U.S. Oil Production: The Effect of Low Oil Prices
136
U.S. Oil Production: The Effect of Low Oil Prices July 1987 NTIS order #PB88-142484
Transcript of U.S. Oil Production: The Effect of Low Oil Prices
U.S. Oil Production: The Effect of Low OilPrices
July 1987
NTIS order #PB88-142484
Recommended Citation:
U.S. Congress, Office of Technology Assessment, U.S. Oil Production: The Effect of LowOil Prices–Special Report, OTA-E-348 (Washington, DC: U.S. Government Printing Office,September 1987).
Library of Congress Catalog Card Number 87-619846
For sale by the Superintendent of DocumentsU.S. Government Printing Office, Washington, DC 20402-9325
(order form can be found in the back of this report)
ForewordThis special report responds to requests by the Government Operations Commit-
tee, the Energy and Commerce Committee, and the Subcommittee on Energy and Powerof the House of Representatives for a review of the effect of volatile oil prices on U.S.domestic oil production. The review was conducted as part of OTA’s ongoing assess-ment on Technological Risks and Opportunities for U.S. Energy Supply and Demand.
Congress’ attention became focused on U.S. domestic oil production as a resultof the largely unexpected plunge in world oil prices that began in December 1985.The price plunge began when Saudi Arabia attempted to recapture lost oil marketsby increasing production and offering new and more attractive contract terms, throw-ing world oiI supply and demand out of balance. One effect of the lower prices—which dropped from $28 per barrel in 1985 to below $15 per barrel for much of1986—was to quickly force a portion of existing U.S. production out of service andto sharply reduce drilling and other exploration and production-oriented activity, guaran-teeing that U.S. production would decline still further in the future. The Departmentof Energy and others have projected that the decline in production, coupled with in-creases in (price-sensitive) oil demand, will drive U.S. oil imports past the 50 percentmark by the early 1990s at the latest. Congress asked OTA to provide an independentassessment of these postulated effects.
This special report presents the results of OTA’s analyses of a group of factors webelieve will strongly influence the future direction of U.S. oil production. These fac-tors include the expected profitability of new investments in drilling, the potential ofnew oil exploration, development, and production technologies, the nature of the re-maining oil resource base, and structural changes in the oil industry. The special reportalso provides a brief discussion of some policy options for Congress to consider if itdecides to moderate the expected accelerated decline in U.S. oil production.
OTA is indebted to the numerous individuals who contributed substantial time tothis special report, providing information and advice and reviewing drafts. Also, thecontributions of our colleagues in the Congressional Research Service, who providedanalyses in two key areas, are gratefully acknowledged. ..
Director
Acknowledgments
OTA thanks the many institutions and individuals who contributed to this report by providinginformation, advice, and substantive reviews of draft materials. Although we cannot name each ofthese, OTA would like to list those individuals who reviewed our drafts and participated in OTA’stwo workshops:
Reviewers
M.A. AdelmanMassachusetts Institute of
Technology
Tom BarberMichel Halbouty Energy Co.
E.J. BaumgartnerAmoco Production Co.
Dave BeecyU.S. Department of Energy
Neil BunisConoco Inc.
Michael CanesAmerican Petroleum Institute
Hubie ClarkeBaker International
William DeitzmannDallas Field OfficeEnergy Information
Administration
John DewesChevron
S.M. DildineConoco Inc.
Larry DrewU.S. Geological Survey
Bill FingerExxon
Bill FisherBureau of Economic GeologyUniversity of Texas at Austin
Ed FlomAmoco Corp.
Tom GarlandOTA contractorDallas, Texas
Bernard GelbCongressional Research Service
Michel HalboutyMichel Halbouty Energy Co.
W.C. HauberShell Oil Co.
Bobby HickmanMitchell Energy Corp.
Robert HillChevron
H.R. HirschConquest Exploration Co.
Robert HirschARCO Oil & Gas Co.
Bill HochheiserU.S. Department of Energy
Robert KalischAmerican Gas Association
Ike KerridgeHughes Tool Co.
Vello KuuskraaLewin & Associates
John LichtblauPetroleum Industry Research
Foundation
Charles MankinOklahoma State Geologist
Chuck MastersU.S. Geological Survey
Vince MatthewsChamplin Petroleum Co.
W.H. McMillianARCO Oil & Gas Co.
Richard O’NeillFederal Energy Regulatory
Commission
Joe RivaCongressional Research Service
Dick RowbergCongressional Research Service
Jack SchanzCongressional Research Service
Ted ScottChevron
Richard SpadingIndependent Petroleum
Association of America
Hossein TahmassebiAshland Oil, Inc.
Arlon TussingArlon R. Tussing & Associates,
Inc.
Michael WooHouse Energy and Commerce
Committee
Tom WoodsGas Research Institute
Scott WileyCopeland, Wickersham,
Wiley & Co.
NOTE: OTA appreciates and IS grateful for the valuable assistance and thoughtful critiques provided by the reviewers. The reviewers donot, however, necessarily approve, disapprove, or endorse this report. OTA assumes full responsibility for the report and the ac-curacy of its contents.
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Workshop 1: at MitchellEnergy, Houston—July 17, 1986
John AmorusoAmoruso Petroleum
Tom BarberMichel Halbouty Energy Co.
Ken BurkeErnst & Whinney
Mickey HermannMitchell Energy
Bobby HickmanMitchell Energy
Bob HirschConquest Exploration Co.
Ike KerridgeHughes Tool Co.
Tony LentiniMitchell Energy
Vince MatthewsChamplin Petroleum Co.
Workshop Participants
Workshop II: atJuly 30, 1986
John BaumgartnerAmoco
David Behling
O T A –
Chase Manhattan Bank
Neil BunisConoco
Bill FisherUniversity of Texas at Austin
Ed FlomAmoco
Bob HillChevron
W.H. McMillianARCO
Richard NehringNRG Associates
Joe RivaCongressional Research Service
Jack SchanzCongressional Research Service
Ted ScottChevron
Hossein TahmassebiAshland Oil, Inc.
John WoodDallas Field Office, EnergyInformation Administration
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OTA Project Staff–Phase 1: U.S. Oil Production
Lionel S. Johns, Assistant Director, OTAEnergy, Materials, and International Security Division
Peter D. Blair, Energy and Materials Program Manager
OTA Project Staff
Steven E. Plotkin, Project Director
Karen Larsen (Oil Industry Restructuring)
Contributing Staff(Analysis of Arctic National Wildlife Refuge)
James W. Curlin, Oceans and Environment Program
William E. Westermeyer, Oceans and Environment Program
Congressional Research Service Contributors
Bernard A. Gelb, Economics Division
Jane G. Gravelle, Economics Division
Joseph P. Riva, Jr., Science Policy Division
Administrative Staff
Lillian Chapman Linda Long
Contractors
Thomas M. Garland, Dallas, Texas
Elaine F. Hahn, San Francisco, California
Contents
Page
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Overview and Findings . . . . . . . . . . . . . . . . . . 1Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 4How and Why would U.S. Oil Production
Decline? . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5An Approach To Understanding Oil
Production . . . . . . . . . . . . . . . . . . . . . . . . . . 9Economic and Resource Factors Affecting
Production . . . . . . . . . . . . . . . . . . . . . . . . . . 10Changes in the Oil industry Affecting
Production . . . . . . . . . . . . . . . . . . . . . . . . . . 14Resisting a Decline in U.S. Oil Production:
Should Government Play an Active Role?. 19
Chapter 1: introduction . . . . . . . . . . . . . . . . . . . 25The Origins of Today’s Low Oil Prices. . . . . . 25Effects on the Oil Industry . . . . . . . . . . . . . . . . 25Congressional Concerns . . . . . . . . . . . . . . . . . 27The OTA Study . . . . . . . . . . . . . . . . . . . . . . . . 28
Chapter 2: Projections of U.S. Crude OilProduction . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Projections of U.S. Oil Production Made
Prior to the Price Break . . . . . . . . . . . . . . . 31Recent Projections of U.S. Oil Production
Assuming Continued Low Oil Prices . . . . . 32
Chapter 3: International Oil Prices: Where AreThey Going? . . . . . . . . . . . . . . . . . . . . . . . . 35
History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Alternate Projections of Future Oil Prices . . . 36Determinants of Future Oil Prices . . . . . . . . . 38
Chapter 4: What Will Determine FutureProduction? . . . . . . . . . . . . . . . . . . . . . . . . . 41
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 41The Reliability of Forecasts of U.S. Oil
Production . . . . . . . . . . . . . . . . . . . . . . . . . . 41Factors Affecting Future Oil Production . . . . . 42
Chapter 5: Economic and Resource FactorsAffecting U.S. Oil Production. . . . . . . . . . . 45
The Profitability of New Investment in OilExploration, Development, andProduction . . . . . . . . . . . . . . . . . . . . . . . . . . 45
Capital Availability and the Permanence ofCapital Flight . . . . . . . . . . . . . . . . . . . . . . . . 66
Premature Loss of Existing Production:Stripper Wells . . . . . . . . . . . . . . . . . . . . . . . 71
The Nature of the Resource Base. . . . . . . . . . 75The Effects of the Natural Gas Surplus. . . . . . 87
Chapter 6: Changes in the Oil IndustryAffecting U.S. Oil Production. . . . . . . . . . . 89
PageChanges in the Climate for Oil Investments
in the United States and Overseas. . . . . . . 89The Efficiency of E&D Activities . . . . . . . . . . . 90Changing Oilfield Technology. . . . . . . . . . . . . 93Deteriorating Industry Infrastructure and the
Potential for a Rebound in Oil Production 95The Restructuring of the U.S. Oil Industry. . . 99
Chapter 7: Production Loss From ReducedDril l ing . . . . . . . . .....................125
The Level of Dril l ing Activity . ............125The Distribution of Drilling Targets, and the
Likely Success at Adding Reserves andProduction . . . . . . . . . . . . . . . . ..........126
Projecting Oil Reserve Additions andProduction Based on ExtrapolatingRegional Drilling Patterns and Per WellReserve Addi t ions . . . . . . . . . . . . . . . . . . . . 127
BoxesBox Page
A.
B.
Recent Studies by the National Petroleum -
Council and the Department of Energy . . . . 5Potential Problems With the Interstate OilCompact Commission/The RAM Group, Ltd.Estimate of Stripper Well Production LossesDue to Low Oil Prices . . . . . . . . . . . . . . . . . . 74
FiguresFigure No. Page
1.
2.3.
4.
5.6.7.
8.
9.
Net U.S. Oil Imports as a Percentage ofOil Consumption, as Projected by theNational Petroleum Council . . . . . . . . . . . . . 1Oil and Gas Drilling Trends . . . . . . . . . . . . . 6How Profit Expectations for the Sameprospect would Have Changed Over Time:An Oil Exploration Prospect in Texas’Permian Basin . . . . . . . . . . . . . . . . . . . . . . . . 11Regional Differences in Oil Reserves AddedPer Well Drilled . . . . . . . . . . . . . . . . . . . . . . 17U.S. Crude Oil Production, 1947-86 . . . . . . 27Oil and Gas “Finding Costs” . . . . . . . . . . . . 65Size Distribution of Discovered Oil andGas Fields in the Lower 48 States . . . . . . . . 79Known and Projected Size Distributions ofDiscovered Oil and Gas Fields in theLower 48 States. . . . . . . . . . . . . . . . . . . . . . . 80Oil “Finding Rate” . . . . . . . . . . . . . . . . . . . . 92
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TablesTable No. Page
1.
2.
3.
4.
5.
6.
7.
8.9.
10.
11.
12.
13.
14.
15.
16.17.18.19.20,
21.
22.
23.24.
25.
26.
. . .
Recent Projections of Future U.S. OilProduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Projections of Future U.S. Oil Production,1985 Outlook . . . . . . . . . . . . . . . . . . . . . . . . 32Recent Short-Term Projections of U.S. OilProduction at Low Prices . . . . . . . . . . . . . . . 32Recent Projections of Future U.S. OilProduction at Low Prices . . . . . . . . . . . . . . . 34“Why Oil Prices Will Remain Low”-Arguments Used by Forecasters of LowFuture Oil Prices . . . . . . . . . . . . . . . . . . . . . . 38“Why Oil Prices Will lncrease”-Arguments Used by Forecasters of HighFuture Prices . . . . . . . . . . . . . . . . . . . . . . . . . 39Assumed Costs To Drill, Equip, andOperate Development Wells, SelectedYears . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Oil Prices for West Texas Crude . . . . . . . . . 49Economic Analysis of Drilling Prospects:Development Wells in Reservoirs NotProducing Before 1979 . . . . . . . . . . . . . . . . . 50Economic Analysis of Drilling Prospects:Development Wells; Effect on Profitabilityof Windfall Profits Tax “Tiers”. . . . . . . . . . . 51Economic Analysis of Drilling Prospects:Effects of Oil Price on Rate of Return Tier3 Development Wells, Drilling andProduction Begun in 1986 . . . . . . . . . . . . . . 51Economic Analysis of Drilling Prospects:Effect of Changing Drilling Costs on Rate ofReturn . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51Economic Analysis of Drilling Prospects:Policy Options for Improving theProfitability of Development Drilling . . . . . . 52Economic Analysis of Exploration andDevelopment Projects . . . . . . . . . . . . . . . . . . 53What Happens If Dry Hole Risk IsReduced? . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53Characteristics of Hypothesized Prospects . 54Estimated Investment and Operating Costs. 55Assumed Crude Oil Prices . . . . . . . . . . . . . . 55Tax and Financial Variables . . . . . . . . . . . . . 56Estimated Anticipated Profitability of U.S.Oil Prospects: 1972, 1981, 1985, and 1986 56Estimated Anticipated Profitability of U.S.Oil Prospects, Under Specified Price andPolicy Alternatives . . . . . . . . . . . . . . . . . . . . . 58Economic Analysis of Exploration andDevelopment Projects . . . . . . . . . . . . . . . . . . 59Lower-48 0il and Gas Production....:. . . 59Economic Prospects for Drilling, Based onGRI Hydrocarbon Model Runs . . . . . . . . . . 61Sensitivity of Leasable Resource Amountsto Current Oil Price . . . . . . . . . . . . . . . . . . . 62U.S. Exploration and Development Outlaysfor 1973 to 1985. . . . . . . . . . . . . . . . . . . . . . 66
Table No. Page
27.
28.
29,
30.
31.
32.
33.34.
35.36.
37.
38.
39.
40.
41.
42.
43,
44,
45<
Sources and Uses of Working Capital of aGroup of Petroleum Companies . . . . . . . . . 67Financial Performance of Selected OilCompanies, First 9 Months 1986 v. First 9Months 1985 . . . . . . . . . . . . . . . . . . . . . . . . . 70Effect of Falling Oil Prices on StripperWells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73Estimated Oil and Gas Resources in theArctic National Wildlife Refuge Section1002 Area . . . . . . . . . . . . . . . . . . . . . . . . . . . 83Drill Rig Equipment: Storage andAvailability . . . . . . . . . . . . . . . . . . . . . . . . . . . 98U.S. Oil and Gas Reserves ReplacementsPercentage of Production, 1979-85 andDomestic Implied Finding Costs . ........102Valuations of Proved Reserves . ..........103Values Added Through Exploration andDevelopment–Worldwide . . . . . . . . . . . . . .104Value Added Ratios–Worldwide. . .......104Mergers and Acquisitions in the U.S. OilIndustry . . . . . . . . . . . . . . . . . . . . . . . . . . . . .105Financial Performance of a Group of OilCompanies, 1983-85 . . . . . . . . . . . . . . . ....109Comparison of 20 Largest U.S. OilCompanies, 1980 and 1985.. . . . . . . . . . . .112Comparison of Historical Concentration inthe U.S. Oi l Industry. . . . . . . . . . . . . . . . . . .112Capital and Exploration Expenditures forSelected Oil Companies, 1983-85 . .......115Changes in Planned Expenditures on U.S.Exploration and Production . ............116Reinvestment in Oil and Gas Explorationand Production . . . . . . . . . . . . . . . . . . . . . . .119Share Repurchase Programs of Selected OilCompanies . . . . . . . ....................120Reserve Additions Per Oil Well Drilled,1980-1984 Average . . . . . . . . . . . . . . . . . . . . 126Past and Projected Alaska Oil Status ... ...l28
46. Past and Projected California Oil Status ...12847
48
495051
52
53
5455
Past and Projected Rocky Mountains andNorthern Great Plains Oil Status . ........128Past and Projected West Texas and EasternNew Mexico Oil Status. . . ..............129Past and Projected Gulf Coast Oil Status ..129Past and Projected Midcontinent Oil Status 129Past and Projected Eastern Interior OilStatus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .130Past and Projected Michigan Basin OilStatus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .130Past and Projected Appalachians RegionOil Status . . . . . . . . . . . .................130Past and Projected United States Oil Status 131Impact of lncreased Stripper WellAbandonment on Low Drilling ScenarioProduction and Reserves Projections ... ...132
Summary
Overview and Findings
The recent precipitous drop in world oil pricesfrom about $28 per barrel ($28/bbl) in 1985 tobetween $12 and $18/bbl through much of 1986dealt the U.S. oil industry a severe blow. In thefirst year after the price drop, U.S. crude oil pro-duction dropped by nearly 700,000 bbl/day, in-dustry capital spending on exploration and pro-duction dropped from about $33 billion/year toabout $16 billion, drilling activity dropped fromover 70,000 well completions/year to approxi-mately 37,000, and the basic infrastructure of theindustry, including its skilled personnel, shrankconsiderably. There is now a strong consensusthat domestic oil production will continue todrop, to between 6 million and a bit over 7 mil-lion barrels per day (mmbd) by 1990, down fromthe 1985 level of 9 mmbd, if oil prices remainin the $12 to $18/bbl range.
A substantial drop in U.S. oil production is onlyone component of a chain of events . . . resultingfrom lower world oil prices . . . that could createfuture problems for the United States’ economicstability and national security. First, this Nation’sprice-sensitive demand for oil will rise as its oilproduction declines—a combination resulting ina sharp increase in the level of imported oil. Mostindustry projections of the effects of continuedlow oil prices envision imports reaching 50 per-cent of U.S. oil consumption by the early 1990sor before. (Figure 1 shows the National PetroleumCouncil’s import projections for a low and highprice track.) At an oil price of $18/bbl, this willamount to a 50 to 60 billion dollar per year drainon the United States’ balance of payments.
Simultaneously, similar trends in oil supply anddemand will be occurring outside the UnitedStates. Lower oil prices are expected to depressoil production outside of the Organization of Pe-troleum Exporting Countries (OPEC) and the Mid-dle East while increasing the worldwide demand
Figure 1 .—Net U.S. Oil Imports As a Percentage ofOil Consumption, As Projected by the
National Petroleum Council
1 I I I
1980 1985 1970 1975 1980 1985 1990 1995 2000Year
SOURCE: National Petroleum Council, Factors Affecting U.S. Oil & GasOutlook, February 1987.
for oil (except where higher taxes maintain pricesat previous levels). These changes will increaseOPEC’s share of the world oil market, with muchof the increase going to the Middle Eastern OPECnations. In time, the Middle Eastern OPEC pro-ducers will have returned to the levels of marketshare and production capacity utiIization that inthe past allowed them to affect prices or disruptoil markets. And, thus, they will have regainedan ability to upset U.S. economic stability andnational security.
OTA’s evaluation of a set of factors affectingfuture U.S. oil production lead to the followingconclusions:
1. The available evidence points strongly to acontinuing, and substantial, decline in U.S. oil
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production if oil prices remain in the $12 to$18/bbl range. This evidence includes: a) recentproduction trends and trends in drilling and otheroilfield activity; b) the financial state of the indus-try; c) industry surveys of future oilfield invest-ment; d) the results of oil supply models; and e)a limited amount of economic analysis.
2. Recent rates of drilling activity are much toolow to allow domestic oil production to stabilizeclose to today’s already depressed productionlevels. Even with quite optimistic assumptionsabout the productivity of future drilling, a con-tinuation of 1986 drilling rates would lower year2000 U.S. oil production to about 6 mmbd– athird lower than 1985 production levels.
3. Available estimates of the magnitude of theproduction decline should be viewed as “bestguesses” rather than as precise calculations, evenif the uncertainty associated with future oil pricelevels is disregarded. Most current productionforecasts assume implicitly or explicitly that pre-vious trends and relationships established overthe past few decades will continue into the fu-ture. The severity of the economic dislocationscaused by the recent drop in oil prices, coupledwith major changes in the industry over the pastfew years, imply that this assumption deservesto be reexamined. It is probably prudent to as-sume that the oil industry will adapt in variousways to the new economic environment and, inadapting, will break with many past trends.
4. It is not clear whether a break with pasttrends would lead to production levels higher orlower than an analysis based on historical be-havior would predict. On the optimistic side, theoil industry might be expected to follow an ini-tial period of disrupted operations with move-ment to more efficient management and positivetechnological adaptations. On the pessimisticside, any positive effects on oil production levelsassociated with an adaptive move to higher effi-ciency might be offset by several factors:
● the industry’s higher debt levels caused bythe wave of takeovers and mergers duringthe 1980s, which could depress total explo-ration and development (E&D) investment;
● the improvement in financial terms offeredby several potential overseas producing
countries, which might shift E&D investmentout of the U. S.;the current drop in spending on researchand development, which could slow tech-nological innovation; andthe apparent shift in basic industry E&D in-vestment strategy, downplaying the impor-tance of replacing company reserves andstressing the requirement that E&D invest-ments sat i s fy r igorous prof i tabi l i ty re-quirements.
There is no ready way to estimate the net ef-fect on production of these diverse factors, Also,further uncertainty is added to estimates of fu-ture production levels by the dependence of pro-duction on a number of other factors that are notknown with any precision, such as the magni-tude, geographic distribution, and physical na-ture of remaining oil resources. Finally, uncer-tainty is added by the relatively low priority thatappears to have been given to publicly availableanalysis of the economic attractiveness of newinvestment in drilling and other production-ori-ented ventures (the oil industry conducts extensiveeconomic analysis of new investment prospects,but most of the analyses are proprietary and notavailable to assist in the public policymaking proc-ess). The attractiveness of such investment is thekey indicator of long-term prospects for adequateU.S. reserve replacement and production.
If oil prices do stay low–perhaps averaging be-tween $14 and $16/bbl for the next severalyears—what might be the outcome for domesticoil production? With rapid restructuring of theweaker companies, favorable adjustments in E&Dstrategies, innovation in E&D technology, andfavorable potential for continued reserve growthin older oilfields, domestic production might beable to hold above 7 mmbd through 1990 (theupper end of the range of most industry estimates)and drop less steeply than projected thereafter.For the period beyond the early 1990s, the open-ing of Federal and State lands to exploration andthe successful discovery of large oilfields on theselands could be of special importance. On theother hand, if the industry continues to shift tomore overseas investment and fails to improveefficiency further, technological change slows be-
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cause of reduced R&D spending, and reserve ad-ditions from older fields slow because of reducedgeologic potential and poor economics, produc-tion could sink to the lower end of the consensusrange (about 6 mmbd) in 1990 and conceivablyeven below the expected range in later years.
5. Further economic and technical analysiscould be useful to policy makers concerned withfalling oil production. With or without such anal-ysis, however, substantial uncertainty will remainabout how domestic production will respond todifferent price levels and policy environments,and policy makers must be prepared to make keydecisions without precise knowledge of their out-comes. Some questions that cannot be fully an-swered with further analysis include:
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How will industry investment behavior adaptto the new price environment and to achanging business environment overseas?To what extent will the major industry re-structuring of the 1980s eventually lead tohigher efficiency and increased interest innew domestic E&D ventures? Will newlymerged and restructured companies be ableto eliminate their heavy debt burdens withina few years, and will they then act to boosttheir investment in traditional E&D activities?To what extent will technological change actto offset some of the negative effects on prof-itability of lower oil prices?Will relatively low cost drilling in the UnitedStates’ older oilfields continue to providelarge volumes of new reserves, or did the in-tensive drilling of the past decade essentially“use up” most of these fields’ remaininggrowth potential?If large new blocks of Federal and State landare made available for exploration, especiallyoffshore California and in the Arctic, willsuper giant fields be discovered and de-veloped?How long will it take (or what conditions arenecessary) to restore enough confidence topotential investors in E&D that they will re-spond readily to reasonable profitabilityprospects? To what extent could investmentlevels rebound without a concurrent re-bound in cash flow from the industry’s pastinvestments?
6. There are ways to reduce, though certainlynot eliminate, uncertainty about the magnitudeof a future production decline and the potentialeffect on production of alternative governmentpolicy measures. Of most value would be a com-prehensive analysis of the prospective profitabilityand productivity of new investment in oil explo-ration and development. Although some valuableeconomic analyses are available (e. g., the Na-tional Petroleum Council’s evaluation of E n -hanced Oil Recovery) these are too limited inscope and uncoordinated to qualify for the typeof comprehensive analysis needed for carefulforecasting and policy analysis.
Other potentially useful analyses include:
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A cataloging and analysis of changes in thebusiness environment for oil and gas invest-ment overseas.An evaluation of the dissemination and useof new technologies in oil exploration, de-velopment, and production during the pastdecade, and an examination of new technol-ogies just introduced or on the near horizon.An economic analysis of existing oil produc-tion with high operating costs (especiallystripper production), incorporating collec-tion of physical and economic data at theindividual well level.An examination of the differences in individ-ual companies’ E&D strategies and results,to gain further perspective about the poten-tial for industry wide improvements in E&Defficiency.
Congress is faced with difficult choices, notonly in ‘selecting policies to combat trendstowards lower domestic oil production andhigher imports but also in deciding whether anactive government role is wise. Unfortunately,some of the key issues associated with choosingan appropriate government role are ambiguous.For example, earlier concerns about the effectof higher oil imports on U.S. economic stabilityand national security have been complicated—but not negated–by the significant changes inoil markets and government preparation for mar-ket disruptions since the early 1970s. Thesechanges include the construction of the Strate-gic Petroleum Reserve, the advent of a strong spot
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market for crude oil, the beginning of a futuresmarket, and substantial changes in the role of oilin the U.S. economy.
Another complication is that the majority ofproduction forecasts prior to the 1985-86 oil pricedrop projected domestic oil production to beginfalling rapidly in the 199os; in other words, mostforecasters expected the production decline andsubsequent increase in imports to occur even inthe absence of a large price drop, albeit a dec-ade later. At first glance, these predictions wouldappear to favor a “hands off” policy on oil pro-duction since boosting production today wouldappear to be only delaying the inevitable. Notal I forecasters agree with this “conventional wis-dom,” however; they contend that U.S. produc-tion could have been maintained, had prices nottumbled, with continued intensive field growthand innovation in enhanced oil recovery. Further,“buying” an extra decade of moderate importlevels could be worthwhile if the decade wereused to add flexibility and security to the U.S.energy system, rather than to artificially preservethe status quo, so that the Nation would be bet-ter prepared to deal with higher import levelswhen they occurred.
There is also uncertainty about whether allow-ing U.S. oil production to decline now might yieldhigher future production rates than would be pos-sible if today’s production rates were proppedup and the resource base depleted more inten-sively. Although resource depletion is a valid con-cept, the remaining U.S. petroleum resource baseis less a small resource than it is a low-grade re-source whose recovery is amenable to improvedtechnology. Thus, the pace of technology devel-opment—likely to be more rapid if productionis kept high by tax or other incentives—conceiv-ably may outweigh resource depletion as an in-fluence on future production levels.
If Congress does decide to work to stabilize do-mestic oil production, it can use a number of pol-icy mechanisms. The following options are dis-cussed briefly in the report:
● oil import fees (either to raise wellhead pricesor to establish a price floor);
● tax concessions (including investment taxcredits, depletion allowances, cuts in sever-
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ance and ad valorem taxes, drilling credits,abolishing the Windfall Profits Tax);removing the ban on oil exports from theAlaskan North Slope;bolstering investment in oil exploration anddevelopment R&D; andremoving leasing restrictions on frontier/off-shore areas.
IntroductionThe long price slide that took world oil prices
from about $40/bbl in 1981 to $28/bbl in De-cember, 1985, and then precipitously downwardto the $12 to $15/bbl level throughout much of1986 has created a depression in the U.S. oil in-dustry. Most indicators of the level of oilfieldactivity have been slipping since the “peak” yearof 1981 and dropped sharply in the early monthsof 1986:
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●
●
●
The number of rotary drilling rigs workingin the United States dropped from over 4,000in 1981 to about 1,900 in July 1985 to be-low 700 a year later; they have since re-bounded slightly.Industry employment dropped from a 1982high of 708,000 to 585,000 in 1985 and to422,000 in September 1986, with oilfieldservice employees bearing the brunt of thedrop.Total well completions, which had declinedmoderately from 89,000 in 1981 to 73,000in 1985, dropped below 40,000 in 1986. Fig-ure 2 illustrates the rise and fall of well com-pletions between 1970 and the present.The monthly seismic crew count, that is, thenumber of teams doing seismic surveys foroil and gas exploration and development, fellfrom 681 in 1981 to 378 in 1985 and to 195in 1986.
U.S. oil production has slid from 9.03 millionbarrels per day (mmbd) at the end of 1985 to 8.35mmbd a year later, a decline of over 7 percent.Coupled with increased oil demand, the produc-tion decline has forced U.S. net imports of crude
‘That is, crude oi I plus ‘ I lease condensates, ’ natural gas I iq u idsrecovered in the field. Total domestically prduced petroleum alsoincludes natural gas liquids recovered from gas processing plants,refinery processing gain, and small amounts of alcohol.
5
Box A.—Recent Studies by the National Petroleum Council and the Department of Energy
The National Petroleum Council (N PC) and the U.S. Department of Energy (DOE) have recently pub-lished reports on U.S. energy supply: Factors Affecting U.S. Oil & Gas Outlook and Energy Security, re-spectively. Both reports focus particularly on domestic oil production but also evaluate U.S. and worldenergy supply and demand.
The DOE report, the more pessimistic of the two regarding oil production prospects, projects U.S.crude oil production to be 6.9 mmbd in 1990 and 5.2 mmbd in 1995 (compared to about 9 mmbd in1985) if oil prices* rise from about $14/bbl in 1986 to $16/bbl by 1990 and $22/bbl by 1995. The NPCreport projects slightly higher production rates at somewhat lower prices: 7.1 mmbd in 1990 and 5.7 mmbdin 1995 with oil prices at only $12/bbl in 1986 and rising to $14/bbl by 1990 and $17/bbl by 1995. Bothof these projections are well within the mainstream of forecasts released within the past year, and aresubstantially more optimistic than several. For both, net petroleum imports reach the 50 percent level inthe early 1990s.
Both reports also examine a higher oil price case. With prices in the low $20s by 1990 and the high$20s by 1995, DOE projects domestic crude oil production to be 7.8 mmbd in 1990 and 6.6 mmbd in1995; for similar prices, NPC projects production to be 8.0 mmbd in 1990 and 7.0 in 1995. These resultsimply that an import fee that raised oil prices by $5 to $10/bbl could substantially slow the productiondecline.
DOE’S projections are based on a detailed computer model of U.S. energy supply, the Energy Infor-mation Administration’s Intermediate Future Forecasting System. NPC’s projections are based on a surveyof U.S. and world oil supply and demand forecasts from various sources. Both projections are supple-mented by quantitative and qualitative evaluations of oil supply factors. The NPC report plainly acknowl-edges the substantial uncertainty associated with the projections:
Even sophisticated statistical analysis of past events is inadequate for predicting the future if the historical datado not contain an event similar to the current or expected future events . . . Energy forecasters have no recenthistorical events to measure the impact of sharply falling prices of petroleum . . .
Both reports identify the deterioration of industry infrastructure-loss of skilled workers, declining man-ufacturing capacity of critical oilfield equipment, deterioration of the rig fleet, and so forth-as a criticalroadblock to a future drilling recovery. OTA shares these concerns but is somewhat more optimistic aboutthe ability of the industry to increase its rate of additions to oil reserves if incentives improve.
Although both reports evaluate several policy options to increase domestic oil production, only theDOE report presents a quantitative analysis of these options, calculating the net costs and production re-sponse for many of them. The uncertainty associated with these estimates is likely to be extremely high,however (in some cases, e.g. lower minimum bids on Outer Continental Shelf acreage, so high that cost/pro-duction estimates were not made).
*Measured as the cost of crude oil to U.S. refiners.
6
oil and petroleum products up by about 14 per-cent over a year before, from 4.9 mmbd, or 30percent of total U.S. petroleum supply, to 5.6mmbd, or 34 percent of supply.
These trends appear to be pushing U.S. oil sup-ply towards a dependence on imports reminis-cent of the situation in the late 1970s, before theproduction stimulating and demand suppressingeffects of the two oil price shocks finally took holdand began weaning the United States from agrowing reliance on foreign oil supplies. In fact,a renewed dependence on foreign supplies is pre-cisely what the oil industry and most energyanalysts are predicting for the United States—absent either a rapid return to previous pricelevels or major Federal intervention in the mar-ketplace. Typically, they are projecting a likelydecrease (from 1985 production levels) in domes-tic oil production of 2 to 3 mmbd by 1990, andsimilar increases in demand, if world oil pricesstay at about $15/bbl. Table 1 presents severalprojections of future U.S. crude oil productionassuming continued low oil prices, as well as pro-jections completed before the price drop for com-parison.
How and Why Would U.S.Production Decline?
Several mechanisms will drive theproduction decline.
Oil
expected
Figure 2.—Oil and Gas Drilling Trends
1970 1972 1974 1976 1978 1980 1982 1984 1986
Year
SOURCE Off Ice of Technology Assessment 1987: based on AmericanPetroleum Institute data
First, production from stripper wells2 and othermarginal wells (wells with high per barrel produc-tion costs) will drop because many of these wellscannot be operated profitably at low oil pricesand will be shut down. These wells cannot re-main out of production for long periods; after ayear (or other period depending on State rules)they have to be “plugged” (sealed with concrete)for safety and environmental reasons, and areunlikely to be reopened thereafter. Other shutdown wells may be lost because of water en-croachment.
Second, fewer new development wells will bedrilled, yielding less new production to offset thenatural decline in production from older wells,
Third, fewer exploratory wells will be drilled,yielding fewer new fields and thus fewer new op-portunities for development drilling,
Fourth, production from enhanced oil recov-ery (EOR) operations, which seek to capture asmuch as possible of the estimated two-thirds oforiginal oil-in-place left behind by conventionaldrilling and waterflooding, will decline becausemost new projects, and many planned project ex-pansions, will be cancel led as no longer eco-nomical.
Fifth, research and development (R&D) will de-cline, exacerbating the overall problem becauseR&D traditionally has been an important driverin pushing the industry into new areas andsources of oil production as older sourcesdecline.
In addition, many analysts warn that the indus-try is losing its ability to recover swiftly in theevent of a return to high prices; the infrastruc-ture necessary for such a recovery is rapidly beingdismantled as drilling rigs are scrapped, cannibal-ized for parts, or even sold abroad; manufactur-ing facilities are retooled; and skilled personnelare laid off, many Ieaving the industry for good.
Although the reasons given for their predictionsmay differ, the analysts have tended to focus theirarguments on three areas in particuIar:
7
Table 1 .—Recent Projections of Future U.S. Oil Production
Projected crude oi l product ion(million barrels per day)
Source 1990 1995 2000 Price expectation (dollars/bbl, 1986 dollars)At low prices:DRI . . . . . . . . . . . . . . . . . . 7.8 6.3 5.5 $20 by 1995, $30 by 2000Chevron . . . . . . . . . . . . . . 5.9-6.9 NA NA $10 to $15 thru 1987, $18 to $22 by 2000API . . . . . . . . . . . . . . . . . . 6.2 NA NA Constant $15CWW ... . . . . . ., . . . . . 6.1 NA NA $15Unocal . . . . . . . 6-6.5 NA NA $13.50Amoco . . . . . . . . . . . . . . . 6.7 NA 4.5 “Low price”Fisher . . . . . . . . . . . . . . . . 6.8 NA NA $15Conoco A . . . . . . . . . . . . 7.0 5.5 3.5 <$12 thru 1995, $20 in 2000Conoco B . . . . 7.8 6.9 6.1 <$20 thru early 1990s, $20 in 1995, $26 in 2000GRI D . . . . . . . , . . . . . , . , . . 7 .3 5.4 5.0 $12 in 1986, $14 in 1990, $21 in 2000NPC . . . . . . . . . . . . . . . . . 7.1 5.7 4.5 $12 in 1986, $14 in 1990, $21 in 2000DOE . . . . . . . . . . . . . . . . . 6.9 5.2 NA $14 to $16 thru 1990, $21 in 1995Price outlooks of 1985:Chase . . . . . . . . . . . . . . . . 8.3 7.0 5.7 Drops to low $20’s by 1990, rises 0.9 ‘\. /year thereafterDRI B . . . . . . . . . . . . . . . . . 8.6 NA 6.8 Drops to $21 by 1987, constant to 1994, $32 by 2000EIA . . . . . . . . . . . . . . . . . . 8.1 6.5 NA Dips but is $28 by 1990, $31 by 1995GRI . . . . . . . . . . . . . . . . . . 8.5 8.2 7.8 Dips but is $34 by 1995, >$40 by 2000+xcludeS Natural Gas Llqulds 1985 Product Ion, 9mmbdNA = Not available
SOURCES: DRI Data Resources, Inc , Energy Rewew, Summer 1986.Chevron Economics Department, Chevron Corporation, World Energy Outlook, June 1986API American Petroleum Institute, Two Energy Futures: FJational Choices Today for the 1990s, July 1986 (1990 production actually for 1991)CWW Jack L Copeland, Copeland, Wickersham, Wiley & Co , Inc , Presentation to the Keystone Energy Futures Project: Liquid Fuels POIICY, July 14, 1986.Unocal Fred L Hartley, Unocal Corp j “The High Cost of Low-Priced Oil,” submitted to the US Senate Energy and Natural Resources Committee, March 20, 1986Amoco Economics Department, Amoco Corp., World Energy Outlook, April 30, 1986Fisher Wlillam Fisher, Bureau of Econom!c Geology, Unlverslty of Texas at Austin, Testimony to the Fossil and Synthetic Fuels Subcommittee, Energy andCommerce Committee, March 6.1986Conoco A and Conoco B Coordinating and Planning Department, Conoco, Inc , World Energy Outlook Through 2000, September 1986GRI Gas Research Institute, submission to the National Petroleum Council’s Survey of US. Future Oil and Gas Outlooks.NPC National Petroleum Council, Factors Affecting U.S. 0(/ and Gas Outlook, February 1987.DOE U S Department of Energy Energy Security” A Report to the President of the Un/ted States, DOEL3-0057, March 1987.Chase Chase-Manhattan Bank, Global Petroleum Division, World 01/ and Gas 1985, August, 1985.DRI Data Resources Inc Energy F?ewew Winter 1985.EIA Energy Information Adm!nlstratlon, Annual Energy Outlook 1985, DOE/EIA-0383(85), February 1986GRI Gas Research Institute, Basellne Project/on Data Book 1985 GRI 13asellne Projection of US. Energy Supply and Demand to 2010
Argument One: The established models of U.S.drilling activity and oil production virtuallyunanimously predict low rates of drilling andrapid declines in reserve additions and pro-duction if low prices continue. Current indus-try surveys of expected future drilling levels,reserve additions, and production basicallysupport these predictions.
Available models of U.S. oil supply generallyrely on extrapolation from past trends to projectfuture levels of drilling activity, reserve replace-ment, and production. Under stable conditions,these models can be reliable predictive tools.They are not likely to be as reliable, however,when forced outside the range where past trendsprovide a good analog.
It is virtually certain that the extrapolativemodels of oil production are directionally correctin their prediction of a U.S. oil production de-
cline. Under current conditions, however, pol-icymakers shouId be skeptical of the accuracy ofthese models. The events of the past year, andof the 1980s in general, in several ways are ma-jor departures from past events. The nation hasjust undergone a period during which oil prices,a key determinant of industry exploration and de-velopment activity, have undergone severe dis-location, and in a direction opposite past dis-locations. Moreover, during the 1980s, severalcompanies comprising a large segment of the in-dustry’s reserve replacement capability under-went significant changes in business strategies,were restructured, or merged with other compa-nies. In addition, the period of the early 1970sto the present has been a period of hyperinfla-tion followed by collapse in industry costs; thefuture path of such costs–a key determinant ofthe economic attractiveness of new E&D invest-ment—is unlikely to be stable or predictable.
8
I
While the results of industry surveys of futuredrilling rates, reserve additions, and productionare very important, policy makers are likely to de-mand substantial analytical evidence to back upthe survey results. For one thing, in recent yearsthe industry (along with just about everybodyelse) has not been very successful in predictingwhich way prices and production would turn,and different segments of the industry and differ-ent companies often have been at odds aboutmajor resource and production projections. Sec-ond, the industry participants in these surveyshave been the direct recipients of significant fi-nancial blows and have seen their friends and col-leagues laid off, retired, or even bankrupted. Itseems fair to have concerns about whether theirexpressed views of the future of the U.S. oil in-dustry reflect a cool-headed appraisal or insteadreflect their depression about the immediate re-sults of the industry downturn. Third, the indus-try has a very large financial stake in any policymeasures that could alleviate a production de-cline. Whether or not this stake affects their an-nounced projections of future production, somepolicy makers and segments of the public believethat it may. These concerns suggest that an ana-lytical verification of industry estimates, capableof being reviewed by independent analysts,would be desirable and probably necessary forpublic acceptance.
Argument Two: The large drop in oil prices hasdrastically cut oil industry revenues and placedmany of the industry’s past investments injeopardy. After paying off its obligations, theindustry’s remaining internal cash flow issharply reduced from earlier levels. At thesame time, the industry’s traditional sourcesof outside investment and loan capital, facedwith low prices and uncertainty, have backedaway from the oil market. These capitalsources are particularly important to the in-dependent sector of the industry. Withoutnew sources of investment capital and with-out a restoration of cash flow from prior in-vestments, the industry will not have enoughcapital to invest in the major new explorationand development ventures needed to arrestthe rapid decline in production.
This argument is most important for projectingoilfield activity levels in the short term, perhapsover a 2- or 3-year period. Many of the financialentities generally responsible for U.S. drilling andother production activities have been hurt badlyfrom the large cut in revenues from their past in-vestments; uncertainty about their survival—espe-cially for many of the small independents—willkeep away outside capital, and they have mini-mal internal resources. Similarly, many banks andother sources of investment capital experiencedsevere losses and may be reluctant to reenter theoil market. In the short term, new investment willsuffer because it will take time for the industryto resolve mismatches between financial re-sources, drilling capability, and land positions andreserve ownership. After an industry shakeout,however, drilling and other activity, and reservereplacement, could revive if adequate incentives,measured by the expected profitability of newE&D investment relative to competing invest-ments, were available. Also, a number of com-panies, especially those larger integrated compa-nies and independents that had avoided largedebt loads, still have substantial internal resourcesand/or access to external capital sources. Theargument that inadequate capital resources willprevent the industry from investing in new pro-duction, which attempts to tie the level of newinvestments to the success of old ones, may ex-plain short term investment behavior of the oilindustry (or, at least, some segments of it) butdoes not adequately explain the industry’s long-term investment behavior.
Argument Three: The large drop in oil pricescoupled with fears about future price col-lapses have undermined the expected profit-ability of new investments in exploration anddevelopment. With current price expectationsand conservative investment requirements (toaccount for higher uncertainty), there are toofew economically attractive drilling opportu-nities to spur continuation of the industry’spast level of domestic exploration and devel-opment activity.
This argument ties the level of future invest-ments in reserve replacement and productiondirectly to the economic attractiveness of theseinvestments. In OTA’s view, the attractiveness,
or expected profitability, of future drilling andother production-oriented ventures is the key in-dicator of long-term prospects for adequate U.S.reserve replacement and production.
Current industry analyses supporting conclu-sions about declining U.S. oil production pros-pects generally stress arguments one and two andpay somewhat less attention to argument three.Models and surveys, the bases of argument one,have been widely used. The second argumentabout inadequate capital and reduced cash flowsis analytically very straightforward and has beenadvanced with intensity, especially by spokesper-sons for the independent sector of the industry.In contrast, few in the industry have supportedthe third, “expected profitability” argument withthe careful analysis necessary to establish its credi-bility.3 The substantiation of industry projectionsof declining production that would be providedby a careful analysis of expected profitability mustbe viewed as very important in light of the highsocial costs—many billions of dollars—associatedwith many of the policy measures being consid-ered to arrest the projected decline.
Evaluating the attractiveness of new E&D invest-ment opportunities relative to competing invest-ments is a complex undertaking. It would requirea substantial commitment of resources and in-formation from the industry, and much informa-tion that would be useful in such an evaluationis proprietary. Although many and perhaps mostof the larger oiI companies have undertaken ex-tensive analyses of their own investment pros-pects, these analyses are not likely to be madeavailable to the public. Furthermore, a crediblenational analysis will still have to rely on someform of detailed assumption about that portionof the total remaining oil resource base that isphysically available to the industry for exploita-tion within the time frame of interest. No widelyaccepted resource model currently exists, al-though there are a few computer models of oilsupply (e.g., the Gas Research Institute’s Hydro-carbon Model) that constitute some first attemptsat such a model.
3We do not doubt that many of the i ndustry’s survey responsesabout future 011 production levels are based on companies’ privateevaluations of expected profitability of new E&D investments.
9
An Approach to UnderstandingOil Production
Given the concerns about the reliability of cur-rent oil supply models under today’s radicallychanged economic conditions, an appropriatemeans to gauge future oil production is to gainan understanding of both the changes the oil in-dustry has undergone and the forces that willdrive future production. The following discussionexamines:
Economic and resource factors affecting pro-duction:—changes in the economics of dri l l ing
prospects over time;—changes in capital availability and how
these changes affect E&D investmentlevels;
–loss of oil production from stripper wells;—the nature of the oil resource base, and in
particular, the availability of drilling oppor-tunities that might remain profitable in alow price environment; and
—the effects on drilling of the current sur-plus in natural gas supply.
Changes in the oil industry affecting pro-duction:—the potential effects of industry restructur-
ing on industry investment strategy and ca-pabilities,
—the changing business climate for E&D in-vestment overseas and its effect on domes-tic versus overseas spending,
—changes in the efficiency of explorationand development activity and their effectson rates of reserve additions and pro-duction,
—the potential for technological change tooffset some of the drop in profitabilitycaused by low oil prices, and
—the effects of a deteriorating industry in-frastructure on industry’s ability to re-bound to higher drilling levels.
The goal of examining these factors is to deter-mine whether the preponderance of evidencetends to support or undermine the industry’s pes-simistic predictions for future oil production, and
10
to better understand how Congress might bestintervene to shore up production if it chose todo SO.
Economic and Resource FactorsAffecting Production
Changes in the Economics ofDrilling Prospects
OTA’s interviews with oil industry plannerspaint a pessimistic picture of remaining domes-tic exploration and development prospects at lowprices. Essentially all of those interviewed con-tend that the “inventory” of economic oil andgas prospects has shrunk enormously at mid-1986 prices of$12 to $15/bbl despite the accom-panying sharp declines in drilling and othercosts. They assert that the only arena capable ofsupporting substantial drilling levels at theseprices is relatively low-risk, low-to-moderate costdevelopment drilling, primarily for oil objectives,with short lead times; they also assert that explo-ration drilling is virtually dead at these prices.
In addition to low risk shallow extension andinfield drilling,4 other prospects still consideredto be viable at oil pricesof$12 to $15/bbl include:
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continuation of projects where most front-end capital has been spent (enhanced oil re-covery, offshore development drilling, water-floods5);drilling to satisfy lease and contract require-ments; andsome exploration drilling where productioncould not begin for 7 to 8 years or longer,so the current price environment is not rele-vant (although several major companieshave backed away from this type of drilling).
Most of those interviewed were pessimisticthat an increase to $18 to $20/bbl would spark
4Extension drllllng seeks oil and gas just outside the known bound-aries of discovered fields; infield drilling seeks oil and gas insideof these boundaries by drilling in previously undrilled sections e:drilling at smaller spacing than previous drilling.
Swaterflooding is an oil recovery technique whereby water is in-jected into the reservoir to maintain or restore reservoir pressureand push additional oil towards the producing wells.
a major drilling revival, although all felt that cer-tain additional prospects would become eco-nomic, including:
●
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●
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●
●
some deepwater Gulf of Mexico exploratoryprospects;some onshore wildcat prospects;additional enhanced oil recovery, especiallyC02 gas injection projects with readily avail-able sources of CO2, and some projects usingthe injection of polymers;Beaufort Sea exploration and delineationdrill ing;limited offshore California development; andmany waterflood projects.
There are only scattered published economicanalyses that can offer confirmation of these as-sertions. In an attempt to test at least a few of theassertions, OTA examined how the expectedprofitability of small-scale exploration and de-velopment drilling programs i n the United Stateshas changed over time. OTA compared 1986profit expectations with expectations for the samephysical prospects in: 1985, immediately beforethe major price drop; 1981, at the height of thedrilling boom; and 1972–before the first OPECprice shock. Although only a few physical pros-pects were examined, we believe that the resultsare fairly widely applicable to drilling projects ofmodest scale.
In our analysis, we found that the profit expec-tations for the 1986 drilling projects, assumingoil prices would remain in the $14/bbl rangeduring the 1980s, were substantially lower thanexpectations in 1981 and 1985 in every case; forexample, onshore development well drilling proj-ects with expected real rates of return (beforetaxes) of 15 percent in 1986 would have beenexpected to earn 35 to 52 percent in 1985 and23 to 43 percent in 1981. Although drilling costsdropped substantially from 1981 to 1985 and, toa lesser extent, from 1985 to 1986, the oil pricedrop has proved to be the more important fac-tor influencing profitability. This result agreesstrongly with the assertions of the industry that
6Expectecf profitability is calcu Iated by using oil price forecaststypical of the analysis year. Realized or actua/ profitability is calcu-lated by using actual price levels up to the present, and forecastedor assumed price levels thereafter.
11
the price drop has substantially reduced thenumber of profitable domestic E&D opportu-nities.
We also found, in every case, that 1986 ex-pected profitability (based on the assumed $14/bbl future oil price) was much better than ex-pectations in 1972, primariIy because 1972 oilprice expectations were modest. Thus, for thecases examined, today’s economic conditionsfor drilling development wells and explorationwells aimed at small fields would appear to besubstantially superior to conditions in 1972, forwells of the same physical promise. At firstglance, this appears to indicate that the industryhas better economic opportunities today than in1972. Because so many of the better prospectswere drilled in the years between 1972 and 1986,however, today’s remaining physical prospectsmay be considerably poorer than those availablein 1972. On the other hand, this effect of “re-source depletion” is tempered by the additionof new prospects to the resource “inventory” be-cause of improvements in exploration technol-ogies and in geologic understanding. The net ef-fect of these factors is unclear without furtheranalysis, although an industry consensus wouldlikely be that today’s physical drilling prospectsare substantially inferior to those available in1972.
Figure 3 illustrates the change over time in ex-pected profitability for a single exploration pros-pect in the Permian Basin, Texas.
Another important result of OTA’s analysis wasthat the actual profit performance of the drillingprojects was considerably different than the ex-pected performance. For the wells drilled in1972, actual profits were much higher than ini-tially expected; for the 1981 and 1985 wells, ac-tual profits were much lower than expected.7
In fact, there is little difference in realized ratesof return between the 1986 wells and the 1981and 1985 wells. The higher drilling costs incurredin 1981 and, to a lesser extent, in 1985 offset thehigher average oil revenues obtained with thesewells.
7Assumln~ continued $14/bbl oil prices beyond 1986
Figure 3.—How Profit Expectations for the SameProspect Would Have Changed Over Time: An Oil
Exploration Prospect in Texas’ Permian Basin
75
50
25
019
$20 oil
$14 oilprice
1986
Year
The expected drilling program:. 20 wells drilled● 10 producing wells at 8900 ft.● Initial year production = 222,000 bbl.● 10 percent depletion rate
SOURCE:Off Ice of Technology Assessment. 1987, based on CongressionalResearch Service analysis for this study
OTA also examined the effects of assumed $10/bbl and $20/bbl oil prices on 1986 expected prof-itability. At $20/bbl, if drilling costs do not rise,expected profitability for the projects evaluatedwill be in the same range as 1981 and 1985 profitexpectations, implying that a drilling revivalcould occur at this price level. However, thestrength of any revival would be limited by in-creases in drilling costs that would occur as thecurrent “surplus” of drilling services is used up.Also, for a revival to occur, producers must bereasonably assured of continued price stability.Today, many producers say that they are requir-ing proposed drilling projects to pass a ‘‘low-pricehurdle,” that is, they must retain profitability atprices that could occur if surplus productiondrove prices back down again. A hurdleof$10/bbl is frequently mentioned. At $l0/bbI, drillingprospects that would yield 15 percent real ratesof return at $14/bbl become either outrightlosses or yield barely a few percent. Thus, con-servative price/cost accounting in approvingproposed drilling projects may be playing an im-portant role in stifling drilling activity.
Our analyses apply only to oil exploration anddevelopment aimed at small fields and modest-
72
sized development wells, and only to physicalexamples that do not stray far from average con-ditions. In our view, the great importance to na-tional policy makers of having an accurate esti-mate of domestic E&D economics demands awealth of additional analysis. This analysis mustexamine the full range of E&D activity, from thevarious forms of enhanced oil recovery to ex-ploratory drilling in the Arctic and deep offshore,to extension well and infill drilling in older fields,and so forth. Considerable analysis is alreadyavailable, for example the National PetroleumCouncil’s report on enhanced oil recovery, butthe separate analyses must be collected, inten-sively reviewed for accuracy, and reworked tofit into a consistent economic framework. Sub-stantial new analyses will be needed to fill in thegaps.
Problems of Capital Availability
As noted previously, the large reductions incash flow to the oil industry and, to a lesser ex-tent, the withdrawal of outside loan and invest-ment capital are widely viewed as critical factorsin driving down levels of investment in oil explo-ration and development. Total oil and gas well-head revenues were about $70 billion in 1986,about 43 percent below 1985 levels. Althoughreliable data for private financing, a major sourceof funds for independent producers, are not avail-able, many industry analysts are convinced thatavailability of private funds has declined substan-tially because of current conditions in the indus-try. Furthermore, many of the regional bankswhich had financed the efforts of many smalloperators during the late 1970s and early 1980swere placed under severe pressure by the bank-ruptcies of many of their oil service industry bor-rowers and the reduced values of the oil and gasreserves used as collateral for their loans to in-dependent producers. Poor performance in theagriculture and real estate sectors also played amajor detrimental role in the banks’ loan port-folios. Many of these banks have pulled backfrom the oil and gas loan market.
Although capital availability problems are wide-spread, they are not uniform in their intensityacross the industry. The small independent pro-ducers have the worst capital problems, with no
alternative sources of cash flow and profits andgreatly reduced access to the external capitalsources they had relied on; the larger integratedcompanies have been buffered somewhat againstthe effects of reduced production revenues byincreased profits from their downstream (e.g.,refining) operations. Those larger integrated com-panies and independents that previously hadavoided large debt loads generally cannot (anddo not) claim that their E&D spending is capitallimited; they retain substantial internal resourcesand/or access to outside capital. Although mostof these companies have reduced their E&Dbudgets and activity levels, they presumably havedone so because of changed investment pri-orities.
Although the importance of the drop in cashflow and withdrawal of outside capital to theshort-term investment behavior of the industryis not in question, this is not the case with theimportance of these factors to the industry’s long-term behavior. There is disagreement amonganalysts of the industry as to whether the cashflow from previous investments or the profitprospects for new investments will control theindustry’s future level of investment. I n the past,industry investment levels appeared to be closelytied to levels of cash flow. However, classical eco-nomic theory predicts that the volume of new in-vestment should be more closely tied to the char-acteristics of the new investments. Past industryfinancial losses and recently reported shifts in theindustry’s attitude about replacing company re-serves—discussed in the section on industry re-structuring—reinforce the view that the industryis likely to base its future decisions about the mag-nitude of E&D investment primarily on a carefulevaluation of prospective profits.
Over a period of a few years, companies in aweakened financial condition may go out of busi-ness; undeveloped and partially developed prop-erties and equipment will be sold at low prices;companies will merge and be restructured; prob-lem loans will be renegotiated or written off; andnew financial entities will enter the industry ifgood investment opportunities are available. Inthis manner, the industry would be in positionto attract new E&D investment capital if costs are
13
low enough and E&D efficiency high enough tocreate attractive E&D investment opportunities.
Losses in Oil Production From“Stripper” Wells
There is widespread concern that low oil priceswill force many of the nation’s “stripper” oilwells, wells whose production averages 10 bar-rels of oil per day or less (averaged over the lease),to shut down. Once these wells shut down fora year (or other period determined by State rules),they must be “plugged,” i.e. sealed with con-crete; most wiII never be returned to production,and their reserves wiII be lost. This concern ismagnified by the importance of stripper wells toU.S. supply. Over 400,000 stripper wells pro-duced approximately 1.3 mmbd, 14 percent oftotal domestic oil production, in 1985. Thesewells are concentrated in Texas, Oklahoma, Cali-fornia, and Kansas, which together have three-fourths of the Nation’s stripper production.
The probable loss of stripper production atdifferent price levels is highly uncertain becauseof a scarcity of data about stripper well physi-cal characteristics and production costs. Further-more, the data that are available reflect historicbusiness practices and costs. Both stripper welloperators and the businesses that serve themhave been forced to make adjustments in re-sponse to the sharp drop in oil prices. Analysesof stripper well production must account for re-cent declines in the cost of utilities, materials, andservices to operators as welI as changes in oper-ating practices, such as deferring maintenance,that affect both costs and production levels.
Two quantitative studies of lost stripper wellproduction have been conducted. A study spon-sored by the Interstate Oil Compact Commission(IOCC) estimates that, during the first year,176,000 bbl/day of stripper production, 2 percentof total U.S. crude oil production,8 would be lostat $18/bbl oil prices, and 277,000 bbl/day or 3.1percent of U.S. production would be lost at $15/bbl. The Energy Information Administration (EIA)estimates a first-year loss of 85,000 bbl/day, 1 per-
8Based on average 1985 production of 8,9 mmbd.
cent of U.S. production, at $18/bbl oil prices, withan additional 4,300 bbl/day loss in later years asmajor repairs for the still-operating wells becomenecessary; at $15/bbl, first year losses are esti-mated at 148,000 bbl/day, with later year lossesof 77,500 bbl/day for a total loss of 226,000bbl/day or 2.5 percent of U.S. production. ElA’sestimated first year losses are about half of theIOCC’s estimates.
More recently, an IOCC survey of California,Kansas, New Mexico, North Dakota, Oklahoma,Texas, and Wyoming indicates that 110,000 wellsin these States, with 307,000 bbl/day of oil pro-duction, were shut in during 1986, with 12 per-cent of the wells permanently abandoned. Thesevalues do not break out the production lost solelybecause of low oil prices (each year, thousandsof wells are abandoned even at high oil prices),and thus they are not strictly comparable to theprojections above. However, most of the produc-tion loss is likely to be attributable to the pricedrop, and the survey appears to add credibilityto the (higher) IOCC projections.
The Nature of the Resource Base
The nature of the remaining U.S. oil resourcebase will play a vital role in the response of U.S.domestic oil supply to changing oil prices. Thereis, however, substantial disagreement in the oilindustry about the physical nature of the re-maining resources, about where future U.S. re-serves will come from, and at what price.
A central issue in this resource base disagree-ment is the question of whether the major sourceof new reserves will be the discovery of large newoilfields, particularly in the frontier areas anddeep offshore, or whether it will instead be theaggregation of many thousands of modest incre-ments of reserves gained by drilling new wellsin old fields, improving recovery through en-hanced oil recovery techniques, and exploringfor small fields in familiar producing territories.These different views of the remaining resourcesin the United States lead to different preferencesfor policy initiatives (e.g., different degrees of im-portance attached to expanded leasing of newfrontier areas) and to different views of the oilprices necessary for a revival of higher levels ofreserve replenishment. Frontier and deep off-
14
shore oil resources may, in many cases, requireprices in excess of $30/bbl for economic devel-opment, whereas a considerable portion of theresources available from the smaller scale effortsare viewed as available at prices between $15 and$25/bbl.
The recent history of oil reserve additions gen-erally supports the view that the aggregation ofmany small reserve additions, especially from thegrowth of discovered fields through extensionwell drilling and other mechanisms, plays theweightier role in overall U.S. reserve growth. Forexample, about 70 percent of total U.S. reserveadditions during 1979 to 1984 came from drillingin oilfields discovered before this period, and thepercentage of total reserves coming from thissource has increased from earlier decades. How-ever, those who view the frontier areas as the crit-ical source of new reserves believe that the in-tensive drilling of the last decade and a half hasalready squeezed most of the reserve growthavailable from our older fields, and that any re-maining growth requires much higher prices thanbefore because the easy reserve targets were ex-ploited first. Unfortunately for the advocates ofsearching for giant fields, however, the record ofthe past decade of oil exploration has not beenvery promising, with successes in offshore Cali-fornia and the Gulf of Mexico perhaps more thanbalanced by grave disappointments in the Gulfof Alaska, Georges Bank, St. Georges Basin, andelsewhere. Clear signs of this disappointment arethe very large reductions in recent industry andgovernment estimates of frontier resources,
Resolving the potential roles that continuedfield growth and giant new fields may play in thefuture development of the United States’ oil re-sources may not be possible at this time. What-ever the “correct” view of the resource baseturns out to be, however, both the search forgiant fields as well as the intensive pursuit ofsmall-scale reserve additions must be pursuedif the slide in U.S. production is to stand anychance of being halted.
The Effects of the Natural Gas Surplus
The state of markets for natural gas is impor-tant to oil production. Much exploratory drillingsearches for hydrocarbons, not specifically for oil
or gas. Added incentives for finding gas wiII stim-ulate this type of “nondirectional” drilling andlead to more oil resources being found and devel-oped—and inadequate incentives will do the op-posite. Also, because gas is present in nearly alloil wells, the profitability of these wells dependson having a market for the gas at a reasonableprice.
Since the early 1980s, a surge in deliverabilityand declining demand in the electric utility andheavy industry sectors have created a surplus ofnatural gas deliverability. Low oil prices haveadded to the gas surplus by promoting gas-to-oilfuel switching. The gas surplus has, in turn, keptgas prices low and kept some producers fromhaving an assured market for their production.Although the reduced incentive for gas drillinghas tended to help keep drilling costs low, thenet effect on oiI driIling is almost certainIy nega-tive. A tightening of gas markets in the next fewyears, as predicted by many experts, would havea positive effect on drilling in general and wouldlikely lead to increased oil well completions andproduction capacity. However, uncertaintiesabout the volume of additional gas imports thatcould be made available from Canada, the ac-tual level of excess deliverability, the volume ofgas that could be quickly added to the deliver-able base, and future changes in demand for gashave lead to a substantial divergence of opin-ion about the timing of any end to the currentnatural gas surplus.
Changes in the Oil IndustryAffecting Production
The Effects of Industry Restructuring
During the 1980s, the oil industry underwentimportant changes that seem likely to affect theindustry’s exploration and development strate-gies and financial capabilities. These changeshave included a series of mergers, both volun-tary and “hostile,” as well as internal restructur-ing measures such as asset redeployment, stock-enhancement through stock buy backs, spinoff ofnew companies, asset sales, elimination and con-solidation of functions, and other measures.While many of these changes are widely viewedas destructive of the industry’s willingness and
capability to replace its reserves, some of thesame changes are defended either as strength-ening industry’s reserve replacement capabilitiesor simply as being necessary to allow the partici-pating companies to survive.
During earlier debate over the effects ofmergers and acquisitions in the oil industry, manyof the representatives of acquiring companies,their investment bankers, and their defendersstrongly denied that exploration efforts would bereduced. Despite these assurances, mergers andacquisitions have been widely viewed as destruc-tive of the industry’s reserve replacement capa-bility. Between 1979 and 1985, over $75 billionwas spent on oil industry acquisitions in excessof $1 billion each, adding substantially to longterm debt and presumably lowering the capitalavailable for E&D spending. According to OTA’sreview of a group of companies, merged com-panies have spent substantially more of theiravailable cash flow on debt repayment and lesson oil and gas exploration than other companies.The merged companies typically cut combinedcapital spending significantly in 1984 to 1985,while other large companies in the group weremore often maintaining or increasing their invest-ments. In addition, a number of companies haveadded substantial debt in the process of fightingoff attempted hostile mergers, or simply in pre-paring defenses against potential takeovers. De-spite potential long-term benefits of mergerssuch as improved management and improve-ments in the “fit” of assets and financial andmanagement capabilities, the available evidencestrongly suggests that the short-term effect ofmergers and attempted mergers on the oil in-dustry’s investment in exploration and develop-ment has been negative on balance. Initial suc-cesses of some merged companies at reducingdebt loads may, however, signal that this bal-ance could change.
A significant apparent change in industry be-havior, more a cause of the restructuring than asymptom of it, is a shift in emphasis among manyintegrated companies away from maintaining asecure domestic source of reserves to supplytheir refining and marketing operations, andaway from the former high priority they gaveto recycling much of their production revenues
back into exploration and development. Com-panies are now said to be evaluating E&D invest-ment as a separate profit center, requiring eachinvestment to meet stringent financial criteria.These behavioral shifts are said to be the resultof both the financial losses incurred by many ofthese companies in their past E&D investments,and the easy availability of crude oil associatedwith the expanded role of the spot market. If thiswidely perceived behavioral change is real andpermanent, a return to previous levels of profitpotential in production investments may notcause a return to previous levels of drilling andreserve replacement. This has negative implica-tions for the likelihood of a “rebound” in pro-duction following a price increase.
The Changing Business Climate Overseas
Industry experts consulted by OTA claim thatone cause of the current low level of domesticinvestment in E&D is that the U.S. oil industry hasdecided to shift its domestic/overseas balance ofE&D investments in favor of overseas investment.
In earlier years, many U.S. companies focusedon domestic E&D despite the relative “maturity”of the United States’ oil resources and the bettergeologic prospects overseas. They did this partlybecause of the greater stability and security avail-able within the United States, but also becausemany oil-bearing countries offered relativelydemanding terms for development of their oil re-sources.
Although problems of stability and security re-main, many countries have eased their terms foroil development. They have removed formercaps on the prices paid to foreign developers,eased currency restrictions, lowered taxes androyalty rates, and otherwise improved the po-tential profitability of private oil and gas devel-opment. At the same time, industry spokesmenhave claimed the United States has enacted taxand regulatory changes that worsen the businessclimate for domestic oil and gas investment.
Evaluating the relative business climate for pe-troleum investments of the United States versuscompeting foreign nations is complicated, andOTA is not aware of a comprehensive attemptat such an evaluation. Nevertheless, the attempts
16
by many nations to ease investment restrictionsand improve potential profitability in develop-ing their oil resources clearly have increased theattractiveness of overseas investment vis-a-visUnited States investment. In evaluating the ef-fects of this increase, however, policy makersshould keep in mind that most analysts believethat any increased oil supply outside of the Mid-dle East will tend to enhance market competi-tiveness and stability whether it occurs insideor outside of the United States—and that, dol-lar for dollar, overseas exploration investmentswill tend to purchase considerably more oil re-serves than will U.S. investments.
Changes in the Efficiency of Explorationand Development Activity
An accurate projection of the reserves foundand production capability created by the shar-ply reduced levels of drilling and other oilfieldactivity caused by low oil prices requires an ac-curate estimate of the “efficiency” of this activ-ity, as measured by the footage and wells drilledper rig, the reserves found per well, the wildcat
Isuccess rate, and so forth. These measures haveproved to be sensitive to oil prices and oilfieldactivity levels. For example, rig efficiency (foot-
I age and wells drilled per rig per year), reserves
1 added per well or per foot drilled, and manyother measures of efficiency declined from themiddle 1970s to the early 1980s as oil prices roseand oilfield activity accelerated. Part of this de-cline was due to the use of inexperienced per-sonnel and marginal equipment, made possibleby the inability of the supply of services to keepup with the demand. Another element of declinewas the spread of drilling activity to more mar-ginal prospects with lower reserves and some-times under more difficult physical conditions.This was partly a result of the improved eco-nomics of these prospects and partly an effect ofresource depletion as the best prospects wereused up.
The decline in oil prices that began in 1981forced the industry to become more efficient. Forexample, drilling became more efficient as thenumber of inexperienced drilling crews declined,inefficient rigs were dropped from service, foot-age and turnkey contracts replaced contracts that
paid drillers by the day (day rate contracts offeredlittle incentive for efficiency), and drilling tech-nology improved. These factors were importantcauses of the sharp increase in rig efficiencymeasured between 1981 and 1985. The indus-try drilled 89,000 wells in 1981 with nearly 4,000rotary rigs active; 84,000 wells in 1982 with 3,100rigs active; and 85,000 in 1984 with 2,400 rigs.
Unfortunately, however, the precise dimen-sions of the actual increase in efficiency are ob-scured by other factors that also affect measuredrig efficiency. These factors include:
●
●
●
the proportion of total drilling devoted to ex-ploration, because exploratory drilling ismore time-consuming than developmentdrill ing;possible changes in the number of rigs thatare not included in the datag9; andshifts in the geographic distribution of drill-ing, because drilling in some areas, such asthe Gulf Coast, is more rapid than in others,e.g., the Midcontinent and Rocky MountainOverthrust Belt, because of different rockconditions and other physical factors.
Similarly, as the industry cuts budgets anddrilling rates and retreats from marginal areaswith high costs and low payoffs, measures suchas reserves added per well or per dollar investedshould improve. Consequently, reserve addi-tions should not drop quite as precipitously asdrilling or drilling budgets have. This effect willbe tempered, however, by a likely shift in drillingpatterns away from deep, high risk exploratorydrilling (see the earlier discussion on the Eco-nomics of Drilling Prospects), and also towardshallower and lower risk (but potentially loweryielding) targets. Also, drilling patterns are af-fected by company lease positions and contrac-tual obligations.
Figure 4 shows the regional variation in oil re-serves added per well, illustrating the potentialeffect of shifting the geographic distribution ofdrilling.
Shifts in drilling during the early part of 1986seemed to follow the expected pattern of retreat-ing from regions with low average returns. If only
‘Commonly used rig counts include only so-called rotary drilllngrigs, rigs that drill by rotating a drill bit and its attached drilling pipe.
Region
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the regional shifts in drilling are considered, thereserves added per average U.S. well in 1986could be 37 percent higher than the 1981 to 1984United States average.10
Although this estimate could be interpreted asoptimistic for U.S. oil supply, in fact it is sober-ing. Even if these reserve/well values are correct—and they are almost certainly too high—theystill imply a substantial drop in U.S. oil produc-tion if recent drilling levels continue. For exam-ple, estimating Alaskan and stripper well produc-tion separately, if mid-1986 drilling levelscontinue for the next decade and a half andachieve the regionally adjusted (and optimistic)values of reserves added per well, year 2000United States production will still be 29 percentbelow 1985 levels, or about 6.4 mmbd. Thus,the United States cannot hope to slow the cur-rent decline in domestic oil production unlessit increases substantially its level of drillingactivity.
A reliable projection of future production ratesrequires an accurate estimate of how the indus-try will adapt its investment behavior to the newI
I price environment. Since this adaptation should, take a few years, current drilling patterns shouldI
not be viewed as permanent. At this time, a pro-jection of likely adaptive behavior, and its likely
Ieffect on reserves/well values and other measuresof E&D efficiency, will clearly be speculative.
Insight on the potential for adapting to lowprices might be gained by analyzing the differ-ences among individual oil companies’ histori-cal investment patterns, management styles, andinvestment outcomes. Some companies, such asShell Oil, have had consistently low finding costsover the past decade or more. If the more suc-cessful companies have simply occupied low cost“niches” in domestic E&D, their success may notoffer much room for hope that the rest of the in-dustry could, with appropriate changes in invest-ment behavior, successfully match their cost per-formance. On the other hand, if their success isowed primarily to behavior that could be copiedby the rest of the industry, the long-range out-look for production might look considerablybetter.
101986 drilling based on July 1986 projections.
The Effects of Technological Change
The continuing evolution of oilfield technology,particularly as it may facilitate the exploitation ofexisting resources at lower cost, clearly is an im-portant factor in the ability of the industry to keepreserve replacement and production close tohistoric levels in the face of low oil prices. In gen-eral, however, the majority of the operators andanalysts we talked with were skeptical of the po-tential for both new technology and improve-ments in existing technology to allow access tosignificant volumes of oil that currently are un-economical at prices below $20/bbl. In supportof this view, statistics of important measures ofexploration and development efficiency-such asreserves added per well drilled and explorationsuccess rates—have either held steady or deteri-orated over the past decade despite the introduc-tion of such technologies as three dimensionalseismic analysis, seismic interpretation with per-sonal computers, advanced reservoir modeling,and an array of others. If technology develop-ment has made a difference during the past dec-ade, especially in the onshore lower 48 States,it appears to have been primarily one of coun-terbalancing the negative effects of continuingresource depletion.
Nevertheless, there is a significant minority inthe industry who have a far more positive viewof the potential of improved oilfield technology.They can point to a number of new technologiesjust being deployed, or on the immediate hori-zon, that have promise for lowering industry costsenough to either allow development of additionalresources at current low prices, or at least to al-low added resource recovery at prices signifi-cantly lower than previously thought possible,often in the lower $20/bbl range. These technol-ogies include:
●
●
●
important improvements in the resolutioncapability and cost of seismic imagery;new developments in chemical enhanced re-covery that lower the price threshold from
$25 to $30/bbl to about $20/bbl; andimprovements in horizontal drilling that of-fer the potential of expanding a field’s recov-erable reserves by allowing operators to ex-ploit thinner pay zones.
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Even if industry optimists are correct, the po-tential of new technology will not be realizedwithout a significant R&D effort on the part of theindustry. Although precise figures are not avail-able, industry observers agree that industry R&Dexpenditures are down by at least 30 or 40 per-cent over the past 3 years. Although some cut-backs clearly are appropriate (e.g., for effortsaimed at accessing very high-cost resources in dif-ficult environments that are not now technicallyrecoverable) the overall size of the cutbacks anda general shift away from long term research tar-gets are of substantial concern.
Effects of a DeterioratingIndustry Infrastructure
The large drop in industry activity levels accom-panying the price drop has meant a shrinking ofthe industry’s “in frastructure,” that is, the inven-tory of rigs and other equipment used in explo-ration and development activity, the manufactur-ing capacity to produce the equipment, and thepeople to man the equipment and plan and su-pervise its use. The industry has expressed theconcern that, in the event of an oil price rise orother incentive for a “rebound” in activity levels,the lack of infrastructure would mean severe de-lays, inefficiency, and cost inflation as too muchdemand for oilfield goods and services chases toolittle supply–a repeat of the hyperinflation inthese goods and services that marked the mid-dle to late 1970s and early 1980s.
Any rapid improvement in E&D investmentprospects, fueling increased demand for oilfieldgoods and services, will create delays and in-flationary pressure, but increasing effective oil-field activity should be less difficult and infla-tionary than it was in the 1970s. One reason forthis conclusion is that the level of activity of theearlier drilling “boom” was much higher thanwas justified by the results, primarily becausedrilling rigs were operated inefficiently, inade-quate equipment was used, and many wells weredrilled with minimal prospects for success. Thus,it is not necessary to return to 1981 levels of ac-tive rigs or employment to achieve 1981 levelsof reserve additions and added production ca-pacity. Another reason is that most oilfield equip-
ment is relatively sturdy and will not deteriorateexcessively if moderate precautions are taken i nstorage. Finally, in recent years there has beenan oversupply of trained workers and profession-als in the industry, and there is little reason tobelieve that most of these have been irrevoca-bly lost to other fields. A 2,500 rig fleet, operat-ing efficiently, probably can achieve the sameresults as a 4,000 rig fleet did in 1981. For nowand for at least another few years, there shouldbe adequate equipment and personnel to assem-ble and operate such a fleet relatively quickly—perhaps within 6 months to a year. However,this conclusion presupposes that a rebound inoilfield activity levels will be accompanied byinvestor and industry confidence that the re-bound will not be short-lived, so that contrac-tors will be willing to invest in refurbishing rigs,laid off workers will be willing to return, etc.This is not necessarily a foregone conclusiongiven the “lesson” administered by the recentprice drop. Also, the capability for a reboundwill decline over time.
Policy makers should recognize that OTA’sguarded optimism about the ability of industryinfrastructure to support a rebound in activity isnot shared either by the National PetroleumCouncil or the Department of Energy. Their re-spective reports, Factors Affecting U.S. Oil andGas Outlook and Energy Security, both identifythe destruction of the industry’s infrastructure asa key roadblock to a drilling recovery.
Resisting a Decline in U.S. OilProduction: Should Government
Play an Active Role?
For reasons encompassing both national secu-rity and U.S. economic competitiveness, manyenergy analysts and significant segments of theoil industry (especially the independent produc-ers) are arguing that the Federal Governmentshould intervene to halt or ameliorate the ex-pected decline in U.S. oil production.
The policy preferences of Federal policy makersare likely to depend on how they would answerthe following two questions:
1. Will declining domestic oil production seri-ously damage U.S. economic and nationalsecurity interests? and
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2. Can Federal intervention succeed at stabiliz-ing domestic crude oil production withoutincurring unacceptably high costs (in termsof direct consumer spending, Federal bud-get impacts, or market distortions)?
Properly addressing both of these questions re-quires a comprehensive examination of U.S. andworld energy supply and demand, not merely anexamination of domestic oil production. For ex-ample, the shift in oil trade away from long termcontracts to the spot market has served to makethe world oil market more unified. With thepresent market structure, new discoveries andproduction capabilities anywhere in the world–and especially outside of the Middle EasternOPEC nations–contribute to market stability andthus to U.S. economic and national security in-terests, Similarly, the ability of energy consumers
I to switch to other fuels, improve their efficiencyof energy use, or even shift the basic structure
i of their economies will affect their reliance onI
oil. Consequently, an evaluation of United Statest crude oil production can provide only a piece
of a larger puzzle, albeit an important piece. Inthe following discussion, we address the abovequestions in the limited fashion allowed by thebounds of our analysis.
Will Declining Domestic Oil ProductionSeriously Damage U.S. Economic andNational Security Interests?
If imports provide the least expensive sourceof oil, should we care if U.S. domestic oil pro-duction decreases and import dependence rises?Are the potential damages from rising import de-pendence large enough to justify the costs to theU.S. economy of subsidizing domestic oil produc-tion or taking other measures to restrain importlevels? This question forms the core of a seriouspolicy dispute. Unfortunately for policy makers,there are a number of substantive opposing argu-ments as well as significant uncertainties aboutthis issue.
Advocates of oil import fees and other meas-ures designed to forestall added U.S. dependenceon oil imports believe that both economic andnational security interests justify the costs of suchmeasures. They note that the drop in oil indus-try investment has hurt significant sectors of thenational economy as well as the economies of
oil-producing States such as Texas, Oklahoma,and Louisiana, and that expanded imports hurtthe U.S. trade balance. Perhaps most importantfrom an economic standpoint, they believe thatexpected increases in oil demand and decreasesin non-OPEC oil production capacity will soonreturn market control to OPEC and thus restorethe potential for future price shocks and accom-panying economic disruption. As for nationalsecurity, the industry points to the strategic im-portance of oil to the United States, both for it-self and even more for its allies, and the likelihoodthat increased import dependence will translateinto an increased vulnerability to future oil dis-ruptions.
These arguments must be balanced against thepotential negative impacts an import fee or thelike would have on the U.S. economy, as wellas arguments that the national security implica-tions of rising oil imports have been temperedsubstantially by economic and physical changesthat have occurred since the earlier price shocks.
The negative economic effects of an import feeare viewed as including an increase in the rateof inflation, a decline in gross national productresulting from reduced discretionary income, anda decline in trade competitiveness among theUnited States’ energy-intensive industries (e.g.,chemical products). Balancing negative and posi-tive impacts requires extensive, sophisticated eco-nomic analysis, with the best analyses yieldingresults that will still be highly sensitive to argu-able input assumptions.
Changes in oil markets and the U.S. economicstructure that have occurred since the early1970s, combined with certain insurance meas-ures such as the Strategic Petroleum Reserve,have likely made the United States less vulner-able than previously to future oil price shocks andsupply disruptions. For example, the growth ofa large spot market in crude oil has made em-bargoes extremely difficult to enforce and shouldact to curb the “inventory panic” that in the pastserved to escalate prices rapidly at the first signsof a shortage. Other positive changes include:
● the U.S. decontrol of oil prices, which allowsa more rapid market adjustment to changesin oil supply and prices;
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●
●
●
the increase in diversification of producingcountries, which adds stability to worldsupply;the increase in oil stocks held by Japan, WestGermany, and other U.S. allies; andthe growth of natural gas supplies through-out the world, which allows for substantialfuel-switching capability in industrial andelectric utility markets.
Although these improvements in the U.S. stra-tegic situation do not imply that growing oil im-port levels represent no threat, they do imply thatcomparisons with earlier years must be viewedcautiously.
To keep these arguments in perspective, it isimportant to understand where U.S. oil produc-tion was heading before prices dropped soprecipitously. Even before the sharp 1986 de-clines in world oil prices, most energy analystswere predicting a future of declining domesticoil production and increasing imports. For ex-ample, one so-called “consensus view” of futureU.S. production under previous price expecta-tions (prices in the mid to low $20s/bbl for a fewyears and a gradual increase thereafter) had U.S.production declining from about 8.9 mmbd in1985 to below 7 mmbd by 1995 and below 6mmbd by 2000. Therefore, the recent price dropmight be said to have advanced by 5 or 10 yearsa process of declining U.S. production that mostindustry analysts believe would have occurredanyway because of the maturity, and thus de-clining prospects, of the U.S. resource base.
Not all analysts would agree with this view. Aminority of oil analysts believe that U.S. produc-tion could have been maintained at stable levelsfor another few decades had oil prices held upand had the industry expanded its efforts to at-tain increased recovery from its older fields. Thismore positive view is based on an optimisticassessment of the remaining oil resources that canbe recovered by more intensive drilling as wellas by enhanced recovery. If correct, this view im-plies that the “cost” of the price drop to theUnited States, in terms of lost domestic produc-tion capacity, could be considerably greater thanimplied by the more pessimistic pre-price dropproduction forecasts.
Policies To Bolster U.S. Oil Production
Advocates of government action to slow thedecline in U.S. oil production have suggested avariety of potential solutions, Most involve sub-stantial present or future costs; all of these areopposed by powerful constituencies.
OTA has not undertaken the kind of compre-hensive evaluation that policy makers must havebefore deciding on a specific course of action.Although the results of OTA’s study offer a num-ber of insights about the effectiveness of specificpolicies, we were not able to measure the actualeffects on oil production of the policies nor theirnet social costs.
1. Oil Import Fees.–Oil import fees may bestructured either as a constant dolIar addition tothe prevailing price of imports or as a sliding feedesigned to raise import prices to a predeter-mined value (e.g. $25/bbl). An interesting alter-native is a price floor, deliberately set belowprices prevailing at the time of enaction, designedto guard against future price drops and thus toease the downside risk of new production in-vestments.
To the extent that an import fee raises domes-tic oil prices higher than prices that would haveoccurred without it,11 it will raise industry reve-nues and improve the prospective profitability ofnew production investments. This in turn will en-sure that oil investment and production will alsobe higher than without the fee, at least for a con-siderable period. For example, OTA’s economicanalyses show that for the small scale develop-ment and exploratory drilling prospects exam-ined, increasing oil prices from $1s to $20/bblraised expected rates of return to the levels ex-pected in 1981,12 when oilfield activity was ata peak. Such an increase in expected profitabil-ity would be bound to stimulate new oil in-vestment. However, policy makers must be con-
1 I Over the long term, an import fee might help to hold down
world oil prices by reducing the demand for Imports and thus re-ducing OPEC market dominance. It is therefore quite conceivablethat the net domestic oil price could eventually be lower than itwould have been in the absence of the fee.
1 zASSUnllng drll[lng costs would not rise. This assumption will be
reasonable only if any increase in drilling activity stimulated by theprice rise was not so large as to use up much of the current sur-plus of drilling capacity.
cerned about the cost to consumers of higher oilprices, both directly and as a result of higher man-ufacturing costs, and the effects of such highercosts on the U.S. balance of trade. In addition,because of uncertainties about the resource base,the effects of structural changes in the industry,and other factors affecting production, policy-makers cannot predict with a high degree ofconfidence how much additional productionwill be “purchased” with an import fee. Thereis little agreement in the industry as to what oilprice would be necessary to stabilize produc-tion—or whether it is even possible to do so.
Based on OTA’s conversations with industryplanners, the sharply perceived threat of futureplunges in oil prices plays an important role inindustry reluctance to invest, especially for longerterm projects. If this is so, the institution of aprovisional tax designed to establish a price floorbelow current price levels–possibly at $15/bbl—could also boost investment at no immediatecost to consumers. OTA’s economic analyses re-veal some of the potential of such a price floor.For small-scale development and exploratorydrilling, using a $10/bbl “hurdle price” to guardagainst future price risk transforms an attrac-tive prospect at $15/bbl—with a projected real(before tax) rate of return of over 15 percent—into an outright loser. Thus, for investors whofeared future price drops, a price floor couldprovide the assurance necessary to proceed withdrilling.
The perceived attractiveness of a price floor de-pends in large measure on the policy maker’s ex-pectations for future oil prices. If he expects pricesto stay above $15/bbl at most times, with occa-sional brief declines below this price, a $15 pricefloor looks particularly attractive because it re-duces risk at a low cost. On the other hand, ifhe envisions prices plunging below the floor pricefor extended periods, the consumer cost and bal-ance of trade questions may become paramount.
2. Tax Concessions.—OTA examined the ef-fects of several tax changes on the expected prof-itabiIity of small-scale driIling. These changes in-cluded reinstituting investment tax credits (of 20percent), allowing a 27.5-percent depletion al-lowance for all producers, cutting severance andad valorem taxes in half and to zero, and institut-
ing a 20-percent drilling credit. For the small-scale drilling examined, lower State taxes andadditional tax credits for Federal income taxesimproved the prospective profitability of newinvestments, with a 20-percent drilling creditand a higher depletion allowance having thegreatest effect. However, none of these meas-ures achieved nearly as much of an increase inprofitability as a $6/bbl increase in oil prices.13
For example, for the development wells exam-ined, cutting severance taxes in half addedabout 2 percentage points to the real after taxrate of return, whereas adding $6/bbl to the oilprice increased the return by between 12 and17 percentage points.
Industry spokespersons have claimed that thenew tax code will hurt the industry’s investmentcapability. An examination of this claim is beyondthe scope of this study. However, OTA did ex-amine the effect of the new code on the profitexpectations for a series of small scale explora-tion programs. Contrary to OTA’s expectations,the calculated after tax return on investmentfrom a number of small exploratory drilling pro-grams was slightly higher under the new taxcode than under the old. For these cases, thebenefits of the lower tax rates in the new codeoutweighed the loss of the investment tax credit.Were company profits low or nonexistent, how-ever, the lower tax rates would have little valueand the loss of the investment credit would havebeen the primary factor. The alternative minimumtax in the new code, not accounted for here, mayalso affect the balance of the old and new codes.
The industry has been united in its advocacyof repeal of the Windfall Profits Tax (WPT), whichwas originally enacted to prevent domestic pro-ducers from obtaining a financial windfall fromthe decontrol of domestic oil prices. Although thetax is not collected at today’s lower oil prices,it represents both an administrative burden to theindustry and a disincentive to E&D investment,especially for projects with delayed productionstarts and for investors who expect oil prices torise significantly during the production lifetime
13The reader is reminded that a fair comparison of alternative POl-icy measures requires an estimate of costs as well as results. Ideally,policies should be judged based on a measure of (productiongained) /(cost).
23
of the project. The magnitude of the investmentincentive represented by WPT repeal depends onthe price expectations of the oil companies; giventhe wide range of announced price forecasts andthe current turmoil in the market, estimates ofthe oil production potentially added by repealwiII be especialIy uncertain,
3. Removing the Ban on Oil Exports From theUnited States.– Federal law currently prohibitsthe export of Alaskan North Slope crude oil fromthe United States. The effect is primarily to forcethe shipment of Alaskan crude oil via high-costdomestic tankers to a saturated west coast mar-ket or all the way to gulf coast or east coast mar-kets. Were Alaskan oil to be shipped via lowestcost tankers to Pacific markets, the reduced ship-ping costs would yield a significantly higher netback price to the producer; additionally, reducedpressure on west coast markets would likely raiseproducer prices there as well. The Minerals Man-agement Service has estimated the prospectiveincrease in Alaskan wellhead prices resultingfrom an end to the export ban to be $2 to $3/bbl; others have estimated the increase to be ashigh as $4 or $5/bbl. Even at the lower end ofthe range, the price differential represents a sig-nificant percentage of current well head prices,because these are kept well below world oil pricelevels by the Trans-Alaskan pipeline fee (about$6/bbl) and other shipping and tax costs.
4. Bolstering Investment in R&D.—Improvingthe technology of exploration, development, andproduction is an important means by which theoiI industry can minimize the negative effects onoil production associated with continuing lowprices. As noted earlier, however, the industryhas been cutting back on R&D in line with its de-creasing oil and gas revenues. In particular, theoilfield service sector has played a major role inprevious industry R&D, yet has absorbed thebrunt of financial damage associated with theprice drop.
Research and technology development thatcould help the industry stem the production slideat low prices include:
. improved understanding of the potential foradding new reserves in older fields from con-ventional drilling;
improvement in enhanced oil recovery tech-nologies, and better understanding of howto apply them to a wide variety of geologicsituations;improvement in the resolution and cost ofseismic analyses, to allow the wider use ofpre-drilling geologic analysis, to reduce dryhole risk, and to allow better placement fordevelopment wells; andfurther development of offshore productiontechnologies that negate or moderate the re-quirement for giant production platforms.
The first three research areas might be includedin a more general program aimed at improvingthe state-of-the-art in petroleum geosciences (i.e.,improving our understanding of where the oil isin a reservoir, how it moves, and how it can berecovered).
Policies to bolster R&D appear especially attrac-tive because they are an order-of-magnitude lessexpensive than direct economic incentives forincreased production. However, policy makersmust recognize that most industry planners be-lieve that technological change can play only amodest role in stopping a production slide in theface of continuing low prices. Also, designing apolicy measure that will provide an efficient in-centive to promote effective R&D is not likely tobe easy, with particular problems being indus-try fears about losing proprietary advantages, thepotential for government direction to be out oftouch with industry requirements, and the diffi-culty of restricting the benefits of incentive pro-grams to the primary R&D objectives.
Suggested policies for bolstering R&D include:
government sponsorship of industry/univer-sity cooperative projects,allowing intra-industry cooperative projectsby granting anti-trust exemptions,direct government assistance in the form ofgrants and contract awards,government-directed research projects, andtax incentives.
5. Removing Leasing Restrictions on Frontier/Offshore Areas.–Industry groups have longurged the Federal Government to open up a va-riety of publicly owned properties to oil explora-
24
tion and development as a means of bolsteringdomestic oil reserves and production capacity.This recommendation has become more urgentin light of the recent oil price drop and its pro-jected negative impact on domestic production.Two of the primary target areas are the Califor-nia offshore basins and the Arctic National Wild-life Refuge (ANWR); both have potential recov-erable oil resources of a few billion barrels. Bothof these areas have been held from leasing be-cause of environmental objections. For Califor-nia, the primary objections involve the potentialeffects of spills on vulnerable ecosystems andhigh-value recreational areas and the air qualityproblems associated with production, transpor-tation, and other ancillary facilities associatedwith development. For ANWR, the primary ob-jection is the potential danger to the PorcupineCaribou herd and to other important species, andthe loss of the area’s wilderness character.
Arguments about opening these areas to oil ex-ploration and development center about threetypes of questions:
1. Are the estimates of environmental impactsaccurate?
2.
3.
Will development of the areas really makea difference in the United States’ long-termstrategic position vis-a-vis energy supply?Which are more important, the environ-mental values that would be preserved byforegoing development or the energy sup-plies that would be made available? IS it pos-sible to have development while protectingmost of the environmental values.
These questions have been extensively airedin the media and in reports and congressional tes-timony, and there is little OTA can add at thistime. One point worth making, however, is thatvolumes of oil obtained from these areas shouldbe compared to rates of domestic oil production,and not to total U.S. energy consumption, as issometimes done to illustrate the supposed insig-nificance of the resource. By the time areas suchas ANWR could be developed—not much before2000–oil will be even less interchangeable withalternative fuels than it is now, assuming the shareof oil used for transportation fuel or chemicalfeedstocks continues to grow.
Chapter 1
Introduction
The Origins of Today’s Low Oil Prices
In December 1985, the Kingdom of Saudi Ara-bia reversed its oil market strategy. During thefirst half of the 1980s it had been serving as the“balance wheel” of the world oil market, rais-ing or cutting back its oil production rate to re-strain or shore up prices as necessary, thus main-taining a precarious balance between world oildemand and production capacity. During thistime, however, powerful economic forces wereeroding its position. The stimuIus to oiI explora-tion and development provided by the priceboosts of 1973 and 1979 had led to large in-creases in non-OPEC oil production. From a pro-duction rate of 25.6 million barrels per day(mmbd) in 1974, non-OPEC production rose to37.2 mmbd in 1985.1 Simultaneously, the higherprices were encouraging investments in energyefficiency; behavioral changes leading to reducedoil use; and fuel switching from oil to coal, natu-ral gas, and other energy sources. Consequently,despite a worldwide rise in economic output of15 percent between 1979 and 1985, worldwideoil consumption declined by nearly 6 mmbd,2 or9 percent, during the same period.
World oil prices continued for a time on an up-ward path despite these trends, largely due to theOPEC countries’–and particularly the Saudis’–willingness to cut their production rates to reducethe downward pressure on prices. Between 1979and 1985, OPEC production was cut in half, andits oil revenues declined from $285 billion (1985$)in 1980 to $131 billion in 1985. The Saudis, hav-ing the largest oil reserves and production capac-ity in OPEC, and having a relatively small popu-lation (and thus relatively lower revenue needs),absorbed the brunt of these declines, allowingtheir production to drop from nearly 10 mmbdduring 1979-81 to 2 mmbd during the third quar-ter of 1985. Finally, however, faced with expec-
1 Arthu r Andersen & Co, and Cambr idge Energy Research Asso-
ciates, Wor/d 0// Trends: A 5tatlstica/ Profile, 1986-87 ed., tables6 and 10. Excluding natural gas Iiqulds.
‘1 bid,
tations of still further production cuts and the un-acceptable prospect of a rapid drawdown of theircapital reserves, they announced their intentionto recapture a fair market share, doubled theirproduction rate, and instituted a series of con-tractual offerings to oil buyers that gave Saudi oila competitive advantage in the market.
The immediate result was a sharp drop in oilprices as competing oil producers scrambled tomaintain their own market shares. Within 4months, the average price of oil had been cut inhalf, from approximately $28/bbl in Decemberof 1985 to $14bbl in April of 1986. From therethe price has fluctuated, dropping below $10 inJuly and rising to about $15 in September and$18 by the end of the year. And although thereis no consensus as to how prices will behave inthe short term, there is almost a universal expec-tation that oil prices for the next few decades willbe significantly lower than the prices projectedprior to the Saudi action.
Effects on the Oil Industry
The consequences of the price drop have rever-berated through the world economy: the econ-omies of principal oil exporting nations have gen-erally suffered because of sharply reduced oilrevenues, while oil importing nations are enjoy-ing the equivalent of a large tax cut. The pricesof competing energy sources have been forceddownward to compete with newly cheap oil,while production costs of energy-intensive goodsand services have dropped. Producers of high-cost oil—and particularly producers in the UnitedStates–now face prices that in many cases do notcover replacement costs for their oil, and in somecases do not even cover operating costs. Forthese producers, the price drop has brought mas-sive economic disruption and the prospects forsubstantial production declines. I n addition, thelower oil prices also appear likely to boost do-mestic oil consumption. These expected produc-tion and consumption trends will result in in-creased U.S. dependency on foreign oil, and
25
26
possibly increased vulnerability to future oilcutoffs.
Although estimates of the timing and extent ofthe expected drop in U.S. crude oils3productiondiffer, a mean value for the expected size of thedrop would likely be about 2 mmbd by 1990(from a base of 8.9 mmbd in 1985) if prices aver-age about $15/bbl. This reduction wouId be thecumulative effect of several forces. First, marginalproducing wells with high production costs willbe shut in either because revenues are too lowto pay for daily operating costs, or because thewells require expensive “workovers” that nolonger appear attractive at the low prices. Of pri-mary concern here are the several hundred thou-sand “stripper wells, ” wells producing 10 bar-rels per day (bbl/day) or less, that currentlyaccount for about 15 percent of U.S. oil produc-tion. Second, plans for many of the secondaryand tertiary recovery operations that partiallycompensate for normal production declines inolder fields will be canceled and, in a few caseswhere operating costs are high, existing opera-tions will be shut down. Third, fewer develop-ment wells will be drilled; these wells also helpmaintain field production despite normal produc-tion declines in existing wells. Fourth, a slow-down in exploration will depress the inventoryof newly discovered fields, and the developmentprospects associated with those fields, further de-pressing development well drilling in the future.And fifth, reductions in R&D expenditures willslow the development of new technologies andthe acquisition of new knowledge that in the pasthelped the industry to increase oil recovery andfind new sources of oil.
This process appears to have begun. AverageU.S. crude oil production during 1986 was 3.3percent, or 297,000 bbl/day, below 1985 produc-tion, while oil products supplied to consumersrose 2.7 percent, or 423,000 bbl/day. Net importshave risen by 24 percent or 1,007,000 bbl/day
3That is, crude plus natural gas IIquids recovered in the field, calledlease condensate. This is generally what is being referred to whenthe terms “crude oil” or “oil” production are used. “Total liquids”or “petroleum” production includes, in addition, natural gas liq-uids recovered from gas processing plants, refinery processing gain,and alcohols.
over the same period.4 Also, on a monthly ba-sis, production has dropped even more: from De-cember 1985 to December 1986, U.S. crude oilproduction dropped by 670,000 bbl/day, or over7 percents
Although the early 1980s was a boom periodin oiI drilling, exploratory drilling and other ex-ploration activity peaked as early as 1981 and de-clined rather steadily through 1985, and total oilwell completions began to slide in 1985 anddropped precipitously in 1986. Although manyanalysts view the earlier drops in activity as a nec-essary correction after a drilling boom, most viewthe 1986 drop as a virtual dismantling of two im-portant segments of the domestic oil industry, theindependent producers and the well service com-panies, that will greatly harm prospects for U.S.domestic oil production.
Among the activity declines are the following:
●
●
●
●
●
seismic crew count dropped by four-fifthsfrom its September 1981 peak to September1986;overall industry employment dropped froma 1982 high of 708,000 to 422,000 in Sep-tember of 1986; oilfield service companyemployment absorbed four-fifths of the drop,going from 435,000 to 206,000 during thesame period;unemployment of senior petroleum geolo-gists is 25 percent according to a recentAmerican Association of Petroleum Geolo-gists poll;drilling rig counts and utilization rates fellfrom 3,970 and 79 percent in 1981 to 3,105and 55 percent in 1982, to 1,976 and 45 per-cent in 1985, to about 700 and 20 percentin mid-1986—rig count has since reboundedslightly;we// completions, which peaked at about89,000 in 1981 and were still at 73,000 in1985, slid to slightly below 40,000 in 1986;6
and
4Energy Information Administration, Week/y Petro/eurn Status Re-poti, Data for Weeks Ended: Dec. 26, 1986, Jan. 2, 1987, DOE/EIA-0208(87-01 )(87-02).
‘Ibid.blndependent Petroleum Association of America, “united States
Petroleum Statistics, 1986 Final, ” and “American Petroleum lnstl-tute, Quarterly Completion Report, First Quarter 1987. ”
27
● exploration/production capital spending hasslid from about $50 billion in both 1981 and1982 to $33 billion in 1985 and then to $16bill ion in 1986. 7
To an extent, this drop in domestic oil produc-tion and industry activity levels is reminiscent ofthe production decline and drop in drilling thatoccurred in the early to middle 1970s. As showin figure 5, U.S. crude oil production had beenclimbing steadily for decades before the 1970s,and peaked at about 9.6 mmbd in 1970. Produc-tion then began a decline that lasted until 1976.in that year, however, the downward trend wasarrested by a combination of a surge in drillingactivity that slowed and eventually stopped thedecline in production the Lower 48 States, andthe onset of production from Prudhoe Bay inAlaska. Prudhoe Bay production eventually reached1.8 mmbd, almost 20 percent of U.S. oil produc-tion, by 1985. Had the 1970-76 rate of declinecontinued without abatement, lower 48 produc-tion would have been 1.7 mmbd lower in 1985than it actually was; without Alaska as well, U.S.production would have been 3.5 mmbd—morethan a third–lower in 1985 (assuming that theeffort expended in developing and producingAlaskan oil would not have been transferred else-where). Many in the oil industry point to the “res-cue” of U.S. oil production by a combination ofintensive driIling and the opening of new “fron-tier” production as a warning for the future ifactivity levels do not recover and new frontierareas are not opened for exploration and devel-opment.
Congressional Concerns
Congress has two basic reasons to be con-cerned about low oil prices. First, the reducedprices have important implications for the entireU.S. economy. Some of the implications areclearly positive, at least in the short term—the re-ductions in energy costs to both consumers andindustry, and the expected economic stimulusprovided by these reductions. Some, however,are sharply negative—the severe reductions in
7Arth u r Andersen & Co. and Cambridge Energy Research Asso-ciates, World Oil Trends: A Statistical Profile, 1986-87 ed.; and Oiland Gas journal, Feb. 23, 1987, p. 31,
Figure
1947 1951 1956 1961 1966 1971 1976 1981 1986
SOURCE: American Petroleum Institute (Energy Information Administration).
revenue streams and values of energy reservesheld by energy producers, the resulting drop ininvestments in exploration and development, andthe subsequent loss of business suffered by in-dustries servicing the producers; the damage tothe U.S. banking industry caused by the wide-spread company failures and loan defaults; thepotential loss of business suffered by industriessupplying products and services that are mar-keted primarily for their energy-conserving fea-tures; and the unemployment, loss of tax receipts,and other negative effects flowing from theseproblems, largely concentrated in a few key oil-producing States such as Texas, Louisiana, andOklahoma.
Second, to the extent that the projections ofreduced domestic oil production and increasedoil demand are correct and the United States isforced to resume high levels of oil imports frompolitically insecure sources, the current lowerprices may represent a potential threat to theUnited States’ national security as well as to itsfuture economic health. Congress clearly viewedthe high levels of oil imports of the 1970s as justsuch a threat, and responded with extensive leg-islation including programs to promote synfuelsdevelopment, tax incentives for energy conser-vation and alternative energy sources, an exten-sive energy R&D program, and the establishmentof the Strategic Petroleum Reserve (SPR). I n addi-tion, funds were appropriated to establish mili-tary forces specifically designed to deal withthreats far from established U.S. military bases,and in particular the Middle Eastern oilfields.
28
Industry advocates of strong congressionalmeasures to fight the increases in U.S. oil importsprojected to result from low oil prices have por-trayed these potential increases in precisely thesame manner, i.e., as a serious threat to theUnited States’ security and long-term economicinterests. in responding to this advocacy, how-ever, Congress must weigh the differences be-tween the U.S. energy situation in the 1970s andthe situation today,
First, the United States now has an SPR con-taining approximately 500 million barrels of crudeoil, the equivalent of about 100 days of oil im-ports at current levels. Similarly, Europe and Ja-pan have also added to their strategic storage,although not to the same extent as the UnitedStates.
Second, world oil production has become sub-stantially more diversified since the 1970s, withOPEC’s share of the world oil market decliningfrom 60 percent in 1979 to approximately 35 per-cent today, For several years, at least, no singlecountry or cohesive group of countries can con-trol as large a share of the world market as waspossible previously. Eventually, however, if oilprices remain below $20/bbl, OPEC may regainits previous market share.
Third, a considerable portion of any increasein oil consumption both in the United States andin the remainder of the Free World will be re-versible. For example, much of increased oil usein transportation will involve changes in con-sumer behavior, such as increased driving, thatwould be quickly reversed in case of an oil short-age or large price increase. I n the industrial sec-tor, the shifts to oil for a boiler fuel can be rap-idly reversed with a shift back to coal or naturalgas. Similarly, in the electric utility sector, a sub-stantial portion of any increased oil use is likelyto involve the use of existing oil-fired generatingcapacity—removed from baseline service whenoil prices rose in the 1970s—at the expense ofcoal, gas, or even nuclear plants. As long as theindustry retains excess generating capacity, thisuse can be readily reversed,
A threat to reversibility is the potential for in-adequate supplies of natural gas resulting fromthe same drilling slowdown acting to reduce oil
production. This potential is a realistic possibil-ity only in the United States. There is consider-able controversy about U.S. gas supply adequacyfor the future. Some analysts are projecting animminent market tightening within just a fewyears if gas prices stay low, followed by supplyproblems as domestic production capability con-tinues to decline. Others claim, however, thatsuch a shortage is extremely unlikely, becauseadditional large volumes of gas can be madeavailable rapidly if markets tighten, by increas-ing import levels and by developing reserves nowkept out of the market by low demand.
Fourth, the United States and its allies haveundergone two major price shocks in the recentpast, and this additional experience, as well asa series of international agreements on oil shar-ing, may assist them in a future supply crisis.Many oil experts are skeptical about the useful-ness of these agreements, however.
Fifth, U.S. oil prices are no longer controlledas they were during the 1970s. In the event ofa new price increase, the market forces that actto reduce demand and increase supply will befelt in full (assuming price controls are notresumed).
Sixth, most of the world’s oil trade now oper-ates on the spot market, in contrast to the long-term contracts of the 1970s. Coupled with an ac-tive futures market, this new oil trading situationmakes single country embargoes, which couldnever be airtight even in the past, still less of athreat.
These mostly positive changes in the world oilmarket do not negate arguments that UnitedStates security can be threatened by an increasein oil imports, but they clearly lessen the overallrisk and should be carefully considered in anypolicy debate.
The OTA Study
In April, 1986, the Chairmen of the Commit-tee on Government Operations, the Committeeon Energy and Commerce, and the Subcommit-tee on Fossil and Synthetic Fuels of the U.S.House of Representatives asked the Office ofTechnology Assessment to assess “the effect of
29
volatile oil prices on short- and long-term domes-tic oil production . . . (including) an examinationof changes in the industry that have already oc-curred . , . and an evaluation of the significanceof these changes to domestic production.”8
OTA’s approach to this assessment explicitlyacknowledges the high degree of uncertaintyassociated with attempting to project future do-mestic oil production. One cause of this uncer-tainty is that much of the data on the explora-tion and development opportunities available tothe industry—a crucial determinant of its futurebehavior and thus of future production potential—is held closely by the individual oil companies.Another cause is that most of the projectionsavailable to the public are based on extrapola-tions from past experience . . . but there has notbeen a rapid decline in oil prices within the pastseveral decades. It seems reasonable to questionwhether the statistical record, amassed during aperiod of escalating prices, is sufficient to fore-cast the future actions of the oil industry and thelikely effects on production of these actions.
Consequently, OTA has not tried to produceyet another forecast based on extrapolation. ln-
‘Letter of Apr. 17, 1986, Jack Brooks, Chairman, Comm Ittee onGovernment Operations, U.S. House of Representatives, to Dr. JohnH. Gibbons, Director, OttIce of Technology Assessment.
stead, we have exam ined and attempted to gainan understanding of an array of factors that willinfluence future production, with the dual goalsof, first, determining how production outcomesmay differ from those predicted by extrapolatingfrom past experience, and second, determininghow government action might influence futureproduction rates. The factors we examinedinclude:
●
●
●
●
●
●
●
changes in industry business strategies andcapabilities associated with the restructuringthe industry has undergone;the profit potential of the array of explora-tion, development, and production pros-pects available to the industry;the physical nature of the oil resource base;changes in the climate for oiI and gas invest-ment overseas;the deterioration of the industry’s servicesector;the surplus of natural gas deliverability; andchanges in exploration and developmenttechnology.
While OTA could not comprehensively analyzeeach of these factors and reliably determine theirexact effects on future production, it is hopedhope that this study will contribute significantlyto Congress’ understanding of—and ability to re-spond to—the evolving domestic oil supply sit-uation.
Chapter 2
Projections of U.S. Crude Oil Production
Introduction
projections of future United States crude oilproduction are made by a variety of oil compa-nies and associations, consulting firms, govern-ment agencies, and individuals. Although severalprojections are published on a regular schedule
(i.e., those of the Gas Research institute, theEnergy Information Administration, Data Re-sources Inc., Chevron, Conoco, etc.), many ap-pear only at crisis points or in response to pro-posed government initiatives affecting oil supply.Documentation of the projections is often incom-plete or nonexistent, although the projections ofthe Energy Information Administration, the GasResearch Institute, and Data Resources Inc. areextensively documented.
OTA examined and cataloged the results ofa number of projections of future crude oil sup-ply published either in 1985, prior to the pricedrop, or well enough after the price drop to rep-resent a first guess at the long-term consequencesof lower world oil prices. OTA did not attempta detailed analysis of the methodologies or as-sumptions of the projections, though the meth-odologies of many of the major models havebeen scrutinized in the past.
We caution the reader to be skeptical of theprojections, even those made with sophisticatedmodels. Both the simple and the complex pro-jection methods generally rely on extrapolationfrom past trends to produce estimates of such im-portant variables as the number of wells drilledi n a given year. A common source of error forthese methods, then, is to force them outside therange where past trends can be hoped to apply.The United States has just undergone a periodduring which oil prices, a key determinant of in-dustry activity, have undergone a severe dislo-cation, and one in the opposite direction frompast dislocations. Also, during the past few years,several companies comprising a large segmentof the industry’s reserve replacement capabilityhave been restructured, merged with other com-panies, or been the object of takeover attempts,
All these changes have serious implications forindustry capabilities and business strategies. His-torical relationships between industry investmentbehavior and economic variables such as inter-nal cash flow may be inapplicable to the presenteconomic environment. Finally, the period of theearly 1970s to the beginning of the 1980s—whenmany of the relationships used by the forecast-ing methods were defined—was a period of ex-tremely rapid growth in activity accompanied byhyperinflation in the costs of drilling and otherfactors of oil production. It appears unlikely thatthese relationships will prove stable.
Projections of U.S. Oil ProductionMade Prior to the Price Break
To keep the recent, very pessimistic forecastsof future U.S. oil production in perspective, it isimportant to note that a future of declining do-mestic production and increasing imports waswidely predicted even before the sharp 1986 de-clines in world oil prices. In 1985, a majority ofanalysts expected oil prices to remain between$20 to $25 per barrel for a few years and thenbegin a gradual increase, in real terms, back toand beyond $30 (in 1985 dollars) by 2000. Ac-cording to the Chase Manhattan Bank, a consensusview of future U.S. production u rider these con-ditions would have crude oil production declinefrom about 8.9 million barrels per day (mmbd)in 1985 to below 7 mmbd by 1995 and below6 mmbd by 2000 (see table 2). Although threeof the four other prominent forecasts in table 2are considerably more optimistic than Chase’s,all forecasts project declines from 1985 produc-tion levels of at least 1 mmbd by 2000 and 2mmbd by 2010. Coupled with expected declinesin natural gas liquids production and increasesin oil demand, large increases in U.S. oil importsseemed inevitable.
As discussed later, there are alternative viewsof the oil resource base, and the potential of newtechnology to access greater portions of that base,that lead to more optimistic assessments of fu-
31
I
32
Table 2.—Projections of Future U.S. Oil Production, 1985 Outlook
Projected crude plus condensate production(mmbd)
Source 1990 1995 2000 2010 Price expectation (per barrel)1. DRI . . . . . . . . . . . . . . . . . . . . . 8.60 6.81 5.66 Price to $20 (1984 dollars) by 1987,
stays there until 1994, up to $30 by2000.
2. Chevron. . . . . . . . . . . . . . . . . 8.30 7.60 7.60 6.90 Prices stagnant until 1990s, then rise.3. Chase “Consensus” . . . . . . 8.31 6.96 5.71 NA Price drops to low $20s (1985 dollars)
by 1990, rise 0.9 percent/yr to 2000,real 2000 price below 1984 price.
4. EIA Energy Outlook . . . . . . 8.05 6,53 NA NA Price dips but is at $27 (1985 dollars)by 1990, $30 by 1995.
5. GRI Baseline . . . . . . . . . . . . 8.46 8.18 7.76 6.79 Price dips but is up to $32 (1984dollars) by 1995 and $38 by 2000.
a1985 production was 8.92 mmbdNA = Not available
SOURCES 1 Errergy Review, winter 1985.2 Economics Department, Chevron Corp , kVor/d Energy Out/oo/r, June 1985 3 Chase-Manhattan Bank, Global PetroleumDwlsion, Wor/d 01/ and Gas 1985, August, 1985.4, Energy Information Administration, Annual Energy Outlook 1985, DOE/ElA-0383(85), February 1986 5 GasResearch Institute, Base/fne Projection Data Book 1985 G/?/ Elase/ine Project/on of U S Energy Supp/y and Demand to 2010.
ture U.S. oil production potential. These viewsfocus particularly on the continued potential forthe growth of reserves in the United States’ olderfields through both conventional drilling and, viaimproved technology, through enhanced oil re-covery methods. These views, and the expecta-tion that U.S. production could have been main-tained for several more decades had prices notdropped so precipitously, are definitely minor-ity positions. Nevertheless, the uncertainty asso-ciated with the resource base and the potentialfor technological innovation easily encompassessuch alternative views.
Recent Projections of U.S. OilProduction Assuming Continued
Low Oil Prices
Short-Term Projections
Table 3 presents 10 alternative views of thelikely magnitude of U.S. oil production during thenext 2 to 3 years. Few in the industry expectedlarge reductions in annual oil production by 1986,primarily because the adverse effects of reduceddrilling of exploratory and development wellswould just be surfacing, and because it was felt
Table 3.—Recent Short-Term Projections of U.S. Oil Production at Low Prices
Projected crude plus condensateproduction prices (mmbd)
Source 1985 1986 1987 1988 Prices1. Stolz . . . . . . . . . . . . . . . . . . . . . . . . . . 8.9 7.72. API . . . . . . . . . . . . . 8 $153. API . . . . . . . . . . . . . . . . : : : : : : : : : : : : 7.1 $104. EIA . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.73 8.52 $10 by third quarter 1986, $15 by summer 19875. Spears . . . . . . . . . . . . . . . . . . . . . . . . . 7.96. CWW . . . . . . . . . . . . . . . . . . . . . . . . . . 8.35 7.83 $157. ARCO . . . . . . . . . . . . . . . . . . . . . . . . . . 8 7 “low prices”8. Chevron . . . . . . . . . . . . . . . . . . . . . . . . 7.69. DRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.75 8.5 $15-$16
10. IPAA . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.8 8.5SOURCES: 1 Earl Stolz, of Howard, Weil, Labouisse, Friedrichs, reported In P/aft’s Ollgrarn Arews, Friday, Sept. 5, 1988 2, American Petroleum Institute, Two Energy
Futures. Nationa/ Choices Today for the 19S0s, July 1988 (1990 production actually for 1991). 3. Energy Information Administration, Short-Term Energy Out/ook,Ju/y 1986, DOE/EIA-0202(88/3 Q). 4. John Spears, Spears ii Associates, Inc., reported in Oi/ and Gas Journal Alewsletter, July 28, 1986 5 Jack L. Copeland,Copeland, Wickersham, Wiley & Co., Inc., Presentation to the Keystone Energy Futures Project: Liquid Fuels Policy, July 14, 1988.6. Robert 0. Anderson,ARCO. 7. Economics Department, Chevron Corp., World Energy Outlook, June 1986 8. Data Resources, Inc., Energy Review, summer 1988.9 IndependentPetroleum Association of America, “Report of the IPAA Supply and Demand Committee Annual Meeting—Dallas, TX, Oct. 26-28, 1986. ”
33
that most operators of marginal wells would beunlikely to stop production this soon. For manymarginal wells, reservoir characteristics dictatethat a prolonged shutdown of production willdamage future production potential; for others,stopping production will violate lease terms andresuIt in lease forfeiture. The great majority ofoperators with wells of this type will hesitate be-fore “shutting in” production because this wouldbe essentially abandoning their investments.Thus, the production projected to be lost by year- end
•
●
●
1986 was expected to largely be from:
marginal wells requiring immediate expen-sive repairs,the modest number of uneconomic wellsand enhanced recovery operations that couldbe shut in without losing the well or thelease, anda small number of marginally economicoperations whose owners believed that aprice rebound was inevitable and thereforedecided to forego small current profits forlarger future profits.
The actual 1986 average production, estimatedat year end 1986, was about 8.67 mmbd, downabout 3 percent from 1985’s average productionrate. However, the daily rate at year end 1986had sunk considerably below the average, toabout 8.35 mmbd, or nearly 8 percent below therate a year earlier.1
The projections for 1987 show more stronglythe effects of the expected slowdown in drillingand resuIting failure to compensate for naturalproduction declines in existing wells. These pro-jections show a very wide variation. This is par-
tially a function of assumed price; the API pro-jections show a 900,000 barrel per day (bbl/day)production loss in going from a $15 to a $10 perbarrel oil price. Another potential reason for thevariation is a disagreement about how much strip-per well production and other marginal produc-tion will be shut in, primarily because the avail-able database on the physical and economiccharacteristics of these wells is too weak to al-low reliable projection of production losses.
Both the 1986 and 1987 projections wouldhave been somewhat more pessimistic withoutwidely expected increases in Alaskan oil produc-tion. Despite cutbacks at the Milne Point field,increased flows from the Kuparuk River field andthe Lisburne reservoir of the Prudhoe Bay fieldwere expected to yield 1.6-percent increases inAlaskan production in both years.2
Longer Term Projections
Table 4 shows 12 recent projections of longerterm U.S. oil production. If the two projectionswith somewhat higher price tracks (GRI a n dChevron B) are set aside, there is a strong con-sensus among the forecasters that a continuationof low oil prices will drive U.S. oil production,which was about 8.9 mmbd in 1985, to 7 mmbdor below by 1990. Coupled with expected dropsin natural gas plant liquids production—the GRIprojection, assuming moderately higher prices,expects a drop of over 400,000 bbl/day by 1990—these forecasts project total U.S. liquids produc-tion to drop by well over 2 mmbd by 1990. Incomparison, none of the pre-price break projec-tions (table 2) show expected production declinesabove 1 mmbd, and most expect a decline ofabout half that amount.
2Energ} Intorrnatlon Admlnl\tratlI)n $hon Tt’rm fn(,r,q~ ( hJt/{JOL /u/\ / ~H(JD[)E ‘E IA-0202 (86/3 Q), August 1986
34
Table 4.—Recent Projections of Future U.S. Oil Production at Low Prices
Projected crude oil production(mmbd) Price expectation
Source 1990 1995 2000 (dollars/bbl, 1986 $)
1. DRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.8 6.3 5.5 $20 by 1995, $30 by 20002. Chevron . . . . . . . . . . . . . . . . . . . . . ..5.9-6.9 $10 to $15 thru 1987, $18-22 by 20003. API . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2 constant $154. CWW . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1 $155. Unocal . . . . . . . . . . . . . . . . . . . . . . . . . 6-6.5 $13.506. Amoco . . . . . . . . . . . . . . . . . . . . . . . . . 6.7 4.5 “Low Price”7, Fisher. . . . . . . . . . . . . . . . . . . . . . . . . . 6.8 $158. Conoco A . . . . . . . . . . . . . . . . . . . . . . 7 5.5 3.5 <$12 thru 1995, $20 in 20009. Conoco B . . . . . . . . . . . . . . . . . . . . . . 7.8 6.9 6.1 <$20thru early 1990s, $20 in 1995, $26 in 2000
10. GRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.3 5.4 5.0 $12 in 1986, $14 in 1990,$21 in 200011. NPC . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1 5.7 4.5 $12 in 1986, $14 in 1990,$21 in 200012. DOE . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.9 5.2 $14-16 thru 1990,$21 in 1995SOURCES: 1. Data Resources, inc. Energy Review, summer 1986 2. Economics Department, Chevron Corp, Wor/dEnergy Out/ook, June 1986 3. American Petroleum
Institute, Two Energy Futures: Nationa/ Choices Today fortfre f9$Ms, July 1986 (199) production actually for 1991) 4 Jack L. Copeland, Copeland, Wickersham,Wiley A Co., Inc., Presentation to the Keystone Energy Futures Project” Liquid Fuels Policy, July 14, 1988.5. Fred L. Hartley, Unocal Corp., “The High Costof Low-Priced Oil, ” submitted to the U.S. Senate Energy and Natural Resources Committee, Mar. 20, 1986.6. Economics Department, Amoco Corp., WorldEnergy Outlook, Apr. 30, 19S8. 7. William Fisher, Bureau of Economic Geology, University of Texas at Austin, Testimony to the Fossil and Synthetic FuelsSubcommittee, Energy and Commerce Committee, Mar. 6, 1986 8. and 9. A Coordinating and Planning Department, Conono Inc., World Energy OutlookThrough 2000, September 1986 10. Gas Research Institute, submission to the National Petroleum Council’s Survey of U.S. Future Oil and Gas Outlooks11 Nattonal Petroleum Council, Factors Affecfiog U.S. Oi/ and Gas Outlook, February 1987 12 U S Department of Energy, Energy Security A Reporf tothe Presfderrt of fhe Unifed States, DOEK-0057, March 1987
Chapter 3
International Oil Prices:Where Are They Going?
History
The two surges in oil prices that marked the1970s shocked a generation of oil company ex-ecutives and analysts who had known decadesof oil price stability. Many—though certainly notal l—of those same executives and analysts wereshocked again by the sharp price drop of 1985to 1986. The surges convinced most observersthat the world was entering an era of energy scar-city, and touched off an expensive search foralternative energy sources and a new round ofgovernmental intervention in energy markets.The price drop has served to remind us, however,that oil is a commodity, albeit one whose con-centration of low cost reserves in the Persian Gulfestablishes some real potentials for price manipu-lation . . . and, like other commodities, it mayundergo periods of rapid price movements in ei-ther direction.
The era of stable prices that preceded the firstprice shock–l 935 to 1972–was a reflection ofcontinuing intervention in the marketplace byboth State and Federal forces and the major oilcompanies, with the Texas Railroad Commission(TRC) playing a critical role. The United States’leverage on the world market was made possi-ble by the dominant role played by Texas andthe United States Gulf of Mexico in world oil pro-duction during this period. In 1951, for example,world crude production was 4.3 billion barrels,of which 2.2 billion barrels, or 52 percent, wassupplied by the United States. Texas’ productionof 1 billion barrels was 45 percent of the UnitedStates and 24 percent of the world’s production.(In comparison, Saudi Arabia in its peak year pro-duced only 17 percent of the world’s oil.) Usingthis leverage, the TRC controlled the amountproduced by Texas producers (through “pro-rationing”) and, along with similar actions byother producing States and with Federal importrestrictions, was able to balance domestic sup-
ply and demand and maintain a stable domesticprice. A stable price in the United States, in turn,meant a stable world price.
For this to work, the TRC needed cooperation.Texas producers and property owners had to ac-cept a stable price as adequate compensation forsometimes operating their best welIs at less thanhalf capacity. In addition, the other major UnitedStates producer States needed to be supportivein their own State policies. And finally, the ma-jor companies that dominated the rest of theworld markets had to honor the status quo intheir behavior.
In the period 1930 to 1970, the United Stateshad a substantial surplus production capacity; inthe last two decades of the period, the surpluswas as high as 2 million barrels per day. in addi-tion to the older major fields still producing inCalifornia, Kansas, and Oklahoma, there were thelater, major discoveries that stretched from WestTexas to Southern Louisiana, including the hugeEast Texas field (discovered in 1931). In the ab-sence of restrictions on production, the price warsthat were triggered by the discovery of East Texaswould have continued until the excess supplyhad been absorbed by the financial exhaustionof the industry.
Despite these four decades of relatively stableoil markets, the long-term history of oil has beenone of price volatility. Even with the inclusion ofthe Commission’s 37 year reign, the real priceof oil has swung up or down by an average ofabout 20 percent per year during the 125-yearperiod of U.S. oil production.1 More importantly,the slow but sure response of oil supply and de-mand to prices tended to guarantee that periodsof scarcity and high prices would be followed byperiods of oversupply and falling prices, and viceversa.
‘A. R. Tusslng, “How To Think About Energy Prices, ” Society ofPetroleum Engineers Paper No. 13193, 1984.
35
36
In retrospect, the price increases in the 1970sand the subsequent price decline and then freefall can be easily explained. In the decade or twoprior to the Arab Oil Embargo and the first priceshock, oil’s ready availability, low price, and con-venience had won it a rapidly increasing shareof the world’s energy consumption: from a 28-percent share of primary energy consumption in1950, oil had risen to a 43-percent share by 1968.The rapidity of oil’s rise in consumption and theabsence of apparent supply problems had ledoil-importing nations to ignore the fact that theirconsuming sectors had little fuel flexibility in theshort term. With OPEC, and specifically the Per-sian Gulf nations, producing a large share of theoil in international trade, the importing nationswere vulnerable to any artificial manipulation ofsupply. As a consequence, when the Persian Gulfnations wrestled control from the United Statesoil companies and prices began to rise in re-sponse to their manipulation of supply, the im-porting nations attempted to secure assured sup-plies by competing among themselves, thus furtherdriving up prices.
Over the long run, however, the resulting re-straint in demand and the increase in supply, nat-ural consequences of a quadrupling of price, cre-ated an oversupply that OPEC could not manageand drove the price right back down. For exam-ple, although in the early 1970s the demand foroil seemed to display little response to the higherprices, 2 between 1979 and 1985 world oil con-sumption declined by 7 mmbd (13 percent) whileeconomic output rose 15 percent. Oil’s share ofworldwide primary energy consumption droppedto 45 percent from 55 percent. Although a sub-stantial part of this decline came from greaterefficiency in use, much of it represented a shiftto cheaper energy forms: at prices above $20 perbarrel, oil often found itself at a competitivedisadvantage against alternative fuels–such ascoal—in
markets for electric-utility and industrial boilerfuels, cement and brick making, distillation ofwater, alcohols and petroleum itself, metallurgy,the drying of materials, and every other applica-tion where the object of demand is raw calories.3
At the same time, there was an explosion ofsuccessful oil exploration and accelerated devel-opment of previous large discoveries which re-sulted in stabilization of or actual increases in pro-duction among the mature producing regions,such as the United States Lower 48 and Mexico,and the opening up of major new provinces suchas the North Sea. Non-OPEC production, 26mmbd in 1974, had surged to 37 mmbd by 1985.Coupled with the reductions in worldwide de-mand, the new production forced OPEC into dra-matic cutbacks in its own production—a 50 per-cent reduction between 1979 and 1985—to propup prices. Saudi Arabia, which bore the brunt ofthe cutbacks, had seen its production drop to 2.2mmbd from a peak of about 10 mmbd. The even-tual Saudi reaction to the drastic reduction in itsrevenues was its late 1985 doubling of produc-tion to 4.5 mmbd coupled with enactment of at-tractive “netback” deals4 to consumers to assuresales. These actions caused an almost immedi-ate collapse of worldwide oil prices. This seems,in retrospect, an almost inevitable conclusion tothe pressures caused by the 1979 to 1980 pricehike and the radical changes in oil supply anddemand that had been set in motion 10 yearsearlier. And although the first half of 1987 hasseen oil prices firm and rising back above $20/bbl,the potential for renewed price instability and arepeat of 1986 price levels is now an accepted“fact” in the industry.
Alternate Projections ofFuture Oil Prices
Before the strong upward price movement inmid-1987, there were a wide range of projectionsof future oil prices, but with a central theme towhich many oil analysts appeared to subscribe:that oil prices would undergo a fairly brief periodof instability around a relatively low mean price(perhaps $1 S, or possibly as high as $18 to $20),ranging in length from a year to perhaps 5 or 6years, and would then begin a moderate althoughnot inconsequential rise. The uncertainty in thetiming for a settling down of prices was based pri-marily on differing estimations of the potential fora successful and sustainable production agree-
Zln the LJnited States, price controls masked the price increases.3A, R. Tusslng, “Oil Prices Are Still Too High, ” Energy /ourna/,
VOI. 6, No, 1.
‘A “netback ” deal ties the price of crude to the sales price ofrefined products, effectively guaranteeing to the refiner a minimumprofit margin on product sales.
37
ment in OPEC. A shorter time period was basedon the thesis that OPEC members would soonsee the strong self interest in reining in produc-tion and profiting from the resulting higher priceseven at decreased sales volumes. A longer inter-Iude of instability presumed that such an agree-ment must wait until increased worldwide demandand a significant decline in non-OPEC produc-tion, both in response to the lower prices, tight-ened the market. A tighter market would in turnallow an agreement to succeed with only mod-erate production cutbacks required among thoseOPEC members who traditionally have found itdifficult to stay within their allowable productionlevels. The gradual rate of increase was based onthe assumption that OPEC’s, and primarily SaudiArabia’s, goal is to stabilize the market and main-tain price levels that allow high production profitswithout stimuIating excessive competition or sti-fling demand.
Two other price projections had a number ofadherents. The first presumed that prices wouldstay low—at or below $1 5—long enough for highercost production to be severely damaged or evencrippled and for oiI demand to increase substan-tially. At this time, prices would soar back to orabove 1981 peak levels. These projections gen-erally presumed a Saudi strategy of crippling itshigh cost competition; alternatively, an ascen-dance to OPEC power of the price “hawks,” Iedby Iran, would do equally well as a baseline as-sumption for this scenario.
The second projection foresaw an indefinitecontinuation of price instability, with prices cy-cling about both short term events (rumors, wars,temporary production cutbacks) and long termsupply and demand trends responding to changesin mean price levels. The long term cycling wouldgenerally fall inside the $10 to $20 range in to-day’s dollars, in line with the long term averageprice of oil over most of its history; shorter ex-cursions considerably above and below this levelare possible and probable. This projection isbased on the conclusion that oil is essentially acommodity and will follow the same unstableprice paths followed by most other commodities.The $10 to $20 range is based on the loss of sub-
stantial production capacity below $10 and thelarge fuel substitution and conservation poten-tial above $20.5
Notwithstanding the recent apparent return toa semblance of price stability, these alternativeviews of future prices still demand attention. I nthe absence of a functioning and effective institu-tional control of prices, the history of oil priceprojections has been one of abject failure. Forexample, a recent report6 concludes that, dur-ing the last decade and a half, there has been asuccession of strong consensuses about futureprices, each clearly based on an extrapolation ofprice trends of the immediate past, and eachdead wrong. Thus, the history of oil prices im-plies that policy makers would be unwise to ac-cept the price path of the past six months as aforerunner of future prices. Also, if the “centraltheme” described above actually does representa general consensus among oil analysts, a pru-dent businessperson or government executiveshouId still hesitate before using it as a planningtool. Additionally, there are substantial reasonsfor industry spokespersons to be circumspectabout their true beliefs, including competitivepressures and ongoing legislative initiatives withimportant implications for future industry profits.
The petroleum industry’s investment decisionprocess is guided to a considerable degree by itsfuture price expectations and the potential forprofits they imply.7 A reasonable way to guessindustry’s true belief about future prices is to ex-amine its behavior, although interpreting recentbehavior is difficult because the past several monthsand the coming year or so represent a transitionperiod with a high “noise” component. Never-theless, drilling costs are now quite depressed,and the potential profit from many longer termprospects would be very high it oil prices wereto rebound near the time when production could
~For a more detailed examination of future price trends, see J.J.
Schanz, Jr. and L.C. Kumins, The Many Faces ot 0//, Congres\lonal
Research Service Report No. 86-1 36S, July 24, 1986.bThe Future of Oil Prices: The Perils of Propheq, D. Yergl n, J.
Stan islaw, B. Kates-Garnick, and I C. Bupp, Cambridge Energ} Re-search Associates and Arthur Andersen & Co., CERA 497-6446,1984.
‘Although declslons about the oierall magnitude of spending de-pend as well on capital aiallability, and particularly on the indus-try’s Internal cash flow.
38
be brought on line. Despite this, the industry hasbeen showing lessened interest in drilling forprospects that have a delayed prospect, as dem-onstrated by the drop in exploratory drilling off-shore. Consequently, this may indicate that mostproducers are not confident that prices will in-crease significantly within a few years, and per-haps not even within 5 or 6 years. Unfortunatelyfor the reliability of this conclusion, however, theindustry’s investment behavior is also a responseto its recent poor cash flow and earnings, whichwould tend to focus investment onto projectswhich can add quickly to cash flow.
Determinants of Future Oil Prices
An examination of the factors influencing cur-rent and future oil prices shows a mixed picture
with regard to pressures for high or low pricelevels. In general, arguments for a future of highoil prices focus on the immediate depressing ef-fects of low prices on oil and gas exploration anddevelopment and subsequent expected declinesin future supply, the likely increases in oil de-mand in response to current prices, the tremen-dous financial incentives for OPEC nations to co-operate with one another in limiting production,and finally the concentration of basic oil re-sources within OPEC and especially within thePersian Gulf. Arguments for continued low prices,or for instability centered around a low pricelevel, focus on the entrenchment of oil use effi-ciency in the economy, the availability of cheapersubstitutes for oil, especially natural gas, at pricesabove $20, the low marginal production costsand low replacement cost for much of the world’s
Table 5.— “Why Oil Prices Will Remain Low”- Arguments Used by Forecasters of Low Future Oil Prices
1.
2.
3.
4.5.
6.
7,
The current worldwide excess of producing capacity islarger (absolutely and relative to consumption) thanduring the late 1960s and early 1970s, and the worldwideReserves to Production ratio is just as high.The diversification of major oil producing countries isconsiderably greater than when OPEC established marketcontrol. In addition, the concentration of commercialcontrol in a few multinational firms no longer exists.Natural gas, given its availability, can readily substitutefor more than half of world oil use, and can potentiallysubstitute for much of the rest. Also, availability isbecoming less of a problem. Natural gas resources andproducing/distributing capacity have exploded since theearly 1970s. Since 1973, global gas reserves haveincreased by the energy equivalent of 30 years of OPECoil production. The United States has gone from appar-ent shortage to surplus, Europe’s available supply hasexploded, and West Africa and the Middle East candisplace oil in space heating, industry, and electric gen-eration if delivery systems can be built.Coal capacity and delivery systems are in surplus.A large percentage (some say more than half) of theexisting fossil electric generating capacity—and virtuallyall of the new capacity—has dual fuel capacity.Despite current low prices, oil consumption still is likelyto stagnate because oil intensity is controlled by thereplacement of facilities and equipment and the substi-tution of goods and services . . . and this will continueto be in the direction of the less efficient to the moreefficient, and more oil intensive to less oil intensive. Thistendency will be reinforced by consumer skepticismabout the stability of low oil prices.Contrary to conventional wisdom, world oil productioncapacity is not likely to decline dramatically in the faceof lower oil prices; it may even be able to increase overtime. In the past, higher prices had the perverse effectof depressing investment in new capacity in low costareas, where most of the world’s known reserves occur.At lower prices, these nations will be more likely to seek
8.
9.
10.
11.
12,
to increase capacity in order to maintain revenues. (Likelycandidates for expansion include Kuwait, Iraq, Mexico,and Saudi Arabia) Also, initial declines in drilling havespurred many current and prospective producing coun-tries towards greater flexibility in their dealings with oilcompanies, and this should lead to expanded investment.Also, the costs of replacing oil and gas reserves havefollowed prices down, primarily because many of thesecosts were inflated during the drilling boom and are nowat distress levels. The production levels in the so calledhigh-cost regions will not suffer as much as is supposedas investors become better aware of the new cost/pricerelationships.Oil prices do not occur in a vacuum, and oil will not readilyrecapture the markets it lost when oil prices soared,because prices for natural gas and coal will follow oilprices down in order to compete and retain the marketsthey now have.Importing nations are in a far better position now thanin the past to beat down attempts by OPEC to create arti-ficial shortages and raise prices. In particular, strategicreserves and agreements on oil sharing will serve asbuffers. In addition, past experience has taught theimporters some important lessons about strategic behav-ior, especially about the futility of seeking to attain uni-laterally assured supplies at the expense of other nations.Nor will they, given the uncertainty about price behavior,be willing to risk too much on a dependency on low oilprices as a permanent condition.Arguments about declining supplies ignore the strong po-tential for new technologies and expanded knowledge.For example, producers are likely to push developmentof new cost-saving technologies to allow them to pros-per in a low-price environment.The 1973 to 1985 period was an anomaly as far as oilprices are concerned; during the entire 125-year periodof oil production, prices averaged less than $15 in today’sdollars. Thus, $15/bbl or less is likely to be the world long-term oil supply price.
39
Table 6.— “Why Oil Prices Will lncrease”-Arguments Used by Forecasters of
High Future Prices
oil, and the historic inability of cartels to sustainhigh prices. Tables 5 and 6 summarize the argu-ments for low and high oil prices.
1. Past successes in exploration provided the Middle Eastwith known oil reserves, both developed and undeveloped,well beyond the immediate needs of this region given theircurrent rate of production, Outside of the Middle East, onthe other hand, there is little excess production capacityand far less undeveloped reserves. This imbalance in bothpresent and future production capacity, coupled with theworldwide slowdown in exploration and developmentcaused by current low prices, and with the dominance ofthe Middle East in undiscovered resources, will leadinexorably to a resumption of OPEC market control and,subsequently, to higher prices.
2. Oil demand is bound to increase during a period of lowprices, planting the seed of future market tightening. Al-though the demand increase will not mirror the decreasecaused by high prices, any expectations that our interestin energy efficiency and other energy savings is “lockedinto” the energy system are as incorrect as were pastexpectations that high levels of growth in oil demand wouldcontinue despite high prices.
3. Low prices have already begun to stifle oil production in
4.
5.
6.
—
high cost areas; failure to continue intensive explorationwill result in substantial losses in worldwide producing ca-pacity within a few years.An increase in demand for OPEC oil of only about 5 mmbdcaused by demand growth and loss in non-OPEC produc-tion capacity (or drop in production in cooperation withOPEC) would restore OPEC’s leverage in its efforts to in-fluence world oil prices.Expectations that the availability of natural gas as asubstitute boiler fuel will provide a buffer to oil priceincreases ignore the likely declines in gas productioncapacities as a result of the overall slump in drilling, espe-cially in the United States, and, elsewhere, the difficulty—and great expense—of building the gas transmission in-frastructure needed to allow effective competition with oil.The incentive for OPEC nations to manipulate production—i.e., the potential to maximize revenues over time becauseprice increases can be balanced against lower sales vol-umes—is sufficiently high, and sufficiently well under-stood, to eventually lead to a higher level of cohesion andcooperation within OPEC.
Clearly, these differences in the alternativeviews of future oil prices are based in large parton differences in judgments made about the re-sponse of supply and demand to price, as wellas on the expected actions of major players suchas the OPEC nations. The major uncertainties i nthe direction that future prices will take are thefollowing:
1.2.
3.
4.5.
the response of oil demand to lower prices;the possibility of increases in production ca-pacity in the low cost oil regions8;the uncertainties in OPEC actions, based onuncertainties about the underlying motivesof the Saudis, if any, the potential for the“hawks” to gain control of OPEC and toseek higher prices immediately, and the abil-ity of the OPEC nations to maintain produc-tion discipline;the potential for new oil disruptions; andthe future levels of non-OPEC production,including the uncertain ability of supposedlyhigh-cost oil producing regions to find an an-swer to maintaining production levels in alow and unstable price environment.
aHigh oil prices and the attempt to control supply actually led
to stifling expansion of productive capacity in the low-cost oil re-gions; most investment went into relatively high-cost regions. Someanalysts now speculate that the reverse could happen at low oilprices.
Chapter 4
What Will Determine Future Production?
Introduction
There is widespread agreement among oil in-dustry analysts that United States oil productionis Iikely to drop substantialIy in the coming yearsif oil prices remain at or near their current lowlevels. As noted earlier, the production declinewouId come from the combined influence of theclosing of thousands of wells and enhanced oilrecovery (EOR) projects whose production costsare too high, reduced levels of drilling of produc-tion and exploration wells, cutbacks in new EORprojects, and a slowdown in technology improve-ment with reduced R&D spending.
The logic of these predictions appears gener-ally correct. For one thing, the evidence “on theground” right now is extremely supportive of along-term decline in U.S. production; the over-all level of activity in development drilling, in allphases of exploration, in enhanced oil recovery,and in R&D have undergone a drastic decline,the existence of natural production declines inexisting wells is simply indisputable, and monthlydomestic oil production has already dropped bynearly 8 percent over a one year period. ’ Sec-ond, many of the companies involved in drilling,well servicing, and other aspects of oil explora-tion, development, and production have sufferedserious financial reversals as a result of the lossof revenue associated with the price drop andthe decline in oilfield activity, and their ability tomaintain previous levels of activity has sufferedas well. Third, the large drop in prices would ap-pear to have an inevitable adverse effect on theeconomics of drilling and other production pros-pects, thus sustaining the decline in activity andthe current trend towards lower production. Andfourth, the variety of available projections of fu-ture U.S. oil production have used several differ-ent approaches, yet they have arrived at similarconclusions about a substantial production drop.
1 A drop ot 680,000 bbl’day I n domestic crude production, fromDecember 1985 to December 1986, in Energy lntormatlon Admln-Ist rat Ion, Short-Term Energy Out/ook. Qu,; rter/v Pro/ectlons, ja n-
uary 1987, DOE,’ EIA-0202(87,’l Q}
74-272 0 - 87 - 2 : QL 3
However, there is considerable uncertaintyabout the magnitude of a production decline, andthere are even some grounds to question the ideathat the decline must be very large. Before ac-quiescing to the view of inevitable and largeproduction declines, policy makers should askwhether recent forecasts of future oiI productionare basically reliable, and shouId examine care-fully the assumptions underlying the pessimisticprojections. In OTA’s view, there are importantquestions about the accuracy of these projec-tions, because of changes to the industry that theprojections have not taken into account, becauseof basic uncertainties about key aspects of oil sup-ply responses to price changes, and because thenature of the price changes that have occurredare outside the experience of forecasters. In thefollowing discussion, OTA outlines the concernsabout the forecasts, and then reviews some ofthe primary factors that should be taken into ac-count in projecting future production. OTA doesnot attempt to arrive at any “most likely” rateof future U.S. oil production. OTA cone/udes,however, that the available evidence, althoughincomplete, points strongly to a continuing, andsubstantial, decline in U.S. oil production if oilprices remain well below $20 per barrel.
The Reliability of Forecastsof U.S. Oil Production
Despite the variety of their level of detail andspecific analytical approaches, most forecasts offuture oil production can be divided into twobasic categories: those that rely primarily on ap-plying relationships (e.g., between productionrevenues and drilling rates) discovered by exam-ining the historical record of oil exploration, de-velopment, and production and those that relyon economic analyses of expected exploration,development, and production opportunities. Thetwo forecasting methods are not mutually exclu-sive; all economic analyses include the applica-tion of some historical analysis.
The great majority of forecasts made availableto the public and to Congress use historical rela-
41
42
tionships to project future U.S. production. Ingeneral, forecasts of this type are particularly vul-nerable to errors caused by applying the relation-ships outside a relatively narrow band around theindependent variables. Such forecasts basicallyare extrapolations from past trends, and remainvalid only when the degree of extrapolation—represented by the changes in the independentvariables—is small. Current and expected futureconditions affecting the oil industry, however,represent considerable changes from past con-ditions. In fact, as discussed in several of chaptersbelow, there are good reasons to believe thatstraightforward extrapolation of past trends in sev-eral areas—e.g., in the way companies decidehow much of their revenues to allocate to explo-ration and development—will give inaccurate re-sults. Consequently, extrapolative methods nowappear to be working welI outside of their rangeof reliability. In OTA’s view, forecasts of U.S. oilproduction based on uncritical acceptance of theresults of extrapolative methods are an unrelia-ble basis for policymaking.
Forecasts that rely primarily on direct economicanalyses of exploration, development, and pro-duction prospects may appear more reliable be-cause they are more closely tied to the decisionprocess used by the oil industry. However, suchforecasts cannot escape entirely from the prob-lems associated with extrapolating from historictrends; they may use historic data to simulate theindustry’s method of selecting drilling prospectsor budgeting its overall E&D programs, or to esti-mate certain key variables such as the successrate of wildcats. In addition, the economic anal-yses are likely to use proprietary data on oilfieldopportunities, preventing the access to analyticalscrutiny necessary for credibility. Although someof the forecasts of major oil companies may bebased on a careful economic analysis of drillingprospects, the assumptions and detailed meth-odologies behind these forecasts are not availablefor review. The possibility that some companieshave unannounced agendas will, deservedly ornot, undercut the credibility of their forecasts. Fi-nally, the reliability of forecasts based on eco-nomic analyses demands an accurate assessmentof the geologic resources that may be accessedby the industry within the time frame of the fore-
cast. OTA believes that the reliability of resourceassessments—especially at the level of detailneeded for economic analysis—is inherently low.
Factors Affecting Future Oil Production
In discussing why they believe that U.S. oil pro-duction will fall, and fall drastically, in the yearsto come if world oil prices remain both low andvolatile, oil analysts have stressed a number offorces driving the predicted decline. Most havestressed that drastically lowered industry reve-nues have crippled the industry’s ability to re-cover its past capital investments and pay off itsloans, severely damaging the industry’s financialhealth. Some analysts stress in addition (or in-stead) that the basic economics of E&D invest-ment have been damaged severely by lower oilprices, in other words, that it is no longer profita-ble to conduct much of the drilling and other E&Dactivity that was attractive at higher oil prices.
The precise role in industry investment deci-sionmaking of cash flow, on the one hand, andE&D profit prospects on the other is by no meansa settled issue. Some analysts are convinced thatcash flow is the critical determinant of the mag-nitude of E&D investment, and that profit pros-pects primarily shape only the nature of that in-vestment. Indeed, many analytical models ofinvestment spending and drilling use cash flowas the key parameter. Other analysts are equallyconvinced that cash flow will not be the primarydeterminant of future industry investment, at leastfor the longer term, that the basic economics ofdrilling will be the key driving force. A correctassessment of the roles of each of these factorswill be critical not only to projecting future pro-duction but also to determining effective policyactions to combat a production decline.
Aside from cash flow and the economic pros-pects for new investment, additional factors thatwi l l
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●
affect future oil production levels include:
the potential for premature loss of some ex-isting production with high operating costs;the nature of the oil resource base, whichis intimately linked to the economic pros-pects for new investment because it deter-mines the physical character of available in-vestment opportunities;
43
the current surplus of gas deliverability,which discourages gas driIling and can hurtthe economics of some oil drilling;structural changes in the oil industry thathave increased debt, altered the industry’slikely business strategy and objectives, andare likely to affect industry efficiency;changes in the “efficiency” of explorationand development activity (as measured byfactors such as the reserves found per welland the success rate of exploratory drilling),which wiII alter the historic relationship be-tween E&D activity levels and their resultsin terms of reserves found and productioncapability added;changes in the climate for oil investments inthe United States and overseas that will in-
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fluence company decisions about dividingE&D investment budgets between the UnitedStates and overseas;prospects for technological change in the in-dustry, and especially the potential for cost-saving technology to help the industry suc-cessfully adapt to an environment of lowprices; andthe damage to the oilfield service industry,which might hamper attempts at a drillingrebound if oilfield investment prospectsimprove.
The following chapters discuss these factors,where possible drawing conclusions about thedirection and likely magnitude of their effect onfuture production levels.
Chapter 5
Economic and Resource FactorsAffecting U.S. Oil Production
The Profitability of New Investmentin Oil Exploration, Development,
and Production
Introduction
As noted previously, there is a basic disagree-ment among analysts of the oil industry aboutwhether it is the prospective profits of newinvestments in exploration and development(E&D) activity or the revenues flowing into theindustry from its previous E&D investments, thatis, cash flow, that are the key determinant of themagnitude of the industry’s future E&D invest-ments. This question is complicated by the sub-stantial changes in the industry’s managementand structure that have been wrought in the1980s, and the as-yet unknown long-term effectsthat the new oil price environment will have onindustry investment decision making.
I n the short term—perhaps for 2 or 3 years—the level of cash flow from past investments andthe effect it has on the industry’s basic financialhealth seems likely to have a very strong effecton the level of new investment even if prospectsfor profitable investments are basically good.Many of the financial entities generally respon-sible for U.S. driIling and other production activ-ities have been hurt badly because of the largecut in their revenues. Because these companiesmay hold land positions that could yield profita-ble drilling opportunities but no longer have ade-quate financial resources, new investment willsuffer from a mismatch between opportunity andcapability. Over the course of the next few years,however, loans will be renegotiated, companieswill be restructured, and properties will be sold;many of the companies will go under, but thoseremaining should be stronger financially. Even-tually, investment dollars will be made availableto the industry if there are attractive investmentopportunities. Thus, the long-term outlook foroil supply is dependent on the basic profitabil-ity of the oil exploration and development pros-pects available to the industry.
In OTA’s view, it is by no means obvious thatthe potential profitability of the industry’s avail-able investment possibilities in exploration anddevelopment have sunk in Iockstep with oilprices. Because the costs of oilfield services hadescalated so sharply during the late 1970s andvery early 1980s, there was considerable roomfor deflation in these costs when oil prices be-gan to slide in 1981, and in fact these costs con-tinued to deflate into 1986. ’ Only a careful ex-amination of the balance of development costsand the oil revenues that will flow from incur-ring these costs will yield a true picture of thelikely future of the industry in the face of con-tinuing low oil prices. If the basic prospect eco-nomics are not as bad as they seem at first glance,there may be some real potential for industryactivity levels—and reserve additions and produc-tion potential—to begin to rebound within a fewyears.
An evaluation of the potential profitability ofdomestic oil production prospects available to theU.S. oil industry would be invaluable in project-ing the likely future levels of reserve replacementand production for the United States. For a vari-ety of reasons, such an evaluation is not readilyavailable. First, there is no reliable inventory ofthe available prospects, although a partial inven-tory (particularly of development prospects)could be assembled from drilling data and leaseand field inventories in databases managed bygroups such as Dwight’s, NRG Associates, andothers. A particular difficulty here is the substan-tial uncertainty associated with the size and char-acteristics of the remaining oil resource base. Sec-ond, much of the information necessary to doeconomic analysis, as well as extensive analysesof new prospects carried out by oil companiesand their consultants, are proprietary. Third, werethe necessary data available, the complexity ofthe evaluation would be very great, in part be-cause of the large site-to-site variations among the
I Although drllllng costs rose briefly In 1985, according to the 1985Joint Assoclatlon Survey.
45
46
many thousands of prospects, and in part due tothe complexity of the government taxes and reg-ulations (e.g., the windfall profits tax) that stronglyinfluence the profitability of the prospects.
To OTA’s knowledge, there are no widely ac-cepted, regularly updated evaluations of the po-tential profitability of new investments in oil E&D.There are, however, a number of sources of in-formation and analysis that can provide some im-portant insights about potential profitability:
● Industry comments: The oil companies con-duct evaluations of profitability for their ownproperties and those properties they mightwish to purchase, and most companies haverecently undertaken extensive reevaluationsin light of the new price environment.
These evaluations are strictly proprietary,for obvious competitive reasons. However,a number of industry planners have beenwilling to discuss the general results of theseanalyses with OTA.
● OTA economic analyses: OTA has spon-sored a limited series of economic analysesof potential oil exploration and developmentprograms, in order to evaluate some of theclaims of our industry contacts and to evalu-ate the impacts on profitability of alternativegovernment policies, changes in expectedoil prices, and improvements in efficiency.
● Supply models using economic evaluation:A few computer models of oil supply containsubmodels that conduct economic evalua-tions, but these are very general in natureand appear unlikely to capture the full rangeof effects of the price drop. The Hydrocar-bon Model used by the Gas Research insti-tute contains an economic analysis packagewith one of the more detailed models of theoil and gas resource base, and the results ofmodel runs can be useful in gauging changesin profitability; however, the model does notevaluate improved recovery of gas- and oil-in-place, an important factor in future reserveadditions and production.
● Analyses of one or a few types of invest-ment: A number of analysts have publishedresults of individual profitability analyses forspecific projects or areas. In addition, a fewgroups have conducted detailed economic
●
analyses of some components of E&D activ-ity. These include the Minerals ManagementService’s analyses of the U.S. Outer Con-tinental Shelf resources and the National Pe-troleum Council’s study of Enhanced Oil Re-covery. 2
Media statements: Some industry executiveshave stated an oil price or price range thatthey claim is necessary to revive drilling orstabilize production, but these statements areessentially impossible to evaluate and theyadopt different assumptions about costs, in-terest rates, future prices, and other criticalvariables . . . if they are indeed the result ofactual analysis.
in addition, an examination of how drilling andother E&D costs may change over time will givefurther insight into how prospective profitabilitymay change in the future.
Survey of Industry Analysts
Despite industry secrecy, some oil companyanalysts have offered to OTA some general in-formation on the profitability prospects of newoil and gas E&D investment.
Essentially all of these analysts contend that the“inventory” of profitable oil and gas prospectshas shrunk enormously at mid-1986 price levelsof $12 to $15/bbl despite substantial declines indrilling costs and significant though lesser de-clines in other costs. One source estimates thatonly about 10 to 15 percent of the opportunitiesavailable at early 1980 prices remain available at$12 to $15/bbl. This figure is in line with the re-sults of the IPAA/SIPES drilling survey, whichshows an 80- to 85-percent drilling decline at$13,3 and an API survey predicting an 83-percentdecline (by 1991 ) at $10.4 Although some com-panies claim that there are large numbers of eco-nomic prospects at these prices, most are saidto be quite small and do not in the aggregate of-fer a major opportunity to replenish reserves. A
zNational petroleum Council, Enhanced Oi/ Recovery, June 1984.lsuwey of their rnernberstllps conducted by the Independent pe-
troleum Association of America and the Society of IndependentProfessional Earth Scientists.
4API Crude Oil Price Effects Survey, May 1986, compiled byCoopers and Lybrand for the American Petroleum Institute, resultsin API, Two Energy Futures: National Choices Today for the 1990s,1986 edition, July 1986.
47
very common theme is that the only arena thatcan support substantial drilling levels is relativelylow risk, low-to-moderate cost development drill-ing, primarily for oil objectives (because gas mar-
kets are poor), with short lead times. This impliesthat most drilling will involve step-out (extension)and infill drilling, primarily at shallow depths, inareas with little risk of cost overruns or curtail-ments (for gas prospects). Other categories ofprospects still viable at $12 to $15 include:
continuation of projects where the majorityof front-end capital has already been spent(enhanced oil recovery, offshore develop-ment drilling, and waterfloods that havepassed the early development stages);projects that are necessary to maintain com-pany positions, e.g., development and ex-ploratory drilling needed to satisfy leaserequirements, and joint ventures with sub-stantial performance penalties; andprojects with very distant production start-ups, if the company is confident of higherfuture oil prices. Although a few companiesare continuing a portion of their long-termprojects, more commonly these are beingcanceled despite company projections of“inevitable” long-term price increases.
common and disturbing theme is that ex-ploratory drilling is virtually dead at $12 to $15.A l imi ted number of h igh-grade explorat ionprospects are said to remain economic, such asshallow pressured objectives,5 and the shallowGulf of Mexico. However, the bulk of high re-serve potential prospects, both exploratory anddevelopment, are thought to be no longer eco-nomic. These include:
Ž Beaufort and Bering Seas, and most otherfrontier exploration;
● deep gas prospects;Ž heavy oiI offshore CaIifornia (but some de-
velopment projects with large sunk costs willcontinue);
● deepwater GuIf of Mexico;● higher cost enhanced oil recovery, especially
“grassroots” projects; and● Overthrust Belt exploration.
5That IS, sha I low d rl I I I ng ohjectl\,es wlt h reservol r pressures a t)o~ e
the pressure caused by the weight ot the rock, requirtng lower-than-
average pu mplng energy for production.
It has been reported in the trade press that thereis little agreement in the industry about the crudeprice necessary to stimulate a drilling recovery,with some saying that $20/bbl would generate sig-nificant new activity and others that $35/bbl isnecessary. G Most of our contacts were pessimis-tic that an increase to $18 to $20 oil prices wouldin any sense “rescue” the industry, although alladmitted that significant additional prospectswould become economic. These were said toinclude:
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some deepwater Gulf of Mexico exploratoryprospects;considerable onshore wildcat drilling;additional enhanced oil recovery projects,especially select second-generation CO2
projects with available CO 2 supplies, andsome polymer projects;exploration and delineation drilling in theBeaufort Sea;limited offshore California development; andmany waterflood projects, whose economicthreshhold prices are-often between $15 and$20.
Although virtually all contacts would agree thatthere would be significantly more drilling activ-ity at the $18 to $20 price, there was very sub-stantial disagreement about the effect on reserveadditions at that price. The more optimistic com-panies foresaw a considerable reduction in therate of decline of reserves, for example, from a9 to 12 percent/year decline at $12 to $15 to a5 to 7 percent decline at $18 to $20. Other com-panies saw little improvement in reserve additionswith a moderate price increase. Part of the dis-agreement may rest on the type of additionaldrilling activity foreseen at the higher price, withthe pessimists possibly being skeptical that thisprice will elicit the high risk drilling they believeis necessary for the addition of important new re-serves. All, however, agreed that a critical factorwas price stability, which can be just as impor-tant as price level. Without stable prices, deci-sions on prospects will require either higherthreshold rates of return or the functional equiva-lent, the need to satisfy profitability thresholdsat prices substantially below the “expected”levels.
“’Fiscal 1985 Returns for 0GJ400 Mixed, ” In 0// and Gaj Jour-nal, Sept. 8, 1986.
4 8
OTA Economic Analyses of DrillingOpportunities
OTA Prospect Analyses of Hypothetical Drill-ing Prospects.—OTA7 has examined the poten-tial profitability of some hypothetical onshoredrilling prospects, focusing in particular on howprofitability has changed over time, using a com-mercial economic analysis software package8 andadditional software developed by our contractor.The analysis evaluates both development and ex-ploration prospects.
The development drilling prospects are 2,000,4,000, 8,000, and 12,000 ft onshore wells with“per well” drilling and operating costs averagedacross several geographic areas. The perspectiveis from the viewpoint of a driller who has a landposition and must determine whether or not todrill.9 The basic cost assumptions used in the anal-ysis are summarized in table 7.
For each well, OTA calculated the profitabil-ity expected at the time of drilling—1972, 1981,1985, and 1986–and, for the earlier years, theprofitability actually obtained. The “expected”calculations used price scenarios generally reflec-
7Analysis by Thomas Garland, OTA contractor, Dallas, TX.8The OGRE I I Oil and Gas Reserve Evaluation System analysis
packdge developed by David P. Cook & Associates.9For a longer term view of drilling econom ICS, front-end bonuses
must be added to total capital costs.
tive of price forecasts of the time (see table 8);10
the “actual” calculations used historic prices forwest Texas crude to 1985, and then adopted aprice scenario assuming, in 1986 dollars, a $14/bbl price through 1990 and then a gradual in-crease to $20/bbl in 2000. For windfall profits taxcalculations, OTA assumed that the wells were“Tier 3“ wells, i.e. wells drilled on properties orinto reservoirs that were not producing before1980. Drilling and other costs were based onEnergy Information Administration compilationsof cost data for the relevant years. The key wellparameters, initial production rate and reservesper well, were selected by calculating the valuesneeded to allow a 15 percent before tax real rateof return in 1986, assuming the $14/bbl pricescenario.
Table 9 shows the (before tax) rates of returnfor the four drilling dates and expected/actualprice paths. Although the precise results applyonly to the particular cases evaluated, the con-sistency of the results as well depth varies and
IOOTA recognizes, however, that there has not been at any timea universal consensus about future prices, nor IS it necessarily truethat the price expectations actually used in oil company prospectanalyses were similar to those made public. For example, althoughOTA used a level price, in constant dollars, for the 1972 expectedcase, some operators claim that they had expected to see increas-ing real prices at that time. For those operators, our calculated ratesof return for the 1972 expected case are too low.
Table 7.-Assumed Costs To Drill, Equip, and Operate Development Wells,Selected Years
Depth
Year 2,000 feet 4,000 feet 8,000 feet 12,000 feet
Average equipment cost per well (less tubing costs):1972 . . . . . . . . . . . . 21,690 29,074 39,121 30,1431981 . . . . . . . . . . . . 58,625 75,381 109,830 98,4071985 . . . . . . . . . . . . 54,278 70,413 98,396 82,1541986 . . . . . . . . . . . . 51,564 66,893 98,396 82,154
Average operating costs per well/yr:1972 . . . . . . . . . . . . 3,541 4,456 5,701 6,8031981 . . . . . . . . . . . . 9,976 13,227 16,530 22,9141985 . . . . . . . . . . . . 11,512 14,810 18,840 27,1421986 . . . . . . . . . . . . 10,594 14,070 17,898 25,784
Average oil well drilling costs:1972 . . . . . . . . . . . . 35,187 68,039 151,839 484,8271981 . . . . . . . . . . . . 144,598 296,037 705,519 2,113,3901985. , . . . . . . . . . . 93,440 204,444 483,200 1,242,8161986 . . . . . . . . . . . . 74,752 227,555 386,560 994,253
Average dry hole drilling costs:1972 . . . . . . . . . . . . 23,164 43,682 94,383 318,8241981 . . . . . . . . . . . . 114,753 236,737 541,811 1,622,4401985 . . . . . . . . . . . . 68,320 145,600 321,778 992,4481986 . . . . . . . . . . . . 54,656 116,480 257,422 793,958SOURCE: Energy Information Administration data.
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. - -
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Table 9.—Economic Analysis of Drilling Prospects: Development Wellsin Reservoirs Not Producing Before 1979 (“Tier 3“ oil)
Depth (feet) . . . . . . . . . . . . . . . . 2,000 4,000 8,000 12,000Initial production (bbl/day) . . . 14 23 44 97Reserves (bbl) . . . . . . . . . . . . . . 30,000 51,000 102,000 230,000
Year Scenario Real before tax rate of return (percent)
1986 $14/bbl Oil . . . . . . . . . 14.6 14.3 14.8 15.11985 Expected . . . . . . . . . . 52.0 44.0 41.5 35.2
“Actual” . . . . . . . . . . . 22.2 18.3 16.5 15.11981 Expected . . . . . . . . . . 42.9 38.2 32.2 22.6
“Actual” . . . . . . . . . . . 27.0 22.0 16.5 7.61972 Expected . . . . . . . . . . Loss Loss Loss Loss
“Actual” . . . . . . . . . . . 9.1 11.3 13.3 9.6SOURCE’ Office of Technology Assessment, 1987.
our examination of the regional variations indrilling costs lead us to believe that the generaltrends apparent in the results apply to a consider-ably broader set of oil development prospects.
The critical patterns apparent in the results pre-sented in table 9 are as follows:
. At every depth, the expected profitabiIity for1986 is substantially lower than the expectedvalues for both 1981 and 1985. Althoughdrilling costs have declined substantially fromprevious years, many drilling prospects thatappeared profitable in the early 1980s wouldnot be drilled in 1986 even if capital wereavailable. This tends to confirm, at leastqualitatively, the claim made by most in theindustry that a substantial part of the inven-tory of formerly economic prospects are nowuntenable.
● Because price expectations in both 1981 and1985 were unrealistically high, the actualprofitability of the drilling prospects wouldhave been much lower than expected. Inmost cases, actual 1981 and 1985 profitabil-ity would have been similar to the expected1986 profitability, which is based on quitemodest price expectations.
● At every depth, prospects that would be con-sidered profitable in 1986 would have beenexpected to be outright losses in 1972, be-fore the initial price shock. This result is espe-cially interesting because some analysts havelikened 1986 conditions to 1972 conditions,concluding that U.S. production is likely tofall as quickly as it had been falling in 1972.Based on our results, these expectations mayseem overly pessimistic. However, our anal-
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ysis does not consider the availability of gooddrilling prospects. Most analysts would arguethat, despite advances in technology and ge-ologic knowledge since 1972, the availabil-ity of good physical prospects in 1972 wassuperior to that of 1986.Despite the substantial fall in prices between1981 and 1985 and the reduced expectationsfor future price increases, the prospectslooked somewhat more attractive in 1985.The improvement in profit expectations stemsfrom the substantial decline in drilling costsbetween 1981 and 1985.Taking a longer term perspective, of an oper-ator deciding whether to purchase and de-velop an unleased property, requires add-ing lease bonuses to the capital costs usedin the analysis. This wouId tend to narrowthe range of profitability between the differ-ent years, because bonuses typically arehigher when profit expectations are higher,pulling down the profit from the prospectswith the best potential. As discussed previ-ously, the current slowdown in drilling activ-ity gives the bargaining advantage to theoperator, and lease bonuses for new prop-erty are likely to be low. Thus, the potentialprofitability of buying and developing a prop-erty in 1986 will be closer to the potentialprofitability of the same prospect in 1981than the values shown in table 9.
Aside from the baseline analyses, we conducteda number of sensitivity runs to examine the ef-fects of changing assumptions.
Table 10 shows the effect on profitability ofdrilling in an “old” reservoir rather than one
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Table 10.—Economic Analysis of Drilling Prospects:Development Wells; Effect on Profitability of
Windfall Profits Tax “Tiers”
Type of producer: independentWells: same physical parameters as in table 9.Date of first production: 1981
Real rate of return (before tax) (o/o)
“Actual” prices Expected prices
Depth (feet) Tier 3 Tier 1 Tier 3 Tier 1
2,000 . . . . . . . . . . 27.0 21.1 42.9 34.24,000 . . . . . . . . . . 22.0 17.1 38.2 29.88,000 . . . . . . . . . . 16.5 12.8 32.2 25.1
12,000 . . . . . . . . . . 7.6 5.2 22.6 17.3SOURCE: Off Ice of Technology Assessment, 1987
which was not producing prior to 1980. Becausethe tax rate is higher for old, “Tier 1“ oil, andthe “windfall profits” higher because of previ-ous price controls on the oil, the profitability ofthe Tier 1 prospects would have been consider-ably lower than otherwise identical Tier 3 (“newoil”) prospects. As shown in the table, both theactual and expected rates of return were substan-tially lower for the Tier 1 drilling prospects. In fact,for the deepest prospects, the expected profit-ability for 1981 is little different than the expected1986 profitability. This effect would be exagger-ated for major companies, because the windfallprofits Tier 1 tax rate is 70 percent for majors andonly 50 percent for independents (the resuIts inthe table are for independent drillers).
Table 11 illustrates the strong effect of expectedoil prices on expected profitability. For everycase, a price drop to $10/bbl transforms a mod-estly profitable prospect into a disaster, whereasa $20 price transforms the prospect into a hand-some one. The strongly negative effect of the $10price is particularly important because several ofthe exploration managers and planners inter-viewed by OTA claimed that drilling prospectswere being subjected to a “low price hurdle, ”i.e., being rejected unless they would remainprofitable under the lowest price foreseeable . . .with the hurdle price often set at about $10. Theeffect illustrates the potential value of a govern-ment-legislated price “floor”; even if such a floordid not affect actual prices,11 it might encourage
I 1 FxcePt, perhap5, by d ISCOU ragl ng exporters from sel II ng at be-
low the floor, since the eventual landed price would be taxed u pto the floor anyway.
Table 11 .—Economic Analysis of Drilling Prospects:Effects of Oil Price on Rate of ReturnTier 3 Development Wells, Drilled and
Production Begun in 1986
Real rate of return (before tax) (o/o)
Oil price ($/bbl) 2,000 ft 4,000 ft 8,000 ft 12,000 ft
20 . . . . . . . . . . . . . . . . 41.3 37.2 34.3 33.014 . . . . . . . . . . . . . . . . 14.6 14.3 14.8 15.110 . . . . . . . . . . . . . . . . Loss Loss 1.3 3.49SOURCE: Off Ice of Technology Assessment. 1987
drilling by raising the hurdle price required fordrilling prospects, presuming that the companiestrusted the government not to remove the floorif world prices fell well below it. Also, of course,the strongly positive effect on profitability of the$20 price implies that a mechanism to raise oilprices could have significant positive effects ondrilling. The ultimate value of such a mechanismcannot be judged, of course, without a reliableanalysis of how much drilling—and how muchadditional reserves and production capacity—wouId be created by each additional dolIar in theoil price.
The price sensitivity calculations were made as-suming drilling costs would not change within theprice range examined. This is likely for the $10case because current costs are so low that thereis little room for downward movement. If $20 oilgenerates substantial new drilling activity, how-ever, drilling prices might rise somewhat, reduc-ing profitability.
Table 12 illustrates the effect on profitability ofchanging drilling costs, for a single 4,000 ft de-velopment well. As discussed in the section oncosts, drilling costs have gone through a classicboom and bust cycle during the last decade orso, and some analysts fear that a substantial re-bound in costs could occur if drilling activity be-gins to pick up. Conversely, substantial improve-ments in drilling technology have occurred overthe same time period, although the effects oncosts of the improvements were submerged bythe imbalance between demand for and availabil-ity of drilling services. Continuing technology im-provements could keep costs down if the indus-try accepts fully the challenge of finding andproducing oil in a low price environment.
The results show that the movement in drillingcosts from the 1985 average ‘‘per well’ costs to
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Table 12.—Economic Analysis of Drilling Prospects:Effect of Changing Drilling Costs on Rate of Return
4,000 ft. development well, Tier 3Initial production = 23 bbl/dayReserves = 50,000 bblDrilled, production begins in 1986$14/bbl oil price
Rate of return (o/o)
Drilling cost Before taxes After taxes
1985 average . . . . . . . . . . . . 8.1 7.810°/0 below 1985 . . . . . . . . . 10.8 10.120°/0 below 1985 . . . . . . . . . 14,3 12.830°/0 below 1985 . . . . . . . . . 18.5 15.8SOURCE: Office of Technology Assessment, 1987.
30 percent below the average–which has oc-curred in some areas—approximately doubles therate of return, a substantial effect.
Finally, table 13 illustrates the effect on profit-ability of changing Federal and State tax policiesto ease tax burdens on the industry, as has beencalled for by numerous industry spokespersons.As shown clearly by the results, a moderate eas-ing of taxes—adding investment tax credits, rais-ing depletion allowances, and cutting State sever-ance and ad valorem taxes—does improve the1986 expected profitability of these wells, butonly modestly.
In addition to the analyses of developmentprospects, OTA examined the comparative prof-itability over time of a series of exploration anddevelopment programs that find and developsmall oilfields (each field requires five producingwells for full development) in known producing
provinces. The wildcat wells in the program aresuccessful in one out of six attempts; develop-ment wells are assumed to be 80 percent success-ful. Well costs, expected oil prices, and other eco-nomic variables are assumed to be the same asin the previous analysis, except that geophysicaland other costs associated with exploration wellsare assumed to add 20 percent to the total costsof these wells.
Table 14 displays the rates of return (real, be-fore taxes) associated with the exploration anddevelopment efforts at 2,000, 4,000, 8,000, and12,000 ft, with and without lease acquisition costsincluded.12 A constant (real) $20 oil case is in-cluded to show the effects of an import tariff setat this level. I n contrast to the earlier effort, only“expected” rates of return—associated with typi-cal oil price expectations of the time—are shownfor the 1972, 1981, and 1985 cases. The table alsoshows the per well initial production rate and re-serves necessary to obtain a 15 percent before-tax real rate of return for 1986.
The rates of return results are very similar tothe previous analysis for development welldrilling: at every depth, prospects that would beconsidered profitable (15 percent before-tax realrate of return) in 1986 would have been expectedto be outright losses in 1972 and, in contrast, con-siderably more attractive in 1981 and 1986,whether or not lease acquisition costs are in-
I Zva{ Ues for lease acquisition costs were obtained from the Con-
gressional Research Service analysis described below, see table 17.
Table 13.—Economic Analysis of Drilling Prospects: Policy Options for Improvingthe Profitability of Development Drilling
Same physical parameters as in table 9Date of drilling and first production: 1986Expected price = $14/bblType of producer: small independent
Real after tax rate of return (o/o)
2,000 feet 4,000 feet 8,000 feet 12,000 feet
1. 1986 tax system . . . . . . . . . . . . . . . . . . . . 13.27 12.75 12.73 12.782. Change investment tax credits
a. to 200/0 . . . . . . . . . . . . . . . . . . . . . . . . . . 14.16 13.44 13.30 13.19b. to O (new law) . . . . . . . . . . . . . . . . . . . . 12.08 11.83 12.05 12.33
3. Allow 80°/0 depletion limit. . . . . . . . . . . . 13.38 12.80 12.74 12.784. Cut severance and ad valorem taxes
from 100/0 to 50/0 . . . . . . . . . . . . . . . . . . . . 15.56 14.71 14.39 14.335. Allow higher depletion allowance:
200/0 of gross. . . . . . . . . . . . . . . . . . . . . . . 14.00 13.53 13.50 13.50300/0 of gross. . . . . . . . . . . . . . . . . . . . . . . 14.35 14.15 14.26 14.25
SOURCE: Office of Technology Assessment, 1987.
53
Table 14.—Economic Analysis of Exploration and Development Projects
Well depth, feet . . . . . . . . . . . . 2,000 4,000 8,000 12,000Initial production rate,
bbl/day/well . . . . . . . . . . . . . . 20 35 71 172Reserves, bbl/well. . . . . . . . . . . 41,000 72,000 146,000 377,000Initial year Expected rates of return, real before tax, percentA. Without lease acquisition costs:
1986 $20/bbl oil . . . . . . . . . . . 38 34 33 301986 $14/bbl oil . . . . . . . . . . . 15 14 15 151985 . . . . . . . . . . . . . . . . . . . . . 45 39 38 331981 . . . . . . . . . . . . . . . . . . . . . 35 31 27 211972 . . . . . . . . . . . . . . . . . . . . . Loss Loss Loss Loss
B. With lease acquisition costs:1986 $14/bbl oil . . . . . . . . . . . 9 8 9 91985 . . . . . . . . . . . . . . . . . . . . . 30 25 25 211981 . . . . . . . . . . . . . . . . . . . . . 21 18 16 121972. . . . . . . . . . . . . . . . . . . . . Loss Loss Loss Loss
SOURCE Office of Technology Assessment, 1987
eluded. Also as in the previous analysis, expec-tations of a constant $20 oil price from 1986 onwill boost expected profits to the same generalrange as the 1981 and 1985 prospects. This re-suIt lends some credibility that an import tariffset to produce a minimum $20 domestic pricemight do some good, at least for this sort of “smalltarget” drilling and assuming that drillers (andtheir investors) trust the Federal Government tomaintain the tariff even if world oil prices wereto plunge.
Comparing the initial production rates and re-serves needed to produce a 15 percent return be-tween this exploration case and the earlier de-velopment dri l l ing case demonstrates thatexploration requires better prospects than devel-opment to achieve the same return. Although thisonly confirms the obvious—the exploration pro-gram must pay off the high cost of multiple dryholes (and buying the lease), whereas for incre-mental development drilling this cost is “sunk”-it serves to bolster the industry’s contentions thatexploration dril l ing will absorb substantiallygreater cuts than will development drilling.
The “dry hole risk” is crucial to the economicsof exploratory drilling. Although technologicaloptimists have often predicted large reductionsin this risk, and in certain situations this has beenaccomplished, improved technology has been es-sentially unsuccessful in boosting the indus-trywide risk in any measurable way, Table 15
shows how such a boost might effect the eco-nomics of exploration programs, by examininghow the rate of return would shift if the wildcatsuccess rate shifts from one new field discoveryi n six attempts to two or three discoveries in sixattempts. As shown in the table, an improvementto a 50 percent success rate would double therate of return for the type of exploration programexamined in this analysis. Unfortunately, most oilproducers would view such an improvement asa more appropriate topic of science fiction thanof scientific analysis. Nonetheless, the results il-lustrate the value of pursuing improvements inthe efficacy and cost of seismic and other explo-ration techniques.
Prospect Analyses Conducted for OTA by theCongressional Research Service. -Jane Gravelle,Specialist in Industry Analysis and Finance, andBernard Gelb, Analyst in Industry Economics,both of the Economics Division of the Congres-sional Research Service, have conducted a ser-
Table 15.—What Happens If Dry Hole Risk IsReduced? ($14/bbl oil, no lease acquisition costs)
Well depth, feet
2,000 4,000 8,000 12,000Expected rates of return,
Success rate real before tax
1:6 . . . . . . . . . . . . . . . . 15 14 15 152:6 . . . . . . . . . . . . . . . . 20 19 20 203:6 . . . . . . . . . . . . . . . . 29 29 30 33SOURCE Office of Technology Assessment, 1987
54
ies of economic analyses for this study. 13 T h eanalyses are of a series of combined exploration/development programs hunting for relativelysmall fields in four producing regions: the Per-mian Basin, Powder River Basin, Anadarko Ba-sin, and the Gulf Coast Basin of Offshore Loui-siana. The exploration/development programs aredescribed in tables 16 and 17. As in the OTA anal-ysis described above, the same physical prospectsare evaluated for four different years: 1972, 1981,1985, and 1986. The oil prices used in the anal-yses generally conform to the price expectationsof the times (table 18), except for 1986, whichuses three hypothetical price scenarios. Only the“expected” profitabilities are examined, since de-cisions to driII are made on the basis of such ex-pectations.
The prospect evaluation employs a discountedcash flow analysis, with revenues and costs dis-counted to the present, to arrive at estimates of“net present value’’—the amount that the netafter-tax revenues (gross revenues less operatingcosts, royalties, and all taxes), discounted to thepresent, exceeds the initial investment. In thebaseline runs, the lease acquisition costs were notincluded, primarily because these costs are so
‘ ‘B.A. Gelb and J.G. Gravelle, “Oil Prospect Profitability in theUnited States: Estimated Expectations in 1972, 1981, 1985, and1986, ” CRS Report No, 87-38E (revised), Mar. 24, 1987.
variable from project to project. The real discountrate was set at 10 percent, so that when the netpresent value is zero, the project earns a real (i.e.,corrected for inflation) 10 percent rate of return.Table 19 presents the tax and financial variablesused in the analyses.
The results of the baseline series of prospectanalyses are presented in table 20, with the re-sults displayed in the form of the net present valueexpressed as a percent of the initial investment.If a real 10 percent rate of return is consideredthe minimum “hurdle rate” of a prospect–theminimum expected profitability that would con-vince the operator to proceed with the program—then the 1972 Powder River Basin project, withzero net present value, could have proceededif the operator did not have to pay a lease bonus(unlikely) or if he had paid the bonus already and,perhaps on the basis of new information, reeval-uated the property to arrive at the expected re-sult displayed in the table. Prospects with posi-tive net present values allow the operator someleeway to pay bonuses, with the amount deter-mined primarily by the competition for proper-ties and the land’s potential for some alternativeuse that might be hindered by a drilling program.
The results are generally similar to those of theOTA analysis of development and exploration
Table 16.—Characteristics of Hypothesized Prospects
Producing region and type of operator
Permian Basin Powder River Basin Anadarko Basin Offshore LouisianaVariable Independent Major Independent Independent Major
Number of wells:Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 10 10 10 6Successful . . . . . . . . . . . . . . . . . . . . 10 10 10 10 13
Well depth (feet):Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,500 6,400 6,400 3,300 8,800Successful . . . . . . . . . . . . . . . . . . . . 8,900 6,100 6,100 3,300 8,900
Initial year production:(thousands of barrels). . . . . . . . . . . 222 169 169 48 1,450
Annual physical depletion:(percent) . . . . . . . . . . . . . . . . . . . . . . 10 10 10 10 10
NOTE: The Permian Basin is mainly in Texas; the Powder River Basin, in Wyoming; and the Anadarko Basin, in Kansas. Except for well depths, the data shown referto each individual prospect as a whole.
SOURCES AND METHODS OF ESTIMATION: Number of holes (wells) —Based on Congressional Research Service (CRS) geologist’s field experience and industry rulesof thumb regarding: a) ratios of dry holes to successful wells holes; and b) the typical number of producing holes for a reasonably profitable prospect. The ratioof successful holes to dry holes for the offshore prospect is higher than onshore because the much higher cost of drilling offshore forces operators to be morecautious in drilling “wildcat” wells. Well depth—Typical well depths of the respective producing regions in 1972, based on data from the Joint Association of Drill-ing Costs, published by the American Petroleum Institute. Offshore wells are assumed to be drilled in 100 feet of water, and production platforms to have 12 “slots,”Initial year production-Derived by CRS from the relationships among total industry production, outlays (for exploration, development, and production), and reservesfor a “normal” year. Based on data from the Annual Survey of Oil and Gas, compiled and published by the U.S. Bureau of the Census. Annual physical depletion—Based on actual ratio of total U S crude oil production in a year to proved reserves.
55
Table 17.—Estimated Investment and Operating Costs (thousands of dollars)
Producing regionPermian Basin Powder River Anadarko Offshore Louisiana
Geological andgeophysical . . . . . . . . . . . . . . 1972
198119851986
}Land acquisi t ion
and Ieasinga. . . . . . . . . . . . . . 1972198119851986
Drilling . . . . . . . . . . . . . . . . . . . . 1972198119851986
Lease and well equipment . . 1972198119851986
Annual operating costs . . . . . . 1972198119851986
12% of sum of drilling plus lease and well equipment
25°)0 of sum of drilling plus lease and well equipment33°/0 of sum of drilling plus lease and well equipment25°/0 of sum of drilling plus lease and well equipment20°/0 of sum of drilling plus lease and well equipment
2,42411,95610,1407,600
2931,1551,1451,090
50142165164
1,7756,7535,1653,850
325872935890
49142152151
4361,8511,4361,080
153575520495
27829392
14,40016,4163,0001,500
9,68050,92928,57121,150
2,1706,2006,2005,830
7422,4172,3602,300
aNot Included In the estimation of expected profltab!llty
SOURCES AND METHODS OF ESTIMATION Geological and Geophysical average ratio— derived from data in the Annual Survey of Oil and Gas, compiled and pub-Iished by the U S Bureau of the Census Land Acquisition and Leasing—Onshore: Ratios for 1972 and 1981 derived from data in the Annual Survey of 011 andGas, ratios for 1985 and 1966 estimated by authors, based on price expectation scenarios. Offshore: Derived from average lease bonuses paid per acre in Federaloffshore lease sales Drilling —Assumed number of wells Onshore—10 dry, 10 pay; offshore—6 dry, 13 pay. Drilling costs estimated from Joint Association ofSurveys on Drilling Costs published by the American Petroleum Institute, for 1972, 1981, and 1984, from the 1985 Survey of Combined Fixed Rate Overhead Chargesfor Oil Producers, published by Ernst and Whinney, and from comments by an oil industry association economist Lease and Well Equipment—Estimated for 19721981, and 1985 from data in Costs and Indexes for Oilfield Equipment and Production Operations in the United States, published by the Energy Information Adminis-tration, estimated for 1986 based on comments by Energy Information Administration industry expert. Annual Operation Costa-Same as for lease and well equipment
Table 18.—Assumed Crude Oil Prices
Producing region 1972 1981 1985 1986
Price per barrel in initial year (initial year dollars)
Permian Basin . . . . . . . . . . . . . . $3.35 $35.90 $26.00 $14.00Powder River Basin . . . . . . . . . 3.30 35.90 28.00 14.00Anadarko Basin . . . . . . . . . . . . 3.25 35.90 25.50 14.00Offshore Louisiana . . . . . . . . . . 3.55 36.00 27.25 14.00
Anticipated annual change as of initial year (constant dollars)
All producing regions . . . . . . . No change A) +2°/0 indefinitely 1985-90: –3.00/0 A) 1985-90: + 8%B) See note After 1990: +2.5°/0 After 1990: +2°/0
B) 1985-90: OO/oAfter 1990: 3.5°/0
C) 1985-90: OO/oAfter 1990: 0°/0
NOTE: Anticipated annual changes for 1981 price scenario “6’’ -1981 to 1985: – 0.80/0; 1985 to 1990 + 8 20/0, 1990 to 1995: +6.5°/0, 1995 to 2000 + 2 3°0, 2000 to 2020+ 0.9%. Initial year price for 1981 price scenario “B’” asumed to be $34 per barrel for all producing regions
SOURCES Initial year prices based directly and/or indirectly on data from the Energy Information Administration, U.S. Department of Energy, Petroleum Supply Annual,Monthly Energy Review, and Annual Energy Review Anticipated changes based directly and/or indirectly on Projections by the Energy Information Adminis-tration and by several private organizations, including oil companies, energy industry groups, and other organizations
56
Table 19.—Tax and Financial Variables
1986a
1972 1981 1985 Old New
Interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.20/oInflation rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.60/oDebt share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.0%
Federal Income Tax TreatmentRate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48.0%Intangible drilling costs . . . . . . . . . . . . . . . . . . . . ExpensedLosses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ExpensedEquipment
Investment credit rate . . . . . . . . . . . . . . . . . . . 10.0%Tax Life (years) . . . . . . . . . . . . . . . . . . . . . . . . . 9.2Depreciation methodb . . . . . . . . . . . . . . . . . . . SYDReduction in basis . . . . . . . . . . . . . . . . . . . . . . No
Depletable costsc . . . . . . . . . . . . . . . . . . . . . . . . . Percentagedepletion
State Tax TreatmentSeverance Tax
Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .078**Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .046Wyoming*** . . . . . . . . . . . . . . . . . . . . . . . . . . . . .03Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0
Income TaxLouisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,04Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .0675
16.0%9.6%
17.0%
46.0%ExpensedExpensed
10.0%4.5
150 DBNo
costdepletion
.125
.046
.040
.0800.0675
12.7%4.0%
17.0%
46.0%Expensed*Expensed
10.0%4.5
150 DB1/2
costdepletion
.125
.046.015-.06
.08
.0800.0675
10.2%4.0%
17.0%
46.0% 34.0%Expensed* Expensed+Expensed Expensed
10.0% o4.5 7
150 DB DDB1/2 No
cost costdepletion depletion
.125
.046.015-.06
.08
.0800.0675
%ldrefers to Federal tax lawin effect in 1986. New refersto the Tax Reform Act of 1986, which became effectivetn ?987.bSYD—Sum of yearsdigits; 150 DB—15(J percent declining balance; DDB—Double declining balancec22% percentage depletion for 1972.~Thirty percent of costs of majors amortized over five years.Twenty percent of costsof majors amortized over three years.
“’The Louisiana severance tax wasa per unit tax of26 cents per barrel in 1972. The rate equivalent in the table would decline overtime.““*The Wyoming severance tax risesto6 percent after 1989, but is currently 15 percentNOTE: Because of data limitations, It was not possible to incorporate local property taxes. Application of the windfall profits tax dependson price levels,
SOURCES: inflation andlnterest rates are basedon Iaggedvalues following Patrick Hendershott and Sheng-Cheng Hu, “Investment in Producer’s Equipment;’HowTaxes Affecf Econorrrtc Behavioc Herrry Aaron and Joseph A. Pechman (eds), Brookings institution, Washington, DC, 1981, p. 85-128, Debt ratios are fromDon Fullerton andRogerGordon, “Afle-examination of Tax Distortions in General Equilibrium Models;’ Behaviora/Simu/ation &fethods lnTax Po/icyAna/y-SIS, Martin Feldstein (ed.h National Bureau of Economic Research, Universityof Chicago Press, 1983, p 372.
Table 20.—Estimated Anticipated Profitability of U.S. Oil Prospects 1972,1981,1985, and 1986 (net present valueas a percent of initial investment)
Producing region and type of operatorInitial year and Permian Basin, Powder River Basin, Anadarko Basin, Offshore Louisiana, Unweightedprice scenario Independent Major Independent Independent Major average1972 . . . . . . . . . . . . . . . . . . . . . . 7 0 0 – 4 16 41981A . . . . . . . . . . . . . . . . . . . . . 74 113 113 86 97 971981 B . . . . . . . . . . . . . . . . . . . . . 74 114 114 84 97 971985 . . . . . . . . . . . . . . . . . . . . . . 60 119 120 72 142 103Old Tax Law:1986 A . . . . . . . . . . . . . . . . . . . . . 21 49 50 13 661986 B . . . . . . . . . . . . . . . . . . . . . 14 39 40 6 51 281986 C . . . . . . . . . . . . . . . . . . . . . 1 24 24 – 7 29New Tax Law:1986A . . . . . . . . . . . . . . . . . . . . . 25 59 60 14 791986B . . . . . . . . . . . . . . . . . . . . . 17 46 48 6 60 331986 C . . . . . . . . . . . . . . . . . . . . . 1 28 29 –10 34NOTE Real discount rate assumed to be 10 percent,
SOURCE: Congressional Research Service, 1987
wells, but the regional detail provided by the CRSanalysis yields some interesting insights. The ex-pected profitability of the hypothetical prospectsin mid-1986 was lower than the expected profit-ability in 1981 or 1985, but generally higher thanin 1972—precisely as in the OTA analysis. Evenif future oil prices are assumed to rise quite rap-idly (8 percent per year in real dollars, as in pricescenario 1986A), and despite a sharp drop indrilling costs between 1985 and 1986, expectedprofitability in 1986 is appreciably lower than in1985 for all five prospects. However, in the Per-mian and Anadarko Basins, under the 1986Bprices (identical to those used in the OTA analy-sis), the expected profitability for 1986 is onlymodestly better than it was in 1972, If the $14oil price is assumed to hold, except for rising withthe cost of living, the 1986 prospects are slightlyinferior to the 1972 prospects in these basins.
The Permian and Anadarko Basins correspondto regions JS and JN in table 24 (in the nextsection), which displays the relative developmentprospects computed by GRI’s HydrocarbonModel. That model calculated the prospects forboth these regions to be quite good. These re-sults are not necessarily contradictory, becausethe Hydrocarbon model runs incorporated rela-tively optimistic assumptions about oil prices.
In addition to the cases discussed above, CRSexamined the effects on prospect profitability ofthe Tax Reform Act of 1986 (which will take ef-fect starting in 1987). A most surprising result isthat the new tax rules show a small but signifi-cant improvement in profitability over the cur-rent tax law in every prospect, for every price sce-nario. Apparently, the lower tax rates in the newlaw override the effects of losing the investmenttax credit. This conclusion would likely not holdfor a company that had excess tax credits or anactual net loss under the current law (becausethe lower tax rates under the new law would beirrelevant), nor does it account for any adverseeffects of the alternative minimum tax in the newcode. It will hold, however, for situations wherethe decision to pursue the prospect is at the mar-gin where the company is deciding whether topursue one more prospect, and the companydoes not have excess tax credits or a net loss forthe year. I n OTA’s view, this is the decision most
57
worth examining, since it is the one faced by mostcompanies trying to decide whether to increasetheir rate of drilling . . . and thus it is the deci-
sion that, made in the aggregate, will determinewhether a drilling rebound is likely to occur.
CRS also examined the effects of a $10/bbl and$20/bbl expected (real) price, an assumed repealof all State severance taxes, a 20 percent refund-able tax credit for driIling costs (costs which arecurrently in the nature of intangible drilling costs,and which exclude depreciable equipment anddepletable geological and geophysical costs), anda 27.5 percent oiI depletion allowance.14 The re-sults are displayed in table 21.
The results for the $10 and $20 oil price andthe cut in severance taxes are pretty much thesame as those arrived at in the OTA analysis. The$10 price–which is particularly significant since,conservative industry analysts may use this priceas a “hurdle” price for profitability—creates a dis-astrous drop in profitability. The $20 price, whichsimulates a variable import tariff set at this value,boosts profitability substantially. (However, itdrilling costs were to increase as a result of re-vived activity, the boost in profitabiIity wouId bepartially offset. ) The cut in severance taxes hasonly a modest beneficial effect in most regions(the Louisiana offshore prospect is an exception),and does not appear capable by itself of makinga substantial difference i n industry activity.
An interesting exercise is to compare the re-sults of the $20 price case to the 1981 and 1985results, because drilling in these two years wasat a high level (even though the 1985 rig countwas somewhat depressed). The net present valuesat $20 oil were back to 1981-85 levels for all re-gions but the Anadarko, implying that an importtariff set at this level might spur a significantdrilling rebound if the oil companies trusted theFederal Government to leave the tariff in placeAND if sufficient capital were made availableto the independent producers. Of course, con-fidence in such a result would require an exami-nation of a far wider set of cases than was accom-plished here. Also, we stress that this result doesnot imply that a return to a free market price of
14All ot the cases i n c o r p o r a t e t h e n e w tax rules.
58
Table 21 .—Estimated Anticipated Profitability of U.S. Oil Prospects, Under Specified Price and PolicyAlternatives (net present value as a percent of initial investment)
Producing region and type of operator
Permian Basin, Powder River Basin, Anadarko Basin, Offshore Louisiana, UnweightedPrice or policy alternative Independent Major Independent Independent Major average
$10/bbl constant pricea . . . . . . –14 6 7 –25 6 – 4Variable import tax setting
price at $20/bbla . . . . . . . . . . 53 102 103 44 120 8420°/0 drilling cost creditb
1986A . . . . . . . . . . . . . . . . . . . 41 73 74 26 931986 B . . . . . . . . . . . . . . . . . . . 32 61 62 18 74 471986 C . . . . . . . . . . . . . . . . . . . 17 42 43 2 48
No State severance taxes1986A . . . . . . . . . . . . . . . . . . . 30 65 66 24 1061986B . . . . . . . . . . . . . . . . . . . 21 52 54 15 85 421986C . . . . . . . . . . . . . . . . . . . 5 29 31 – 3 54
27.5°/0 depletion allowance1986A . . . . . . . . . . . . . . . . . . . 39 76 77 29 1051986 B . . . . . . . . . . . . . . . . . . . 29 64 65 20 84 491986 C . . . . . . . . . . . . . . . . . . . 11 44 45 1 53
27.5°/0 depletion allowance, with old tax law1986A . . . . . . . . . . . . . . . . . . . 40 76 77 33 1031986 B . . . . . . . . . . . . . . . . . . . 31 64 65 25 84 511986 C . . . . . . . . . . . . . . . . . . . 15 44 45 8 55
aprices are per barrel of crude oil Estimation procedure for impori tax assumes that the price of domestic oil would eqUal that Of imported oil.bunderthls option, Federal income tax ~abilit~ forata~ year would be reduced by an amount equal t02fJ percent of expenditures for drilling in that yearCUnder this option, Federal income tax )iabllity for a tax year would be reduced by an amount equal to 27.50/. of gross iflCC)l?’le from the prOpe~y,
NOTE Except where Indicated, the estimates have been made using the provisions of the new tax law,
SOURCE: Congressional Research Service, 1987,
$20 might also accomplish a drilling rebound. Itis the expectations of future prices as much asthe current price that drives industry activity, andthe current volatility of prices will tend to under-mine industry confidence.
The 20 percent drilling credit, an idea not ex-plored in the OTA prospect analysis, does pro-duce a moderate improvement in profitability inall cases, and could prove interesting to policy-makers who favor using the tax code to boostE&D activity.
The 27.5 percent depletion allowance also pro-vides a moderate improvement in profitability inall cases. in general, it boosts profitability slightlymore than the 20 percent drilling credit.
Inclusion of lease acquisition costs in the anal-yses will tend to make the 1985 and 1986 resultslook more favorable in comparison to the 1981results, because 1981 was the height of thedrilling boom and lease acquisition costs wereespecially inflated. As evident from table 17, thesecosts have come down considerably in recentyears, especially in the offshore.
Table 22 presents the net present values for thesame cases as in table 20, as well as for the $20oil case, with the lease acquisition costs incor-porated in the analysis. Inclusion of these costschanges none of the basic conclusions obtainedfrom examining table 20, but the results do dem-onstrate more decisively than the original analy-sis that 1985 was actually a very attractive timeto drill, that reduced oil revenues were oftenmore than compensated for by reduced costs.
Analyses by the Gas ResearchInstitute (G RI)
GRI operates an energy supply and demandforecasting system called the Hydrocarbon Modelthat incorporates a detailed description of theUnited States Lower 48 oil and gas resource base,on a field-by-field basis, and an economic anal-ysis model that assesses the expected profitabil-ity of exploratory and development drilling basedon the characteristics of the resource opportu-nities. GRI’s Strategic Analysis and Energy Fore-casting Division has recently conducted a spe-
59
Table 22.—Estimated Anticipated Profitability of U.S. Oil Prospects 1972, 1981, 1985, and 1986 WithLease Costs Included (net present value as a percent of initial cost, including lease acquisition costs)
Producing region and type of operation
Permian Basin, Powder River Basin, Andarko Basin, Offshore Louisiana,Initial year price scenario Independent Major Independent Independent Major1972 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . –12 –18 –18 –21 –461981A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 64 64 43 581981 B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 65 65 42 581985 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 80 80 41 1251986A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 27 28 – 4 581986 B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 3 18 19 – l o 431986 C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . –14 5 5 –21 26$20 Constant Price .. ... ... ...... . . . 30 72 73 22 109SOURCE Office of Technology Assessment based on Congressional Research Service analysis, 1987
cial run of the Hydrocarbon Model aimed atevaluating the effects on oil and gas productionof low oil prices. 15
The primary assumptions used for the analysiswere:
● oil price (1986$) of $11.76/bbl in 1986, ris-ing to $14.41 in 1990 and $21.60 in 2000;gas prices of $1.47/mmBtu, $l.60, and $2.95,respectively;
● 1986 drilling costs 10 percent below 1985levels; and
. producers accept a minimum real rate of re-turn, after tax, of 7 percent.
Some characteristics of the model and the as-sumptions used will tend to drive the estimatesof oil and gas production both above and belowa “most likely” level. For example, factors thatwould tend to overestimate supply include:
● The minimum rate of return, 7 percent, ap-pears low. This rate is lower than the rateused by GRI in its baseline (higher price)runs. Most industry analysts expect that theperceived instability of oil prices will raisethe minimum rate of return acceptable to theindustry.
. The drilling model does not consider theavailability of capital as a constraint, im-plicitly assuming that capital will be madeavailable to the industry if there are accept-able drilling prospects to pursue. For at least
‘;T, J. Woods and P.D. Holtberg, “Hydrocarbon Activity In anEra of Low Oil Prices, ” 61st Annual Technical Conference and Ex-hlbltlon of the Society of Petroleum Engineers, New Orleans, LA,Oct. 5-8, 1986, SPE Paper 15355.
the short term, a lack of capital is an impor-tant constraint on industry activity, especiallyamong independent producers.
Factors that would tend to underestimate sup-ply
●
●
include:
The model does not include the effects onsupply of enhanced oil recovery and otheractivities to improve the recovery of oil- orgas-in-place.Actual 1986 drilling costs may be as muchas 30 percent below- 1985 level’s, and not the10 percent assumed in the model run (how-ever, many operators do not expect costs toremain this low for long).
The results of the model run, displayed in ta-ble 23, show oil production declining at a 5 per-cent/yr rate through 1990, then 3.1 percent/yrrate through 1995, and a 1 percent/yr ratethrough 2000. Gas production holds constantthrough 1990 and then declines at about 1.2 per-cent per year through 2000. Development drillingis projected to dip considerably and remain atlevels substantially lower than those of the early
Table 23.—Lower-48 Oil and Gas Production(excluding increased recovery from old fields)
O i la GasYear (million b p d ) (tcf) b
1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.63 16.11990 . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.13 16.11995 . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.36 15.12000 . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.16 14.3aDoeS riot inclurje lease condensatebTrilllon cubic feet
SOURCE T J Woods and P D Holtberg, “Hydrocarbon Activity in an Era of LowOil PrlCeS, ” 61st Annual Technical Conference and Exhibition of theSociety of Petroleum Engineers, New Orleans, Louisiana, Oct. 5-8, 1!386SPE Paper 15355 Congressional Research Service, 1986.
1980s—e.g., 32,500 total development wells in1990 versus the rate of 50,000 to 70,000 wellsper year sustained during the first half of the1980s, (Part of this dip may be attributed to themodel’s exclusion of drilling designed to increaserecovery efficiency in known fields.) On the otherhand, exploratory drilling is projected to dip ini-tially and then recover sharply, to nearly 14,000wells/yr in 1990 and 23,000 wells/yr in 1995versus 13,000 to 17,000 wells/yr during the early1980s. This latter result is surprising because ofthe greater costs generally associated with ex-ploratory drilling and the widely held industryopinion that most future drilling will focus on fielddevelopment and away from exploration.
The model shows Lower 48 crude oil (not in-cluding lease condensates) production decliningby 1.5 mmbd by 1990 and 2.3 mmbd by 2000(from 1985 production). As shown in chapter 3,of the forecasts prepared in 1985, with expecta-tions of stable oil prices in the low-to-mid $20sfor the remainder of the 1980s, the most pessi-mistic—the EIA Energy outlook—projected a 0.9mmbd reduction in total United States crude pluscondensate production16 by 1990, with only 0.7mmbd attributable to Lower 48 production. TheChase “Consensus” forecast projected only a 0.6mmbd drop for the United States as a whole. TheEIA projection for 1995 is for a 2.4 mmbd dropin total United States production, with 1.9 mmbdattributable to Lower 48 production, whereas theChase projection for the total United States is for
I a 2 mmbd drop. Thus, on the surface, the GRIresults imply a substantial decline in future oilproduction attributable solely to the projecteddifference in prices between the moderate 1985expectations and a lower price scenario basedon an extension of 1986 price levels. However,the authors of the GRI papers describing this anal-ysis do not themselves interpret these results sopessimistically, because they believe that greaterrecovery of oil-in-place—not incorporated in themodel—will compensate for much of the pro-jected reduction in “standard” oil production.They attribute the current drilling decline prima r-
lbpresumably, lease condensate production will decline when nat-
ural gas production declines, so that the projected total decreasein crude plus condensate production implies a lesser decrease incrude alone.
ily to the immediate effects of the large drop inthe oil industry’s cash flow and conclude that theoverall resource economics of drilling have notbeen greatly affected by the price drop.
Aside from the overall production projections,the GRI model exercise yields interesting insightsinto other potential changes associated with the1986 price drop. In particular, the exercise yieldsinsights into the viability of new drilling activity,and the profits likely to be gained from earlieractivity, in different portions of the country. Forexample, the model results indicate that the ex-tensive drilling in the early 1980s to all depthsin southern Louisiana, to 5 to 15,000 feet in theTexas gulf coast, and to 10 to 15,000 feet in thePermian Basin are yielding poor economic re-turns, and new drilling in these area/depth com-binations should drop sharply with continuing ex-pectations for unacceptable rates of return oreven outright losses. On the other hand, pros-pects for new drilling in many region/depth com-binations remain surprisingly good despite thelower prices, including offshore California, espe-cially in shallow water (less than 600 ft), onshoreCalifornia to O to 10,000 ft, the Rocky Mountainsand Northern Great Plains to all depths above15,000 ft, and several other regions. Table 2 4shows the economic prospects for drilling in theHydrocarbon Model regions based on the lowprice exercise.
MMS Analysis of the Effect of Lower OilPrices on OCS Recoverable Resources
A reduction in oil exploration activity on theOuter Continental Shelf (OCS) and the statementsof industry planners imply that many OCS explo-ration prospects that were economic in the early1980s at oil prices in the $25 to $35 price rangeare not economic at $15 or $18. This in turn in-dicates that the total recoverable oil resource wasdiminished by the recent oil price decline.
The Minerals Management Service (MMS) ofthe Department of the Interior has evaluated theeffect of varying oil price on the magnitude ofthe undiscovered “leasable resources” in theOuter Continental Shelf (leasable resources areresources that would be profitable to explore forand develop). Table 25 presents MMS’s estimate
61
Table 24.—Economic Prospects for Drilling, Based on GRI Hydrocarbon Model Runs
Region Prospects
A
B
c
D
E
G
HI
J N
J S
L
EGO
LO
(Ohio, Kentucky, Tennessee, Georgiafurther east and offshore)
(Mississippi, Alabama, Florida)
(Minnesota, Wisconsin, Michigan, lowa,Illinois, Indiana, Missouri)
(Arkansas, North Louisiana, Central Texas)
(South Louisiana)
(Texas Gulf Coast, South Texas)
(Dakotas, Nebraska, Montana, Wyoming,Idaho, Colorado, Utah, Arizona, NewMexico)
(Mid-Cent-KanSaS, Oklahoma, Texas, R R D
#lo)
(Permian Basin, Southeast New Mexico,Texas RRD 7C,8,8A)
(California, Nevada, Pacific North West)
(West Gulf, offshore Louisiana and Texas,shallow offshore Alabama, Mississippideep Norphlet)
(Offshore California and Pacific NorthWest)
excellent* at 0-10,000 ft (established depths), good to poor atgreater depth
good to excellent shallow and deep, poor at 5,000-10,000 ft (mostcommon drilling interval)
marginal
good at 0-10,000 ft (most common drilling interval), marginal topoor below
poor at 0-15,000 ft, marginal at greater depth
good to excellent at 0-5,000 ft (high past active drilling), marginal5,000-15,000 ft (most common drilling interval), poor at greaterdepths
good to excellent at 0-15,000 ft, marginal at greater depth
good at 0-5,000 ft, and greater than 10,000, good to excellent at5,000-10,000 ft
good at 0-10,000 ft, greater than 15,000 ft, marginal 10,000-15,000 ft
excellent at 0-10,000 ft (most common drilling intervals), poor tomarginal at greater depths
good at all water depths except uncertain in Norphlet trend
excellent at 0-600 ft. water depths (most common drillinggood beyond 600 ft
* Definition of Terms Poor = below 5 percent real after tax rate of return; Marginal = 5-10; Good = 10-15; Excellent = above 15
SOURCE Off Ice Technology Assessment, based on GRI data
of leasable resources in 22 planning areas forUnited States Gulf of Mexico oil prices of $17,$23, $28, and $34/bbl 17 in January 1987.
The analysis indicates that a 50 percent dropin price yielded a 34 percent decrease in leasa-ble resources overall, but that, in some basins(Beaufort Sea, St. Georges Basin, Chukchi Sea,and others), 100 percent of the resource was ren-dered uneconomic. Presumably, some of the ba-sins were lost because the level of recoverableresources dropped below levels necessary to sup-port the costs of required transportation systemsor other minimum fixed costs.
A reliable evaluation of the effect of the OCSresource “loss” on U.S. oil production requiresa detailed examination of the individual basinsand the various governmental and industry plansfor developing these basins. However, it appearslikely to us that in most cases the effects on pro-
] Zwlfh an assumed 1 percent annual real price growth.
duction of the loss at the $17 price will
interval),
be smallwithin this century, because of the long timelag–generally a decade or so–between OCS ini-tial leasing and initial production, and becausegenerally the higher cost resources would not beforemost on most development schedules any-way. Of course, this conclusion will not holdwhen the total loss in leasable resources becomeslarger . . . as will certainly happen at prices sub-stantially below $17.
OTA does not believe that the MMS analysesare necessarily relevant to projecting the incen-tives for exploratory drilling aimed at very large,long-term frontier prospects. Many or most ma-jor companies will pursue such prospects regard-less of current prices because they cannot projectprices for the time frame of actual developmentof any potential discoveries (in most cases, be-yond 10 years) and they cannot pass up thechance of discovering a field that is so large it canbe profitably developed at almost any conceiv-able oil price.
62
Table 25.—Sensitivity of Leasable Resource Amountsto Current Oil Price
Leasable resources, million
1987 U.S. Oil Price/bbl barrels of oil equivalent
Gulf of Mexico $17 $23 $28 $34
Planning area:Western Gulf of Mexico .. .3,790Central Gulf of Mexico. .. .3,930Southern California. . . . . . . 540Navarin Basin. . . . . . . . . . . . 0Middle Atlantic . . . . . . . . . . 90South Atlantic . . . . . . . . . . . 250St. George Basin . . . . . . . . . 0Eastern Gulf of Mexico . . . 180Chukchi Sea. . . . . . . . . . . . . 0Beaufort Sea . . . . . . . . . . . . 0Northern California . . . . . . . 150North Atlantic . . . . . . . . . . . 10Central California . . . . . . . . 110Washington/Oregon . . . . . . 50Gulf of Alaska . . . . . . . . . . . 0North Aleutian Basin . . . . . 0Norton Basin . . . . . . . . . . . . 0Kodiak . . . . . . . . . . . . . . . . . . 0Florida Straits . . . . . . . . . . . 0Hope Basin. . . . . . . . . . . . . . 0Shumagin . . . . . . . . . . . . . . . 0Cook Inlet . . . . . . . . . . . . . . . 0
T o t a l . . . . . . . . . . . . . . . . . 9 , 1 0 0
4,4904,070
730180110410
0330
00
28030
18050
0000
10000
4,6304,110
880720230680260420
0250410
3022060
0000
10000
4,6304,110
880790230770260470400310410
7022060302020
010000
10,870 12,910 13,690
Percent of $34 resource . . . 660/0 79 ”/0 94% 100%
SOURCE: U.S. Department of the Interior, Minerals Management Service, 5-YearOuter Continental Shelf Oil and Gas Leasing Program for January1987-December 1991, app. F, draft
costs
The cost components relevant to a particulardecision about exploration, development, or con-
i tinued production depend on the precise circum-stance of that decision:
I● I n deciding whether to continue production
from an existing well in good operating or-der, only the net production costs–calledthe “lifting costs’’—are considered. The costof acquiring the lease, finding the oil, drillingthe production well, and building the nec-essary infrastructure such as pipelines are im-portant to the company’s profit and losssheet, but these costs are “sunk” and shouldnot enter the specific production decision;production will continue as long as the netrevenues from the well’s production exceedthe lifting costs. For wells needing significantrepairs, the amortized cost of these repairsmust be added to Iifting costs, and the sumbalanced against revenues.
●
●
Decisions to expand production by drillingnew wells in known fields need to considerthe expected lifting costs plus the cost ofdrilling the well, including a risk factor to ac-count for the possibility that the well couldbe dry. If the well is drilled outside theknown boundaries of a reservoir, i.e., a newpool test or an extension test, the risk com-ponent could be quite substantial.Adding production from a new (as-yet-undis-covered) field requires considering the costsof acquiring the lease, drilling a number ofexploratory wells to discover the field, drill-ing development wells, and, at times, add-ing significant infrastructure.
Finally, many decisions must be made at stagesintermediate to these cases . . . for example, thedecision whether to drill exploratory wells afterthe lease is acquired. Such intermediate decisionsare forced on producers when economic condi-tions change suddenly, disrupting the previouscalculations that led to the initial phases of oil-field activity.
In other words, at any instant, the oil industryhas a large “inventory” of potential investmentopportunities ranging from unleased, unexploredland with potential oil reserves that are only agleam in a geologist’s eye, to older fields with afew remaining undrilled sections, or with somepotential for infill drilling (drilling at a closer spac-ing than was initially planned) or other produc-tion-enhancing investments. For the older fields,most or all of the leasing, exploration, and infra-structure costs have already been incurred. Thus,it is inherently cheaper to pursue a prospect inthe most developed areas, and becomes progres-sively more expensive—i n terms of incurring ex-penses for lease bonuses, seismic exploration, lay-ing pipelines, etc.—to pursue prospects at earlierand earlier stages of the production cycle. Theonly reasons why undeveloped prospects are pur-sued at all are because the inventory of prospectsin known and partially developed fields is limitedand must be replenished, and because the com-pany believes it will find more profitable oil orgas wells–with more reserves, higher productionrates, higher quality oil, with less water cut andlower operating expenses–than in the more de-veloped areas.
63
Lifting Costs.—As noted above, decisions tocontinue production from existing wells are de-pendent on lifting costs remaining below the rev-enues flowing to the producer, that is, total rev-enues less royalties and taxes18 must exceed costs.Thus, when oil prices are $15/bbl, royalties areone-sixth, and taxes are 5 percent, lifting costsmust be less than $ (15 - 15/6) * .95, or $11.88/bblfor the well to remain profitable to operate.
According to the “standard reference” for lift-ing costs—the Joint Association Survey19-averagelifting costs for oil and gas in the United Stateshave been well below “per barrel” oil prices,even with taxes and royalties factored in. Aver-age U.S. lifting costs were between 60 and 70cents per barrel between 1959 and 1970, and didnot rise above $2 per barrel until 1980. The 1982Annual Survey of Oil and Gas shows 1982 lift-ing costs (without taxes) for oil and gas to beabout $3.40 per barrel of oil equivalent (BOE),with average costs for Alaska at $0.97/BOE,20 theLower 48 onshore at $4.03/BOE, and the offshoreat $2.81/BOE. Lifting costs for oil alone shouldbe a bit higher because operating costs are gen-erally higher for oil wells than for gas wells. Theaverages conceal a wide range, especially for theLower 48; for onshore production, wells withhigh water production or in high cost secondaryand tertiary recovery operations may have lift-ing costs exceeding $15/bbl, whereas certain highoutput wells may produce oil at less than $1/bbl.
Estimates of U.S. lifting costs at values consider-ably higher than the values reported in the JointAssociation Survey have been reported in the me-dia and elsewhere. The reasons for the discrepan-cies are not clear, although they may includedefinitional problems (the estimates may includeexcise taxes, although these are unlikely to addmuch more than $1.00/bbl to the total, or mayrefer onIy to higher cost wells without specify-ing that this is so). Some examples of higher re-ported lifting costs are:
18Some analysts choose to Ignore taxes and royalties because these
are ~lew ed as negotiable; they believe these wi II be reduced shar-
ply by their collectors If the alternative IS a mass ive shutdown ot’
drllllng and production. For example, see the writings of M. Adel-man dnd A. Tusslng. Thus tar, there is little indication that majorreductions I n roya]tles and taxes are takl ng place.
I gjoi nt Assoclatlon SU rvey, America n petroleum I nstltute.20Llfting Costs for Alaska are low because the high transportation
costs to bring this 011 to mdrket have precluded the developmentof resources with high I Ittl ng costs,
●
●
●
●
“Average United States lifting costs, includ-ing taxes” reported to be just above $10/bblfor the oil and gas system as a whole, in tes-timony of Dr. Alan Greenspan, President,Townsend-Greenspan & Co., Inc.The lifting cost of bringing oil to the surfaceis reported as varying from $7 to $15/bbl atonshore wells by R. Stanfield in NationalJournal, 3/29/86.Operating costs (including royalties andseverance taxes) for different U.S. regions arepresented as: Texas, $4 to $8/bbl exceptstrippers, Gulf of Mexico $8 to $10/bbl, Arc-tic North Slope $14 to 24/bbl, in N. Barakatand S.M. Chronowitz, “Crude Oil: Nearingand Equilibrium, ” Smith Barney FinancialServices, Futures Special Report, Vol. 8 No.5, spring 1986.Average lifting costs in sample lower 48 fieldsestimated as - $6.80/bbl, in J. L. Copeland,Presentation to the Keystone Energy FuturesProject on United States Liquid Fuel Policy,July 14, 1986, Copeland, Wickersham, Wiley& Co., Inc.
In general, OTA is skeptical of estimates of lift-ing costs well above those of the Joint Associa-tion Survey. However, the Copeland, Wicker-sham, Wiley, & Co. estimates were derived froma field-by-field survey of production costs andcannot be dismissed so lightly.
To what extent might lifting costs decline fur-ther in response to low oil prices?
Operating costs for specific categories of wellshave begun to trend slightly downward duringthe past few years as a result of reductions inenergy costs and some reductions in the costs ofservices and equipment for well maintenance. Inparticular, costs for fuel have declined in paral-lel with oil prices; this is an important cost com-ponent for enhanced oil recovery projects, butgenerally is less important for ordinary produc-tion because pumping energy often is electric andelectricity costs have not fallen significantly. Ingeneral, the very substantial cost reductions seenin drilling services have not been matched by sim-ilar reductions in operating costs, nor are theylikely to be. The drilling cost reductions havebeen driven primarily by the very large decreasesin demand for these services; for example, the
64
itI
[
I
1
1
t
I
I
I
I[
number of operating rigs has declined from over4,000 in 1981 to about 700 in 1986. The num-ber of wells, on the other hand, will not declinedrastically, and may even increase, so mainte-nance services will not have to face the enormousidle capacity faced by the drilling service indus-try. However, many well operators will defermaintenance, lessening the overall demand forthese services, and certain categories of services—e.g., workovers for offshore wells—will face com-petition from equipment formerly devoted todrilling new wells. Other costs–e.g., electricitycosts—may face downward pressure from Stategovernments concerned about the potential forwell closings. For example, the Oklahoma Cor-poration Commission has asked Oklahoma elec-tric utilities to lower rates for well operations.Therefore, operating costs seem likely to remainstable or perhaps decline slightly in the near fu-ture, assuming oil prices stay low.
In addition to some moderate reductions intechnical operating costs, there is some poten-tial for reductions in royalties and taxes. In gen-eral, most royalty reductions are likely to be con-centrated on new operations where operatorscan take advantage of the dropoff in competitionfor new properties to pressure property ownersfor concessions. There is less potential for royaltyreductions with properties that have already beenleased. For them, the property owners may beparticularly reluctant to accept a lower royaltyrate because their royalties have already beenslashed because of the lower oil prices. Also, fur-ther development of producing properties willoften remain quite attractive even at low oil pricesbecause the major capital expenditures have al-ready been made, so there will be less economicpressure on the owners of such properties togrant royalty concessions. However, on the mostmarginal properties, those most likely to be shutin, some property owners may be faced with thechoice of accepting a lower royalty rate or los-ing their royalties entirely as the production shutsdown.
The potential for lower tax rates is uncertain.The primary oil-producing States face a consid-erable dilemma in assessing tax strategy for oilproduction. A major portion of their operatingrevenues are derived from taxes on oil produc-
tion, and the substantial dropoff in collectionsassociated with the price drop has caused con-siderable budgetary problems. Reductions in taxrates probably would save some wells from shut-ting down. Given the low average lifting costs foroil wells, however, it seems likely that any reduc-tion would lead to a further significant drop inState revenues, because the revenues “saved”because of the few wells prevented from shut-ting in would be overwhelmed by revenue lossesassociated with wells that would have continuedto produce without a tax break. However, eachshut-in well costs the State jobs, reduced taxesassociated with employment, and costs associ-ated with added needs for social services.
From the above, OTA concludes that pressuresfor reductions in lifting costs from existing wellsare likely to continue to drive down average U.S.lifting costs, although only to a moderate extent.In addition, new drilling in a low price environ-ment may tend to avoid areas and geologic situ-ations known to yield high operating costs, eventhough operating costs are not the primary fac-tor considered in drilling decisions; this wouldtend to hold down the average lifting costs of newwells. Finally, the wells being shut in and thusremoved from the U.S. inventory of producingwells are those with the highest costs. Thus, OTAexpects the U.S. average lifting cost to declinein the coming years if oil prices remain low, al-though most of this decline will result from a shiftin the distribution of physical characteristics inthe U.S. inventory of wells rather than from a sub-stantial lowering of costs for particular servicesand types of wells.
“Finding” Costs.– Finding costs are the fullrange of costs—including the cost of lease acqui-sition, seismic surveying, exploratory drilling,reservoir modeling, and development drilling—needed to bring oil and gas reserves to the pointwhere they can be produced.
As explained above, decisions to drill new wellsor otherwise develop new production depend onexpected finding costs, or on components ofthese costs, depending on the stage of develop-ment the proposed activity is in. For example, thedecision to buy a lease and drill new field wild-cats should consider every component of find-
65
ing costs as well as expected lifting costs if oil andgas are discovered. The decision to drill a devel-opment well should consider only the compo-nents of finding cost beginning with the cost ofplanning that particular well, since all previouscosts have been sunk and cannot be retrieved.
Finding costs have undergone a major cycling,through boom and bust, during the past decade.For example, figure 6 illustrates the changes infinding costs over the past decade and a half, firstduring the drilling surge that followed the 1972embargo and then during the decline accom-panying the oil price declines that began in 1981.The major factors affecting these costs include:
● The hyperinflation associated with the rapidincreases in demand for drilling services,land, and other factors of production. Theinflation was caused by a growing ineffi-ciency in providing drilling services and the
Figure 6.—Oil and Gas “Finding Costs”(costs for exploration and development)
1973 1975 1977 1979 1981 1983 1985
Year
NOTES1 “Surrogate finding costs” match reserves booked in a year to expenditures
made in that same year, even though actual costs to find and developreserves are spread out over a number of years “Ultimate finding costs” at-tempt to match exploration and development costs to reserves by assumingtypical lag times and levels of field growth.
2 The conversion to 1985 dollars was based on the GNP price deflator
SOURCESA—L T Byrd, (The Keplinger Companies) and D.L. Moore (Arther Anderson &
Co ), “U S Oil and Gas Flndlng and Development Costs, 1973-1982, Lower48 Onshore and Off shore,” Sept 18, 1984 For lower 48 States.
B–Arfher Andersen & Co., Oil and Gas Reserve Disclosures, 1980-1983 and 0//arrd Gas Reserve Disc/osures, 1981-1985. For entire United States
C—A T Guernsey, ProfItabI/Ify Study, Crude 0// and Natura/ Gas .Exp/oratiorr,Deve/opnrerrt and ProductIon Actfwt~es m the USA 7959-1983, report toShell 011 Co , June 1985 For lower 48 States
●
●
greater “economic rent” collected by pro-viders of these services . . . and the turn-
around in costs was caused by the overalldrop in oilfield activity. Similarly, the costsof the other “factors of production” —includ-ing land and seismic analysis—rose with thedrilling boom and have deflated with theslide in drilling activity.Changes in drilling targets, with operatorsexpanding their driIling efforts towards mar-ginal targets and targets in difficult-and highcost—environments during the period of ris-ing oil prices (driving finding costs up), thenadjusting during the price slide by withdraw-ing from higher cost targets and focusing pri-marily on targets in less difficuIt environ-ments with lower finding costs. Some of themovement towards marginal targets, how-ever, reflected not economics but resourcedepletion, that is, a declining availability oflow-cost opportunities.Technological improvements in drilling, seis-mic surveying, and other components of ex-ploration and development.
There currently is no consensus on how find-ing costs will vary in the future. Although manyanalysts expected finding costs to continue adownward trend, established in late 1982, into1985, the 1985 finding costs appear to havetrended upwards.21 In all probability, a substan-tial part of any future changes will be the resultof changes in drilling patterns, as these patternscontinue to adjust to the new economic condi-tions caused by the lower oil prices. Effects oftechnological change are difficult to predict be-cause lower research budgets would tend to slowchange whereas the radicalIy new price environ-ment might act to spur it on.
There also is no consensus on how the basiccosts of services and other factors of productionwill behave in the future, although changes inthese costs were a primary driver of past changesin finding costs. Right now, certain of thesecosts—especially drilling costs—are so low thatthe providers of the services are barely surviving,
I I According to the Arthur Andersen & Co. Oil and Gas ReserveDisclosures, 1981-1985, 1985 finding costs per barrel were $11.85
(wi thout rev is ions) and $9.39 (wtth rev is ions) compared to $9.94
and $8.29 In 1984 .
66
III
I
I
I
I
I
,#I,
II
deferring equipment maintenance and actuallylosing money in many operations.22 For theseservices, any tightening of supply will surely leadto price increases, but the extent of such increasesand their timing is not readily predictable (cer-tainly, the overhanging surplus of equipment willlimit cost increases in the near term). For factorsthat need not involve risk or investment on theprovider’s part—such as lease acquisition—itseems more likely that costs can remain ex-tremely low until there is a substantial recoveryof drilling activity.
Capital Availability and thePermanence of Capital Flight
Many industry analysts point to a shortage ofcapital to finance investments in exploration anddevelopment as a major factor in the severe de-pression that is rocking the upstream sectors ofthe oil industry, especially the independent pro-ducers. The severity and duration of this capitalshortage would appear to be a critical deter-minant of future U.S. oil reserve additions andproduction.
During the late 1970s and early 1980s massiveamounts of capital flowed into the oil industryas oil prices and corporate revenues soared amid
ZZFor example, certain types of drilling services can now be ob-
tained at less than the cash cost of providing these services. Theproviders are willing to accept the loss because the cost of moth-balling their rigs is greater than the net cost to them of drilling.
Table 26.—U.S. Exploration and Development
expectations of even higher world oil prices. Be-tween 1978 and 1985 over $300 billion was in-vested in petroleum exploration and develop-ment (see table 26). Annual expenditures peakedat $57.7 billion in 1981 and then declined to $33billion in 1985. In the wake of the 1985-86 pricedrop, industry spending on E&D dropped sharplyto half the 1985 leveI.23 As can be seen from table26, much of the increased E&P spending up tothe early 1980s came from the independentsector.
The original wave of investment in explorationwas funded from several sources: from rapidlyexpanding internal cash flows generated byhigher oil prices; from private investors seekinghigh returns on publicly traded stocks and bondsor tax sheltered investments in oil and gas drillingfunds, partnerships and trusts; from conventionalbank loans secured by equipment or reserves;and from private placements by banks, other fi-nancial institutions, and large investors. Table 27shows the sources of funds for the Chase Man-hattan Group of large oil companies. Similar ag-gregate information is not available for inde-pendents.
Since the 1981 peak in the exploration boom,several trends have combined to limit internaland external capital availability for new explo-ration:
ZJOII and Gas Journal, Feb. 23, 1987.
Outlays for 1973 to 1985 (billions of dollars)
Larger firmsa Independents b TotalYear $ Billions ‘/0 Change ‘/0 Total $ Billions % Change % Total $ Billions % Change
1973 . . . . . . . . 5.3 25 65 2.9 27 35 8.1 261974 . . . . . . . . 8.6 62 69 3.8 33 31 12.4 521975 . . . . . . . . 6.4 –25 62 3.4 –10 33 10.3 –171976 . . . . . . . . 8.6 36 60 5.7 66 39 14.5 421977 . . . . . . . . 10.3 19 62 6.2 9 38 16.5 141978 . . . . . . . . 11.3 9 58 8.0 30 42 19.3 171979 . . . . . . . . 15.0 33 56 11.8 46 44 26.8 391980 . . . . . . . . 20.6 37 57 15.6 33 43 36.2 351981 . . . . . . . . 29.8 45 53 26.7 71 47 56.5 561982 . . . . . . . . 30.0 1 54 25.4 – 5 46 55.4 – 21983 . . . . . . . . 22.7 –25 55 18.2 –28 45 40.9 –261984 . . . . . . . . 22.1 – 3 53 19.4 6 47 41.5 11985 . . . . . . . . NA NA NA NA NA NA 33.0 –20Exploration and Development Outlays include both capital expenditures and and exploration expenses excluding that portion associated with proven property acquisition.&LLar9er firms<, Inclu(jes most of the major oil companies in the Chase Manhattan Bank Group plUS several other large domestic independents. Figures are drawn
from the annual publication by the Chase Manhattan Bank, “Financial Analysis of a Group of Petroleum Companies” and adjusted for the additional companies.b,,lndependents,, includes all other oil and gas explo~ation and production companies, Figures are derived by subtracting expenditures by larger firmS frOm tOtal indus-
try expenditures.NA = not available.
SOURCE: Independent Petroleum Association of America, “United States Petroleum Statistics—19Bf3° (final).
Table 27.—Sources and Uses of Working Capital of a Group of Petroleum Companies (million dollars)
Funds available from Funds used for ‘-
Cash Long term Stock a Capital Long termYear earnings debt issued issued Other b Total expenditures Dividends debt repaid Other c
Total Internal funds External funds Total funds
1975 . . . . . . . 22,7141976 . . . . . . . 25,8281977 . . . . . . . 29,0031978 .. . . . , 33,1841979 . . . . . . . 55,8441980 . . . . . . . 66,8591981 . . . . . . . 63,2071982 ..., . . . 60,8841983 . . . . . . . 60,2561984 . . . . . . . 53,5491985 (est.) . 63,600
10,12910,3108,6784,9308,568
11,90016,58514,9808,704
22,16819,100
a
a
aa
a
a
a
450300179500
1,2172,4264,4245,2266,9845,8621,7236,2836,706
–4,73814.200
34,06038,56442,10543,34071,39682,82181,51582,59775,66971,15897,400
24,20526,03627,15628,77042,22953,77663,97664,53849,52143,18247.900
4,8195,2085,9956,7818,127
10,30511,06811,26511,05710,29712,600
5,3165,2305,9546,8858,2499,728
10,0209,2817,5248,280
22.600
1,740829
1,5081,5622,4732,6134,8673,7314,507
21,67119,500
36,08037,30340,61343,99861,07876,42289,93190,01972,60983,430
102.600
23,93128,25433,42738,41062,82870,72164,93067,16766,96248,81177.800
10,12910,3108,6784,9308,568
11,90016,58515,4308,707
22,34719.600
34,06038,56442,10543,34071,39682,62181,51582,59775,66971,15897.400
alncluded in Long Term Debt Issued.bothe r Includes sales of assets and other transactionscother Includes investments and advancements and preferred and common stock retireda Included In Long Term Debt Issued
SOURCE. The Chase Manhattan Bank, Flnanclal Analysts of a Group of Petroleum Compan]es
68
●
●
I ●
I
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,
●
●
,
●
The windfall profits tax cut sharply into themajors’ earnings from oil production atprices over $20/bbl, removing an additionalsource of funds that might have been avail-able for exploration and production (E&P)spending and perhaps deterring additionalinvestments. (Countering the effects of theWPT, however, were tax incentives such asthe investment tax credit. )Lower wellhead oil and gas prices meantlower revenues and earnings for many of theindependent producers, who carried a lowerWPT burden, and thus reduced internal cashflows that could be available for exploration.Federal income tax law changes in 1982diminished the attractiveness of oil and gastax shelters for private investors at the sametime as the overall rate of return on oil in-dustry investments began to decline in rela-tion to the rate for manufacturing industries.The price-related decline in the value of oiland gas reserves and drilling equipment alsoreduced the value of assets that could beused as CO I lateral for bank loans.24
The high debt levels incurred by many in-dependents to fund the boom in explorationin 1979 to 1981 began to take an increasingshare of available cash flow as prices fell andcut into discretionary capital spending.Similarly, the increased debt levels incurredby restructuring strategies (see section on“The Restructuring of the U.S. Oil Industry”)absorbed a significant share of cash flow.A number of regional banks in the Southwestwhich had heavily financed E&P spendingcame u rider pressure from the simultaneouspoor performance of loans to the oil and gasdrilling services and equipment sectors andthe agriculture and real estate sectors. Witha rise in problem loans, many of these bankswere less willing to lend their available fundsfor risky drilling ventures.
zdf3anks were commonly using a rule of thumb that required POst-
ing of collateral that had at least twice the value of the securedloans under several price scenarios. Oil prices have fallen as muchas 60 percent in 1986. Moreover, some analysts believe that proven011 reserves have declined in average price from $9 to $5 per bar-rel as of late 1986 and the value of loans that they could be usedto secure has gone down correspondingly.
Even as the amount of capital available wasconstrained by these trends, disappointing explo-ration results and a decline in both oil and natu-ral gas prices deterred investments of availablefunds in many high risk plays by oil companiesand private investors. Exploration no longer en-joyed a privileged status among the major in-tegrated oil companies and larger independents,as management weighed various options for en-hancing shareholder values, and some opted in-stead to use available internal and external fundsto pursue acquisitions, share buy backs, and otherinvestments.
The sharp drop in oil production revenues andearnings that followed the 1985-86 price dropdrastically increased the entire industry’s capitalavailability problems by dramatically reducing thecash flow available to fund exploration and cap-ital investment. The decline in capital availabil-ity has affected sectors of the industry differently,however, with the drilling and service companiesand the smaller independent producers sufferingthe most. The high debt loads incurred by thesecompanies, which funded much of the boom,placed them at greater risk during the initial pricedecline and the 50 percent fall in drilling activitybetween 1981 and 1985. By 1985, many of thesefirms were under financial stress, some wereforced into default and were liquidated, and somesought protection under the bankruptcy laws. Ofthe remaining operators, many saw their finan-cial condition weakened as a higher share of theircash flows went to debt service and the value ofassets that could be used as collateral plunged.This reduction in collateral values also causedsome loans to go into technical default, eventhough operators remain able to meet scheduledpayments. As noted above, the regional bankswhich had financed their efforts were also u riderpressure from poor performance in the agricul-ture and real estate sectors, and were less likelyto lend their available funds for risky drilling ven-tures. Although there are no reliable sources ofinformation on private financing, which is a ma-jor source of funds for independent operators,many industry analysts believe that availability ofprivate funds has declined because of currentconditions in the industry and uncertainties over
the implementation of the 1986 tax law. Withfewer willing investors, companies may have tooffer better terms to acquire funds, and combinedwith uncertain oiI prices, this provides a strongincentive to avoid the high risk exploration ven-tures that often represent the best opportunitiesfor reserve replacement.
Also hard hit were larger companies that werehighly leveraged due to corporate acquisitions oranti-takeover strategies. These firms cut E&Pspending first in 1985, with only a modest declinein world oil prices. They took even larger cutsin 1986 as cash flow was diverted to meet or re-duce debt obligations and to maintain key finan-cial indicators. These companies have less flexi-bility in the use of their available cash, and theirability to borrow further may be impaired by thehigh level of existing debt and uncertainty overfuture revenues. Perhaps because of this concern,several of these highIy leveraged companies havedevoted substantial efforts to reduce their highdebt levels and/or to refinance the debt at moreattractive interest rates.
In general, however, the larger companies—and especially those companies that did not in-cur sizable debt loads during the boom years—do not appear to have suffered nearly as muchfrom capital availability problems. In particular,the integrated companies’ downstream earningshelped to cushion some of their upstream lossesas refinery margins increased and demand forgasoline and residual fuel oil increased. For ex-ample, as table 27 shows, total funds availablefrom internal and external sources declined byonly about $11 billion in 1982 to 1984, while cap-ital spending (excluding acquisitions) droppedover $20 billion. Rather than a capital shortage,there appears to have been a deliberate shift awayfrom E&P spending towards other uses of capi-tal, such as acquisitions and debt repayment.Statements in company annual reports and con-gressional testimony generally attribute the re-duced capital spending to a lack of profitable op-portunities and not a lack of funds from internalor external sources. Also, the 1985 annual and1986 quarterly reports of many major integratedoil companies and larger independents continueto show new long-term debt, indicating that theiraccess to financing has not been substantially im-
69
paired. In 1985 to 1986, the use of borrowedfunds changed; with limited exceptions, thesefunds have been largely used to refinance exist-ing obligations, to repurchase shares, and to ac-quire assets of other companies rather than tofund new oil and gas development.
Even with the most recent drop in revenues,large oil companies remain among the largestcash flow generators in the United States and theworld. Table 28 shows changes i n revenues andearnings for selected major U.S. oil companiesfor the first 9 months of 1986. Not all of the earn-ings losses in the exploration and production seg-ments this year will translate into lower cash avail-ability, as many companies took one-time paperwriteoffs against earnings.
Even the problems of the independent sectormust be evaluated carefully. According to EnergyPerformance Review, independent oil and gasproducers and oil field service companies suf-fered sharp declines in revenues and earnings in1986; a group of 126 independent producersposted losses of $1.8 billion for the first 9 monthsof 1986. However, more than 100 percent of yearto date losses were attributable to noncash chargesagainst income.25 The size of the noncash chargesindicates that many companies likely posted netgains on their continuing operations that werethen reduced by noncash charges against earn-ings to reflect such things as writedowns in thevalues of reserves because of lower prices, andlosses on the sale of operations.
The critical question for determining the futureof industry investments in exploration and devel-opment is: To what extent is the current patternof the domestic oil and gas industry a transitionalphase, and to what extent is it essentially stableso long as prices do not rise?
Many industry observers believe that uncer-tainty over oil prices and the factors noted abovevirtually ensure that, in the short run, little out-side capital will flow into oil exploration and de-velopment. In the longer run, however, the rela-tive importance of these factors is less clear. Otherindustries have been able in the past to adjust
25’’ Rough Third Quarter for Energy Companies, ” Energy Dal/y,Dec. 8, 1986, p. 1,
70
Table 28.—Financial Performance of Selected Oil Companies, First 9 Months 1986 v. First 9 Months 1985
Revenues Net profits Capital and exploration expenditures
85-86 1986 85-86 1985 1986 1985 % Change % of net incomeCompany Million $ % Change Million $ % Change Million $ Million $ Million $ 85-86 1986 1985
* Exxon 57,470● M o b i l 37,233● Chevron 21,685● Texaco 24,800● S h e l l 12,841● Amoco 15,394● ARCO 11,368
Conoco 7,495● Sun 8,230● Phillips 7,642
Ashland 7,300* O c c i d e n t a l 1,175● Unocal 6,297
Texas Oil & Gas 732Louisiana Land & Exp 620Murphy 1,048Coastal 48Marathon 6,100Pennzoil ., 1,414American Petrofina 1,493
● T e n n e c o 10,930● Diamond Shamrock 1,951
Amerada Hess 3,139K e r r – M c G e e 1,946
* S t a n d a r d 7,750T o t a l 270,805
● OTA group total 224,766
*OTA Group
SOURCE : Oil and Gas Journal
– 1 6 3,880–16–37–29–14– 2 8–33–21– 2 3–36–11
4– 2 8–39– 2 9– 3 7
– 9–23– 1 7– 1 5
– 2–21–45–20–24–22–23
1,204801675628582551331315217209161127382513
(1)(1)
(30)(42)(73)
(278)(301)(376)
8,6608,649
2796
– 1 5– 2 7– 3 7– 6 3
—
– 2 7179
–3342
– 7 5– 7 3– 8 7– 6 7– 7 9– 9 5
————————
– 2 8—
3,065615946926998
1,563————
147643460
———
94—————
105109
1,07910,751
10,295
5,6272,1792,0191,6012,1312,114
————
281687666
———
125—————
184230
1,38019,224
18,404
7,1442,4362,9142,0052,6363,372
————
290749
1,100———219
—————
427325
2,11525,731
24,471
to economic shocks by writing off bad invest-ments, selling capital stock to new investors whocan make a profit because they are buying at bar-gain prices, restructuring to reduce costs, rethink-ing their investment strategies, and developingnew technologies that can better deal with achanged business environment. For larger inte-grated companies and independents without siz-able debt loads, bank loans and private financ-ing appear to remain available. Even though thesefunds have been largely used to refinance exist-ing obligations, to repurchase shares, and to ac-quire assets of other companies rather than tofund new exploration ventures, it is by no meanscertain that this spending pattern will continue.
It may be overly pessimistic to assume that theoil industry’s level of investment in explorationand development will not improve without a risein oils prices that will restore some of the profit-ability of prior investments and boost cash flows.In the long run, the level of investment in E&D
–21–1131
– 2 0–19– 3 7
————
– 3– 8
–40———
–43—————
– 5 7–298
–35–25
—
145181252237339363————
135427526———
2655————————
263
213
233396308217264216————
198116239———
233—————
405298196239
238
may be determined primarily by the basic eco-nomics of exploration and development, as de-fined by the question: How much return on in-vestment can be gained by an additional dollarof investment? If new investments in oil explora-tion and development appear profitable, compa-nies may once again plow back more of theirfunds into those ventures, and either new sourcesof capital could appear or else the old sourcescould return.
However, a critical and highly uncertain issue,for which there are no readily apparent answers,is the amount of time it might take for investmentcapital to return. Given the rapidity of projectedproduction declines, an uncertainty of a year ormore in a recovery from the industry’s capitalflight translates into a substantial uncertainty inthe amount of any actual production decline. Fur-thermore, it is probable that any initial injectionof capital into the industry will tend to gravitateto the lowest-risk opportunities. For a time, these
71
opportunities may be the purchase of reservesand producing properties.26 Only after the inven-tory of available properties shrinks is capital likelyto flow primarily to the exploration and devel-opment activities needed to revitalize the in-dustry.
Premature Loss of ExistingProduction: Stripper Wells
There is widespread concern that low oil priceswilI force many of the Nation’s “stripper” oilwells, wells averaging 10 barrels or less per day,to shut down, with many or most never to re-open, their reserves lost. This concern is magni-fied by the importance of stripper wells to theU.S. oil supply, Approximately 1.3 mmbd–14percent of total domestic oil production—areproduced by stripper wells. There are over400,000 of these wells in operation, producingan average 2.8 barrels daily .17 U.S. oil reservesassociated with stripper wells total about 4.5 bil-lion barrels,28 16 percent of current U.S. reservesof 28.4 billion barrels .29
A large shutdown, were it to occur, would af-fect a few States disproportionately. Betweenthem, Texas and Oklahoma have a bit over halfthe Nation’s stripper well production. Addingstripper production from California and Kansasincorporates fully three-fourths of the Nation’sstripper production .30
The concern about shutdowns stems from thewells’ physical characteristics as well as from theState and Federal regulations that govern them.Many of the wells have high per barrel operat-ing costs because their maintenance costs arespread over so few barrels of production and alsobecause, in many areas, the well production in-cludes a high proportion of water that must be
2bTh~ ~rlC~ O( Olj and gas reserves has plunged from about $9/BOE
I n the ti rst quarter of 1984 to about $5/BOE In the th Ird quarterof 1986. Source: Strevlg & Associates, In Business Week, Dec. 1,198b, p. 114.
“AS of Dec. 31, 1984, from Interstate 011 Compact Commissionand National Stripper Well Association, “National Stripper WellSur\ey, ” Jan. 1, 1985.
~gl bid.XIA5 ot Dec. 31, 1985, irom Energy I ntormat!on Adm I n IStrdtl On !
Ad\ance Summary ot the U.S. Crude 011, Natural Gas, and Natu-ral Gas L\qu\ds ReserLes 1985 Annual Report, September 1986,DOE/EIA-0216(85)Ad\ance Summary.
101 nter~[ate of I compact Corn m Isslon, OP. clt.
pumped to the surface, separated from the oil,and properly disposed of. At low oil prices, rev-enues from oil sales may drop below operatingcosts for many wells. For other wells with smallpositive cash flows during ordinary operation, theonset of any extraordinary repair costs may sig-nal an impending well closure. And even with-out closure, many operators are likely to delayneeded repairs and thus forfeit the additional pro-duction rates these repairs would allow.
If the oil production from shut-in stripper wellscould be restarted, there wouId be no impact onnational security. in many cases, however, pro-duction shutdowns will be permanent. For ex-ample, for “water-drive” wells—wells where for-mation water pressure moves oil to the well bore—a prolonged production shutdown may ruin thewell, i.e., renewed pumping would produce onlywater. For all stripper wells, the time period dur-ing which a well’s production can be shut in islimited by State and Federal regulations to pre-vent contamination of groundwater aquiferspenetrated by the wells. Prior to the current pricedrops, most State and Federal regulations limitedshut-ins to 90 days, with requirements that thewell either be returned to production or be per-manently plugged (with a concrete seal) after thatt ime. Wi th cur rent wel l -p lugging techniques,reentering a well is said to be little different i ncost from drilling a new well. For wells with par-ticularly low production rates, it seems unlikelythat production would ever be restarted, andplugging these wells would likely result in a per-manent loss of the reserves associated with thewells. Because of the concerns about a wide-spread loss of both production and reserves,some States have lengthened their shut-in graceperiod to a year or more.31
There is little disagreement with the thesis thatoil prices at levels near or below $15 per barrelwill have a significant adverse effect on stripperwell closure rates and U.S. oil production rates.Unfortunately, however, a general lack of dataon stripper wells makes it quite difficuIt to esti-mate quantitatively just what the effect will be.
~ 10j the two States with the h Ighest st rl pper product Ion, Texas
now allows 1 year and Oklahoma 2 years before a shut-tn well mustbe plugged, The Department of the Interior also has lengthenedits grace period to 1 year t’or well~ on Federal leases. Energy DaI/),July 21, 1986, and other dates.
72
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Also, the severe dislocations caused by the sud-den price drop have altered operating and othercosts and may have affected the business strate-gies followed by the well operators.
Estimates of production losses generally assumethat traditional operating costs and business prac-tices still apply. These estimates will likely over-estimate the effect of lower oiI prices. The loweroil prices have been accompanied by small butsignificant reductions in day-to-day operatingcosts and large reductions in costs for major itemssuch as well reworking. Operators are negotiat-ing with their service companies for lower pricesor switching to alternative services. They are cut-ting labor to the bone and deferring maintenance.32
In some States, authorities are pressuring utilitiesto grant lower rates of service to well operators.For example, the Oklahoma Corporation Com-mission has ordered the State’s utilities to developlower electricity rates for oil wells, with reportedrate reductions ranging up to 22 percent. 33 And,in the face of declining oil production and threatsof extensive well closures, States may take ame-liorative actions such as cutting taxes to preventthe loss of jobs and the other economic hardshipsthat the closures would create.
Before the price drop, stripper well operatorsgenerally would abandon wells as soon as the in-coming oil revenues could not cover cash costs.Unless fracturing or some other production en-hancement treatment (most of which are expen-sive) could boost production, there was littlelikelihood that the well would be profitable againsoon enough to justify continuing to operate itat a loss. In the current situation, however, manyoperators are likely to believe that there is a fairlyhigh probability that prices will rise sufficientlyquickly, and to high enough levels to justify con-tinuing production for (currently) unprofitablewells. Indeed, many stripper well owners viewtheir wells as a family inheritance, one that hasprovided the means to keep family farms or edu-cate their children. These owners are especiallyunlikely to give up their wells in the face of what
~zof Course, deferring maintenance wi II cause production prob-lems sooner or later,
~~fnergy Da;/y, JU!Y 21, 1986.
many see as a short-lived attempt by OPEC toeliminate its competitors, to be followed by aninevitable price hike.
OTA knows of two analyses of the potentialstripper oil production lost to low oil prices. Onewidely quoted analysis was sponsored by the In-terstate Oil Compact Commission and conductedby The RAM Group, Ltd. of Oklahoma City.34 Thisstudy first computes the stripper well productionat different oil prices in Oklahoma using data ob-tained for that State’s wells, and assumes thatother States will sustain the same percentage strip-per well production loss at each price level asOklahoma. The study also assumes that wells willshut down when cash flows become negative,that is, when operating expenses exceed oil rev-enues.35
The results of the study for the United Statesas a whole are shown in table 29. At a $15 oilprice, the study predicts a first year productionloss of 277,000 barrels per day (bbl/day), or 3 per-cent of U.S. production.
The general approach of this analysis seemsreasonable given the limited data, although OTAbelieves that the focus on cash flow and the in-ability to account for still-continuing changes inoperating costs will tend to lead to an overestimateof the likely production loss. Also, the pattern ofresults as shown in table 29 does not appear real-istic. Taken together with the data problems, theproblems with the trends shown in the publishedresults may limit the usefulness of the results asthe basis for policymaking. OTA’s overall objec-tions are explained in more detail in box B.
The second analysis was conducted by theDallas Field Office of the Energy InformationAdministration as part of their short-term oil pro-duction forecasts.36 In this analysis, EIA used dataon oil, water, and gas production from Dwight’sEnergy Data, Inc. production tape and Dwight’s
3<lnterstate oil compact Commission, ‘‘Impact of Decreasing
Crude Oil Prices on Stripper Oil Wells, Production, and Reserves, ”The RAM Group, Ltd.
3~Wjlllam Taljey, President, The RAM Group, Ltd., personal com-
munication, 1986.36 Energy Information Administration, Short-Term Energy Outlook
ju/y 1986, DOE/ElA-0202(86/3 Q), August 1986, updated by letterof Apr, 7, 1987, John Wood, Dallas Field Office, EIA to Steve Plot-kin, Office of Technology Assessment.
73
Table 29.—Effect of Falling Oil Prices on Stripper Wells*
Gross value ofPercentage of Number of Production production lost Total
Oil price stripper wells stripper wells lost first first year reserves lost($/bbl) abandoned abandoned year (b/d) (thousand $) (million bbl)
$10/bbl . . . . . . . 40.8 184,547 638,046 2,328,869 2,610.880$15/bbl . . . . . . . 22.5 101,958 277,090 1,517,065 733.812$18/bbl . . . . . . . 15.6 70,370 175,746 1,154,654 278.490$20/bbl . . . . . . . 10.0 45,390 106,586 778,077 92.783$23/bbl . . . . . . . 5.0 22,446 49,756 408,618 16.862$25/bbl . . . . . . . 0.0 0 0 0.000 0.000* Based on 452,543 stripper wells as of Jan. 1, 1985, and average production of 2.8 bbl/day.
SOURCE: Interstate Oil Compact Commission and Ram Group Ltd. , 1988, in Oil and Gas Journal, Mar 3, 1986, page 38
Petroleum Data System, and published well oper-ating cost data37 to construct a distribution ofstripper wells according to their oil production(and, given an oil price, their revenues) and oper-ating expenses, by State. The primary data prob-lems were the unavailability of water productiondata (critical to determining well operating costs)for some States and the overaggregation of muchof the production data, some of which was avail-able only at the field level.
The EIA analysis estimates that first year pro-duction losses will be 148,000 bbl/day at an oilprice of$15/bbl, with additional losses of 77,500bbl/day a year or two in the future as more wellsare abandoned when major expenditures be-come necessary, for a total loss of 225,000bbl/day. At $18/bbl, first year losses are 85,000bbl/day, with additional losses of 4,300 bbl/daylater, yielding a total loss of 89,300 bbl/day. Forthe $15/bbl case, the major State losses occur inTexas (73,900 bbl/day total, or 18 percent of Statestripper well production), California (46, 100 bbl/day, or 29 percent), Louisiana (15,400 bbl/day,or 57 percent), Oklahoma (1 3,400 bbl/day, or 5percent), New Mexico (1 2,400 bbl/day, or 30 per-cent), and Kansas (6,200 bbl/day, or 5 percent).
Overall, the EIA estimates of first year stripperwell losses are about half the IOCC/RAM esti-mates. However, although the difference be-tween the two sets of estimates may appear great,in OTA’s view the differences in the national to-tal are not at all unusual given the lack of data.
I~\’,T, Funk a n~ T,C. A n d e r s o n , D a l Ias Field C)ttice, Energy In-
tormatlon Admtnlstration, Costs and /rrdices for Dornestlc 0;/ andGas Fle/d Equjpment and Production Operations 1985, DOE/EIA-0185(85), April 1986.
The EIA analysis’ wide State-to-State differencesamong the fraction of total production that isabandoned is, however, quite different from theRAM analysis.
More recently, an IOCC survey of California,Kansas, New Mexico, North Dakota, Oklahoma,Texas, and Wyoming indicated that 110,000 wellsin these States, with 307,000 bbl/day of oil pro-duction, were shut in during 1986, with 12 per-cent of the wells permanently abandoned. * Thesevalues do not break out the production lost solelybecause of low oil prices (each year, thousandsof wells are abandoned even at high oil prices),and thus they are not strictly comparable to theprojections above. However, most of the produc-tion loss is likely to be attributable to the pricedrop, and the survey appears to add credibilityto the (higher) IOCC projections. However, thestate-by-state breakdowns show a wide variationamong the States in the percentage of produc-tion lost (range: 3.6 to 11.1 percent), contrary tothe assumption of interstate uniformity in theIOCC analysis.
As noted above, warnings about impending re-ductions in stripper well production invariably in-clude the prediction that the reserves associatedwith the abandoned wells will be lost, either for-ever or until oil prices reach $50 to $100 per bar-rel. This is undoubtedly true for older wells thathave depleted a major share of their original re-coverable oil, or for newer wells that have beenfractured and have already passed through theinitial production surge associated with fractur-ing, assuming the use of current well abandon-ment techniques and well drilling technology.*Oil and Gas Journal, Apr. 27, 1987, p. 24.
74
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I
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However, much of the drilling during the recentboom was aimed at geologic targets that prom-ised stripper-type production levels. This impliesthat, where a substantial level of depletion hasnot occurred, a return to the economic condi-tions of the late 1970s to early 1980s may allowrecovery of the “lost” reserves through newdrilling. in addition, previously there was no in-centive to devise well plugging techniques thatwould allow a relatively inexpensive reentry intothe well. If such techniques could be devised, orif advances in drilling technology substantially de-creased drilling costs, stripper abandonmentcould be reversed more readily.
The Nature of the Resource Base
The nature of the oil exploration and develop-ment prospects available to the industry and, inparticular, the distribution of high- and low-costoil is a primary determinant of future supply, anda critical uncertainty. Future development pros-pects, for example, range from a variety of en-hanced recovery operations, to infill drilling andextensions, to high cost development in the Arcticand deep offshore; exploration prospects simi-larly range from new pools in old fields, to largenumbers of small onshore fields, to the searchfor giant fields in difficult frontier areas. There issubstantial controversy about the number of via-ble prospects in each category, and thus a simi-lar degree of controversy about the true replace-ment costs of oil and the likely supply responseat any price.
There are three types of prospects that repre-sent the critical sources of uncertainty in consid-ering the ability of the remaining U.S. oil resourcebase to support continuing development and pro-duction, especially in a low price environment.These are:
●
●
●
the range of conventional drilling prospectsthat create field growth,exploration for small fields. andexploration for large fields including frontiergiants.
The Prospects for Continued High Levelsof Field Growth
The basic argument that continuing low oilprices will devastate future U.S. oil productionhinges on the conception of the U.S. oil resourcebase as a mature, high cost resource base. Ac-cording to this concept, most of the United States’low-cost oil has been found and produced; in-creasingly, new production must come from oilfinds in hostile, expensive frontier areas or fromhigh technology, high cost enhanced oil recov-ery operations, and neither of these sources canbe developed at world oil prices of $15/bbl.
The recent history of the oil industry’s effortsto regenerate the United States’ oil reserves im-plies that this conception of a high cost resourcebase may be somewhat misleading. It is true thatthe geographic and technological frontiers—com-plex enhanced oil recovery technologies, drillingin the deep waters of the Outer Continental Shelf,onshore drilling to depths well below 15,000 feet,and exploring and producing in the extreme con-ditions of the arctic–have captured the majorpublicity. However, the great majority of oil re-serves added to the U.S. inventory during recenttimes has come from non-glamorous sources.Fully 70 percent of the total U.S. reserve addi-tions during 1979 to 1984 came from drillingthousands and thousands of extension and infieldwells in the United States’ large inventory of dis-covered oilfields. If Alaska and the offshore aresubtracted, extensions and infield drilling frompreviously discovered fields accounted for 76 per-cent of reserve additions during the last decade,up from 66 percent during the 1950s and 1960s.38The potential for continuing high rates of reservegrowth in discovered oilfields at relatively lowcost is one key to the future of U.S. domestic oilproduction in a low price environment.
When new fields are discovered, their reservesare “booked” according to the geologic infor-mation gained from the discovery well and otherinitial delineation wells. For most fields, the ini-tial estimates of reserve volumes are associated
J8W. L, Fisher and R.J, Finley, ‘‘Texas Still Has Blg Resource Bdse,
Oil and Gas journal, June 2, 1986, pp. 57-69.
76
I
I
I
II
!I
I
,IIII
only with those wells drilled in the discovery year.Afterwards, as the field is developed, the reserveestimates change, and most often grow. Reservesgrow as additional wells are drilled to delineatethe field’s outer boundaries (extension wells) orto find additional reservoirs associated with thefield (new pool tests). If prices rise or more effi-cient recovery technologies are developed, areasof the field that were previously subeconomic willbe developed with additional development wells.Further knowledge of the reservoirs gained byproduction histories may lead to revisions in thereserve estimates, or may indicate that the exist-ing well spacing is not recovering all of the re-coverable oil, leading to an infill drilling programthat can add to total recovery and thus to re-serves. Rising prices may change the “abandon-ment” point (when the well is shut in becauseoperating expenses overwhelm revenues) of theexisting wells, leading to further positive reserverevisions. I n some cases, for example when thereservoir rock has low permeability, well stimu-lation techniques such as fracturing may allowincreased recovery, further adding to reserves.Finally, the portion of the oil-in-place that wouldnot normally flow to the wellbore might be re-covered with enhanced oil recovery (EOR) tech-niques that loosen the oil’s bonds to the rock byheating or chemical means or that drive the oilto the well using a fluid or gas.
How will U.S. fields grow in the future? Thehistorical record of reserve additions suggests thatolder oilfields have “grown” by a factor of about7 to 8 and gas fields by a factor of about 4 overthe 60-year period from 1920 to 1979.39 Thus, thepotential for further reserves from field growthwill depend on the extent to which these oldfields will continue to grow, and the extent towhich more recently discovered fields, and newfields, will duplicate the growth potential of theolder fields.
The primary argument for a relatively high re-serve growth in new fields and continuing growthin older fields is that the volumes of “mobile
oil’’—oil that can be recovered with conventionaldrilling and well stimulation techniques–havebeen consistently underestimated, and that largeamounts of this oil can be recovered with moreintensive drilling even in the Nation’s most ma-ture oil basins. Proponents of this view point tothe 1978 USGS estimate, based on a statisticalanalysis of past field growth, of potential reservegrowth in Texas. The estimated ultimate growthof 4 billion barrels has already been virtuallyachieved in the 8 years since the original estimatewas made,40 and growth is continuing at a steadypace.
A high estimate of the volume of mobile oil inexisting oilfields is based on the proposition thatthe so-called “macroscopic” heterogeneity ofhydrocarbon reservoirs is “the least studied, theleast known, and the most difficult of the . . .types of variations to define with precision,”41
and is often ignored or severely underestimated.Macroscopic heterogeneity refers to changes inreservoir characteristics that can partially orwholly isolate significant volumes of the reservoir,extending a few acres a realIy or a few feet verti-cally, from the remainder of the reservoir. lso-Iated compartments or layers of this nature wouldbe obvious targets for infill drilling and multiple-zone completions.
A recent study of the potential volumes of mo-bile oil over and above that recoverable withnormal field development suggests a “target” onthe order of 80 billion barrels of mobile oil-in-place for the total United States, with an un-known but possibly high fraction of that beingeconomically recoverable.42 Continued advance-ment of the state-of-the-art of reservoir model-ing and engineering, it is hoped, will allow infilldrilling and well stimulation programs to beundertaken with relatively low technical risk. As-suming that this is so, the potential profitabilityof investments aimed at recovering additionalmobiIe oiI wiII depend on the trade-off betweendrilling and stimulation cost, on the one hand,
‘qD. H. Root, “Estimation of Inferred Plus Indicated Reserves forthe United States, ” app, F In G, L. Dolton, et al Estimates of’ theUndi$co\ered Reco~erable Conventional Resources of oil and GasIn the Urrlted Stafe5, U.S. Geological Survey Circular 860, 1981.
~OLewi n & Associates, I nc,, Re$erve Growth and Future b’. S. oil
Supp/ies, prepared for U.S. Department of Energy, June 30, 1986.~~w~. Fisher and VV. E. Galloway, “Potential for Additional Oil
Recovery in Texas, ” Geological Circular 83-2, Buredu ot’ EconomicGeology, The Unlverslty of Texas at Austin, 1983.
~~Lewi n & Associates, I nC. , Op. L It.
77
and the additional oil volumes recovered. Thereferenced study43 gives some examples of infillprojects that appear, on the basis of the reserves/well recovered, to have some economic poten-tial even at today’s low oil prices if drilling costscan be sustained at current low levels. However,there is little guarantee that these examples arereflective of the actual resource potential; it isworth noting that the analysts primarily respon-sible for raising the issue of mobile oil are acutelypessimistic of the potential for continuing highrates of field growth at current low prices .44
To place this potential for field growth in fur-ther perspective, it is important to note that thereis by no means a consensus that heterogeneitieswithin known field boundaries will yield largequantities of additional oil. Controversy about theability of infill drilling to add substantively toreserves—rather than just to speed production—has continued for years. In 1967, a massive studyof 312 reservoirs by the American Petroleum In-stitute’s Subcommittee on Recovery Efficiencycould not determine a relationship between wellspacing and ultimate recovery .45 And a recent re-view i n the Journal of Petroleum Technologyreiterated that:
A key question in the debate is: “What portionof the additional oil recovered by infill drilling re-sults from accelerated production of old reservesand what portion resuIts from increased reserves?”This relationship is hard to quantify, and assess-ments differ.46
OTA’s past work supports an optimistic viewof the potential for infill drilling to add significantlyto recoverable oil reserves. In a previous study,OTA examined the question of infill drilling’s abil-ity to add substantially to domestic gas reserves.47
As part of this examination, OTA conducted aseries of interviews with persons familiar with infill
4‘1 bld-$~Fj5her and Fin !ey, Op. cit.~JA. F, van Everdingen, letter to George Fumich, Department of
Energy, January 1980.4b’’lndustry Weighs Infill Drllllng and EOR In Plannlng To Max-
)m)ze Uhlmate Production, ” Journa/ ot’ Petro/eurn Technology, No-vemher 1983,
47u, S. Congre55, Office ot’ Technology Assessment, Energy andMaterials Program, S(a~l’Mernorandurn on the EfYects of’ Decontro/on (lid Gas Recovery, February 1984.
drilling and reservoir analysis. OTA found a def-inite majority in favor of the view that infill drillingcould add substantially to gas reserves, not onlyin fields that were widely known to be hetero-geneous, but also in fields that were generallyconsidered to have relatively homogeneous,blanket-type reservoirs. This majority favored theview that recent experience supported the viewof oilfields as more heterogeneous than previ-ously understood, that this led to a substantialpotential for increasing ultimate recovery throughcarefully selected infill drilling, and that this ex-perience applied to gasfields as well.
Aside from the technical argument about reser-voir heterogeneity, many producers argue thatthe large amount of infill drilling conducted inthe 1970s and early 1980s has used up most ofthe infill potential in the Nation’s stock of olderfields, or at least that portion of the potential thatwas economic at the earlier oil prices. Further-more, these producers argue that today’s “lessfavorable” drilling economics reduce the currentinfill potential still further. The investigations ofinfill potential have not as yet produced detailedevaluations of the distribution of drilling prospectsthat would allow an economic analysis. As im-plied by OTA’s analyses of some limited drillingventures, however, low risk drilling prospectsmay be less attractive to producers at prices of$14/bbl or so than were identical ventures a fewyears ago, but prices closer to $18 or $20/bblcould turn this around; lower drilling costs havelowered significantly the “minimum requiredprice” for most prospects.
Pessimists about the role of future field growthalso believe that new fields may have less ulti-mate growth potential beyond their first year re-serve estimates than the older fields. For onething, the size distribution of new fields isweighted more heavily towards the smaller endof the spectrum, both because the largest fieldstended to be discovered first and because recenthigher prices had allowed fields to be developedin a size range that would have been termed un-economic in earlier times. Most analysts wouldexpect field growth to be highest for large fields,because the first year’s discovery and delineationwells will discover more of a small field’s reserves
78
than they will of a large field’s reserves.48 Also,the location of many recently discovered fieldsin the offshore or frontier areas far from estab-lished pipelines demanded better delineation offield size before the reserves could be bookedand transportation systems developed.49 Our im-proved seismic technology and understanding ofreservoir behavior also would tend to yield better—and generally higher—initial reserve estimatesfor newly discovered fields.
Exploration for Smaller Fields
A second important resource issue concernsthe extent to which smaller fields–many of whichmight have been considered “dry” under previ-ous economic/technological conditions—couldprovide substantial reserve additions, and pro-duction, in the coming decades. This issue hingeson both the magnitude of resources containedin small fields and the economic viability of pur-suing small fields as a major exploration target.
Historically, small fields have played a minorrole in oil and gas development. Fully 80 percentof all discovered oil and gas resources were foundin fields of at least 50 million barrels of oil equiva-lent, whereas 1 million BOE is considered the cut-off point for “significant” field size. The size dis-tribution of discovered oil and gasfields is shownin figure 7. As shown in the figure, as one movesto smaller field sizes, the number of discoveredfields increases steadily down to about AAPGField Size D and then rapidly levels off. At leasta portion of this “truncation, ” or leveling off, ofthe field size distribution is undoubtedly due topast economics. Many small finds were too smallto be economically developed and consequentlywere reported as dry holes rather than added tothe historical record as a class D or E field. Also,explorers may have been quick to abandon the
daone interesting though specu Iative counterweight to this argu-
ment is the observation that reserves found in small fields have more“boundary” than an equivalent magnitude of reserves in large fields(small volumes have a larger ratio of circumferential area to volumethan large volumes), and thus may have more potential for exten-sions. Source: Charles Matthews, Senior Consultant, Shell Oil Co.
qgHowever, the proportion of U.S. oil production from offshore
areas has been relatively stable for the past two decades; the ma-jor period of growth was from the middle 1950s to the late 1960s.This somewhat weakens the lower field growth argument for oil.On the other hand, the proportion of offshore gas production hasincreased steadily from the 1950s to the present.
search for additional fields in a productive areawhen it appeared that most or all remaining findswould be small. Thus, it has been argued that afield size distribution of all fields, discovered andundiscovered, would look more like the dark barsin figure 8. This distribution assumes that theprogression of field sizes established by the dis-covered larger fields would continue for the smallerfield sizes if economics did not intrude.
Arguments about the number of small fieldsthat may be available for exploitation are neces-sarily speculative because they are based on ex-trapolation only; no petroleum basin has experi-enced the intensity of drilling that would berequired to find the postulated number of smallfields. Some past experience with field size dis-tributions supports the general principal that atleast part of the dropoff in the number of smallfields is caused by economic rather than geologicforces, however. For example, USGS studies offield size distributions in the Gulf of Mexico, theDenver Basin, and the Permian Basin show thatthe “truncation point” of the distribution movesto larger field sizes when exploration and devel-opment costs are higher, which would be ex-pected if the truncation were economically de-termined. 50 On the other hand, some analystsargue that certain types of petroleum basins—containing a significant portion of U.S. petroleumresources—show a dropoff in the number of dis-covered fields at a field size level that is too highto be explained by economics.51
If the most optimistic field size distributionpostulated in figure 8 is correct, or largely cor-rect, there may be a substantial oil and gas re-source residing in small undiscovered fields. inmany instances, these fields would be in produc-ing areas with an existing pipeline and process-ing plant infrastructure, so development costswould be low. However, the small size of thesefields implies that the costs of discovery will be
5oJ. H. Scheunemeyer and L.j. Drew, “A Procedure To Estimatethe Parent Population of the Size of Oil and Gas Fields As Revealedby a Study of Economic Truncation, ” Mathernat;cal Geo/ogy, vol.
15, No. 1, 1983.51 R. Nehring, The Discovery of Significant Oi/ and Gas fields in
the United States, R-2654/l-USGS/DOE, RAND Corp., January 1981,pp. 78-94. Excursis, “The Distribution of Petroleum Resources byField Size in the Geologic Provinces of the United States. ”
79
40,00(30,000
20,000
10,000
5,000
1,000
500
100
50
20
0
Figure 7.— Size Distribution of Discovered Oil and Gas Fields in the Lower 48 States
20 19 18 17 16 15 14 13 12
bcf IntervalsAAAA >3000AAA 1200-3000AA 600-1200 2
300-600 3150-300 460-150 5
6-60 6<6
9101112131415161718
bcf
76,800-153,60038,400- 76,80019,200- 38,4009,600- 14,2004,880- 9,6002,400- 4,8001,200- 2,400
600- 1,2003oo- 600150- 30075- 150
37.5-18.75- 37.59.38- 18.754.69- 9.382.34- 4.691.17- 2.34
.59 - 1,17
.29- .59
.15- .29
11 10 9 8 7 6 5 4 3 2 1
Field size
SOURCE: R. Nehring. “Problems in Natural Gas Reserve, Drilling, and Discovery Data,” contractor report to OTA, 1983
high, assuming historic ratios of dry holes to suc- possibility that substantial quantities of oil can becessful new field wildcats. Past studies of the eco-nomics of oil and gas recovery from the PermianBasin show that the number of exploration wellsthat will be drilled is extremely sensitive to oilprices, with as many as 38,000 exploration wellsdrilled at $40/BOE wellhead prices but only 5,000drilled at a $10/BOE price.52 Consequently, the
~zu ,s. Geological SU rvey, Circular 828—Future Supply otO;/ and
Gas From the Perm/an 13asln of West Texas and Southeastern ,Ne\iMexfco, Interagency oil and Gas Supply Project, 1980, It shouldbe noted, however, that the economic model used In this studydoes not capture the effect on drtlltng rates and resource economicsot the dependency of drilling costs on 011 prices
recovered from small fields at low oiI prices de-pends primarily on the potential to lower thecosts of discovering these fields by improving dis-covery technology and raising the success rateof exploratory drilling.
Finding New Large Fields
A third key to the continuation of high ratesof reserve replenishment and the maintenanceof long-term oil production is the extent to whichU.S. oil explorers can continue to find large newfields at rates comparable to those of the past dec-
,I
I
:
i
80
Figure 8.— Known and Projected Size Distributions of Discovered Oil and GasFields in the Lower 48 States
40,00030,000
20,000
10,000
5,000
100
50
20
0 20 18 17
Intervals bcfbcf
AAAA >3000 1 76,800-153.600
14 13
Field size
AAAAAA
DE
1200-3000 2 38,400- 76,8003 19,200- 38,4004 9,600- 14,2005 4.880- 9,600
4.800150-30060-150
6-80<6
6 2,400-1,200-
600-9 3oo-
10 150-75-
37.5-13 18.75-14 9.38-
4.69-16 2.34-17 1.17-18 .59-
.29-20 .15-
2,4001,200
600300150
37%18.759.384.692.341.17.59.29
6 5 4 3 2 1
SOURCE: Office of Technology Assessment, based on data from R. Nehring,“Problems in Natural Gas Reserve, Drilling, and Discovery Data,” contractor report to OTA, 1983
ade and a half, and whether any of the few re-maining prospects of extremely large size will besuccessfuI.
Since the early 1970s, the industry has discov-ered between 200 and 250 “significant” oil andgas fields (of size greater than 1 million BOE)every year.53 In addition, the per well “findingrate” of exploratory drilling, which had been fall-ing for decades, stabilized during the same timeperiod and now appears to be relatively flatat about 470,000 BOE per exploratory well.54
Nevertheless, this finding rate has not been suffi-cient to allow new field discoveries to play a reallycrucial role in reserve replacement during thepast decade. For example, during 1979 to 1984new field discoveries (with expected field growth)have added only about 2.4 billion barrels of re-serves to the U.S. total, out of a total of approxi-mately 15 bil l ion barrels added during thisper iod.55 The reason for this is that very few ofthe new fields found have been the “giants” thatplayed such a major role in the United States’emergence as an oil superpower. I n recent years,the search for very large fields has been disap-pointing, with the well-publicized Mukluk dryhole being only one of a string of failures. Recentexploration efforts in the Gulf of Alaska, EastCoast Jurassic Reef Play, Georges Bank, BeaufortSea, St. Georges Basin, and the Norton and Nava-rin Basins have been either outright faiIures orhave produced far fewer discoveries than antic-ipated, and recent assessments of U.S. recover-able petroleum resources are said to have se-verely downgraded prospects for frontier oil andgas. During the past decade, only six “one bil-lion BOE’’-size plays have been discovered–’’theBarrow Arch oil and gas trend in Alaska, theNorthwest Santa Barbara Channel oil trend inCalifornia, the overthrust Mesozoic oil and gasplay in Utah and Wyoming, the Pliocene trend
~ JR Neh rl ng OTA workshop on the Effects of Lower Oi I prices
on U.S. Oil Production, June 25-26, 1986.5~T, j, Woods and p.D. Holtberg, “Hydrocarbon Activity in an
Era ot Low Oil Prices,” Society of Petroleum Geologists Paper 15355,1986.
jJLewi n & Associates, Inc., Reserve Growth and Future U.S. OilSupp/les, op. cit., based on Energy Information Administration, U.S.Crude VII, Natural Gas and Natural Cab Liquids Reserves, 7984Annual/ Report, DOE/E IA-021 6(84), September 1985,
81
offshore Louisiana, and the Pleistocene Shelf andSlope trends offshore Louisiana and Texas.” 56
In the continuing search for large fields, the in-tersection of resource base issues and prospecteconomics comes into sharp focus. There still aresufficient geologic opportunities to continue the“baseline” discovery of 200 to 250 significantfields yearly if the exploration effort aimed at find-ing these fields holds up . . . but it is precisely in
the area of exploration for new fields that indus-try analysts are most pessimistic about continu-ing the previous level-of-effort. Many companiesare telling their stockholders that the focus of theirreserve replacement efforts wiII be shifting awayfrom exploration in the United States and towardsfield development. On the other hand, the “lowoil price” run of the Gas Research Institute’s Hy-drocarbon Model, discussed elsewhere, indicatedthat, on a resource economics basis, exploratorydrilling could hoId up quite well. An accurateforecast of the level of exploratory drilling is crit-ical to obtaining a credible forecast of reservereplacement and future U.S. production.
For the very most promising areas—those thatappear to have real prospects for supergiantfields–arguments about current resource eco-nomics may be somewhat meaningless becausethe only remaining areas with such promise arein the deep offshore and Arctic regions, with timelags between leasing and production of a dec-ade or more. It does not appear likely that themore aggressive majors wouId pass u p opportu-nities to explore in these areas, because oil pricesat the time of any production are unlikely to bearany relationship to today ’s.
Two such prospective areas critical to longerterm U.S. oil production potential are the un-leased California offshore and the coastal plainof Alaska’s Arctic National Wildlife Refuge (ANWR).Both these areas boast structures that could holdreserves of supergiant size, although the recentMukluk disappointment should serve as a warn-ing that there often is a long distance betweenpotential and reality when it comes to petroleum
%bcom m ittee on U.S. C) I I and Gas outlook, National petroleum
Council, Factors Affecting U.S. Oil and Gas Out/ook, draft final re-port, Nov. 3, 1986, quoted with permission.
82
resources. Both areas are extremely controver-sial leasing targets as well, California because ofthe remembrance of the Santa Barbara spill anda longstanding aversion among many of theState’s residents to offshore development, andAlaska because of the wildlife and wildernessIssues.
Because the ANWR is considered by many ge-ologists to represent the most prospective remain-ing frontier area in the United States, and becauseit is today embroiled in controversy, OTA thoughtit useful to discuss it here in greater detail.
I
The Arctic National Wildlife Refuge
ANWR was established in the extreme north-east corner of Alaska in 1960 as the Alaska Na-tional Wildlife Range. It is the part-time residenceof approximately 180,000 caribou and millions,of waterfowl and home to such species of ani-mals as musk oxen, Dall sheep, wolves, arcticfoxes, wolverines, brown bears, polar bears, andarctic ground squirrels and other rodents. Origi-,nally comprising 8.9 million acres, the Range was
I expanded in 1980 to 19 million acres (about halfthe size of the State of Washington) with the
1 adoption of the Alaska National Interest LandsConservation Act (ANILCA). In all, ANILCA ad-ded more than 106 million acres to Federal con-servation systems in Alaska. ANWR was redesig-nated as a refuge at this time, and 8 million acres
1 of it were added to the wilderness system. At thebehest of Senator Stevens of Alaska, 1.5 million
i acres on the coastal plain, which were consid-ered to have significant oil and gas potential, wereset aside for further study. The area is known asthe 1002 area, since Section 1002 of ANILCA re-quired the Secretary of the Interior to prepare areport to Congress on the fish and wildlife re-sources and oil and gas potential of the area andto recommend whether further exploration, de-velopment, and production of oil and gas shouldbe allowed. A draft of the study was released inDecember 1986, and the final report was deliv-ered in April 1987.
Petroleum Resources
The western boundary of ANWR lies approxi-mately 60 miles east of the giant Prudhoe Bayoilfield—the largest in the United States. Prudhoe
Bay was discovered in 1968 and was estimatedto contain over 10 billion barrels of recoverableoil. Once in full production, the field producedabout 1.5 million barrels of oil daily —approxi-mately 12 percent of the crude oil processedthrough U.S. refineries each day. The so-called1002 area of ANWR, which is being consideredfor possible future mineral leasing, is located inthe coastal plain as is Prudhoe Bay and sharesmany of the geological features of that highlyproductive field. For this reason it is believed thatlarge recoverable oil and gas resources may alsooccur in ANWR.
All of the oil production from the Prudhoe Bayand the smaller adjacent Kuparuk River field isfrom sandstone rocks of the Ellesmerian se-quence. At the time the Ellesmerian sequencewas formed, conditions prevailed for the accumu-lation of potential petroleum-producing sedi-ments which are believed to have later under-gone transformation into hydrocarbons. Theporous Ellesmerian sandstone is believed to havepermitted the petroleum to migrate through theformation until intercepted and trapped by im-pervious, folded basement rocks. Geologists be-lieve that the petroleum potential of the 1002 areawill largely depend on the extent that the Elles-merian sequence underlies the ANWR coastalplain.
Other parts of the 1002 area are underlain bythe younger Brookian sandstone sequence whichis producing oil in the Endicott oilfield offshorePrudhoe Bay and in the Point Thomson field nearANWR. A number of offshore wells in the Cana-dian portion of the Beaufort Sea north of Mack-enzie Bay are also producing oil from Brookianrocks. Geologists expect fewer sealed traps to ex-ist in areas underlain by the Brookian sequence,hence the prospect for large quantities of petro-leum to exist in such areas is less than for theEllesmerian sequence. Oil seeps on the coast nearKaktovic, Point Thomson, and Demarcation Pointare additional evidence of oil potential in the1002 area.
In preparing its Section 1002 resource reportfor Congress, the Department of the Interior col-lected seismic information over 1,300 miles of theANWR coastal plain. Interpretation of the seismicdata by the U.S. Geological Survey identified 26
83
potential hydrocarbon traps. Underground fea-tures or structures in the northwest quarter of the1002 area appear to dip gently to the northeastwith comparatively little deformation, in a man-ner similar to the Prudhoe Bay structures. Thesoutheastern portion of the 1002 area is muchmore complex and contains many folded andfaulted structures. Complex geology of this kindmakes interpretation of the existing seismic datamore difficult, but several very large structuralclosures that couId contain oil have been identi-fied. Similar overthrust structures in the Canadianand U.S. Rocky Mountains have produced sig-nificant amounts of oil and gas.
The 26 identified possible hydrocarbon trapsare located in 7 plays (areas with similar geologiccharacteristics that share common geological ele-ments). Resource estimates for the 1002 area arebased on geologists’ judgment about the geologicfactors necessary for formation and retention ofoil and gas and evaluation of the properties thatcouId determine the size of a petroleum deposit.Based on such expert judgment, statistical anal-yses are used to determine probability estimatesof possible in-place oil and gas resources. Finally,economic analyses are applied to the geologicalestimates to determine the volume of oil thatcould be removed from the deposit using cur-rent technology.
Because of the inexactness of resource esti-mates based largely on seismic data, geologicalanalogies, and future cost-price assumptions, pe-troleum resource estimates such as those assignedto the 1002 area should be considered as “rela-tive indicators” for comparison with other poten-tial resource-rich areas rather than as absolute
volumes of recoverable petroleum. A shift in as-sumed oil prices can significantly change the eco-nomics of the minimum field size, which in turncan increase or decrease estimates of recoverableoil. Changes in the geologic assessment can dra-matically change the estimates of economically
recoverable oil. In the final analysis, estimates ofboth in-place and recoverable oil and gas re-sources should be considered more “guess-timates” than scientific assessments. Exploratorydrilling remains the only certain and totally ob-jective way to determine the presence and ex-tent of oil and gas resources.
it is clear that ANWR ranks high among therange of potential petroleum-producing prospectsremaining in the United States either onshore orin the Outer Continental Shelf. Even though theresource potential for the 1002 area is consideredto be great, however, USGS geologists give oddsof only one in five (20 percent) that a commer-cial discovery will be made in the entire areashould it be explored. This so-called “marginalprobability” for discovering an economic depositseems surprisingly low for an area with suchfavorable geological attributes and demonstratedoil production close by. However, the NationalPetroleum Reserve in Alaska (NPRA), which liesto the west of Prudhoe Bay about 50 miles in asimilar coastal setting, has thus far failed to yielda commercially important oilfield after substan-tial drilling, although the U.S. Geological Surveyestimated in 1979 that 7 billion barrels of oil in-place (not gauged by its recoverability) could beexpected.
DOI’s resource estimates for the 1002 area ofANWR are shown in table 30.
Table 30.—Estimated Oil and Gas Resources in the Arctic National Wildlife RefugeSection 1002 Area (recoverable volumes based on oil price of $33/bbl, 1984$)
Oil Gas(billion barrels) (trillion cubic feet)
Type of estimate 95 ”/0 Mean 5% 950/0 Mean 5%
In-place resources ... ... ... ... .>4.8 >13.8 >29.4 >11.5 >31.3 >64.5Conditional recoverable ... ... ..>0.6 >3.2 >9.2 — —Recoverable risked meanc . . . . . . . —
—>0.6 — — — —
a~otal volume below the ground of which perhaps 25 to 35 percent may be recovered economically An estimate based whollyon geological factors
bEconomlcal[y recoverable 011 that may be available If an economic deposit occurs The odds are one In five (20 Percent) thatthis WIII be the case
cThe estimate of Conciitlonally Recoverable 011 reduced 80 percent to allow for the possibil ity that none may occur
SOURCE U S Geological Survey
84
Undiscovered oil and gas estimates frequentlyresult in confusion during debates over resourcedevelopment on public lands. Petroleum geolo-gists express oil and gas resource statistics in threedifferent ways:
1.
2.
3
“In-Place” resources–the total volume ofpetroleum expected to occur without regardto economic recoverability or the chancesthat petroleum may not occur at all.“Conditional, Economically Recoverableresources’’—the volume of oil or gas thatcould be recovered under assumed eco-nomic conditions and levels of technology,ignoring the possibility that resources maynot occur at all.“Recoverable Risked Mean’’–the condi-tional economically recoverable resourceestimate adjusted downward by the prob-ability that oil or gas may not occur in com-mercial quantities in the area.
Each type of estimate has its uses, but one mustbe careful about the interpretation lest he bemisled. In-place resource estimates have not beensubjected to the vagaries of economic and tech-nological assumptions and predictions that de-termine how much of the oil in place can be eco-nomically recovered. Should oil actually bediscovered in economic quantities in the ANWR1002 area, in-place estimates can provide an in-sight to a field’s ultimate potential as technologiesor economics improve. This is important for long-range planning in anticipation that drilling andproduction technologies may improve or thatenergy prices may change in the future.
Conditional economically recoverable oil andgas estimates, on the other hand, provide infor-mation useful in determining the economic andstrategic potential of a prospect based on exist-ing or foreseen economic and technologicaltrends. It provides a basis for evaluating the worst-case scenario for environmental and socioeco-nomic impacts that could result from develop-ment of the ANWR 1002 area should commer-cially important discoveries occur. The chancethat commercial-scale deposits may not occur inthe area is not a factor considered in the condi-tional estimate.
Risked mean economically recoverable oil andgas estimates factor in the possibility that no eco-nomically recoverable resources exist in the 1002area. This reduces the conditional estimates ofrecoverable oil in proportion to the risk that nocommercially recoverable oil exists in the area.In the case of ANWR, 3.2 billion barrels of eco-nomically recoverable oil is reduced by 80 per-cent (the probability that no commercial discov-eries of oil wil l occur in the 1002 area) todetermine the risked mean estimate of about 640million barrels of oil. Natural gas was not con-sidered currently economically recoverable,hence no estimates of gas were included in ei-ther the conditional and risked mean estimates,although a mean of 31 trillion cubic feet are esti-mated to occur in-place.
The risked mean resource estimate accountsfor the realities of exploring for oil and gas in fron-tier regions where few exploratory or stratigraphicwells have been drilled. It is most useful for esti-mating regional and national oil and gas re-sources, where estimates of the potential re-sources in several unexplored areas must becombined, or for comparing areas. In the offshorefrontier OCS areas, the marginal probability thatoil might occur ranges from one percent in theHope Basin to 70 percent in the Beaufort Sea offthe north coast of Alaska. Why the marginal prob-ability of oil in commercially recoverable volumesis 20 percent for the ANWR 1002 area and in-creases to 70 percent in the Beaufort Sea offshorearea immediately north of ANWR, where evenless is known about the subsurface geology, wasnot addressed in the U.S. Geological Survey’s re-source estimates of the 1002 area.
ANWR is one of the few remaining unexploredmajor onshore prospects in the United States. Al-though much of Alaska remains unexplored foroil and gas, ANWR holds the most promise forthe discovery of giant fields. Most of the otherhighly prospective oil and gas areas are offshorein the Outer Continental Shelf. When riskedmean resource estimates of oil for the ANWR1002 area are compared with the frontier OCSoil and gas lease planning areas, it ranks third,behind the Navarin Basin (1.3 billion barrels), andthe Beaufort Sea (0.9 billion barrels). Further-more, when the results of recent drilling disap-
85
pointments in the Navarin are formally factoredinto resource calculations, ANWR might rank stillh igher . R isked mean resource est imates forANWR nearly match those expected for the en-tire Atlantic OCS Region (0.68 billion barrels).
Both the Navarin Basin (upper Bering Sea) andthe Beaufort Sea, being in offshore Arctic waters,are located in difficuIt operating environmentswhich must contend with sea ice, severe weatherconditions, extremely low temperatures and longwinter periods of near total darkness. Offshoreexploration and development is extremely expen-sive under these conditions, and the distancesthat oil would have to be transported will likelyrequire very high per-barrel prices ( >$32 per bar-rel) and giant fields of 250 to 500 million barrelsto warrant development. The Department of theInterior determined that the most likely minimumeconomic field size in ANWR would be 440 mil-lion barrels at $33/bbl (1 984$). This appears tobe somewhat larger than might be expectedwhen compared to more expensive offshore de-velopment. However, the determination of eco-nomic field size depends on many assumed eco-nomic factors, in addition to location onshore oroffshore, which cannot be determined in fron-tier regions until a field is delineated.
ANWR Petroleum Resourcesin Perspective
The economics of any exploration and devel-opment of oil and gas resources that may occurin the ANWR 1002 area are closely tied to theexistence of the Trans-Alaska Pipeline System(TAPS) which originates at Prudhoe Bay. TAPS has
the capacity to transport about 2.2 mmbd of oilfrom the North Slope to its marine terminal at Val-dez on the southern coast of Alaska. Prudhoe Baythroughput has ranged between 1.5 and 1.8mmbd since the field came on line at maximumproduction. However, with Prudhoe Bay produc-tion soon to be declining and increases in oil re-serves through field extension not keeping pacewith drawdown, there will likely be ample ex-cess pipeline capacity to accommodate as muchas 1 mmbd of oil from ANWR by the time thatmaximum production could possibly occur,
While the cost of a feeder pipeline from ANWRto Pump Station No. 1 at Prudhoe Bay would besubstantial, the existence of TAPS and its poten-tial excess future capacity boosts the economicoutlook for ANWR. However, the potential re-source base is not equally distributed through-out the 1.5 million acres of the ANWR 1002 area.Over three-quarters of the in-place oil is expectedto occur in the extreme western portions and theextreme eastern portions, with the central areahaving the lowest potential. Resources that maybe discovered in the eastern blocks of A N W Rwould require almost double the length of feederpipeline required for resources occurring in thewestern block.
Although natural gas was not considered by theDepartment of the Interior in determining the esti-mates of economically recoverable resources, itspotential as a future resource cannot be whollyignored. Prudhoe Bay gas is currently reinfectedinto the producing formations to maintain pres-sure and conserve the resource. Production inANWR would follow a similar course. But the un-certainty of the U.S. energy future suggests thatAlaskan natural gas may evolve into a future eco-nomic resource of considerable value. Althoughno credible analysis could be devised to provethis point, sufficient uncertainties about energypricing and hydrocarbon supplies exist so that thepossibility of future economic viability should notbe discounted.
Current prices in the depressed world oil mar-ket logically raise questions about the feasibilityof exploring for petroleum in the high-cost Arc-tic Tundra. But today’s oil prices are not a rea-sonable measure of economic feasibility for in-vestment in exploration and development thatmay require decades to complete. From the timethe Secretary of the Interior forwarded the ANWRreport to Congress (in April 1987), at least 3 to5 years may be necessary for the enactment ofleasing legislation. Unless Congress approvedadministrative shortcuts, at least an additional 3to 4 years would be needed to promuIgate regu-lations, prepare an environmental impact state-ment, and process leases.
If exploration and development were to beginbetween 1992 and 1995–6 to 9 years after thelegislative process begins–it would not be until
86
2002 to 2005 that production would likely be-gin in ANWR assuming 10 years from the begin-ning of exploration to development and first pro-duction. Recent experience with erratic changesin energy prices and the course of the nationaleconomy suggests that it is foolhardy to specu-late on economic conditions 15 to 18 years inthe future.
Exploration costs in the coastal plain of ANWRwould be considerably cheaper than any com-parable offshore exploration program in the OCSwith the highest prospects for the discovery ofvery large oilfields. The cost of drilling an explora-tory well onshore in the Arctic is generally esti-mated to be in the range of about $10 to $25 mil-lion. An exploratory well in the frontier NavarinBasin in the Bering Sea is estimated to cost about
$55 million. Exploratory wells in the Beaufort Seaare estimated to cost on the order of $30 millionfor ice-free conditions and up to about $50 mil-lion for ice conditions. The Mukluk explorationwell on an artificial island in the Beaufort north-west of Prudhoe Bay, when abandoned as a dryhole, cost an estimated $140 million, althoughpart of the high cost has been said to be due tothe need to maintain a very fast pace.
The Department of the Interior foresees theneed for about 25 exploratory wells for theANWR 1002 area under its full leasing scenarioand 16 under a scaled-down alternative centeredon the best drilling prospects. If drilling costs canbe held to the low side of the range for onshoreArctic drilling, total cost for exploratory drilling(not including general support facilities) onANWR could range between $160 million and$250 million. Compared with the costs for drillingexploratory wells at single locations in the bestoffshore prospects of Alaska ($30 to $50 millionand up, for most situations), ANWR may offer thecheapest and perhaps the most direct way to de-termine whether another giant oilfield lies belowlands under the jurisdiction of the United States.However, before ANWR is leased and explored,formidable environmental issues must be re-solved.
Environmental Issues
Background.–A major battle is expected be-tween development-oriented and environmental
groups over the issue of whether or not to pro-ceed with oil and gas exploration and eventualdevelopment in ANWR. The oil industry, as wellas many elected officials from the State of Alaska,key personnel from the U.S. Department of theInterior, and several native Alaskan organizations,view the coastal plain of the ANWR as having themost promising oil and gas potential of any re-gion in the country. Environmental groups con-tend that the wilderness value and wildlife habi-tat the area provides are unparalleled and thatdevelopment would threaten the animals (par-ticularly the Porcupine caribou herd) that spendall or part of their time in the Refuge.
The Fish and Wildlife Service (FWS) was des-ignated by the Department of the Interior to con-duct the 1002 study on the fish and wildlife re-sources and petroleum potential of the ANWRcoastal plain. The study is essentially a responseto the question of whether or not oil and gas de-velopment can coexist with wilderness and wild-life in the ANWR area, or, alternatively, a deter-mination of the relative importance with respectto national needs of oil development and pres-ervation of the refuge. FWS found that “long-termlosses of fish and wildlife resources, subsistenceuses, and wilderness values would be inevitableconsequences of a long-term commitment to oiland gas development, production, and transpor-tation, ”57 and also that leasing of the 1002 area“could contribute billions of barrels of additionaloil reserves toward the national need for domesticsources. ’ ’58 Based on its findings, FWS has rec-ommended that Congress authorize the Secre-tary of the Interior to lease the entire 1002 areafor oil and gas exploration and development.59
Key Environmental and Socioeconomic Con-cerns.–The entire ANWR, including the coastalplain, is in fact if not in name a wilderness area,that is, an area essentially untouched by devel-opment. Although the area considered for leas-ing (1.5 million acres) is only a fraction of the ref-uge, it includes virtually the entire coastal plainof northeast Alaska.
szu .S. Depaflrnent of the Interior, ArctK National W//d/ife Ref-
uge, A/aska, Coasta/ P/ain Resource Assessment (Washington, DC:U.S. Department of the Interior, November 1986), p. 6.
5albid., p. 8.s91bld., p. 1.
87
Environmentalists argue that oil developmentin ANWR would not only diminish the wilder-ness nature of the coastal plain but would even-tually make it easier to explore adjacent offshoreareas and the remaining State land between Prud-hoe Bay and the ANWR for oil and gas poten-tial. All of these developments would have ad-ditional negative environmental impacts on theArctic coastal plain. A bill to designate the coastalplain of the ANWR as wilderness has alreadybeen submitted to Congress by CongressmanMorris Udall and was recently reintroduced inthe 10Oth Congress.
A key concern is the impact that developmentwiII have on the approximately 180,000 caribouof the porcupine herd that use the refuge. Onepart of the coastal plain is particularly importantas a calving area for the Porcupine herd. Thecoastal plain also offers relief to the herd frominsects. Before actual exploration and develop-ment occurs, it is difficult to say what the impactof oil and gas development on the herd will be.Those in favor of development point out that theCentral Arctic caribou herd, whose range in-cludes the Prudhoe Bay area, has actually in-creased in size since development began. ThePorcupine herd, however, spends less time onthe coastal plain than the Central Arctic herd, andthe question of whether the Porcupine herd canbe acclimated to development like the CentralArctic herd is open to debate.
The U.S. Fish and Wildlife Service has con-cluded that it is reasonable to assume that de-velopment can proceed with minimal adverse im-pacts on the herd. In the draft 1002 report, FWSproposed that the most sensitive area (an areaof approximately 242,000 acres) be leased last—after determining how the caribou respond andwhat mitigation measures would be most effec-tive. The final version of the draft, however, rec-ommended that the entire coastal plain beopened to leasing. Most environmental groupsare not convinced that oil and gas developmentis compatible with the health of the caribou herd.Also, although the focus of attention has beenon caribou, other wildlife in the area could b eaffected by development.
Of particular concern to some environmen-talists is construction of a haul road and pipeline
connecting Prudhoe Bay with the ANWR. Thepresence of either would disqualify the coastalplain for wilderness status. in addition, the pipe-line could be a barrier to caribou migration, andsome worry that it could eventually be extendedto the MacKenzie Delta area in the Canadian Arc-tic,60 thereby eliminating more wilderness.
Socioeconomic consequences for the native ln-uit population (especially in the village of Kakto-vik) are also expected to be significant. The Inuithave subsurface rights to a considerable amountof acreage and can be expected to profit fromdevelopment. Two native corporations, the Kak-tovik Inupiat Corp. and the Arctic Slope RegionalCorp., are involved, and have generally been sup-port ive of control led development. Other nat ivegroups–particularly those dependent on the Por-cupine herd but unlikely to share in the directeconomic benefits of oil development—have op-posed development.
Development would bring changes in the tradi-tional subsistence lifestyle of most natives, asmore Inuit would have the opportunity to workfor cash in the oilfields. Introduction to 20th cen-tury culture has proven to be a two-edged swordto Inuit in other parts of the Arctic, however.Modern conveniences benefit Inuit just as theybenefit others, but development is also at leastpartly responsible for the increase of such socialproblems as alcoholism. While happy to have ad-ditional income, many Inuit regret the decline oftraditional culture.
The Effects of the NaturalGas Surplus
Since the early 1980s, natural gas productioncapacity has been in substantial surplus, primar-ily because of declining demand in the electricutility and heavy industry sectors but also becauseof a surge in gas deliverability. This surplus hasbeen remarkably persistent, and it has createda situation in which producers in some parts ofthe country cannot be assured of markets for newgas production. The disincentive for gas drilling
fJJAlthOugh there appears to be I ittle reason for such an exten-
sion, because the TAPS plpellne should have adequate excess ca-pacity in the appropriate timeframe to handle any ANWR pro-duction.
88
created by poor markets has affected overalldrilling patterns of the past few years. The over-all economic effect on oil drilling is mixed: onthe one hand, because many oil wells producegas and because some drilling seeks hydrocar-bons rather than oil or gas in particular, the slackgas market can hurt oil drilling; on the otherhand, the reduction in total drilling caused by thepoor gas market was one of the causes of thelarge reduction in drilling costs between 1981 andthe present, and this reduction in turn improvedthe economics of oil drilling. Most probably, an
I end to the surplus and reestablishment of firm
without a very large increase in drilling—an un-likely event if oil prices remain low. However,the two determinants of the date of an end to thesurplus—gas supply and gas consumption—arequite uncertain. Consumption is greatly affectedby fuel switching to oil, which in turn is depen-dent on uncertain oil prices and the ability of gaspipelines to compete with oil on price. Future gassupply is the subject of a substantial divergenceof opinion, even more so than is future oil sup-ply, although most forecasts agree that U.S. do-mestic production will decline in the 1990s andwill require added imports, especially from
gas markets would aid in a general E&D recov- Canada.I ery because drilling costs are unlikely to rebound
’
I
i
Chapter 6
Changes in the Oil IndustryAffecting U.S. Oil Production
Changes in the Climate for OilInvestments in the United States
and Overseas
The United States represents the most “ma-ture, ” most intensively drilled of the world’s pe-troleum regions, yet continues to attract a lion’sshare of exploration and development expendi-tures. The raw statistics—70,000 barrels found perU.S. wildcat well v. 7 million per wildcat for therest of the world—paint too extreme a picture ofthe United States’ geologic inferiority, becausethe nature of its infrastructural developmentmakes economic many low-payoff driIling ven-tures that could not be attempted elsewhere. Itis nevertheless true that geological prospects gen-erally are far superior overseas than in the UnitedStates, particularly the Lower 48 States, yet themajor oil companies, most based in the UnitedStates, continue to spend most of their capital do-mestically.
An important reason for this appears to be thegreater stability and security available within theUnited States. The major oil companies learneda harsh lesson when the Middle East OPEC na-tions nationalized their oil production and trans-formed these companies from producers tobuyers. Also, the governments of many oil-bearing countries offered only relatively harshterms for development of their oil resources.Their strategy was stimulated by the belief thatoil prices would continue to rise, so that theycould benefit by withholding their resources forlater development (at much higher prices).1 Inaddition, until recently, hostility to foreign, pri-vate investment of any sort was common amongthe developing nations.
Industry analysts claim that the business climatefor overseas oil investment is improving relative
‘See MA. Adelman, “World Oil: Availability and Price: The NextTen Years, ” AsIan Development Bank, Regional Meeting on Ener-gy Policy, Dec. 11-12, 1986.
to that of the United States and that, in response,oil company attitudes towards overseas invest-ment are shifting. Industry experts at an OTAworkshop unanimously agreed that the large oilcompanies were shifting their attention to over-seas drilling prospects. A recent Salomon Bros.survey found that U.S. oil companies expect tospend 29 percent of their 1987 budgets outsidethe United States compared to 12 percent in1986.2
Presumably, the reasons for the improving cli-mate are twofold. First, the developing nationshave become more sophisticated both economi-cally and politically. They have come to appreci-ate the potential benefits of private and foreigninvestments and do not fear as much as previ- 1
ously the accusation that they are selling out toforeign interests. Second, they have come to rec- *ognize, in light of falling prices, that the delay of oil and gas development has created a substan-tial loss, rather than a gain, in investment value. IThese shifts in attitude and understanding havebeen translated into a variety of concrete actions .designed to attract oil and gas investment, in-cluding:
●
●
●
●
●
●
●
●
removal or raising of former caps on pricespaid to foreign producers (Angola, Color-n- ‘bia, Morocco, Canada, Turkey);contractors now paid in dollars rather thanlocal currency (Argentina, Chile);removal or reduction of prior oil taxes (Can-ada, Morocco, Trinidad, United Kingdom);reduction of royalty rates (Canada, China,Morocco, United Kingdom);easing of requirements for training and em-ploying nationals (China);flexibility in shifting lease areas (China);tax or royalty relief for areas deemed diffi-cult to explore (Chile, it-eland);customs taxes waived for imported materi-als needed for oilfield operations (Chile);
‘Oil and Gas Journal, Feb. 23, 1987, p. 30.
89
74-272 0 - 87 - 3 : QL 3
90
● government loans for seismic surveys, ex-ploratory drilling, etc. (Korea); and
● a variety of more favorable tax and cost re-covery rules and other incentives.3
Oil industry spokesmen claim that the UnitedStates, in contrast to most other countries com-peting for oil investment, has enacted tax and reg-ulatory changes that substantially worsen thebusiness climate for oil and gas investment,4 andweaken the Nation’s ability to attract such invest-ment. For example, the American Petroleum In-stitute claims that the 1986 Tax Law will cost theindustry $10 billion over the next 5 years, andthat the potential reclassification of drilling wastesto the hazardous category by the EnvironmentalProtection Agency could cost the industry up to$8 billion annually.5
Evaluating the relative “business climate” forpetroleum investments of the United States versuscompeting foreign nations is difficult. It is depen-dent on the type of investment being contem-plated, the differences in geologic situations, thecomplex tax, royalty, and regulatory structuresi n the United States and abroad, differences inthe availability of skilled labor and other factorsof production, and impossible-to-measure differ-ences in political stability and physical security.In general, we are impressed with the failure ofmost discussions of the opposing climates to dealwith the above factors in a careful fashion, andwe warn against drawing simplistic conclusions.Also, overseas oil investment can be beneficialto U.S. national security because increased re-serves and production outside of the Middle Eastincreases market stability and diffuses the poten-tial for embargoes and price shocks. Thus, al-though it probably is fair to claim that the rela-tive attractiveness of overseas investment isimproving vis-a-vis domestic investment, it is notclear whether this shift is towards or away froma desirable balance of overseas and domestic in-vestment.
3Barrows Company Inc., New York, NY, “World Incentives forPetroleum Investment, 1980-1 986, ” prepared for the United Na-tions Department of Technical Cooperation for Development.
4See, for example, American Petroleum Institute, Two Energy Fu-tures: Nationa/Choices Today for the 1990s, 1986 edition, july 1986.
“’API Counts the Burdens of Regulation, ” The Energy Dai/y, Dec.2, 1986.
The Efficiency of E&D Activities
As drilling budgets and other indicators of E&Dactivity have declined in the face of sharply loweroil prices, the results of that activity, in new fieldsdiscovered, volumes of oil added to reserves, andadded production capacity also would be ex-pected to decline. However, it is unlikely thatthese results will drop precisely in lock step withthe declines in activity levels, because the “effi-ciency” of this activity is likely to change also.Understanding how the various measures of effi-ciency might change is important to projectingfuture oil reserve additions and production levels.
Few if any of the measures of efficiency in ex-ploration and development have remained sta-ble over the past decade and a half. Such effi-ciency measures as finding costs (reserves addedper dollar spent on exploration and develop-ment), rig efficiency (annual footage or wellsdrilled per active rig), finding rate (reserves ad-ded per well or per foot drilled), and completionrate (successfuI wells/total wells drilled) have var-ied substantially as oil prices and overall indus-try activity has ridden a cycle of boom and bust.Because these measures have in the past beenso sensitive to changes in economic conditionsand especially to changes in oil prices, they arelikely to have shifted dramatically–and possiblyto continue to shift-in the face of the severe eco-nomic dislocations of the past several months.
As an example, finding costs escalated rapidlyduring the 1970s and very early 1980s, peakedin 1982 at $13.53/bbl (including revisions) andthen have slid substantially in the face of declin-ing oil prices.6 Reliably projecting future findingcosts is critical to projecting future production,and especially critical to production projectionsthat rely on first predicting capital spending andthen calculating reserve additions by using theequation:
Reserves added = (Capital Spending) /(Finding Costs)
To project likely future finding costs, it is nec-essary both to understand the relationship be-
bAflhUr AnderSen & Co., op. cit. Note that the authors Cal! thesevalues “surrogate” finding costs because they combine expendi-tures made and reserves added in the same year, whereas true find-ing costs would match expenditures to the actual reserves theseexpenditures created, usually a few years later.
91
tween finding costs and the variables affectingthem, and to predict the future values of thesevariables. Unfortunately, finding costs—like theother efficiency measures—are functions of sev-eral variables, some of which cannot be easilytracked. These variables, which are not inde-pendent of each other, include oil prices, drillingand other service costs, drilling strategies (espe-cially the relative emphasis on deep drilling andother high cost drilling), resource depletion, theavailability of promising exploratory acreage, andthe technical efficiency of exploration and pro-duction technologies. In general, rising oil priceshave led to rising finding costs, and vice versa,largely because higher prices stimulate activityaimed at smaller reserve targets or higher costenvironments, and lower prices force operatorsto focus on higher quality (lower finding cost) tar-gets. The past few years have seen sharply de-creased finding costs. A fair expectation is thatfinding costs will remain low if oil prices remaindepressed. However, this is not certain, and itwiII be difficuIt to predict the magnitude of find-ing costs with any precision. For example, theenergy economist Arlon Tussing, in his testimonyof March 6, 1986 to the House Energy andCommerce Committee, predicted that the slidein finding costs that began in 1982 would befound to have continued into 1985, with costsdeclining about $1.50/bbl from their 1984 value.The recently published Arthur Andersen surveyfound, however, that 1985 finding costs had goneup from 1984’s costs by about $1/bbl, presuma-bly because of the relatively low reported 1985reserve additions as well as a 7 percent increasein completed well costs.
Another efficiency measure, so-called “rig effi-ciency” (footage and wells drilled per rig peryear), declined from the middle 1970s to the early1980s as oil prices rose and oilfield activity ac-celerated. Part of this decline was due to the useof inexperienced personnel and marginal equip-ment, made possible by the inability of the sup-ply of services to keep up with the demand. Partwas due to the spread of drilIing activity to moremarginal prospects, with lower reserves and per-haps more difficult drilling conditions, and to highpayoff but high cost prospects–like deep gas–that required more rig time; this was partly a re-
su l t of the improved economics of theseprospects, and partly an effect of resource deple-tion as the best prospects were used up,
As oil prices began to decline in 1981, drillingbecame more efficient as the number of inex-perienced drilling crews declined, inefficient rigswere dropped from service, footage and turnkeycontracts replaced contracts that paid drillers bythe day (day rate contracts offered little incen-tive for efficiency), and drilling technology im-proved . . . and thus rig efficiency increased shar-ply between 1981 and 1985: the industry drilled89,000 wells in 1981 with nearly 4,000 rotary rigsactive; 84,000 wells in 1982 with 3,100 rigs ac-tive; and 85,000 in 1984 with 2,400 rigs. Unfor-tunately, however, the precise dimensions of theactual increase in efficiency are obscured byother factors that also affect measured rig effi-ciency. These factors include: the proportion oftotal drilling devoted to exploration, because ex-ploratory drilling is more time-consuming thandevelopment drilling; possible changes in thenumber of rigs that are not included in the data7;shifts in the balance of drilling for gas and for oil,because gas wells often require more rig timethan oil wells; and shifts in the geographic distri-bution of drilling, because drilling in some areas,such as the gulf coast, is more rapid than i nothers, e.g., the Midcontinent and Rocky Moun-tain Overthrust Belt, because of different rockconditions and other physical factors. AlthoughOTA is not aware of analyses that have systemat-ically isolated the effects of the various factors in-fluencing rig efficiency, several of our reviewersbelieve that shifts in drilling targets areas impor-tant as actual changes in drilling equipment andoperational efficiency as causes of the changesin rig efficiency over the past decade and a half.
Another measure critical to many forecastingmethods is the “finding rate” of drilling, meas-ured in reserves added per well drilled. s The de-cline in drilling now occurring, and expected to
7Commonly used rig counts include only so-called rotary drill-ing rigs, rigs that drill by rotating a drill bit and Its attached drllli ngpipe.
aThere are other measures of fi ndl ng rate, for example, reservesadded per exploratory well. Problems In tying together “reservesadded’ and the specific activities that ‘‘created” these reserves areendemic to oil and gas analysis, and no particular measure of find-ing rate can escape these problems,
92
continue, will certainly not be so uniform as toleave the finding rate untouched; a 50 percentdecline in drilling is unlikely to yield a 50 per-cent decline in reserve additions except by someunlikely coincidence.
Figure 9 shows the change in oil finding ratefrom 1960 to 1983, with “reserves found” com-puted by assuming a time lag between explora-tory drilling and reserve development of 4 yearsfor onshore drilling and 7 years for offshore.9 Thedrop in finding rate beginning in the early 1970smay be partly because of resource depletion, butcommon sense implies that, because of improvedeconomics associated with higher oil prices, asubstantial role must have been played by in-creased drilling of marginal prospects within eachregion, as well as increased drilling in less produc-tive regions. The role of shifting drilling patternsis complicated by the observation that, during thesame period, some explorers responded to theprice increases by drilling in expensive, high riskregions that promised very high returns per well.However, the lack of exploration success in manyof the new drilling areas and the huge numberof new marginal wells that were drilled sustainthe above interpretation.
OTA believes that the average finding rateachieved by the smaller number of wells beingdrilled in 1986 might be somewhat higher thanrecent historical rates; in other words, OTA be-lieves that the finding rate is likely to swing backup the curve in figure 9. Some insight into thepotential increase in finding rate can be gainedby examining recent regional shifts in drilling.Short-term changes in drilling patterns, as pro-jected by the Oil and Gas Journal,10 imply thatdrilling declines will be greatest in areas with rela-tively low finding rates. Because finding rates dif-fer greatly from region to region, such a shift hasgreat potential to change the national finding rate.For example, adopting the assumption that 1980to 1984 regional finding rates will still bereflected in 1986 drilling will result in an esti-mated national finding rate for 1986 that is 40 per-
‘A. T. Guernsey, Profitability Study. Crude Oil and Natural GasExploration, Development, and Production Activities in the USA,1959- /983, for Shell Oil Co., June 1985.
‘O’’ OGj’s Revised Drilling Forecast for 1986–U.S. and Canada, ”Oil and Gas journal, july 28, 1986, p. 67.
Figure 9.—Oil “Finding Rate” (Reserves Added perOil Well)
1960 1970 1980
Year
SOURCE: A T Guernsey, Profltabf/lty Study, Crude 0// arrd Natura/ Gas .Exp/or-at~on, Deve/oprnent, and Production Actwlfies In the USA, 1959-7983, June 1985 for Shell 011 Co
cent higher than the 1980 to 1984 national rate,if the projected shift in drilling patterns holds. Thisin turn would yield 1986 reserve additions for theUnited States that would be considerably higherthan would be projected assuming a 1 -to- 1 rela-tionship between reserves and drilling rates: spe-cifically, 2.2 billion barrels for the regionally ad-justed value versus 1.6 billion barrels without theadjustment, assuming that 46,000 wells (includ-ing dry holes) are drilled in 1986. ’
OTA does not believe that the “regionally ad-justed” estimate of 2.2 billion barrels is the“right” value for 1986 reserve additions. A vari-ety of other factors, such as intraregional shiftsin drilling, must still be accounted for. In particu-lar, oil companies are predicting a significant shiftaway from exploratory drilling towards low riskdevelopment drilling; such a shift would tend tolower finding rates and thus lower reserve addi-tions. Also, in the years following 1986, drillingpatterns will continue to change even if pricesdo not. A portion of near-term drilling is tied to
11 Ibid. It is further assumed that the ratio of completed 011 wells
to completed gas wells established in 1980 to 1984 WIII hold tor1986.
93
present lease and other commitments, and thesewill expire. Company strategies will change, espe-cially since current drilling behavior is affectedsubstantially by its nearness in time to the recentprice shock and the turmoil it created. As dis-cussed above, the industry is in a period of tran-sition, and it is far from clear what its explora-tion and development strategies will look like afew years from today.
Despite the uncertainties created by these fac-tors, it is useful to project future domestic oil pro-duction levels by using a “what if” scenario thatassumes a continuation of the projected 1986drilling levels and the optimistic value for re-serves/well that reflects only the new geographicdistribution of drilling without accounting for fac-tors that might reduce the reserves/well value.The results of just such a projection are discussedin detail in chapter 7.
Changing Oilfield Technology
Continuing evolution of the technology of oilexploration, development, and production islikely to play an important role in the basic eco-nomics of oil exploration and development andthe size and rate of exploitation of the recover-able oil resource base. For example, advance-ments in seismic technology that allow for bothfiner resolution and significant reductions in datacollection and analysis costs will be crucial infinding and producing the many thousands ofsmall oil and gasfields. Technological advance-ments that will substantially decrease productioncosts—e.g., subsea production systems—are crit-ical to developing offshore fields at today’s low.oil prices.
Unfortunately, analysts have had little successat trying to quantify the effects of technologicalchange on oil development. For one thing, thereis enormous variability of technical requirementsacross different prospects, so patterns of techno-logical use are difficult to track. Also, technicalcapability varies widely among oilfield operators,so that different operators working in the samefield and same physical conditions may choosedifferent technical approaches. In our interviewswith oilfield operators, OTA was struck by theirdiffering assessments of the importance of tech-
nological changes in the past and the potentialfor such changes in the future. Some describe thepast decade and a half as a time of only modesttechnological change; others describe “tremen-dous advances in exploration and extraction tech-nologies.” 12 It is OTA’s impression, however, thatthe majority of oilmen are pessimistic about thepotential for technology to make a big differencein costs in most situations. in particuIar, oilmenpoint to the failure of new exploration technol-ogy to cause a measurable change in dry holerisk, and the steady downward progression ofperformance measures such as reserves addedper well.
OTA believes that technological change hasplayed an important role in oil exploration anddevelopment during the past decade or two, butthat other forces affecting oil markets, especiallythe price shocks following the Yom Kippur Warand the Iranian revolution, obscured the effectsof technology. Most importantly, the hyperinfla-tion of oilfield services starting in the middle1970s simply overwhelmed any statistical evi-dence of the many cost-cutting effects of new andevolved technologies, Nevertheless, the follow-ing technological changes clearly played a sig-nificant role in stimulating the movement of re-sources into the recoverable range, whether byaffecting the economics of prospects that previ-ously could have been recovered but had insuffi-cient profit potential, or by moving resources outof the technically unrecoverable range to the re-coverable:
●
●
●
●
significant improvements in the longevity ofdrill bits;movement of seismic interpretation fromstrict reliance on mainframe computers towidely available minicomputers, and the de-velopment and spreading use of 3-D seismictechniques;numerous advances in enhanced oil recov-ery technologies;development of subsea completion andfloating production systems, that both allow
‘2H. R. Linden, “Impact of Advances in Science, Technology andi n the Understanding of the Terrestrial Origin of Hydrocarbons onthe Role of Natural Gas and Crude Oil in Meeting Future PrimaryEnergy Needs,” Gas Research Institute, july 18, 1986.
94
●
●
●
●
●
●
●
the exploitation of smaller offshore fields andlower the risk of certain high-risk large fields;improvements in offshore platforms, espe-cially movement to lighter, less expensive de-signs (e.g., the tension leg platform);development of measurement-while-drillingtechniques 13 that help avoid mishaps, per-mit more accurate directional drilling, andreduce the probability of missing productivezones;continuing evolution of various subsystems,e.g., drilling mud systems;development and/or improvement of sophis-ticated nonseismic exploration techniques,including remote sensing techniques andgeochemical techniques;vast improvement in fracturing techniquesfor low-permeability reservoirs, especiallycritical for gas recovery;development of horizontal drilling tech-niques that allow economic recovery fromthin pay zones and promote full field devel-opment at lower costs; anddevelopment of more sophisticated mathe-matical models for reservoir simulation thatallow better design of well placement forfield development.
OTA has become aware of several recent tech-nological improvements that demonstrate the po-tential of advanced technology to make impor-tant changes in the economics of exploration anddevelopment:
●
●
●
A factor of two improvement in the resolu-tion capability of seismic imagery, which hasimportant implications for development wellplacement and exploration for small fields.The recent development of improved nu-clear logging tools that can detect oil and gasbehind well casing. This will allow the iden-tification of producing zones that weremissed during initial exploration, with par-ticular implications for increasing productionfrom existing wells.The development of so-called stratigraphic-seismic techniques which can improve ex-ploratory well success.
13Measurement of rock permeability and porosity, hydrocarbon
presence, and other important variables without shutting down drill-ing and removing the drill “string. ”
●
●
●
●
●
●
New methods of 3-D seismic mapping ofreservoirs that provide similar detail at halfthe cost of previous approaches. Although3-D seismic is a powerful exploratory and de-velopment drilling tool, its use has beenlimited because of its cost.New developments in chemical enhancedoil recovery (EOR) that have lowered thethreshold of profitable application from $25to $30/bbl to about $20/bbl for this type ofEOR. This will offer major opportunities forimplementing EOR more widely than previ-ously expected, with higher recovery effi-ciencies.New techniques for three-phase flow meas-urements of oil, water, and gas that will al-low the elimination of expensive test sepa-rators in offshore platforms, lower ingsomewhat the economic threshold for off-shore recovery.Substantial decreases in the cost of mul-ticomponent seismic imagery, which usesstandard compressional waves in combina-tion with shear waves to allow higher spa-tial resolution, direct identification of rocktypes, measurement of porosity and permea-bility and direct hydrocarbon detection. Anew multicomponent seismic source costsonly about 50 percent more than compres-sional seismic, which will open this technol-ogy to practical application.The initial uses of CAT scanning to observa-tion of flow inside porous rocks. Continuedresearch should lead to improved mathe-matical modeling of non-uniform flow insidereservoirs, critical to optimizing EOR design.The first Alaskan well using “extended reachhorizontal drilling” was drilled by StandardOil and tripled the output of conventionaldrilling in the same formation. By allowingthe development of areas where the pay istoo thin to develop with conventionaldrilling, it is hoped that this technique willallow increased recovery at Prudhoe Bay.14
The continuing development of new and im-proved technologies, especially focusing on cut-ting costs, will be a crucial determinant of the fu-
1 gArlOn R. TUSSing & Associates, Inc., The PrOPeffY- Tax Base ofthe North Slope Borough, Alaska, May 1, 1986.
95
ture success of the industry in reducing thedecline in oil reserves and production rates ex-pected to accompany lower oil prices. Althoughthe level of effort in oilfield R&D is difficult to trackbecause it is hidden in many different account-ing “cub byholes,” most industry observers feelthat it has been cut back substantially. For exam-ple, the former president of Exxon Research &Engineering Co. has estimated that research, de-velopment, and engineering within the industryhas been cut by at least 30 to 40 percent in thelast 3 years.15
If the observers are correct, and if the indus-try wishes to be able to prevent large productiondrops, the industry probably is doing the oppo-site of what it should be doing, despite its needto economize in response to drastic cuts in rev-enues. I n the face of drastic changes in their eco-nomic environments, other industries haveachieved large cuts in production costs. It seemsreasonable to project that the oil industry wouldstand a good chance of achieving the same.
According to the French Petroleum Institute (ln-stitut Francais du Petrole, or IFP), potential near-term improvements in oilfield technology can of-fer very substantial cost savings. IFP identifies keyadvances as:
● optimization and automated control andmanagement of drilling, based on the mostsophisticated use of measurement-while-drilling, offering a potential reduction indrilling cost of 30 to 35 percent;
● optimization of the understanding of reser-voirs as the result of progress in the model-ing of their dynamic behavior, leading to bet-ter well placement and the need for fewerdevelopment wells;
● further development of seismic imagery tohelp in understanding reservoir behavior, in-cluding increasing its power of resolution toprovide detailed images of the reservoir; de-velopment of seismic devices that can oper-ate inside the well bore, leading to the sameresult as above as well as a higher successrate for exploration wells;
1 ~Edward E, David, quoted In the “News and Comment’ sec-
tion of Science, vol. 232, June 27, 1986.
● improvement in enhanced recovery tech-niques, including drilling techniques such ashorizontal drilling; and
● continued improvement i n offshore plat-forms for shallower waters, and developmentof “all on the bottom” systems for deeperwaters. 16
IFP estimates that full success of such a tech-nology development program and its successfulimplementation couId create substantial savingsin the overall technical costs of production (in-cluding exploration and development costs),namely:
Onshore fields .......................... savings of 20 to 25 percentConventional offshore fields savings up to 30 percentDeep offshore fields:...................... savings of 30 to 50 percent’ 7
If the IFP estimates are valid, then technologi-cal advances could move a large share of petro-leum resources from the subeconomic to the eco-nomic range at $15 to $20 oil prices. The majorityof industry reviewers of the draft version of thisreport were quite skeptical of the IFP estimatesand felt they were substantially overoptimistic.There were, however, a minority of “technologyoptimists, ” some of whom are familiar with cur-rent research and development programs, whoare hopeful about the potential for achieving costsavings of this magnitude. These hopes are, ofcourse, dependent on the industry somehowresisting the current trend towards reduced R&Dexpenditures and focusing a substantial effort oncost-saving technology.
Deteriorating Industry Infrastructureand the Potential for a Rebound in
Oil Production
Introduction
Although the current decline in U.S. domesticoil production and the expected further produc-tion declines are dismaying in and of themselves,the declines translate into problems for U.S. na-tional security and economic stability only to theextent that production levels cannot rebound
“j. Fa)re, “Research and lnno~atlon To Cet Out of a Crisis: The
Cost-Reduction Policy of the Institut Francals du Petrole,” presentedat the Conference on Impact of Price Declines on Oil Exploration,Development and Financing, Dallas, TX, Sept. 3-5, 1986.
1‘1 bld
soon after the onset of a physical shortage of oilor a large increase in its price. In fact, if produc-tion could rebound in this way, future disruptionsmight be less probable.
In general, a decline in domestic productionwill not be easily reversible. it is true that someof the wells that are shut in can be placed backin production (although the number of such wellswill diminish sharply after a few years). I n addi-tion, some EOR projects that are moth balled canbe restarted (although it may take a few monthsfor additional production to start flowing and theproduction response to the EOR may be re-duced). In general, however, significant amountsof incremental production can be added only byreworking old wells, by drilling new ones, bothexploratory and development, and by develop-ing new EOR projects or expanding existingprojects. All of these activities are capital-,manpower-, and equipment-intensive, and gain-ing significant increments of production—whichwill require tens of thousands of individual drillingand other projects—will be time-consuming evenif capital, equipment, and manpower areplentiful.
There are now substantial doubts as to whethercapital, equipment, and manpower will be plen-tiful, given the deterioration of the industry’s in-frastructure that has occurred over the past fewyears and the loss of the confidence in steadilyrising oil prices that marked the rapid buildup ofindustry infrastructure that took place in the1970s, Many in the oil industry are arguing that,once U.S. oil production declines to levels wellbelow those of today, a production rebound inresponse to a sudden price hike would be ex-tremely slow, would be accompanied by massiveinflation in equipment and manpower costs (aswell as inflation in associated costs such as leas-ing bonuses), and would likely fall well short ofrecapturing the losses in production rates. Exam-ining this hypothesis requires an evaluation of thefactors of production and the timetables for eachphase of the production cycle.
People
There is widespread concern in the industrythat the current depression in E&D activity andthe accompanying layoffs, company failures, and
crippled hiring programs will rob the industry ofa major portion of its most valuable personnel.Overall industry employment has dropped fromits 1982 high of 708,000 to 425,000 in August of1986. Oilfield service company employmentdropped from 435,000 to 206,000 in the sameperiod, indicating that this sector has absorbedthe brunt of the layoffs. A special concern is thatthe very pessimistic perception on college cam-puses of the industry’s future and the virtual haltof industry recruitment efforts will decimate well-established university programs in petroleum ge-ology and engineering. Another concern is thatmany of the employee reduction programs arefocusing on the older, more experienced (andmore highly paid) professionals, and that the in-dustry is thus losing its most effective workers.This concern is intensified by the 3-year trainingperiod said to be necessary for skilled oil serviceworkers and the 7- to 10-year period needed forprofessionals.
The seriousness of these concerns is by nomeans settled. For one thing, the drilling boomof the late 1970s and early 1980s attracted verylarge numbers of students to petroleum-relatedprograms. For example, the Society of PetroleumEngineers reports that a large oversupply of pe-troleum engineering graduates has existed since1980-81, and expects this condition to last at leastthrough the end of the decade. This situationprobably exists in other petroleum fields as well.Although many of these graduates as well as thelaid off engineers, geologists, and other profes-sionals and skilled workers will find work in otherfields, it is by no means certain that they will be“lost” to the industry. Previous experience withother industries—e.g., in aerospace technologies—implies that many of these trained personnelcan be recaptured by the industry in the eventof a sudden leap in oilfield activity, at least if thereis convincing evidence that the new jobs will bestable. Further, the possibility of “recapture”should be strongly influenced by the attractive-ness of replacement jobs. Although OTA is notaware of data on the success of laid-off oilfieldworkers in finding employment, and on the rela-tive salary levels of replacement jobs, laid-offmanufacturing workers in simiIar situations havetended to take substantial salary cuts, and oilfieldworkers would likely have to do the same.
Capital Availability
The opportunity for a rapid rebound in oil pro-duction will be possible only with a large increasein cash flow, presumably from a substantial oilprice increase, or a massive influx of outside cap-ital into exploration and development activities.During the drilling boom of the 1970s and early1980s, attracting such capital was relatively easybecause of favorable tax policies and because ofa widespread perception that inexorable in-creases in oiI prices would rescue even weak in-vestments so long as some producible oil wasfound. In contrast, capital availability to fuel a po-tential production rebound is likely to depend pri-mariIy on skeptical analyses of the economic fun-damentals of the individual oil prospects usingconservative assumptions about future pricegrowth. Investors will have to be convinced thatthe economic conditions appearing to favor newoilfield investment are stable, or else that theirinvestment wiII be safeguarded against a returnto low prices. Consequently, the potential for asuccessful rebound in U.S. oil production will de-pend strongly on the precise geopolitical circum-stances—and the perceptions of these circum-stances—that accompany the events driving theoil market towards shortages and/or sharply higherprices. Also, because perceptions and realityclearly do not have to—and often do not—agree,and because a variety of unpredictable factorsfuel perception, considerable uncertainty existsabout the potential response of capital marketsto an oil market situation in which a reboundmight be attempted.
Some analysts, seeing that the independentproducers’ supply of outside capital (from banksand private and public driIling funds) has virtu-ally disappeared, and recognizing that internalcash flow was the primary source of the indus-try’s investment dollars even when outside cap-ital was readily available, assume that any re-bound will have to be funded from internal funds.In OTA’s view, this is unrealistic. The currentwithdrawal by banks and funds from oil invest-ment seems a logical short-term response to thelarge financial losses sustained by these capitalsources and the widespread perception of mas-sive instability in oil prices. Eventually, however,a portion of these capital sources will return to
97
the industry if profitable investment opportuni-ties are perceived to be available. The timing ofthis return, however, being as much a psycho-logical event as a financial one, is highly un-certain.
It is also important to recognize that the dry-ing up of internal capital is not universal to theindustry, because many of the integrated com-panies retain substantial cash flows from theirdownstream operations, and even the reducedcash flows from production can buy considera-bly more drilling services than would have beenpossible in the early 1980s, because of the sub-stantial reductions in oilfield costs.
Equipment
Equipment availability is an additional concernin the event of any attempt at a rapid restorationof lost U.S. oil production. As noted above, sucha restoration will involve the drilling and equip-ping of many thousands of new wells in additionto the completion of thousands of other produc-tion-related and equipment-intensive projects.
Although the industry has expressed substan-tial concern about equipment availability, therecurrently is a substantial surplus of oilfield equip-ment both in a ready status and in storage. At thepeak of the drilling boom in 1981 there were over5,000 land drilling rigs available in the UnitedStates, the majority of them constructed withina few years of that date. Although utilization rateswere high during the boom (79 percent in 1981,for example), most industry observers will agreethat rig efficiency was low. Indeed, the industrydrilled nearly 86,000 wells in 1984 using only2,400 rigs, whereas nearly 4,000 rigs dril led89,000 wells in 1981.18 Also, many of the wellsdrilled in 1981 were drilled with only marginalprospects for success. A more efficient industrycould have added the same volume of reserveswith far fewer rigs than were actually deployed.
I Bsome pan of the difference I n rlg efficiency is said tO be due
to a reduction in deep drilling for gas after 1981. Average well depthdeclined by only 250 feet during tbe period, however. other fac-tors aside from actual improvements in equipment and operation-a I efficiency that may have contributed to rig efficiency changesinclude shifts in the locational distribution of drllllng and changesin the proportion of exploratory drilling.
98
Although a “target” rig count for a successfulrebound is a speculative figure at best, a returnto a 3,000- or 4,000-rig onshore fleet seems ex-cessive. If a 2,500 rig count is a reasonable tar-get level for a production rebound, it appearslikely that the capability for quickly assemblingthat size fleet will remain viable for at least sev-eral years. Although some of the used equipmenthas been sold to foreign operators, overseas activ-ity levels seem unlikely to expand sufficiently towarrant concern over additional losses. Otherareas of concern include the cannibalization ofrigs to keep the current fleet operating, the po-tential for scrappage, and the potential for dete-rioration due to improper storage. Cannibaliza-tion is occurring and will eat into rig availability,but there are so many excess rigs that this shouldnot be a major problem for a considerable time.Little of the equipment is likely to be scrapped,however, because in most cases the price of scrapsteel is low, and dismantling is expensive. Finally,although concerns about proper storage are wellfounded, much of the equipment now out ofservice is simple and durable (see table 31), andthe best rigs are the most likely to be properlymoth balled and maintained. An indication of in-dustry recognition of the value of proper storageis the formation of services designed to handlesome or all aspects of storage for rig owners.19
In conclusion, although an attempt to addquickly to drilling rates will likely run into somebottlenecks, especially in high volume goodssuch as drill pipe and drill bits, for the next fewyears equipment should not be a major constrainton a drilling revival.
The Resource Base and Availability ofE&D Opportunities
The turnaround in U.S. oil production that tookfirm hold in the late 1970s owed much to thelarge “inventory” of potential drilling opportu-nities amassed during the previous decades oflow oil prices. By going back to old well logs andfield records, geologists and engineers couldidentify many thousands of opportunities thatwere uneconomic at $3/bbl yet low-risk, profita-
19L. R. Aalund, “Rig Owners Grapple With Offshore Stacking,”0// and Gas Journal, Sept. 15, 1986.
Table 31 .—Drill Rig Equipment:Storage and Availability
Derrick: The derrick is made to be stored in the open, andshould not present a problem.
Mud pumps: Mud pumps should be stored out of the weather,but are relatively easy to store. Lots of upgrading was doneto the fleet’s mud pumps in 1983 to 1984, and most shouldbe in good condition.
Drill pipe: Drill pipe is quite likely to be sold off and mayrepresent a high potential for a short-term shortage in caseof a rebound in drilling activity.
Draw works: Draw works are vulnerable to the elements, butstill relatively easy to store properly.
Prime movers: Engines are most likely to be sold to other in-dustries, and could be in shortage in a rebound.
Drill bits: Since drill bits do not last long, a rebound will re-quire substantial bit manufacturing capability. This capa-bility is being rapidly diminished, and drill bits may be inshortage in a rebound.
SOURCE Office of Technology Assessment, based on discussions with equip.ment suppliers.
ble producers at $10 and up. Although most weremodest producers, in the aggregate they madea significant contribution to total U.S. production.In addition, Alaskan production was just begin-ning to start up in the early 1970s and providedan additional, massive boost to U.S. productionlevels.
Prospects for a rebound in production follow-ing a substantial price increase will depend inlarge measure on whether or not a similar inven-tory exists now of drilling and other production-related opportunities. Without such an inventory,a substantial boost in production would have towait a number of additional years to workthrough the early stages of the production cycle. . . stages that are bypassed when low risk op-portunities in discovered fields can be identified.The importance of such an inventory is furtherenhanced by the imminent decline of Alaskanproduction and the lack of any replacement pro-ducing province.
The issue of whether or not the inventory ofoil opportunities will be adequate to supportmoderate levels of drilling activity for a numberof years is basically the same issue of continuedfield growth that appears in Section Vd on theResource Base. As discussed in that section, thereremains substantial controversy about the poten-tial for field growth through conventional drillingof the existing U.S. oil and gas fields. Two im-
portant questions are whether many opportuni-ties remain to attain additional reserves throughextension wells and infill drilling designed to pro-duce mobile oil that would not have b e e nproduced at previous levels of well spacing, andwhether or not recently discovered fields, whichare on the average smaller than their predeces-sors, will grow at historical rates. The former ques-tion remains controversial because of continu-ing disagreements about the actual level ofheterogeneity existing in many of the Nation’s oil-fields.
The Restructuring of the U.S.Oil Industry
Introduction
During the 1980s the U.S. oil industry has beenundergoing a transition that has left virtually nosegment of the industry unchanged. “Restructur-ing” is the overall term commonly used to de-scribe the fundamental shifts in the size and com-position of the domestic oil industry as a wholeand the changes in internal organization anddirection of individual companies. The currentrestructuring is reflected in the increasing con-solidation of the industry and in widespread,often drastic adjustments in the operational andfinancial structures of individual companies andtheir petroleum investment strategies. This chap-ter describes some of the recent changes in theU.S. oil industry and the possible future impli-cations for continued investment in domestic ex-ploration and production.
Well before the 1986 oil price plunge, manyof the major and independent oil companies em-barked on ambitious operational and financialrestructuring efforts in response to conditions cre-ating increased uncertainty about oil’s future prof-itability. Restructuring has taken varied forms in-cluding:
1.
2.
corporate mergers, acquisitions, and majorasset sales and purchases;operational and organizational changes tostreamline business divisions and cut costsby combining or eliminating functions and,often, reducing the number of employees;
3.
4.
5.
6.
asset “redeployments” with companies ex-panding in operating segments and geo-graphic areas where they perceive an advan-tage and e l im inat ing le s s p ro f i tab leoperations through sales, asset writedowns,and liquidations;adoption of financial strategies designed toenhance the market value of the companyby increasing dividends, buying back stock,changing debt levels, or creating new equityinvestment opportunities (e. g., m a s t e r
limited partnerships);increased use of joint ventures and other riskspreading arrangements for exploration anddevelopment projects; and in some extremecases,reorganization of assets and liabilities underthe protection of bankruptcy proceedings.
There is general agreement that the current res-tructuring was prompted by prevailing conditionsin the industry following the 1981 boom :20
1.
2.
3.
There was a worldwide surplus in oil pro-duction capacity and excess capacity inrefining and marketing operations as a re-sult of the higher oil prices and industry ex-pansion in the 1970s.Oil consumption declined from 1979 to 1983due to higher prices and conservation effortsand the recession; many industry forecastspredicted that annual growth in oil demandwould be less than 1 percent per y e a rthrough the year 2000.Excess oil production capacity, reduced de-mand, and the breakdown of OPEC set ofta steady decline in oil prices in 1981. By1983 there was a growing consensus that oilprices would remain low, and perhaps de-cline further, until at least the early 1990s.
~~’See, tor example, statement of T. Boone Pickens, jr., in Leg/\-l~tlon Attect/ng (XI tlerger Proposals: Hearing on S. 2362a BI// toAmend the Mineral [.]nci% Lea~ln<q Act of 1920 and for Other Pur-poses Before the Subcommittee. on Energ) and Mineral Resourcesof the Senate Comm. on Energy and Natural Resources, 98th Cong.,2d sess. 320 (1984), and supplementary material provided by FrankW. Bradley of Chevron Corp., Id. at 536. (These hearings are here-after referred to as Leg/slat;on Atiectjng 0)1 Merger Proposals. ) Seealso Impact of Oil Company Mergers: Report to the United State>Senate, Prepared by the Majority Staft”otthe Senate Committee onEnergy and Natural Resources, S. Prt. 98-206, 98th Cong., 2d sess.( 1984).
100
4. Many oil industry managers and investorswere disappointed by the relatively highfinding costs and the difficulty in finding andproducing new domestic oil reserves, par-ticularly in the light of the massive invest-ments in exploration. There was a growingperception among some major oil compa-nies that because of the past extensive on-shore exploration in the United States, therewere now fewer “good” U.S oil prospectsremaining.
Some industry analysts wouId add to the forego-ing conditions: concern over possible changes i nFederal tax and oil and gas leasing policies, thepressures on companies from increasingly aggres-sive institutional investors demanding greatershort-term returns from their holdings, and thefear of possible hostile takeover offers by cor-porate raiders.
Al though changes in capital s t ructures,mergers, acquisitions, liquidations, and bankrupt-cies are not unusual in the oil industry, recentyears have seen a high level of these activities.21
These widespread occurrences, coupled with thegeneral conditions of overcapacity, reduced de-mand, and declining prices suggested to someobservers that the domestic industry had entereda period of fundamental structural change beforeit began to experience the adverse effects of theplunge in world oil prices in 1986.22 If the cur-rent restructuring is indeed symptomatic of the
J 1,Vaterla13 prepared for the Senate Banking Cornrn Ittee Indicatethat the number of mergers and acquisitions from 1983 to 1985has been much higher than during the 1970s and has involved sub-stantially more funds than ever before. According to Mergers andAcquIsItIorrs, oiler $122 billlon was spent on completed transactionsIn 1984; oil and gas industry transactions probably were one thirdto one halt’ ot that total. See Impact otCorpor,]te Takeo~er$: Hear-ings on the Eifects otMergers on Management Practices, Cost, AL all-abliity ot Credit, and the Long-Term Vi.]bil@ oiAmer/c.]n Indu$tr]’Before the Subcommittee on Secur~ties oi [he Senate Committeeon Banking, Houh\n,g and Urban Aiiairs, 99th Cong., 1 st sess. 591-593 (1985). (Hereafter reterred to as /rrrpact oiCorporate Takeovers.)
~~U.S. Congress, joint Economic Committee, “The U.S. 011 in-dustry in TransKlon: Causes, Implications, and Policy Responses, ”Comm. Print, 99th Cong., 2d sess., S. Prt. 99-154, May 20, 1986,at 9. Th IS study by the Business School at Southern MethodistUnl\erslty concludes that current trends In the oil industry are char-acteristic ot the mature phase of an ind us.try life cycle: excess ca-pacity, low growth, business failures and consolidation. The studycompared the oil industry to other “distressed” mature domestic
I nd ustrles I n transition such as steel, textiles, automobl Ies, and agri-
cu Itu re.
maturity of the U.S. oil industry, rather than theresult of cyclical influences of world oil prices,this further suggests that a return to the slightlyhigher oil price levels preceding the price slidewill not stem the eventual contraction of the in-dustry and the decline in U.S. oil production. Butthere are others in the oil business who do notshare the view that the U.S. industry is in inevi-table decline. To them restructuring is desirable,but marks a normal and healthy evolution of theindustry in response to changing conditions. Theypoint out that the oil industry has been throughsimilar periods of expansion and contraction inthe past.
Restructuring has already had profound effectson the industry and on oil companies and theirinvestment decisions. The success of their restruc-turing efforts and other strategies adopted by in-dividual companies in response to low oil pricesmay well determine their economic viability ina new era of more volatile oil prices and strongercompetition from foreign oil imports. The cumu-lative result may be oil’s transformation into asmaller, more efficient industry with fewer com-panies and a different approach to business. Buta smaller industry may not conduct as extensiveor aggressive an exploration program to replacedomestic reserves and this could increase U.S.reliance on foreign oil. Moreover, there is con-cern that the sharp increase in corporate indebt-edness associated with recent mergers, acquisi-tions, and internal restructuring, coupled withdeclining earnings due to low oil prices, willmean sharply reduced expenditures for explora-tion and development in the short term as avail-able cash flow is diverted to debt repayment. Inthe long term, this trough in exploration expend-itures could contribute to a decline in oil pro-duction.
Conditions Causing Restructuring
World oil trends in the 1980s began to raiseconcerns about the future profitability of the do-mestic industry. Even as oil revenues soared in1979-82, present and future earnings were be-ing undermined by growing worldwide overca-pacity in upstream and downstream operations,lower oil prices, declining demand, and changesin domestic tax policies. AdditionalIy, the indus-
101
try was becoming more vulnerable than in thepast to rapid changes in oil prices as more andmore oil was sold on the spot market or at spot-market-related prices.
One clear implication of these trends was thatthe majors could no longer rely on rising pricesand expanding product sales to assure futureprofits growth. The earnings of major U.S. oilcompanies did not reflect much of the initial oilprice drop in 1981 to 1985 because most of theexcess price over $20/bbl was taxed away by thewindfall profits tax (WPT). The contribution tocash flow in dollars per barrel of crude oil equiva-lent for major U.S. companies after deducting theWPT fell only 1.6 percent between 1981 to1984.23 The independents, who generally carrieda smaller WPT burden, however, were more seri-ously affected by the steady slide in oil prices.By 1985, many independents were already in fi-nancial difficulty because of the combined effectsof lower oil prices and lower prices for naturalgas. But as the price fell below $20/bbl in 1986,cash flows for both majors and independentswere squeezed.
The prospects of slow demand growth anddeclining oil prices forced managements to refor-mulate their long-term business plans to decidehow best to protect the future profitability of theircompanies. This reassessment accompanied theemergence of a management philosophy thatplaces greater emphasis on financial performanceand short-term returns to shareholders than onfinding oil. With world oil industry conditionslargely beyond their control, companies beganto look inward for ways to cut costs and main-tain profits and to reexamine the assumptionsunderlying their business strategies. Restructur-ing and a move away from continued heavy in-vestment in domestic oil exploration have beentwo results.
Many integrated companies began to shift awayfrom their past emphasis on maintaining a securesource of domestic reserves to supply their refin-ing and marketing operations and to end thetraditional priority given to recycling a high
z I u,s, Dep~ nment of Energy, Energy I nformatlon Ad m I n Istratlon,
Pertbrmance Prot’//es of Ma]or Ener~y Producers 1984, tables 21and 22.
proportion of their production revenues back intoexploration and development activities. The cut-back in domestic exploration also marks a reeval-uation of the potential for finding additional largeoilfields in domestic frontier areas. Oil industryobservers and company annual reports indicatethat several companies appear to have alteredtheir views on the economic viability of conduct-ing a broad-based exploration and developmentprogram in the Lower 48 States at prices experi-enced in recent years. For example, Lodwrick C.Cook, the Chairman of the Board and Chief Ex-ecutive Officer of ARCO, told his shareholders:
[I]n the lower 48 we intend to maximizeproductivity of existing fields and not try to re-place production through further exploration inthis declining region—though we will buy re-serves when good opportunities come a long... Es-sentially we’ve shifted away from the high-risk,major-stakes emphasis of recent years and towardprojects that can be expected to produce eco-nomic results more reliably. As the price of crudeoil increases we can step up exploration again,although not on the large scale of recent years.Results of the industry’s late 1970s, early 1980sdrilling boom weren’t that encouraging—at anypredictable price. (Emphasis added. )24
Many majors and independents have not beenable to replace their U.S. oil and gas productionwith new reserves despite heavy investment indomestic exploration, and the reserves they didfind came at a high cost. For example, as shownin table 32, oil and gas reserve additions for manymajor oil companies, excluding purchased re-serves, felI short of replacing annual productionover the period 1979 to 1985. Even when pur-chased reserves are taken into account, manycompanies still did not replace depleted reserves.Over the same period, the U.S. industry replacedabout 92 percent of its liquids production.
The poor success of some exploration effortsis also reflected in the relatively high implied find-ing costs incurred by some firms over the years1979 to 1985. The average weighted implied find-ing cost for the major oil companies shown i ntable 32 was $10.58 per equivalent barrel in 1979
2 4 Remark~ of C h a i r m a n Lodwrlck c, cook at the 1986 annual
shareho lders meeting, reprinted in Atlantic Richfield Co. 1986 First
Quar ter Repor t , a t 12, 15.
102
Table 32.—U.S. Oil and Gas Reserves Replacement as Percentage of Production, 1979-85, andDomestic Implied Finding Costs
Production replacementexcluding purchases and sales(weighted average 1979-85)a
Major integrated oil companies:Amoco Corp. 109.0%A r c o 103.9Shell Oil Co. 99.2C h e v r o n C o r p . 81.4Murphy O i l Co . 75.9Exxon C o r p . 75,6M o b i l C o r p . 72.1Phillips Petroleum Co. 69.5U n o c a l C o r p . 65.6Sun Co. 58.1Kerr-McGee Corp. 51.7Standard 011 Corp. 22,2Texaco, Inc. Neg.
Independent producing companies:Noble Affiliates, 150.7Mitchell Energy & Development Co. ., 1423Pogo Producing Co. 93.6Sabine Corp. 88.5P e n n z o i l C o , 86.4Louisiana Land & Exploration Co. ... 39.8
Production replacementincluding purchases and sales(weighted average 1979-85)b
11 2,8%108,5147.6169.377.877.2
121.398.3
66.2579.362.423.047.8
151.6146.793.8
1 17.4d102.340.7 e
Implied finding costs$/Bbl oil equivalent
(weighted average 1979-85)C
$ 7 . 9 17.057.469.48
15.199.93
10.189.539.62
11.0521.0926.61
Neg.
9.04104114171204
8.9121.91
ar.@pl’C8m8flt {ncludes reserves added through dlscoverles, extensions Improved recovery and revlslons of PrevfrJus estimatesbReplacement ln~ludes rese~es added through dlscoverles, extensions, improved recovery and rewons Of prewous t? StlmateS Plus the effects of reserves purchases and salesCFlndlng cost excludes proven rese~es purchases e~’ept where properfy acquisition COSIS @ not break out proven and u n p r o v e n acreagedExcludes reserves dlsmbuted to the Sabme Royalty TrusteExc~udes reserves distributed to the LL&E Royalty Trust
SOURCE Ofhce ot Technology Assessment from Oonald F Textor Todd L Bergman Cmtlna Tlscareno Flndlng Cost and Reserve Replacement Results 1979-1985 Goldman Sachs Research April 1986
to 1985. There was a wide range in reported find-ing costs among these companies, from $7 toover $26/bbl. Several companies had extremelypoor results in their domestic exploration pro-grams with implied finding costs well above the$5 to $9/bbl average purchase cost of proven re-serves over the same period .25
High finding costs translate into a low profitmargin per barrel (or even a loss) if prices do notrise. The declining profitability of newly addedreserves was becoming apparent even at pricesover $20/bbl. This trend is reflected in severalcommonly used indirect measures of the profit-ability of exploration and production activities:
● Discounted Future Net Cash FIows.—Ameasure of the present value of all provenoil and gas reserves derived by applying year-end oil and gas prices to estimated future
lsAfl~~ r A~~erSe~ & CO., oil & Gas Reserves Disclosures: 1981
to /985 Survey of375 Pub/ic Companies, s-46 (1986). and estimatesprovided by Strevig & Associates in “ Prices for Reserves Purchaseson the Upswing, ” Oi/ & Gas Journal, Feb. 16, 1987, at 46.
●
●
production to yield expected production rev-enues flows, then subtracting estimated fu-ture production and development costs andfuture income taxes, and discounting the re-sulting annual future net cash flows by anannual discount rate (usually 10 percent).Present Values Added Through Explorationand Development.—The present value ofnew reserves added as a result of explora-tion and development activities in a givenyear. This measure is calculated for newlydiscovered reserves in the same manner asdiscounted future net cash flows above.Value-Added Ratios.–Two measures of thereturns on exploration and development in-vestments. The value-added ratio for explo-ration and development is expressed bycomparing the present value of new reservesadded by exploration and developmentactivities with the costs incurred to acquire,explore and develop the reserves. The value--added ratio for all sources compares thepresent values of reserves added through ex-
103
ploration, revisions, and reserves purchases(less sales) to the total costs incurred to ob-tain the reserves including amounts paid tobuy proven properties.
The above measures are calculated assumingthat all future production is at year-end prices andlifting costs; the year-end prices are not escalatedu n less the reserves are covered by a contract pro-vision requiring such an adjustment. The meas-ures are recalcuIated each year to reflect changesin prices and costs and are required by the Secu-rities and Exchange Commission (SEC) to be in-cluded i n many oil company annual reports. Al-though companies general ly disc laim theaccuracy of these measures as indicators of fu-ture E&P profitability, the measures do allow forcomparison between companies and for identifi-cation of industry trends.
According to an Arthur Andersen & Co. anal-ysis, shown in table 33, projected future net cashflows for 375 of the largest publicly held oil andgas companies remained fairly steady in 1981 to1984, with the initial price decline offset some-what by lower lifting costs and taxes.26 In 1985future net cash flows dropped 8 percent at year-end prices of about $25/bbl. At mid-1986 pricesof $15/bbl and less, the future cash flows fromproven reserves will likely be substantially less.Some analysts believe that the increases in re-serve values experienced as a result of the priceincrease in 1979 to 1981 will probably be wipedout by the 1986 price fall.
Moreover, the values of new reserves addedthrough exploration and development by majoroil companies worldwide declined between 1981to 1985 as shown in table 34. The Arthur Ander-sen study attributed the decline to the fact thatmuch of the majors’ new reserves came fromcostly improved recovery techniques and explo-ration in high cost remote areas .27 The value ad-ded on a per-equivalent barrel basis for the 375companies analyzed in the study has also de-clined since 1982. The majors generally postedthe lowest added value per barrel from explora-tion. The profitability of these low value reservesis expected to be highly sensitive to pricechanges.
The troubling outlook for the profitability of ex-ploration investments is indicated when thevalues of reserves added are compared to thecosts of discovering and developing the new re-serves. As shown in table 35, since 1981, com-panies have spent more looking for oil and gas(the “costs incurred for exploration and devel-opment”) than the present value of the reservesfound. Only in 1985 did new reserves values ex-ceed costs incurred, primarily because the costsdeclined more than the net decrease in the valueof reserves added. The value added from all newreserve sources, including exploration, develop-ment, revisions and net purchases and sales,however, significantly exceeded the related costsincurred in the same period.
“Arthur Andersen & Co., [III and Gas Reserves Disclosures: 1981-1985 SurLey of 37.5 Public Compan\es, at s-37 to s-38.
ZzAn add itiona I reason for the low present va I u es Of the new re-
serves posted by the majors is that many of these d Iscoveries haj,elong lead times before commercial production anci cash inflowsbegin, In contrast, many of the non-majors’ reserie acfdltions haverelatively short Ieadti mes before prod uctlon and I ncorne start,
Table 33.—Valuations of Proved Reserves
Discounted future net cash flowsa (billions)
In the United States Worldwide
1985 1984 1983 1982 1981 1985 1984 1983 1982 1981Majors . . . . . . . . . . . . . . . . . . . . . . . . ..$109.2 $118.9 $115.0 $120.9 $122.5 $167.4 $172.8 $169.9 $176.1 $181.1Independent . . . . . . . . . . . . . . . . . . . . . 13.8 14.8 14.8 14.7 13.2 17.2 15.0Pipeline/utility 7.3 7.3 6.8 6.3 5.6 9.1 9.1 8.6 8.8 7.6Diversified . . . . . . . . . . . . . . . . . . . . . . . 23.1 25.6 25,5 26,3 25.7 38.9 40.9 39.1 40.7 41.1
Total . . . . . . . . . . . . . . . . . . . . . . . . . .$153.4 $166.3 $162.1 $168.2 $167.0 $232.3 $240.0 $234.7 $242.8 $244.8aBa~ed On sFAs No, 69 Crlterla.
SOURCE Arthur Andersen & Co “0!1 & Gas Reserves Disclosures 1981-85 Survey of 375 Publ!c Companies, ” 1986.
104
Table 34.—Values Added Through Exploration and Development—Worldwide
Present value of reserves addeda (millions)
1985 1984 1983 1982 1981
Majors. . . . . . . . . . . . . . . . . . . . . . ..$15,447 $17,926 $16,760 $18,948 $22,071Independents . . . . . . . . . . . . . . . . . . 2,007 2,672 2,362 3,221 3,447Pipeline/utility ........ . . . . . . . . 1,850 2,009 1,576 1,597 1,583Diversified . . . . . . . . . . . . . . . . . . . . 6,677 7,927 5,988 7,712 8,262
Per equivalent barrel
1985 1984 1983 1982 1981
$ 5 . 8 3 $ 5 . 2 4 $ 5 . 6 5 $ 7 . 6 1 $ 7 . 3 98.38 10.71 10.41 11.67 11.388.61 9.91 10.37 5.66 b 9.408.44 9.08 8.65 10.31 10.05
Total/weighted averages . . . . . .$25,981 $30,534 $26,686 $31,478 $35,363 $6.67 $6.43 $6.61 $8.29 $8.26“EXten~lOnS and discoveries plus improved recoveries.blncludes the effectsof oneconlpany,sdo~nvv~rd quantity revisions in Igsl,subsequently reflected as quantity additionsln 1982.
SOURCE’ Arthur Andersen & Co., “Oil & Gas Reserves Disclosures: 1981-85 Survey of 375 Public Companies, ” 1988.
Table 35.—Value Added Ratios-Worldwide
Five-yearExploration and development average 1985 1984 1983 1982 1981
Majors . . . . . . . . . . . . . i . . . . . . . . . . . . . . 91 “/0 100% 780/o 920/o 890/o 95 ”/0Independents . . . . . . . . . . . . . . . . . . . . . . 99 92 133 106 92 84Pipeline/utility . . . . . . . . . . . . . . . . . . . . . 87 102 101 90 73a 71a
Diversified . . . . . . . . . . . . . . . . . . . . . . . . . 103 119 130 100 91 87Weighted average ., . . . . . . . . . . . . . . 93 ”/0 103 ”/0 890/o 94 ”/0 890/o 920/o
Ail sourcesMajors . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144”/0 b 177”/0 b 145”/0 1300/0 1lOO/o 1620/oIndependents . . . . . . . . . . . . . . . . . . . . . . 127 96 147 116 127 141Pipeline/utility . . . . . . . . . . . . . . . . . . . . . 132 131 152 140 183a 51aDiversified . . . . . . . . . . . . . . . . . . . . . . . . . 145 125 184 123 115 176
Weighted average . . . . . . . . . . . . . . . . 143% b 158% b 150% 1280/o 1160/0 1590/0aprlncipally reflects one company’s downward revisions In 1981, subsequently reflected as upward revisions in 1982blncludes the effect of downward revisions of certain Alaskan gas reserves ifl 1985. Excluding such revfslons, the malors’
and 5-year averages would be 181 0/0 and 161 0/0 In 1985, respectively, and unchanged for the 5 years.
SOURCE” Arthur Andersen & Co., “Oil & Gas Reserves Disclosures 1981-85 Survey of 375 Public Companies, ” 1986
These trends posed two concerns for the oil in-dustry:
1. that lower future cash flows would mean lessinternal capital available to replace depletedreserves; and
2. that under existing price expectations, do-mestic exploration was proving to be a dis-appointing and costly means of replacing re-serves.
These prospects led some companies to concludethat their limited exploration funds should bespent elsewhere—e.g., more intensive develop-ment drilling, more foreign exploration, or acquir-ing other companies or buying proven proper-ties, or investing internally by buying back sharesor boosting dividends.
Mergers and Acquisitions
The recent wave of mergers and acquisitionshas reordered the domestic industry and thinnedthe ranks of majors and independents alike. The
sheer size of some of the transactions involvedand the controversial tactics of corporate raidersand target company managers have attractedheadlines and raised concerns over the poten-tially adverse effects of “merger mania” on thedomestic oil industry. Among the concerns werethe effects on competition in the industry and theimpacts on capital spending and exploration ofthe massive increase in merger-related debt.
During the period 1979 to 1986 over $75 bil-lion was spent on the acquisition of publiclytraded oil and gas companies. Table 36 lists someof the largest transactions involving oil produc-ers.28 Many oil companies concentrated on ac-
~RTh is 11st is not lrlcluslv~ and does not, for example I nc I ude ~1 I
company acqu isltions of coal companies and nonenergy compd-nles during the same period. Among the more notable of these trans-actions were Standard 011’s $2 billion purchase ot Kennecott Corp.In 1982 and Gulf Oil CO. (
S purchase of Kemmerer Coal Co., In 1981.Large-scale mergers in the mid-l 980s hd~e not been Iimlted to 011companws. Other multl-billlon dollar transactions Include IBM’$purchase of Rolm, Nestle’s acquisition of Carnation, General Elec-trlc’s takeover of RCA, and Capital Cities Communlcatmns’ buy-out of ABC. See Impact ot Corporate Takeover5, $upra note 2.
105
Table 36.—Mergers and Acquisitions in the U.S. Oil Industry
Year
19791979197919801980198119811981198219821982198219831983198319831983198319841984198419841984198419841984198519851985198519851985198519861986198619861986
Acquiring company Target Millions of dollars
Broken Hill Proprietary Ltd. . . . . .Houston Natural Gas . . Mobil Oil Corp. . . . . . . .Getty Oil Co.
Mobil Oil Corp.S h e l l O i l C o r p . Mobil Oil CorpT h e S u n C o . , I n c . E . l . d u P e n t d e N e m o u r s & C o .O c c i d e n t a l P e t r o l e u m C o r p .T e n n e c oA s h l a n d O i l C o ,A s h l a n d O i l C o Occidental Petroleum Corp. .U . S . S t e e lBurlington NorthernC S X C o r p . Diamond.F r e e p o r t M c M o R a nI n t e r n o r t h ( E n r o n )Phillips Petroleum .C h e v r o n C o r p . D a m s o n O i lFreeport McMoRanM o b i l 0 1 1 C o r p . Phillips PetroleumTexaco, Inc.The Sun Co , Inc.U . S . S t e e l B H P P e t r o l e u m A m e r i c a sBurlington Northern .C o a s t a l C o r p .E n r o n ( I n t e r n o r t h )F r e e p o r t M c M o R a nM i d c o n C o r p .U n i o n T e x a s P e t r o l e u mFreeport McMoRanLouisiana Land & Exploration Co. Mesa Limited PartnersO c c i d e n t a l P e t r o l e u m C o r p . U.S. Steel
E n e r g y R e s e r v e s G r o u pF l o r i d a E x p l o r a t i o nV i c k e r s E n e r g y . , . ,R e s e r v e O i l a n d G a sG e n e r a l C r u d e O i l .Belridge Oil ., ... . .T r a n s O c e a n O i l . . .Texas Pacific Oil & GasC o n o c o , I n c . C r e s t m o n t O i l & G a sH o u s t o n O i l & M i n e r a l sT h e T r e s l e r O i l C o .S c u r l o c k O i l C o , . , . ,Cities Service ... .,M a r a t h o n O i lEl Paso Natural Gas ., .,Texas Gas Resources .,Shamrock Natomas. . , . : . . . . . . . .S t o n e E x p l o r a t i o nB e l c o P e t r o l e u m . . , : : : : : : : . . .G e n e r a l A m e r i c a n O i l . . .G u l f O i l C o r p . . . . , . . ,D o r c h e s t e r G a s . . . , . . . .Midlands Energy. . . . . .S u p e r i o r O i l . . . . .Aminoil USA, . . . , .Getty Oil. . . . . . . . . . . . . . . .. . . .Exeter Oil . . . . . .Husky Oil USA . . .M o n t s a n t o O i l . . . S o u t h l a n d R o y a l t y . . . . .A m e r i c a n N a t u r a l R e s o u r c e sH o u s t o n N a t u r a l G a s . .P e l - T e x O i l . . .U n i t e d E n e r g y R e s o u r c e sU n i o n T e x a s P e t r o l e u m . .Petro-Lewis & American Royalty Trust: Inexco Oil ., .,P i o n e e r P r o d u c t i o n C o . . . . : Midcon Corp. . . . . . . . .Texas Oil and Gas
n.an.an.a
620,0792.0
3,660.0715.0
2,300.07,800.0
82.31,650.0
90.013.0
3,984.05,950.01,300.01,100.01,500.0
112.0800.0
1,100.013,300.0
400.0294.0
5,720.01,600.0
10,200.075.0
488,0575.0
2,400.02,200.0
70.51,200.0
n.a440.0470.0
1,575.03,700.0
Remarks
From Esmark
From International Paper
Properties acquisition only
Stock for stock
Cash plus stock
From R.J. Reynolds
Asset acquisitionFrom Monsanto
Assets acquisition only
LBO from Allied-Signal Corp.jointly with Kidder Peabody
Mesa Units and DebtCash for 53% plus Oxy stock
n.a = not available
SOURCES: Oil and Gas Journal, Arthur Andersen & Co., and Congressional Research Service report, “Mergers and Acquisitions by Twenty Major Petroleum CompaniesJanuary 1981 through February 1984. ”
quiring other companies in their core energy and The largest of the mergers were in 1984 aschemical businesses. This pattern differs from the Chevron bought Gulf, Mobil bought Superior,1970s when many energy companies sought to and Texaco acquired Getty. As the mergers anddiversify into other areas to cushion themselves acquisitions trend continued in 1985 to 1986, thefrom the uncertainties of world oil markets. For transactions frequently involved the absorptionexample, ARCO bought Anaconda Minerals, a of a smaller ailing company into a larger, moremajor copper producer, and Mobil bought Mont- financial sound company. (For example, Loui-
gomery Ward Department Stores. For many ma- siana Land & Exploration’s acquisition of Inexcojor oil companies, the diversifications have been Oil, and Freeport-McMoRan’s bid for Petro-disappointing and now, as part of restructuring Lewis.) Major asset purchases have also con-programs, they are selling, spinning off, or li- tinued. Some larger independents, such as Mur-quidating these subsidiaries to return to their core phy Oil and Noble Affiliates, have told their share-energy and chemical businesses. holders that they are aggressively seeking
106
acquisitions as a means of adding reserves at lowcost. Takeovers and consolidations can be ex-pected to continue as lower prices undercut thefinancial viability of many independent pro-ducers.
The recent mergers and acquisitions raised anumber of major criticisms:
1.
2.
3.
4.
5.
that massive merger-related borrowing by oilcompanies could crowd out other industriesin capital markets;that acquisitions would divert funds from ex-ploration and development and other capi-tal investment;that the mergers eliminate viable competi-tors and contribute to the harmful consoli-dation of the industry;that companies that acquired new reserveswould be less likely to maintain an aggres-sive exploration program to replace produc-tion; andthat the massive new long-term debt as-sumed by some companies to successfullyfend off hostile tender offers would seriouslyimpair their ability to fund future explora-tion activities.
These concerns are countered with the argu-ments offered by those who strenuously defendedall or some of the merger activities:
1.
2.
3.
4.
5.
6.
merger-related borrowing by oil companieswas only a small portion of total loans out-standing and did not deprive other borrowersof credit;in the past, oil industry merger-related loanswere paid down within a few years out ofasset sales and cash flow;the funds paid for the acquired company didnot disappear from the economy, but werereturned to shareholders who could thenreinvest them;the merged firms will have to continue andeven expand exploration programs to sup-port the combined production levels;investments in exploration are determinedby expectations of future oil prices and prof-itability and are not influenced by the sepa-rate and independent considerations per-taining to mergers and acquisitions;mergers and acquisitions are the market-
7.
8.
place’s natural mechanisms for weeding outinefficient companies, moving assets to moreefficient operators, and providing opportu-nities for new entrants into the industry andfor expansion of existing firms;newly merged firms are stronger competi-tors, both nationally and internationally; andfinallyeven unsuccessful takeovers contribute tothe necessary restructuring of the industrybecause, to avert takeovers, target manage-ments are forced to make changes in capi-tal and operating structures that enhanceshareholder values.
Reasons for Oil Industry Merger Mania
There have been many explanations offered incongressional hearings for the wave of ‘‘mergermania” that struck the oil industry; some are sum-marized below. Many of the differences in view-point are not factual disputes, but represent con-trasting values, policies, and theories. Thesereasons can be divided into two categories: thosethat relate to mergers and acquisitions in general,and those that reflect the special circumstancesof the U.S. oil industry in the 1980s.
Among the general conditions resulting in mergerand acquisition activity are:
● Mergers and acquisitions are the marketplace’snatural remedies for inefficient corporatemanagement and are the means for assetsto flow to more productive use by stronger,more efficient companies. To the extent thatthe market value of oil companies is less thantheir book value, this reflects the stock mar-ket’s correct assessment of their performance.
● Even a profitable company with competentmanagers can become a takeover target, ifanother company believes that the target’sassets might be more valuable and profita-ble in its hands or if the target has some spe-cial expertise or capabilities that cannot eas-ily be reproduced. The purchaser can thusafford to offer a premium over the marketprice to acquire the target to realize an in-crease in value of the assets under differentmanagement or as a means of entry into anew market or industry.
107
Federal income tax benefits made corporateacquisitions attractive investments becauseof the deductibility of interest payments onmerger-related debt, the stepped up basis inthe acquired assets, and accelerated depre-ciation.Some recent takeover attempts were profita-ble for some companies and their financialbackers, even if they did not succeed, forseveral reasons. To avert a threatened take-over the defending management sometimesbrought the hostile offerors’ shares at a sub-stantial premium over the original purchaseprice. For example, Mesa Petroleum netted$214 million on its unsuccessful offer forGulf, $4 I million from its offer for Phillips Pe-troleum, and an additional $83 million fromits Unocal offer before the sale of another14.6 million shares of Unocal it still held in1986.29 In other circumstances, the takeoverthreat caused the target management to ini-tiate programs to return greater value to allshareholders, which the takeover group thenshared. Once a takeover attempt was an-nounced, the target company’s stock oftenrose. Because securities laws only requirepublic notification when an individual orcompany acquires more than a thresholdpercent, the takeover group could “accumu-late” a substantial position in the target’sstock on the open market before the an-nouncement and then gain from selling thestock at a higher post-announcement pricewithout ever completing the takeover bid.30
Some critics contend that raiders and theirinvestment bankers put companies “in play”by announcing a takeover bid without everintending to complete the bid just to profitfrom “greenmail” offered by the target com-panies and from the runup in the stock’sprice.
Conditions in the oil industry in the 1980s alsotended to favor mergers and acquisitions activity:
29Mesa petroleum, A n n u a l R e p o r t 1985, P. 24.~~TakeOVer C3fi’ers can be annou n e e d ‘ ‘ c o n t i n g e n t o n ii nanClng. ”
T h e t a r g e t a n d o f f e r o r s t o c k p r i c e s o f t e n r i s e following t h e a n -n o u n c e m e n t a n d the of feror cou ld la ter w i thdraw the o f fer w i th-
out ever purchasing any tendered stock and stil l benefit from the
Increase In va lue of the shares a l ready he ld . In adcJitton to gatns
on the sale ot stock, the backers of a takeover group often receive
commi tment tees , commissions and legal fees.
●
●
●
The mergers and acquisitions could be seenas part of a larger trend in the restructuringof the oil industry. Mergers and acquisitionsare symptomatic of the structure of a “ma-ture” or “declining” industry. The consoli-dation reflects the expectation that the ma-ture industry has only modest growthprospects and may have entered a period ofinevitably declining production as remain-ing reserves are depleted.31
The high debt levels and interest rates as-sumed by many independent oil companiesto expand rapidly during the 1979-82 boomplaced them in severe financial difficultywhen oil prices began to decline. In orderto survive, many of these businesses soughtbuyouts or mergers with other, strongercompanies .32Some recent takeover attempts were profita-ble for some companies and their financialbackers, even if they did not succeed, forseveral reasons. To avert a threatened take-value as the underlying oil and gas reservesafter oil prices tripled in 1979 to 1980. Oi lcompany stocks sold for less than their per-share appraised value and for considerablyless than the per-share breakup value. Sev-eral stocks sold for less than the per sharebook value of the company’s assets.33 Thisdisparity made the companies attractivetakeover targets. Corporate raiders, backed
31 See joint Economic Committee Study, supra note 3.Jzsee testimony of Jon Rex Jones for the Independent Petroleum
Association of America in Legislation Affecting Oil Merger Proposals,supra note 1, at 321,
33 Acc-orcfing to testimony given a House Comm Ittee, I n March
1984 the stocks of five large integrated international oil companies,Exxon, Gulf, Mobil, Standard of California (SoCal) and Texaco wereselling at an average 43.9 percent of their ).S. Herold appraisedvalue. Of the group, Gulf, which was later acquired by SoCal, wasselling at 57.2 percent of it’s appraised value, the highest of thegroup. See testimony of Mark Gilman, in Od /ndustry Mergers: Hear-
ings on H.R. 5153, H.R. 5175, and H.R. 5452, Bills to Amend theFederal Trade Commission Act to Require a Study of Mergers, Ac-quisitions, and Joint Ventures in the Auto and 011 Industnes, andfor Other Purposes Before the Subcommittee on FOSSII and Syn-thetic Fuels and the Subcommittee on Commerce, Transportation,and Tourism of the House Committee on Energy and Corn merce,98th Cong., 2d sess. 250 (1984). (Hereafter, Oi/ Industry Mergers. )See also material submitted by T. Boone Pickens on comparativestock values and book values of major oil companies appendedto testimony of Claude Brinegar of Unocal in /rnpact o~corporareTakeovers, supra note 2, at 82, 89-90. In his testimony Brinegarnoted that the stocks of three companies that had previously res-tructured were selling at a lower percent of appraised value thancompanies that had not.
108
●
by aggressive institutional investors, WallStreet investment bankers and arbitrageurs,and often financed by “junk bonds, ” put in-creasing pressure on oil companies to im-prove their return to investors or to becometakeover targets.Acquisitions also were a more attractive in-vestment alternative than some high risk ex-ploration ventures for the huge revenuesgenerated from oil production during theperiod of higher prices. Acquisitions alsooffered a quick and effective means ofreplacing reserves depleted through produc-tion. Some companies believed it was morefinancially attractive and less risky to “drillfor oil on Wall Street” (by buying other com-panies for their proven reserves) than to con-tinue to invest in risky exploration activities.Buying a company also offered the prospectsof an immediate cash infusion from its pro-ducing reserves and from the sale of un-wanted assets. In contrast, it is often yearsbefore there is any return from investmentsin long-term exploration and developmentprojects .34
Effects of Mergers and Acquisitions
Mergers and acquisitions are claimed to bebeneficial overall for stockholders and economy.Among the positive effects generally cited are:improved efficiency and lower costs for themerged entity, lower costs to consumers, and in-creased returns on investments in the stock ofpublicly held companies either from the premiumover market value offered in the takeover, or fromthe correction in discounted stock prices. 35
Jqsee responses of Mobil Oil Co. to Committee questions i n Leg-islation Affecting Oil Merger Proposals, supra note 1, at 638.
35Efficiency gains are a~ribute~ to: i) increased economies of scale
due to the larger size of the new entity; ii) marriage of complemen-tary factors such as the combination of a reserves-rich firm witha reserves-poor company with extensive refining, marketing andpetrochemical operations; iii) rationalization of production facil-ities by, for example, maintaining the most efficient facilities of thecombined operations and eliminating others; iv) replacement ofweak management; and v) economical technology transfer. See Tes-timony of Joseph j. Wright, Office of Management and Budget, inImpact of Corporate Takeovers, supra note 2, at 610-612. See alsostatement of Morgan Stanley & Co., Inc. in Legislation AffectingMerger Proposa/s, supra note 1, at 516, and testimony of Profes-sor Edward j. Mitchell, Graduate School of Business, University ofMichigan in Oi/ /rrdustry Mergers, supra note 13, at 359-60.
Another claimed benefit of mergers among ma-jor oil companies is that the larger combinedcompanies will be stronger technically and finan-cially and, thus, better able to sustain the increas-ing costs and risks of developing reserves in fron-tier areas and to compete with large foreign oilcompanies, often supported by their govern-ments, in acquiring and developing concessionsabroad. 36 Except for the gains realized on the saleof stock in the acquired companies, it is still tooearly to determine whether the recent mergerswiII in fact have these effects over the long term.
At the same time that mergers may prove ben-eficial to individual companies there remains thepossibility that they could contribute to a net re-duction in domestic petroleum production in thelong term. The most obvious short-term resultsof the mergers have been an increased consoli-dation of the oil industry, a significant increasein long-term debt, and an apparent reduction incapital spending on exploration and production.For many industry observers, fewer companiesand less exploration spending means fewer wellsdrilled, fewer reserves discovered, and eventu-ally lower oil production.
OTA has reviewed the financial performanceof 26 major and independent oil companies toassess the impacts of mergers and other restruc-turing changes in recent years. Table 37 presentsaggregate information on these companies fromtheir annual reports in 1983 to 1985. The com-panies are also subdivided into those that wereinvolved in major corporate acquisitions (bothsuccessful and unsuccessful) in 1982 to 1986 andthose that were not.37 They include two groups,14 major integrated oil companies, and 12 smallerindependent oil companies. Measuring the im-pacts of mergers on these companies is compli-cated by the fact that most of the companies haveongoing restructuring programs that are intendedto have some of the same results as somemergers. Nevertheless, OTA found some cleardifferences between companies involved intakeovers and other companies. There were alsoclear differences in expenditures for combined
Jbsupplernentary material submitted by Standard Oi I CO. Of Cali-fornia in Legislation Affecting Oil Merger Proposals, supra note 1,at 540.
JzFor Purposes of this study ‘ I major’ acquisitions are those over
$400 million.
109
In-m-
Ccggw.r=-o-
1 -
110
I
111
companies before and after the mergers. For ex-ample, as discussed later, OTA found that thelarge post-merger firms spent a smaller portionof available cash flow for exploration and othercapital expenditures and devoted a higher levelof cash flow for debt reduction than did firms thatwere not involved in acquisitions.
Several of the large company mergers have re-sulted in a retrenchment and contraction of re-sulting entities into something significantly lessthan the sum of the combined pre-merger com-panies with fewer employees, fewer total re-serves, and less totaI production than before.While some downsizing reflects efficiency gainsin the reduction of redundant overhead, othershrinkages are the results of asset sales and ad-ditional cost-cutting so that cash can beredirected to paying down debt.
There has also been a redistribution of oil andgas assets through post-merger asset sales. Thismay resuIt in properties being transferred to newowners who can make more efficient and profita-ble use of them. Some major oil companies areselling off less profitable wells in smaller produc-ing oilfields with high overhead levels. Theseproperties could be attractive to other compa-nies with extensive holdings in the same field thatcould benefit from economies of scale, or to in-dependent producing companies with loweroverhead. Some new owners have made or an-nounced planned investments to expand produc-tion in their newly acquired properties. These as-set sales are also coming at a time when the pricefor proven properties is much lower than it hasbeen, so that companies buying reserves canoften do so for much less than average findingcosts.
Mergers and the Consolidation ofthe Oil Industry
The new combinations arising from the recentmergers reordered the rankings of the major oilcompanies. Table 38 shows the top 20 petroleumcompanies ranked by assets, liquids reserves, andliquids production in 1980 and 1985. By 1985,9 of the top 30 oil companies in 1980 had beenacquired. The primary changes in the rankingsare the disappearance of some “second tier” in-
dependent integrated companies and the eleva-tion of smaller companies into the ranks of themajors. As shown in table 39, the relative hold-ings of the top 8 firms have increased throughthe Gulf-Chevron merger and the absorption ofseveral of the larger independents, Getty, Mara-thon, and Superior.38 At the same time the con-centration levels of the largest 20 oil companieshave declined relative to the rest of the industry.
Consolidation has also been significant amongthe independents. Mergers and acquisitions, aswell as bankruptcies, dissolutions, and liquida-tions have also contributed to a thinning and con-solidation in the ranks of the independents.According to the 0il and Gas Journal annualreports on the 400 largest publicly held oil andgas producers, the year-end value of assetsneeded to place on its list dropped from $2.37million in 1983 to $276,000 in 1984, to $179,000in 1985.39 Among the smaller public and privateindependents, there has also been a severeshrinkage which has been estimated at about 25to 30 percent of the independent exploration andproduction companies. While detailed informa-tion on the disappearance of the independentsis not readily available, the estimated number ofindependents, as presented in testimony on be-half of the Independent Petroleum Associationof America (IPAA), declined from over 15,000 in1984 to about 12,000 in mid-1986.40 Some be-lieve that the majors could be a more dominantinfluence in domestic exploration and produc-tion than before 1980 as a result of the consoli-dation among the larger companies and the dis-appearance of so many independent operators.
Some industry observers believe that the con-traction of the majors could create more oppor-tunities for independents in some niches. Withsmaller exploration staffs and less money to spendon drilling, the majors may be willing to do more
~BTh.e table does not fully reflect the acquislt!ons announced In1986; when these transactions are taken into account they will tur-ther reflect this trend.
3982 Oil & Gas JoUrna/ 103, Sept. 10, 1984; 83 01/ d Ga5 Journal
89, Sept. 10, 1985; 84 01/ & Gas Journal 55, Sept. 8, 1986.~OSee te5t i mon y Of RayrnO ncj H, H efner, for the I PAA i n tlear-
irrgs on the Domestic and /nternationdJ Petroleum Situation andthe Implications of Fees on Imported 0// Before the Senate Comm.on Energy and Natural Resources, 99th Cong., 2d sess. 196, 225(1 986). See also, testimony of Jon Rex jones for the IPAA in Legis-lation Affecting Oil Merger Proposals, supra note 1, at 315.
112
Table 38.–Comparison of 20 Largest U.S. Oil Companies, 1980 and 1985
Top 20, 1985 Total assets Top 20, 1980 Total assetsRank company ($ billions) Rank company ($ billions)
1 Exxon Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . .2 Mobil Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . .3 Chevron Corp. . . . . . . . . . . . . . . . . . . . . . . . . .4 Texaco, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . .5 Shell 0il Co. . . . . . . . . . . . . . . . . . . . . . . . . . .6 Amoco Corp. . . . . . . . . . . . . . . . . . . . . . . . . . .7 Tenneco, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . .8 Atlantic Richfield Co. . . . . . . . . . . . . . . . . . . .9 Standard Oil Co. . . . . . . . . . . . . . . . . . . . . . . .
IO Phillips Petroleum Co. . . . . . . . . . . . . . . . . . .11 Sun Co., Inc. . . . . . . . . . . . . . . . . . . . . . . . . . .12 Occidental Petroleum Corp. . . . . . . . . . . . . .13 Unocal Corp. . . . . . . . . . . . . . . . . . . . . . . . . . .14 Marathon Oil Co. . . . . . . . . . . . . . . . . . . . . . .15 Conoco Corp. . . . . . . . . . . . . . . . . . . . . . . . . .16 Enron Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . .17 Coastal Corp. . . . . . . . . . . . . . . . . . . . . . . . . . .18 Amerada Hess Corp. . . . . . . . . . . . . . . . . . . .19 Columbia Gas System, Inc. . . . . . . . . . . . . . .20 Midcon Corp. . . . . . . . . . . . . . . . . . . . . . . . . . .
69.1641.7538.9037.7026.5325.2020.4420.2818.3314.0512.9211.5910.8010.079.909.898.296.225.845.81
1 Exxon Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . .2 Mobil Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . .3 Texaco, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . .4 Standard of California (Chevron) . . . . . . . . .5 Standard Oil (lndiana) . . . . . . . . . . . . . . . . . . .6 Gulf Oil Corp. . . . . . . . . . . . . . . . . . . . . . . . . .7 Shell Oil Co.. . . . . . . . . . . . . . . . . . . . . . . . . . .8 Atlantic Richfield Co. . . . . . . . . . . . . . . . . . . .9 Tenneco, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . .
10 Standard Oil (Ohio) . . . . . . . . . . . . . . . . . . . . .11 Conoco Corp.... . . . . . . . . . . . . . . . . . . . . . . .12 Sun Co., Inc. . . . . . . . . . . . . . . . . . . . . . . . . . .13 Phillips Petroleum Co. . . . . . . . . . . . . . . . . . .14 Getty Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15 Union Oil of California. . . . . . . . . . . . . . . . . .16 Occidental Petroleum Corp. . . . . . . . . . . . . .17 Amerada Hess Corp. . . . . . . . . . . . . . . . . . . . .18 Cities Service. . . . . . . . . . . . . . . . . . . . . . . . . .19 Marathon Oil Co. . . . . . . . . . . . . . . . . . . . . . . .20 Coastal Corp. . . . . . . . . . . . . . . . . . . . . . . . . . .
56.5832.7126.4322.1620.1718.6417.6216.6013.8512.0811.0410.969.848.276.776.635.905.365.044.11
NOTE: Excludes mergers after Dec. 31, 1985
SOURCES Oil and Gas Journal, Sept 5, 1988, Fortune Magazine, “500 Largest Industrial Corporations," 1980 data, published May 4, 1981, at 322
Table 39.—Comparison of Historical Concentration in the U.S. Oil lndustry(percent of U.S. total)
Concentration ratio-U.S. net crude oil, condensate, and natural gas liquids production1955 1960 1965 1970 1975 1980 1983 1984 1985
4 - F i r m . . . . . . . . . . . . . . . . . . . . . 1 8 . 1 20.8 23.9 26.3 26.0 25.3 25.0 26.1 26.20/o8-Firm . . . . . . . . . . . . . . . . . . . . . 30.3 33.5 38.5 41.7 41.2 40.8 38.4 44.5 43.615-Firm . . . . . . . . . . . . . . . . . . . . 41.0 44.2 50.3 56.9 57.0 56.1 53.5 56.4 53.220-Firm . . . . . . . . . . . . . . . . . . . . 46.3 49.1 55.0 61.1 61.2 60.6 57.6 59.4 55,8
Concentration ratio-U.S. Iiquids reserves1975 1980 1983 1984 1985
4-Firm . . . . . . . . . . . . . . . . . . . . . 36.3 31.1 29.0 29.6 29.10/o8-Firm . . . . . . . . . . . . . . . . . . . . . 55.6 46.3 43.2 48.6 41.715-Firm . . . . . . . . . . . . . . . . . . . . 70.4 59.5 56.1 59.1 47.320-Firm . . . . . . . . . . . . . . . . . . . . 74.5 62.7 59.4 61.2 58.9SOURCE: Office of Technology Assessment from American Petroleum Institute, Market Shares and Individual Company Data
for U.S. Energy Markets 1950-84, Discussion Paper #O14R, Oct. 1985; 1985 Data from Oil and Gas Journal and In-dependent Petroleum Association of America, Petroleum Statistics 1985.
farmouts with independents and may even bewilling to share some of the costs rather thanmerely contributing drilling rights.41 Moreover,if the merged companies cut back their unprovenproperty acquisitions and exploration efforts, in-dependents may be more successful in obtain-
~lRemarksof Ray Hunt, at SMU-lSM conference on Lower World011 Prices in Dallas, September 1986.
ing some of the better prospects with reducedcompetition from the majors.
There has been concern expressed that thenew combinations will diminish competitionwithin the domestic industry. But, by severalcommonly used antitrust enforcement measures,the oil and gas industry remains competitive.Concentration levels in liquids production and
113
reserves are still within historical levels (see ta-ble 39). The Federal Trade Commission has char-acterized the oil and gas production industry as“not highly concentrated.”42 Applying the cur-rent antitrust enforcement guidelines used by theDepartment of Justice and Federal Trade Com-mission to the market for crude oil, no mergerbetween competing oil companies is likely to bechallenged based on its effects in the overallcrude market. I n several large mergers, the Fed-eral Government found significant downstreamantitrust problems and ordered divestitures of cer-tain downstream marketing and refining opera-tions before approving the mergers.
In testimony before Congress, several witnessesquestioned the adequacy of the standard meas-ures for assessing mergers among large oil com-panies. Concentration ratios, HHI and other in-dices are primarily concerned with measuring theeffects on market share of horizontal mergers(combinations between competing companies),and do not adequately reflect the true impactson competition of mergers in the vertically in-tegrated oil industry. For example, it was notedthat the six largest oil companies could combineinto a single giant company without exceedingthe HHI indices triggering enforcement review.43
Moreover, they noted, traditional antitrust andcompetition considerations were not the onlyareas of economic or social concern raised bythe mergers.
qzsee tes t imony of T imothy j. Muris, D i rec tor , Bureau ot’ Comp-
etition, Federal Trade Commission in Legislation Affecting Oi/Merger Proposa/s, supra note 1, at 71, citing a 1982 FTC study onconcentration in the 011 Industry. See also, American PetroleumInstitute, Market Shares and Individual Company Data for U.S.Energy Markets: )950- 1984, Dlscusslon Paper, October 1985. Esti-mates of 4-firm and 8-firm concentration ratios in the oil industryhave been fairly steady, varying only a few percentage points ei-ther way since 1970. The 1982 Department of justice Merger Guide-lines use numerical standards to ascertain whether a proposedmerger between competl ng companies may tend to affect compe-tition adversely—the Herfindahl-H lrschman n Index or HH 1. The gov-ernment IS most likely to challenge a proposed merger if the post-merger H H I Index IS above 1,000 or If It increases the post-mergerHHI IS increased by more than 100 points to above the 1800 level.“The HHI measured In terms of U.S. production is only about 270and In terms of U.S. crude oil reserves is approximately 329. AllOi these values are wel l be low the 1,000 HHI level lhdl ~0[/7kl//ytriggers potential antitrust concern with a merger between com-petitors. ” Testimony of Timothy j. Murris in 0;/ /ndustry Mergers,supra note 13 at 234-237.
4 30 11 /ndu5fry Mergers, supra note 13, at 204.
Increase in Long-Term Debt
The wave of acquisitions and anti-takeoverdefensive tactics added substantially higher levelsof debt for the oil industry as a whole, as wellas for individual companies. The Department ofEnergy found an increase in debt equity ratioamong the Financial Reporting System (FRS) com-panies from 34.8 to 49.5 percent in 1984 alone,with much of this increase attributable to the ef-fects of the Chevron-Gulf, Texaco-Getty, andMobil-Superior takeovers. 44 OTA’s review of agroup of oil companies also shows higher debtlevels for most merged companies (see table 37).Total long-term debt of the companies studiedmore than doubled between 1983 and 1985. Thelargest increases were by firms involved intakeovers; their debt levels nearly tripled in 1983to 1984 but repayments in 1985 lowered theiroverall long-term debt to 2½ times the 1983levels. The heavier debt loads, at least in the shortterm, have been accompanied by lower total ex-penditures by the combined companies on ex-ploration and capital investment in 1985 than in1984. Among the companies not involved intakeovers, new long-term debt was used to re-tire prior debt at higher interest rates, to repur-chase shares, to buy assets, and to provide addi-tional capital for investment. The highest debt todebt plus equity ratios, a common measure ofdebt load or leverage, was shown by the twocompanies that successfully averted hostiletakeover offers—increasing from 0.23: 1 in 1983to 0.72:1 in 1985.
wu .s. Depaflment of Energy, Energy Information Adm in istratlon,
Performance Prot’iles of Major Energy Producers 1984, 20-21 (1986).The FRS companies are a group of companies that are requiredto file detailed annual reports. The FRS companies were selectedfrom the top 50 publlcly owned domestic crude oil producers in1976 who had at least 1 percent of either the production or re-serves of oil, gas, coal or uranium, or 1 percent of refining capac-ity or or petroleum product sales. I n 1984 the FRS group included:Amerada Hess Corp.; American Petrofina, Inc.; Ashland Oil, Inc.;Atlantic Richfield Co.; Burlington Northern, Inc; Chevron Corp.;Cities Service Oil Co.; Coastal Corp.; El. du Pent de Nemours &Co.; Exxon Corp.; Getty 011 Co.; Gulf Oil Corp.; Kerr-McGee Corp.;Mobil Oil Corp.; Occidental Petroleum Corp.; Phillips PetroleumCo.; Shell Oil Co.; Amoco Corp.; Standard Oil Co.; Sun Company,Inc.; Superior Oil Co.; Tenneco, Inc.; Texaco, Inc.; Unocal Corp.;Union Pacific Corp.; and United States Steel Corp. Four acquiredcompanies, Cities Service, Gulf, Getty, and Superior, all filed sep-arate FRS reports for 1984 because the mergers were not fullycomplete.
114
Many of the corporate acquisitions followed in-tense, and sometimes bitter, battles for corporatecontrol. The impacts on corporate finances ofdefensive tactics adopted to fend off unwantedor “hostile” takeover offers raised concerns aboutthe targets’ future ability to fund exploration activ-ities. In several successful takeover defenses, thetarget companies averted the takeover by buy-ing the offerors’ shares at a premium. In others,the target merged with a friendly “white knight”,which often outbid the original offerors. Thedefending company was left with much higherdebt. The unsuccessful offeror was left with a siz-able gain on the stock transaction. Results suchas this have led some raiders and other critics tocontend that the target managements were moti-vated more by concern over protecting their ownjobs than in advancing the shareholders interests.
An increase in long-term corporate debt is notby itself reflective of a weakened financial posi-tion. Debt and equity are the two principal meansof raising capital for acquisitions and for capitalspending. Increased debt has some risks, how-ever. Debt brings with it a requirement to payinterest that, unlike dividends, generally cannotbe deferred. High debt levels among oil compa-nies raise two concerns: reduced flexibility indeciding how to spend its available cash flow;and reduced commitments to exploration andproduction as assets are sold and capital expend-itures are cut to pay off debt.45
Effects on Exploration
The pattern of reduced exploration expendi-tures following recent mergers tends to contradictsome of the earlier studies and examples citedin testimony in 1984 at the height of the mergers.Following the acquisitions of Marathon by U.S.Steel, Conoco by Du Pent, and Belridge by Shell,exploration expenditures were reported to haveincreased. But these results predated the morerecent round of mergers and both the U.S. Steeland Du Pent acquisitions involved essentially newentrants into the oil business that operated theirpurchases as separate subsidiaries. More recent
qSTota[ long-term debt over 40 percent of a cOmpanieS total
capitalization (Total long-term debt, plus total equity) is consideredhigh, but not unmanageable, however debt levels of 70 percentof capitalization or more are a matter for concern.
mergers have involved the disappearance by ab-sorption of one energy company into another andthe overall contraction of the combined entity,with lower production levels, reserves, and ex-ploration expenditures.
During the debate over the effects of mergersand acquisitions in the oil industry, many of therepresentatives of acquiring companies, their in-vestment bankers, and their defenders stronglydenied that exploration efforts would be re-duced. 46 Some company executives even sug-gested that exploration could be expanded be-cause of efficiency gains and the stronger cashflows and asset bases of the merged companies.However, others inside and outside the industryargued as strongly that exploration would be cutbecause the newly purchased reserves reducedthe incentive to look for more oil and repaymentof the new long-term debt would divert cash flowthat otherwise might be used for E&D.
The available evidence strongly suggests thatthe short-term results of the merger activity forthe U.S. oil industry as a whole are reducedspending on exploration, fewer wells drilled, andless R&D than there was before the mergers and,arguably, than there might have been had thesefirms continued as separate entities. The amountof this change is not possible to quantify, but isprobably much less than the losses attributableto the decline in prices. The merger-related ex-penditure declines are probably less than thosecaused by low prices because the 1986 spend-ing cuts by all companies tended to be as largeor larger than the 1985 cuts by merged compa-nies. The fact that merged companies took cutsin E&P and capital expenditures in 1985, whileothers were still spending at previous levels orhigher, suggests that the mergers have signifi-cantly decreased exploration expenditures belowlevels that might have been maintained by inde-pendent entities. If, for example, Gulf, Superior,
46FOr examples, See: supplernentay material submitted by Stand-
ard Oil Company of California in Legidation Affecting Oi/ MergerProposa/s, supra note 1, at 540; response of Chevron U.S.A. to Com-mittee questions, id. at 539; statement of Morgan Stanley & Co.,Inc., id. at 516; and material submitted by the Department of theInterior, id. at 529. See also, Testimony of Joseph j. Wright, Officeof Management and Budget, in Impact of Corporate Takeovers,supra note 2, at 610-612; and testimony of Professor Edward ).Mitchell, Graduate School of Business, University of Michigan inOil Industry Mergers, supra note 13, at 359-60.
115
Getty, and Cities Service had remained separateand continued their active exploration programsand if these programs were cut at the industryaverage, the separate exploration expendituresadded to the baseline expenditures for Chevron,Mobil, Texaco, and Occidental, respectively,wouId likely exceed the totals for the merged en-tities.
The merged companies typically cut combinedcapital spending significantly in 1984 to 1985,while other large oil companies were maintain-ing or increasing their investments. This patternis also seen in other surveys of U.S. explorationand development expenditures shown in table40 for 1983 to 1985. Table 41 shows a similar pat-
tern in different, but comparable data on domes-tic exploration expenditures in 1986 to 1987.When oil prices fell in 1986, the merged com-panies reduced exploration budgets that were al-ready constricted, and the share of their cash flowdirected at debt reduction is undoubtedly muchhigher than was anticipated when the mergersoccurred.
There are others who maintain that it is purelycoincidental that exploration expenditures ofsome combined companies were cut substantiallyafter the mergers. In their view the reasons forthe cuts were related solely to the anticipated fu-ture oil prices and the quality of the available ex-ploration prospects. There are of course other fac-
Table 40.—Capital and Exploration Expenditures for Selected Oil Companies1983-1985 (thousands of dollars)
1985 1984 1983capital capital capital
and and andexploration Percent change exploration Percent change explorationspending 1984-85 spending 1983-84 spending
Exxon Corp 10,339,000Amoco Corp 5,306,000Shell 011 Co 4,080,000Mobil Corp 3,513,000
S u p e r i o r 0 1 1 —
C o m b i n e d 3,513,000Texaco, Inc 2,824,000
Getty 011 —Combined 2,824,000
Atlantic Richfield Co 3,595,000Chevron Corp 4.035,000
Gulf 011 —C o m b i n e d 4,035,000
Sun Co I nc . 1,748,000Standard 011 Co. 4,277,000U n o c a l C o r p . 1,847,400T e n n e c o , I n c 1,719,000Conoco Corp. 1,402,000Phillips Petroleum ., 1,060,000Amerada Hess Corp. ... 929,000O c c i d e n t a l P e t r o l e u m C o r p . . , 1 , 1 5 1 , 7 0 0
M i d C o n C o r p . 354,869Combined a —. . . .
Marathon Oil Co. . . 1,165,000Texas Oil & Gas Corp. . . . 739,400I n t e r n o r t h , I n c . 591,200
Houston Natural Gas Corp. ., –C o m b i n e d 591,200
Diamond Shamrock Corp 679,900Pacific Lighting Corp. ., 527,114Coastal Corp. 341,300
American Natural Resources —Combined ., 341.300
6.014.63.9
– 7,7—
–7 7–24 6
—–24 6
10,4– 15.7
.
– 15,7– 2 6 , 5
83.6– 5 . 0– 1,7
1.1– 2 3 . 6– 16,5
5.5● 8.2
.60.2
– 3 . 8– 8 . 8
—– 4 4 , 3
7,0–7, 1
122—
– 3 8 . 9
9,755,0004,630,0003,927,0003,806,000
—3,806,0003,744,000
—3,744,0003,257,0004,786,000
—4,786,0002,377,0002,329,0001,944,8001,748,0001,387,0001,387,0001,112,1611,091,240
327,951—
727,000768,679648,548413,652
1,062,200635,500567,335153,542404,600558,142
8 413,237,8
–12 4—
–12 4–26 O
—– 26.0
– 2 . 9– 18.0
—– 18,0
83.71.3
11.18.6
– 2 0 . 521,653.114.78.9
—– 2 5 . 0
16,1155,233.088.036.1
– 10.834.834.434.5
9,000,0004,091,0002,850,0003,330,0001,016,8554,346,8553.833,0001,223,3195,056,3193,355,3843,067,0002,770,0005,837,0001,294,0002,298,0001,751,0001,609,0001,744,7001,141,000
726,365951,019301,229
969,000662,332254,152310,971565,123466,853636,013113,893301,100414,993
aMerger completed m early 1986
SOURCE OTA from 011 & Gas Journal and company annual reports
116
Table 41 .—Changes in Planned Expenditures on U.S. Exploration and Production
Actual June ’86 Percent change Actual Jan. ’87 Percent change1985 budget 1985-86 1986 est. budget 1986-87
Major oil companies:Amerada Hess Corp . 310 120 –61 95 75 –21A m o c o C o r p . 3,170 1,650 – 4 8 1,300 1,300 0Atlantic Richfield Co. 2,300 1,035 – 5 5 1,000 750 – 2 5Chevron Corp.a . . 1,800 1,200 – 3 3 1,050 975 – 7E l . d u P e n t d e N e m o u r s a 700 420 – 4 0 500 550 10E x x o n C o r p . . 4,700 3,050 – 3 5 2,700 2,565 – 5K e r r - M c G e e . . 140 75 – 4 6 75 70 – 7Mobil Corp.a . . 1,460 1,020 – 3 0 1,020 1,020 0Occ identa l Pet ro leum Corp. a 375 260 –31 260 235 – 1 0P e n n z o i l . , 270 175 – 3 5 140 120 – 1 4Phillips Petroleum Co a 455 335 – 2 6 200 240 20She l l O i l Co . . 1,800 1,350 – 2 5 1,645 1,520 – 8Standard 1,700 1,000 – 4 1 1,250 1,150 – 8S u n C o . , I n c . 820 625 – 2 4 430 430 0Tenneco, Inc. 565 240 – 5 8 310 235 – 2 4Texaco, Inc . a 1,670 1,100 – 3 4 1,000 900 – 1 0U n i o n P a c i f i c 400 200 – 5 0 195 185 – 5USX Corp. a . . 1,255 725 – 4 2 560 480 – 1 4U n o c a l C o r p .a 945 680 – 2 8 600 640 7
T o t a l m a j o r s . . . . . . . . 2 4 , 8 3 5 1 5 , 2 6 0 – 3 9 14,330 13,440 – 6
Selected independents:Apache. 120 80 – 3 3 65 25 – 6 2Burlington Northerna 430 95 – 7 8 100 100 0D i a m o n d S h a m r o c ka 190 90 – 5 3 105 130 24E n r o na 200 100 – 5 0 100 91 – 9E n s e r c h 250 140 – 4 4 158 103 – 3 5Freeport-McMoRan a 122 55 – 5 5 55 52 – 5L o u i s i a n a L a n da . . . . 260 155 – 4 0 155 147 – 5Mitchell Energy ... 130 89 – 3 2 65 65 0M u r p h y . 113 60 – 4 7 50 50 0P o g o P r o d u c i n g . . 115 70 – 3 9 65 40 – 3 8S a n t a F e S o u t h e r na 195 145 – 2 6 100 95 – 5T r a n s c o E x p l o r a t i o n 280 125 – 5 5 125 120 – 4
–50 1,143 1,018 –11Total independents. 2,405 1,204.
‘Companies lrlVOlv@ In major takeovers 1982-86SOURCES OTA from Oil & Gas Journal July 21, 1986, and Jan 19. 1987
tors that contributed to lower explorationexpenditures in recent years, such as lower prop-erty acquisition costs because of reduced offer-ings of Federal offshore leases and lower bonuses,cost deflation in drilling and services, and defer-rals of major projects because of price uncer-tainty. These factors affected both merged andnon merged firms alike, however.
Oil production may actually increase if the pur-chaser can exploit the acquired reserves moreefficiently. The classic example of this was ShellOil Co.’s acquisition of Belridge Oil in 1979. Fol-lowing the merger, Shell invested in enhancedrecovery to expand heavy oil production from
Belridge’s California reserves. More recently, agood geographic “fit” of acquiring and acquiredcompanies was cited as an advantage in the Phil-lips’ takeovers of General American Oil andAminoil, and in Louisiana Land & ExplorationCo.’s purchase of Inexco Oil. These transactionsinvolved complementary reserves holdings inareas where the purchasers were already activeand allowed expansion into other areas wherethey were not represented.
Some major acquisitions may have been moti-vated primarily by reserves replacement, ratherthan as a means of corporate expansion. Severalcompanies that bought other firms for their re-
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serves had not been particularly successful inreplacing their reserves through exploration .47This motivation is suggested by the shrinkage ofthe post-merger companies as many unwantedproducing properties and operations are sold orabandoned. The acquiring company may be suc-cessful in maintaining its production level in thefuture out of its purchased reserves, but it maysupport a production level that is less than thecombined companies before the acquisition. Cu-mulatively, overall domestic production coulddrop because of reduced total spending on ex-ploration.
It has been argued that mergers need not re-sult in reduced exploration and fewer reservesadded. For example, a merger might create a newentity that is more efficient and successful at find-ing oil than its predecessors. Moreover, the com-bined firm would still face the need to replacethe reserves lost through production (assumingit maintains the same production level after themerger) and would still be subject to require-ments to drill many of its leases or lose them. Thecombination might lead to improved economiesof scale by eliminating or reducing duplicativeoverhead and nondevelopment-related expend-itures allowing more productive use of the com-bined financial resources and technical people.48
The Department of the Interior has suggested thateven if the merged company only conducted thesame amount of exploration as before, it couldcombine information on geology, and geophysicsof exploration prospects and select the bestdrilling sites from a larger menu and it might ac-tually improve its exploration results with lessoverall spending on exploration and fewer holesdrilled than might have been spent by the firmsseparately. 49 (This suggested result is questiona-ble, however, since high grading would not nec-essarily increase the amount of reserves found,particularly if the acquired company was no moresuccessful at finding oil than the acquiring com-pany or if the exploration staff responsible for the
~zsee Donald F. Textor, Todd Bergman, and Cristina Tiscareno,
“Flndlng Costs and Reserves Replacements Results 1979-1 985, ”Goldman Sachs Investment Research, Apr. 2, 1986.
~esee, for examp~e, response of Chevron U.S. A. to Committee
questions in Legislation Aftecting Oil Merger Proposals, supra note1, at 539.
~gAdditlonal material submitted by the Department Of the I nterlor,
Leglslatlon Attectlng Oi/ Merger Proposa/s, supra note 1, at 529.
reserves position of the acquired company is laidoff or leaves. )
Others doubt that there are any added efficien-cies in oil exploration to be gained through themergers among large oil companies. Historically,the range of finding costs posted by both first andsecond tier major oil companies have been sim-ilar. The biggest companies did not necessarily
have the lowest finding costs. Moreover, most ofthe anticipated savings would come from cuttingstaff, which may lead to long-term inefficienciesin exploration from the lack of experienced tech-nical people. so
it is too soon to tell whether the mergers willmean a net increase or decrease in explorationand production in the long term. Several mergedcompanies, e.g., Chevron and Mobil, have madesubstantial efforts to pay down debt even withlower oil prices. In a few years, they maybe readyto reallocate resources to exploration and re-search from a stronger financial and resource po-sition.
In the longer term, even at lower oil prices,many of the larger merged companies wiII againhave cash available that could be used for E&Pafter reducing their long-term debt. It will thenbecome more apparent whether the added debtburden, asset sales, and restricted explorationactivities assumed to undertake the merger willhave produced a sounder, more efficient enter-prise better suited to an era of uncertain oil prices.Table 41 shows preliminary 1987 explorationbudgets for some firms, and it is notable that sev-eral of the merged firms are slightly increasingtheir exploration budgets.
Other Restructuring Activities
Oil companies have adopted a variety of res-tructuring strategies which they believe will helpthem to compete in the current era of volatileenergy prices. Mergers and acquisitions havebeen perhaps the most public aspect of the res-tructuring, but they have been only part of arange of industry responses to changing con-ditions.
~~see, for exam Pie, the testimony of Howard W. Pifer, I I 1, Man-
a g i n g D i r e c t o r , P u t n a m , H a y e s & B a r t l e t t , I n c . , In Oi/ /ncfustryMergers, supra note 13, at 211.
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Segmentation and 66Dis-integration”
Changes in the world oil industry following theOPEC price shocks of the 1970s have contributedto the modification of the traditional integratedstructure of some major companies. Maintenanceof a secure source of crude supply is no longera priority for many integrated companies becauseof: 1 ) current world overcapacity in oil produc-tion; 2) a greater diversity of sources for crudeoil with decreased reliance on mideast OPEC oil;and 3) the widely shared expectation that oil de-mand (and hence sales) will grow only modestlythrough the end of the century.
The process of buying and selling of crude oilhas also changed. Oil prices now can fluctuatemuch more rapidly than before. The traditionallong-term contracts for crude, which used to ac-count for 90 percent of U.S. supplies, have largelybeen abandoned, and in 1986 up to 90 percentof supplies from outside the United States wereobtained on the spot market or at spot-market-related prices. Netback arrangements with for-eign producers are a part of this trend .51 Manycompanies have turned to options trading tomoderate the risks of volatile oil prices.
Increasingly, segments of the oil industry arebeing separated vertically and operationally.Some integrated companies no longer depend ontheir own reserves to supply their refining andmarketing operations.52 Downstream operations
s! Netback contracts are an arrangement between the Seller of
crude oil and the purchaser in which the ultimate price per barrelthat the seller receives is tied to the sales price of refined prod-ucts. This arrangement guarantees the refiner a minimum marginon product sales. Netback pricing was implemented by Saudi Ara-bia [n late 1985 as part of Its drive to regain market share. The termsof netback pricing arrangements are highly confidential, but byspring 1986 it was estimated that 3.5 to 4.5 million barrels of 011per day were sold under these terms by the Saudis and others. Ar-thur Andersen & Co., Oil and Gas Reserves Disclosures: 1981-1985Survey of 375 Pub/ic Companies, 1986 at s-9. It should be notedthat in early 1987, the Aramco Companies were reported to havesigned a long-term fixed price agreement with the Saudis. Whetherthis marks a shift away from netback pricing is not yet known, sincethe terms of these agreements are confidential.
‘2’’ Crude oil production and crude oil refining and marketing arealmost completely unrelated aspects of the petroleum business.Crude oil today is a fungible commodity in trade. Petroleum com-panies sell most of their crude to third parties and buy most of theircrude for refining purposes from third parties. This is the very na-ture of the business. There is not a direct tie between the wellheadand the gasoline pump within a company. ’ Statement submittedby Gulf Oil Corp. in response to Committee questions in Oi/ /n-dustry Mergers, supra note 13, at 426.
are frequently seen as separate from upstream ex-ploration and production activities. The down-stream activities are now treated as independentand important profit centers rather than as an out-let for a company’s crude. In the early 1980s, thisshift led to the closing of many company-ownedretail outlets and a net reduction in domesticrefining capacity as refineries were upgraded andoutmoded facilities were closed. Some compa-nies have begun to redeploy their resources totheir most profitable segments functionally andgeographically instead of maintaining an in-tegrated nationwide operation from explorationand production to shipping, refining, distribut-ing, and marketing. For example, Ashland OilsoId many of its producing oil properties and re-lies more heavily on crude purchases to supplyits refineries. Arco has pulled out of the retail oilmarket in the northeast. The cost-cutting and up-grading in refining operations as part of the earlyrestructuring of downstream operations appearto have benefited some companies during theprice plunge, with higher profit margins in refin-ing helping to offset upstream losses.
According to some industry analysts, the grow-ing segregation of upstream and downstreamactivities has contributed to a decline in theproportion of production revenues “plowedback” into acquiring and developing unprovenproperties. The 60 percent “plowback” in 1985was the lowest in at least 5 years (see table 42).As noted earlier, a primary factor driving thesechanges has been the mediocre result of muchof the E&D activity of the last 10 years reflectedin the extremely high finding costs reported bymuch of the industry and the serious disappoint-ments in exploration on the frontiers.
Cost-Cutting
Many restructuring programs were announcedas efforts to cut costs and conserve capital andcash flow in anticipation of a prolonged periodof low oil prices and sluggish demand. Althoughthese changes were announced in early to mid-1985, most companies underestimated how shar-ply, and quickly, oil prices would actually fall in1986 so that these programs were not fully inplace to offset potential losses.
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Table 42. —Reinvestment in Oil and Gas Exploration and Production (375 publicly held oil & gas producers)
Plowback ratiosUs. Foreign Worldwide
1985 1984 1983 1982 1981 1985 1984 1983 1982 1981 1985 1984 1983 1982 1981
Exporation and developmenta
Majors 58% 64% 58% 68% 68% 32% 33% 37% 49% 47% 47% 52% 50% 62% 59%Independents 57 56 62 105 134 75 59 52 93 99 62 58 60 104 133Pipeline/utillty 74 78 83 107 106 51 63 81 90 94 68 75 79 104 103Diversified 67 63 69 109 123 52 41 65 51 64 61 55 69 84 100
Weighted average 60% 64% 61% 77% 80% 37% 36% 42% 51% 52% 50% 53% 54% 69% 70%
All sources b
Majors 63% 111 % 62% 68% 68% 33% 57% 38% 49% 47% 500/0 89% 52% 62% 59%Independents 93 93 92 131 145 75 65 63 122 104 91 89 87 130 144Pipeline/utillty 113 90 107 108 106 74 63 162 92 94 107 84 111 105 104Diversified 92 74 73 150 136 55 43 69 59 102 77 62 73 110 124
Weighted average 71% 103% 67% 85% 83% 38% 55% 45% 53% 59% 58% 85% 59% 74% 74%aExcludes proved property acqulsmon costsblncludes proved propefly aCqulSltlOn cos ts
DEFINITIONS Plowback ratios are one measure of the level of a company’s capital reinvestment m 011 and gas actlvltles In this survey, plowback ratios are measured [n Iwo different ways● E&D Plowback compares cash flows from net production revenues to the costs recurred to acquire unproved acreage and explore and develop new reserves. All Sources Plowback compares cash flows from net production revenues to the costs recurred to purchase eXiSt109 proved reserves and search for new reserves
These ratios are designed to measure the degree to which companies are using produchon cash flows and capital frOM other sources to replace reserves whether through explorationand development or by acquiring exlstlng reserves
SOURCE Arthur Andersen & Co 011 & Gas Reserves Disclosures 1981-85 Survey of 375 PUbliC Companies, ’ 1986, s-40
Companies have reorganized divisions to elim-inate duplicative functions and streamline activ-ities. As part of accompanying changes in invest-ment priorities and philosophies, many firms havemade sharp reductions in exploration and devel-opment budgets. Within E&D programs, capitalspending has been directed away from unprovenproperty acquisition and frontier-wildcat drillingtoward more development drilling and intensivedevelopment of existing fields. (These shifts arein addition to the increases in developmentspending that would normally follow the highlevels of exploratory activity in the early 1980s.)Although more development drilling generallyleads to more production, over the longer term,lower exploration expenditures eventually willlead to lower production unless reserves arereplaced from other sources. A continuation ofthese trends implies less overall exploration anddevelopment expenditures, as well as less R&Dspending in an industry with historically low R&Dspending.
With less exploration activity, exploration andproduction staffs have been slashed. Corporation-wide personnel reductions have been achievedthrough early retirements, hiring freezes, layoffs,and voluntary and involuntary separations. Oilindustry employment is down by about 25 per-cent from 1980 levels according to early 1986 esti-
mates. personnel cuts have meant one-timecharges against earnings for severance benefitsat many companies, but may mean lower costsin the future. Of course, the risk inherent in theloss of so many experienced people is that theywill not return to the industry if oil prices and ex-ploration activity rebound.
Financial Strategies
Pressures from large investors and a generalshift in corporate management philosophy havegiven greater emphasis to “enhancing share-holder values” in addition to the bottom lineprofit or loss as a measure of financial perform-ance. Restructuring activities have included strat-egies to alter a corporation’s capital structure andto improve key indicators of financial perform-ance (e.g., earnings per share, assets per share,return on assets, return on equity). These strate-gies include buying-back shares, increasing or de-creasing long-term debt, major asset sales,spinoffs, and writedowns. Companies have some-times increased or maintained dividends to in-crease shareholder returns even when it was nec-essary to borrow money to do so.
Share Buybacks.–Some companies haveelected to make strategic investments to reducethe number of their outstanding shares throughshare buyback programs to boost indicators such
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as assets per share, cash flow per share, and earn-ings per share. Share buy backs are also seen asa means of increasing the return to shareholders,but the cash benefits only accrue to those dis-posing of their shares. Before the 1986 tax lawchanges, share repurchase programs were gen-erally preferable for tax reasons to increasing divi-dends because of the capital gains treatment onany increase in share value. The 1986 tax lawchanges and sharply restricted cash flows prob-ably have reduced or eliminated most currentbuyback programs, but should financial condi-tions improve, such programs will again competewith exploration as an alternative use of discre-tionary cash flow.
It has been widely thought that the announce-ment of a buyback program also benefits thosewho retain shares, because share prices gener-ally go up following such an announcement.However, the long-term effect of this share priceboost is less clear; there is no evidence showingthat stocks of companies participating in buybackprograms outperform industry averages.
Share repurchases by oil companies are partof a broader trend in the economy, the replace-ment of equity with debt. Total equity retirementfrom mergers, buy backs, and leveraged buyoutsexceeded new equity offerings of nonfinancialcorporations by almost $160 billion in 1984-85and by $35 billion during the first half of 1986.53
Oil company buy backs have been financed outof internally generated funds, and in some in-stances through new long-term debt. Many of thebuyback programs were directed at open mar-ket purchases, but some were undertaken toeliminate certain classes of preferred stock, or toacquire the shares held by hostile tender offerors.Phillips petroleum and Unocal went heavily intodebt to buy back their own shares to thwarttakeover bids.
As shown in table 43, share repurchases ab-sorbed billions of dollars in oil company fundsin recent years. To a certain extent, share buy-
‘]’’Surging Business Debt May Not Be a Cause for Alarm, ” Busl.ness Week, Nov. 10, 1986, p 28.
Table 43.—Share Repurchase Programs of Selected Oil Companies
AmountCompany Year (mil l ions) Remarks
Phillips Petroleum Co. . . . . . . . . . . . . 1985
Texaco, Inc. . . . . . . . . . . . . . . . . . . . . . 19841983
ARCO . . . . . . . . . . . . . . . . . . . . . . . . . . 19851984
Exxon, Corp. . . . . . . . . . . . . . . . . . . . . . 198519841983
Sun Co., Inc.. . . . . . . . . . . . . . . . . . . . . 198519841983
Standard Oil Co. . . . . . . . . . . . . . . . . . 19861985
1983-84Mobil Oil Corp. . . . . . . . . . . . . . . . . ..1982-83Amoco Corp. . . . . . . . . . . . . . . . . . . . . 1985
1984Mitchell Energy & Dev., Inc. . . . . . . . 1986Louisiana Land & Exploration Co. . . 1986
198519841983
Shell Oil Co. . . . . . . . . . . . . . . . . . . . . . 1984
$4,972
$1,28274
3,489781
$2,6872,631
762221203
$100561
70482806
1,1913.7
16.4
10.811.6
212.8$5,900
Exchange offer of debt securities of $4.5 billion for 72.58 mil-lion shares of common stock in 1985
Purchase of common stock
Bought back 28°/0 of outstanding common stock before sus-pending program in January 1986 because of lower oil prices
54 million shares164 million shares21 million sharesPurchase of common stock for treasury
Authorized for share purchaseIncludes $523 million for 11 million shares repurchased in Aug.
1984 tender offerOpen market purchase of 1.5 million shares.Repurchase of shares for treasuryNet increase in treasury shares
Purchase of 218,400 sharesRepurchase of 604,700 shares before suspending authorized
repurchase of 2 million shares in 1985-86Purchase of 10.7 million shares 1983-85
Parent company Royal Dutch Shell purchased remaining 31 0/0 ofpublicly held shares.
SOURCE: Office of Technology Assessment, based on company annual and quarterly reports 1984-87
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backs raise the same concerns as mergers andacquisitions because substantial funds that couldhave been used for oil exploration were returnedto shareholders. In the companies analyzed byOTA, share buy backs generally increased as aportion of discretionary cash expenditures rela-tive to investment in E&P in recent years. In 1985,among large oil companies i n the OTA group notinvolved in takeovers, share repurchase programsabsorbed 23 percent of internal cash flow anddomestic E&P spending 53 percent.
Changes in Debt Levels.–The oil industry hadbeen historically cautious in using debt financ-ing before the late 1970s, with the majors gen-erally carrying lower debt loads than the inde-pendents. Many companies increased their debtlevels in the early 1980s because debt financingwas seen as more cost effective than equityfinancing to raise capital for expanded explora-tion activities. Also, interest payments, unlike divi-dends, are tax deductible, and an increase indebt, unlike an increase in shares, doesn’t diluteshareholder values.
The oil industry has not been alone in increas-ing debt; all U.S. industries carried substantiallyhigher long-term debt in 1986 than they did in1980. Business Week estimates that the debt toequity ratio of the Nation’s nonfinancial corpo-rations soared from 35 percent in 1980 to an alltime high of 47 percent in mid-1986.54 Some WallStreet analysts view a rise in oil company debtand a corresponding decrease in equity as ben-eficial. They believe that U.S. oil companies are“overcapitalized” and thus, “too quick to makeinvestments that might not have been very care-fully worked out.”55 Greater reliance on exter-nal debt financing might, in their view, assure thatexploration funds were invested in potentiallymore profitable areas and only after a rigorousreview. Equity capital should not continue to beinvested in oil and gas projects with below aver-age returns, they reason, but rather should bereturned to shareholders who might put it to
541 bld55see ‘‘ Restructu r! ng Shifts FO C U S of (3I I I n d u s t r y , ~ ; / and Gas
/ourna/, No\. 18, 1985, pp. 87-92, cltlng Kurt Wulft’ of Donaldson,Luttkln, & jenrette Securltles Corp., p. 90.
more profitable use. Reducing equity capital isone reason for the trend in share repurchases dis-cussed above.
Increased leverage has also been seen as ameans to repel hostile takeovers. An SEC studyof recent U.S. corporate takeovers found thatcompanies that successfully fended off hostiletakeovers tended to have higher debt loads thancompanies that were acquired.56
As noted previously, after initially increasingdebt, many merged oil companies are now pay-ing down or refinancing long-term debt to im-prove their leverage position. Chevron, Texaco,and Mobil have made significant progress in re-ducing the massive debt loads incurred in acqui-sitions of other companies, redirecting availablecash flow to pay debt by slashing capital expend-itures, cutting overhead, and selling assets.
Reducing the Asset Base.—Many companieshave adopted strategies to downsize or reducethe asset base of the company, There are vari-ous sound business reasons for making a com-pany smaller—to concentrate on core businesses,to remove subsidiaries that might create largelosses in order to make the balance sheet strongerand to increase the percent return on assets. Theasset shrinkage has been accomplished througha combination of spinoffs, sales, abandonments,and writedowns. Writedowns, reductions in thevalue of the assets carried on corporate books,were often taken to reflect price-related changesin the values of reserves and other assets, suchas drilling rigs.57 Asset sales bring cash directlyto the company, while tax writeoffs yield someoffsetting tax benefits.
In a move to improve other indicators of finan-cial performance, some oil companies haveresorted to spinoffs of unprofitable mining ordrilling contractor subsidiaries to remove their im-
IGsee John pound, Kenneth Lehn, and Gregg Jarrell, ‘‘Are
Takeovers Hostile to Economic Performance?” Regu/at/on, Septem-ber/October 1986, pp. 25-30, 55-56.
~TSome ~tritedolin~ are largely \olunta ry decisions, but others
are mandatory. SEC accounting ru Ies for companies using the fullcost accounting method, mostly Independent oil companies, re-quire writedowns in the value of 011 and gas reserves to reflect lowerprtces.
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pacts on earnings. Other spinoffs involved thenonenergy businesses that oil companies boughtduring the 1970s diversification trend. Whenthese subsidiaries are “spun off” or sold, the as-sets of the parent company are adjusted down-ward by an amount reflecting the value assignedto the newly separated entity. Interests in thenewly independent entities are distributed toshareholders and then can be separately traded,creating additional opportunities to realize valueon corporate assets. Examples of this trend in-clude: Amoco’s spinoff of Cyprus Mining; Arco’ssale or liquidation of most nonenergy activitiesof its Anaconda Minerals subsidiary; and NobleAffiliates’ spinoff of its drilling services subsidiary.
Oil and gas writedowns have generally beenof very high cost reserves in remote frontier areas,e.g., Arco’s writeoff of North Slope gas reserves.Other writedowns reflect discontinued operationsor anticipated losses on asset divestitures, suchas Mobil’s writedowns in preparation for itsplanned divestiture of Montgomery Ward Depart-ment Stores.
Looking for New Internal Sources of Funds.–As companies look internally for new ways togenerate cash flow, some have turned to em-ployee pension funds as a potential source offunds. Exxon and Phillips have announced plansto tap overfunded employee pension plans byclosing out the existing plans, purchasing annui-ties for participants and taking the excess funds,and starting a new employee pension plan. (Theplans have “excess” funds over their anticipatedliabilities because their investments have per-formed well.) Exxon anticipates that it will recap-ture about $1 billion from its employee pensionfund, an amount equal to roughly one-third ofits domestic E&P spending in 1986. This optionmay appear attractive to other large companies.
Creation of New Financial lnstruments/lnvest-ment Arrangements. —The 1980s saw the crea-tion and the expanded use of new financial in-struments and investment vehicles, such as royaltytrusts and master limited partnerships (MLPs), asways to attract investment dollars and returnvalue to shareholders. These arrangementsoffered several advantages over traditional stockownership and previous investment devices. For
example, MLPs pay no corporate income tax andthus pass through income to the partners or “unitholders” along with a share of partnership deduc-tions that can be applied on the partners’ per-sonal income tax returns. (As discussed below,the 1986 tax law changes have limited some taxaspects of oil and gas MLPs.) The MLPs androyalty trust units also can be freely traded onstock exchanges and are thus more liquid thanprevious vehicles.
MLPs have also become an attractive mecha-nism for both small and large oil companies toreturn value to shareholders in response to pres-sures from aggressive investors or takeoverthreats. Some companies transferred many oftheir producing oil and gas properties to MLPsand royalty trusts and distributed interests toshareholders. The interests in the partnershipsand trusts can be separately traded, perhaps re-sulting in a greater return to investors, while theparent company retains a managing interest andcontrol over the properties. Some companieshave also offered shares in the partnerships androyalty trusts to the public to raise explorationfunds as an alternative to issuance of new com-mon stock or long-term debt. (Some examplesinclude Mesa Petroleum’s Mesa Energy Partners,Sun Co. ’s Sun Energy Partners, and TranscoEnergy’s Transco Exploration Partners.)
Royalty trusts were a popular vehicle for inde-pendents to attract funds from outside investorsfor development drilling. But the creation ofroyalty trusts by converting existing corporate oiloperations drew much criticism because theywere seen essentially as a liquidation of a com-pany’s reserves position. Royalty trusts were saidto reduce the availability of internally generatedcash flow for exploration because income fromthe producing reserves in the trust and relatedcorporate tax incentives were transferred to in-vestors, who might not reinvest them in the oilindustry.58
These vehicles drew billions to petroleum in-vestments, but their future attractiveness isclouded by uncertainty over tax treatment of the
5eSee, for example, testimony of John H. Lichtblau, President,
Petroleum Industry Research Foundation, Inc., in Legls/a[mn Attect-ing Oi/ Merger Proposa/s, wpra note 1, at 374.
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investment, the currently poor oil price outlook,and the prospect of lower overall tax rates. Al-though the tax bill maintained some of the taxadvantages of oil and gas investments, there isconcern that with lower tax rates, high-incomeinvestors will be less likely to invest in risky oiland gas ventures without a significant riskpremium.
The 1986 tax law changes preserved many ofthe tax benefits for oil and gas exploration thatcan still be passed through to the unitholders.They did, however, limit the deductibility of “pas-sive” losses from the partnerships, which couldfurther diminish their attractiveness. Such passivelosses can only be charged against similar pas-sive income and cannot be used to shelter otherincome unless the partner shares in the risk ofthe venture at a level in excess of the investment.To continue the tax shelter aspect of oil and gasinvestments, investors must share liability ex-posure. Some industry tax experts have suggestedthat new investment packages will be created toovercome the passive loss restriction—perhapsa combination of a partnership interest and aninsurance policy to cover losses in excess of theparticipation.
Effects of Restructur ing
The long-term effectiveness of these restructur-ing efforts wiII not be known for several moreyears. Many cost-cutting moves will not provideimmediate actual savings, and the sudden pricedrop and slide in revenues this year appears to
have caught many companies by surprise. Inaddition, because major restructuring is unlikelyto have been undertaken at random—each kindof restructuring was more likely to be undertakenby those companies most in need of the poten-tial benefits it offered, or most vulnerable to itif the restructuring was imposed—the results ofindustrywide surveys of financial performancewill be ambiguous about the “success” of res-tructuring. For example, many companies ab-sorbed by hostile takeovers were vulnerable tosuch takeovers because of financial weakness;these companies may have been expected to un-dergo significant budget cutting with or withoutmergers, perhaps at levels greater than industrynorms. Thus, post-merger statistics showing re-duced investment levels beyond industry aver-ages must be interpreted carefuIly to separate theeffects of the takeover from other market effects.
Nevertheless, it is quite telling that extensiveassurances about the positive effects of mergerswere given to Congress in hearings held to ex-plore the effects of the wave of mergers on theindustry, and the more easily measured of thesepositive effects (increased E&D activity) haveclearly not materialized. It seems clear that theshort-term effects of mergers on E&D spending,and probably on R&D as well, have been nega-tive. The short-term effects of mergers on less eas-ily measured characteristics, such as the “effi-ciency” of E&D activity, and the effects of otherrestructuring activities have not been carefullymeasured.
Chapter 7
Production Loss From Reduced Drilling
All oil wells experience a declining productionrate as reservoir pressures decline and as the oilclosest to the wellbore is produced. Althoughdifferent geologic conditions, production strate-gies, and oil characteristics yield different declinerates, in all cases production in a field can onlybe maintained by proceeding with secondary andtertiary recovery and by drilling additional pro-ducing wells. And as production rates in somefields inevitably decline, discovery wells must findnew fields to exploit if national production is tobe maintained.
As noted above, one source of lost domesticoil production resulting from low oil prices is theearly abandonment of stripper wells and othermarginal wells. Additional production will be lostas existing wells continue their natural declinesand too few additional wells are drilled to com-pensate for these declines. As discussed earlier,declines may be expected in all aspects of drilling,from shallow, low-cost development wells to themost expensive offshore and arctic wells on thefrontier. The reduced level of development drill-ing will affect production the soonest, becausesome of these wells can often be producingweeks or a few months after they are “spudded”(drilling has begun). At the opposite end of thespectrum, exploration wells in frontier areas mayprecede production by a decade or more as in-frastructure is built and, in some deep offshorecases, as new production technology is designedand tested.
In order to evaluate accurately the effect of lowoil prices on drilling and, eventually, on produc-tion, it is necessary to understand how the oilprice change and other factors associated withit will change the level of drilling activity, the dis-tribution of drilling (geographically, by the natureof the target, etc.), and the likely success of thedrilling in adding to reserves and production. InOTA’s view, there are strong uncertainties withall of these factors.
The Level of Drilling Activity
From 1981 to 1985, oil drilling rates remainedvery high despite declining prices and a declinein the number of operating drilling rigs (from3,970 rotary rigs in 1981 to 1,980 in 19851); dur-ing these years, the number of oil well comple-tions ranged between 37,000 and 43,000 wellsper year, with 1984 being the peak year.2 Appor-tioning dry holes between oil and gas accordingto the ratio of oil to gas completions, the totalwells drilled “for oil, ” successful and dry, rangedbetween 55,000 and 60,000 thousand wells peryear.
The rig count hovered around 700 for muchof 1986, and, around mid-year, analysts expectedthe industry to drill somewhat over 30,000 “oilwells” (successful and dry)3 during that year. As-suming that prices remain low, it is by no meansclear whether drilling activity in 1987 and afterwill rise, fall, or remain at the same general level.Some of the 1986 activity is a short-term continu-ation of activity planned and begun before theprice drop, with much of the capital investmentsunk. For some of these projects, there will beno replacement upon their conclusion. Some ad-ditional projects will be continued because theyare necessary to hold leases or fulfill contractualobligations, and these too may have no replace-ments. Finally, some industry analysts argue thatthe list of viable drilling prospects at 1986 oilprices is a very limited one, so that a continua-tion of those low prices for any length of timewould exhaust the industry’s inventory of drilla-ble prospects and force down the drilling rate.
T Independent Petroleum Association of America, ‘‘U n Ited StatesPetroleum Statistics, 1986. ”
‘Ibid.lln industry usage, an oil well is a Successful ly CO Mp[eted 011-
producing well, In fhjs secljon, 07A added a proportional num-ber of dry holes–unsuccessful wells that are abandoned–to thenumber ot completed wells, and thus our terminology will not cor-
respond to the s tandard usage.
125
126
On the other hand, there are many independ-ent drillers who claim that they have access todrilling prospects that are economic, but cannotdrill because of a lack of capital. Although capi-tal availability has seemingly evaporated from theoil market, it seems unlikely that this will con-tinue for long if there are reasonable prospectsfor profitable investments. As discussed in chap-ter S, there are substantial disagreements aboutthe number of economic prospects still availableto the industry.
The Distribution of Drilling Targets,and the Likely Success at Adding
Reserves and Production
As discussed in chapter 6, “The Efficiency ofE&D Activities,” reductions in exploration and de-velopment activity because of the price drop willnot be uniform, since changing economics affectsdifferent regions, geologic targets, and activitytypes differently. For example, most of OTA’s in-dustry contacts expect drilling activity to focuson low risk prospects, with shallow developmentactivity to sustain only a moderate decline andhigh-risk exploratory and deep drilling activity tosuffer a substantial decline. A sign that this is be-ginning to happen is the downward shift in aver-age depth of new wells; for the first 8 months of1986, the average well depth was 4,153 v. 4,440feet for 1985.4 This shift in activity probably wouldtend to increase well success rates but decreasethe reserves found per well drilled. On the otherhand, some geographic shifts will tend to favorthose areas that traditionally have paid off morehandsomely in terms of reserves added per well.Table 44, which shows the 1980-1984 averagereserves per oil well driIled for the nine regionsin the United States, amply illustrates why a re-gional shift in drilling can greatly affect overalldrilling results in terms of reserve additions.
Projections of regional drilling rates for 1986made in JuIy of that year by the Oil and Gas Jour-nal,5 a respected industry publication, indicate
dEnergy Information Administration, Short-Term Energy Out/ook
Quarter/y Projections, &t. 1986, DOE/EIA-0202(86/4Q), NOV. 1%6.
5j.C. McCaslin, “U.S. Drilling to Fall 47 percent This Year, ” Oi/and Gas Journal, July 28, 1986.
Table 44.-Reserve Additions Per Oil Well Drilled,1980-1984 Average (barrels par well)
Reserves added per oil wellRegion (including dry holes)
Alaska . . . . . . . . . . . . . . . . . . . .California . . . . . . . . . . . . . . . . . .Rocky Mountains and
northern Great Plains . . . . .West Texas and eastern
New Mexico . . . . . . . . . . . . .Gulf Coast . . . . . . . . . . . . . . . . .Midcontinent . . . . . . . . . . . . . . .Eastern interior. . . . . . . . . . . . .Michigan basin . . . . . . . . . . . . .Appalachian. . . . . . . . . . . . . . . .National average. . . . . . . . . . . .
2,524,000177,000
7 8 , 0 0 0
49,00071,00014,0005,000
62,0006,000
50.000SOURCE: J.P. Riva, Jr., “Domestic Oil Production and Reserves Projected to 2000
on the Basis of Regional Drilling and Per Well Reserve Additions, ” Con-gressional Research Service, 1986.
that drilling will tend to favor regions with highhistoric rates of reserve additions per well, thoughnot uniformly. For example, 1986 drilling in Alaskais expected to be higher than normal, about 265wells drilled compared to an average of 150 wellsdrilled per year during 1980-84. California drillingalso is expected to be high, about 2,460 wells,only slightly lower than recent levels. (However,in both these States, much of this drilling requireslengthy planning and considerable advance cap-ital investment, and thus the 1986 drilling levelmay not reflect the price drop as much as activ-ity levels in other areas.) The Gulf Coast, another“high reserves per well” area, also holds up wellat about 6,700 wells, one-third under recent aver-age levels. On the other hand, activity in theRocky Mountains and Northern Great Plains(2,1 50 wells) and Michigan Basin (380 wells), thetwo other “high reserves per well” areas, is pro-jected to decline at about the national rate.
The implication of this nonuniformity in the re-duction of drilling activity is that 1986 oil reserveadditions are not likely to be as low as might beexpected from the percentage fall in the nationaldrilling rate. Had the reduction been uniform andhad the overall rate of reserve additions per wellremained at recent levels, the expected 1986 re-serve additions would have been 1.6 billion bar-rels. Applying the historic per well reserve ratesto the regional drilling breakdown gives expected1986 reserve additions of about 2.2 billion bar-rels, a value only slightly below the average for
1 2 7
the 1980s. Note, however, that the latter valueis not the “correct” value either, because:
● wide year-to-year swings in regional findingrates virtually guarantee that any individualyear’s average will vary considerably fromthe historic rate;
● the changes in drilling patterns caused by thelower oil prices occur within regions as wellas across them, and applying the regionalfinding rates does not take intraregional shiftsinto account;
● i n some key States—California, in particuIar–past increases in reserves depend signifi-cantly on enhanced oil recovery (EOR) inaddition to exploratory and developmentdrilling, and using such simple measures as‘‘reserves per well” cannot capture the ef-fects of drastic changes in the attractivenessof EOR investments; b and/or
● the drilling mix is said to be shifting towardsdevelopment drilling and away from explora-tory drilling; such a change in the drilling mixwould tend to lower overall finding rates.
Projecting Oil Reserve Additions andProduction Based on ExtrapolatingRegional Drilling Patterns and Per
Well Reserve Additions
Joseph Riva of the Science Policy Research Di-vision, Congressional Research Service has pro-jected regional and U.S. oil reserve additions andproduction to the year 2000
7 by using the aver-age reserve additions achieved per oil well drilledfor each of nine regions during the 5-year period1980-84, as discussed above, and assuming thatprojected low rates of drilling for 19868 will con-tinue indefinitely. As noted previously, an “equi-librium” in drilling has by no means been reached,and thus an assumption of constant drilling ineach region is clearly a risky one . . . as is the as-
bAlt hough most E(>R projects req u I re d ri I II ng for I njectlon andotlen for prod uctlon.
“j, P. Rlva, jr,, “Domestic (II Production and Reser\es Projectedto 2000 cm the Bdsls O( Reglona/ Drl//ing and Per w’e~~ Reserve Ad-ditions, ” Congressional Research Serv\ce, Library ot Congress, Dec.9, 1986.
8{]// and Gas Journal, j u Iy 28, 1986, op. clt.
sumption that per well reserve additions will re-main steady at the 1980 to 1984 average. Never-theless, this is a useful “What if. . .“ analysis thatcan act as a counterpoint to similar analyses thatpostulate a considerably lower rate of reserve ad-ditions based on alternative assumptions thatOTA considers overly pessimistic.
Tables 45 through 53 present the past and pro-jected production, proved reserves, and reservesto production (R/P) ratios for the nine regions. Ta-ble 54 presents similar projections for the UnitedStates.
The regional tables show extremely interestingvariations in the projected year 2000 productionrates as compared to current rates. By the year2000, Alaska and California production rates areprojected to increase by 2 and 25 percent respec-tively. This is contrary to current expectations.According to virtually all industry sources, Alaskanproduction, although it is actually somewhat higherthis year than last, is expected to begin a longdecline beginning around 1989. The source ofthe decline will be the supergiant Prudhoe Bayfield, which is expected to fall from its presentproduction rate of 0.55 billion barrels per year(1.5 million barrels per day) by more than one-half by 1995 and more than three-quarters byyear 2000.9 In this case, extrapolation of historicreserve additions and current drilling rates doesnot appear to work. Although recent develop-ment of new reservoirs at Prudhoe has been quitesuccessful, there are few such opportunities left,and the recent exploratory drilling record hasbeen disappointing: it may be that the primarypossibility for a substantial recovery, after pro-duction has begun its decline, lies with the ArcticNational Wildlife Refuge, discussed in chapter S.And were the Arctic National Wildlife Refuge tobe successfully explored and developed, produc-tion is unlikely to begin before the year 2000.
In California’s case, maintaining or increasingproduction depends on offshore developmentand exploration and on enhanced oil recovery.Between 1980 and 1985, almost half of Califor-nia’s oil reserve additions came from enhanced
9J.f’. Riva Jr., O P. cit.
128
Table 45.-Past and Projected Alaska Oil Status
Reserve additionsProduct ion Proved reserves Average oil 1 09 bbls/well
Year 1 09 bbls/yr 1 09 bbls R/Pa Total oil wells rig count Wells per rig per oil well
1970 . . . . . . . .1975 . . . . . . . .1980 . . . . . . . .1981 . . . . . . . .1982 . . . . . . . .1983 . . . . . . . .1984. . . . . . . .1985. . . . . . . .1986. . . . . . . .1990. . . . . . . .1995. . . . . . . .2000. . . . . . . .
0.0830.0700.5910.5920.6270.6650.6380.6670.670.670.680.68
10.14910.0378.7518.2837.4067.3077.5637.0567.0607.0607.0507.050
122/1143/1
15/114/112/111/112/111/111/111/110/110/1
7261
122159201159157
20245 est.
1313142221141420
5.54.78.77.29.6
11.411.2
1.0
0.1361110.0002130.0038280.000780
–0.001244 b
0.0035600.0056940.008000
aproved resemes/annual production.bNegativevalue5 for reserve additions perwe~ o~cur~hen Iarge negative revisions are recorded for the region during the reference year
SOURCE: J.P. Riva, Jr., “Domestic Oil Production and Reserves Projected to 2000 on the Basis of Regional Drilling and Per Well Reserve Additions, ” CongresslonaiResearch Service, 1986.
Table 46.— Past and Projected California Oil Status
ProductionYear 1 09 bbls/yr
1970 . . . . . . . .1975 . . . . . . . .1980 . . . . . . . .1981 . . . . . . . .1982 . . . . . . . .1983 . . . . . . . .1984 . . . . . . . .1985 . . . . . . . .1986 . . . . . . . .1990 . . . . . . . .1995 . . . . . . . .2000 . . . . . . . .
0.3720.3220.3600,3830.3940,4000.4150.4170.420.440.480.52
Proved reserves1 09 bbls
3.9843.6485.4705.4415.4055.3485.7075.8015.8205.8305.7005.360
R/Pa
11/111/11 5/114/114/11 3/11 4/114/114/113/11 2/110/1
Total oil wells
1,9702,1842,4163,0112,4642,2423,2592,9592,460 est.
Average oilrig count
5078
116152125103104
81
Reserve additions1 09 bbls/well
Wells per rig per oil well
39.4 0.00005728.0 0.00018920.8 0.00023419.8 0.00011819.7 0.00014521.7 0.00015331.3 0.00023736.5 0.000173
aproved resewes/annual production.
SOURCE: J.P. Riva, Jr., “Domestic Oil Production and Reserves Projected to 2000 on the Basis of Regional Drilling and Per Well Reserve Additions,” CongressionalResearch Service, 1986.
Table 47.—Past and Projected Rocky Mountains and Northern Great Plains Oil Status
Reserve additionsProduction Proved reserves Average oil 1 09 bbls/well
Year 1 09 bbls/yr 1 09 bbls RIPa Total oil wells rig count Wells per rig per oil well
1970 . . . . . . . . 0.281 2.086 7/1 2,645 125 21.2 0.0000701975 . . . . . . . . 0.259 1.849 7/1 2,835 177 16.0 0.0000461980 . . . . . . . . 0.258 1.777 7/1 3,478 283 12.3 0.0001221981 . . . . . . . . 0.257 1.660 6/1 5,501 432 12.7 0.0000251982 . . . . . . . . 0.249 1.709 7/1 4,135 355 11.6 0.0000721983 . . . . . . . . 0.252 1.900 8/1 3,693 209 17.7 0.0001201984 . . . . . . . . 0.254 1.889 7/1 4,555 267 17.1 0.0000531985 . . . . . . . . 0.255 2.014 8/1 3,211 212 15.1 0.0001161986 . . . . . . . . 0.25 1.930 8/1 2,154 est.1990 . . . . . . . . 0.23 1.640 7/11995 . . . . . . . . 0.20 1.430 7/12000 . . . . . . . . 0.18 1.320 7/1aproved re.servesjmnual production.SOURCE: J.P Riva, Jr., “Domestic Oil Production and Reserves Projected to 2000 on the Basis of Regional Drilling and Per Well Reserve Additions,” Congressional
Research Service, 1986.
129
Table 48.—Past and Projected West Texas and Eastern New Mexico Oil Status
Reserve additionsProduct ion Proved reserves Average oil 1 09 bbls/well
Year 1 09 bbls/yr 109 bbls R/Pa Total oil wells rig count Wells per rig per oil well
1970 . . . . . . . . 0.792 7.876 10/1 4 , 5 4 2 1 8 7 2 4 . 3 0 . 0 0 0 2 4 51975 . . . . . . . .1980 . . . . . . . .1981 . . . . . . . .1982 . . . . . . . .1983. . . . . . . .1984. . . . . . . .1985. . . . . . . .1986. . . . . . . .1990. . . . . . . .1995. . . . . . . .2000. . . . . . . .
0.8090.6700.6450.6250.6200.6080.6200.620.590.530.48
6.4966.2406.2725.9775.9236.0526.4546.215.324.453.85
8/19/1
10/110/110/110/110/11o11
9/18/18/1
6,933 276 25.1 0.0000359,948 379 26.2 0.000070
13,112 520 25.2 0.00005212,768 337 37.9 0.00002612,563 357 35.2 0.00004514,490 394 36.8 0.00005112,946 457 28.3 0.0000797,703 est.
aproved resewe5/annual ProductIon
SOURCE J.P. Riva, Jr, “Domestic Oil Production and Reserves Projected to 2000 on the Basis of Regional Drilling and Per Well Reserve Additins,” CongressionalResearch Service. 198
Table 49.— Past ad Projected Gulf Coast Oil Status
Reserve additionsProduction Proved reserves Average oil 1 09 bb l s /we l l
Year 1 09bbls/yr 109 bbls R/Pa Total oil wells rig count Wells per rig per oil well
1970. . . . . . . . 1.381 12.174 9/1 4,923 296 16.6 0.0002311975. . . . . . . . 1.118 8.470 8/1 4,613 303 15.2 0.0000551980. . . . . . . . 0.812 5.643 7/1 7,370 584 12.6 0.0001001981 . . . . . . . . 0.774 5.707 7/1 10,036 831 12.1 0.0000831982. . . . . . . . 0.755 5.273 7/1 8,891 514 17.3 0.0000361983. . . . . . . . 0.773 5,214 7/1 9,989 509 19.6 0.0000721984. . . . . . . . 0.803 5.148 6/1 11,957 561 21.3 0.0000621985. . . . . . . . 0.786 5,012 6/1 9,987 410 24.4 0.0000651986. . . . . . . . 0.78 4.71 6/1 6,727 est.1990. . . . . . . . 0.65 3.75 6/11995. . . . . . . . 0.55 3.24 6/12000. . . . . . . . 0.51 3.03 6/1aproved reswveslannual ProductIonSOURCE: J.P. Riva, Jr. “Domestic Oil Production and Reserves Projected to 2000 on the Basis of Regional Drilling and Per Well Reserve Additions," Congressional
Research Service, 1986.
Table 50.—Past and Projected Midcontinent Oil Status
Reserve additionsProduction Proved reserves Average oil 1 09 bbls/well
Year 109 bbls/yr 1 09 bbls R/Pa Total oil wells rig count Wells per rig per oil well
1970. . . . . . . . 0.324 2.108 7/1 4,560 118 38.6 0.0000531975. . . . . . . . 0,231 1.759 8/1 5,512 197 28.0 0.0000351980. . . . . . . . 0.200 1.329 7/1 12,852 418 30.7 0.0000031981 . . . . . . . . 0.218 1.428 7/1 17,695 748 23.7 0.0000181982. . . . . . . . 0.224 1.493 7/1 15,617 626 24.9 0.0000161983. . . . . . . . 0.221 1.380 6/1 14,195 396 35.8 0.0000101984. . . . . . . . 0.233 1.425 6/1 13,331 388 34.4 0.0000211985. . . . . . . . 0.223 1.503 7/1 9,616 290 33.2 0.0000311986. . . . . . . . 0.22 1.37 6/1 6,637 est.1990. . . . . . . . 0.16 .98 7/11995. . . . . . . . 0.12 .79 7/12000. . . . . . . . 0.10 .71 7/1aproved reserves/annual production
SOURCEJP Riva, Jr. “Domestic Oti Production and Resemes Projected to20000n the Baslsof Regional Drilling and Per Well Reserve Additions,” CongressionalResearch Service, 1!3S6
130
Table 51 .—Past and Projected Eastern Interior Oil Status
Reserve additionsProduction Proved reserves Average oil 1 09 bbls/well
Year 109 bbls/yr 1 09 bbls R/Pa Total oil wells rig count Wells per rig per oil well
1970 . . . . . . . . 0.063 0.327 5/1 1,617 15 108 0.0000031975 . . . . . . . . 0.038 0.224 6/1 2,159 18 120 0.0000191980 . . . . . . . . 0.027 0.171 6/1 4,859 27 180 –0.000001 b
1981 . . . . . . . . 0.027 0.181 7/1 6,802 45 151 0.0000051982. . . . . . . . 0.030 0.214 7/1 7,321 84 87 0.0000091983. . . . . . . . 0.030 0.204 7/1 7,591 67 113 0.0000031984. . . . . . . . 0.032 0.227 7/1 6,458 49 131 0.0000091985. . . . . . . . 0.034 0.218 6/1 4,263 33 129 0.0000061986. . . . . . . . 0.03 0.21 7/1 3,423 est.1990. . . . . . . . 0.03 0.17 6/11995. . . . . . . . 0.02 0.14 7/12000. . . . . . . . 0.02 0.14 7/1aproved rese~eslmrlual production.bNegatlve valu es for re~erve additions per Well o~~ur~hen large negative revisions are recorded forttle region during the reference year
SOURCE:J.P Riva, J r , “Domestic Oil Production and Reserves Projected to 2000 on the Basis of Regional Drilling and Per Well Resewe Addltlons,” CongressionalResearch Service, 1986
Table 52.—Past and Projected Michigan Basin Oil Status
Reserve additionsProduction Proved reserves Average oil 109 bbls/well
Year 109 bbls/yr 1 09 bbls R/Pa Total oil wells rig count Wells per rig per oil well1970 . . . . . . . . 0.012 0.046 4/1 201 8 25 0.0000301975 . . . . . . . . 0.024 0.093 4/1 439 23 19 0.0000801980 . . . . . . . . 0.037 0.205 6/1 530 25 21 0.0001571981 . . . . . . . . 0.034 0.240 7/1 650 31 21 0.0001061982 . . . . . . . . 0.029 0.184 6/1 773 27 29 – 0.000035b
1983 . . . . . . . . 0.031 0.209 7/1 671 26 26 0.0000831984 . . . . . . . . 0.027 0.180 7/1 902 28 32 –0.000002 b
1985 . . . . . . . . 0.030 0.191 6/1 638 28 23 0.0000641986 . . . . . . . . 0.03 0.18 6/1 382 est.1990 . . . . . . . . 0.03 0.14 5/11995 . . . . . . . . 0.02 0.14 7/12000 . . . . . . . . 0.02 0.14 7/1aproved reserveslanrlual production.bNegative values for resewe additions per well occur when large negative revisions are recorded for the re9i0n during the reference Year
SOURCE J.P Riva, Jr., “Domestic Oil Production and Reserves Projected to 2000 on the Basis of Regional Drilling and Per Well Resewe Additions,” CongressionalResearch Serwce, 19S6
Table 53.—Past and Projected Appalachians Region Oil Status
Reserve additionsProduction Proved reserves Average oil 1 09 bbls/well
Year 109 bbls/yr 1 09 bbls R/Pa Total oil wells rig count Wells per rig per oil well1970 0.018 0.243 14/1 1,323 20 66 0.0000101975 0.017 0.210 12/1 1,550 17 91 0.0000061980 0.016 0.181 1 1/1 4,336 55 79 0.0000081981 0.015 0.174 12/1 4,928 71 69 0.0000021982 0.019 0.196 10/1 3,490 45 78 0.0000121983 0.024 0.228 10/1 2,926 31 94 0.0000161984 0.025 0.232 9/1 3,217 38 85 0.0000121985 0.020 0.167 8/1 3,052 43 71 –0.000015 b
1986 0.02 0.16 8/1 2,483 est.1990 0.02 0.12 6/11995 0.01 0.08 8/12000 0.01 0.08 8/1aproved resemeslannual Production.bNegative values for resewe additions per well occur when large negative revisions are recorded for the region during the reference Year
SOURCE’ J.P. Rlva, Jr., “Domestic Oil Production and Resewes Projected to 2000 on the Basis of Regional Drilling and Per Well Reserve Additions,” CongressionalResearch Service, 1966.
131
recovery operations in the large heavy oilfieldsof the San Joaquin basin, and an additional thirdcame from large oiIfields discovered offshore.10
Further activity in the offshore may be restrictedby California’s environmental aversion to offshoredrilling. Further development of EOR operationsmay require higher prices than today’s, and thereare air quality restrictions as well; however, therather basic techniques used in many of the Cali-fornia fields are not at the high end of the costspectrum for EOR,11 and price might not be asmuch of a constraint here as it would be else-where. An important source of uncertainty is thepotential for technological improvements thatcould reduce production costs. In conclusion, ful-filling the projection for California production willrequire success in two difficult areas—not impos-sible, but surely requiring considerable goodfortune.
Year 2000 production rates in all other regionsare projected to decline from 1985 rates, asfollows:
Rocky Mountains and northern Great Plains ..–29%West Texas and eastern New Mexico . . . . . . –23%Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . –35%Midcontinent . . . . . . . . . . . . . . . . . . . . . . . . . . –55%Eastern interior . . . . . . . . . . . . . . . . . . . . . . –41%
Michigan basin. ., . . . . . . . . . . . . . . . . . . . . . . –33%Appalachian region . . . . . . . . . . . . . . . . – 50%
‘O! txd .I I personal Corn m u n Icatlon, joseph Rwa, Congressional Research
Ser\lce,
These very substantial projected declines dem-onstrate the fragility of domestic oil production,especially given the uncertainty associated withour ability to maintain production levels in Alaskaand California.
Table 54 shows that the projected decline intotal U.S. production associated with the dropin drilling activity is 17 percent by the year 2000.This is a modest decline when compared to theprojected declines discussed in chapter 2. How-ever, this projection does not account for the pos-sibility that large numbers of existing wells maybe abandoned as uneconomic, as discussed inthe previous section. Although there appear tobe problems with the analysis of stripper wellabandonments conducted by the interstate oilCompact Commission (IOCC), it is worthwhileto incorporate their projections into the drillingprojections above. Table 55 illustrates how futureproduction might change if the IOCC’s projectedproduction losses at oil prices of $15/bbl wereto occur. The primary effect would be to increasethe expected year 2000 production loss from 17to 22 percent.
Furthermore, a less optimistic–and manywould say more realistic—projection of Alaskanand Californian production would substantiallyaffect the national estimate. For example, assum-ing that only about half the Prudhoe decline canbe replaced with production from other fields (as
Table 54.—Past and Projected United States Oil Status
Product ion Proved reserves Average oilYear 109 bbls/yr 1 09 bbls R/Pa Total oil wells rig count Wells per rig
1970 . . . . . . . . 3.3281975 . . . . . . . . 2.9011980 . . . . . . . . 2.9751981 . . . . . . . . 2.9491982 . . . . . . . . 2.9501983 . . . . . . . . 3.0201984 . . . . . . . . 3.0371985 . . . . . . . . 3.0521986 . . . . . . . . 3.041990 . . . . . . . . 2.821995 . . . . . . . . 2.61
39.00132.68229.80529.42627.85827.73528.44628.41627.6525.0123.02
12/111/110/110/19/19/19/19/19/19/19/1
21,52226,25345,31660,94055,60052,57761,39948,48932,234 est.
8321,1021,9012,8522,1341,7121,8431,574
2624242126313331
Reserve additions1 09 bbls/wellper oil well
0.0005900.0000510.0000660.0000420.0000250.0000550.0000610.000062
2000 . . . . . . . . 2.52 21.68 9/1a pr o v ed reseffes/annual product ion
SOURCE: J.P. Riva, Jr., “Domestic Oil Production and Resetves Projected to 2000 on the Basis of Regional Drilling and Per Well Reserve Additions. ” CongressionalResearch Service, 1986.
132
Table 55.—impact of Increased Stripper WellAbandonment on Low Drilling Scenario Production
and Reserves Projections
Production Proved reservesYear (billion bbl/yr) (billion bbls)
1985 . . . . . . . . . . . 3.052 28.4161986 . . . . . . . . . . .3.04 – .10 = 2.94a 27.65 –.73 = 26.92b
1990 . . . . . . . . . . . 2.76 24.331995 . . . . . . . . . . . 2.52 22.352000 . . . . . . . . . . . 2.38 21.26aThat is, stripper production of .10 billion bbllyr iS lost.bstripper resemes Of .7s billion bbls are 10.St.SOURCE: J,P. Riva, Jr., “Domestic Oil Production and Reserves Projected to 2000
on the Basis of Regional Drilling and Per Well Rese~e Additions, ” Con.gressional Research Sedice, 19S6.
noted, a three-quarter decline in current Prud-hoe Bay production is expected by 2000), theyear 2000 production rate would be about 2.17billion barrels per year, a 29 percent decline from1985 production. An important-and sobering–note about this computation is that much ofAlaska’s expected production decline is not pricebut geology dependent. Although lower priceswill stifle some development and exploration, andsome production also will be dependent on tech-nology development, much of the production de-cline was expected at higher prices.
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