources that are federally-owned, as well as their present share of domestic production. TABLE 1.1—Percent of Total U.S. Resources and 1972 Production Which Were Federally Owned Proven Reserves Oil Offshore 11 Onshore 4 TOTAL 15 Gas Offshore 15 Onshore 6 TOTAL 21 Coal 48 Oil Shale 25 gallons per ton shale n.a. 15-25 gallons per ton shale n.a. Geothermal No breakdown available— approximately 50 percent of domestic total Uranium No breakdown available— approximately 50 percent of domestic total Potential Resources 30 8 38 36 8 44 n.a. 1972 Production 10 5 15 16 6 22 2 81 1/ 78 1 / n.a. 2/ n.a. n.a. n.a. - not available 1/ No commerical production. 2 / Small amount of production on private lands, but no commercial production on Federal lands. SOURCE: Energy Policy Project of the Ford Foundation, A Time to Choose (Cambridge: Ballinger Publishing Company, 1974), table 39, p. 271. -2- Throughout its history, the United States has con¬ sistently favored the development of its energy resources by private enterprise. This principle was stated explicit¬ ly in the Mining and Minerals Policy Act of 1970 (30 U.S.C. §21a): The Congress declares that it is the continuing Policy of the Federal Government in the national interest to foster and encourge private enterprise in (1) the development of economically sound and stable domestic mining, minerals, metal, and mineral reclamation industries; (2) the orderly and economic development of domestic mineral resources, reserves, and reclamation of metals and minerals to help assure satisfaction of industrial security, and environmental needs .... The Government has thus rejected the option of developing its own resources. Given this policy, some mechanism is needed to transfer the resources into private hands for development. Historically, two policies have been employed-- the system of mining claims, as codified in the Mining Law of 1872; and the system of mineral leasing, as set forth in the Mineral Lands Leasing Act of 1920, the Acquired Lands Leasing Act of 1947, and other statutes of similar intent. - 3 - According to the Mining Law of 1872, any citizen of the 4 United States may prospect for, stake, and develop mineral deposits located on public lands. After discovery and filing of a claim, rights of possession are maintained by the annual expenditure of at least $100 in labor or improve¬ ments of a mining nature on that claim. While a patent to the claim (a conveyance of the Government's right in the land) is not required, it may be obtained through the performance of additional assessment work coupled with further payments. Nearly all energy resources and other minerals were initially subject to the Mining Law of 1872. Now, however, only the disposal of uranium is still conducted under its provisions, with most other energy resources covered by various special mineral leasing statutes. The passage of the Mineral Lands Leasing Act of 1920 marked an important shift in the Nation's attitude toward mineral development. Prospecting and production were no longer viewed as the natural right of every citizen, with mining claims freely dispensed. Instead, the development of the public lands was to be more closely regulated, with a larger proportion of revenues flowing into the National Treasury. The powers of the Federal Government were broadened in recognition of its expanded role. Most mineral lands were to be offered at competitive auction with the money collected, both immediately and through subsequent rentals and royalties, accruing in the first instance to the Federal Government, which then distributes a portion to the States affected. Similar control over acquired lands (i.e., land obtained by the Government through purchase, condemna¬ tion or gift, or by exchange for such lands) was provided for by the Acquired Lands Leasing Act of 1947, while the Outer Continental Shelf Lands Act of 1953 conferred upon the Federal Government authority for offshore areas. Leasing of Federal energy resources raises numerous interesting and important policy questions. The first relates to the timing of lease-granting. Should the Govern¬ ment lease all lands immediately, making a maximum contribu¬ tion to present energy supplies? Should it adopt a con¬ servationist policy, leasing the lands gradually; or is some intermediate policy appropriate? Second, do pre¬ sent leasing policies contribute to the efficient develop¬ ment of Federal energy resources, in the sense of obtaining resources from such lands at lowest cost? Third, - 5 - are Federal leasing policies designed to enhance competi¬ tion in the energy extraction industries? Sub-questions include whether large firms are favored at the expense of smaller competitors, and whether policy works in the direction of increasing market concentration unnecessarily. Fourth, is the Government obtaining fair value for the lands it leases, or is it unwittingly providing a bounty to corporations obtaining leases? In addition to these specific issues, there is a broader question of how leasing fits into overall national energy policy. Clearly, the leasing of Federal energy lands should be more than a real estate operation conducted in different ways by several Government agencies. This study will examine the extent to which leasing has appeared to follow some overall policy direction, and what that direction has been. It will also recognize that leasing is only one of many policy tools the Government can use to affect the development of energy resources. Others include taxes, subsidies and incentives, and the pro¬ motion of research and development on new fuels. Leasing policy cannot be evaluated without an apprecia¬ tion of how it fits into an overall "package" of energy development measures. The Timing of Resource Development Through its control over Federal reserves, the Govern¬ ment can regulate the rate at which energy resources flow into the market. The timing of resource development has particular significance because energy reserves are exhaust¬ ible. Eventually, all of the petroleum in the ground will be depleted. How many years this will take is not clear, since the rate of consumption varies, as does the pace of new discoveries and the ultimate amount expected to be discovered. Nevertheless, there is at least a possibility that we will run out of oil, or that the supply of oil re¬ maining will be extremely high priced. The same can be said of coal reserves, although the time horizon is con¬ siderably more distant. Normally, the price system can be relied upon to ration scarce resources. As the price of petroleum rises, less will be consumed, and the development of alternate energy sources will be stimulated. Very high petroleum prices may lead to greater use of coal, the - 7 - development of liquid petroleum synthetics from coal, oil shale and tar sand development, greater reliance on nuclear energy, and so forth. In the distant future all fossil fuels may be depleted, and we may have to rely on fusion power, solar power, or some other technology not yet perfected. In the past, the transition from one energy source to another has been made smoothly and gradually, with little inconvenience or disruption of production processes. In home heating, wood was displaced by coal, which was in turn largely replaced by fuel oil, natural gas, or electricity. Railroads made a similar conversion from wood-burning loco¬ motives to steam and later diesel power. It is obvious that today's energy-hungry industrial society could not function at its present levels with wood or even coal as its primary energy source. Yet those who in the past predicted disaster because we would run out of energy resources such as coal have been proven wrong. New technologies and new energy deposit discoveries have always postponed the day of reckoning. -8- This may continue to happen in the future. Our great- great-grandchildren may have more energy at their disposal, at lower cost, than we do because of technological break¬ throughs not yet envisioned. On the other hand, blind faith in technological progress may not be justified. Future con¬ sumption levels may be curtailed by dwindling fossil fuel reserves because dramatic new technologies simply do not materalize. High levels of energy consumption now may thus be robbing future generations of vital fossil fuel reserves. Choices between present and future consumption are made by market processes through the intermediation of the interest rate. Income to be received several years in the future is greatly discounted at compound interest. In fact, with high interest rates, income or consumption 50 years from now would be valued at virtually zero. The market mechanism working in this way provides an answer to the question of present versus future energy con¬ sumption, according little weight to the future. The private market rate of discount is high, and consumption taking place 50 or 100 years from now is discounted so heavily as to be almost valueless. The unfettered market thus provides a fairly clear answer for longrun energy policy: consume now; the distant future and unborn generations mean almost nothing. - 9 - From the standpoint of social policy, however, a different answer may be favored. Although most people value their own welfare highly, they also have some con¬ cern about civilization in the future. They may be will¬ ing to make sacrifices in present consumption to avoid the decline of the future industrial society that could result from energy shortages. The implication is that the "private" and "social" discount rate may differ rather substantially, with the "social" discount rate being appreciably lower. Perhaps Government policy with regard to energy re¬ serves should be one of conservation rather than rapid consumption, as dictated by the market. Energy reserves under Government control could be viewed as an "insurance policy" against the contingency that fossil fuels may become nearly exhausted before new energy technologies be¬ come fully available. Federal energy lands could be held in reserve and then leased to prevent an absolute energy "crunch" from developing. An alternate policy which either assigns little weight to the future or is optimistic about future technological developments could also be pursued. This would involve using Federal energy resources as a means of smoothing - 10 - price fluctuations and easing temporary shortages. If the price of oil rises, more land could be leased. When prices are lower, less land could be leased. This policy would view Federal lands in a shortrun buffer stock sense rather than as a hedge against long-range shortages. In addition to choices on when leases are offered, the timing of resource development is also affected by lease provisions. For example, bonus bid leasing may lead to relatively faster development than leasing with royalty payments, since royalty payments raise the marginal cost of production and may induce a reduction of output. Efficiency Consequences Another aspect of Federal land disposal policy is its effect upon production efficiency. Policies should encourage least-cost production and minimize resource allocation distortions. An optimum policy would result in the leasing first of least-cost tracts—that is, tracts where mineral extraction costs are lower. Also, the exploitation of tracts of optimum size should be encouraged. The acreage required for - 11 - efficient development varies with individual fuels. Leases should be designed to provide sufficient quanti¬ ties of minerals for efficient development. Also, inefficient geographic patterns should be avoided. For ex¬ ample, haphazard leasing might result in a "checkerboard" pattern less efficient than the assignment of contiguous tracts. Impact on Market Structure and Competition Government land disposal policies can have anti¬ competitive effects if they tend to favor large firms at the expense of smaller competitors. Of course, they alone dc not determine the basic market structure for established fuels such as petroleum and coal. Market structures in these fuels were developed historically through both private and public land development and through mergers. They are also affected by barriers to entry not related to land acquisition. Nevertheless, leasing policies could influence future changes in market structure. - 12 - In the newer resource areas such as uranium and oil shale, the Government's land policies could have a considerably greater effect in determining what type of market structure evolves. Developing or promoting competition might thus be one of the goals of energy resource leasing policy. There are several ways mineral land disposal policy could affect competition. Not all can be spelled out in a general fashion, and the details for each of the fuels will be examined subsequently to ascertain whether any provisions unnecessarily favor large firms. Two aspects appear particularly relevant, however. The first is the extent to which the procedures increase capital barriers to entry. Exploration for and development of mineral reserves can require substantial amounts of capital in any event, but some leasing methods increase the amount of capital needed. Specifically, bonus-bid leasing methods may require the payment of large sums of money prior to resource develop¬ ment, making it more difficult for small firms to participate. - 13 - Risk is a second key variable influencing competition. Diverse leasing policies offer a broad potential spectrum of risk-sharing, from the bidding firms' being required to assume nearly all the risk to various arrangements in which the Government bears a significant share. Policies which require bidders to accept most of the risk favor large enterprises or consortia. The prevalence of joint ventures in bidding for leases is an indication of the desire among private firms to share risk. While joint ventures are not necessarily anticompetitive, they do have that potential. This study will examine the extent to which bidding is done via joint ventures and how the composition of the joint ventures affects competition. Obtaining Economic Rent for Government Lands Lands capable of producing energy resources are scarce, and their quality varies. Their exploitation enables private firms to earn substantial profits, particularly from the more productive tracts. Profits obtained in excess of the normal rate of return or opportunity cost of capital may be criticized as unfair if they come from public lands. Therefore, the Govern¬ ment has often tried to expropriate such profits by - 14 - obtaining "fair value" for the lands it leases. This can be done in several ways, such as the sale of mineral rights through bonus bidding competition or the imposi¬ tion of royalties. Bonus bidding has proved to be a good revenue-raising device, but it also shifts most of the resource development risk to the bidder and, as we have seen, requires large initial capital expenditures, raising entry barriers. Royalty, payments entail considerably less risk and make it easier for small firms to participate, but they also have undesirable output-discouraging effects. These and other considera¬ tions must be weighed carefully in choosing a system of payment for Government lands. Whether the Government is in fact obtaining "fair value" for the lands it leases is difficult to answer empirically. One test would be to see if on the average companies earn only normal profits from their leased lands. Since such profitability data are seldom available f a second method might be to see whether the prices paid for Government lands are comparable to those paid for similar private lands. Again, this is difficult to accomplish owing to data limitations. A third, perhaps more feasible method is to examine the bidding history of Government tract sales. Is there an adequate number of - 15 - bidders? How do prices obtained relate to expert valua¬ tions of the lands? Does there appear to be any evidence of collusion in bidding? All three of these approaches will be employed where feasible in the individual energy resource chapters of this report. The Central Questions As this introduction has suggested, the transfer of Government energy lands can be a flexible policy instrument. A large number of alternative procedures, regulations, and specific contractual terms can be employed. Whatever their differences in form, however, every land disposal policy must solve four fundamental questions: 1. Which lands are to be transferred to private possession? 2. At what rate should they be leased? 3. Who is to be granted access to the resource? 4. At what price is the resource to be transferred? The answers to these questions depend in turn upon two factors—the overriding objectives land disposal policy must serve, and the economic and technological environment in which each mineral industry operates (which determines how those objectives can be achieved). - 16 - These issues have shaped the current study. In September 1973, Congress mandated the Federal Trade Commission to conduct a study of the energy industry, to include "consideration of the effects of decisions by government departments and agencies ... on the price and supply of energy."iy Federal leasing and disposal policies play an especially important role here. Through their impact on the patterns of resource ownership and development, they influence industry structure, ultimately affecting the level of competition in the marketplace. And the degree of competition that prevails has significant implications for energy prices and availability. The study draws upon numerous data sources, includ¬ ing published works, various special studies and data files of Federal Government agencies, and interviews with specialists in industry, government, and universities. No significant use has been made of the compulsory process powers conferred by Section 6 of the Federal Trade Commission Act. The first four chapters following this introduction provide an analytical framework for evaluating the land 1/ Conference Report HR 93-520, September 1973 - 17 - disposal policies which have been pursued in specific energy areas. Chapter 2 surveys the historical develop¬ ment of U.S. mineral lands policy. Chapter 3 then examines the economic issues underlying the choice of basic leasing policy variants. Chapter 4 provides an overview of the relevant public policy goals. The effectiveness of specific bidding and revenue collection mechanisms in implementing those goals is then analyzed at some length in chapter 5. Each of the subsequent chapters focuses upon a par¬ ticular energy resource, building upon the earlier theoreti¬ cal discussion. Offshore oil and gas, onshore oil and gas, oil shale, coal, uranium, and geothermal energy sources are considered separately. The chapters characterize past land disposal policies, explore the economic and technological conditions relevant to the choice of a leasing approach, and evaluate the general direction and effectiveness of policy for each fuel area. A final chapter provides an overall summary of recommendations for public policy. - 18 - Chapter 2 HISTORY OF PUBLIC LAND MINERAL POLICY Introduction and Overview The proper disposal of public lands has been the subject of continuing debate, commencing at least by 1785 with the famous Land Ordinance and persisting into today with a multitude of legislative proposals. The treatment of mineral lands has been a part of the debate since the beginning. In fact, with most of the land usable for agriculture and grazing long since removed from the public domain, the question of the mineral lands has, if anything, an even greater proportionate significance now. The following discussion of the history of public land mineral policy attempts to provide an historical framework for subsequent chapters dealing with economic issues and specific energy fields. It is not intended - 19 - as a comprehensive treatment of the subject, 1/ nor is it meant to deal in a detailed way with the various energy resources. That task is performed by the chapters on specific resources, which combine a statu¬ tory analysis with an assessment of what occurs in practice. Because America was originally almost completely unsettled, the question of how to treat public domain lands has always been an important one. It has been dealt with frequently by Congress with certain basic themes running throughout the debate. The central dialectic has had on one side the men of the West (wherever that may have been at any given time), who wanted the Federal Government to give up its land at little or no cost to the citizens of the West to promote rapid development of the Western States. On the other side were those less concerned with quick exploitation and more con¬ cerned about filling the Federal coffers with revenue 1/ One excellent history is Robert W. Swenson's "Legal Aspects of Mineral Resources Exploitation," ch. XXIII in History of Public Land Law Development , by Paul W. Gates (Washington: Public Land Law Review Commission, 1968). -20- from the land or preventing its spoliation and monopo¬ lization. For over 80 years Congress failed to come to grips with the problem of mineral lands in any consistent way, making half-hearted turns in one direction and then tacking to another course when discontent developed. It was only in the 1860's, under the pressure of huge gold and silver finds in California and other Western States, that Congress developed a coherent policy. This policy, embodied in the Mining Act of 1872, 2/ was a triumph for the West. It provided for the transfer at very little cost of public domain land containing minerals to those willing to work and exploit it. The succeeding century has seen the strength of the original developers wane as problems began to be apparent. Reaction to the exploitationist view led to passage of the Mineral Lands Leasing Act of 1920, 3/ removing 2/ 30 U.S.C. §22 et seg. 3/ 30 U.S.C. §181 et seq. - 21 - i certain minerals from the coverage of the 1872 Act. 4/ Renewed dissatisfaction with the 1872 Act is likely to lead to further legislation in the near future. Prelude to a Policy Early Mineral Land Action Mineral land policy in America began with royal charters granted by the English Crown to the Colonies. Most of these conferred title to the mines and minerals on the colonists, but reserved as rental one-fifth of £/ The 1872 and 1920 Acts not only are landmarks in the evolution of public mineral land policy, but still largely govern all of the energy resources save geothermal reserves, whose utilization was not foreseen by either act. Uranium mining is largely controlled by the 1872 Act, and the other energy minerals—oil and gas, coal, oil shale—by the 1920 Act. -22- all gold and silver ore. 5/ Royal title to precious metals had previously been established by English Law. 6/ Because the United States Government owned no portion of the Thirteen Original Colonies, a Federal policy covering mining on public lands was not immedi¬ ately necessary. It is important to point out that the statutory history reviewed here relates almost entirely to Federal public domain land. Consequently, it has little bearing on the Original Colonies and is not important for areas of the United States which were 5/ George A. Blanchard and Edward R. Weeks, Leading Cases on Mines, Minerals and Mining Water Rights (San Francisco: Sumner, Whitney & Co., 1877), pp. 87, 88. After the Revolution the Crown and proprietor's rights apparently devolved on the former colonies. See Shoemaker v. United States , 147 U.S. 282, 306-320 (1893). New York State still claims the right to ownership of all gold and silver found in private property because King Charles II ceded all mineral lands to the Duke of York, predecessor of the State, in return for 40 beaver skins a year. Rocky Mountain Mineral Law Foundation, ed., American Law of Mining , vol. I (Boulder: Matthew Bender, 1974), §1.2. See McKinney's New York Public Lands Lav; §81. Curtis Lindley, A Treatise on the American Law Relating to Mines and Mineral Lands , vol. I, 3d Edition (San Francisco: Bancroft-Whitney, 1914), §331. 6/ Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , pp. 700, 701. -2 3- settled early. Over 90 percent of the public domain land other than in Alaska (which is 95 percent owned by the Federal Government) is in the Western States. 7/ A Federal policy became necessary as the Original Colonies ceded their claims to land west of the Alleghenies to the Federal Government. The maiden congressional effort was the Land Ordinance of May 20, 1785, which provided for surveying and disposition of the land. The Continental Congress reserved for the National Government one-third of all gold, silver, lead, and copper mined in the newly acquired territories. 8 / This policy was an adaptation of the system used by the English Crown in its earlier dealings with the Colonies. 9/ The legal validity of the reservation 7/ Public Land Law Review Commission, One Third of the Nation's Land (Washington: U.S. Government Printing Office, 1970), p. 22. 8/ John C. Fitzpatrick, ed., Journals of the Continental Congress , vol. XXVIII, 1785, pp. 375, 378. 9/ Lindley, A Treatise on the American Law Relating to Mines and Mineral Lands , op. cit. , §30. - 24 - ceased with the dissolution of the Continental Congress. 10 / The new United States Congress' first disposition of mineral lands provided, at the prompting of Alexander Hamilton, for the sale at auction of copper lands near the Great Lakes. In 1807 Congress changed its approach, authorizing the lease of lead mines in the Indian Territory. 11 / The purpose of the leasing policy was to raise revenue. In this it failed; the cost of collection exceeded the revenue raised. In fact, as one commentator points out, making revenue the prime goal of public lands policy was more appropriate to a settled country like England than to a country in need of development such as the United States. 12 / Leasing 10 / The Rocky Mountain Mineral Law Foundation, ed., American Law of Mining , op. cit., §1.3. 11 / Authority for the disposal of public lands comes from the Constitution which provides "that Congress shall have power to dispose of and make all needful Rules and Regulations respecting the Territory or other Property, belonging to the United States." Art. IV §3, CL2. In the case of United States v. Gratiot 39 U.S. (14 Pet.) 526 (1840) it was held that the power to dispose included the right to lease as well as to sell 12/ Clyde 0. Martz, Cases and Materials on the Law of Natural Resources (St. Paul: West Publishing Co., 1951), p. 2. - 25 - was abandoned in Missouri in 1829, and the leased lead mines were sold at congressional direction. How¬ ever, leasing was continued in the Upper Mississippi Valley. The closest student of this leasing found it to have been successful and supported by the miners until governmental corruption and neglect fatally damaged the program. 13 / But in 1845, President Polk asked that the leasing system be terminated, and in the succeeding two years, legislation was passed providing for the outright sale of Mississippi region mineral lands. 14 / The California Gold Rush In January of 1848, gold was discovered near John Sutter's sawmill on northern California's American River. Thousands of forty-niners were soon camped in the foothills of the Sierra Nevadas. A legal system was necessary to prevent chaos in the camps. In the 13 / James E. Wright, The Galena Lead District : Federal Policy and Practice, 1824-1847 (Madison, Wise.: State Historical Society, 1966), pp. 82-85, 104. 14 / Lindley, A Treatise on the American Law Relating to Mines and Mineral Lands , op . cit ., §34. V - 26 - succeeding years, mining discoveries were made and booms occurred in scores of places„ Among the most famous were Pike's Peak (1859); Virginia City, site of the Comstock Lode (1849); Tucson (1862); and the Snake River Valley (early 1860's). Nearly all of these discoveries took place on public domain land, yet Congress was unwilling or unable to enact legislation regulating such mining. In fact, in 1851, President Fillmore endorsed this legislative inaction as follows: I am inclined ... to advise that they [the mines] be permitted to remain, as at present, a common field, open to the enterprise and industry of all our citizens, until further experience shall have developed the best policy to be ultimately adopted in regard to them. 15 / In the absence of State or Federal laws protect¬ ing their diggings (technically the miners were tres¬ passers on Federal land), the miners organized them¬ selves and set up codes of conduct backed by a hang¬ man's noose. 15 / Cong. Globe , 32d Cong., 1st sess., App. p. 4 (1851). - 27 - Between 1851 and 1866, over 1,000 such codes were drawn up in mining districts. 16 / These codes soon acquired the force of law and were frequently cited in court opinions. California even amended its civil practice act in 1851 to provide that: In actions respecting "mining claims", proof shall be admitted of the customs, usages, or regulations established and in force at the bar or diggings embrac¬ ing such claims; and such customs, usages or regulations, when not in conflict with the Constitution and laws of this State, shall govern the decision of the action. 17 / The United States Supreme Court itself recognized the legal force of the mineral rules in an opinion by its mining expert, Mr. Justice Field of California: These regulations and customs were appealed to in controversies in the State courts, and received their sanction; and properties to the value 16/ The Rocky Mountain Mineral Law Foundation, American Law of Mining , op. cit. , §1.9. 17/ Cited in Morton v. Solambo Copper Mining Co, 26 Cal. 528, 533 (1864). - 28 - of many millions rested upon them. For eighteen years—from 1848 to 1866--the regulations and customs of miners, as enforced and moulded by the courts and sanctioned by the legislation of the State, constituted the law governing property in mines and in water on the public mineral lands. 18 / While these codes varied from location to loca¬ tion, certain basics were generally similar. Partly, this similarity resulted from a common legal heritage and partly from similar environmental conditions. While the antecedents of the mining camp laws are in dispute, they bear a strong resemblance to the Spanish codes in Mexico (California became a part of the United States only in 1846 and the influence of Mexican law remained strong), and to the regulations of Devonshire and Cornwall tin miners (many of the California miners were Cornish in origin). 19 / Also, as might be 18 / Jennison v. Kirk , 98 U.S. 453, 458 (1878). 19 / Lindley, A Treatise on the American Law Relating to Mines and Mineral Lands , op. cit. , §42; Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , pp. 709, 710. - 29 - expected, they did not vary too much from American law in general. 20 / They dealt with discovery, the size and marking of claims, the amount of development work necessary to hold a claim, water rights, etc. The key rules were that discovery was the basis of the property right and that development was the basis for continuance of that right. Similarly, prior appropriation was the rule of the day for water (necessary for both placer and hydraulic mining). 21 / One major innovation not found in contemporaneous mining law was the concept of extra¬ lateral rights, which entitled the discoverer of a vein to work it to any depth, regardless of who owned the surface rights above its course. 22 / 20 / The Rocky Mountain Mineral Law Foundation, American Law of Mining , op. cit. , §1.9; Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 709. 21 / Lindley, A Treatise on the American Law Relating to Mines and Mineral Lands , op. cit. , §42; Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 709. Lindley, A Treatise on the American Law Relating to Mines and Mineral Lands , op. cit. , §43. 22 / The Triumph of the Miner The 1866 and 1870 Acts The mining booms in California and other parts of the West eventually brought irresistible pressures on Congress to enact legislation. Events had made it impossible not to act. Two principal bodies of opinion emerged. One group from non-mining States wished to maximize Federal Government revenues from the land, whether by sale, lease, or reservation of royalty interest. In the mid- 1860's, when major legislation was being considered, there was a great need for Federal revenues due to the financial strains of the Civil War. One New York Congressman sponsored a resolution requesting the President to protect the Government mineral lands in Arizona and Colorado, pointing out that revenues from those lands would reduce the necessity for "unprecedented and onerous taxation." He was angered that companies intending to mine on public lands were being organized by "Wall Street speculators" who were making money -31- the Government should receive. 23/ Another revenue- maximizer, Congressman Julian of Indiana, introduced a bill to sell off the public mineral lands, a step he felt would aid the Treasury in two ways: it would yield revenue from the sale, and solidify the currency by putting more gold and silver in circulation. 24/ Representative Julian was sensitive to charges that his bill could lead to a monopoly of gold and silver. But he believed a Government monopoly was no less pernicious than any other type of monopoly. Also, monopoly already existed in the mining areas and was bound to continue to some extent in any event. And he expected the first purchasers to be those already mining rather than monopoly-minded capitalists. 25/ The other group, principally Westerners, fought these bills, desiring instead free exploration and occupation of the public land and legitimization of 23/ Cong. Globe, 38th Cong., 1st sess., pp. 1695, 1696 “ ( 1864 ): — 24 / Cong. Globe , 38th Cong., 2d sess., pp. 684-687 (1865). 25 / Ibid ., pp. 686, 687. -32- t the claims of those already on it. Their objective was the speedy development and growth of the West. As Senator Stewart, a mining lawyer from Nevada, said during the congressional debate, "The facts of history furnish abundant proof that large yields of the precious metals are the best and strongest incentives to industry, the accumulation of wealth, and the advancement of society." 26/ In addition, the Westerners had come to believe over the years that the land was theirs, "secured through long years of incessant toil and privation." As most miners were poor, it was argued that any sale arrangement would result in possession of the land by "capitalists and speculators." 27 / At this stage in the Nation's history, the emphasis was on development, the more rapid the better. The Homestead Act of 1862 exemplified the spirit of that time. Any citizen or prospective citizen could enter on up to 160 acres of public land "for the purpose of actual settlement and cultivation" and, after three years of such occupation and cultivation. 26/ Cong. Globe, 39th Cong., 1st sess., pp. 3228, 3229 (1866). 27/ Ibid ., p. 3226. -33- obtain title to the land. 28/ This was also the period of vast land-grants to railroads building lines across prairie and mountain to the West. Whether the feeling was justified or not, the prior Federal leasing experience had left a bad taste. Representative Julian claimed that "the experiment [leasing] failed utterly." 29/ Historian James Wright pointed out how leasing was denigrated (falsely, he believed) by proponents of the 1866 Act: TThe 1866 law] marked the complete triumph of economic, exploitative values in the disposition of the nation's mineral wealth. Any attempt to introduce leasing in the West was quickly shouted down, its opponents pointing to the "fiasco" in the Upper Mississippi Valley. This anti-leasing group failed to recognize, or admit, that leasing was in fact successful at the public mines of Wisconsin and Illinois until the 1830's and that governmental neglect, illegal sale of reserves, and hostility on the part of local officials demolished an otherwise operable system. 30/ 28 / 43 U.S.C. §61 et_ seq. 29 / Cong. Globe , 38th Cong., 2d sess., p. 685 (1865). 30 / James Wright, The Galena Lead District , op. cit. , p. 104. -34- Given this climate of opinion, it is not sur¬ prising that the pro-mining forces won a complete victory. On July 26, 1866, a law managed by Senator Stewart became effective. We need not examine it in detail because it was essentially super¬ seded by the General Mining Law of 1872, which carried forward its general principles. Its general outline should, however, be noted. Section I declared "the mineral lands of the public domain . . . to be free and open to exploration and occupation" subject to governmental regulations "and subject also to the local customs or rules of miners in the several mining districts." 31 / This first section seems broad enough to cover both placer and lode mining. 32 / The remainder of the 1866 Act was limited to lode mines, probably because placer mining had greatly diminished by 1866 in California. 33 / It authorized the patent or grant of any lode if the 31/ 14 Stat. 251 (1866). 32 / Placer mining is of superficial deposits, generally of gravel in river or valley beds, while lode mining is of ore deposits in place. 33 / The Rocky Mountain Mineral Law Foundation, American Law of Mining, op. cit., §1.14. -35- claimant had occupied the land and spent $1,000 on its improvement. All the claimant had to do was file a diagram of the vein at the local land office. After 90 days of posting, if no conflicting claim was made, the miner paid $5 and received his patent (a muniment of title issued by a government body for the con¬ veyance of some portion of the public domain). In addition, the Act limited the length of a vein and recognized extralaterality. The significance of the 1866 Act cannot be under¬ estimated. It marked the inauguration of a fixed and definite legislative policy with regard to public lands. It changed trespassers into legitimatized land¬ holders under conditions no more burdensome than the miners themselves had imposed. 34/ The Placer Act of 1870 amended the 1866 Act by extending patentability to placer mines. The Californian who authored the Act claimed that this step was necessary because the surface placer mines had been exhausted and it had become necessary to 34/ Lindley, A Treatise on the American Law Relating to Mines and Mineral Lands , op. cit. , §55. -36- tunnel, a procedure requiri n g large amounts of land. 35 / The Placer Act provided for a 160 acre patent, while the mining codes often allowed no more than 40 acres. 36/ Those supporting the bill made the usual argument that only if they could own the land would miners cease their nomadic lives, settle down, and invest in their prop¬ erties. Ireland was pointed to as an example of the evil effect of a tenancy system. 37/ The bill was attacked by Senator Cole, also of California, on the ground that 160 acres was too large a limit, the result of which would be "to throw the mining lands of California into the hands of moneyed men and speculators to the exclusion of . . . honest miners." 38/ Cole's amendment to cut the maximum allowable acreage to 10 acres was at first accepted, but the final bill reverted to the 160 acre limit. 39 / 35 / Cong. Globe , 41st Cong., 2d sess., pp. 316, 317 (1869). 36/ Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 722. 37/ Cong. Globe , 41st Cong., 2d sess., p. 2028 (1870). 38/ Ibid. , pp. 3054, 3055. 39 / Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 722. -37- The Placer Act had a short life, being replaced in less than two years by the Mining Law of 1872. The Act of May 10, 1872 The 1872 General Mining Law both unified and modified the acts of 1866 and 1870. Until passage of the 1920 Mineral Lands Leasing Act, nearly all mining rights on Government-owned land were governed by its terms. To this day, it is the major instrument by which rights to hard-rock minerals are gained. Among these is uranium, the only energy mineral still controlled by the 1872 Act. 40 / The same lines were drawn and the same arguments made as during consideration of the previous mining acts. Best exemplifying the philosophy of those pushing the legislation is this excerpt from a speech by Representative Sargent of California, floor manager of the bill in the House: 40 / The other minerals involved in the FTC study--coal, oil shale, oil and gas—fall primarily under the 1920 Act. A minute amount of uranium mining is also done under post-World War II legislation. -38- Now sir, this legislation was originally an experiment. In 1866, when the original quartz law was passed, the question was fiercely debated whether it was worth while for the Government to sell the mineral lands of the United States. Some thought that on some idea of royalty belonging to the Government, or some principle growing out of the constitutional right to regulate its coinage, it ought to keep control of the precious metals, and hence it was not advisable for the mines to pass out of its own hands into the hands of its people. But it was argued that these people were to a great extent nomadic and unsettled, in one section this year, and next year in some other place, and it was necessary to attach them to the soil, so that they would make more permanent improvements, and acquire for themselves lands which they could improve, upon which they could build their little homes. Where agricultural land was connected with mining lands, and these are almost inextricably intermixed, the miner would make improvements, culti¬ vate his land, raise his peach trees and potatoes, and conduct his mining and farm¬ ing operations at the same time, or at different seasons of the year, and the result would be a more settled community, and the creation of more taxable property to the benefit of both the State and General Governments. 41 / The basic philosophy of the General Mining Law of 1872 is identical to that motivating the 1866 and 1870 Acts. It affirms that "all valuable mineral 41 / Cong. Globe , 42d Cong., 2d sess., p. 534 (1872). -39- deposits . . . shall be free and open to exploration and purchase," and provides procedures by which public lands may have claims located on them and be patented. 42/ The first locator who diligently works a claim is pro¬ tected against latecomers and may remove all the minerals he finds with no payment to anyone, even if he does not patent the land. This approach is exactly the same as that developed by the miners themselves. While the philosophy and economic forces behind the three acts were identical, the details were not, although Congressman Sargent glossed over the changes. 43 / The chapter on uranium contains a more detailed discussion of the 1872 Act's provisions. The Turn Toward Leasing The Struggle for a Leasing Policy; 1872-1920 During the 50 years following enactment of the General Mining Law, it remained the basis for nearly all exploration and development of minerals on public 42 / 30 U.S.C. §21 et seg . 43 / Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 723. -40- lands. Gradually, though, a national consensus emerged that for certain minerals—notably coal, oil, oil shale, and gas—the location and patent system was inadequate. In 1920, the Mineral Lands Leasing Act was passed embodying that opinion. Supplanting the General Mining Law for all energy minerals other than uranium was not easily accomplished, however. Throughout the period between the two Acts a familiar struggle took place. On one side was the West, standing for rapid and free exploitation and development; on the other Easterners, concerned with increasing Federal Government revenues, the monopolistic power of huge mineral developers such as Standard Oil and (in coal mining) the railroads, and, for the first time, concerned with the conservation of resources. 1. Coal Lands Even before passage of the General Mining Law, special provisions governed the mining of coal. Why coal lands were treated differently from other mineral lands is unclear. Perhaps the coal lands were more readily discoverable and thus were thought to have a greater revenue potential; or possibly it was because of coal's -41- relatively lew value and localized market structure It is true that copper and iron ore lands in the Great Lakes region had earlier been sold. 44 / Whatever the reason, in 1864 an act was passed empower¬ ing the President to sell coal lands to the highest bidder for no less than $20 an acre. 45 / The next year, the sale of such lands was limited to bona fide miners actually engaged in mining, and the size of a tract was limited to 160 acres. 46 / Coal leasing procedures were revamped in 1873 by passage of the Coal Lands Act. This Act allowed individual entry onto 160 acres of vacant and unreserved land and group entry to 320 acres (640 acres if the group had spent $5,000 on work and improvements). The minimum price was $20 per acre for land within 15 miles of a completed railroad and $10 per acre for land more than 15 miles from a railroad. 47 / While the Coal Lands Act remained the basic tool for disposing 44/ Ibid., p. 725. £5/ 13 Stat. 343, 344 (1864) . 46/ 13 Stat. 529, 530 (1865). 47/ 17 Stat. 607, 608 (1873). of coal lands until 1920, it had been beset by- scandal and criticism long before then. 48 / The acreage limits were too small to justify the commercial development of many types of coal fields. To evade them, companies engaged in widespread fraud, using dummy entrymen or entering under the agricultural land statutes In the early part of the 20th century several such scandals were uncovered. An Interstate Commerce Commission investigation found that through extensive use of dummy entrymen, the "Denver and Rio Grande Railroad Company has had absolute control of the production, transportation, and marketing of the fuel supply of the State of Utah." 49 / The Union Pacific Railroad Company exercised similar power in Wyoming. 50 / At the same time, the conservation movement was rising. It won a victory in 1891 with the passage of 48 / Swenson, "Legal Aspects of Mineral Resources Exploitation, op. cit. , pp. 724-727. 49 / U.S. House of Representatives, Hearings before the Committee on Public Lands on Coal Lands and Coal-Land Laws of the United States, pp. 2, 3 (1906) 50/ Ibid., p. 7. -43- the Forest Reserve Act, intended to protect Federal domain timber lands from sale. 51 / However, the movement's zenith was reached with the Theodore Roosevelt administration and its ardent conservationists such as Gifford Pinchot. This period was also the hey-day of "trust-busting," with one exploiter of public mineral lands, the Standard Oil Company, cast as the arch-villain by antitrust advocates. Thus, it was not surprising that in 1906 Senator LaFollette of Wisconsin offered a resolution authorizing the withdrawal from entry and sale of public oil and coal lands. 52 / He was concerned that coal and oil lands were "rapidly passing under the control of corpora¬ tions that are thus acquiring a monopoly of the coal and oil supply," to the detriment of future U.S. industrial development. Congress failed to act on the LaFollette resolution; but later in 1906, President Roosevelt ordered all public land known or believed to contain coal withdrawn from entry, at first from any 51 / Note, "Management of Public Land Resources," 60 Yale Law Journal , 455, 460 (1951). 52 / 40 Cong. Rec ., p. 8763 (1906). -44 entry and then from coal entry only. Roosevelt mentioned both the land frauds and conservation as grounds for his action and stated that on the withdrawn lands the Government should see that "no excessive price was charged consumers." 53 / The President's action was bitterly opposed by Westerners. The total lands affected were said to comprise more than 64 million acres. Representative Mondell of Wyoming attacked both the legality and wisdom of Roosevelt's action. He believed the Executive orders withdrawing the lands from sale went far beyond presi¬ dential authority. Nor did Mondell consider the action needed. He pointed out that only a little more than 400,000 acres had been disposed of in the 34 years during which the Coal Lands Act had been effective. To him a leasing system meant "state socialism, paternalism, and centralization" and would make a criminal out of the traditional Western hero, the pick and shovel prospector. He was also unhappy that the West was "to be made to pay 53 / 41 Cong. Rec. , pp. 2614, 2615 (1907). -45- w a tribute of heavy royalties for the benefit of the balance of the country." 54 / 2. Oil Lands A similar development occurred with respect to public oil lands. At first, the mining laws were presumed to apply. But in 1896, the Interior Department announced in the Union Oil Co. case that oil did not t- fall under the protection of the then existing mining laws. 55 / This opinion was reversed by Interior a year later, but in the meantime Congress passed the Placer Act of 1897, sponsored by Representative Mondell, which certified that oil lands could be entered and patented under the Placer Law. 56 / Certain problems resulted from the application _ of the Placer Law to oil. First, to search for oil required expensive drilling before a discovery was made, and the mining laws provided no protection for 54 / Ibid ., pp. 2618, 2619. 55/ Union Oil Co., 23 L.D. 222 (1896); rev'd, 25 L.D. 351 (1897). 56/ 29 Stat. 526 (1897). -46- an explorer prior to discovery until the doctrine of pedis possessio developed, which protects the rights of the first miner on a parcel of locatable land. Second, the $100 annual expenditure requirement encouraged drilling work even though there was no ready market. Third, as in the case of coal, the acreage limits were too small to permit efficient development, and as a result dummy entrymen were common.57/ In 1909, President Taft ordered over 3,000,000 acres of California and Wyoming oil land withdrawn from entry. 58 / Coming on the heels of President Roosevelt's coal land withdrawal and withdrawals of land for national forests, 59 / a furor naturally resulted. Taft himself was uncertain about the constitution¬ ality of his action and asked for congressional valida¬ tion. His message to Congress mentioned the frauds 57/ Swenson "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 732. 58/ Ibid ., p. 733. 59 / These had been unpopular with Congress, which in 1907 passed legislation blocking the President from setting aside additional forest land in six Western States. Because the forest provision was attached to an appropriations bill he favored, Roosevelt could not veto it. So in a two-day period before it went into effect, Roosevelt set aside 16 million acres. Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 725. -47- which had resulted from past Government prodigality. He stressed conservation along with the need for legislation that would encourage development and "prevent a monopoly or misuse of the lands or their products." 60/ Representative Pickett of Iowa introduced such a bill in 1910. Opposing it was an amalgamation of coal, oil, grazing, lumber, and mining interests, supported by some Western railroads, "capital," and the West as a whole. The debate was not confined to one or two minerals, but dealt with the entire question of how the Nation should manage its natural resources. 61/ The original Pickett bill suffered a number of amendments in the Senate. These induced many who had been hostile to the bill before to embrace it. One key amendment was to secure the rights of all oil and gas explorers conducting work when a withdrawal was made. One historian calls this the most important feature of the bill as passed, since the President's 60 / 45 Cong. Rec ., p. 622 (1910). 61 / John Ise, The United States Oil Policy (New Haven: Yale University Press, 1928), pp. 317, 318. -48- withdrawal power was in any event later upheld by the courts. 62/ The Mineral Lands Leasing Act of 1920 1. Prelude The passage of the Pickett Act by no means ended the controversy. In succeeding years, withdrawn lands was one of the great public issues. By 1909 half of all the withdrawn coal lands had been restored to entry, but pressure still came from the West for further action. 63 / Leasing's nose entered the tent twice: first with the passage in 1914 of legislation authorizing coal land leasing in Alaska, and then in 1917 with a bill 62 / Ibid ., pp. 319, 320. The Supreme Court upheld the withdrawal power in United States v. Midwest Oil Company , 236 U.S. 459 (1915). This decision referred only to the President's power prior to passage of the Pickett Act. But by now it seems well-established that the President still has the withdrawal power. See Arizona v. California , 373 U.S. 546, 598 (1963) . 63/ Whether this position was economically rational is debatable. A close student of the issue concluded that as far as oil and gas was con¬ cerned, there was overproduction from private lands throughout the period. Ise, United States Oil Policy , op. cit. , pp. 325, 327. - 49 - authorizing potash land leasing. The latter bill was triggered by wartime interest in potash for the manu¬ facture of explosives. 64 / Representative Mondell of Wyoming, who had fought the withdrawals, testified in favor of coal leasing legislation for Alaska and expressed his hope that eventually legisla¬ tion would be passed allowing leasing all over the United States. 65/ Mondell's position was symptomatic of a shift in views by Westerners. Before the withdrawals, they had been defenders of the mining status quo, strongly opposing a leasing system. After the withdrawals, leasing began to appear the only way any activity could be begun on Federal energy mineral lands. Consequently, most Westerners came to support leasing legislation. 66 / 64 / Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 741. 65/ U.S. House of Representatives, Hearings before the Committee on Public Lands on Alaska Coal-leasing Bill, 63d Cong., 2d sess., at 98 (1914). 66 / And they saw the withdrawals as intended to force a change in the law. As Representative Mondell testified: "Why the withdrawals? To compel a leasing law. There has been no other apparent purpose." U.S. House of Representatives, Committee on Public Lands, Hearings on Oil Leasing Lands (H.R. 3232 and S.2812), 65th Cong., 2d sess., p. 624 (1918). - 50 - During the second decade of the 20th century, numerous mineral land leasing bills were introduced and extensive hearings were conducted. The Wilson administration backed one combination lease-sale bill, introduced in 1913 by Rep. Scott Ferris of Oklahoma, Chairman of the House Committee on Public Lands. 67 / The Ferris bill, apparently drafted by lawyers with little understanding of the oil business, left open the possibility of private wells draining Government lands, but at the same time did not grant explorers a large enough acreage in remote areas. 68/ Those speaking for the Ferris bill tied conserva¬ tion and concern over monopolization together. One Progressive cited his party's platform: "The natural resources of the Nation must be promptly developed and generously used to supply the people's needs, but we can not safely allow them to be wasted, exploited, monopolized or controlled against the public good. We heartily favor the policy of conservation, ... We believe that the remaining forests, coal and oil 67 / Ise, The United States Oil Policy , op. cit. , p. 327. 68 / Ibid., p. 32 8. - 51 - lands, . . . are more likely to be wisely conserved and utilized for the general % welfare if held in the public hands. 69 / The bill's acreage limits, it was claimed, would cure problems such as Rockefeller control of a company producing 20 percent of Colorado's coal. 70 / Representa¬ tive Mondell supported the bill's concept "because we can not get a better policy at this time," but expressed a preference for public control exercised by the States. 71 / Some Westerners, such as Representative Taylor of Colorado, continued to oppose leasing legislation because of their belief that the public domain lands belonged to the respective States. 72 / But what doomed Ferris' and other similar bills was the question of relief for the operators on withdrawn lands. The operators, mostly Californians, were willing and able to block any legislation that did not provide relief for them. 73 / One bill which did meet their specifications \ 69 / 51 C ong. Rec ., p. 14944 (1914). 70/ Ibid ., p. 14949. 71/ Ibid ., pp. 14952, 14953. 72/ Ibid ., p. 14946. 73/ Ise, The United States Oil Policy, op. cit., pp. 332-335, 339, 340. - 52 - * foundered on the opposition of Gifford Pinchot and other conservationists and anti-oil men who thought the bill too liberal in its treatment of the operators on withdrawn lands.74/ 2. Passage of the 1920 Act Finally, in August of 1919, Senator Smoot of Utah introduced the bill which became the Mineral Lands Leasing Act of 1920. 75/ The arguments made concerning Smoot's bill were a continuation of the debate begun with the 1906 coal land withdrawals. Smoot made it clear that he had long opposed a leasing system for mineral lands, and he still believed leasing was not the best way to develop such lands. But 6,500,000 acres of oil land, 2,700,000 acres of phosphate land, 3,500,000 acres of oil shale land and 43,700,000 acres of coal land, of which only 27,300,000 acres had been classified, had been withdrawn. If development was not to be frozen forever, the Western congressmen would have to agree to a leasing program. 76/ 74/ Ibid ., pp. 338-340. 75/ 30 U.S.C. §181 et seq. 76 / 58 Cong. Rec ., pp. 4111, 4112, (1919). - 53 - Senator Ashurst of Arizona attacked Pinchot and other "false conservationists" who proposed "to make a preserve out of the entire West and subject millions of American citizens to a system of 'absentee landlord¬ ism. '" Ashurst claimed that the Standard Oil interests welcomed land withdrawals because they created a scarcity of oil. He went on: I do not like a leasing system. I do not believe there is a single western Senator here who will rise and say he likes a leasing system. Is there a western Senator here who desires to depart from the great mining law of the past that built our States? Comes now the conservationist. I have great respect for the conservationist, but his spectacles are rainbowed. He has dreams that do not function and that will not work in the ordinary practical affairs of life. . . . When the vote is taken on a leasing bill I may hold my nose and vote for it. 77/ Senator Walsh of Montana was one Westerner who planned to vote for the bill without holding his nose. He feared that if the Government gave up ownership of the land completely, some great trust, such as Standard Oil, might get its hands on it. 78 / 77/ 58 Cong. Rec., p. 4250 (1919). 78/ 58 Cong. Rec., p. 4251 (1919). * - 54 - Senator Thomas of Colorado expressed the resent¬ ment of Westerners, great chunks of whose States "never can pass into private ownership" or contribute tax revenues to the States, at Easterners "living in states unburdened by such conditions, states which were once public-land states also, but whose lands have passed entirely into private ownership." 79/ He claimed leasing had been tried 100 years earlier and had been unpopular and unsuccessful. 80/ Senator Kirby of Arkansas proposed that the Federal Government itself develop the oil and coal lands. He was immediately attacked by Western senators, including Albert Fall of New Mexico (who later, as Secretary of the Interior, secretly leased the Teapot Dome Naval Reserve to his oil industry comrades). Kirby's amend¬ ment was defeated on a voice vote. 81/ Senator LaFollette proposed giving the Government the right to set the price at which coal and oil from leased lands would be sold. This proposal was 79/ 58 Cong. Rec., P- 4253 (1919). 80/ 58 Cong. Rec., P- 4255 (1919). 81/ 58 Cong. Rec., pp. 4283-4290, 4416 (1919) - 55 - rejected 48-10. 82 / LaFollette also attacked the relief provision for those operating on public land, including the naval reserves, but his amendment to strike that section of the bill was also defeated. Among those benefiting from the relief provision was the old enemy of the Progressives, the Standard Oil Company.83/ After passage by the Senate, the bill underwent extensive debate and some modification in the House. The House cut back on the Senate bill's relief pro¬ visions and an attempt was made to reduce the amount of the royalty to be paid to the States. The Western States naturally wanted as high a share of the royalty payments as possible, believing that they were being cheated out of the tax revenues which would accrue if the lands passed into private hands. The House attempt to cut the States' share failed on a germaneness 82 / 58 Cong. Rec., pp. 4731-4736 (1919). 83/ 58 Cong. Rec., pp. 4746, 4772, 4773 (1919) - 56 - ruling, but the conference committee did trim the States' share to 37-1/2 percent from the Senate's 45 percent. 84 / The final conference report accompanying the bill gives an explanation of its objectives: The legislation provided for herein, it is thought, will go a long way toward the development of the West and of the natural resources of the West and at the same time reserve to the Government the right to supervise, control, and regulate the same, and prevent monopoly and waste and other lax methods that have grown up in the admin¬ istration of our public-land laws. In addition thereto, royalties and rentals are provided, so that the Government may not be passing to title the natural re¬ sources without receiving something in return therefor. 85 / It also noted why many of those opposed to leasing went along with the bill: Sharp differences of opinion have existed as to the advisability of installing leasing legislation of any kind. But for 84/ 58 Cong. Rec ., pp. 7649-7651 (1919). 85 / U.S. House of Representatives, Report No. 1138, 65th Cong., 3d sess., p. 19 (1919). - 57 - many years the West has been practically tied up and no development had, due to the antiquated land laws that have been on the statute books and the strict interpreta tion of them, which has rendered them valueless, unworkable, and utterly imprac¬ ticable. 86 / An earlier report on the Ferris bill by the House Committee on Public Lands had placed an even greater emphasis on the role of mineral legislation in dealing with monopolies. Referring to coal, the report said a leasing system would "afford competition to the coal monopoly and better prices to consumers; . . . [and] enable coal companies to lease an area large enough to justify competition with present monopoly; . . . 11 8 7/ As for oil, the bill's first two objectives were "To free both producer and consumer from monopoly; [and] to insure competition." 88 / How well these objectives have been met is dealt with in subsequent chapters. 86/ Ibid . 87 / U.S. House of Representatives, Report No. 206, 65th Cong., 2d sess., p. 3 (1917). 88 / Ibid. , p. 5. - 58 - Also covered in the succeeding chapters are relevant detailed provisions of the 1920 Act. Here we confine ourselves to a bare outline. The Act, which became law on February 25, 1920, covers deposits of coal, phosphate, sodium, potassium, oil and gas, and oil shale. A 1960 "tar sands" amendment added native asphalt, solid and semisolid bitumen, and bituminous rock (including oil-impregnated rock or sands from which oil is recoverable only by special treatment after the deposit is mined or quarried). 89 / The public domain to which the Act was applicable included the national forests but excluded lands acquired under the Appalachian Forest Act. It also excluded lands in cities, towns, and villages, and in national parks and monuments, as well as those acquired after the date of the Act and lands within naval petroleum and oil shale reserves. 90/ The Act was also made applicable to all former public lands on which the United States 89/ 30 U.S.C. §181. 90/ Ibid. - 59 - retained the mineral rights while disposing of surface rights. 91/ Leases were limited to citizens of the United States and countries which allow U.S. citizens reciprocal privileges. Aliens living in countries not granting reciprocity were not even allowed stock ownership in companies holding leases. Originally, the Senate bill would have further restricted alien ownership. The House modified the provision despite the fears of a Californian that Japanese would buy up all the Nation's minerals and ship them abroad. 92 / At the time, Great Britain denied to aliens the right to own oil lands, which upset many congressmen.93/ There were separate provisions applicable to the various minerals covered: coal, phosphates, oil and gas, oil shale and tar sands, sodium, sulfur and potash. Generally, these provisions delimited the lease 91/ 30 U.S.C. §182. 92/ 58 Cong. Rec., p. 7514 (1919). 93/ 58 Cong. Rec., p. 7528 (1919). - 60 - acreage in any one State which a person was entitled to hold (an amount which has steadily been amended upwards) and set the conditions under which a prospect¬ ing permit or lease would be issued, including the duration and terms of leases, and the amount of work required. They also specified the conditions under which a lease would be issued through competitive bidding (usually, if there is a "known geologic structure") and set rentals and royalties for the leased land. 94 / Monies received under the Act from sales, bonuses, royalties, and rentals were distributed as follows: 37.5 percent proportionately to the States from whose lands the monies came, 52.5 percent to the reclamation fund (except for Alaska, which was allowed to keep its 52.5 percent), and the remaining 10 percent to the United States Treasury. 95/ The Secretary of the Interior was empowered to cancel prospecting permits if due diligence was not exercised in carrying out prospecting work, and to 94/ 30 U.S.C. §184 et seg . 9_5/ 30 U.S.C. §191. - 61 - cancel leases if their terms were not respected. The Secretary could also grant the right to sublet or relinquish a lease. (For oil and gas leases, this permission is no longer needed). 96/ Finally, there were extensive and complicated relief provisions for those who had located on withdrawn lands. As these are no longer relevant, they need not be discussed here. 97 / The Mineral Lands Leasing Act is administered primarily by the Department of the Interior. Within the Department, the responsibility has been divided among several different bureaus, most notably the Bureau of Land Management (BLM) and the U.S. Geological Survey (USGS). BLM administers the processing and approval of permits and leases for Federal lands. This work is done by its various field offices, except for coal lands, which are temporarily under the jurisdiction of 96/ 30 U.S.C. §§183, 187-187(b) 9 y 30 U.S.C. §227. - 62 - the Washington office. The USGS assists BLM by providing scientific and technical information germane to lease and permit awarding decisions. USGS bases these reports on site information gathered by its staff engineers and geologists. USGS is also responsible for enforcing lease terms and pertinent regulations once the lease has been issued. In addition, other agencies, principally the Forest Service and other Department of Agriculture divisions, have some jurisdiction over the implementation of Federal leasing policies. Under the Acquired Lands Act, the agency administering any such lands has explicit and complete leasing powers. 98/ For lands which are not acquired, but rather reserved for a special purpose and put under a particular agency's jurisdiction, the Secretary of the Interior usually accedes to the views of the administering agency. But if there is a con¬ flict, the final decision as to whether to issue a 98/ 30 U.S.C. §351 et seq. - 63 - lease or a prospecting permit rests with Interior. 99 / Since 1920, the Mineral Lands Leasing Act and amendments thereto have governed nearly all dispositions of public land energy minerals, except for uranium. There have been times, though, when leasing of a particular mineral has been halted by Executive action. The first such occasion was in 1929. Shortly after his inauguration, and hard on the heels of the Teapot Dome scandal. President Hoover closed the public domain to oil leas¬ ing, saying, "there will be no leases or disposal of Government oil lands, no matter what category they may lie in . . . there will be complete conservation of Government oil in this administration." 100 / Hoover had two main reasons for this move. There was growing public concern over possible oil shortages and the 99 / One such case involved a company granted a phosphate prospecting permit over the objection of the Department of Agriculture. The land involved was being used for sheep research purposes. Agricultural Research Service, Northern Investment Company , Montana 071954,810 (Jan. 17, 1969). 100 / 30 U.S.C. §§351-359. Blakely M. Murphy, ed., Conservation of Oil and Gas, A Legal History, 1948 , (Chicago: Section of Mineral Law, American Bar Association, 1949), p. 602. - 64 - Federal Oil Conservation Board had discovered extravagant waste, depletion, and over-production of oil. 101/ Coinciding with the closure was a drive to weed out the more than 20,000 permits already granted. Be¬ tween 1929 and 1932, some 16,000 permits were dropped because of failure to pursue exploration and develop¬ ment diligently. 102/ Naturally, the oil industry challenged the action. Ultimately, the Supreme Court upheld the withdrawal in United States ex rel. McLennan v. Wilbur , 283 U.S. 414 (1931). Justice McReynolds, speaking for a unanimous court, held that the Interior Secretary's view that he was only authorized, not obligated, to issue prospecting permits was not unreason¬ able, especially since the Act was passed when it was thought petroleum production was on the verge of a decline but instead there had resulted a "troublesome surplus." 101 / Burl Noggle, Teapot Dome: Oil and Politics in the 1920's (Baton Rouge: Louisiana State University Press, 1962), p. 210. 102 / Murphy, ed., Conservation of Oil and Gas: A Legal History, 1948 , op. cit. , pp. 602, 603. - 65 - In 1930, President Hoover also withdrew oil shale lands from leasing through an Executive order. Hoover's withdrawal was attacked much later by some potential leaseholders. However, in 1966 it was held that the Pickett Act applied to leasing as well as to the specifically named "settlement, location, sale, or entry," and that the Act's provision for a "temporary" withdrawal was not violated by a 36-year withdrawal period, "considering its permanence compared to the life of man, and the significance of oil shale as a natural resource." 103 / Also, while the Mineral Lands Leasing Act authorized the Secretary of the Interior to lease oil shale deposits, it did not compel him to do so. The withdrawal did not eliminate all private rights to public oil shale land, however. While there was little shale leasing in the 1920-30 period, there had been a considerable number of earlier locations under the 1872 Mining Act. Between 1927 and 1933, the Department of the Interior attempted to cancel many of these for failure to perform the required assessment work. 104/ This attempt was frustrated by the Supreme Court, which held that failure to perform assessment work did not invalidate a claim but only made it 103 / Mecham v. Udall , 369 F.2d 1,4 (10th Cir. 1966). / 104/ Maurice T. Reidy, "Do Unpatented Oil Shale Mining Claims Exist?," 43 Denver Law Review , 9, 13, 14 (1966). - 66 - subject to relocation. 105 / The effect of these decisions was essentially to freeze such claims, because after 1920 no public domain oil shale land could have a location made on it. For some time, the Interior Department seemed resigned to its loss and some patents were actually issued to claimants on these lands. 106 / Then, in 1964, the Secretary reversed this policy, holding that decisions canceling claims which had not been appealed earlier were valid. 107 / After losing in both the district and appellate courts, the Secretary was upheld by the Supreme Court. 108/ Justice Douglas' opinion explained what had occurred in most of the 98 claims on appeal: speculators purchased claims from original locators and then per¬ formed one year of assessment work to eliminate possible rival titleholders. The opinion then narrowly construed Krushnic and Virginia-Colorado to apply only to 105 / Wilbur v. United States , e x rel. Krushnic , 280 U.S. 306, 317 (1930); Ickes v. Virginia-Colorado Development Corp ., 295 U.ST 639 (1935). 106 / Reidy, "Do Unpatented Oil Shale Mining Claims Exist?" op. cit. , p. 14. 107 / Union Oil Co. of California , 71 I.D. 169 (1964). 108 / Hickel v. Oil Shale Corp. , 400 U.S. 48 (1970). - 67 - situations where there was "substantial compliance with the assessment work requirements of the 1872 Act," 109 / The withdrawn lands logjam began to break in 1967, when Secretary Udall issued rules and regulations to implement a program of oil shale leasing. 110 / Details of this program will be presented in chapter 8. The Limits of Coverage Where Are the Public Mineral Lands ? The evolution of public mineral land legislation has been traced through the Mining Law of 1872 and the Mineral Lands Leasing Act of 1920, still the two principal statutes governing mineral land disposal. We now delineate exactly what lands are affected. Obviously, neither act covers private or State lands. Only Federal V governmental lands are affected, and of them, only public domain or public lands. Public lands do not include acquired, reserved, or withdrawn lands, or lands 109 / 400 U.S. at 57. 110 / 32 Fed. Reg . 7086 (1967). - 68 - ( covered by water. The mining statutes apply to these lands only if the Congress specifically so provides. The public domain began with the cession of Western land to the United States by those seven of the Original Colonies who had land claims outside their own boundaries. None of the land within the original 13 Colonies was public domain land because each colony succeededfcto the Crown lands in its territory at the end of the Revolutionary War. Nor is any of the land in the four States carved out of the original 13 States: Kentucky, Maine, Vermont and West Virginia. North Carolina put such strictures on her cession to the Federal Government of what is now Tennessee that the United States turned over all its lands therein to the State. 111 / Most of the rest of the public domain has been acquired by purchase or conquest. Texas never contained any public lands because *5 the Texas Republic retained its lands when it became a State. Several other States—Illinois, Indiana, Iowa 111 / The Rocky Mountain Mineral Law Foundation, ed., American Law of Mining , op. cit., §2.2 • - 69 - ( and Ohio—once had public lands, but they were all disposed of even before the 1866 mining law was enacted. Oklahoma was also effectively excluded from the mineral laws by a congressional classification of nearly all its lands as agricultural. Congress has specifically legislated that the Federal mining laws have no application in six other States: Alabama, Kansas, Michigan, Minnesota, Missouri, and Wisconsin. Hawaii was also excluded from the public land laws in force when it became a territory in 1898. 112/ At one time or another, the United States acquired 1.84 billion acres of public domain land. It still possesses 723 million acres of public domain and 50 million acres of acquired lands. On 36 million acres of patented land, the U.S. retains mineral rights. Only 177,818,461 million acres in the conterminous U.S. and 299 million acres in Alaska have not been withdrawn, reserved, or otherwise set aside and remain under the control of the Bureau of Land Management. As might be expected, the remaining public land is basically in the West. Of the 177,818,461 acres, 177,116,170 are in Arizona, 112/ Ibid. - 70 - ( California, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming. 113/ Limitations on the Disposal of Public Lands Reserved, withdrawn and acquired lands are not disposable under the public land mineral laws unless Congress enacts a specific provision that they may be. Reserved lands are those that have been set aside by Congress or the President for a specific purpose, such as national forest reserves, Indian and military reserva¬ tions, national parks and monuments, etc. 114 / Some of these lands, such as the national forests, are still open to mineral entry because of congressional action. 115/ Indian lands are subject to neither the 1872 Mining Act nor the 1920 Mineral Lands Leasing Act. Rather, they are covered by an entirely separate statutory scheme, embodied in two acts, the first passed in 1909 (25 U.S.C. §396) and the second in 1938 (25 U.S.C. §396a-f). These acts 113/ Ibid. 114/ Ibid., §2.1. 115/ Ibid., §2.3. - 71 - provide for the leasing of Indian land. No location or claims are allowed, even for hard-rock minerals. Withdrawn lands are similar to reserved lands. The term came into being during the Roosevelt-Taft era. The distinction between the two is not altogether clear, but the withdrawal form of removal has more of a temporary air. As with reserved lands, certain with¬ drawn lands are open to mineral entry. For instance, lands whose withdrawal from coal or oil and gas develop¬ ment was ratified by the Pickett Act remain open to mining for metalliferous minerals. 116 / Acquired lands are, as the name implies, lands obtained by the United States from private parties or States, usually for a specific public purpose. They are not generally subject to the mineral land laws. However, in 1947 Congress passed the Acquired Lands Act (30 U.S.C. §351 et seq. ) which provides that the Secretary of the Interior may lease acquired lands under the terms of the Mineral Lands Leasing Act of 1920. The Acquired Lands 116/ Ibid. - 72 - ( Act applies only to minerals covered by the 1920 Act. In other words, uranium and other hard-rock minerals may not be so leased. But in Reorganization Plan No. 3 of 1946, the responsibilities of the Secretary of Agriculture over the bulk of acquired lands were transferred to the Secretary of the Interior. 117 / These responsibilities and powers had been laid out in a series of acts through which the United States acquired land, among them Title II of the National Industrial Recovery Act of June 16, 1933 [40 U.S.C. §401, 403(e) and 408]; the Act of March 4, 1917 (16 U.S.C. §520); the Emergency Relief Appropria¬ tion Act of April 8, 1935 (49 Stat. 115, 118); Section 55 of Title I of the Act of August 24, 1935 (49 Stat. 750, 781); and the Act of July 22, 1937 (50 Stat. 522,525,530), as amended July 28, 1942 [7 U.S.C. 1011(c) and 1018]. Most hard-rock mineral exploration and development on acquired lands is done under leases issued by the Secretary of the Interior pursuant to the powers granted to him by Reorganization Plan No. 3. Given Reorganization Plan No. 3 and its leasing provisions, one might think the Acquired Lands Act redundant. While the Acquired Lands Act is broader 117/ 60 Stat. 1099 (1946). - 73 - than the Reorganization Plan in some ways, the crucial difference was summed up in a May 12, 1947, letter from Assistant Secretary of Agriculture Charles Brannan, vehemently protesting the extension of the Mineral Lands Leasing Act's provisions to acquired lands because of the loss of revenue which would result. The Department of Agriculture generally used competitive bidding in its leasing; the 1920 Act authorizes competitive bidding only for known geologic structures. Brannan claimed that in a two-year period, the Department of Agriculture took in $3.2 million in bonuses alone on lands not within any known structure—lands for which leases under the 1920 Act would have collected only a nominal sum. Agriculture's rental fees were also higher than those under the 1920 Act. 118 / The Outer Continental Shelf Lands We noted earlier that watery areas were not included within the public domain covered by the 1872 and 1920 acts. This lacuna became important when the 118/ U.S. Code Congressional & Administrative News, pp. 1664-1666 (1947). - 74 - Supreme Court held that all submerged coastal areas belong to the United States, not to the individual States. 119/ Prior to the 1930's, it had been widely presumed by the States and acquiesced in by the Federal Government that submerged lands within the three-mile limit belonged to the Coastal States. Oil drilling off the California coast began in 1897 with no Federal protest. In 1921 California passed a statute enabling it to lease these lands. Louisiana and Texas took similar steps. The Interior Department declined to issue a permit to drill off the California coast on the ground that California owned the land. 120/ Then, in 1937, Secretary of the Interior Ickes persuaded Senator Nye of North Dakota to introduce a resolution claiming Federal ownership of the submerged land. It passed the Senate, but died in the House. The legislative tide shortly changed and in 1946 and 1952, 119/ United States v. California , 332 U.S. 19 (1947). See also United States v. Louisiana , 339 U.S. 699 (1950); United States ~v. Texas , 339 U.S. 707 (1950). 120 / Joseph Cunningham , 55 I.D. 1,2 (1934). - 75 - both Houses of Congress passed resolutions quit-claiming any Federal interest in the submerged lands, only to have President Truman exercise a veto. 121 / In the meantime, the Executive Branch brought and won three submerged land cases against California, Louisiana, and Texas. Finally, when Dwight D. Eisenhower became President, the quitclaim measure was passed again and signed into law as the Submerged Lands Act (43 U.S.C §1301 et. seq. ) . The supporting House Report cited the need to settle the ownership question once and for all to promote immediate development of the submerged land— development which, it said, had been almost brought to a standstill. 122 / The Submerged Lands Act relinquished Federal title to all land up to three miles from a State's coastline. The original bill included provisions governing areas 121 / Nossaman, Waters, Scott, Krueger, and Riorden, Study of Outer Continental Shelf Lands of the United States , for the Public Land Law Review Commission, vol. II, ch. 3, pp. 125-129 (1969). 122/ U.S. Code Congressional & Administrative News, pp. 1385, 1386 (1953). ( - 76 - beyond the three-mile limit, but they were dropped before final passage. Instead, these provisions after slight amendment became the Outer Continental Shelf Lands Act (43 U.S.C. §1331 et seq. ) passed later in 1953. 123/ The total U.S. Continental Shelf area covers some 290,000 square miles (with an additional 600,000 square miles off Alaska), extending as much as 250 miles offshore in places. Roughly 27,000 square miles lie within the three-mile limit and belong to the States. The Outer Continental Shelf Lands Act (OCSLA) authorizes leasing of the remaining 90 percent of the Shelf. 124/ The central provision of the OCSLA allows the Secretary of the Interior to grant leases for oil and gas exploration to the highest qualified bidder chosen by competitive bidding. Bids are sealed and, at the Secretary's discretion, may be on the basis of a cash bonus, with a royalty of at least 12.5 percent. 123 / Ibid ., p. 2177. 124/ Ibid., p. 2178. - 77 - Oil and gas leases run for five years and as long there¬ after as there is production, or as long as drilling or reworking operations approved by the Secretary are continued. Leases are for no more than 5,760 acres. 125/ Sulfur leasing is also explicitly covered, and there is a provision that other minerals (except for uranium and similar minerals) may also be leased on a competitive bidding basis. All helium produced belongs to the United States. 126 / Another section stipulates that anyone who wants to can conduct geological and geophysical explorations on the Continental Shelf, as long as he obtains the permission of the Secretary and does not interfere with lease operations or unduly harm aquatic life. 127 / AEC Leasing on Federal Lands The one energy mineral still subject to location and patent is uranium. But for a time, even uranium was a leasable mineral. The AEC leasing program grew 125 / 43 U.S.C. §1337. 126 / 43 U.S.C. §§ 1337, 1341(e), (f). 127/ 43 U.S.C. §1340. - 78 - out of uranium's new-found importance as the prodigal atomic energy source. Only a month after Hiroshima was bombed. Executive Order 9613 of September 1945 reserved all lands containing radioactive materials. This Order was relaxed a few months later, and in 1946 the Atomic Energy Act was passed. It allowed patenting and leasing of public lands containing fissionable materials, but permitted the Government to requisition any such materials mined. The 1946 Act also allowed the AEC to explore and have land containing fissionable materials withdrawn from entry. Nearly 1,000 square miles of Colorado and Wyoming were withdrawn. 128 / Leasing of this land began in 1947. Between 1947 and 1962, 50 leases were issued, and in 1973 the AEC leased the last 25,000 acres it had withdrawn. The leased land produced in total only about one percent of the Nation's uranium up to 1974. The 1973 leases were estimated to hold about one percent of the Nation's uranium reserves by an AEC source. 128/ USAEC Hearings on Leasing Methods and Procedures, Grand Junction, Colorado, March 29-31, 1955, pp.3, 4. - 79 - Geothermal Leasing Some rather specialized public lands are those containing geothermal resources. Because geothermal reservoirs consist of hot or super-heated water or steam, which are not legally considered minerals, they cannot be located under the 1872 Mining Act or leased under the 1920 Mineral Lands Leasing Act. Because the Department of the Interior believed existing legisla¬ tion did not entitle it to dispose of public geothermal lands, 129 / development of geothermal resources lagged in the United States, although they have long been used as a source of energy for heating and the production of electricity in other countries. The problem was resolved by passage of the Geothermal Steam Act of 1970, which authorizes geothermal resource leasing. 130/ Details are discussed in chapter 11. 129/ U.S. Code Congressional & Administrative News, pp. 5115, 5116 (1970). 130/ 30 U.S.C. §§1001-1025. - - 80 - Conflict Over Multiple Use While some public domain land is reserved for specific purposes, most can be disposed. But who will be allowed to use it? For some land, that is no problem. It may lie in a fertile prairie useful only for agriculture, or on a barren mountainside with only hard- rock mineral deposits. But often land is useful for more than one purpose; e.g., for grazing and mining. President Roosevelt recommended in 1907 that title to the surface land be distinct from the underlying minerals, and a series of statutes between 1909 and 1914 allowed nonmineral entry on coal and oil and gas lands. 131 / The Stockraising Homestead Act of 1916 (43 U.S.C. §291 et seq .) let homesteaders patent stockraising land, but with a mineral reservation to the United States. The Taylor Grazing Act of 1934 (43 U.S.C. §315) allows ranchers to graze livestock on public land for a fee. 131/ Swenson, "Legal Aspects of Mineral Resources Exploitation," op. cit. , p. 755. - 81 - Perhaps an even thornier problem arose from the conflict between the location and leasing systems. Some land contained both hard-rock minerals and leas¬ able minerals. Could locations for hard-rock minerals be made on leased land, or could leases be granted for non-metalliferous minerals on land covered by a claim? The first consideration of the question seems to be the case of Joseph E. McClory et al ., 50 L.D. 623 (1924). The factual situation was simple: McClory discovered gold and applied for a mineral patent on land for which one Sackett had been granted an oil and gas lease. McClory was willing to have an oil and gas reservation placed in his patent, but Interior decided it had no authority to issue a patent containing a reservation. The Department admitted that "the effect of this decision seems to bar the exploration and purchase under the mineral land laws of metalliferous minerals con¬ tained in lands covered by a subsisting permit in good standing . . . ." 132 / But a prior claim does not necessarily defeat a lease under the 1920 Act. Another 1924 Interior opinion, this time given in answer to a congressman's question, held that: 132/ 50 L.D. at 626. . . . the Department would be unable to recognize as of any validity a mining location sought to be made, since the dates of the leasing acts, on account of a metallif¬ erous deposit, of land known at the time of such attempted location to be valuable for any of the minerals named in the acts. 133/ But if a parcel of land is not known to be valuable for leasing minerals when a claim is made on it, the location does defeat any subsequent attempt to lease the land. 134/ The tension between the 1872 and 1920 acts was not important enough to engage Congress' attention until the post-World War II uranium boom. The uranium ore found in the Colorado Plateau area generally occurred in a type of sedimentary deposit which also might contain oil and gas. As much as 75 percent of the available uranium land was already under oil and gas leases. 135 / Clearly, a change had to be made if uranium was to be mined. 133 / 50 L.D. 650,652. 134 / Jebson et al. v. Spencer et al. , 61 L.D. 161 (1953). 135 / Swenson, "Legal Aspects of Mineral Resources Exploita¬ tion," op. cit. , p. 751. - 83 - The first result was the passage in 1953 of the Uranium Relief Act, Public Law 250. It provided a procedure for the validation of all claims filed between July 31, 1939, and January 1, 1953, located on land leased under the 1920 Act or known to be valuable for minerals covered by the Act. The Leasing Act minerals were reserved to the Federal Government. 136/ This stop-gap legislation was superseded by a broader measure, the Multiple Mineral Development Act of 1954 (30 U.S.C. §§521-31). The goal of the Act was to further the development of U.S. mineral resources by allowing development of both locatable, especially uranium, and leasable minerals to proceed simultaneously on the same tract of land. The Senate Report noted that one immediate effect would be freeing 60 million acres of public land, then under oil and gas leases, to location for uranium and other minerals. 137 / Both the National Petroleum Council and the American Mining Congress supported the concept of the legislation. 138/ 136 / 30 U.S.C. §§501-05. 137/ U.S. Code Congressional & Administrative News, pp. 3026, 3027 (1954). 138/ Ibid., pp. 3026-3028. The - 84 - core of the Act is simple. Both leases and locations are permitted on the same public land. The law was changed to allow locations on leasable land, but all patents or mining claims became subject to a leasable minerals reservation if on land covered by a lease or lease application, or if on land known to contain valuable leasable minerals. Each type of operation must be carried on "so far as reasonably practicable, in a manner compatible with such multiple use." 139 / Uranium was the cause of another piece of multiple land use legislation. While the Multiple Mineral Development Act took care of the case where oil and gas and uranium existed in different strata under the same surface, a new problem had arisen. On certain lands, particularly in South Dakota, uranium was dis¬ covered on lands containing lignite. There were thousands of conflicting mining claims located thereon. 140 / The lignite and uranium did not occur in different strata, but were intermixed; the uranium 139 / 30 U.S.C. §526 et seq. 140/ U.S. Code Congressional & Administrative News, pp. 2993, 2994 (1955) . - 85 - could not be mined without removing the lignite as well. Consequently, the Bureau of Land Management held that such lands were not subject to location. 141 / To break the impasse, an act was passed allowing locations on and patents of lignite lands containing uranium with a payment to the United States of $.10 for every ton of lignite mined. 142 / At the suggestion of the Interior Department, the act's life was limited to 20 years because of the possibility that lignite, while not greatly in demand in 1955, might be in the future. 143/ Therefore, the statute was written to expire on August 11, 1975, with the President authorized to extend its effectiveness another 10 years. The expiration date passed recently with no extension by the President. The Continuing Debate How best to dispose of mineral resources on public lands is still a hotly-debated issue. Congress has recently been considering major changes in public mineral land laws. The debate is still between champions of the location 141 / Ibid. , p. 2994. 142 / 30 U.S.C §541. 143/ U.S. Code Congressional & Administrative News pp. 3000, 3001 (1955). - 86 - system, stressing free and rapid development, versus the proponents of leasing and conservation. The main contemporary question is whether hard-rock minerals should be treated in the same way as leasable minerals. Since this issue significantly affects only uranium of the energy resources analyzed in the present volume, further discussion is best deferred to chapter 10 which deals specifically with uranium. An important focal point in the debate over mineral resource policy was the report issued in 1970 by the Public Land Law Review Commission. 144 / In addition to recommending changes in the system for claiming hard- rock minerals, the Commission proposed that a greater proportion of oil and gas leases be subject to competi¬ tive bidding. Three commissioners went even further. They advocated the abolition of all non-competitive leasing. 145 / The general economic analysis of energy resource exploitation approaches and the detailed analyses of specific fuels which follow in subsequent chapters will. 144 / Public Land Law Review Commission, One Third of the Nation's Land , op. cit. 145/ Ibid., pp. 132, 133. - 87 - we hope, contribute constructively to the current debate over Federal land policies. Yet, if our survey of the earlier debates is any guide, the choice of new policies will not be an easy one. Deep-seated differences in the way various actors perceive the policy goals will have to be resolved. We cannot settle those basic goal conflicts, but we shall in the pages which follow attempt to keep them clearly in view. Chapter 3 ECONOMIC THEORY AND ALTERNATIVE LEASING POLICIES Introduction The focus of this chapter is essentially twofold. First, considerable effort is devoted to developing the relevant tools of economic theory with which to characterize the performance of markets for energy resources. In the first section, supply and demand analysis is used to explain how markets determine how much output will be produced and what price will be charged. In the next two sections, the analysis is expanded to characterize market behavior when resources have to be allocated over time and in the face of uncertainty. In addition, the concept of economic efficiency is developed as a standard against which to measure the actual performance of private markets and as a socially desirable resource allocation criterion. Although the discussion may at times be complex and abstract, an understanding of the meaning and importance - 89 - of economic efficiency as a criterion for judging leasing policy and how markets function in different leasing environments is crucial to the development of a rational and effective leasing policy. We make two fundamental assumptions in our characteri¬ zation of market behavior. We assume that the amount of a good which consumers purchase at any given price is the amount they in fact desire to purchase at that price, given their income and the prices of other goods and services which they could purchase instead. In other words, we assume that consumers are not constantly deceived about what goods they "really" want. 1/ Furthermore, we assume that the amount of a good which producers supply at any given price is the amount that maximizes their profits, subject to their costs of production. In other words, we assume that the dominant objective of producers is profit maximiza¬ tion rather than some other goal such as maximizing 1/ For an alternative view of consumer preferences, see J. K. Galbraith, The Affluent Society (Boston: Houghton Mifflin, 1958) . - 90 - managerial perquisites. 2/ Given these assumptions, it is possible to say a good deal about consumer behavior, producer behavior, and hence market behavior. In evaluating efficient resource allocation, economists embrace a normative assumption that consumer sovereignty should be respected in consumption decisions. We do not propose to say what is best for consumers, but rather assume that their market behavior is the best measure of what is best for them. 3/ Our standard of efficiency will be the "Pareto criterion." 4/ An allocation of resources will be considered efficient if there is no possible reallocation that can make one member of society better off without at the same time making another member of society worse off. 2/ For a discussion of alternative views of the profit- maximization assumption, see F. M. Scherer, Industrial Market Structure and Economic Performance (Chicago: Rand McNally & Company, 1970), p. 27ff. 3/ Cf. Scherer, loc. cit ., pp. 19, 20. £/ For a more detailed discussion of the Pareto criterion, see any intermediate microeconomics textbook; e.g., C. E. Ferguson, Microeconomic Theory (Homewood, Ill.: Richard D. Irwin, Inc., 1972), p. 472. - 91 - The Pareto criterion is a conservative standard for evaluating resource allocation. It is concerned with the prevention of waste and not with the distribu¬ tion of economic well-being which results from efficient resource allocation. If society has standards of equity in the distribution of economic welfare, it might be quite willing to make one wealthy individual worse off by reallocating resources if the transfer improves the welfare of a disadvantaged person. Nevertheless, it seems reasonable that society should make any income transfers as efficiently as possible. If the economic pie is to be sliced and distributed differently from the distribution obtaining in the competitive market, then the reduction in the size of the pie resulting from such a redistribution should be minimized. Economic theory provides no unique insights into these distributional questions. Nevertheless, in the discussion which follows, we will try to identify the ♦ broad groups in society—consumers, producers, resource owners, and taxpayers—that benefit or suffer under alternative land disposal policies. When resources are allocated efficiently, the total pie available for - 92 - 4 redistribution is as large as possible. The distribu¬ tion which can feasibly be achieved may not be as favorable, however, as another distribution which could be achieved with the sacrifice of some efficiency. Economic theory cannot determine whether the equity gain is worth the efficiency cost, but it can describe the choices for the policymakers who must ultimately decide. The material which follows is organized according to the following plan: 1. The section titled "Static Efficiency" analyzes market behavior and economic efficiency in a static context in which decisions made about current supply and demand have no effect on future conditions. In this context, bonus bid leasing is demonstrated to lead to efficient resource allocation by the competitive market, as well as to maximize Government revenue, consistent with efficient resource allocation. 2. The section titled "The Efficient Allocation of Exhaustible Energy Resources" analyzes market behavior and economic efficiency in situations where - 93 - resources are exhaustible and production today affects future production possibilities. 3. The section titled "The Effects of Uncertainty on Market Behavior and Economic Efficiency" analyzes the effects of uncertainty about future supply and demand conditions. Two issues are considered. On the one hand, the competitive market may not be able to allocate resources efficiently in the presence of uncertainty. On the other hand, there is uncertainty about the dis¬ tribution of economic welfare which will result even if resources are allocated efficiently. In this section we examine conditions under which bonus bidding will still accomplish the objectives of Government mineral land policy, leaving a consideration of alterna¬ tive leasing policies to Chapter 5. Static Efficiency 5/ Production Costs and the Supply of Energy Resources In this section we examine the conditions determining the "supply schedule" for an energy resource such as petroleum. The supply schedule for petroleum is a method of relating the amount of petroleum producers are willing to supply to the price at which petroleum can be sold. Since businessmen are presumably in business to make money, they will be interested in supplying petroleum only if the price at which petroleum can be sold is at least as great as the cost of producing it. In addition to such costs as wages, salaries, and the cost of materials, the "opportunity cost" of business firms contemplating investing in the petroleum industry needs to be covered if they are actually to participate. This opportunity cost is the profit which would be earned in the next-best alternative to 5/ Cf. H. D. Henderson, Supply and Demand (London, Cambridge, 1922), and J. de V. Graaf, Theoretical Welfare Economics (Cambridge: Cambridge U. Press, 1967) . - 95 - petroleum production. An individual entrepreneur who is considering entering the petroleum industry has to decide if his expected profits are at least as attrac¬ tive as the profits he would expect to earn by devoting his time and energy to some other business venture. Similarly, stockholders will evaluate the profitability of petroleum production as compared to other investment opportunities open to them in deciding whether to invest in petroleum companies. This "opportunity cost" is often called the "normal profit," or the minimum profit required to attract firms into petroleum produc¬ tion rather than into some other industry. As such, it is a cost just like the competitive wage which must be paid in order to attract labor into the petroleum industry. Production costs for different sources of petroleum vary widely. This is so because there is considerable variability in the physical characteristics of petroleum sources. For example, an operation located far offshore and drilled into a deep pool will be more expensive than an equally productive operation located onshore and drilled into a pool located close to the surface. Furthermore, there is considerable variation in the productivity of different petroleum deposits. Large pools with strong natural drive are less expensive to tap than smaller pools or older pools which require the application of secondary recovery techniques. If we were to take an inventory of known petroleum sources in the United States at any moment in time, it would be possible to rank those sources according to their costs. The best sources would have the lowest production costs per barrel, and costs vc uld increase as the quality of the sources declined in terms of productivity and accessibility. Table 3.1 represents a highly stylized and hypothetical example of such an inventory in which there are only three sources of petroleum. Suppose that all of the oil-bearing property in these three areas is in the public domain and that any oil producer who wants to can have access to this property for a nominal claiming fee (which is included as a production cost in table 3.1). Then, if the price of oil is slightly above $9 per barrel (e.g., $9.05), there will be a rush to stake claims to area A, - 97 - TABLE 3.1.—Hypothetical Inventory of Petroleum Sources Production Cost Production Source (dollars per barrel) (barrels per day) Area A 3.00 6,000,000 Area B 9.00 4,000,000 Area C 15.00 2,000,000 since production costs are only $3 per barrel. Once all the oil-bearing land in area A has been claimed and production is six million barrels per day, there are no more sources of oil which can be developed at a cost of only $3 per barrel. If there is to be any further production, it can only come from sources of lower quality and higher cost. Still, a price of $9.05 per barrel is just enough to allow for production in area B as well. Production costs, including a normal profit, are more than covered by the $9.05 price. Hence, there is no opportunity more profitable than oil production available elsewhere in the economy, and firms should be willing to produce petroleum on area B property. The story is quite different with respect to area C. Here production costs are greater than price, and no one would be interested in supplying oil from area C. The supply of oil at $9.05 per barrel is therefore the six million barrels per day produced by firms operating in area A and the four million barrels per day produced by firms operating in area B. - 99 - If the price of oil should drop below $9.00 per barrel, profits from producing in area B would drop below the level of normal profits, and no one would wish to continue investing in oil production in area B. On the other hand, if the price of oil should rise to $15.00 or more per barrel, normal profits could be earned even in area C, and the supply of oil would expand by the production of two million barrels of oil per day forthcoming from area C. Thus, any price greater than or equal to $3 per barrel will elicit production of six million barrels per day from area A; any price greater than or equal to $9 per barrel will call forth an additional four million barrels per day from area B; and any price greater than or equal to $15 per barrel will increase supply still further by the two million barrels per day produced from area C. This information can then be used to construct the supply schedule for petroleum which appears as table 3.2. An alternative way of representing this same information is to use the "supply curve," a geometrical representation of the relationship between the price TABLE 3.2.--Hypothetical Supply Schedule for Petroleum Petroleum price (dollars per barrel) Quantity supplied (barrels per day) Less than 3.00 0 At least 3.00 but less than 9.00 6,000,000 At least 9.00 but less than 15.00 10,000,000 At least 15.00 12,000,000 of petroleum and the quantity supplied. Figure 3.1 represents the supply curve derived from the supply schedule of table 3.2. Price is read on the vertical axis, and quantity supplied on the horizontal. Picking any price, such as $8, the quantity supplied at that price can be found by locating the point on the supply curve corresponding to the $8 price and dropping down to the quantity axis to find that six million barrels per day are supplied at the $8 price. Alternatively, the price necessary to elicit any given level of output, say eight million barrels per day, can be found by locating the point on the supply curve corresponding to eight million barrels per day and reading across to the price axis to find that the price has to be $9 a barrel to elicit a supply of eight million barrels per day. The hypothetical inventory of petroleum sources from which figure 3.1 has been constructed is rather unrealistic in its assumption that there are only three distinct areas from which petroleum can be produced and that costs are identical on all properties in a given area but differ markedly between areas. Any realistic inventory of petroleum sources in the United States -102- Price (dollars per barrel) |FIGURE 3.1.--Hypothetical Supply Curve Quantity (million barrels per day) t -102A- ■rr would show an almost continuous increase in production costs as one moves from the highest quality resources to the worst quality. 6 _/ Instead of a supply schedule with distinct price jumps required to bring about increases in supply, we would have a supply schedule for which even small increases in price would elicit at least small increases in supply. Instead of a step-like supply curve as in figure 3.1, we would more realistically expect to have an almost smooth supply curve such as that drawn in figure 3.2. The Supply Curve and the Social Cost of Production At any moment in time, the productive resources of the economy are in scarce supply. If they are fully employed, the only way to increase the supply of one good, such as petroleum, is to withdraw the necessary i men and machines from the production of some other good, such as coal. The value of coal production which is lost when petroleum production is increased represents the "social cost" of the increase in petroleum production. We call the minimum incremental cost entailed in increasing petroleum production by a single barrel the 6/ See, for example, the testimony of Henry Steele in U.S. Senate, Committee on the Judiciary, Subcommittee on Anti¬ trust and Monopoly, Hearings, Governmental Intervention in the Market Mechanism: The Petroleum Industry, pt. 1, TT9'69) , ppY 208-222.- -103- Price (dollars barrel) FIGURE 3.2 -- Hypothetical Smooth Supply Curve / -103A- I "marginal social cost" of petroleum production. When the prices of all inputs into petroleum production measure the value of the output which these inputs could produce in alternative uses, the production cost of the marginal barrel of oil which is being supplied also represents the marginal social cost of petroleum produc¬ tion . For example, table 3.1 tells us that the first six million barrels of oil which are produced can be produced at a cost of $3 per barrel. For any level of output up to six million barrels, the marginal social cost of petroleum is $3, since the incremental cost of producing one more barrel is the $3 production cost of that barrel. However, when production is six million barrels, marginal social cost jumps to $9, since the marginal barrel, the six-million-and-first, can only be produced at a cost of $9. Up to ten million barrels, marginal social cost remains at $9, but the ten-million- and-first barrel can only be produced at a cost of $15. Hence, marginal social cost at a production level of ten to twelve million barrels is $15. -104- If we wish to calculate the total social cost for any level of supply, where total social cost represents the total value of other goods and services foregone due to the use of resources in petroleum production, we can add up the marginal social cost of each individual barrel (as long as the prices of inputs are not affected by the level of petroleum industry output). Thus, the total cost of producing eight million barrels of oil in figure 3.1 is $36 million, since the marginal cost of each of the first six million barrels is $3 and the marginal cost of the remaining two million barrels is $9 ($3 x 6,000,000 + $9 x 2,000,000 = $36 million). Remembering that marginal cost represents the increment in costs from an increment in production, we get total cost by adding up the costs of each increment. Since the minimum price required to elicit the marginal barrel supplied at any level of output is equal to the production cost of that barrel, this supply price is an accurate measure of social cost at that level of production as long as production costs are an accurate measure of social costs. Thus, by adding up the supply prices of each increment in output, we can calculate the -105- total social cost of producing a given level of output. Geometrically, the price read off the supply curve represents the marginal social cost of a given level of output and the area under the supply curve represents the total cost of a given level of output. Consumer Tastes and the Demand for Energy Resources In this section we examine the conditions which determine the characteristics of the "demand schedule" for an energy resource such as petroleum. The demand schedule for petroleum is a method of relating the amount of petroleum consumers demand to the price at which petroleum can be purchased. If consumers have some sub¬ jective scale of values and evaluate their purchases rationally, then the amount of petroleum they purchase will be such that the subjective value of each barrel of petroleum purchased is at least as great as the subjective value of any other good or service which could be purchased instead. Although we cannot measure consumers' subjective evaluations of their purchases directly, we can observe their purchasing behavior. Since the price of a good -106- such as petroleum is a measure of the value oi other goods and services which have to be foregone in order to purchase an additional barrel of oil, consumers' willingness to make the petroleum purchase is evidence that the subjective value of that barrel of oil is greater than the subjective value of other goods and services which could be bought with the same amount of money. If consumers place diminishing subjective value on each additional barrel of petroleum they consume, they will be willing to sacrifice fewer and fewer other goods and services for each increase in their petroleum con¬ sumption. Thus, consumers will increase their demand for petroleum only in response to a fall in price, which reduces the value of other goods and services whose consumption must be foregone to make increased petroleum consumption possible. For example, if the demand for petroleum is 12 million barrels per day when the price of petroleum is $3 per barrel, we conclude that for each of those 12 million barrels consumers have found uses which they value at $3 or more. Otherwise, the demand for petroleum would be less than 12 million barrels per day. We also -3 07- / conclude that no use which any consumer values at $3 or more can be found for a 12,000,001st barrel of oil, because if such a use existed, the demand for oil would be greater than 12 million barrels per day. If the price of oil should drop below $3, then the demand for oil will increase by the number of barrels that can satisfy needs and wants which the consumer values between $3 and the new lower price. On the other hand, if the price of oil should increase, the demand for oil will decline by the amount of oil which only satisfies needs valued between $3 and the new higher price. The demand curve in figure 3.3, like the supply curve in figure 3.2, depicts geometrically the relation¬ ship between price and quantity derived from the demand schedule. It can be used to determine either the quantity of a good which will be demanded at any particular price or the maximum price that will still elicit any particular demand. If consumer sovereignty is respected, then the demand price can also be inter¬ preted as the value society places on the con¬ sumption of the marginal barrel of oil. We might designate this value as the "marginal social value" of -108- f \ « petroleum. For example, in figure 3.3 a price of $3 per barrel is associated with a demand for 12 million barrels of oil per day. Three dollars is the maximum value of other goods and services society is willing to give up in order to be able to consume 12 million barrels of oil per day rather than 11,999,999 barrels per day. Just as the area under the supply curve represents the total social cost of producing any given level of output, the area under the demand curve represents the total social value of any given level of output. The demand price of each incremental unit of output measures the incremental or marginal value of the increase in output. Hence, total value is obtained by adding all the incremental increases. In terms of the demand curve's geometry, the price read off the demand curve measures the marginal social value of output and the area under the demand curve measures the total social value of output. -10 9- 0 Price (dollars per barrel) I FIGURF 3.3•--Hypothetical Demand Curve / ( ¥ -109A- k Equilibrium in the Market for Energy Resources Unless the market price for an energy resource such as petroleum is such that the demand for petroleum at the market price is equal to the supply of petroleum at that price, there will be either excess demand or excess supply. If there is excess demand, there are some consumers who would be willing to purchase more petroleum at the market price but are unable to find a producer willing to sell to them. If there is excess supply, there are some producers who are willing to sell more at the market price but are unable to find buyers. These two situations are represented in figures 3.4(a) and 3.4(b), respectively. If there is excess demand, some consumers are willing to pay more than the market price in order to be able to make a purchase. If they are able to express this willingness to producers, the market price will rise and the supply will increase to the point at which demand equals supply. If there is excess supply, some producers who cannot find buyers at the market price will cut their price. Those producers with the highest -110. production costs will not be able to withstand the price reductions and will cease production. The quantity supplied will decrease and the market price will fall until the excess supply is removed and supply equals demand. When demand equals supply at the market price, the market is said to be in equilibrium. Figure 3.5 represents market equilibrium at a price of $9. I FIGURE 3.4(a)— Excess Demand Price (dollars per barrel) (million barrels per da FIGURE 3.^(b)—‘ Excess Supply l Price (dollars per barrel) The Efficient Level of Production If society is to derive the maximum value from its scarce resources, the allocation of those resources should be organized efficiently. The level of a good's production is efficient if no change in the level of output can increase the social value of output by more -112- than the social cost. If the demand price reflects the marginal social value of production and the supply price reflects the marginal social cost, then the efficient level of output is the competitive market equilibrium level of output. At this level of output, marginal social value is equal to marginal social cost. In figure 3.5, the efficient level of output in petroleum production is eight million barrels per day, and the price is $9 per barrel. To see that this is in fact the efficient level of production, consider first a situation in which output is only six million barrels per day. At this level of output, the marginal social value of output, measured by the demand price, is greater than the marginal social cost, measured by the supply price. Consumers put a value of $12 per barrel on increases in petroleum output, while the value of other goods and services which they would have to sacrifice in order to achieve increases in output is only about $8 per barrel. Clearly, it is worthwhile to increase output up to the point at which the value of another barrel of petroleum is just equal to the cost of producing that barrel. This result is FIGURE 3.5.--Market Equilibrium Price -113A- achieved when the demand price, which falls with increases in output, becomes equal to the supply price, which rises. Consider now a situation in which output is greater than eight million barrels of oil per day. Suppose it is 12 million. At this level of output, consumers value oil at $3 per barrel while the cost of oil is $12 per barrel. If output is cut back, costs are reduced by $12 and the value of the output which is lost is only $3 per barrel, leaving a net social gain of $9 per barrel. Clearly, such a reduction in output should take place up to the point at which the value lost reducing output by another barrel becomes equal to the cost savings effected through reducing output by another barrel. Once more, this result is achieved at eight million barrels of oil, where the demand equals the supply. The Distribution of Economic Welfare The net social value of each barrel of oil produced is equal to the difference between the value of other goods and services which consumers would be willing to give up rather than not have that barrel produced and the value of other goods and services whose production does actually have to be sacrificed in order to free the resources necessary to increase production by a barrel. This net value per barrel declines with increasing production as the value of each additional barrel falls and the cost of producing each additional barrel increases. At the competitive equilibrium level of out¬ put, the net social value of the marginal barrel is zero. The total net value of output, therefore, can be obtained by adding the net values of each barrel produced. The net social value of production can be represented geometrically by the area between the demand curve and the supply curve up to the market equilibrium level of output. Efficient resource allocation implies that the net social value of output is maximized. Society might nevertheless be concerned not only with the net value of output, or the size of the economic pie, but also with the way the pie is sliced up and distributed among various groups within the economy. We will be concerned with the distribution of this net value of output between -115- two categories: "consumers' surplus" and "economic rent." 7/ Consumers' surplus is defined as the difference between the value which consumers would be willing to pay in order to make a purchase and the amount which they actually have to pay. For example, if the value to consumers of the six millionth barrel of oil supplied is $12 and they only have to pay $9 per barrel, then there is a consumers' surplus of $3. A shrewd petroleum producer could possibly extract this full surplus from a consumer who was ignorant of the going market price. 7/ The use of consumers' surplus and rent to measure the welfare effects of Government policy can be found in Marshall's classic Principles of Economics . Book III, chapter 6 deals with consumers' surplus; appendix H with producers' surplus—which corresponds to our rent concept [cf. M. Blaug, Economic Theory in Retrospect (Homewood, Ill.: Richard D. Irwin, Inc., 1968), p. 390, in which Blaug identifies Marshall's producers' surplus concept as Ricardian rent]. Subsequent analysis has dealt with numerous technical difficulties with Marshallian surplus (cf. Blaug, pp. 359-375. Nevertheless, at our elemen¬ tary level of exposition it is useful and instruc¬ tive to use Marshall's consumers' surplus and (Ricardo's) rent to measure the welfare effect of Government mineral disposal policies. In general, however, the consumers' surplus accrues to well-informed consumers. We can represent consumers' surplus geometrically as the shaded area C in figure 3.6. The demand price at each level of output is the marginal value of output, and $9 is the price which actually has to be paid. All consumers who consume petroleum which they value at more than $9 enjoy consumers' surplus. Economic rent is the portion of the price paid for a good which does not affect supply. Thus, it is the difference between the market price and production costs. From the supply schedule of table 3.2, it should be clear that a price of $9 per barrel would be required to elicit production of nine million barrels of oil per day, but that producers of the six million of those barrels that come from area A would be willing to supply their oil even if the price were only $3 per barrel. This difference between the price actually received and the minimum price at which producers are willing to supply their oil is called economic rent. -117- r L FIGURE 3.6. --'Hie Distribution of Economic Welfare Price (dollars per barrel) Quantity (million barrels per day) / L. -117A- Economic rents arise from situations in which a resource is in fixed supply. In this case, the number of high-quality petroleum sources is sufficient only to produce six million barrels of oil at $3 per barrel. Were it not for this limitation in the amount of high quality petroleum reserves, a price of $9 per barrel could not be supported. If there were more oil produc¬ ible at $3 per barrel than the market wished to purchase, anyone willing to sell at $3 could take the business away from someone trying to charge any higher price. Although the producer selling at $3 would only make "normal" profits, any producer trying to charge a higher price would have no customers and hence no profits. Such a situation will arise in our example whenever the demand for petroleum drops below six million barrels per day. When demand is greater than six million barrels, however, there is not enough oil producible at $3 to meet the entire demand. Producers who are fortunate enough to have access to $3 oil can sell all they produce for $9 without satisfying the entire demand. The gap between the total demand for oil and the supply of $3 oil has to -118- be met out of $9 oil. It is the cost of the marginal barrel of oil which determines the price all producers charge. Any difference between this market price and the actual costs of producing on a given source is an economic rent. Clearly, changes in market price lead to changes in the size of these rents. If demand should drop below six million barrels per day, additional $3 oil is still available and all rents will be eroded. On the other hand, if demand should increase to more than 10 million barrels per day, $15 oil must be produced to meet the incremental demand, and rents will be earned on both $3 oil and $9 oil. In our more realistic example, assuming a smooth supply curve, any increases in price have two effects. On the one hand, the price increase makes it worthwhile for producers to increase supply by operating on petroleum sources of lower quality and higher costs. On the other hand, producers who already were supplying petroleum will continue to do so and will benefit from increases in rents equal to the increase in price. When price falls, some petroleum sources become unprofitable and go out of production, thus reducing supply. At the same time. - 119 - those producers who continue to supply petroleum even at the lower price suffer a loss in rents equal to the fall in price. The shaded area R in figure 3.6 repre¬ sents rents geometrically. The important feature of economic rent from the standpoint of Government resource transfer policy is that supply decision incentives are unaffected by who captures the economic rent. In our example thus far, we have assumed that oil producers were able to claim petroleum resources for a nominal fee. Hence, access to high- quality reserves was determined simply by priority of claim. Any rents which arose would accrue to the petroleum producers. Suppose, however, that the Government offered to sell mineral rights, rather than allowing them to be claimed. If everyone expected the price of oil to be $9 per barrel, then companies should be willing to pay as much as $6 per barrel for the rights to produce in area A. Although they would like to pay less and keep some of the rents to themselves, producers know that under competition there will always be someone willing - 120 - I to offer nearly $6 rather than not acquire the riqhts at all. Hence, competition to acquire the riqhts Lo high-quality reserves will assure that all of the rents accrue to the Government. Nevertheless, producers still retain $3 per barrel after payment of the rent. They are therefore willing to supply six million barrels of oil per day from area A even if they have to pay a rent of $6 per barrel, assuming that the price remains at $9 per barrel. It would be a mistake for the Government to assume that, because it receives $6 per barrel for mineral rights in area A, it can also receive $6 per barrel for mineral rights elsewhere. If it tries to charge $6 for mineral rights in area B, no one will wish to purchase these rights. Because the quality of reserves in area B is lower than in area A, and because production costs are therefore higher, the rents which the Government can hope to collect are smaller. In fact, at a price of $9, no rents can be earned in area B. However, there is no compelling short run reason why the Government should not give away mineral rights in area B. Although no one will be willing to pay for - 121 - mineral rights in area B when the oil price is $9, they will be willing to produce four million barrels of oil per day in the area if they are given the mineral rights. Once again, it would be a mistake for the Government to think that because it induces production in area B by giving away the mineral rights, it can also get production in area C through the same policy. If the price of oil is only $9 and production costs are $15, no one will produce in area C even if the Government gives away the mineral rights there. Only by providing a production subsidy of $6 per barrel could the Government induce production in area C. Absent either a production subsidy or an arbitrary restriction on the leasing of any properties to which the industry would like access, the supply of energy resources is the same under a competitive leasing system as it would be if all mineral rights were given away. The only difference is that the Government receives the economic rent under a leasing system, while industry captures the rent when mineral rights are given away or - 122 - are subject to claim at a nominal fee. The supply is also the same as if all resources were privately owned and the mineral rights were sold in private transactions. Once again, the resource seller, if he is shrewd enough, should be able to extract all the economic rents from the petroleum producer. The petroleum producer should be willing to pay up to the full amount of the rents, since he is still left earning a normal profit after doing so. If resources are allocated efficiently, then the sum of consumers' surplus plus economic rent is as large as possible. Furthermore, no redistribution of this surplus and rent will affect the total net social value of production. For example, very shrewd resource owners could conceivably exploit consumer ignorance of market conditions and capture not only the economic rents but also the full consumers' surplus by charging the full price that any consumer would be willing to pay for each barrel of petroleum produced. On the other hand, if the Government were sufficiently clever to tax away all rents and consumers' surplus, it could redistribute the economic pie in any way it chose among its citizens. - 123 - Thus, suitable selective taxation could let the Govern¬ ment capture the full net social value of petroleum production without affecting the equilibrium market price and supply. Market Failure Two situations in which markets can fail to achieve an efficient allocation of resources deserve mention. When there is "imperfect competition," less than the efficient level of output is produced and the price charged is higher than the efficient price. When the social costs of producing a good exceed the private costs calculated in the supply decision, more than the efficient level of output is produced and the price charged is lower than the efficient price. We examine each of these "market failure" cases in greater detail now. 1. Imperfect Competition The supply curve derived previously characterizes the output which would be supplied by a competitive industry at any given price. A competitive industry is - 124 - one in which each firm is a "price taker" and can sell as much output as it wishes at the prevailing market price. Firms are price takers when their output is so small relative to the industry output that changes in an individual seller's output have an imperceptible effect on the market price. When there is imperfect competition, however, firms are sufficiently large relative to the market that their output decisions have a perceptible effect on price. The extreme form of imperfect competition is monopoly, a situation in which a single firm is the sole producer. When there are only a few sellers, the market is characterized as oligopolistic. If oligopolistic firms are capable of colluding effectively, they will behave almost like monopolists. If collusion is less effective, oligopolistic industries may price like competitive industries. However, there is no simple general theory of oligopoly pricing. Figure 3.7 characterizes the production and demand conditions a monopolist might face in the petroleum industry. If we assume that the monopolist experiences - 125 - the same production costs as a competitive industry, then the competitive supply curve represents not only the marginal social cost of producing petroleum but also the monopolist's marginal production costs. Thus, the curve labeled MC is identical to the competitive supply curve. The demand curve confronting the monopolist is the same as the demand curve for a competitive petroleum industry. However, unlike a competitive seller, a monop¬ olist recognizes that he can increase his output only by lowering his price. His net increase in revenue from increasing output will be the price received for the additional unit of output less the revenue which is lost by the price reduction on all of the units of output which he would have sold anyway at the higher price. The line MR represents this "marginal revenue," the change in monopoly revenue from increasing the output of petroleum by a barrel. Because of the loss in revenue on the sale of output which could have been sold at a higher price, the marginal revenue from increasing output by a barrel is always less than the price at which the marginal barrel can be sold. Hence, the marginal revenue - 126 - curve lies below the demand curve D. The monopolist maximizes his profits at that level of output for which marginal revenue equals marginal cost. If he were to increase his output by one more barrel of oil beyond six million barrels per day, the marginal cost of the increment would exceed the marginal revenue, hence it would not be profitable. Similarly, if he were to reduce output by one barrel, he would lose more in revenue than his cost reduction. By producing six million barrels of oil per day and charging $12, the most consumers would pay and still consume six million barrels, the monopolist maximizes his profit. We can see from figure 3.7 that the monopolist produces less than the socially efficient level of output, which is eight million barrels, and he charges more than the efficient price of $9. To ascertain that society is worse off under monopoly, it is only necessary to recognize that society values another unit of output beyond six million barrels at nearly $12 while the social cost of producing that extra unit is only $8. The net increase in the value of output which could be realized - 127 - FIGURE 3.7.--Inefficiency Due to Monopoly Price, (dollars ba-rel) Quantity (million barrels Der day) -127A- c by increasing petroleum production by one barrel is therefore $4. In fact, increases in output which add to net social value would continue until eight million barrels of oil were being produced. Every barrel between six and eight million barrels costs less to produce than its value to consumers. The shaded triangle in figure 3.7 measures the entire net loss to society when petroleum production is six million barrels per day rather than eight million barrels per day. Monopoly is undesirable because of the loss of out¬ put. Resources are not allocated efficiently and the price charged is too high. Furthermore, there is a socially undesirable redistribution of income from consumers to the monopolist. - 128 - 2. Externalities 8/ Suppose offshore oil production is characterized by periodic oil spills which are costly to clean up and which impair nearby fishing. If oil producers are not required to clean up their spills and compensate fisher¬ men for the damage caused by the spills, then the private costs that determine supply conditions will not include these two clearly social costs of oil production. Economists use the term "externalities" to describe gaps between the private costs and benefits which guide individual supply and demand decisions and full social costs and benefits. In figure 3.8, D and S represent the demand curve and the supply curve, respectively, for a competitive petroleum industry. However, if there are social costs such as environmental damage not included in the private 8/ For a more complete discussion of externalities, see American Economic Association, Readings in Welfare Economics , K. J. Arrow and T. Scitovsky, eds., (Homewood: Richard D. Irwin, Inc., 1969), part III; and E. J. Mishan, "Reflections on Recent Developments in the Concept of External Effects," The Canadian Journal of Economics and Political Science (February 1965). - 129 - Pri re (dollars per barrel) FIGURE 3.8.--Inefficiency Due to Social Cost Externality (million barrels t -129A- costs, then the supply curve will not reflect the full marginal social cost of producing petroleum. The curve S' is derived by adding the marginal environmental costs attributable to petroleum production to private marginal costs to get the true marginal social cost curve. The competitive output is eight million barrels of oil per day and the competitive price is $9 per barrel. However, the true social cost of the eight millionth barrel is not $9 but $15. If resources are to be allocated efficiently, output should be only six million barrels and price should be $12 per barrel. The shaded area in figure 3.8 represents the net social loss when producers and consumers of petroleum are guided by prices that do not reflect true social costs. When the efficient level of output is produced, there is still some environmental damage, but it is less than the amount which would be experienced in a myopic competitive market. - 130 - Resource Transfer Policy in a Static World t We are now in a position to apply some principles of supply and demand to analyze resource transfer policy in an idealized world in which there is general agreement about supply and demand conditions and in which these condi¬ tions are not expected to change appreciably over time. We will consistently assume that competitive conditions prevail in the markets for energy resources and that I there are no externalities. We consider two effects of Government resource transfer policy: its effect on the efficiency of resource allocation, and its effect on the distribution of economic welfare. Although the specific conclusions arising from this analysis of land disposal policy in an "ideal world" will have to be modified when real-world complications are introduced, the analysis is nevertheless an important touchstone for later, more realistic explorations. ^ In all of the diagrams which follow, S represents the supply curve for an energy resource such as petroleum, and because we assume no externalities, it is also the marginal social cost curve. D represents the demand - 131 - curve and the marginal social value curve. As we have already seen, resources are allocated efficiently and the net social value of output is maximized at the intersection of the supply curve and the demand curve. 1. Claiming and Noncompetitive Leasing One method by which the Government could transfer the mineral rights on Government lands to private developers would be simply to give the resources away— either by lottery, as is essentially the case in the noncompetitive leasing of onshore oil and gas property, or through a claims system, as is still used for uranium. Neither the demand curve for energy resources nor the supply curve will be affected by such a policy. Hence, the efficient level of output will be produced. Those developers lucky enough to obtain leases or claims with production costs less than the market price will earn economic rents, and those consumers who value the resource at more than the market price will earn consumers' surplus. Figure 3.6 represents the market price which will prevail as $9, the efficient price. The quantity which will be produced is eight million - 132 - barrels per day, or the efficient level of output. The net social value of production is distributed between rents, the shaded area R, and consumers' surplus, the shaded area C. 2. Bonus Payments Suppose the Government were to auction off the mineral rights to Government resources. As we have explained earlier, the maximum "bonus payment," or flat fee, which any developer would be willing to pay for a particular lease is the value of the rents which arise from differences between the market price and production costs. The only difference between giving the resource away and collecting a bonus is that the Government rather than the resource developer captures some or all of the rent. In fact, if there is sufficient competition in the bidding, the Government will capture all this rent in the form of bonus payments. Figure 3.9 shows that the efficient level of output will still be produced and consumers' surplus will be the same. The only difference between bonus bidding and a claiming or noncompetitive bid system for disposing of mineral - 133 - 9 Price (dollars per barrel) FIGURE 3.9.--Bonus Bid Leasing 1 2 3 4 5 6 7 8 9 10 11 12 13 14.15. L Quantity (million barrels per day) -133A- rights is who collects the economic rent. Government revenue is represented by the shaded area labeled G, which is identical to the economic rent R in figure 3.6. 3. Supply Restrictions Suppose the Government were to withhold some of its properties from leasing. These properties would be withdrawn from the inventory of available resources and the supply curve would be altered. Assume, for simplicity, that the Government withholds properties on which production costs are greater than a specified amount, say $6. The supply curve is now represented by the jagged line in figure 3.10 labeled S'. Because of the reduction in supply, the price of petroleum will be higher and rents on the still-available resources will be higher. If leases are offered by means of bonus bidding, the bonuses will be larger now on the tracts still available. In fact, if the Government makes available only the monopoly quantity of resources but producers bid for these resources competitively, it will maximize its bidding revenues. The effect of such a policy, however, is that resources are allocated FIGURE 3.10.--Restricted Supply Leasing Price (dollars per barrel) Quantity- barrels per day) -134A- f inefficiently. Even if the Government were to give back all of its leasing revenues to the citizens in the form of lower taxes, the reduction in supply would cause a welfare loss equal to the triangle labeled WL. 4. Summary and Conclusions Claiming, noncompetitive or giveaway leasing, and bonus bid leasing all lead to the production of the efficient level of output in our ideal static world. The only difference between them is that resource developers capture the economic rents under either of the first two systems, while the Government captures them under bonus bid leasing. If one makes the reason¬ able value judgment that the Government, as the owner of the resources, should capture rents reflecting the resources' value, then bonus bidding is to be preferred over either of the alternatives. Under both claiming and noncompetitive leasing, potentially valuable mineral rights are given away arbitrarily. If the Government captures the rent, it is in a position to distribute the revenue in a way considered most equitable by its decision-makers. -135- In the ideal static world analyzed thus far, bonus bidding appears superior to alternative grant or leasing schemes. When more complicated assumptions are introduced, however, the superiority of bonus bidding becomes less clear. We turn now to an examination of more complex, dynamic, and uncertain real-world leasing environments. The Efficient Allocation of Exhaustible Energy Resources 9/ Resource Exhaustibility A major deficiency in the discussion of efficient energy resource allocation thus far is that the treat¬ ment has been in a static context. We have ignored the fact that all the major energy resources considered in this report are depletable, and that supply conditions will almost certainly change over time as low-cost resources are exhausted. For example, a petroleum pool 9/ The seminal article on this topic is H. Hotelling, "The Economics of Exhaustible Resources," Journal of Political Economy , 39, April 1931. See also R. M. Solow, "The Economics of Resources or the Resources of Economics," American Economic Review, LXIV, May 1974. -136- that can produce 50,000 barrels of oil per day today will not still be capable of producing 50,000 barrels per day 20 years from now if it is operated continuously in the interim. Reworking and secondary recovery may allow production to be maintained somewhat, but certainly not indefinitely and only at an increased cost. For a time, new discoveries can replace the decline in recovery from older fields, but such new discoveries cannot continue indefinitely either. For simplicity in the following analysis of resource exhaustibility effects, we assume that all potential sources of a resource have already been found and that there is no longer any possibility of new discoveries to augment existing supplies. Let the curve labeled S in figure 3.11 represent the marginal cost curve for the total available supply of oil. Increases in oil production, up to 30 billion barrels of oil, can be achieved by tapping more and more costly reserves, but no more than 30 billion barrels are available at any cost. To simplify matters, we assume that individual reservoirs of oil are exhausted in a year. Thus, the supply of oil available for consumption -137- 4 in the second year is that left over after the first year's consumption has reduced total supply. Let the curve labeled D in figure 3.11 represent the annual demand for petroleum, and assume that demand conditions do not change over time. Thus, D remains the demand curve from year to year. If producers are myopic and consider only the present year's production costs, the supply of oil will be 15 billion barrels in the first year, and the most costly oil supplied will be extracted at $9 per barrel. At the end of the first year, the stock of oil will be depleted by the exhaustion of all oil producible at a cost of $9 or less. Hence, the supply curve of oil in the second year will consist of that portion of the original supply curve which lies above $9. This curve is labeled S' in figure 3.11. If producers continue to take into account only their current production costs in the second year, then with annual demand still represented by D, 10 billion barrels of oil will be produced, and the price will be $12. The petroleum still available for third year production is then represented by the supply curve S". -138- FIGURE'3.11.--Myopic Production Plan Price year) -138A- / In the third year, the remaining 5 billion barrels of oil will be extracted and sold at the market price of $15. The total supply of 30 billion barrels will there¬ fore be exhausted in three years. Table 3.3 summarizes the production plan which results when producers determine output on the basis of their current-year production costs. However, it is not the only possible way to allocate the available 30 billion barrels of oil to consumption in different time periods. Nor, as we shall see, is it the plan which will be chosen by less myopic producers, who realize that they may profit by postponing production in order to take advantage of price increases. The plan is also not socially efficient. In fact, as we shall demonstrate in subsequent sections, it will usually be desirable to defer production, at least to some extent. Under certain circumstances, the amount by which competitive producers wish to defer production will also be the amount by which production should be deferred if the timing of resource development is to be efficient. - 139 - TABLE 3.3.--Myopic Production Plan Year Price Output Cuinulative Output 1 $ 9.00 15 15 2 $12.00 10 25 3 $15.00 5 30 4 $18.00 0 30 - 140 - The Production Decision of an Individual Producer Suppose an individual petroleum producer has access to a petroleum reservoir with production costs of $5 per barrel. If the current price of oil is $6, it is profitable to sell the oil from that reservoir immedi¬ ately and earn a net income of $1.00 per barrel. However, if the price of oil is expected to be higher than $6 at some future date and production costs are expected to remain at $5, a greater profit can be earned by deferring production and selling the oil at the higher price in the future. We might therefore expect petroleum producers to wait for the highest price before extract¬ ing and selling their oil. This would be true if it were not for the important fact that there is an opportunity cost to leaving petroleum in the ground without producing. If today's profits can be loaned out at interest, the interest foregone by leaving oil in the ground is the opportunity cost of deferring production. If, for example, the price of oil is expected to be $6.05 a year hence, a profit of $1.05 can be realized by waiting a year to produce, compared with a profit of - 141 - $1.00 from immediate production. Suppose, however, the opportunity exists to lend money at an interest rate of 10 percent so that $1.00 today can be transformed into $1.10 a year hence. A producer of $5 oil in this situation will find it more profitable to produce immediately. His net income will be $1.00 per barrel today, or if he is willing to lend his proceeds and wait a year, $1.10 per barrel a year hence. By deferring production for a year in anticipation of the price increase, he can have only $1.05 per barrel a year hence. On the other hand, if the interest rate were less than five percent, it would be more profitable to defer production. A producer interested in receiving income today rather than waiting a year can borrow against next year's $1.05 per barrel profit. At an interest rate of three percent, for example, $1.05 a year hence can be transformed into a little less than $1.02 today. With the $1.05 net income from production a year hence, our producer can repay the loan of $1.02 plus the interest charge of three cents. Thus, by deferring production when the interest rate is three percent, a producer can receive a net income of either $1.02 per barrel immediately or $1.05 per barrel a year hence. Producing immediately, he could have either $1.00 immediately or, by making a loan at three percent, $1.03 a year hence. Whether he prefers to receive income immediately or a year hence, he can get more by deferring production and, if necessary, borrowing against future income than he can from immediate production. In general, the process known as "discounting" can be used to compare sums of money received at different moments in time. The "discounted present value" of a specified amount of money to be received at some date in the future is the amount of money one would have to invest at compound interest today in order to have the specified amount of money at that future date. For example, the discounted present value of $100 to be received ten years hence is about $38.56 when the interest rate is ten percent and about $61.39 when the interest rate is five percent. If $38.56 were invested at ten percent, or $61.39 at five percent, the yield in ten years of annual compounding would be $100. Thus, when the interest rate is ten percent, $38.56 on hand today is equivalent to $100 available ten years hence. - 143 - Algebraically, the discounted present value of x dollars t years hence at an interest rate of r percent per year is given by X (1+r) 1 * A rational businessman will be indifferent between selling an exhaustible resource such as petroleum immediately and deferring production for sale at a higher price in the future only if the discounted present value of the net income from either action is the same. If current net income exceeds the discounted present value of net income from sale at any future date, the incentive is to produce now. If the discounted present value of net income from future sale exceeds that from immediate sale, the incentive is to defer production to that period whose net income has the highest discounted present value. Only if producers are myopic will they take into account only current costs and revenues in making their production decision. Farsighted producers will also take into account the possibility of making higher profits by deferring production. - 144 - The Competitive Market Timing of Resource Development Let us reconsider the myopic production decision example summarized in figure 3.11 and table 3.3. If the petroleum market is competitive, the actions of any individual producer will have no noticeable effect on the market price of oil. Suppose a single shrewd producer of $8 oil calculates the discounted present value of net income from deferring production for a year. If no one else makes the same calculation, his net income a year hence will be $4 per barrel, since the market price will be $12 in the second year. Assuming the interest rate to be ten percent, the discounted present value of this $4 net income is $3.64, which compares quite favorably with the $1.00 net income from immediate production. Thus, the producer of $8 oil has a strong incentive to defer production. Even in a competitive market, a decision by numerous producers to change output will have an effect on price. If every producer whose costs are greater than $8 also calculates the return to deferring production on the assumption that the second year price will remain - 145 - $12 and the first year price $9, each will find it profitable to defer production. However, first year production will then be the 12.5 billion barrels indicated in figure 3.12 rather than the 15 billion barrels of our myopic example, and the market clearing price in the first year will be $11, not $9. The amount of oil which could be supplied in the second year is indicated by the supply curve S' in figure 3.12. Assume as a first approximation that 11.5 billion barrels of oil will be produced in the second year and the price will be $11.30. 10/ 10 / The astute reader will note that a billion barrels of oil seem to have been lost in this reallocation. Whereas cumulative production in the first two years had been 25 billion barrels (15 billion in the first year and 10 billion in the second year), it is now only 24 billion barrels (12.5 and 11.5). Of the 2.5 billion barrel reduction in first year production, only 1.5 billion can be profit¬ ably sold in the second year. However, if produc¬ tion of the remaining one billion barrels is deferred to the fourth year, the discounted present value of net income will still be higher than if this oil is produced in the first year. The most any of this oil could cost is $9. According to the demand curve, one billion barrels can be sold at a price of $17.60. Thus, the net income per barrel is at least $8.60, the discounted present value of which is $8.60/(1.10)3 - $6.46, since the income is not received until three years hence. Recall that net income per barrel from production in the first year would be less than $1.00 per barrel. FIGURE 3.12.--A Less Jfyonic Production Plan Price . 1 / -146A- Under these circumstances, the producer of $8 oil can anticipate earning a net income of $3 by producing in the first year or a net income of $3.30 by deferring production to the second year. Since the discounted present value of $3.30 a year hence at ten percent interest is $3, the producer of $8 oil should be indifferent between producing in the first year and deferring production to the second year. A producer whose costs are greater than $8 will definitely find it more profitable to defer production. For example, a producer of $8.10 oil will earn $2.90 by producing immediately and $3.20 by deferring production for a year. The discounted present value of $3.20 is $2.91. Although the advantage of deferring production is slight, a rational businessman will still prefer to take the course of action which yields the greater profit. By the same token, any producer whose costs are less than $8 will not find it profitable to defer production. For example, a producer of $7.90 oil can earn $3.10 from immediate production and sale or $3.40 by waiting a year to produce, but the discounted present value of the $3.40 is only $3.09. < * -147- Thus, the producer of $8 oil is the marginal producer when the market price is $11 and is expected to be $11.30 a year hence. No firm whose costs are less than $8 finds it more profitable to defer production than to produce immediately, and no firm whose costs are greater than $8 finds it more profitable to produce immediately than to defer production. Nevertheless, the petroleum market is not in equilibrium with first year production at 12.5 billion barrels and the first year price at $11. Production in the second year will be 11.5 billion barrels and the second year price will be $11.30 only if entrepreneurs revert to myopic behavior. Just as producers of the most costly oil which would be supplied in the first year under a myopic decision rule find it more profitable to defer production to the second year, producers of the most costly of the 11.5 billion barrels which could be supplied at a profit in the second year will find it even more profitable to defer production to the third year. As a result, production in the second year will be less than 11.5 billion barrels, and the price will exceed $11.30. At a higher second -148- year price, it becomes profitable to defer production of more oil from the first year to the second year. For example, at a price higher than $11.30, a producer of $8 oil will no longer be indifferent between producing in the first year and selling at $11 vs. deferring production to the second. The discounted present value of net income from second year production will exceed the $3 net income from first year production. The petroleum market cannot be in equilibrium until i every producer is selling his oil in the year for which the discounted present value of net income is highest. Otherwise, some producer would have an incentive to switch the year in which he produces. The market will be in equilibrium if the net income of the marginal producer in every year is equal to the discounted present value of the net income from deferring production a year. No firm whose costs are less than those of the | marginal producer will wish to defer production to any later year, and no producer whose costs are greater than those of the marginal producer will wish to produce any earlier. -149- 4 This condition with respect to the marginal producer allows us to characterize the rate of change of price over time if the market is in equilibrium. Consider the marginal producer in the first year. If his costs are and the price in the first year is P his net income will be - c^* If price is P 2 in the second year, the net income from deferring production to the second year will be N = P 2 - C^. T * le di- scountec * present value of N 2 is N 2 /(l+r), where r is the interest rate. In equilibrium, the discounted present value of N 2 must be equal to for the marginal producer, hence: P^ - = (1 + r)(P^ - C^). Rearranging terms gives: P 2 - Pi = rN-^. In other words, the change in price must be equal to the interest on the net income of the marginal producer. Specifying the change in price for each year is not sufficient to characterize the price path fully, how¬ ever. It is also necessary to determine the price level itself at some point along the path. It is difficult to provide a non-mathematical explanation of how to do this. 11 / Roughly stated, the price at which 11 / Cf. Hotelling, op. cit ., pp. 141, 142. -150- the very last barrel of oil is sold should be high enough that the price which would be required in the subsequent period to make it profitable to defer production still another year would be a price higher than the $18 price which elicits zero demand. Although our assumption that petroleum reservoirs are exhausted within a single year is clearly unrealistic, the basic feature of our example—the fact that costs increase over time as high-quality resource deposits are exhausted—realistically characterizes exhaustible resource industries. The main conclusion of our example is also valid for any situation in which the unit cost of an exhaustible resource increases over time as the total supply is depleted. Price increases in each year will equal the opportunity cost of deferring production for the marginal producer in that year, and the price at the time the resource is exhausted will be the price at which there is no longer any demand for the resource. Physical exhaustion of the resource may not be the only circumstance in which production eventually comes to a halt. It is never profitable to supply a resource when unit production costs exceed price, and since unit production costs increase over time with the exhaustion of lower-cost resources, they might rise to such a level that they exceed the price which elicits zero demand. Under such conditions, the supply of resources that can be produced economically will be exhausted before the resource is physically exhausted. Nevertheless, the same conditions characterize the profit-maximizing timing of resource development, whether the resource becomes physically or economically exhausted. It should be re-emphasized that the market we have been describing is a competitive market--one in which each producer is a price taker and cannot have a notice¬ able effect on price through his individual production decisions. Individual producers cannot force up prices and increase profits by independently withholding production, and rational businessmen recognize that in a competitive market, they can only react to existing prices and choose the production plan which maximizes profits subject to present and expected future prices. Yet resource development is stretched out over a longer interval when the market is competitive and producers are farsighted than it would be if output were myopically -152- pushed to the level at which price equals marginal production costs in every year—i.e., if the opportunity cost of future price increases were ignored. Production is not delayed indefinitely, since there is also an opportunity cost to leaving resources unexploited: the interest which could be earned on the net income from immediate production. In a competitive market for an exhaustible resource whose potential sources have already been fully explored, the price of the resource will increase over time and the quantity produced will decline. Until all potential deposits of the resource have been proved up, new . -- ^ discoveries can offset this tendency toward higher prices and declining production by increasing the total supply more rapidly than the resource is consumed. Eventually, however, the influence of declining resource stocks must lead to rising prices and falling output. Government Ownership and Resource Development Timing The Federal Government owns significant reserves of all major exhaustible energy resources. Its policy has been to transfer these resources to private developers -153- rather than undertake development itself. Nevertheless, the Government can have an effect on the timing of resource development by using leasing policy to determine the rate at which private developers gain access to Government-owned resources. Our aim in this section is to develop some principles of optimal resource develop¬ ment timing useful in formulating leasing policy. For simplicity of exposition, we assume that the Government owns all of the Nation's energy resources and that one condition for acquiring a lease from the Government is an agreement to undertake immediate development. We then ask at what rate the Government should lease its v , resources and what price should be charged for a lease. The Government should presumably try to achieve an efficient timing of resource development, but it should also try to maximize its leasing revenue consistent with efficient development. Resource development is efficient when the net social value of output is maximized. In a static context, all production takes place at one time, and the net social value of output is maximized when the marginal social value of production is equal to the marginal social cost. When output is produced over -154- a number of years, however, costs and benefits do not f accrue at the same time, and there is a net social value of output for each year of production. Society will generally not value future output as highly as current output, and like businessmen who use discounting to compare income received over different years, the Government can use discounting to compare the net social value of output produced in different years. The Government can also use discounting to compare leasing 0 revenue received in different years. For reasons which will be explained later, the discount rate used by the Government might differ from the market interest rate used by private decision-makers, but the principle remains the same. In the analysis which follows, we will consider the timing of resource development to be efficient if the discounted net social value of output summed over the whole production period is maximized. For simplicity, we will often refer to this sum as the net social value of output. Just as, in the static context, the maximum Government revenue consistent with efficient resource development is equal to the economic rent, the maximum -155- Government revenue consistent with the efficient timing of resource development is equal to the discounted present value of the economic rents over the entire production period. Let us illustrate how one determines the efficient timing of resource development and the maximum Government leasing revenue by considering again the example of figure 3.11 and table 3.3. The production plan assumes that the Government leases less costly oil first, leasing 15 billion barrels in the first year, 10 billion barrels in the second year, and 5 billion barrels in the third year. If the bidding for leases is competitive, any winning bidder will have to pay the difference between the market price and the production cost of the oil he acquires. The static efficiency criterion will be met in each year, and the Government will capture the full static rent each year. However, the timing of resource development will not be efficient, since the overall net social value of output will not be maximized. Nor will this production plan maximize the discounted present value of Government revenue. -156- To see that the net social value of output is not maximized, we need only show that there is a feasible reallocation of output which increases this value. Consider postponing the production of a barrel of $8 oil for a year. Recalling that the demand price measures the marginal social value of output, we see that the reduction in the social value of output in the first year will be $9. The reduction in cost will be $8. Hence, the reduction in the net social value of output in the first year will be $1.00. The increase in the social value of ¥ output in the second year will be $12 and the increase in cost $8. Therefore, the increase in the net social value of second year output will be $4, the discounted present value of which is $4/1.10 or $3.64. Thus, by giving up a unit of output in the first year and increasing output in the second year, the net social value of output over the two years is increased by $2.64. I In fact, the net social value of the first two years' output can be increased further by reallocating production of all 2.5 billion barrels of oil with unit -157- « production costs between $8 and $9 from the first year to the second or even later years. Referring to figure 3.12, we see that the first year's output will be 12.5 billion barrels and the price $11. In the second year, 11.5 billion barrels can be produced and sold at $11.30. 12 / No further allocation of oil from the first year to the second can increase the net social value of output with these prices. To see this, consider the fact that $8 oil is marginal oil. Its discounted net social value will be the same whether production takes place in the first year or the second. In the first year it is ($11 - $8) or $3; in the second year it is ($11.30 - $8) or $3.30, the discounted present value of which is $3.30/1.10 or $3. 12/ The remaining one billion barrels can then be sold in the fourth year at a price of $17.60. This oil will have a cost of less than $9 a barrel and a value in the fourth year of at least $17.60; hence, the net social value per barrel in the fourth year is at least $8.60. The discounted present value of $8.60 three years hence is $6.46. If this oil were produced in the first year, its net social value would be less than $1.00 per barrel. Cf. footnote 10, supra . -158- If any oil less costly than $8 were produced in the second year rather than the first, the discounted net social value of that oil would be lower than its first- year net social value. For example, the net social value of $7.90 oil produced in the first year is $3.10. If that oil were produced in the second year, its net value would be $3.40, but the discounted present value of $3.40 is only $3.09. The difference is even more dramatic for less expensive oil. Similarly, if any oil more expensive than $8 were produced in the first year instead of the second, its net social value would be less than the discounted net social value when it is produced in the second year. For example, $8.10 oil has a net social value of $3.20 in the second year and a discounted net social value of $2.91. If this oil were produced in the first year instead, its net social value would be only $2.90. The difference rises as oil extraction costs increase above $8.10. Government revenue is also higher when 12.5 billion barrels are produced in the first year, 11.5 billion in the second year, 5 billion in the third, and 1 billion in the fourth 13 / than when 15 billion barrels are produced in the first year, 10 billion in the second, and 5 billion in the third. Because the market price is $11 instead of $9, the 12.5 billion barrels still produced in the first year earn rents higher by $2 per barrel. Thus, the increase in rents is $2 x 12.5 billion, or $25 billion. However, some of this is offset by the fact that rents fall by $0.70 on the 10 billion barrels that would have sold for $12 in the second year but now sell for $11.30. This reduction is $7 billion, the dis¬ counted present value of which is $6.36 billion. The 2.5 billion barrels of oil which are reallocated from.first year to later production have average produc¬ tion costs of $8.50. If this oil were produced in the first year and sold at a price of $9, the average rent would have been $0.50 per barrel and leasing revenue would have been $0.50 x 2.5 billion, or $1.25 billion. Actually, 1.5 billion barrels sell in the second year at $11.30 for an average rent of $2.80 per barrel, and 1 billion sell in the fourth year at $17.60 for an average 13/ See footnote 12 supra . -160- rent of $9.10 per barrel. The discounted present value of these rents is $2.80 x 1.5 billion/1.10 + $9.10 x 1 billion/(1.10) 3 f or $10.66 billion. The net increase in rent from this reallocation is therefore $25 billion - $6.36 billion - $1.25 billion + $10.66 billion, or $28.05 billion. 13/ However, this leasing schedule still does not maximize government revenue. The exact revenue-maximizing schedule is complicated to derive and of little interest at this point. What is important to know, however, is that the revenue-maximizing time plan does not coincide with the efficient plan. In general, the revenue-maximizing schedule will involve less current production than the efficient time plan. This is analogous to our static analysis of the way in which the Government could maximize its revenue by leasing less than the efficient amount of the resource. As in the static analysis, the revenue-maximizing leasing policy would be to lease the 13/ This example and these numbers are purely hypo¬ thetical, and no inferences about revenue from leasing U.S. energy resources should be drawn from them. -161- amount of oil a monopolist would wish to produce each year. 15/ As in the static analysis, however, there is also a deadweight welfare loss from pursuing such a leasing policy: the gain to taxpayers from increased Government revenue (requiring therefore less taxation) is less than the loss of net social output value to oil consumers. Although we have shown that the production schedule of table 3.3 is neither efficient nor revenue-maximizing, we have not yet characterized the leasing policy which does imply efficient development or maximum revenue. To do so rigorously would require sophisticated mathe¬ matical techniques. 16 / Instead, we simply describe the conditions which must hold if the timing of resource development is to be efficient, along with those for maximizing Government revenue. We then appeal to the foregoing analysis to suggest their plausibility. 15/ Cf. Hotelling, op. cit . , pp. 151, 152. 16/ Ibid ., pp. 157, 159. -162- I The timing of resource development will be efficient when (1) the discounted net social value of the marginal barrel produced in any year is equal to the discounted net social value of that oil if its production were delayed for a year, and (2) the price of oil at the time the very last barrel is produced is equal to the price which elicits zero demand. The algebraic state¬ ment of the first condition is the following: t (P t+1 - C t )/(1 + d) t+1 = (P t - C t )/(1 + d) t where P t is the price of oil in year t, P t +i is the price in the subsequent year, and d is the discount rate. This expression can be rearranged to yield the price increase from year to year when the timing of resource development is efficient: p t+l “ p t = ^ ( p t “ ' Tiie right hand term in this equation can be interpreted as the social opportunity cost of delaying production of the marginal oil for a year. In our earlier example, the price change from the first year to the second satisfied this condition: ($11.30 - $11) = 0.10 ($11 - $8). This is as we should -163- 0 expect, since no further reallocation could be found which increased the net social value of the oil produced in the first two years. However, if we consider the change in price from the second year to the third, we see that the efficiency condition is violated. The condition can be satisfied if some second year production is delayed to the third year so that the second year price increases and the third year price falls enough to let the price change equal 0.10 x (P 2 - C 2 )• However, the resulting increase in P 2 will mean that the efficiency condition is no longer satisfied for the first two years. Thus, even fewer than 24 billion barrels will be produced over the first two years, and production will be spread over a number of years. The fact that the price at which the last barrel of oil is sold cannot be so low that the net social value of output could be increased by delaying production one more year suggests that the price at which that last barrel of oil is sold should be close to the price which elicits zero demand. More rigorous analysis confirms this suggestion. Another implication of the efficiency conditions is that the lower the discount rate, the - 164 - more protracted is the resource's exploitation period. If Government policymakers determine the rate of change of price in every year and the price level in the last year, then it is possible to calculate the entire price path consistent with the efficient timing of resource development. Knowing the demand curve and the price of oil in each year along the efficient time path is sufficient to know the amount of production which should take place in each year. By our earlier assumption, a condition for acquiring a lease is the promise to undertake immediate development. Thus, the optimal timing of leasing to achieve efficient develop¬ ment is accomplished by leasing in each year the appropri¬ ate amount of oil for production in that year. If the bonus bid extracted for each lease is equal to the market value of the oil found on the lease less its production cost, the discounted present value of leasing revenues over the entire leasing period will be as large as possible consistent with the efficient timing of resource development. As we have noted, however, even higher revenues could be extracted. By protracting the leasing period even more, the Government could increase the discounted present value of the rents it captures, but only at the sacrifice of efficient resource development timing. A deadweight welfare loss will result from trying to maximize leasing revenue per se . Our judgment is that this welfare loss should be avoided if possible, and we will henceforth assume that the Government attempts to capture only that amount of revenue con¬ sistent with maximizing discounted net social value; i.e., following the efficient development time path. Oil with the lowest production costs will be leased first and will command the highest bonus bid per barrel. As the quality of leased resources declines, so will the revenue from leasing. If the Government should calculate a minimum acceptable bid greater than the value of the rents from producing on a lease, it will encounter no successful bidders. If the Govern¬ ment should charge a price less than the value of the rents, it will needlessly sacrifice revenue. - 166 - Thus far we have assumed that production from a lease takes place all in one year. This is obviously unrealistic, but the basic analytic conclusions are unchanged when production occurs over a longer interval at a declining rate. One still seeks a leasing plan which entails production of least-cost resources first and in which the price increase from year to year is equal to the opportunity cost of delaying production of the marginal resource. The price charged for a lease should equal the discounted present value of rents which will accrue over the lease's productive lifetime. The Market Interest Rate, the Government Discount Rate, and the Social Discount Rate What rate should the Government use to discount future costs and benefits from the production of exhaustible energy resources in order to calculate the optimal timing of their development? What rate should be used to discount future leasing revenue? These questions are among the most vexing issues addressed by analysts of public economic policy, but their importance is so great that they must be faced squarely. 17 / The appropriate rate for discounting future costs and benefits is tautologically the rate at which society wishes these costs and benefits to be discounted; i.e., the "social discount rate." The problem comes in determining its value. One approach is to accept the result of market decisions individuals make with respect to the value of consumption at different points in time, much as we may accept the sovereignty of consumers' preferences toward the value of different commodities at any one moment in time. As Arrow and Kurz argue, "It is hard to see why the revealed preference of indi¬ viduals should be disregarded in the realm of time, where it is accepted, broadly speaking, in evaluating current commodity flows." 18/ 17 / See, e.g., K. J. Arrow and M. Kurz, Public Investment, The Rate of Return, and Optimal Fiscal Policy (Baltimore: John Hopkins, 1970), pp. 5, 6; and C. J. Hitch and R. N. McKean, The Economics of Defense in the Nuclear Age (Cambridge: Harvard University Press, 1960) , pp. 209-211. 18/ Arrow and Kurz, op. cit ., p. 12. - 168 - Rational consumers will adjust their savings- consumption balance up to the point at which the interest which could be earned from postponing another dollar of current consumption is equal to their "marginal rate of time preference"—the premium they would be willing to pay in order to consume now rather than wait a year to consume. At the prevailing interest rate (e.g., ten percent)/ rational consumers save just enough so that they are indifferent between enjoying another dollar of current consumption or another $1.10 of consumption a year hence. In other words, a ten percent discount rate is applied to future consumption. Because consumption in any given period confers diminishing marginal satisfaction, however, the more one consumes today compared to next year's anticipated con¬ sumption, the less one tends to value current consumption in relation to future consumption and the lower the marginal rate of time preference. A decrease in the interest rate will therefore lead consumers to reduce their savings and increase their current consumption until the marginal rate of time preference has again fallen into line with the interest rate. - 169 - What determines the market interest rate? The interest rate is a price much like the market prices analyzed earlier. It is determined by the interaction of supply and demand. The demand in this instance is the demand for investment funds with which to acquire capital goods. The supply is the supply of savings from individuals willing to give up current consumption in exchange for increased future consumption. The demand for investment funds derives from the fact that capital is productive and can increase future profits. Imagine, for example, a machine which costs $100, lasts forever, and increases future profits by $10 a year. The annual "rate of return" from purchasing this machine is thus ten percent. If the funds needed to purchase the machine are available at any interest rate less than 10 percent per annum, the purchase is worth¬ while. Suppose the borrowing rate is eight percent. Every year the profit from the machine will be $10 and the interest payment will be $8, leaving a net profit of $2. 19 / Only if the interest rate is greater than 10 percent will it not be profitable to borrow 19 / Strictly speaking, the $10 per year "profit" before deduction of interest costs is called a "quasi-rent." - 170 - the funds and invest in the machine. In general, it will be profitable to make an investment if the rate of return on the investment is less than the interest rate. If we were to rank all of the economy's potential capital investments according to their rate of return, we would note that the lower the rate of return is, the greater will be the number of investments which promise at least that rate of return. Thus, the lower the interest rate, the greater is the demand for investment funds. We can represent this relationship geometrically with the line DI in figure 3.13. At any given level of investment, the interest rate read off DI is also the rate of return on the marginal investment. If the rates of return to private investors reflect social rates of return, the interest rate read off the invest¬ ment demand curve will measure the marginal social rate of return on investment. Thus, the investment demand curve will measure society's opportunity for transforming current income into future income. If consumer sovereignty with respect to intertemporal consumption decisions is accepted, the interest rate read off the supply of savings curve SS in figure 3.13 - 171 - FIGURE 3.13.--Market Interest Rate Determination / -171A- will measure the marginal social rate of time preference. At any given interest rate, the supply of savings will be such that each and every consumer will have struck what he considers to be the best balance between current and future consumption. Thus, the supply curve will measure society's willingness to transform current consumption possibilities into future consumption possibilities. Figure 3.13 shows the equilibrium interest rate to be ten percent and equilibrium savings and investment to be $100 billion. In this equilibrium, the net social value of investment is maximized. If investment were less, say $80 billion, the marginal social rate of return on investment would be 12 percent and the marginal rate of time preference would be eight percent. Potential savers would be willing to give up more current consumption for an interest rate of eight percent, and they can earn 12 percent by doing so. Further invest¬ ment is socially worthwhile up to the point at which the marginal social rate of return equals the marginal social rate of time preference. At this point, savings and investment are in equilibrium. Investing even more - 172 - would yield a rate of return less than the rate society requires to incur the necessary sacrifice of current consumption. Under these circumstances, the interest rate at which the savings and investment market attains equi¬ librium can be viewed as the social discount rate. It is also the rate at which the Government should be able to borrow and therefore the rate which should be used to discount future leasing revenues. If it so desired, the Government could borrow the present value of future leasing revenue, discounted at the market interest rate. It is quite likely, however, that the market interest rate overstates the social discount rate. One reason is that a corporate profits tax drives a wedge between the marginal social rate of return on invest¬ ment and the marginal social rate of time preference. In figure 3.14, DI now represents the gross, or pre¬ tax, rate of return to private investors. With a 50 percent corporate profits tax, the net, or post-tax, rate of return will be only half as large, as represented - 173 - 9 (9 FIGURE 3.14.--Distortion of Interest Rate Due to Taxation / * / -173A- by D'l. 20 / Thus, D'l now represents the effective private demand for investment funds, since the relevant comparison for determining the profitability of investment to private enterprises is between the market interest rate and the net rate of return. Market equilibrium will occur at an interest rate of 12 percent, as seen in figure 3.14, and the marginal social rate of return on investment will be 12 percent. However, because profits are taxed, the net private return will be only 6 percent. Also, the marginal social rate of time preference will be only 6 percent. Relative to that level of investment at which the marginal social rate of return on investment equals the marginal social rate of time preference (i.e., 9 percent), too little investment will occur, and the market interest rate will exceed the appropriate social discount rate. 20 / We assume that firms raise their capital through instruments such as equity shares whose returns are not tax exempt. When capital is raised, at least in part, through borrowing and the "interest" is tax deductible, the analysis becomes more complex. -1 74- Even in the absence of distortions caused by taxes, ethical objections can be raised against using indi¬ vidual preferences as the guide in determining the social discount rate. The implication of discounting is that the welfare of future generations should count for less than the welfare of current generations. Yet there is no compelling argument for treating generations differently on a purely chronological basis. A more reasonable ethical position might call for equal treat¬ ment of generations with equal opportunities. Adopting such a position, however, involves us in an ethical conundrum. If every generation into the infinite future is to have the same consumption possibilities with respect to the supply of exhaustible energy resources, the entire stock has to be passed on from generation to generation, and no generation can consume any of the resource. This is so because a finite stock divided by an infinite number of generations implies zero consump¬ tion in any given (current) generation. We can escape this dilemma, however, by recognizing that capital accumulation and technological progress increase the consumption possibilities of future generations. When future generations are expected to enjoy a higher - 175 - standard of living with respect to non-energy goods, their energy consumption can be discounted. Nevertheless, future generations are not represented directly in the market interactions which determine interest rates, and myopic current generations might still tend to discount the welfare of future generations by more than it would be discounted by an objective social planner with a long planning horizon. How seriously one should take these objections to using the market interest rate as the social discount rate is not settled. Some economists with a strong faith in the ability of markets to allocate resources efficiently would opt for using the market interest rate as the appropriate measure of the social discount rate (although they might con¬ currently reject the whole notion of Government planning on the basis of that rate). Other more agnostic economists give more credence to the argument that the market rate exceeds--perhaps by an appreciable margin— the "correct" social discount rate. - 176 - Leasing Policy for Exhaustible Resources & A few pages earlier we saw how the Government could implement leasing policy to achieve an efficient time path for resource development. We assumed that all of the Nation's energy resources were Government- owned. The problem then was to determine the amount of production required each year and to lease resources accord¬ ingly, requiring immediate production as a condition for lease acquisition. The U.S. Government does not, however, own the entire stock of domestic energy resources and therefore it cannot exercise such complete control over timing. Designing leasing policy in such a world is either quite simple or quite complicated, depending upon one's belief in the free market's ability to allocate resources efficiently. One policy the Government could pursue would be simply to lease all of its energy resources at once to the highest bonus bidder on each tract, with no restrictions on production. The private sector would then possess the entire resource stock, and market forces would control the timing of resource development. - 177 - If the market is "effectively competitive" in the sense that no resource owner has the power to effect prices significantly through his production decisions, the time path of development will be the one described on pp. supra. If we compare the expression characterizing the efficient time path of resource development, (Pt+1 - Pt) = d(Pt - Ct), 21/ with the expression characterizing the competitive market pattern (Pt+1 - Pt) = r(Pt - Ct), 22/ we see that the only difference is the use of the Government's discount rate in the first case and the market interest rate in the second. If the Government employs the market interest rate for its discounting, the timing of resource development in an unfettered competitive market will be the same as the timing under Government control. If the market rate of interest is the correct social discount rate, the timing of resource 21/ Cf. p- 163 supra. 22/ Cf. p- 150 supra. - 178 - development will be optimal from the standpoint of society. This is a most important insight into the role of competitive market processes. 23 / Furthermore, if there is effective competition in the bidding to acquire leases, the winning bidder on each tract will have to offer a bonus bid equaling the discounted present value of the rents he will earn from production. Thus, the Government will capture the maximum discounted present value of leasing revenue consistent with efficient resource development. Certain considerations cloud this sanguine appraisal of immediate bonus bid leasing's efficacy. For one, if there is imperfect competition in selling the output of leases, the time path of development will be inefficient. In general, an imperfectly competitive industry will develop resources more slowly than an effectively competitive industry, and the net social value of the imperfectly competitive industry's output will be lower. 23 / Cf. Hotelling, op. cit ., p. 143. - 179 - On the other hand, if the market interest rate exceeds the social discount rate, resources will be developed at a faster than optimal rate under competi¬ tion. Given this interest rate divergence, an imper¬ fectly competitive market might actually develop resources more efficiently than a competitive market. 24/ This, of course, is not to say that imperfect competition is socially desirable. For example the transfer of income from consumers to producers under imperfect competition may be unsatisfactory even when resources happen to be allocated efficiently. In other words, correcting for one type of market failure—the excessive level of the market interest rate—by letting competition break down could exacerbate the overall market failure. Even if energy resource markets are competitive and the competitive market development time path is efficient. Government revenue might suffer from leasing large amounts of any resource at once. Offering large quantities simultaneously might sufficiently dilute competition in the bidding to acquire leases that the 24/ Cf. Solow, op♦ cit ., p. 8. - 180 - bids on individual tracts are noncompetitive and do not reflect the full discounted value of the leased resources' rents. This problem could be ameliorated if the Government were to spread its leasing initiatives over time. As long as the Government never restricts the supply of resources to less than what a competitive time path requires, neither the efficiency of resource development nor Government revenue should be adversely affected. The following chapter on leasing methods deals in more detail with this problem of maximizing bidding competition. In summary, the Government as a major energy resource landholder can affect the timing of resource development through its leasing policy. Although there is a set of ideal conditions under which the Government can be passive and simply lease all its exhaustible resources at once to private developers, a more prudent policy might appear to involve more gradual leasing. By maintaining control over significant quantities of resources, the Government preserves the flexibility to deal with objectionable situations. If some markets come to have undesirable anticompetitive characteristics. - 181 - resources might be leased only to new entrants in an attempt to restore competition. If there is a con¬ sensus that the unfettered market is insufficiently conservationist, the Government can withhold resources in order to protect the interests of future energy¬ consuming generations. The danger of such a policy is that the Government might do an even worse job than the competitive market in anticipating the Nation's energy needs and achieving an efficient development time path. When future demand and supply conditions are uncertain, achieving efficient resource development is even more difficult. We turn our attention now to that critical problem. The Effects of Uncertainty on Market Behavior and Economic Efficiency Uncertainty in Energy Resource Development Thus far, we have assumed that energy resource development takes place in a world of certain knowledge about future demand conditions and long run total stocks. This was useful in focusing attention on the principles of optimal resource development scheduling, - 182 - t but it is clearly unrealistic. In this section we expand the analysis to characterize market behavior and economic efficiency in an uncertain world. One major source of uncertainty concerns the physical availability of a resource. Prior to any exploratory effort, it is impossible to know whether or not a particular tract contains a valuable deposit. Preliminary geophysical studies can identify geologic structures likely to contain resource deposits, but at least in the case of oil and gas, drilling is required to prove their existence. Further exploratory and developmental drilling is usually needed to establish quantity and quality. The easier and cheaper it is to conduct such exploration, and the more pressing is the need to find new reserves, the more information there will be about total resource availability. In the case of coal and oil shale, ease of exploration has permitted sub¬ stantial deposits to be identified far in advance of demand for them. For oil and gas, on the other hand, the expense and risk involved in exploration make (f - 183 - discovering new reserves difficult even when there are significant economic incentives. Furthermore, the Government's offshore leasing restrictions have kept some potential areas from being explored except in a very preliminary fashion. In any case, a firm engaged in oil or gas production faces greater discovery risk than a company exploiting coal or oil shale resources. Discovery risk is of course only one type of risk encountered in energy resource development. In mature industries like petroleum, gas, and coal, the technology is fairly well established. With oil shale, however, many technological problems remain to be mastered. One of the most significant risks faced by a would-be oil shale developer is uncertainty about the technology and costs for producing shale oil suitable as refinery feed¬ stock. Technological risk is more acute in oil shale development, but some offshore drilling or coal gasifica¬ tion and liquefaction techniques are also subject to significant uncertainties. Even when the existence of resource deposits and their quantity and quality have been established with some precision, and even when the exploitation technology - 184 - is well in hand, uncertainty concerning economic variables may also play an important role. Such uncertainties relate in particular to development and extraction costs and to the market price. Weather and climate inject further uncer¬ tainty. Ice and snow in Alaska and hurricanes in the Gulf of Mexico, for example, necessitate decisions about how much risk to accept by using less expensive and hence less weather resistant materials rather than sturdier and costlier materials. From society's standpoint, there is con¬ siderable uncertainty about the environmental impact of resource development in many areas, perhaps especially with respect to strip mining and offshore drilling. Private companies are also not immune to the risk of economic loss due to environmentally damag¬ ing events such as oil spills. And last but not least, there is uncertainty about the price at which resources can be sold. Prices can be affected by domestic public policy, future consumer preferences, technological develop¬ ments, and international political developments—all highly unpredictable. - 185 - Private Risk and Social Risk In the face of these cost and market uncertainties, private developers find energy resource development a risky undertaking. However, there is also an irreducible "social risk" associated with uncertainty about total resource availability, future technology, and inter¬ national political developments which would be exper¬ ienced even in a centrally-planned economy. In analyzing resource development by private enterprises, it is necessary to deal with the effects of private risk on production decisions. In determining whether resource development is efficient from society's standpoint, one must come to grips with social risk, which in many instances will be less severe than private risk. Consider, for example, uncertainty about remaining undiscovered U.S. petroleum reserves. To simplify the analysis, suppose that newly-discovered petroleum pools can be classified into five categories on the basis of production costs and the quantity of oil found. Type A discoveries are dry holes; type B discoveries are pools with high production costs and modest quantities of oil; - 186 - type C discoveries are pools with modest production costs and modest quantities of oil; type D discoveries are pools with high production costs but lots of oil; and type E discoveries are low-cost gushers. For a given set of anticipated future oil prices, one can calculate the discounted present value of net income in excess of normal profits to be earned from developing each type of discovery as well as the net social value of that production. Absent market failure, the production plan which maximizes net income will also maximize the net social value of production. However, when an individual company decides to explore for additional reserves, the value of the oil to be discovered is not known, since there is uncertainty about which type of pool will be discovered. Similarly, the net social value of the oil to be discovered is uncertain. Suppose that through preliminary geophysical exploration, undrilled geological structures can be classified into three categories--I, II, and III— differing in the statistical likelihood that a particular type of pool will be found. Assume further that the classification has been done by extrapolating - 187 - from previous experience and that there is a high degree of confidence in the extrapolation. Once a structure has been drilled, the type of pool becomes known and the value of the discovery is therefore known, too. Table 3.4 summarizes the information available about different structures before drilling takes place. If the structure turns out to be dry (i.e., of type A), its value will clearly be zero. If the structure turns out to be extraordinarily rich and has good natural drive and other features that make recovery especially cheap (i.e., type E), it may be worth as much as $20 million. Typical structures, however, turn out to be worth $10 million. Although the average value of the petroleum in each category is $10 million per structure, only in category I does every structure contain exactly $10 million worth of petroleum. Sixty percent of the category II structures contain petroleum worth $10 million, but 20 percent contain more and 20 percent contain less. In the third category there is an even greater dispersion of possible - 188 - TABLE 3.4.— Statistical Properties of Petroleum Structure >1 3 P d) 0 rH H CP O H 0 p •p -p H 1 —1 *0 CP C -H o 0 CP rH x o p d) > o u U) •H Q i -P PQ U w -189- outcomes. The "expected value" of the petroleum in a structure of some category is the average value which would be found if a large number of structures in that category were drilled. Each category has the same expected value per structure, but structures in categories II and III are riskier than those in category I because the possible values for any single structure are more widely dispersed. There can be considerable private risk in exploring and developing a single structure. A firm which explores a category III structure, for example, may end up drilling a dry hole or a $20 million gusher. When the dispersion of possible values for an individual undertaking is large, the private exploration risk is large. For society as a whole, however, the total value of unexplored petroleum reserves can be known fairly precisely when there are a large number of geologically cataloged but undrilled structures. The dry holes counterbalance the gushers, and the value per structure averages out to be $10 million. If there are 100 structures of each type, then the value of the petroleum found will be about $3 billion. In this - 190 - ( situation, social risk is negligible because the risk cancels out over a large number of structures. Private risk for small developers, however, remains substantial because some exploration will result in dry holes and some in highly valuable deposits. Another situation in which private risk can be considerably greater than social risk is in the develop¬ ment of a new technology. In oil shale, for example, a number of possible retorting technologies exist. The probability that at least one of the many alternatives will prove successful is greater than the probability that any particular technique will pan out. Thus, an individual firm pursuing a particular technology has some chance of being a winner and developing a valuable new technology, but it may also be unsuccessful and lose its R & D investment. Society, on the other hand, » is more certain that one of the alternatives explored will pay off. Although social risk can often be less than private risk, it is not always negligible. A lack of confidence in simple extrapolations from past drilling - 191 - experience has led to increased uncertainty about remaining undiscovered U.S. petroleum reserves. It is also not clear that any low-cost oil shale technology will be developed. Finally, the value of U.S. energy resources will be determined to a large extent by the behavior of world petroleum prices. These are not only potentially volatile, but also largely beyond the control of domestic policymakers. In the absence of social risk, the conditions for efficient resource development are those derived in earlier sections. But the intrusion of private risk can interfere with the ability of a competitive market to achieve this efficient allocation. Furthermore, private risk might have effects on the distribution of economic welfare absent under conditions of certainty. When there is substantial social risk as well, these problems are compounded by the fact that even a centrally-planned economy will not have sufficient information to be confident about following an efficient resource development time path. To analyze the effects of uncertainty on market behavior and economic efficiency in more detail, we begin by laying out some - 192 - elements of the theory of decision-making under uncertainty. Decision-Making Under Uncertainty 25 / The behavior of decision-makers under uncertainty is conditioned by their attitudes toward risk. These can be classified into three categories: "risk-neutral," "risk-averse," and "risk-loving." To illustrate the differences, we consider a decision about how much to pay to acquire and explore petroleum lands with the statistical properties of structures in table 3.4. Risk neutrality implies disinterest in the dis¬ persion of possible outcomes. A risk-neutral firm is willing to pay the expected value and is therefore unconcerned, for example, with the 20 percent chance that it will acquire a category II property worth only $5 million as long as there is an equal chance of acquiring one worth $15 million. A risk-neutral firm 25 / See K. J. Arrow, Essays in the Theory of Risk- Bearing (Amsterdam: North Holland Press, 1970). - 193 - would thus be willing to pay the $10 million expected value for a property in any category. A risk-averter, on the other hand, places more weight on the consequences of an unfavorable outcome than on those of an equally probable favorable outcome. Thus, a risk-averse firm does not feel that the 15 per¬ cent chance of getting a category III property worth $15 million compensates for the 15 percent chance of getting one worth only $5 million. A risk-averter is willing to pay less than the expected value of a tract in either category II or III. The difference between the expected value of the property and the amount a risk-averter is willing to offer for it under effective competition reflects the insurance or "risk premium" the risk-averter requires against unfavorable outcomes. The more uncertain the outcome, the larger the required risk premium. Hence, a risk-averter will pay less for a category III property than for a category II property, since the dispersion of possible outcomes is larger in category III. A risk-lover, on the other hand, is just the opposite: he is willing to pay a premium over the expected value of a property in order to gamble on the - 194 - small probability of a highly favorable outcome. Attitudes toward risk can also influence production decisions. If there is uncertainty about future market conditions, a risk-averse firm is unlikely to commit itself to as large a resource development investment as a risk-neutral firm would. Similarly, a risk-loving firm is apt to invest heavily in risky situations in the hope of being able to capitalize on any especially favorable market situations which might arise. Uncertainty can also affect the rate at which firms discount the future. For example, risk-averse enterprises might shy away from risky long-term development projects despite high expected values, concentrating instead on projects with relatively quick and certain payoffs because they add a risk premium to the discount rate used in evaluating potential investments. Uncertainty and Market Behavior To proceed further with our analysis of uncertainty and market behavior, we assume that social risk is negligible and that all resources are privately owned. - 195 - We also assume that there are numerous landowners whose property contains potential petroleum reserves, but that no exploration has been done and no reserves have been identified with certainty. Finally, we assume that landowners lack the expertise to develop petroleum resources found on their property, while the petroleum companies which possess that expertise own no reserves. Thus, before production can begin, the mineral rights have to be transferred somehow from landowners to petroleum firms. Each landowner possesses an asset whose value is uncertain, and each petroleum company is offering to purchase that uncertain asset. If all landowners and all petroleum companies are risk-neutral and all agree on the statistical distribution of possible values for any individual property, then landowners should be willing to sell at any price greater than or equal to the expected value of their properties, and petroleum companies should offer to buy at any price less than or equal to the properties' expected value. Hence, properties should change hands at their expected value. - 196 - ► In the aggregate, landowners will capture all rents, while petroleum companies will earn a normal profit. Some landowners will receive less than their properties' true worth because some properties end up being worth more than their expected value. These, however, will be offset by landowners who receive more than the true value of their sub-par properties. Similarly, some petroleum companies will suffer losses because they have paid more for properties than they are worth, but others will earn above normal profits because they have paid less than the properties are worth. Those companies which earn above normal profits will be balanced by those which suffer losses. Once an oil company has acquired a property, sub¬ sequent production decisions will be unaffected by the acquisition costs. These are "sunk costs" which have to be committed regardless of subsequent profitability. The production plan which maximizes the discounted present value of net income in the absence of any sunk costs will also maximize that value net of sunk costs. Thus, the timing of resource development in a competi¬ tive market will not be affected by uncertainty if - 197 - decision-makers are risk-neutral. Absent market failure or a divergence between the market interest rate and the social discount rate, the competitive market time path of resource development will also be socially efficient. If petroleum producers are risk-averse, however, the time path may not be efficient. As we have mentioned, one manifestation of risk aversion is a tendency to add a risk premium to the risk-free market interest rate in arriving at the private discount rate for evaluating future income streams. Although it may also be appropriate in governmental planning to add a risk premium to the social discount rate, private discount rates are all the more likely to exceed the social discount rate if private risk exceeds social risk and the private risk premium exceeds the appropriate social risk premium. Private risk in excess of social risk is generally the risk of income transfer. A petroleum producer who pays a certain amount to acquire mineral rights runs the risk of ending up with resources worth less than what he has paid, and a landowner who transfers the I - 198 - mineral rights to his land runs the risk of receiving less than the true value of those rights. In the first * instance, the landowner gains at the expense of the petroleum producer; in the latter, the reverse is true. Both have an interest in reducing risk of this kind, and the market may well develop the means to do so. One such mechanism is the formation of joint ventures among petroleum producers. Instead of ten firms each purchasing and exploring a single property, they could form a joint venture to acquire ten properties. The expected value of a one-tenth share in the joint venture would be the same $10 million as if each firm acquired a single property, but the probability of a return significantly less than $10 million or one significantly greater than $10 million would be reduced. Risk averse firms would willingly sacrifice the like¬ lihood of above-average outcomes for a reduction in the likelihood of similarly below-average outcomes. Resource owners might wish to reduce the risk of giving up their properties for less than their true value by collecting a royalty on production. An initial bonus payment might be charged as well, but this bonus will be smaller than the bonus which would be paid if there were no royalty payments. When a property is above average, the discounted present value of royalties plus the initial cum-royalty bonus payment will exceed the value of a bonus which would be paid in the absence of a royalty. When a property is below average, this sum will be less than the pure royalty- free bonus. Resource owners may well be willing to give up the possibility of getting the larger pure bonus for below-average properties in return for the chance to earn royalties on above-average properties. Risk-averse petroleum firms may also prefer acquiring petroleum rights on a royalty basis because they are protected against greatly overpaying for below-average properties. Under these circumstances, the negotiation of royalty terms is a mutually beneficial risk-pooling arrangement. The formation of joint ventures and the use of royalty payments are two ways the private market may cope with uncertainty. To the extent that forming a joint venture reduces risk and mitigates the adverse efficiency effects of risk-averse behavior on resource - 200 - / development timing, it is a socially beneficial arrangement. However, joint ventures may also reduce competition or even facilitate outright collusion. Royalties may have similar mixed effects. Their risk¬ sharing feature may mitigate overdiscounting of the future, but as we shall see in chapter 5, royalties may have other effects in discouraging production and hence impairing efficiency. / The institutions the market develops to cope with private risk evolve in response to private risk prefer¬ ences. If the Government respects consumer preferences toward risk as well as consumer preferences for the timing of consumption and the choice of consumption goods, it will not subvert those preferences by attempt¬ ing to compensate for market failures which remain despite, or as a direct result of, market arrangements ( for sharing risk. As we shall see next, however, it is difficult even to develop criteria for judging the market's effectiveness in securing an efficient alloca¬ tion of resources when there is substantial social risk. - 201 - Social Risk and Efficient Resource Development In the absence of social risk, there is a unique time path of resource development which maximizes the discounted net social value of the Nation's energy resources. However, when future demand and supply conditions are uncertain and social risk is inescapable, a resource development time path which is efficient under one unfolding of future events may be quite inefficient under another. In this section we attempt to develop some principles of resource development under uncertainty which are useful both in evaluating market performance and in designing leasing policy. 26 / Much uncertainty concerning the efficient timing of exhaustible resource development stems from the paucity of information concerning the total resource stock. The chance of making a disastrously wrong decision could be greatly reduced if more were known 26 / Cf. Hitch and McKean, op. cit ., upon which much of this discussion is based, for a more detailed dis¬ cussion of analogous problems involving uncertainty in evaluating defense resource allocation. - 202 - / about the quantity of resources which will be forth¬ coming from as-yet-unexplored areas. Through extensive exploratory efforts, true resource availability could no doubt be measured with considerable precision, but exploration on a very large scale may be inefficient. Information cannot be acquired costlessly. Up to a point, the value of additional information is greater than the cost of acquisition, but like all economic goods, information is characterized by decreasing marginal usefulness and increasing marginal acquisition cost. Hence, gathering information efficiently usually means stopping short of attaining full information. More exactly, information gathering should be carried only to the point at which the information's marginal social value equals the marginal social cost. Nevertheless, there is reason to suspect that the competitive market will generate less than the socially efficient amount of information. This will be true, for example, if the private benefits from expenditures on exploration are less than the social benefits, or if private costs are greater than social costs. Initial exploratory efforts in virgin areas such as the 1 - 203 - Atlantic Outer Continental Shelf yield valuable information about the likelihood of success from I subsequent exploration in the same area. The company which actually does the exploration will generally be unable to keep its results secret, nor can it capture the full value of the acquired information by selling geologic data to others. Thus, in deciding its level of exploratory expenditure, a profit-maximizing company will spend up to the point at which the marginal value of expected reserve additions from new discoveries equals marginal exploration cost. However, society would benefit from still more exploration—up to the point at which the marginal value of reserve additions plus the marginal value of information about total resource supply and the possibility of further reserve additions equals marginal exploration cost. A similar divergence between private and social benefits arises in the case of research and develop¬ ment on new energy technologies. In oil shale, for example, developing an economically viable retorting technique is still an unsolved technological problem. If companies do not capture the full social value of any - 204 - » successful development—e.g., through licensing fees—the private benefits from successful R & D will be less than the social benefits, and too little R & D will be supported. This is not to say that all technological possibilities should be pursued blindly ignoring their costs. The rule for R & D is the same as the rule for exploration: it should be carried to the point where its marginal social benefit equals marginal social cost. ( As long as foreign oil is needed to satisfy U.S. demand, uncertainty about future world oil prices will affect domestic reserve exploration and development choices and decisions concerning R & D investment to develop alternative energy technologies. For example, extensive exploration of the Atlantic OCS and intensive efforts to develop oil shale retorting techniques will have a much higher social value if the OPEC cartel remains strong and keeps world oil prices high than if the cartel collapses and prices fall toward cost. However, explora¬ tion and R & D decisions must be made in ignorance of future prices. - 205 - Furthermore, successful development of an alternative to foreign oil is quite likely to affect the world price. The current world oil price is at least an order of magnitude higher than marginal production cost. This surplus of price over production cost represents a rent attributable largely to the monopolistic restriction of supply by the OPEC cartel.27/ There is insufficient non-OPEC oil with low enough production costs to restrain OPEC's monopoly power. However, if the U.S. should successfully develop the Atlantic OCS, oil shale, or some other alternative with costs appreciably below the OPEC price, its demand for OPEC oil will decline. It might even become a net exporter. The development of competitive alternatives will put a ceiling on OPEC prices and could conceivably threaten the cartel's pricing discipline. Care in designing policies to improve our informa¬ tion about total U.S. energy resources reserves or to develop alternative energy sources will reduce some of 27 / As we have seen, however, efficient resource development timing requires that price be somewhat higher than marginal production costs (pp. supra. - 206 - the social risks of energy resource development. Policies which reduce the monopoly power of the OPEC cartel will further attenuate social risk by lessening uncertainty about future prices. However, any policy for reducing social risk has costs, and a rational policy will not call for the elimination of all risk. Given social risk, choosing efficient resource develop¬ ment time paths will be more difficult if a strategy which is efficient under one set of contingencies is disastrously inefficient under another. If each strategy being con¬ sidered has very unsatisfactory characteristics under a plausible set of contingencies, more effort should be devoted to finding a more satisfactory strategy than to choosing among existing strategies. This problem is often compounded by difficulty in assigning probabilities to the various contingencies. A strategy which maximizes expected net social value given one assignment of probabilities may be much inferior to another strategy if the probabilities are different. Although it is virtually impossible to determine through strict benefit/cost analysis the optimal amount of information which should be gathered, difficulty in planning on the basis of available information is usually an indication that it is worthwhile to try to acq\i re additional information. The dilemmas inherent in planning energy resource development under uncertainty should advise caution in advocating Government energy management. Government bureaucracies are not omniscient. They are subject to judgmental mistakes and operating inefficiencies. Furthermore, private market speculators might serve to keep the market from deviating too greatly from the development time path an omniscient planner would choose. For example, producers whose evaluation of future supply and demand conditions suggests that the current pace of development will lead to shortages and an unanticipated price increase at some time in the future may choose to curtail production and wait for the higher prices. If they are correct, these speculators will have per¬ formed a socially desirable function of deferring production to a time when its discounted net social value is higher. - 208 - However, if one has little faith in the efficacy of such speculation, or if there is a social consensus against allowing speculators to profit from their activities, one might wish to have the Government act as a "speculator of last resort" by keeping an eye on lon<^run demand and supply conditions and intervening when the market appears to deviate from the desired development path. But before intervening in this way, Government policymakers ought to be reasonably confident that the multitude of individual market participants are wrong in their evaluation of future demand and supply conditions. In energy resource development, considerable uncertainty about the correct course is unavoidable, whether decisions are made by a Government bureaucracy or the collection of buyers and sellers constituting a market. I - 209 - ( Chapter 4 POLICY GOALS The previous chapters have described the historical context of Federal mineral land disposal policy and analyzed its economic foundations. In this chapter we examine specific policy goals. Leasing and other land disposal activities can be evaluated in terms of purely economic goals, along the lines suggested in the previous chapter. It is clear, however, that actual policies over the years have also incorporated non-economic goals. Early land policies were formulated with the objective of promoting rapid development of the largely unpopulated West. The Government was less concerned about collecting the fair value of mineral land than with promoting rapid exploration and development. Now Project Independence aims to stimulate domestic energy resource production for a different set of reasons. Reliance on foreign oil imports is viewed as a threat to national security and a strain on the balance of payments. Public policy may therefore dictate a departure from the resource *- 210 - development path that would be selected for purely economic reasons. Traditionally, three goals have been pursued by the Department of the Interior in administering mineral leasing programs: (1) orderly and timely resource development; (2) receipt of fair market value; and (3) protecting the environment. 1/ From time to time, other objectives have been suggested or pursued. Among them, the following have been most prominent: 1/ Each of these objectives is codified in statutes, with the pertinent laws being the Mineral Leasing Act of Feb. 25, 1920 (30 U.S.C. §§181-287), the Acquired Lands Leasing Act of Aug. 7, 1947 (30 U.S.C. §§351-359), the Outer Continental Shelf Lands Act of Aug. 7, 1953 (43 U.S.C. §§1331-1343), the National Environmental Policy Act of 1969 (42 U.S.C. §§4321-4347), the Mining and Minerals Policy Act of 1970 (30 U.S.C. §21a), the Geothermal Steam Act of 1970 (30 U.S.C. §§1001-1025), Title 31 U.S.C. §483 (obligating the Federal Government to obtain fair market value for public lands leased or sold), and the Mining Law of 1872 (as it pertains to uranium on public land). See U.S. Senate, Committee on Interior and Insular Affairs, Federal Leasing and Disposal Policies , 92d. Cong., 2d. Sess., June 19, 1972, pp. 38, 39. - 211 - ( » (4) promoting domestic energy self-sufficiency (e.g., Project Independence); (5) promoting competition and discouraging monopolies in energy resource development; (6) maximizing Government revenue; and (7) meeting the current fiscal needs of govern¬ ment . Several of these objectives are in clear conflict with one another. Others remain amorphous, of little practical use to a policymaker without further elabora¬ tion . Alternative Leasing Policy Objectives Chapter 3 identified full collection of the economic rent and efficiency in resource development as desirable leasing policy goals. Other goals have been pursued in the past, and still others have been suggested. They should be analyzed in light of the objectives derived from economic theory. ) - 212 - Orderly and timely resource development, one of the three objectives established by the Interior Department, is an ambiguous guide to policy, subject to varying interpretations. A more rigorous definition, we believe, would bring it within the broader objective of efficient resource development. The precise meaning of orderly and timely develop¬ ment has never been clear. For example, oil companies have always supported accelerated leasing of Outer Continental Shelf lands, believing that such a policy would lead to the appropriate rate of development. Environmentalists, on the other hand, have urged a "go slow" policy, arguing that only then would we have adequate environmental safeguards, which, they maintain, are necessary for orderly and timely development. Project Independence assumes that an accelerated rate of development is appropriate. Yet rapid use of present energy resources takes place at the expense of future generations and creates a danger of transitional shortages during the period between the exhaustion of existing fuel resources and the development of new technologies. - 213 - Protecting the environment, another Interior Department objective, is also consistent with economic > efficiency. Efficiency, as we noted in chapter 3, requires the explicit consideration of environmental impacts. Otherwise, real social costs will be ignored. The passage of the National Environmental Policy Act in 1969, which prompted the inclusion of environmental protection as a leasing policy objective, forced corporate and governmental decision-makers to recognize these costs. The result should ideally be a more efficient allocation of society's resources. The remaining Interior Department leasing policy objective—insuring the receipt of fair market value for public lands—can be analyzed in the light of our earlier discussion of economic rent. Equity considera¬ tions argue that the Government, as custodian of public lands and fisc, should collect the full value of leased lands' economic rent. Fair market value, we believe, should be defined as equivalent to the competitive economic rent. Otherwise, private firms might pay less for public resources than they could justifiably pay while still retaining adequate profits. -214 In summary, the three leasing policy objectives established by the Interior Department fall within the broader concepts of full economic rent capture and efficient resource development. Other objectives have, however, been suggested or employed. They can be analyzed with reference to the efficiency and rent capture goals. Following the Arab oil embargo, the United States became increasingly concerned about its dependence on foreign energy sources. Project Independence was framed on the theory that national security requires a greater degree of domestic energy self-sufficiency. In the past, similar considerations were held to justify imposing oil import quotas and prorationing. The acceptance of these measures has resulted in large efficiency losses, with the public paying handsomely— in the form of higher than necessary oil prices—for the additional security. 2/ Increased emphasis on 2/ See, for example, Alfred E. Kahn, "The Combined Effects of Prorationing, the Depletion Allowance, and Import Quotas on the Cost of Producing Crude Oil in the United States," Natural Resources Journal , Jan. 1970), pp. 53-61. - 215 - domestic energy resources, which would initially require relying on higher cost fuels, would lead to similar sacrifices of orthodox economic efficiency. This is not to say that national security (and, as a corollary, energy self-sufficiency) is not a desirable objective of mineral lands disposal policy. The pre¬ scriptions of economic theory must square with political realities. It appears that the people of the United States do desire a greater degree of energy independence. The extent of that independence, however, has yet to be determined. Energy self-sufficiency is attainable only at considerable cost. Nordhaus has estimated that free trade in energy was worth in 1973, on the average, $16 billion annually over the 20-year period 1970-1990. 3/ The degree to which we wish insulation against political machinations abroad must be balanced against the efficiency losses we are willing to shoulder. 3/ This calculation is made in 1970 dollars and assumes that foreign sources of energy are competitively priced. In light of the concerted actions of the OPEC cartel, the actual value would be lower. See William D. Nordhaus, "The Allocation of Energy Resources," Brookings Papers on Economic Activity , vol. 3, The Brookings Institution, 1973, p. 566. - 216 - In chapter 3 we found that economic efficiency and effective competition are closely linked. Only in the absence of monopoly elements can the free play of market forces result in optimum resource allocation. The importance of effective competition in ensuring the efficient development and production of energy resources cannot be overstated. As a leasing policy objective, then, promoting competition and discouraging monopolies in energy resource development is consistent with the pursuit of economic efficiency. In addition, truly competitive bidding for leases is more likely if there is a competitively structured energy industry. Under those circumstances, it is easier for the Government to collect the full value of the economic rent from its lands. Leasing policies which increase industrial con¬ centration—i.e., which increase the dominance of a small number of entrenched firms—must be evaluated critically, for they may be incompatible with broader efficiency and equity goals. This is not to suggest that mineral land policies should be designed to ensure the participation of small businesses. As the courts have noted, protecting competitors is not the same as promoting competition. For certain resources, large capital costs and economies of scale may make small business participation inappropriate. Whether or not small firms' involvement is desired must be decided on the basis of the specific technological and economic conditions of the energy resource in question. The remaining two objectives—maximizing Govern¬ ment revenues and meeting the current fiscal needs of government—can also be related to our earlier theo¬ retical analysis. With its dominant position as a mineral landlord, the Government is capable of acting like a monopolist, maximizing the revenues it collects. It can accomplish this by limiting the supply of mineral bearing lands it makes available, offering them at a rate which lags far behind demand. Such a policy, however, would result in resources being developed at an inefficient rate over time. -218 Similar arguments apply to the policy of limiting lease offerings to meet the Government's fiscal needs— for instance, using lease sales as a means of reducing spending deficits. 4/ This policy, too, is inefficient. There is no reason to expect that scheduling lease sales in such a fashion will lead to an efficient allocation of mineral resources over time. If a balanced budget is the Government's goal, other policies would be better suited to its attainment. From the foregoing discussion, we conclude that current Government leasing policies reflect five main objectives: (1) fully capturing the economic rent; (2) promoting efficient resource use; (3) protecting the environment; 4/ This policy has, on occasion, been pursued. See U.S. House of Representatives, Permanent Select Committee on Small Business, Subcommittee on Activities of Regulatory Agencies, Energy Data Requirements of the Federal Government (Part III - Federal Offshore Oil and Gas Leasing Policies), 93d. Cong., 2d. sess., March 26, 27; April 9, 10, 11; May 7, 1974, p. 168. - 219 - (4) promoting competition and discouraging monopolies in energy resource development; and (5) ensuring national security through increased energy self-sufficiency. The first two objectives are the most important, for they incorporate the third and fourth and (under a broader conception of efficiency) the fifth, too. However, the degree to which a particular policy meets these goals is difficult to assess. Therefore, promot¬ ing competition to foster realization of the other goals becomes especially important. Taken as a whole, we believe, these five objectives provide a sound basis for evaluating alternative leasing policies, with the precise trade-offs to be established through the political process. - 220 - Chapter 5 LEASING METHODS This chapter examines in detail various leasing methods the Government might use to achieve its overall policy goals. These include different types of bidding mechanisms, oral auctions, sealed bids, and so forth. Also, different types of payment arrangements such as bonus payments, production royalties, rental fees, etc., are examined. Three major criteria are applied in evaluating alternative leasing methods: First, the effect in terms of obtaining "fair market value" from the leased property. Second, the effect on economic efficiency, both in the technical sense of obtaining resources at lowest cost, and in the broader sense of promoting competition. Third, the effect of alterna¬ tive leasing methods on the degree of U.S. energy self- sufficiency. - 221 - Competitive vs. Noncompetitive Systems Given the amount, location, and timing of the transfer of mineral rights to the private sector, two questions remain: who will be granted these valuable rights, and how much will they pay for them? Absent externalities, a competitive market answers these questions in an efficient manner. The resources go to those willing to pay the highest price, generally where they are needed most or can be developed at the least cost. This contributes toward the goal of maximizing economic efficiency. Assuming effective competition, bidders are forced to offer the full amount of a lease's value. The Government, therefore, receives the "fair market value" of the lease and, if the winning bidder's valuation of the lease was correct, collects the full economic rent. Under noncompetitive lease allocation systems, neither economic efficiency nor receipt of fair market value is likely to be achieved. If the Government - 222 - grants mineral rights (or even title to the land) free or for a nominal fee, the resources will go to those quick enough to grab first or lucky enough to win a lottery drawing. If these persons could in turn sell their mineral rights to those who are willing to pay the highest price, a competitive market would be established, and the resources would still be developed in an economically efficient manner. Whether or not this is the case, it is highly unlikely that the Government will collect the full economic rent if the lands are allocated noncompetitive- ly. If they are given away, the Government, of course, receives nothing. If they are sold at a set price, it is not likely to be the correct price. In fact, the price has usually been nominal. If the price is negotiated, the Government is open to charges of favoritism. Only a competitive market provides an impersonal mechanism for allocating energy resources to their best uses at a "fair" price. - 223 - Noncompetitive lease allocation systems would appear to be justifiable under two circumstances, but closer analysis shows that they should not be used even in these cases. (1) Where the degree of competition under a competitive system would not be sufficient to provide the desired results, and results would be better under a noncompetitive system than under such a poorly-working system, it would appear that a noncompetitive system should be used. However, this suggests that the leasing system should be changed to increase the degree of competition or that the land should not be leased until sufficient industry interest is demonstrated. (2) Where goals other than economic efficiency and a fair return to the Government are to be cultivated, noncompetitive leasing systems may help achieve those goals. If the primary policy objective were to increase the rate of the resource's development, for example, giving the mineral rights to companies at little or no cost would encourage production. The distribution of Federal lands can also be used as a - 224 - means of encouraging particular activities. For • instance, granting low-cost leases to persons who have discovered mineral resources may encourage exploration. Similar grants could be used to encourage research and development in energy technologies. Even in these cases, it would be preferable to allocate leases competitively and then provide a direct monetary or tax allowance subsidy to the activity that is to be encouraged. Then leases would tend to be allocated efficiently, and the amount of the subsidy would be known. Nationalization Although the present study analyzes in detail only various competitive leasing systems, it should be noted that the Government need not lease public lands at all. Instead, it could explore for, develop, and produce the resources itself. In view of the uncertainties involved in exploration, the possibility that bidding for leases and sale of the resources might not be competitive, and the existence of other market - 225 - imperfections, we cannot presume that it is always best to transfer energy resources to the private sector for development. It is possible that nationalization would be a superior alternative. In this section we consider three forms of nationalization: full nationalization of exploration and production, full nationalization of exploration only, and partial nationalization of exploration and production. Full Nationalization of Exploration and Production Due perhaps to ideological tradition more than anything else, the United States has resorted to public ownership and operation of industry only when private markets were thought not to function satisfactorily. At least four categories of market failure can be iden¬ tified in the development of natural resources. 1 / First, there are important externalities. Private firms may not receive the full benefits from their expenditures (e.g., their exploration activities 1/ For a more thorough discussion of market imper¬ fections, see chapter 3. - 226 - benefit other firms by providing information about an area's geology). Nor do they pay the full costs of their activities (e.g., the cost of environmental damage). However, nationalization is not essential to correct this type of market failure. Externalities can be "internalized" by applying appropriate regulations, taxes, and subsidies. Second, the private rate of time preference may differ from the social rate. This is really a form of the externality problem. Private industry may develop resources at a rate which does not adequately take the interest of future generations into account. This problem could also be solved by means other than nationalization—principally, by regulating the rate of leasing or by applying taxes in order to reduce the rate of consumption. Third, the existence of uncertainty tends to reduce the level of production below the socially optimal level. It is not clear that nationalization would eliminate this problem. Government managers may have the same incentive to produce "good" results - 227 - (i.e., a favorable ratio of discoveries to dry holes) as do private managers. If this is the case, their decisions will also be affected by risk aversion. Fourth, the industry that develops the resource may be monopolistic, resulting in restrained production and increased prices. However, since a profit maximiza¬ tion criterion is commonly prescribed as a guide to decision-making and accountability in public enter¬ prises, Government enterprises might also have an incentive to restrict output and raise prices. 2/ The performance of a Government-managed company may also experience less pressure to reduce costs and innovate, rigidities introduced by Government standards and procedures, and political intervention. It is possible to find examples of Government enterprises that have performed admirably (such as certain U.S. Army arsenals and the Tennessee Valley Authority) as well as those that have performed poorly (the U.S. Post Office being a prime example). We simply do not have enough 2/ See Frederic M. Scherer, Industrial Market Structure and Economic Performance (Chicago: Rand McNally & Company, 1970) , pp"i 420-422. - 228 - evidence to say whether nationalized enterprises work more or less efficiently than private firms in the "typical" case. 3/ Given the potential drawbacks of public enterprise, however, the nationalization route would appear warranted only if there are serious market imperfections that cannot be corrected adequately by measures such as taxes, subsidies, antitrust enforce¬ ment, and regulation. Full Nationalization of Exploration An alternative is for the Government to explore for resources and then sell the deposits discovered to private firms for development and production. This would reduce the adverse effects of uncertainty, since the quantity and quality of the resources transferred to the private sector would be better known. It would also alleviate a significant externality problem: the "information spillover" which occurs when the explora¬ tion activity of one firm benefits other firms. Nationalization would also eliminate unwarranted 3/ Ibid . - 229 - duplication of exploration activities. The benefits of nationalization might nevertheless be outweighed by a serious drawback. Under nationaliza¬ tion, decisions on whether or not to explore an area would be made by only one organization. Under a private enterprise system, numerous firms, each with different interpretations and varying preferences for diverse types of prospect, arrive at different decisions. For example, the exploration of some maverick firm could lead to the discovery of a giant oil field in an area that had been bypassed by organizations with different interpretations of the geophysical and geological data. Duplication of exploration activity may therefore be well worth the added cost. If exploration is nation¬ alized., the benefits of pluralism are lost. Partial Nationalization of Exploration and Production Another policy option is the establishment of a Government corporation to compete with private firms. Under this strategy, only part of the industry is Government-owned. The two principal purposes would be - 230 - to provide a yardstick against which to measure the performance of private firms and to counteract monopo¬ listic behavior. In order to be useful as a yardstick, a public corporation must be put on equal footing with private firms. It should not be given preferred access to public lands, but should be required to bid com¬ petitively for such lands like any other company. The corporation should also be required to make payments in lieu of taxes. Alternatively, if the public corporation does possess advantages over private firms, appropriate analytic adjustments must be made when comparing its costs or profits with those of private firms. It would be particularly difficult to apply the yardstick approach in the case of petroleum production, since a Government enterprise may develop deposits quite different from those developed by other petroleum producers. The average production cost of the public corporation would depend on the quality of the lands explored, the size of deposits discovered, the water depth, etc. One cannot presume that production costs should be the same for private firms, since they may operate under different conditions. Costs are also difficult to compare because of unavoidable arbitrari¬ ness in allocating the joint costs of oil and gas pro¬ duction. Thus, while a Government corporation may serve as a yardstick in some cases, care would have to be taken to ensure that the yardstick is used to measure comparable entities. A Government corporation might also stimulate competition or counteract monopolistic conduct. For example, the corporation could expand output and under¬ cut the prices of private producers. The problems with this are that: (a) it may be difficult to tell whether private firms are behaving in a monopolistic fashion; (b) the Government corporation, anxious to show a profit and to avoid complaints about subsidization, may find that monopolistic behavior is in its own interest; 4/ and (c) such a strategy presumes that the Government knows the optimal level of output. In view of uncer¬ tainty concerning the socially optimal level of output, it cannot be taken for granted that the Government's attempt to enforce such a level would produce better i/ Ibid ., p. 420. - 232 - results than those obtained by even an imperfectly competitive market. While nationalization should be considered as a significant alternative, it is evident that both full and partial nationalization have serious drawbacks. It is therefore important to determine the relative advantages and disadvantages of alternative competitive lease allocation systems—a task undertaken in the remainder of this chapter. Competitive Bidding Mechanisms Competitive bidding can take place through an oral auction, a sealed bid system, or a combination of the two. The appropriate bidding mechanism depends upon the effectiveness of competition, the Government's knowledge of the value of the resource, and the characteristics of the buying industry. 5/ 5/ See Walter J. Mead, "Natural Resource Disposal Policy—Oral Auction Versus Sealed Bids," Natural Resources Journal , vol. 7, no. 2, April, 1967, pp. 194-224, on which this section was based. - 233 - Oral Auction Where competition is weak, an oral auction is not an appropriate method of allocating Federal energy resources. When there are few bidders, a rather well- defined community of bidders is established. Firms can therefore agree tacitly or explicitly to keep bids low, or to refrain from bidding on certain leases. If one member of a collusive arrangement violates the agreement, the others can outbid him. The recalcitrant party can even be punished by driving up the bids on the leases in which he is interested or outbidding him in every case, therefore precluding him from obtaining any of the resource offered. Such practices, called punitive and preclusive bidding, could also be used to prevent new firms from entering the market. Even if there is no explicit collusion, bids at an oral auction may serve as signals. For example, a high initial bid or a large raise may be used to show that the firm is determined to win that particular lease. Other bidders may refrain from bidding up the price on that lease, with the expectation that the favor will be - 234 - returned when they have a strong interest in another lease. Aside from the potential for collusive practices when the degree of competition is low, companies derive two advantages from an oral bidding system. First, the bidding is sequential, so firms can stop bidding when they have secured the desired acreage or exhausted their bidding budgets. Under a sealed bid system, partici¬ pants may win more leases than they can finance or desire to develop. This could be a severe problem for small firms if they find it difficult to resell leases. Companies may also win fewer leases than they desire to acquire. Secondly, peculiar technological or logistic circumstances may make it necessary for firms to acquire specific leases. If transportation costs are high, for example, a firm may be dependent upon nearby resource deposits to supply a plant in which it has a large fixed investment. They may also need to acquire specific tracts in order to "block up" an area of sufficient size to permit economical operation. In an oral - 235 - auction, the firm can react to other bids, so it will have to pay only slightly more than the entity that places the second highest value on the tract. Under a sealed bid system, the firm may feel compelled to bid more than the amount that would yield normal profits to be sure of winning the lease in order to keep its plant in operation. The firm will be willing to operate the plant at a loss as long as revenues are greater than operating costs, even if fixed costs (mainly the cost of investment sunk in the plant) are not covered. The Government would therefore capture the profits of the firm as well as the economic rent. 6/ There are at least two disadvantages to an oral auction system from the viewpoint of a large firm. Since decisions must be made on the spot, it may be necessary for high-ranking officers to attend the auctions. Sealed bid decisions can be made at loca¬ tions and times more convenient to management and under less emotional circumstances. £/ A possible solution to this problem is the use of a sealed bid system with the option of oral auction at the request of bidders. Such a system is used in New Mexico. - 236 - < Oral auctions also present the problem of the "free rider." Bidders may use the extent of competition for a tract and the level of bids by companies that have con¬ ducted pre-lease exploratory work as indicators of a tract's value. They thereby take advantage of other firms' exploratory work at no cost to themselves. For this reason, enterprises that spend large amounts on exploration are likely to prefer sealed bidding over an oral auction. Sealed Bidding Sealed bidding is the most effective method of lease allocation when the degree of competition is weak. Since the number and identity of bidders are not known until after the bids are opened, firms will not be certain of how much competition there is for a particu¬ lar tract. They are therefore under pressure to submit a higher bid than they would if it became obvious during an oral auction that other firms were not interested in the tract. - 237 - Sealed bidding is not conducive to the collusive practices encouraged by oral auctions. Colluding firms would not be able to react to a higher bid by an out¬ sider or a firm that breaks the agreement. Preclusive and punitive bidding are less likely, because the necessary level of the bid would not be known. Since each bidder can submit only one bid, bids cannot be used as signals of determination to win the lease. Advantages of sealed bidding to bidders are that high-level officers need not be present at the lease sales, and the "free rider" problem is avoided. One disadvantage of most sealed bid systems is that the bids on all tracts are entered simultaneously. There¬ fore, a firm may end up with no leases or with more leases than it wants. This problem could be avoided by opening sealed bids sequentially rather than simul¬ taneously. That is, bids on a lease or group of leases would not be offered until after the bids on the previ¬ ous lease or group of leases have been opened and accepted or rejected. This would allow companies to raise their bids if they failed to win any of the early leases and to stop bidding when they have acquired the - 238 - c desired number of leases. However, sequential bidding would also facilitate the kinds of collusive practices encountered in oral auctions. As long as one or more lease sales are held each year, firms could acquire desired additional leases with¬ out excessive waiting. And if there is a secondary market for leases, excess tracts could be sold to firms that desire additional tracts. Under these circumstances, there would be no need to adopt a sequential sealed bid system which tends to facilitate collusive practices. A significant disadvantage of the sealed bid system from the perspective of bidders is that only one bid can be entered, so there is no opportunity to react to the bids of other firms. For example, one company may place a value of $200,000 on a lease. If it believes that few other firms are interested in the tract and that none is likely to bid more than $150,000 for the tract, the company may submit a bid of $150,000. As events transpire, the second-high bid may turn out to be only $50,000. The winning bidder therefore paid about $100,000 more than necessary to win the lease. While - 239 - the winning bidder may understandably be irked by the large amount of money "left on the table" (i.e., the difference between its high bid and the second-high bid), there is no effect on economic efficiency, since the winner valued the lease at $200,000. Sealed Bid Followed by Oral Auction If there are compelling reasons why certain firms might need to acquire particular leases, it may be preferable to institute a system of sealed bids followed by an oral auction. Under this system, bidders must submit a sealed bid equal to or higher than a specific undisclosed amount in order to qualify for the sub¬ sequent oral auction. Such a system has all the advantages and dis¬ advantages of an oral auction system. While avoiding the principal disadvantage of a sealed bid system, it retains to some degree the outstanding advantage of that system. The danger that the tract will be leased for a nominal bonus is reduced, since bidders must meet the minimum bid that qualifies them for participation - 240 - in the auction. As long as the level of the minimum bid is uncertain, firms seeking to acquire the lease may bid an amount closer to their valuation of the tract. If the minimum bid is consistently set well below the value of the tract, however, companies may feel con¬ fident that they will qualify for oral bidding with a sealed bid considerably below their own true valuation. If the minimum bid is disclosed before the sealed bidding takes place, the sealed bid stage is redundant and the system becomes essentially an oral auction system with a minimum opening bid. Refusal Prices In the combination sealed bid/oral auction system described above, the minimum acceptable sealed bid serves as a refusal price—that is, a price below which the tract will not be leased. Where the value of a resource is known, it certainly makes sense to have refusal prices, unless the Government's objective is to lease additional land regardless of whether or not the fair market value is received. Establishing a minimum acceptable bid ensures that the tract will not be - 241 - leased at a fraction of its value if (owing to collusive behavior or fewness of bidders) the bids are below the bidders' true tract valuations. Where the resource's value is uncertain, refusal prices become both more important and more dangerous. The greater the degree of uncertainty, the greater is the probability that someone could win a lease with a bid below his valuation of the tract. Tracts of highly uncertain value could even be won through a "fishing bid"--i.e., an extremely low bid which is made without carefully estimating the tract's value. It is there¬ fore important to have a refusal price in order to avoid disposing of resources at too low a price. Unfortunately, the greater the degree of uncertainty (and therefore the greater the need to establish refusal prices), the more difficult it is to determine the correct refusal price. If the refusal price is too low, the Government may collect only part of the economic rent. If it is too high, resources that should be developed will not be leased. - 242 - 0 The refusal price need not be close to the market value of the lease in all cases, however. In order to prevent a serious misallocation of resources, it should probably be on the conservative (low) side. The important thing is for it to be unpredictable, i.e., not always on the conservative side, therefore forcing bidders to bid an amount closer to their true estimate of the lease's value. Nevertheless, as long as there is a possibility that the refusal price is set too high, it should be recognized that more complete capture of economic rent by the Government is achieved only at the sacrifice of some economic efficiency. Summary Where there is a high degree of competition for leases, the choice of bidding mechanism should be determined by industry preferences. If the number of bidders is small compared to the number of tracts offered for lease, however, the high bid is more likely to approximate fair market value under a sealed bid system than under an oral auction system. If lease sales are held infrequently and there is no secondary * - 243 - market for leases, the tracts offered in a given sale should be leased sequentially rather than simultaneously. When the degree of competition for leases is low, the oral auction method should be considered only if it is essential that firms acquire specific leases. When an oral auction is held, it is especially important to establish refusal prices. Refusal prices should generally be unpredictable but biased on the conserva¬ tive side. - 244 - I Alternative Bidding Systems 7/ Bidding systems are usually categorized according to the type of payment on which the bidding is based. We will discuss alternative leasing systems under six main categories. Cash bonus bidding, royalty bidding, profit share bidding, rental bidding, and exploration or R&D work commitment bidding will be analyzed as pure systems; i.e., as if there were only that single mode of payment. All combination systems—those involving more than one method of payment—will be lumped together in 7/ This section is based largely on the following sources: U.S. Public Land Law Review Commission, Study of Outer Continental Shelf Lands of the United States , prepared by Nossaman, Waters, Scott, Kreuger, and Riordan (Los Angeles, California, October 1968, revised November 1962); U.S., Senate, Committee on Interior and Insular Affairs, Hearings, Outer Continental Shelf Policy Issues , 92d Cong., 2d sess., 1972; U.S., Senate, Committee on Interior and Insular Affairs, Hearings, Federal Leasing and Disposal Policies , 92d Cong., 2d sess., 1972; U.S., House of Representatives, Subcommittee on Activities of Regulatory Agencies of the Permanent Select Committee on Small Business, Hearings, Energy Data Requirements of the Federal Government , 93d Cong., 2d sess., 1974; and Hayne E. Leland and Richard B. Norgaard, An Economic Analysis of Alternative Outer Continental Shelf Petroleum Leasing Policies , pre¬ pared for The Office of Energy R&D Policy, National Science Foundation (September 1974). -245- L the final category. We will examine the possible effects of each system on the receipt of fair market value, economic efficiency, and energy self-sufficiency. Cash Bonus Bidding 1. Receipt of Fair Market Value. Under a competitive bonus bidding system, the lease is awarded to the bidder who offers the largest lump-sum cash payment. Cash bonus bidding is the most appropriate method of lease allocation under conditions of certainty. In practice, however, several factors may impart significant disadvantages to a cash bonus bidding system. Most of the problems stem in one way or another from uncertainty. Actual revenues and costs from a lease may turn out to be quite different from what bidders originally expected. If firms bid com¬ petitively on the basis of their best cost and revenue estimates, and if the cost estimates subsequently prove too low or the revenue estimates too high, the -246- Government "over-collects" the economic rent, and the winning bidder suffers a loss. If costs turn out to be lower or revenues higher than expected, the Government does not collect the full economic rent, and the firm enjoys a windfall gain. Although the Government may receive more or less than the true value of individual leases, the over-collections should on average offset the under-collections as long as three conditions hold: (1) a large number of tracts are leased; (2) there is no tendency for firms consistently to bid less than or more than their estimated value of the leases; and (3) there is no unforeseen shift in costs or product prices. Even if the first condition holds from the Government's perspective, individual companies (espe¬ cially small firms) may not acquire a large enough number of leases to ensure that their gains and losses average out. If they are risk-averse, they will tend to bid less than the expected value of leases. f -247- The effect of uncertainty and risk on Government lease revenue depends to a large degree on the level of bonus bids. Firms may not be reluctant to lease a tract that may prove to be worthless if they are risking only a few hundred dollars. They will be much more wary if they are risking millions of dollars or a large frac¬ tion of their exploration budgets on one lease. 8/ The higher the level of bonus bids, the greater is the effect of risk aversion. High bonus bid levels may also reduce Government lease revenues in other ways. If companies rely on internal cash flow for financing bonus payments or have fixed exploration budgets, the higher the level of bonuses, the lower will be the number of tracts on which each firm can bid. If they seek outside capital to expand their exploration efforts, they may find it difficult or costly to raise additional funds where the degree of risk is high. Again, such capital 8/ Firms are actually risking all expenditures made before a commercial deposit is discovered. Only the large bonus payment is unique to a bonus bidding system, however. Other pre-discovery costs, such as exploratory drilling, are incurred regardless of the lease allocation method. -248- rationing will limit the amount of bidding. Large bonus bids combined with uncertainty may reduce the number of tracts on which large firms can bid, prohibit small firms from bidding on the most attractive tracts, and discourage new firms from entering the industry. Given the number of tracts to be leased, the result is a reduced number of bidders per tract, weaker competition, and a tendency for bids to fall below the fair competitive value of leases. In summary, under conditions of uncertainty, the Government will receive less than the fair market value of some leases and more than the fair market value of other leases. On the whole, to the extent that the value of leases is uncertain, bidders are risk-averse, bonus levels are high, and there is capital rationing, the Government will collect less than the fair market value of the resources transferred to the private sector through cash bonus bidding. -249- 2. Economic Efficiency. A cash bonus bidding system per se has no direct effect on economic efficiency. To the extent that it reduces competition, however, it affects economic efficiency as well as Government revenue. When the market is thin (i.e., when there are few bidders relative to the number of tracts to be leased), leases may be allocated by chance, rather than to the firm able to develop the tract most efficiently. Also, if cash bonus requirements act as a barrier to entry by small firms or newcomers, most of the leases may be acquired by a few large firms. This could lead to high concen¬ tration or to domination by a few firms. From high concentration and barriers to entry follows pricing behavior which tends to misallocate resources and reduce social welfare. 9/ Where the cash bonus bidding system reduces the degree of competition for leases, the adverse effects on economic efficiency may be compounded by the effects 9/ See Joe S. Bain, Barriers to New Competition (Cambridge: Harvard University Press, 1956). -250- of minimum bids or refusal prices. When competition for leases is low, the Government is more likely to feel compelled to reject bids that fail to exceed some thresh¬ old. The result can be the withholding of marginal tracts which should in fact be leased at very low bonuses. An additional potential problem is that if lease sales are not held on a regularly scheduled basis, producers cannot adequately plan their leasing programs. While this is a problem of administration rather than an inherent defect of a particular lease allocation system, its effects can be much more severe under bonus bidding. If bonus bids are large relative to company financial resources, and if notice of a sale is not made far enough in advance to allow firms to adjust their financial positions, some companies which would otherwise have wanted to acquire leases will not be able to do so. Small firms are most apt to be dis¬ advantaged in this way. -251- 3. Energy Self-Sufficiency. The effects of a cash bonus bidding system on the achievement of energy self-sufficiency also occur for the most part indirectly through its effects on com¬ petition. If a bonus system heightens risk or capital barriers to entry, companies which would otherwise explore for a resource may be unable to do so. If such barriers also result in high production concentration, output might be lower than it would be under competitive conditions. In both cases, the probable result is less domestic production and hence (at least in the short run) less self-sufficiency. Several arguments which are sometimes heard con¬ cerning the effects of bonus bidding are not convincing. It has been argued that large bonus payments drain away capital that would otherwise be available for explora¬ tion and development. While this may be true to some extent, there are also self-correcting forces. If the cash bonus system reduces competition and enhances risk aversion, bidding will be less vigorous than it might be under alternative systems, and this in turn -252- constrains the amount bid and tends over the long run to conserve bidders' capital. Another argument is that a large bonus payment provides an incentive to develop the tract sooner in order to earn a quick return on one's investment. This argument is invalid, for the bonus, once paid, is a "sunk" cost. It cannot be taken back or invested else¬ where. The decision on when to develop the tract depends, then, upon estimated future revenues, costs, and opportunities. By analogy, what matters is not how far one has already drilled and hence how much capital is invested, but what is expected to come from further drilling. It has also been suggested that the bonus bidding system provides an incentive to explore and develop a lease more fully in order to amortize the fixed bonus cost over the maximum amount of production. This, however, would not be profit-maximizing behavior. In order to maximize profits, firms will continue to produce only as long as the additional costs incurred are less than or equal to the additional revenue -253- (i.e., until marginal cost rises into equality with marginal revenue). Any production beyond this point will reduce bonus cost per barrel, but it will also reduce profits. And it is probable that firms are more interested in maximizing profits than in minimizing bonus cost per barrel of oil. 4. Deferred Bonus Bidding Variants. Under a deferred bonus bidding system, only a portion (perhaps one-third) of the bonus is paid at the time the lease is awarded. Subsequent payments are then made at various stages of exploration and develop¬ ment or at the end of specified time periods, such as at the end of the third and fifth years. The rationale for such a system is that it reduces the amount of the initial bonus payment and thereby reduces the capital requirement barrier to entry by small firms. The deferral provision would reduce initial capital requirements for a new firm and give the firm more time in which to raise the capital necessary to pay for a particular lease. If the firm continues to -254- acquire leases, however, it will have to pay the second or third installments on some leases at the same time that it must pay the initial installment on others. It would still be faced with large annual capital require¬ ments . Table 5.1 compares the payment streams for ac¬ quiring a series of seven $100,000 leases under two bonus systems: a lump-sum bonus system and a deferred bonus system in which the bonus is paid in three installments. It is evident that, except during the first two periods and the last two periods, the capital requirements are the same for both systems. Under a deferred bonus system, payments are lower than under a lump-sum bonus system in the early periods and higher in the last periods. Since the firm is better off if I it does not have to pay for the lease until some time in the future, leases offered under a deferred bonus system are more attractive, all else equal, and bidders should be willing to bid more to acquire them. The fact that bids will be higher under a deferred bonus system attenuates the effect of the system in reducing capital requirements. Entry may nevertheless be easier -255- TABLE 5.1.—Payment Streams on a Series of Seven $100,000 Leases Under Lump-Sum and Deferred Bonus Systems CO CO CO CO O 'i CO ro co r" o co co | vo r-' CO co CO CO CO CO o o o o CO CO CO CO CO CO in U (d i—i co co co UO r-H CO CO CO o 'O n_| CO CO CO ^ o co co co CO CN in 03 G id in 9 0 Xi Eh co co co co co co co co CO co CO CO CO o CO o rH T3 03 10 in o Q) 4-1 9 •rH Jh G G >_i 5-i 1 03 in 0) fd 6 in +j c U G in c Q) 5-1 in (1) i —1 to 1 0) £ (D P £ fd p & £ m c 4-* G (d 0) 0 fd O O 9 fd cu O Xi Cu Eh Xi G5 Dj -255A- % and more widespread under deferred bonus bidding if capital rationing is severe and small firms seek to acquire leases only sporadically. Deferred bonus bidding may owe its attractiveness at least as much to its effects on risk as to its lessened capital requirements impact. There are two main risk-attenuating features. For one, in the early periods of leasing, the firm with a fixed exploration budget can hold more leases under the deferred bonus system than under the lump-sum bonus system. This may not be important to a major oil company with hundreds of leases. But for a small firm, it may mean three chances to strike oil rather than a one-shot gamble. Thus, in cases where a lump-sum bonus system raises capital requirement and risk barriers to entry by small firms, a deferral provision would reduce such barriers. A variant of the deferred bonus bidding approach has an even stronger risk-reducing impact. Under it, the bonus is paid in installments, but the lease can be relinquished at any time, with no liability remain¬ ing for that portion of the bonus which has not been -256- paid. This system is similar in effect to a rental bidding, system, which is described below. Rental Bidding Under a rental bidding system, leases would be awarded to the firm that bids the highest annual (or longer period) rental. The rental must be paid as long as the lease is held, but the lease can be relinquished at the end of any rental period. The effects of such a system on the receipt of fair market value, economic efficiency, and energy self-sufficiency differ sub¬ stantially from those of a bonus bidding system. 1. Receipt of Fair Market Value. The rental bidding system differs from the cash bonus bidding system in the degree of risk assumed by the lessee. If the tract is less productive than had been expected or if costs are higher or prices lower than anticipated, the lessee can relinquish the lease, having paid only the rental for the period that it held the lease. -257- At first it appears that this should have an adverse effect on Government revenues. Under the bonus bidding system, the Government receives more than the "fair" value of the lease when conditions turn out to be less favorable than the lessee had expected. Under a rental bidding system, however, the lessee can surrender the lease if conditions prove to be unfavorable. The Government therefore loses revenue from those leases, while it does not collect additional revenue when con¬ ditions are more favorable than anticipated. This effect may be offset to some extent, however, by the effect of risk reduction on the prices paid for leases. Under rental bidding, unlike bonus bidding, the probability of incurring a large loss is limited by the firm's ability to terminate the lease. But the probability of making windfall gains remains unchanged. Firms will therefore be willing to bid more vigorously for leases. The reduced risk and capital requirements should also increase the number of firms competing for leases, providing greater assurance that the fair market value will be bid. -258- ( As demonstrated below, however, a rental bidding system would lead to the premature abandonment of leases. Therefore, some of the economic rent would not be collected. A rental bidding system may also contain at least two loopholes. First, companies may relinquish tracts and then re-lease them at a lower rental. Second, in the case of fluid resources, the resource can some¬ times be extracted from adjacent tracts commanding lower rental payments, while tracts with higher rental pay¬ ments are relinquished. 2. Economic Efficiency. To the extent that it reduces risk and capital requirements, a rental bidding system may increase competition for leases. As noted in the discussion of bonus bidding, this has beneficial economic efficiency effects. Nevertheless, a rental bidding system also has adverse efficiency effects. While the bonus system affects efficiency indirectly through its effects on competition, a rental system can have serious direct effects. The prospect of continuing rental payments may make it appear unprofitable for the firm to -259- commence or continue production from a tract when it would be socially desirable to develop the tract. When the decision whether or not to continue renting the lease is made, the socially optimal decision is "yes" if the value of the resource to be produced in the future is greater than the real incremental cost of producing it. A profit-maximizing firm, however, will continue renting the lease only if the value of the resource is greater than the real cost of producing it plus payments to the Government for rent. Since the rental payment adds to the firm's calculated costs of producing additional output, pro¬ duction may be discontinued prematurely and valuable resources may remain undeveloped. Marginal tracts will not be developed at all. Even moderately productive tracts will not be developed if the rental bid is very high. This is likely to be a serious problem, since companies might submit high bids in the hope of finding large low-cost resource deposits. The successful bidder will simply not renew the lease if its hopes are less than fully realized. Of course, leases that are dropped could be re-let at lower rentals, but this - 260 - almost always implies at least a significant delay in resource development and appreciable re-start costs. Also, the decision to continue production or forfeit the lease will still be affected by even modest rentals in later stages of development as real extraction costs rise. A rental bidding system would also induce devia¬ tions from the optimal rate of development. The system creates an incentive for rapid production in order to minimize the number of rental payments made. The sooner the tract can be developed and relinquished, the lower total rent payments will be. Unless there are other institutional factors which work in the opposite direction, the result may be physical as well as economic waste of the resource. Scarce exploration resources may also be directed from promising new bonus bid tracts to less attractive rental bid tracts in order to minimize the rental term and obtain early information useful in deciding whether to continue paying rent. - 261 - Finally, the number of rental payments is smaller the sooner the tract is explored and developed. Firms that can explore the lease the fastest, can bid more for the lease. Thus, the winning bidder may be the company that can explore and develop the lease most rapidly rather than most efficiently. 3. Energy Self-Sufficiency. The tendency of a rental bidding system to enhance competition acts to increase the output of a resource, but the premature abandonment of leases has the opposite effect. Rental systems encourage rapid exploration and production of leased tracts. However, this may result in the waste or inefficient use of resources, and thus not really contribute toward the goal of achieving energy self-sufficiency. How these diverse effects balance out is difficult to determine without a richer set of facts on the particular leasing situation. - 262 - Royalty Bidding Under a royalty bidding system, leases are awarded to the firm that bids the highest royalty, stipulated as a percentage of the volume or value of production. Since payment is not made unless and until production begins, the effects of this system are quite different from those of a bonus bidding system or a rental bidding system. 1. Receipt of Fair Market Value. Under a royalty bidding system, risks are shared more evenly between the lessee and the Government than under a rental bidding system. This is so for two related reasons: (1) Payment for the lease varies directly with actual production and prices at the time production takes place. Under a rental bidding system, the annual payment remains the same as long as the lease is held, no matter how productive the lease proves to be or what happens to the resource's price. - 263 - (2) The Government shares in unexpected gains as well as losses. Under a rental bidding system, payments for the lease do not increase if the tract proves to be more valuable than expected, but they fall to zero if the tract falls so far short of original expectations that the lease is relinquished. Because the royalty payment varies with the lease's productivity and the resource’s price, the payments for individual leases will tend to cluster nearer their fair market values than would be the case under a bonus bidding system, where bids may be much higher or lower than a tract's eventual value. On the average, however, bonus overpayments tend to offset underpayments, so the aggregate result from the Government's revenue-raising standpoint should, at least as a first approximation, be the same under both systems. Other factors must nonetheless be considered. The royalty bidding system has two features in common with a rental bidding system: it reduces the risks borne by the lessee and it induces the premature abandonment of leases. A royalty bidding system reduces risk to a - 264 - greater extent than does a rental bidding system. Under a rental system, the lessee risks all payments up to and including the period in which a forfeiture decision is taken. Under a royalty system, no payment is made until production begins, and the payment depends upon the value of production. In this regard, the royalty bid¬ ding system is more effective than the rental bidding system in ensuring the receipt of a lease's fair market value, since it does more to combat risk aversion and increases the competition for leases. As we shall elaborate below, however, the royalty bidding system can also lead to suboptimal levels of production and the premature abandonment of leases. It is impossible to say whether these effects are greater under a rental or royalty system. That depends upon the actual cost, output, and revenue streams for the leases, \ and the size of the winning bids. In any event, the cost of overbidding on a lease is relatively low under a royalty bidding system, since nothing is paid for the lease unless production takes place, and the firm - 265 - will not produce unless it is profitable to do so. 10/ The Government's revenue loss due to the nondevelopment or premature abandonment of leases would therefore be substantial under a pure royalty bidding system. If the resource is fluid, there would also be an incentive to reduce royalty payments by channeling production through an adjacent tract on which a lower royalty had been bid. 2. Economic Efficiency. The reduction of risk under royalty bidding minimizes the adverse effects of risk aversion on economic efficiency and increases the competition for leases, which also has beneficial efficiency effects. The principal defect of the royalty bidding system is that it can cause inefficient production decisions. A profit-maximizing firm will continue producing as long as the revenue from the sale of the additional units of output is greater than or equal to the cost of 10 / The firm could be forced to produce by means of contractual diligence requirements, but this would increase risk and have adverse efficiency effects discussed in chapter 6. - 266 - producing that output. As we learned in chapter 3, a pure bonus bidding system does not distort this process of equating marginal revenue with marginal cost; and as a result, production decisions under bonus bidding are efficient, barring the existence of externalities. A royalty bidding system is different. As ad¬ ditional quantities of the resource are produced, the firm must pay additional royalties to the Government. From the perspective of an individual firm selling in a competitive market (i.e., in a situation where its output decisions do not perceptibly affect the re¬ source's price), this in effect implies a downward shift in the firm's marginal revenue curve from MR to MR' in figure 5.1. 11 / Imposition of the royalty reduces the firm's profit-maximizing output from Q to Q'. 11 / Alternatively, the firm receives the same marginal revenue, but the royalty payment increases the cost of producing each unit of output. This would be depicted by an upward shift in the marginal cost curve. The result is the same no matter which approach is used. - 267 - FIGURE 5.1.--Reduction in Lease Output Due to Royalty Payments -267A- This firm's eye view provides only a first approxi¬ mation. The widespread use of royalty bidding would also affect the price at which a market equilibrium is established. Figure 5.2 provides the necessary analysis. The industry demand curve (D) shows the quantity that buyers would purchase at various prices. It is downward sloping to show that the lower the price is, the greater is the quantity demanded. The industry supply curve (S) shows the quantity that producers would offer for sale at various prices. It is upward sloping because as additional quantities of the resource are produced, the marginal cost of production increases and firms will supply more only if stimulated by a higher price. The competitive equilibrium level of output is at Q, where supply equals demand. At lower output levels, the value of additional output (the demand price) exceeds the cost of producing it (the supply price). Society is there¬ fore better off if more is produced. - 268 - FIGURE 5.2.--Social Welfare Less Due to the Imposition of a Royalty -268A- l Now assume that a 50 percent royalty is imposed on total industry production. Although the demand curve (D) still indicates the prices at which various levels of output can be sold, producers will now receive only half that price, since they must pay a 50 percent royalty. The effective demand curve faced by producers therefore shifts downward to D 1 . As a result of the royalty, the equilibrium level of output becomes Q', where the quantity supplied by the industry at the price producers realize (the market price minus the royalty, or Q'A) is equal to the quantity demanded by consumers at the price they must pay (the market price, Q'B). The output is lower and the price higher than they would be if there were no royalty obligations. The loss of social welfare due to the royalty's distorting effect on incentives is the difference between the value of the output foregone as a result of the royalty and the cost of producing that output. From figure 5.2, it can be seen that the value of the -269- output foregone is the area under the demand curve between Q and Q' (area Q'BCQ). The cost of producing that output is the area under the supply curve between Q and Q' (area Q'ACQ). The welfare loss attributable to the royalty is represented by the difference between these two areas, or area ABC. It represents the surplus of the value of the output not produced over the cost of that output. It can be shown that the welfare loss is equal to roughly one-half the royalty times the change in output; i.e, area ABC = 1/2 AB (Q - Q'). It can also be seen from the diagram that the magnitude of the welfare loss depends on: (1) The relative position of the D' curve. This is determined by the size of the royalty. The higher the royalty, the larger the gap between D and D', and the greater the welfare loss. (2) The slope of the S curve. This reflects how sharply the marginal costs of production rise as output is increased. The steeper the supply curve, the less -270- i the welfare loss tends to be. (3) The slope of the D curve, which reflects how much the quantity demanded falls as the price consumers must pay increases. The steeper the demand curve, the less is the retarding effect of the royalty on output and the lower the welfare loss will be. 12/ 12 / More precisely, the welfare loss varies directly with the elasticities of supply and demand. Triangle ABC is only an approximate measure of welfare loss due to the royalty, since it assumes that no other imperfections exist. The impact is also influenced by the presence of royalties or other forms of taxation in other sectors of the economy. See Arnold Harberger, "Taxation, Resource Allocation and Welfare," in The Role of Direct and Indirect Taxes in the Federal Revenue System (Washington: Brookings Institution, 1964), pp. 25-70. The analysis here has assumed a competitive in¬ dustry. Under monopolistic conditions, the welfare loss due to the royalty would be half that under perfect competition, although the total welfare loss (including that due to the monopoly) would be greater. It is difficult to say what the result would be under oligopoly. If producers believe that demand for the resource is inelastic and act in a paral¬ lel manner, they may increase prices by the total amount of the royalty. This is more likely to happen if the royalty is the same for all firms. -271- The adverse effect of the royalty will always occur as a resource becomes depleted and marginal cost rises. In some cases, however, the royalty could prevent the development of the tract at all. Suppose that exploit¬ able resources are discovered on the leased tract, but that the cost of extracting them is higher than antici¬ pated. Assume further that the revenue received from the sale of the resource would slightly exceed the cost of production (excluding any royalties or other rents). Our efficiency goal would call for the resource to be produced, since the value of the output exceeds the cost of production. Under a bonus bidding system, the fact that the firm had bid more than the lease was worth would not affect the production decision, since the bonus is already "sunk" and cannot be recovered. The firm would decide to produce the resource because it would receive more for the output than the incre¬ mental cost of production. While it will incur a loss because it paid too high a bonus, it will minimize this loss by producing and selling the resource. -272- Under a royalty bidding system, however, the firm may decide not to produce the resource. Since produc¬ tion will be less than it had expected, the firm will also have to pay less royalties than it had expected. Nevertheless, the royalty it does have to pay could reduce its net revenue per unit below unit cost. If so, the firm would be better off abandoning the lease. The difference between the royalty and the bonus is that royalty payments can be avoided after the lease has been signed by not producing, while the bonus payment cannot. An example can illustrate this important point. Assume that the firm expects to receive $200 for the resource produced from the tract and that it will cost $100 to produce it. After the tract has been leased, the firm discovers that the tract contains only $150 worth of the resource, but the extraction costs will be the same. The situation under a bonus bid system is: Revenue Cost Bonus Expected $200 $100 $100 Actual $150 $100 $100 -273- If the firm does not produce, it will lose $100, the amount competition forced it to pay for the lease. If it does produce, it will lose only $50, the difference between the bonus payment and the $50 operating profit from selling the resource. Undertaking production is the most profitable (i.e., loss minimizing) choice. The situation under a royalty bidding system would be: Revenue Cost Royalty (50%) Expected $200 $100 $100 Actual $150 $100 $ 75 If the firm does not produce, it will lose nothing (ignoring any exploration costs already incurred). If it does produce, it will lose $25 (the difference be¬ tween the $150 revenue and the payment of $175). The firm will not undertake production. If social welfare is to be maximized, the resource should be produced, because it is worth $150 and it would cost only $100 to produce it. The royalty bid¬ ding system thus may result in suboptimal levels of -274- v production, whereas a bonus bidding system would not have this effect. The premature abandonment effect could be allevi¬ ated by re-offering the tract for lease. The tract could then be re-leased at a lower royalty. There are at least three problems with this, however. First, a time will come when it will become unprofitable to continue production even with the lower royalty. The early shut-down problem remains as long as there is any royalty. Second, the original leaseholder has an in¬ formation advantage that might deter other firms from competing effectively for the tract. In order to avoid this problem, the original lessees would have to be excluded from bidding or all the information gathered from exploring and developing the tract could be made available to other potential bidders. Third, if development had already begun on the tract, it would be necessary to determine the price at which the wells and equipment that must remain on the tract are to be transferred from the original to the new lessee. -275- The premature abandonment problem would be severe under a pure royalty bidding system where there are large potential economic rents. There would be an inducement to submit high bids on tracts with strong but uncertain potential. If the tract proves to be highly productive, the firm can earn substantial profits. If the tract is only moderately productive, it can be abandoned without having to make any lease payment. Under a rental bidding system, the bidder must risk some payment (the annual rental) until the decision whether or not to produce is taken, but it keeps all windfall gains (i.e., revenues above what it had expected). Under a royalty bidding system, no payment is made for the lease unless production is undertaken, but the firm must share the windfall (unexpected) gains with the Government in the form of royalties. Both systems encourage high bidding and premature abandon¬ ment . It has been argued that a royalty bidding system would encourage leasing by speculators. Since no pay¬ ment is due until production begins, successful bidders could hold the lease in the hope of selling either the -276- lease or the resource later at a higher price. It should be noted, however, that this is a problem only when leaseholders possess monopoly power, so they can affect the resource's price by keeping their reserves off the market. If no such monopoly power exists and firms refrain from developing their leases only because they expect the competitively determined price to rise, they are, as chapter 3 demonstrated, actually contrib¬ uting to efficient allocation over time. In summary, the principal effects of a pure royalty bidding system on economic efficiency are to induce suboptimal levels of output, premature abandon¬ ment of leases, nondevelopment of tracts that should be developed, and higher resource prices. If economic rents (and therefore royalties) are high, these adverse effects are likely to outweigh the royalty system's beneficial efficiency effects—notably, reducing the impact of risk aversion and increasing competition. -277- 3. Energy Self-Sufficiency. To the extent that it reduces barriers to entry and mitigates risk aversion, a royalty bidding system encourages exploration and development of resources. But it also leads to the premature abandonment of leases and lower production levels. Which effect predominates depends on the characteristics of the industry. If there is considerable technological, geologic, and market uncertainty and the industry is highly concen¬ trated, the output-enhancing effect is apt to pre¬ dominate. If economic rents and hence royalty rates are high, a net output-suppressing bias is more likely. 4. Royalty Bidding With a Declining Royalty Rate. The distorting effects of a royalty system could be offset to some extent by lease provisions permitting the lessee to petition that the royalty be reduced or eliminated when it is no longer profitable to continue production at the original royalty rate (i.e., when the firm reaches output level Q' in figure 5.1). In administering such a system, the Government would have -278- to monitor production rates and costs to determine whether the firm would in fact discontinue production if the royalty were not reduced. Even if it were possible to do this, the administrative costs would be high, and the Government might be swamped with petitions, appeals, and charges of favoritism. Alternatively, provision could be made for the royalty to be reduced automatically at specified time periods or stages of production (e.g., after a pre¬ determined cumulative output has been achieved). Such a "sliding scale" royalty bidding system would be easier to administer than a "petition" system, but it would not eliminate all resource misallocation and Government revenue losses, since the amount and timing of the royalty reductions would not always coincide with what is needed to stimulate continued production. This is illustrated in figure 5.3. The economi¬ cally efficient level of output is at E, where marginal revenue equals marginal production cost. Because of the royalty, the MR curve for the firm shifts down to MR' and the decision is made to discontinue production -279- FIGURE 5.3.--The Effect of a Declining Royalty $ unit -279A- at R, since the cost of producing the resource beyond this point would be greater than the revenue net of royalties paid. If there is a provision for eliminating royalty payments when output level X is reached, the marginal revenue curve will shift back up at that point. Note, however, that under the conditions depicted in figure 5.3, the firm will still discontinue production at output R. While increasing production from X to E would be profitable (since marginal revenue is greater than marginal cost), the firm would incur losses on the additional production from R to X (since it would have to pay royalties on that output, so marginal cost would be greater than marginal revenue). Since the losses (the area of triangle "a") are greater than the gains (the area of triangle "b"), the firm will not produce beyond output R. Under different conditions, however, the area of triangle "b" could exceed the area of triangle "a" and the firm would continue production up to the efficient level E. This would be the case: -280- (1) If the price of the resource were higher. The marginal revenue curve would then be higher. We recall that the effect of a widespread royalty system on total industry output may be a higher price. (2) If the royalty were lower. The MR' curve would then be higher. (3) If the royalty were discontinued at an earlier level of output. This would shift the point where the MR' curve shifts up (point X) to the left. While the declining royalty would have the desired effect under the right conditions, it can be seen from figure 5.3 that a provision for reducing or eliminating the royalty at specified cumulative production levels could be self-defeating. It would not change the bidder's estimate of the tract's gross production revenues. It would reduce estimated outlays, however, since lower royalties would be paid at later stages of production. The net present value of the lease would therefore be higher, and the firm, under effective competition, would bid a higher royalty. Thus, while -281- eliminating the royalty at an earlier time would in¬ crease the area of triangle "b," it would also induce higher royalty bids and therefore shift the MR' curve down further, increasing the area of triangle "a." The effect of the declining royalty provision on the level of bids would depend upon how much firms know about the probable productivity of the leased tract, future prices, and future costs. If the positions of the curves in figure 5.3 are highly uncertain, the declining royalty provision is unlikely to have a significant effect on bids. Also, if the royalty's reduction or elimination would not take effect until many years after the lease is issued, the discounted savings from anticipated royalty payment reductions would be relatively low, and bids would be little affected. Profit Share Bidding Under a profit share bidding system, tracts are leased to the bidder offering to pay the Government the largest share of the net profit from its lease - 282 - operations. Net profits are the difference between the revenues and costs attributable to production. What percentage of its net profit will a firm bid? Under competitive conditions, it should bid away all expected profits in excess of what is necessary to induce its investment away from the next-best alternative oppor¬ tunity. If an enterprise can earn 15 percent from investing in an alternative venture with a similar degree of risk, it will under competition submit a profit share bid permitting it to anticipate a return on its investment slightly above 15 percent. All profits in excess of these "necessary" profits con¬ stitute economic rent and are bid away. The effects of this system on economic efficiency, the collection of fair market value, and the attainment of energy self-sufficiency stem mainly from its risk-sharing properties. 1. Receipt of Fair Market Value. Risks are shared to a greater extent under a profit sharing system than under any other lease allo¬ cation system. No payment is made for the lease unless - 283 - and until profits are earned. Such a system shares not only discovery and market price risks, but also cost risks. If production costs are higher than anticipated, profits will be lower and the payment for the lease will be correspondingly reduced. A profit-sharing system minimizes the adverse effects of risk aversion and opens the doors to maximum competition for leases. If properly administered, it comes closest to capturing the fair market value of leases. In fact, if "necessary profits" were accounted for as costs, net profits would consist entirely of excess profits. The fair market value of the lease would therefore be equivalent to the net profits. If this were the case and if there were effective competi¬ tion for leases, all bids should be 100 percent, since firms would be forced by competition to give up all their excess profits in order to obtain the lease. Of course, if all bids converged on 100 percent, it would be difficult to determine which firm was high bidder and hence should be awarded the lease. - 284 - "Necessary profits" are not counted as costs under generally accepted accounting principles. It is useful therefore to distinguish two components of net account¬ ing profits: the "necessary profits" and excess profits. If a firm under competition bids 70 percent of net profits, it presumably estimates that 30 percent of the expected accounting profits from its lease operations will provide just enough of a return on its capital to make it worth while to acquire the lease. The remaining 70 percent is in excess of this necessary return—that is, it represents economic rent—and the firm is willing under competitive pressure to give it up to obtain the lease. Of course, the firm may be wrong. If the tract's productivity is much lower than originally anticipated, net profits from the lease could be quite low. Thirty percent of this low residual may be less than the "necessary profits" commensurate with the lessee's development and production investment. Conversely, if the tract proves to be much more productive than originally expected, net profits will be high, and 30 percent of net profits would more than compensate - 285 - the firm for investing its capital. In other words, the firm would retain some excess profits. Thus, it is still possible that the Government will not receive the fair market value of leases. The loss of Government revenue is unlikely to be serious, how¬ ever, because: (a) the relatively low risk and capital requirements of a profit-sharing system promote competi¬ tion and encourage high bids; and (b) payment for the lease varies directly with the tract's productivity and the price of the resource and inversely with the costs of production. If the lease proves to be more or less valuable than expected, the payment for the lease will respond accordingly. If, in particular, a lease which appeared to be a poor prospect turns out to be a bonanza, the Government will capture a share of the unexpected profits. This would not be the case under a bonus bidding system. Even if the value of the lease were known with certainty, however, a profit share bidding system can¬ not ensure that leases will be awarded to the most efficient firm or that the Government will collect the - 286 - fair market value of the lease. This will be discussed in the section on economic efficiency below. Another disadvantage of the profit-sharing system derives from the difficulty of measuring profits. The allocation of overhead and common costs is often arbi¬ trary. The lessee's accountants would have an incentive to shift expense items from other areas to lease opera¬ tions. There would also be an incentive to allocate items such as area-wide exploration costs to leases on which the firm had bid a high profit share. In addition, for vertically integrated producers, it may be difficult to value output transferred internally to company processing units rather than being sold at arm's length market prices. Nevertheless, all this will have little impact on the Government's ability to capture the fair market value of leases as long as the following conditions hold: - 287 - (1) There is a strict formula for computing net profits. The formula need not be correct, but it must be consistent. (2) No firm has a significant advantage in being able to shift book profits between profit-sharing and other operations; and (3) There is effective competition for leases. Then, even if the formula for calculating net profits permits the "padding" of costs or fails to deduct some real costs, the Government may still receive fair market value. As long as the factors which overstate or understate net profits are generally known, firms will adjust their bids accordingly. Competitive bids are not based on accounting profits, but on the firm's real profit expectations. If, for example, it becomes evident that costs can be overstated sufficiently that reported net profits are less than true net profits, firms competing for leases will compensate by increasing their profit - 288 - share bids. * In sum, a profit share bidding system does not ensure the collection of fair market value. Owing to its risk-sharing properties and effects on competition, however, it might come closer to achieving this objec¬ tive than any other lease allocation system. 2. Economic Efficiency. A profit share bidding system based upon account¬ ing profit cannot ensure that leases will be awarded to the most efficient firm, since it is biased against firms which use relatively capital intensive production techniques, even though such techniques may be the most efficient. 13/ To see this, consider the profit share bids which would be made by two firms in the following hypothetical situation. A lease will yield $10 million in revenue each year. Firm A would invest $10 million in capital equipment and produce the resource at a cost of $5 million per year for wages, materials, 13 / The following analysis was developed by Calvin Roush. - 289 - taxes, and other operating expenses. Firm B would produce the resource by investing only $5 million, but at an annual operating cost of $6 million. We assume that the initial capital remains invested as long as the lease is held. Under competition, each firm would bid away all net accounting profit (i.e., revenue minus operating costs) except the amount necessary to cover the opportunity cost of its capital. Assume that both firms could earn 10 percent in their next-best invest¬ ment opportunities. The bids of firms A and B would be determined as follows: Firm A Firm B ($ million) Revenue 10.0 10.0 (-) Operating Cost 5.0 6.0 Accounting Profit 5.0 4.0 Capital Investment 10.0 5.0 (X) Best Alternative Rate of Return 10% 10% "Necessary Profit" 1.0 0.5 Accounting Profit 5.0 4.0 (-) "Necessary Profit" 1.0 0.5 Excess Profit 4.0 3.5 - 290 - Firm A would be willing to give up $4 million of its $5 million accounting profit. It would therefore submit a profit share bid of 80 percent. Firm B would be willing to give up $3.5 million of its $4 million accounting profit. It would therefore submit a profit share bid of 87.5 percent. Since firm B would offer a higher profit share bid, it would win the lease. This is true even though firm B would pay only $3.5 million per year for the lease, while firm A would have paid $4 million per year. It is therefore possible that the highest profit share bid will not yield the greatest revenue to the Treasury. Note also that winning bidder firm B uses $6.5 million of economic resources each year ($6 million in operating expenses and $0.5 million in the opportu¬ nity cost of capital), while firm A would have used only $6 million ($5 million in operating expenses and $1 million in the opportunity cost of capital). Owing to its more capital-intensive production technique, firm A incurs a dis¬ advantage in net profit share bidding, even though it is clearly the more efficient firm. - 291 - This may not be the only source of inefficiency. It has been argued that a profit share bidding system would reduce producers' incentive to minimize their costs, since they would receive only a portion of the benefits. This is not likely to be a serious problem, however. If the tract is expected to be only moderately productive, the profit share bid would be relatively low, so the firm would retain a large portion of the benefits from being efficient. If the tract is ex¬ pected to be highly productive, the profit share bid would be quite high, so the firm would retain only a small fraction of the higher profits stemming from cost reduction. This small proportion would be applied to a high level of output and absolute profits, how¬ ever, so that the benefits to the firm would be sub¬ stantial. Moreover, high profit share bids may coincide with situations in which the lessee bid away all excess profits and must keep costs to a minimum merely to realize its necessary profits. It is often said that a profit-sharing system would not affect production and pricing decisions. The reasoning is that since the profit share payment - 292 - i is dependent upon profits earned, it cannot make the production of additional output unprofitable. This is correct if only excess profits (or economic rents) are subject to sharing. As indicated above, however, the net profits subject to profit-sharing include not only excess profits, but also "necessary profits," or profits a firm must anticipate earning on its capital if it is to undertake investment. Once equipment is in place and production has commenced, a company is not likely to discontinue production if it could not earn its "necessary profit," since the capital has already been committed. When the decision whether or not to develop a tract is made, however, no capital will be invested if it becomes obvious that the firm's profit share bid was excessive and that the necessary rate of return cannot be at¬ tained. Some tracts that should be developed will therefore remain undeveloped. They could be re-offered for lease, but the delay, startup cost, and information disparity problems discussed earlier in connection with royalty bidding would be present. - 293 - The argument that a profit-sharing system would not affect the price of output assumes that the industry is perfectly competitive and that firms always try to maximize shortrun profits. If the industry is monopo¬ listic, a profit share "tax" may lead to an increased price for the resource. Firms may not strive to maximize shortrun profits if the profit-maximizing price is high enough above the average cost of produc¬ tion to encourage the entry of new firms, to prompt antitrust action, or to encourage a demand for higher wages. Instead, they may decide to hold the price at a level which discourages such reactions. If so, after a profit share "tax" is imposed (thereby raising costs), firms may increase prices in order to restore that price-cost differential. 14/ 14/ For a more complete discussion of possible effects of a profits tax on price and output, see Richard A. Musgrave, The Theory of Public Finance, (McGraw-Hill, 1959,) pp. 276-287. - 294 - 4 3. Energy Self-Sufficiency. A profit share bidding system would probably be more conducive to the attainment of energy self- sufficiency than any other seriously considered lease allocation system. The system's only adverse effect is that the development of some tracts would be delayed because the initial profit share bids are excessive and the original lessees will surrender their leases rather than invest unprofitably in their development. On the positive side, a profit share system would do more than other systems to encourage entry of new firms into exploration and development, including the ex¬ ploration of wildcat areas. The profit share system is the only major lease allocation system that provides for the sharing of cost risks (as long as profits are earned or losses can be offset against the "tax" paid on profits from other areas), as well as discovery and market price risks. The inhibiting effects of risk aversion are therefore minimized. - 295 - Work Commitment Bidding Under a work commitment bidding system, bids take the form of commitments to perform specified types of exploratory and development work on the leased tract. The lease would be awarded to the firm that submits what is considered the most favorable tract development plan. While such a system may be competitive, the winner of the lease is not determined by an impersonal market mechanism, (as when the lease goes automatically to the firm offering the highest cash bonus or royalty), but by the judgment of the leasing agency. The evaluation of competing development proposals would be difficult and highly subjective. Actual performance would also be difficult to monitor and enforce. Nevertheless, a work commitment system may be conducive to the achieve¬ ment of at least some leasing policy objectives. 1. Receipt of Fair Market Value. The principal objective of a work commitment bidding system is to encourage certain types of work (such as exploratory drilling or research and - 296 - i development) which will promote the development of particular resource areas or fields of technology. Some observers believe, for example, that the large amounts of capital flowing into cash bonus payments for offshore oil and gas leases should be used instead for exploration and development. A work commitment system could release this capital and ensure that it is used in desired activities. In order to be effective, a work commitment system can provide for only limited bonus, rental, or royalty payments. The difference between such payments and the fair market value of the lease is in effect a subsidy for the activities being encouraged. Therefore, work commitment bidding is by design inconsistent with securing fair market value. 2. Economic Efficiency. A work commitment bidding system is justified on efficiency grounds only when existing institutions cause under-investment in certain activities and a suboptimum rate of resource development. Even then, - 297 - the work commitment approach to subsidization could lead to a distorted allocation of resources. Since competition for leases would center on the quantity of exploratory and developmental work to be performed, there is an incentive to propose work that may be unnecessary. Moreover, under conditions of uncertainty, the optimum development program for either a geologic structure or a new technology can only be determined over time, as information accumulates. It is unlikely that a prespecified work plan would turn out to provide for the correct activities being performed at the correct times. Unless improved criteria for granting leases are devised and the contract specifications are subject to amendment, it may be preferable to award leases on the basis of bidders' past performance rather than on promises to perform specified work. 3. Energy Self-Sufficiency. The raison d 1 etre of a work commitment bidding system is to increase the rate of a resource's develop¬ ment. As long as the work commitment provides for the performance of activities that need to be encouraged. - 298 - the subsidizing effect of the system does promote development. Since the amount of the subsidy depends upon the value of the tract, it is difficult to deter¬ mine the amount of the subsidy ex ante . Even if the right activities are subsidized, it is unlikely that they will be subsidized by the right amount. A direct and flexible subsidy should normally be preferred over a subsidy of unknown amount given in return for the promise to perform a specified amount of work that may turn out to be the wrong work or the wrong amount of work. Combination Systems It should be apparent that the seriousness of the adverse effects of various alternative pure bidding systems depends largely upon the level of bids. Under the bonus bidding system, for example, the impact of risk aversion and the height of risk and/or capital requirement barriers to entry increase with the level of bonus bids. Similarly, the extent to which royalties or rental payments induce suboptimal pro¬ duction levels and the premature abandonment of leases - 299 - depends upon the level of royalty or rental bids. One way to minimize the adverse consequences of such payments is to specify a combination of two or more payment types, so that no single set of effects is excessive. For example, provision could be made for an annual rental covering the leasing program's admin¬ istrative costs as well as the opportunity cost of the j r leased areas; I f / moderate fixed royalty or profit share payments; and cash bonus payments, the level of which would be determined by competitive bidding. By spreading the lease payments over several different formulae, the distorting effects of each payment method can be held in check. The appropriate combination of payment types and levels depends upon the particular industry conditions and resource characteristics, as well as the relative weight given to the various objectives of leasing policy. It should also be recognized that the cost — " - 1 " ^ . 1 4 / That is, the cost of foregoing alternative uses that could be made of the area if it were not leased. - 300 - of administering a combination system is greater than for a pure system, in which the bidding variable is the only lease payment. Two further general points deserve mention. First, although there can be several types of payment, there should probably not be more than one bidding variable for any given lease sale. Otherwise, it would be difficult to compare bids. Would an $800,000 cash bonus bid be higher than a 60 percent royalty bid, for example? Secondly, the cash bonus should probably be the bidding variable. As we have seen, the cost of overbidding is low if awards are based on rental, royalty, or profit share payments, since the lease can be surrendered before full payment is made. If a firm submits an excessive bonus bid, on the other hand, it must pay the full costs of that mistake. There would therefore not be a tendency to overbid and then abandon tracts. - 301 - CONCLUSION We find in sum that the Government has at its disposal a wide array of alternative bidding and payment approaches in leasing mineral lands. Which method is best depends upon the specific industry and tract characteristics. Variables which are particularly important in the choice of a leasing method include the extent of technological, geologic, and market uncer¬ tainty; the degree to which potential bidders of various sizes are risk-averse; the "best-estimate" value of resources less development and production costs; the anticipated time profile of costs, including the rate at which unit cost rises as the resource is depleted; the extent of currently existing competition and the desirability of stimulating new competitive entry; and the leasing objectives the Government chooses to emphasize. These and other relevant vari¬ ables must be kept firmly in mind as we turn now to our analysis of land disposal policies and practices for specific energy resources. - 302 - Chapter 6 OFFSHORE OIL AND GAS Importance of Federally-Owned Resources Unlike other lands containing energy resources, none of the oil and gas fields lying offshore the United States are privately owned. They have been claimed by the Federal Government, State governments and, in some cases, both. Although the petroleum industry had been producing oil and gas offshore since the 1890's (from piers extending off the California coast), the first Federal lease sale of oil and gas rights did not take place until October 1954. 1/ The United States claimed ownership of the natural resources on the Continental Shelf adjacent to its coasts by presidential proclamation in 1945. The Submerged Lands Act and the Outer Continental Shelf Lands Act of 1953 defined the area of Federal jurisdic¬ tion as that lying seaward on a line extending three 1/ Don E. Kash et al ., Energy Under the Oceans (Norman: University of Oklahoma Press, 1973), p. 25. - 303 - miles from the coastline. This area is referred to as the Outer Continental Shelf (OCS). The States retained rights to the resources lying between the shoreline and the OCS, while the Federal Government assumed control over leases the States had issued on OCS lands. 2/ Production from Federal OCS Leases. The Department of the Interior now administers all oil and gas leases on the OCS. These include both leases originally issued by the Federal Government ("Section 8" leases) and leases which were issued by the States, but are now under Federal jusisdiction ("Section 6" leases). 3/ tTable 6.1 indicates that oil and gas pro¬ duction from the OCS has increased relative to production from State leases. The proportion of total offshore oil and condensate production coming from Federal OCS leases has 2/ Ibid . For a detailed history of legislation con¬ cerning the OCS, see U.S. Public Land Law Review Commission, Study of Outer Continental Shelf Lands of the United States , prepared by Nossaman, Waters, Scott, Krueger, and Riordan (Los Angeles, Calif., Oct. 1968, revised Nov. 1969). 3/ These refer to Sections 6 and 8 of the OCS Lands Act. - 304 - TABLE 6.1.—Oil and Gas Production from Offshore "State" and "Federal OCS Lands, Selected Years and Cumulative Through 1974 g o -H -p o P o p CU CO fd O -P g CU o p CU a co VO r-» ro (N VO 00 ro CTi VO ro in in CM ro oo vo CM c o •H W •H > •H Q G 0 ■H • •H «b P CO rH O 00 o CT> 00 CTi ro d) oo rH -H CM •O' ro r—1 CM in (0 •h n av (N CM vo G - S P 0 r- O ro •O' CM U oo ro c o •H -p o T3 0 P O P cu a -p to cn co ro i"* in o vo o ro vo ro oo vo CM ro in in in ■vf >i Ou CU a > P - P — co m r- rH C' r- CO w d) 44 p p CM in CM CM 0 rH 0 P in i—1 H< ro fd x: fd rH CM in in in 4-) 4J 13 ** vo G G (U CU S-S p -p fd G Cu o CU CJ Q p • cu CO -P • p o o Cn W P U P in O LO o 0 Pi fd in VO VO f" r- p D cu o> CTi av X O rH rH rH rH rH 94 CO -304A- increased from 11 percent in 1955 to 68 percent in 1974. Federal (OCS) leases accounted for 83 percent of total offshore gas production in 1974. Table 6.2 indicates that gas production from the OCS has steadily increased from 0.86 percent of total U.S. production in 1955 to 16 percent in 1974. Crude oil and condensate production from the OCS increased from 0.3 percent to 11.2 percent of total U.S. production over the same period. In 1970, it was estimated that the OCS would ac¬ count for approximately 18 percent of total U.S. oil production and 38 percent of total U.S. gas production by the year 1985. 4/ Political and economic events since then have generated pressures to increase the rate of Federal offshore land leasing. The OCS is to play a major role in Project Independence. More recent pro¬ jections of future production from the OCS are present¬ ed in table 6.3. Tables 6.4 and 6.5 contain estimates 4/ U.S. Department of the Interior, Bureau of Land Management, The Role of Petroleum and Natural Gas from the Outer Continental Shelf in the National - Supply of Petroleum and Natural Gas , Technical Bulletin 5 (May 1970) , pp. 28-51. - 305 - • 1 CO p • a; D t a 4H CD CN ro in w o 00 rH O o o fd • • • • • -P CN TT rH co CO c rH i —i U •H o o Q w P 4-4 r* ro 00 CN (0 -P rH CN o in CD r-' G o id o ** 0 c P -P -H rH ro m 00 -H 0 a o P} 00 r- rH rH -P •H Eh P CN CO in fd 4-> w o % > O H • G i—1 00 ro CN O U cn D 0 ID ro in o 00 W T3 •H ro o n- CO o fd QJ r-H i—1 k > • O 4-> (d rH in rH o o a) a a -P -H o f" ro CN o > 73 a) O S r- o o\ oc p % G rH Eh — V. 3 ,—, fd W ac CN CD rH rH CO m CO rH rH CN CN rH rH oc •H * rd rH O G o 0 • •H 0) 4-1 -rH G 1 CO Cn G i—1 4-* 0 P • 0 P a) o ■H O CN r-H a) 0 GW O • • • • • u w rH >4 T3 fd rH in o rH o fd Pu 0 -P 1 — 1 rH •rH -p P CO G p -P G • au CO G CO 0 o o x: o rH CO * a) o o p •H • G 00 ro o o £ G Eh Q) O D fd (N ro rH in o •rH 1 P4 w ac in o p -p 1 CL) rH P fd G • TJ fd 0 00 o a o CN P4)£ 00 r-> rH ro • i Q CD UEh- P P CN CN CN ro ro fd • a) w G CO -P PI •H • 3 CQ £ D O C •H Eh i-H H r — 1 rH rH r — 1 i—i * CO -305A- TABLE 6.3.—FEA Projections for Offshore Oil and Gas Production as a Percent of Total U.S. Production, 1980 and 1985 Offshore production as percent of total U. S. production* Assumptions Oil 1980 1985 Gas 1980 1985 Business as Usual 25.5 32.6 Oil Price $7 per bbl. 16.1 22.1 Oil Price $11 per bbl. 14.6 17.5 Accelerated Development 28.6 35.9 Oil Price $7 per bbl. 18.5 23.9 Oil Price $11 per bbl. 17.7 20.3 * Offshore and total U.S. estimates are for the "Lower 48" States; Alaska is excluded. SOURCE: Federal Energy Administration, Oil Task Force Report (November, 1974), pp. IV-3 and IV-4; and Natural Gas Task Force Report (November, 1974), p. III-24. -305B- TABLE 6.4.—Offshore Oil and Gas Production, Reserves and Resources Relative to U.S. Totals •a fd 0) • • • • • • • 0 P o VO CM rH l'' •'T' CM VO O CD p CM 00 co O 00 CM rH cn > p rH ■H o o TO o cn G 0) cd D P p CO to cd CM TO a) cn cd O r- i un vo in o p P • • • • • • • p P CM CO rH r*^ rH m vo CD X o cn CM rH VO o CM ro x fd o -H no cn c cd m p to in P P cn a> fo cn cu cd 2 p c o *rH X as O P ■H TO O P a, o c > o -H -H X X fd o rH P P TO i o p p u ai ■H o CD TO P P CJ m vo • • o in VO CM CO • • co o' co ■K (N • • O CO CO O' ■K (N < < 2 2 < 2 < 2 cn fd o p p p -p fd 2 O rH • • vo r~ co m CM IT) O' • • CO rH CM CM m o vo cn TO •H P Ol cn fd O cd p p -P (d vo < 2 2 o cd O i - 1 TO CD o G CD 0 CD rH p i—i 0 H P P rH (D fd • fd O (X 4-1 X -h cn o (1) < >1 CD fd MH X CD rH CM P OP CD rH i—1 00 o 00 rH f" X! X fd c > £ X X VO vo in o in G •H O O G c O cn 00 rH td mh 6 - p CD XL - G CD rH ■H 1 o 0 0 P P TO fd o C CD C CD CD p x = O £ CD -H p g CD td cn o < X CD CM • X CD CD cn > rH -P -p > CD 0 >1 0 fd -s • X p -X x fd o o • • X • • cn X cn -h CD 1—1 x P rH cd cn CD TO -H X X • r> x • O X A O CD O £ CD 5 TO cn (d rH X O P O £1 P P P 0 X CD G -H cn X) O G P p p fd G P x c X) G -P 0 -P C O TO O mh £ fd a) • 0 G c •H G 0 cn cd cn • H TO X X TO CD G -H CD O rH CD •H CD > CD CD X G CD cn G rH OH U •H 1-1 O •H P 0 P P cn id Sh 0 X •H rH P i—1 •H P rH p fd CD CD o fd rH -H CD i—1 p CD •H Td X TO - - p rH iH X) Xi ■H X) X XI CD = cd cn cn cn cn fd •H ■H • P • —’ -H •H CD CD CD CD G fd X! cn cn -P cn co MH CD Mh -P o x o cn •H > — • td • • fd • • •H X •H ro P fd P CD TO fd cn D cn D cn -P -P -P E P £ P P p cd • 0 Q) • CD • G G -H O -H 0 P rH X P D P rH P D P H D CD CD CD -P cn x cn cp o O o 0 td 0 o x> POP x O X 0 \ \ < OHO O H O H rH 1 CM | m| | * 2 TO cn CD CD •H X X rH 0 in fd Oh O' E Oj cn c •H fd G -H X 0 X cn cn •H X w •H cn cd •h cn Sh > • O' CD • >H >i 0 p cn fd O' rH CD o 0 0 *■ > "H rH G cn p cn 0 X G CD O G o O cn h X CD •H CD 0 o X cn p cd CD G O' X G CD TO O X CD CD O' •H X X rH G X CD fd X •H O o fd X CD X -H p cn •n 0 TO o •H G c > X •H x -h fd CD rH X TO P G X •H inn c X P CD -H •H rH P G S X 5 X fd o cn TO G X -H CD S cn cn x X O fd CD O G • CD i-H CD -P X cn cd cn rn o p p O' *H X TO (1) TO G P o p c p £ o p Ip TO o -p fd c O TO •H C cn td SOURCE : 1974 production - U.S. Department of the Interior, Geological Survey, Conservation Divi Outer Continental Shelf Statistics (June 1975), p.89. Cumulative production, reserves resources - U.S. Department of the Interior, Geological Survey Circular 725, Geological Estimates of Undiscovered Recoverable Oil and Gas Resources in the United States , by Betty M. Miller et. al. (1975). TABLE 6.5.—Estimates of Undiscovered Recoverable Oil Resources of the United States (0 0 td o 0 p 44 o o 42 cn -P 4-1 p 4-1 0 u p 0 cu 01 dp H p cr 01 td CP •H o td •P o E-t 0 P 0 42 01 4-1 44 o 0 P O 42 01 p o CM rH Tj. vi) (N (N O < no no co 2 • • • oo m cm o co in co h o tp i—i i—i h* i o o CM o •H -p cd 2 O •H •p id 2 0 n 42 p w co co • • D D h cn nm vo P oi cp rd rH 42 QJ . . O cd > g cd P 0) P i—I cd o p CP -P CU P 0 I *H CH p >1 ■H i—I i—I I rH •H O a. cd a p cd o •H p t> QJ O P QJ •P O CO o. rH p cd P p 42 QJ fc -P P aj g p 01 01 0) o p p o 01 QJ P QJ P 0 44 rH QJ X CO 01 p o ■H P QJ ■P P QJ 42 4-) 44 0 >144 42 0 42 0 44 P O in dp X cd tP p 01 44 42 CO ai 2 •H •H 44 P 44 44 dP 1 p dP 22 > 44 0) P 1—1 P CP QJ QJ p 0 g P td cd cd CM > P • 0 w -D 0 p o o •H 01 0 dp p 01 •H i—i • ci cd QJ E-t 0) p cd 01 P Cn •H a 01 44 44 42 cd a* td P 0 O CH •H X cd 42 44 QJ o P4 rH dp 0 g 01 aj a 0 0 •k < in 00 CP p •H P t p dp 0 rH co in z CM CM p QJ 44 U P 0 0 p dP u 42 in i-4 P 01 cd X 42 cd P 44 QJ CO QJ 0 44 •H o > QJ a D O 0 o JP •H O QJ rH cd P p o p o • 1 P X iH P aj 01 44 •H 0 0 r4 a QJ cd a •H 0 QJ •H o rH 44 PS td in o "S’ < r- CN CP £ 44 i D 01 S 01 0 P o CP CO 2 CN CO p QJ 44 >4 44 PH H dp 44 CO CN 01 QJ •H • • PS QJ • rH P 0 0 I 1 a> 42 1 01 42 44 cd 0 P 0 P \ VO 44 44 i—1 QJ rH P P g td 42 0 p CO| CO cd •H 0 td P QJ < a 0 44 > 0 \ i—1 g P 0 P P S 42 o o 0 rH *H 1 .—. •H •H P QJ 0 42 P rH O 44 0 rH in 44 0) 0 P dp P 0 O 0 ■H r~. t'- 01 01 42 01 •H 4C 22 > rH ■H £ CM CP QJ QJ 44 QJ s td •k 0 td 4J dP i—l m |cd | P PS aj • 0 a P P P • CP — >H P 0 p P 44 o 0 2 2 i-H r—« ,—- ■H CP 44 01 »>. 42 a td 44 ■H g 01 CP a •H i 0 td • P O 44 i—( CJ CP CP p P O 42 42 CO p 2 CTi cd 44 •H P rH rH o QJ QJ dp P Eh o Or 0 0 O CM | QJ —' '—' u 42 O p QJ dp • • •H 0 • 0 0 CQ P •H Eh P cd •H QJ 01 CO 44 42 CHQ 44 P r-k O >1 >1 £ QJ z u • dp • aj • rd 44 td rH 0 •'T CO QJ QJ 3 a • rH CO CP •H (P p 2 P •<. • g 42 u r* > > QJ • M •H 00 > 00 rH 0 44 in CO •H CP 44 p P r-l rH o 0 o 44 0 rtf • • rH 0 r- • 44 £ i—i 0 p P o •H H" 0 z o • p • > m 0 a\ 2 0 0 9 —■ \co CO p o 1—1 a Or a i O 44 i —t w 0 QJ >i^r 1 44 44 44 • p • rH o P • • 44 rH . g 1—1 rH QJ QJ o P QJ CO g - 01 cd a> < O CO t—1 cd o Pu QJ , _s cd cd CH rH O 44 CM QJ CN QJ CM QJ rH 01 CH • td 44 p P dp N' a a 42 p 44 i—1 dp 44 g 42 0 dp 0 w 0 o CO 44 O cd •H •H rH rd o r*- QJ cd QJ cd QJ cd 44 0 P 0 44 •H QJ U o CP CP co cd QJ •H td 44 cd o rH •H a 44 •H rH 44 rH •H rH 0 o •H 0 44 P o rH 44 01 44 -H Cu 44 0 cd 44 44 0 -H cd O cd 44 QJ QJ 44 O W i—1 cd QJ 44 Or 01 p 44 0 0 0 P P p P e> O cd QJ 2h 44 P •k 0) cd H 0 rH W o 2 CP P o u 42 -P «tr CP CN CN CN 01 QJ PS • CO 2 p QJ 42 £4 44 <—< I P QJ > O O • P CO QJ • 42 2 O = PS QJ rH 42 cd -p o •H 44 Cd 2 42 tddP P -H O 42 P H QJ - 42 m 44 CM ["• p •H p cd oi rH Q) P O O P p p •H O U 01 QJ >iPS QJ > P ■H 44 44 (d 44 CO O 2 cn | cnl-^l in|i£>l2 W U PS 2 O co of undeveloped OCS oil and gas resources. It is evident from table 6.5 that the estimation of undiscovered recoverable oil resources is far from an exact science. Due to wide differences in the estimates of undiscovered oil resources, the anticipated share of offshore resources relative to total U.S. resources varies from about 30 to 63 percent. The actual significance of offshore oil and gas pro¬ duction will depend to a large degree on which leasing policy options are chosen. The purpose of this chapter is to describe past and present OCS leasing policies and to analyze their effects on the time pattern of resource development, economic efficiency, and the receipt of fair market value for leases. The effects of leasing policies on competition will be stressed. The probable effects of alternative policies will also be discussed. Past and Present Leasing Policies The Outer Continental Shelf Lands Act and its Adminis¬ tration - The Outer Continental Shelf Lands Act 5/ gave the Federal Government jurisdiction over submerged lands of 5/ P.L. 212, 43 U.S.C. §1331 et seq . - 306 - ( the OCS and authorized the Secretary of the Interior to lease these lands ". . .to meet the urgent need for further exploration and development of the oil and gas deposits of the submerged lands. ..." 6/ Section 5 of the Act provides that: The Secretary shall administer the provisions of this Act relating to the leasing of the outer Continental Shelf, and shall prescribe such rules and regu¬ lations as may be necessary to carry out such provisions. The Secretary may at any time prescribe and amend such rules and regulations as he determines to be necessary and proper in order to provide for the prevention of waste and conserva¬ tion of the natural resources of the outer Continental Shelf. ..." 7/ Within the Interior Department, the Bureau of Land Management (BLM) administers the Act's leasing provisions, while the U.S. Geological Survey (USGS) oversees the exploration and development activities of petroleum companies. The Bureau of Land Management: 6/ 43 U.S.C. § 1337 (a). 7/ 43 U.S.C. § 1334(a)(1). - 307 - (1) Selects tracts to be included in a lease « sale ; (2) Prepares an environmental impact statement for each sale; (3) Together with USGS, makes an economic, engi¬ neering and geologic evaluation of tracts to be leased; (4) Receives the bids and accepts or rejects the high bid on each tract; (5) Receives revenues from lease sales; and (6) Grants rights-of-way for pipelines from leases to shore. The Geological Survey: (1) Issues and enforces detailed regulations in the form of OCS orders and notices; (2) Issues geophysical and geological exploration permits; (3) Approves post-lease exploration and develop¬ ment plans; (4) Issues permits for exploratory and develop¬ ment drilling; (5) Approves pipelines as a part of field - 308 - development; and (6) Collects royalties. 8 / To analyze the administration of the Outer Contin¬ ental Shelf Lands Act, we will examine the following major facets of leasing policy: (1) the selection of lands for lease; (2) the size and timing of lease sales (3) the size of tracts leased; (4) the method of lease allocation (i.e., the selection of lessees); (5) the term of leases; and (6) the determination of drilling and production requirements. 1. Selection of Lands for Lease. The OCS Lands Act does not specify the area to be leased or how such areas are to be selected. BLM regu¬ lations provide that leases will be issued "... upon the [Interior] Department's motion or upon a request describing the area and expressing an interest in 8/ Kash ojd. cit . , p. 101. For a more detailed pre¬ sentation of the relevant laws and regulations and their administration, see Public Land Law Review Commission, ojd. cit . , ch. 4 and appendixes 3-A, 4-A, 4-B, and 4-C. - 309 - leasing a unit or units. ..." 9/ The Government has played mostly a passive or re¬ active role in selecting lands for lease. Offshore lands.have been leased where the petroleum industry has indicated sufficient interest. The usual procedure was (and to a large extent still is) as follows: (1) Prospective bidders, having secured geological and geophysical information on offshore areas, request that certain areas be offered for lease. Firms may ob¬ tain this information by conducting exploration activi¬ ties, by entering joint exploration ventures with other firms, by purchasing data from other firms, or by rely¬ ing on publicly available information. (2) When sufficient interest in an area is demon¬ strated, BLM issues leasing maps and a call for tract nominations. (3) Prospective bidders nominate the specific tracts in which they are interested. In order to 9/ Public Land Law Review Commission, op. cit., p. 4-B-4. -310- conceal from competitors the tracts which it believes to be valuable, a company may nominate more tracts than those in which it is really interested. This may con¬ fuse not only the competition, but also the Government, since BLM often is unable to screen out these "dummy" nominations when selecting the tracts to be offered for sale. 10 / (4) From the tracts that have been nominated by industry, BLM selects those to be offered for sale. BLM occasionally adds tracts that have not been nomi¬ nated but which it believes should be included in the lease sale. 11 / In selecting the tracts to be of¬ fered, BLM relies upon industry for geological and geo¬ physical data (which are collected and analyzed by the U.S. Geological Survey). For a number of reasons, this information is often not sufficient to determine which areas should be offered for lease. For one, data are available only on areas that have been explored by industry. Second, firms are not required to furnish geophysical data acquired under exploration permits to 10 / Public Land Law Review Commission, 0 £. cit ., p. 190. 11 / Ibid ., p. 602. -311- USGS. 12 / Third, although firms can be required to provide geological and geophysical data acquired during lease operations, USGS lacks the staff and facilities necessary to analyze large volumes of such data thorough¬ ly, and therefore does not make full use of its power to collect the data. Although BLM has relied principally upon industry to nominate tracts, the reliance has not been total. The Bureau has always held lease sales for drain¬ age tracts (i.e., tracts subject to drainage from pro¬ ducing tracts within the same geologic structure) on its own initiative. It has also taken factors other than industry demands into consideration. In some in¬ stances, tracts were not offered for lease if explora¬ tion and/or production operations would conflict with other uses, such as scientific and recreational activi¬ ties and defense operations, or environmental considera¬ tions. 13 / 12 / In 1975 the Interior Department was considering a proposed regulation which would require disclosure of such data. 13/ Public Land Law Review Commission, op. cit., pp. 190, 610, 661. -312- Since 1974, the Interior Department has adopted a "two-tier" system for selecting tracts to be leased. This system differs from the one described above in three respects. First, it calls for regional nomina¬ tions prior to tract nominations. Second, the request for nominations solicits geological, environmental, bio¬ logical, archaeological, socio-economic, and other in¬ formation which might bear upon the decision of which area to lease. Third, comments are being sought from Federal, State, and local governments, industry, univer¬ sities, research institutes, environmental organizations, and the general public in order to identify areas that should not be leased because of conflicting uses (such as fishing), environmental hazards, or other factors. 14 / 2. Size and Timing of Lease Sales. Decisions concerning the size (i.e., the number of tracts or acres offered) and timing of OCS lease sales are among the most important elements of Federal leas¬ ing policy. They determine the rate at which the lands 14 / U.S. Department of the Interior news release, November 26, 1974. -313- will be leased and developed. 15/ They also influence the level of competition in the market for oil and gas leases, competition in the petroleum industry generally, the supply of oil and gas, the prices of oil and gas, the amount of Government revenue derived from lease sales, and the economic efficiency of Federal petroleum resources development. Neither the OCS Lands Act nor Interior Department regulations specify standards for determining the times at which lease sales are to be held or the number of tracts to be offered. Table 6.6. shows that the timing and size of lease sales have varied considerably. "In the past there has been no affirmative policy and the timing of sales appears to have been a function of industry demand and varying administrative pressures for increasing revenue to meet the fiscal requirements of the Federal Government." 16 / 15 / This assumes that the industry desires to develop additional resources. If it does not, the leases will not be developed or, if diligence requirements force lessees to develop their leases, they will not bid on the tracts offered. 16/ Public Land Law Review Commission, op. cit., p. 610. -314- TABLE 6.6.—OCS Oil and Gas Lease Sales, 1954-1974 o o o tv X X o X o O o o o X o o o o o o X O O O o X vt o rv X o X o o o XJ O o o X o CM X o X o o X vt o o X o vt o rv O rv o o o o rv o o ON —4 X X vt \D o •H X c ON r-~ X X CM X •—4 p—1 X 4—4 o vt o X o X X CO o X O 4—4 o p—1 X vt o o O i/N X P—4 O X u o e- rv r—4 vt CM o o X X X X o rv 4—4 •— 1 X 4—1 o rv o O X o o rv O rv X ON o rv (V X p—4 X a) a) CM .—i o vt O X X o vt vt vt X X •— 1 P—4 X X X X vt —4 X X X o X X vt X rv X X p—4 a. v-. •» •4 •» •» • •* * •* •> a __1 CM eg o r-4 X X X o X o X p—i rv rv X X X X CO .—i 4—4 X X p—• ON X n3 x co 4—1 X X X r-4 rv •-4 X o X X X X vt X X X U ** of re X vt CM CM X o rv X rv X o X o rv X X X O rv X X X o o X o O X vt O X X X vt X O <0 M OO 00 CO O' o rv X O X X X rv ON X X o vt ON vt -* X X o X o rv X X o vt X rv X X X O vt |v X m CM rv X X X o X X o X X o vt X X X o rv o IV X o X rv rv X X rv vt X X O' vt in O' p—4 X vt X X •—1 X r—4 vt vt X vt X vt 4—4 X X o vt o 4—4 O X X 4—4 o o rv X o o vt X m >-< X co CO CM p—1 X •—1 X rv X X X X X o o o p—4 •—4 X X o 4—4 o X ON X X X > 01 •» •» < (X CM X X o X X X X X X X vt X X ON CM vt CM O vt X o rv o rv X X X X O o X X X o o X X o X X o vt o X X X rv CM X X rv CM X X o X X X X rv X X X o rv X vt X X O P—4 X X X X X X X X O X rv ■—1 0) X X X X vt X o c rv e- r—4 ,_i X CM o o rv X rv rv o X vt X vt o o o O X rv X o vt vt IV o IV X O X X X X o iv uo CO ON r—1 X X O X X |V. X O 3 X X vt X X rv p—4 o X X o X X o X p—i o X p—4 X X vt 4—4 X X X CO vt o rv o rv ON X X rv X X rv rv X —• r—4 O rv X X O o rv rv X X X X o X X X X o o co 00 o X X X rv rv X X o rv rv X o f—4 o X X o vt X rv X X X X r—4 X o rv X CM o X X vt rv X vt .—4 X X X o X 4—4 o o vt vt X o vt o X X o o ON IV X X ON 4-1 f—4 r—4 X ■—< X X X X 4—4 X X X X vt o vt •* •* •* •* »> H X vt ON O Cv O o O X X O O X X X X o X rv X X 4—4 vt o vt X X X X p—4 vt X rv X eg X X X CM n X o X vt X eg X o ei vt X < CO f—4 CM r—4 ei vt o ON X vt «V X X X X X X vt vt X 4—4 vO rv c U-4 O'- r -1 CM O' eg p—4 vt O o •—4 O X X 1 V X *“4 X X rv 4—4 4—4 X 4—4 4—4 4—4 4—4 X P—4 o X ON O 4—4 X o co X 4-4 p—4 P—4 .—4 p—1 4—4 4—4 4—4 X . CD CD M o M 0) CM 55 i~l r-» O' o pv O rv o X X o X X X X O X rv X X 4—4 X X X o X X X vt X IV rv X vt eg X CM vt X o X X X r-4 o o X X rv rv X r .| o 0—4 ON o vt X X X X X X X o rv rv p—4 ON X o rv X X to CM rv 00 vt o vt rv vt X X X ON X vt vt On IV o X X X X X —• X vt X X X X o X X rv IV O rv O' CM CM X o O r—4 X X vt X X X X X vt X X X o o o X X X X X X X O ON X o CM X -< *H X 55 X o 00 O m O X o X X o X X rv X vt O X X X ON o vt O vt o X X X o X rv X X ON X o o 00 O o O 4— 4 X X rv X X X rv X X vt o o o X o X eg X X X X rv X X vt o 4—4 iv X X p—i eg to o rv o o O X rv- X X X X X rv o —* O o X o vt X X X X rv X vt X X O X X ON X rv o X ON 00 •—4 X X X rv X X o o X o vt X X X rv p—4 o X X X X X X X X vt rv 1V o X X o X r—4 r—< m m X X rv o o X X X X X X X X rv X vt O o rv CN X X o o —4 X X On rv X O' < tv p—4 CM vt vt vt p—4 X rv X X X X o X rv X X X X 00 ON X X X O •» r—4 O ei of s O' X ON o X rv. X o o o o X o rv X X X o o X X rv vt rv X X X o rv X X X rv o ON CO CO rv X X o X o X x 4—4 X X vt vt 4—4 X o 4-4 X X X X X X p— ' iv X eg vt o vt m X p—4 vt a» u .— 1 1—4 X vt X —4 •—4 X P—4 p—4 4— 1 p—4 i — 4 4—4 X X X ei vt X 03 »» E M 3 4-> vt 55 X m 0) • .—4 H 0) cd .—4 CD V CD CD X 4—1 X o O X O X X X X 4-4 4—4 X rv X —4 o X X X X X rv o O Cj *” 1 4—4 "■ ‘ 1 H ^ -v. O ^1 n /V /V -• — /"V /V /V ✓“V /-v /-V /V /■“X n /V /V /V /V f-N /V Q Q Q a o o O O o o O O O o o CUr-4 CTJ v-/ 'w' v_^ V/ V4 v_^ VP" W v— - H oo OJ si ■i-4 X) SI s d) 0) O TJ • "f —4 0» X) o Od 00 c X) 3 >% o cd i 0) si H -* | cvi | ro | -Jc Source: U.S. Department or tne Interior, Bureau of Land Management, New Orleans Office, Outer Continental Shelf Statistical Summaries. In the latter half of the 1960's, the Interior Department was under a great deal of pressure from the Bureau of the Budget to ensure that the Government re¬ ceived the "fair market value" of leases. This in¬ volved keeping the size of lease sales relatively small so there would be greater competition for the leases; i.e., more bidders per tract. 17 / According to one authority on OCS leasing policies, "The extent and timing of the Santa Barbara lease sale was clearly motivated in large part by the fiscal needs of the federal government at that very little considera¬ tion being given to the broader resource policy objectives of the federal government." 18 / The timing of lease sales has also sometimes been influenced by short-term Government fiscal needs. This has involved arranging the date of sales so that the 17 / Statement of Monte Canfield, Jr. (Deputy Director, Ford Foundation Energy Policy Project) in U.S. House of Representatives, Select Committee on Small Business, Energy Data Requirements of the Federal Government , Part III, Hearings before Subcommittee on Activities of Regulatory Agencies, 93d Cong., 2d sess., 1974, pp. 167, 168. 18 / Robert B. Krueger, "An Evaluation of the Provisions and Policies of the Outer Continental Shelf Lands Act," Natural Resources Journal , 10 (Oct. 1970), No. 4, p. 767. -315- bonus payments would be received near the end of the cur¬ rent fiscal year rather than at the beginning of the next fiscal year. 19 / After almost 18 years of sporadic leasing, the Interior Department announced a formal five-year leasing schedule in June 1971. The schedule specified the region and month in which lease sales would be held during the next five years. The plan was to be updated annually. 20 / Interior's stated policy was to schedule new OCS lease sales to help meet regional oil and gas supply- demand imbalances. Lands were to be leased where V regional shortages were identified. At the same time, the leasing schedule was to be limited to two general sales of 300,000 to 600,000 acres per year in order to maintain a "competitive" market for leases and ensure 19 / See Kreuger, ojd. cit . , footnote 19; and Canfield, op . cit ., p. 168. 20 / Kash, o£. cit., p. 175. -316- collection of the leases' "fair market value." 21 / Nowhere is the conflict between two policy objectives (the Department's stated objectives of "orderly and timely" resource development and the receipt of "fair market value") more evident. The growing shortage of oil and gas soon made it clear that domestic supply-de¬ mand imbalances could not be corrected while at the same time the rate of leasing was being limited in order to maintain the return to the Treasury. It should be noted that the Interior Department's concepts of "orderly and timely" resource development and the receipt of "fair market value" were not the same as those defined in previous chapters of this study. "Orderly and timely" resource development apparently did not mean the economically efficient or socially optimal rate of development. Rather, it meant a pattern which would not glut regional oil and gas markets at 21 / U.S. Department of the Interior, Questions and Policy Issues Related to Oversight Hearings on the Administration of the Outer Continental Shelf Lands Act . . ., in U.S. Senate, Committee on Interior and Insular Affairs, Outer Continental Shelf Policy Issues , hearings pursuant to S.Res. 45, A National Fuels and Energy Policy Study, 92d Cong., 2d sess., 1972, Part I, p. 128. -317- current price levels. Like market demand prorationing, the policy was designed to maintain petroleum prices and prevent market disruptions. According to the testimony of Dr. William A. Vogely, Acting Deputy Assistant Secretary of the Interior for Energy and Minerals: Prior to 1972, the pacing of Outer Continental Shelf sales was based upon the fitting of production from the Outer Continental Shelf into a situation of excess producing capacity in the United States. And so the pacing of Outer Continental Shelf development was based upon whether there was a market for the oil. 22/ It is also evident that the receipt of "fair market value" for leases did not mean collecting the economic rent when the resource is produced efficiently. Rather, it simply meant restricting the size and fre¬ quency of lease sales in order to keep bonus bids high. The attempt to provide stability for the leasing schedule was doomed to failure not only by internal 22 / U.S. House of Representatives, Select Committee on Small Business, Energy Data Requirements of the Federal Government , op. cit., Part III, p. 249. -318- issued in November 1974. The current goal is to ac¬ celerate development of offshore resources by leasing frontier areas. The revised schedule proposes an aver¬ age of six sales per year during the 1975-78 period. 23 / 3. Size of Tracts Offered for Lease. The Outer Continental Shelf Lands Act provides that oil and gas leases shall cover a compact area not ex¬ ceeding 5,760 acres. 24 / However, most offshore Louisiana leases are 5,000 acres in size, since the State of Louisiana had leased its offshore lands in 5,000-acre blocks and Federal regulations provide that the official leasing maps should conform as far as practicable to the system of the adjoining State. 25 / Although most tracts leased to date have been the maxi¬ mum size, a significant proportion of the tracts leased have not been full tracts. As of 1968, 18 percent of gulf coast tracts were half-tracts and 18 percent were 23 / U.S. Department of the Interior, News Release , June 18, 1975. 24/ 43 U.S.C. § 1337 (b). 25/ 43 C.F.R. § 3380.2 (b). -319- of other sizes less than the maximum. Off the Pacific coast, 80 percent of the tracts were full tracts, 13 percent were half-tracts, and 5 percent were quarter- tracts. 26 / 4. Method of Lease Allocation. Under the Outer Continental Shelf Lands Act: . . . the Secretary is authorized to grant to the highest responsible qualified bidder under regulations promulgated in advance, oil and gas leases on submerged lands of the Outer Continental Shelf .... The bidding shall be (1) by sealed bids, and (2) at the dis¬ cretion of the Secretary, on the basis of a cash bonus with a royalty fixed by the Secretary at not less than 12-1/2 percentum in amount or value of the production saved, removed or sold, or on the basis of royalty, but at not less than the percentum above mentioned, with a cash bonus fixed by the Secretary. 27 / In practice, all tracts except those leased in a 1974 royalty bidding experiment have been leased on the basis of the highest cash bonus bid plus a fixed 26 / Public Land Law Review Commission, op. cit., pp. 191, 192. 27/ 43 U.S.C. § 1337 (a) . -320- 16-2/3 percent royalty. The reason for the specifi¬ cation of a one-sixth royalty rather than the minimum one-eighth royalty is not clear. It may be due to the fact that some of the State offshore leases in the area where Federal leasing policy was first applied (offshore Louisiana and Texas) provided for a one-sixth royalty rate. 28 / Leasing regulations reserve to the Federal Govern¬ ment the right to reject any and all bids. 29 / Until the November 19, 1968, lease sale, a minimum acceptable bid (varying from $5 to $25 per acre) was specified in each Notice of Lease Sale. Bids below the minimum would not be considered, although bids above the mini¬ mum could also be rejected. Since that time, no mini¬ mum acceptable bid has been published prior to the lease sale. Rather, the Bureau of Land Management has rejected bids partly on the basis of confidential pre¬ sale evaluations prepared by the U.S. Geological Survey. 28 / Public Land Law Review Commission, 0 £. cit ., p. 208. 29/ 43 C.F.R. § 3382.5. -321- Beginning with the March 28, 1974, lease sale, the pre-sale tract value estimates have been generated through Monte Carlo simulation techniques. A range of values for the major variables that determine the value of the tract is established. A computer runs through these values (weighted by their probabilities) and randomly selects a value for each of the variables. The combination of these values determines the estimated value of the tract. This is done hundreds of times, generating hundreds of tract value estimates (each based on a random selection of variable values). The pre-sale evaluation of the tract, called the "mean value" of the tract, is the mean of these estimates. -322- The estimated mean value of tracts is the primary figure used in deciding whether to reject high bids. BLM evaluations also consider the "discounted mean value"; i.e., the mean value discounted due to the loss of a lease's present value caused by the two-year delay before the tract could be re-offered for lease if the bid is rejected. 30/ The average of all evaluations of the tract (the mean value plus all bids received) and the number of bids on the tract are also considered in deciding whether to accept or reject bids. 31 / 30 / The delay is due to possible appeal of the rejec¬ tion and pre-lease administrative requirements. 31 / U.S. House of Representatives, Select Committee on Small Business, Energy Data Requirements of the Federal Government , op . cit ., Part III, pp. 205-206. -323- The history of the rejection of high bids for OCS Section 8 oil and gas leases is presented in table 6.7. The frequency of bid rejections has evidently increased over time. During the years 1954-64, only four percent of the high bids on tracts which received bids were re¬ jected. During the years 1965-1969, fourteen percent of the high bids were rejected; while 12 percent of the high bids were rejected over the 1970-74 period. A closer examination of table 6.7 also reveals that in most cases where a relatively high percentage of the bids were rejected, either the sale was a drainage sale 32 / or a large number of tracts were offered for lease. Under these circumstances, competition for * leases may be relatively weak and more "winning" bids are likely to fall below the Government's estimated tract value. When numerous leases are offered for sale, there is apt to be a large number of tracts which re¬ ceive only two or fewer bids. As shown in a subsequent section, the level of bids tends to be lower when there 32 / A drainage sale is one in which the tracts are not nominated by industry, but are offered for lease by the Government because the petroleum resources beneath them could be drained away through wells on adjacent tracts. -324- TABLE 6.7.—Rejected Bids, 1957-74 OCS Oil and Gas Lease Sales Sale State No. of bids rejected 1/ Rejected bids as percent of no. of tracts bid on Type sale No. of tracts 2/ offered 10/13/54 La. 0 0 G 199 11/9/54 Tex. 0 0 G 38 7/12/55 Tex. 0 0 G 39 7/12/55 La. 0 0 G 171 5/26/59 Fla. 0 0 G 80 8/11/59 La. 9 32 D 38 2/24/60 Tex. 0 0 G 97 2/24/60 La • 26 21 G 288 3/13/62 La • 6 3 G 401 3/16/62 Tex. 0 0 G 30 3/16/62 La. 5 3 G 380 10/9/62 La. 5 36 D 19 5/14/63 Cal. 1 2 G 129 4/28/64 La. 0 0 D 28 10/1/64 Ore. 0 0 G 149 10/1/64 Wash. 0 0 G 47 3/29/66 La. 1 6 D 18 10/18/66 La. 8 25 D 52 12/15/66 Cal. 0 0 D 1 6/13/67 La. 14 8 G 206 2/6/68 Cal. 4 5 G 110 5/21/68 Tex. 31 22 G 169 11/19/68 La. 5 24 D 26 1/14/69 La. 6 23 D 38 12/16/69 Ld • 0 0 D 27 7/21/70 La. 2 10 D 34 12/15/70 La. 9 7 G 127 11/4/70 La. 2 15 D 18 9/12/72 La. 12 16 G 78 12/19/72 La. 3 3 G 132 6/19/73 Tex.-La 4 4 G 129 12/20/73 Miss., Fla. Ala 2 2 G 147 3/28/74 La. 23 20 G 206 5/29/74 Tex. 21 17 G 245 7/30/74 La.-Tex . 30 61 G 258 10/16/74 Ld • 13 9 G 287 10/16/74* La. 0 0 G 10 TOTALS 242 9.4 4,451 1/ The number of rejected bids was calculated by subtractomg the number of tracts leased from the number of tracts bid on . 2/ G=general; D=drainage. SOURCE: U.S. Department of the Interior, Bureau of Land Manage¬ ment, New Orleans Office, Outer Continental Shelf Statistical Summaries. -324A- are few bidders per tract. In the case of drainage tracts, the percentage of bids rejected has been rel¬ atively large for two main reasons: (1) the Govern¬ ment is more certain of the value of the leases; and (2) competition for the tract is diminished owing to advantages which the lessee of an adjacent tract (through which drainage is possible) possesses—notably, greater knowledge of the tract's value and ability to drain the tract. For all OCS leases issued by the Federal Government as of December 31, 1974, drainage tracts accounted for eight percent of the total number of tracts bid on, but 16 percent of the tracts on which the high bid was rejected. 33/ 5. Term of Lease. The Outer Continental Shelf Lands Act stipulates that oil and gas leases shall: 33 / Computed from data of table 6.7. - 325 - . . . be for a period of five years and as long thereafter as oil or gas may be pro¬ duced from the area in paying quantities, or drilling or well reworking operations as approved by the Secretary are conducted thereon. . . . 34/ The five-year term appears to have been carried over from the Mineral Lands Leasing Act of 1920. A five-year primary term is also customary in private oil and gas leases in many States. 35/ Regarding extensions of leases beyond the primary term, OCS operating regulations provide that: . . . in the interest of conservation the supervisor may direct or, at the request of a lessee, may approve the suspension of operations or production, or both, including the approval of suspension of production for (i) leases on which a well has been drilled and determined by the supervisor to be capable of being produced in paying quantities and thereafter temporarily abandoned or permanent¬ ly plugged and abandoned to facilitate proper development of the lease, and (ii) leases on which a well has been drilled and determined by the supervisor to be capable of being produced in paying quantities, but which cannot be produced because of the lack of 34/ 43 U.S.C. § 1337 (b). 35/ Public Land Law Review Commission, ojo. cit . , p. 204. - 325 - transportation facilities. Suspensions of operations or production, or both, may be approved for an initial period, not exceeding 2 years, and for succeeding periods, not exceeding 1 year each. 36/ Table 6.8 shows that there were 101 extended-term Section 8 OCS leases as of January 1974. While most of these have been extended less than eight years beyond their primary terms, some have been extended as long as 15 years. The weighted average duration of the extensions was about four and one-half years. 6. Drilling and Production Requirements. The Outer Continental Shelf Lands Act authorizes the Secretary of the Interior to prescribe regulations necessary ". . . to provide for the prevention of waste and conservation of the natural resources of the Outer Continental Shelf . . . ." 37 / The regulations re¬ quire that: 36/ 30 C.F.R. § 250.12 (d) (1). 37/ 43 U.S.C. § 1334 (a) (1). - 327 - TABLE 6.8.—Extended-Term Leases 1 / As of January 1974 Years beyond primary term No. of leases Acres Bonus ($000) 0- 3 50 244,289 349,533 4- 7 43 200,994 43.245 8- 10 4 20,000 11,046 11- 15 4 12,457 5,766 Total 101 477,740 409,590 1/ Section 8 leases (OCS leases issued by the Federal Government). SOURCE: Federal Power Commission, Offshore Investigation: Producible Shut-in Leases (First Phase), Bureau of Natural Gas, Office of Economics, Staff Report (March 1974), -327A- (a) The lessee shall diligently drill and produce such wells as are necessary to pro¬ tect the lessor from loss by production on other properties, or in lieu thereof, with the consent of the supervisor, shall pay a sum determined by the supervisor as adequate to compensate the lessor for failure to drill and produce any such well. . . . (b) The lessee shall promptly drill and produce such other wells as the supervisor may reasonably require in order that the lease may be properly and timely developed and pro¬ duced in accordance with good operating practices. 38 / Area oil and gas supervisors are directed to ad¬ minister OCS regulations ", . .to the end that all operations shall be conducted in a manner which will protect the natural resources of the Outer Continental Shelf and result in the maximum economic recovery of the mineral resources in a manner compatible with sound conservation practices." 39/ They are authorized to approve well locations and well spacing programs neces¬ sary for proper development and to specify "... the permissible production of any such well that may be produced when such action is necessary to prevent waste or to conform with such proration rules, schedules, or 38/ 30 C.F.R. § 250.33. 39/ 30 C.F.R. § 250.11. - 328 - procedures as may be established by the Secretary." 40 / A ( Rather than devising an independent system of drill¬ ing and production requirements, the Interior Department has generally adopted the requirements of the Coastal States. In fact, operators on the OCS first, obtained Louisiana State permits concerning production allowables, well spacing, and other factors affecting the rate of pro¬ duction. The Federal administrators then reviewed the State rulings and imposed identical conditions. 41 / As a result, the Federal Government extended the State systems of "market demand prorationing" to OCS petroleum production. A market demand prorationing system is implemented in four basic steps: (1) Based upon the physical characteristics of each petroleum reservoir, a "maximum efficient rate" of production (MER) is determined. Owing to the loss of pressure and other factors, the 40/ 30 C.F.R. §§ 250.16 and 250.17. 41/ Public Land Law Review Commission, op. cit., pp. 223, 224. -329- higher the rate of production from a reservoir, the lower is the amount of oil ultimately extracted. On the other hand, a very slow rate of production would result in high operating costs and a reduced present value of the resource sales. The establishment of an MER involves a trade-off between these opposing factors. (2) Each of the reservoir's producers is assigned (prorated) a share of the maximum permitted level of production. This is called his "allowable." (3) An estimate is made of the current demand for petroleum at the prevailing price. (4) Each producer's allowable is reduced by a per¬ centage "market demand factor" so that total production will coincide with total demand and prices will remain stable. (In times of excess productive capacity, prices would fall if firms were permitted to produce their full "allowable.") Market demand prorationing is therefore essentially a system for maintaining market prices. -330- As the growth of petroleum demand outpaced supply additions during the late 1960's, estimated ex¬ cess capacity of OCS oil wells decreased as follows: 42 / January 1, 1969 - 357,000 BOPD 43/ January 1, 1970 - 348,000 BOPD January 1, 1971 - 103,000 BOPD January 1, 1972 - zero Production allowables were correspondingly increased until production at the full MER was allowed. On December 5, 1970, State-determined restrictions on OCS oil and gas well production rates were removed. Limitations on production rates are now imposed only by the maximum efficient rate of production from an oil or gas reservoir and ". . .by the well's ability to pro¬ duce, consistent with good operating practice." 44/ 42/ U.S. Department of the Interior, Questions and Policy Issues Related to Oversight Hearings on the Outer Continental Shelf Lands Act..., op. cit., p. 59. 43/ Barrels of oil per day. 44 / U.S. Senate, Committee on Interior and Insular Affairs, Outer Continental Shelf Oil and Gas Development , op . cit ., p. 770. Regulations governing oil and gas operations on the OCS state: Section 5(a)(1) of the [Outer Continental Shelf Lands] Act, authorizes the Secretary in the interest of conservation to provide for unitization, pooling and drilling agree¬ ments. Such agreements may be initiated by lessees or where in the interest of con¬ servation they are deemed necessary they may be required by the Director. 45 / Unitization is the pooling of all oil and gas interests covering a petroleum reservoir. It is a form of joint venture. The reservoir is developed as a single unit by one operator, rather than by competing developers. The unit agreement specifies how costs will be shared and how the reservoir's oil and gas will be allocated 4 among the participants. Unitization prevents firms from drilling unnecessary wells and from producing at a rapid rate in order to increase their share of the oil and gas contained within the reservoir. 45 / 30 C.F.R. § 250.50. -332- Although the Government has not used its powers to require unitization, several unit agreements have been reached voluntarily. Table 6.9 presents a history of unit plans and the share of total OCS oil and gas pro¬ duced by unitized operations. In 1974, 112 unit plans accounted for 32 percent of OCS oil production and 33 percent of OCS gas production. 46/ Economic and Technological Conditions of the Industry General The United States petroleum industry is commonly viewed as being populated by giant companies. As noted by James McKie, however, this has not been the case for the industry's exploratory stage: Refining and transportation are dominated by the large integrated companies. A combination of economies of scale and market advantages of integration in those stages has left only a secondary role for the independent oil company. In contrast, exploration swarms with independent oil companies. It is the habitat of the individual oil "wild-catter," a contemporary legen in American industry. The disadvantages of small size and obstacles to entry which prevent the independent and unintegrated 46 / The 112 unit plans outstanding in 1973 encompassed 260 leases. (U.S. Senate, Outer Continental Shelf Oil and Gas Development , opl cit . , p~. 771.) -333- rH (d -P 0 C 0) E-* 0 03 ] i i i CO CO in VO VO 00 CN o r- r- r- vo rr CO in •H O 1 i i i «—1 l — 1 rH rH CN CO CO CN CN CN CN CN CO CN G 4-t p P O O 0 G •H 3 QJ 03 QJ TJ O •H Cn 0 P > 03 P QJ •H -P G. rH Ph a G •rH rH o CO 00 rr l"» r- 00 r- 00 O o o co n' N 1 CN r-' d) 03 o rH CN CN CN co CO co CO co CO "T CO co CO CO co G O U 0 P O •H a) P G rd > T3 p C a) i • P rH rH rH rH rH rH rH G QJ O. p oj QJ > •H P e P - C 3 QJ P — o G i O • QJ in m O VO 0 rH CN CO VO in in in VO rH 00 CO r- cn 00 C0 co o CN CN CN P r- 4-1 •H UO 2 rH rH rH rH rH rH rH 1—1 CN CN *3* r- cn cn o rH rH rH Cn rH cn rH p cn rH rH rH rH cd rd >—i QJ a rH o x P a) o cn rH r' O co O o CN vo in rH o CO c •H QJ 03 T3 oj Cn uo cn o rr VO r-' CN o VO vo o o 00 in r-H rd cn c o p 03 CN in o CN CN 00 vo o 00 vo cn vo rH O P pH u fd \ QJ 04 rH rd cu qj oj 03 p 00 CN CN in rH r-H rH CN rH rH o 1—1 o ^ p >H G o i CO i CN in co i 1 i CN m CN o C'- r» uo CO 00 P Q) G 'O 03 03 < i I i 1 1 rH r-H vo •H O 03 QJ (U p rH a) G O C N 03 a. -p P -H •H •H T3 03 p p p -p G -p G 4-1 0 03 c •H a) •H o o G E p p u D rd D H w QJ rd u QJ G P P p 0 c in QJ • ■H H -P 0 i rH I rH rH rH i i 1 rH co rH 1 co CN co CO CN CN p p P 2 i i i i 1 1 rH co o QJ i—1 O cd X QJ 1 P P X 1 p in • QJ CN r> o o rH o o CO VO CN CO cn CO VO CO o 00 p" G 4H CO Cn r- o o o o f" m r- O o r* 00 VO vo 00 CN o rH cn vo r-H r- O P -H H rH rH rH rH rH rH rH l—1 rH l—1 r-H rH rH rH rH rH rH rH rH Eh rH 1 fd 1 enterprises from flourishing at other stages of the industry are apparently absent here. 47 / Yet McKie recognized that the importance of the independents is to some degree illusory, due to the cooperative arrangements prevailing among majors and independents. The exploratory activities of majors and independents are partly competitive and partly complementary, resulting in what McKie called a pattern of "symbiotic competition." 48/ The petroleum production process encompasses three stages—exploration, development, and extraction. Put succinctly, "exploration and development . . . create reserves, an intermediate product; extraction con¬ verts or depletes this asset into a final product." 49/ The exploration stages consist of research activity designed to discover oil and gas bearing lands. In addition to exploratory drilling, exploration can encompass geophysical activity such as seismic surveys, bottom sampling and coring, and aerial inspections. 47 / James E. McKie, "Market Structure and Uncertainty in Oil and Gas Exploration," Quarterly Jouranal of Economics 74 (November 1960), p. 543. 48/ Ibid . 49 / M. A. Adelman, "The Supply and Price of Natural Gas," Journal of Industrial Economics, Supplement (1962), p. 3. -334- Once a prospective reservoir is located, development drilling takes place in order to delineate the boundaries of the hydrocarbon deposit and to prepare for eventual production. The predominant activity in this stage is developmental or "step out" drilling. As the name implies, the extraction stage refers to the relatively straightforward process of extracting gas or oil from the reservoir. Of these three, the exploration phase accounts for the largest volume of expenditures. In 1973, exploration costs totaled $5.9 billion, 44 percent of total produc¬ tion expenditures. Development costs totaled $3.3 billion, while extraction cost $4.2 billion (table 6.10). Exploration costs have been rising at a much faster rate than those for either development or extraction. Since 1969, exploration costs have risen from 34 to 44 percent of total expenditures. The principal factor in this change has been the rising importance of lease acquisi¬ tion costs, which have increased over 300 percent during the 1969-73 period. 50/ 50/ Lease acquisition costs rose from $1.1 billion in 1969 to $3.6 billion in 1973. See 1973 Joint Association Survey of the U.S. Oil and Gas Producing Industry (American Petroleum Institute, February 1975), p. 76. -335- TABLE 6.10.—Estimated Expenditures for Exploration, Development, and Production of Oil and Gas in the United States: 1973 Amount (millions of dollars) Percent of total expenditures Exploration 5,865 43.9 Development 3,255 24.4 Production 4,235 31.7 Total expenditures 13,355 Source: American Petroleum Institute, 1973 Joint Association Survey of the U.S. Oil and Gas Producing Industry (February 1975). -335A- Offshore Technology Although offshore petroleum production has not received much public attention until recently, it is not a new activity. Oil and gas were produced from piers extending off the California coast as early as the 1890's, and the first drilling platform out of sight of land was completed off the coast of Louisiana in 1947. 51 / Offshore operations are similar to onshore pro¬ cedures, and much of the equipment is identical. The major differences are due to two factors: (1) operations must be conducted from ships, platforms, or subsea com¬ partments; and (2) the dangers of environmental damage are much greater. Seismic surveying is conducted from ships using contained gas explosions or electronic vibrators rather than dynamite or other explosives that may kill fish. Exploratory and development drilling is done from barges, drill ships, jack-up rigs, or semi-submersible rigs, depending upon water depth and weather conditions. 51 / Hash, op. cit ., p. 25. -336- Extraction operations are generally conducted from fixed platforms. Subsea production systems and inter¬ mediate systems (such as buoyant towers and tension-leg platforms) are being developed and tested. Due to the danger of environmental pollution, exploratory, develop¬ ment, and production activities are monitored by the Federal Government, and precautionary measures and equipment are required. 52 / Costs It is extremely difficult to estimate the cost of producing oil and gas. Perhaps the severest problem, particularly for offshore operations, is the sparsity of data on expenditures. Table 6.11 presents cost estimates for the late 1960's prepared by the Bureau of Land Management. The data used, the assumptions made, and the limitations of the estimates are explained in the BLM study. Note in particular that: (1) the estimates are for combined oil and gas production; 52/ For a more detailed description of offshore tech¬ nology, see Kash, op. cit ., pp. 25-81. -337- TABLE 6.11.—Summary of Estimated Costs of Finding and Producing Hydrocarbons 1/ U.S., excluding Gulf Onshore Gulf of of South Mexico and Mexico Louisiana onshore So. La. 2/ -(Dollars per barrel)-- Finding costs Successful well drilling costs .45 .47 .42 Lease facilities . 08 .10 . 13 Dry holes .24 .28 .22 Lease acquisitions 3/.27 .12 .13 Geophysical, geological, lease rentals, land, scouting, and other exploratory expenses . 15 .20 .17 Total finding Costs 1.19 1.17 Other costs Production operating expenses . 35 . 41 .47 Transportation of crude oil and lease condensate .08 Production taxes — .25 .13 Overhead expenses .16 .18 .17 Total other costs .59 . 84 .77 Total costs 4/ 1.78 2.01 1.84 1/ Non-associated gas converted to equivalent barrels of oil on revenue basis. See source for limitations of estimates. Estimates are for the late 1960's. 2/ Alaska is also excluded. 3/ Current lease acquisition costs are much higher. 4_/ Excludes royalties. Source: U.S. Department of the Interior, Bureau of Land Management, The Role of Petroleum and Natural Gas from the Out er Continental Shelf in the National Supply of Petroleum and Natural Gas (Washington, D.C.: Government Printing Office, 1970), p. 205. -337A- (2) the estimates are given in terms of cost per barrel discovered or produced; (3) exploration costs and development costs are combined into a category called "finding costs"; (4) overhead costs are not allocated; (5) costs are compared among the Gulf of Mexico (offshore), onshore South Louisiana, and the remainder of the U.S. (excluding Alaska); and (6) the cost figures cannot be used to estimate profitability, because they do not include royalty payments, and costs and revenues must be discounted in order to estimate profit¬ ability. (Most costs are incurred in the early stages, while revenues are spread over a long period of time.) The cost estimates presented in table 6.11 indicate that: (1) well drilling costs per barrel of reserve additions were similar in the three areas. Although drilling costs were higher offshore, this was more than offset by the higher pro ductivity of offshore reservoirs. The productivity of crude oil reservoirs (in terms of reserve additions per foot drilled) was more than twice as high in the Gulf of Mexico as in the onshore areas. The productivity ^ of gas reservoirs in the Gulf of Mexico was more than twice as high as onshore South Louisiana and more than four times as high as in the remaining U.S. (excluding Alaska). 53/ 53 / U.S. Department of the Interior, Bureau of Land Management, The Role of Petroleum and Natural Gas from the Outer Continental Shelf in the National Supply of Petroleum and Natural Gas, op. cit., p. 160. -338- v. Of course, offshore drilling costs increase as drilling takes place at greater water depths, due primarily to the increased cost of constructing drilling platforms. 54 / (2) The difference between onshore and offshore costs was greater for lease acquisitions (bonus payments) than for any other cost element incurred both onshore and offshore. Based on experience in the years 1954-64, the cost of lease acquisitions per barrel of reserve additions was twice as high in the Gulf of Mexico as onshore. Since the productivity of offshore reservoirs was on average two or four times that of onshore reservoirs, absolute leasing costs were about four to eight times as high offshore as onshore. The difference is no doubt even greater today, since OCS lease bonuses have increased sharply. The average bonus per acre leased was $2,210 for the period 1965-74, compared to $265 for the 1954-64 period used for making the cost estimates in table 6.11. (3) Geophysical, geological, and other explora¬ tory expenditures per barrel (excluding drilling exploratory wells) in the Gulf of Mexico were 25 percent below onshore South Louisiana and 10 percent below the remaining United States (excluding Alaska). (4) The "other costs" were lower in the Gulf of Mexico than onshore, primarily because there were no State production taxes on Federal leases. Production operating expenses per barrel produced were lower in the Gulf of Mexico than onshore. Again, 54 / Ibid ., p. 180. -339- while absolute costs were higher offshore, this was more than offset by the higher productivity of offshore reservoirs. Risks The risks encountered in petroleum exploration and production influence the structure of the industry and the ability of the Federal Government to realize its leasing objectives. Oil and gas companies (or other leaseholders) face several types of risk. The most important is "discovery risk," or the risk that the company will not find as much oil or gas as it had expected to find when it decided to lease a tract or to drill a well. 1. Discovery Risk. Although geological and geophysical exploration techniques have advanced over time, it is still true that whether a geological structure contains petroleum is typically not known until several holes have been drilled. The extent of risk depends upon the prob¬ abilities of discovering oil or gas (ranging from a dry tract to a bonanza) and the level of exploration costs which must be incurred. Table 6.12 summarizes the results of exploratory drilling in the United States for the years 1966-73. The cumulative percentage of wells which turned out to be dry is the same for offshore as for onshore: about 83 percent. Since 1970, the percent of wells classified as dry holes has been greater offshore than onshore. However, the dry hole percentage for offshore wells is overstated because offshore wildcat wells are often plugged even though commercial quantities of oil or gas are found. Since such "expendable" wells would not be completed for production, they would be classified as dry holes. 55 / Table 6.13 shows the average cost of drilling wells in two different depth ranges for offshore and onshore in 1973. Offshore drilling was two and one-half to 55 / American Association of Petroleum Geologists Bulletin (June 1969), 1274. Expendable wells are exploratory wells drilled for information purposes only. They are not intended to be used for production. Production wells are drilled later from fixed platforms. -341- TABLE 6.12.—Exploratory Wells in the United States 1/ \ Onshore Offshore Total number of Average depth Percent Total number of Average depth Percent Year wells (feet) 2/ dry wells (feets) 2/ dry 1973 7,188 5,882 79.2 278 8,975 90.3 1972 7,281 5,846 82.5 258 9,608 94.6 1971 6,602 5,606 84.2 320 10,544 85.3 1970 7,485 5,752 83.4 208 10,572 85.1 1969 9,368 5,574 82.5 333 10,692 82.0 1968 8,458 5,466 85.7 421 11,228 80.5 1967 8,669 5,190 82.8 390 10,606 74.4 1966 9,967 5,136 84.6 346 11,647 77.7 All Years 65,012 5,556 83.2 2,553 10,572 82.6 1/ The first year for which offshore statistics were presented seperately was 1966. 2/ There is no large difference between the average depth of dry holes and successful wells. Both onshore and offshore, dry holes tend to be 200-300 feet shallower than the average well. Source: Computed from The American Association of Petroleum Geologists Bulletin, 1967-1974. I -341A- TABLE 6.13.—Average Cost of Drilling per Foot Drilled, 1973 (Dollars) Depth Onshore Offshore range Dry All Dry All (feet) hole holes hole holes 5,000- 7,499 11.05 14.43 57.21 66.85 10,000-12,499 19.27 25.15 62.41 66.51 Source: Computed from Joint Association Survey of the U.S. 0 and Gas Industry: 1973, American Petroleum Institute (February 1975), pp. 8, 9. -34IB- ( five times as expensive per foot as onshore drilling. Since the average offshore exploratory well for the years examined in table 6.12 was 10,572 feet deep, drilling the average offshore exploratory well would have cost about $660,000, compared to about $61,000 for the average onshore exploratory well. 56 / In addition to exploratory drilling, the other major exploration cost is the cost of lease acquisition. This is also a very risky type of investment. Accord¬ ing to the only available estimate, 25 percent of leases in the United States are productive. 57 / Table 6.14 shows that of the Federal OCS leases sold between 1954 and 1964, 60 percent had been wholly relinquished by 1970. The relinquished leases accounted for 61 per¬ cent of the acres leased and 33 percent of the bonuses paid. About $400 million dollars was paid for the relinquished leases. Eighteen of the 1,020 leases 56 / We have assumed that the dry hole costs shown in table 6.13 are representative of the costs of exploratory wells. 57 / U.S. Department of the Interior, Bureau of Land Management, The Role of Petroleum and Natural Gas . . . , op. cit ., p. 188. -342- TABLE 6.14.--Wholly Relinquished Leases by Individual Sales (Relinquishments through 1970) T3 05 (1) -p Q) u x: C W O w w 01 o 4-1 -H 0) O G 0 05 n co tru (II J3 C 0) (li (0 -H f—I MH OirH o as u CN CTi o r-' o cn co in co o o TP O o o O CD o m o CN r- o CN o Cn o o co o ro in tp o co o CN co TP o CN CN o o m rH rH rH rH rH 'O 0) cn 43 4-> 0) 05 G Sh -H CO r-' o CO o o CN rH tp o in cn o CO o CO <15 U G • O c0 tr 1 CN o o o CN o in in o in co o o o rH G in CO o CD o Tp 00 CO TP o CO TP o CO o CD 05 *4-4 •H rH rH rH 1—1 rH ft OH 0) u 05 0) 0) <0 in o r- o ID 0) u *4H rH I O 05 0) iH 04 (0 >1 05 EH HH 05 O 0) 05 • <0 O 0) Z «H 05 -P (0 4J CO <15 rH fd OOOOOQOOOOCJQOQO ocr\r"tfcoo5co(jMOOU5cnr^nH cnrHCNmCNrHTPCnOrHcn in CM o CN rH f-\ •XX*<0»X**X*» flja)a5icrHccjG)icj(tf(D<0f0 tg^EHjfeigEHigigEHigig 4H •H I— I CO o c0 Gl 43 05 CO £ o3 a) Sh o o CN o 05 TP II *4H in TP in m cn m o O CN CN CN CN CO TP TP 05 O \ in in in in in ID ID CD CD CD CD CD CD CD I — 1 O CO \ \ \ \ \ \ \ \ \ \ \ \ (0 05 i — l cn CN CN ID rH CD CD ro CD CD cn TP CO i — 1 ■P 4-> \ \ rH rH CN rH CN CN rH r—1 rH \ rH CN \ o CO o rH \ \ \ \ \ o \ \ O Eh \ Q 1 — l rH r' r-~ CN 00 CN CN CO CO CO i—1 in TP rH ■H | 05 tn CO G •H CO M TO CO P as G a) CT> -342A- Source: U.S. Department of the Interior, Geological Survey, Conservation Division (preliminary manuscript). were relinquished after establishing production, but these accounted for only 1.5 percent of the acreage, 3.7 percent of the bonuses paid, and 0.7 percent of the value of production obtained from all leases issued in 1964 and prior years. 58 / Although the lease relinquishment statistics imply that a greater fraction of offshore than onshore leases are productive, the average cost of offshore leases in recent years has been much higher than onshore leases. By 1973, the average bonus per acre for onshore Federal (public and acquired) lands leased competitively was less than $25, and the average bonus per tract leased was about $7,000 59 / In the same year, the average bonus per acre for OCS leases was about $3,000 and the 58 / U.S. Department of the Interior, Geological Survey, Conservation Division, Relationships Between Bidding and Hydrocarbon Production on the Federal Outer Continental Shelf (through 1970) , (preliminary manuscript). 59 / Derived from U.S. Department of the Interior, Bureau of Land Management data, in U.S. Department of the Interior, Geological Survey, Conservation Division, Federal and Indian Lands Oil and Gas Production , Royalty Income, and Related Statistics (June 1974), p. 10. average bonus per tract was $16,484,000. 60 / We have seen that in exploring for oil and gas, the chance of drilling a dry hole is lower offshore than onshore, and the chance that an entire lease will be unproductive is lower offshore than onshore. Due to the higher productivity of offshore lands, the expected revenues are greater for offshore leases than onshore. On the other hand, offshore costs are much higher than onshore costs. Since the range of possible outcomes (gains or losses) is much wider for offshore than onshore operations, offshore operations are much more riskier. The risks involved in offshore exploration may discourage all but relatively large firms from acquir¬ ing offshore leases. As noted above, a substantial fraction of OCS leases prove to be unproductive. Yet in 1973 the costs of exploring and developing a typical OCS tract were roughly: 60 / Derived from table 6.6. - 344 - Lease costs Exploration wells Development wells ($3,000 per acre) (3 per tract) (12 per tract) $15 million 1.5 million 25 million 61/ Of course, development costs are incurred only if commercial quantities of oil or gas are found. On the other hand, leasing and exploration costs are incurred on both successful and unsuccessful tracts. Leasing costs, therefore, account for a large proportion of total exploration and development expenditures. According to the April 1974 testimony of senior company officials, lease bonus payments accounted for about 60 percent to 70 percent of the cumulative offshore exploration and development costs of three major oil companies. Melvin J. Hill, vice-president of Gulf Oil Corp., stated that Gulf had spent about $885 million on Federal OCS leases since 1953 and $620 million in exploring and developing the leases. 62 / Henry K. Holland, Jr., vice-president of Mobil Oil Corp., testified that Mobil had spent about 61 / Commissioner Rush Moody, Jr. dissenting, Federal Power Commission, Amerada Hess Corp. et al ., Docket No. RI74-15 (October 15, 1973). 62 / U.S. House of Representatives, Select Committee on Small Business, Energy Data Requirements of the Federal Government , ( op. cit .) Part III, P. 306. - 345 - ion of Federal offshore $900 million for the acquisit leases since 1954 and about $400 million in other ex¬ ploration and development costs, 63 / John L. Loftis, Jr., senior vice-president of Exxon Co. U.S.A., testified that since the mid-1940 Exxon had paid $1.3 billion in bonuses for state and Federal offshore leases and had spent more than $900 million on subsequent exploration and development of the tracts purchased. 64 / While lease bonus payments account for a large proportion of total exploration and development expendi¬ tures, they constitute an even larger fraction of outlays which are incurred before it is known whether or not the tract contains commercial quantities of oil or gas. As noted above, leasing costs in 1973 were ten times as high as the cost of drilling exploratory wells. All this concerns the risk involved in acquiring and exploring a single lease. If a firm acquires several leases, however, the risk is greatly reduced, because 63/ Ibid., P- 350. 64/ Ibid., P- 378. - 346 - the gains from some leases can be expected to offset the losses from others. Large petroleum firms must generally conduct more extensive exploration to supply their needs than small firms, so they engage in more risk pooling. They also tend to have easier or less costly access to capital for ambitious exploration programs. Large firms therefore tend to experience a lower average degree of exploration risk. Although smaller firms might secure the same advantage by entering joint ventures, the average costs of offshore leasing and exploration are so high that small companies may not be able to acquire a significant number of promising leases even when they form joint ventures with each other. Onshore, an important means of entry for smaller independent oil companies is through the "farm-out," in which a major oil company turns over some of its leases » to a small independent in return for his promise to drill a wildcat (exploratory) well. The major company usually retains an overriding royalty or some other kind of interest in the lease and saves the cost of drilling the well itself. The independent then raises the - 347 - capital necessary for drilling by securing contributions from companies with adjacent leases (which would benefit by the information gained from the exploratory drilling), speculative investors, and other sources. 65 / In view of the relatively large size of leases, the high bonus payments, and the high cost of drilling wells, we would not expect such arrangements to occur frequently on the Outer Continental Shelf. One study of the composition of the OCS petroleum industry stated: "Because of the high cost of . . . lease bonuses, there are few farm-outs, and only the large independents are able financially to participate in them." 66 / To conclude, it appears that discovery risk has affected the onshore and offshore segments of the petroleum industry in very different ways. Onshore, it has created for the small independent a niche in prospects which the majors do not find desirable but 65 / McKie, op. cit ., p. 567. 66 / U.S. Department of the Interior, Bureau of Mines, Offshore Petroleum Studies , Composition of the Offshore U.S. Petroleum Industry and Estimated Costs of Producing Petroleum in the Gulf of Mexico, Information Circular 8557, by L. Kl Weaver, Hi Fl Pierce, and C. J. Jirik (Washington, D.C.: 1972), p. 3. - 348 - which smaller companies with different risk preferences are willing to try. Small independents have also entered the industry through farm-outs and other "oil deals" with majors. Offshore, due principally to the high cost of leasing and secondarily to the high cost of exploratory drilling, these opportunities for the small independent do not occur as frequently or simply do not exist. 2. Other Risks In addition to discovery risk, petroleum producers face several other types of risk. For one, the costs of exploration and production are uncertain. Fairly reliable estimates of the costs of drilling and producing at various well depths, water depths, and under varying weather conditions can be made. The risks of inflation are similar to those faced by other industries with large fixed capital investments. The biggest cost risk occurs only offshore. This is the possibility of a major oil spill, which can impose large unforeseen costs. One Gulf of Mexico oil spill resulted in direct costs of $30 million. These included only outlays for - 349 - stopping the flow and cleaning up the spilled oil, and not fines or the costs of possible lawsuits for damages. 67 / Since the oil or gas from a reservoir is generally extracted over a period of 15 to 20 years, the sales revenue which will be received is also uncertain. While it does not seem likely that lower-cost substitutes will be developed, the international petroleum cartel could conceivably collapse, making imports available at lower prices. Unless imports are restricted, this would reduce the price at which domestic oil could be sold. As explained in chapter 5, both royalty payments and net profit share systems reduce the risk caused by market price changes, since the lease payment would vary with changes in petroleum prices. Another type of risk is that of sudden changes in Government policies which affect the cost of exploration, development, or production, or the market prices of oil and gas. Government policies will have important 67 / Kash, op. cit ., p. 90. - 350 - effects on the costs and revenues (and therefore profit¬ ability) of petroleum production. An example is the recent elimination of the depletion allowance. The decision on whether or not to deregulate the price of natural gas will also have a pronounced effect, since deregulation would lead to substantially higher natural gas prices. Economic Evaluation of Past and Present Leasing Policies Taking into account the economic and technological conditions of the offshore oil and gas industry, we now analyze the effects of past and present OCS leasing policies on the time pattern of resource development, economic efficiency, competition in the petroleum industry, and the receipt of fair market value for public resources. The Time Pattern of Resource Development The principal effects of Government leasing policies on the time pattern of OCS petroleum resource development stem from decisions regarding the size and - 351 - timing of lease sales. Three historical stages were identified earlier: a period of restricting the rate of leasing, a period of trying to meet regional supply- demand imbalances with a moderate leasing rate, and the current attempt to accelerate leasing rapidly. The Government has never followed a true conserva¬ tion policy. Conservation involves regulating the rate of production (or depletion) of a limited resource so that the net benefit to society (including future generations) is maximized. It is doubtful that this can be done even roughly, since the total stock of the resource is unknown, the value of the resource to future generations is highly uncertain, and the appropriate social rate of time discount is debatable. Instead of seeking a longrun optimum, the Govern¬ ment has adjusted its leasing rate to meet short-term energy needs. In the past, it avoided leasing offshore oil and gas lands at a rate which would have caused petroleum supply to exceed demand at prevailing prices and would therefore have caused prices to fall. Prices were maintained, whether or not they were "correct" in - 352 - the sense of maximizing consumer welfare. Now OCS lands are to be leased at a rapid rate to help meet the perceived energy shortage and reduce the degree of dependence on foreign supply sources. Policies determining the size and timing of lease sales permit firms to develop OCS oil and gas resources, but they do not compel development (although the five- year lease term does tend to ensure that leased tracts are explored quickly). Drilling and production require¬ ments have served as more direct policy instruments to influence timing. When the objective was to prevent a market glut, demand prorationing was extended to OCS lands. Now that the Government's objective has changed toward stimulating production, there are proposals to impose and strictly enforce diligence requirements. It can be argued that inappropriate goals have been pursued; that leasing policy should not be implemented to keep bonus payments high, to maintain petroleum prices, or to promote national security (by increasing domestic production and reducing the need for imports). To achieve the last goal, alternate policies such as - 353 - maintaining emergency reserves might well be more effective. Nevertheless, since we do not know the optimal time path of development, we cannot say whether the policies described above have brought us closer to, or caused us to deviate from, such a path. Economic Efficiency Economic efficiency is affected by Government actions in each of the six major policy areas addressed here. 1. Selection of Lands for Lease. As noted in chapter 3, one requirement for economic efficiency is that the best lands (i.e., those which yield a given amount of oil or gas at the lowest social cost) be developed first. That this has not occurred is for the most part due to uncertainty. No one knows for sure where the best areas are. To some extent, how¬ ever, this shortcoming has been due to lax leasing policies. Leasing activity has tended to be concentrated near fields which have already been leased and explored, primarily because little is known about other areas. - 354 - Much more information on the OCS is necessary if these lands are to be leased in the most efficient % sequence. The Interior Department's new two-tier nomination system is a step in this direction. It calls for pro¬ spective lessees to estimate the relative potentialities of various OCS regions. It also invites the input of environmental groups. State and local governments, and other organizations or persons that may have information relevant to identifying areas which should or should not be leased. The Department is also considering requir¬ ing permittees to disclose the geological and geo¬ physical data obtained during exploration of OCS lands. 2. Size and Timing of Lease Sales. As noted above, we cannot say whether the time path of development has been an efficient one. Whatever time pattern is chosen, however, the schedule of lease sales should be made known well in advance, since industry must plan for the funds, equipment, and personnel needed to evaluate, explore, and develop the - 355 - leases. If prospective lessees have insufficient time to make the necessary arrangements, they will not be able to bid in a manner which reflects their true desire to obtain the leases and their ability to develop the tracts efficiently. Smaller firms have been particularly disadvantaged by the unpredictable timing of lease sales, since their relatively small stocks of capital, equip¬ ment, and undeveloped leases do not confer the flexibility which larger firms possess. The leasing schedule should also be as regular as possible. The wide fluctuations in demand for supporting services and supplies resulting from irregularly spaced lease sales had serious economic repercussions on offshore companies. The smaller or more specialized the company, the more serious were the effects. 68 / 68 / Testimony of Charles D. Matthews, president of the National Ocean Industries Association, U.S. Senate, Committee on Interior and Insular Affairs, Outer Continental Shelf Oil and Gas Development , op. citT^ p^ 694. - 356 - It is questionable whether the plan to lease ten million acres in one year can be successfully ^ accomplished. This is such a large increase that industry may not be able to secure the funds, drilling pipe, drilling rigs, other equipment and personnel necessary for such a large program. 69 / Of course, new supplies of these inputs will eventually come forth, but this takes time. This illustrates the importance of a regularly scheduled leasing program. The Government may also not be able to evaluate the environmental and economic impacts of such a large program in so short a time frame. Given the current five-year lease term, a sharply accelerated rate of leasing could result in the offering of more tracts than industry desires to lease. While highly promising tracts would still receive 69 / See U.S. Senate, An Analysis of the Department of the Interior's Proposed Acceleration of Development of Oil and Gas on the Outer Continental Shelf , staff report of the National Ocean Policy Study pursuant to S. Res. 222 , 94th Cong., 1st sess. , 1975; and Exhibit B of Atlantic Richfield Company, in U.S. House of Representatives, Energy Data Requirements of the Federal Government, op. cit., Part III, p. 431. - 357 - several bids, many of the less promising tracts would receive only one bid or no bid at all. Under these circumstances, much of the bidding is "competitive" in name only. Even though there is no collusion, the bidders know they will face little if any competition. If there is ineffective competition for leases, firms will be able to win leases with bids below the true value of the leases. This results not only in the loss of Government revenue but also in economic inefficiency, for it allows inefficient firms to win leases. When there are only one or two bidders per tract, firms are not forced to bid the full economic rent. 70 / Since they can win without paying the full value of a lease, inefficient firms can still earn a profit. Of course, bids which appear to be noncompetitive could be rejected, but there is no way of knowing the true value of tracts. This would therefore lead to the rejection of some bids which should have been accepted and hence to the misallocation of resources. 70 / This is explained below. - 358 - The market for offshore oil and gas leases appears to be effectively competitive. We have found no evidence of collusion (which would be difficult in view of the large number of bidders). In general, the number of bidders per tract has been large enough to ensure that the pressures of potential competition impinge upon bidders. For all tracts which received bids in the 1954-74 period, there were on average 3.5 bidders per tract. Nevertheless, as shown in table 6.15, the average number of bidders per tract was low for some lease sales. When a large number of tracts is offered, the competitive pressure on bidders is almost certain to decline. 3. Size of Tracts. There is no evidence that the 5,000 or 5,760 acre lease tract size has caused serious inefficiencies in exploring for or producing offshore oil and gas. Nevertheless, it is possible that larger tracts should be offered in unexplored areas in order to increase the chance of a discovery and thereby encourage wildcat drilling. - 359 - TABLE 6.15.--Average Number of Bidders per Tract 1954-74 OCS Oil and Gas Lease Sales Date of sale State Type of sale 1/ No. of tracts bid on Average number of bids per tract 2/ Average bid per acre (dollars 10/13/54 La. G 97 3.4 294.84 11/9/54 Tex. G 19 4.7 347.84 7/12/55 Tex. G 27 1.2 56.34 7/12/55 La. G 94 3.7 395.92 5/26/59 Fla. G 23 1.0 12.92 8/11/59 La. D 28 2.0 2,267.78 2/24/60 Tex. G 48 2.2 148.59 2/24/60 Lei • G 125 2.7 532.07 3/13/62 La. G 212 2.5 186.23 3/16/62 Tex. G 10 1.0 19.37 3/16/62 La. G 200 3.3 288.63 10/9/62 La. D 14 1.9 2,712.79 5/14/63 Cal. G 58 1.2 40.93 4/28/64 La • D 23 3.0 1,846.69 10/1/64 Ore. G 74 2.2 65.27 10/1/64 Wash. G 27 2.1 49.96 3/29/66 La. D 18 3.6 2,534.43 10/18/66 La. D 32 2.5 946.98 12/15/66 Cal. D 1 7.0 10,618.49 6/13/67 La. G 172 4.3 685.17 2/6/68 Cal. G 75 2.2 1,659.56 5/21/68 Tex. G 141 3.9 1,097.16 11/19/68 La. D 21 1.8 5,049.58 1/14/69 La • D 26 1.5 907.90 12/16/69 La • D 16 3.6 1,112.29 7/21/70 La • D 21 2.8 2,190.06 12/15/70 La. G 127 8.2 1,535.70 11/4/71 La. D 13 2.5 2,587.30 9/12/72 La. G 74 4.4 2,017.86 12/19/72 La • G 119 5.8 3,108.04 6/19/73 Tex.-La. G 104 5.3 2,908.40 12/20/73 Miss.-Ala. & Fla. G 89 4.2 3,071.85 3/28/74 La. G 114 3.5 4,967.76 5/29/74 Tex. G 123 2.9 2,604.53 7/30/74 La.-Tex. G 49 1.2 301.64 10/16/74 La. G 149 2.2 2,248.22 10/16/74* La. G 8 7.1 25.00 17 G = general; D = drainage. 2/ Number of bids received divided by number of tracts bid on. Royalty bid sale. Source: Compiled from data in table 6.6. -359A- It should also be noted that several half- and quarter-tracts have been leased. These increase the probability that the tract will not cover the entire reservoir if petroleum is found and more than one lessee will be able to drain the reservoir. The result¬ ing problems are discussed in the chapter on onshore oil and gas leasing. 4. Allocation of Leases Outer Continental Shelf oil and gas lands are leased through competitive sealed bidding. As noted in chapter 5, there are two possible disadvantages to a sealed bid system: (1) bidders may win more or fewer leases than they desire to acquire; and (2) bidders are not able to react to other bids, so they cannot be sure of winning particular leases which they feel they must have. Since there is apparently a strong secondary market in leases (so that companies can sell excess leases or buy desired leases), since lease sales are to be held six times a year, and since there is no absolute necessity for firms to acquire particular leases, these are not serious disadvantages. Because it better ensures that the bidding will be competitive than does an oral auction system, the present system of sealed bidding appears to be the best mechanism for allocating leases. The cash bonus bidding system has only one direct effect on economic efficiency: it adds to risks. Because of this, marginal tracts (those for which the anticipated value of the resource exceeds only modestly the cost of extracting it) will not be leased because firms apply a risk discount to expected gains. Tracts which would be leased at low bonuses in the absence of front-end bonus bid risks will not be leased. This is not a serious problem, however, for the following reasons: (1) Only marginal tracts are affected. Tracts expected to be more productive will be leased despite the higher risk, although the risk will lead to lower bids. (2) There may be a backlog of more productive tracts to be developed, so that marginal tracts should - 361 - not be leased anyway. (3) Since the bids on marginal tracts would be very low, the bonus (and therefore the adverse effect of risk) would be low. (4) The Government would probably reject such low bids anyway. The indirect effects of the bonus bidding system on economic efficiency are potentially more serious, how¬ ever. As shown above, if too many tracts are leased under a bonus bidding system, the lack of sufficient competition may allow inefficient firms to win leases. The bonus bidding system also affects economic efficiency through its impact on competition in the production and sale of oil and gas. This will be discussed below. The present method of lease allocation is not a pure bonus bidding system. It provides for the payment of a 16-2/3 percent royalty and a $3-$10 per acre annual rental. It was demonstrated in chapter 5 that royalty payments lead to the premature abandonment of - 362 - leases and the failure to develop some leases which should be developed. The effects of royalty payments are discussed further in a subsequent section. 5. Term of Leases The five-year term for OCS oil and gas leases creates the potential for substantial inefficiencies. For one, a term of five years may be inadequate where adverse conditions make exploratory drilling usually time consuming because of additional work requirements or limited working seasons. 71 / Secondly, the fixed term may force firms to make inefficient exploration decisions. If information acquired after a tract has been leased indicates that the tract will probably not be very productive, it would be best to devote explora¬ tory effort to more promising areas. Yet the five-year term may induce the firm to drill exploratory wells on the unpromising tract first. Thirdly, the fixed term may force firms to make inefficient production decisions. It is in the firm's interest to produce the oil or gas 71 / Public Land Law Review Commission, op. cit ., pp. 690, 691. - 363 - when it will receive the greatest profit from doing so. Unless there are serious divergences between private and social costs or benefits, this also maximizes the benefit to society. There are cases where companies seem to be "sitting" on leases. This means that firms are holding the petroleum until a future time when they expect prices to be higher. If the Government could determine the optimal time path of consumption, this speculative withholding would be unnecessary. Lands would be leased only when increased production is desirable. Since the Government may be incapable of such fine tuning, however, it may be preferable to allow the market to determine when the resource will be produced, unless it can be shown that the market rate is clearly not the socially optimal rate. As noted in chapter 3, the social rate of time discount may be lower than the private rate. We may therefore want to reduce the rate of resource extraction to provide for future generations. This would call for a strategy the opposite of forcing more rapid development. -364- V Other market imperfections must be recognized. External costs and benefits must be taken into account. It has also been argued that firms delay production from leasing in order to drive prices up. To behave in this way, they must possess individual or collective monopoly power. Or they may choose to wait until natural gas prices are deregulated and sell the gas at higher deregulated prices. The imposition of a fixed lease term or diligence requirements would not get to the root of these problems, and such prescriptions should not be used as policy tools to alleviate problems that call for more fundamental solutions. Because of the inefficiencies it causes and its ineffectiveness in solving the problems it was intended to solve, the five-year term for OCS oil and gas leases should be extended to 10 years or longer or abolished altogether. 6. Drilling and Production Requirements. Strict enforcement of diligence requirements (i.e., requiring lessees to drill wells and commence production within a certain time period) would cause even greater -365- inefficiencies than the five-year lease term. Lease operators are generally in a better position than the Government to determine how a tract should be developed. The timing and pattern of development should not be determined by a preconceived plan, but should evolve as information from exploration reveals the most 1 efficient pattern. Competitive Impact Offshore oil and gas leasing policies have a competitive impact on two distinct markets: the market for oil and gas leases and the market for oil and gas. The level of competition in the market for leases is the primary determinant of whether or not the Government receives the fair market value of leases, so this aspect of competition will be discussed in the section on obtaining fair market value. The level of competition in the market for oil and gas affects the supply and price of energy. This is our immediate concern. -366- An important indicator of the level of competition in an industry is the degree of seller concentration; i.t»., the degree to which relatively few companies account for a large percentage of the industry's output. Seller concentration is typically expressed in terms of 4-firm, 8-firm, and 20-firm concentration ratios, which are the percentages of total industry output controlled by the largest 4, 8, and 20 sellers. The higher the level of concentration, the greater the probability that firms will recognize their mutual interdependence and have an influence over market price. High concentration may lead to the coordination of price and output policies to reap monopoly profits. A previous staff report to the Federal Trade Commission 72 / concluded that the degree of production concentration in the oil and gas industries was rela¬ tively low compared to many other industries, but that 72/ U.S. Federal Trade Commission, Concentration Levels and Trends in the Energy Sector of the U.S. Economy , by Joseph P. Mulholland and Douglas W. Webbink (Washington, D.C.: Government Printing Office, 1974) - 367 - concentration has been steadily increasing in the oil industry since 1955 and in the natural gas industry since 1960. It was suggested that one factor which may have contributed to the rising concentration trend was the growing importance of oil and gas production on the Outer Continental Shelf, where risk and capital require¬ ment barriers to entry are higher than onshore. As an increasing proportion of oil and gas is produced from the OCS, the overall concentration level could be expected to continue its upward trend. 73 / In the present section we will quantify the level of concentration on the Outer Continental Shelf, estimate its impact on the concentration of total U.S. production, and determine to what extent OCS leasing policies have contributed to the concentration trends. We will then evaluate policy alternatives which might reduce the level of OCS concentration. 73 / Ibid ., pp. 44-54 and 63-65. - 368 - 1. Concentration of Winning Bids. Capital requirements and risks are clearly higher offshore than onshore. We might therefore expect smaller firms to be discouraged from entering the industry's offshore segment, both because they are not large and diversified enough to bear the risks involved and because they may find it difficult to raise the necessary capital. Table 6.16 shows that large firms (those with total assets of about $1 billion or more in 1970) 74 / accounted for 70 to 99 percent of the total dollar amount of winning Federal OCS lease bids for each year in which lease sales were held. 75 / 74 / The $1 billion criterion was adjusted for earlier years by applying an index based on the "total assets" estimates in the U.S. Department of the Treasury, Internal Revenue Service, Statistics of Income, Corporation Income Tax Returns . 75 / Although concentration has sometimes been measured in terms of the number of tracts or the acreage held by the largest leaseholders, the dollar amount of winning bids is a better measure for our purposes, since it reflects the capital requirements involved and it also reflects (albeit, imperfectly) the value of the leases. The other measures treat all acreages as having equal value, which is certainly not true. The "number of tracts" measure has the further disadvantage that not all tracts are of equal size. - 369 - TABLE 6.16.—Percent of Total Dollar Amount of Winning Bids Accounted for by: z ml SO CM CO ID O' r- CM SO in in rH m Os o 1 < p • -P so o o O' CO CO o CN I"" r CM a; cn • 0) • CM 00 CO SO so O' rH rH rH CP in (■" as • •H T3 cn o d> < • < rH •h nu CM 1 CM tp • O rH CP O' as CN 00 i—1 CO 00 i^- CM CM • P XI •H u Z CP 00 C' 00 as CP CP 00 00 CP in CP SO Z id X U) id CD as • P Pi c CP C/3 a) p •H G • a o G •H D p IH C G 73 •H C -P 0 -p O CN o r- O' IP C" rH IP r-~ O’ so r~ 73 •H W p 0) • 00 00 r- 00 ID o O' o CP 00 r- r" r'~ • CD Q) a, a) < • • < -P Eh P o G •P u -p rH CO CO rH rH rH r- 00 in O CO o r~ T3 0 rH a a) e p -p rH rH O o t-~ ID o C" CO o cn •H 0 P CP in so 00 CO o CO LO CP r" IH P d-i 0 o CD • • * • • * * * • • * • * • • • p •H 0 m CM cp IP CP r-~ ID CM O' CN SO SO O' id o +J p CP ip ip CP CP CP 00 r-- 00 00 a) a) G G +> id >ittO P G rH | PI cn •H 0 G cm 0) rH o O u cn x P rH u a o p 4-1 id •H id o CD a) XI id -p G ■p SO in o o CP SO o CM O’ r~ rH 00 in o g >i cn cn G cn 00 00 in in 00 * so CP in o rH 00 CP rH ID CP •H rH 6 cn a; -H 0) • • • • • * • • • • • • • • • • CD p e CP £ 00 CP IP 00 t" in O' as 00 in O' CP in CM as r- cn x •H p p p so CP SO r- 00 so CP in CP O' in in P ■p in in •H id a) id a) 0 in • rH cn PI XS G o ID id nu •H cn CN 00 rH d) 0) •H ■p X X rH X cn di C C id Eh •p r- as 00 in O' o ID CP O' CN so o so o CM o p cn id Id rH in CP o CN CO m o O' CO CN rH 00 in as in rH CO cp a) cn x X •H a) • • c o id -P -P id O' cp CO CO o rH o o rH O' ID O' CP CM in rH in •H p > p SO 00 O' in o ID in O' ID so O' SO CM O' CO C H P P id id rH G 0 id d> 0) PI •H p -P 5 -P 5 Ch 0 dJ d) o -P Pm z +j -p cn cn x 1 1 1 *n cn d) d) x • o d) tP CP-H < cn CP rH O O o CM o O O' O CN 00 SO t-> rH 00 so p P S * • • id o CN O' O' CN in CN O' in CP co CO rH r- 00 in id id * z o d) iH r—1 rH O' >H rH rH 1—1 rH rH co r—1 rH W z rH E <3 d) p X X -h a a a Q Q a a a E-I EH IP • • cm P O' LO ID l''* 00 CP O iH CM CO O' in so r- 00 CP o rH CN CO O' W id in in in in in in so ID so so so VD so so SO so r» r- r- [•" Eh d)

i rH iH «H rH i —i iH i—i rH i — \ i —i iH iH •H rH rH rH t—1 rH rH rH rH — 1 |lN |co|2 D - years in which one or more drainage sales were held. Source: Computed from U.S. Department of the Interior, LPR-5 data base; and Bureau of Land Management, Outer Continental Shelf Statistical Summaries. The concentration of winning bids has also been quite high for most years. 76 / Figure 6.1 illustrates that concentration of winning bids has varied considerably from year to year but appears to have fallen to a lower level after 1971. It is evident from table 6.16 that much of the variation in the concentration of winning bids is associated with the occurrence of drainage sales Concentration tends to be higher for years in which drainage sales were held, because such sales typically consist of a limited number of highly valuable tracts. The relatively few firms which acquire these tracts will therefore account for a high share of the winning bid totals. Some of the variation in the winning bid concentra¬ tion is explained by annual variations in the number of leases issued. The lower the number of tracts 76/ Joint bids were allocated among the joint venture partners according to their percentage interest in the joint venture. Although this is probably a reliable indicator of their relative capital contributions, the actual control of each company over exploration, development, production, and marketing decisions cannot readily be determined. - 370 - o to r d •H W 1 O o I H > --T d C- d i 1 > -T d lc\ o> a\ d M o o I yo fij g to M ip fc! fa t) £ Pi to • • d to r/J d d g a) (]J 5 ' 1 •; 4 •d •H )-» a> to 0> a> cvJ tO fO 0) aj nj f—1 CD > >5 >s p X! P d d d o o O Ch r H Tj d d 0) 0) a> P p p fl r ) r ' c 3 ;S n O o 6 o r ■. a O O a) cd oj to to to Hi r O' -d •rH •H •rH ,U p P s , sj| h s e d C -H r! -d £ rH d d 0) P QJ a; a to f\ O c> d aj d d 0) (L) (J) d) Oh rH P-. P. | O 0. 1 1 * -\ o * y o co -37f) A- leased, the greater the concentration of winning bids tends to be. To take an extreme example, if only four tracts are leased, the 4-firm concentration ratio would necessarily be 100, even if every lease were won by a different firm. The drop in winning bid concentration in the 1970's appears to be due to two factors. One is the large number of leases issued. The second is the Federal Power Commission order of 1970 permitting interstate pipeline companies to include in their rate bases advance payments to independent or affiliated producers for purposes of financing lease acquisitions. The FPC order was timed to enable pipelines to participate in the December 15, 1970, lease sale. Gas pipelines and distributors were quick to enter and were major factors in boosting the level of bids. 77/ In November 1971, the FPC decided that it would no longer allow pipelines to include in their rate bases advance payments for exploration and lease acquisition, although advances for other purposes would be allowed through 1972. Rate base treatment for exploration advances (not including lease 77 / The Oil and Gas Journal (November 15, 1971), p. 96. -371- acquisition) was restored at the end of 1972, and a modified advance payment program has been extended through 1975. 78 / The data on billion-dollar corporation and winning bidder concentration tell us little about the identity of successful offshore bidders. As the appendix to this chapter shows, the list of companies with the largest share of winning bids has in fact changed considerably from year to year. Table 6-17 shows that the largest U.S. crude oil producers' share of winning bids on OCS leases was larger than their share of total U.S. crude oil and <, natural gas liquids production until the 1970's, when the opposite was true. This reversal may have been due to the fact that much of the acreage leased in those years was favorable for natural gas, and the FPC policies described above encouraged pipeline companies to enter joint bidding ventures and to finance independent producers. 78 / See Foster Natural Gas Report (Washington, D.C.: Foster Associates, Inc., 1$75), No. 983, pp. 4-8. -372- TABLE 6.17.--The Largest U.S. Crude Oil Producers' Share of the Value of Winning Bids on OCS Leases, Compared with Their Share of Total U.S. Crude Oil and NGL Production, 1960-72 C O - • -p CO 00 CD o 00 00 CN co o r- o 0) CO O 4-> M • d r~ r- 00 CO o ro r~- co rH l—1 CO uo CO 1/3 o •• D 43 CN CN CN CN CN CN CN ro ro ro ro ro ro 03 O 4-1 0 03 rH S3 • 03 C 03 CD •H CO •H 43 ro CO ro CO o CO CN ao 00 00 43 c • C -H • * c D S3 43 CO ro o rH rH CO r- o o CN 1/3 •H •H CN rH CN UO ro rH 1 — 1 CN a) £ 5 rH cd C/3 o a) w o cd u a) d •—I o o M o 1 — 1 CN ro -sr UO CO 00 CO O 1 - 1 CN 2 H 1 — 1 rH r—1 i — 1 rH t — 1 i—l i — l rH rH rH ■ — i i — l * -372A- The enterprises which acquire leases are not necessarily the firms that will develop them or control their output. As noted above, we cannot assume that each member of a joint venture will control the sale of its share of the oil and gas produced from a lease. This is obvious when the joint venture partner is an insurance company, a bank, or a drilling fund (a group of investors). An original lessee may also find that it has won more leases than it can develop and therefore sell some to other firms. Some bidders may be speculators not intending to develop the lease but to sell it later at a higher price. When the full record title to a lease or any portion of a lease's acreage is assigned, the transfer must be approved by the Government. The records avail¬ able indicate that the transfer of leases is a common phenomenon. Some leases have been transferred several times. There are not even any notification require¬ ments, however, for the creation or transfer of working interests, overriding royalty interests, or other payments out of production. 79 / This is a 79/ Public Land Law Review Commission, op. cit., pp. 216, 217. -373- serious deficiency, for it obscures information on the disposition of oil and gas from leases and the extent of total royalty payments. 80 / Table 6.18 provides some indication of how con¬ centrated lease ownership was in 1973. Concentration of lease ownership (i.e., the share of the cumulative dollar value of winning bids on leases owned by the largest 4, 8, and 20 leaseholders) is lower than con¬ centration in individual years when leases were sold. Much of this difference is no doubt due to the fact that the list of the largest winning bidders changes sub¬ stantially from year to year. Some of the difference may also be due to the transfer of leases from one firm to another. To the extent that this is true, the figures in table 6.18 nevertheless reflect only lease title transfers. We do not know the quantity of resources transferred. It could be that the leases were transferred only after most of the oil or gas had been produced, in which case the transfers are given 80 / Royalties, as noted in chapter 5, may have an adverse effect on economic efficiency. -374- \ / TABLE 6.18.—Percent of the Cumulative Dollar Value of Winning Bids on OCS Leases Owned in 1973 by Various Groups of Firms Percent accounted for by: Percent of winning bids 1/ The 4 largest leaseholders 25.9 The 8 largest leaseholders 46.1 The 20 largest leaseholders 76.6 The 4 largest U.S. crude oil producers* * 23.6 The 8 largest U.S. crude oil producers* 38.9 The 20 largest U.S. crude oil producers* 65.1 The 20 major oil companies 2/ 68.6 The 8 major oil companies 2 ~J 38.9 "Large" firms 3/ 69.6 x 1/ Joint bids were allocated according to the percent interest of each firm. 2/ See table 6.26. 3/ Firms with total assets of $1 billion or more in 1972. * As of 1970. Source: Computed from U.S. Department of the Interior, LPR-5 data base. r too much weight. On the other hand, inflation (and especially the recent escalation in oil prices) means that more recent leases are given too much weight relative to older leases acquired at what now appear to have been bargain bonuses. 2. Concentration of Oil and Gas Production on the OCS. Due to both conceptual and data problems, it is impossible to measure precisely the concentration of oil and gas production on the Outer Continental Shelf. Since we do not know exactly how joint ventures work (the arrangements for deciding how much to produce, to whom to sell, and at what price vary from case to case), it is not clear how the output from jointly held leases should be allocated. The allocation can only be made in either of two imperfect ways. For one, it can be assumed that each of the joint venture members has control over output in proportion to its financial interest in the joint venture. If the joint venture is composed of four firms, each with a 25 percent interest, one-fourth of the output from the -375- lease is allocated to each firm. While this may be a valid assumption in most cases, there are some cases in which it obviously is not. For example, sometimes one of the joint venture partners is a non-petroleum company. Such companies let a petroleum company handle production and marketing. Likewise, if a major oil company has a 70 percent interest in the lease and three independents each have a 10 percent interest, it is likely that the major effectively controls all output from the lease. To make matters worse, data are not maintained on the owners of leases at the time production takes place. It is therefore necessary to allocate the production from a lease to the firm(s) that originally won the lease, even though the lease may have been transferred sub¬ sequently. In order to determine the firm(s) owning the lease during its production, it would be necessary to examine thousands of documents. We did examine the records of more than 200 leases accounting for about 97 percent of the crude oil and condensate produced from Federal OCS (Section 8) leases -376- in 1972. Most of the lease title transfers that took place were among small producers. When production from the leases examined was allocated to the firms which held the leases in 1972 (rather than to the original lease¬ holders) , there was no change in the concentration ratios. Since the leases producing in 1972 constitute a large percentage of the total productive OCS leases, it does not appear that lease transfers have had a significant general effect on the concentration of OCS production. The other main method of allocating joint venture outputs is to assume that the lease operator (the firm conducting the actual production operations) controls all the output from the lease. Again, there are cases where this is obviously not valid. In some cases, the operator does not even have an interest in the lease but serves essentially as a contractor. In other cases, production and marketing decisions may be made by committee vote. 81 / 81 / This is sometimes done in unitization agreements. See Stephen L. McDonald, Petroleum Conservation in the United States: An Economic Analysis , (Baltimore published for Resources for the Future by The Johns Hopkins Press, 1971), p. 200. i -377- Interior Department data on lease ownership usually list each different company name as a separate entity, even though one company may be the subsidiary of another. In some cases, the previous name of a company that changed its name may be recorded. In calculating the concentration ratios presented in this chapter, produc¬ tion figures of such interrelated companies were consolidated. Table 6.19 shows that concentration of oil produc¬ tion on the Outer Continental Shelf 82 / has been extremely high but has been falling. In 1974, the four largest oil producers accounted for 43 percent of total Federal OCS production and the eight largest for 61 percent. The 20 largest producers accounted for 89 percent of production. Concentration of oil production from Section 8 leases in 1974 could be described as "moderate to moderately high." 82 / Production from each lease is allocated to the original leaseholder(s). Only production from federally issued (Section 8) leases is included. Data for companies which merged during the 1954-74 period were consolidated for all years (even the years before the merger took place), resulting in an overstatement of concentration in earlier years. The bias was greatest in 1959, when the 4-firm and 8-firm concentration ratios were overstated by 3.6 percentage points. -378- TABLE 6.19.--Crude Oil and Natural Gas Liquids Production 1955-74. Concentration Ratios: Federal OCS and Total U.S. > o CM PC u PC U o CM pc u co u o G p 0) n •H -P • CO •H p CO rH a) *H •H T3 £ p 1-1 £ D CM h* CO CM CD H' co in G G rC *H G 0 (U -P P C -p o G G • u ip O 2 d) Q) 0 (D O d) a CO 1—1 -H -p -p G > rd o c - •H P O o d) co P d) 0 rH £ -P -P CO o CTC oc ryi 00 CTC r- CO r" CM i—1 uo in r- rH ■P P CO rH P p 0 G XJ o O'! G\ CTi (Ti o\ CTi (Ti o\ G\ (Ti cn CC ac 00 00 cp a d) G 0 i—1 co d) PC H p rd 'O Q (D 5 CD 0 P rd O T3 (U P O 5 -P G U dJ 0 0 PU Cm 2 co o r—1 CM CO m co C" 00 o rH CM CO • CO CO CO CO co CO CO CO CD co r- r- [-" c- < i 'i 00 03 H rH rH rH rH rH 1 — l rH i — l 1 — 1 t — 1 i — 1 .H rH rH rH rH id rH P 0 c p G w (D • 0 0 nd CO s , H • 0 D - nd rC fcS G d) rH | fd Cfl cd o id • -P rH d) c 0 w -H 0 (H Cfi rH •H e fd rH -P p P fd o • o G G 3 P Cm fd ■H nd 0 S 03 O •H C ■H p P 0 Ph P (X d) -H -P o -P W •H dn G W) rH d) 0 H -H •H E •p -P -P dJ £• D G x: o 0 Q) -P u o •P O P dn d) rH no d> 0 03X1 d) a g P -p -p id P id o G jC o o d) u W O rH £ X - rH -p w rH P p nd id o id no 0 <4H Or G 0 cn P H • -H rH t/J P (D E dn fd -P -P a 0 P P 01 *H P o d) o P > 4H CM nd and p d) CD c d) C C Cm OS —1 CO o id ■h x: . -p -p • • a d) 3 p u nd d) p o 2 p P CD 0 CH Pm CO rH |+ 379A Table 6.21 presents concentration ratios for cumulative total OCS production when control is attributed to the operator of the lease rather than to the leaseholders. Note that the 4-firm and 8-firm concentration ratios for section 6 leases are signifi¬ cantly lower than those for section 8 leases. 83 / Table 6.22 presents 1972 natural gas concentration ratios for offshore (State and Federal) Louisiana, based on Federal Power Commission data on sales to interstate pipeline companies. Again, these concentration ratios are not perfect measures of production concentration. Sales to interstate pipelines by named firms may include gas they purchased from other producers; and sales made in association with other companies are arbitrarily attributed to the producer "first named" in the associa¬ tion. 84 / - ( 83 / Section 6 leases are those that were issued by the States but which are now administered by the Federal Government. Section 8 leases are those issued by the Federal Government under the OCS Lands Act. 84 / U.S. Federal Power Commission, Sales by Producers of Natural Gas to Interstate Pipeline Companies , 1972 (Washington, D.C.: Government Printing Office, 1974), p. V. -380- I TABLE 6.21.—Concentration of Cumulative Oil and Gas Pro duction to January 1, 1969, form Federal OCS (Section 8) Leases and Validated State (Section 6) Leases in Federal Areas (percent) Percent of production from section 8 leases accounted for by: Oil Ga s 4 largest producers (operators) 73.4 60.0 8 largest producers (operators) 86.2 78.8 20 largest producers (operators) 97.4 95.5 Percent of production from section 6 leases accounted for by: 4 largest producers (operators) 67.6 47.8 8 largest producers (operators) 81.1 66.1 20 largest producers (operators) 98.8 98.9 Source: Computed from data in appendix table 6 A.l -380A- TABLE 6.22.—Concentration of Sales of Offshore Louisiana Gas to Interstate Pipeline Companies, 1972 Percent of total volume of gas sold by: 33.9 60.4 91.6 4 largest sellers 8 largest sellers 20 largest sellers Source: Calculated from data of Federal Power Commission, Sales by Producers of Natural Gas to Interstate Pipeline Companies, 1972 (Washington, D.C.: Government Printing Office, 1974), pp. 277-88. -38 OB- OCS oil and gas production concentration ratios must be put into proper perspective. Under tree market conditions, the Outer Continental Shelf would not constitute a separate market for oil and gas. Offshore oil and gas enters the same market as onshore oil and gas. Therefore, the concentration ratios cannot be used as an indicator of the degree of competition, since the relevant market is broader than the OCS. 85 / The concentration ratios do reveal that relatively few firms account for a large percentage of oil and gas production from Federal OCS leases. This reflects the generally high concentration of winning bids among relatively few companies. Although OCS production concentration does not relate to a separate market, it affects the level of total U.S production concentration and hence it may 85 / Owing to the present system of national gas price regulation, much onshore gas is sold in intrastate markets, where it commands a higher price than in the regulated interstate market. This has resulted in the division of the market into intrastate and inter¬ state segments. All OCS gas sales fall within the interstate sector and are regulated by the Federal Power Commission. The influence of the high OCS gas production concentration on the price of gas therefore depends upon the effectiveness of FPC regulation. -381- influence the vigor of U.S. oil and gas market competi¬ tion. This is especially true, since OCS production will no doubt account for an increasing proportion of total U.S. petroleum production. As an increasing amount of highly concentrated offshore production enters the market, concentration in the overall U.S. market can be expected to rise. This assumes that the largest OCS producers are also the largest onshore producers. If they are not, concentration of total U.S. production could decline as offshore petroleum enters the market. Table 6.23 shows that the largest U.S. producers overall also tend to be the largest OCS producers. For the years 1960 through 1972, the four largest U.S. crude oil producers accounted for from 39 to 64 percent of OCS production, compared to 24- to 34 percent of total U.S. production. The eight largest U.S. producers accounted for 70 to 86 percent of OCS production, compared to 38 to 53 percent of total U.S. production. The 20 largest U.S. producers accounted for 89 to 98 percent of OCS produc¬ tion, compared to 57 to 76 percent of total U.S. production. -382- f TABLE 6.23.—Percent of Federal Section 8 OCS Crude Oil and Natural Gas ILiguids Production Accounted for by the Largest U.S. Crude Oil Producers, 196D-72 x c 0 o p 0 O. to X p • 10 • 0 Tv • d • • CM p D r o TV r* 00 TV o CO r- TV rH rH TO uo VO VO • d cn P Cb P D o O' CO CM ID in CM 00 CM 00 CO CO td X td 0 r- c- r- 00 00 00 00 ID ID ID 0 cn r—1 p rH X U Cb 0 O X X o d X td Cb 0 0 E O 0 e a p to 0 i p o rH CM CO O' uo VD r- 00 TV O rH CM td VO VO VD VD VO VD VD vo VD VO r- r- r- 0 Tv -• X rH i— 1 X X X r —1 X X t— 1 X rH X -382A- As could be expected, given the downward trend in / OCS lease ownership concentration, the largest U.S. producers' shares of OCS production have been declining, while their shares of total U.S. production have been rising. In 1972, the four largest U.S. producers accounted for 47 percent of OCS production, compared to 34 percent of total U.S. production. The eight largest U.S. producers accounted for 63 percent of OCS production, compared to 53 percent of total U.S. production. The 20 largest U.S. producers accounted for 89 percent of 1970 OCS production, compared to 76 percent of total U.S. production. For natural gas production, it is less clear that the rising importance of offshore operations is increasing overall domestic gas production concentration. Table 6.24 shows that although the largest U.S. producers generally accounted for an even larger share of OCS ( production, this was not true for the four largest firms. Increased gas production from the OCS may therefore tend to reduce the 4-firm concentration ratio for total U.S. production. - 383 “ r TABLE 6.24.—Percent of Federal Section 8 OCS Natural Gas Production Accounted for by the Largest U.S. Natural Gas Producers: I960, 1965, 1970, and 1972 c o *rH p o 3 0 P a co 4-1 o CD P id X co p 03 m p CD o p P s 3 05 • CD £ O CD CO O CD in O o CD O P 00 (J> • 3 • • • • 05 P X P D TD r- o ON ON id P p id 0 m CD CD i—i P i—1 t 00 a CD CO X P 1 o 3 < id a CD CD £ 0 05 s o CD 03 0 i—1 P P p CO X 05 • CD p u id CD CO o i—i ON ON o P tJN • 3 • • • • G P D TJ CM rH V£> o O 0 id 0 rH CM rH CM •H 05 i—i P P • • i—1 a O CD cd 3 O ■UP CD 0 3 CD P 0 CO a co p o in o CM id CD CD r- r- CD ON ON ON ON rH 1-1 rH rH -383A- Table 6.25 shows the shares of cumulative oil and gas production from section 6 and section 8 OCS leases accounted for by the major oil companies. Production was allocated to lease operators rather than to owners (i.e., the lessees). Two definitions of "majors" were used to track two different ways of viewing the industry. The first embraces a group of eight oil companies (listed in table 6.26) prominent in all phases of the petroleum industry. These are identical to the eight largest U.S. crude oil producers as of 1970. The tecond i.eludes 20 oil companies (also listed in Table 6-26) which were highly integrated (with significant shares of total U.S. production, refining, transportation, and marketing) and which had total assets of $1 billion or more in 1970. Eighteen of these 20 were among the 20 largest U.S. crude oil producers in 1970. 86 / Except for gas production from section 6 leases, the major oil companies account for a very high share of OCS produc¬ tion. The majors' shares of cumulative OCS production are much higher than their shares of overall 1970 U.S. production. 86 / For a more detailed definition of the 20 majors, see U.S. Federal Trade Commission, Concentration Levels and Trends in the Energy Sector of the U.S. Economy , op. cit ., p. 235-239. - 384 - TALBE 6.25.—Percent of Oil and Gas Production from OCS Leases Accounted for by Major Oil Companies, Cumulat ivo to January 1, 1969, Compared with their Share of Overall 1970 U.S. Production 1/ Federal OCS (Section 8) Leases * * 8 Majors 20 Majors Oil and condensate 81.6 96.6 Natural gas 64.6 92.1 Validated State (Section 6) Leases in Federal Areas * Oil and Natural condensate gas 8 Majors 72.2 30.6 20 Majors 91.8 77.5 1970 U.S. Production Oil and Natural condensate gas 8 Majors 49.1 38.9 20 Majors 68.4 55.1 T7 Production from each lease was allocated to the lease operator. * Actual percentages may be slightly higher, since only majors included in the 20 largest producers were counted. Source: OCS computed from data in appendix table 6 A.l U.S., from Federal Trade Commission, Concentra ¬ tion Trends in the Energy Sector of the U.S. Economy , by Joseph P. Mulholland and Douglas W. Webbink (Washington, D.C.: 1974), pp. 37, 60 and 239. ) -384A- TABLE 6.26. --The Major Oil Companies ( A. The 8 Majors 1. Exxon Corp. 2. Texaco, Inc. 3. Gulf Oil Corp. 4. Shell Oil Co. 5. Standard Oil Co. of California 6. Standard Oil Co. of Indiana 7. Atlantic Richfield Co. 8. Mobil Oil Corp. B. The 20 Majors 1-8 The above eight plus: 9. Union Oil Co. of California 10. Getty Oil Co. 11. Sun Oil Co. 12. Continental Oil Co. 13. Marathon Oil Co. 14. Phillips Petroleum Co. 15. Cities Service Co. 16. Amerada-Hess Corp. 17. Tenneco Corp. 18. Champlin Oil & Refining Co. (Union Pacific Corp.) 19. Standard Oil Co. of Ohio 20. Ashland Oil & Refining Co. I -384B- It is not obvious that the level of offshore production concentration will necessarily have serious adverse consequences for future petroleum industry concentration levels. Even assuming the Federal Energy Administration's highest projection--that OCS will account for 24 percent of total U.S. crude oil production in 1985—and that 1970 onshore and offshore production concentration ratios persist, the 1985 overall four- firm domestic crude oil concentration ratio would be about 38 percent and the eight-firm ratio 55 percent. Barring other circumstances which facilitate tacit or explicit collusion, these ratios connote at worst a loose oligopoly industry structure. However, if the upward trends in overall concentration should continue or accelerate, a tighter oligopoly structure could emerge. 3. Joint Ventures Calculated concentration ratios may, as we have seen, understate the true level of concentration when production from jointly held leases is allocated among the joint venture partners according to their percent -385- interest in the joint venture. Joint ventures may have procompetitive or anticompetitive effects, depending upon the particular members and arrangements concerning disposition of the oil and gas. Joint ventures among independents are likely to increase the level of competition, for they allow smaller firms to spread risks and compete with the more diversified majors. Absent joint ventures, very few independents would be able to participate in the industry's offshore segment. On the other hand, joint ventures among major oil companies are potentially anticompetitive, because they may increase the largest producers' combined market power and place them in a situation which fosters a cooperative rather than a competitive spirit and facilitates collusive behavior. The extent to which this occurs depends upon the existing degree of market power. If the firms possess sufficient collective market power, joint ventures could be used as a vehicle for restraining output in order to raise prices. As we have observed, seller concentration is not very high in domestic petroleum production, but it has been rising, partly due to the high concentration of OCS production. -386- The competitive impact of joint ventures between majors and independents depends upon the operatinq and marketing agreements incident to the joint bidding venture. If each member can use or market in any way its share of the oil and gas produced, competition is increased, since the joint venture helps independents enter, reducing concentration. However, if the major oil companies have effective control over the level and disposition of output, the "independents" would merely be providing capital to enable the majors to control an even greater share of reserves and production. Figure 6.2 shows that the frequency of successful joint bidding ventures has varied from year to year, but their significance has increased in recent years. Joint ventures accounted for 82 percent of the total dollar amount of winning bids in 1972, 92 percent in 1973, and 74 percent in 1974. From table 6.27, it can be seen that joint ventures accounted for 75 percent of the total dollar value of winning bids in the 1968-73 period. Most of the joint ventures were either among the 20 majors or between the 20 majors and independents (non-majors). Joint ventures involving only the eight -387- FIGURE 6.2.— Percent of Dollar Amount of PERCENT 'winning Bids Accounted for ty Joint Ventures 1551-74 ICO-1 ■0 IB 1974 1073 1972 1971 1970 1969 1963 1967 1966 1965* 1964 1063 f 1962 1961* i960 1959 1958* 1957* 1956* 1955 1954 0 ; fin tH ( 1 ) XI CO aJ -p C o> p c: o o b •P 1 CD ro cJ XI ctf -p cd r d LO I ■ 1 . -I o •I I x: -p o 4 g CD 1—1 6 CD -p x: g CO a a; G) • r H 10 CO '.cj CD CO * *H co jw 0) CO . r] aJ X) d CD jo 1—1 c/o 0 G) 1 —1 1—*• O ctf 1 Ej 0 P *H O -P * C/0 CO •H -P aJ x> co o CO o o •=r C\J -387A- to r*» t-> o in CO in in > CN CM T3 h H 1 P X r- to id <7\ X X rH P 1/4 04 X q VO m 00 CO VO o 0 X g • • • • • • iH 3 r~ VO 00 CM P 04 r- z rH m VO i —1 fO X rH - P X P • • • • • • P 04 P — ?—t m T CO f-~ O P 04 0) co to > r-~ > P X •H i 0) P tn -P 00 X 0 P to VO P P u •H i—1 ov 04 H T3 P rH q r- co O' vo m p d e g • • • • • • 04 04 •H p 3 00 co CM CM 00 VO X X cq u 2 CM CM i—i uo 1—1 X P — O x X P oo O T3 •H 1 4J P 0 oo p X (0 t-3 VO 04 P (Tr o O' 04 04 iH rH p p E in P <0 •H >i X td X - CM p >i r—1 P X W W '—■ p i—i p rd to 0) -H X C 0 in in Qm fO i 0 •o E w a, E C/4 uo 1 (0 p fO X •n tO p E • 1 1 <0 0> > to 6 o o 0 P D • x i 04 P - vo td O d 04 d) -p p X O' X X • O 1—1 4-> 04 x X! 0 X P P in W to 4-4 X -P p p 0 •H d 04 0) PI d -P X p d) d CL) E •H CQ P O O p O' O' ID O' in p X 04 p < to X o p P 2 in p >1 04 1—1 P tn to Eh X o 0 O 4-> P O rH p O a, rd g i— l d) P o g E 04 04 E p p P in E p § •H X u d p 0 u s C/4 p in in in in -H in ^ 04 in to X d) d d) d4 04 X 04 in > 04 to O Qj-H p P P p p p E • • x P P P P P o X P 04 04 d x -P -P 04 X TO p X 00 o O' P O' P P P X P to •H p p t0 to p d) d> 04 -P 04 6 O 04 04 p X •H > > > O > 1 TO > X o P in p p X C/4 d) d p 4-> -P -P 73 X 0 i—1 X U •H -H P P P P p p (0 P X P X £ •H •H -rH fO •H X •H O d) o O o 0 0 0 Cm d d d d Eh d -387B majors accounted for 5.4 percent of the value of winning bids, while joint ventures among independents account'd for 13.7 percent. Note that in 1974, joint ventures among the eight majors exclusively rose to 7.1 percent and joint ventures among independents fell to 5.9 percent of the value of winning bids. In the same year, 25.7 percent of the total value of winning bids was attributable to joint ventures including two or more of the eight majors. Tables 6.28 and 6.29 lay out the results of the 1974 OCS oil and gas lease sales in greater detail. Table 6.28 uses the "20 majors" definition of major oil companies to show the importance of the smaller companies (usually referred to as "independents"). Except for the July 30 sale, the independents did not win a substantial share of the value of the leases either through individual bids or through bids made jointly with other independents. Joint ventures between the independents and the 20 majors accounted for a large percentage of the winning bids, but the independents had a small share in most of those bids. Table 6.29 invokes the "eight majors" definition of major oil companies to pinpoint the importance of the largest companies. Except for the October 16 sale, joint -388- * ■*T r- \ in t"- CN rr VO i—1 l~"- o CO • • » • • • • • X rH ro o 00 r-~ X r—1 o G \ CN ID CN ro o 0 o 1—1 X • i—i co MH 0 0 X a) P rH x P 0 to r- O CD in ■—1 ro CD CTi o 0 £ cn \ • • • • • • • • 0 i • • o CN CN ro 00 o i—1 rH o p p cn Q) ro i—1 in ro i—1 o p cn 0 to \ 1—1 CQ P to r- rH p — 0 fd p cn PI P o c p O -H 0 O MH x -H P > r- -ro O r- O ro r- o CN rH o P CO «4-i 0 \ l—l G 0 PI 0 U ro 0 p rH X u • £ G p cn 0) CP p 0 MH 0 >, 04 c P G woe '—■ •H 0 X cn to X a. p 0 X Oi G 0 G u c e p a o 000 * 0 u P O CO * p • CA rH | CO p CO • cn p 1 -rH O • • 0 o X X 0 • 0 1 o CN •H TO ■ H 0 p D P • X G to X X p oo cn Cp tO £ p 0 E O cn cj C P d) CL P X x P o • O X MH 0 x £ CD o to U X P - ID CO 0 Mh CD -P o X — CN p — p G Mh P P x u P CO 0 CO X •H O c W ' Q) X +J G O P 0) X P ■rH O X 0 PI P 0 0 P O X P O CO > P X 0 £ CQ X -P CP 0 0 CP to p O TO X -H o P 0 P 0 P -P 0 £ t>l >1 £ X G P a 0 0 £ 0 0 £ i X X i •rH CO £ C X O to >1 X) rd G cn G rH X X 0 0 to u rH X) O X) CO CO O fO X ■H x U S P (0 cn G CO G CO G -H X X C P c X tO 0 d) 0 0 fO 0 — X X -H X tO -P cn P P P X X •H >i P .. X p CO p CO P CO p CO > p p 0 0 M-l X P P -P P -P CD G i — 1 1 — 1 0 ■H G X G Cj O XI G 0 G O G X •H to a) -h X - H 0 p d) TO d) TO 0 G O p P c c 0 p -p cn > fO > to > fO TO X X to •H TO 0 0 o G G £ E a -H ■rH Qj Pi s cn 0 -rH p 4-> X £ i—1 > > £ rH 1—1 O G G O G O G O to •H •H O to to P G •H CN X CN -h a -p X X o p p 0 X 0 0 0 o G G O 0 * P-t 5 x X X Eh H H Eh Eh * -K ) -388A- TABLE 6.29. —Successful Bonus Bidding Ventures: 1974 Federal OCS Oil and Gas Lease Sales (using 8-company definition of majors) P G 0 O p 0 CU VO VO r-' ro vo oo vo CN \ o 99 11 78 ov 12, 22. o o Q in H p \ 00 CM \ ro r- in vo p CO CM in r-' CO o eg ro P VO . P eg o o • • > XI P P o 0 P 0 X 0 G p G 0 rH P tn 0 G C > G 0 O E rH O 0 0 O !>i P 0 01 p 0 0 G P 01 P O G G P -H P 01 0 xt C p 0 0 P Cj> > -ro G G 0 0 -H P 6 O C G P G •H 00 0 -H o PU 5 G oi 0) •H G a) 0 x p c to 0 •H 00 O G P 0 X — P oi 0 P o tr> to G 0 0 6 d G 0 0 G 0 — P G oi P 0 G -H 0 G > 0 G O •H O 0 G 01 G ■rH XI p G •H O •ro 0 P O Bn 01 P 0 •ro 0 E * * oi G •H X! 0 00 P — G 0 0) G 0 X P •H X P 0 01 > P 0 -ro •H 0 •H G >i >i e X G X X 1 •H G 1—1 0) 01 0 0 G G G c G C •H •H ' X 0 X X •H 01 > P P p 0 •H G 0 0 *H G •H G G G G 0 G G 0 •H •ro ■ H •h a > > E i—( P •H •H O 0 0 G G O P P C G o 0 H H Eh Eh P 0 tr> G •H G c G 0 p CO |g 0 |G G O P 0 G 0 G G O o Ip 0 c oi 0 p G G •H T3 X 0 U >1 p • • P 0 0 1 G 0 0 0 « 2 CO * I* * -388B- ) ventures among the eight majors accounted for a very small fraction of the value of winning bids. Except in the May 29 sale, individual bids by the eight majors accounted for roughly 20 to 25 percent of the dollar amount of winning bids. Joint ventures between the eight majors and other companies accounted for a high percentage of the value of winning bids in all four sales. Table 6.30 analyzes the winning bid patterns of the eight major oil companies in the 1968-73 lease sales. The eight majors accounted for 44.5 percent of the value of winning bids made within that period. There does not appear to be a consistent pattern of winning bids. Standard Oil of California entered almost 30 percent of its winning bids in combination with other majors, while Shell did not win any leases jointly with other majors. Standard Oil of Indiana and Mobil won a large fraction of their leases (in terms of dollars bid) with companies other than the eight majors, while Texaco and Atlantic Richfield won over 50 percent of their leases indi¬ vidually. The largest winning joint venture combinations were between Exxon and Texaco, Mobil and Gulf, and Mobil and Standard Oil of California. I -389- TABLE 6.30.—Winning Bid Patterns of the Eight Major Oil Companies, OCS Oil and Gas Lease Sales, 1968-1973 •a«a* U H -H o a q (-> jz a -s C”> •9 >9 O 00 O' 00 9 r-~ 00 r-t m 00 m oo m sO m oo CVJ sO o CM fM on vO w £ U-J TJ O ^ • N <0 a t3 5 M ) 0 ‘M 3 3 r-» § a o 01 H <0 CM >9 00 *9 as m so sO CM cn >9 CM -389A- 4. Reducing the Anticompetitive Impact of OCS Leasing Policy. The evidence presented above suggests that there are barriers to entry into oil and gas production on the Outer Continental Shelf. The cash bonus bidding system is probably the most important barrier. We saw earlier that bonus bids account for a high proportion of pre¬ discovery expenditures--the riskiest stage of investment and the most difficult to finance. Smaller, relatively undiversified firms appear unable to absorb the risk and capital requirements imposed by the offshore bonus bidding system. An Independent Petroleum Association of America survey of 20 offshore operators found that the principal factors deterring independents from moving into offshore areas are unlimited liability for pollution (insurance is expensive and hard to obtain) and the cash bonus system. 87 / Serious consideration should be given to alternative bidding systems which would reduce the capital require¬ ments and risk barriers to entry. The Interior 87 / "Offshore Entry Baffles Independents," The Oil and Gas Journal (December 6, 1971), p. 44. -390- Department conducted a royalty bidding experiment in its October 16, 1974, lease sale. Ten of the 297 tracts offered were selected at random on each of ten separate geological structures and offered for competitive bidding on the basis of royalty rates. There was a fixed bonus payment of $25 per acre. Two of the tracts received no bids. The winning royalty bids on the eight tracts which were leased ranged from 51.8 percent to 82.2 percent. That is, the winning bidders agreed to pay the Government 51.8 to 82.2 percent of the quantity or value of petroleum eventually produced from the leases. An Interior Department analysis of the experiment's results concluded that royalty bidding might introduce broader industry participation on the OCS, but that there would be a high risk of substantial losses, or at least delay, of oil and gas recovery. Royalty bid tracts attracted an average of 7.1 bidders per tract, compared to an average of 2.2 bidders per tract on bonus bid tracts. Royalty bid tracts also received signif¬ icantly more bids than bonus tracts with comparable -391- Geological Survey pre-sale evaluations. More new bidders (defined as those currently holding no interest in an OCS oil and yas lease and not having bid since the sharp December 1973 increase in oil prices) were attracted to the royalty tracts than to the bonus tracts. Royalty bidding, therefore, appears to have increased the competition for tracts, but it also pushed the bids to levels which may turn out to be too high. Faced with paying a high fraction of any production proceeds to the Government, winning bidders have a diminished incentive to risk their funds on exploration or, if they find oil, to invest in the development of marginal tracts or in high-yield production methods. The result could be the failure to develop leases or the premature abandonment of those which are developed. The Interior Department analysis concluded that with royalty bidding, the potential loss or delay of production would be substantial. 88 / 88 / U.S. Department of the Interior, Office of OCS Program Coordination, An Analysis of the Royalty Bidding Experiment in OCS Sale #36 . -392- As noted in chapter 5, a net profit sharing system would be a more effective system for reducing risk. If properly administered, it would not have the adverse effects on efficiency generated by a royalty bidding system. A study of the feasibility and cost of administering such a system should be undertaken. While a profit-sharing system may prove to be unworkable, there are no apparent adverse effects from a deferred bonus bidding system, and such a system could be easily administered. Deferral of bonus pay¬ ments would reduce the capital requirements barrier to entry. It would also permit greater diversification, which would reduce the risk deterrent. Greater participation in OCS oil and gas produc¬ tion could also be encouraged by increasing the rate of leasing. This would probably result in lower bonus bids, thereby encouraging entry and greater participa¬ tion. However, it is far from clear that an acceleration of leasing is warranted merely to increase competition, especially if it means overshooting the socially desirable rate of production and/or collecting less -393- than the fair market value of leases. Rather, policies which increase the level of competition without adversely affecting other goals should be sought. One such policy would be the prohibition of joint ventures unnecessary for reducing risk or for other justifiable purposes. Joint bidding ventures among major companies would undoubtedly fall into this category. The Interior Department has issued proposed regulations to ban joint bidding ventures between two or more major oil companies. Such firms would still be permitted to bid jointly with non-majors. In the first draft of a proposed amendment to the regulations, companies were to be classified as majors if they held five billion barrels or more of crude oil reserves. A more recent draft would apply the ban to companies producing more than 1.6 million barrels per day of crude oil or liquefied petroleum gas. The ban would therefore apparently apply only to Exxon, Texaco, Gulf, Standard Oil of California, and Mobil. 89 / 89 / Weekly Energy Report , 24 February 1975, p. 5. -394- Since the proposed regulation's purpose is to prohibit joint ventures between companies able to diversify (and therefore reduce risk) without joint bidding, the criterion used to identify such companies should reflect their diversification. Although diversification into such activities as general retailing (e.g., Mobil - Marcor) might con¬ ceivably be considered, a more realistic approach would recognize that for a petroleum company, what is crucial is finding enough oil to replace depleted reserves. A company's degree of diversification in this respect depends upon the number of chances it has to strike oil. The criterion should probably be based, therefore, on the level of reserves or the exploration budget. The level of production also reflects the need to replace reserves, however, and it is much easier to measure. It therefore makes sense to prohibit joint bidding ventures between the largest petroleum producers, but it is not obvious that a cutoff point of 1.6 million barrels per day, which would apparently exclude only five companies, is the appropriate level. -395- Table 6.31 shows that if Exxon, Texaco, Gulf, Mobil, and Standard Oil of Indiana had been prohibited from bidding jointly, 7.2 percent of the number of winning bids made during the 1968-73 period would have been affected. These bids accounted for 21.7 percent of the total dollar amount of winning bids. In 1974, 12.8 per¬ cent of the number of winning bids and 25.1 percent of the value of winning bids would have been affected. If the proposed ban on joint bidding ventures between major oil companies is adopted, bidding patterns would have to change considerably. To maintain their past level of leasing, the majors would have to submit more bids individually, increase their participation in joint ventures with non-majors, or enter a greater number of joint ventures with non-majors. Table 6.31 also indicates that it would not have made much difference if the eight majors, rather than just five companies, had been prohibited from bidding jointly. For the 1968-73 period, bids involving two or more of the five leading firms accounted for 21.7 percent of the total value of winning bids, while bids involving two or more of the eight majors contributed -396- TABLE 6.31.--Winning Joint Bids Involving Two or MOre Major Oil Company Winning Joint Bids Involving Two or More of the Five Leading Companies as a Percent of Total Winning Bids Year Percent of Percent of no. of bids value of bids 1968-73 7.2 21.7 1974 12.8 25.1 Winning Joint Bids Involving Two or More of the Eight Majors as a Percent of Total Winning Bids Year Percent of Percent of no. of bids value of bids 1968-73 16.5 27.1 1974 14.0 25.7 Source: Computed from U.S. Department of the Interior, LPR-5 data base and Outer Continental Shelf Statistical Summaries -396A- 27.1 percent of the total value of winning bids. For 1974, the difference between five-and eight-company dollar bid shares was only six-tenths of a percentage point. Collecting the Fair Market Value of Leases Table 6.32 shows that OCS oil and gas leases directly yielded $18 billion in revenue to the Federal Government during the 1953-74 period. Does this indicate that the fair value of the leases is being collected? If production on a leased tract will be carried out efficiently over time, then collecting the fair market value'for the lease becomes merely a matter of extracting the economic rent. We have seen earlier that restrictions on the rate of leasing, required percentage royalties, lease size restrictions, and market demand prorationing may adversely affect productive efficiency. In this section we ignore these sources of inefficiency to focus on the evidence con¬ cerning the links between bonus bidding and the extraction of economic rent. -397- in rH h* a) r- XI I c/3 ro in rH CTl flj f—1 -P g (L) c •H -P G o u a) > •H -P id P g p p a) u -P P o g o p MH 0) p c d> > d) OS ’V G a3 0) P to d) 'd -P CL) G CO 0) £ - G cn p cu d) (A > (O O 0) O PI I in • to cm 0 ro • Xi C tO to W PI ca < CO p to o D CM uo t —i nr M* oo nr m ro ID o 00 iH cn O CM k «■ k - rH r~ oo O r- CM ro td »—1 vT CTl r- r» r- .-1 • o to ■—1 ro CN VO CO in (0 ■r| -p - •k k - -p O' o r~- ro cn in •^r ID G o E-t i—i CM o ro CT\ CTl d) rH in ■—t ro rH CM in O e O a k k — >i d) H rH m 00 (0 O -p r-t a to — - rH in P -P id O -r| -P \. P 03 <—t! o in P u to ID CM cm in ID in •rH i p rH ro 0 • o r—i p 03 ID in ro r- in •H 0 10 0 -P o CM 00 O CTi ID G •H p 10 o r- CM ID i" r- "H to > 4H in <13 e U -H d) •rl o ID o o -H P 10 P -P h* o m in CM ro -P d) P rH r—i 00 ID CM CM td 10 G P tP td k» k. •H O C *H in CD os CM in rH • • ■p td d) d) k to to > os a ro 0) P G T3 g d) rH P C r-. Q) O 4h 0 m p in in ro in CM G U r- CM r—i rH •H . -p in 00 1—1 o 00 p p d) c g 10 in ID O o 00 in x: g P P 0 P k k -p O P ^ P G 00 CM m CM ro o CJ U3 ^ 4h o o 00 CM CTi E CQ t —1 CM CTi O k >1 in P • • i—t o d) tr o d) p p p td o r- ■ u to p in O in o H* i ro td n ID ID r> r- in d) cr> CT> CTl CTi CTi CTi >• i—t i—i i—1 i—1 rH i—1 rH | rH T3 r-t 0) G -P O U to in to to p -p XI p TJ to G to d) P rH d) -H s o CO P d) o CO 4H to d) in H d) p p p P Co 4-1 -H rH 4-t P to d) p G d) > d) P 4-1 C o •H f0 G CO -H tO CO -P U XI O O 6 O f -397A- Extracting economic rent on any particular lease is a problematic affair. Even if it operates perfectly, bonus biddinq will collect only the appropriately discounted economic rent expected by the company evaluating the property most highly. In any particular instance, this expectation will probably be wrong. Since the true economic rent earned from the tract will not be known until the tract is fully exploited—perhaps 30 or more years in the future--and since there is a great deal of uncertainty attached to any prediction of future events, it is unlikely that rents will be correctly anticipated at the time of a lease sale. If, however, the bidding is competitive, the bidders have a good idea of the probabilities involved, and a large number of tracts are to be let, then the sum of the winning bids on all tracts should approximately equal the sum of the discounted economic rents from all tracts. On some tracts the winning company will have bid more than the economic rent and will end up incurring a loss. On some it will have bid less than the economic rent and will retain more profit than expected. But the gains and losses will tend to balance out over a large number of tracts. - 398 - If there is ineffective competition in bidding or if companies have an incorrect notion of the relevant probabilities or are risk-averse, the total bonuses collected and economic rents will not tend toward equality. If bidding is competitive but winning bidders are overly optimistic, the sum of bonus payments will exceed total economic rents. This should be evidenced by lower than normal profitability in off¬ shore operations. (Recall that economic rent was defined as earnings in excess of the normal profit required to attract companies into the activity.) On the other hand, if bidding is not competitive or if winning bidders are excessively pessimistic or risk- averse, the sum of bonus bids will tend to be less than the tracts' economic rent. Government revenues in this case will be lower than the fair market value of the tracts. Here again, the discrepancy should show up in the profitability of offshore operations. In - 399 - this case, profits should be higher than normal. 90 / Evidence on offshore petroleum operations indicates that they have on average not yielded above-normal profits. To the extent that this is true, it supports an inference that bonus bidding offshore has been effective in capturing the economic rent from the tracts sold. An early study of the rate of return on Outer Continental Shelf investment was done by Walter Mead under the sponsorship of the Public Land Law Review Commission. 91 / Mead examined 189 tracts offered for 90 / The identification of what is a "normal" profit is not as straightforward as it may appear. What is usually used as a figure for normal profits is the average rate of profits for the onshore segment of the petroleum industry or for all extractive industries. If, however, offshore petroleum production is considerably riskier than the reference industries, we would expect the "normal" profit for offshore to be higher than the normal profits for these other industries. This is so because a risk premium is necessary to attract investment. In the absence of a risk premium, firms would employ their resources in a less risky endeavor which offers the same return. 91 / Public Land Law Review Commission, op. cit., pp. 521-527. 400 - sale during 1954 and 1955. At the time of the study, over ten years after the tracts were leased, considerable cost and revenue data concerning these tracts were available, and reasonably accurate projections of future costs and revenues were possible. The results of the examination were summarized as follows: The discounted internal rate of return . . . in the 1954 and 1955 outer continental shelf leases is 7.5 percent before taxes. This is substantially below the historical rate of returns on oil industry investments. The "petroleum refining and related indus¬ tries" earned 13.2 percent return after taxes on stockholder equity in 1955. The profit rate had declined to 11.8 percent by 1965. The return on the outer continental shelf oil and gas lease investments is very low relative to a "normal" return. Even if the estimated 7.5 percent rate of return before taxes is 100 percent wrong and the true before-tax yield is 15 percent, this yield is also below the normal yield in investments in the oil industry. The analysis establishes that bonus bidding for the 1954 and 1955 leases was not too low in the aggregate in terms of subsequent productivity. To the contrary, it shows that industry may have overbid in terms of the resource value. 92 / A later study using a similar methodology was conducted by the Bureau of Land Management. Its results are summarized in table 6.33. After-tax rates 92/ Ibid., p. 526. TABLE 6.33.—Discounted Cash Flow Return Indicated by Current Cost-Revenue Relationships (After Taxes) (Percent) Oil Reservoirs Gas Reservoirs Total Hydrocarbons Gulf of Mexico 5.0-5.4 5.7-6.6 5.6 Onshore South Louisiana 6.4 5.8 6.2 Other continental U.S. 4.3 3.2 4.0 1/ Non-associated gas converted to equivalent barrels of oil on a revenue basis. Source: U.S. Department of the Interior, Bureau of Land Management, The Role of Petroleum and Natural Gas from the Outer Continental Shelf in the National Supply of Petroleum and Natural Gas, Technical Bulletin 5 (May, 1970), p. 169. ) -401A- of return for Gulf of Mexico, onshore southern Louisiana, and other onshore U.S. areas were computed. The results indicate that while OCS profitability may have been somewhat higher than for much of the continental United States, it was lower than profitability for the most geologically similar area, onshore southern Louisiana. 93/ A 1972 study conducted by the Bureau of Mines examined seven randomly selected producing oil fields from the Gulf of Mexico. For each field, a discounted rate of return was computed. Some of the pertinent figures are shown in table 6.34. One thing clearly shown is the failure of bonus bids to capture the economic rent from individual leases. The rates of return on different fields varied from 1.1 percent to 19.5 percent. A model of a "typical" offshore operation which the Bureau of Mines constructed based on the experience observed in the seven sample fields yielded rates of return ranging from 13.7 to 17.2 percent. 93 / For comparison with the statement from the PLLRC report quoted above, U.S. Bureau of the Census, Statistical Abstract of the United States (91st edition, 1970), p. 482, reported the "Petroleum Refining" industries after-tax rate of return on stockholder's equity to be 11.7 percent in 1969. - 402 - I TABLE 6.34.—Summary of Cash Flow Analyses for Seven Gulf of Mexico Oilfields ) ) 0 M-t C P P o P G c G a> in 00 rH nj* CP in P 0 P o O P 0 P CP 00 rH 00 vo vo in o td P 0 rH rH rH rH to u a •H ’—" Q to P 5-1 rH •h td p d> rH rH CM 00 o CO M—1 f—1 0 P ro 00 CO rH •H

p td P 0 ro 00 00 CO rH CP CN 5-j 4 «—1 d) P CP 00 00 vo CP VO CO ty h 04 P • p ■P > o id IN CN CN CN CN CN CN 0 G Q P s •H '— to __„ 5-1 rH rH td p d> CN r- vo in •^r CP CP td P rH d) p VO o in ■'3' r- r- -P CO rH Or P • • • • • • • O O O td rH CN CN rH rH rH rH E-t O Q P to 0 u rH e x Q p G •H Cr» to . G P »H -h P td p d) vo rH CN CN CN o P to rH d) p CP rH CO in in td O r- rH vo td G "H O td rH Or P O' • • • • • • p ^ ao td ■H o a P 1-1 > —’ CP 0 2 •H | 'p a» to G — P o td to o in o ro o o m id h > CO •H p tr > g o o w td O' 13 iO 0 TO < cu — CM CM rH CM o rH rH m H CM rH o 0 u u o •H 0 O 0 M TO 0 W to 0 U) TO •H XI a) u o e o oo 4- > G 0 O 5- 1 0 CU ^•ooMoooihouncionojincoor-i'TOHoj^inoitifNin in to in ^ cn o ^ oo ionnMnoiomiDNOj('imc\ tn x o to 5-1 -P ‘W O ■P C 0 O n (NNfNnOlOCOtN^inODtNO oocMcor-ooooooO'' 3 , ooooooorHoocMrHoo h n (N ^ io tn n V I m-i tn TO O 4-> oo at I—I Gt CM CM r—I CT\ T O tJt I—I m CM t - "- CM rH CM in h I—I I—l(Ni—Irli—I CM iH rH rH rH 0 -P to -p CO • • X • to 0 ) to XI Eh XI • • • • • • f~j • • • X t 0 • • X • • X • <—l • 0 tn • • i—I • i—IX • • • •• 0M0000000005-I000000000000 E-iIXXIXIEhXIXIEhXIUXIOISXIXICJXIUE-'XIXIXIXIXI CD -P fO TO CD vd oo at o inH’LninatatOOOMCMCMOMOOH'H'H'COCDCDr'' CO to ot to O r' \LninininincDlDCOCOCDlDCOCOCOCDCOWcOCOCO\CO\r-\ ooWWWWWWWWco in \cd \at \cd \m 0 rH to CO HOt(N(NtDHTTmOiOffiTOOHHOtHHm\r-(HTHHH \\HHMr((N|(NHHH\H(N\\(N\\HtDN\H\N\ HHhMnconiftintOfOHinTHHHHHtOtNinHHHhH 0 f—( 0 CO OOOOOQOO0OOQOQOOQQQOOOQQQQO TABLE 6.35.--Continued G O ► 0 cn 0 p p O' ui O (d .0 2 (0 rH op cx> cx> P G rH COHOO 0 O P 0 in o h cr> > X) 0 TO « « ^ ^ < a,— (N N m (N • • O' cn G no •H •H -—' > XI -p •H G 0 0 0 O P O in vo oo co 0 O P r-~ r'- P e 0 Cu TO p 0 0 W 2 ro 0 i — 1 0 -P O (0 p -p MH 0 ,—. •P -p TO G G •H 0 0 X5 O oo vo n 'f O P rH rH CN P rH 0 0 Or (X 4-( cn no 0 ■p 0 o cn rl(N CO O • rd cd rH ID rH O 0 p 0 rH i—1 2 -P rH 0 • X -P 0 fd • • • -p id P 2 CO (d u •rH O' O rH o (D O P O •H 0 -p c Q) x: •p MH o •p G a) £ • -p 0 p cn • •> O *H i—I U Q (fl P 0 G 0 0 O' o p li 2 o O CO -410B- In a study for the Public Land Law Review Commission, Walter Mead attempted to take differences in the value of lands into account by dividing the average high bid for each sale by the mean value of the subregion (Louisiana or Texas). The results showed a close positive relationship between the average number of bidders per tract, divided by the mean of the subregion, and the average regionally-adjusted high bid. A multiple regression analysis also indicated that the number of bidders submitting bids for a tract was highly correlated with the amount of the high bid. The greater the number of bidders, the higher the winning bid. 103 / Table 6.36 presents the results of an Interior Department study which adjusts for differences in the tract value by comparing the number of bids per tract with the average ratio of the high bid to the Government's pre-sale tract evaluation. 104 / As the number of bidders per tract increases, the value of 103 / Public Land Law Review Commission, op♦ cit ., p. 493. 104 / For each of the four lease sales, the tracts receiving bids were divided into groups accord¬ ing to the number of bids they received. For each of these categories, the sum of the high bids was divided by the sum of the Government's evaluations. - 411 - TABLE 6.36.--The Ratio of the Average High Bid to US GS Tract Value Estimates in Selected 1973 and 1974 OCS Lease Sales* No. of bids per tract June 1973 December 1973 March 1974 May 1974 1 .50 .60 1.0025 2.42 2 .71 2.41 1.54 2.39 3-4 . 50 1.10 1.90 3.35 5-7 1.14 1.56 2.38 11.94 8 + 1.59 1.13 6.16 4.24 * When the high bid equaled the USGS estimate, the ratio equals 1.00. Source: U.S. Department of the Interior, Office of Minerals Policy Development. -411A- the winning bid increases relative to the value USGS geologists placed on the tract in their pre-sale evaluation. Other things remaining constant, the number of bidders per tract depends on the number of tracts offered for lease. Recall from our discussion of past leasing policies that for long periods of time, the rate of leasing was retarded in order to keep bonuses high or to prevent a glut of the petroleum market. During the 1960's, however, the rate of leasing was accelerated, and there was a drop in the level of bonus bids. A staff report of the National Ocean Policy Study showed that as the acreage offered for lease increased ever the 1973-74 period, there were signifi¬ cant decreases in the proportion of tracts bid on, the average number of bids per tract, and the average bonus per acre leased. 105 / The State of California also experienced disappointing results when it sharply accelerated its offshore oil and gas leasing in 1965 and 1966. Several bids had to be rejected because 105 / U.S. Senate, An Analysis of the Department of Interior's Proposed Acceleration . . . (op. cit .), pp. 17-21. - 412 - there were so few bidders per tract and the bids did not appear to reflect the true value of the tracts. 106 / Leasing at the socially optimal rate and collecting the fair market value of leases are not incompatible goals as long as the optimal rate of leasing is less than or equal to the rate at which industry desires to develop leases. If policymakers decide, however, that leasing should be more rapid than the rate at which industry desires or is able to develop leases, a conflict between the two goals is inevitable, at least under a bonus bidding system. There will be a low average number of bids per tract and a high incidence of one- and two-bid tracts. Under such conditions, it is improbable that the Government will receive the fair market value 106/ Public Land Law Review Commission, op. cit., 12-A-124. - 413 - of leases. 107/ * The degree of competition for leases can be increased either by reducing the number of tracts offered or increasing the number of bidders. The former approach is insupportable. The rate of leasing should be determined according to policymakers' best judgment con¬ cerning the optimal time path of development, not by revenue considerations. On the other hand, the number of bidders could be increased by reducing entry barriers and by prohibiting certain types of joint bidding ventures. 107 / The situation is self-correcting to some degree, but some economic rent is lost. The increased number of tracts offered leads to a lower average number of bidders per tract, which in turn results in lower bonuses. The lower bonuses will encourage new firms to enter and existing firms to bid on more tracts, thereby increasing the average number of bidders per tract and tending to raise the level of bonuses. The increased rate of leasing allows firms to capture some of the economic rent. This is in effect a subsidy which encourages new firms to enter. The increased competition causes bonuses to rise again; but some of the economic rent has been transferred from the Government to the industry in the process. - 414 - To the extent that the cost of acquiring geolog¬ ical and geophysical data discourages smaller companies from participating in OCS lease sales, an Interior Department proposal to require public disclosure of data acquired under exploration permits would provide smaller firms with such information. It would also discourage larger firms from incurring the expense of collecting the data, however. It has also been argued that offering more half- and quarter-tracts would increase participation by smaller companies. This may be true, but it does not increase the competition for tracts. Even if it increased the number of bidders, it would also increase the number of tracts offered. The available evidence suggests that offering smaller tracts does not in fact intensify competition. In the 1968 Texas sale, only 60 percent of the quarter-tracts offered received any bids, and only 12 percent received more than one bid. In the same sale, 95 percent of the full-tracts received bids, and 70 percent received more than one bid. Several of the quarter-tracts, it should be noted, had been selected by BLM for their relatively high i -415- potential. 108 / As we have seen earlier, prohibiting joint ventures among major producers would probably increase the average number of competitors in tract bidding. Limiting joint venture formation might also lessen the ability of firms to learn, through negotiations with prospective partners, which tracts are likely to attract few bids. When they possess such knowledge, bidders are more likely to sub¬ mit bids substantially below their estimate of a tract's value. An analysis of the March and May 1974 OCS lease sales revealed that the majors did pay less for tracts relative to the Government's pre-sale tract value esti¬ mates than did the non-majors. Also, on tracts which received only one bid, the ratios of the major oil companies' bids to the USGS tract value estimates were considerably lower than those of the Sun Oil Company, which almost always bids alone. These patterns are consistent with the hypothesis that the majors can 108/ Public Land Law Review Commission, op. cit., p. 613. -416- r reduce their bids because they know how weak the potential competition is. 109 / If effective competition for leases cannot be assured, the Government is unlikely to receive the fair market value of leases. The bid rejection system will surely not prevent OCS lands from being leased at less than their fair market value. It is evident from Table 6.37 that the pre-sale evaluations on which bid rejections are based have been substantially lower than the winning bids or the average bids. For all leases issued between the May 21, 1968, and July 30, 1974, sales, the sum of pre-sale evaluations was only 20 per¬ cent of the sum of winning bids and 54 percent of the sum of average bids. The average relative standard deviations are all negative, indicating that the pre¬ sale evaluations tend to be lower than the average bid. The average relative standard deviation reflects the probability that bids will be greater than the pre-sale evaluation as follows: 109 / U.S. Department of the Interior, Office of Minerals Policy Development staff paper. The majors were defined as Amoco (Standard Oil of Indiana), Exxon, Gulf, Mobil, Shell, Standard Oil of California, and Texaco. I) -417- , Percent of leases Pre-sale evaluations with pre-sale No. of leases No. of Sum, millions of dollars as percent of: Average Avg. relative evaluation greater tnan: with re-sale Date Type of tracts Winning Average Pre-sa e Winning Average No. of bids standard Winning Average evaluation greater of sale State sale 2/ leased bids bids* evaluations bids bids* per tract deviation bid bid* than winning bid m m cn c ml in I oo mmOoor-i<'g.-<0r-<\0\0v^r'*'i3v000m O(Nir'HNcc r 'vcmon0'iri\c (NrNp» s jco^int'jNCh--—< m • i O' n co io ooCT''X) < 0'0'00'COnncomJo is OOOQOOOOO IOOOO • *tJ X *0 *TJ a u| nj| 3 * -417A- ARSD = -3 : About 99.5% of the bids will be greater -2 : About 97.5% of the bids will be greater -1 : About 83.5% of the bids will be greater 0 : 50 percent of the bids will be greater, 50% lower. Further analysis of table 6.37 suggests two additional observations. First, the deviation between the Govern¬ ment's evaluation of tracts and industry's evaluation of tracts has not decreased over time. Despite the use of more sophisticated evaluation methods, the Govern¬ ment's estimates continue to be too conservative. Second, for 85 of the 888 tracts leased, or about 9.6 percent, the high bids were lower than the tracts' pre¬ sale evaluations, but the bids were accepted. It is again apparent that in the absence of effective competition for leases, there is a conflict between developing resources efficiently and collecting the fair market value of leases. Conservative refusal or bid-rejection prices mean that the Government will fail to collect some economic rent. It is evident from the preceding analysis that if the competition for leases had been less vigorous, the Government would have received substantially less than it actually did receive - 418 - On the other hand, if refusal prices are set too high, oil and gas resources which should be developed will not be leased. If the bid rejection system had to be relied upon more frequently, both Government revenue and economic efficiency would undoubtedly suffer. This demonstrates the importance of maintaining effective competition. Summary In 1973, production from the Outer Continental Shelf accounted for 12 and 14 percent of total U.S. oil and gas production, respectively. By 1985, the OCS may provide as much as 24 percent of domestic oil and 36 percent of the gas produced. The leasing policies of the Federal Government will determine whether or not these resources will be transferred to the private sector at the appropriate rate, whether or not they will be produced efficiently, and whether or not the public will receive the fair market value of its resources. Until the 1970's, OCS oil and gas lease sales were held sporadically, and the size of sales was limited to keep cash bonuses high and to prevent a glut of the - 419 - oil and gas markets. It appears that on the whole the Government received the fair market value of the leases. On the other hand, the high bonus bids created capital requirements and risk barriers to entry. As a result, independent producers were able to win only a small fraction of the leases, generally the less productive tracts, and the production of OCS oil and gas has been highly concentrated. Although concentration ratios have fallen to moderate levels as the Gulf of Mexico has become relatively well explored, they may rise again as frontier areas are developed. Since OCS production is concentrated in the hands of the largest U.S. petroleum companies, concentration of U.S. oil and gas production can be expected to rise as offshore operations supply an increasing share of the market. In January 1974, a decision was made to increase sharply the rate of leasing. This should generate greater opportunities for independents to acquire leases, but unless leasing policies are modified, it may also lead to inefficient resource development and failure to capture the fair market value of leases. Effective competition is central to achieving the broad objectives of Federal leasing policy. Without effective competition in the market for oil and gas, - 420 - resource development is unlikely to be efficient. And without effective competition in the market for oil and gas leases, the receipt of fair market value for the leases cannot be assured. The major defects of the present OCS oil and gas leasing system stem from impediments to competition caused by the cash bonus bidding system and the prev¬ alence of joint ventures. The bonus bidding system has hindered the entry of smaller petroleum companies. While the high costs of drilling and the risks of oil- spill damage also discourage offshore investment, cash bonus requirements impose a substantial but avoidable barrier. Owing to the constrained rate of leasing in the past, the competition for leases has been sufficient despite the limited ability of independents to bid successfully for leases. If the rate of leasing is accelerated, however, greater participation is essential if competition is to be maintained at a level sufficient to ensure the collection of the leases' fair market value. The barriers to entry associated with the cash bonus bidding system have also led to the concentration of offshore oil and gas production in the hands of a relatively few large firms. Since those firms are also the largest onshore producers, this could eventually foster an excessively concentrated U.S. petroleum market structure. Since the OCS is expected to provide less than 25 percent of total U.S. oil production in 1985, however, market concentration will continue to be determined to a large extent by the concentration of onshore production. The cash bonus bidding system has also encouraged the formation of potentially anticompetitive joint ventures. Joint ventures among the major oil companies may further reduce competition, although our leasing study has uncovered no clear evidence that this has actually happened. It has been demonstrated, however, that joint ventures among majors have probably reduced the number of bidders per tract and, by providing information on the bidding intentions of competitors, inhibited the vigor of bidding. In view of the adverse effects of the present bidding system, alternative systems should be seriously considered. Recommendations for improvement will be - 422 - taken up in chapter 12. - A program as important as OCS leasing should be kept under continuous scrutiny to ensure that its objectives are being met. The Interior Department has traditionally been most concerned with collecting the fair market value of leases. Although that is important, more effort should be directed toward seeing that the resources of the Outer Continental Shelf (and indeed all energy resources) are developed in the most efficient manner. While the Department has been appropriately concerned with the impact of leasing policies on the level of competition for oil and gas leases, it has not paid sufficient heed to the effect of leasing policies on competition in the supply of petroleum. As leasing records are currently compiled, it is impossible to determine what companies have effective control over offshore oil and gas reserves. Since OCS production will have an increasing impact on overall oil and gas markets, better information on which firms control that output should be secured. - 423 - In view of the increasing number of proposals to change the existing laws and regulations so that OCS oil and gas development can be regulated more closely, we close the present chapter with one further comment. Offshore oil and gas leasing policy issues are extremely complex, and many of the most important decisions must be based on political rather than economic considera¬ tions. The OCS leasing system has worked relatively well principally because the provisions of the Outer Continental Shelf Lands Act are general enough to leave the Interior Department sufficient flexibility to adapt its policies to changing economic, technological, and political conditions. Any changes in the Act should not impose rigid requirements, but provide for continuing or even enhanced flexibility. - 424 - APPENDIX TO CHAPTER 6 Supporting Data for Tables 6.12, 6.19, and 6.24 TABLE 6A-1.--Quantity and Value of Cumulative Hydrocarbon Production to January 1, 1969, from Federal Leases (Sec. 8) and Validated State Leases (Sec. 6) in D to rd 0 u < -h £ 03 0 Eh V G (d • CO C 44 pa o o CO •H £ < -P pa CO O C •a rd G O o T) -H 00 0 rH U -H 2 ca -h O £ H Eh U ca CO to f—1 o 0 G 0 u d+J o n H G rd -H U X .d CO 4-) rd pa COtl s HOP •H d t C Pm O G 0 0 O 0 G -H U ft H Pm r-H iJ ■H D 0 >1^4 c o rd 4-J a rd e sh O CD U C4 O ro o r-H O in in r- ro ac CM rd 0 i—1 0 • 44 • CO U Eh 0 u 0 • T5 0 0 -- -- u u 0 •—1 pa u 44 4-> rH u 0 • V 0 • • 0 •H 1—1 •H • r d rH 0 • 0 a pa o 0 44 a • c •H CJ 44 • u U o • V 4C u 0 rd o •H 0 0 • G • O -H a 0 u rH rH o 1—1 u u rd T3 rH u > •H u rH • •H rd *H c O 4-1 rd u pa i—1 •H Td O U rH o i—1 H •H CO 4-> rH 0 rH •H O 4-> •H •rH u --- c •H CO u •H O CO G 44 o 0 O 0 0 o •H o 0 --- 0 O u 0 £ • G 0 4-1 rH i—1 u c 0 • 1-1 u Pa -h >i 0 G • > • 0 c o •H rd >4 4-> 4J •H rd 1—1 £ o 0 0 *H g G A X G 0 G 4-> 4-> 1—1 p x: P U 4C u c 0 H 0 0 rd u O 0 •H 4-1 o CO PC o D Eh 2 Eh pa U 0 u < 1—1 CM ro in CD CO ac o rH CM ro rH rH rH rH 1 03 p 1 — 1 *H SC CO co in co n CO O CN O O'! 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Calif. 10.7 Forest Oil Corp. Humble Oil & Refining Co. 4.4 (Std. N.J.) 4.4 Magnolia Petroleum Co. (Mobil) 3.8 Tidewater Associated Oil Co. 3.6 Atlantic Refining Co. 3.6 Union Producing Co. 2.9 Placid Oil Co. 2.3 Peoples Production Co. 2.2 Sinclair Oil Corp. 2.2 Continental Oil Co. 2.1 El Paso Natural Gas Co. Cities Production Corp. 1.6 (Cities Service) 1.4 Roy Lee 0.8 Western Natural Gas Co. 0.5 Texas Co. (Texaco) 0.4 Standard Oil Co. Ind. 0.1 Concentration Ratios: Percent 4-firm 64.0 8-firm 79.9 20-firm 99.9 U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 date base. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 TABLE 6A-3.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1955 Company Percentage of total dollar amount of winning bids California Co. (Std. Oil Calif.) 15.6 Shell Oil Co. 13.2 Superior Oil Co. 7.7 Kerr-McGee Oil Co. 7.0 Tidewater Associated Oil Co. 6.3 Cities Service Co. 6.3 Atlantic Refining Co. 6.3 Continental Oil Co. 6.3 Sinclair Oil Corp. 3.9 Humble Oil & Refining Co. (Std. N.J.) 3.8 Phillips Offshore Oil 3.8 Texas Co. (Texaco) 3.7 Standard Oil Co. Ind. 3.0 Sun Oil Co. 2.6 Pure Oil Co. 2.6 Ohio Oil Co. (Marathon Oil Co.) 2.6 Union Oil Co. Calif. 1.2 Gulf Refining Co. 1.1 Hunt Oil Co. 1.1 Union Producing Co. 1.1 Concentration Ratios: Percent 4-firm 43.5 8-firm 68.9 20-firm 99.5 4 c U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. 1 2 3 4 5 6 7 8 9 10 11 12 TABLE 6A-4.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1959 Company Percentage of total dollar amount of winning bids Shell Oil Co. 42.9 Tennessee Gas Trans. Co. (Genneco) 16.7 Pan Amer. Petroleum Co. (Std. Ind.) 10.3 Texaco, Inc. 10.3 California Co. (Std. Oil (Calif.) 7.5 Gulf Oil Corp. 4.9 Humble Oil & Refining Co. ((Std. N.J.) 3.4 Magnolia Petroleum Co. (Mobil) 1.5 Phillips Petroleum Co. 0.9 Cabot Carbon Corp. 0.9 J. Ray McDermott & Co., Inc. 0.8 Hunt Oil Co. 0.0 Concentration Ratios: Percent 4-firm 80.3 8-firm 97.5 20-firm U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 TABLE 6A-5.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1960 Company Percentage of total dollar amount of winning bids Shell Oil Co. 12.9 Phillips Petroleum Co. 12.2 Socony Mobil Oil Co., Inc. 8.3 Gulf Oil Corp. 7.9 Continental Oil Co. 6.6 Union Producing Co. 6.1 Union Oil Co. Calif. 6.0 Tenn. Gas Trans. Co. (Tenneco) 5.5 Atlantic Refining Co. 5.4 Tidewater Oil Co. 4.9 Cities Service Oil Co. 4.9 Pure Oil Co. 3.6 Texaco, Inc. 2.8 Humble Oil & Refining Co. (Std. N.J.) 2.7 Pan Amer. Petroleum Co. (Std. Ind.) 2.6 Kerr-McGee Oil Co. 2.2 Superior Oil Co. 1.1 M. A. Hanna Co. 0.7 Felmont Oil Co. 0.6 Forest Oil Corp. 0.6 Concentration Ratios: Percent 4-firm 41.4 8-firm 65.5 20-firm 97.6 U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. C 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 TABLE 6A-6.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1962 Company Percentage of total dollar amount of winning bids Gulf Oil Corp. Humble Oil & Refining Co. 16.4 (Std. N.J.) 15.2 Shell Oil Co. 10.1 Tenn. Gas Trans Co. (Tenneco) 8.9 Texaco, Inc. 8.2 Socony Mobil Oil Co., Inc. 7.3 Union Oil Co. Calif. California Oil Co. (Std. Oil 5.1 Calif.) 3.8 Pure Oil Co. 3.5 Forest Oil Corp. 3.4 Ohio Oil Co. (Marathon Oil Co.) 3.1 Pan Amer. Petroleum Co. (Std. Ind.) 2.7 Superior Oil Co. 2.5 Richfield Oil Corp. 1.1 Allied Chemical Co. 1.0 La. Land & Exploration Co. 1.0 Armerada Petroleum Co. 1.0 Signal Oil & Gas Co. 1.0 Miss. River Fuel Corp. 0.9 Murphy Corp. 0.6 Concentration Ratios: Percent 4-firm 50.5 8-firm 74.9 20-firm 96.8 U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base TABLE 6A-7.--Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1963 Rand Company Percentage of total dollar amount of winning bids 1 Shell Oil Co. 2 Humble Oil & Refining Co. (Std. N.J.) 3 Standard Oil Co. Calif. 4 Superior Oil Co. 89.3 5.7 4.6 0.4 Concentration Ratios: Percent 4-firm 100.0 8-firm 20-firm SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 TABLE 6A-8.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1964 Company Percentage of total dollar amount of winning bids California Oil Co. (Std. Oil Calif.) 30.2 Shell Oil Co. 12.2 Phillips Petroleum Co. 9.6 Gulf Oil Corp. 9.4 Pan Amer. Petroleum Co. (Std. Ind.) 9.2 Socony Mobil Oil Co., Inc. 7.8 Union Oil Co. Calif. 7.2 Atlantic Refining Co. 4.0 Superior Oil Co. 3.3 Kerr-McGee Oil Co. 2.2 Southern Natural Gas Co. 2.1 Humble Oil & Refining Co. (Std. N.J.) 1.2 Texaco, Inc. 0.7 Skelly Oil Co. 0.3 Cities Service Oil Co. 0.3 Richfield Oil Corp. 0.3 Concentration Ratios: Percent 4-firm 61.5 8-firm 89.7 20-firm U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 TABLE 6A-9.--Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1966 Company Percentage of total dollar amount of winning bids Fumble Oil & Refining Co. (Std. N.J.) Continental Oil Co. Cities Service Oil Co. Gulf Oil Corp. Skelly Oil Co. Mobil Oil Corp. Chevron Oil Co. (Std. Oil Calif.) Phillips Petroleum Co. Atlantic Richfield Co. Texaco, Inc. Amerada Petroleum Corp. La. Land & Exploration Co. Marathon Oil Co. Union Oil Co. Calif. Signal Oil & Gas Co. Tenneco Oil Co. Pan Amer. Petroleum Co. (Std. Ind.) Southern Natural Gas Co. Shell Oil Co. 24.7 11.5 9.4 8.9 4.6 3.9 2.8 2.6 2.6 2.3 2.0 1.7 1.7 1.5 0.1 0.0 Concentration Ratios: Percent 4-firm 54.4 8-firm 78.9 20-firm U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. ( 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 TABLE 6A-10.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1967 Company Percentage of total dollar amount of winning bids Shell Oil Co. 20.0 Chevron Oil Co. (Std. Oil Calif.) 9.1 Texaco, Inc. 8.7 Cities Service Oil Co. 8.4 Continental Oil Co. 6.1 Atlantic Richfield Co. 4.9 Gulf Oil Corp. 4.2 Skelly Oil Co. 4.1 Tenneco Oil Co. 4.0 Metals Service Co. 3.5 Mobil Oil Corp. 3.0 Humble Oil & Refining Co. (Std. N.J.) 2.5 Sinclair Oil Corp. 1.9 Oil & Gas Futures, Inc. 1.9 Hunt Oil Co. 1.9 Placid Oil Co. 1.9 Amerada Petroleum Corp. 1.7 Kewanee Oil Co. 1.6 Offshore Operators, Inc. 1.5 Marathon Oil Co. 1.4 Concentration Ratios: Percent 4-firm 46.2 8-firm 65.5 20-firm 92.4 U.S. Department of the Interior, Geological Survey, Conservation Divison, LPR-5 data base. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 TABLE 6A-11—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1968 Company Percentage of total dollar amount of winning bids Humble Oil & Refining Co. 26.8 Texaco Inc. 21.2 Union Oil Co. Calif. 9.6 Mobile Oil Corp. 6.6 Gulf Oil Corp. 5.8 Marathon Oil Co. 2.5 Standard Oil Co. Calif. 2.4 Forest Oil Corp. 2.3 Shell Oil Co. 2.1 Amerada Petroleum Corp. 2.0 LA. Land & Exploration Co. 2.0 Superior Oil Co. 1.6 Sun Oil Co. 1.6 Pauley Petroleum Inc. 1.5 Signal Companies 1.3 Standard Oil Co. Ind. 1.3 Sunray DX Oil Co. 1.1 Colorado Oil & Gas Corp. 0.9 Atlantic Richfield Co. 0.8 Ashland Oil, Inc. 0.8 Concentration Ratios: Percent 4-firm 64.1 8-firm 77.1 20-firm 94.1 U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 TABLE 6A-12.—Largest Winning Bidders, OCS Oil & Gas Lease Sales, 1969 Company Percentage of total dollar amount of winning bids Cities Service Oil Co. 32.2 Shell Oil Co. 15.6 Texaco, Inc 12.4 Humble Oil & Refining Co. (Std. N.J.) 9.6 Pan Amer. Petroleum Co. (Std. Ind.) 9.3 Chevron Oil Co. (Std. Oil Calif.) 5.3 Mobile Oil Corp. 5.0 Getty Oil Co. 4.7 Continental Oil Co. 1.8 Tenneco Oil Co. 1.3 Champlin Petroleum Co. 1.0 Texas Gulf Sulphur Co. 0.9 Atlantic Richfield Co. 0.6 Cabot Corp. 0.1 La. Land & Exploration Co. 0.1 Concentration Ratios: Percent 4-firm 69.9 8-firm 94.1 20-firm — U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 TABLE 6A-13.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1970 Company Percentage of total dollar amount of winning bids Tenneco Oil Co. 14.7 Pennzoil Off. Gas Operators, Inc. 12.1 Chevron Oil Co. (Std. Oil Calif.) 8.9 Sun Oil Co. 6.9 Shell Oil Co. 5.1 Forest Oil Corp. 5.0 Mobil Oil Corp. 4.2 Humble Oil & Refining Co. (Std. N.J.) 3.1 Placid Oil Co. 2.7 Transocean Oil, Inc. (Esmark, Inc.) 2.0 Getty Oil Co. 2.0 Allied Chemical Corp. 1.9 Phillips Petroleum Co. 1.9 Superior Oil Co. 1.9 Hunt Oil Co. 1.9 Kewanee Oil Co. 1.8 Pan Amer. Petroleum Co. (Std. Ind.) 1.7 Texas Gulf Sulphur Co. 1.6 Texaco, Inc. 1.6 Southern Natural Gas Co. 1.2 Concentration Ratios: Percent 4-firm 42.5 8-firm 59.9 20-firm 82.3 U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. 2 3 4 5 6 7 8 9 10 11 12 13 TABLE 6A-14.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1971 Percentage of total dollar amount of Company winning bids Atlantic Richfield Co. 33.0 Chevron Oil Co. (Std. Oil Calif.) 14.6 Continental Oil Co. 10.1 Getty Oil Co. 10.1 Cities Service Oil Co. 10.1 Humble Oil & Refining Co. (Std. N.J.) 9.0 Oil & Gas Futures Inc. 5.5 Mobil Oil Corp. 3.3 Texaco, Inc. 1.8 Amerada-Hess Corp. 0.6 La. Land & Exploration Co. 0.6 Marathon Oil Co. 0.6 The Signal Cos. 0.4 Concentration Ratios: Percent 4-firm 68.0 8-firm 95.9 20-firm U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 TABLE 6A-15.--Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1972 Company Percentage of total dollar amount of winning bids Shell Oil Co. 7.7 Gulf Oil Corp. 6.5 Mobil Oil Corp. 6.0 Sun Oil Co. 5.4 Texaco, Inc. 5.0 Chevron Oil Co. (Std. Oil Calif.) 4.5 Humble Oil & Refining Co. (Std. N.J.) 3.6 Columbia Gas Development Corp. 3.6 Energy Ventures, Inc. 3.4 Continental Oil Co. 3.3 Amoco Production Co. (Std. Ind.) 3.3 Pennzoil Co. 3.2 Getty Oil Co. 3.1 Burmah Oil Development Inc. 3.0 La. Land & Exploration Co. 2.8 Mesa Petroleum Co. 2.8 Tenneco Exploration, Ltd. 2.7 Transcontinental Prod. Co. 2.4 Atlantic Richfield Co. 2.3 Cities Service Oil Co. 2.2 Concentration Ratios: Percent 4-firm 25.5 8-firm 42.2 20-firm 76.6 U.S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 data base 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 i TABLE 6A-16.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1973 Company Percentage of total dollar amount of winning bids Exxon Oil Corp. 11.8 Mobil Oil Corp. 11.5 Pennzoil Co. 9.0 Getty Oil Co. 8.8 Gulf Oil Corp. 6.3 Cities Service Oil Co. 4.2 Chevron Oil Co. (Std. Oil Calif.) 4.1 Champlin Petroleum Co. (Union Pacific) 3.9 Standard Oil Co. Indiana 3.4 Union Oil Co. of Calif. 2.8 Sun Oil Co. 2.7 Mesa Petroleum Co. 2.7 Atlantic Richfield Co. 2.7 Tenneco Oil Co. 2.5 Canadian Occidental Petroleum Ltd. 2.4 Burmah Oil Development Inc. 2.1 Columbia Gas Development Corp. 1.8 The N. W. Mutual Life Ins. Co. 1.5 Texaco, Inc. 1.4 Kerr-McGee Corp. 1.2 Concentration Ratios: Percent 4-firm 41.1 8-firm 59.6 20-firm 86.9 .S. Department of the Interior, Geological Survey, Conservation Division, LPR-5 base. TABLE 6A-17.—Largest Winning Bidders, OCS Oil and Gas Lease Sales, 1974 Percentage of total Rank Company dollar winning amount of bids 1 Texaco, Inc. 11.1 2 Mobil Oil Corp. 9.5 3 Amoco Production Co. (Std. Ind.) 7.6 4 Exxon Corp. 7.1 5 Gulf Oil Corp. 6.7 6 Chevron Oil Corp. (Std. Oil Calif.) 5.7 7 Shell Oil Co. 5.5 8 Atlantic Richfield Co. 4.7 9 Sun Oil Co. 4.6 10 Union Oil Co. of Calif. 3.9 11 Tenneco Expl., Ltd. 2.8 12 Pennzoil Off. Gas Ops., Inc. 2.7 13 Marathon Oil Co. 2.1 14 Continental Oil Co. 2.0 15 Amerada-Hess Corp. 1.8 16 Placid Oil Corp. 1.6 17 Getty Oil Co. 1.5 18 Mesa Petroleum Co. 1.4 19 Cities Service Oil Co. 1.2 20 Signal Companies 1.2 Concentration Ratios: Percent 4-firm 35.3 8-firm 57.9 20-firm 87.4 SOURCE: U.S. Department of the Interior, Bureau of Land Management, Outer Continental Shelf Statistical Summaries. TABLE 6A-18.—The 20 Largest Leaseholders and Their Shares of the Total Dollar Amount of Winning Bids On Tracts Under Lease in 1973 Rank Company Share of Total dollar Amount of winning bids 1 Texaco, Inc. 7.5 2 Shell Oil Co. 6.3 3 Getty Oil Co. 6.3 4 Pennzoil Co. 5.8 5 Standard Oil Co. of Calif. 5.5 6 Gulf Oil Corp. 4.9 7 Mobil Oil Corp. 4.9 8 Exxon Corp. 4.9 9 Cities Service Oil Co. 4.1 10 Tenneco Oil Co. 3.9 11 Burmah Oil Development Corp. 3.1 12 Standard Oil Co. Ind. 2.7 13 Union Oil Co. of Calif • 2.5 14 Continental Oil Co. 2.4 15 Hunt Oil Co. 2.3 16 Atlantic Richfield Co. 2.2 17 Marathon Oil Co. 2.0 18 Mesa Petroleum Co. 1.9 19 La. Land & Exploration Co. 1.9 20 Sun Oil Co. 1.5 SOURCE: Computed from U.S. Department of the Interior Geological Survey, Conservation Division, LPR-5 data base. TABLE 6A-19—Rank By Liquid Production from Federal (Section 8) OCS Leases, 1956 Rank Company Production (barrels) Percent of Total 1 Gulf Oil Corp. 371,561 68.6 2 Shell Oil Co. 72,276 13.4 3 Pennzoil Co. 72,177 13.3 4 Phillips Petroleum Co. 17,557 3.2 5 Atlantic Richfield Co. 1,976 0.4 6 Getty Oil Co. 1,846 0.3 7 Continental Oil Co. 1,846 0.3 8 Cities Service Co. 1,846 0.3 9 Standard Oil Co. of Calif. 131 0.0 10 Northern Natural Gas Co. 131 0.0 11 El Paso Natural Gas Co. 99 0.0 12 W. w. Ruck III 31 0.0 Total 541,477 Concentration Ratios: 4-firm 98.5 8-firm 99.8 20-firm — SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-20—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1957 Rank Company Production (barrels) Percent of Total 1 Gulf Oil Corp. 711,107 51.7 2 Forest Oil Corp. 187,507 13.6 3 Shell Oil Co. 148,077 10.8 4 Pennzoil Co. 147,408 10.7 5 Phillips Petroleum Co. 120,451 8.7 6 Exxon Corp. 22,147 1.6 7 Atlantic Richfield Co. 10,372 0.8 8 Getty Oil Co. 9,577 0.7 9 Cities Service Co. 9,577 0.7 10 Continental Oil Co. 9,577 0.7 11 Standard Oil Co. of Calif. 109 0.0 12 Northern Natural Gas Co. 109 0.0 13 El Paso Natural Gas Co. 83 0.0 14 W. W. Ruck III 26 0.0 Total 1,376,127 Concentration Ratios 4-firm 86.8 8-firm 98.6 20-firm — SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-21—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1958 Rank Company Production (barrels) Percent Total 1 Gulf Oil Corp. 1 ,336,739 43.3 2 Phillips Petroleum Co. 450,397 14.6 3 Forest Oil Corp. 236,847 7.7 4 Atlantic Richfield Co. 230,451 7.5 5 Shell Oil Co. 224,299 7.3 6 Pennzoil Co. 120,167 3.9 7 Getty Oil Co. 103,453 3.3 8 Continental Oil Co. 103,453 3.3 9 Cities Service Co. 103,453 3.3 10 Exxon Corp. 60,194 1.9 11 Northern Natural Gas Co. 38,805 1.3 12 Standard Oil Co. of Calif. 38,805 1.3 13 El Paso Natural Gas Co. 29,491 1.0 14 W. W. Ruck III 9,313 0.3 Total 3 ,085,867 Concentration Ratios: 4-firm 73.1 8-firm 90.9 20-firm SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-22—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1959 Rank Company Production (barrels) Percent Total 1 Gulf Oil Co. 1/ 876,191 36.3 2 Shell Oil Co. 794,498 15.4 3 Atlantic Richfield Co. 617,903 12.0 4 Exxon Corp. 387,769 7.4 5 Phillips Petroleum Co. 296,811 5.7 6 Forest Oil Corp. 244,865 4.7 7 Getty Oil Co. 185,902 3.6 8 Cities Service Co. 185,902 3.6 9 Continental Oil Co. 185,902 3.6 10 Pennzoil Co. 125,409 2.4 11 Northern Natural Gas Co. 76,267 1.5 12 Standard Oil Co. of Calif. 76,267 1.5 13 El Paso Natural Gas Co. 57,963 1.1 14 Union Oil Co. of Calif. 36,061 0.7 15 W. W. Ruck III 18,304 0.4 16 Standard Oil Co. of Ohio 2,258 0.0 17 Sun Oil Co. 2,258 0.0 18 Mobil Oil Corp. 256 0.0 19 Standard Oil Co. of Indiana 28 0.0 Total 5, 167,814 Concentration Ratios: 4-firm 71.1 8-firm 88.7 20-firm 100.0 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-23—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1960 Rank Company Production (barrels) Percent Total 1 Gulf Oil Corp. 2,392 .30 32.7 2 Shell Oil Co. 1,624,173 22.2 3 Exxon Corp. 641,374 8.8 4 Atlantic Richfield Co. 557,183 7.6 5 Continental Oil Co. 363,806 5.0 6 Cities Service Co. 363,793 5.0 7 Getty Oil Co. 363,793 5.0 8 Phillips Petroleum Co. 334,090 4.6 9 Pennzoil Co. 211,102 2.9 10 Forest Oil Corp. 149,208 2.0 11 Standard Oil Co. of Calif. 99,687 1.4 12 Northern Natural Gas Co. 77,436 1.0 13 El Paso Natural Gas Co. 58,852 0.8 14 Union Oil Co. of Calif. 56,829 0.8 15 W. W. Ruck III 18,585 0.2 16 Standard Oil Co. of Ohio 2,371 0.0 17 Sun Oil Co. 2,371 0.0 18 Standard Oil Co. of Indiana 916 0.0 19 Mobil Oil Corp. 654 0.0 20 Superior Oil Co. 118 0.0 Total 7,319,171 Concentration Ratios: 4-firm 71.3 8-firm 90.9 20-firm 100.1 SOURCE: U.S. Department of the Interior, Survey, Conservation Division. Geological TABLE 6A-24—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1961 Production Percent of Rank Company (barrels) Total 1 Shell Oil Co. 3,713,179 31.2 2 Gulf Oil Corp. 2,669,225 22.5 3 Standard Oil Co. of Calif. 1,295,534 10.9 4 Phillips Petroleum Co. 819,027 6.9 5 Atlantic Richfield Co. 692,175 5.8 6 Exxon Corp. 691,075 5.8 7 Getty Oil Co. 428,591 3.6 8 Cities Service Co. 428,591 3.6 9 Continental Oil Co. 428,591 3.6 10 Forest Oil Corp. 233,945 2.0 11 Pennzoil Co. 200,946 1.7 12 Northern Natural Gas Co. 73,514 0.6 13 Union Oil Co. of Calif. 56,444 0.5 14 El Paso Natural Gas Co. 55,871 0.5 15 Hunt Industries 48,362 0.4 16 W. W. Ruck III 17,643 0.1 17 Standard Oil Co. of Indiana 14,422 0.1 18 Mobil Oil Corp. 6,270 0.1 19 Standard Oil Co. of Ohio 2,085 0.0 20 Sun Oil Co. 2,085 0.0 Total (All Companies) 11,878,985 Concentration Ratios: 4-firm 71.5 8-firm 90.3 20-firm 99.9 SOURCE U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-25—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1962 Rank Company Production (barrels) Percent Total 1 Shell Oil Co. 4,740,415 26.7 2 Gulf Oil Corp. 3,676,762 20.7 3 Standard Oil Co. of Calif. 2,831,343 16.0 4 Exxon Corp. 967,315 5.5 5 Atlantic Richfield Co. 941,292 5.3 6 Phillips Petroleum Co. 866,748 4.9 7 Continental Oil Co. 635,161 3.6 8 Cities Service Co. 634,581 3.6 9 Getty Oil Co. 634,581 3.6 10 Standard Oil Co. of Indiana 346,543 1.9 11 Texaco, Inc. 327,756 1.8 12 Forest Oil Corp. 237,441 1.3 13 Pennzoil Co. 193,429 1.1 14 Mobil Oil Corp. 173,533 1.0 15 Superior Oil Co. 156,117 0.9 16 Hunt Industries 132,716 0.7 17 Union Oil Co. of Calif. 81.670 0.5 18 Northern Natural Gas Co. 68,437 0.4 19 El Paso Natural Gas Co. 52,012 0.3 20 W. W. Ruck III 16,425 0.1 Total (All Companies) 17,741,287 Concentration Ratios: 4-firm 68.9 8-firm 86.3 20-firm 99.9 SOURCE: U.S. Department of the Interior, Survey, Conservation Division. Geological TABLE 6A-26—Rank By Liquids (Section 8) OCS Production from Leases, 1963 Federal Rank Company Production (barrels) Percent of Total 1 Gul Oil Corp. 6,407,293 24.2 2 Shell Oil Co. 5,936,975 22.4 3 Standard Oil of Calif. 4,009,339 15.2 4 Atlantic Richfield Co. 1,534,847 5.8 5 Exxon Corp. 1,265,523 4.8 6 Continental Oil Co. 1,009,574 3.8 7 Cities Service Co. 1,000,774 3.8 8 Getty Oil Co. 1,000,774 3.8 9 Standard Oil of Indiana 876,943 3.3 10 Texaco, Inc. 821,172 3.1 11 Phillips Petroleum Co. 708,444 2.7 12 Union Oil Co. of Calif. 565,956 2.1 13 Mobil Oil Corp. 455,077 1.7 14 Forest Oil Corp. 211,376 0.8 15 Superior Oil Co. 192,903 0.7 16 Pennzoil Co. 158,910 0.6 17 Hunt Industries 120,646 0.5 18 Northern Natural Gas Co. 66,917 0.3 19 El Paso Natural Gas Co. 50,857 0.2 20 W. W. Ruck III 16,060 0.1 Total (All Companies) 26,444,614 Concentration Ratios: 4-firm 67.6 8-firm 83.8 20-firm 99.9 SOURCE U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-27—Rank By Liquids Petroleum from Federal (Section 8) OCS Leases, 1964 Rank Company Production Percent of (barrels) Total 1 Gulf Oil Corp. 10,428,448 28.5 2 Shell Oil Co. 6,609,312 18.0 3 Standard Oil Co. of Calif. 5,057,491 13.8 4 Exxon Corp. 3,705,054 10.1 5 Union Oil Co. of Calif. 2,146,382 5.9 6 Standard Oil Co. of Indiana 1,559,360 4.2 7 Atlantic Richfield Co. 1,275,737 3.5 8 Texaco, Inc. 1,248,905 3.4 9 Mobil Oil Corp. 774,364 2.1 10 Continental Oil Co. 766,549 2.1 11 Cities Service Co. 765,724 2.1 12 Getty Oil Co. 765,724 2.1 13 Phillips Petroleum Co. 538,639 1.5 14 Superior Oil Co. 253,378 0.7 15 Forest Oil Corp. 214,498 0.6 16 Pennzoil Co. 210,919 0.6 17 Hunt Industries 114,527 0.3 18 Northern Natural Gas Co. 49,285 0.1 19 Hanna Mining Co. 43,343 0.1 20 El Paso Natural Gas Co. 37,457 0.1 Total (All Companies) 36,642,554 Concentration Ratios: 4-firm 70.4 8-firm 87.4 20-firm 99.8 SOURCE: U.S. Department of the Interior, Survey, Conservation Division. Geological TABLE 6A-28—Rank By Liquids Petroleum from Federal (Section 8) OCS Leases, 1965 Rank Company Production (barrels) Percent Total 1 Gulf Oil Corp. 16,697,777 31.7 2 Exxon Corp. 9,574,939 18.2 3 Shell Oil Co. 8,210,826 15.6 4 Standard Oil Co. of Calif. 6,318,562 12.0 5 Union Oil Co. of Calif. 2,709,096 5.2 6 Standard Oil Co. of Indiana 1,773,674 3.4 7 Texaco, Inc. 1,185,948 2.2 8 Mobil Oil Corp. 1,094,650 2.1 9 Atlantic Richfield Co. 1,029,569 1.9 10 Phillips Petroleum Co. 978,701 1.8 11 Getty Oil Co. 625,263 1.2 12 Continental Oil Co. 625,263 1.2 13 Cities Service Co. 625,263 1.2 14 Superior Oil Co. 306,289 0.6 15 Pennzoil Co. 273,969 0.5 16 Forest Oil Corp. 247,523 0.5 17 Hunt Industries 124,571 0.2 18 Hanna Mining Co. 97,750 0.2 19 Consolidated Natural GAs Co 55,378 0.1 20 J. Ray McDermott & Co., Inc 35,921 0.1 Tctal (All Companies) 52,644,558 Concentration Ratios: 4-firm 77.5 8-firm 90.4 20-firm 99.9 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-29—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1966 Rank Company Production (barrels) Percent of Total 1 -L Gulf Oil Corp. 23,995,087 28.3 2 Exxon Corp. 17,706,972 20.8 3 Shell Oil Co. 15,616,038 18.4 4 Standard Oil Co. of Calif . 10,027,240 11.8 5 Union Oil Co. of Calif. 3,487,127 4.1 6 Phillips Petroleum Co. 1,962,996 2.3 7 Tenneco Corp. 1,597,341 1.9 8 Standard Oil Co. of Indiana 1,586,996 1.9 9 Atlantic Richfield Co. 1,501,599 1.8 10 Mobil Oil Corp. 1,279,197 1.5 11 Getty Oil Co. 1,046,934 1.2 12 Cities Service Co. 1,046,934 1.2 13 Continental Oil Co. 1,046,934 1.2 14 Texaco, Inc. 1,014,897 1.2 15 Superior Oil Co. 512,003 0.6 16 Forest Oil Corp. 366,291 0.4 17 Roy Lee 355,137 0.4 18 Pennzoil Co. 288,518 0.3 19 Hunt Industries 232,646 0.3 20 Consolidated Natural Gas Co. 106,628 0.1 Total (All Companies) 84,930,035 Concentration Ratios: 4-firm 79.3 8-firm 89.5 20-firm 99.7 U.S. Department of the Interior, Geological Survey, Conservation Division. SOURCE: TABLE 6A-30—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1967 Rank Company Production Percent of (barrels) Total 1 Gulf Oil Corp. 29,803,220 26.9 2 Shell Oil Co. 21,521,405 19.4 3 Exxon Corp. 20,238,046 18.2 4 Standard Oil Co. of Calif. 12,291,634 11.1 5 Union Oil Co. of Calif. 5,725,970 5.2 6 Phillips Petroleum Co. 3,128,151 2.8 7 Tenneco Corp. 2,733,795 2.5 8 Atlantic Richfield Co. 2,554,696 2.3 9 Continental Oil Co. 1,812,962 1.6 10 Cities Service Co. 1,812,806 1.6 11 Getty Oil Co. 1,812,806 1.6 12 Standard Oil Co. of Indiana 1,716,525 1.5 13 Mobil Oil Corp. 1,548,422 1.4 14 Texaco, Inc. 1,306,898 1.2 15 Superior Oil Co. 742,189 0.7 16 Roy Lee 626,814 0.6 17 Kerr-McGee Corp. 323,963 0.3 18 Pennzoil Co. 304,015 0.3 19 Forest Oil Corp. 197,727 0.2 20 Hunt Industries 190,427 0.2 Total (All Companies) 110,960,745 Concentration Ratios: 4-firm 8-firm 20-firm 75.6 88.4 99.6 U.S. Department of the Interior, Geological Survey, Conservation Division. SOURCE: TABLE 6A-31—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1968 Rank Company Production (barrels) Percent Total 1 Gulf Oil Corp. 33,904,418 23.5 2 Exxon Corp. 27,504,782 19.0 3 Shell Oil Co. 27,128,611 18.8 4 Standard Oil Co. of Calif. 15,488,631 10.7 5 Union Oil Co. of Calif. 7,324,177 5.1 6 Tenneco Corp. 3,917,886 2.7 7 Phillips Petroleum Co. 3,812,238 2.6 8 Atlantic Richfield Co. 3,806,708 2.6 9 Continental Oil Co. 3,452,387 2.4 10 Cities Service Co. 3,410,089 2.4 11 Getty Oil Co. 2,647,911 1.8 12 Mobil Oil Corp. 2,621,069 1.8 13 Standard Oil Co. of Indiana l 1,756,512 1.2 14 Texaco, Inc. 1,608,912 1.1 15 Kerr-McGee Corp. 1,240,980 0.9 16 Superior Oil Co. 954,249 0.7 17 Roy Lee 645,743 0.5 18 Hunt Industries 544,543 0.4 19 Felmont Oil Corp. 380,437 0.3 20 Cabot Corp. 331,496 0.2 Total (All Companies) 144,434,980 Concentration Ratios: 4-firm 8-firm 20-firm 72.0 85.0 98.7 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-32—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1969 Rank Company Production (barrels) Percent Total 1 Gulf Oil Corp. 36,558,720 19.6 2 Exxon Corp. 34,182,055 18.4 3 Shell Oil Co. 31,381,783 16.9 4 Standard Oil Co. of Calif. 19,999,349 10.7 5 Union Oil Co. of Calif. 9,899,637 5.3 6 Continental Oil Co. 6,387,731 3.4 7 Cities Service Co. 6,304,210 3.4 8 Atlantic Richfield Co. 4,864,975 2.6 9 Phillips Petroleum Co. 4,721,363 2.5 10 Tenneco Corp. 4,383,640 2.4 11 Getty Oil Co. 3,793,074 2.0 12 Mobil Oil Corp. 3,775,849 2.0 13 Kerr-McGee Corp. 3,711,365 2.0 14 Texaco, Inc. 2,345,961 1.3 15 Hunt Industries 2,099,840 1.1 16 Standard Oil Co. of Indiana 1,889,954 1.0 17 Champlin Petroleum (Union Pacific Corp.) 1,684,789 0.9 18 Superior Oil Co. 1,151,565 0.6 19 Felmont Oil Corp. 1,143,518 0.6 20 Cabot Corp. 999,669 0.5 Total (All Companies) 186,059,376 Concentration Ratios: 4-firm 65.6 8-firm 80.4 20-firm 97.2 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-33—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1970 Rank Company Production Percent of (barrels) Total 1 Shell Oil Co. 44,825,982 19.1 2 Gulf Oil Corp. 40,911,596 17.4 3 Exxon Corp. 33,821,962 14.4 4 Standard Oil Co. of Calif. 21,799,463 9.3 5 Union Oil Co. of Calif. 12,799,463 9.3 6 Tenneco Corp. 7,109,619 3.0 7 Mobil Oil Corp. 6,802,576 2.9 8 Continental Oil Co. 6,313,045 2.7 9 Cities Service Co. 6,242,615 2.7 10 Atlantic Richfield Co. 5,307,919 2.3 11 Getty Oil Co. 5,148,418 2.2 12 Kerr-McGee Corp. 4,583,202 2.0 13 Phillips Petroleum Co. 4,297,500 1.8 14 Texaco, Inc. 3,937,204 1.7 15 Amerada Hess Corp. 3,927,572 1.7 16 Hunt Industries 3,324,217 1.4 17 Champlin Petroleum (Union Pacific Corp.) 2,774,113 1.2 18 Standard Oil Co. of Indiana 2,661,552 1.1 19 Superior Oil Co. 2,388,277 1.0 20 Marathon Oil Co. 1,746,622 0.7 Total (All Companies) 234,631,010 Concentration Ratios: 4-firm 60.2 8-firm 74.3 20-firm 94.1 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-34—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1971 Rank Company Production (barrels) Percent Total 1 Shell Oil Co. 61,682,003 20.1 2 Gulf Oil Corp. 38,241,457 12.5 3 Exxon Corp. 37,239,329 12.1 4 Standard Oil Co. of Calif. 25,771,968 8.4 5 Union oil Co. of Calif. 15,316,151 5.0 6 Mobil Oil Corp. 11,530,211 3.7 7 Texaco, Inc. 9,847,468 3.2 8 Amerada Hess Corp. 8,914,044 2.9 9 Tenneco Corp. 8,457,626 2.8 10 Kerr-McGee Corp. 7,277,478 2.4 11 Getty Oil Co. 6,989,858 2.3 12 Continental Oil Co. 6,564,586 2.1 13 Cities Service Co. 6,496,164 2.1 14 Marathon Oil Co. 5,960,492 1.9 15 Atlantic Richfield Co. 5,933,242 1.9 16 Hunt Industries 5,650,246 1.8 17 Sun Oil Co. 5,124,481 1.7 18 Superior Oil Co. 4,926,003 1.6 19 Champlin Petroleum (Union Pacific Corp.) 4,923,319 1.6 20 La. Land & Exploration Co. 4,050,604 1.3 Total (All Companies) 306,968,842 Concentration Ratios: 4-firm 53.1 8-firm 67.9 2 0-firm 91.4 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-35--Rank By Liquids Production from Federal (Section 8) OCS Leases, 1972 Rank Company Production Percent of (barrels) Totals 1 Shell Oil Co. 65,657,551 21.4 2 Exxon Corp. 35,415,493 11.5 3 Gulf Oil Corp. 33,081,974 10.8 4 Standard Oil Co. of Calif. 26,254,307 8.5 5 Union Oil Co. of Calif. 14,716,283 4.8 6 Mobil Oil Corp. 11,204,720 3.6 7 Texaco, Inc. 9,485,194 3.1 8 Tenneco Corp. 9,148,600 3.0 9 Kerr-McGee Corp. 8,732,603 2.8 10 Atlantic Richfield Co. 8,473,333 2.8 11 Getty Oil Co. 8,307,218 2.7 12 Cities Service Co. 7,801,756 2.5 13 Amerada Hess Corp. 7,777,511 2.5 14 Continental Oil Co. 7,440,276 2.4 15 Sun Oil Co. 5,737,234 1.9 16 Marathon Oil Co. 5,247,587 1.7 17 Standard Oil Co. of Indiana 4,697,754 1.5 18 Hunt Industries 4,251,621 1.4 19 La. Land & Exploration Co. 3,992,750 1.3 20 Superior Oil Co. 3,905,119 1.3 Total (All Companies) 307,396,003 Concentration Ratios: 4-firm 52.2 8-firm 66.7 20-firm 91.5 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-36—Rank By Liquids Production from Federal (Section 8) OCS Leases, 1973 Rank Company Production Percent of (barrels) Totals 1 Shell Oil Co. 69,431,962 22.7 2 Guld Oil Corp. 27,503,560 9.0 3 Exxon Corp. 26,742,961 8.8 4 Standard Oil Co. of Calif 23,768,154 7.8 5 Atlantic Richfield Co. 13,923,249 4.5 6 . Union Oil Co. of Calif. 12,349,988 4.0 7 Mobil Oil Corp. 11,809,345 3.9 8 Tenneco Corp. 10,400,624 3.4 9 Texaco, Inc. 10,180,297 3.3 10 Cities Service Co. 9,133,670 3.0 11 Getty Oil Co. 8,332,139 2.7 12 Continental Oil Co. 7,838,649 2.6 13 Amerada Hess Corp. 7,137,187 2.3 14 Kerr-McGee Corp. 7,119,873 2.3 15 Stnadard Oil Co. of Indiana 6,635,393 2.2 16 Marathon Oil Co. 5,278,328 1.7 17 La Land & Exploration Co. 4,582,474 1.5 18 Hunt Industries 4,412,633 1.4 19 Pennzoil Co. 3,399,150 1.1 20 Sun Oil Co. 3,399,150 1.1 Total (All Companies) 305,474,434 Concentration Ratios: 4-firm 48.3 8-firm 64.1 20-firm 89.5 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-37--Rank By Liquids Production from Federal (Section 8) OCS Leases, 1974 Rank Company Production Percent of (barrels) Total 1 Shell Oil Co. 60,139,094 19.9 2 Exxon Corp. 25,495,086 8.4 3 Gulk Oil Corp. 24,490,976 8.1 4 Standard Oil Co. of Calif. 20,975,889 7.0 5 Tenneco Corp. 13,931,689 4.6 6 Atlantic Richfield Co. 12,840,203 4.3 7 Union Oil Co. of Calif. 12,581,471 4.2 8 Mobil Oil Corp. 12,318,625 4.1 9 Cities Service Co. 10,262,365 3.4 10 Texaco, Inc. 9,925,524 3.3 11 Continental Oil Co. 8,830,073 2.9 12 Getty Oil Co. 8,380,927 2.8 13 Standard Oil Co. of Indiana 7,866,205 2.6 14 Amerada Hess Corp. 6,929,395 2.3 15 Pennzoil Co. 6,533,932 2.2 16 Kerr-McGee Corp. 5,997,843 2.0 17 Marathon Oil Co. 5,851,490 1.9 18 Southern Natural Resources, Inc. 4,988,861 1.6 19 Hunt Industries 4,847,896 1.6 20 La. Land & Exploration Co. 4,451,876 1.5 Total (All Companies) 301,796,114 Concentration Ratios: 4-firm 43.4 8-firm 60.6 20-firm 88.7 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-38—Rank By Gas Production from Federal (Section 8) OCS Leases, 1959 Rank Company Production (thous. cu.ft. Percent of ) Total 1 Union Oil Co. of Calif. 8,242,232 56.7 2 Shell Oil Co. 3,319,775 22.8 3 Standard Oil Co. of Ohio 1,458,088 10.0 4 Sun Oil Co. 1,458,088 10.0 5 Phillips Petroleum Co. 60,741 0.4 Total 14,538,924 Concentration Ratios: Percent 4 -firm 99.5 8-firm - 20-firm — SOURCE: U. S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-39--Rank By Gas Production from Federal (Section 8) OCS Leases, 1960 Rank Company Production (thous. cu. ft. Percent ) Total 1 Shell Oil Co. 15,784,389 38.2 2 Union Oil Co. of Calif. 14,985,124 36.3 3 Phillips Petroleum Co. 4,979,353 12.1 4 Gulf Oil Corp. 2,985,540 7.2 5 Standard Oil Co. of Ohio 1,228,524 3.0 6 Sun Oil Co. 1,228,524 3.0 7 Standard Oil Co. of Indiana 32,504 0.1 8 Standard Oil Co. of Calif. 21,053 0.1 9 Atlantic Richfield Co. 15,384 0.0 10 Getty Oil Co. 15,384 0.0 11 Cities Service Co. 15,384 0.0 12 Continental Oil Co. 15,384 0.0 13 Pennzoil Co. 1,176 0.0 Total 41,307,723 Concentration Ratios: Percent 4-firm 93.8 8-firm 99.9 20-firm — SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-40—Rank By Gas Production from Federal (Section 8) OCS Leases, 1961 Rank Company Production (thous. cu. ft Percent .) Total 1 Shell Oil Co. 17,844,337 32.3 2 Union Oil Co. of Calif. 17,707,996 32.0 3 Phillips Petroleum Co. 8,459,703 15.3 4 Gulf Oil Corp. 7,363,207 13.3 5 Standard Oil Co. of Ohio 1,516,201 2.7 6 Sun Oil Co. 1,516,201 2.7 7 Standard Oil Co. of Indiana 517,048 0.9 8 Standard Oil Co. of Calif. 223,784 0.4 9 Pennzoil Co. 90,805 0.2 10 Tenneco Corp. 41,281 0.1 Total 55,280,563 Concentration Ratios: Percent 4-firm 92.9 8-firm 99.6 20-firm t r SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-41—Rank By Gas Production from Federal (Section 8) OCS Leases, 1962 Rank Company Production Percent of (thous. cu. ft.) Total 1 Union Oil Co. of Calif. 24,397,592 28.8 2 Shell Oil Co. 23,528,194 23.0 3 Gulf Oil Corp. 10,933,921 10.7 4 Phillips Petroleum Co. 10,486,851 10.2 5 Superior Oil Co. 5,889,097 5.7 6 Mobil Oil Corp. 5,036,055 4.9 7 Getty Oil Co. 3,388,366 3.3 8 Cities Service Co. 3,388,366 3.3 9 Continental Oil Co. 3,388,366 3.3 10 Atlantic Richfield Co. 3,388,366 3.3 11 Standard Oil Co. of Ohio 3,033,145 3.0 12 Sun Oil Co. 3,033,145 3.0 13 Standard Oil Co. of Indiana 1,004,534 1.0 14 J.Ray McDermott & Co., Inc 546,697 0.5 15 Standard Oil Co. of Calif. 468,624 0.4 16 Exxon Corp. 362,983 0.4 17 Tenneco Corp. 125,970 0.1 18 Pennzoil Co. 95,745 0.1 Total 102,496,017 Concentration Ratios: Percent 4-firm 67.7 8-firm 84.9 20-firm 100.0 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-42—Rank By Gas Production from Federal (Section 8) OCS Leases, 1963 Rank Production Company (thous. cu. ft Percent of .) Total 1 Shell Oil Co. 32,149,834 22.9 2 Union Oil Co. of Calif. 24,586,390 17.5 3 Gulf Oil Corp. 16,728,836 11.9 4 Mobil Oil Corp. 11,919,356 8.5 5 Getty Oil Co. 7,760,841 5.5 6 Continental Oil Co. 7,760,841 5.5 7 Cities Service Co. 7,760,841 5.5 8 Atlantic Richfield Co. 7,760,841 5.5 9 Superior Oil Co. 6,487,327 4.6 10 Phillips Petroleum Co. 6,267,995 4.5 11 Standard Oil Co. of Ohio 2,966,896 2.1 12 Sun Oil Co. 2,966,896 2.1 13 Exxon Corp. 1,456,250 1.0 14 Standard Oil Co. of Indiana 1,444,708 1.0 15 Forest Oil Corp. 972,377 0.7 16 Standard Oil Co. of Calif. 795,289 0.6 17 J.Ray McDermott & Co., Inc 478,759 0.3 18 Tenneco Corp. 212,853 0.2 19 Pennzoil Co. 125,189 0.1 Total 140,602,319 Concentration Ratios: Percent 4-firm 60.8 8-firm 82.8 2 0-firm 100.0 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-43--Rank By Gas Production from Federal (Section 8) OCS Leases, 1964 Rank Company Production Percent of (thous. cu. ft.) Total 1 Shell Oil Co. 33,224,567 18.6 2 Union Oil Co. of Calif. 32,997,739 18.4 3 Gulf Oil Corp. 30,200,099 16.9 4 Mobil Oil Corp. 22,710,536 12.7 5 Getty Oil Co. 7,527,725 4.2 6 Cities Service Co. 7,527,725 4.2 7 Continental Oil Co. 7,527,725 4.2 8 Atlantic Richfield Co. 7,527,725 4.2 9 Superior Oil Co. 7,172,483 4.0 10 Exxon Corp. 4,956,205 2.8 11 Phillips Petroleum Co. 4,732,716 2.6 12 Standard Oil Co. of Ohio 3,866,303 2.2 13 Sun Oil Co. 3,866,303 2.2 14 Forest Oil Corp. 1,837,006 1.0 15 Standard Oil Co. of Indiana 1,488,808 0.8 16 Standard Oil Co. of Calif. 918,217 0.5 17 J.Ray McDermott & Co., Inc 400,850 0.2 18 Tenneco Corp. 300,406 0.2 19 Pennzoil Co. 230,820 0.1 20 Hanna Mining Co. 419 0.0 Total (All Companies) 179,014,504 Concentration Ratios: Percent 4-firm 66.6 8-firm 83.4 20-firm 100.0 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-44--Rank By Gas Production from Federal (Section 8) OCS Leases, 1965 Rank Company Production Percent of (thous. cu. ft.) Total 1 Gulf Oil Corp. 38,919,480 20.6 2 Shell Oil Co. 28,570,753 15.1 3 Union Oil Co. of Calif. 27,357,843 14.5 4 Mobil Oil Corp. 19,880,772 10.5 5 Exxon Corp. 19,461,340 10.3 6 Superior Oil Co. 7,820,488 4.1 7 Getty Oil Co. 7,058,995 3.7 8 Continental Oil Co. 7,058,995 3.7 9 Cities Service Co. 7,058,995 3.7 10 Atlantic Richfield Co. 7,058,995 3.7 11 Phillips Petroleum Co. 3,942,711 2.1 12 Standard Oil Co. of Ohio 3,627,765 1.9 13 Sun Oil Co. 3,627,765 1.9 14 Forest Oil Corp. 1.956,742 1.0 15 Standard Oil Co. of Indiana 1,948,309 1.0 16 Standard Oil Co. of Calif. 1,546,843 0.8 17 Pennzoil Co. 1,097,624 0.6 18 Tenneco Corp. 436,640 0.2 19 J.Ray McDermott & Co., Inc 288,955 0.2 20 Hunt Industries 68,080 0.0 Total (All Companies) 188,789,492 Concentration Ratios: Percent 4-firm 60.7 8-firm 82.5 20-firm 99.9 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-45—Rank By Gas Production from Federal (Section 8) OCS Leases, 1966 ( Rank Company Production Percent of (thous. cu. ft.) Total 1 Gulf Oil Corp. 95,435,231 25.0 2 Shell Oil Co. 69,155,753 18.1 3 Exxon Corp. 49,682,088 13.0 4 Mobil Oil Corp. 39,592,785 10.4 5 Union Oil Co. of Calif. 33,855,340 8.8 6 Standard Oil Co. of Calif. 24,863,270 6.5 7 Superior Oil Co. 18,093,349 4.7 8 Roy Lee 6,915,921 1.8 9 Tenneco Corp. 5,715,717 1.5 10 Atlantic Richfield Co. 5,182,365 1.4 11 Getty Oil Co. 5,182,365 1.4 12 Cities Service Co. 5,182,365 1.4 13 Continental Oil Co. 5,182,365 1.4 14 Phillips Petroleum Co. 4,117,859 1.1 15 Sun Oil Co. 3,013,638 0.8 16 Standard Oil Co. of Ohio 3,013,638 0.8 17 Pennzoil Co. 1,976,783 0.5 18 Hunt Industries 1,794,992 0.5 19 Forest Oil Corp. 1,724,983 0.4 20 Standard Oil Co. of Indiana 1,618,116 0.4 ( Total (All Companies) 382,184,553 Concentration Ratios: 4-firm 8-firm 20-firm Percent 66.5 88.3 99.9 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. ( TABLE 6A-46—Rank By Gas Production from Federal (Section 8) OCS Leases, 1967 Production Percent of Rank Company (thous. cu. ft.) Total 1 Gulf Oil Corp. 118,017,533 21.5 2 Shell Oil Co. 101,501,009 18.5 3 Exxon Corp. 58,895,338 10.7 4 Union Oil Co. of Calif. 47,511,171 8.7 5 Phillips Petroleum Co. 37,890,144 6.9 6 Mobil Oil Corp. 36,466,888 6.6 7 Standard Oil Co. of Calif . 32,239,112 5.9 8 Superior Oil Co. 24,969,994 4.6 9 Tenneco Corp. 14,903,454 2.7 10 Atlantic Richfield Co. 11,779,335 2.2 11 Getty Oil Co. 11,533,056 2.1 12 Continental Oil Co. 11,533,056 2.1 13 Cities Service Co. 11,533,056 2.1 14 Roy Lee 11,163,873 2.0 15 Standard Oil Co. of Indiana 4,864,842 0.9 16 Standard Oil Co. of Ohio 3,117,491 0.6 17 Sun Oil Co. 3,117,491 0.6 18 Texaco, Inc. 1,847,365 0.3 19 Pennzoil Co. 1,774,152 0.3 20 Hunt Industries 1,342,693 0.2 Total (All Companies) 548,295,284 Concentration Ratios: Percent 4-firm 59.4 8-firm 83.4 20-firm 99.5 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-47--Rank By Gas Production from Federal (Section 8) OCS Leases, 1968 Rank Company Production Percent of (thous. cu. ft.) Total 1 Shell Oil Co. 162,111,009 21. 4 2 Gulf Oil Corp. 152,836,098 20.1 3 Exxon Corp. 74,701,278 9.8 4 Union Oil Co. of Calif. 72,372,217 9.5 5 Mobil Oil Corp. 54,102,278 7.1 6 Superior Oil Co. 42,318,488 5.6 7 Standard Oil Co. of Calif. 39,145,763 5.2 8 Phillips Petroleum Co. 35,344,177 4.6 9 Tenneco Corp. 23,394,348 3.1 10 Cities Service Co. 18,357,769 2.4 11 Getty Oil Co. 18,061,886 2.4 12 Atlantic Richfield Co. 14,942,043 2.0 13 Continental Oil Co. 14,587,234 1. 9 14 Roy Lee 11,002,816 1.5 15 Standard Oil Co. of Indiana 7,828,299 1.0 16 Texaco, Inc. 3,288,583 0.4 17 Sun Oil Co. 3,059,946 0.4 18 Standard Oil Co. of Ohio 3,059,946 0.4 19 Hunt Industries 1,968,442 0.3 20 Pennzoil Co. 1,633,778 0.2 Total (All Companies) 759,450,366 Concentration Ratios: Percent 4-firm 8-firm 20-firm 60.8 83.3 99.3 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-48—Rank By Gas Production from Federal (Section 8) OCS Leases, 1969 Rank Company Production Percent (thous. cu. ft.) Total 1 Shell Oil Co. 216,149,940 18.9 2 Gulf Oil Corp. 183,856,871 16.0 3 Union Oil Co. of Calif. 122,137,966 10.6 4 Exxon Corp. 86,550,772 7.6 5 Mobil Oil Corp. 85,544,149 7.5 6 Tenneco Corp. 62,118,464 5.4 7 Superior Oil Co. 61,639,623 5.4 8 Standard Oil Co. of Calif. 51,450,056 4.5 9 Phillips Petroleum Co. 47,521,976 4.2 10 Cities Service Co. 28,145,610 2.4 11 Getty Oil Co. 26,834,263 2.3 12 Atlantic Richfield Co. 26,378,444 2.3 13 Continental Oil Co. 21,489,208 1.9 14 Kerr-McGee Corp. 16,756,304 1.5 15 Standard Oil Co.of Indiana 15,614,272 1.4 16 Hunt Industries 11,635,718 1.0 17 Roy Lee 10,051,196 0.9 18 Forest Oil Corp. 9,757,867 0.8 19 Champlin Petroleum (Union Pacific Corp.) 8,030,201 0.7 20 Texaco,Inc. 4,847,882 0.4 Total (All Companies) 1,146,139,743 Concentration Ratios: Percent 4-firm 53.1 8-firm 75.9 20-firm 95.7 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-49--Rank By Gas Production from Federal (Section 8) OCS Leases, 1970 Production Percent of Rank Company (thous. cu. ft.) Total 1 Shell Oil Co. 247,337,987 15.6 2 Gulf Oil Corp. 183,735,750 11.6 3 Tenneco Corp. 161,086,909 10.2 4 Union Oil Co. of Calif. 157,899,484 10.0 5 Mobil Oil Corp. 115,379,504 7.3 6 Exxon Corp. 99,805,734 6.3 7 Standard Oil Co. of Calif. 76,204,281 4.8 8 Forest Oil Corp. 69,985,540 4.4 9 Getty Oil Co. 68,271,810 4.3 10 Cities Service Co. 48,832,667 3.1 11 Superior Oil Co. 46,496,153 2.9 12 Phillips Petroleum Co. 44,607,835 2.8 13 Atlantic Richfield Co. 42,118,022 2.6 14 Continental Oil Co. 40,610,851 2.6 15 Standard Oil Co.of Indiana 37,335,675 2.4 16 Kerr-McGee Corp. 23,839,509 1.5 17 Hunt Industries 16,687,835 1.0 18 Champlin Petroleum (Union Pacific Corp.) 11,434,725 0.7 19 Amerada Hess Corp. 9,358,850 0.6 20 La. Land & Exploration Co. 8,425,165 0.5 Total (All Companies) 1, 585,102,176 Concentration Ratios: Percent 4-firm 47.4 8-firm 70.2 20-firm 95.2 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-50--Rank By Gas Production from Federal (Section 8) OCS Leases, 1971 Production Percent of Rank Company (thous. cu. ft.) Total 1 Shell Oil Co. 251,417,615 13.0 2 Gulf Oil Corp. 180,974,064 9.4 3 Tenneco Corp. 160,038,141 8.3 4 Union Oil Co. of Calif. 159,795,880 8.3 5 Mobil Oil Corp. 143,833,619 7.4 6 Exxon Corp. 119,285,216 6.2 7 Forest Oil Corp. 105,838,318 5.5 8 Getty Oil Co. 101,768,076 5.3 9 Standard Oil Co. of Calif. 96,547,971 5.0 10 Standard Oil Co.of Indiana 77,080,433 4.0 11 Cities Service Co. 59,454,568 3.1 12 Texaco, Inc. 54,426,246 2.8 13 Superior Oil Co. 53,777,986 2.8 14 Continental Oil Co. 50,864,997 2.6 15 Atlantic Richfield Co. 50,777,612 2.6 16 Phillips Petroleum Co. 37,725,229 2.0 17 Southern Natural Resources r Inc. 26,197,593 1.4 18 Kerr-McGee Corp. 25,751,231 1.3 19 Hunt Industries 21,585,323 1.1 20 Amerada Hess Corp. 20,925,216 1.1 Total (All Companies) 1, 931,692,601 Concentration Ratios: Percent 4-firm 39.0 8-firm 63.4 20-firm 93.2 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-51--Rank By Gas Production from Federal (Section 8) OCS Leases, 1972 Rank Company Production Percent (thous. cu. ft.) Total 1 Shell Oil Co. 257,186,987 11.6 2 Tenneco Corp. 204,025,044 9.2 3 Gulf Oil Corp. 193,392,708 8.7 4 Union Oil Co. of Calif. 171,428,221 7.7 5 Mobil Oil Corp. 148,347,579 6.7 6 Exxon Corp. 140,269,782 6.3 7 Getty Oil Co. 127,211,412 5.8 8 Standard Oil Co. of Calif.114,079,608 5.2 9 Forest Oil Corp. 105,773,109 4.8 10 Standard Oil Co.of Indiana 99,249,249 4.5 11 Texaco, Inc. 75,895,062 3.4 12 Cities Service Co. 68,691,892 3.1 13 Continental Oil Co. 62,267,808 2.8 14 Atlantic Richfield Co. 58,378,291 2.6 15 Murphy Oil Corp. 51,544,800 2.3 16 Kerr-McGee Corp. 48,570,774 2.2 17 Phillips Petroleum Co. 39,415,859 1.8 18 Superior Oil Co. 38,587,472 1.7 19 Southern Natural Resources, Inc. 37,409,379 1.7 20 Amerada Hess Corp. 21,161,110 1.0 Total (All Companies) 2,214,211,608 Concentration Ratios: Percent 4-firm 37.2 8-firm 61.2 20-firm 93.1 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-52--Rank By Gas Production from Federal (Section 8) OCS Leases, 1973 Rank Company Production (thous. cu. ft Percent of .) Total 1 Shell Oil Co. 234,875,148 9.7 2 Tenneco Corp. 221,916,206 9.2 3 Mobil Oil Corp. 188,295,557 7.8 4 Gulf Oil Corp. 166,925,973 6.9 5 Exxon Corp. 155,808,340 6.4 6 Forest Oil Corp. 145,519,0.8 6.0 7 Getty Oil Co. 141,474,265 5.9 8 Standard Oil Co.of Calif . 128,005,395 5.3 9 Union Oil Co. of Calif. 123,570,148 5.1 10 Standard Oil Co. of Indiana 101,218,465 4.2 11 Cities Service Co. 96,398,373 4.0 12 Continental Oil Co. 81,367,532 3.4 13 Texaco, Inc. 74,894,021 3.1 14 Atlantic Richfield Co. 65,457,279 2.7 15 Pennzoil Co. 54,352,221 2.2 16 Southern Natural Resources, Inc. 54,058,460 2.2 17 Kerr-McGee Corp. 50,904,245 2.1 18 Hunt Industries 43,107,008 1.8 19 Superior Oil Co. 36,783,154 1.5 20 Phillips Petroleum Co. 31,159,580 1.3 Total (All Companies) 2,417,404,278 Concentration Ratios: Percent 4-firm 33.6 8-firm 57.2 20-firm 90.8 SOURCE: U.S. Department of the Interior, Geological Survey, Conservation Division. TABLE 6A-53—Rank By Gas Production from Federal (Section 8) OCS Leases, 1974 Rank Company i Production (thous. cu. ft. Percent ) Total 1 Tenneco Corp. 286,648,432 10.4 2 Shell Oil Co. 198,432,789 7.2 3 Exxon Corp. 174,337,021 6.3 4 Mobil Oil Corp. 173,080,456 6.3 5 Forest Oil Corp. 169,093,000 6.1 6 Union Oil Co. of Calif. 164,871,584 6.0 7 Getty Oil Co. 147,773,123 5.4 8 Gulf Oil Corp. 144,177,939 5.2 9 Chevron Oil Co. 132,731,696 4.8 10 Cities Service Co. 116,669,441 4.2 11 Continental Oil Co. 101,569,587 3.7 12 Standard Oil Co.of Indiana 96,029,073 3.5 13 Texaco, Inc. 87,907,177 3.2 14 Superior Oil Co. 79,315,164 2.9 15 Atlantic Richfield Co. 77,893,180 2.8 16 Pennzoil Co. 70,550,125 2.6 17 Hunt Industries 70,166,450 2.5 18 Southern Natural Resources, Inc. 66,825,518 2.4 19 Phillips Petroleum Co. 45,445,212 1.6 20 Kerr-McGee Corp. 42,844,136 1.6 Total (All Companies) 2,758,879,770 Concentration Ratios: Percent 4-firm 30.2 8-firm 52.9 20-firm 88.7 SOURCE U.S. Department of the Interior, Geological Survey, Conservation Division. Chapter 7 ONSHORE OIL AND GAS Importance of Federally-Owned Resources There are about 762 million acres of onshore land in the United States administered by the Federal Government. 1/ The Government has also retained the mineral rights to other lands whose surface rights have been transferred. As a result, the Government administers the mineral rights for some 822 million acres. 2/ As of January 1974, over 75 million acres were under Federal lease for oil and gas, 3/ and over 376 million acres are considered by the Department of the Interior to be prospectively valuable due to the presence of oil and gas resources. £/ 1/ U.S. Department of the Interior, Public Land Statistics: 1972 , p.l. 2/ Ibid ., p. 104. 3/ U.S. Department of the Interior, Geological Survey, Federal and Indian Lands Oil and Gas Production , Royalty Income, and Related Statistics: Calendar Year 1973, June, 1974, p. 22. £/ U.S. Senate, Committee on Interior and Insular Affairs, Federal Leasing and Disposal Policies, Hearings , 92d Cong., 2d sess., June 19, 1972, p. 201. - 425 - Table 7.1 shows the oil and natural gas reserves and potential resources estimated by the U.S. Geological Survey to exist in the United States. The percentage of these reserves and resources estimated to lie onshore and on Federal onshore lands is also shown. The estimation of reserves and especially of undiscovered resources is not an exact science. The range estimates of undiscovered resources shown in table 7.1 represent a very large change from the estimates made by the U.S. Geological Survey in the preceding year. There has been a dispute of long standing about the proper way to estimate the size of undiscovered deposits. The latest revision of the USGS estimates resulted from adopting a previously controversial estimation method. 5/ The percentage estimates of undiscovered resources on Federal lands are also subject to error, but are probably more reliable than the quantity estimates. The proportion of U.S. oil and gas production from Federal onshore lands historically has been smaller than 5/ For a discussion of the dispute which preceded the table 7.1 estimates, see "Oil and Gas Resources: Academy Calls USGS Math 'Misleading'," Science , February 28, 1975, pp. 723-727. * - 426 - > fdl (0 0) u fd p p p Id 52 Xi G fd •H o 03 rd 3 p u P o (0 a) o p 3 o CO 03 PS Xi G fd w 03 > P d) CO d) PS cn D W P) CQ g CO fd 0 •H o P rH Oil d) c fd P r—< I—1 LO Cd 03 P 0 • • • rH G o 03 XX VO VO O' fd to •H p 'd CO u 03 CO 03 03 G -H cn 3 PM CM O Cd lP 0) u p CO 00 VO O' d) PS 03 G > G • PM O P •H i—i 03 • P CO • 0 • 03 10 1 (0 03 e'¬ d) 00 03 p er* •H 1 VO 1—i O Ol P rH fd P fd G • d) a P xi E V V 0 -P 1—1 •H 0 G •H 03 VO •H P Ol in XX td CO fd P CO CM i—1 co in fd O G) CO fd rH rH o rH VO vo -P i—1 ox 03 03 XX fd •H •H • • i o rH o p P O' 1—1 CM G 03 CO # 03 03 p 0 p 3 CO o Ol ■H 0 fd CM Cd P fd Eh O Ol Ol CO 0 CM G S 'O V fd CO G P X) V p £ r 3 0 G in 03 V 0 fd r- p G CO P p Cd o 03 oil 03 ■—i i—i P P P rH d) d) -p •H G O fd G fd p XX G o V fd -H E 03 P o O' VO •n tH in a' p -H O d) xx a • • G d> CM E 03 P P Xi CO n CO O' fd 03 rH O' P CO 03 03 G U XX XX rH G w CM IP O -p fd p fd H d) P fd o d) i—1 P CD rH •H P o • o > P P O p CO •H | fd 0 o CO 3 03 -P d) -p p o p •H P 0 P G P G 03 •H P G CO td a> 0 vo Ol CO CO ax PS U fd 03 03 E O XX • • • e P E PS •H P CO o o\ 00 £ •p Xi CO P P a; G a> 00 VO P p 03 d) P CO CO PM O fd p > 03 fd fd 0) G PM P p 03 03 V Q 0 03 D Xi td rH 1 'd o Cd G G G 03 • CO i—1 G • fd fd O CO CO 03 ■H fd ■H 03 p •H 1—1 o VO o- P • Xi C3 CO • rH i—1 rH 03 LT) CO Ol D G ■H P D •rH p fd rH p Ol O' rH CO D Cd o 0 -P •H p • • 1 £ e o'd E 0 XX (d H’ r- o p o P iH d) 0 • p Eh --' XX CO Ol in d) p 0 0 P p 03 G P P d> P p • •H CO o CM D O P Xi 03 E Xi CM O 03 p V 0 03 xi *d 1 P fd CO O P 03 •H p CO P E 03 3 CO E 03 G PM •H P 03 CM •H > O E p fd P E > 0 ) CO CO 0 •H O CO P 03 0 03 £ CO 03 P 03 O 03 \, • • P fd p U P fdl 03 3 O P CO O CO •H 03 -H 03 P id •d p 'd rH 3 03 G G G XI O S H -H D fd 03 oil I < l£> O] TT I the percentage of reserves and resources currently estimated to exist on these lands. Table 7.2 shows produc¬ tion of oil and gas on Federal onshore lands (excluding Indian lands) for the years 1950 through 1973. Both the absolute quantity and the percentage of total U.S. produc¬ tion are shown. From 1920 through 1973, a cumulative total of more than 5.2 billion barrels of oil and 17.1 trillion cubic feet of natural gas were produced. 6/ Oil production has never reached 7 percent of the U.S. total, however, and had declined to 5.4 percent in 1973. Federal onshore gas production peaked at 5.7 percent of total U.S. production in 1967 and had declined to only 4.5 percent in 1973. If the percentage estimates of indicated and inferred reserves (table 7.1) are any guide to near future levels of production, Federal onshore oil production is likely to continue declining relative to total U.S. production. Federal onshore gas production might increase by a couple of percentage points. In the more distant future, the Table 7-1 estimates of undiscovered recoverable resources suggest that both oil and gas production on Federal 6/ Computed from Federal and Indian Lands . . ., op. cit . - 427 - Year 1950 1951 1952 1953 1954 1955 1956 1957 1958 1959 1960 1961 1962 1963 1964 1965 1966 1967 1968 1969 1970 1971 1972 1973 TABLE 7.2.—Federal Onshore Oil and Gas Production: 1950-1973 a/ Oil and Condensate Natural Gas Percent of Percent of MB U.S. Total MMCF U.S. Total 88,010 4.5 127,279 2.0 98,149 4.4 157,317 2.1 101,014 4.4 192,190 2.4 111,918 4.7 239,492 2.9 116,252 5.0 293,654 3.4 127,171 5.1 316,654 3.4 136,798 5.2 367,883 3.6 144,898 5.5 479,988 4.5 145,950 6.0 483,870 4.4 158,384 6.2 534,321 4.6 167,104 6.5 582,471 4.6 180,703 6.9 609,686 4.6 183,507 6.9 630,495 4.5 191,096 6.9 697,001 4.8 192,426 6.9 778,949 5.0 195,258 6.9 794,241 5.0 201,615 6.7 887,776 5.2 210,931 6.6 1,040,213 5.7 216,164 6.5 1,004,911 5.2 216,315 6.4 963,097 4.7 210,380 6.0 999,040 4.6 196,740 5.7 1,042,463 4.6 186,889 5.4 996,467 4.4 180,263 5.4 1,028,746 4.5 a/ Excludes oil and gas production from Indian Lands. Source: Computed from U.S. Department of the Interior, Geological Survey, Federal and Indian Lands Oil and Gas Production, Royalty Income and Related Statistics: Calendar Year 1973, June 1974. - 428 - onshore lands may increase relative to total U.S. produc¬ tion, but neither is likely to exceed 8 percent of the total. Leasing Policies and Procedures The basic statute governing the leasing of Federal onshore oil and gas lands is the Mineral Lands Leasing Act of 1920. 7/ The Department of the Interior is charged with granting and administering leases. Within the Depart¬ ment, leasing authority is delegated to Bureau of Land Management (BLM) regional offices. The U.S. Geological Survey (USGS) assists the BLM offices in the technical aspects of lease evaluation and administers exploration and production activities and royalty collection. Both competitive and noncompetitive leasing systems are used to allocate oil and gas mineral rights. Which of three different leasing methods is employed depends upon the geological potential of the tract and whether or not the tract has previously been leased. 7/ 41 Stat. 437; 30 U.S.C. 181 et seq., as amended. Both public and acquired lands are leased under essentially the same procedures. See chapter 2 for elaboration. If a tract has not been previously leased and if it does not overlie a "known geologic structure/' the lease 8 / is awarded to the first person who applies for it. — A known geologic structure (KGS) is an oil or gas trap which has actually been discovered by drilling. The geographical limits of a KGS are determined by USGS geologists using information on the geologic structure and available well data. This method of leasing is called "the over the counter" method. A $10 fee is charged for processing an application. A tract which has previously been leased and which does not overlie a KGS is reoffered for lease under the "simultaneous filing" system. The BLM office in each region compiles a monthly list of oil and gas properties whose leases have been relinquished, terminated, canceled, or have expired. The BLM office then accepts applica¬ tions for these leases for a specified period of time. An individual or corporation can submit only one applica¬ tion for any particular lease. At the end of the period, 8/ In order to obtain a lease, an applicant must meet certain minimal requirements such as being an adult U.S. citizen. - 430 - v if more than one application has been submitted for a property, a drawing is held to determine who will be awarded the lease. A property which receives no applica¬ tions may subsequently be leased by the first qualified applicant. If a tract overlies a KGS it must be leased by competitive bidding. Eligible lands which have been evaluated as overlying a KGS by the USGS are put up for competitive bonus bids by the appropriate BLM regional office. Leases issued noncompetitively are limited to a maximum of 2,560 acres. Competitively issued leases are limited to 640 acres. No person or company may own or have an interest in more than 246,080 acres in any one State except in Alaska, where 300,000 acres may be ( held in each of two parts, northern and southern. The primary term of noncompetitive leases is ten years. For competitive leases it is five years. For either type, the primary term may be extended for two years if drilling is actually underway at the expira¬ tion of the primary term. All leases remain in effect -431- so long as production is obtained from the property. There are no explicit diligence requirements for either competitive or noncompetitive leases. To maintain a nonproductive lease in effect during the primary term, the leaseholder need only continue payment of a specified minimum rent. In most instances, the minimum rent is $2 per acre per year for a property which overlies a KGS and $.50 per acre per year for a property 9/ which does not. — For all producing leases, a royalty payment is required. On noncompetitive leases, the royalty is 12-1/2 percent, the statutory minimum. For competitively issued leases, the royalty is geared to a sliding scale. The royalty rate for oil slides from 12-1/2 percent if production is 110 barrels per well per day or less to 25 percent if production exceeds 400 barrels per well per day. For gas the royalty is 12-1/2 percent if production is less than 5,000 MCF per well per day and 16-2/3 percent if production exceeds 5 f 000 MCF. A minimum royalty 9/ The higher rate is applied to leases as soon as they are classified as overlying a KGS, even though they were not so classified when the lease was issued. - 432 - payment of $1.00 per acre is required on all producing leases. Prior to 1960, all leasing of non-KGR properties was done on a first come, first served basis. The simultaneous filing system was introduced in that year to reduce confusion and conflict among applicants. The rent on noncompetitive leases was also raised in 1960 to its present level of $.50 per acre, and the primary lease period was extended from five years to ten years. Prior to this, the annual rent had been $.50 per acre in the first year, no charge in the second and third years, $.25 in the fourth and fifth years, and $.50 per year if the lease was renewed for additional years. 10 / The vast majority of leases have been issued noncompetitively. For instance, in fiscal year 1967 almost 9 million acres were leased on a noncompetitive basis and only about 60,000 acres on a competitive basis. 11 / In 1972 the Interior Department estimated 10/ John W. Sprague and Bernadette Julian, "Onshore Oil and Gas Leasing Revenue," Natural Resources Journal , July 1970, pp. 517 and 518. 11/ Ibid., p. 516. that over 90 percent of the 105,000 oil and gas leases outstanding had been issued noncompetitively. 12 / Most noncompetitive leases are issued under the simul¬ taneous filing system. Noncompetitive leases predominate because most of the eligible property around an explora¬ tory well is acquired by the operator prior to the commence¬ ment of drilling. When a successful wildcat well results in the classification of an area as KGS, little or no land is left to be leased competitively. 13 / Economic and Technological Conditions of the Industry The basic technological and economic conditions facing the onshore petroleum industry are similar to those facing the offshore industry. These conditions along with the major differences between onshore and offshore endeavors were described in chapter 6, so we shall not duplicate the narrative here. 12 / U.S. Senate, Committee on Interior and Insular Affairs, Subcommittee on Minerals, Materials and Fuels, Mineral Development on Federal Lands, Hearings , 93d Cong., 2d sess., March 27, 29, and April 2, 1974, p. 176. 13/ See Sprague, op. cit ., p. 516. - 434 - Economic Evaluation of Leasing Policies ( Several aspects of Federal leasing regulations may influence the efficiency of onshore oil and gas lands development. Included are regulations which influence the time path of resource development, the size of leased tracts, and the allocation of leases. Each will be discussed in turn. Time Pattern of Resource Development The time path of resource development on Federal onshore oil and gas lands is strongly influenced by petroleum market forces, but it is also shaped by aspects of leasing policy such as the rate of leasing, production requirements and incentives, royalty rates, and output restrictions. The rate of leasing is determined almost exclusively by the market mechanism. In the case of offshore lands, there are many areas which the petroleum companies have been eager to develop but which have not yet been offered for lease. Onshore, however, most Federal lands not - 435 - already leased have not been leased simply because no one believed they are worth the nominal $10 filing fee and the $.50 per acre annual rental fee. There may be interest in some unleased lands which have been recently i classified as KGS or which were previously leased but have not yet been reoffered, but it can be expected that such lands will be offered for lease after an administrative delay of several months average duration. By the same token, leaseholders under the present leasing regulations are given little stimulus other than the existing market stimulus to develop their tracts rapidly. Only three aspects of the regulations tend to encourage rapid development. One is the small annual rent which imposes a cost for speculative withholding of production. The rental rate increases if a property is classified as a KGS and thus becomes a more likely candi¬ date for development. The only way this rent can be avoided is by giving up the property, in which case it might fall into the hands of someone more anxious to develop it. The second stimulus to development is the renewal option, which requires that drilling be in progress at the time the lease expires. This requirement was undoubtedly intended to counteract the negative - 436 - t effect on development of the expiration date rather than to provide a positive stimulus to drill, but it may achieve the latter purpose nonetheless. The final stimulus in present leasing regulations is the fact that the lease does have a finite duration unless it is brought into production. Since the primary term is reasonably long—ten years for most leases--this factor probably does not accelerate development much, but it may lead to a slightly higher rate of development than would occur if mineral rights were granted indefinitely. The adverse effects of percentage royalties have been analyzed in chapter 5. In theory, the royalty leads to suboptimal levels of production and premature lease abandonment. Since all onshore Federal oil and gas lease production is subject to a minimum 12-1/2 percent royalty, and in some cases up to 25 percent, these effects are undoubtedly present under existing leasing procedures. Unfortunately, the data needed to determine the actual magnitude of the effects are not available. As chapter 5 indicated, the impact of any given royalty rate on the level of production depends upon the elasticity of supply, and the typical or average elasticity of crude oil supply on Federal onshore lands is not known. - 437 - t That the royalty rate on competitive leases is lower for smaller production rates probably results in greater efficiency compared to a high fixed royalty rate. 14/ This is so because the adverse efficiency effects are positively related to the size of the royalty and, in the case of oil, are probably negatively associated with the rate of production from a given well. A high output rate generally implies a new flush well in the primary stage of production. A well with a low rate of produc¬ tion, on the other hand, may be on the verge of secondary recovery, and the size of the royalty rate might make the difference between profitability and unprofitability of secondary recovery measures. Present leasing regula¬ tions do allow for a reduction of the royalty rate if the leaseholder can show that the royalty normally required makes production uneconomical and thus reduces the ultimate amount of oil recovered. This provision may alleviate many problems which percentage royalties would otherwise cause. 14 / The adverse effect of a sliding royalty rate should also be kept in mind, however; i.e., the stimulus it provides for producers to drill more than the optimum number of wells in order to decrease production per well and thus qualify for a lower royalty rate. - 438 - The largest deviation from the market rate of produc¬ tion has probably been caused by the various state systems of market demand prorationing. In past periods of crude oil surplus, these prorationing systems have served to support crude oil prices by artificially restricting the output of crude oil. The Interior Department has allowed Federal producing leases to be subjected to State prorationing regulations, although there was no legal requirement that it do so. As chapter 6 pointed out, prorationing may induce both static and dynamic inef¬ ficiencies in well drilling and operation. The net effect of various leasing policies on the time path of development appears to have been to retard development as compared to the rate which would have been experienced in an unfettered market. The retarding effects of prorationing and royalty provisions have undoubtedly outweighed the weak incentives for rapid development provided by fixed rentals and lease expiration provisions. Since, as chapter 3 revealed, it is difficult to determine objectively whether the optimal rate of non¬ renewable resources development is more or less rapid than the unfettered market rate, no confident judgment on this aspect of leasing policy can be rendered. If one assumes that the market overdiscounts the future, the modest retardation caused by Federal leasing policies would have to be considered beneficial on balance. The policies were clearly not intended for this purpose, however; and if they had such a desirable effect, it was accidental. Since royalty charges and proration¬ ing may result in inefficiencies unrelated to the optimal time path of development, alternative methods should be explored if retarding the rate of future development is considered desirable. Tract Sizes Another factor which can affect the efficiency of production from Federal lands is the size restrictions on individual leases. Stephen L. McDonald indentifies the primary factors leading to inefficient petroleum production as: "the joint effects of two conditions: (a) the existence of two or more owners of operating interests in the surface - 440 - overlying a single reservoir and (b) the fluid, hence migratory nature of reservoir contents." 15 / There is nothing leasing policies can do about condition (b), but the lease size allowance can affect condition (a). If a prospector does not have complete control of the pool he discovers, other leaseholders over the pool can capture part of the benefits from his effort. They can drain some of the pool's resources without having incurred the expense of exploring their tracts to verify the resource's presence. This is a classic case of an external economy, and it can be expected to have the classic result: there will be a sub- optimal level of exploration, because those who incur exploration costs are not able to realize all the benefits which flow from their expenditures. In addition, after a discovery is made, there will with multiple leases be a tendency for too many wells to be drilled and for production to occur at too rapid a rate. This is because each individual profits only from his own 15 / Stephen L. McDonald, Petroleum Conservation in the United States (Baltimore: The Johns Hopkins Press, 1971), p. 197. - 441 - production and not from the reservoir's overall produc¬ tivity. Each must concern himself with extracting as much of the resource as he can before other leaseholders drain the pool. And if the pool reaches the point where secondary recovery becomes practical, the externality problem arises again. There will be a greatly reduced incentive for any single leaseholder to repressurize the reservoir, since all other leaseholders will realize some of the benefits, but he alone will suffer the costs. The problems of multiple ownership would of course be eliminated if leases were of such a size that they covered entire pools. Since the location of pools is unknown in the exploratory stage and the boundaries are uncertain well into the development stage, the pre¬ exploration issuance of leases which cover pools completely will happen only by chance. The probability of this happening increases, however, as the size of the lease increases. One way the advantages of single ownership can be obtained where there are multiple leaseholders over a discovered or potential pool is through the formation of a unit agreement. Under a unit agreement, all leaseholders - 442 - over the relevant area agree to operate as a single unit, and they divide the resulting proceeds in some predetermined manner. Such an agreement leads to efficient operations which benefit both the leaseholders and society. One problem hindering unitization is getting all the lease¬ holders to agree on an equitable division of the pro- 16/ ceeds. — The obstacles are generally reduced if there are fewer parties involved, and this is more probable if individual leases are larger in size. Another way of overcoming the multiple ownership problem is for one firm to acquire all relevant leases from the other leaseholders. Under existing regulations, leaseholders can assign their right to others. Here again, however, negotiating acceptable terms with all of the other leaseholders may be difficult. Such negotiations are expensive and time consuming, complicated among other things by holdout tendencies. Efficiency losses may still intrude since, in transferring their leases, the original lease owners typically insist on receiving percentage royalties over and above those due the Government. 16 / See ibid., pp. 213-215, for a more extensive explanation. /C - 443 - These additional royalties may intensify the production disincentives caused by Government royalties. Of course, the problems arising from multiple owner¬ ship are not unique to Federal lands. Many States have detailed regulations and established procedures which attempt to deal with the problem. These include compulsory well spacing plans and in some States compulsory unitiza¬ tion. The Department of the Interior usually allows such State regulations to be applied to Federal leases. While regulatory procedures may reduce inefficiency, especially during the production phase, it is not clear that any system of regulation can provide the same degree of flexibility and incentives to efficient operation which would face a self-interested owner or operator of an entire pool. 17 / A study conducted for the Public Land Law Review Commission (PLLRC), 18/ undertook an extensive empirical 17 / See ibid ., pp. 150-226, for a complete discussion of the various State systems and their shortcomings. 18 / Abt Associates, Inc., Energy Fuel Mineral Resources of the Public Lands (Springfield, Va.: National Technical Information Service, 1970), vol. 1. - 444 - analysis aimed at identifying the optimal lease size. The average sizes of oil fields in various areas, the acreage generally assembled by petroleum companies prior to exploration and development, and the acreage operated under unit agreements were examined. It was determined that in the Rocky Mountain States, where Federal holdings of potential oil and gas lands are most significant, 89.8 percent of producing acreage was in fields that covered more than 2,000 acres. 19 / From observation of industry operating practices, it was concluded that "a firm will apparently very seldom consider drilling an exploratory well if its acreage interest is less than 640 acres," and that "in only a limited number of cases would the maximum non-competitive lease of 2,560 acres . . . be worth drilling." 20 / The average unit agreement examined was about 9,669 acres for producing units and over 20,000 acres for exploration units. 21 / For original leases on non- KGS land the limit on 19 / Ibid ., p. 128. 20/ Ibid ., p. 133. 21 / Ibid ., p. 141. - 445 - lease size poses no fundamental problem. Although the maximum size of 2,560 acres for a single lease may be restrictive in the exploratory stage, if additional acreage is desired, an applicant can request more than one lease in the same area. For leases issued under the simultaneous filing system, a problem does arise. The legal maximum on such leases is also 2,560 acres, but more important is the fact that they are typically reissued with no change in size when they become available. In 1973, the average size of oil and gas leases on public and acquired Federal 22 / lands was only about 651 acres. — The PLLRC study cited above examined the sizes of leases offered under the simultaneous filing system in five Western States and found that in a sample of 1,272 leases, only 7.5 percent (accounting for 27.1 percent of total sample acreage) were for tracts larger than 2,000 acres. Over 20 percent 23/ were for tracts of 100 acres or less. — 22 / Computed from Federal and Indian Lands . . . , op. cit ., p. 22. 23 / Abt Associates, Inc., op. cit ., pp. 113 and 114. - 446 - It would appear that many or most leases issued under the simultaneous filing system are of suboptimal size. It should be recalled that simultaneous filing leases are the most common type of leases. Of the non-competitive leases simultaneous filing leases are probably most important in terms of resource potential. It is likely that land which has yet to be leased for the first time and which can be obtained by over the counter filing is that land which has a very low probability of containing economic petroleum resource deposits. There is a major obstacle to correcting the problem of suboptimal lease size for leases issued through simultaneous filing. Although the Department of Interior may, under existing regulations, combine the acreage in more than one expired lease to create a larger single lease, contiguous tracts of land seldom become available for reissue at the same time. This means that, absent a fortuitous occurrence, small tracts would have to be held in an unleased status while awaiting the expiration of adjacent leases. It seems clear that when the opportunity arises to combine small leases into larger ones without undue delay, it should be done. It is not clear whether holding small leases off the market for - 447 - extended periods to assemble a larger tract would on balance increase or decrease efficiency. In the case of competitively leased lands, the 640 acre maximum seems unnecessarily and perhaps restrictively small. The size of newly issued competitive leases depends strongly on the size of the unleased area over a newly defined KGS. If, as is usually the case, this area is less than 640 acres, the acreage limitation is irrelevant. There seems to be no good reason, however, why a new unleased KGS area larger than 640 acres should be broken into more than one tract when it is offered for lease. In the case of competitive leases being reissued, the same problem as with reissued noncompetitive leases exists: contiguous small leases seldom become available at the same time. For competitive leases, however, the 640 acre statutory maximum prohibits consolidation up to an efficient size even if a suitable block of tracts should become available. Allocation of Leases A final aspect of the present leasing system which - 448 - may have adverse effects on economic efficiency is the manner in which leases are allocated under simultaneous filing. Ideally, each lease should be issued to the company or individual able to exploit it most efficiently. This person can presumably be identified because he is the one willing to bid the highest price. But under the simultaneous filing system, the winner of a lease is not apt to be the one best able to exploit the lease. It is more likely the winner will be a speculator with no desire to explore or produce on the lease, but who merely intends to profit by selling it to a petroleum company. — Presumably, the company best able to exploit the lease will offer to pay the highest price to the speculator and will eventually gain the lease. If a competitive bidding process were used, that company would probably have submitted the highest bid and acquired the lease directly, without any capture of profit by middlemen. One study examined two sample sets of Federal leases acquired by a group of major petroleum companies. One set was let competitively and the other noncompetitively. 24 / Mineral Development on Federal Lands . . . , op. cit. , p. 166 . - 449 - Of the competitively let tracts, 87.1 percent were acquired directly from the Government, while only 12.9 percent had been originally acquired from the Government by other companies or individuals and then later assigned to the 25/ major companies. — Of the noncompetitively let tracts, only 25.6 percent were assigned directly to the major companies by the Government, while 74.4 percent were 26 / transferred through middlemen. —■ There are at least two adverse efficiency effects from having leases pass through a middleman rather than 27/ directly to the companies best able to exploit them. — First, transaction costs are increased under a two-stage search, negotiation and assignment process. Second, the agreement to assign the lease may be contingent upon the payment of overriding royalties to the middleman. This will exacerbate any inefficiencies already caused 25 / Abt Associates, Inc., op. cit ., p. 204. 26 / Ibid ., p. 202. 27 / The shift of revenues from the Government to the middleman is perhaps more significant than the efficiency problems. It will be discussed in detail below. - 450 - by the Government's required royalty payments. Competitive Impact Perhaps the most important point to remember when assessing the impact of Federal onshore leasing policies on the petroleum industry's competitiveness is that the state of competition is not likely to vary much, depending upon who acquires the Federal lands. Even if all produc¬ tion on Federal lands were transferred to the largest domestic crude oil producer—a result unlikely under any leasing policy—the national eight-firm concentration ratio would rise by only about three percent. Alterna¬ tively, if all Federal onshore production currently in the hands of the eight largest producers were transferred to smaller firms, concentration would fall by less than two percent. Available evidence indicates that the aggregate share of Federal onshore production accounted for by the largest petroleum companies is in fact somewhat lower than their combined share of total United States production. Table 7.3 shows the quantities of hydro¬ carbons produced from Federal onshore leases operated by -451 TABLE 7.3.—Summary of Oil, Gas and Liquids Production For 17 Operators and/or Lessees, Fiscal Year 1974 a/ Operator and/or Lessee Federal Onshore Oil (thousand barrels) Gas (trillion cubic ft.) Liquids (thousand barrels) Standard Oil of Ind. 25,417 69,323 882 Standard Oil of Calif . 21,955 30,666 287 Continental Oil 14,011 32,011 1,409 Marathon Oil 9,333 13,955 305 Texaco 9,093 34,751 676 Tenneco Oil 5,197 49,026 111 Gulf Oil 3,445 10,386 173 Exxon 2,995 7,957 118 Atlantic Richfield 2,913 26,686 482 Union Oil of Calif. 2,715 61,887 783 Phillips Petroleum 2,344 8,606 175 Shell Oil 2,341 17,157 362 Sun Oil 1,270 4,088 219 El Paso Natural Gas 1,230 180,453 25 Mobil Oil 351 49,998 558 Placid Oil 152 677 33 Kerr-McGee 13 2,612 46 Total, 17 companies 105,275 600,239 6,644 Percent of Grand Total 59 58 51 Grand Total, all companies 179,298 1,036,286 13,048 a/ Oil includes condensate. Exxon includes Humble; Standard Oil of Calif, includes Chevron; Standard Oil of Indiana includes Amoco and Pan American. Source; U.S. Geological Survey, Conservation Division, mimeographed table, September 27, 1974. v -451A- 17 companies in 1974. 28 / Among these 17 companies are the eight largest domestic crude oil producers. Table 7.4 presents for these eight largest producers the estimated net quantity of domestic crude oil and natural gas liquids extracted by each company in fiscal year 1974 and the percentage of total U.S. production which that quantity represented. Also shown for comparison is the quantity of crude oil and gas liquids produced from Federal onshore leases operated by the eight firms, along with the commensurate percentage of total Federal onshore production. Most companies' share of Federal onshore production was less than their share of total domestic production. For all eight companies together, the share of Federal onshore production was 10 percent less than their share of total United States production. If the distribution of Federal onshore leases has affected competition in the petroleum industry, the effect, by reducing overall concentration, has probably been pro-competitive. 28 / It should be pointed out that the operator of a lease is not necessarily the owner of the hydro¬ carbons produced on it. A company may operate leases owned by other companies or individuals and may in turn have some of its leases operated by other companies. Information on the quantity of hydro¬ carbons produced on leases owned by each company would be preferred, but it is not available; and the operator information must serve as a proxy. - 452 - > ■H cn O P 01 P d g G 01 P >H u I »—I i G • o n< co • -H r- tn W G OQ C Eh P o 01 o p g 01 P fd p c (D O O d p -h (HOP o 3 C (P G w CU o p G d o o u CU VO P ^3 r—I IT) P co r' vo oi r^ P CO p P O co o o 1—1 >i 01 id p 01 rH 01 id 01 01 •H G rH 01 >i p fd C G fd fd g \ p p i CO CP CO in av CN CXI CP 03 vo < g o 01 01 -P G C » — 1 vo o CP OV -3 rH o "3 •3 CP G Cu p fd fd o rH C" I" co CM (N vo "3 in CO 01 G d o P CU *H • • > 0 0 E G 01 £ 1 •H -p p QJ G P • G p > cr 4 O C /1 O ai 01 •H •H • -H CO CP CN o rH VO 00 vo CO o G G p G P D P • • d d fd G U «H VO VO vo m •'3 CO CO o c rH d (Drl G rH ■3 o c H G c u fd d rH S £ fd P -P 0 0 •—1 G *3 ai o p G *H O r—l r> cu -p cu 0) o G O G — •H O 03 P "H i—I O P 0) GPP •drl U w o e fd • P G D CU in o in h id G a p c d d rH rH d p o o CU 0 id •—) fd c G p -p fd G P 2 p E X X 01 i—i g fd rH G p P -h cu u-i x CP 01 , Sh 1—I O P X t) CCS 5-1 4-1 CO o o p CO CP O’ o DC o' rH 00 CD CM CO 5h p- rH p rH CO in CM o CO CO p- rH 00 00 00 CO 00 O rH CD O CO Sh < in p CN CD P CM o in 00 in CP rH CM o O'! 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CO D • • CD O 5h P O co .r * i < i—i cc o' * Table 7.3 that these companies' productive leases accounted for 59 percent of total crude oil production. Since about 92 percent of all productive onshore Federal leases (accounting for roughly 97 percent of productive acreage) were let by noncompetitive methods, the data from tables 7.3 and 7.6 can be presumed to reflect the lease distribution results obtained under a noncompetitive system. The final distribution of productive lands among major and independent companies after lease transfers may be much the same under noncompetitive leasing methods as it is under competitive methods. One supporting indication is observed in the results of competitive Federal lease sales. These sales involve only lands likely to be productive because they cover known geologic structures. The above-cited BLM study found, for a sample of 326 competitively issued Federal leases, that 39.3 percent of the leases were originally won by the majors, and another 5.8 percent were assigned to the majors, for a total of 45.1 percent. 47 / 47 / Abt Associates, Inc., op. cit ., p. 203. - 462 - This figure does not greatly exceed the 39 percent of all Federal producing leases owned in 1974 by the 17 companies listed in Table 7.6 even though the BLM figure was based on a larger number of firms. There is another indication that the final distribu¬ tion of desirable leases between majors and independents may not vary much with the type of leasing method, competitive vs. noncompetitive, used. The BLM study compared drilling activity on State and Federal lands in Colorado, New Mexico, and Utah. Most of the State lands were let competitively and most of the Federal lands non- competitively. If the majors were relatively more successful in obtaining good leases through competitive bidding, one would expect the percentage of wells drilled by the majors on State lands to be higher than the per¬ centage drilled by them on Federal lands. In fact, the percentage of wells drilled by the majors on Federal lands was higher than on State lands. On State lands, only 991 out of 2,385 wells (41.6 percent) were drilled by majors. On Federal lands, 1,502 out of 3,047 (49.3 percent) were drilled by the majors. 48 / 48/ Ibid ., pp. 205-209. - 463 - In summary, the available evidence indicates that majors and independents fare about the same under competitive vs. noncompetitive Federal leasing methods. Independents appear to be viable under both systems, capturing perhaps half of the competitive leases. 49/ Those benefiting most from the noncompetitive system are probably speculators, who win leases under simultaneous filing and then sell them for their true market value to either major or independent producers. Speculators perform a valuable function in many markets. But there appears to be no purpose in this case in allowing them to achieve revenues which could be easily captured by the Government if the simultaneous filing system were replaced by competitive leasing. 50 / 49 / A study of 891 leases issued by the Navajo Indian Reservation between 1953 and 1967 also verified this conclusion. Most of the leases were offered under a fixed royalty, bonus bid system. Eighteen of the largest integrated petroleum companies won 43.5 percent of the tracts offered. Ibid. , p. 231. 50 / Competitive leasing could also be extended to tracts currently leased over the counter. There appear to be no strong reasons for a change in this case, but no harm would result so long as all lands nominated by individuals desiring to lease them were rapidly put up for lease. - 464 - If competitive leasing were adopted for lands currently leased by noncompetitive methods, bidding competition should be relied upon to ensure the collection of fair market value, even though there would probably be many sales with only a single bidder or a few bidders. Since the value of most of the land involved is highly speculative, very low bids are often appropriate. Expend¬ ing substantial resources in an attempt to evaluate the lands prior to sale (as is done for offshore leases) would probably result in reduced net Government revenues. In most cases, the judgment of a trained geologist who has reviewed the high bid, the available geological informa¬ tion concerning the tract to be leased, and the produc¬ tivity of surrounding tracts could be relied upon to screen out bids which are too low. Only on rare occasions should more extensive post^-bid analysis be necessary (e.g., in the case in which a few bids are received for a tract, and all are considerably lower than bids which have been made for similar tracts). An indication that this bid review system is cost-effective is that it is used by the Navajo Indian Tribe, 51 / which has had much experience in leasing onshore lands. Since the Tribe 51/ Ibid ., pp. 217-242. stands to gain or lose directly on the basis of its bid evaluations, its selection of the selective post-bid review method in selling rights to its considerable oil and gas resources constitutes a strong endorsement. Summary and Conclusions The stated goals of the Department of the Interior in leasing energy resources are: (1) To assure orderly and timely resource development; (2) To protect the environment; (3) To insure the public a fair market value return on the disposition of its resources. 52/ Weighed against these self-proclaimed goals, the Department’s leasing policy for onshore oil and gas lands has been only partially successful. Protection of the environment does not appear to be a serious problem in onshore oil and gas leasing. Assuring orderly and timely resource development has been left primarily to the market mechanism. since so little is known about the socially optimal time path of development, it is hard — 7 S^-eral Leasing and Disp osal Policies , op. cit - 466 - to show that such reliance is unwise. The adverse efficiency effects of percentage royalty requirements and maximum lease sizes are difficult to assess, but they have probably not been severe. Only in allowing State market demand prorationing to apply to Federal lands may the Department have fostered serious inef¬ ficiencies, and those are of more historical than current interest. The final goal—securing a fair return on the disposition of public resources—has probably been achieved on leases issued through competitive bonus bidding and on the initial assignment of noncompetitive leases. For the majority of leases, however—those let by the noncompetitive simultaneous filing system— fair market value has probably not been obtained. Although the revenue foregone on these leases has been miniscule in comparison with total Government revenues, there is no good reason why such leases should not be allocated through competitive bonus bidding. Maintaining and encouraging competition is not an expressed goal of Interior Department leasing policies. Our analysis indicates, however, that while Federal onshore oil and gas resources are too limited to affect - 467 - the structure of the petroleum industry greatly , existing leasing policies have not had adverse effects on competition. Chapter 8 OIL SHALE Importance of Federally-Owned Resources Although extensive areas of the United States are known to contain oil shale deposits, the magnitude and quality of the resources in the Green River Basin of the Rocky Mountains make all other deposits insignifi¬ cant by comparison. Oil shale contains kerogen, an organic material which yields crude oil when it is heated. In a relatively concentrated area of approxi¬ mately 25,000 square miles (about 16 million acres), extending over parts of Colorado, Utah, and Wyoming, are 17,000 square miles believed to contain about 600 billion barrels of crude oil in high-grade oil shale, and perhaps 1,200 billion barrels of oil in lower-grade -469 oil shale. 1/ In contrast, a recent report by the Department l of the Interior estimates that there are between 50 and 127 billion barrels of undiscovered crude oil in the United States, 2/ and that at the end of 1974 there were 34 billion barrels of measured crude oil reserves. 3/ While these figures are rough and different researchers make quite different reserve estimates, one major fact is clear: when and if it becomes technologically, environmentally, and economically feasible to produce crude oil from oil shale, shale 1/ "High-grade" oil shale is at least 10 feet thick and averages 25 or more gallons of oil per ton, whereas the lower-grade oil shale mentioned above might contain 15 to 25 gallons per ton. See: U.S. Federal Energy Administration, Project Independence Blueprint, Final Task Force Report, Potential Future Role of Oil Shale: Prospects and Constraints , under direc¬ tion of U.S. Department of the Interior, November, 1974 (Washington, D.C.: Government Printing Office, 1974), pp. 89-96. 2/ U.S. Department of the Interior, Geological Survey, Geological Estimates of Undiscovered Oil and Gas Resources in the United States , Geological Survey Circular 725, table 7, pp. 4,5. 3/ Ibid. - 470 - could greatly expand the U.S. oil supply. However, the timing of commercial feasibility is not yet evident. Whether oil shale production will be profitable depends, among other things, upon the price of substitutes (imported and domestically produced crude oil), develop¬ ments in oil shale technology, the availability of necessary inputs to the oil shale retorting process (especially water), and the solution of environmental problems (especially what to do with the waste product, spent oil shale). All these factors are highly significant for the Federal leasing program, since an estimated 72 percent of the oil shale land in the Green River Basin is public domain, and this land contains an estimated 80 percent of the high-grade deposits. 4/ It is not obvious, however, that the land is under clear Federal control, since it has been subject to unpatented mining claims over the years. A 1968 Department of the Interior study indicated that much of the Green River Basin £/ U.S. Department of the Interior, Prospects for Oil Shale Development-Colorado, Utah, and Wyoming, May, 1968, p. 3. - 471 - public land thought to contain oil shale is subject to such claims. 5/ Table 8.1, which is derived from data presented in that study, indicates the ownership status of Green River Basin oil shale lands by acreage and potential resource availability in 1968. The Department of the Interior has recently attempted to clarify this ownership situation. It evidently expects that many of the unpatented claims on public oil shale lands will not prove to be valid. By mid-1974, all of Wyoming's 2.6 million acres of land with clouded title, half of Colorado's 1.1 million acres, but none of Utah's 3.0 million acres had been cleared in favor of the Government. 6/ Assuming that no unforeseen reversals occur in this title clearing process, the ownership status of Green River Basin deposits should not remain clouded much longer, and the Federal Government should regain clear title to most of the public land containing oil shale. Table 8.2 shows Government-owned resources as a percentage of 5/ Ibid ., pp. 32-34. 6/ Potential Future Role of Oil Shale: Prospects and Constraints, op. cltT^ pp. 92-98. - 472 - TABLE 8.1—Ownership Status of Green River Basin Oil Shale Lands by Acreage and Potential Resource Availability, 1968 Federal lands Non Oil yield from oil shale Clear title Clouded title Total Federal lands Total lands Acres of land (thousands) Low grade or unappraised 600 3,600 4,200 1,695 5,895 15-25 gallons per ton 370 1,700 2,070 840 2,910 Over 25 gallons per ton 200 1,400 1,600 600 2,200 Total 1,170 6,700 7,870 3,135* 11,005 Barrels of oil (billions) 15-25 gallons per ton 200 700 900 250 1,150 Over 25 gallons per ton 90 390 480 110 590 Total 290 1,090 1,380 360 1,740 * Note: Figures from original source were changed so that totals are correct. Source: U.S. Department of the Interior, Prospects for Oil Shale Development: Colorado, Utah, and Wyoming, May, 1968, appendix A. -47 2A- TABLE 8.2—Governirient-owned Shale Resources as a Percentage of Total Resources, Green River Basin, 1968 Oil yield from oil shale Percent of acres Percent of of land barrels of oil Over 25 gallons per ton 73 81 15-25 gallons per ton 71 78 Low grade or unappraised 71 N.A Total 72 1/ 79 N.A. - not available 1/ Excluding any estimate of barrels of oil in land containing low-grade or unappraised oil shale. Source: Table 8.1. -472B- total resources in the Green River Basin, assuming that the Government will gain clear title to all of the claims clouded in 1968. To date there has been no large scale commercial production of shale oil in the United States on public or on private lands, but many observers believe that shale oil will assume increasing importance as an energy source over the next 30 years. Because produc¬ tion has been minimal, this chapter will devote only brief attention to past leasing policies. Instead, major emphasis will be placed on the Government's ability to influence future oil shale production. Past and Present Leasing Policies Under the Mineral Lands Leasing Act of 1920, the Secretary of the Interior is responsible for the leasing of oil shale deposits on public lands. The Secretary is empowered to lease to any qualified person or corporation "... any deposits of oil shale - 473 - ‘ . . . belonging to the United States and the surface of so much of the public lands containing such deposits, or land adjacent thereto, as may be required for the extraction and reduction of the leased minerals.. . ."7/ The Act gives the Secretary broad discretionary power in setting lease terms, including the length of time for which the lease shall be granted, the royalty rate to be paid, and any "covenants relative to methods of mining, prevention of waste, and productive development." 8/ The statute includes a provision for an annual rental of 50 cents per acre, but this rental can be credited against the year's royalty payments. In order to encourage development, the Secretary is empowered to waive both the royalty and rental payments in the first five years of the lease. Royalty rates are renegotiable at the end of each 20-year period. 7/ 30 U.S.C. § 241. 8/ Ibid . - 474 - Only two provisions in the 1920 Act limit the Secretary's authority in shaping the provisions of shale leases. The size of any one lease is limited to 5,120 acres of land, and no individual or corpora¬ tion is permitted to hold more than one lease in the United States. 9/ Oil shale lands have not always been leased. At the time of the first significant commercial interest in oil shale, when from 1915 to 1920 there was fear of a crude oil shortage, oil shale lands fell under the provisions of the Mining Law of 1872. Any citizen or declared prospective citizen who discovered a valuable mineral deposit on Federal land was entitled to stake a claim and work the deposit without rendering any accounting to the Government concerning the revenues received. Although not required and not often sought, a patent to a claim, conveying the United States' rights to the land, could be obtained. In 1920, however, 9/ On April 24, 1974, in a memorandum to the Director of the Bureau of Land Management, the Solicitor of the Department of the Interior ruled that a person, association, or corporation may hold interests in more than one oil shale lease if the pro rata shares of such leases in terms of acreage do not constitute more than an aggregate of 5,120 acres. - 475 - the Mineral Lands Leasing Act included oil shale in the list of minerals which were removed from the claiming provisions of the 1872 Act and which could subsequently only be leased. In 1930/ an Executive order by President Hoover withdrew lands containing oil shale from leasing or any other type of disposition. 10/ Nevertheless, in 1966 there was a claims rush on Colorado oil shale lands, apparently in response to reports of the presence of aluminum in the dawsonite found interspersed with the shale. These were the claims on which the Interior Department is currently engaged in clearing title in order to avoid conflicts with future oil shale claims. 10 / For more detail, see the Statement of Secretary of the Interior Wilber, contained in U.S. Senate, Committee on Public Lands and Surveys, Oil-Shale Lands , Hearings on S. Res. 379, hearings transcripts, 71st Cong., 3d sess., Jan. 31-Feb. 27, 1931, p. 213. - 476 - A renewed effort at oil shale leasing was initiated in 1968, when the Interior Department, without solicit¬ ing tract nominations from industry, selected three oil shale tracts in Colorado for leasing. 11/ One tract received two bids, a second tract received one bid, and the third tract received no bids. All bids were rejected because they were far below the Department's "minimum acceptable bids." The Prototype Oil Shale Leasing Program In response to President Nixon's clean energy message of June 4, 1971, the Secretary of the Interior initiated "a leasing program to develop our vast oil shale resources, provided that environmental questions can be satisfactorily resolved." 12/ Two tracts each in Colorado, Utah, and Wyoming were offered for sale, one each month starting in January 1974. The tracts were offered using competitive bonus bids with fixed 11 / For the 1968 lease provisions, see "Oil Shale Lease Form No. 1-Rev. December 10, 1968," in 33 F.R. No. 242, December 13, 1968, pp. 18523-18525. 12 / U.S. Department of the Interior, "News Release," November 28, 1973. - 477 - royalties and fixed rental payments. Bidders were allowed to make the bonus payments in five equal annual installments, so that at an interest rate of 12 percent, the present discounted value of the bonus payment is only about 80 percent of the nominal value. In addition, development expenditures made within the first three years may be credited against the fourth bonus payment, and development expenditures made in the fourth year may be credited against the fifth bonus payment. If the lease is surrendered before the fifth anniversary, the final two bonus payments are forgiven. These conditions were evidently intended to decrease the risk to bidding firms, and thereby to make the leases more attractive to industry than had been the case in 1968. The 1974 prototype lease provisions differ in other important respects too from those embodied in the 1968 offering. The earlier provisions required the compul¬ sory licensing of new technology after five years and a minimum level of shale oil production beginning on the eighth anniversary date (unless excused due to a failure in technology). The 1968 provisions also permitted the Government to publish development data. -478 In contrast, the 1974 leases do not include the patent licensing provision, the diligence clause, and the development data publication provision. The prototype leasing program has a number of at least partially conflicting goals. The stated objectives of the program are: 13/ 1. to provide a new source of energy to the Nation by stimulating the development of commercial oil shale technology by private industry; 2. to insure the environmental integrity of the affected areas and at the same time to develop a full range of environmental safeguards and restoration techniques that will be incorporated into the planning of a mature oil shale industry, should one develop; 3. to permit an equitable return to all parties in the development of this public resource; and 4. to develop management expertise in the leasing and supervision of oil shale development in order to provide the basis for future administrative proce¬ dures . The program is therefore one of limited scope. It is designed to make some of the high quality oil shale 13 / Ibid. - 479 - in the Government’s possession available for commercial development while maintaining the Government's preroga¬ tive to ameliorate the social costs of massive private oil shale development. Of the six tracts offered for lease in 1974, the four tracts in Colorado and Utah were actually leased. According to Interior Secretary Morton's decision statement on the prototype leasing program, "The Department is committed to withhold further leasing of public oil shale lands . . . until the environmental effects of these prototype leases are better known." 14 / However, the Department announced in April 1975 that it will offer two additional tracts for a joint industry/ Government effort to accelerate the development of in situ shale oil recovery. Economic and Technological Conditions of the Industry At present there is no operating shale oil industry, but the vast quantities of oil contained in 14/ Ibid . - 480 - f U.S. oil shale deposits and the shrinking or uncertain availability of conventional energy sources provide an environment conducive to developing such an industry. The social importance of U.S. oil shale resources depends crucially upon the economic and technological conditions under which oil shale can be mined and transformed into a shale oil competitive with crude oil and alternative synthetic liquids. When oil shale is retorted (i.e., heated to release the oil from the shale), the yield is a low gravity, high nitrogen, moderate sulfur crude oil of high viscosity. Through modest upgrading, this oil can be converted to a synthetic crude oil suitable for ordinary refining into the whole range of petroleum products. Thus, shale oil is an almost perfect sub¬ stitute for crude oil, and the supply of shale oil will depend upon the amount of oil shale that can be mined, retorted, and delivered to the refinery at or below the cost of crude oil. To understand the influence leasing policy can have on oil shale development, we discuss in this section the economic and technological conditions facing potential entrants into this nascent industry. Since it is not yet clear whether large scale oil shale production will be both technically feasible and 4 8,1- 4 commercially viable, it is premature to consider in detail the possible impact of current leasing policy on such goals as the rate of production, efficiency in production, the maintenance of competition, and the generation of Government revenue. Only after the technology has been proved through full scale operations can the Government decide what conditions it may wish to impose on any additional leasing. Uncertainty and Risks There has been no large-scale commercial develop¬ ment of an oil shale industry to date, largely because there is considerable uncertainty about the economic viability of such an industry. Areas of uncertainty include resource availability, the technological feasibility of commercial scale production, development costs, market prices, and Government policy. Each will be discussed in turn. 1. Discovery and Resource Risks Oil shale deposits show considerable diversity - 482 - with respect to thickness, oil content, and accessibility. Hence, the characteristics of any particular oil shale deposit cannot be known without exploratory effort. However, core drilling and other exploration are capable of establishing a deposit's characteristics with considerable precision. Therefore, the acquisition of an oil shale deposit is subject to much less uncertainty with respect to ultimate resource availability than, for example, the acquisition of an offshore oil or gas property. 15 / While large areas of the U.S. are known to contain oil shale, recent exploration and leasing have been concentrated on the most promising oil shale deposits in the Green River formation. 16 / Should there be increased leasing, uncertainty about the availability of oil shale resources in less explored areas should not be a serious constraint on the industry's development. Another major source of uncertainty is the 15 / B. Delworth Gardner, "Toward a Disposal Policy for Federally Owned Oil Shales," in Extractive Resources and Taxation , edited by Mason Gaffney (Madison: The University of Wisconsin Press, 1967), p. 184. 16 / Potential Future Role of Oil Shale: Prospects and Constraints, op. cit., p. 89. - 483 - availability of water, which is needed in large quan¬ tities for surface retorting of shale. For example, it has been estimated that an underground mine producing 50,000 barrels of oil per day through above-ground retorting would require 6,060 to 9,600 acre-feet of water per year. 17 / While some energy companies already have substantial water rights in Colorado, Utah, and Wyoming, other firms interested in obtaining such rights may be unable to obtain them, even though they might be prepared to bid higher than some existing owners, because Federal and State laws and regulations constrain alternative uses of water and the transfer of water rights. 18/ 2. Technological Risks Technology for oil shale development is subject to even more uncertainty. What is best may vary according 17 / U.S. Department of the Interior, Final Environmental Statement for the Prototype Leasing Program, Vol. 1 ; Regional Impacts of Oil Shale Development , (Washington, D.C.: Government Printing Office, 1973), table III-5, p. III-34. 18 / See, for example: Jack Hirshleifer, James C. De Haven, and Jerome W. Milliman, Water Supply: Economics , Technology, and Policy , (Chicago: The University of Chicago Press, 1969), pp. 222-254. - 484 - to the characteristics of individual shale deposits. The technique for recovering oil from oil shale with which there is the most experience is mining combined with surface retorting. However, some observers believe that the technique that may ultimately be more efficient is in situ recovery, by which the resource is retorted while still in the ground and liquid shale oil rather than oil shale rock is brought to the surface. 19 / Neither of these techniques has been established on a commercial scale. Mining and surface retorting have been conducted in demonstration projects considerably smaller than the 50,000 to 100,000 barrels-per-day scale envisaged for commercial production. In situ projects are still mostly in the experimental stage. 19 / Potential Future Role of Oil Shale: Prospects and Constraints , op. cit ., pp. 259-297; Prospects for Oil Shale Development-Colorado, Utah, and Wyoming , op. cit. , pp. 40-73; and Energy from Oil Shale; Technical, Environmental, Economic , Legislative, and Policy Aspects of an Undeveloped Energy Source , report prepared for the U.S. House of Representatives, Committee on Astronautics, Sub¬ committee on Energy, 93d Cong., 1st sess., 1973, pp. 9-14. j-4 85- The technological uncertainties which remain with respect to surface retorting relate mainly to scaling up demonstration projects to full-scale commercial levels. The mining technique with which there has been the most oil shale experience is the room-and-pillar method, but this method is suitable only for the richer and more accessible deposits of less than 100-foot thickness. It has the further disadvantage of leaving considerable amounts of the resource unrecovered. 20 / Also, the extraction rate of approximately 175,000 tons per day needed to supply a 100,000 barrels-per-day production facility is far beyond current mining experience--about 60,000 tons per day. 21 / In those few areas where it is currently feasible without major environmental disruption, open pit mining offers the chance of a much higher recovery rate than underground 20 / See U.S. House of Representatives, Committee on Science and Astronautics, Oil Shale Technology , Hearings before a Subcommittee on Energy on H.R. 9693, 93d Cong., 2d sess., May 8, 1974, pp. 17, 18. 21 / Dr. Charles Prien of the Denver Research Institute has estimated that large-scale room-and-pillar mining will require an operation approximately 60 times the scale of present technology and four times any shale mining rate attained to date. Letter to Federal Trade Commission, Bureau of Competition, dated May 9, 1975. - 486 - or in situ recovery, but any large-scale attempt to employ surface mining must come to grips with the problem of truly enormous damage to the surface environ¬ ment. If proved feasible, both cut-and-fill and block caving underground mining systems offer advantages over room-and-pillar systems with respect to recovery rates and thicknesses which can be mined. Some such advantage will have to come if the thick, rich deposits of the Piceance Creek Basin of Colorado, where most of the best federally-owned resources are located, are to be developed successfully. Several different methods of above-ground retorting have been developed. All require crushing the shale before processing, but the crushing process does not seem to have any technological difficulties and repre¬ sents a small element in the cost of producing shale oil. The processes do, however, differ from one another in the degree to which the oil shale input must be free of too finely crushed rock and the severity of a dust problem. All above-ground retorting processes yield a higher volume of spent shale than the volume of unprocessed shale input. Hence, the waste disposal - 48 ?- problems of a large-scale shale oil industry based on above-ground retorting will be considerable. The most important source of retorting technology uncertainty, however, concerns engineering problems which must be solved in scaling up existing demonstration-sized processes to commercially feasible levels. 22 / Research is continuing, but thus far the above-ground retorting technology has not been demonstrated on a commercial scale. In situ processing is even less well developed, but it has recently drawn research interest because of the advantages it offers over above-ground retorting processes. Since the retorting takes place in the ground, there are less materials handling and lower processing costs as well as considerably reduced waste disposal problems. Water and manpower needs are also lessened. Very thick, badly faulted, and deep deposits can be exploited more easily and ultimate recovery is greater, since lower grade shale deposits are amenable 22 / Potential Future Role of Oil Shale: Prospects and Constraints, op. cit., pp. 259-294. .-488- to in situ processing. 23/ Apart from the fact that in situ development is still in the experimental stage, a possible problem is that valuable minerals such as aluminum which occur in oil shale deposits cannot be recovered concurrently with the shale oil. If a successful in situ process can be developed, however, the processing costs and environmental disruption from shale oil production should be reduced and the ultimate recoverability of shale oil increased over mining and surface retorting processes—if not at first, then later when the areas most suited to mining and surface retort¬ ing have been depleted. Because there has been no experience with large- scale commercial shale oil production, estimates of commercial production costs remain uncertain. Although numerous estimates have been generated, it is difficult 23 / For a comprehensive discussion of the alleged advantages of in situ processing by a company which has engaged in substantial in situ research, see the statement of Donald Garrett, Garrett Research and Development, a subsidiary of Occidental Petroleum Corp., before the Subcommittee on Mines and Mining of the Committee on Interior and Insular Affairs, U.S. House of Representatives, Hearings on Information on Oil Shale Development , November 29, 30; December 3 and 4, 93rd Cong., 1st sess., 1973, p. 124. -489- to compare them since they vary so widely with respect to assumptions about size of plant, mining technology, retorting technology, oil shale characteristics, etc. Table 8.3 presents the cost estimates prepared by the Bureau of Mines for the Project Independence Oil Shale Task Force. According to that report, a 100,000 barrels- per-day facility would have capital costs of $520 million or $600 million, depending upon whether underground or surface mining techniques were used. However, a more recent estimate by the Colony Development Operation suggests that a 50,000 barrels-per-day facility might have capital costs above $800 million. 24 / Not only are the cost estimates themselves uncertain; they also do not include the development and shakedown costs normally associated with implementing a new technology and which must be borne by the firms which first initiate shale oil production on a commercial scale. It seems clear that the early cost estimates were overly optimistic. For example, in 1973 the Colony Development Operation estimated that construction costs for their 50,000 barrels-per-day plant would be $450 million. But by 24/ Business Week, April 28, 1975, pp. 87, 88. -490- TABLE 8.3—Estimated Capital and Operating Costs for Shale Oil Production (Millions of dollars) Capital Process Costs Underground mining, 50,000 barrels per day from 30 gallons per ton shale 280 Underground mining, 100,000 barrels per day from 30 gallons per ton shale 520 Operating Costs per year 45 80 Surface mining, 100,000 barrels per day from 30 gallons per ton shale 600 80 In situ , 50,000 barrels per day from 22 gallons per ton shale 380 140 Modified in situ, 50,000 barrels per a) day from 18 gallons per ton shale 310 110 b) 25 gallons per ton shale 280 90 Source: U.S. Federal Energy Administration, Project Independ ence Blueprint, Final Task Force Report, Potential Future Role of Oil Shale: Prospects and Constraints 1974, table III-l, p. 65. -490A- 1974 the projection for 1977 had jumped to more than $800 million, and construction was suspended indefinitely. 25/ An additional problem which might deter develop¬ ment is fear of technological obsolescence. As more experience is gained, new oil shale processing tech¬ niques will probably be developed which are cheaper and better than the processes installed by initial entrants. Recognizing this possibility, some firms may be reluctant to enter. Indeed, uncertainty concerning such changes may have been an important consideration in the decisions of some early shale technology developers to defer investing in commercial conversion plants. 3. Market Risks The technological and developmental cost risks of bringing shale oil production up to commercial levels are complemented and exacerbated by substantial 25 / Wall Street Journal , October 7, 1974. -491- uncertainty about the future prices at which shale oil can be sold and the attitude the Government will adopt toward shale oil development. According to Bureau of Mines cost estimates prepared in the fall of 1974 for the Project Independence Blueprint Report, at average world oil prices of $4 per barrel, shale oil production is not sufficiently attractive to undertake private development. At $7 per barrel, after tax rates of return calculated on a discounted cash flow basis will be in the neighborhood of 15 percent, while at $11 a barrel they will be about 20 percent. 26 / The 20 percent return should surely be sufficient to attract industry interest. Based on this analysis, the Bureau of Mines estimated possible shale oil production levels through 1990, which are shown in table 8.4. However, these production forecasts appear overly optimistic in view of recently rising cost estimates. It now appears that even at $11 per barrel, it may not be profitable to undertake oil shale production. 26 / All prices were estimated in 1971 dollars. -492- TABLE 8.4.—Shale Oil Production Potential Development schedule World Oil price (dollars/ bbl.) None $4.00 Business as usual $7.00 Accelerated ment develop- $11.00 Shale oil production (thousand barrels per day) 1977 1980 1985 1990 0 0 0 0 0 50 250 450 0 100 1,000 1,600 Source: U.S. Federal Energy Administration, Project Independ¬ ence Blueprint, Final Task Force Report, Potential Future Role of Oil Shale: Prospects and Constraints , November, 1974, table 1-1, p. 8, and pp. 64-69. -492A- Moreover, the rates of return and production levels could be reduced, perhaps substantially, if very strict environmental standards are imposed or if the depletion allowance is reduced significantly below its current figure of 15 percent. No one knows the future course of world oil prices, and the Government has not yet formulated a definitive oil shale policy. Hence, considerable uncertainty concerning shale oil profit¬ ability can be expected to persist for some time into the future. In summary, uncertainty about the technological characteristics and costs of commercialization combine with uncertainty about the economic environment in which shale oil will be sold to make oil shale development investment quite risky and costly. If world oil prices remain high and alternative energy sources such as offshore oil and gas and alternative synthetic fuels fail to materialize in sufficiently large quantities, the payoff from oil shale development could be sub¬ stantial. Conversely, if world oil prices fall sufficiently, there may be no private payoff from oil shale development within the next 20 years. This uncertainty can affect the realization of leasing policy objectives if potential investors are risk-averse and offer bonus bids substantially lower than the expected value of the resource deposit. The maximum amount a company should be willing to pay to acquire the rights to an oil shale deposit is the dis¬ counted present value of profits from the production of shale oil and any associated by-products, over and above the minimum profits required to attract that firm's investment. Competition among risk-neutral bidders provides reasonable assurance that this maximum amount will have to be offered by the purchaser who actually acquires the property. When bidders are risk-averse, however, offers will be lower, all else equal. There is no conclusive indication whether potential oil shale investors are risk-averse or not, or whether they are more or less risk averse than other energy companies. It has been noted that only token bids were offered in the 1968 lease sale; whereas bids sub¬ stantially in excess of Interior Department expecta¬ tions were received in the 1974 sale. However, the low bids in the 1968 oil shale lease sale might be explained -.494- by the bidders' reaction to the stringent patent and disclosure provisions or by the relatively low cost of conventional crude oil at that time rather than risk aversion. Interior's presale evaluations were based on world crude oil prices of $3.74 per barrel for the estimates on one tract and $6.70 on the other tracts, 27 / but the bidding companies probably had in mind $8-$12 oil prices by the time the sale took place. Consequently, there is no clear evidence that oil shale bidders either are, or are not, risk-averse. Lease Acquisition Costs If the amount of money that must be offered to acquire oil shale rights is substantial, small operators may be precluded from bidding, with possibly detrimental consequences for the competitiveness of the industry. Table 8.5 presents data on the 1974 prototype leasing sales showing various measures of what acquiring an oil 27/ See U.S. House of Representatives, Permanent Select Committee on Small Business, Subcommittee on Activities of Regulatory Agencies, Energy Data Requirements of the Federal Government, Part II , Oil Shale , Hearings, 93d Cong., 2d sess., January 28, 1974, pp. 58-62. -495- TABLE 8.5—Winning Bids in the 1974 Prototype Leasing Sale 44 c •P g d) H 44 0 44 CO i—1 c — CD rH i — 1 CM a co P O CD CD *d CO G •P 44 (D -P CQ 0 P o CM CD p o •H 44 PQ —' 0 'd d 43 G — CO rH 00 00 P d co • • • • CD CO p rH ro 00 add 0 rP ■d x: •H e p rH rH rH •p a) rH p CO •H CO CD B \ w p rH | CM | •p 1 CM Tract d i 12 cd i 12 1 1 u U i D 1 D c d o P CD Cn O P d CD 44 ■d p G d p cn c o 44 p CD a •H 0 44 o co g o d Cn a) P O e P O co cd > p P d) co co 4 -> c •H d u 44 CO c o O' u p CD i-4 d co o o d) c d to -P o CD a CO 0 P cm CQ CO d) X •P ■d c CD a Q, d cd cn p 44 o CO CD 44 d s •H 44 ■'3* r- d) o H 44 44 CP G r4 44 C H P CM o B CO 44 CO •H CD CD G 44 p d) G CO p d E •p CD O 44 G d •p d p 44 44 p ip CD G o CD > O 44 rP O O G G d U 0 H -P 0 -P 44 44 CD G • • P X! d) • 43 CD +4 44 u CD a o • 44 4 -i CM Q d iH 0 B •H G -p 0 44 -H G 44 G 0 CO 44 CD 43 44 CD 0 e > • • P o CD CD CO O CO P CD d> d P G 0 •P cn CO CO c CM I -495A- shale lease cost. The bids per acre ranged from $8,000 to $41,300, while the bids per ton of estimated oil¬ bearing shale ranged from 11.3 cents to 22.1 cents, and the bids per gallon of estimated oil content ranged from 0.38 cent to 0.74 cent. These amounts appear quite small when the world price of crude oil is above $10 per barrel, or 24 cents per gallon. Evidently, bidders expected substantial development and production costs to squeeze profits, or applied a large risk premium in view of the prevailing uncertanties, or some combination of the two. Nevertheless, the magnitude of the winning bids was large in absolute terms and within the range of the Outer Continental Shelf oil and gas bonus bids which have aroused concern as barriers to entry. The special five-year payment, cancellation, and develop¬ ment offset provisions reduce their size and riskiness somewhat. But even so, the size of the bonus payments was large enough to evoke concern about the ability of small firms to undertake such an investment. There is reason to believe that these bonus payments may have been larger than would characterize a full-scale shale oil leasing program. The tracts leased in 1974 were among the most attractive for oil -496- shale development. Most privately held oil shale properties are of significantly lower quality; and other Government properties, apparently including the unleased Wyoming tracts, are less suited to rapid commercial development using technologies on which there has been the most work. It is not unreasonable, therefore, to suppose that these premium tracts drew premium bids. Also, the first three prototype lease awards took place during the last three months of the Arab oil embargo, when there may have been expectations of continued oil shortages and/or rapidly rising world oil prices. Furthermore, except for an offering of two additional tracts, there is no immediate prospect for the leasing of similar quality oil shale deposits, since the Interior Department's stated goal is to evaluate the prototype sales results carefully and not to lease further properties until that evaluation has been completed. Pressures to accelerate domestic oil production may of course lead to a policy change. However, the plausible expectation that no new tracts will soon be made available may have acted to enhance the value of those few tracts because of possible technological advantages accruing to the first firms. In a fully developed oil shale industry, leases of -4 97- ( varying quality will still receive different sized bids, but if there is no artificial restriction of the supply of oil shale lane, bonus bids should be lower and the acquisition of leases might be less expensive than a direct extrapolation from the 1974 prototype sale evidence would indicate. Age and Structure of the Industry 1. Age of the Industry The oil shale industry is in its infancy, and the current concentration of production and reserve owner¬ ship should not say much about future patterns, since the Government can be expected to lease much more oil shale land if and when the technological, environmental, and economic viability of oil shale production is proven. There are three million acres of potentially valuable oil shale lands and over 100 billion barrels of high quality reserves under private control. These holdings constitute a relatively small fraction of the total acreage believed to contain oil shale—less than 30 percent--and an even smaller fraction of the estimated high quality reserves (about 20 percent). - 498 - i* Furthermore, even the best quality deposits in private hands are deemed to be of marginal commercial importance compared to the deposits on public land. The Project Independence report on oil shale suggests that there are only three to five deposits suitable for commercial production on private lands, excluding those leased under the prototype leasing program in 1974, 28 / but it is unclear how that figure was determined, since there are many other large parcels of oil shale land in private hands. 2. Industry Structure and Concentration of Reserve Ownership Since shale oil must compete directly with crude oil, concentration in oil shale is important only to the extent that it affects overall concentration in petroleum. Table 8.6 lists the winning bidders on the four oil shale tracts leased in 1974. With the exception of the Oil Shale Corp., all of the winning bidders were large oil companies. In addition, 28 / Potential Future Role of Oil Shale: Prospects and Constraints , op. cit ., pp. 98-102. - 499 - TABLE 8.6.—Winning Bidders in the 1974 Prototype Oil Shale Lease Sale Td •H XI TJ 0 ) c m rH 00 00 P rd W • • • • OW}-i rH ro 00 rd c rd CN rH O rH d> -P 0 Ch'-' Td Td •H c — ro 00 UO rH Cn 0 W • • • • C -H p o uo in •H r—1 fd i —i i—i r~ Ci — 1 i — 1 CN rH C’HH •h e o ^ — Td 0 0 Td Td d) rd rd x X -p 5-i p td rd fd 0 o -P -P -p !—1 ■—i Cd D co 0 0 u u 5-1 -P - o c P X * •H fd • Td td 0 o • Td P 0 C d) u o c QJ U I15X • 4H u H a rH +j 0 rH 0 otr u •h e m rH W Td O • P 0 • •P O -H •* 0 cu d) P W r-l d) -H o • U rH > fd d rH Td P Q 4J 0 cn -h •H fp -H -H P U C rH U d) PuO Pi C H O fd >i fd iH 1—1 •H fd i — i Td Td CH OH fd rH C d) -P -H C £ C C o -p x -h x rH P -P CO X P 5h fd rd r-l C CO o CO •H CO •H Pi CO •H -t-1 O x x pm CO u (1 [2 -49 9A- Source: Potential Future Role of Oil Shale: Prospects and Constraints , appendix table B-l, appendix pp. 17, 18. all the winning bidders except Ashland Oil Co., Inc., apparently already possess some private oil shale land (cf. table 8.7), and at least five of the nine companies appear to control more than one billion barrels of shale oil reserves each. Evidently, there has been no complete survey of private ownership of oil shale lands, and different sources report substantially different estimates of ownership. A Project Independence report listed 16 oil companies with private holdings totaling some 238,780 acres of potentially valuable oil shale lands in 1974. These companies and their holdings are listed in the top part of table 8.7. However, other sources listed 10 additional oil companies with oil shale holdings in 1967. It is unknown whether those companies retained their private holdings in 1974. Those earlier sources also listed a number of non-oil companies with oil shale holdings in 1967, whereas the 1974 Project Independence report did not provide any estimate of shale holdings by non-oil companies (see table 8.7). Table 8.7 also includes 1967 estimates of oil shale reserve holdings, where that information was available. However, there are large discrepancies - 500 - TABLE 8.7.—Estimated Holdings of Private Oil Shale Lands, 1967 and 1974 r~ co cr> m rH o TO U) 0 w C -p •P r—1 6 P rH (U •H 0) rH p -P w •H p W CD XI to w P 43 cooootNiiruo^HnmHnm^HO f'- m oj n n o\ h P *P o o p to c to •H P 0 •H rH u tO 0 O M (L) i—1 S U cp • Eh 0 •P u •p rH •H to to O g Oh o a to p u o o •p o 04 rH M rH rH p P 1 g i—i TO g •p dj P rH TO d; P e •H g 0 to •P (0 -H g 0 p -p p d) rH g g ro g P (0 •H X -P rH p tO X g P rH 04 CO CO CO EH s p p 43 •H 1—i 6 p X 0 •H (I) i—1 P -p CO •P P CO 0 XI fd w p XJ 2 & cm 2 2 l£> P- < iH CX> VO (N CO 2 H H H CO P x 0 t-* P u fd 3 P • P • u •H • E •P a 0 CO H PP o G a p E G rH 0 p •P CJ 0 fd p 0) P fd T3 0 •P CO 0 fd rH a 0 rP a) • G p G VM u Oh T) rd E u 0 rH • 13 O fd -p i •P G 0 (D -H a) rH •H 03 P CO a P rH rH fd -P >1 CO -P T3 O rH 0 o G 03 P e -P o rH p -p x •H i—1 g •H 0 > 0 X X 0 0 0 G •H a/ p co P >i fd U G p CD a) •p fd CO X u a *H x E D 1 P OXG O P -p rH £1 G X a) x C/3 CM < W 2 XI c/3 c/3 o co Q) u En D D 5: O p CM 0 r- X vo • 1 G -P cp 0 O rH rH CN 3 4 5 mo r~ 00 r-t 2 rH CM n x IT) fd X fd T3 c (d p X E • • 0 03 P ■p p • P X 0 O ■p u P o • fd • X X in X i—i X a O O O 03 03 to •—i X CO X G CP 03 CO rH 03 (d O G CO X ftf o E X •H CO G S£ P •H p p •P P X P fd CM fd T3 0 to 03 03 P G CO 03 ax >i X td 03 X to Oh 03 CO G • *» 1 — I G (0 X O rH X fd 0 p G CJ O fd X 1 — 1 •p 03 rH P to X fd E 03 P rd x 03 G • X X tJiX X fd CM fd *p < rd 2 O in X to rH p to X in E P CO X G P r" 04 M 03 fd CO VO • CO O 03 G cp 00 0 03 P P M rH m p rp P fd 0 X CM X O T3 'P V. p • 0 03 CTi X p c 03 X 0 rH CO 03 •p X CO G tp to C rH -P ■p rH 03 1 — 1 x CP O 03 •P CM •p »- G O O 0 G • W X •P O CP 0 X P • X G G X o 0 03 o O 0 O X i—1 03 U P rp VO G X 0 o tn x O X X E DC G 03 • X •H X fd •H X CM o CJ a) X P p g CPi p G td 03 o X p •H 2 m au 0 X p E p CM P 0) to rd ■p Oh d) i — 1 G 03 P p X >i£* O X CP rd i—i G p rH rd O O fd 03 PQ -P rH G P CQ •p g fd 03 CM X 2 0) CP C/3 0 G p X 03 X 0 03 X CO 0) • i — 1 X X > 'vD p C/3 fd 0 O X CTv O • X X CM o 0 iH E D CO O r- vo OV co Cn 1 p (U a, o o o o o o r- oo ^ o oo ^ h fo o in ro 'T < V H ^ ^ in CN CO O (N H oo co h* p- ■< 3 ’ o CO 00 CN r-~ ro r-* CN o CN rH o in o o o o ''T 00 ON 00 M0 O', 00 00 rH CO rH ^ ^ K ^ v V ro ro co cn o cn cn ro [—^ m >1 0 -P rH -P ro •H U 0 P 1—1 0 0 0 4 H o p 0 a O 0 •H 13 P P 0 u a in o o o o in CN 63 o O • • • • • • • • • 00 o co o r- 00 o o rH rH cr\ m o in CN (N 1—1 rH rH rH o o o o o o •••••# 00 ro O o o o r'fomooin rH rH CM P 0 •H cn, i —1 1 - 1 rH rH ro ro H 1 4 H •P H 1 in in LO LO in in in in 0 > > P P -P •P 0 P 0 P 0 0 0 P P O O -p a, IP < 2 2 2 h) I'D O O id 0 a p H* CN CO cn 1—1 cn cn O', o CP ,—1 rH i —1 CN i—i CN cu P O id o p 0 0 0 b IS P Q CO li cn o in cn oo CN CN rH rH rH T3 p Id 0 p e 0 id ■H P -P (0 4-» U O ■h 0 r—I -ro a o 0 ^ P < (X o u o u •rH o p o rH -p •p -P -p •H p P p P o 0 0 0 0 • • • E E E E 0 o 0 o a,\ , a a a, U u • u u O col 1 0 o 0 •H 0 rH rH rH rH > u 0 cn •H o u to CD -P P -H P o p > 0 n u u *H o >1 -p ■p 0) •H o p o p > .g o u o u 0 p > o 0 -H a -p id >1 p p 0 o a, i —i o o 0 p > o 0 -H a -p id >. p p 0 o a rH O O U 0 P > o 0 -H a -p p >i p p 0 o CL, rH o o u o u T) •—I 0 •H 4 H o 0 P -H > 0 CP 0 -H Q -P U id -H >i P -P P 0 P O h, 0 ,—I O '—l O -P u —I rH 0 -H U 4h CN r~ l—1 in o in CD rH CO in cn CN CN H* 00 o cn rH CO r-~ CO CO CN 00 CO 00 O', oo o', OC O 1—l i—i rH rH rH rH rH CN o CO CN o >i 3 0 d) ifl < 2 Pti 2 in O) oo vr i—I CN r-1 W 31 CQ < E-) O 3 M & • M u o • 3 u o H u CD **■ I —I MW 0) n) -rl (D (1) H d)£ o > U ID U U) •H M -H M M Oh 3 M 3 r-l 0 0 -P O -H -H 0 cn cn cn O m -P CD 3 CD CD •H Oh T3 Oh CD &l .3 3 £5 3 2 H E-t CO t“H (N O 00 H 00 vo ^ O 00 O '=f oo CO 00 oo Os) CN CN CN rH CD r-H cn 3 3 M g >H 0 0 d 1—1 +J rH u rH cn d cn d -3 o 3 TS cn M 4-) CD M N rH Or ■H -H •H d'' > cn o 3 •rH >1 0 cn • r—1 ,3 d M CD Eh 0 CD -P 31 CD d 3 -H • 0 ■H M 0 t—1 cn CL • u d 3 0 •p -3 w u M T3 • cn Cu 3 i—l 0 CD Du 0 0 u r-H -p d U •rH ■H d 4H 3 o •P CD 0 -3 0 cn -p -P a u 0 d d •H H a 0 u -P Pi • T3 d cm cn -p O d Cu O 44 0 OO M CD 0 •rH 44 4-> 1 0 cn 3) • •P -H 0 H r—1 d 3 H u M 0 >. u 0 d u Oh u u O T3 H 1 • rH M -P T3 0 Oh .3 T3 0 d < 3 ,3 -P CD u 3 d 4-) ■* •H *H d (L) rH ID :? c >1 U CD M 1 d ,3 -P d > O M (D a 0 0 44 M T3 g >i 3 H d 0 0 0 u -P 0 6 O 0 •H 3 rH a U 0 -P ^ 0 rQ cn d d u d 3 g d Cn u m d 0 -P 3 0 d 0 0 -P •H M 'd a - d r—1 d 3 O • •P rH •rH 0 H o cn 14-1 cn 0 d -P u • 3 rQ 3 3 i—i rH U 0 0 0 g d o 0 -H cn •H 6 2 -P > -P -P d -p & 0 3 d d x: •H 0 i—l 0 5 u 'd H 0 g oo •rH • 0 3 0 M 3 r~ g rH cn 0 o > -P 0 o a c SH u 0 0 M t—i M Du 0 o a cu •H 44 d •rH 0 0 > H •P Q 3 >. o 3 u 'O 5 d 1 3 -H EO 0 0 0 o r — 1 1 O -3 3 rH •H d >i H O rH g •H 4H H 3 rH o cn d 0 d O-i 0 3 u 3 > •p -p a •H 0 •» •rH o 3) o d -P 3 3 Eh 0 0 •H ^3 •H O u M 'd 0 •rH d -h •H 3 rH cn -P • • -P td 0 0 •H M d 0 d > U Eh 0 u O V 0 u 3 0 U cn 0 II II -P a, 3 rH 0 cn M M 0 H ,3 0 Q Eh d O cn < -p u O Oh O * \ rH | CN | 001 -512R- TABLE 8.9.—Utah Water Right Applications tv cn tv CO G G G G G •P P ■H •H •P •H •P f0 4-> P X P X P D> to G G G G G 0 4-> 0 o 0 (1) Q) PI CO CL CL CL CL CL 44 0) 44 0) C rP G P 0 P 0 a) 0) fO tO tO fO co a) r—1 i—i ■—1 P X P xj P 4-1 t0 to rO CL CO CL CO to X X -C Q) 3 CO tn CO P >H P rP 4-> Q) -P a> -p fO P r—1 i—i r-H 3 O 3: O 4-> 0 •rH •rH •H O 0 in 44 o o o CL U3 CL <43 44 0 — CD P r- r~ p* in r- P 44 to 140 uo rp1 CO uo CD Q) >1 CO p o o i—i CO o a) O P 1—1 r—i i 0 P 4-1 0 G •H 44 0 4-1 O o o O o o G O CD • • • • • to •H CO LT) in o in uo P X 1—1 c—i ro CM p a p p o 0 CL G O •H 4-1 t>i >1 tO G G P fO to 0 CL CL CL E £ P O O 0 O U • U 4-1 0 P P G U 0 rH rH fO ■—1 0 0 o e to ■H •p •H p X 44 44 pH a) tn x: X CL rH G u O CL 0 r-H O •p •P < p •H CO PS PS 4-1 O P 0) tO U a CL G PI •P •p P 4-> 4-4 0 CL) • G G •H 4-> K tO fO X CO i—1 i—1 0 d) • 4-> 44 tn £ Pm < O G G 0 o rH (V o rp •H ro rH ro f" 4-1 r-~ rH i-H G W 0 4-> fO -P CO X (0 4-1 D X 4-> •H 3 P 0 i—I ■H 4-1 CO G O •H -P tO O cl a res CO -p X tv •H u p 0) -p tO e o u 4-1 P a) G •P tO -P X O to 4-1 to P e fO u Cn O u CL tv G •rH CO to 0 X as i—i to X in •H O 0 -P o +J o p cl ro 0 CX rG 4-> » P o 4-1 CO I M H 4-> G G W t0 G •H Em 0 O P P O CO -512C- Many experts argue that in situ processing is likely to prevail in a mature oil shale industry. Its water requirements are perhaps only one-half to two- thirds as great as those of surface retorting. 4 3 / But if States do not allow water rights to be freely trans¬ ferable, then control of those rights could act as a barrier to entry. Access to high quality resource deposits is currently limited by the Government. If oil shale development becomes profitable on more marginal private lands because of continued high oil prices, and if the Government does not lease its oil shale holdings, control of the available reserves will confer upon major oil companies more market power than they would have if there were extensive leasing of public oil shale deposits to non-majors. The Interior Department plans not to lease further lands except two in situ tracts until the prototype leasing sale has been evaluated fully. But once the private and social costs of oil shale development are better known, a 43/ Potential Future Role of Oil Shale: Prospects and Constraints, op. cit., pT 274. - 513 - pro-competitive leasing policy can eliminate Government reserve ownership as an important barrier to entry. Economies of Scale A discussion of shale oil production economies of scale is difficult, since there has not yet been commercial production on any scale, much less on an optimal scale. The only available information consists of engineering estimates assuming the scaling up of demonstration projects to commercial levels. The Bureau of Mines estimates presented in table 8.3 assume that capital costs for a 100,000 barrels-per-day under¬ ground mining process would be 1.9 times those for a 50,000 barrels-per-day process, and the operating costs would be 1.8 times as great. These are the same scaling factors used in the Battelle computer model for Project Independence. 44 / On rich, thick, accessible deposits, economies of scale may be important. But because it is costly to transport bulky oil shale to the retort, the availability of resources in the 44 / It is not clear, however, on what basis these estimates were made. Potential Future Role of Oil Shale: Prospects and Constraints , op. cit . , appendix D. - 514 - neighborhood of the retort is likely to limit the expansion of individual processing operations# especially since cost savings associated with greater processing volume are apparently not substantial in any case. Nevertheless, it appears that there will be some cost savings from increasing output to at least 100,000 barrels per day, which again suggests that very small firms are unlikely to enter the industry. Externalities Oil shale mining and processing could conceivably cause severe environmental disruption. According to the final environmental impact statement for the prototype oil shale leasing program: An evolving oil shale industry would produce both direct and indirect changes in the environment of the oil shale region in each of the three States of Colorado, Utah, and Wyoming, where commercial quantities of oil shale resources exist. Many of the environmental changes would be of local significance, while others would be of an expanding nature and have cumulative impact. These major regional changes will conflict with other physical resources and uses of the land and water involved. Impacts would include those on the land itself, the water resources, the air quality, on fish and - 515 - wildlife habitat, on grazing and agricul¬ tural activities, on recreational and esthetic values, and on the existing social and economic patterns. 45 / The biggest environmental problem now envisioned relates to disposing spent shale processed in above¬ ground retorting plants. Since the spent shale is at least 12 percent larger in volume than the original material, it will be necessary to acquire land on which the shale can be dumped. 46 / The second major problem will be that water used in processing the shale will not be available for other uses unless it is treated to remove various minerals and organic compounds. 47 / It is not yet clear how much of the water could be recycled for other uses, although some shale oil processes are plainly much more water¬ intensive than others. The third environmental effect will be air pollution caused by mining and retorting. 48/ 45 / Final Environmental Statement for the Prototype Oil Shale Leasing Program, vol. I, 1973, op. cit., p. III-l. 46/ Ibid., p. 1-22. • 47/ Ibid., pp. 1-20 to 1-23 and pp. III-31 to III-114 48_/ Ibid., pp. III-115 to 111-17 0. - 516 - Through its prototype leasing program, the Interior Department intends to gather better informa¬ tion about the environmental impact of oil shale development. It currently maintains that most of the air and water pollution effects can be kept within existing environmental protection standards and that the spent shale disposal problem can be solved. Evaluation of Present Leasing Policies In the section which follows the reader will discover that many of the "facts" concerning past, present, and future leasing policy are subject to varying interpretations by the different authors of this chapter. For that reason, opposing opinions or evaluations will be presented where significant dis¬ agreements exist. Developing a New Technology Any evaluation of oil shale leasing policy must recognize one major fact: unlike offshore oil and gas, onshore oil and gas, coal leasing, and uranium mining, there is no past large-scale production - 517 - experience from which inferences can be drawn about past leasing performance. Indeed, the commercial feasibility of any oil shale technology is yet to be proven. While one can speculate about the future impact of current leasing policies, there can be no definite answers until large-scale oil shale technology has been proven. The costs of a 50,000 barrels-per-day oil shale plant may be as high as $800 million, and there is substantial uncertainty about the future market price for any shale oil produced. This means that if the Government wishes to see large-scale oil shale produc¬ tion facilities brought on stream within the next 10 to 15 years, it may need to encourage or subsidize development of the technology. This suggests that a two-stage development process is desirable. In the first stage, the Government would make enough oil shale land available to allow diverse companies to develop and implement different processes in order to ensure that the most efficient technology is identified and that the industry is not prematurely - 518 - locked into an inferior technology. 49/ The principal criterion for awarding a lease in the first stage would be technological promise. If there are some promising technologies (such as in situ retorting) which no company is willing to try without aid, the Government could provide whatever subsidies are neces¬ sary to conduct a test. It is conceivable that the fastest and most efficient method of getting oil shale technology developed would be for the Government to agree to buy a certain amount of oil (say 50,000 barrels per day for 10 years) at a stated price (say $10 or $15 per barrel) from each of the first six companies to produce shale oil. In any case, during this first stage, the goal of obtaining revenue for the Government would be largely irrelevant; developing the technology is what matters. This also implies that in the first stage the Government should lease no more land than is necessary to induce 49 / See U.S. Senate, Committee on Government Operations, Subcommittee on Federal Spending Practices, Efficiency, and Open Government, Extract from Report of the Commission on Government Procurement , Volume 2, Part C, Acquisition of Major Systems , 94th Cong., 1st sess., (March 1975), pp. 55-36. - 519 - technological development. Such a strategy would allow the Government to retain the rest of the land until it had a better idea of what economic rent it could obtain through subsequent leasing. In the second stage, after the technology has been proven, the Government could lease as much additional land as is consistent with its long-term goals concern¬ ing the rate of production, efficiency in production, industry structure and competition, securing revenue, and environmental impact. Time Pattern of Resource Development Although Government policy has not been consciously conservationist, most of the oil shale best suited to commercial development remains in the public domain and unavailable to private developers. Furthermore, the Department of the Interior has no current plans for extensive further oil shale leasing until the proto¬ type oil shale leasing program has been evaluated fully. Whether or not this policy of withholding oil shale lands from potential developers is consistent with the socially optimal path of oil shale resource - 520 - development is debatable. On the one hand, it prevents any small group of companies from leasing a large share of Federal lands when there is still great uncertainty about future costs and revenues. On the other hand, it may prevent some potential entrants from acquiring land, even though they are now ready to do so. There is certainly substantial oil company interest in acquiring oil shale property, as the summary of 1974 sale bidding in table 8.10 shows. 50 / The minimum royalty in lieu of production plus the deferred bonus payments make it expensive not to develop an acquired lease. 51 / The royalty formula is complicated and depends upon the volume and quality of a tract's shale, but estimates of the royalties' magnitude have been developed. Using a 12 percent discount rate, the 50 / According to the Department of the Interior, at least 71 private firms have indicated an interest in oil shale. See Potential Future Role of Oil Shale: Prospects and Constraints , op . cit . , appendix K. However, expressing interest is not necessarily the same as being willing to invest large sums of money in development. 51 / However, the minimum royalties required in lieu of production are far less than the royalties a lessee would have to pay if he were engaged in full-scale production. - 521 - TABLE 8.10.--Bids Received, 1974 Prototype Oil Shale Leasing Program Sales Bonus bid Bonus bid per acre (million (thousand Tract Firms bidding for tract dollars) dollars) C-a 1 . *Standard Oil Co. (Indiana) and Gulf Oil Co„ 210.3 41.3 2. Sun Oil Co. 175.0 34.3 3. Marathon Oil Co., American Petrofina Co. of Texas, Phelps Dodge Corp. 80.0 15.7 4 . Atlantic Richfield Co., Ashland Oil Inc., The Oil Shale Corp. 63.3 12.4 5. Shell Oil Co. 63.0 12.4 6 . The Carter Oil Co. 33.1 6.5 7. Occidental Oil Shale, Inc. 16.4 3.2 C-b 1 . *Atlantic Richfield Co., The Oil Shale Corp., Ashland Oil, Inc., Shell Oil Co. 117.8 23.1 2. Geokinetics Group (Andarka Production Co., Koch Industries, Inc., Mesa Petroleum Co., Murphy Oil Corp., Signal Oil and Gas Co.) 52.5 10.3 U-a 1 . *Phillips Petroleum Co., Sun Oil Co. 75.6 14.8 2. Occidental Oil Shale, Inc. 25.0 4.9 3. Geokinetics Group (Andarka Production Co., Diamond Shamrock Corp., Koch Industries, Inc., Murphy Oil Corp., Signal Oil and Gas Co., Allied Chemical Corp., 3.8 0.7 U-b 1 . *White River Shale Oil (Standard Oil Company of Ohio, Phillips Petroleum Co., Sun Oil Co.) 45.1 8.8 2. Geokinetics Group (Andarka Production Co., Murphy Oil Corp. 9 Signal Oil and Gas Co.) 11.5 2.2 * Winning Bid. Source: Potential Future Role of Oil Shale: Prospects and Constraints , op. cit ., appendix tables B-l and B-2, aAppendix pp. 17, 18. -521A- discounted present value of the payments required to hold a lease without production was calculated for each winning bid in the 1974 sale. The results are shown in table 8.11. Clearly, if a company was interested in holding oil shale property for speculative gain, it had to be willing to pay a considerable price. However, some firms might pay the high cost of holding land to assure themselves a sufficient high grade reserve base to permit rapid imitation should other firms or the Government successfully develop a full-scale commercial shale oil process. The evidence does suggest that companies bidding on the 1974 leases were interested in developing them, not just holding them. Yet at least two of the 1974 lessees have announced that they do not intend to go forward with oil shale plant investment on Government lands without further Govern¬ ment subsidies or guarantees such as guaranteed pro¬ curement, direct grants or loans. 52 / If the Government had made more tracts available, there would have been bids on those tracts as well, but many of the winning bids would probably have been 52 / "Shale Oil's High Risk Future," Business Week, April 28, 1975, p. 87. TABLE 8.11.—Cost of Holding an Oil Shale Lease Without Production (Millions of Dollars) Present value of payment 1/ Tract Bonus payment Rent and Royalty in lieu Bonus of production payment Rent and Royalty in lieu of Production Total C-a 210.3 14.1 169.9 2.9 172.8 C-b 117.8 7.7 95.2 1.6 96.8 U-a 75.6 2.6 61.1 .5 61.6 U-b 45.1 2.8 36.4 .6 37.0 1/ Present value of rent and royalty payments is the value of those payments discounted at 12 percent, if there is no production for 20 years. Bonus payments are the present value of those payments if they are made in five equal yearly installments and discounted at 12 percent. Source: Calculated from U.S. Department of the Interior, Office of Oil Shale Coordinator, "Program Decision Option Document, The Proposed Prototype Oil Shale Leasing Program," October, 1973 (reprinted in U.S. Senate, Committee on Interior and Insular Affairs, Subcommittee on Minerals, Materials and Fuels, Prototype Oil Shale Leasing Program , Hearings, 93d Cong., 1st sess., December 17, 1973, and March 5, 1974, pp. 92-96). -522A- lower per acre or ton than those on the four proto¬ type lease tracts, since the total supply of tracts would have been larger. Evidence that the time pattern of oil shale resource development is restricted below the free market rate, however, does not necessarily show that it is below the socially optimal rate. If the private discount rate exceeds the social discount rate or if there are substantial environmental externalities, the socially optimal rate of development will be slower than the free market rate of development. Too little is known about these quantities to draw definite conclusions about the effect of restricted leasing on the rate of oil shale resource development. The prototype program does offer the opportunity to get better information with which to answer the key questions. Thus, one view is that the Government ought not to be particularly interested in the rate of production from existing leases, except to the extent that rapid technological development is secured. However, if the primary goal is rapid technical progress, guaranteed - 523 - direct payments for a specified output might be the most efficient method of attaining that goal. An alternative strategy for expediting commercial scale-up, the most vital test of shale technology, is to compel the lessees to commit themselves within the first years of the lease either to invest in a commercial plant or to relinquish the lease and forfeit the bonus payments. In subsequent leasing, this could be achieved by including stringent diligence require¬ ments calling for production at commercial levels within a given time period. This approach implies that the economic costs of not producing on existing leases may be insuffi¬ cient to assure investment in a commercial plant. However, stringent diligence requirements can be economically in¬ efficient for two reasons. If they are sufficiently stringent, they may discourage firms from bidding on new leases, and thus retard development. If they are applied^ to existing lessees, they may induce production at a rate faster than the optimum. - 524 - Economic Efficiency Determining the best time pattern for oil shale resource development involves some difficult and indeed unanswerable questions about trade-offs between present and future generations. But assuming any given development rate, it is desirable to have production be as efficient as possible. Therefore, it is important to see whether any aspects of current leasing policy might interfere with efficient resource develop¬ ment. The prototype leasing program calls for a royalty of 12 cents per ton of 30 gallon shale, with adjust¬ ments for shale quality but a minimum of 4 cents. A royalty, as chapter 5 brought out, leads to inefficient development by raising the marginal costs faced by producers above marginal production costs. However, a royalty of 12 cents per ton for oil shale which contains over 25 gallons of oil per ton means a cost of about one-half cent per gallon of oil, and thus is - 525 - l unlikely to have a very large impact on marginal cost. Moreover, the depletion allowance of 15 percent on the value of production tends to lower marginal cost. Thus, the two effects may partially offset each other. Under the provisions of the 1920 Mineral Lands Leasing Act, which still governs oil shale leasing, lease size is limited to 5,120 acres, and no individual can own or control more than a single Federal lease in the entire country. For the richest Colorado deposits, this limitation should impose no restriction on the achievement of scale economies, but for the lower quality deposits of Utah and Wyoming, commercial scale opera¬ tions may not be possible with leases of this size.53/ Either a relaxation of acreage limitations or an expansion of individual ownership restrictions would allow more efficient development of poorer quality deposits. This limit might well be written in terms l * ■ of recoverable reserves rather than acres of land. However, it may be difficult to measure such reserves accurately, in which case an acreage limitation would be more workable. Moreover, it is debatable whether any acreage limit is currently necessary, and especi¬ ally why individuals are limited to only one tract, 53 / Potential Future Role of Oil Shale : ( Prospects and Constraints , op. cit. , pp. 38, 111-117. ^ - 526 - given the vast amount of unleased oil shale lands and the fact that too little is known about future scale economies and technology to determine an appropriate limit.54/ And if one firm could produce shale oil at lower costs than other firms, it would be inefficient to limit it to a single lease. Other specific provisions of the prototype leasing program are less important for future oil shale develop¬ ment efficiency, since they will presumably not be used in later stages. For example, the offset of development expenditures against final bonus payments is designed to bring the technology of large-scale oil shale processing to a commercial level, and once commercial viability has been established, there should be no need for non-market encouragement. Also, the leasing program requires the gathering of environmental baseline data for a year before the submission of a detailed develop¬ ment plan (which must be submitted before the third anniversary of the lease) and a year before the start 54 / The acreage limit could have the perverse effect that even a completely new entrant with no current energy production would be limited to an amount of shale oil small relative to petroleum industry output. -52 7- of commercial operations. Additional environmental protection clauses require annual environmental monitor¬ ing and the posting of bonds against various forms of disruption. Presumably, there will be a continued need for certain environmental protection measures in sub¬ sequent oil shale resource development, but the exact form will depend upon the environmental costs identified through the prototype program. Competitive Impact Since oil shale is a potential source of crude oil, and hence a substitute for conventionally produced crude oil, the relevant market for measuring concentration or market power is all crude oil, however produced. As a result, oil shale concentration would be significant only to the extent that oil shale production becomes a significant enough fraction of total crude oil production to affect crude oil concentration. At present, the developmental work on the four prototype lease tracts is being done by large oil companies or the Oil Shale Corporation. These large energy companies could conceivably become entrenched through technological know-how advantages and/or acquiring a large fraction of oil shale lands. One could therefore argue that positive steps must be taken to encourage entry by other companies which do not yet control any oil shale lands. Nevertheless, since there is no large-scale oil shale production yet and since the Federal Government has leased less than one percent of its oil shale resources (albeit including some of its highest quality lands), it may be too early to draw any conclusions about future concentration, much less worry about current market power. Under this more sanguine view, the Government can in the future induce as much additional entry as it wishes by leasing more land and, if necessary, providing appropriate subsidies, as long as no key patents are controlled by only a few firms. One interpretation of the prototype leasing program is that by allowing major oil companies to win all four prototype oil shale tracts, the Interior Department has adopted a course which will lead to high oil shale concentration and ultimately higher crude oil concentra¬ tion. As table 8.10 shows, several smaller oil companies also bid for the four tracts, but joint ventures made - § 2 9 - up of major oil companies bid higher in every case. This could mean that the bonus bid approach may have acted as a substantial barrier to entry. An alternative view is that the tracts account for only one percent or so of Federal oil shale, so that the identity of the winners indicates little about future concentration, even if the same leasing procedures continue to be used. It can be seen in table 8.10 that all of the winning bids on the prototype lease tracts and a number of the losing bids involved joint ventures including major oil companies. Some of the losing individual company bids were by large firms such as the Sun Oil Co., Exxon (Carter Oil Co.), and Shell Oil Co. Some were by smaller firms such as Occidental Oil Shale, Inc. Since individual major firms evidently considered them¬ selves capable of entry without joint ventures, and given the tendency of joint ventures to reduce the number of independent sources of initiative, one might argue that joint oil shale development ventures among majors should be banned. Indeed, one might go further and insist that in addition to banning joint ventures among large oil firms, certain lease tracts should be set aside for bidding by small companies only. Smal] potential entrants might also be given special tax subsidies, such as being allowed to use faster depreci¬ ation write-offs than large companies. 55 / An alternative view is that because of the high risks involved, joint ventures should not be dis¬ couraged. If they increase the number of possible participants, as in the demonstration project, they may even be positively desirable. That joint ventures involving large companies bid higher in the 1974 lease sale could be attributable to greater risk spreading capability. Reserving some tracts for small firms and/or giving them special tax subsidies might also lead to substantial inefficiencies if the largest firms enjoy lower average R & D, production, or capital-raising costs owing to economies of scale. On a number of occasions certain companies, such as the Colony Development Operation (a joint venture involving Atlantic Richfield Co., Ashland Oil Co., 55 / See also George Miron, "Competitive Aspects of the Government's Research and Leasing Policies for the Rocky Mountain Oil Shale Lands," Natural Resources Journal , 8 (October, 1968) , p. 645"! - 531 - Shell Oil Co., and the Oil Shale Corp.) have indicated a strong interest in oil shale, but they have deferred investing in private land development when they had the opportunity to acquire Federal lands. 56 / One view of this phenomenon is that entry by non-major oil companies should be encouraged, since they are less likely to abandon their shale ventures to invest in alternative energy resource projects. Another view is that it is sound business practice for any firm, large or small, to defer or even drop a business venture when new information suggests that other alternatives are more profitable. Thus, the fact that certain large firms have changed their minds one or more times about oil shale is no reason to favor other firms in future shale leasing. The leading innovations in oil shale technology have evidently been the "TOSCO" retorting process developed by the Denver Research Institute under contract to the Oil Shale Corporation, the "Paraho" process developed by Cameron and Jones, an engineering firm, and now being tested by a group of 17 firms, and 56 / Wall Street Journal , October 7, 1974, p. 7. the in situ process being developed by Occidental Petroleum. One interpretation is that small independent firms rather than major oil companies are more likely to develop new oil shale processing technology, and so small firms should be ensured access to oil shale lands. On the other hand, even if the concepts are originated by small firms, it is possible that companies must be large to undertake the development of full-scale plants. For that reason it is unclear that any simple conclusion can be drawn about optimal lessee size. However, if it could be shown that smaller innovative firms were precluded by land acquisition costs from developing a new technology, then it might be desirable for the Interior Department to make oil shale land available at nominal cost to firms which appear to be the most innovative. Implicit in such a policy is the assumption that rapid innovation is more important to the Government than current revenue. In addition to oil shale land, companies intending to produce shale oil must have sufficient water and sufficient land on which to dispose of the spent shale. One suggestion which follows is that Federal land leasing policies should be coordinated with the - 553 - relevant States to make certain that water rights are available as well. A different view emphasizes that water rights ought not to be given away for a nominal price, discouraging the search for low-cost alternatives and encouraging water waste, but should be made avail¬ able for oil shale use only if the shale developer is prepared to bid higher than other users (including agriculture, recreation, and other industrial users). Because oil shale processing is so new, an absolutely critical question is whether developing the technology will give pioneer firms such know-how or patent advantages that potential entrants will be excluded. The current prototype leases include no provisions for sharing the technology or for the compulsory licensing of patents. This should give the lessees a maximum incentive to invest in research and development, since they will be able to appropriate the value of all results. Yet it could also be the source of an important future barrier to entry. Thus, an argument can be made for compulsory licensing with "reasonable" royalty rates and/or compulsory sharing of non-patented know-how. However, to the extent that such provisions would diminish companies' willingness to invest, it might be necessary for the Government to provide additional direct research subsidies. Attaining Fair Market Value Another issue important to many observers is that the Government receive "fair market value" for the land it leases. The secret refusal price calculated by the Interior Department's presale evaluation panel for Colorado tract C-a was $5.6 million, whereas the winning bid was $210.3 million, or about 37 times as large. The panel's estimate evidently assumed pre-Arab oil embargo prices, even though world oil prices greatly increased after the presale evaluation and before the bidding took place. 57 / After congressional hearings in which Interior officials explained these and other techni¬ cal aspects of their presale evaluation procedures, for tract C-a panel members were directed to cease calculating a single presale evaluation figure and instead to prepare three estimates: the "most probable" estimated resource 57 / See U.S. House of Representatives, Select Committee on Small Business, Subcommittee on Activities of Regulatory Agencies, Energy Data Requirements of the Federal Government , op. cit ., pp. 5-41 - 535 - value, a high possible value, and a lower possible value. 58 / Using these categories, the panel made calculations for tract C-b ranging from a high of $269.9 million to a low of $0. 59 / One interpretation of this experience is that without significant improvements in the presale evalua¬ tion procedures, there can be no assurance that the public will receive a "fair" return in future leasing efforts. Consequently, it is held, the Department of the Interior needs to improve vastly its method of estimating refusal prices. Among other things, it should calculate a single refusal price rather than a range of tract value estimates. An alternative view is that the important goal in the short run is to create a viable oil shale industry, and therefore no bid from a bidder likely to develop the technology should have been refused, no matter how low it was. Furthermore, it can be argued that if competition among bidders is working, there is no need 58/ Ibid., P. 62. 59/ Ibid., P- 64. - 536 - for the Interior Department to set minimum refusal prices. The high bid should give the Government approximately the value of the land's economic rent, allowing for risk and uncertainty. Society could well lose more by refusing a low bid and having no output produced and no revenue generated than by accepting a low bid which ultimately leads to unexpected windfall gains. It can also be argued that the large difference between the Interior Department's estimate and the highest bid for tract C-a merely reflected honest differences in calculating the value of a resource under uncertainty. Indeed, the range of tract C-b estimates ($0 to $269.9 million) indicates the problem precisely: the shale may be quite valuable, or it may be unprofitable to produce at all. Another issue of potential concern is alleged speculative withholding of resources. According to one view, when the Government has leased lands for develop¬ ment, undesirable speculation occurs if the holders of the lease do not elect within the first five years of the lease to invest in a commercial plant or to - 537 - c relinquish the lease and forfeit the bonus payments. The alternative viewpoint is that unless there is monopoly power or a large gap between private and social costs or benefits, it is desirable for companies not to extract a resource until it is profitable to do so, taking into account current knowledge about market conditions and the level of risk and uncertainty. This interpretation assumes that holding resources off a market in anticipa¬ tion of a higher future price contributes to dynamic efficiency and serves a socially useful function. In addition, since there are large capital costs associated with oil shale production, it would be quite risky for a company to begin producing oil shale before it had acquired or contracted for sufficient reserves to cover a large fraction of the plant's expected life. For that reason, it is important to distinguish acquiring land for future capital gains from acquiring sufficient land to be able to operate a shale retorting plant efficiently. If 100,000 barrels per day is the optimum plant size and if the plant will last for 20 years, it will need about 0.73 billion barrels of shale oil. If it could last for 40 years, it will need twice as much shale oil. Thus, companies will need to 1 -538- c acquire large blocks of reserves before they can justify building a retorting plant. Summary The prototype oil shale leasing program appears to be a reasonable compromise between the more rapid development of the Nation's oil shale resources desired by industry and a segment of the public, and environ¬ mentalists' concern with the potentially disruptive effects of oil shale development. The program has released a small amount of the most valuable oil shale land for commercial development and has been structured to provide incentives for early expenditures on develop¬ ment. At the same time, however, the program requires that fairly stringent environmental protection measures be taken. Once a better understanding of the commercial viability and social costs of oil shale processing is achieved, a leasing policy designed with either con¬ servation and environmental protection or commercial development as its main objective, whichever is more appropriate, can be promulgated. If the former objective is stressed, then the Government has maintained control of oil shale lands and can dispense them at the 539- most desirable perceived rate over time. If the latter objective makes more sense because environmental costs are deemed low and there is no overriding conservation motive, then leasing by bonus bidding of substantial Government oil shale tracts should be initiated. - 540 - Chapter 9 COAL* The Importance of Federally-Owned Coal Coal is the most abundant fuel found in the United States. 1/ In 1972, it was estimated to account for approximately 88 percent of proved U.S. recoverable energy reserves on a Btu basis. 2/ Tonnage estimates indicate that as of January 1, 1972, there were some 1.6 trillion tons of mapped and explored coal remaining jV This chapter was prepared prior to the September, 1975 release of the Final Environmental Impact Statement , Proposed Federal Coal Leasing Program , U.S. Department of the Interior. 1 / Anthracite, bituminous, subbituminous and lignite are the four basic types of coal. These classifi¬ cations represent a ranking based on carbon content, degree of moisture, volatility, and heat content (Btu/lb.). We are primarily concerned with the last three types of coal--bituminous, subbituminous, and lignite, which for simplicity will be referred to as bituminous coal or simply coal. Anthracite coal is recognized in industry publications as a separate industry. In 1972, anthracite coal produc¬ tion amounted to approximately 1.1 percent of total U.S. coal production. U.S. Coal Production by Company . . . 1972 , Keystone Coal Industry Manual (New York: McGraw-Hill, 1973), p. 6. As of January 1, 1974, anthracite reserves amounted to 1.7 percent of the U.S. demonstrated reserve base. The bulk of these reserves (94.4 percent) occurs in Pennsylvania, and only 30 million short tons, or 0.4 percent, occur in the West (Colorado and New Mexico). See U.S. Bureau of Mines, "Demonstrated Coal Reserve Base of the U.S. on January 1, 1974," Mineral Industry Surveys , June, 1974. 2/ Bimuminous Coal Facts 1972 , National Coal Associa¬ tion, Washington, D.C., p. 9. - 541 - in the ground. 3/ Assuming that 50 percent of this coal can be recovered, and that the current rate of U.S. coal consumption of 600 million tons per year remains constant, the U.S. would have enough coal to last 1,300 years. £/ The bulk of federally-owned coal reserves occur in the West, particularly in the States of Colorado, Montana, New Mexico, North Dakota, Oklahoma, Utah, and 3/ U.S. Department of the Interior, Geological Survey, United States Mineral Resources , by Donald A. Brobst and Walden P. Pratt, Professional Paper 820, 1973, p. 137. Includes beds of bituminous coal and anthracite 14 inches or more thick and subbituminous coal and lignite 2-1/2 feet or more thick to a depth of 3,000 feet. £/ A more meaningful reserve estimate by the U.S. Bureau of Mines, termed the "Demonstrated Reserve Base" shows 433,948 million tons of coal remaining in the ground. This figure includes bituminous and anthra¬ cite in seams 28 inches or more thick and subbitum¬ inous and lignite coal in seams 60 inches or more thick. Underground coal is generally included to a maximum depth of 1,000 feet and strippable coal to a depth of 120 feet. Underground lignite is not included. U.S. Department of Interior, Bureau of Mines, Division of Fossil Fuels, "Demonstrated Coal Reserve Base." Using this estimate and assuming 50 percent recoverability and the maintenance of current consumption patterns, the U.S. coal supply would last over 350 years. - 542 - Wyoming. 5/ These States in turn account for approxi¬ mately 53 percent of the Nation's mapped and explored coal reserves. 6/ While current estimates of recover¬ able coal reserves are imprecise at best, available rough estimates (table 9.1) indicate that the Federal Govern¬ ment owns approximately 29 percent of the mapped and explored recoverable coal reserves in these seven States. 7/ 8/ This amounts to some 15.4 percent of total 5/ No complete tabulation of Federal coal reserves exists owing to complex ownership patterns (in some cases, only a partial interest is owned by the Government) and the lack of detailed geological information. On an acreage basis, however, the vast majority of federally-owned coal lands lies in Alaska, Colorado, Montana, New Mexico, North Dakota, Oklahoma, Utah, and Wyoming. Alaska has been excluded from this study. The States with substantially less Federal coal ownership are Alabama, California, Kentucky, Ohio, Oregon, Washington, and West Virginia. They have also been excluded. 6/ U.S. Department of the Interior, United States Mineral Resources , p. 137. Using the more narrowly defined "Demonstrated Reserve Base" data, these states would account for approximately 46 percent of the U.S. total. Calculated from "Demonstrated Coal Reserve Base. . .," op. cit. , p. 4. 7/ However, according to Federal Energy Administration, U.S. Department of the Interior, Interagency Task Force Report on Coal, Project Independence Blueprint (Washington, D.C.: Government Printing Office, 1974), p. 75, "The Federal Government owns over 60 percent of Western Coal reserves. . .." The staff was unable to determine the definition of reserves in this instance. 8/ The extent of Federal western coal ownership can also be viewed in terms of acres. As shown in the U.S. Department of the Interior Draft Environmental Impact Statement , Proposed Federal Coal Leasing Program (Washington: Govern ment Printing Office, 1974), pp. 1-208, the Federal Govern ment owns 50.5 percent of the coal acreage in these same seven States. - 543 - TABLE 9.1.—Federally-Held Coal Reserves for Seven Western States, 1974 0 co c \ to O CM I 0 G > Td P G (D 0 G 0 > fd fd •H G G CD CO G CO 44 •H > G W fd 0 co •—1 G p •H tj 1 fd td td c •H -P 0 a co . d) g 0 d) co QJ fd -p iH £1 g H p Td CO •H QJ P G ■-1 Td o in o o o o o t'- fd •H 0 QJ p 4-1 fd 0 fd 0 • Td co 1-1 > P P • (d d) O p G co l—1 CTi in •'T* CM 00 00 0 fd G 0 O T3 > QJ P P d> in in (N 00 CM U 0 •p W > 44 d) Td P (D Td o P G G 0 £ fd CQ Or d) Td -p d> -P O d) P o E 44 0 6 44 0 G 1 -1 •H 2 Td P >. G fd P -P o £ fd c rH 0 p G £ g fd G i—1 P • Q 0 G •rH G -H G G 0 0 O 6 G id 0 G i—f G G o •H -P fd p u o tn (d p p >1 0 > p p co aj QJ P G QJ fd P P fd •H Or G G r-H G co 0 p cd G fd 0 •H fd td S QJ g CO co a Td c G > Td Or G O 0 P CO QJ •H d> fd fd Or • •H 1 P p S rH G •H 0 CO P >1 QJ 4-1 ID o 1 — 1 CT« in 00 r* CD P CO p o td 0 -H P G 0 0 rH rH 0 r" O rH CM co CM m ID P •H o i—1 Td 0 G G > rH r-H £ co r- rH 00 r-' r-~- •H G -H 04 G o G CO >i p o td td CO Pm Eh P X td >i 0 G 0 0 p p G r-H i—1 00 CO OC 00 CO QJ QJ P 0 fd 0 0 •H CO o dJ aj O CM 1—1 -'T’ CM CM G G g 4-1 G g 0 Td > •H rH • • G Td 4-1 G •H p • QJ 0 r-H o CO H G 0 CO G O X m Pm o rH CM d) fd P fd O 0 0 Td • dJ ■H 00 > QJ 0 0 G O G p 0 p p s p G Td fd 4-1 G Or p p QJ G QJ 0 0 CO g 0 QJ CO 04 p « P P 44 rH p a OJ 4-1 04 P O G 0 0 Or 0 \ fd P O fd PQ fd 44 X •H rH 1 CO Or g • G G G 0 0 p G QJ G CTi G G 0 CO 0 QJ 0 rH rH G 0 P O 0 O p Td G r-H •H CO fd G d) p 0 CM g CO fd G G G i — 1 G G fd g td •H 1 04 CO 0 0 fd H td co G • cr Td 0 G > -P CM co rH rH ID CM CM co 0 a 0 G 04 0 CO 0 Td Or G 0 P co 00 r- CO ID 00 co O QJ o QJ G H rH G 0 Or o co 0 4-1 QJ Q Eh Td fd CO G (d 44 QJ QJ G o o o in 1 - 1 1 — 1 o rH O P 0 G 0 P ■H g 0 P > CO •'T r-H CO r'- 1 — 1 ID CO P • G r- fd o g P rH rH H* Or QJ in • G CTi Td 0 G rH QJ 4-1 G • cr> rH >i 0 fd 0 P G 1 g CM 0 0 0 0 g o P QJ P G 1 G 1 — 1 G p G 0 G • EH > QJ •H rH G G 0 G fd 0 co P G P -P G 0 G G 0 fd c P QJ Td • 0 g G >1 co G G Or 0 co Td aj 04 g 0 O rH 0 fd Eh 0 g Td G G 0 G > 0 Q 0 rH O •H P fd G O p CP fd -P > G fd G 0 G • • td fd o 0 G aco Cn CO 1 0 \ \ o co u S 2: 2 o P 5 Eh rH | CM CO -543A- U.S. recoverable coal reserves. Despite the enormity of the Federal coal reserves, the Federal Government has hardly begun to lease its holdings. 9/ Although the data are rough, it appears that the Government has leased only about 15 billion tons of recoverable reserves, or roughly 12 percent of its 9/ As of June 14, 1974, there were 533 coal leases, distributed as follows: State Alabama Alaska California Colorado Kentucky Montana New Mexico North Dakota Ohio Oklahoma Oregon Utah Washington Wyoming Number of leases 2 4 1 113 1 17 28 20 1 53 3 197 2 91 - 544 - total recoverable reserves, in the seven Western States. The distribution of leasing is shown in table 9.2. Federal coal leasing proceeded on an unrestricted basis from 1920 to 1971. Subsequent to a Bureau of Land Management coal leasing study published in 1970, 10/ however, indicating that 91.5 percent of the total acre¬ age under coal lease was within non-productive leaseholds, and further that coal brokers had substantial ownership of Federal coal prospecting permits, the Department of the Interior ceased granting leases and prospecting permits. The aim of this informal moratorium was to allow the Government to re-evaluate its coal leasing policies and practices. The moratorium was formalized on February 17, 1973, and has continued into 1975. A limited number of leases have been granted, however, under short-term leasing criteria set out in the February 1973 announcement. These criteria were designed to supply existing coal operators with 10 / Gary Bennethum, "Holdings and Development of Federal Coal Leases," U.S. Department of the Interior, Bureau of Land Management, Division of Minerals, November 1970. - 545 - TABLE 9.2.--Federal Recoverable Reserves Under Lease for Seven Western States, 1974 P CD r d p r—1 G CD p cn fd i P rd in 3 POP .G CG in G P CD di • 1 CD fdH c P C •H 0) 0) CD > CD (Tv c» CN in \ VT p di cn P P CD ■H P ! “i P O di P in (Tv 00 CN vo ro|cr o CN O CD i—1 CD P CD g i—1 P .Q 3 P CD (D fd • • • • • • • CN > CD rC cn p rd fd CD CO P CD Cm W di W CD CD G G VO cn > 3 rd c p CD CD W P fd P -H p fd 1—1 rG g \ 0 G 44 -H CD fd O 0 cn • CD o o G CN 1 p CD i—1 > P , cd CD rQ ■H r~* g CD U) -p CD o O CD CD P P P Ph 2 r—\ CD p P O p cn n G fd • >1 cn P & > 0 fd »• CD id ph cn fd •H 0 0 rd P rG P CO d) p i-H U CD fd cn • g •H p CD cn co CD rH •H p o CD CT .C p 1—1 CD W vo o H (Tv in 00 r~ VO G g CD *H H U U cn O P P fd (d > CD 44 r~ o rH CN VO CN in VO p fd 3 rH CG CD CN fd CG P p 0 p O ro r^ rH 00 CTv r» o rG cn p CG CO rH di 1 rG CD 3 o » fd P cn td G fd fd CN i—1 P di Cn P (D i—1 cn •H ■—i 00 ro CT 00 co a fd p O CD P G fd U rd c CN •H -3* CN CN g 0) CD *H P rG CD • P G •H G p 0 rH H cn cn > p h Pd • CG 0 •H CG rH CD •H a) fd O o CD Cn CG 0 fX3 di rH rH rH o (d - Cm G P p *H P P CD I—1 fd CD • d) 0 • G CD p 0 Cm •H p P rH P 0 di G - U P CD CD p >i a G CD fd 2 CD fd CD •H g P cn P CD r d o P P rH p di U a •H g g a 0 p td CO •H O CD g 0 3 • •h cn c CTi • 3 o x: •H P CD cn cn rH -H CD CG tro p X •H di G rQ 0 O cn p 00 ro 0 p \ cn G fd 1p 0 ID A CD -P fd G CD •—1 i—1 cn cd CO CD Cn 44 CD 1 rd •—1 u P M U rH CG fd -H P 0 cn G cn P 0 a o fd •H CG CD P • >1 fd rH cn 0 3 CD P £ •H 44 6 < p -h cn G P 0 CD o fd > CD cn m o CN in in O CO O rG P P CD td CO G rH o 0 t CT CN O oo O CTv r" p P 3 o CD c G cn CG rG 0 O G CD rH rH p fd cn H G >1 cn •H p P •H ^1 H CD X) • 00 td O -H CD o •H rH 3 g CD CD rH 44 fd cd r- 0 P U rG p i—1 P G •I—V di cn i-H CD G 0 CTv u fd p p fd cn O di CD CD CD •H G 4 1 -rl fd i—1 P CD P •H fd rQ Cm P 6 P g P p 0 g CD 00 G X G p p rG g g 3 CTv CD CD • CD P 44 tdd> 3 O Cn 0 cn £ CD P 0 ox; cd W •H HUM • 5 rG P fd G p p cn (G r"- -h P o p 3 G 4-1 p CD CD fd (Tv G CG p •H P cn fd G P t G CD i—1 -H 0 CD •H 5 3 CD o 0 CD CD -H P u P CX > P > i—1 g P W G G cd cn G di P p P fd CO P rd P • 3 CD CD CD CD CD TD CD ■H (D >1^ fd 0 CD iH di 2 rH 0 a cn p CD di P P rQ f" P O CD r — 1 fd CD o g CD 44 fd CG C rH CT a CD cn fd O di o (d •H cd • fd 5 3 rd d) H p CD o u 3 t X a CT> CO CD o G i — 1 0 G \ p o rH CD rd G CD fd O G W G o H fd cn o 3 p CN | CD o O p rd s rG P A •H rH • CD CN p CD 0 0 rQ 44 CD • X p 0 p p O (dG g fd DHd 1 CD cn P d rH fd CD fd rH G £ p M iH fd 0 P fd P o T5 fd fd p c CD rQ CD p o O CD O fd ,x P >i 0 NO 3 in CD cd x: cn a 3 3X3 0 G X H C 0< X w x a; £ X O O M - X 0 u X X 5) d) H O 0 3 0 a to 0 p 3 4-1 -P •r~> Q 0 C£> G O p co • d) P 0 3 0 X £ C4 X m 0 p cm a X CO a o X 0 (0 tn r 0 P G X X 0) •H d) *H 0 O X X 4-1 If) > £ f0 G co 5 X u HD d) 0) W CO 0 o 0 (1) > r—1 0 -H T3 3 P -P CO > £ G G 0 CO 4H (0 0 3 D •H CO (0 (0 < PC p X 0 x p D CO c P Q X > o 0 0 -p o o p > o 0 G - to -H GP P 1 x x fO G 3 0 X O G X fO 0 r-H •H o H G X X co 2 0 O 3 0 X 4-1 E -H X 5-1 x Sp to O G X 3 0 3 a p 0 X 0 > -p C 0 X P X U 0 co dJ-O G •H G U X 0 0 > 0 ,—1 0 c CO tn £ G X 3 p •H -P w o P 0 CO d) P CO 0 >—1 -P G X 3 TJ 3 CO O X Du 0 P 0 O CD CT> Cp Q) S G - Q O 0 *0 •H p x 00 0 G d) • 0 CO 0 • t, d) CO > CO o 3 CO 1 > 3 d) w 0 r- 1 d) O £ • 1 • a l • CO •HOD X CO O CM > x O 0 P r- • 5h X p C4 a\ 0 o - • 0 3 • X CD to x tr> 0 a, W G CP £ 3 x x a, PI (0 (0 o X X X PQ CD X • •H rr pH n* co oo CTi r-' CO LO e P ID o o cr> G G rH 44 o •H CM r" O ID CM ID c rH G •H CT> *H •H CQ rH p T3 p 4-1 G X • • e CO X P X cn to 0 G O 0 r- G G rd o o> •H X 03 a) ID 03 X T3 >i G cn G G T3 CM X O X a\ • rd 0 r- x rH rH •'T O X G Cn 0 i P 4-1 XI 0 rH X in x O 144 G in o 03 T3 P cn O P a> G 03 x co X TJ G CM rd >-• CO G in CO 0 u P 5 rH in X X X g a) o 0 c CTi P p 0) >* ID 0 G G p rH O •H O •H T3 X rd P 4-1 <44 P X TD rd C C 0 0 rd 0 0 4-> G 0 X G •H *H a 0 P 0 X X • 0 co t3 •H C3 P X 4-> rH CO G P 2 a rd < G (1) V \ 03 T3 0 0 X O - in 8 3 1 7 in X ID CM O 73 O rH •H G G P in • • • • • • • g rd P 4-1 H a X O'! rH ai ai 0 O P rH a 4-1 4-1 u P ID H Q 0 rd TS X P H G 4-> rH 0 X O X • 03 rd G O P >1 C ax 0 c 4-1 X . CO X H rd p G D P •H rd 2 4-1 a) O P co rd X 03 e c 4-1 \ CO 4-> rd v X • *H 0 o cm| p G H | CM | w (G cn a G CQ 03 g P S x X •H 0 u rH a O X 4-> rd x e E-r GG rH • 03 e rH C g rH >i O o G • a g U S 2 2 o D £ 03 u P D —' X < ^T in l V relative to total Western State production. Table 9.4 shows that the Federal lease percentage shares have varied from 23.9 percent in 1972 to 25.9 percent in 1955, with no clear trend evident. The coal production actually occurring has come from a small number of leases. Of the 519 Federal coal leases issued in the seven Western States between 1929 and 1974, only 154 are currently in production or have ever produced any coal. There are several explanations for the paucity of western coal production. Since the coal is generally located far from industrial centers, transportation costs historically increased the delivered price so much as to make it noncompetitive with eastern and midwestern coal. Until the passage of the Clean Air Act Amendments in 1970, which required utilities to reduce emissions of sulfur oxides, utilities did not have an incentive to pay the high cost of transporting western low sulfur coal to the East. They relied on high sulfur coal. -547- TABLE 9.4.--Production of Coal From Public and Acquired Lands in Seven Western States as a Percentage of Total State Coal Production: Selected Years, 1955-72 1/ I p c Q) P U rd P CD CD >h P u CM CM CD O CM r-~ t" CT\ r" cr> ID CM CM CM ■*r CD CO rH ro rH CM rH -s* CO CM o o 3 * CM O oc 00 in r- uo CM co CD ac CTC ac CD CM oc CD CD oc 1—1 »—1 r-H 1 - 1 r-H CO CM in fN co 00 o r-H CD in ac UO on CM rN CO IN- o uo rH l —1 rH rH rH co CM a) p rd P co rd -p o o rHl o -h id (d d id XQ E cnrH rd c cd o c , u S z z o a £ fH r* h* r* G CM CT> CD > i—1 CO CD rH cd (0 43 • rd • 00 CD O 0) rH CD CO P CO > TJ T5 O 0 CD CD 42 u 43 P rd a p •H G CO rH p O 1 CD ac •C3* Id o o P CM 0 P rd rH P •H CD T) rH CO •0 0 42 a; p G CD in r—1 p a a 43 rH CD •H P O G rH E D 1 (d 0 P rr in 0 0 P 0 rH id u p P t> ih G G G rd 0 0 rd P •H •H 0 P p O P O o in in •H G G CD CO i 'd t o UO 42 42 0 0 G p P in G\ CUT) cu a iH CD P rd rH rH O -H rd rd > 0 0 S -H a O co G T3 V \ \ CO iH • iH C CM | ml CO rd CD rd G id 0) a) cd P > P W OdHr^ -P G ,—> 43 P O O 0 g c w cd O co Eh rd Eh 42 Eh o t id t) a P •H c P rd -p cd a) o CO -P o \,C0 \ U O P Eh U Eh H | CM | CO col rH p -H -H rH G G a) id d h d o o CD p p o 42 cro p 0 o > rd 0 P P U o 0 p o CD P E-i CU CL 1 rH P x: x) > fd X co CD P 0 X Cl) X 0) CD fd X cd r—1 X CD X G >H P -p fd CO fd (d G X fd •H o ■—i G o s •H CO P cd O CO •H fd p m X D 1 OS U •H X X 0 CD fd 0 X CO X X of p fd i fd c X n3 id CD 0 0) Cel p •H c X > G X p r- 0 2 fd a p 0 a) of X CO cd P p 2 rH ** o o e CO cd CD fd P •H x 0 rH X G X 0 i—1 (X o rH rQ X O G fd •H XI c fd 03 CL) •H 0 X p p •ti H o 1—1 tn x •H 1 tj> (d X p fd 0 G E 0 +J 0 > X -H •H H 0 u i—1 rH fd X 0 0 X p id 0 a) p 0 O CD 4-1 0) a) P 04 co P X • • 0 o p td CO x X c CO os CD P rH < 0 • 0 n3 • 2 O fd P X >1 •H G CO > X rH 04 O x 4-> fd c • fd p •H fd 0 u X G •H X G -p X p cd fd a) X 0 fd o p CD X rH X E 0 P •H p 0 O 4 X X -H CO X G p a G 0 p 0 CO CO 0 x iP 2 Eh fd id < • X cd p (D O fd ** CO G X i—1 CD X > X CO • • •H fd fd P X • •H fd X 0 D P X p •H X a 0 04 CO cd s 4-4 p (d Of E a) XI O Of 0 Eh ■— 1 0 p G CD p rH CD • p o, 0 eh CD X CO G 1 —1 X X X G a) G 0 fd G fd E -O a) G 0 ■P O cd x CN X o o E p O X O a) r-' n3 p X X O c Of Q 4-1 X p O P CO rn -H X G fd 2 X P CO fd X) fd 04 G X 0 O -P X • • 0) CD O p c »H rQ G W p £ Q •H Q 4 -H 0 fd u 3 CO CO £ OS «3 •H • •H •H p 3 O CD 0 o X xl CO > CO fd -p CO P CO o X 0 • ■H fd 0) •H Of Cl) Of co 0 CO D a X >1 PQ X 2 X -547B- In the future the role of coal and Federal coal lands must be viewed in a different light. The demand for coal is expected to increase markedly over the next several decades, especially if the Organization of Petroleum Exporting Countries-induced oil price increases persist. One major component of future increased coal demand is traceable to electric utilities. Demand is also expected to rise as the technology for converting coal to synthetic natural gas and petroleum liquids becomes perfected. Research on existing and incipient coal gasification and liquefaction methods is being supported by the Office of Coal Research, which on January 19, 1975, became part of the Energy Research and Development Administration. Of the $426.3 million budgeted in fiscal year 1975 for all Federal Government coal research and development programs, almost $225 million was designated for gasification and liquefaction research. 12 / Although one industry spokesman stated recently that the 12 / James G. Phillips, "Coal R & D Program to Lead Drive for Self-sufficiency," National Journal Reports , July 13, 1974, p. 1048. -548- technologies to gasify non-coking coals and to convert coal to the liquid methanol are fully developed, 13 / more conservative estimates indicate that reliable and economic techniques will be available in the early 1980's. 14/ Increases in the demand for coal will also come with the perfection of other more experimental techniques such as solvent refined coal 15 / and fluidized bed combustion. 16 / These systems could eliminate the need for utilities to burn low sulfur coal or use stack gas scrubbers to meet air pollution requirements, and thus could significantly increase the demand for coal. 13 / Coal News , March 28, 1975, p. 4. 14/ Phillips, "Coal R & D Program. . .," op. cit .j p. 1048. 15 / Ibid , p. 1050. This process converts coal to a heavy solvent with a heat value in the range of 16,000 Btu per pound. 16 / Ibid . A technique whereby burning coal is immersed in limestone. -549- Although the exact pattern of demand changes attributable to substitute fuel price trends and tech¬ nological development cannot be determined, Project Independence estimates that domestic coal production will increase from 599 million tons in 1973 to between 895 million and 1.4 billion tons in 1980, and from there to between 1.3 and 2.8 billion tons in 1990. 17 / The range of low and high projections reflects the difference between "business as usual" and "accelerated demand" strategies. Production from the Western States (substituting Arizona for Oklahoma) is forecast to increase from 56 million tons in 1973 to between 134 and 235 million tons in 1980 and between 235 and 486 million tons in 1990. 18 / These projections depend in some part upon the continuation of high oil prices and, for western coal, the lack of commercially successful stack gas scrubbers and the enactment of strip mining legislation that does not substantially increase the cost. Nevertheless, it seems likely that the relative significance of western coal will increase in coming years. Accompanying this increase will be a growth in the importance of federally- owned coal lands. Thus, Federal coal leasing regulations may have a substantial impact on competition within the coal industry and the general rate of coal resource development. 17 / U.S. Department of the Interior, Interagency Task Force Re on Coal, Project Independence Blueprint , op. cit. , p. 16. 18/ Ibid. -550- Against this backdrop, we turn to an overview of the coal industry, with special emphasis on the western part, before proceeding to analyze Federal coal leasing statutes and regulations. Economic and Technological Conditions of the Coal Industry In 1972 there were 4,879 active bituminous coal mines in the United States 19/, owned or operated by approximately 4,000 companies. 20/ The 4, 8, and 20 largest firms accounted for approximately 29.9, 39.8, and 55.6 percent, respectively, of national production in 1973. Statistics on the leading firms are provided in table 9.5. The 50 largest firms accounted for approximately 68.2 percent of production. 21 / 19 / U.S. Department of the Interior, "Coal—Bituminous and Lignite," Bureau of Mines Minerals Yearbook , p. 12. 20 / U.S. Coal Production by Company. . . 1972 , op. cit. , p. 6. 21 / Ibid ., pp. 9-13. -551- u 4-* g CD i — 1 fd -P OV CM ov cm CO p- o’ 1 — 1 rH 00 00 LO m O' CM » — 1 0 8 8 7 CM CM CTi O O • • • u 4-J f-1 O m ro CM CM CM CM CM rH 1 —i rH rH rH rH rH rH CT\ cn O' CTi •—i P- o OV o O' CO CO VO o CM CM o •H cn U p- p~ p- OV o CM CM CO o O' O' O p- MO 00 VO rH M0 o p- in o £ 0 •H P Td 1—1 o’ CO p- o' CM i—1 in uo 00 M0 00 VO O CO in rH VO VO CM P' o a i—1 Td c •* *w V *. V. ** - •» V. v -P •H O td o o CM 00 VO VO CN CM o o 00 00 00 p' VO VO ■O' •O’ O’ O' rH •H £ Td >4 CO r- VO CM rH i—1 rH rH i—1 rH rH rH CM OV CQ 3 G a 3 CO m c •H to o 4 £ G *rH 4-1 rH 3 fd 4G C •H CD O • 0 ) O • i X CO 0 o .—. 0 td d) 44 • >iCJ c u rH u g to O 0 G o CD 4-1 •H -rH o td 54 u 04 4-J CD rH 54 i —1 Qu CD a. c (x u a •H Cn g c 0 (D 54 o G 0 O 0 o G r4 rH CD • •H U P< *H •H fd fd 4-> Td a G 4-J 4-J 4-J 4-J 4-1 G 54 54 •H i —1 fd u a 4-> G G 0 ) W (d 0 2 fd G p p 0 0 CL) £ • od u • 0 G o fd P O 4-> fd a 0 G CD X O Pl. G • o a • LG U cn 0 54 rH CJ H ^ • CdJ 2 g 4 5h r—t u O >i - Pj CJ P CO 4-J c/d •H —- a) O • fd • Td o fd rH X • a) 4-J 4-J to • +J rH rH £ U a o O. CD rH S fd u CO CO 0 CJ> CO to CD D fd • fd fd 5h u 54 4-> fd CO Td ^ G *H G 4-J U • 54 CD a) CP 1 >4 o o 0 — CO 0 0 fd o O -H • O 54 O 4-J 0 fd Cn cr> 54 1 cd u u u CD CJ G u •H CJ •H 2 a-H 4-> C/d •H >1 u X • 54 54 fd • a • G td o g 54 4-J O p-i Co C/d fd fd X in o ■H Td -X 0 •H i —1 ' u 1—1 O Td 54 rH o • i-Q I-Q • fd a> a) • u a fd •—i •H fd to c G U G rH •H i4S CD fd CM D o CTV u 0 4-J CD 0 rH U -H 54 0 to td LhG 54 « £ G 0 O’ 00 CM 0 u fd u U rH Q) e CD O CD u i—i Q Corn CD CD 54 W U W "0 u fd a) 0 ) G £ CD G *H -P C •H CD rH rH *44 M4 44 X £ >1 -H c o 4-> X •H TJ >5! G G Sh rH p O G fd x; 4-> G 5h fd fd 0 0 0 CQ p Td rH Td 0 u c n 0 ) 2 G a) 5h 0 fd M U CO 54 CD 4-J 4-J < •H 0 o c CO rH fd 4G CQ a) i 54 CO 44 •H 54 CD 0) rH 0 0 CD 0 ) a) E4 fc. XI CO fd 4-J X • -C rG rH 4-J 4-J -P a) JH X, 54 CD X 4-> CJ 1 Eh Eh 54 54 54 td C «H 4-> fd C/d 4-> O X 54 Td 10 CO G 4-J P fd CD 4-> O to a) fd fd fd CD 0 CO •H £ • CD 54 to O rH fd a) 1 in G 0 p r-~ TO CO -=T CU 3 X X TO CT> G (0 G —i •H O H 0 0 •k, •nH i—1 CO rH to X <0 t0 O 0 u fO - 0) CP • x d) 0 G rH u c 0 fO to X O *H O CO o (0 >< • 0 - CU TO CM U X 2 G m to (0 p e • to -H m • ^ a. X rH • rH rH U tn 1 era S O G x< 0) P fO X G a G X t0 O £T O o X o X 4-t -H u CTi cm 0 P • CU rH G CU >i 3 >. •H c e G TO X X o <2 (0 rH CO •H cr i—1 G rH to X TO e f0 0 •H £ o G o X •H cc 3 f0 o O X 1 TO X o 5 G 0 • X 3 to O P 0 o O TO p •H ftU t0 X 0 o X i'H 0 u p . m (0 CO t0 to • £ o co r- VO Oh rH VD CM CO CM r" 00 CO r- o o A P 3 0J >1 m I i" OV TTfsiuDr-irNir^air^ nc»(Nou s >ooo (0 p a) c •H s o in in Oh in r- 00 CO VO r- 00 f'- rH VD Oh rH CM m rH 5 5 3 T? C <0 r- r- 00 in in CN CM rH CM VD r- VD VD Oh M»n VD m Ch 3 rH TT CM 3 1 5 5 3 0 c VD Oh 00 rH r~ in r- CO £ VD Oh o CO Oh 00 i-* CM in P Oh p rH ro CO rH in m CO •H • i • LO o 00 CO r- r- rH rr CO rH VD rH CO CO rH VD m rH VD <0 0) Oh 0 o rH in CM CO CM in VD CO rr • u -H CX S P p 00 00 Oh in CM CO in in o VD CO VD N •—i CO O rH H 4 c w Oh o a) cn «—1 in CM ro CM m r~ CO •H c c p •rl •H (0 s P CO CO CM Oh Oh CO CM 00 Oh •rH C VD Oh 00 00 rH VD CN rH ro O p •H Oh O o P rH in CM VD CM CM o CM in o CO in 3 o 0 Oh c •H u rH VD CO VD CM VD VD CO H 4 o p *H Q) • p P in 3 C • O in Oh CO Oh Oh in in Oh z M Z VD 00 Oh CM r~ CO H 4 VD Oh Q) rH in ro in CM VD VD CO H* CN x: • • r- P c Oh o in CO CO CO H 4 VD in H 4 O rH P p in VD O 1—1 CO 00 on o in o tn Oh c n C rH in CO VD CM in VD H 4 H* P p •H o c x: fd 0) W o Oh ro Oh 00 H 4 rH Oh H 4 Ph fc 3 m o ro ro CO H 4 CO CO p S Oh f—1 p rH in CM in CM LO '3' co H’ (0 It 0 a P u a) c a •H w p V) 3 • CU (0 qj O in 0) p 4-i c • p o o (0 •H D a o .X p £ o •H <0 3 in p 'O 3 X Q e CT> p • • fd c QJ *H o C TS •H W aj p rd x: x: QJ m a p o .p p ro x: E -P (X id » —1 c S p rH 3 O •H z P o o QJ o X. p >1 c \ o W u 2 S3 z O Z Z £3 rH 1 in -606A- » individuals correctly anticipated that coal prices would rise, increasing the value of Federal western coal lands. There was no doubt a recognition that the enactment of air quality standards could stimulate demand for low sulfur western coal. 109 / It is also possible that companies were purchasing Federal coal lands in anticipation that liquefaction and gasification technology would be commercially available within the next 10 to 15 years, and that large blocks of reserves would be needed to support these plants. The Department of the Interior has cited two additional reasons for the increase in coal lease demand during the 1960's. 110 / One was the need for additional reserves to support existing and new coal-burning power plants. Second, it is said that applicants wished to obtain leases before changes 109 / The potential hazard of sulfur oxides to human health was recognized in the late 1950's. The Federal Government began allocating money for research in this area in 1957 and increased the allotment throughout the 1960's (S. Rep. No. 403, 90th Cong., 1st sess., 1967, pp. 19-21). The first Federal criteria for sulfur oxides were issued pursuant to the Clean Air Act of 1963. 110 / General Accounting Office, Improvements Needed in Administration of Federal Coal-Leasing Program , op . cit ., p. 29. I -607- were made in Government leasing policy. The anticipation of such policy changes appears to have been well founded, since the Department did alter its rental, royalty, and environmental requirements in the late 1960's and early 1970's. It seems clear that Interior did not anticipate the ris¬ ing value of Federal coal with as much foresight as pri¬ vate companies and individuals. EMARS, the proposed Federal coal leasing program, will actively involve the Department in setting the timing of Federal lease sales and coordinating coal leasing with projected coal demand. The success of this program depends on the accuracy of the Government's projections. If the Government under¬ estimates future demand and leases too little Federal coal land, coal prices may be driven up, leading inter alia to higher electricity prices. If, on the other hand, the Government leases too much coal land in rela¬ tion to actual future demand and imposes strict produc¬ tion (diligence) requirements on lessees, coal may be mined more rapidly than the balancing of longrun costs and benefits warrants. These possibilities must be weighed against the costs of letting the rate of Fed¬ eral coal leasing depend largely upon private industry -608- demand. The primary cost of such a laissez faire policy is that the Government may forego some revenue if future coal prices turn out to be higher than either the Government or private industry anticipate at the time of the lease sale. 111/ 2. Location of Leases In addition to letting industry control the timing of Federal lease sales, the Interior Department has also allowed industry to designate the location of each lease. This, as table 9.9 shows, has led to a very uneven dis¬ tribution of leases throughout the seven Western States. Industry lease initiative may ensure that leases issue where coal can be produced and delivered at the lowest possible cost. Little effort, however, has been made by the Interior Department to consider the effects of such leasing on the local economy, social structure, and environment in a given area, and therefore to price in the externalities of coal production or mandate recla¬ mation. 111 / It should be pointed out, however, that if coal prices turn out to be lower than anticipated at the time of the lease sale, the Government would gain, rather than forego additional revenue. -609- TABLE 9. in the 9.—Federal Coal Acreage Leased Seven Western States, 1920-74 State Acres Colorado 120,912 Montana 36,232 New Mexico 40,957 North Dakota 16,435 Oklahoma 89,211 Utah 267,435 Wyoming 201,768 Total 772,950 SOURCE: Bureau of Land Management data. -609A- 3. Lease Size The sizes of leases have also been set according to industry demands. Presumably, a mining company would not want a lease larger or smaller than it could effec¬ tively utilize. Leases range in size between 40 acres and 20,701 acres, with the average in the seven Western States area being 1,489 acres. It has been suggested that the small size of many Federal coal leases has deterred their development. 112 / This would not be true, however, if these smaller leases were located in proximity to other Federal leases or private coal lands. Similarly, although the average lease size is far smaller than that needed to sustain a coal gasification plant or utility contract. Federal leases could be com¬ bined with other Federal and non-federal lands to sup¬ port such a project. 113/ The only size constraint 112 / See testimony of Edwin R. Phelps before the Sub¬ committee on Minerals, Materials, and Fuels, Com¬ mittee on Interior and Insular Affairs of the U.S. Senate, May 8, 1975. 113 / In the sample of 142 of the 146 competitive coal leases sold between 1970 and 1974, 7.7 percent have sufficient reserves (at least 110 million tons of 8,500 Btu coal) to supply a 1,000 MW powerplant for 30 years, while 15.1 percent have sufficient reserves (225 million tons of sub-bituminous coal) to support a single 250 million standard-cubic- feet-per-day gasification plant. -610- currently imposed is the 1920 Act's limitation of 46,080 acres on Federal coal holdings in a State. 114 / This clause was included to prevent the monopolization of Federal coal land. In certain States several com¬ panies are approaching the 46,000 acre limit. 115/ The utility of present acreage limitations is dubi¬ ous, however, since the relationship between recoverable reserves and acres may vary widely with seam thickness, overburden, and local geology. Monopolization of Fed¬ eral coal resources could probably be hindered more effectively by limiting the amount of Federal recover¬ able reserves that could be held by any company in the U.S. 116/ 114 / 30 U.S.C.A. 184. The Interior Department, can grant additional acreage not to exceed 5,120 acres in a State. 115 / Kennecott-Peabody has 45,575 acres under lease in Utah, and Resource Company (Arizona Public Services Co. and San Diego Gas & Electric) has leased 39,354 acres in Oklahoma. Kennecott-Peabody holds leases under both names of Kennecott and Peabody; these leases have been added together to obtain their 45,575-acre holding in Utah. 116 / This type of limitation has been proposed in S.391, the Federal Coal Leasing Amendments Act of 1975. -611- (I 4. Type of Lease In addition to allowing industry to determine the rate, location, and size of Federal leases, the Interior Department has also allowed industry within certain bounds to choose between preference right and competitive leases. As discussed earlier, prospecting permits and preference right leases can be granted only in areas where the i U.S. Geological survey does not know the extent and quality of the underlying reserves. Subject to this condition, industry has been free to choose one type of lease over the other. Table 9.10 shows the breakdown of preference right and competitive leases issued by year from 1920 to 1971. The overall preference right and competitive lease sums are close—252 for the former and 253 for the latter. However, figure 9.2 illustrates the surge of interest in preference right leases during the 1960 to 1969 period. The peaks in preference right leasing correspond generally to the surge of overall interest in acquiring Federal coal lands. A more accurate measure of industry's demand for -612- CD > ercent petiti bid 3/ c fa g (U o > o cn o 0) U -P d> -H CO MH p rH dJ (d c p p p G (L> C -P C co fa 1 (D 1 5 o 1—1 cr» Q) fa > PI •H PQ +J < •H H -P T3 d) -H ap> g 0 u p fd CD I* oo OMnooooiooinoinooHOuionoH o o o o OlTKNOOin'XIHO'JfS^hM/lM/mOh o n h (NinfOMnininMninooiNcooio rHrHor-^roo^rsicMcoofM'^'Lncr\r^ocxirMvx)ror' iH ror^nincNcNforo cn rH OOOOrHOOOm^rOrHOrHOOrHOOOOO OOOOOOr^rH'^CTiU3'X)r s r^r^^ou3'i5vo^o | x)U)^0vovDiDLf)inininiriiri rH l—I i—I i—I r—I i—I r—) rHI i—I rH rH rH rHI r—I rH{ rH rH rH rH rH rH i—( J I I < CN »— 1 VD I » u o 44 'd .Hi G fO T5 J CD G c •H 4-> G O O G U CD V (D En G O cn I r- l o CD G +J CO G Sh CD 4-> W (D & o c rH Q) . > CTt a) CO w t-3 CQ < Eh (D •P > \ G -H ro| -H CD CD 43 O. a e O U G 4-1 O Eh 04 I CD TS P CD Cn 4-) CD (0 co Cn CD o G CD 4-> U 43 CD CX> <4H CD U CA H u CD > •H 4-1 •H 4-> Ti (D -H Oj43 e o u on-ooooooa^oouDi^-ooooooor-o ocoomooomcNOoincoooooooovoo unoifiMnooh^oim/UDO O O O O M3 O lOo^vflM'MCNnM’r^H^c^rofNrj'fotNncNnnH OlHOOOOOOOOOOOOOOOOOOOO I CQ CN r—I M3 CNCMCOiHrHOO.-H^OCN'^r—lO^rCOOOOOr-HO nvoronHCNinroroHMincNtNoocNncjncNH u G CD (NHOff>coi^voin'jfO(NrHocricor^'£)in^ro(NrH 0^G^0\1 0 0 a 0) 0 > d) X 0 ■H ro| G X X 0 CO •h dt o o o o o o o o o r- X 0 -P -H • o 0 X in ID o o o o in o o o | 00 X d! Oa ID in o o m r- o o o x 0 0 0 B rH rH rH rH 1—1 X o CO 0 D G CO o 0 0 a p 0 CO a B CO X 0 •H 0 X 0 0 Z rH X X X rH o 0 i—1 p X 0 0 0 X ro CN CN rH cn x in i—1 ro o O'! 0 X Eh O rH X X z Eh in 0 0 X 0 d! in Q 0 ■d G (Ml X •H E 1 X > P 0 d5 p •H rH P 0) 0 dJ 0 Cn X o o o O o o o o o o o x u 0 0 rH G W Cn 0 0 0 X O X •H X X CO 0 0 0 0 dJ 0 - s X •H G > 0 -P 2 X •H P X 0 o dJ 0 CO rH 1—1 1 — 1 O o i — 1 i-H o o o o CN z •H 9 X -H in X Z d! 0 P CN s 0 P 0 d) •H (X G 0 •H p 0 G X 0 X 0 a G 0 0 CO > x s •H •H X i 0 •H o 0 o CO X CN > d> 0 0 -H 0 0 a rH •p P rH • e •H dJ 0 0 0 0 -P -H ro CN I—1 CN rH .— I ro in 1—1 ro o ro rH 'd to u X 0 X! uo 0 0 0 z X 0, CN u X 0 6 rH p O co Cn CN 0 u 0 0 X X dJ P 0 G P Cn p £ rH rH 0 0 $ 0 o co x! rH X G 0 0 o rH H < u Eh p o CTi 00 r-~ ID in ■'3’ ro CN rH o 0 0 ro CN CN CN CN CN CN CN CN CN CN -P 0 O'! O'* O'* O'! O'! 1 rH rH rH rH rH rH rH rH rH rH rH Eh ^H | cn| ro | * I I u CN I— I ID I id SOURCE: Bureau of Land Management. different lease types is the number of acres leased. Table 9.11 shows the number of acres leased in each State from 1920 to 1974 under preference right and com¬ petitive leases. Among the States, the ratio between preference right and competitive leases varies widely. In the seven-States area as a whole, however, 2.1 percent more land area has been leased by competitive sales than by the preference right method. In the future this balance could be drastically alter¬ ed. In 1973, 361,099 acres were held under prospecting per¬ mits and 303,780 acres under preference right lease applications. 117/ According to the Mineral Lands Leasing Act of 1920, if the holders of such permits and appli¬ cations can show that the land contains coal in com¬ mercial quantities, they are entitled to a lease for all or part of the land. Therefore, when the moratori¬ um is lifted, permit holders able to meet the commercial quantity test can be awarded Federal coal leases. This 117 / U.S. Department of the Interior, Draft Environ ¬ mental Impact Statement , op. cit. , p. 1-205 and 1-206. Includes Alaska, Colorado, Montana, New Mexico, Utah, Wyoming, Oklahoma, and West Virginia. Alaska and West Virginia account for a very small percentage of the total acreage held under prospecting per¬ mits . -613- could lead to a near tripling of the acreage leased under preference rights, with preference right leases accounting for as much as 72 percent of all federally leased acreage. The consequences of having a large portion of Federal coal leased by the preference right method are twofold. Under this method, there is no bonus bidding. The Government receives only a $10.00 filing fee plus stipulated royalties and land rents which do not neces¬ sarily reflect the economic value of the coal. This means that roughly half of the land leased thus far has been leased without the Government's receiving any pay¬ ment reflecting the economic value of the coal at the time of the lease. Second, as we shall see momentarily, production from preference right leases has lagged con¬ siderably behind that from competitive leases. These two factors suggest that the preference right is not the most effective leasing method. 5 . Coal Production How, when, where and why the Government has leased Federal coal lands reflects only part of the resource allocation problem. Also important are those lease provisions -614- TABLE 9.11.--Acres Leased by Lease Type, 1920-74 1 — 1 1 — 11 Id >1 -P XJ TJ O -H -P T) a d) *4-1 W CD O (TJ > CU -H 4-> H -P co I - " CM co co co r- C -H (U W +J co O 00 CTC C" o O O Q) CO T r- CM CO r~ uo m n a o o e cm cd 0 o CM CM in rH in 00 o rH rH CO in CO iH co co uo A3 oc CM ac •<3* CM C" ■P 0 o CO o co OC rH CM Eh CM CO rH 00 co o f" rH CM CM r- 'O a) -p CO rH uo 0) CO CM CM o p x CM rr CO OC CO *3* in •H h* CM CM co o o in -P rH 00 co 00 rH CO •H o CO CM 00 ac CO -P Q) i—1 ■«3* CO CM in uo uo rH CM co rH rH CM o uo oc E rH rH co 0 O id -P 0 O o 44 O •H id (d 0) 'd 3-* 1 o u 2 2 2 O D 5 EH i i ' 3 ' CO I ILL SOURCE: Bureau of Land Management. that attempt to assure prompt production. The Depart¬ ment of the Interior has thus far largely allowed produc¬ tion from Federal leases to proceed at the lessee's pre¬ ferred pace. Examination of tables 9.12A and B reveal that the fraction of Federal leases sold between 1920 and 1968 on which coal has actually been mined varies widely from State to State, with a high of 63 percent in North Dakota and a low of 12 percent in New Mexico. The overall average percentage is extremely low. Of the 488 leases held by industry in 1968, only 147 have ever produced any coal. Included in these figures are leases that produced at one time but were not producing in 1973. Moreover, there is wide variation in production experience between preference right and competitive leases. As illustrated in table 9.12 and shown graphically in figure 9.3, only 20 percent of the preference right leases in the seven Western States have ever produced coal. In contrast, 41 percent of all competitive leases have produced. On a tonnage basis, according to data obtained from the Bureau of Land Management and U.S. Geological Survey, 3.5 times as much coal has been produced from competitive leases as from non-competitive preference rig]- leases, even though roughly the same amount of land has been -615- TABLE 9.12.A--Federal Coal Leases Sold During the 1920 to 1968 on Which Any Coal Was Ever Produced as of 1973 'O O W P £ e -h 0 o o 3 rH o VO o 00 CM CO o •H 0 P T3 CM o o CO rH CM CM p rH r~ vn rH CO OV CO CO CM -P Cn p £ c: £ 0) -H 0 o o uo CM CO o CM o e p p CO ■*r rH VO CM CM CO 0 0 'O tn 0 0 p £ P-I 0 2 w tn TJ 0 P c £ W 0 -H 0 0 n o cn CO o o iH r- P 0 e 3 CO iH CM in iH 1— \ 3 no iH VP 2 0 0 f—1 p 0 cu £ P 0 0 0 Eh P p 3 0 i—i VO VO VO O rH 00 00 m rH rH CM rH in •H -P Cn •H G -P P -H CD CD CD cu P P e £ P 0 3 o cj 2 P QJ in CM CD ro o CM O CO KD CM CO CM in CM O'! cn ro oo CJC -P G CD e CD C7> fd G fd £ g td PI CH 0 P fd CD P CD P P p o o in ro CM ro r» CQ m i—1 rH *—i rH C 7 \ ro CM CD 2 P Eh 0 fd 0 o -P fd P fd •H 0 £ Cn • • td G X P 0 G W CD p (d CD fd P •H rH CD -P 0 -P £ Q fd £ £ fd Ph id i—i G .H fd 0 P P •P 0 0 • • P •P >i 0 O cm CD s 2 2 O P Eh cm > -615B- 3 0) jQ to Source: Bureau of Land Management leased by each method. The difference in production experience between competitive and preference right leases indicates that some characteristic of a preference right lease is associated with a lower propensity to mine the tract. Since royalty and rental provisions are identical between preference right and competitive leases, and since the bonus payments under competitive leasing are sunk costs and therefore neither retard nor enhance develop¬ ment incentives, some characteristic other than payment type must account for the systematic production dif¬ ferences. As lands subject to preference right leasing are generally unexplored at the time prospecting permits are issued, it is possible that tracts so leased may have higher coal production costs or inferior coal quality, or they may be more remote from transportation media than competitively leased lands. Sufficient data are not available to examine coal mining costs and quality differences. However, by utiliz¬ ing U.S. Geological Survey railroad maps and plotting lease coordinates, an estimate of lease proximity to - 616 - railroad transportation was obtained for two of the seven Western States--Colorado and Wyoming. These States were selected as representative of the seven-States sample because they had a substantial number of competitive and preference right leases, but there were wide differences in production experience under the two lease types be¬ tween States. Wyoming had 23 percent of both its com¬ petitive and preference right leases in production, while Colorado had 54 percent of its competitive and 21 percent of its preference right leases in production 118/ The comparison is detailed in table 9.13. As can be seen, in Colorado approximately 63 percent of the competitive leases and 61 percent of the preference right leases were within 12 miles of a railroad trunk line; 86 percent of the competitive and 82 percent of preference right leases were situated within 24 miles. In Wyoming 35 percent of the competitive leases and 50 percent of the preference right leases were within 12 miles of a trunk line; 86 percent of the competitive and 92 percent of the preference right leases lay within 24 miles. 118 / Based on leases leased through 1968 that were in produc¬ tion as of 1973. - 617 - TABLE 9.13. —Approximate Distance to the Nearest Railroad Trunk Line for Competitive and Preference Right Leases in Colorado and Wyoming: 1920-74 1/ >1 03 O G 4-1 54 03 G o 54 03 W Cn 0) O Q3 03 44 P 044-1 03 03 >i W O 03 -H fd fd > 4-1 03 03 ■H fd rH 4-1 rH G •H p 44 H 4-1 got 03 3 4-1 04 0 *H g 5 0 u hHNOOO O 1 54 o PI 03 U3 4-1 03 fd cn o d 03 03 rH tn td 4-1 03 O rH •H U £ 03 XI CD O G 0) 4-> 5-1 X 03 On 4-1 -H 03 54 54 04 03 > •H 4-1 •H -p 03 04 £ o u td 4-1 o E4 o 4-1 Tj U3 fd 03 0 rH 54 -H 1—1 g •H fd 03 54 4-> fd 4-1 g 10 •H 03 X 54 o fd 54 03 04 G 04 < c fd P d OV H O O VO CO rH m 44 oo in o i—i rH i—i vo 0 H H CO p fd 03 5-1 p m 0) X 4-1 o fd 54 o rH o u d CM VO H O CO rH O m On C oo vo d m o -H r4 d e o >1 & o c—I in vo o m cm o o co VO CO >H rH r- i—i h* r~~ i—i i—i i—i co cn h 1 |in | u 54 03 03 > > O 0 X) i—i n rH CN 00 CN VO G fd CN H 1 00 CM vo G fd i—1 CM r- cn fd 4-1 rH CM o> fd -P 1 1 1 i 1 0 1 1 1 i l 0 iH co in cn CO r- E4 rH co m av co r-* E4 i—i CM r- av rH CM r^- (T\ XI XS 03 •H rH a • 04 W P 04 o) td e fd 4-1 'O fd fd t 0 54 tTl r4 G -H •h td 4-> 54 4-1 0 >i iH 03 04 > 54 >i P X! VJ XS 1 —I 0) o 0 cd P 5-1 •H (15 d I — 1 .H c/5 •H 05 rd 0 ■—1 rH pc; rd rd rd 05 P d p rH 0) •H CO X) CP 0 d! 05 0 5-1 05 P rH rd +J 0 0 rd '—i 0 !Z Cp rd o 05 d T3 rd -d 'd d p 05 P 05 0 0 id rd 4J 05 P p p S g rd 05 rd rd rd •H cp -h Cp cp CP 'd X 05 05 0 0 d 0 P 05 P p p rd P cpp Cp cp CP P cu 05 P 05 0 0 a 05 05 05 0 p < P 0 1 X 0) 05 O 0 1 •H P d d d • 05 P o P 0 rd m rd 0 •—i 05 05 05 0 p • 05 T5 0 0 0 d d d d • a PQ d *H d d d w < H T5 H H H u Eh 0$ p \ \ \ \ o CM 1 rd 1 ^ 1 in| C/5 While these measurements are admittedly crude, they do not support the hypothesis that preference right leases are generally farther from transportation media than are competitive leases. Hence, systematic differences in production patterns may possibly be related to pro¬ duction costs and coal quality differences, but further research is necessary before that conclusion can be sus¬ tained. While coal production on Federal lands has thus far been allowed to proceed in response to market forces, it is conceivable, as was discussed in chapter 3, that the imposition of per-ton royalty payments may have had the effect of retarding coal production by raising the marginal costs of production. Up to 1971, coal royalties were set on an absolute rather than a percentage basis, varying from 10 to 22.5 cents per ton, depending upon the year of the lease and whether or not the coal was mined on a strip or underground basis. 119/ The average coal price per ton in 119 / Prior to 1964, the per-ton royalty rate ranged from 10 to 15 cents. After 1964, the standard strip coal royalty was 2.5 cents per ton higher than that for underground coal. - 618 - the seven Western States during 1971 ranged from a low of $1.82 in Montana to a high of $7.37 in Utah. Thus, the highest royalty of 22.5 cents per ton would have ranged between 12.4 and 3.1 percent of the average selling price. 120 / This compares with royalties of 16.5 percent in offshore oil and gas. In 1971 a percentage royalty system was adopted by the Department. Royalty rates are 5.0 percent of the f.o.b. value of strip-mined coal, and from 2.5 to 4.0 percent of the f.o.b. value of underground coal, depending upon the mine depth. While we cannot quantify the precise effects of per-ton royalties on coal production, it is likely that they have not had a severe retardant effect. However, the effects have undoubtedly varied, depending upon specific States and coal production costs within them. In recent years, the Interior Department has at¬ tempted to encourage production from Federal coal lands. Two contractual stimuli have been used--accelerated rentals and minimum royalties after the fifth year of 120 / Based upon the average price data in table 9.8, a 22.5 cents per-ton royalty would translate into the following percentages of f.o.b. mine prices in 1971: Colorado, 3.5; New Mexico, 6.9; North Dakota, 11.8; Oklahoma, 3.3; Wyoming, 6.6, and United States 3.2. - 619 - ( fr r the lease. Another, diligence requirements, is being readied for application. Owing to the general decline in the number of com¬ petitive leases issued after 1967 and the moratorium im¬ posed in 1971, few leases incorporate the Interior Department's new production stimulating policy of ac¬ celerated rentals. Our sample of 142 of the 146 competi¬ tive leases let during the period 1960-74 includes only 19 leases issued in 1968 or later. Of these 19 leases, 14 have rents of $4.00 or more an acre beginning in the sixth year. Five were in production as of 1973. While in most cases not enough years had elasped between the lease date and 1974 to activate the $4.00 or more per acre portion of the rental clause, it is doubt¬ ful that rentals of this magnitude would have a signifi¬ cant effect in stimulating production. For our sample of 146 leases, the average lease size was 2,080 acres, and the average coal reserve per lease was approximately 87,900,000 tons. Assuming that 50 percent of the re¬ serves are recoverable, the average leased acre would contain approximately 21,130 tons of recoverable coal. Hence, a $4.00 per acre annual rental would amount to - 620 - about .02 cents per ton. 121/ Thus, if an average leaseholder expected that the value of his recoverable reserves would appreciate by even one cent per ton per year, he would not be induced to produce by the $4.00 per acre rental. Since the early 1960's, minimum royalty payments beginning in the sixth year have also been used by the Interior Department to encourage production. Until 1973, the usual clause provided for a $1.00 per acre minimum royalty payment even if the lease was not producing. Our sample of 142 competitive leases included 15 leases with such a provision. Of these 15, only two were producing as of 1973. In New Mexico, where all the sample leases contained such a clause, none of the leases was in pro¬ duction. As a $1.00 per acre annual minimum royalty fee would translate into roughly .005 cents per ton of 12] / In absolute terms, a $4.00 per acre annual rental for the average 2,080 acre lease amounts to $8,320 per year. - 621 - recoverable coal reserves, 122 / this is not surpris¬ ing. 123/ As indicated previously, diligent development and continuous operation are requirements of the Mineral Lands Leasing Act of 1920. The Interior Department has never enforced these requirements. In December 1974, Interior published proposed regulations to define "diligent de¬ velopment" and "continuous operation," as the terms ap¬ pear in both the 1920 Act and the Standard Lease Form. Underlying the imposition of diligence requirements is the notion that the public has an interest in the early development and continuous operation of leased Federal resources. Diligence requirements may be viewed as one means of ensuring that the public, and not private speculators, recoups any benefit from the increased value of coal over time. In addition, they could facili¬ tate alternative uses of coal lands, such as for agricul¬ tural purposes, if those uses become more attractive 122 / In absolute terms, a $1.00 per acre minimum royalty amounts to $2,080 per year on an average size lease. 123 / Additionally, on most Federal leases, rental pay¬ ments can be offset against royalty payments, negating the obligation to pay the advance royalty. - 622 - than coal mining and no coal has been mined from the leases. These benefits must be weighed against the poten¬ tial economic and social costs of diligence requirements. On the cost side, very strict requirements which force a lessee to produce coal or lose his lease could reduce would-be lessees' bonus bids and hence reduce Government revenue. 124 / But more importantly, as was discussed in chapter 3, if the social discount rate is less than the private discount rate, private companies would normally produce coal at a faster than optimal rate. Strict diligence requirements would serve to reinforce this disparity of intergenerational interests, so that coal would be produced at an even faster rate. The diligence requirements actually proposed by the Interior Department will not have as great an effect as the extreme "produce or lose" clause. The proposed definition of "diligent development" is broad and 124 / This type of diligence provision appears in section 7 of H.R. 3265 (94th Congress), a bill to amend the Mineral Lands Leasing Act of 1920: "Any lease which is not producing in paying quantities at the end of the primary ten-year term shall be terminated." -623 contains many undefined components. The only require¬ ment is that preparatory work be undertaken eventually to bring the lease into production. There is no pro¬ vision whereby a lessee could lose his lease if he were not actually producing by the end of a certain time period. In addition, the proposed regulations do not indicate whether they will be applied to all leases im¬ mediately or at the time of lease renegotiation. Thus, the anticipated effects of the proposed regulations are unclear. 6. The Moratorium Since 1971, the Federal Government has sustained an informal coal leasing moratorium. As was discussed in chapter 3, society makes optimum use of its coal re¬ sources if it uses first the coal with the lowest cost of supply and best quality. To the extent that these "least cost" coal reserves are not currently held by the Federal Government, the leasing moratorium should not by itself cause coal reserves to be exploited inefficiently. However, to the extent that substantial "least cost" coal reserves lie unleased on Federal lands, the mora¬ torium could impose additional and unnecessary social - 624 - costs. Sufficient data are not currently available to determine who holds such reserves. Substantial reserves are in non-federal hands, and these probably include many "least cost" tracts. However mild the moratorium's impact may have been thus far, it seems clear that the longer the moratorium remains in effect, the greater are the chances of forcing inefficient coal resource de¬ velopment. 7. Summary In summary, past Federal coal leasing policies do not appear to have caused the rate of coal production to deviate appreciably from what market forces dictated. While the imposition of strict diligence requirements could have substantial costs, the currently proposed Interior Department diligence policy does not appear to be very strict. Furthermore, the current coal leasing moratorium has probably not introduced significant de¬ velopment path inefficiencies. But the longer it remains in effect, the greater is the likelihood that it will do so. - 625 - Competition 1. Competition for Federal Coal Leases Active competition among bidders when coal lands are sold assures that the land is awarded to the appli¬ cant who values the land most highly. This is consonant with the Interior Department's policy goal of obtaining fair market value for coal leases. Competition is also fundamental to ensuring efficient resource development. An analysis of all competitive coal lease sales between 1920 and 1974 shows that the majority have at¬ tracted very few bidders. 125/ Twenty-one leases sold during this period had no bidders, so that the tracts were leased without payment of a cash bonus to an applicant who had originally nominated them. 126/ In addition, there have been a substantial number of leases in every decade since the passage of the 1920 125 / As noted earlier/ about half of the Federal leases have been transferred on a competitive bid basis. The other half have been leased under the non¬ competitive preference right system. 126 / These cases for the most part occurred early in the administration of the Act. - 626 - Act which attracted only one bidder. Table 9.15 shows that 63 percent of all competitive leases in seven Western States attracted one bidder, and only 4.6 percent had more than four bidders. Although table 9.10 shows that there was a substan¬ tial increase in the number of competitive lease sales during the 1960's, table 9.14 indicates that the propor¬ tion of competitive leases attracting only one bidder decreased only 2.5 percentage points from the overall average for 1920 to 1974. There were more substantial increases during the 1960's in the percentage of leases with two and three bidders, but the total number of leases in these classes was still very low. On a State-by-State basis, the percentage of leases sold between 1960 and 1974 with only one bid varied con¬ siderably. All such leases issued in New Mexico had only one bidder. In contrast, only 37.5 percent of Colorado leases fell into the one-bidder class. 127/ Wyoming had 127/ Based upon the BLM competitive lease sample, the percentage of leases sold between 1960 and 1974 re¬ ceiving one bidder in the seven Western States was as follows: Colorado, 37.5; Montana, 72.7; New Mexico, 100.0; North Dakota, 80.8; Oklahoma, 85.7; Utah, 68.9; and Wyoming, 47.4. ♦ - 627 - W (D w d d X O •• Cn cn r- i—1 •H W d w c • ■ -P d X d -H 00 ro •H -p G W d! CD -P d d d'd d -P O d -H a cn PHJ3 g d 0 G P4 u p d P x 0 w X d & 0) 5h G d d di > S3 d •h cn X m O G P X -H W 0 di 4-1 W P G 0 d d d W i—1 CM X X p d IN in g d d rH G JQ rH 2 I 1 1 2 00 00 • • r- in ro H cn W X CQ 1 rH W & d d a d di p i— i G d d a d • A d> d x X 0 d ■H -P di -P P d d D d A d) a -P P d d d di 2: g x d d 0 -p -P x w G d Cn d d rH G P A X •H cnx o P d P P w di d d -p 2s -P W G 0 d d 4-> X w O G d d •h d Q d rH a i— i Xi *H X Pj i — 1 -P in d a P H" a 0 i—1 G d 2 d d d X d A 0 -P P gn o d •H X A 0 15 • d A 2 CM W -P • G P W £ i—1 O 0 P d •H 4-1 C 4-1 -P 0 0 d d A G g d d -P d A G rH •HOW d a w d -P g w o G d -p P 0 w Odd 2 d di d H Si 4-1 4-1 -H 0 0 G d A di 0 P -P d 0 G P di d G d o d W g rH w d di >i 0 d A G d u PQ g d a \ rH 1 i • d d w a A d d 4-> W Q d d d • W H X W G G d d d) d W O d g d d -P d d XI d cn r—1 Cn d H d G CM d p d rH 4-> cn O d 2 P 4-) w di 0 G 44 w p d •H o X d A 44 rH 4-> X A Cn 0 d G G rH •H -H G •H di d d di di d > d -H p d d) X G G m -P H O 0 O G G G p •H W 0 d ■H •H P X P • d 0 d d >i 2s G P x cn d G 0 w d X H H P P Eh 0 d d d G di X X di • X O •H W A d A d G X Eh W d 0 44 d g di 0 d G X C i—i Cn G d P •H d d H w g w A d w X d) E G d P P 3 0 d d G ■H >i Xdi -P X d G d •H Q d X di di X -P d) d • cn d x cn G d • X 0 G Cn d d D o d > P 4-> d Cn •• d H d w P W w u Pd D O -a* 1 m| cn i < r- CM ID I the largest average number of bidders for Federal coal leases--2.45 per sale—between 1960 and 1974. 128 / The small number of bidders in competitive lease sales to date leads one to question whether the system has in fact been competitive. Despite the fewness of actual bidders, competition could be effective if the presence of potential bidders were sufficiently pervasive to force actual bidders to bid the highest price they would pay rather than risk losing the lease. While we are unable to demonstrate that potential bidders in fact had this effect, several factors at least point in that direction. First, there are a large number of operating coal companies, and the industry has a relatively low concentration level. Second, barriers to entering the industry are low to moderate. Third, a large and rather diverse mixture of coal companies, non-coal companies, and individuals hold leases on Federal land. And fourth, coal lease sales are publicly announced in local 128 / In the competitive lease sub-sample, the average number of bidders for leases sold between 1960 and 1974 in the seven Western States was as follows: Colorado, 1.92; Montana, 1.36; New Mexico, 1.0; North Dakota, 1.20; Oklahoma, 1.14; Utah, 1.49; and Wyoming, 2.45 \ - 628 - newspapers and at the Bureau of Land Management State Office. Interested persons or companies may also re¬ quest placement on State mailing lists to receive advance mail notification of lease sales. Hence, there appears to be a large number of potential bidders, a sizable number of whom have evidenced sufficient interest in western coal lands to win at least one or more tracts in an environment of easy access to advance lease sale an¬ nouncements. Whether these factors were sufficient to compel the ultimate bidders to bid the competitive price is unknown, but they must at least have exerted competi¬ tive pressure. 2. Impact of Federal Coal Leasing on Market Structure and Competition Although relatively little coal has been produced from Federal lands to date, there is little evidence that Federal coal leasing practices have had a substantial effect on competition within the industry as a whole. This is due primarily to the relatively insignificant role thus far of western coal in the nationwide market. - 629 - Prior to leasing any of its coal reserves, the Federal Government owned approximately 29 percent, or 123.8 billion tons, of mapped and explored reserves in the seven Western States. It has thus far leased only 15 billion tons. While 15 billion tons is not a small amount in an absolute sense, 129 / it represents only about 3.5 percent of the 431 billion tons of recover¬ able mapped and explored reserves in the seven Western States, or 2.0 percent of the roughly 750 billion tons of recoverable mapped and explored U.S. coal reserves. 130 / From this perspective, it would be difficult for the coal reserves transferred to private hands under past Federal leasing policies to have much longrun effect on competition in the coal industry. Moreover, as there is no way of knowing total U.S. coal reserves, let alone Federal holdings in unmapped 129 / Given the current U.S. coal consumption rate of 600 million tons per year, it is equivalent to a 25-year supply. 130 / See tables 9.1 and 9.2, supra . The U.S. recoverable reserve figure was obtained by taking the 1.5 tril¬ lion ton mapped and explored reserve figure shown in the "U.S. Geological Survey Professional Paper 820," op. cit ., and assuming an average recover¬ ability factor of 50 percent. - 630 - I or unexplored areas, it is possible that the Federal coal reserve holdings may be even less significant than that shown above. Reserves in unmapped and un¬ explored areas have been estimated as roughly equivalent to the resources classified as mapped and explored. 131/ Table 9.15, which presents 1974 Federal Western land acreage holdings for the 20 largest acreage holders, shows that the 4, 8, and 20 largest firms accounted for 28.6, 44.5, and 68.3 percent of the leaseholdings, respectively. Ranking the 20 largest Federal coal lease¬ holders by estimated total coal reserves in place yields somewhat higher concentration ratios. Categorized in this manner, the 4 largest reserve holders accounted for 131 / In "U.S. Geological Survey Professional Paper 820," op . cit ., the source used in estimating the State reserve universe against which Federal reserve ownership was measured, hypothetical coal resources in unmapped and unexplored areas of the U.S. are said to be 1.3 trillion tons, compared to an esti¬ mated 1.5 trillion tons in mapped and explored areas. For the seven Western States, mapped and explored coal resources accounted for the follow¬ ing percentages of estimated total coal resources (mapped and explored plus estimated unmapped and explored) at similar depth and seam thickness: Colorado, 35.6; Montana, 58.5; New Mexico, 69.5; North Dakota, 33.9; Oklahoma, 14.1; Utah, 53.0; Wyoming, 27.1; and seven States total 49.6. Ad¬ ditional resources, in deeper coal formations, also exist. - 631 - TABLE 9.15.—Twenty Largest Holders of Federally Leased Coal Acreage in Seven Western States: 1974 1/ G o rH r~ ID m CO CO CM CM CM CM CM rH rH rH rH rH rH 0 o p 0 a. to o p o < >1 G 0 cu e o u -X G rd on in ld 1 i—1 •rH G •H > — 0 O P • Pm <-3 0 • Pm £ i—1 co a, to P 0 rH 0 u 0 0 U •H •P o 0 •H U o G •H u u 0 •P 0 t—1 .r—'s. -p rH O -P G -P O G • CO 0 -H G 0 •H • P •H rH O P 0 > 0 o -P 0 Pm P o G t -P P o H G CO 0 G G 0 0 O G • — H CO CO G U Cn G 0 •P •H 0 G 0 < 0 G 0 HG hi u 0 to P o o — X •H N W Cn — CO X 0 0 6 *H -—- G • •H 0 0 •H 0 Pm 0 -P 0 Cn 0 u 0 P 0 • on rH rH rH 0 rH O X P P 0 u 0 U 10 0 Pm 2 0 U Q 0 •H 0 -P 0 CJ 0 0 0 0 t 0 •H p ■P u 0 o •H CO 0 2 G ■P u >i-H T3 0 Q o 0 0 G H 0 •H -p P U G "H G O d h c p •H p to H •H P ■p CO p -P p p S 2 W 2 0 O 0 p G <4H 0 0 o 0 G 0 to 0 CO 0 0 -p 10 rH 0 0 •H g Pm -G rC 0 • -p P CO G -P z G -P P 0 G P co CO o g 0 G O rH CO P 03 •H 0 CO o G P 0 O 0 0 0 0 rH •P P •H -p • 0 G 0 > 0 MH P P 0 OM U O on CO Pm w w D CO on < D U M x w 5 o < X X i—i cj (O rf inior^cocriOHorO'rinior' i—I i—I rl i—I i—I i—I i—IrH oo -631A- a 3 73 O CD U G c 73 -H CD fa W C 1^ rH p" iH O'1 td rH P CO cn P G 0) P 73 a) i—i fa O cn ffi a> £ fa cn c cd a) cn > p CD id cn PI c -P G CD CD Cd £ fd Eh CD I P I O • < m • • • • c rH 00 O' 00 •h 73 73 . rH rH id -p fa B G G 0 •H •H rC 0 o id •ro ■ro rH PC in in CO cm ro o id id in r» ro 00 H' rH CD ro ID o ro in 73 73 p ^ ^ ^ id CD ID u cn 00 o cn in fa fa fa < i—i CD 04 CN o P P O'- 04 ro in PC 0 0 id a, a \ p 0) CD in! P P • X 0 -p in cn U p CD CD 0 p P • fa 2 o O —- • c id id cn CD G (D g o CD o o > -P u H* rH fa P in i—i •H l"" CD G CD id X - ca fa >H > 0 CD 00 • ro g C — u S rH o rH fa rH (d H • CD • •H id a 0 -P 73 £ mh a, fa £ O g u u (d CD CD 0 P 0 CD •H o •H fa in 2 0 •H • Cd u P P fa id au CUfa 0 0 • -P CD 1 CD •H •H U rH >*< O £ G PI -P -P -P id X G x p 0 CD CD 0 CD in in in G in rH cn cd rH CD > rH fa > >i CD CD CD id P 0 p fa id U P fa CD iH I7> Cd CT» fa CD O CD CD 0 G id fa rH CD P P P G G G G fa u • fa Id 73 id td id id id 0 £ -H £ w fa 73 id c—i p id PI Pi PI 2 0 PI 0 >i • rH id > id CD CD v —' • rH D id > CD -P 73 P 7 CO O fa fa 0 id u CD 2 0 i cn cd in x G XI W H & < fa < -p H O U fa c X id o \ \ o fa 04 rH I 04 | ro | ^1 ml fa I CO rH fO CD I 4 34.6 percent of total leased Federal reserves in the seven Western States; the 8 largest, for 56.6 percent; and the 20 largest, for 81.7 percent. 132 / Concentra¬ tion ratios for reserve holdings broken down separately by strippable recoverable resources and underground recoverable reserves are quite similar. For strippable recoverable reserves, the 4, 8, and 20 largest firms accounted for 44.3, 68.9, and 92.8 percent of total Federal leased strip reserves. For underground reserves, the shares for the 4, 8, and 20 largest firms were 47.1, 60.5, and 82.0 percent. 133 / These statistics suggest that Federal coal leasing practices have not led to particularly high ownership concentration within the federally-owned reserve base. To determine whether Federal leasing policy has enhanced the reserve control of the leading coal companies on all western lands--private, State, and Federal--it would be necessary to identify all coal reserve holders and determine the extent to which reserve ownership is con¬ centrated. Such data are currently unavailable, so 132 / Based upon confidential reserve estimates obtained from the U.S. Geological Survey. 133 / Ibid . 4 - 632 - broader conclusions cannot be drawn. It is clear, however, that the holders of Federal leases are not necessarily the top coal and energy companies of the Nation as a whole. Table 9.16 com¬ pares the identity of the 20 largest Federal lease¬ holders by acreage with the top western coal producers in 1973, the leading coal producers for the entire United States, and companies with the largest production in 1970 of all energy resources. As can be seen, only 5 of the top 20 coal producers nationally, 8 of the top 20 Western States coal producers, and 7 of the 20 largest energy companies rank among the 20 largest holders of federally-leased coal acreage. Moreover, there does not appear to be any close correlation of ranks among these various groups. Hence, the groups do not appear to have dominated Federal coal lease acre¬ age holdings. The Federal coal leasing system has also not raised capital requirement entry barriers enough to preclude the participation of smaller companies. Half of the leases issued have been preference right leases, which require no bonus payment. In addition, only since 1970 - 633 - E O a) u u c (0 (0 o CM cn 1 CL 44 O cn m ft >1 cn d) cn c •—i C ft -ft d) i 2 43 44 • cn cn d) • a) cn D 42 ft rH 44 <0 10 d) >3 O 42 cn O 44 G o \ o CM cn C ...cn E 3 -ft < Cn O C2 G in m cn O •H ft r- ft E CL 2 Q< cn ^22 Z Z 2 o -«r cm rH Z O Z rH Z (0 o o 0) 42 -P 44 cn 0) im cn o ft (0 .* .3 c t0 O (X CM I I v£> cn W id O U •d a> cn (0 d) .3 nJ ft a) TJ Cn) ft <0 o CM Cn (2 r—1 C i—i (U 10 ■H 10 > cn O o o d> d) \ U 3 o in 44 CN X3 (0 H O cn C 44 10 ft 3 •p4 in ft CL O cn d) C2 cn c r- >1 •rH ft ft o\ cn Cn £ d) CD rH tn ft p a 44 d) 44 3 cn 44 c X3 •H •d a) cn w C 03 o S d) (0 ft CnX3 »3 CL •“•I cj &\ cu E (0 c >. c (0 D. E Ol U CM 2 2 222>^222w>ZZ ao cn oo 2 2 mo2H222'»22 I < CO cn >44 I CM ro •'T iruo c -od 1 o 43 id d) M2 CL — <0 O -c CJ -H o C O •—I -H (0 44 44 n3 C X3 0) C H *H O 44 cn c c a o u U o u Cn C •H c •H s ■-H o m u o U cn h a ft w (0 d) u o — o o •H cn ft 0) 44 O CJ •ft CD 44 > r-4 42 ^ W cn CD -ft cn co ij • o O CD 41 u •ft (0 O ^ H 0) (0 ^ o s o ft o>o u aj tx -ft Pl QUO 43 3 10 G o N C >44 0) •H <0 -ft E ft cn C4 E c it a> — <4> CL SX cn (Cj rH O <0 c o •ft 44 (0 c Pc CD 44 C o c cn 44 c w 'd o (Ti • <44 • C rH ft • o U O 4E |0 42 d> (/) O •rH m o (X rH 3 U *H H £> 1 —l 1 —l • -H d) r d (D <0 ft 10 -H 0 • (X rH rH CD C rH d) 0 d) ft o o cn (0 a. 42 m rH 44 £3 24 u o o H d *H •H ft 44 O <0'C 42 10 c u rH 3 -ft -ft U > IX 1 a-p 0 CP CO r~ p >1 o\ a) tr> c rH E P -P — qj a) B . a) CO • >1 3 XI • CO • D rl co cn Odd) 0 cn -P N (TJ CM cn c -P 3 -P CO 0 .__ C in C m -p p p E d) d) ON 3 0 -p I—1 •P 3 in — •P TJ d) co 0 2 P a eg •P I C 2 ■P I 0J e (0 c >. e P cu e o o 2 <0 TJ I TJ fO (tJ > E^ O E O o w co D ( 1 ) x p 4H O P O P O a> E o -iH P p p c o -H cn cn O U 0) TJ 10 p Eh iP m p a> tj a) u* c m (0 p a ON O • E 3 rP/ CM P d> ip B — § TJ 1 H • • nJ rr ON • O TJ r- • • P r- a. 0 u dJ rp VO in Eh on cn p -p 1 1 l rH d> 0 p p 1 —I ON ON ON r— rp U P d) (0 (0 XI 0 s -P 0) dJ 0) P X (0 aj cu 0 Ip ip (U 0 Eh d) -P JO P JQ XI X TJ p O W O f0 fC QJ nJ O 10 2 Eh Eh Cp 2 • • p p a) 2 CM | cn| -M 1 1 « E> - O CO -633B- have competitive western coal leases brought an average bonus bid exceeding $35 an acre. Assuming the aver¬ age 1960-74 competitive lease sample tract size of 2,080 acres, a $35 per acre bonus would amount to $72,800. For the highest annual average bonus of $267 per acre, which occurred in 1974, the capital requirements on an average tract would be $555,000. Com¬ pared to the $6.25 million capital investment required in 1969 to develop a one million tons-per-year Montana lignite strip mine, or the $7.7 million required for a million ton sub-bituminous strip mine in the South¬ western United States, 134 / the addition to capital costs of even the highest average bonus bid appears small. Thus, the relatively modest concentration of competitive bid acreage shown in table 9.17 should not be surprising. Furthermore, large coal and oil 134 / U.S. Bureau of Mines, "Cost Analyses of Model Mines for Strip Mining of Coal in the United States," Information Circular 8535, 1972, pp. 70 and 101. For a five million tons-per-year Montana lignite strip mine and sub-bituminous strip mine in the Southwest, the capital costs would be $20.0 and $27.8 million, respectively. See pages 78 and 86, in the same source. The capital costs for the one million tons-per-year mines are based on a 1,500 acre lease in Montana and a 1,920 acre lease in the Southwestern U.S. These capital costs exclude Government bonus payments. TABLE 9.17.—The 20 Leading Winners of Competitively Leased Federal Coal Acreage in Seven Western States, 1960-74 1/ Rank Company Acreage Percent 1 Sun Oil Co. 2/ 21,240 7.2 2 Richard D. Bass 20,401 7.0 3 Sentry Royalty Co. 19,170 6.5 4 Peter Kiewit & Sons 3/ 16,407 5.5 5 Exxon Corp. 15,490 5.2 6 W. Brannan 15,445 5.2 7 Atlantic Richfield 12,716 4.3 8 Kemmerer Coal Co. (Lincoln Corp.) 12,400 4.2 9 Kerr-McGee 9,992 3.4 10 Nevada Electric Invest¬ ment Co. (Nevada Power Co. ) 9,899 3.3 11 Pacific Power & Light Co. 9,130 3.1 12 U.S. Steel 8,887 3.0 13 Energy Development Co. (Iowa Public Service) 8,683 2.9 14 J.D. Karcher 8,031 2.7 15 Peabody (Kennecott) 6,350 2.1 16 Arkland Minerals Corp. (Ashland Oil & Hunt Enterprises 6,315 2.1 17 Malcolm & Armeda, McKinnon 6,076 2.1 18 Heiner Coal Co. (Occidental Petroleum Corp .) 6,315 2.0 19 American Metal Climax 5,960 2.0 20 Paul F. Faust 5,884 2.0 Total 4/ 295,656 4 Largest 77,518 26.2 8 Largest 133,569 5/ 45.2 20 Largest 224,795 5/ 76.0 1/ Based upon data for 142 of the 146 competitive leases let from 1960 to 1974. The named companies and indi¬ viduals are not necessarily the present acreage hold¬ ers, but rather those who originally won the competi¬ tive bonus bidding sale. -634A- TABLE 9.17.—The Twenty Leading Winners of Competitively Leased Federal Coal Acreage in Seven Western States, 1960-74—continued * 2/ Includes Cordero Mining Co. 3/ Includes Decker Coal Co. 2/ Total for the 142 lease sample. 2/ Does not equal column total due to rounding. SOURCE: Bureau of Land Management companies do not appear to dominate the list of the 20 leading competitively leased acreage winners. In summary. Federal leasing practices by themselves have not significantly affected concentration in the coal industry either nationally or in the seven Western States. By and large, this lack of effect can be at¬ tributed to the relative abundance of non-federal coal reserves, the relatively small amount of Federal coal reserves leased thus far, and the small capital costs needed in the past to acquire a Federal coal lease. In the future, when the current leasing moratorium is lifted, the effects on industry concentration of Federal coal leasing policy may still be modest. The Mineral Lands Leasing Act of 1920 limits a company's Federal coal land hold¬ ings to 46,080 acres per State. Assuming the recoverable reserve average of 21,130 tons per acre experienced in our 1960 to 1974 competitive lease sample, a maximum holding of 46,080 acres in each of the seven Western States would amount to 6.8 billion tons of coal per company, or 1.6 percent of total estimated recoverable reserves in the region. 135/ 135 / The per-acre reserve tonnage assumes a 50 percent recovery factor, as does the total seven-State re¬ coverable reserve estimate. - 635 - Fair Market Value 1. Legislative History and Statutory Basis Obtaining fair market value for Federal coal leases is one stated goal of the Interior Department in its management of Federal coal lands. 136 / The Department has indicated that this objective is based upon its interpretation of the legal mandates of the 1920 Mineral Leasing Act, along with Title 31 U.S.C.A. 483, which outlines Federal policy regarding fees to be charged for the receipt of Federal services or land. 137/ The Act of 1920 does not in fact require or even suggest the receipt of fair market value. According to the purpose clause, the Act's primary objective is to promote the mining of coal, phosphate, oil, oil shale, and i sodium in the public domain. Furthermore, there is no indication in the text or its legislative history that 136 / U.S. Senate, Hearings before the Committee on Interior and Insular Affairs, Federal Leasing Policies and Issues Governing the Management and Development of Energy Resources on the Public Lands , June 19, 1972, no. 92-32 pp. 38,39. 137/ Ibid. - 636 - the revenue provisions were designed to provide a fair market return to the Government. The conference report accompanying the final bill stated: . . . royalties and rentals are provided, so that the Government may not be passing title to the natural resources without receiving someting in return therefor. 138 / The statutory royalty and rental terms are stated in terms of minimum charges unqualified by any reference to obtaining fair market value. The statute's authori¬ zation of the preference right system as an alternative to competitive bonus bidding also suggests that the receipt of fair market value was not a primary legisla¬ tive goal. Title 31 U.S.C.A. 483 also does not require the receipt of fair market value for using Government property. It provides only that fees be "fair" and equitable, taking into consideration direct and in¬ direct cost to the Government, value to the recipient, 138 / U.S. House of Representatives, House Conference Re¬ port, No. 1138 (1919) 65th Cong., 3d sess., p. 19. - 637 - public policy or interest served, and other pertinent facts. It seems, therefore, that receiving fair market value for Federal coal leases is not a legal require¬ ment. In fact, Harrison Loesch, Assistant Secretary of the Interior for Public Management, indicated in 1972 that the receipt of fair market value was mandated by the Office of Management and Budget to maximize Federal revenues, and is not required by law. 139 / 2. Definition of Fair Market Value Apart from the question of statutory authority, there is a significant question as to what securing the "fair market value" of a lease means. One inter¬ pretation is that fair market value is the value re¬ ceived under an effectively competitive bidding system. Alternative constructions emphasize maximizing Govern¬ ment revenues or exacting the economic rent which ac¬ crues to a coal lease as its value increases over time. These three concepts are quite different. 139 / Federal Leasing Policies and Issues Governing the Management and Development of Energy Resources on the Public Lands , op . cit ., p. 102. - 638 - The last two relate not to competitive conduct, but to use by the Government of whatever monopoly power it possesses to increase its lease revenue, either by restricting the supply of coal leases and hence driving up coal lease prices, or by extracting additional revenues from lessees who bought leases for a small bonus in the past and now possess very valuable coal rights. The use of the term "fair market value" in these quite diverse contexts had led to retrospective value judgments that the prices received for past Federal coal leases were not in the public interest. Usually these post hoc judgments do not include an examination of the uncertanties actually prevailing, but merely re¬ flect a conclusion that, given today's coal prices and demand conditions, the bonus price accepted years ago was too low. 3. Revenue Received for Federal Coal Leases To shed factual light on these issues, we now examine the revenue the Government has actually received for Federal coal lands and the factors affecting its - 639 - amount. The Government is compensated in three different ways for coal leases: one-time bonus payments, annual rental payments, and annual royalty payments based on actual or potential production. The average bonus payment per acre fluctuated between 1954 and 1966, but except for a sharp jump in 1959, remained under $10.00. During the latter part of the 1960's, however, as table 9.18 shows, the average winning bid remained with some fluctuation above $10.00. There was a sharp peak in 1971, the year of the informal moratorium. An analysis was conducted of factors that might affect the size of the winning bonus bids. One obvious hypothesis is that the bid per acre was positively re¬ lated to the number of bidders and the year of the bid. To test this hypothesis, we applied ordinary least squares regression analysis to our sample of 142 com¬ petitive leases between 1961 and 1974. 140/ 140 / For a discussion of ordinary least squares regres¬ sion analysis, see J. Johnston, Econometric Methods, (New York: McGraw-Hill, 1963). - 640 - TABLE 9.18.—Competitive Coal Lease Sales on all Federal (Public and Acquired) Lands, Fiscal Year Basis, 1954-74 Fiscal year Acreage Bonus (Dollars) Average bonus per acre (Dollars) 1954 400 420 1.05 1955 458 504 1.10 1956 4,316 4,317 1.00 1957 3,993 6,297 1.58 1958 15,375 19,414 1.26 1959 8,085 224,179 27.73 1960 4,358 9,055 2.08 1961 12,733 20,531 1.61 1962 39,502 202,931 5.14 1963 20,780 143,023 6.88 1964 10,788 39,532 3.66 1965 23,364 146,358 6.26 1966 44,894 753,737 16.79 1967 43,885 721,294 16.44 1968 88,181 3,077,880 34.90 1969 — — — 1970 18,493 370,395 20.03 1971 28,546 7,626,954 267.18 1972 — — — 1973 — — — 1974 4,069 394,826 97.03 Total 372,220 13,761,637 36.97 U.S. Department Survey, Federal of and the Interior, Geological Indian Lands Coal Phosphate, Potash, Sodium, and other Mineral Production, Royalty Income, and Related Statistics (Washington: U. .S. ' Government Printing Office, May 1974), pp. 17-20. -640A- Specifically, we estimated: X. = a + b^N^ + b Y. + b D.; J I. where = the winning bonus bid per acre (in dollars) for the ith lease; N. = the number of bidders on the ith lease; 1 — Yj_ = a variable denoting the year in which the ith lease was put up for bid, with values rising from 1 to 15 for the period 1960 to 1974; and = A 0-1 dummy variable to account for a change in the Department of the Interior's leasing policy, taking on a value of 0 from 1960 through 1970 and 1 from 1971 (the year of the informal lease moratorium) through 1974. The result obtained was: X ± - 28.21 + 24.56** N ± ”.10 Y ± + 152.75** D ± ? (2.81) (1.33) (16.97) where the adjusted coefficient of determination R equaled .67. The standard errors are presented in parentheses be¬ low the coefficients, and the double asterisks denote co¬ efficients significantly different from zero at the .01 level. These results indicate that the winning bonus bid per acre rose with the number of bidders and was higher after the informal leasing moratorium (in 1971) - 641 - than before. The lack of statistical significance of the year term indicates that in the context of this model, a consistent time trend of winning bonus bids was not found. As the number of bidders significantly affected the size of the winning bonus bid per acre, an examination of factors which might influence the number of bidders appeared warranted. The hypothesis developed was that the quantity and quality of the coal reserves on a given lease and the year of the lease sale would con¬ stitute such factors. Specifically, N i = a + b! s i + b 2 U i + b 3 R i + b 4 Hj_ + b 5 Y i + b 6 D i'* where = number of bidders on the ith lease; = millions of tons of recoverable strip re¬ serves on the ith lease; - millions of tons of recoverable underground reserves on the :1th lease; = average sulfur content per unit of coal weight; th = average heat content per ton of coal, in thousands of Btu's; = a variable for the year in which the ith - 642 - lease was put up for bid, having a range of 1 through 15 for the period 1960 to 1974; and = a 0-1 dummy variable to account for a change in the Department of the Interior's leasing policy, taking on a value of 0 from 1960 through 1970 and 1 from 1971 (the year of the informal lease moratorium) through 1974. The data utilized for the coal quantity and quality variables S^, U^/ R-jy and were from Bureau of Land Management files as of 1974. Therefore, they were not necessarily available in the same form to prospective bidders prior to a lease sale. The results obtained were the following: N i = 1.068 + .004** S i + -004 U ± -.003 R ± (.001) (.004) (.002) + .023 H i + -049 + 1.036* D i ; (.036) (.035) (.447) 2 where the adjusted R equaled .34. The single asterisk denotes coefficients significantly different from zero at the .05 level. These results indicate that, other things being equal, the greater the strip reserve ton¬ nage on a lease, the larger was the number of bidders. - 643 - In addition, the number of bidders tended to be larger during and after 1971 than before. No statistically significant relationship between the number of bidders and the quantity of underground reserves, the sulfur content, and the Btu content was found, nor was there a significant time trend in the number of bidders. Since these same coal quantity and quality vari¬ ables might also exert an influence upon the size of the winning bonus bid per acre, we next combined both sets of variables into the same equation. In doing so, the relative explanatory power of coal quality and quantity, the number of bidders, and time could be deter¬ mined. We found that: X ± = - -26.50 + 21.34** N ± + -06* S ± + .01 U ± (3.25) (.03) (.15) + .01 R i + -18 H ± -.51 Y l + 158.16** D i ‘, (.09) (1.38) (1.35) (17.23) where the adjusted R 2 equaled .67. Other things being equal, the greater the number of bidders and the more strip reserve tonnage on a given lease, the larger was the winning bonus bid per acre. In addition, larger winning bonus bids were received during and after the informal moratorium than before. No significant time - 644 - trend was found, nor was there a significant relation¬ ship between the winning bid and underground reserve tonnage, sulfur content, or Btu content. It should be noted that adding the coal quantity and quality vari¬ ables to the number of bidders and time did not increase the amount of bonus bid variance explained; the R values were the same with and without the quantity and quality variables. However, it does appear that the quantity of strip reserve tonnage influences both the number of bidders and the size of the winning bonus bid. Regardless of the mechanism determining coal lease bonus bids, the Government has in general received very little bonus revenue per ton for Federal coal. Table 9.19 shows the dollar amount received per thousand tons of coal reserves for competitive coal leases in the seven Western States between 1960 and 1974. As can be seen, the proceeds varied from as little as 3 cents per thousand tons for Colorado coal in 1962 to $27.35 per thousand tons for Utah coal in 1974. Within indi¬ vidual States, an upward trend is not clearly evident, and the amounts received in the 1970's were not always higher than in earlier years. - 645 - Cn G ■iH e 0 MH si 0 cn c 0 td Eh -P P 73 G id to td p E 0 0 x: p Eh td i—1 a) r" o P i o -P vd td G cn 4-> Q) rH o 6 >1 td tO •• Q cu cn a) p cn > -p P g iH c a) 0 o cn 2 m qj Pi u 0 to a) O i—1 rH •H i-H rQ X 0 cd QJ Q G s 0) Q) > £ IT O CD (0 O 2 G td < G 1 td 1 -P • G cn cn cn cn cn >H t —) rH i-H i-1 i—l rH (—i rH 1—1 iH i—i rH i—i rH iH W U Pi D O c /1 -645A- As table 9.20 shows, the amount received by the Government from coal lease royalties between 1920 and 1974 also has been very low. One reason is the lack of coal production from Federal lands. However, even if production increases dramatically. Federal lease royal¬ ties have been set at low fixed rates. Only recently has the Interior Department set royalty rates on a per¬ centage of value basis, permitting the Government to share in the increasing value of coal over the years. In summary, the Federal Government has received relatively small bonus payments and royalties from coal produced on Federal lands. The size of the bonus payments was determined under a competitive bidding process at the time the lands were nominated for lease. Hence, these bonus payments undoubtedly reflect how the market valued the tracts at the time of the lease sale, rather than how much they might be worth today. We found that the size of the bonus bid per acre was higher, the larger the number of bidders, the more recent the year, and the larger the quantity of strip reserves. - 646 - TABLE 9.20.— Royalties Received from Federal Coal Lands, 1920-74 Fiscal year Royalty value (dollars) Prior to 1948 11,696,969 1948 772,754 1949 845,956 1950 799,748 1951 1,020,301 1952 918,517 1953 866,016 1954 865,447 1955 723,381 1956 702,969 1957 708,758 1958 660,288 1959 608,385 1960 621,042 1961 645,014 1962 740,098 1963 634,522 1964 718,061 1965 777,557 1966 835,928 1967 933,084 1968 925,423 1969 1,079,035 1970 1,069,925 1971 1,504,704 1972 1,606,362 1973 2,198,891 1974 3,374,134 Total 1920-74 38,853,269 SOURCE: U.S. Department of the Interior, Geological S urvey, Federal and Indian Lands Coal, Phosphate, Potash, Sodium and Other Mineral Production, Royalty Income, and Related Statistics, pp^i 4"8~i 49. -646A- Summary and Conclusions Vast amounts of the Nation's coal reserves lie in the Western United States. While the majority of these reserves appear to be in non-federal hands, the Federal Government still owns a substantial portion. To date, however, only a relatively small fraction of these Federal reserves have been leased, largely because de¬ mand for western coal was inhibited by high transporta¬ tion costs to major consuming areas prior to 1971 and a leasing moratorium has been in effect since then. Discovery risks, technological risks, development costs, and other entry barriers historically have been low to moderate in the coal industry. At present, the lack of a coordinated Government energy policy concern¬ ing the requirements of the Clean Air Act and the pro¬ posed strip mining reclamation legislation appears to impose the largest degree of uncertainty. Prior to the current leasing moratorium, Federal coal leasing policy permitted industry to control the timing, location, and size of lease sales. Private companies that had the foresight to acquire Federal - 647 - leases before the moratorium will capture the economic rent attributable to dramatic coal price increases of recent years. About one-half of Federal western coal acreage was leased under the preference right system, without any competitive bid bonus accruing to the Federal Government. The competitively leased acreage attracted relatively few bidders, raising some question as to how competitive past bidding has been. It is not clear how potential competition sub¬ stituted for actually observable competition. The Government has received relatively little revenue from Federal coal, whether through royalties, rentals, or bonus bids. In part because of this. Government coal revenue policy does not appear to have erected significant capital requirements entry barriers. Since vast amounts of non-federal coal land exist and since relatively little Federal coal land has been leased thus far, competition in the coal industry does not appear to have been affected substantially by past Government leasing policy. Because much non-federal coal exists, the current leasing moratorium is unlikely to interfere greatly with efficient coal resource - 648 - development. But the longer the moratorium is in ef¬ fect, the greater is the opportunity for it to cause resource misallocations. In the future, there is likely to be an increase in the demand for western coal and with it an increase in the importance of federally-held reserves and leas¬ ing policy. While the details of future leasing policy are unclear, the general direction appears to be away from laissez faire market operation. There is a perceptible movement toward Government decision¬ making concerning the location, timing, and size of lease sales as well as direct Government involvement in coal production decisions. - 649 - Chapter 10 URANIUM LAND POLICIES Introduction Nuclear energy has been used to generate electric power for a comparatively short period of time. Since the introduction of the first commerical-scale nuclear electric power plant in 1957, however, the number of such plants in operation, under construction, or on order has grown rapidly. 1/ The primary reason for utility companies' interest in nuclear power is the relative overall cost advantage, despite higher capital costs, of nuclear over fossil-generated electricity. 2/ 1/ Two hundred thirty-six nuclear power plants with a total capacity of 234,913,600 kilowatts were opera¬ tional, under construction, or on order in the United States as of March 31, 1975. ERDA News Release No. 9., May 1, 1975. 2/ Twenty-one U.S. electric utilities have found that nuclear plant costs, including capital costs, average 10.52 mills/kwh, compared to fossil plant costs of 17.03 mills/kwh. The fuel cost advantage of nuclear plants is even greater—2.15 mills/kwh compared to 11.25 mills/kwh for fossil fuel. N. Jacobson and C. FitzGerald, "The Year of the Cutback," Nuclear News , vol. 18, no. 3, Mid-February, 1975, p. 29. See also Federal Energy Administra¬ tion, Project Independence Blueprint: Task Force Report, Nuclear Energy , (U.S. Government Printing Office, Washington, D.C., 1974), p. 1.0-6. - 650 - Thus, a recent projection by the U.S. Energy Research and Development Administration (ERDA) indicates that by 1985, about 30 percent of all U.S. electric power will be nuclear-generated. Recently the nuclear industry has experienced setbacks owing to licensing problems, construction delays, opposition by anti-nuclear advocates, the difficulties of raising capital, and a projected decrease in the long-term growth rate of demand for electricity. These suggest that ERDA's nuclear growth projections may be overly optimistic.3/ It seems clear, however, that nuclear power will share significantly in meeting the Nation's demand for electricity during the last two decades of this 3/ U.S. Atomic Energy Commission, The Nuclear Industry , 1974 , WASH 1174-74, (Washington: U.S. Government Printing Office, 1974), p. 5. See, for example, L. J. Perl, "The Future of Nuclear Power in the Electric Utility Industry," Nuclear News , vol. 17, no. 15 (December, 1974), p. 60, and P. Joskow and M. Baughman, "The Future of the U.S. Nuclear Energy Industry," Massachusetts Institute of Technology, Department of Economics Working Paper No. 155, April, 1975. - 651 - TABLE 10.1.—Projected Installed Electric Generating Capacity in the United States (thousands of megawatts) Actual on-line Type of generation capacity 9-30-74 Hydro 62 Internal combustion and gas turbine 42 Steam: Coal, oil and gas 331 Nuclear 26 Total 461 Projected capacity 1975 1980 1985 1990 1995 2000 70 88 97 115 133 150 42 52 64 81 107 141 355 430 408 489 530 639 43 85 231 475 760 1,090 510 655 800 1,160 1,530 2,020 Source: U.S. Atomic Energy Commission, The Nuclear Industry, 1974, WASH 1174-74, p.14. -651A- century. 4/ In a fossil-fueled steam-electric power plant, coal oil, or gas is burned in the boiler's firebox. In a nuclear power plant, the nuclear steam supply system replaces the boiler and the nuclear fuel core replaces the fossil fuel. A nuclear fuel core contains specially fabricated fuel which, when activated, undergoes nuclear fission and thereby produces energy in the form of heat. The heat converts water into steam which, as in a fossil-fueled plant, turns a turbine generator and thus produces electricity. The fuel used in a nuclear power plant may be uranium, thorium, plutonium oxide, or a mixed oxide combination. Uranium is a natural element, and its 4/ There is, of course, considerable debate over potential dangers associated with nuclear power, leading some to speculate that nuclear generation of electricity will or should be far less signifi¬ cant than most expect. This report does not attempt to evaluate the safety issue or to arrive at independent conclusions concerning the pros and cons of nuclear power. We therefore assume that the nuclear industry will continue to grow at a pace dictated primarily by the demand for electric¬ ity and the comparative availability and overall costs of other generating methods. - 652 - isotope U-235 is capable of fission. Thorium is a natural element relatively plentiful compared to uranium, but it does not fission until exposed to fission, typically in a nuclear fuel core in which uranium is the essential ingredient. Plutonium is a radioactive product of uranium U-238 which has similarly been exposed to fission. Hence, uranium is essential for production of nuclear-generated power. At present all commercial nuclear power plants through¬ out the world use uranium as the principal fissionable ingredient. While the domestic uranium industry is over 25 years old, the Federal Government was the industry's primary customer until about five years ago, and private demand failed to take up the slack until the beginning of 1973. Since that time, however, demand for uranium has increased sharply, and the average prices both for spot sales and for future sales have risen spectacularly (see figure 10.1). Since U.S. uranium demand is expected to increase further during the next decade, and since approximately eight years' lead time is required to develop a mineable uranium - 653 - reserve, it seems clear that exploration for new uranium deposits will have to be expanded in the near future to satisfy this increased demand. 5/ Public Ownership Of Uranium Lands Nearly all of the uranium discovered thus far in mineable grades and amounts is located in the Western States, where Federal land ownership is concentrated. Figures 10.2 and 10.3 show the geographic distribution of known reserves. The Energy Research and Development Administration has estimated that over 54 percent of all U.S. acreage held for uranium exploration or mining as of January 1, 1974, was held under mining claims on public lands. Approximately 38 percent of the Nation's 5/ See remarks by John F. Hogerton, executive vice president, S. M. Stoller Corp., "Domestic Uranium Supply, Near-Term and Long-Range," presented before the Atomic Industrial Forum Conference on Energy Alternatives, Feb. 19, 1975. - 654 - r known uranium reserves 6/ recoverable at a forward cost of $8 per pound of uranium concentrate were located on Federal lands held under patented or unpatented claims. Virtually all of the remaining reserves were on lands which once belonged to the Federal Government, but which passed into private hands through homesteading or grants to railroads, Indian tribes, States, educa¬ tional institutions, and the like. The leasing of public lands for exploration and mining has played a minimal role in the development of the uranium industry. Such leases have in fact accounted for less than two percent of domestic uranium production to date. 7/ This is not because uranium 6/ It is important not to confuse the term "reserves" with estimates of total available resources. Reserves represent only those deposits that have been discovered and delineated and are considered minable at some determined forward price, A comprehensive five-year Government program is underway to evaluate domestic uranium resources and to identify areas favorable for uranium exploration. It is expected, however, that future uranium production will continue at least initially to take place on deposits located in the public domain. 7/ However, a substantial amount of uranium leasing has taken place on Indian tribal lands. See Federal Trade Commission, Staff Report on Mineral Leasing on Indian Lands, 1975. - 655 - c deposits have not been found on public lands. Rather, it reflects the fact that uranium lands have been transferred from Government to private hands, primarily under the General Mining Law of 1872, 8/ which allows individuals and companies to locate or stake claims on, and consequently exercise control over, such lands. The principal focus of this chapter will thus be on the 1872 law and the so-called location-patent system rather than leasing practices. The objectives are to describe the mechanics of the present system, to analyze its strengths and weaknesses, and to evaluate suggested measures by which the system might be improved. 9/ 8/ 30 U.S.C. § 22 et seq. 9/ For an excellent exposition of relevant problems, see P. Strauss, "Mining Claims on Public Lands: A Study of Interior Department Procedures", Utah Law Review, vol. 1974, Summer, no. 2, p. 185. - 656 - r The Location-Patent System Under the General Mining Law of 1872, no license or permit is required in order to prospect for uranium or other hard-rock minerals on the public domain. 10 / Any U.S. citizen is entitled to locate a mining claim provided he discovers a valuable deposit and performs a few simple acts. 11 / The maximum size of any single lode claim is 600 feet by 1500 feet (i.e., approximately 20 acres). However, there is no limit on the number of separate claims a person may locate. 12 / A valid claim entitles the claimant to certain surface and mineral rights, except for certain specified minerals governed by other laws. 13 / 10 / Much of our information on mining customs and practices was obtained through the efforts of Jimmie Jinks, mining engineer, Division of Mineral Resources, Bureau of Land Management, Department of the Interior. 11 / 30 U.S.C. §22. 12 / 30 U.S.C. §23, Zollars v. Evans , 5F. 172 (1880); Gwillim v. Donnellan, 115 U.S. 45, 5 S. Ct. 1110, 29 L. Ed. 348 (1885) . 13 / 30 U.S.C. §26. Wilbur v. United States ex rel. Krushnic, 280 U.S. 306, 50 S. Ct. 103, 74 L. Ed. 445 (1930). - 657 - Customarily, the first step in establishing a mineral claim is the physical act of "location." To locate a claim, one must physically mark out its boundaries on the land, post a notice containing certain information about the claim and the claimant, and then record the claim at the local office where land records are kept (normally the county courthouse or recorder of deeds office). 14 / There is no requirement, nor is there any provision, for notifying the Federal Government. t Once a valid discovery has been made and the acts necessary to perfect the claim have been performed, the claimant has the right to exclusive possession, 15 / subject to a further requirement that he spend at least $100 each year on labor or improvements (known as "annual assessment work") on the claim and file a 14/ 30 U.S.C. §28, Smith v. Union Oil Co., 135 P. 966, 166 Cal. 217, affirmed 249 U.S. 337, 39 S. Ct. 308, 63 L. Ed. 635 (1918) . 15 / Such possession is normally considered "exclusive," although others may be granted rights for grazing, drilling for oil, and other activities which preserve the claimant's rights. - 658 - r notice of such expenditure in the county land office. 16 / Failure to perforin assessment work in a given year leaves the land open to the location of a claim by another party. However, even if the work is not performed for one or more years, the original claimant may maintain his claim by bringing the assessment work up to date, as long as no one else has located a claim on the property in the interim. 17 / The property rights conferred by a valid mining claim are equivalent in some respects to fee simple ownership, the highest level of real property ownership recognized by law. As long as the annual $100 require¬ ment is met, the holder of a valid claim has the right not only to exclusive possession and extraction of specified valuable minerals, but also to assign, lease, or otherwise dispose of the claim as he sees fit. 18 / In addition, a mining claim is considered a property 16/ 30 U.S.C. §28; Chamberlain v. Montgomery, 1 Utah 2d 31, 261 P. 2d 942 (1953). 17/ Pascoe v. Richards, 201 C.A. 2d 680, 20 Cal. Rptr. 416 (1962). 18/ Wilbur v. United States ex rel, Krushnic, 280 U.S. 306, 50 S. Ct. 103, 74 L. Ed. 445 (1930). - 659 - c right which cannot be seized by the Government without compensation once a valuable discovery has been made. 19 / Although a claimant may freely explore for and extract minerals from a property held under a valid mining claim, he may be subjected to attempted encroach¬ ment, nuisance actions, and the like by others. Also, some financial institutions may be reluctant to advance credit for mining or development on property that is not held in fee simple. Thus, in order to secure permanent and absolute rights to a property containing a valuable mineral deposit, a claim holder may wish to file an application with the U.S. Department of the Interior for the issuance of a patent to the claim. In applying for a patent, the claimant must indicate the precise location of the land, prove that < the mineral deposit is sufficiently valuable to warrant profitable mining operations, certify that at least $500 has been spent on labor and improvements, and pay 19/ United States v. North American Transportation & Trading Co., 253 U.S. 330, 40 S. Ct. 518, 64 L. Ed. 935 (1918) . - 660 - r the Government $5 per acre plus a filing fee of $25 for each application. 20 / If the application is approved, the claimant is awarded full and absolute title to the property, and he may thereafter mine it or otherwise do with it as he sees fit. 21 / Weaknesses Of The Location-Patent System From a number of standpoints, both the General Mining Law of 1872 and the ways it is administered are outmoded and inadequate with respect to the discovery and extraction of uranium located on publicly-owned lands. 22 / 20 / 30 U.S.C. §29. The per-acre charge is only $2.50 for applications based on placer claims. Uranium deposits occur almost entirely on lode claim land, however. 21/ Deffeback v. Hawke, 115 U.S. 392, 6 S. Ct. 95, 29 L. Ed. 423 (1885). 22 / Our inquiry has not focused on whether the ex¬ traction of other types of minerals is similarly affected. It seems plausible, however, that the problems are similar if not identical. - 661 - For example, the system anticipated by the framers of the 1872 law was one in which prospecting for and discovery of a mineral deposit preceded the location and recording of a claim. However, from the beginning most prospectors have tended to locate claims first, often on mere speculation, and explore for minerals afterwards. The courts have long recognized this de facto amendment of the law, although the cases hold that in the absence of a valid discovery by a claimant, others are free to enter upon the claimed land and prospect for themselves. Should the subsequent locator (known in less genteel times as a "claim jumper") have the first valid discovery, his claim will be superior to that of the prior claimant. 23 / While this doctrine, known as pedis possessio , 24 / protects prior claimants by extinguishing the rights of later claimants whose entry is "forcible, fraudulent, surreptitious, or 23 / Ranchers Exploration and Development Co. v. Anaconda Co. , 248 F. Supp. 708 (1965). 24 / Defined as "actual possession," meaning a foothold on the land, as opposed to "possession in law" which follows in the wake of title. Churchill v. Onderdonk, 59 N.Y. 134 (1874). -662- clandestine," 25 / later peaceable claimants appear to enjoy no similar protection against forcible ejection by prior claimants. Thus, prospectors who have been forced off or kept off a claim of questionable validity by shotgun have no recourse but to institute legal action, which is ordinarily far too costly merely to determine whether or not a valuable deposit has in fact already been discovered. Moreover, even if the matter is litigated, it is necessary (and difficult) to prove the lack of any valuable discovery by another to a court's satisfaction. And even if the absence of dis¬ covery is proven, all that can be awarded is the right to prospect—a right of uncertain value. Faced with such unfavorable odds and modest rewards, few prospectors choose to expend their limited funds and energies on claim challenges, even though the law permits them to do so. Thus, as a practical matter, a claim that is legally invalid due to the lack of a valuable discovery is nevertheless relatively secure against other 25/ Atherton v. Fowler, 96 U.S. 513, 24 L. Ed. 732 (1878) . -663- prospectors, and such prospectors cannot roam freely over the land looking for valuable minerals as Congress originally intended. The physical act of location causes additional problems. As noted previously, to locate a claim requires that the prospector physically stake the land, post a notice, and record the claim at the county land office. This series of acts along with mineral dis¬ covery are supposed to perfect the claim and put the world on notice that the claimant has first rights to the property in question. Yet the system works better in theory than in practice. For one thing, location notices are often vague, containing such language as "starting at a point northwest of the big ponderosa tree." As a result, there is extensive overlap among claims and frequent "over-staking" (staking of claims to the same piece of property, intentionally or other¬ wise, by more than one party). In addition, some prospectors record a notice of location but neglect to stake the land physically. Others may stake the land and post a notice but not record the claim. This can and often does result in complicated and expensive -664- litigation to determine who has a claim to what parcel of land. There is another common cause of confusion. Once a claim has been located and recorded, all that is necessary to abandon it is to cease doing the required annual assessment work, in which case another prospector may legitimately locate a claim to the same property. Consequently, companies or individuals active in exploration often hire agents to watch a particular area of interest and relocate claims on any properties that may be ripe for takeover due to assessment work lapses. However, if a claimant not wishing to abandon the claim has actually done the assessment work but has merely neglected to file his yearly performance notice, he may revalidate his claim by filing such notice, even if someone else has relocated a claim to the property in the meantime. Thus, many claims are located by individuals and companies who literally do not know whether the previous claim is valid. Furthermore, several claims to the same property may be located and recorded, so that if the first claimant either abandons his claim or fails to do his assessment work, the next -665- claimant in line will be able to exercise control. Since the cost of staking and recording is so low and the potential reward appreciable, such claims may be as many as seven or eight deep in the case of promising uranium properties. Much vexatious litigation as well as confusion and hard feelings result all too frequently from these gaps and anomalies in the law's prescriptions. It should be noted that a claimant's rights against other private parties, which are primarily governed by State laws and precedents, are substantially different from those against the Federal Government. For example, while a claimant who is working towards discovery but has not yet found a valuable mineral deposit cannot be forced off the claim by another prospector prior to discovery, he has virtually no rights as against the Federal Government. Should the Government choose to withdraw lands from the public domain upon proper notice and adequate hearing, private claim holders will lose their property rights. 26 / 26 / Cameron v. United States , 252 U.S. 450, 40 S. Ct. 410, 64 L. Ed. 659 (1920); Best v. Humboldt Placer Mining Co., 371 U.S. 334, 83 S. Ct. 379, 9 L. Ed. 2d 350 (1963) . -666- In addition, the Department of the Interior may at ► any time require a claimant to prove the validity of his claim by showing that the mineral deposit is suf¬ ficiently valuable to warrant profitable mining opera¬ tions. This requirement was interpreted in the past under the so-called "prudent man" test. It required the mineral deposit to be one on which "a person of ordinary prudence would be justified in the further expenditure of his labor and means, with a reasonable prospect of success, in developing a valuable miner." 27 / The Interior Department has chosen, however, a more precise and demanding meaning of "valuable mine," requiring that the mineral discovery have "present marketability." In United States v. Coleman , 390 U.S. 599 (1968), the Supreme Court affirmed the validity of the "present marketability" standard. Furthermore, a Federal appellate court has held that "[A] mineral locator or applicant, to justify his possession, must show that by reason of accessibility, bona fides in development, proximity to market, existence of present 27/ Castle v. Womble , 19 L.D. 455, 457 (1894). Chrisman v. Miller, 197 U.S. 313, 25 S. Ct. 468, 49 L. Ed. 770 (1905). i -667- I demand, and other factors, the deposit is of such value that it can be used, removed and disposed of at a profit." 28 / "Present marketability" does not mean that the applicant must have a mine in operation. It simply requires that the applicant be able, with reasonable effort, to mine the deposit at a profit. Since Coleman, lower courts have rejected arguments that the future marketability of the mineral should be considered: Nor can we accept [the] argument that the "prudent man test" should be deemed satisfied if an increased market and the depletion of better quality reserves are reasonably to be anticipated. The "marketability test" requires claimed materials to possess value as of the time of their discovery. Locations based on speculation that there may at some future date be a market for the discovered material cannot be sustained. What is required is that there be, at the time of discovery, a market for the discovered material that is sufficiently profitable to attract the efforts of a person of ordinary prudence. 29 / 28 / Layman v. Ellis , 54 I.D. 294 at 296 (1933); Foster v. Seaton , 271 F.2d 836 at 838 (1959). 29 / Barrow v. Hickel , 447 F.2d 80, at 83 (1971); Multiple Use, Inc. v. Morton, 353 F. Supp. 184, at 195 (1972) . -668- The adoption of the marketability standard developed by this line of cases has weighty implications, since it renders invalid all claims based upon discoveries of mineral deposits containing ore which is not yet, but which may be in the future, valuable enough to develop. Thus, higher-cost uranium reserves and estimated poten¬ tial resources cannot validly be protected either by claim or patent. Even a uranium deposit which is the subject of an existing contract for future delivery at a relatively high price might not qualify for a claim if the deposit is not marketable at today's prices. As a practical matter, however, such claims have proved relatively secure, for the Interior Department long ago adopted a policy of challenging only claims located on land to be withdrawn from the public domain or which are clearly fraudulent, such as when someone builds a vacation home on a property held via mining claim. The present marketability standard is also used by the Interior Department in awarding patents. Should the Department determine when a patent application is -669- ( filed that the mineral deposit in question is not currently marketable, the applicant will not only have his application denied, but his mining claim will be invalidated as well. Thus, while the potential benefit from patenting a claim may be comparatively small in terms of practical control over the land, the potential risk should the patent be denied is total—the claim will be lost entirely. Because of this asymmetry, comparatively few mineral patent applications are 1 filed, 30 / and as table 10.2 shows, a far greater pro¬ portion of the uranium mined domestically comes from land held by claims than from those held by patent. One might suppose that since the Government receives only token compensation ($5 per acre) for the land it awards by patent, it should not care whether the land is held by claim or patent. However, two < further problems become increasingly significant, given that the majority of lands most likely to contain 30/ A staff survey of Bureau of Land Management offices in three of the most active uranium States revealed that in 1974, only one application for a patent to uranium land was filed in New Mexico and none were filed in Utah. Five filed in Wyoming were still pending. -670- I TABLE 10.2.—Domestic Uranium and Production by Land Type Percent of uranium production as of January 1974 Percent of total $8 uranium reserves in January 1974 Unpatented mining claims 37 24 Patented mining claims 17 14 Government leases (ERDA and Department of Interior) 2 2 Indian tribal land 19 16 Other (includes homestead, railroad, State, Indian allotment, national parks, military, land grants) 25 44 100 100 Source: Interview with Carl Appelin, Chief, District Resource Evaluation Branch, ERDA. -670A- TABLE 10.3.--Acreage Held for Uranium Mining and Exploration as of January 1975 Acres (thousands) Percentage of total Claims 11,634 54.7 Fee 5,596 26.3 State 2,968 13.9 Indian 634 3.0 Acquired 275 1.3 Railroad 168 .8 21,275 100.0 Source: Statistical Data of the Uranium Industry, GJO-100 (75), U.S. Energy Research and Development Administration, Grand Junction Office, January 1, 1975, p. 65. -670B- deposits of economically minable uranium are now under Government control. The first relates to the Government's ability to know who owns or has rights to what land. No Government agency keeps records with any appreciable degree of accuracy on who holds mining claims to which parcels of land. As previously noted, mining claims are recorded at local offices in the counties where the claims are located. There is no requirement that notice of any kind be given to any arm of the Federal Government regarding the filing of a claim, nor is there any program for the forwarding of claim informa¬ tion by local offices to the Interior Department or some other agency. The Department in turn makes no attempt to keep track of claims or claimants, except where patent applications are filed. Thus, Interior can only guess at what proportion of public lands is held under mining claims. Even if the Interior Department did attempt to inventory mining claims and claimants, it would likely be thwarted by the common prospectors' practices of 671- locating claims in the names of agents or straw men and claiming all locatable minerals, whether actually dis¬ covered or not. Agents are used to conceal from com¬ petitors the location of properties being explored for minerals until claims have been perfected, and in the process to assemble a large enough area to permit economical development and mining. In many cases, of course, those familiar with the mining district and its inhabitants learn to recognize these agents and can deduce the identity of the company for which the claims are being located. Nevertheless, this practice does make it more difficult to keep track of claims and those who hold them. In addition, claims are often assigned by one party to another. Such transfers may not be recorded for some time after they are effected, adding to the confusion. Thus, it is impossible under the present system to inventory the ownership of claims in any meaningful way. Similarly, most claims are located and recorded so as to encompass most or all conceivable minerals allowable under the Mining Law, rather than the mineral or minerals actually discovered. This may be done for -672- two reasons. Since it costs a claimant no more to claim all possible minerals in a parcel of land than to claim only one mineral, it makes sense to do so. Secondly, as noted earlier, prospectors normally attempt to keep their discoveries secret from their competitors so that they may assemble as much contiguous mineral land as possible. By claiming all minerals, a prospec¬ tor may be able to conceal the particular mineral he is searching for or has discovered. Thus, unless an application for patent is filed, the Government is unlikely to know either the identity of the claimant or the true basis for the claim. With respect to uranium lands, one Government agency does at least make a conscientious attempt to keep track of claims and claimants. The Energy Research and Development Administration and its predecessor, the Atomic Energy Commission, have for a number of years employed a contractor, Lucius Pitkin, Inc., which regularly abstracts mining claims in those areas of the United States where uranium prospecting and exploration are known to be taking place. (A notable exception is Texas, where no Federal lands are -673- available.) Pitkin says it is able to determine with relative accuracy whether a mining claim is actually for uranium and who the beneficial holder is. It does this by carefully examining the identity of the claim¬ ants and the areas involved. In addition, its employees often cultivate and maintain friendships among local persons who may be up on the latest gossip. Whether or not this method is accurate (which it may well be), it is clear that it is highly subjective. 31 / It hardly seems proper that the Federal Government should have to guess, however well calculated that guess may be, at how much of its own land is claimed for various minerals by private parties whose identities are unknown to it. Evaluation Of The Claim System’s Effects There are a number of significant problems associ¬ ated with the use of the claim system for uranium resources. These include its effects on the rate of development, its tendency to transfer mineral wealth 31 / Among other things, the number of claims abstracted by Pitkin is arbitrarily reduced by 25 percent to account for abandonments and overstaking. I -674- to the private sector without compensation to the public, its silence concerning the environmental impact of prospecting and mining, and potential anticompetitive consequences. Each will be examined more closely in the sections which follow. Impact on Rate of Development Mineral resource development can often proceed economically only when large parcels of land are assem¬ bled. The claim system frustrates this in two ways. First, the market in mineral rights is characterized by high transaction costs, since it is frequently difficult to verify who, if anyone, has a valid claim to certain tracts. Location notices are often vague and as a result there is extensive overstaking. Some prospectors file a location and never stake the land; others stake the land and fail to file a location. Moreover, companies and individuals rarely report the abandonment of a claim. Where there are conflicting claims, costly litigation is often required to deter¬ mine whose claim is valid. Second, even after rights of ownership have been established, individual claim -675- holders often have the power to hold out so as to extract all the gains to be had from consolidating claims. In similar fashion, the claim system may adversely affect the introduction of new extractive technologies. The trend toward large-scale, capital-intensive mining of low-grade deposits indicates that a firm would probably have to negotiate separately with many owners of inactive claims to amass an economically viable mineral deposit. The likelihood of successfully locating and bargaining with so many separate owners may preclude the adoption of technologies dependent upon large-scale operations. The same is true with respect to the introduction of new exploratory tech¬ niques. New developments include the use of airborne magnetic surveys to determine regions of mineralization. Should minerals be located in this fashion, prior claims may vitiate the discovery. To the extent that these techniques are best suited for extensive surveying, rather than intensive prospecting, they would be more readily adopted if the land were not tied up by -676- numerous small claims. 32/ These problems have probably not been of great historical significance, given the long period of slack demand the uranium industry has faced. However, they may assume greater importance as demand increases, especially if nuclear power grows at projected rates and the prospects for introduction of breeder reactors by 1985 remain dim. An example may help illustrate the kinds of problems continued operation of the claims system could pose for the uranium industry in the future. Consider table 10.4, which presents AEC estimates of the capital and operating costs (per pound of con¬ centrate recovered) associated with various planned rates of output for open-pit and underground uranium mining operations. These estimates suggest that there are significant scale economies in uranium production. The average unit cost declines at a decreasing rate 32 / It might be preferable for large-scale aerial exploration to be conducted by the Government, followed by a competitive auction of major dis¬ coveries . -677- TABLE 10.4.—Cost Estimates for Various Sizes Sizes and Types of Uranium Concentrate Production Facilities (Dollars per pound of U^ 0 g recovered) Scale of Operation 500 1,000 2,000 3,000 5,000 Open Pit a/ tons/day tons/day tons/day tons/day tons/day Costs: Capital Acquisition 0.158 0.158 0.158 0.158 0.1 r | 0.526 Exploratory drilling 0.526 0.526 0.526 0.526 Development drilling 0.263 0.263 0.263 0.263 0.263 Mine primary drilling 1.605 1.421 1.368 1.355 1.329 Mine plant and equipment 0.053 0.053 0.053 0.053 0.053 Mill construction 0.632 0.513 0.421 0.368 0.316 Total capital 3.237 2.934 2.789 2.723 2.645 Operating: Mining 0.632 0.632 0.632 0.632 0.6^ 0.1 ' Hauling 0.171 0.171 0.171 0.171 Milling 1.592 1.224 1.013 0.908 0.868 Royalty 0.355 0.355 0.355 0.355 0.355 Total operating 2.750 2.382 2.171 2.066 2.026 Total costs $5,987 $5,316 $4,960 $4,789 $4,671 -677A- TABLE 10.4.—Continued 500 1,000 2,000 3,000 5,000 Underground b/ tons/day tons/day tons/d ay tons/day tons/day Costs: Capital Acquisition 0.158 Exploratory drilling 0.526 Development drilling 0.263 Mine primary development 0.874 Mine plant and equipment 0.189 Mill construction 0.505 Total capital 2.515 Operating: Mining 2.947 Hauling 0.168 Milling 1.305 Royalty 0.368 Total operation 4.788 Total costs 7.303 0.158 0.158 0.158 0.158 0.526 0.526 0.526 0.526 0.263 0.263 0.263 0.263 0.684 0.547 0.579 0.495 0.147 0.105 0.116 0.095 0.411 0.295 0.337 0.253 2.189 1.894 1.979 1.790 2.526 2.211 2.316 2.126 0.168 0.168 0.168 0.168 1.011 0.758 0.842 0.727 0.368 0.368 0.368 0.368 4.073 3.505 3.694 3.389 6.262 5.399 5.673 5.179 a/ Estimates based on operations at 0.20 percent U^Og in ore and depth-to-thickness ratio of 24. b/ Estimates based on operations at 0.25 percent UgOg in ore and a depth-to-thickness ratio of 76. Source: J. Klemenic, Chief, Production and Cost Evaluation Branch, Ore Reserves and Production Division, Grand Junction Office, U.S. Atomic Energy Commission, "Examples of Overall Economics in a Future Cycle of Uranium Concentrate Production for Assumed Open Pit and Underground Mining Operations," October 20, 1972, tables I and II. -677B- with the size of the venture, regardless of the type of mining operation. The chief factors accounting for the fall in unit costs are the costs associated with mine development and (most importantly) the costs of con¬ structing and operating a mill. While the capacity of newly constructed mills will depend upon the magnitude and geographic distribution of the resources to be extracted 33/ as well as the expected rate and total volume of output, assume for purposes of illustration that ore availability conditions warrant the construc¬ tion of a 5,000-tons-per-day mill. If one firm owned the deposit, it would construct a mill of this size. But what if claims are distributed among a number of different firms? If the individual claim holders can easily identify one another, they may be able to negotiate a mutually acceptable agreement permitting construction of the efficient-sized mill. One company might be able to buy the others out and construct the mill itself, or the firms might agree to construct and operate the mill as a joint venture. Yet under the 33 / Uranium is about 65 percent heavier than lead, and raw uranium ore is rarely shipped to mills more than 15 to 20 miles away. claim system, the costs of identifying who the claim holders are and negotiating with them could easily be so high as to offset the advantages of building an efficient-sized mill. Even if ownership rights are clearly delineated, the claim system could still inhibit efficient development because individual claim holders may have the power to hold out in an attempt to extract all the gains from having an efficient-sized mill. Returns to the Government Under the claim system, the Government receives only token compensation for the mineral rights on public land. To the extent that these rights are valuable, the system in effect provides a subsidy to those who stake claims to mineral-bearing lands. In the case of uranium, the income transfers attributable to the claim system appear thus far to have been relatively modest. This can be seen by extrapolating from the experience with those Federal and Indian lands that were leased for uranium - 679 - mining. 34/ Between 1948 and 1972, some 243,700 tons of U 0 concentrate were obtained from all Federal and 3 8 Indian lands, both leased and located. Of this total, 33,325 tons were extracted from lands transferred to developers through leasing. 35/ The average royalty per ton of concentrate mined from the leased lands was $1,085. Had this amount been collected on all production from Federal and Indian lands, rather than only the leased lands, royalties would have totaled approximately $264 million. Thus, assuming that uranium-bearing lands mined under the claim system were similar in productiv¬ ity to leased lands, existing uranium land policies can be said to have transferred roughly $228 million from 34 / The leasing methods used on Indian lands, which differ somewhat from those used by the Federal Government, are described in a separate Federal Trade Commission staff report. Since there has been very little leasing of Federal lands, the Indian lands data provide the broadest available base for extrapolation. U.S. Atomic Energy Commission, Statistical Data of the Uranium Industry , GJO-100 (1973), p. 14. 35 / the public sector to private developers. 36 / The Government's failure to obtain compensation for uranium mining rights will presumably assume greater signifi¬ cance as the demand for uranium increases and the in¬ dustry's output grows. Environmental Impact Under the claim system, the Federal Government exercises little control over environmental disruption on public lands and imposes no restorative requirements. According to environmentalists, the legal requirement that $100 of effort be expended annually to maintain a claim results in purposeless scars on the land. They argue, too, that the scattered pattern of land holdings, the tendency for non-mining activities to be carried 36 / This assumes inter alia that the same amount of uranium would have been produced over the 1948-72 period with full leasing. Because the cost of uranium is a small part of the total costs of generating electricity using nuclear energy, the demand for uranium should be fairly inelastic. Paul MacAvoy, Economic Strategy For Developing Nuclear Breeder Reactors (MIT Press, 1969), p. 61. With inelastic demand, the cost-increasing effect of a leasing policy would have a relatively small influence on the quantity of uranium produced. - 681 - out under mining patents, and the negligible Federal monetary charges levied for private use of public lands all demonstrate the need for a rational land use plan¬ ning system. Environmental restoration requirements would undoubtedly increase uranium prices, but the total increase is apt to be small. Uranium production has historically been divided about equally between open- pit and deep underground mining operations. In open- pit uranium mining, the cost of stripping the overburden to expose the ore has recently ranged from about $0.50 to $1.50 per pound of concentrate. Assuming that re¬ placing the overburden, contouring, and planting will cost somewhat more, it is estimated that the open-pit mines can be completely reclaimed for less than $2 per pound of concentrate; 37/ i.e., about a third of the U_0 price prevailing during the early 1970's but less than 10 percent of more recent price levels. 37/ T. B. Cochran, The Liquid Metal Fast Breeder Reactor (Resources for the Future, 1974), pp. 94,95. - 682 - In underground mining the problems are different. The principal environmental cost is associated with radioactivity. Protection of mine personnel against overexposure is approached in two ways: (1) controlling radiation levels, principally by ventilation; and (2) controlling each miner's cumulative exposure by personnel monitoring and rotation of working locations. Cochran has estimated that $2 per pound of concentrate would adequately cover all anticipated environmental costs associated with undergroun ning, including control of mine wastes. 38/ Effec ts on Competition As Demsetz has observed, "the essence of monopoly power is the ability to prevent an expansion of capacity when price exceeds unit cost." 39 / In a natural resource industry, this power is measured by the con¬ trol that one firm, or a group of firms acting together. 38/ Op. cit. , pp. 95-99. 39 / Harold Demsetz, "Two Systems of Belief About Monopoly," reprinted in Industrial Concentration: The New Learning (Harvey J. Goldschmid et al., eds., 1974), p. 166. - 683 - has over the resources available for sale under existing economic conditions. The more extensive the control over potentially competing resources, the greater is the probability that prices will be set at monopoly levels. The claim system could provide a comparatively easy means of tying up potentially competitive resources at low cost. Checks against excessive filing for deposits not meeting the test of value exist only through challenges by the Department of the Interior. Such challenges (which involve inspection by a mining engineer, assay of the ore content, and possible litigation) are expensive. Usually they are initiated only when a competing use for the land materializes. The possibility that a few firms might preempt ownership of mineral rights on a widespread scale could be significant in the uranium industry, since concen¬ tration levels are higher than in any other fuel resource. There are currently about 100 companies "active" in uranium, but 25 of them (listed alpha¬ betically in table 10.5) control roughly 95 percent of the uranium reserves estimated to be available at or - 684 - TABLE 10.2.—Principal Uranium Mining and Milling Companies 1 . Anaconda Co. 14. Kerr-McGee Corp. 2. Atlantic Richfield Co. 15. Mobil Oil Corp. 3. Atlas Corp. 16. Pioneer Nuclear Corp. 4 . Cleveland-Cliffs Iron Co. 17. Ranchers Exploration and Development Co. 5. Continental Oil Co. 18. Reserve Oil and Minerals Corp 6. Cotter Corp. 19. Rio Algom Mines, Ltd. 7. Dawn Mining Co. 20. Sohio Petroleum Co. 8. Exxon Corp. 21. Union Carbide Corp. 9. Federal-American Partners 22. Union Pacific Mining Co. 10. Getty Oil Co. 23. United Nuclear Corp. 11. Gulf Oil Corp. 24. Utah International, Inc. 12. Homestake Mining Co. 25. Western Nuclear Corp. 13. INEXCO Source: U.S. Atomic Energy Commission -684A- 1 below a cost of $8 per pound of concentrate. Of these companies, eight control over 75 percent of the reserves, although no single firm owns more than 20 percent. While it is difficult to conceive of a few companies tying up all the Nation's uranium resources, given the vast areas of land with uranium bearing potential that exist, the ease with which such a strategy could be pursued with¬ out the Government's even being aware of the attempt is perhaps cause for concern. Summary The transfer of uranium resource rights on public lands is accomplished primarily through the claim system codified by the General Mining Law of 1872. There appear to be several problems associated with the system. First, the system is a legal and administrative night¬ mare, with many small overlapping claims and no central record of who has claimed what. The Government liter¬ ally has no idea who holds mining rights on its own land. Second, the claims system may have a detrimental impact on economic efficiency. The high transaction costs characterizing the market in mineral rights - 685 - frustrate efficient resource development and the introduction of new mining technology. Third, the claim system transfers mineral wealth to the private sector with virtually no compensation to the public. Fourth, the system provides no control over the environ¬ mental impact of prospecting and mining. It does, on the other hand, provide a comparatively easy means of tying up potentially competitive resources at low cost. - 686 - CHAPTER 11 GEOTHERMAL ENERGY Introduction In addition to fossil fuels and nuclear energy, Federal leasing policies affect another potentially significant energy source—geothermal energy, or heat from the earth. At present, only one commercial generating project in the United States uses geothermal energy. Located at The Geysers, California, it provided approximately one tenth of one percent of the Nation's total electricity in 1974. Nevertheless, geothermal energy could play a more signifi¬ cant role in the future, depending upon developments in drilling and utilization technology and, as with any new energy source, future cost trends for established fuels. Approximately 56 percent of the Nation's known geothermal sources are estimated to be on Government land, primarily in eleven Western States. A Federal leasing program has been established to develop these lands, although little actual leasing has occurred. This chapter will provide information about the technology and economics of geothermal energy as well as a summary and evaluation of the Federal leasing program. -687 Nature and Extent of the Resource "Geothermal" literally means "earth heat." The interior mantle of the earth contains tremendous heat, the apparent result of nuclear decay under pressure. This heat slowly radiates up through the earth's outer crus! and might poten¬ tially provide an immense source of energy. Unfortunately, given present technology, most of this heat energy is too diffused to be collected efficiently. Certain areas of the crust are unusually hot owing to rifts, breaks, and other weaknesses and anomalies which allow the heat to rise more readily toward the surface. The heat becomes trapped and concentrated in specific geologic layers or structures, re¬ sulting in a "geothermal reservoir" analogous to a petroleum reservoir. If the rock in the reservoir is somewhat porous and permeated with superheated water and steam, a natural medium may exist through which the heat may be brought to the surface and utilized. It is easier and less expensive to utilize a reservoir whose temperature is high enough to discharge only steam, but such "dry steam" areas are rare. More common are "hot water" areas, where only part of the extracted water flashes into steam upon reaching the surface. In addition, "hot dry rock" areas exist where sub-surface temperatures are high, but there is no water or steam to convey the heat to the surface. It may be possible to produce steam from such areas by artificially injecting water. 688- Finally, there are "geopressured reservoirs" located along the Texas and gulf coasts. These layers of clay and sand are permeated by water under high temperature and extreme pres¬ sure. Their utility as an energy source is complicated by the high pressures involved and by methane gas mixed with the water. The potential importance of geothermal energy depends both on the extent of geothermal resources and the develop¬ ment of technologies for harnessing it. Several utilization processes are now in various stages of research and develop¬ ment. They include dry steam generation, hot water systems, and hot dry rock generation. Dry Steam Generation Dry steam is the only type of geothermal resource now used for generating electricity in the United States. "The Geysers" complex, located about 85 miles north of San Francisco, currently generates about 502 megawatts of electricity. It is estimated to have an ultimate capacity of about 2,000 megawatts. One other largely dry steam field has recently been discovered in the Raft River area of Idaho. Its capacity is still undetermined. In a dry steam system, steam from the ground is piped directly into turbines to generate electricity. The steam is subsequently condensed and reinjected into the -689- ground. Problems include high noise levels from the wells, air pollution from hydrogen sulfide and other gases, and pollution of drinking water supplies due to mineral laden condensate. These problems are solvable however, and are not currently a serious impediment to the production of power at The Geysers. The major barrier to generating electricity from dry steam is its limited availability. Although the exploitation technology is known, it appears doubtful that many fields will be found. Thus, the future of geothermal energy depends largely upon developing sources other than dry steam. Hot Water Technologies Dry steam fields appear to be much rarer in nature than hot water fields, and it is clear that the role of geothermal energy will depend largely upon the development of the latter. Although hot water fields are used on a small scale for home heating in Idaho and Oregon, no electric power is currently generated from them in the United States. However, a number of countries, including New Zealand, Mexico, and the Soviet Union, are now using hot water sources in this way. Most of these foreign projects have involved direct or indirect government subsidies. ) -690- Numerous problems must be overcome before significant amounts of electricity can be generated from hot water fields. The first step is to locate fields where hot water of sufficiently high temperature and pressure is available at accessible depths. Although geothermal hot water is known or suspected to exist in many areas, the temperature and pressure characteristics cannot be determined without actually drilling experimental wells. Estimates of geothermal potential made without actual drilling are subject to a wide margin of error. 1/ 1. Flashed Steam Process v There are two principal processes for generating electric power from hot water fields. The first is the "flashed steam" process. As the geothermal water moves up the well, a portion of it boils owing to the decreasing pressure. In high-temperature hot water fields, about 20 percent of the water flashes into steam upon reaching the surface. Flashed steam drives the turbines of geothermal power 1/ By way of illustration, prior to the actual drilling at the East Mesa geothermal field in the Imperial Valley of California, it was estimated that temperatures of 600°F would be found at 6,000 ft. with a flowing pressure of 242 lbs. per square inch. In fact, actual drilling revealed temperatures of only 370° to 400°F and pressures of 56 to 96 lbs. per square inch. This not only meant that the field's energy potential would be considerably less than estimated, but also that the established flashed steam system would be impractical, and instead, the experimental binary cycle system (which has never been used outside the Soviet Union) would be the only feasible process. -691- plants now operating in New Zealand, Mexico, and Japan. The geothermal fluids in the Imperial Valley were originally thought suitable for utilization in this manner. However, disappointingly low temperatures and high mineral concentra¬ tions have cast doubt on its feasibility there. 2. Heat Exchange Process (Binary Cycle) Another process is known as the "binary cycle" or "heat exchange" system. Here the hot water is used to heat a second fluid, such as isobutane or freon, with a lower boiling point. The "steam" from this second fluid then drives the turbine. This process is potentially more efficient than the flashed steam process, which wastes the energy in the 80 percent of the hot water not boiling. A number of private firms are researching the heat exchange technique, while the Energy Research and Development Agency currently plans to construct a 10 megawatt prototype plant in the Imperial Valley by 1978. The high concentration of minerals in the Imperial Valley water may cause scaling and clogging of equipment, but these difficulties can probably be solved. The Soviet Union has operated a binary cycle plant since 1967. It now has a capacity of 29 megawatts. -692- 3. Total Flow Process Other processes currently in the experimental stage include the "total flow" system featuring a combined steam turbine and waterwheel utilizing the heat and natural pressure of both steam and water in one generating process. This system is potentially more efficient than the binary cycle method, but its practicability has not yet been demon¬ strated. Serious problems include scaling and corrosion of the nozzle and turbines from the hot, mineral-laden geo¬ thermal liquid. Hot Dry Rock Technology Geothermal energy might also be extracted from hot dry rock. The basic process involves drilling wells to depths where high temperatures exist and then injecting cold water into the rock formation. The cold water under pressure would cause the rock to crack, and the water could then circulate through the rock formation, absorbing heat. When brought back to the surface, the hot water could be utilized by the same means as natural geothermal hot water. Hot dry rock formations are much more extensive than geothermal steam or hot water areas. If the hot dry rock process could be developed commercially, it would greatly increase the contribution of geothermal energy. At present. -693- however, the hot dry rock process is in the early experimental stages. Problems to be investigated include whether the hot dry rock will actually fracture enough to permit adequate water circulation and whether the fracturing of deep rock formations and injection of huge amounts of water could induce earth¬ quakes. Since hot dry rock formations often underlie arid and remote areas, it might also be difficult to obtain the needed water. The Geothermal Leasing Program The foundation of the geothermal leasing program is the Geothermal Steam Act of 1970, which authorizes the Secretary of the Interior to dispose of Federal lands to develop goethermal steam and associated resources found within public, withdrawn, and acquired lands, as well as in lands that have been conveyed away subject to a reservation of mineral rights. 2/ Although there is some dispute on this point, the Federal Government apparently lacked authority to lease geothermal resources to private parties prior to the 1970 Act. The Act provides two primary ways to obtain leases: noncompetitive application and competitive bid sales. A noncompetitive lease is free except for certain procedural 2/ The Geothermal Steam Act of 1970, 30 U.S.C. 1000-1025, Public Law 91-581 (hereinafter referred to as Geothermal Steam Act). -694- expenses (e.g., filing fees), while a bonus bid is required to obtain a lease in a competitive sale. Whether competitive bidding occurs depends upon whether land is located within a "known geothermal resources area" (KGRA). This two-level leasing scheme is patterned after the onshore oil and gas program, where the type of lease depends upon whether the land falls within a "known geological structure of a producing oil or gas field." However, the KGRA definition is much broader than the oil field definition, making it easier to classify geothermal lands into the competitive bidding category. A third way to obtain a geothermal lease is to convert an interest previously obtained under certain other statutes such as the Mineral Lands Leasing Act of February 25, 1920. This "grandfather" right was quite controversial during the 1970 Act's legislative evolution and was a major reason for President Johnson's veto of an earlier 1966 bill. The Interior Department has assigned responsibility for geothermal leasing to two agencies, the Bureau of Land Management and U.S. Geological Survey. BLM has the authority to issue and enforce the leases, while USGS manages the actual lease operations and unit plans. This division of responsi¬ bility is similar to the arrangement in other leasing programs. -695- Leasing Terms The 1970 Act provides for a primary lease term of ten years, but the lessee may obtain an extension of up to 40 years by achieving production of steam in commercial quanti¬ ties. After this term expires, the lessee has a preferential right to renewal for a second 40 year term if the land is not "needed for other purposes." 3/ The Act also authorizes the Secretary to "readjust the terms and conditions ... at not less than ten year intervals beginning ten years after the date the geothermal steam is produced. . ." 4/ An exception is made for the level of rentals and royalty rates, which may not be readjusted at less than 20- year intervals beginning 35 years after the date geothermal steam is produced. 5/ Another five-year extension of the original ten-year primary term is available if the lessee is diligently engaged in drilling operations when the tenth year ends. 6_/ 3/ Geothermal Steam Act, Sec. 6(b), 30 U.S.C. 1005(b). 4/ Ibid ., Sec. 8(a), 30 U.S.C. 1007(a). 5/ Ibid ., Sec. 8(b), 30 U.S.C. 1007(b). 6/ If the lessee achieves production during the life of his extension, the term may then be extended for a maximum of 35 more years. -696- This approach emulates the onshore oil and gas leasing program. 7/ A lease may also be extended a maximum of five years if it can no longer produce geothermal steam but is still capable of by-product production in commercial quanti¬ ties. 8/ The maximum lease size is 2,560 acres. No firm or individual may hold more than 20,480 acres of geothermal leases in any one State, except that acreage is exempt if included in a cooperative or unitized development plan. This limitation is the same for every State and applies equally to all Federal lease acreage, however obtained. It may be increased to as much as 51,200 acres by the Secretary in 1985. 7/ See 30 U.S.C. 226(e). 8/ Geothermal Steam Act, Sec. 6(e), 30 U.S.C. 1005(e). Where a by-product is a mineral leasable under the Mineral Lands Leasing Act of February 25, 1920 (30 U.S.C. 181 et seq .) or the Mineral Leasing Act for Acquired Lands (30 U.S.C. 351- 358), the lessee may convert his geothermal lease into a mineral lease, or locate under the mining laws if it is a locatable mineral. -697- Royalty and Rental Payments Section 5(a) states that royalties must be "not less than 10 percentum or more than 15 percentum of the amount or value of steam, or any other form of heat or energy. . . ."9/ This tight range on royalty rates does not appear in previous leasing acts. Precursors such as the Mineral Lands Leasing Act of 1920 or the Outer Continental Shelf Lands Act have specified minimum rates but no maxima. Combined with the narrow range of royalties chargeable on the first lease is the right of the Secretary to readjust them later. Rentals and royalties can be readjusted at "not less than 20-year intervals beginning 35 years after the date geothermal steam is produced. ... In the event of such readjustment, neither the rental nor royalty may be increased by more than 50 percentum over the rental or royalty paid during the preceding period, and in no event shall the */ royalty payable exceed 22-1/2 percentum." 10 / 9/ Geothermal Steam Act, Sec. 5(a), 30 U.S.C. 1004(a). 10/ Ibid. , Sec. 8(b), 30 U.S.C. 1007(b). -698- Like the maximum 90-year term, these readjustment rights provide some hedge against the risk of large unanticipated future resource value increases. BLM has thus far charged royalties of 10 percent on all its competitive leases except for The Geysers, where 12.5 percent was asked. With the 50 percent maximum increase limitation, it would take two adjustments, or 55 years after production was achieved, to reach the maximum rate of 22.5 percent. An unusual feature of the Act is a provision that the royalty charged must be based on the "amount or value of steam, or any other form of heat or energy derived from production . . . and sold or utilized by the lessee" or "on the amount of steam that is reasonably susceptible to sale or utilization by the lessee." 11 / In other words, the lessee may be liable for royalties on steam not actually sold. This is in effect an implicit diligence provision. 11/ Ibid. , Sec. 5(a), 30 U.S.C. 1004(a). -699- The Act further provides for an especially low maximum royalty of five percent for by-products. Section 5(c) of the 1970 Act establishes an annual rental payment of not less than $1.00 per acre. It must be paid in advance. The Act sets no maximum rental payment. However, in the eight competitive lease sales held up to March 1, 1975, the BLM announced annual rentals of $2.00 per acre. Once a lessee has achieved production in commercial quantities he may pay a "minimum royalty of $2 per acre or fraction thereof in lieu of rental. ..." 12 / In other words, rental payments are effective only during the first ten to fifteen years at the longest. After that, production will either have been achieved or the lease will be terminated. Also, when the lessee expends more on explora¬ tion than is required by the diligence requirements, the excess expenditures may be credited against rental payments. 12 / Ibid., Sec. 5(d), 30 U.S.C. 1004(d). -700- Diligent Exploration Section 24 of the Act states that the Secretary shall prescribe rules and regulations to ensure "the maintenance by the lessee of an active development program." 13 / To fulfill this mandate BLM has provided by regulation a schedule of escalating rental payments as well as an escalating schedule of required expenditures for diligent opera¬ tions, both commencing with the sixth year. 14 / Table 11.1 shows the rents for a 2,000-acre lease. The rent begins at the statutory minimum of $1.00 per acre and then escalates by $1.00 per acre per year in years six through ten. It is apparent that the BLM 1 s escalating schedule does TABLE 11.1.—Schedule of Base and Escalated Rents Year Base rent Escalated rent Total rent 1-5 $10,000 -0- $10,000 6th 2,000 $2,000 4,000 7th 2,000 4,000 6,000 8 th 2,000 6,000 8,000 9th 2,000 8,000 10,000 10th 2,000 10,000 12,000 Cumulative total $20,000 $30,000 $50,000 13/ Ibid. , Sec. 24, 30 U.S.C. 1023. 14 / 43 C.F.R. 3205.3-3, "Escalating Rental Rates," and 3203.5, "Diligent Exploration." - 701 - not result in large total rents. Moreover, decisions by a lessee to hold the lease another year or abandon it and to conduct exploration now or later are usually made on a yearly basis, and the yearly marginal costs are quite sma11. The impact of the escalating rental schedule cannot be evaluated fully without looking also at the required "expenditures for diligent operations." Rules specified by the Interior Department in 43 C.F.R. 3203.5 state that after the fifth year, the minimum annual expenditure for diligent operations shall equal two times the sum of (a) the minimum annual rental required by statute ($1.00 per acre) plus (b) the amount of rent exceeding the fifth year's rent (the portion resulting from escalation), with an absolute maximum of two times the tenth year's rent. - 702 - TABLE 11.2.—Lease Rental and Minimum Expenditure Amounts < Year Rental totals (Base and escalated combined) Required diligence expenditures Total rent and expenditures 1-5 10,000 -0- 10,000 6th 4,000 8,000 12,000 7 th 6,000 12,000 18,000 8th 8,000 16,000 24,000 9th 10,000 20,000 30,000 10th 12,000 24,000 36,000 Cumulative total 50,000 80,000 130,000 Table 11.2 shows the required minimum expenditures for diligent operations for a 2,000-acre lease together with the rental payments. The sums are obviously larger than those in table 11.1 but still are not very great. For the lessee choosing whether to conduct further exploration or abandon the lease, delay will often be worthwhile. During the coming year, his information may improve because of a nearby discovery by himself or someone else. The escalation schedules make delay more expensive and force an earlier decision. However, if the land has even moderate - 703 - potential value, the lessee is likely to undertake the required expenditures whether they yield useful information (as the diligence expenditures should) or not. Noncompetitive Leases Section 4 of the 1970 Act states that when land is not located within a KGRA, the lease must be issued to the "qualified person first making application." 15 / From January 1, 1974, through June 30, 1975, 4,764 noncompetitive applications covering approximately ten million acres were filed. Of them, almost 35 percent will not become leases owing to rejections, applicant withdrawals, application overlaps of 50 percent or more, or because the land has been redesignated to new or expanded KGRA status. About 220 noncompetitive applications encompassing 413,000 acres have thus far resulted in leases, while approximately 2,600 applications are still active and await action. 16 / Table 11.3 summarizes the noncompetitive bid applications and leases by State from January 1, 1974 to June 30, 1975. 15 / Geothermal Steam Act, Sec. 4, 30 U.S.C. 1003. 16 / U.S. Department of the Interior, Bureau of Land Management, BLM Fact Sheet, July 30, 1975. - 704 - TABLE 11.3.--Number of Applications and Noncompetitive Leases by State, January 1, 1974 - June 30, 1975 State Applications filed Leases issued Acreage Alaska 0 0 0 Arizona 24 4 6,508 California 868 0 0 Colorado 140 0 0 Idaho 568 25 44,211 Montana 88 0 0 Nevada 1,071 103 194,163 New Mexico 504 47 104,210 Oregon 822 2 1,268 Utah 381 40 62,335 Washington 267 0 0 Wyoming 19 0 0 Eastern States 12 0 0 Total 4,764 221 412,695 (approximately 10.1 million acres) Source: U.S. Department of the Interior, Bureau of Land Management BLM Fact Sheet, July 30, 1975. -704A- Lease by Competitive Bid The Geothermal Leasing Act does not specify the type of bid to be used for competitive leases. However, strict royalty rate limitations eliminate the possibility of royalty bidding and hence point toward cash bonus bidding with fixed royalties, which the Department of Interior has in fact adopted. Each bidder is required to submit a separate sealed bid for each unit in which he is interested. The BLM must accept the high bid within 30 days or all bids for that unit are considered rejected. Likewise, the high bidder has 30 days to accept the lease once notified. Preparation for a sale involves selection of the area, environmental analysis reports, calculation of the minimum acceptable bid, formulation of protective stipulations, and determination of royalties and rents. Logically, areas with the greatest prospective value should be selected. However, it is difficult to determine geologic potential for such a new resource even under favorable conditions. And without access to the proprietary data of companies holding nearby private leases, the USGS may have little solid knowledge on which to base tract selection decisions. - 705 - The regulations provide for "nomination" of areas by industry, but there have been few of these. Most companies appear fearful of alerting their competitors or encouraging the USGS to revise its minimum bid estimates upward. As in other leasing programs, the USGS is responsible for recommending the minimum acceptable bid. BLM has authority to accept or reject the USGS evaluations, but in practice it has apparently accepted them consistently. The USGS employs a "risk simulation" formula in which a range of values is given to different factors affecting prospective value. Still, it is recognized that such calculations cannot be very reliable, and USGS often determines values on the basis of "intuition." 17 / The BLM does not reveal its minimum acceptable bid value in notices of sales. As of June 30, 1975, there had been 19 lease sales in which 189 different tracts spanning 19 KGRAs were offered for competitive bidding. Of the 222 tracts offered or reoffered, 49.1 percent received no bids and an additional 21.2 percent received only one bid. The winning 17 / An official of the Geological Survey emphasized in an interview the lack of solid data and suggested that bidding on a geothermal lease was like "buying a pig in a poke." - 706 - bids ranged from $3.27 to $3,283 per acre, with an average for all 69 winning bids of $74 per acre. There were only two lease sales in which the high bid exceeded $400 per acre, and these both took place in The Geysers, where existing geothermal power plants are located. 18 / There are several possible explanations for this low level of interest. In The Geysers, where commercial feasi¬ bility had been demonstrated, there were two or more bids for each tract. The low level of interest elsewhere may reflect doubt as to commercial feasibility. For example, there appears to have been stronger bidder interest in hot water sites when the chances of finding hot water were good, as at Vale, Oregon. In any event, most of the tracts offered outside The Geysers were apparently considered by industry to have low or uncertain value. 18 / The two highest bids per acre were the $3,283 mentioned above and $1,368. Source: U.S. Department of the Interior, Bureau of Land Management, BLM Fact Sheet, July 30, 1975. - 707 - Table 11.4 compares USGS "minimum acceptable bid" recommendations with the actual bids received for The Geysers, Mono-Long Valley, and East Mesa. "Minimal" values were assigned by USGS to all the tracts in Mono-Long Valley and East Mesa. The largest bid, both in absolute terms ($3.2 million) and per acre, was made by Shell Oil Company on a Geysers tract to which USGS assigned a "minimal" evaluation. The two units in Mono-Long Valley and East Mesa for which Republic Geothermal paid $515,767 and $432,810 were also evaluated as "minimal," with "D" data reliability ratings. - 708 - e -h rH 1-1 •H CQ i—i rtf rtf in c fd £ 03 £ in 03 ■H CD E o in •H •H rH Td £ rH •H r- in G CM £ CM •H P3 C CO •H •H CP 03 (d •H 2 s a -p s m 3 e o CQ Td c fd w c o •H -P fd 3 r—I fd > w 03 O 03 D in O C O 03 •H M (0 a e o u i i • W PI CQ < Eh Td 03 a D 03 Q3 Pi O < O -P a td Pi Eh CD i—I fo in > CM in (N CM CM CO 03 rH 00 cH r- in h* LD in o oo oo o oo in cm o O r- o CO in o O CO o in o o O 03 r- H' rH O CM 03 rH CO in o O 00 a> a) o in in CM CO in o O in o 00 rH in in o rH 00 in rH in CM 00 i—1 o o in CO 'ir CO r- H 1 o 03 o CM in CO o "=r r- r- CO CO r-~ 00 co CM CM co rH rH Csl td CD O) Pi o in ■M* o in CO o CO rH CO 00 in CM rH h- 00 00 CM O o CM CM 00 o i o rH in in co CM o in in 03 co rH CM rH CM 00 rH rH rH 00 CD 03 CM in r* CM CO rH rH CO rH U Td CP •H CO rH rH rH CQ 03- 03- 03- o> o> 03- 03- o CO CM CO in in O'- CM in CM 03 in m 03 co CM in CM 00 CM CO in in 03 Pi CD 03 CD U -708A- d 0) P C ■H -P G O U I c/3 d •H PQ c/3 P £ O CQ d G rd 0) G O *H -p (0 I o CM co o I—1 03 o CD CD CD CD 00 CO cd r- CD 00 as m 00 as e- 00 rd O CD o 00 rH CD in CD oo r- CO CD CD o in o > 03 W U in r- CO CM CO 00 r» cm rr CD 00 00 as 00 m as uo CD CM CO CM r- CD CM in rH rH as CM 03 03 r—1 rH CM r—1 d rd •H 03 CQ to- to- to- to- to- to- d •H E d 03 > rd E -H G s CM CO O CM co cm r- 00 r- co CD o o CM CM i—I ( ■ LO CM O O O CO CM i—I ^ LD CM ID O O CO CO 00 CD CD O LD i—I r~ LD CM rd E •H G •H s o in rd E •H G •H S cm n in in rH o in CM o CD CM CM CM in in m e'¬ en i—i 00 in as oo oo as CM CM co Cn G 0 tP I 0 c o 5C 03 rd > -708B- 1773 $ 515,767 291 Minimal 281,504 159 92,196 52 52,504 30 27,069 15 TABLE 11.4.—Comparison of USGA Pre-Sale Evaluations and Bonus Bids T3 CD p c •H 4 -> C o u I • 1 G CD 0 TJ G •H •H CA e pq CD •H p CO > e o CD •H •H rH XI Q C XI 4-> •H (X3 rH i—1 rH rH rH G E +J fd 03 fd rd CO 0 a GEE E E 4-> •H CO CD ■H -H -H •rH •H a 44 0 o c c c G £ 0 rd co o •H -H -H •H •H r) > D rd 2 2 2 2 2 rd G CD >i CO rH G i—1 0 CD rd U u G o CD V ft G !>i \ CD CD co¬ CNCMO rH CM CP > r~ CO G i—i rH 2 P 0 CQ rH rd • 0 CO •rH rf rs CP 0) •H 0 > XI rH •H mn o in O 0 0 o n h CM CD CD CD o CN CM CO oc G CO CM Ch 0 rf CD •H •H O u CQ O CD rd 44 G E H 3 E CD CO •H JP u g (13 rH a X CO O 5 u * o O X O ^ H v 4-> aco (13 © 0 rH § (13 X 0 Eh P 0 X a X 0 X c a) to tt-H s a Eh LD 00 ro co¬ in i -p P CO a - 0) (0 X -P (0 C 6 1 04 o fd •H rH >i i—i X CD X C a 0 > •rl 0 p CD CD o •H X Or T3 r—1 (d CN rH i—| c 04 0 04 CD fd rH CD fd T3 p X o CD X fd e •H X CO CD G fd CD TJ CD p x rH Eh O C •H • 0 e to w HS O 0 o -p X (13 3 P CD 0 O X C CD 0 a x -p 04 00 o (13 04 fd o •H 04 (d o X fd x CD O c CD X CO o o >iO p ' T3 co o (d rH 'rl X to CD CD o G CD TJ X CT> CD C H X mh C (d Mh •H a •H •H TJ TJ G 0 CD U 0 E (d rH rH C C -H a 0 0 • rH rH CD rH 08 CN X X o CD CD CD (d o rH ro 0 O O p-nj£ 0 G 04 CD CD 0 0 0 X CO 0 •ro •ro P X P 33 0 0 0 04 >iX P P X (D X o a a P . p X P c o X CO CD >H CD to tri-H G CO X p • • X 0 -rl CO X CD 0 Id TJ CD Eh o x 0 co- E x 3 AC O TJ 0 P X c 0 P o (d p 0 i—1 33 co •rl CO P CD > C o o G 0 T3 CD CO (d OQ CN G 0 P > CD x u p CD r 0 •rl CD p a CQ >1 XI CD T3 (d E co CD -P fd E •H -p CO CD G 0 TJ CD CO (d CQ ro O O P >H P T> -P O x p o X T3 a rH a X T3 0 CO •H 0 G Eh X CD 0 p P H X X • o CD CD CD fd X >1 TJ N a x X c CD •H o • CO CO fd X CO CO CD X 4 0 X X 0 P X a p u CD CO X o a a fd X CD > rH X u •k X ‘ JX •H Eh >1 fd CD ^ X 0 o T3 Ph X X X X CD CO CO (d CD > (d x CD S CD rH x • cd CD rH C •rl -H P > X fd p CD O P X CD CD X T! X P P MH (D 3 r—I •H +J x cd G X D X 717A- Cost Competitiveness of Electricity Produced from Geothermal Energy Except for localized heating applications, the primary use for geothermal energy is generating electricity. Because of rapid heat losses during transportation, geothermal fluids must be utilized within about a mile of their extraction point. Since most areas with geothermal potential are located far from industrial centers, geothermal generating plants will probably be sited at some distance from the major population centers which comprise the primary market for electricity. Industry spokesmen have estimated that in order to justify the expense of erecting transmission lines, a geothermal reservoir must have the capacity to support a geothermal complex of at least 200 megawatts. When the resource is near a populated area or an established trans¬ mission grid, the minimum feasible size would be less. 30 / Nevertheless, this size requirement makes exploring for geothermal resources much riskier. A second obstacle is the long time lag likely to occur between investment in the development of geothermal energy and the realization of a return. The enterpreneur who 30 / Republic Geothermal and Southern California Edison are working on plans for 50 megawatt projects in the Imperial Valley. - 718 - discovers a reservoir of commercial size cannot sell his output immediately. Even though a buyer has been obtained, there will be no sales of steam until generating facilities and transmission lines have been built. This may require another five years, or it may never occur, since the utility must obtain approval from a State regulatory commission for the project. These time lags require that the ultimate posi¬ tive cash flow from geothermal steam sales be larger in order to justify the greater developmental investment than it would have to be if more immediate commercial exploitation were feasible. At The Geysers geothermal electric generating facility, the geothermal steam suppliers were paid 3.22 mills per kilowatt hour of electricity generated in 1974. At this price, electricity could be produced at a cost equivalent to that of an oil-fired plant if the price of oil were four to five dollars per barrel. While electricity from dry steam reservoirs is thus cost-competitive with fossil fuel plants or nuclear energy at present price levels, the competitiveness of electricity generated from hot water geothermal resources is more difficult to judge. Chevron Oil Company estimated in 1974 that it could earn a 13.7 percent rate of return on its investment in finding and developing a hot water geothermal resource if it received - 719 - a price of 4.8 mills per kilowatt hour of electricity gener¬ ated. 31 / In 1973, a Westinghouse Electric Corporation study found that a utility could pay a steam supplier 6.3 mills per kilowatt hour of electricity generated from a hot water geothermal resource and be competitive with nuclear reactor generation costs. 32 / The Project Independence staff concluded that electricity generated from hot water geothermal resources may be competitive with oil-fired generators at a petroleum price level of $4 per barrel. Although these estimates are necessarily rough, many authorities appear to agree that hot water geothermal re¬ sources can be cost-competitive with alternative fuels for electricity generation and that the rates of return attain¬ able are sufficient to encourage geothermal development. Donald White of the U.S. Geological Survey has estimated that geothermal energy could account for as much as 10 percent of the Nation's electric power supply by the year 2000. At the other extreme, the National Petroleum Council has predicted a contribution of only one-half percent. Table 11.7 summarizes various analysts' estimates of how much electrical power might be produced from geothermal resources in diverse years. 31 / Greider, op. cit. , p. 53. 32 / Ibid. -720- TABLE 11.7.--Geothermal Energy Estimates from Various Sources, Selected Years Percent of Total projected electricity supply in • rH r~ • CM I 1 1 14.1 o o o o o o 1 1 o o 2 o o 1 | o o E V CM o LO in r- OO CO rH T) -P 4-> (0 (D -H C4J4J U >i O 0 U -H rH O Eh CT\ CO CM rH rH CO rH o o o o o 00 £ o o in o —• rH g — a) P PI p CD •O' CO -p rH CD ’— 1 in CD 0 CO ■- G M-l CM P cd > *H 0 — P U IH CM s CD r- -P P C4 P CD O' m 4-1 c o rH CO rH 0 o 0 CD -H rH *H cd p E P cd o u o 1 cd r—1 G CD G cn (0 p CO cd CD C o •H a s s 4-1 a) o c P 4-1 • (0 o CO CD a) P -p o P c p PQ o p o o C p CO o CD Ql Du rH p cd in E TJ rH P CD cd ro >iP cd rH -p -Q CD 0 -P cd u) cd tr> CD E -P ■H E cd X o E 0 p •H p 1 P p 04 co Di CD W (flXI - 721 - (footnotes cont'd on next page) (footnotes from previous page) (2) Assessment of Geothermal Energy Resources, Department of the Interior, 1972. (3) & (4) U.S. Energy Outlook , National Petroleum Council, 1972. Case I estimates were calculated under highly favorable economic and political factors while Case IV calculations were made according to least favorable factors. (5) Geothermal Energy, A Special Report, Walter J. Hickel, 1972. Source : Final Environmental Statement for the Geothermal Leasing Program, U.S. Department of Interior, Vol. 1, 1973, p. 11-18. Summary and Conclusions In summary, the future of geothermal power depends largely upon processes which have not yet been developed on a commercial scale or those which are in the early experi¬ mental stages. If these processes can be developed to be cost-competitive with other fuels, geothermal energy could account for a significant percentage of total electrical generating capacity. If not, geothermal energy will continue to play a miniscule role. A geothermal industry is slowly forming. It is composed mostly of large oil companies. This is not surprising, since geothermal energy extraction is similar to oil and gas production in technology and the risks of exploration. There are some small independent geothermal companies, but they have not yet become major investors. Because electricity generated from geothermal energy must compete with electricity generated using fossil fuels or nuclear fission, concentration of geothermal power production alone is relatively meaningless as a structural index of competition. Nevertheless, it is desirable to encourage the development of a competitive geothermal energy industry structure to the maximum feasible extent. Interfuel com¬ petition will be promoted if the geothermal energy industry is - 723 - not dominated by the same firms controlling the production of fossil and nuclear fuels. The fact that the leading geothermal developers are also leading west coast petroleum suppliers suggests that interfuel competition may not be greatly en¬ hanced. Competition within the geothermal industry would also help insure that the Federal Government receives fair value for the lands it holds. Although geothermal energy is unlikely to fill much of the Nation's energy needs in the foreseeable future, it could make a substantial contribution in the Western States. The Federal Government controls roughly 56 percent of estimated geothermal resources, and the way it makes them available will affect future geothermal development. Overall, the program appears workable. Yet, if geothermal energy is to reach its full potential quickly, the leasing program must be shaken loose from the delays which have characterized its start. Specific recommendations for improvement are included in chapter 12. - 724 - Chapter 12 CONCLUSIONS From the analyses in this volume follows the inescapable conclusion that substantial improvements can be made in Federal Government policies for transferring energy lands to the private sector for development. The present-day land disposal machinery, some dating back to the 19th century, has evolved in ad hoc response to contemporaneous demands, often without adequate assessment of basic policy goals and the trade-offs that must be faced. The Federal Trade Commission staff cannot decide what national energy policy goals should be; nor can we determine the directions in which particular trade-offs should be pushed. What we can do is identify the crucial policy considerations and trade-offs and assess the dimensions of feasible alternatives, so that those who make policy may do so with the fullest possible knowledge. To provide this perspective for policy¬ making is the objective of this concluding chapter. We begin by articulating our underlying assumptions concerning the problems Government energy land transfer policy must solve. Then we present an idealized model of leasing - 725 - strategy. The strategy's efficacy depends upon the validity of certain key assumptions, but it can be adapted to fit a wide range of specific circumstances. Finally, we shall apply the model's underlying logic to arrive at leasing policy recommendations for each of the energy resource segments covered by the preceding chapters. The Dimensions of Government Leasing Policy In judging what policies ought to govern the transfer and development of Federal energy resource lands, three sets of considerations are crucial: the goals to be satisfied; the relevant technological, geological, and economic charac¬ teristics; and some basic assumptions concerning political and demographic events. There is, we believe, widespread consensus that energy resources should be developed efficiently, taking into account among other things environmental effects, and that the public should receive the "fair market value" of energy resource lands transferred into private use. 1 / On the question of resource 1/ There is, as we have brought out in chapter 3, an inevitable element of ambiguity in the concept of "fair market value." It clearly involves something more than the nominal return frequently achieved in the past, when mineral rights to Government land were virtually given away. Presumably, unless policy considerations not now apparent become paramount a "fair return" should not include monopoly profits to the Government as landlord. Our view is that competitive conditions should determine, as nearly as possible, the level of return. - 726 - development timing, a difficult trade-off between the welfare of present and future generations must be faced. We assume, consistent with national policy, that some acceleration of U. S. energy resource development is desired, in part to enhance shortrun domestic energy independence. We are con¬ vinced that these goals are best achieved when competition in the purchase and sale of energy resources is kept as vigorous as it can be, consistent with the realization of scale economies. Absolutely critical is a further assumption: that energy will continue over the foreseeable future to be relatively expensive, as it has been during the past year, and hence that there will be no return to the "cheap energy" days of the 1950's and 1960's. This follows from several additional assump¬ tions: that a world population of increasing size and affluence will exert mounting pressure on energy resources; that petroleum will continue to play a key role in satisfying world energy demands; and that the OPEC cartel will continue its output- restricting, price-elevating policies despite temporary or even chronic excess capacity. If we are wrong on the behavior of OPEC, crude oil prices could drop by a half or two-thirds relative to 1975 levels, and the accelerated development of such resources as oil shale, deep-water offshore oil and gas, and coal located far from consumption centers will make little - 727 - economic sense. The availability of abundant cheap oil would drastically reduce the market value of most substitute energy reserves. But the rewards for cooperative output restraint by OPEC nations are so vast that the cartel and its pricing policies appear likely to hold firm. And even if oil prices fall in the immediate future, they are almost certain to return to relatively high levels over the longer run as growing demand eventually overtakes the diminishing stock of low-cost reserves. It follows that, for at least a substantial time to come, domestic reserves of oil, gas, and substitute energy resources will be much more valuable than they were during the 1950's and 1960's. This has compelling implications for the satis¬ faction of the Government's "fair market value" goal. When energy was cheap, the Federal Government's vast coal, uranium, oil shale, and other energy land holdings were worth little more than their value in such alternative uses as agriculture and settlement. Transferring those lands into private use for nothing or next to nothing—e.g., under the claim, preference right, or simultaneous filing systems — involved little sacrifice of potential compensation. In an era of dear enfer-gy, the Federal lands are much more valuable, motivating land transfer policies that exact for the public's benefit the substantial rents realizable through mineral exploitation. - 728 - Accompanying the rise in energy land values has been a substantial increase in the degree of uncertainty confront¬ ing energy resource development investors. This uncertainty has several dimensions. For one, price uncertainty has intensified. Oil prices rose sharply, pulling coal and other energy resource prices along. But what goes up might go down, and the economic attractiveness of exploiting marginal and unconventional energy resources is inextricably linked to high oil prices, which depend in turn upon the behavior of a potentially unstable international cartel. Furthermore, to the extent that oil prices do remain high, there are incentives to extend the frontiers of energy resource exploitation both geographically and technologically. New, previously unexplored offshore oil and gas tracts become attractive. New uranium deposits—perhaps lying deeper than those exploited to date—will be tapped. New technol¬ ogies such as oil shale retorting and hot water or hot dry rock geothermal steam generation are being developed. The dry hole and technological failure risks associated with those new ventures are appreciable, and in some cases the investments required are of unprecedented magnitude. These uncertainties and risks create a dilemma. Leasing through competitive bonus bidding, as we have seen in chapters - 729 - 3 and 5, is in most theoretical respects the best way of ensuring that the Federal Government captures the rents from its energy resource lands. In practice, bonus bid leasing of exploration and production rights has been favored when the Government has made a conscious effort to receive fair market value. As energy resources become more valuable, bonus bids for these rights should also tend to rise, increasing the public revenue from energy-bearing lands. This very increase in the absolute size of bids may, however, lead to a smaller proportion of the rents being captured from the lands leased. If would-be wildcatters are subject to capital rationing, bids which reflect the full increase in potential lease values will be inhibited. This problem is intensified if the Government makes promising public lands available for exploration at a more rapid rate. In addition, when substantial front-end payments must be hazarded to explore new wildcat areas, risk aversion is apt to temper bidders' ardor and keep winning bids lower than they would be in a less uncertain environment. Granted, we found in chapter 6 no evidence of a significant risk-averse bias in past bonus bidding for offshore oil tracts. Yet with the rise in oil prices, the stakes have escalated, and even the largest companies are likely to become more risk- averse as a result of such experiences as the Exxon group's $650 million "dry holes" in the Gulf of Mexico's Destin Dome. - 730 - the extent that energy developers do manifest risk aversion i and the effects of capital rationing in their bidding, the Government is less successful in gaining fair market value for its leased energy lands. As experience with the leasing of offshore oil and gas tracts in the days of cheaper energy demonstrated, high explo¬ ration risks and sizable bonus bids work to the relative disadvantage of smaller corporations, who are either excluded altogether or feel compelled to enter joint ventures. The consequence is a lessening of competition, with further adverse effects on the vigor of bidding and hence the receipt of fair market value. Rising resource values, capital rationing, and conditions which limit the number of companies engaged in exploration interact to create another difficult trade-off. The more extensive and pluralistic exploration is, the more discovery there will be and, ultimately, the more energy resource pro¬ duction there can be. In addition, exploration generates important information "spillovers." There is at present great uncertainty concerning the magnitude of the Nation's yet- untapped energy reserves. 2 / Without much better information 2 / See "Oil and Gas Resources: Academy Calls USGS Math ■Misleading,'" Science, February 28, 1975, pp. 723-727. - 731 - on the scope of resources in such frontier areas as the Atlantic coastal shelf and the north Alaskan slope, it is hard to choose rationally between rapid resource depletion and conservation. But when exploration and production rights are leased as a package through bonus bidding in the face of risk aversion and capital rationing, increased exploration can be encouraged only by putting out more tracts for bidding, which in turn drives down the average bid per tract. Under the present system, then, there is a conflict between the amount of revenue the Government receives for its leased energy lands and its ability to stimulate early, extensive exploration. In sum, the bonus bidding system currently used to transfer valuable energy lands into private hands leaves much to be desired in an environment of high energy prices and substantial uncertainty. The claim location, preference right, and simultaneous filing systems are also ill-adapted to the new era. In permitting virtually free exploration and development, they fail even more seriously to compensate the public for the exploitation of its resources. Some other more suitable approach is evidently needed. Possible alterna¬ tives include royalty bidding or profit share bidding. But as we observed in chapter 5, a straight royalty bidding system in high-risk but potentially high-payoff situations tends to - 732 - draw bids that provide inadequate incentive for the explora¬ tion and development of less bountiful deposits. Exploration may therefore be inhibited and inefficient production fostered. Profit-sharing systems do not retard exploration, but they engender more complex production inefficiencies and they are difficult to administer. Since traditional methods measure up poorly against the emerging economic and technological imperatives, efforts to devise a new, better land transfer system appear warranted. A Proposed Two-Stage Bidding Approach The essence of the problem to be solved can be stated succinctly. We wish to stimulate vigorous exploration and discovery by keeping exploration costs as low as possible and providing strong incentives for investment. We also want to encourage effective competition and minimal risk aversion in the bidding for exploitable resources. This in turn implies (1) waiting until discovery has occurred before soliciting development right bids; (2) keeping entry into the bidding open; and (3) making the maximum feasible amount of geologic information available to bidders. The difficult part, and the point at which all land transfer systems now in use falter. - 733 - is affording strong incentives for exploration while keeping post-discovery entry open. One way to achieve both sets of objectives simultaneously is a two-stage competitive bidding procedure which we shall call the TSCB system. Under TSCB, public land would be subdivided into tracts reflecting the average size of economically workable mineral deposits or reservoirs. The rights to explore a tract and the development-production rights would be granted in separate actions. The leasing procedures at the second (development- production) stage would be similar to conventional competitive bonus bidding methods, except that bids would be solicited only after economically workable quantities of an energy resource are discovered. Pure bonus bids could be sought or, if the Government prefers to share the risk of unanticipated resource price or yield changes, the familiar "mixed" system involving a modest fixed royalty plus competitively-varying bonus bids could be employed. The more novel aspect of TSCB involves the granting of exploration rights and their impact on subsequent development leasing. Access to public lands for exploration would require no front-end monetary payment. A tract could be nominated for exploration by any individual or company. Under one major - 734 - variant of TSCB, exploration rights would then be opened up for competitive bidding. The bidding variable would be what we shall call the discovery bonus share (DBS)—that is, the explorer's share of any subsequent winning bonus bid for development and production rights. Exploration rights would be awarded to the first-stage bidder who bids the lowest DBS or, in other words, who agrees to accept the lowest share of the bonus payment received if valuable resources are in fact discovered. 3 / If no discovery is made, the firm with exploration rights would of course receive nothing for its efforts. When on the other hand a discovery is made and reported, the discovering entity or any other firm could request a development-production leasing sale. The decision when to hold the sale would be made by the Department of the Interior, taking into account relevant efficient development timing considerations. Appro¬ priate advance notice of the sale would be given, and competi¬ tive bonus bids would be solicited. The discovering firm would have to compete with all comers for rights to develop the 3/ The firm obtaining exploration rights would also have to provide an acceptable environmental impact plan providing assurance of appropriate damage-limiting measures and indemnification of significant damage to third parties. - 735 - ( discovery. Its exploration contribution would be rewarded, however, by the DBS to which it is entitled. Suppose the DBS has been set through the first-stage bidding at 17 percent. In selecting the winning bidder, the Government would favor that bid which yields the highest dollar amount net of the discover's bonus. Given its 17 percent share entitlement, the discoverer would be the winning bidder as long as its net outlay (that is, the bonus bid less its discovery bonus share) equaled or exceeded 83 percent of the highest non¬ discovering firm's bonus bid. If the discover's bid is less than 83 percent of another firm's bid, the other firm would win rights to develop the tract and the discoverer would be paid 17 percent of the winning bonus. The discoverer would also receive its 17 percent share if it chose not to bid for development and production rights. To ensure that the Government receives fair market value for its energy resource lands, it is important that all bonus bidders have as much information as possible on the geology of tracts offered for sale. Firms awarded exploration rights would therefore be required to file with the U. S. Geologic Survey comprehensive information, including drilling core logs and any relevant flow test data, resulting from their explor¬ ation. When significant quantities of any energy resource are - 736 - discovered on a tract, the discovering firm would normally be expected to drill a sufficient number of wells or cores (e.g., for oil or gas, three) to estimate the magnitude of the deposit. All such information would be made available promptly for public inspection. Obviously, discoverers may not be happy about being put on an equal footing with rival develop¬ ment stage bidders in terms of tract knowledge. To the extent that this loss of advantage affects their incentives, however, it will be compensated in the first-stage DBS bidding. Exploration on tracts in wildcat areas is usually much more risky (i.e., yielding more "dry holes" per success) than exploration on tracts adjacent to already proven reserves. For this reason we would expect DBS bids in wildcat areas to be generally higher than in areas near known resource-holding tracts. An enhanced incentive for rapid, thorough exploration of wildcat areas could be created by providing that only the initial discovery in an area would be eligible for the full DBS. Exploration lease provisions could specify that discover¬ ies on tracts in the vicinity of already successful tracts would receive only a fraction of the DBS, with relatively small fractions awarded for second strikes on tracts immediately adjacent to a previous discovery, and progressively larger fractions of the DBS awarded as the distance from the initial - 737 - ( discovery site rises. Further incentive could be provided by allowing the initial discovering firm to claim as its DBS tract that tract among adjacent alternatives which it believes to hold the most valuable reserves and by awarding it a small fraction of the development bonus bids for all tracts adjacent to its discovery. The exact DBS percentages awarded for second strikes and adjacent tracts would be an important part of the incentive structure. They would have to be set on the basis of geologic data much richer than those available to the FTC staff. £/ The knowledge that the DBS payment will be reduced if prior discoveries are made on adjacent tracts should be sufficient incentive in most instances to induce rapid explor¬ ation. However, diligence requirements might be desirable to make sure that companies do not simply obtain tracts through essentially costless first-stage DBS bidding and then sit on them. A rigorously enforced policy of revoking exploration rights for any tracts upon which drilling or other suitable exploration had not commenced within a reasonably short time 4/ Obviously, the incentive formulae and their administra¬ tion can become quite complex. What might be practical for large offshore tracts may be impractical for small coal leases. The main point is that provision should be made in each instance for compensation appropriate to the costs and risks incurred in the discovery process. - 738 - (say, three to five years) would not impair economic efficiency. A firm whose rights were revoked due to lack of diligence might be prohibited from bidding when exploration rights for that tract are next offered. A firm holding exploration rights should, on the other hand, be allowed to forfeit its rights voluntarily at any time and nominate the tract for a new competitive DBS auction in which it could participate. This would prevent firms from sitting on tracts for which they had bid a DBS share that, subsequent geologic information revealed, was too low to warrant continuing exploratory investment. The fact that winning DBS bids might sometimes prove inappropriate in the light of subsequent information consti¬ tutes the main difficulty in the two-stage bidding approach outlined thus far. While some discovery bonus share bids might be too low to induce exploration, others might be higher than the actual circumstances warrant. If companies could freely nominate tracts for first-stage DBS bidding, there would be a natural tendency (since virtually no out-of-pocket cost is incurred) for all remotely interesting tracts to be nominated at the first available opportunity. Bidders would probably submit high DBS bids on many wildcat tracts merely to try their luck, and by chance they could win some of those tracts because other firms failed to bid. If all other geologic - 739 - indications were equal, firms would direct their exploratory efforts toward those tracts on which they happened to be especially lucky in the DBS bidding. Or (more realistically) if certain tracts appeared more promising geologically than others, exploration might nevertheless be deflected toward somewhat less promising tracts which had been won with especially high DBS bids. The result could be an impairment of economic efficiency in exploration. Windfalls might also be realized occasionally as wildcat tracts won with a lucky high DBS bid proved to have valuable mineral deposits. One way to avoid these difficulties would be to have the Interior Department limit the number of tracts offered for first-stage bidding in any period. This, however, could impede the exploration of wildcat areas more promising than Government decision-makers realized. An alternative approach would be to dispense with the first competitive DBS bidding stage altogether and set the first-strike discovery bonus share administratively. Thus, if the average cost of exploring an offshore oil or gas tract were $1.5 million and the average bonus bid were $15 million, or ten times as high, as was the experience in Outer Continental Shelf bidding during 1973, - 740 - the DBS for such areas would be set at 15 or 20 percent to provide ample incentive for exploratory effort. Access to Government lands for exploration would then be completely open, subject only to the satisfaction of environmental protection constraints and the avoidance of overcrowding. Should over¬ crowding prove to be a problem in specific instances—e.g., as several companies all file to explore some particularly interesting tract—the conflict could be resolved by holding a special competitive auction, with the administratively determined DBS as the maximum acceptable bid. This administered DBS approach has the advantage of avoiding instances in which valuable tracts are won through high but lucky DBS bids. It also eliminates any need for Government officials to select tracts for exploration bidding offers, and it confines the cost of holding first-stage competitive auctions to that subset of all cases in which overcrowding would otherwise occur. For these advantages, a price must be paid. More high-level effort would have to be devoted to determining the proper discovery bonus share for each general class of conditions, taking into account explo¬ ration costs and risks. Setting a single fixed first-strike DBS for all tracts in a general class is also less flexible than determining the DBS by competitive bidding in each situation. - 741 - The fixed DBS approach could discourage exploration in certain cases—notably, when explorers have a fairly clear idea of a tract's prospects and when they judge the costs and potential returns to be so closely balanced that they would consider the tract worth developing only at a bonus close to zero. In such marginal cases, exploration would not occur under a fixed DBS system, but it could take place under a competitive DBS approach, with the discoverer's bonus share being bid at approximately 100 percent. Which broad approach to two-stage competitive bidding is employed—competitively or administratively determined discovery bonus shares—would depend upon the particular geologic and economic conditions and the weight decision¬ makers place upon alternative features. In short, the TSCB model is quite flexible, adaptable to a wide range of leasing situations. With it, the "discoverer take all" reward philos¬ ophy now implicit in the noncompetitive leasing of some Government lands would be replaced by a system which would continue to provide strong incentive for active exploration, but would reserve as much revenue as possible for the Government. At the same time, when large payments are made for development rights, both the buyer and the Government would have good knowledge of the value of the resources being sold. Competitive - 742 - leasing would not be commenced, as it often is now for KGS (known geological structure) oil, gas, coal, and geothermal resource areas and all offshore tracts, without at least some exploratory drilling to ascertain the size and quality of the resources. One final point warrants elaboration. As we have suggested, the Government need not immediately lease for development a tract on which valuable resources have been proved if conser¬ vation or other considerations argue for delaying leasing. If Government policy goals dictate a rate of development leasing slower than the rate of discovery, only the most desirable tracts should be leased for immediate development, with higher-cost tracts being retained for later leasing. To reduce the uncertainty confronting explorers, the conditions under which leasing would be delayed should be spelled out in advance as clearly as possible. In the interest of fair and equal treatment, firms whose discoveries were held off the market might be compensated for interest losses suffered owing to the delay. Again, conditions under which this would be done should be spelled out in advance to reduce uncertainty in exploration. - 743 - Further Uncertainty-Reducing Measures The proposed two-stage competitive bidding approach is designed to reduce uncertainty and risk in two important ways: by encouraging exploration and hence the accumulation of informa¬ tion on the location, quantity, and quality of energy resource reserves; and by delaying the competitive award of exploitation rights until bidders can have a clear picture of what they are bidding for. The result of lessened risk and uncertainty should be more vigorous competition, a closer proportioning of bonus payments to economic rents, and a better information base from which to pursue efficient development timing policies. There is, however, another important source of uncertainty and risk which the TSCB system can reduce at best only indirectly uncertainty concerning future resource prices. To be sure, better knowledge of exploitable reserves will have some effect in limiting uncertainty. But substantial uncertainties would remain even if potential reserves were known precisely. They flow in part from the intrinsic difficulty of predicting how the competitive market will react to various shocks and, more prominently, how the market will be distorted by OPEC-like cartels. Further unpredictability has been introduced by domestic Government energy policy. Investment which would - 744 - undoubtedly bring down currently high coal prices may have been inhibited by the Government's coal leasing moratorium, indecision over how vigorously sulfur emission standards will be enforced, and deadlocks over the difficult question of strip mining reclamation standards. Investment in new oil and gas wells, secondary recovery, and the development of substitute fuel technologies has also been affected adversely by the difficulty of predicting whether the prices of interstate natural gas and "old" domestic oil will be deregulated. It is debatable whether much can be done by the Federal Government to reduce or eliminate the price uncertainties caused by OPEC. Such options lie in any event largely out¬ side the scope of this report. It seems clear, however, that resolution of the unsettled environmental policy questions impeding expansion of coal mining would clarify the longrun outlook for both coal and substitute fuels. And for gas, the status quo—with great uncertainty as to whether prices will stay at disequilibrium levels or soar with deregulation— encourages speculative withholding of existing reserves and the deferral of reserve expansion investments. To accelerate the rate of production, the Government should make either a credible commitment to fix and hold prices above the cost of bringing in new reserves or an equally firm commitment - 745 - to letting market forces operate. Ambiguity is the worst of all possible price policies when expansion of supplies is a significant goal. Specific Energy Resource Sector Recommendations Having provided a broad overview of our fundamental assumptions and some indicated directions for change in energy resource leasing policy, we turn now to specific recommendations y for the six sectors analyzed in chapters 6-11. In several cases, we shall find, variants of the two-stage competitive bidding model can be introduced to good effect. Still, no single approach, however flexible, is likely to be best under all circumstances. Alternative and complementary possibilities for improving energy leasing policy will therefore be considered too. And it seems clear that some experimentation with promising policy variants and the mixing of leasing approaches—e.g., ( bonus bidding with royalty bidding—is frequently desirable in view of the technological, economic, and company response uncertainties. Offshore Oil and Gas Under the pre-exploration bonus bidding system currently in use, the large size and high risk of bonus payments have been (t - 746 - an important barrier to the entry of relatively small companies. Although bidding risk would be sharply reduced under a TSCB system, tract bids would rise significantly, and the level of the required ante might continue to inhibit entry by smaller companies. With either TSCB or traditional one-stage bonus bidding, therefore, it would be desirable to permit the winning bidder to spread its bonus payment over a series of annual installments—e.g., over a five-year period. This would reduce initial capital requirements, and if the commitment were irrevocable, it would not conflict with either the "fair market value" or economic efficiency criteria. Since it is mainly smaller companies that are adversely affected by high capital requirements, the payment-spreading option might be limited to corporations with total assets below, say, a thresh¬ old of 52.5 billion. 6/ To avoid discrimination against larger excluded companies, interest should be accumulated on the deferred payments—e.g., at the average rate prevailing for five-year Treasury bonds at the date of leasing. We believe that the two-stage bidding approach with competitive discovery bonus share determination is especially 6/ With a $2.5 billion threshold, 17 U. S. petroleum companies would have been excluded from spreading their payments at the end of 1974. - 747 - c suitable for the leasing of offshore oil and gas tracts. It should therefore be adopted—if not comprehensively at the outset, then at least on an extensive experimental basis. Should the TSCB approach be rejected, the present exploration- plus-development package bonus bid system is probably the second best method. We strongly recommend, however, that pure royalty bidding be used for at least some tracts auctioned in previously unexplored areas. Despite its deficient incentives for production when discoveries are of workable i but disappointing size, royalty bidding is likely to stimulate the entry of smaller firms which would be discouraged by bonus bidding. It will therefore promote diversity in the types of firms performing exploration and development. Leasing a number of tracts through royalty bidding would also generate additional evidence on the approach's efficacy. To minimize the production incentive failure problem, leases let through royalty bidding should include diligence clauses calling for j. cancellation if no discovery has been made within five years of leasing or if production is not sustained after the initial five-year period. Absent a TSCB system, bonus bidding with moderate fixed royalties should be used to lease new tracts in any area where extensive exploration has already occurred. We see no need for diligence requirements in leases issued through traditional bonus bidding or the TSCB system. - 748 - In the past, the timing of Federal offshore lease sales has been gauged in part to maintain existing price levels and avoid oversupply conditions. This, we believe, is undesirable. Nor should the Government again permit the extension of State pro-rationing schemes to Federal oil lands. Federal policy should be to err slightly on the side of leasing too many tracts and then let market incentives govern the rate of develop¬ ment and production. Lease sales should, however, be scheduled regularly to avoid severe instabilities in the offshore drilling and service industries. They should also be announced well in advance so that companies can plan financing and equipment scheduling. A shift to the TSCB system or the partial use of royalty bidding in wildcat areas and permitting smaller companies to spread bonus payments over five years will reduce barriers to offshore oil and gas entry, thereby invigorating competition in resource markets. As a further competition-enhancing measure, serious consideration should be given to the benefits and costs of prohibiting joint offshore oil and gas bidding ventures among the major oil companies. The evidence we have compiled provides no indication that the largest firms are incapable of bidding for and developing offshore tracts independently. > - 749 - Such a joint venture policy could conflict with another of our recommendations: that offshore leases be unitized whenever unitization would promote petroleum resource con¬ servation. When a pool spans adjacent tracts leased by different major companies, the best solution would probably be a sale or swap which eliminates joint production by majors. When smaller oil companies are participants with majors in a unitized pool or other joint venture, arrangements whereby the major markets the smaller firms' oil should normally be discouraged unless the marketing rights are acquired through competitive bidding . Finally, measures should be taken to ensure that complete information on ownership and control of offshore oil and gas resources is available. At present, it is impossible to determine with any precision who controls what. Lessees should be required to report all full and partial lease interest transfers promptly to the Interior Department. The same reporting obligation should bind subsequent lease interest holders. A quinquennial census should be taken to ascertain how concentrated oil and gas production and reserves are on Federal and State leased lands and to identify the degree to which ownership interests are interrelated through joint ventures. - 750 - Onshore Oil and Gas The FTC staff is convinced that Congress should abolish the simultaneous filing system used to transfer Federal land oil and gas rights where no petroleum-bearing structures are known. It is little more than a lottery in which the public receives next to nothing for potentially valuable mineral rights while speculators and middlemen profit. It should be replaced, we believe, by a variant of the TSCB bidding with open exploration and administratively determined discovery bonus shares. This would permit the Federal Government to capture a significant share of the rents from valuable tracts while confining the administrative costs of holding a competitive bonus sale to that small fraction of all drilling ventures in which oil or gas is actually discovered. The next best policy would be competitive bonus bidding with a modest pre-specified royalty rate. Like the simultaneous filing and TSCB systems, it maintains strong incentives for exploration. One disadvantage is the necessity of conducting a competitive lease auction for each wildcat tract. For wildcat areas, we recommend that an appreciable fraction of the tracts be leased by royalty bidding. The aim, as in the offshore realm, would be to increase diversity in the types of - 751 - operators engaged in exploration and to collect information with which to evaluate the effectiveness of the royalty bidding approach. Should market demand prorationing be reinstituted in the future by any State government, we recommend that oil and gas deposits located on Federal lands be exempted from the State regulations. To ensure that onshore deposits are exploited efficiently, the Government should encourage unitization or single ownership of oil and gas pools located on Federal leased lands. Steps which should be taken toward this end include the elimination of acreage limitations on competitively leased tracts and the combination of contiguous expired leases into larger tracts for re-leasing. As with offshore oil and gas, it is difficult to determine who actually controls onshore Federal leases because of frequent rights transfers. A one-time survey should be conducted to determine the beneficial ownership of each leased Federal tract. Subsequent transfers of rights should be reported promptly to the Department of the Interior. - 752 - I Oil Shale The primary objective of the TSCB leasing approach is to encourage vigorous exploration when the location and extent of mineral resources are uncertain while preserving the Government's ability to receive fair market value for its energy lands. With oil shale, however, the essence of the current problem is quite different: it involves the persistence of severe technological, environmental, and economic uncertainties. It is not yet clear which of several contending retorting techniques is best; the costs of alternative full-scale processes are still predictable only within a wide range of possible error; and the feasibility of reclaiming shale mining tracts is uncertain. The only thing which seems reasonably certain is that shale oil extraction can be economically viable in the near future only if the OPEC cartel holds world oil prices well above the competitive level, and OPEC's ability to do so is also unclear. Under these circumstances, the best Federal Government strategy is to work toward reducing or eliminating those uncertainties which are reducible before commencing a large- scale shale land leasing program. Only enough land should be leased to provide a full trial for the most promising alternative I - 753 - technologies. It is surely more important at this early juncture to ensure that the technologies are developed than to extract the full value of possible but highly uncertain rents from the shale oil lands initially leased. Later, when the technology is in hand, costs are known, and a better basis has been established for projecting future price trends, additional lands can be leased from the Government's vast holdings in a way which ensures that "fair value" is received. Whether the Federal Government is doing enough to encourage the development of oil shale technology is unclear. Notably, it is difficult to tell whether the manifest caution of companies currently conducting or contemplating development projects is attributable to genuine uncertainties and prohibi¬ tive costs or a desire to bluff the Government into providing unnecessary subsidies. If, indeed, the firms with projects underway need additional assurance, the most effective stimulus would probably be a Government commitment to buy a specified quantity of shale oil at a guaranteed minimum price—e.g., up to 200,000 barrels per day from 1978 through 1988 at a price of approximately $12.00 per barrel. Shares of this aggregate commitment could be auctioned off competitively. If additional oil shale tracts are to be leased during the current research and development stage, a guaranteed shale oil - 754 - purchase option proportional to the quantity of reserves offered should be included as part of the sale package. This approach, we believe, is preferable to direct Government subsidies for pilot plant development and commercial scale-up. However, vigorous governmental support should be provided for applied research on oil shale processing and reclamation technology. 1_/ One of the principal dangers in the present course of oil shale development is the possibility that some company or consortium might come up with a clearly dominant technological approach and fence itself in behind a wall of patents. As in all major patent policy issues, a delicate balance must be struck. On the one hand, the prospect of gaining some technological advantage is an important inducement to undertaking the massive investments required to develop a shale oil retorting technology and scale it up to commercial throughput levels. On the other hand, if world economic conditions and the technology evolve in 7/ Several FTC staff members, concerned about the slow and erratic pace characterizing oil shale research and develop¬ ment thus far, recommend that Federal leases should contain strict diligence clauses. Legitimate technological failure would excuse or extend the diligence requirement. If, however, significant weight is placed on encouraging economic efficiency, it seems clear that diligence clauses should not be used to force a technology onto the market if its costs and unavoidable uncertainties do not warrant full-scale investment. - 755 - such a way that shale oil becomes a vital component of the Nation's energy resources, and if one patented shale processing technology turns out to have a very large cost advantage over all alternatives, the resulting shale oil industry monopoly could impose severe social costs. We believe the simultaneous occurrence of these contingencies during the life of existing and pending basic patents is improbable. But we could be wrong. As a minimum precautionary measure, the Federal Govern¬ ment should insist upon the right to order compulsory licensing of patents and know-how at reasonable royalties as a condition for further substantial development subsidies or shale oil purchase commitments. Patent cross-licensing agreements and the accumulation of improvement patents should also be monitored closely by the antitrust agencies to ensure that the line separating valid patent practice and illegal monop¬ olization is not overstepped. As with offshore oil and gas leasing, the FTC staff is concerned about the competitive consequences of joint ventures in oil shale development. We recognize that some advantages may flow from joint ventures in the development of a new, very costly technology. It is also possible that entry by non-petroleum companies and small independents—important to achieving a pluralistically structured industry—will be - 756 - fostered by permitting certain joint ventures. We recommend a fresh look at the necessity of joint oil shale development ventures among the largest oil companies. On the other hand, we see no need to prohibit joint ventures between major oil companies and independents or non-petroleum firms, as long as attention is paid to avoiding special circumstances which might aggravate any anticompetitive effects. We believe that the present statutory limitation of 5,120 acres on the amount of Federal oil shale land any individual can hold is inappropriate. For low-yield tracts, it could lead to mines and retorting plants too small to realize all scale economies. And compared to the vast amount of Federal oil shale land available, it imposes an unncessarily tight ceiling on the potential concentration of reserves. Multiple Federal tract ownership should also not be prohibited, although the Government may in the future wish to impose overall multi¬ state reserve tonnage limitations on individual companies if, and only if, the shale oil industry shows promise of becoming an important energy source and if it continues to develop along highly concentrated lines. - 757 - Coal The United States is thrice blessed in its abundant reserves of high quality coal. We believe the Nation should get on with the important task of seeing that those reserves are utilized economically. To do so, the outstanding disputes over air pollution and land reclamation should be settled, and both coal mining and using industries should proceed vigorously to develop and implement appropriate sulfur removal and land reclamation technologies. The moratorium on Federal coal lands leasing should also be terminated. And although the problem lies far outside the scope of this report, effective utilization of the Nation's coal resources demands that policies be adopted to reverse the deterioration of railroad rights-of-way. In the narrower realm of leasing policy, we recommend that the preference right system be abolished or phased out. In an era of high energy resource prices, coal has become far too valuable to be given away as a reward for some prospecting. Since core drilling is relatively inexpensive, the most suitable replacement would be two-stage competitive bidding with competitively determined discovery bonus shares not to exceed ten percent. Alternatively, the conventional - 75 *- bonus bidding plus fixed royalty system might be used uniformly in leasing coal tracts. If it is, the Government should conduct no lease sale until exploratory boring has been completed on the tract—if need be at Government expense — and all relevant data therefrom have been published for analysis by potential bidders. Barriers to entry into coal mining have historically been low, especially in comparison with such energy resources as offshore oil and gas and oil shale. We see no need for special leasing approaches to reduce coal entry barriers further. The 46,080-acres-per-State limitation on a company's Federal coal land holdings appears unwarranted, especially in view of the fact that coal now sells in relevant geographic markets much broader than the boundaries of any single State excepting Alaska. Nevertheless, acreage or reserve tonnage holding restrictions well in excess of an efficient-sized mine's needs are unlikely to interfere with efficient development. And from the standpoint of maintaining the most competitive market structure possible, there is something to be said for overall nationwide limits on a company's Federal coal land holdings. Any such limit should be related to and based upon comprehensive data concerning the ownership of coal resources in both the Federal and non-Federal domains. - 759 - Assuming that a workably competitive structure can be maintained in both the Federal leased land segment of the coal industry and (more importantly) in the combined Federal and private segments, we see no need for diligence requirements on Federal lands leased through competitive bonus bidding or the TSCB system. The choice between production and conservation should then be governed solely by market signals. Uranium The exploitation of uranium ore reserves for electricity generation is at a relatively early stage. The potential is great. Assuming a policy commitment to efficient uranium resources development, it is clear that existing Government land transfer practices are inadequate and inappropriate. An entirely new program entailing leasing should be devised and shaped to further the Nation's energy program objectives. Uranium deposits, like coal fields, have become much too valuable to be given away to anyone who stakes a claim. Uranium should therefore be removed from the categories of minerals covered by the General Mining Law of 1872. Persons purporting to hold claims under the Law of 1872 should be invited to come forward and prove that they have complied with - 760 - the Law's work requirements. If they have, and if they can also satisfy the more stringent standards for patenting, a patent should be issued. If they cannot sustain the burden, their claims should be invalidated and the land should return to the public domain so it can be re-offered competitively. While the basic uranium land development objectives are presumably similar to those for other energy fuels, some special circumstances should be noted. First, before uranium land leasing can be expanded greatly, extensive geological exploration is needed. This suggests the desirability of tailoring the leasing program in its initial stages toward encouraging open explora¬ tion. Second, uranium exploration is not on the whole as costly or risky as oil and gas wildcatting. Therefore, land transfer policies should actively foster competition; e.g., encouraging new competitive entry and discouraging exploration by consortia of companies individually capable of bearing the risks. Third, the exploitation of known uranium reserves presents additional opportunities for enhancing competition in a new and growing industry. Finally, the very newness of a large-scale and growing uranium ore leasing program requires that a high degree of flexibility be maintained as the program develops. This suggests experimentation with various practical leasing technique variations and periodic evaluations on the basis of complete, timely data. - 761 - With these points in mind, we believe that the TSCB | approach to uranium ore leasing is feasible and that it appears to be the best way of encouraging private exploration while reserving to the Government the fair market value of the tracts leased. Open exploration without initial DBS bidding may be preferable to front-end competitive determination of discovery bonus shares. The bonus share for discovery would then be set administratively. Given the unusually high level of uncertainty concerning longrun uranium oxide price trends, ({ inclusion of an appreciable fixed royalty rate along with the variable front-end bonus payment seems warranted for the second (development rights) bidding stage. The next best alternative would be a front-end bonus-royalty combination covering both exploration and development rights. The optimum predetermined royalty rate in this combination should be the subject of some experimentation. The adverse effects of geologic uncertainty on combined exploration plus development bidding could be mitigated by an active program of Government-sponsored surveying, core drilling, and data publication. Whether there should be acreage restrictions on uranium mining ventures is arguable. The current levels of uranium oxide production and reserve concentration are disturbingly high—considerably higher than those of coal or oil or gas. - 762 - Yet the United States has vast unexploited uranium ore reserves, of which the lion's share will presumably be in Federal Govern¬ ment hands once invalid claims are cleared. Demand for uranium is increasing, and the mining and milling industry will probably expand in coming years. Concentration tends to fall in rapidly growing industries. If, however, the level of concentration does not in fact decline significantly, the Government should impose nationwide acreage restrictions. Such restrictions should be sufficiently generous to ensure that enough ore can be acquired to support a milling operation of efficient size. The optimum levels would have to be ascertained through further analysis. To promote the growth of smaller mining enterprises, the Government might also extend preference—e.g., through a modest bonus bid discount—in favor of newly entering firms and existing mining companies below some size threshold. A preference policy of this nature is defensible only if concen¬ tration does not in fact decline to acceptable levels. Geothermal Resources The new leasing policies implemented under the Geothermal Act of 1970 have been in effect for less than two years. The - 763 - geothermal steam industry is in its infancy, and it has experi¬ enced more than its fair share of teething problems—partly bureaucratic in character and partly due to fundamental technological difficulties. It may be premature to assess how well the new policies will work over the longer run. Yet it seems clear that improvements can be made. The nub of the problem is what goals are to be emphasized, given the underlying technological and geologic uncertainties. Processes for generating electricity from hot water have not yet been developed fully, and those based upon hot dry rocks are still in the early experimental stages. There has been so little geologic exploration that it is difficult to predict any given tract’s geothermal steam production potential. Under these circumstances the leasing approach ought to encourage extensive geologic exploration and vigorous efforts to perfect the relevant energy conversion technologies. A proper initial strategy should resemble the approach taken toward oil shale leasing. A few tracts should be made available to firms willing and able to perfect the necessary technology. At the present stage in the industry's history, we believe, encouraging technical progress is more important than squeezing out the last dollar of potential economic rent. -764 It mignt even be appropriate to grant free access to hot water or hot dry rock sources to the first three organizations which propose highly promising technical approaches and commit themselves to work diligently toward a commercial operation. If within five years they have not succeeded or if they abandon their efforts earlier, the lease would revert to the Federal Government. As the industry matures, emphasis should shift toward utilizing competition to ensure that the Government receives fair value for its lands. The experience from early explora¬ tion efforts suggests that the location of a workable geothermal steam resource is more uncertain and costly than finding coal or uranium reserves. It may even approach oil wildcatting in risk. If this is true, it is inappropriate to insist upon traditional bonus bidding before exploration can commence in an area with subterranean hot water or rock deposits whose existence is known, but whose scope and quality are unknown. Worse yet is the classification of tracts as known geothermal resource areas merely because more than one prospector exhibits interest in them. It is also undesirable to grant leases noncompetitively where no known geothermal resources have been found, but which might prove to be valuable if a discovery occurs. The soundest approach is again a two-stage scheme. - 765 - Vigorous exploration and test drilling would be encouraged by the free grant of prospecting rights subject only to environ¬ mental protection constraints. Prospectors who discover a workable resource would then be awarded a discovery bonus share for the subsequent bonus bidding competition. Since generating electricity from geothermal steam does not now appear to offer striking delivered cost advantages over fossil fuel alternatives and since the bonuses bid are therefore not likely to be huge, generous discovery bonus shares would be appropriate to induce investment in costly but uncertain test well drilling. If something approximating the TSCB system is not adopted, the second best alternative would be a mixed approach, with an appreciable fraction of the exploration and development leases in each area being conferred through royalty bid competitions and the remainder through bonus bidding. The third most suit¬ able approach would be extensive Federal Government test drilling of potential sites, followed by competitive bonus bid sales for tracts with proved economic potential. Until the technology of geothermal steam generation is better developed, the current 20,480-acres-per-State limitation on any single company's holdings appears unwarranted. Such limitations could discourage the development of optimal-sized installations, and they have little pro-competitive impact in view of geothermal steam's minute market share among the various energy resources which can be used in electricity generation. The Need for a Reliable Reporting System Our final recommendation, which is foreshadowed at several points in the preceding discussion, is that a central data collection system covering leased Government energy resources should be established. It could be administered by a single agency or through a closely-coordinated consortium of the various responsible Federal agencies. There is no reason why full information on the control of energy reserves from Federal lands should not be collected and made publicly available. If such a data collection system were combined with compulsory reporting of all privately-held reserves under uniform reporting criteria, the Nation's policymakers would not be faced with the almost impossible dilemma of having to reach critical decisions with virtually no reliable information on the United States' true energy resources. Reliable data are also essential to the effective administration of overall leasing policy, and their availability is an absolute prerequisite for the controlled experimentation and periodic assessment that must take place if the Nation's resources are to be developed in an efficient and effective manner. Perhaps it is unrealistic to hope that such a data system can be devised. But it is at least as much an anachronism to lack uniformly-defined, trustworthy energy resource information in an era of continuing energy crisis as it is to be parceling out valuable Government energy resource lands under 19th century mining laws. - 768 - 25071 BLACK 25072 LIGHT BLUE 25073 DARK BLUE 25074 LIGHT GRAY 25075 LIGHT GREEN 25076 DARK GREEN 25077 TANGERINE 25078 RED 25079 EXECUTIVE RED 25070 YELLOW GENUINE PRESSBOARD ACCO INTERNATIONAL INC CHICAGO. ILLINOIS 60619