U.S. Oil Production: The Effect of Low Oil

Prices

July 1987

NTIS order #PB88-142484
Recommended Citation:

U.S. Congress, Office of Technology Assessment, U.S. Oil Production: The Effect of Low

Oil 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 Documents

U.S. Government Printing Office, Washington, DC 20402-9325

(order form can be found in the back of this report)
Foreword

This special report responds to requests by the Government Operations Committee, the Energy and Commerce Committee, and the Subcommittee on Energy and Power

of 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 assessment on Technological Risks and Opportunities for U.S. Energy Supply and Demand.

Congress’ attention became focused on U.S. domestic oil production as a result

of 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 markets

by increasing production and offering new and more attractive contract terms, throwing 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 of

1986—was to quickly force a portion of existing U.S. production out of service and

to sharply reduce drilling and other exploration and production-oriented activity, guaranteeing that U.S. production would decline still further in the future. The Department

of Energy and others have projected that the decline in production, coupled with increases in (price-sensitive) oil demand, will drive U.S. oil imports past the 50 percent

mark by the early 1990s at the latest. Congress asked OTA to provide an independent

assessment of these postulated effects.

This special report presents the results of OTA’s analyses of a group of factors we

believe will strongly influence the future direction of U.S. oil production. These factors include the expected profitability of new investments in drilling, the potential of

new oil exploration, development, and production technologies, the nature of the remaining oil resource base, and structural changes in the oil industry. The special report

also provides a brief discussion of some policy options for Congress to consider if it

decides to moderate the expected accelerated decline in U.S. oil production.

OTA is indebted to the numerous individuals who contributed substantial time to

this special report, providing information and advice and reviewing drafts. Also, the

contributions of our colleagues in the Congressional Research Service, who provided

analyses in two key areas, are gratefully acknowledged.

.

.

Director
Acknowledgments

OTA thanks the many institutions and individuals who contributed to this report by providing

information, advice, and substantive reviews of draft materials. Although we cannot name each of

these, OTA would like to list those individuals who reviewed our drafts and participated in OTA’s

two workshops:

Reviewers

M.A. Adelman

Massachusetts Institute of

Technology

Tom Barber

Michel Halbouty Energy Co.

E.J. Baumgartner

Amoco Production Co.

Dave Beecy

U.S. Department of Energy

Neil Bunis

Conoco Inc.

Michael Canes

American Petroleum Institute

Hubie Clarke

Baker International

William Deitzmann

Dallas Field Office

Energy Information

Administration

John Dewes

Chevron

S.M. Dildine

Conoco Inc.

Larry Drew

U.S. Geological Survey

Bill Finger

Exxon

Bill Fisher

Bureau of Economic Geology

University of Texas at Austin

Ed Flom

Amoco Corp.

Tom Garland

OTA contractor

Dallas, Texas

Bernard Gelb

Congressional Research Service

Michel Halbouty

Michel Halbouty Energy Co.

W.C. Hauber

Shell Oil Co.

Bobby Hickman

Mitchell Energy Corp.

Robert Hill

Chevron

H.R. Hirsch

Conquest Exploration Co.

Robert Hirsch

ARCO Oil & Gas Co.

Bill Hochheiser

U.S. Department of Energy

Robert Kalisch

American Gas Association

Ike Kerridge

Hughes Tool Co.

Vello Kuuskraa

Lewin & Associates

John Lichtblau

Petroleum Industry Research

Foundation

Charles Mankin

Oklahoma State Geologist

Chuck Masters

U.S. Geological Survey

Vince Matthews

Champlin Petroleum Co.

W.H. McMillian

ARCO Oil & Gas Co.

Richard O’Neill

Federal Energy Regulatory

Commission

Joe Riva

Congressional Research Service

Dick Rowberg

Congressional Research Service

Jack Schanz

Congressional Research Service

Ted Scott

Chevron

Richard Spading

Independent Petroleum

Association of America

Hossein Tahmassebi

Ashland Oil, Inc.

Arlon Tussing

Arlon R. Tussing & Associates,

Inc.

Michael Woo

House Energy and Commerce

Committee

Tom Woods

Gas Research Institute

Scott Wiley

Copeland, Wickersham,

Wiley & Co.

NOTE: OTA appreciates and IS grateful for the valuable assistance and thoughtful critiques provided by the reviewers. The reviewers do

not, however, necessarily approve, disapprove, or endorse this report. OTA assumes full responsibility for the report and the accuracy of its contents.

iv
Workshop 1: at Mitchell

Energy, Houston—

July 17, 1986

John Amoruso

Amoruso Petroleum

Tom Barber

Michel Halbouty Energy Co.

Ken Burke

Ernst & Whinney

Mickey Hermann

Mitchell Energy

Bobby Hickman

Mitchell Energy

Bob Hirsch

Conquest Exploration Co.

Ike Kerridge

Hughes Tool Co.

Tony Lentini

Mitchell Energy

Vince Matthews

Champlin Petroleum Co.

Workshop Participants

Workshop II: at

July 30, 1986

John Baumgartner

Amoco

David Behling

OTA –

Chase Manhattan Bank

Neil Bunis

Conoco

Bill Fisher

University of Texas at Austin

Ed Flom

Amoco

Bob Hill

Chevron

W.H. McMillian

ARCO

Richard Nehring

NRG Associates

Joe Riva

Congressional Research Service

Jack Schanz

Congressional Research Service

Ted Scott

Chevron

Hossein Tahmassebi

Ashland Oil, Inc.

John Wood

Dallas Field Office, Energy

Information Administration

v
OTA Project Staff–

Phase 1: U.S. Oil Production

Lionel S. Johns, Assistant Director, OTA

Energy, 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Overview and Findings . . . . . . . . . . . . . . . . . . 1

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

How and Why would U.S. Oil Production

Decline? . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

An Approach To Understanding Oil

Production . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Economic and Resource Factors Affecting

Production . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Changes in the Oil industry Affecting

Production . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Resisting a Decline in U.S. Oil Production:

Should Government Play an Active Role?. 19

Chapter 1: introduction . . . . . . . . . . . . . . . . . . . 25

The Origins of Today’s Low Oil Prices. . . . . . 25

Effects on the Oil Industry . . . . . . . . . . . . . . . . 25

Congressional Concerns . . . . . . . . . . . . . . . . . 27

The OTA Study . . . . . . . . . . . . . . . . . . . . . . . . 28

Chapter 2: Projections of U.S. Crude Oil

Production . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Projections of U.S. Oil Production Made

Prior to the Price Break . . . . . . . . . . . . . . . 31

Recent Projections of U.S. Oil Production

Assuming Continued Low Oil Prices . . . . . 32

Chapter 3: International Oil Prices: Where Are

They Going? . . . . . . . . . . . . . . . . . . . . . . . . 35

History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Alternate Projections of Future Oil Prices . . . 36

Determinants of Future Oil Prices . . . . . . . . . 38

Chapter 4: What Will Determine Future

Production? . . . . . . . . . . . . . . . . . . . . . . . . . 41

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

The Reliability of Forecasts of U.S. Oil

Production . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Factors Affecting Future Oil Production . . . . . 42

Chapter 5: Economic and Resource Factors

Affecting U.S. Oil Production. . . . . . . . . . . 45

The Profitability of New Investment in Oil

Exploration, Development, and

Production . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Capital Availability and the Permanence of

Capital Flight . . . . . . . . . . . . . . . . . . . . . . . . 66

Premature Loss of Existing Production:

Stripper Wells . . . . . . . . . . . . . . . . . . . . . . . 71

The Nature of the Resource Base. . . . . . . . . . 75

The Effects of the Natural Gas Surplus. . . . . . 87

Chapter 6: Changes in the Oil Industry

Affecting U.S. Oil Production. . . . . . . . . . . 89

Page

Changes in the Climate for Oil Investments

in the United States and Overseas. . . . . . . 89

The Efficiency of E&D Activities . . . . . . . . . . . 90

Changing Oilfield Technology. . . . . . . . . . . . . 93

Deteriorating Industry Infrastructure and the

Potential for a Rebound in Oil Production 95

The Restructuring of the U.S. Oil Industry. . . 99

Chapter 7: Production Loss From Reduced

Drilling . . . . . . . . .....................125

The Level of Drilling Activity . ............125

The Distribution of Drilling Targets, and the

Likely Success at Adding Reserves and

Production . . . . . . . . . . . . . . . . ..........126

Projecting Oil Reserve Additions and

Production Based on Extrapolating

Regional Drilling Patterns and Per Well

Reserve Additions . ...................127

Boxes

Box Page

A.

B.

Recent Studies by the National Petroleum -

Council and the Department of Energy . . . . 5

Potential Problems With the Interstate Oil

Compact Commission/The RAM Group, Ltd.

Estimate of Stripper Well Production Losses

Due to Low Oil Prices . . . . . . . . . . . . . . . . . . 74

Figures

Figure No. Page

1.

2.

3.

4.

5.

6.

7.

8.

9.

Net U.S. Oil Imports as a Percentage of

Oil Consumption, as Projected by the

National Petroleum Council . . . . . . . . . . . . . 1

Oil and Gas Drilling Trends . . . . . . . . . . . . . 6

How Profit Expectations for the Same

prospect would Have Changed Over Time:

An Oil Exploration Prospect in Texas’

Permian Basin . . . . . . . . . . . . . . . . . . . . . . . . 11

Regional Differences in Oil Reserves Added

Per Well Drilled . . . . . . . . . . . . . . . . . . . . . . 17

U.S. Crude Oil Production, 1947-86 . . . . . . 27

Oil and Gas “Finding Costs” . . . . . . . . . . . . 65

Size Distribution of Discovered Oil and

Gas Fields in the Lower 48 States . . . . . . . . 79

Known and Projected Size Distributions of

Discovered Oil and Gas Fields in the

Lower 48 States. . . . . . . . . . . . . . . . . . . . . . . 80

Oil “Finding Rate” . . . . . . . . . . . . . . . . . . . . 92

vii
Tables

Table 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. Oil

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Projections of Future U.S. Oil Production,

1985 Outlook . . . . . . . . . . . . . . . . . . . . . . . . 32

Recent Short-Term Projections of U.S. Oil

Production at Low Prices . . . . . . . . . . . . . . . 32

Recent Projections of Future U.S. Oil

Production at Low Prices . . . . . . . . . . . . . . . 34

“Why Oil Prices Will Remain Low”-

Arguments Used by Forecasters of Low

Future Oil Prices . . . . . . . . . . . . . . . . . . . . . . 38

“Why Oil Prices Will lncrease”-

Arguments Used by Forecasters of High

Future Prices . . . . . . . . . . . . . . . . . . . . . . . . . 39

Assumed Costs To Drill, Equip, and

Operate Development Wells, Selected

Years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Oil Prices for West Texas Crude . . . . . . . . . 49

Economic Analysis of Drilling Prospects:

Development Wells in Reservoirs Not

Producing Before 1979 . . . . . . . . . . . . . . . . . 50

Economic Analysis of Drilling Prospects:

Development Wells; Effect on Profitability

of Windfall Profits Tax “Tiers”. . . . . . . . . . . 51

Economic Analysis of Drilling Prospects:

Effects of Oil Price on Rate of Return Tier

3 Development Wells, Drilling and

Production Begun in 1986 . . . . . . . . . . . . . . 51

Economic Analysis of Drilling Prospects:

Effect of Changing Drilling Costs on Rate of

Return . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Economic Analysis of Drilling Prospects:

Policy Options for Improving the

Profitability of Development Drilling . . . . . . 52

Economic Analysis of Exploration and

Development Projects . . . . . . . . . . . . . . . . . . 53

What Happens If Dry Hole Risk Is

Reduced? . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Characteristics of Hypothesized Prospects . 54

Estimated Investment and Operating Costs. 55

Assumed Crude Oil Prices . . . . . . . . . . . . . . 55

Tax and Financial Variables . . . . . . . . . . . . . 56

Estimated Anticipated Profitability of U.S.

Oil Prospects: 1972, 1981, 1985, and 1986 56

Estimated Anticipated Profitability of U.S.

Oil Prospects, Under Specified Price and

Policy Alternatives . . . . . . . . . . . . . . . . . . . . . 58

Economic Analysis of Exploration and

Development Projects . . . . . . . . . . . . . . . . . . 59

Lower-48 0il and Gas Production....:. . . 59

Economic Prospects for Drilling, Based on

GRI Hydrocarbon Model Runs . . . . . . . . . . 61

Sensitivity of Leasable Resource Amounts

to Current Oil Price . . . . . . . . . . . . . . . . . . . 62

U.S. Exploration and Development Outlays

for 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 a

Group of Petroleum Companies . . . . . . . . . 67

Financial Performance of Selected Oil

Companies, First 9 Months 1986 v. First 9

Months 1985 . . . . . . . . . . . . . . . . . . . . . . . . . 70

Effect of Falling Oil Prices on Stripper

Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

Estimated Oil and Gas Resources in the

Arctic National Wildlife Refuge Section

1002 Area . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Drill Rig Equipment: Storage and

Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

U.S. Oil and Gas Reserves Replacements

Percentage of Production, 1979-85 and

Domestic Implied Finding Costs . ........102

Valuations of Proved Reserves . ..........103

Values Added Through Exploration and

Development–Worldwide . .............104

Value Added Ratios–Worldwide. . .......104

Mergers and Acquisitions in the U.S. Oil

Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . .105

Financial Performance of a Group of Oil

Companies, 1983-85 . . . . . . . . . . . . . . . ....109

Comparison of 20 Largest U.S. Oil

Companies, 1980 and 1985.............112

Comparison of Historical Concentration in

the U.S. Oil Industry. . .................112

Capital and Exploration Expenditures for

Selected Oil Companies, 1983-85 . .......115

Changes in Planned Expenditures on U.S.

Exploration and Production . ............116

Reinvestment in Oil and Gas Exploration

and Production . . . . . . . . . . . . . . . . . . . . . . .119

Share Repurchase Programs of Selected Oil

Companies . . . . . . . ....................120

Reserve Additions Per Oil Well Drilled,

1980-1984 Average . ...................126

Past and Projected Alaska Oil Status ... ...l28

46. Past and Projected California Oil Status ...128

47

48

49

50

51

52

53

54

55

Past and Projected Rocky Mountains and

Northern Great Plains Oil Status . ........128

Past and Projected West Texas and Eastern

New Mexico Oil Status. . . ..............129

Past and Projected Gulf Coast Oil Status ..129

Past and Projected Midcontinent Oil Status 129

Past and Projected Eastern Interior Oil

Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .130

Past and Projected Michigan Basin Oil

Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .130

Past and Projected Appalachians Region

Oil Status . . . . . . . . . . . .................130

Past and Projected United States Oil Status 131

Impact of lncreased Stripper Well

Abandonment on Low Drilling Scenario

Production and Reserves Projections ... ...132
Summary

Overview and Findings

The recent precipitous drop in world oil prices

from about $28 per barrel ($28/bbl) in 1985 to

between $12 and $18/bbl through much of 1986

dealt the U.S. oil industry a severe blow. In the

first year after the price drop, U.S. crude oil production dropped by nearly 700,000 bbl/day, industry capital spending on exploration and production dropped from about $33 billion/year to

about $16 billion, drilling activity dropped from

over 70,000 well completions/year to approximately 37,000, and the basic infrastructure of the

industry, including its skilled personnel, shrank

considerably. There is now a strong consensus

that domestic oil production will continue to

drop, to between 6 million and a bit over 7 million barrels per day (mmbd) by 1990, down from

the 1985 level of 9 mmbd, if oil prices remain

in the $12 to $18/bbl range.

A substantial drop in U.S. oil production is only

one component of a chain of events . . . resulting

from lower world oil prices . . . that could create

future problems for the United States’ economic

stability and national security. First, this Nation’s

price-sensitive demand for oil will rise as its oil

production declines—a combination resulting in

a sharp increase in the level of imported oil. Most

industry projections of the effects of continued

low oil prices envision imports reaching 50 percent of U.S. oil consumption by the early 1990s

or before. (Figure 1 shows the National Petroleum

Council’s import projections for a low and high

price track.) At an oil price of $18/bbl, this will

amount to a 50 to 60 billion dollar per year drain

on the United States’ balance of payments.

Simultaneously, similar trends in oil supply and

demand will be occurring outside the United

States. Lower oil prices are expected to depress

oil production outside of the Organization of Petroleum Exporting Countries (OPEC) and the Middle East while increasing the worldwide demand

Figure 1 .—Net U.S. Oil Imports As a Percentage of

Oil Consumption, As Projected by the

National Petroleum Council

1 I I I

1980 1985 1970 1975 1980 1985 1990 1995 2000

Year

SOURCE: National Petroleum Council, Factors Affecting U.S. Oil & Gas

Outlook, February 1987.

for oil (except where higher taxes maintain prices

at previous levels). These changes will increase

OPEC’s share of the world oil market, with much

of the increase going to the Middle Eastern OPEC

nations. In time, the Middle Eastern OPEC producers will have returned to the levels of market

share and production capacity utiIization that in

the past allowed them to affect prices or disrupt

oil markets. And, thus, they will have regained

an ability to upset U.S. economic stability and

national security.

OTA’s evaluation of a set of factors affecting

future U.S. oil production lead to the following

conclusions:

1. The available evidence points strongly to a

continuing, and substantial, decline in U.S. oil

1
2

production if oil prices remain in the $12 to

$18/bbl range. This evidence includes: a) recent

production trends and trends in drilling and other

oilfield activity; b) the financial state of the industry; c) industry surveys of future oilfield investment; d) the results of oil supply models; and e)

a limited amount of economic analysis.

2. Recent rates of drilling activity are much too

low to allow domestic oil production to stabilize

close to today’s already depressed production

levels. Even with quite optimistic assumptions

about the productivity of future drilling, a continuation of 1986 drilling rates would lower year

2000 U.S. oil production to about 6 mmbd– a

third lower than 1985 production levels.

3. Available estimates of the magnitude of the

production decline should be viewed as “best

guesses” rather than as precise calculations, even

if the uncertainty associated with future oil price

levels is disregarded. Most current production

forecasts assume implicitly or explicitly that previous trends and relationships established over

the past few decades will continue into the future. The severity of the economic dislocations

caused by the recent drop in oil prices, coupled

with major changes in the industry over the past

few years, imply that this assumption deserves

to be reexamined. It is probably prudent to assume that the oil industry will adapt in various

ways to the new economic environment and, in

adapting, will break with many past trends.

4. It is not clear whether a break with past

trends would lead to production levels higher or

lower than an analysis based on historical behavior would predict. On the optimistic side, the

oil industry might be expected to follow an initial period of disrupted operations with movement to more efficient management and positive

technological adaptations. On the pessimistic

side, any positive effects on oil production levels

associated with an adaptive move to higher efficiency might be offset by several factors:

● the industry’s higher debt levels caused by

the wave of takeovers and mergers during

the 1980s, which could depress total exploration and development (E&D) investment;

● the improvement in financial terms offered

by several potential overseas producing

countries, which might shift E&D investment

out of the U. S.;

the current drop in spending on research

and development, which could slow technological innovation; and

the apparent shift in basic industry E&D investment strategy, downplaying the importance of replacing company reserves and

stressing the requirement that E&D investments satisfy rigorous profitability requirements.

There is no ready way to estimate the net effect on production of these diverse factors, Also,

further uncertainty is added to estimates of future production levels by the dependence of production on a number of other factors that are not

known with any precision, such as the magnitude, geographic distribution, and physical nature of remaining oil resources. Finally, uncertainty is added by the relatively low priority that

appears to have been given to publicly available

analysis of the economic attractiveness of new

investment in drilling and other production-oriented ventures (the oil industry conducts extensive

economic analysis of new investment prospects,

but most of the analyses are proprietary and not

available to assist in the public policymaking process). The attractiveness of such investment is the

key indicator of long-term prospects for adequate

U.S. reserve replacement and production.

If oil prices do stay low–perhaps averaging between $14 and $16/bbl for the next several

years—what might be the outcome for domestic

oil production? With rapid restructuring of the

weaker companies, favorable adjustments in E&D

strategies, innovation in E&D technology, and

favorable potential for continued reserve growth

in older oilfields, domestic production might be

able to hold above 7 mmbd through 1990 (the

upper end of the range of most industry estimates)

and drop less steeply than projected thereafter.

For the period beyond the early 1990s, the opening of Federal and State lands to exploration and

the successful discovery of large oilfields on these

lands could be of special importance. On the

other hand, if the industry continues to shift to

more overseas investment and fails to improve

efficiency further, technological change slows be-
3

cause of reduced R&D spending, and reserve additions from older fields slow because of reduced

geologic potential and poor economics, production could sink to the lower end of the consensus

range (about 6 mmbd) in 1990 and conceivably

even below the expected range in later years.

5. Further economic and technical analysis

could be useful to policy makers concerned with

falling oil production. With or without such analysis, however, substantial uncertainty will remain

about how domestic production will respond to

different price levels and policy environments,

and policy makers must be prepared to make key

decisions without precise knowledge of their outcomes. Some questions that cannot be fully answered with further analysis include:

●

●

●

●

●

●

How will industry investment behavior adapt

to the new price environment and to a

changing business environment overseas?

To what extent will the major industry restructuring of the 1980s eventually lead to

higher efficiency and increased interest in

new domestic E&D ventures? Will newly

merged and restructured companies be able

to eliminate their heavy debt burdens within

a few years, and will they then act to boost

their investment in traditional E&D activities?

To what extent will technological change act

to offset some of the negative effects on profitability of lower oil prices?

Will relatively low cost drilling in the United

States’ older oilfields continue to provide

large volumes of new reserves, or did the intensive drilling of the past decade essentially

“use up” most of these fields’ remaining

growth potential?

If large new blocks of Federal and State land

are made available for exploration, especially

offshore California and in the Arctic, will

super giant fields be discovered and developed?

How long will it take (or what conditions are

necessary) to restore enough confidence to

potential investors in E&D that they will respond readily to reasonable profitability

prospects? To what extent could investment

levels rebound without a concurrent rebound in cash flow from the industry’s past

investments?

6. There are ways to reduce, though certainly

not eliminate, uncertainty about the magnitude

of a future production decline and the potential

effect on production of alternative government

policy measures. Of most value would be a comprehensive analysis of the prospective profitability

and productivity of new investment in oil exploration and development. Although some valuable

economic analyses are available (e. g., the National Petroleum Council’s evaluation of E nhanced Oil Recovery) these are too limited in

scope and uncoordinated to qualify for the type

of comprehensive analysis needed for careful

forecasting and policy analysis.

Other potentially useful analyses include:

●

●

●

●

7.

A cataloging and analysis of changes in the

business environment for oil and gas investment overseas.

An evaluation of the dissemination and use

of new technologies in oil exploration, development, and production during the past

decade, and an examination of new technologies just introduced or on the near horizon.

An economic analysis of existing oil production with high operating costs (especially

stripper production), incorporating collection of physical and economic data at the

individual well level.

An examination of the differences in individual companies’ E&D strategies and results,

to gain further perspective about the potential for industry wide improvements in E&D

efficiency.

Congress is faced with difficult choices, not

only in ‘selecting policies to combat trends

towards lower domestic oil production and

higher imports but also in deciding whether an

active government role is wise. Unfortunately,

some of the key issues associated with choosing

an appropriate government role are ambiguous.

For example, earlier concerns about the effect

of higher oil imports on U.S. economic stability

and national security have been complicated—

but not negated–by the significant changes in

oil markets and government preparation for market disruptions since the early 1970s. These

changes include the construction of the Strategic Petroleum Reserve, the advent of a strong spot
4

market for crude oil, the beginning of a futures

market, and substantial changes in the role of oil

in the U.S. economy.

Another complication is that the majority of

production forecasts prior to the 1985-86 oil price

drop projected domestic oil production to begin

falling rapidly in the 199os; in other words, most

forecasters expected the production decline and

subsequent increase in imports to occur even in

the absence of a large price drop, albeit a decade later. At first glance, these predictions would

appear to favor a “hands off” policy on oil production since boosting production today would

appear to be only delaying the inevitable. Not

al I forecasters agree with this “conventional wisdom,” however; they contend that U.S. production could have been maintained, had prices not

tumbled, with continued intensive field growth

and innovation in enhanced oil recovery. Further,

“buying” an extra decade of moderate import

levels could be worthwhile if the decade were

used to add flexibility and security to the U.S.

energy system, rather than to artificially preserve

the status quo, so that the Nation would be better prepared to deal with higher import levels

when they occurred.

There is also uncertainty about whether allowing U.S. oil production to decline now might yield

higher future production rates than would be possible if today’s production rates were propped

up and the resource base depleted more intensively. Although resource depletion is a valid concept, the remaining U.S. petroleum resource base

is less a small resource than it is a low-grade resource whose recovery is amenable to improved

technology. Thus, the pace of technology development—likely to be more rapid if production

is kept high by tax or other incentives—conceivably may outweigh resource depletion as an influence on future production levels.

If Congress does decide to work to stabilize domestic oil production, it can use a number of policy mechanisms. The following options are discussed briefly in the report:

● oil import fees (either to raise wellhead prices

or to establish a price floor);

● tax concessions (including investment tax

credits, depletion allowances, cuts in sever-

●

●

●

ance and ad valorem taxes, drilling credits,

abolishing the Windfall Profits Tax);

removing the ban on oil exports from the

Alaskan North Slope;

bolstering investment in oil exploration and

development R&D; and

removing leasing restrictions on frontier/offshore areas.

Introduction

The long price slide that took world oil prices

from about $40/bbl in 1981 to $28/bbl in December, 1985, and then precipitously downward

to the $12 to $15/bbl level throughout much of

1986 has created a depression in the U.S. oil industry. Most indicators of the level of oilfield

activity have been slipping since the “peak” year

of 1981 and dropped sharply in the early months

of 1986:

●

●

●

●

The number of rotary drilling rigs working

in the United States dropped from over 4,000

in 1981 to about 1,900 in July 1985 to below 700 a year later; they have since rebounded slightly.

Industry employment dropped from a 1982

high of 708,000 to 585,000 in 1985 and to

422,000 in September 1986, with oilfield

service employees bearing the brunt of the

drop.

Total well completions, which had declined

moderately from 89,000 in 1981 to 73,000

in 1985, dropped below 40,000 in 1986. Figure 2 illustrates the rise and fall of well completions between 1970 and the present.

The monthly seismic crew count, that is, the

number of teams doing seismic surveys for

oil and gas exploration and development, fell

from 681 in 1981 to 378 in 1985 and to 195

in 1986.

U.S. oil production has slid from 9.03 million

barrels per day (mmbd) at the end of 1985 to 8.35

mmbd a year later, a decline of over 7 percent.

Coupled with increased oil demand, the production decline has forced U.S. net imports of crude

‘That is, crude oi I plus ‘ I lease condensates, ’ natural gas I iq u ids

recovered in the field. Total domestically prduced petroleum also

includes 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 published reports on U.S. energy supply: Factors Affecting U.S. Oil & Gas Outlook and Energy Security, respectively. Both reports focus particularly on domestic oil production but also evaluate U.S. and world

energy 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 in

1985) if oil prices* rise from about $14/bbl in 1986 to $16/bbl by 1990 and $22/bbl by 1995. The NPC

report projects slightly higher production rates at somewhat lower prices: 7.1 mmbd in 1990 and 5.7 mmbd

in 1995 with oil prices at only $12/bbl in 1986 and rising to $14/bbl by 1990 and $17/bbl by 1995. Both

of these projections are well within the mainstream of forecasts released within the past year, and are

substantially more optimistic than several. For both, net petroleum imports reach the 50 percent level in

the 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 in

1995; for similar prices, NPC projects production to be 8.0 mmbd in 1990 and 7.0 in 1995. These results

imply that an import fee that raised oil prices by $5 to $10/bbl could substantially slow the production

decline.

DOE’S projections are based on a detailed computer model of U.S. energy supply, the Energy Information Administration’s Intermediate Future Forecasting System. NPC’s projections are based on a survey

of U.S. and world oil supply and demand forecasts from various sources. Both projections are supplemented by quantitative and qualitative evaluations of oil supply factors. The NPC report plainly acknowledges the substantial uncertainty associated with the projections:

Even sophisticated statistical analysis of past events is inadequate for predicting the future if the historical data

do not contain an event similar to the current or expected future events . . . Energy forecasters have no recent

historical events to measure the impact of sharply falling prices of petroleum . . .

Both reports identify the deterioration of industry infrastructure-loss of skilled workers, declining manufacturing capacity of critical oilfield equipment, deterioration of the rig fleet, and so forth-as a critical

roadblock to a future drilling recovery. OTA shares these concerns but is somewhat more optimistic about

the 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 the

DOE report presents a quantitative analysis of these options, calculating the net costs and production response 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/production estimates were not made).

*Measured as the cost of crude oil to U.S. refiners.
6

oil and petroleum products up by about 14 percent over a year before, from 4.9 mmbd, or 30

percent of total U.S. petroleum supply, to 5.6

mmbd, or 34 percent of supply.

These trends appear to be pushing U.S. oil supply towards a dependence on imports reminiscent of the situation in the late 1970s, before the

production stimulating and demand suppressing

effects of the two oil price shocks finally took hold

and began weaning the United States from a

growing reliance on foreign oil supplies. In fact,

a renewed dependence on foreign supplies is precisely what the oil industry and most energy

analysts are predicting for the United States—

absent either a rapid return to previous price

levels or major Federal intervention in the marketplace. Typically, they are projecting a likely

decrease (from 1985 production levels) in domestic oil production of 2 to 3 mmbd by 1990, and

similar increases in demand, if world oil prices

stay at about $15/bbl. Table 1 presents several

projections of future U.S. crude oil production

assuming continued low oil prices, as well as projections completed before the price drop for comparison.

How and Why Would U.S.

Production Decline?

Several mechanisms will drive the

production 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 American

Petroleum Institute data

First, production from stripper wells2 and other

marginal wells (wells with high per barrel production costs) will drop because many of these wells

cannot be operated profitably at low oil prices

and will be shut down. These wells cannot remain out of production for long periods; after a

year (or other period depending on State rules)

they have to be “plugged” (sealed with concrete)

for safety and environmental reasons, and are

unlikely to be reopened thereafter. Other shut

down wells may be lost because of water encroachment.

Second, fewer new development wells will be

drilled, yielding less new production to offset the

natural decline in production from older wells,

Third, fewer exploratory wells will be drilled,

yielding fewer new fields and thus fewer new opportunities for development drilling,

Fourth, production from enhanced oil recovery (EOR) operations, which seek to capture as

much as possible of the estimated two-thirds of

original oil-in-place left behind by conventional

drilling and waterflooding, will decline because

most new projects, and many planned project expansions, will be cancel led as no longer economical.

Fifth, research and development (R&D) will decline, exacerbating the overall problem because

R&D traditionally has been an important driver

in pushing the industry into new areas and

sources of oil production as older sources

decline.

In addition, many analysts warn that the industry is losing its ability to recover swiftly in the

event of a return to high prices; the infrastructure necessary for such a recovery is rapidly being

dismantled as drilling rigs are scrapped, cannibalized for parts, or even sold abroad; manufacturing facilities are retooled; and skilled personnel

are laid off, many Ieaving the industry for good.

Although the reasons given for their predictions

may differ, the analysts have tended to focus their

arguments on three areas in particuIar:
7

Table 1 .—Recent Projections of Future U.S. Oil Production

Projected crude oil production

(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 2000

Chevron . . . . . . . . . . . . . . 5.9-6.9 NA NA $10 to $15 thru 1987, $18 to $22 by 2000

API . . . . . . . . . . . . . . . . . . 6.2 NA NA Constant $15

CWW ... . . . . . ., . . . . . 6.1 NA NA $15

Unocal . . . . . . . 6-6.5 NA NA $13.50

Amoco . . . . . . . . . . . . . . . 6.7 NA 4.5 “Low price”

Fisher . . . . . . . . . . . . . . . . 6.8 NA NA $15

Conoco A . . . . . . . . . . . . 7.0 5.5 3.5 <$12 thru 1995, $20 in 2000

Conoco B . . . . 7.8 6.9 6.1 <$20 thru early 1990s, $20 in 1995, $26 in 2000

GRI D.......,.....,.,.. 7.3 5.4 5.0 $12 in 1986, $14 in 1990, $21 in 2000

NPC . . . . . . . . . . . . . . . . . 7.1 5.7 4.5 $12 in 1986, $14 in 1990, $21 in 2000

DOE . . . . . . . . . . . . . . . . . 6.9 5.2 NA $14 to $16 thru 1990, $21 in 1995

Price outlooks of 1985:

Chase . . . . . . . . . . . . . . . . 8.3 7.0 5.7 Drops to low $20’s by 1990, rises 0.9 ‘\. /year thereafter

DRI B . . . . . . . . . . . . . . . . . 8.6 NA 6.8 Drops to $21 by 1987, constant to 1994, $32 by 2000

EIA . . . . . . . . . . . . . . . . . . 8.1 6.5 NA Dips but is $28 by 1990, $31 by 1995

GRI . . . . . . . . . . . . . . . . . . 8.5 8.2 7.8 Dips but is $34 by 1995, >$40 by 2000

+xcludeS Natural Gas Llqulds 1985 Product Ion, 9mmbd

NA = Not available

SOURCES: DRI Data Resources, Inc , Energy Rewew, Summer 1986.

Chevron Economics Department, Chevron Corporation, World Energy Outlook, June 1986

API 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, 1986

Amoco Economics Department, Amoco Corp., World Energy Outlook, April 30, 1986

Fisher Wlillam Fisher, Bureau of Econom!c Geology, Unlverslty of Texas at Austin, Testimony to the Fossil and Synthetic Fuels Subcommittee, Energy and

Commerce Committee, March 6.1986

Conoco A and Conoco B Coordinating and Planning Department, Conoco, Inc , World Energy Outlook Through 2000, September 1986

GRI 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 1986

GRI 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 virtually

unanimously predict low rates of drilling and

rapid declines in reserve additions and production if low prices continue. Current industry surveys of expected future drilling levels,

reserve additions, and production basically

support these predictions.

Available models of U.S. oil supply generally

rely on extrapolation from past trends to project

future levels of drilling activity, reserve replacement, 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 trends

provide a good analog.

It is virtually certain that the extrapolative

models of oil production are directionally correct

in their prediction of a U.S. oil production decline. Under current conditions, however, policymakers shouId be skeptical of the accuracy of

these models. The events of the past year, and

of the 1980s in general, in several ways are major departures from past events. The nation has

just undergone a period during which oil prices,

a key determinant of industry exploration and development activity, have undergone severe dislocation, and in a direction opposite past dislocations. Moreover, during the 1980s, several

companies comprising a large segment of the industry’s reserve replacement capability underwent significant changes in business strategies,

were restructured, or merged with other companies. In addition, the period of the early 1970s

to the present has been a period of hyperinflation followed by collapse in industry costs; the

future path of such costs–a key determinant of

the economic attractiveness of new E&D investment—is unlikely to be stable or predictable.
8

I

While the results of industry surveys of future

drilling rates, reserve additions, and production

are very important, policy makers are likely to demand substantial analytical evidence to back up

the survey results. For one thing, in recent years

the industry (along with just about everybody

else) has not been very successful in predicting

which way prices and production would turn,

and different segments of the industry and different companies often have been at odds about

major resource and production projections. Second, the industry participants in these surveys

have been the direct recipients of significant financial blows and have seen their friends and colleagues laid off, retired, or even bankrupted. It

seems fair to have concerns about whether their

expressed views of the future of the U.S. oil industry reflect a cool-headed appraisal or instead

reflect their depression about the immediate results of the industry downturn. Third, the industry has a very large financial stake in any policy

measures that could alleviate a production decline. Whether or not this stake affects their announced projections of future production, some

policy makers and segments of the public believe

that it may. These concerns suggest that an analytical verification of industry estimates, capable

of being reviewed by independent analysts,

would be desirable and probably necessary for

public acceptance.

Argument Two: The large drop in oil prices has

drastically cut oil industry revenues and placed

many of the industry’s past investments in

jeopardy. After paying off its obligations, the

industry’s remaining internal cash flow is

sharply reduced from earlier levels. At the

same time, the industry’s traditional sources

of outside investment and loan capital, faced

with low prices and uncertainty, have backed

away from the oil market. These capital

sources are particularly important to the independent sector of the industry. Without

new sources of investment capital and without a restoration of cash flow from prior investments, the industry will not have enough

capital to invest in the major new exploration

and development ventures needed to arrest

the rapid decline in production.

This argument is most important for projecting

oilfield activity levels in the short term, perhaps

over a 2- or 3-year period. Many of the financial

entities generally responsible for U.S. drilling and

other production activities have been hurt badly

from the large cut in revenues from their past investments; uncertainty about their survival—especially for many of the small independents—will

keep away outside capital, and they have minimal internal resources. Similarly, many banks and

other sources of investment capital experienced

severe losses and may be reluctant to reenter the

oil market. In the short term, new investment will

suffer because it will take time for the industry

to resolve mismatches between financial resources, drilling capability, and land positions and

reserve ownership. After an industry shakeout,

however, drilling and other activity, and reserve

replacement, could revive if adequate incentives,

measured by the expected profitability of new

E&D investment relative to competing investments, were available. Also, a number of companies, especially those larger integrated companies and independents that had avoided large

debt loads, still have substantial internal resources

and/or access to external capital sources. The

argument that inadequate capital resources will

prevent the industry from investing in new production, which attempts to tie the level of new

investments to the success of old ones, may explain short term investment behavior of the oil

industry (or, at least, some segments of it) but

does not adequately explain the industry’s longterm investment behavior.

Argument Three: The large drop in oil prices

coupled with fears about future price collapses have undermined the expected profitability of new investments in exploration and

development. With current price expectations

and conservative investment requirements (to

account for higher uncertainty), there are too

few economically attractive drilling opportunities to spur continuation of the industry’s

past level of domestic exploration and development activity.

This argument ties the level of future investments in reserve replacement and production

directly to the economic attractiveness of these

investments. In OTA’s view, the attractiveness,
or expected profitability, of future drilling and

other production-oriented ventures is the key indicator of long-term prospects for adequate U.S.

reserve replacement and production.

Current industry analyses supporting conclusions about declining U.S. oil production prospects generally stress arguments one and two and

pay somewhat less attention to argument three.

Models and surveys, the bases of argument one,

have been widely used. The second argument

about inadequate capital and reduced cash flows

is analytically very straightforward and has been

advanced with intensity, especially by spokespersons for the independent sector of the industry.

In contrast, few in the industry have supported

the third, “expected profitability” argument with

the careful analysis necessary to establish its credibility. 3 The substantiation of industry projections

of declining production that would be provided

by a careful analysis of expected profitability must

be viewed as very important in light of the high

social costs—many billions of dollars—associated

with many of the policy measures being considered to arrest the projected decline.

Evaluating the attractiveness of new E&D investment opportunities relative to competing investments is a complex undertaking. It would require

a substantial commitment of resources and information from the industry, and much information that would be useful in such an evaluation

is proprietary. Although many and perhaps most

of the larger oiI companies have undertaken extensive analyses of their own investment prospects, these analyses are not likely to be made

available to the public. Furthermore, a credible

national analysis will still have to rely on some

form of detailed assumption about that portion

of the total remaining oil resource base that is

physically available to the industry for exploitation within the time frame of interest. No widely

accepted resource model currently exists, although there are a few computer models of oil

supply (e.g., the Gas Research Institute’s Hydrocarbon Model) that constitute some first attempts

at such a model.

3We do not doubt that many of the i ndustry’s survey responses

about future 011 production levels are based on companies’ private

evaluations of expected profitability of new E&D investments.

9

An Approach to Understanding

Oil Production

Given the concerns about the reliability of current oil supply models under today’s radically

changed economic conditions, an appropriate

means to gauge future oil production is to gain

an understanding of both the changes the oil industry has undergone and the forces that will

drive future production. The following discussion

examines:

Economic and resource factors affecting production:

—changes in the economics of drilling

prospects over time;

—changes in capital availability and how

these changes affect E&D investment

levels;

–loss of oil production from stripper wells;

—the nature of the oil resource base, and in

particular, the availability of drilling opportunities that might remain profitable in a

low price environment; and

—the effects on drilling of the current surplus in natural gas supply.

Changes in the oil industry affecting production:

—the potential effects of industry restructuring on industry investment strategy and capabilities,

—the changing business climate for E&D investment overseas and its effect on domestic versus overseas spending,

—changes in the efficiency of exploration

and development activity and their effects

on rates of reserve additions and production,

—the potential for technological change to

offset some of the drop in profitability

caused by low oil prices, and

—the effects of a deteriorating industry infrastructure on industry’s ability to rebound to higher drilling levels.

The goal of examining these factors is to determine whether the preponderance of evidence

tends to support or undermine the industry’s pessimistic predictions for future oil production, and
10

to better understand how Congress might best

intervene to shore up production if it chose to

do SO.

Economic and Resource Factors

Affecting Production

Changes in the Economics of

Drilling Prospects

OTA’s interviews with oil industry planners

paint a pessimistic picture of remaining domestic exploration and development prospects at low

prices. Essentially all of those interviewed contend that the “inventory” of economic oil and

gas prospects has shrunk enormously at mid1986 prices of$12 to $15/bbl despite the accompanying sharp declines in drilling and other

costs. They assert that the only arena capable of

supporting substantial drilling levels at these

prices is relatively low-risk, low-to-moderate cost

development drilling, primarily for oil objectives,

with short lead times; they also assert that exploration drilling is virtually dead at these prices.

In addition to low risk shallow extension and

infield drilling,4 other prospects still considered

to be viable at oil pricesof$12 to $15/bbl include:

●

●

●

continuation of projects where most frontend capital has been spent (enhanced oil recovery, offshore development drilling, waterfloods 5

);

drilling to satisfy lease and contract requirements; and

some exploration drilling where production

could not begin for 7 to 8 years or longer,

so the current price environment is not relevant (although several major companies

have backed away from this type of drilling).

Most of those interviewed were pessimistic

that an increase to $18 to $20/bbl would spark

4Extensiondrllllng seeks oil and gas just outside the known boundaries of discovered fields; infield drilling seeks oil and gas inside

of 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 injected into the reservoir to maintain or restore reservoir pressure

and push additional oil towards the producing wells.

a major drilling revival, although all felt that certain additional prospects would become economic, including:

●

●

●

●

●

●

some deepwater Gulf of Mexico exploratory

prospects;

some onshore wildcat prospects;

additional enhanced oil recovery, especially

C02 gas injection projects with readily available sources of CO2

, and some projects using

the injection of polymers;

Beaufort Sea exploration and delineation

drilling;

limited offshore California development; and

many waterflood projects.

There are only scattered published economic

analyses that can offer confirmation of these assertions. In an attempt to test at least a few of the

assertions, OTA examined how the expected

profitability of small-scale exploration and development drilling programs i n the United States

has changed over time. OTA compared 1986

profit expectations with expectations for the same

physical prospects in: 1985, immediately before

the major price drop; 1981, at the height of the

drilling boom; and 1972–before the first OPEC

price shock. Although only a few physical prospects were examined, we believe that the results

are fairly widely applicable to drilling projects of

modest scale.

In our analysis, we found that the profit expectations for the 1986 drilling projects, assuming

oil prices would remain in the $14/bbl range

during the 1980s, were substantially lower than

expectations in 1981 and 1985 in every case; for

example, onshore development well drilling projects with expected real rates of return (before

taxes) of 15 percent in 1986 would have been

expected to earn 35 to 52 percent in 1985 and

23 to 43 percent in 1981. Although drilling costs

dropped substantially from 1981 to 1985 and, to

a lesser extent, from 1985 to 1986, the oil price

drop has proved to be the more important factor influencing profitability. This result agrees

strongly with the assertions of the industry that

6Expectecf profitability is calcu Iated by using oil price forecasts

typical of the analysis year. Realized or actua/ profitability is calculated by using actual price levels up to the present, and forecasted

or assumed price levels thereafter.
11

the price drop has substantially reduced the

number of profitable domestic E&D opportunities.

We also found, in every case, that 1986 expected profitability (based on the assumed $14/

bbl future oil price) was much better than expectations in 1972, primariIy because 1972 oil

price expectations were modest. Thus, for the

cases examined, today’s economic conditions

for drilling development wells and exploration

wells aimed at small fields would appear to be

substantially superior to conditions in 1972, for

wells of the same physical promise. At first

glance, this appears to indicate that the industry

has better economic opportunities today than in

1972. Because so many of the better prospects

were drilled in the years between 1972 and 1986,

however, today’s remaining physical prospects

may be considerably poorer than those available

in 1972. On the other hand, this effect of “resource depletion” is tempered by the addition

of new prospects to the resource “inventory” because of improvements in exploration technologies and in geologic understanding. The net effect of these factors is unclear without further

analysis, although an industry consensus would

likely be that today’s physical drilling prospects

are substantially inferior to those available in

1972.

Figure 3 illustrates the change over time in expected profitability for a single exploration prospect in the Permian Basin, Texas.

Another important result of OTA’s analysis was

that the actual profit performance of the drilling

projects was considerably different than the expected performance. For the wells drilled in

1972, actual profits were much higher than initially expected; for the 1981 and 1985 wells, actual profits were much lower than expected.7

In fact, there is little difference in realized rates

of return between the 1986 wells and the 1981

and 1985 wells. The higher drilling costs incurred

in 1981 and, to a lesser extent, in 1985 offset the

higher average oil revenues obtained with these

wells.

7Assumln~ continued $14/bbl oil prices beyond 1986

Figure 3.—How Profit Expectations for the Same

Prospect Would Have Changed Over Time: An Oil

Exploration Prospect in Texas’ Permian Basin

75

50

25

0

19 

$20 oil

$14 oil

price

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 Congressional

Research Service analysis for this study

OTA also examined the effects of assumed $10/

bbl and $20/bbl oil prices on 1986 expected profitability. At $20/bbl, if drilling costs do not rise,

expected profitability for the projects evaluated

will be in the same range as 1981 and 1985 profit

expectations, implying that a drilling revival

could occur at this price level. However, the

strength of any revival would be limited by increases in drilling costs that would occur as the

current “surplus” of drilling services is used up.

Also, for a revival to occur, producers must be

reasonably assured of continued price stability.

Today, many producers say that they are requiring proposed drilling projects to pass a ‘‘low-price

hurdle,” that is, they must retain profitability at

prices that could occur if surplus production

drove prices back down again. A hurdleof$10/

bbl is frequently mentioned. At $l0/bbI, drilling

prospects that would yield 15 percent real rates

of return at $14/bbl become either outright

losses or yield barely a few percent. Thus, conservative price/cost accounting in approving

proposed drilling projects may be playing an important role in stifling drilling activity.

Our analyses apply only to oil exploration and

development aimed at small fields and modest-
72

sized development wells, and only to physical

examples that do not stray far from average conditions. In our view, the great importance to national policy makers of having an accurate estimate of domestic E&D economics demands a

wealth of additional analysis. This analysis must

examine the full range of E&D activity, from the

various forms of enhanced oil recovery to exploratory drilling in the Arctic and deep offshore,

to extension well and infill drilling in older fields,

and so forth. Considerable analysis is already

available, for example the National Petroleum

Council’s report on enhanced oil recovery, but

the separate analyses must be collected, intensively reviewed for accuracy, and reworked to

fit into a consistent economic framework. Substantial new analyses will be needed to fill in the

gaps.

Problems of Capital Availability

As noted previously, the large reductions in

cash flow to the oil industry and, to a lesser extent, the withdrawal of outside loan and investment capital are widely viewed as critical factors

in driving down levels of investment in oil exploration and development. Total oil and gas wellhead revenues were about $70 billion in 1986,

about 43 percent below 1985 levels. Although

reliable data for private financing, a major source

of funds for independent producers, are not available, many industry analysts are convinced that

availability of private funds has declined substantially because of current conditions in the industry. Furthermore, many of the regional banks

which had financed the efforts of many small

operators during the late 1970s and early 1980s

were placed under severe pressure by the bankruptcies of many of their oil service industry borrowers and the reduced values of the oil and gas

reserves used as collateral for their loans to independent producers. Poor performance in the

agriculture and real estate sectors also played a

major detrimental role in the banks’ loan portfolios. Many of these banks have pulled back

from the oil and gas loan market.

Although capital availability problems are widespread, they are not uniform in their intensity

across the industry. The small independent producers have the worst capital problems, with no

alternative sources of cash flow and profits and

greatly reduced access to the external capital

sources they had relied on; the larger integrated

companies have been buffered somewhat against

the effects of reduced production revenues by

increased profits from their downstream (e.g.,

refining) operations. Those larger integrated companies and independents that previously had

avoided large debt loads generally cannot (and

do not) claim that their E&D spending is capital

limited; they retain substantial internal resources

and/or access to outside capital. Although most

of these companies have reduced their E&D

budgets and activity levels, they presumably have

done so because of changed investment priorities.

Although the importance of the drop in cash

flow and withdrawal of outside capital to the

short-term investment behavior of the industry

is not in question, this is not the case with the

importance of these factors to the industry’s longterm behavior. There is disagreement among

analysts of the industry as to whether the cash

flow from previous investments or the profit

prospects for new investments will control the

industry’s future level of investment. I n the past,

industry investment levels appeared to be closely

tied to levels of cash flow. However, classical economic theory predicts that the volume of new investment should be more closely tied to the characteristics of the new investments. Past industry

financial losses and recently reported shifts in the

industry’s attitude about replacing company reserves—discussed in the section on industry restructuring—reinforce the view that the industry

is likely to base its future decisions about the magnitude of E&D investment primarily on a careful

evaluation of prospective profits.

Over a period of a few years, companies in a

weakened financial condition may go out of business; undeveloped and partially developed properties and equipment will be sold at low prices;

companies will merge and be restructured; problem loans will be renegotiated or written off; and

new financial entities will enter the industry if

good investment opportunities are available. In

this manner, the industry would be in position

to attract new E&D investment capital if costs are
13

low enough and E&D efficiency high enough to

create attractive E&D investment opportunities.

Losses in Oil Production From

“Stripper” Wells

There is widespread concern that low oil prices

will force many of the nation’s “stripper” oil

wells, wells whose production averages 10 barrels of oil per day or less (averaged over the lease),

to shut down. Once these wells shut down for

a year (or other period determined by State rules),

they must be “plugged,” i.e. sealed with concrete; most wiII never be returned to production,

and their reserves wiII be lost. This concern is

magnified by the importance of stripper wells to

U.S. supply. Over 400,000 stripper wells produced approximately 1.3 mmbd, 14 percent of

total domestic oil production, in 1985. These

wells are concentrated in Texas, Oklahoma, California, and Kansas, which together have threefourths of the Nation’s stripper production.

The probable loss of stripper production at

different price levels is highly uncertain because

of a scarcity of data about stripper well physical characteristics and production costs. Furthermore, the data that are available reflect historic

business practices and costs. Both stripper well

operators and the businesses that serve them

have been forced to make adjustments in response to the sharp drop in oil prices. Analyses

of stripper well production must account for recent declines in the cost of utilities, materials, and

services to operators as welI as changes in operating practices, such as deferring maintenance,

that affect both costs and production levels.

Two quantitative studies of lost stripper well

production have been conducted. A study sponsored by the Interstate Oil Compact Commission

(IOCC) estimates that, during the first year,

176,000 bbl/day of stripper production, 2 percent

of total U.S. crude oil production,8 would be lost

at $18/bbl oil prices, and 277,000 bbl/day or 3.1

percent 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 per8Based on average 1985 production of 8,9 mmbd.

cent of U.S. production, at $18/bbl oil prices, with

an additional 4,300 bbl/day loss in later years as

major repairs for the still-operating wells become

necessary; at $15/bbl, first year losses are estimated at 148,000 bbl/day, with later year losses

of 77,500 bbl/day for a total loss of 226,000

bbl/day or 2.5 percent of U.S. production. ElA’s

estimated first year losses are about half of the

IOCC’s estimates.

More recently, an IOCC survey of California,

Kansas, New Mexico, North Dakota, Oklahoma,

Texas, and Wyoming indicates that 110,000 wells

in these States, with 307,000 bbl/day of oil production, were shut in during 1986, with 12 percent of the wells permanently abandoned. These

values do not break out the production lost solely

because of low oil prices (each year, thousands

of wells are abandoned even at high oil prices),

and thus they are not strictly comparable to the

projections above. However, most of the production loss is likely to be attributable to the price

drop, and the survey appears to add credibility

to the (higher) IOCC projections.

The Nature of the Resource Base

The nature of the remaining U.S. oil resource

base will play a vital role in the response of U.S.

domestic oil supply to changing oil prices. There

is, however, substantial disagreement in the oil

industry about the physical nature of the remaining resources, about where future U.S. reserves will come from, and at what price.

A central issue in this resource base disagreement is the question of whether the major source

of new reserves will be the discovery of large new

oilfields, particularly in the frontier areas and

deep offshore, or whether it will instead be the

aggregation of many thousands of modest increments of reserves gained by drilling new wells

in old fields, improving recovery through enhanced oil recovery techniques, and exploring

for small fields in familiar producing territories.

These different views of the remaining resources

in the United States lead to different preferences

for policy initiatives (e.g., different degrees of importance attached to expanded leasing of new

frontier areas) and to different views of the oil

prices necessary for a revival of higher levels of

reserve replenishment. Frontier and deep off-
14

shore oil resources may, in many cases, require

prices in excess of $30/bbl for economic development, whereas a considerable portion of the

resources available from the smaller scale efforts

are viewed as available at prices between $15 and

$25/bbl.

The recent history of oil reserve additions generally supports the view that the aggregation of

many small reserve additions, especially from the

growth of discovered fields through extension

well drilling and other mechanisms, plays the

weightier role in overall U.S. reserve growth. For

example, about 70 percent of total U.S. reserve

additions during 1979 to 1984 came from drilling

in oilfields discovered before this period, and the

percentage of total reserves coming from this

source has increased from earlier decades. However, those who view the frontier areas as the critical source of new reserves believe that the intensive drilling of the last decade and a half has

already squeezed most of the reserve growth

available from our older fields, and that any remaining growth requires much higher prices than

before because the easy reserve targets were exploited first. Unfortunately for the advocates of

searching for giant fields, however, the record of

the past decade of oil exploration has not been

very promising, with successes in offshore California and the Gulf of Mexico perhaps more than

balanced by grave disappointments in the Gulf

of Alaska, Georges Bank, St. Georges Basin, and

elsewhere. Clear signs of this disappointment are

the very large reductions in recent industry and

government estimates of frontier resources,

Resolving the potential roles that continued

field growth and giant new fields may play in the

future development of the United States’ oil resources may not be possible at this time. Whatever the “correct” view of the resource base

turns out to be, however, both the search for

giant fields as well as the intensive pursuit of

small-scale reserve additions must be pursued

if the slide in U.S. production is to stand any

chance of being halted.

The Effects of the Natural Gas Surplus

The state of markets for natural gas is important to oil production. Much exploratory drilling

searches for hydrocarbons, not specifically for oil

or gas. Added incentives for finding gas wiII stimulate this type of “nondirectional” drilling and

lead to more oil resources being found and developed—and inadequate incentives will do the opposite. Also, because gas is present in nearly all

oil wells, the profitability of these wells depends

on having a market for the gas at a reasonable

price.

Since the early 1980s, a surge in deliverability

and declining demand in the electric utility and

heavy industry sectors have created a surplus of

natural gas deliverability. Low oil prices have

added to the gas surplus by promoting gas-to-oil

fuel switching. The gas surplus has, in turn, kept

gas prices low and kept some producers from

having an assured market for their production.

Although the reduced incentive for gas drilling

has tended to help keep drilling costs low, the

net effect on oiI driIling is almost certainIy negative. A tightening of gas markets in the next few

years, as predicted by many experts, would have

a positive effect on drilling in general and would

likely lead to increased oil well completions and

production capacity. However, uncertainties

about the volume of additional gas imports that

could be made available from Canada, the actual level of excess deliverability, the volume of

gas that could be quickly added to the deliverable base, and future changes in demand for gas

have lead to a substantial divergence of opinion about the timing of any end to the current

natural gas surplus.

Changes in the Oil Industry

Affecting Production

The Effects of Industry Restructuring

During the 1980s, the oil industry underwent

important changes that seem likely to affect the

industry’s exploration and development strategies and financial capabilities. These changes

have included a series of mergers, both voluntary and “hostile,” as well as internal restructuring measures such as asset redeployment, stockenhancement through stock buy backs, spinoff of

new companies, asset sales, elimination and consolidation of functions, and other measures.

While many of these changes are widely viewed

as destructive of the industry’s willingness and
capability to replace its reserves, some of the

same changes are defended either as strengthening industry’s reserve replacement capabilities

or simply as being necessary to allow the participating companies to survive.

During earlier debate over the effects of

mergers and acquisitions in the oil industry, many

of the representatives of acquiring companies,

their investment bankers, and their defenders

strongly denied that exploration efforts would be

reduced. Despite these assurances, mergers and

acquisitions have been widely viewed as destructive of the industry’s reserve replacement capability. Between 1979 and 1985, over $75 billion

was spent on oil industry acquisitions in excess

of $1 billion each, adding substantially to long

term debt and presumably lowering the capital

available for E&D spending. According to OTA’s

review of a group of companies, merged companies have spent substantially more of their

available cash flow on debt repayment and less

on oil and gas exploration than other companies.

The merged companies typically cut combined

capital spending significantly in 1984 to 1985,

while other large companies in the group were

more often maintaining or increasing their investments. In addition, a number of companies have

added substantial debt in the process of fighting

off attempted hostile mergers, or simply in preparing defenses against potential takeovers. Despite potential long-term benefits of mergers

such as improved management and improvements in the “fit” of assets and financial and

management capabilities, the available evidence

strongly suggests that the short-term effect of

mergers and attempted mergers on the oil industry’s investment in exploration and development has been negative on balance. Initial successes of some merged companies at reducing

debt loads may, however, signal that this balance could change.

A significant apparent change in industry behavior, more a cause of the restructuring than a

symptom of it, is a shift in emphasis among many

integrated companies away from maintaining a

secure domestic source of reserves to supply

their refining and marketing operations, and

away from the former high priority they gave

to recycling much of their production revenues

back into exploration and development. Companies are now said to be evaluating E&D investment as a separate profit center, requiring each

investment to meet stringent financial criteria.

These behavioral shifts are said to be the result

of both the financial losses incurred by many of

these companies in their past E&D investments,

and the easy availability of crude oil associated

with the expanded role of the spot market. If this

widely perceived behavioral change is real and

permanent, a return to previous levels of profit

potential in production investments may not

cause a return to previous levels of drilling and

reserve replacement. This has negative implications for the likelihood of a “rebound” in production following a price increase.

The Changing Business Climate Overseas

Industry experts consulted by OTA claim that

one cause of the current low level of domestic

investment in E&D is that the U.S. oil industry has

decided to shift its domestic/overseas balance of

E&D investments in favor of overseas investment.

In earlier years, many U.S. companies focused

on domestic E&D despite the relative “maturity”

of the United States’ oil resources and the better

geologic prospects overseas. They did this partly

because of the greater stability and security available within the United States, but also because

many oil-bearing countries offered relatively

demanding terms for development of their oil resources.

Although problems of stability and security remain, many countries have eased their terms for

oil development. They have removed former

caps on the prices paid to foreign developers,

eased currency restrictions, lowered taxes and

royalty rates, and otherwise improved the potential profitability of private oil and gas development. At the same time, industry spokesmen

have claimed the United States has enacted tax

and regulatory changes that worsen the business

climate for domestic oil and gas investment.

Evaluating the relative business climate for petroleum investments of the United States versus

competing foreign nations is complicated, and

OTA is not aware of a comprehensive attempt

at such an evaluation. Nevertheless, the attempts
16

by many nations to ease investment restrictions

and improve potential profitability in developing their oil resources clearly have increased the

attractiveness of overseas investment vis-a-vis

United States investment. In evaluating the effects of this increase, however, policy makers

should keep in mind that most analysts believe

that any increased oil supply outside of the Middle East will tend to enhance market competitiveness and stability whether it occurs inside

or outside of the United States—and that, dollar for dollar, overseas exploration investments

will tend to purchase considerably more oil reserves than will U.S. investments.

Changes in the Efficiency of Exploration

and Development Activity

An accurate projection of the reserves found

and production capability created by the sharply reduced levels of drilling and other oilfield

activity caused by low oil prices requires an accurate estimate of the “efficiency” of this activity, as measured by the footage and wells drilled

per rig, the reserves found per well, the wildcat I

success rate, and so forth. These measures have

proved to be sensitive to oil prices and oilfield

activity levels. For example, rig efficiency (footI age and wells drilled per rig per year), reserves

1 added per well or per foot drilled, and many

other measures of efficiency declined from the

middle 1970s to the early 1980s as oil prices rose

and oilfield activity accelerated. Part of this decline was due to the use of inexperienced personnel and marginal equipment, made possible

by the inability of the supply of services to keep

up with the demand. Another element of decline

was the spread of drilling activity to more marginal prospects with lower reserves and sometimes under more difficult physical conditions.

This was partly a result of the improved economics of these prospects and partly an effect of

resource depletion as the best prospects were

used up.

The decline in oil prices that began in 1981

forced the industry to become more efficient. For

example, drilling became more efficient as the

number of inexperienced drilling crews declined,

inefficient rigs were dropped from service, footage and turnkey contracts replaced contracts that

paid drillers by the day (day rate contracts offered

little incentive for efficiency), and drilling technology improved. These factors were important

causes of the sharp increase in rig efficiency

measured between 1981 and 1985. The industry drilled 89,000 wells in 1981 with nearly 4,000

rotary rigs active; 84,000 wells in 1982 with 3,100

rigs active; and 85,000 in 1984 with 2,400 rigs.

Unfortunately, however, the precise dimensions of the actual increase in efficiency are obscured by other factors that also affect measured

rig efficiency. These factors include:

●

●

●

the proportion of total drilling devoted to exploration, because exploratory drilling is

more time-consuming than development

drilling;

possible changes in the number of rigs that

are not included in the datag9

; and

shifts in the geographic distribution of drilling, because drilling in some areas, such as

the Gulf Coast, is more rapid than in others,

e.g., the Midcontinent and Rocky Mountain

Overthrust Belt, because of different rock

conditions and other physical factors.

Similarly, as the industry cuts budgets and

drilling rates and retreats from marginal areas

with high costs and low payoffs, measures such

as reserves added per well or per dollar invested

should improve. Consequently, reserve additions should not drop quite as precipitously as

drilling or drilling budgets have. This effect will

be tempered, however, by a likely shift in drilling

patterns away from deep, high risk exploratory

drilling (see the earlier discussion on the Economics of Drilling Prospects), and also toward

shallower and lower risk (but potentially lower

yielding) targets. Also, drilling patterns are affected by company lease positions and contractual obligations.

Figure 4 shows the regional variation in oil reserves added per well, illustrating the potential

effect of shifting the geographic distribution of

drilling.

Shifts in drilling during the early part of 1986

seemed to follow the expected pattern of retreating from regions with low average returns. If only

‘Commonly used rig counts include only so-called rotary drilllng

rigs, rigs that drill by rotating a drill bit and its attached drilling pipe.
Region
18

the regional shifts in drilling are considered, the

reserves added per average U.S. well in 1986

could be 37 percent higher than the 1981 to 1984

United States average.10

Although this estimate could be interpreted as

optimistic for U.S. oil supply, in fact it is sobering. Even if these reserve/well values are correct

—and they are almost certainly too high—they

still imply a substantial drop in U.S. oil production if recent drilling levels continue. For example, estimating Alaskan and stripper well production separately, if mid-1986 drilling levels

continue for the next decade and a half and

achieve the regionally adjusted (and optimistic)

values of reserves added per well, year 2000

United States production will still be 29 percent

below 1985 levels, or about 6.4 mmbd. Thus,

the United States cannot hope to slow the current decline in domestic oil production unless

it increases substantially its level of drilling

activity.

A reliable projection of future production rates

requires an accurate estimate of how the indusI

try will adapt its investment behavior to the new

I price environment. Since this adaptation should

, take a few years, current drilling patterns should I

not be viewed as permanent. At this time, a projection of likely adaptive behavior, and its likely

I effect on reserves/well values and other measures

of E&D efficiency, will clearly be speculative.

Insight on the potential for adapting to low

prices might be gained by analyzing the differences among individual oil companies’ historical investment patterns, management styles, and

investment outcomes. Some companies, such as

Shell Oil, have had consistently low finding costs

over the past decade or more. If the more successful companies have simply occupied low cost

“niches” in domestic E&D, their success may not

offer much room for hope that the rest of the industry could, with appropriate changes in investment behavior, successfully match their cost performance. On the other hand, if their success is

owed primarily to behavior that could be copied

by the rest of the industry, the long-range outlook for production might look considerably

better.

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 of

existing resources at lower cost, clearly is an important factor in the ability of the industry to keep

reserve replacement and production close to

historic levels in the face of low oil prices. In general, however, the majority of the operators and

analysts we talked with were skeptical of the potential for both new technology and improvements in existing technology to allow access to

significant volumes of oil that currently are uneconomical at prices below $20/bbl. In support

of this view, statistics of important measures of

exploration and development efficiency-such as

reserves added per well drilled and exploration

success rates—have either held steady or deteriorated over the past decade despite the introduction of such technologies as three dimensional

seismic analysis, seismic interpretation with personal computers, advanced reservoir modeling,

and an array of others. If technology development has made a difference during the past decade, especially in the onshore lower 48 States,

it appears to have been primarily one of counterbalancing the negative effects of continuing

resource depletion.

Nevertheless, there is a significant minority in

the industry who have a far more positive view

of the potential of improved oilfield technology.

They can point to a number of new technologies

just being deployed, or on the immediate horizon, that have promise for lowering industry costs

enough to either allow development of additional

resources at current low prices, or at least to allow added resource recovery at prices significantly lower than previously thought possible,

often in the lower $20/bbl range. These technologies include:

●

●

●

important improvements in the resolution

capability and cost of seismic imagery;

new developments in chemical enhanced recovery that lower the price threshold from

$25 to $30/bbl to about $20/bbl; and

improvements in horizontal drilling that offer the potential of expanding a field’s recoverable reserves by allowing operators to exploit thinner pay zones.
19

Even if industry optimists are correct, the potential of new technology will not be realized

without a significant R&D effort on the part of the

industry. Although precise figures are not available, industry observers agree that industry R&D

expenditures are down by at least 30 or 40 percent over the past 3 years. Although some cutbacks clearly are appropriate (e.g., for efforts

aimed at accessing very high-cost resources in difficult environments that are not now technically

recoverable) the overall size of the cutbacks and

a general shift away from long term research targets are of substantial concern.

Effects of a Deteriorating

Industry Infrastructure

The large drop in industry activity levels accompanying the price drop has meant a shrinking of

the industry’s “in frastructure,” that is, the inventory of rigs and other equipment used in exploration and development activity, the manufacturing capacity to produce the equipment, and the

people to man the equipment and plan and supervise its use. The industry has expressed the

concern that, in the event of an oil price rise or

other incentive for a “rebound” in activity levels,

the lack of infrastructure would mean severe delays, inefficiency, and cost inflation as too much

demand for oilfield goods and services chases too

little supply–a repeat of the hyperinflation in

these goods and services that marked the middle to late 1970s and early 1980s.

Any rapid improvement in E&D investment

prospects, fueling increased demand for oilfield

goods and services, will create delays and inflationary pressure, but increasing effective oilfield activity should be less difficult and inflationary than it was in the 1970s. One reason for

this conclusion is that the level of activity of the

earlier drilling “boom” was much higher than

was justified by the results, primarily because

drilling rigs were operated inefficiently, inadequate equipment was used, and many wells were

drilled with minimal prospects for success. Thus,

it is not necessary to return to 1981 levels of active rigs or employment to achieve 1981 levels

of reserve additions and added production capacity. Another reason is that most oilfield equipment is relatively sturdy and will not deteriorate

excessively if moderate precautions are taken i n

storage. Finally, in recent years there has been

an oversupply of trained workers and professionals in the industry, and there is little reason to

believe that most of these have been irrevocably lost to other fields. A 2,500 rig fleet, operating efficiently, probably can achieve the same

results as a 4,000 rig fleet did in 1981. For now

and for at least another few years, there should

be adequate equipment and personnel to assemble and operate such a fleet relatively quickly

—perhaps within 6 months to a year. However,

this conclusion presupposes that a rebound in

oilfield activity levels will be accompanied by

investor and industry confidence that the rebound will not be short-lived, so that contractors will be willing to invest in refurbishing rigs,

laid off workers will be willing to return, etc.

This is not necessarily a foregone conclusion

given the “lesson” administered by the recent

price drop. Also, the capability for a rebound

will decline over time.

Policy makers should recognize that OTA’s

guarded optimism about the ability of industry

infrastructure to support a rebound in activity is

not shared either by the National Petroleum

Council or the Department of Energy. Their respective reports, Factors Affecting U.S. Oil and

Gas Outlook and Energy Security, both identify

the destruction of the industry’s infrastructure as

a key roadblock to a drilling recovery.

Resisting a Decline in U.S. Oil

Production: Should Government

Play an Active Role?

For reasons encompassing both national security and U.S. economic competitiveness, many

energy analysts and significant segments of the

oil industry (especially the independent producers) are arguing that the Federal Government

should intervene to halt or ameliorate the expected decline in U.S. oil production.

The policy preferences of Federal policy makers

are likely to depend on how they would answer

the following two questions:

1. Will declining domestic oil production seriously damage U.S. economic and national

security interests? and
20

2. Can Federal intervention succeed at stabilizing domestic crude oil production without

incurring unacceptably high costs (in terms

of direct consumer spending, Federal budget impacts, or market distortions)?

Properly addressing both of these questions requires a comprehensive examination of U.S. and

world energy supply and demand, not merely an

examination of domestic oil production. For example, the shift in oil trade away from long term

contracts to the spot market has served to make

the world oil market more unified. With the

present market structure, new discoveries and

production capabilities anywhere in the world–

and especially outside of the Middle Eastern

OPEC nations–contribute to market stability and

thus to U.S. economic and national security interests, Similarly, the ability of energy consumers

I to switch to other fuels, improve their efficiency

of energy use, or even shift the basic structure

i of their economies will affect their reliance on I oil. Consequently, an evaluation of United States

t crude oil production can provide only a piece

of a larger puzzle, albeit an important piece. In

the following discussion, we address the above

questions in the limited fashion allowed by the

bounds of our analysis.

Will Declining Domestic Oil Production

Seriously Damage U.S. Economic and

National Security Interests?

If imports provide the least expensive source

of oil, should we care if U.S. domestic oil production decreases and import dependence rises?

Are the potential damages from rising import dependence large enough to justify the costs to the

U.S. economy of subsidizing domestic oil production or taking other measures to restrain import

levels? This question forms the core of a serious

policy dispute. Unfortunately for policy makers,

there are a number of substantive opposing arguments as well as significant uncertainties about

this issue.

Advocates of oil import fees and other measures designed to forestall added U.S. dependence

on oil imports believe that both economic and

national security interests justify the costs of such

measures. They note that the drop in oil industry investment has hurt significant sectors of the

national economy as well as the economies of

oil-producing States such as Texas, Oklahoma,

and Louisiana, and that expanded imports hurt

the U.S. trade balance. Perhaps most important

from an economic standpoint, they believe that

expected increases in oil demand and decreases

in non-OPEC oil production capacity will soon

return market control to OPEC and thus restore

the potential for future price shocks and accompanying economic disruption. As for national

security, the industry points to the strategic importance of oil to the United States, both for itself and even more for its allies, and the likelihood

that increased import dependence will translate

into an increased vulnerability to future oil disruptions.

These arguments must be balanced against the

potential negative impacts an import fee or the

like would have on the U.S. economy, as well

as arguments that the national security implications of rising oil imports have been tempered

substantially by economic and physical changes

that have occurred since the earlier price shocks.

The negative economic effects of an import fee

are viewed as including an increase in the rate

of inflation, a decline in gross national product

resulting from reduced discretionary income, and

a decline in trade competitiveness among the

United States’ energy-intensive industries (e.g.,

chemical products). Balancing negative and positive impacts requires extensive, sophisticated economic analysis, with the best analyses yielding

results that will still be highly sensitive to arguable input assumptions.

Changes in oil markets and the U.S. economic

structure that have occurred since the early

1970s, combined with certain insurance measures such as the Strategic Petroleum Reserve,

have likely made the United States less vulnerable than previously to future oil price shocks and

supply disruptions. For example, the growth of

a large spot market in crude oil has made embargoes extremely difficult to enforce and should

act to curb the “inventory panic” that in the past

served to escalate prices rapidly at the first signs

of a shortage. Other positive changes include:

● the U.S. decontrol of oil prices, which allows

a more rapid market adjustment to changes

in oil supply and prices;
21

●

●

●

the increase in diversification of producing

countries, which adds stability to world

supply;

the increase in oil stocks held by Japan, West

Germany, and other U.S. allies; and

the growth of natural gas supplies throughout the world, which allows for substantial

fuel-switching capability in industrial and

electric utility markets.

Although these improvements in the U.S. strategic situation do not imply that growing oil import levels represent no threat, they do imply that

comparisons with earlier years must be viewed

cautiously.

To keep these arguments in perspective, it is

important to understand where U.S. oil production was heading before prices dropped so

precipitously. Even before the sharp 1986 declines in world oil prices, most energy analysts

were predicting a future of declining domestic

oil production and increasing imports. For example, one so-called “consensus view” of future

U.S. production under previous price expectations (prices in the mid to low $20s/bbl for a few

years and a gradual increase thereafter) had U.S.

production declining from about 8.9 mmbd in

1985 to below 7 mmbd by 1995 and below 6

mmbd by 2000. Therefore, the recent price drop

might be said to have advanced by 5 or 10 years

a process of declining U.S. production that most

industry analysts believe would have occurred

anyway because of the maturity, and thus declining prospects, of the U.S. resource base.

Not all analysts would agree with this view. A

minority of oil analysts believe that U.S. production could have been maintained at stable levels

for another few decades had oil prices held up

and had the industry expanded its efforts to attain increased recovery from its older fields. This

more positive view is based on an optimistic

assessment of the remaining oil resources that can

be recovered by more intensive drilling as well

as by enhanced recovery. If correct, this view implies that the “cost” of the price drop to the

United States, in terms of lost domestic production capacity, could be considerably greater than

implied by the more pessimistic pre-price drop

production forecasts.

Policies To Bolster U.S. Oil Production

Advocates of government action to slow the

decline in U.S. oil production have suggested a

variety of potential solutions, Most involve substantial present or future costs; all of these are

opposed by powerful constituencies.

OTA has not undertaken the kind of comprehensive evaluation that policy makers must have

before deciding on a specific course of action.

Although the results of OTA’s study offer a number of insights about the effectiveness of specific

policies, we were not able to measure the actual

effects on oil production of the policies nor their

net social costs.

1. Oil Import Fees.–Oil import fees may be

structured either as a constant dolIar addition to

the prevailing price of imports or as a sliding fee

designed to raise import prices to a predetermined value (e.g. $25/bbl). An interesting alternative is a price floor, deliberately set below

prices prevailing at the time of enaction, designed

to guard against future price drops and thus to

ease the downside risk of new production investments.

To the extent that an import fee raises domestic oil prices higher than prices that would have

occurred without it,11 it will raise industry revenues and improve the prospective profitability of

new production investments. This in turn will ensure that oil investment and production will also

be higher than without the fee, at least for a considerable period. For example, OTA’s economic

analyses show that for the small scale development and exploratory drilling prospects examined, increasing oil prices from $1s to $20/bbl

raised expected rates of return to the levels expected in 1981,12 when oilfield activity was at

a peak. Such an increase in expected profitability would be bound to stimulate new oil investment. However, policy makers must be con1 I Over the long term, an import fee might help to hold down

world oil prices by reducing the demand for Imports and thus reducing OPEC market dominance. It is therefore quite conceivable

that the net domestic oil price could eventually be lower than it

would 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 the

price rise was not so large as to use up much of the current surplus of drilling capacity.
cerned about the cost to consumers of higher oil

prices, both directly and as a result of higher manufacturing costs, and the effects of such higher

costs 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, policymakers cannot predict with a high degree of

confidence how much additional production

will be “purchased” with an import fee. There

is little agreement in the industry as to what oil

price would be necessary to stabilize production—or whether it is even possible to do so.

Based on OTA’s conversations with industry

planners, the sharply perceived threat of future

plunges in oil prices plays an important role in

industry reluctance to invest, especially for longer

term projects. If this is so, the institution of a

provisional tax designed to establish a price floor

below current price levels–possibly at $15/bbl

—could also boost investment at no immediate

cost to consumers. OTA’s economic analyses reveal some of the potential of such a price floor.

For small-scale development and exploratory

drilling, using a $10/bbl “hurdle price” to guard

against future price risk transforms an attractive prospect at $15/bbl—with a projected real

(before tax) rate of return of over 15 percent—

into an outright loser. Thus, for investors who

feared future price drops, a price floor could

provide the assurance necessary to proceed with

drilling.

The perceived attractiveness of a price floor depends in large measure on the policy maker’s expectations for future oil prices. If he expects prices

to stay above $15/bbl at most times, with occasional brief declines below this price, a $15 price

floor looks particularly attractive because it reduces risk at a low cost. On the other hand, if

he envisions prices plunging below the floor price

for extended periods, the consumer cost and balance of trade questions may become paramount.

2. Tax Concessions.—OTA examined the effects of several tax changes on the expected profitabiIity of small-scale driIling. These changes included reinstituting investment tax credits (of 20

percent), allowing a 27.5-percent depletion allowance for all producers, cutting severance and

ad valorem taxes in half and to zero, and instituting a 20-percent drilling credit. For the smallscale drilling examined, lower State taxes and

additional tax credits for Federal income taxes

improved the prospective profitability of new

investments, with a 20-percent drilling credit

and a higher depletion allowance having the

greatest effect. However, none of these measures achieved nearly as much of an increase in

profitability as a $6/bbl increase in oil prices.13

For example, for the development wells examined, cutting severance taxes in half added

about 2 percentage points to the real after tax

rate of return, whereas adding $6/bbl to the oil

price increased the return by between 12 and

17 percentage points.

Industry spokespersons have claimed that the

new tax code will hurt the industry’s investment

capability. An examination of this claim is beyond

the scope of this study. However, OTA did examine the effect of the new code on the profit

expectations for a series of small scale exploration programs. Contrary to OTA’s expectations,

the calculated after tax return on investment

from a number of small exploratory drilling programs was slightly higher under the new tax

code than under the old. For these cases, the

benefits of the lower tax rates in the new code

outweighed the loss of the investment tax credit.

Were company profits low or nonexistent, however, the lower tax rates would have little value

and the loss of the investment credit would have

been the primary factor. The alternative minimum

tax in the new code, not accounted for here, may

also affect the balance of the old and new codes.

The industry has been united in its advocacy

of repeal of the Windfall Profits Tax (WPT), which

was originally enacted to prevent domestic producers from obtaining a financial windfall from

the decontrol of domestic oil prices. Although the

tax is not collected at today’s lower oil prices,

it represents both an administrative burden to the

industry and a disincentive to E&D investment,

especially for projects with delayed production

starts and for investors who expect oil prices to

rise significantly during the production lifetime

13The reader is reminded that a fair comparison of alternative POlicy measures requires an estimate of costs as well as results. Ideally,

policies should be judged based on a measure of (production

gained) /(cost).
23

of the project. The magnitude of the investment

incentive represented by WPT repeal depends on

the price expectations of the oil companies; given

the wide range of announced price forecasts and

the current turmoil in the market, estimates of

the oil production potentially added by repeal

wiII be especialIy uncertain,

3. Removing the Ban on Oil Exports From the

United States.– Federal law currently prohibits

the export of Alaskan North Slope crude oil from

the United States. The effect is primarily to force

the shipment of Alaskan crude oil via high-cost

domestic tankers to a saturated west coast market or all the way to gulf coast or east coast markets. Were Alaskan oil to be shipped via lowest

cost tankers to Pacific markets, the reduced shipping costs would yield a significantly higher net

back price to the producer; additionally, reduced

pressure on west coast markets would likely raise

producer prices there as well. The Minerals Management Service has estimated the prospective

increase in Alaskan wellhead prices resulting

from an end to the export ban to be $2 to $3/

bbl; others have estimated the increase to be as

high as $4 or $5/bbl. Even at the lower end of

the range, the price differential represents a significant percentage of current well head prices,

because these are kept well below world oil price

levels by the Trans-Alaskan pipeline fee (about

$6/bbl) and other shipping and tax costs.

4. Bolstering Investment in R&D.—Improving

the technology of exploration, development, and

production is an important means by which the

oiI industry can minimize the negative effects on

oil production associated with continuing low

prices. As noted earlier, however, the industry

has been cutting back on R&D in line with its decreasing oil and gas revenues. In particular, the

oilfield service sector has played a major role in

previous industry R&D, yet has absorbed the

brunt of financial damage associated with the

price drop.

Research and technology development that

could help the industry stem the production slide

at low prices include:

. improved understanding of the potential for

adding new reserves in older fields from conventional drilling;

improvement in enhanced oil recovery technologies, and better understanding of how

to apply them to a wide variety of geologic

situations;

improvement in the resolution and cost of

seismic analyses, to allow the wider use of

pre-drilling geologic analysis, to reduce dry

hole risk, and to allow better placement for

development wells; and

further development of offshore production

technologies that negate or moderate the requirement for giant production platforms.

The first three research areas might be included

in a more general program aimed at improving

the state-of-the-art in petroleum geosciences (i.e.,

improving our understanding of where the oil is

in a reservoir, how it moves, and how it can be

recovered).

Policies to bolster R&D appear especially attractive because they are an order-of-magnitude less

expensive than direct economic incentives for

increased production. However, policy makers

must recognize that most industry planners believe that technological change can play only a

modest role in stopping a production slide in the

face of continuing low prices. Also, designing a

policy measure that will provide an efficient incentive to promote effective R&D is not likely to

be easy, with particular problems being industry fears about losing proprietary advantages, the

potential for government direction to be out of

touch with industry requirements, and the difficulty of restricting the benefits of incentive programs to the primary R&D objectives.

Suggested policies for bolstering R&D include:

government sponsorship of industry/university cooperative projects,

allowing intra-industry cooperative projects

by granting anti-trust exemptions,

direct government assistance in the form of

grants and contract awards,

government-directed research projects, and

tax incentives.

5. Removing Leasing Restrictions on Frontier/

Offshore Areas.–Industry groups have long

urged the Federal Government to open up a variety of publicly owned properties to oil explora-
24

tion and development as a means of bolstering

domestic oil reserves and production capacity.

This recommendation has become more urgent

in light of the recent oil price drop and its projected negative impact on domestic production.

Two of the primary target areas are the California offshore basins and the Arctic National Wildlife Refuge (ANWR); both have potential recoverable oil resources of a few billion barrels. Both

of these areas have been held from leasing because of environmental objections. For California, the primary objections involve the potential

effects of spills on vulnerable ecosystems and

high-value recreational areas and the air quality

problems associated with production, transportation, and other ancillary facilities associated

with development. For ANWR, the primary objection is the potential danger to the Porcupine

Caribou herd and to other important species, and

the loss of the area’s wilderness character.

Arguments about opening these areas to oil exploration and development center about three

types of questions:

1. Are the estimates of environmental impacts

accurate?

2.

3.

Will development of the areas really make

a difference in the United States’ long-term

strategic position vis-a-vis energy supply?

Which are more important, the environmental values that would be preserved by

foregoing development or the energy supplies that would be made available? IS it possible to have development while protecting

most of the environmental values.

These questions have been extensively aired

in the media and in reports and congressional testimony, and there is little OTA can add at this

time. One point worth making, however, is that

volumes of oil obtained from these areas should

be compared to rates of domestic oil production,

and not to total U.S. energy consumption, as is

sometimes done to illustrate the supposed insignificance of the resource. By the time areas such

as ANWR could be developed—not much before

2000–oil will be even less interchangeable with

alternative fuels than it is now, assuming the share

of oil used for transportation fuel or chemical

feedstocks continues to grow.
Chapter 1

Introduction

The Origins of Today’s Low Oil Prices

In December 1985, the Kingdom of Saudi Arabia reversed its oil market strategy. During the

first half of the 1980s it had been serving as the

“balance wheel” of the world oil market, raising or cutting back its oil production rate to restrain or shore up prices as necessary, thus maintaining a precarious balance between world oil

demand and production capacity. During this

time, however, powerful economic forces were

eroding its position. The stimuIus to oiI exploration and development provided by the price

boosts of 1973 and 1979 had led to large increases in non-OPEC oil production. From a production rate of 25.6 million barrels per day

(mmbd) in 1974, non-OPEC production rose to

37.2 mmbd in 1985.1 Simultaneously, the higher

prices were encouraging investments in energy

efficiency; behavioral changes leading to reduced

oil use; and fuel switching from oil to coal, natural gas, and other energy sources. Consequently,

despite a worldwide rise in economic output of

15 percent between 1979 and 1985, worldwide

oil consumption declined by nearly 6 mmbd,2 or

9 percent, during the same period.

World oil prices continued for a time on an upward path despite these trends, largely due to the

OPEC countries’–and particularly the Saudis’–

willingness to cut their production rates to reduce

the downward pressure on prices. Between 1979

and 1985, OPEC production was cut in half, and

its oil revenues declined from $285 billion (1985$)

in 1980 to $131 billion in 1985. The Saudis, having the largest oil reserves and production capacity in OPEC, and having a relatively small population (and thus relatively lower revenue needs),

absorbed the brunt of these declines, allowing

their production to drop from nearly 10 mmbd

during 1979-81 to 2 mmbd during the third quarter of 1985. Finally, however, faced with expec1 Arthu r Andersen & Co, and Cambridge Energy Research Associates, Wor/d 0// Trends: A 5tatlstica/ Profile, 1986-87 ed., tables

6 and 10. Excluding natural gas Iiqulds.

‘1 bid,

tations of still further production cuts and the unacceptable prospect of a rapid drawdown of their

capital reserves, they announced their intention

to recapture a fair market share, doubled their

production rate, and instituted a series of contractual offerings to oil buyers that gave Saudi oil

a competitive advantage in the market.

The immediate result was a sharp drop in oil

prices as competing oil producers scrambled to

maintain their own market shares. Within 4

months, the average price of oil had been cut in

half, from approximately $28/bbl in December

of 1985 to $14bbl in April of 1986. From there

the price has fluctuated, dropping below $10 in

July and rising to about $15 in September and

$18 by the end of the year. And although there

is no consensus as to how prices will behave in

the short term, there is almost a universal expectation that oil prices for the next few decades will

be significantly lower than the prices projected

prior to the Saudi action.

Effects on the Oil Industry

The consequences of the price drop have reverberated through the world economy: the economies of principal oil exporting nations have generally suffered because of sharply reduced oil

revenues, while oil importing nations are enjoying the equivalent of a large tax cut. The prices

of competing energy sources have been forced

downward to compete with newly cheap oil,

while production costs of energy-intensive goods

and services have dropped. Producers of highcost oil—and particularly producers in the United

States–now face prices that in many cases do not

cover replacement costs for their oil, and in some

cases do not even cover operating costs. For

these producers, the price drop has brought massive economic disruption and the prospects for

substantial production declines. I n addition, the

lower oil prices also appear likely to boost domestic oil consumption. These expected production and consumption trends will result in increased U.S. dependency on foreign oil, and

25
26

possibly increased vulnerability to future oil

cutoffs.

Although estimates of the timing and extent of

the expected drop in U.S. crude oils3production

differ, a mean value for the expected size of the

drop would likely be about 2 mmbd by 1990

(from a base of 8.9 mmbd in 1985) if prices average about $15/bbl. This reduction wouId be the

cumulative effect of several forces. First, marginal

producing wells with high production costs will

be shut in either because revenues are too low

to pay for daily operating costs, or because the

wells require expensive “workovers” that no

longer appear attractive at the low prices. Of primary concern here are the several hundred thousand “stripper wells, ” wells producing 10 barrels per day (bbl/day) or less, that currently

account for about 15 percent of U.S. oil production. Second, plans for many of the secondary

and tertiary recovery operations that partially

compensate for normal production declines in

older fields will be canceled and, in a few cases

where operating costs are high, existing operations will be shut down. Third, fewer development wells will be drilled; these wells also help

maintain field production despite normal production declines in existing wells. Fourth, a slowdown in exploration will depress the inventory

of newly discovered fields, and the development

prospects associated with those fields, further depressing development well drilling in the future.

And fifth, reductions in R&D expenditures will

slow the development of new technologies and

the acquisition of new knowledge that in the past

helped the industry to increase oil recovery and

find new sources of oil.

This process appears to have begun. Average

U.S. crude oil production during 1986 was 3.3

percent, or 297,000 bbl/day, below 1985 production, while oil products supplied to consumers

rose 2.7 percent, or 423,000 bbl/day. Net imports

have risen by 24 percent or 1,007,000 bbl/day

3

That is, crude plus natural gas IIquids recovered in the field, called

lease condensate. This is generally what is being referred to when

the terms “crude oil” or “oil” production are used. “Total liquids”

or “petroleum” production includes, in addition, natural gas liquids recovered from gas processing plants, refinery processing gain,

and alcohols.

over the same period.4 Also, on a monthly basis, production has dropped even more: from December 1985 to December 1986, U.S. crude oil

production dropped by 670,000 bbl/day, or over

7 percents

Although the early 1980s was a boom period

in oiI drilling, exploratory drilling and other exploration activity peaked as early as 1981 and declined rather steadily through 1985, and total oil

well completions began to slide in 1985 and

dropped precipitously in 1986. Although many

analysts view the earlier drops in activity as a necessary correction after a drilling boom, most view

the 1986 drop as a virtual dismantling of two important segments of the domestic oil industry, the

independent producers and the well service companies, that will greatly harm prospects for U.S.

domestic oil production.

Among the activity declines are the following:

●

●

●

●

●

seismic crew count dropped by four-fifths

from its September 1981 peak to September

1986;

overall industry employment dropped from

a 1982 high of 708,000 to 422,000 in September of 1986; oilfield service company

employment absorbed four-fifths of the drop,

going from 435,000 to 206,000 during the

same period;

unemployment of senior petroleum geologists is 25 percent according to a recent

American Association of Petroleum Geologists poll;

drilling rig counts and utilization rates fell

from 3,970 and 79 percent in 1981 to 3,105

and 55 percent in 1982, to 1,976 and 45 percent in 1985, to about 700 and 20 percent

in mid-1986—rig count has since rebounded

slightly;

we// completions, which peaked at about

89,000 in 1981 and were still at 73,000 in

1985, slid to slightly below 40,000 in 1986;6

and

4Energy Information Administration, Week/y Petro/eurn Status Repoti, 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 lnstltute, Quarterly Completion Report, First Quarter 1987. ”
27

● exploration/production capital spending has

slid from about $50 billion in both 1981 and

1982 to $33 billion in 1985 and then to $16

billion in 1986. 7

To an extent, this drop in domestic oil production and industry activity levels is reminiscent of

the production decline and drop in drilling that

occurred in the early to middle 1970s. As show

in figure 5, U.S. crude oil production had been

climbing steadily for decades before the 1970s,

and peaked at about 9.6 mmbd in 1970. Production then began a decline that lasted until 1976.

in that year, however, the downward trend was

arrested by a combination of a surge in drilling

activity that slowed and eventually stopped the

decline in production the Lower 48 States, and

the onset of production from Prudhoe Bay in

Alaska. Prudhoe Bay production eventually reached

1.8 mmbd, almost 20 percent of U.S. oil production, by 1985. Had the 1970-76 rate of decline

continued without abatement, lower 48 production would have been 1.7 mmbd lower in 1985

than it actually was; without Alaska as well, U.S.

production would have been 3.5 mmbd—more

than a third–lower in 1985 (assuming that the

effort expended in developing and producing

Alaskan oil would not have been transferred elsewhere). Many in the oil industry point to the “rescue” of U.S. oil production by a combination of

intensive driIling and the opening of new “frontier” production as a warning for the future if

activity levels do not recover and new frontier

areas are not opened for exploration and development.

Congressional Concerns

Congress has two basic reasons to be concerned about low oil prices. First, the reduced

prices have important implications for the entire

U.S. economy. Some of the implications are

clearly positive, at least in the short term—the reductions in energy costs to both consumers and

industry, and the expected economic stimulus

provided by these reductions. Some, however,

are sharply negative—the severe reductions in

7Arth u r Andersen & Co. and Cambridge Energy Research Associates, World Oil Trends: A Statistical Profile, 1986-87 ed.; and Oil

and 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 reserves

held by energy producers, the resulting drop in

investments in exploration and development, and

the subsequent loss of business suffered by industries servicing the producers; the damage to

the U.S. banking industry caused by the widespread company failures and loan defaults; the

potential loss of business suffered by industries

supplying products and services that are marketed primarily for their energy-conserving features; and the unemployment, loss of tax receipts,

and other negative effects flowing from these

problems, largely concentrated in a few key oilproducing States such as Texas, Louisiana, and

Oklahoma.

Second, to the extent that the projections of

reduced domestic oil production and increased

oil demand are correct and the United States is

forced to resume high levels of oil imports from

politically insecure sources, the current lower

prices may represent a potential threat to the

United States’ national security as well as to its

future economic health. Congress clearly viewed

the high levels of oil imports of the 1970s as just

such a threat, and responded with extensive legislation including programs to promote synfuels

development, tax incentives for energy conservation and alternative energy sources, an extensive energy R&D program, and the establishment

of the Strategic Petroleum Reserve (SPR). I n addition, funds were appropriated to establish military forces specifically designed to deal with

threats far from established U.S. military bases,

and in particular the Middle Eastern oilfields.
28

Industry advocates of strong congressional

measures to fight the increases in U.S. oil imports

projected to result from low oil prices have portrayed these potential increases in precisely the

same manner, i.e., as a serious threat to the

United States’ security and long-term economic

interests. in responding to this advocacy, however, Congress must weigh the differences between the U.S. energy situation in the 1970s and

the situation today,

First, the United States now has an SPR containing approximately 500 million barrels of crude

oil, the equivalent of about 100 days of oil imports at current levels. Similarly, Europe and Japan have also added to their strategic storage,

although not to the same extent as the United

States.

Second, world oil production has become substantially more diversified since the 1970s, with

OPEC’s share of the world oil market declining

from 60 percent in 1979 to approximately 35 percent today, For several years, at least, no single

country or cohesive group of countries can control as large a share of the world market as was

possible previously. Eventually, however, if oil

prices remain below $20/bbl, OPEC may regain

its previous market share.

Third, a considerable portion of any increase

in oil consumption both in the United States and

in the remainder of the Free World will be reversible. For example, much of increased oil use

in transportation will involve changes in consumer behavior, such as increased driving, that

would be quickly reversed in case of an oil shortage or large price increase. I n the industrial sector, the shifts to oil for a boiler fuel can be rapidly reversed with a shift back to coal or natural

gas. Similarly, in the electric utility sector, a substantial portion of any increased oil use is likely

to involve the use of existing oil-fired generating

capacity—removed from baseline service when

oil prices rose in the 1970s—at the expense of

coal, gas, or even nuclear plants. As long as the

industry retains excess generating capacity, this

use can be readily reversed,

A threat to reversibility is the potential for inadequate supplies of natural gas resulting from

the same drilling slowdown acting to reduce oil

production. This potential is a realistic possibility only in the United States. There is considerable controversy about U.S. gas supply adequacy

for the future. Some analysts are projecting an

imminent market tightening within just a few

years if gas prices stay low, followed by supply

problems as domestic production capability continues to decline. Others claim, however, that

such a shortage is extremely unlikely, because

additional large volumes of gas can be made

available rapidly if markets tighten, by increasing import levels and by developing reserves now

kept out of the market by low demand.

Fourth, the United States and its allies have

undergone two major price shocks in the recent

past, and this additional experience, as well as

a series of international agreements on oil sharing, may assist them in a future supply crisis.

Many oil experts are skeptical about the usefulness of these agreements, however.

Fifth, U.S. oil prices are no longer controlled

as they were during the 1970s. In the event of

a new price increase, the market forces that act

to reduce demand and increase supply will be

felt in full (assuming price controls are not

resumed).

Sixth, most of the world’s oil trade now operates on the spot market, in contrast to the longterm contracts of the 1970s. Coupled with an active futures market, this new oil trading situation

makes single country embargoes, which could

never be airtight even in the past, still less of a

threat.

These mostly positive changes in the world oil

market do not negate arguments that United

States security can be threatened by an increase

in oil imports, but they clearly lessen the overall

risk and should be carefully considered in any

policy debate.

The OTA Study

In April, 1986, the Chairmen of the Committee on Government Operations, the Committee

on Energy and Commerce, and the Subcommittee on Fossil and Synthetic Fuels of the U.S.

House of Representatives asked the Office of

Technology Assessment to assess “the effect of
29

volatile oil prices on short- and long-term domestic oil production . . . (including) an examination

of changes in the industry that have already occurred . , . and an evaluation of the significance

of these changes to domestic production.” 8

OTA’s approach to this assessment explicitly

acknowledges the high degree of uncertainty

associated with attempting to project future domestic oil production. One cause of this uncertainty is that much of the data on the exploration and development opportunities available to

the industry—a crucial determinant of its future

behavior and thus of future production potential

—is held closely by the individual oil companies.

Another cause is that most of the projections

available to the public are based on extrapolations from past experience . . . but there has not

been a rapid decline in oil prices within the past

several decades. It seems reasonable to question

whether the statistical record, amassed during a

period of escalating prices, is sufficient to forecast the future actions of the oil industry and the

likely effects on production of these actions.

Consequently, OTA has not tried to produce

yet another forecast based on extrapolation. ln-

‘Letter of Apr. 17, 1986, Jack Brooks, Chairman, Comm Ittee on

Government Operations, U.S. House of Representatives, to Dr. John

H. Gibbons, Director, OttIce of Technology Assessment.

stead, we have exam ined and attempted to gain

an understanding of an array of factors that will

influence future production, with the dual goals

of, first, determining how production outcomes

may differ from those predicted by extrapolating

from past experience, and second, determining

how government action might influence future

production rates. The factors we examined

include:

●

●

●

●

●

●

●

changes in industry business strategies and

capabilities associated with the restructuring

the industry has undergone;

the profit potential of the array of exploration, development, and production prospects available to the industry;

the physical nature of the oil resource base;

changes in the climate for oiI and gas investment overseas;

the deterioration of the industry’s service

sector;

the surplus of natural gas deliverability; and

changes in exploration and development

technology.

While OTA could not comprehensively analyze

each of these factors and reliably determine their

exact effects on future production, it is hoped

hope that this study will contribute significantly

to Congress’ understanding of—and ability to respond to—the evolving domestic oil supply situation.
Chapter 2

Projections of U.S. Crude Oil Production

Introduction

projections of future United States crude oil

production are made by a variety of oil companies and associations, consulting firms, government agencies, and individuals. Although several

projections are published on a regular schedule

(i.e., those of the Gas Research institute, the

Energy Information Administration, Data Resources Inc., Chevron, Conoco, etc.), many appear only at crisis points or in response to proposed government initiatives affecting oil supply.

Documentation of the projections is often incomplete or nonexistent, although the projections of

the Energy Information Administration, the Gas

Research Institute, and Data Resources Inc. are

extensively documented.

OTA examined and cataloged the results of

a number of projections of future crude oil supply published either in 1985, prior to the price

drop, or well enough after the price drop to represent a first guess at the long-term consequences

of lower world oil prices. OTA did not attempt

a detailed analysis of the methodologies or assumptions of the projections, though the methodologies of many of the major models have

been scrutinized in the past.

We caution the reader to be skeptical of the

projections, even those made with sophisticated

models. Both the simple and the complex projection methods generally rely on extrapolation

from past trends to produce estimates of such important variables as the number of wells drilled

i n a given year. A common source of error for

these methods, then, is to force them outside the

range where past trends can be hoped to apply.

The United States has just undergone a period

during which oil prices, a key determinant of industry activity, have undergone a severe dislocation, and one in the opposite direction from

past dislocations. Also, during the past few years,

several companies comprising a large segment

of the industry’s reserve replacement capability

have been restructured, merged with other companies, or been the object of takeover attempts,

All these changes have serious implications for

industry capabilities and business strategies. Historical relationships between industry investment

behavior and economic variables such as internal cash flow may be inapplicable to the present

economic environment. Finally, the period of the

early 1970s to the beginning of the 1980s—when

many of the relationships used by the forecasting methods were defined—was a period of extremely rapid growth in activity accompanied by

hyperinflation in the costs of drilling and other

factors of oil production. It appears unlikely that

these relationships will prove stable.

Projections of U.S. Oil Production

Made Prior to the Price Break

To keep the recent, very pessimistic forecasts

of future U.S. oil production in perspective, it is

important to note that a future of declining domestic production and increasing imports was

widely predicted even before the sharp 1986 declines in world oil prices. In 1985, a majority of

analysts expected oil prices to remain between

$20 to $25 per barrel for a few years and then

begin a gradual increase, in real terms, back to

and beyond $30 (in 1985 dollars) by 2000. According to the Chase Manhattan Bank, a consensus

view of future U.S. production u rider these conditions would have crude oil production decline

from about 8.9 million barrels per day (mmbd)

in 1985 to below 7 mmbd by 1995 and below

6 mmbd by 2000 (see table 2). Although three

of the four other prominent forecasts in table 2

are considerably more optimistic than Chase’s,

all forecasts project declines from 1985 production levels of at least 1 mmbd by 2000 and 2

mmbd by 2010. Coupled with expected declines

in natural gas liquids production and increases

in oil demand, large increases in U.S. oil imports

seemed inevitable.

As discussed later, there are alternative views

of the oil resource base, and the potential of new

technology to access greater portions of that base,

that lead to more optimistic assessments of fu31
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 by

2000.

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 (1984

dollars) by 1995 and $38 by 2000.

a1985 production was 8.92 mmbd

NA = 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 Petroleum

Dwlsion, Wor/d 01/ and Gas 1985, August, 1985.4, Energy Information Administration, AnnualEnergy Outlook 1985, DOE/ElA-0383(85), February 1986 5 Gas

Research 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 views

focus particularly on the continued potential for

the growth of reserves in the United States’ older

fields through both conventional drilling and, via

improved technology, through enhanced oil recovery methods. These views, and the expectation that U.S. production could have been maintained for several more decades had prices not

dropped so precipitously, are definitely minority positions. Nevertheless, the uncertainty associated with the resource base and the potential

for technological innovation easily encompasses

such alternative views.

Recent Projections of U.S. Oil

Production Assuming Continued

Low Oil Prices

Short-Term Projections

Table 3 presents 10 alternative views of the

likely magnitude of U.S. oil production during the

next 2 to 3 years. Few in the industry expected

large reductions in annual oil production by 1986,

primarily because the adverse effects of reduced

drilling of exploratory and development wells

would 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 condensate

production prices (mmbd)

Source 1985 1986 1987 1988 Prices

1. Stolz . . . . . . . . . . . . . . . . . . . . . . . . . . 8.9 7.7

2. API . . . . . . . . . . . . . 8 $15

3. API . . . . . . . . . . . . . . . . : : : : : : : : : : : : 7.1 $10

4. EIA . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.73 8.52 $10 by third quarter 1986, $15 by summer 1987

5. Spears . . . . . . . . . . . . . . . . . . . . . . . . . 7.9

6. CWW . . . . . . . . . . . . . . . . . . . . . . . . . . 8.35 7.83 $15

7. ARCO . . . . . . . . . . . . . . . . . . . . . . . . . . 8 7 “low prices”

8. Chevron . . . . . . . . . . . . . . . . . . . . . . . . 7.6

9. DRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.75 8.5 $15-$16

10. IPAA . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.8 8.5

SOURCES: 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 Independent

Petroleum 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 be

unlikely to stop production this soon. For many

marginal wells, reservoir characteristics dictate

that a prolonged shutdown of production will

damage future production potential; for others,

stopping production will violate lease terms and

resuIt in lease forfeiture. The great majority of

operators with wells of this type will hesitate before “shutting in” production because this would

be essentially abandoning their investments.

Thus, the production projected to be lost by yearend

•

●

●

1986 was expected to largely be from:

marginal wells requiring immediate expensive repairs,

the modest number of uneconomic wells

and enhanced recovery operations that could

be shut in without losing the well or the

lease, and

a small number of marginally economic

operations whose owners believed that a

price rebound was inevitable and therefore

decided to forego small current profits for

larger future profits.

The actual 1986 average production, estimated

at year end 1986, was about 8.67 mmbd, down

about 3 percent from 1985’s average production

rate. However, the daily rate at year end 1986

had sunk considerably below the average, to

about 8.35 mmbd, or nearly 8 percent below the

rate a year earlier.1

The projections for 1987 show more strongly

the effects of the expected slowdown in drilling

and resuIting failure to compensate for natural

production declines in existing wells. These projections show a very wide variation. This is partially a function of assumed price; the API projections show a 900,000 barrel per day (bbl/day)

production loss in going from a $15 to a $10 per

barrel oil price. Another potential reason for the

variation is a disagreement about how much stripper well production and other marginal production will be shut in, primarily because the available database on the physical and economic

characteristics of these wells is too weak to allow reliable projection of production losses.

Both the 1986 and 1987 projections would

have been somewhat more pessimistic without

widely expected increases in Alaskan oil production. Despite cutbacks at the Milne Point field,

increased flows from the Kuparuk River field and

the Lisburne reservoir of the Prudhoe Bay field

were expected to yield 1.6-percent increases in

Alaskan production in both years.2

Longer Term Projections

Table 4 shows 12 recent projections of longer

term U.S. oil production. If the two projections

with somewhat higher price tracks (GRI a n d

Chevron B) are set aside, there is a strong consensus among the forecasters that a continuation

of low oil prices will drive U.S. oil production,

which was about 8.9 mmbd in 1985, to 7 mmbd

or below by 1990. Coupled with expected drops

in natural gas plant liquids production—the GRI

projection, assuming moderately higher prices,

expects a drop of over 400,000 bbl/day by 1990—

these forecasts project total U.S. liquids production to drop by well over 2 mmbd by 1990. In

comparison, none of the pre-price break projections (table 2) show expected production declines

above 1 mmbd, and most expect a decline of

about half that amount.

2Energ} Intorrnatlon Admlnl\tratlI)n $hon Tt’rm fn(,r,q~ ( hJt/{JOL /u/\ / ~H(J

D[)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 2000

2. Chevron . . . . . . . . . . . . . . . . . . . . . ..5.9-6.9 $10 to $15 thru 1987, $18-22 by 2000

3. API . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.2 constant $15

4. CWW . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1 $15

5. Unocal . . . . . . . . . . . . . . . . . . . . . . . . . 6-6.5 $13.50

6. Amoco . . . . . . . . . . . . . . . . . . . . . . . . . 6.7 4.5 “Low Price”

7, Fisher. . . . . . . . . . . . . . . . . . . . . . . . . . 6.8 $15

8. Conoco A . . . . . . . . . . . . . . . . . . . . . . 7 5.5 3.5 <$12 thru 1995, $20 in 2000

9. 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 2000

11. NPC . . . . . . . . . . . . . . . . . . . . . . . . . . . 7.1 5.7 4.5 $12 in 1986, $14 in 1990,$21 in 2000

12. DOE . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.9 5.2 $14-16 thru 1990,$21 in 1995

SOURCES: 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 Cost

of Low-Priced Oil, ” submitted to the U.S. Senate Energy and Natural Resources Committee, Mar. 20, 1986.6. Economics Department, Amoco Corp., World

Energy Outlook, Apr. 30, 19S8. 7. William Fisher, Bureau of Economic Geology, University of Texas at Austin, Testimony to the Fossil and Synthetic Fuels

Subcommittee, Energy and Commerce Committee, Mar. 6, 1986 8. and 9. A Coordinating and Planning Department, Conono Inc., World Energy Outlook

Through 2000, September 1986 10. Gas Research Institute, submission to the National Petroleum Council’s Survey of U.S. Future Oil and Gas Outlooks

11 Nattonal Petroleum Council, Factors Affecfiog U.S. Oi/ and Gas Outlook, February 1987 12 U S Department of Energy, Energy Security A Reporf to

the 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 the

1970s shocked a generation of oil company executives and analysts who had known decades

of oil price stability. Many—though certainly not

al l—of those same executives and analysts were

shocked again by the sharp price drop of 1985

to 1986. The surges convinced most observers

that the world was entering an era of energy scarcity, and touched off an expensive search for

alternative energy sources and a new round of

governmental intervention in energy markets.

The price drop has served to remind us, however,

that oil is a commodity, albeit one whose concentration of low cost reserves in the Persian Gulf

establishes some real potentials for price manipulation . . . and, like other commodities, it may

undergo periods of rapid price movements in either direction.

The era of stable prices that preceded the first

price shock–l 935 to 1972–was a reflection of

continuing intervention in the marketplace by

both State and Federal forces and the major oil

companies, with the Texas Railroad Commission

(TRC) playing a critical role. The United States’

leverage on the world market was made possible by the dominant role played by Texas and

the United States Gulf of Mexico in world oil production during this period. In 1951, for example,

world crude production was 4.3 billion barrels,

of which 2.2 billion barrels, or 52 percent, was

supplied by the United States. Texas’ production

of 1 billion barrels was 45 percent of the United

States and 24 percent of the world’s production.

(In comparison, Saudi Arabia in its peak year produced only 17 percent of the world’s oil.) Using

this leverage, the TRC controlled the amount

produced by Texas producers (through “prorationing”) and, along with similar actions by

other producing States and with Federal import

restrictions, was able to balance domestic supply and demand and maintain a stable domestic

price. 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 accept a stable price as adequate compensation for

sometimes operating their best welIs at less than

half capacity. In addition, the other major United

States producer States needed to be supportive

in their own State policies. And finally, the major companies that dominated the rest of the

world markets had to honor the status quo in

their behavior.

In the period 1930 to 1970, the United States

had a substantial surplus production capacity; in

the last two decades of the period, the surplus

was as high as 2 million barrels per day. in addition to the older major fields still producing in

California, Kansas, and Oklahoma, there were the

later, major discoveries that stretched from West

Texas to Southern Louisiana, including the huge

East Texas field (discovered in 1931). In the absence of restrictions on production, the price wars

that were triggered by the discovery of East Texas

would have continued until the excess supply

had been absorbed by the financial exhaustion

of the industry.

Despite these four decades of relatively stable

oil markets, the long-term history of oil has been

one of price volatility. Even with the inclusion of

the Commission’s 37 year reign, the real price

of oil has swung up or down by an average of

about 20 percent per year during the 125-year

period of U.S. oil production.1 More importantly,

the slow but sure response of oil supply and demand to prices tended to guarantee that periods

of scarcity and high prices would be followed by

periods of oversupply and falling prices, and vice

versa.

‘A. R. Tusslng, “How To Think About Energy Prices, ” Society of

Petroleum Engineers Paper No. 13193, 1984.

35
36

In retrospect, the price increases in the 1970s

and the subsequent price decline and then free

fall can be easily explained. In the decade or two

prior to the Arab Oil Embargo and the first price

shock, oil’s ready availability, low price, and convenience had won it a rapidly increasing share

of the world’s energy consumption: from a 28-

percent share of primary energy consumption in

1950, oil had risen to a 43-percent share by 1968.

The rapidity of oil’s rise in consumption and the

absence of apparent supply problems had led

oil-importing nations to ignore the fact that their

consuming sectors had little fuel flexibility in the

short term. With OPEC, and specifically the Persian Gulf nations, producing a large share of the

oil in international trade, the importing nations

were vulnerable to any artificial manipulation of

supply. As a consequence, when the Persian Gulf

nations wrestled control from the United States

oil companies and prices began to rise in response to their manipulation of supply, the importing nations attempted to secure assured supplies by competing among themselves, thus further

driving up prices.

Over the long run, however, the resulting restraint in demand and the increase in supply, natural consequences of a quadrupling of price, created an oversupply that OPEC could not manage

and drove the price right back down. For example, although in the early 1970s the demand for

oil seemed to display little response to the higher

prices, 2 between 1979 and 1985 world oil consumption declined by 7 mmbd (13 percent) while

economic output rose 15 percent. Oil’s share of

worldwide primary energy consumption dropped

to 45 percent from 55 percent. Although a substantial part of this decline came from greater

efficiency in use, much of it represented a shift

to cheaper energy forms: at prices above $20 per

barrel, oil often found itself at a competitive

disadvantage against alternative fuels–such as

coal—in

markets for electric-utility and industrial boiler

fuels, cement and brick making, distillation of

water, alcohols and petroleum itself, metallurgy,

the drying of materials, and every other application where the object of demand is raw calories.3

At the same time, there was an explosion of

successful oil exploration and accelerated development of previous large discoveries which resulted in stabilization of or actual increases in production among the mature producing regions,

such as the United States Lower 48 and Mexico,

and the opening up of major new provinces such

as the North Sea. Non-OPEC production, 26

mmbd in 1974, had surged to 37 mmbd by 1985.

Coupled with the reductions in worldwide demand, the new production forced OPEC into dramatic cutbacks in its own production—a 50 percent reduction between 1979 and 1985—to prop

up prices. Saudi Arabia, which bore the brunt of

the cutbacks, had seen its production drop to 2.2

mmbd from a peak of about 10 mmbd. The eventual Saudi reaction to the drastic reduction in its

revenues was its late 1985 doubling of production to 4.5 mmbd coupled with enactment of attractive “netback” deals4 to consumers to assure

sales. These actions caused an almost immediate collapse of worldwide oil prices. This seems,

in retrospect, an almost inevitable conclusion to

the pressures caused by the 1979 to 1980 price

hike and the radical changes in oil supply and

demand that had been set in motion 10 years

earlier. And although the first half of 1987 has

seen oil prices firm and rising back above $20/bbl,

the potential for renewed price instability and a

repeat of 1986 price levels is now an accepted

“fact” in the industry.

Alternate Projections of

Future Oil Prices

Before the strong upward price movement in

mid-1987, there were a wide range of projections

of future oil prices, but with a central theme to

which many oil analysts appeared to subscribe:

that oil prices would undergo a fairly brief period

of 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 6

years, and would then begin a moderate although

not inconsequential rise. The uncertainty in the

timing for a settling down of prices was based primarily on differing estimations of the potential for

a successful and sustainable production agreeZln 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 of

refined products, effectively guaranteeing to the refiner a minimum

profit margin on product sales.
37

ment in OPEC. A shorter time period was based

on the thesis that OPEC members would soon

see the strong self interest in reining in production and profiting from the resulting higher prices

even at decreased sales volumes. A longer interIude of instability presumed that such an agreement must wait until increased worldwide demand

and a significant decline in non-OPEC production, both in response to the lower prices, tightened the market. A tighter market would in turn

allow an agreement to succeed with only moderate production cutbacks required among those

OPEC members who traditionally have found it

difficult to stay within their allowable production

levels. The gradual rate of increase was based on

the assumption that OPEC’s, and primarily Saudi

Arabia’s, goal is to stabilize the market and maintain price levels that allow high production profits

without stimuIating excessive competition or stifling demand.

Two other price projections had a number of

adherents. The first presumed that prices would

stay low—at or below $1 5—long enough for higher

cost production to be severely damaged or even

crippled and for oiI demand to increase substantially. At this time, prices would soar back to or

above 1981 peak levels. These projections generally presumed a Saudi strategy of crippling its

high cost competition; alternatively, an ascendance to OPEC power of the price “hawks,” Ied

by Iran, would do equally well as a baseline assumption for this scenario.

The second projection foresaw an indefinite

continuation of price instability, with prices cycling about both short term events (rumors, wars,

temporary production cutbacks) and long term

supply and demand trends responding to changes

in mean price levels. The long term cycling would

generally fall inside the $10 to $20 range in today’s dollars, in line with the long term average

price of oil over most of its history; shorter excursions considerably above and below this level

are possible and probable. This projection is

based on the conclusion that oil is essentially a

commodity and will follow the same unstable

price paths followed by most other commodities.

The $10 to $20 range is based on the loss of substantial production capacity below $10 and the

large fuel substitution and conservation potential above $20.5

Notwithstanding the recent apparent return to

a semblance of price stability, these alternative

views of future prices still demand attention. I n

the absence of a functioning and effective institutional control of prices, the history of oil price

projections has been one of abject failure. For

example, a recent report6 concludes that, during the last decade and a half, there has been a

succession of strong consensuses about future

prices, each clearly based on an extrapolation of

price trends of the immediate past, and each

dead wrong. Thus, the history of oil prices implies that policy makers would be unwise to accept the price path of the past six months as a

forerunner of future prices. Also, if the “central

theme” described above actually does represent

a general consensus among oil analysts, a prudent businessperson or government executive

shouId still hesitate before using it as a planning

tool. Additionally, there are substantial reasons

for industry spokespersons to be circumspect

about their true beliefs, including competitive

pressures and ongoing legislative initiatives with

important implications for future industry profits.

The petroleum industry’s investment decision

process is guided to a considerable degree by its

future price expectations and the potential for

profits they imply.7 A reasonable way to guess

industry’s true belief about future prices is to examine its behavior, although interpreting recent

behavior is difficult because the past several months

and the coming year or so represent a transition

period with a high “noise” component. Nevertheless, drilling costs are now quite depressed,

and the potential profit from many longer term

prospects would be very high it oil prices were

to 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} Research Associates and Arthur Andersen & Co., CERA 497-6446,

1984.

‘Although declslons about the oierall magnitude of spending depend as well on capital aiallability, and particularly on the industry’s Internal cash flow.
38

be brought on line. Despite this, the industry has

been showing lessened interest in drilling for

prospects that have a delayed prospect, as demonstrated by the drop in exploratory drilling offshore. Consequently, this may indicate that most

producers are not confident that prices will increase significantly within a few years, and perhaps not even within 5 or 6 years. Unfortunately

for the reliability of this conclusion, however, the

industry’s investment behavior is also a response

to its recent poor cash flow and earnings, which

would tend to focus investment onto projects

which can add quickly to cash flow.

Determinants of Future Oil Prices

An examination of the factors influencing current and future oil prices shows a mixed picture

with regard to pressures for high or low price

levels. In general, arguments for a future of high

oil prices focus on the immediate depressing effects of low prices on oil and gas exploration and

development and subsequent expected declines

in future supply, the likely increases in oil demand in response to current prices, the tremendous financial incentives for OPEC nations to cooperate with one another in limiting production,

and finally the concentration of basic oil resources within OPEC and especially within the

Persian Gulf. Arguments for continued low prices,

or for instability centered around a low price

level, focus on the entrenchment of oil use efficiency in the economy, the availability of cheaper

substitutes for oil, especially natural gas, at prices

above $20, the low marginal production costs

and 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 is

larger (absolutely and relative to consumption) than

during the late 1960s and early 1970s, and the worldwide

Reserves to Production ratio is just as high.

The diversification of major oil producing countries is

considerably greater than when OPEC established market

control. In addition, the concentration of commercial

control in a few multinational firms no longer exists.

Natural gas, given its availability, can readily substitute

for more than half of world oil use, and can potentially

substitute for much of the rest. Also, availability is

becoming less of a problem. Natural gas resources and

producing/distributing capacity have exploded since the

early 1970s. Since 1973, global gas reserves have

increased by the energy equivalent of 30 years of OPEC

oil production. The United States has gone from apparent shortage to surplus, Europe’s available supply has

exploded, and West Africa and the Middle East can

displace oil in space heating, industry, and electric generation if delivery systems can be built.

Coal capacity and delivery systems are in surplus.

A large percentage (some say more than half) of the

existing fossil electric generating capacity—and virtually

all of the new capacity—has dual fuel capacity.

Despite current low prices, oil consumption still is likely

to stagnate because oil intensity is controlled by the

replacement of facilities and equipment and the substitution of goods and services . . . and this will continue

to be in the direction of the less efficient to the more

efficient, and more oil intensive to less oil intensive. This

tendency will be reinforced by consumer skepticism

about the stability of low oil prices.

Contrary to conventional wisdom, world oil production

capacity is not likely to decline dramatically in the face

of lower oil prices; it may even be able to increase over

time. In the past, higher prices had the perverse effect

of depressing investment in new capacity in low cost

areas, 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. (Likely

candidates for expansion include Kuwait, Iraq, Mexico,

and Saudi Arabia) Also, initial declines in drilling have

spurred many current and prospective producing countries towards greater flexibility in their dealings with oil

companies, and this should lead to expanded investment.

Also, the costs of replacing oil and gas reserves have

followed prices down, primarily because many of these

costs were inflated during the drilling boom and are now

at distress levels. The production levels in the so called

high-cost regions will not suffer as much as is supposed

as investors become better aware of the new cost/price

relationships.

Oil prices do not occur in a vacuum, and oil will not readily

recapture the markets it lost when oil prices soared,

because prices for natural gas and coal will follow oil

prices down in order to compete and retain the markets

they now have.

Importing nations are in a far better position now than

in the past to beat down attempts by OPEC to create artificial shortages and raise prices. In particular, strategic

reserves and agreements on oil sharing will serve as

buffers. In addition, past experience has taught the

importers some important lessons about strategic behavior, especially about the futility of seeking to attain unilaterally 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 oil

prices as a permanent condition.

Arguments about declining supplies ignore the strong potential for new technologies and expanded knowledge.

For example, producers are likely to push development

of new cost-saving technologies to allow them to prosper in a low-price environment.

The 1973 to 1985 period was an anomaly as far as oil

prices are concerned; during the entire 125-year period

of oil production, prices averaged less than $15 in today’s

dollars. Thus, $15/bbl or less is likely to be the world longterm 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 sustain

high prices. Tables 5 and 6 summarize the arguments for low and high oil prices.

1. Past successes in exploration provided the Middle East

with known oil reserves, both developed and undeveloped,

well beyond the immediate needs of this region given their

current rate of production, Outside of the Middle East, on

the other hand, there is little excess production capacity

and far less undeveloped reserves. This imbalance in both

present and future production capacity, coupled with the

worldwide slowdown in exploration and development

caused by current low prices, and with the dominance of

the Middle East in undiscovered resources, will lead

inexorably to a resumption of OPEC market control and,

subsequently, to higher prices.

2. Oil demand is bound to increase during a period of low

prices, planting the seed of future market tightening. Although the demand increase will not mirror the decrease

caused by high prices, any expectations that our interest

in energy efficiency and other energy savings is “locked

into” the energy system are as incorrect as were past

expectations that high levels of growth in oil demand would

continue despite high prices.

3. Low prices have already begun to stifle oil production in

4.

5.

6.

—

high cost areas; failure to continue intensive exploration

will result in substantial losses in worldwide producing capacity within a few years.

An increase in demand for OPEC oil of only about 5 mmbd

caused by demand growth and loss in non-OPEC production capacity (or drop in production in cooperation with

OPEC) would restore OPEC’s leverage in its efforts to influence world oil prices.

Expectations that the availability of natural gas as a

substitute boiler fuel will provide a buffer to oil price

increases ignore the likely declines in gas production

capacities as a result of the overall slump in drilling, especially in the United States, and, elsewhere, the difficulty—

and great expense—of building the gas transmission infrastructure needed to allow effective competition with oil.

The incentive for OPEC nations to manipulate production—

i.e., the potential to maximize revenues over time because

price increases can be balanced against lower sales volumes—is sufficiently high, and sufficiently well understood, to eventually lead to a higher level of cohesion and

cooperation within OPEC.

Clearly, these differences in the alternative

views of future oil prices are based in large part

on differences in judgments made about the response of supply and demand to price, as well

as on the expected actions of major players such

as the OPEC nations. The major uncertainties i n

the direction that future prices will take are the

following:

1.

2.

3.

4.

5.

the response of oil demand to lower prices;

the possibility of increases in production capacity in the low cost oil regions8

;

the uncertainties in OPEC actions, based on

uncertainties about the underlying motives

of the Saudis, if any, the potential for the

“hawks” to gain control of OPEC and to

seek higher prices immediately, and the ability of the OPEC nations to maintain production discipline;

the potential for new oil disruptions; and

the future levels of non-OPEC production,

including the uncertain ability of supposedly

high-cost oil producing regions to find an answer to maintaining production levels in a

low 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 regions; most investment went into relatively high-cost regions. Some

analysts now speculate that the reverse could happen at low oil

prices.
Chapter 4

What Will Determine Future Production?

Introduction

There is widespread agreement among oil industry analysts that United States oil production

is Iikely to drop substantialIy in the coming years

if oil prices remain at or near their current low

levels. As noted earlier, the production decline

wouId come from the combined influence of the

closing of thousands of wells and enhanced oil

recovery (EOR) projects whose production costs

are too high, reduced levels of drilling of production and exploration wells, cutbacks in new EOR

projects, and a slowdown in technology improvement with reduced R&D spending.

The logic of these predictions appears generally correct. For one thing, the evidence “on the

ground” right now is extremely supportive of a

long-term decline in U.S. production; the overall level of activity in development drilling, in all

phases of exploration, in enhanced oil recovery,

and in R&D have undergone a drastic decline,

the existence of natural production declines in

existing wells is simply indisputable, and monthly

domestic oil production has already dropped by

nearly 8 percent over a one year period. ’ Second, many of the companies involved in drilling,

well servicing, and other aspects of oil exploration, development, and production have suffered

serious financial reversals as a result of the loss

of revenue associated with the price drop and

the decline in oilfield activity, and their ability to

maintain previous levels of activity has suffered

as well. Third, the large drop in prices would appear to have an inevitable adverse effect on the

economics of drilling and other production prospects, thus sustaining the decline in activity and

the current trend towards lower production. And

fourth, the variety of available projections of future U.S. oil production have used several different approaches, yet they have arrived at similar

conclusions about a substantial production drop.

1 A drop ot 680,000 bbl’day I n domestic crude production, from

December 1985 to December 1986, in Energy lntormatlonAdmlnIst rat Ion, Short-Term Energy Out/ook. Qu,; rter/v Pro/ectlons, ja nuary 1987, DOE,’ EIA-0202(87,’l Q}

74-272 0 - 87 - 2 : QL 3

However, there is considerable uncertainty

about the magnitude of a production decline, and

there are even some grounds to question the idea

that the decline must be very large. Before acquiescing to the view of inevitable and large

production declines, policy makers should ask

whether recent forecasts of future oiI production

are basically reliable, and shouId examine carefully the assumptions underlying the pessimistic

projections. In OTA’s view, there are important

questions about the accuracy of these projections, because of changes to the industry that the

projections have not taken into account, because

of basic uncertainties about key aspects of oil supply responses to price changes, and because the

nature of the price changes that have occurred

are outside the experience of forecasters. In the

following discussion, OTA outlines the concerns

about the forecasts, and then reviews some of

the primary factors that should be taken into account in projecting future production. OTA does

not attempt to arrive at any “most likely” rate

of future U.S. oil production. OTA cone/udes,

however, that the available evidence, although

incomplete, points strongly to a continuing, and

substantial, decline in U.S. oil production if oil

prices remain well below $20 per barrel.

The Reliability of Forecasts

of U.S. Oil Production

Despite the variety of their level of detail and

specific analytical approaches, most forecasts of

future oil production can be divided into two

basic categories: those that rely primarily on applying relationships (e.g., between production

revenues and drilling rates) discovered by examining the historical record of oil exploration, development, and production and those that rely

on economic analyses of expected exploration,

development, and production opportunities. The

two forecasting methods are not mutually exclusive; all economic analyses include the application of some historical analysis.

The great majority of forecasts made available

to the public and to Congress use historical rela41
42

tionships to project future U.S. production. In

general, forecasts of this type are particularly vulnerable to errors caused by applying the relationships outside a relatively narrow band around the

independent variables. Such forecasts basically

are extrapolations from past trends, and remain

valid only when the degree of extrapolation—

represented by the changes in the independent

variables—is small. Current and expected future

conditions affecting the oil industry, however,

represent considerable changes from past conditions. In fact, as discussed in several of chapters

below, there are good reasons to believe that

straightforward extrapolation of past trends in several areas—e.g., in the way companies decide

how much of their revenues to allocate to exploration and development—will give inaccurate results. Consequently, extrapolative methods now

appear to be working welI outside of their range

of reliability. In OTA’s view, forecasts of U.S. oil

production based on uncritical acceptance of the

results of extrapolative methods are an unreliable basis for policymaking.

Forecasts that rely primarily on direct economic

analyses of exploration, development, and production prospects may appear more reliable because they are more closely tied to the decision

process used by the oil industry. However, such

forecasts cannot escape entirely from the problems associated with extrapolating from historic

trends; they may use historic data to simulate the

industry’s method of selecting drilling prospects

or budgeting its overall E&D programs, or to estimate certain key variables such as the success

rate of wildcats. In addition, the economic analyses are likely to use proprietary data on oilfield

opportunities, preventing the access to analytical

scrutiny necessary for credibility. Although some

of the forecasts of major oil companies may be

based on a careful economic analysis of drilling

prospects, the assumptions and detailed methodologies behind these forecasts are not available

for review. The possibility that some companies

have unannounced agendas will, deservedly or

not, undercut the credibility of their forecasts. Finally, the reliability of forecasts based on economic analyses demands an accurate assessment

of the geologic resources that may be accessed

by the industry within the time frame of the forecast. OTA believes that the reliability of resource

assessments—especially at the level of detail

needed for economic analysis—is inherently low.

Factors Affecting Future Oil Production

In discussing why they believe that U.S. oil production will fall, and fall drastically, in the years

to come if world oil prices remain both low and

volatile, oil analysts have stressed a number of

forces driving the predicted decline. Most have

stressed that drastically lowered industry revenues have crippled the industry’s ability to recover its past capital investments and pay off its

loans, severely damaging the industry’s financial

health. Some analysts stress in addition (or instead) that the basic economics of E&D investment have been damaged severely by lower oil

prices, in other words, that it is no longer profitable to conduct much of the drilling and other E&D

activity that was attractive at higher oil prices.

The precise role in industry investment decisionmaking of cash flow, on the one hand, and

E&D profit prospects on the other is by no means

a settled issue. Some analysts are convinced that

cash flow is the critical determinant of the magnitude of E&D investment, and that profit prospects primarily shape only the nature of that investment. Indeed, many analytical models of

investment spending and drilling use cash flow

as the key parameter. Other analysts are equally

convinced that cash flow will not be the primary

determinant of future industry investment, at least

for the longer term, that the basic economics of

drilling will be the key driving force. A correct

assessment of the roles of each of these factors

will be critical not only to projecting future production but also to determining effective policy

actions to combat a production decline.

Aside from cash flow and the economic prospects for new investment, additional factors that

wil l

●

●

affect future oil production levels include:

the potential for premature loss of some existing production with high operating costs;

the nature of the oil resource base, which

is intimately linked to the economic prospects for new investment because it determines the physical character of available investment opportunities;
43

the current surplus of gas deliverability,

which discourages gas driIling and can hurt

the economics of some oil drilling;

structural changes in the oil industry that

have increased debt, altered the industry’s

likely business strategy and objectives, and

are likely to affect industry efficiency;

changes in the “efficiency” of exploration

and development activity (as measured by

factors such as the reserves found per well

and the success rate of exploratory drilling),

which wiII alter the historic relationship between E&D activity levels and their results

in terms of reserves found and production

capability added;

changes in the climate for oil investments in

the United States and overseas that will in-

●

●

fluence company decisions about dividing

E&D investment budgets between the United

States and overseas;

prospects for technological change in the industry, and especially the potential for costsaving technology to help the industry successfully adapt to an environment of low

prices; and

the damage to the oilfield service industry,

which might hamper attempts at a drilling

rebound if oilfield investment prospects

improve.

The following chapters discuss these factors,

where possible drawing conclusions about the

direction and likely magnitude of their effect on

future production levels.
Chapter 5

Economic and Resource Factors

Affecting U.S. Oil Production

The Profitability of New Investment

in Oil Exploration, Development,

and Production

Introduction

As noted previously, there is a basic disagreement among analysts of the oil industry about

whether it is the prospective profits of new

investments in exploration and development

(E&D) activity or the revenues flowing into the

industry from its previous E&D investments, that

is, cash flow, that are the key determinant of the

magnitude of the industry’s future E&D investments. This question is complicated by the substantial changes in the industry’s management

and structure that have been wrought in the

1980s, and the as-yet unknown long-term effects

that the new oil price environment will have on

industry investment decision making.

I n the short term—perhaps for 2 or 3 years—

the level of cash flow from past investments and

the effect it has on the industry’s basic financial

health seems likely to have a very strong effect

on the level of new investment even if prospects

for profitable investments are basically good.

Many of the financial entities generally responsible for U.S. driIling and other production activities have been hurt badly because of the large

cut in their revenues. Because these companies

may hold land positions that could yield profitable drilling opportunities but no longer have adequate financial resources, new investment will

suffer from a mismatch between opportunity and

capability. Over the course of the next few years,

however, loans will be renegotiated, companies

will be restructured, and properties will be sold;

many of the companies will go under, but those

remaining should be stronger financially. Eventually, investment dollars will be made available

to the industry if there are attractive investment

opportunities. Thus, the long-term outlook for

oil supply is dependent on the basic profitability of the oil exploration and development prospects available to the industry.

In OTA’s view, it is by no means obvious that

the potential profitability of the industry’s available investment possibilities in exploration and

development have sunk in Iockstep with oil

prices. Because the costs of oilfield services had

escalated so sharply during the late 1970s and

very early 1980s, there was considerable room

for deflation in these costs when oil prices began to slide in 1981, and in fact these costs continued to deflate into 1986. ’ Only a careful examination of the balance of development costs

and the oil revenues that will flow from incurring these costs will yield a true picture of the

likely future of the industry in the face of continuing low oil prices. If the basic prospect economics are not as bad as they seem at first glance,

there may be some real potential for industry

activity levels—and reserve additions and production potential—to begin to rebound within a few

years.

An evaluation of the potential profitability of

domestic oil production prospects available to the

U.S. oil industry would be invaluable in projecting the likely future levels of reserve replacement

and production for the United States. For a variety of reasons, such an evaluation is not readily

available. First, there is no reliable inventory of

the available prospects, although a partial inventory (particularly of development prospects)

could be assembled from drilling data and lease

and field inventories in databases managed by

groups such as Dwight’s, NRG Associates, and

others. A particular difficulty here is the substantial uncertainty associated with the size and characteristics of the remaining oil resource base. Second, much of the information necessary to do

economic analysis, as well as extensive analyses

of new prospects carried out by oil companies

and their consultants, are proprietary. Third, were

the necessary data available, the complexity of

the evaluation would be very great, in part because of the large site-to-site variations among the

I Although drllllng costs rose briefly In 1985, according to the 1985

Joint Assoclatlon Survey.

45
46

many thousands of prospects, and in part due to

the complexity of the government taxes and regulations (e.g., the windfall profits tax) that strongly

influence the profitability of the prospects.

To OTA’s knowledge, there are no widely accepted, regularly updated evaluations of the potential profitability of new investments in oil E&D.

There are, however, a number of sources of information and analysis that can provide some important insights about potential profitability:

● Industry comments: The oil companies conduct evaluations of profitability for their own

properties and those properties they might

wish to purchase, and most companies have

recently undertaken extensive reevaluations

in light of the new price environment.

These evaluations are strictly proprietary,

for obvious competitive reasons. However,

a number of industry planners have been

willing to discuss the general results of these

analyses with OTA.

● OTA economic analyses: OTA has sponsored a limited series of economic analyses

of potential oil exploration and development

programs, in order to evaluate some of the

claims of our industry contacts and to evaluate the impacts on profitability of alternative

government policies, changes in expected

oil prices, and improvements in efficiency.

● Supply models using economic evaluation:

A few computer models of oil supply contain

submodels that conduct economic evaluations, but these are very general in nature

and appear unlikely to capture the full range

of effects of the price drop. The Hydrocarbon Model used by the Gas Research institute contains an economic analysis package

with one of the more detailed models of the

oil and gas resource base, and the results of

model runs can be useful in gauging changes

in profitability; however, the model does not

evaluate improved recovery of gas- and oilin-place, an important factor in future reserve

additions and production.

● Analyses of one or a few types of investment: A number of analysts have published

results of individual profitability analyses for

specific projects or areas. In addition, a few

groups have conducted detailed economic

●

analyses of some components of E&D activity. These include the Minerals Management

Service’s analyses of the U.S. Outer Continental Shelf resources and the National Petroleum Council’s study of Enhanced Oil Recovery. 2

Media statements: Some industry executives

have stated an oil price or price range that

they claim is necessary to revive drilling or

stabilize production, but these statements are

essentially impossible to evaluate and they

adopt different assumptions about costs, interest rates, future prices, and other critical

variables . . . if they are indeed the result of

actual analysis.

in addition, an examination of how drilling and

other E&D costs may change over time will give

further insight into how prospective profitability

may change in the future.

Survey of Industry Analysts

Despite industry secrecy, some oil company

analysts have offered to OTA some general information on the profitability prospects of new

oil and gas E&D investment.

Essentially all of these analysts contend that the

“inventory” of profitable oil and gas prospects

has shrunk enormously at mid-1986 price levels

of $12 to $15/bbl despite substantial declines in

drilling costs and significant though lesser declines in other costs. One source estimates that

only about 10 to 15 percent of the opportunities

available at early 1980 prices remain available at

$12 to $15/bbl. This figure is in line with the results of the IPAA/SIPES drilling survey, which

shows an 80- to 85-percent drilling decline at

$13,3 and an API survey predicting an 83-percent

decline (by 1991 ) at $10.4 Although some companies claim that there are large numbers of economic prospects at these prices, most are said

to be quite small and do not in the aggregate offer a major opportunity to replenish reserves. A

zNational petroleum Council, Enhanced Oi/ Recovery, June 1984.

lsuwey of their rnernberstllps conducted by the Independent petroleum Association of America and the Society of Independent

Professional Earth Scientists.

4API Crude Oil Price Effects Survey, May 1986, compiled by

Coopers and Lybrand for the American Petroleum Institute, results

in API, Two Energy Futures: National Choices Today for the 1990s,

1986 edition, July 1986.
47

very common theme is that the only arena that

can support substantial drilling levels is relatively

low risk, low-to-moderate cost development drilling, primarily for oil objectives (because gas markets are poor), with short lead times. This implies

that most drilling will involve step-out (extension)

and infill drilling, primarily at shallow depths, in

areas with little risk of cost overruns or curtailments (for gas prospects). Other categories of

prospects still viable at $12 to $15 include:

continuation of projects where the majority

of front-end capital has already been spent

(enhanced oil recovery, offshore development drilling, and waterfloods that have

passed the early development stages);

projects that are necessary to maintain company positions, e.g., development and exploratory drilling needed to satisfy lease

requirements, and joint ventures with substantial performance penalties; and

projects with very distant production startups, if the company is confident of higher

future oil prices. Although a few companies

are continuing a portion of their long-term

projects, more commonly these are being

canceled despite company projections of

“inevitable” long-term price increases.

common and disturbing theme is that exploratory drilling is virtually dead at $12 to $15.

A limited number of high-grade exploration

prospects are said to remain economic, such as

shallow pressured objectives,5 and the shallow

Gulf of Mexico. However, the bulk of high reserve potential prospects, both exploratory and

development, are thought to be no longer economic. These include:

Ž Beaufort and Bering Seas, and most other

frontier exploration;

● deep gas prospects;

Ž heavy oiI offshore CaIifornia (but some development projects with large sunk costs will

continue);

● 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, requirtnglower-thanaverage pu mplng energy for production.

It has been reported in the trade press that there

is little agreement in the industry about the crude

price necessary to stimulate a drilling recovery,

with some saying that $20/bbl would generate significant new activity and others that $35/bbl is

necessary. G Most of our contacts were pessimistic that an increase to $18 to $20 oil prices would

in any sense “rescue” the industry, although all

admitted that significant additional prospects

would become economic. These were said to

include:

●

●

●

●

●

●

some deepwater Gulf of Mexico exploratory

prospects;

considerable onshore wildcat drilling;

additional enhanced oil recovery projects,

especially select second-generation CO2

projects with available CO2 supplies, and

some polymer projects;

exploration and delineation drilling in the

Beaufort Sea;

limited offshore California development; and

many waterflood projects, whose economic

threshhold prices are-often between $15 and

$20.

Although virtually all contacts would agree that

there would be significantly more drilling activity at the $18 to $20 price, there was very substantial disagreement about the effect on reserve

additions at that price. The more optimistic companies foresaw a considerable reduction in the

rate of decline of reserves, for example, from a

9 to 12 percent/year decline at $12 to $15 to a

5 to 7 percent decline at $18 to $20. Other companies saw little improvement in reserve additions

with a moderate price increase. Part of the disagreement may rest on the type of additional

drilling activity foreseen at the higher price, with

the pessimists possibly being skeptical that this

price will elicit the high risk drilling they believe

is necessary for the addition of important new reserves. All, however, agreed that a critical factor

was price stability, which can be just as important as price level. Without stable prices, decisions on prospects will require either higher

threshold rates of return or the functional equivalent, the need to satisfy profitability thresholds

at prices substantially below the “expected”

levels.

“’Fiscal 1985 Returns for 0GJ400 Mixed, ” In 0// and Gaj Journal, Sept. 8, 1986.
4 8

OTA Economic Analyses of Drilling

Opportunities

OTA Prospect Analyses of Hypothetical Drilling Prospects.—OTA7 has examined the potential profitability of some hypothetical onshore

drilling prospects, focusing in particular on how

profitability has changed over time, using a commercial economic analysis software package8 and

additional software developed by our contractor.

The analysis evaluates both development and exploration 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 averaged

across several geographic areas. The perspective

is from the viewpoint of a driller who has a land

position and must determine whether or not to

drill.9 The basic cost assumptions used in the analysis are summarized in table 7.

For each well, OTA calculated the profitability expected at the time of drilling—1972, 1981,

1985, and 1986–and, for the earlier years, the

profitability actually obtained. The “expected”

calculations used price scenarios generally reflec7Analysis by Thomas Garland, OTA contractor, Dallas, TX.

8

The OGRE I I Oil and Gas Reserve Evaluation System analysis

packdge developed by David P. Cook & Associates.

9

For 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 for

west Texas crude to 1985, and then adopted a

price scenario assuming, in 1986 dollars, a $14/

bbl price through 1990 and then a gradual increase to $20/bbl in 2000. For windfall profits tax

calculations, OTA assumed that the wells were

“Tier 3“ wells, i.e. wells drilled on properties or

into reservoirs that were not producing before

1980. Drilling and other costs were based on

Energy Information Administration compilations

of cost data for the relevant years. The key well

parameters, initial production rate and reserves

per well, were selected by calculating the values

needed to allow a 15 percent before tax real rate

of return in 1986, assuming the $14/bbl price

scenario.

Table 9 shows the (before tax) rates of return

for the four drilling dates and expected/actual

price paths. Although the precise results apply

only to the particular cases evaluated, the consistency of the results as well depth varies and

IOOTA recognizes, however, that there has not been at any time

a universal consensus about future prices, nor IS it necessarily true

that the price expectations actually used in oil company prospect

analyses were similar to those made public. For example, although

OTA used a level price, in constant dollars, for the 1972 expected

case, some operators claim that they had expected to see increasing real prices at that time. For those operators, our calculated rates

of 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 30,143

1981 . . . . . . . . . . . . 58,625 75,381 109,830 98,407

1985 . . . . . . . . . . . . 54,278 70,413 98,396 82,154

1986 . . . . . . . . . . . . 51,564 66,893 98,396 82,154

Average operating costs per well/yr:

1972 . . . . . . . . . . . . 3,541 4,456 5,701 6,803

1981 . . . . . . . . . . . . 9,976 13,227 16,530 22,914

1985 . . . . . . . . . . . . 11,512 14,810 18,840 27,142

1986 . . . . . . . . . . . . 10,594 14,070 17,898 25,784

Average oil well drilling costs:

1972 . . . . . . . . . . . . 35,187 68,039 151,839 484,827

1981 . . . . . . . . . . . . 144,598 296,037 705,519 2,113,390

1985. , . . . . . . . . . . 93,440 204,444 483,200 1,242,816

1986 . . . . . . . . . . . . 74,752 227,555 386,560 994,253

Average dry hole drilling costs:

1972 . . . . . . . . . . . . 23,164 43,682 94,383 318,824

1981 . . . . . . . . . . . . 114,753 236,737 541,811 1,622,440

1985 . . . . . . . . . . . . 68,320 145,600 321,778 992,448

1986 . . . . . . . . . . . . 54,656 116,480 257,422 793,958

SOURCE: Energy Information Administration data.
49

. . . . . . .

. - -
50

Table 9.—Economic Analysis of Drilling Prospects: Development Wells

in Reservoirs Not Producing Before 1979 (“Tier 3“ oil)

Depth (feet) . . . . . . . . . . . . . . . . 2,000 4,000 8,000 12,000

Initial production (bbl/day) . . . 14 23 44 97

Reserves (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 15.1

1985 Expected . . . . . . . . . . 52.0 44.0 41.5 35.2

“Actual” . . . . . . . . . . . 22.2 18.3 16.5 15.1

1981 Expected . . . . . . . . . . 42.9 38.2 32.2 22.6

“Actual” . . . . . . . . . . . 27.0 22.0 16.5 7.6

1972 Expected . . . . . . . . . . Loss Loss Loss Loss

“Actual” . . . . . . . . . . . 9.1 11.3 13.3 9.6

SOURCE’ Office of Technology Assessment, 1987.

our examination of the regional variations in

drilling costs lead us to believe that the general

trends apparent in the results apply to a considerably broader set of oil development prospects.

The critical patterns apparent in the results presented in table 9 are as follows:

. At every depth, the expected profitabiIity for

1986 is substantially lower than the expected

values for both 1981 and 1985. Although

drilling costs have declined substantially from

previous years, many drilling prospects that

appeared profitable in the early 1980s would

not be drilled in 1986 even if capital were

available. This tends to confirm, at least

qualitatively, the claim made by most in the

industry that a substantial part of the inventory of formerly economic prospects are now

untenable.

● Because price expectations in both 1981 and

1985 were unrealistically high, the actual

profitability of the drilling prospects would

have been much lower than expected. In

most cases, actual 1981 and 1985 profitability would have been similar to the expected

1986 profitability, which is based on quite

modest price expectations.

● At every depth, prospects that would be considered profitable in 1986 would have been

expected to be outright losses in 1972, before the initial price shock. This result is especially interesting because some analysts have

likened 1986 conditions to 1972 conditions,

concluding that U.S. production is likely to

fall as quickly as it had been falling in 1972.

Based on our results, these expectations may

seem overly pessimistic. However, our anal-

●

●

ysis does not consider the availability of good

drilling prospects. Most analysts would argue

that, despite advances in technology and geologic knowledge since 1972, the availability of good physical prospects in 1972 was

superior to that of 1986.

Despite the substantial fall in prices between

1981 and 1985 and the reduced expectations

for future price increases, the prospects

looked somewhat more attractive in 1985.

The improvement in profit expectations stems

from the substantial decline in drilling costs

between 1981 and 1985.

Taking a longer term perspective, of an operator deciding whether to purchase and develop an unleased property, requires adding lease bonuses to the capital costs used

in the analysis. This wouId tend to narrow

the range of profitability between the different years, because bonuses typically are

higher when profit expectations are higher,

pulling down the profit from the prospects

with the best potential. As discussed previously, the current slowdown in drilling activity gives the bargaining advantage to the

operator, and lease bonuses for new property are likely to be low. Thus, the potential

profitability of buying and developing a property in 1986 will be closer to the potential

profitability of the same prospect in 1981

than the values shown in table 9.

Aside from the baseline analyses, we conducted

a number of sensitivity runs to examine the effects of changing assumptions.

Table 10 shows the effect on profitability of

drilling in an “old” reservoir rather than one
51

Table 10.—Economic Analysis of Drilling Prospects:

Development Wells; Effect on Profitability of

Windfall Profits Tax “Tiers”

Type of producer: independent

Wells: 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 34.2

4,000 . . . . . . . . . . 22.0 17.1 38.2 29.8

8,000 . . . . . . . . . . 16.5 12.8 32.2 25.1

12,000 . . . . . . . . . . 7.6 5.2 22.6 17.3

SOURCE: Off Ice of Technology Assessment, 1987

which was not producing prior to 1980. Because

the tax rate is higher for old, “Tier 1“ oil, and

the “windfall profits” higher because of previous price controls on the oil, the profitability of

the Tier 1 prospects would have been considerably lower than otherwise identical Tier 3 (“new

oil”) prospects. As shown in the table, both the

actual and expected rates of return were substantially lower for the Tier 1 drilling prospects. In fact,

for the deepest prospects, the expected profitability for 1981 is little different than the expected

1986 profitability. This effect would be exaggerated for major companies, because the windfall

profits Tier 1 tax rate is 70 percent for majors and

only 50 percent for independents (the resuIts in

the table are for independent drillers).

Table 11 illustrates the strong effect of expected

oil prices on expected profitability. For every

case, a price drop to $10/bbl transforms a modestly profitable prospect into a disaster, whereas

a $20 price transforms the prospect into a handsome one. The strongly negative effect of the $10

price is particularly important because several of

the exploration managers and planners interviewed by OTA claimed that drilling prospects

were being subjected to a “low price hurdle, ”

i.e., being rejected unless they would remain

profitable under the lowest price foreseeable . . .

with the hurdle price often set at about $10. The

effect illustrates the potential value of a government-legislated price “floor”; even if such a floor

did not affect actual prices,11 it might encourage

I 1 FxcePt, perhap5, by d ISCOU ragl ng exporters from sel II ng at below the floor, since the eventual landed price would be taxed u p

to the floor anyway.

Table 11 .—Economic Analysis of Drilling Prospects:

Effects of Oil Price on Rate of Return

Tier 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 33.0

14 . . . . . . . . . . . . . . . . 14.6 14.3 14.8 15.1

10 . . . . . . . . . . . . . . . . Loss Loss 1.3 3.49

SOURCE: Off Ice of Technology Assessment. 1987

drilling by raising the hurdle price required for

drilling prospects, presuming that the companies

trusted the government not to remove the floor

if 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 oil

prices could have significant positive effects on

drilling. The ultimate value of such a mechanism

cannot be judged, of course, without a reliable

analysis of how much drilling—and how much

additional reserves and production capacity—

wouId be created by each additional dolIar in the

oil price.

The price sensitivity calculations were made assuming drilling costs would not change within the

price range examined. This is likely for the $10

case because current costs are so low that there

is little room for downward movement. If $20 oil

generates substantial new drilling activity, however, drilling prices might rise somewhat, reducing profitability.

Table 12 illustrates the effect on profitability of

changing drilling costs, for a single 4,000 ft development well. As discussed in the section on

costs, drilling costs have gone through a classic

boom and bust cycle during the last decade or

so, and some analysts fear that a substantial rebound in costs could occur if drilling activity begins to pick up. Conversely, substantial improvements in drilling technology have occurred over

the same time period, although the effects on

costs of the improvements were submerged by

the imbalance between demand for and availability of drilling services. Continuing technology improvements could keep costs down if the industry accepts fully the challenge of finding and

producing oil in a low price environment.

The results show that the movement in drilling

costs from the 1985 average ‘‘per well’ costs to
52

Table 12.—Economic Analysis of Drilling Prospects:

Effect of Changing Drilling Costs on Rate of Return

4,000 ft. development well, Tier 3

Initial production = 23 bbl/day

Reserves = 50,000 bbl

Drilled, production begins in 1986

$14/bbl oil price

Rate of return (o/o)

Drilling cost Before taxes After taxes

1985 average . . . . . . . . . . . . 8.1 7.8

10°/0 below 1985 . . . . . . . . . 10.8 10.1

20°/0 below 1985 . . . . . . . . . 14,3 12.8

30°/0 below 1985 . . . . . . . . . 18.5 15.8

SOURCE: Office of Technology Assessment, 1987.

30 percent below the average–which has occurred in some areas—approximately doubles the

rate of return, a substantial effect.

Finally, table 13 illustrates the effect on profitability of changing Federal and State tax policies

to ease tax burdens on the industry, as has been

called for by numerous industry spokespersons.

As shown clearly by the results, a moderate easing of taxes—adding investment tax credits, raising depletion allowances, and cutting State severance and ad valorem taxes—does improve the

1986 expected profitability of these wells, but

only modestly.

In addition to the analyses of development

prospects, OTA examined the comparative profitability over time of a series of exploration and

development programs that find and develop

small oilfields (each field requires five producing

wells for full development) in known producing

provinces. The wildcat wells in the program are

successful in one out of six attempts; development wells are assumed to be 80 percent successful. Well costs, expected oil prices, and other economic variables are assumed to be the same as

in the previous analysis, except that geophysical

and other costs associated with exploration wells

are assumed to add 20 percent to the total costs

of these wells.

Table 14 displays the rates of return (real, before taxes) associated with the exploration and

development efforts at 2,000, 4,000, 8,000, and

12,000 ft, with and without lease acquisition costs

included.

12 A constant (real) $20 oil case is included to show the effects of an import tariff set

at this level. I n contrast to the earlier effort, only

“expected” rates of return—associated with typical oil price expectations of the time—are shown

for the 1972, 1981, and 1985 cases. The table also

shows the per well initial production rate and reserves necessary to obtain a 15 percent beforetax real rate of return for 1986.

The rates of return results are very similar to

the previous analysis for development well

drilling: at every depth, prospects that would be

considered profitable (15 percent before-tax real

rate of return) in 1986 would have been expected

to be outright losses in 1972 and, in contrast, considerably more attractive in 1981 and 1986,

whether or not lease acquisition costs are inI Zva{ Ues for lease acquisition costs were obtained from the Congressional Research Service analysis described below, see table 17.

Table 13.—Economic Analysis of Drilling Prospects: Policy Options for Improving

the Profitability of Development Drilling

Same physical parameters as in table 9

Date of drilling and first production: 1986

Expected price = $14/bbl

Type 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 12.78

2. Change investment tax credits

a. to 200/0 . . . . . . . . . . . . . . . . . . . . . . . . . . 14.16 13.44 13.30 13.19

b. to O (new law) . . . . . . . . . . . . . . . . . . . . 12.08 11.83 12.05 12.33

3. Allow 80°/0 depletion limit. . . . . . . . . . . . 13.38 12.80 12.74 12.78

4. Cut severance and ad valorem taxes

from 100/0 to 50/0 . . . . . . . . . . . . . . . . . . . . 15.56 14.71 14.39 14.33

5. Allow higher depletion allowance:

200/0 of gross. . . . . . . . . . . . . . . . . . . . . . . 14.00 13.53 13.50 13.50

300/0 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 12,000

Initial production rate,

bbl/day/well . . . . . . . . . . . . . . 20 35 71 172

Reserves, bbl/well. . . . . . . . . . . 41,000 72,000 146,000 377,000

Initial year Expected rates of return, real before tax, percent

A. Without lease acquisition costs:

1986 $20/bbl oil . . . . . . . . . . . 38 34 33 30

1986 $14/bbl oil . . . . . . . . . . . 15 14 15 15

1985 . . . . . . . . . . . . . . . . . . . . . 45 39 38 33

1981 . . . . . . . . . . . . . . . . . . . . . 35 31 27 21

1972 . . . . . . . . . . . . . . . . . . . . . Loss Loss Loss Loss

B. With lease acquisition costs:

1986 $14/bbl oil . . . . . . . . . . . 9 8 9 9

1985 . . . . . . . . . . . . . . . . . . . . . 30 25 25 21

1981 . . . . . . . . . . . . . . . . . . . . . 21 18 16 12

1972. . . . . . . . . . . . . . . . . . . . . Loss Loss Loss Loss

SOURCE Office of Technology Assessment, 1987

eluded. Also as in the previous analysis, expectations of a constant $20 oil price from 1986 on

will boost expected profits to the same general

range as the 1981 and 1985 prospects. This resuIt lends some credibility that an import tariff

set to produce a minimum $20 domestic price

might do some good, at least for this sort of “small

target” drilling and assuming that drillers (and

their investors) trust the Federal Government to

maintain the tariff even if world oil prices were

to plunge.

Comparing the initial production rates and reserves needed to produce a 15 percent return between this exploration case and the earlier development drilling case demonstrates that

exploration requires better prospects than development to achieve the same return. Although this

only confirms the obvious—the exploration program must pay off the high cost of multiple dry

holes (and buying the lease), whereas for incremental development drilling this cost is “sunk”-

it serves to bolster the industry’s contentions that

exploration drilling will absorb substantially

greater cuts than will development drilling.

The “dry hole risk” is crucial to the economics

of exploratory drilling. Although technological

optimists have often predicted large reductions

in this risk, and in certain situations this has been

accomplished, improved technology has been essentially unsuccessful in boosting the industrywide risk in any measurable way, Table 15

shows how such a boost might effect the economics of exploration programs, by examining

how the rate of return would shift if the wildcat

success rate shifts from one new field discovery

i n six attempts to two or three discoveries in six

attempts. As shown in the table, an improvement

to a 50 percent success rate would double the

rate of return for the type of exploration program

examined in this analysis. Unfortunately, most oil

producers would view such an improvement as

a more appropriate topic of science fiction than

of scientific analysis. Nonetheless, the results illustrate the value of pursuing improvements in

the efficacy and cost of seismic and other exploration techniques.

Prospect Analyses Conducted for OTA by the

Congressional Research Service. -Jane Gravelle,

Specialist in Industry Analysis and Finance, and

Bernard Gelb, Analyst in Industry Economics,

both of the Economics Division of the Congressional Research Service, have conducted a serTable 15.—What Happens If Dry Hole Risk Is

Reduced? ($14/bbl oil, no lease acquisition costs)

Well depth, feet

2,000 4,000 8,000 12,000

Expected rates of return,

Success rate real before tax

1:6 . . . . . . . . . . . . . . . . 15 14 15 15

2:6 . . . . . . . . . . . . . . . . 20 19 20 20

3:6 . . . . . . . . . . . . . . . . 29 29 30 33

SOURCE Office of Technology Assessment, 1987
54

ies of economic analyses for this study. 13 T h e

analyses are of a series of combined exploration/

development programs hunting for relatively

small fields in four producing regions: the Permian Basin, Powder River Basin, Anadarko Basin, and the Gulf Coast Basin of Offshore Louisiana. The exploration/development programs are

described in tables 16 and 17. As in the OTA analysis described above, the same physical prospects

are evaluated for four different years: 1972, 1981,

1985, and 1986. The oil prices used in the analyses generally conform to the price expectations

of the times (table 18), except for 1986, which

uses three hypothetical price scenarios. Only the

“expected” profitabilities are examined, since decisions to driII are made on the basis of such expectations.

The prospect evaluation employs a discounted

cash flow analysis, with revenues and costs discounted to the present, to arrive at estimates of

“net present value’’—the amount that the net

after-tax revenues (gross revenues less operating

costs, royalties, and all taxes), discounted to the

present, exceeds the initial investment. In the

baseline runs, the lease acquisition costs were not

included, primarily because these costs are so

‘ ‘B.A. Gelb and J.G. Gravelle, “Oil Prospect Profitability in the

United States: Estimated Expectations in 1972, 1981, 1985, and

1986, ” CRS Report No, 87-38E (revised), Mar. 24, 1987.

variable from project to project. The real discount

rate was set at 10 percent, so that when the net

present 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 variables

used in the analyses.

The results of the baseline series of prospect

analyses are presented in table 20, with the results displayed in the form of the net present value

expressed as a percent of the initial investment.

If a real 10 percent rate of return is considered

the minimum “hurdle rate” of a prospect–the

minimum expected profitability that would convince the operator to proceed with the program

—then the 1972 Powder River Basin project, with

zero net present value, could have proceeded

if 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, reevaluated the property to arrive at the expected result displayed in the table. Prospects with positive net present values allow the operator some

leeway to pay bonuses, with the amount determined primarily by the competition for properties and the land’s potential for some alternative

use that might be hindered by a drilling program.

The results are generally similar to those of the

OTA 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 Louisiana

Variable Independent Major Independent Independent Major

Number of wells:

Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 10 10 10 6

Successful . . . . . . . . . . . . . . . . . . . . 10 10 10 10 13

Well depth (feet):

Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,500 6,400 6,400 3,300 8,800

Successful . . . . . . . . . . . . . . . . . . . . 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 refer

to 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 rules

of 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 ratio

of 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 more

cautious in drilling “wildcat” wells. Well depth—Typical well depths of the respective producing regions in 1972, based on data from the Joint Association of Drilling 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 reserves

for 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 region

Permian Basin Powder River Anadarko Offshore Louisiana

Geological and

geophysical . . . . . . . . . . . . . . 1972

1981

1985

1986 }

Land acquisition

and Ieasinga

. . . . . . . . . . . . . . 1972

1981

1985

1986

Drilling . . . . . . . . . . . . . . . . . . . . 1972

1981

1985

1986

Lease and well equipment . . 1972

1981

1985

1986

Annual operating costs . . . . . . 1972

1981

1985

1986

12% of sum of drilling plus lease and well equipment

25°)0 of sum of drilling plus lease and well equipment

33°/0 of sum of drilling plus lease and well equipment

25°/0 of sum of drilling plus lease and well equipment

20°/0 of sum of drilling plus lease and well equipment

2,424

11,956

10,140

7,600

293

1,155

1,145

1,090

50

142

165

164

1,775

6,753

5,165

3,850

325

872

935

890

49

142

152

151

436

1,851

1,436

1,080

153

575

520

495

27

82

93

92

14,400

16,416

3,000

1,500

9,680

50,929

28,571

21,150

2,170

6,200

6,200

5,830

742

2,417

2,360

2,300

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 pubIished 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 and

Gas, ratios for 1985 and 1966 estimated by authors, based on price expectation scenarios. Offshore: Derived from average lease bonuses paid per acre in Federal

offshore lease sales Drilling —Assumed number of wells Onshore—10 dry, 10 pay; offshore—6 dry, 13 pay. Drilling costs estimated from Joint Association of

Surveys on Drilling Costs published by the American Petroleum Institute, for 1972, 1981, and 1984, from the 1985 Survey of Combined Fixed Rate Overhead Charges

for Oil Producers, published by Ernst and Whinney, and from comments by an oil industry association economist Lease and Well Equipment—Estimated for 1972

1981, and 1985 from data in Costs and Indexes for Oilfield Equipment and Production Operations in the United States, published by the Energy Information Administration, 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 $14.00

Powder River Basin . . . . . . . . . 3.30 35.90 28.00 14.00

Anadarko Basin . . . . . . . . . . . . 3.25 35.90 25.50 14.00

Offshore 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/o

After 1990: 3.5°/0

C) 1985-90: OO

/o

After 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 Administration 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/o

Inflation rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.60/o

Debt share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.0%

Federal Income Tax Treatment

Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48.0%

Intangible drilling costs . . . . . . . . . . . . . . . . . . . . Expensed

Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expensed

Equipment

Investment credit rate . . . . . . . . . . . . . . . . . . . 10.0%

Tax Life (years) . . . . . . . . . . . . . . . . . . . . . . . . . 9.2

Depreciation methodb 

. . . . . . . . . . . . . . . . . . . SYD

Reduction in basis . . . . . . . . . . . . . . . . . . . . . . No

Depletable costsc . . . . . . . . . . . . . . . . . . . . . . . . . Percentage

depletion

State Tax Treatment

Severance Tax

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .078**

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .046

Wyoming*** . . . . . . . . . . . . . . . . . . . . . . . . . . . . .03

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Income Tax

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,04

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .0675

16.0%

9.6%

17.0%

46.0%

Expensed

Expensed

10.0%

4.5

150 DB

No

cost

depletion

.125

.046

.04

0

.08

0

0

.0675

12.7%

4.0%

17.0%

46.0%

Expensed*

Expensed

10.0%

4.5

150 DB

1/2

cost

depletion

.125

.046

.015-.06

.08

.08

0

0

.0675

10.2%

4.0%

17.0%

46.0% 34.0%

Expensed* Expensed+

Expensed Expensed

10.0% o

4.5 7

150 DB DDB

1/2 No

cost cost

depletion depletion

.125

.046

.015-.06

.08

.08

0

0

.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 balance

c22% 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 percent

NOTE: 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;’How

Taxes Affecf Econorrrtc Behavioc Herrry Aaron and Joseph A. Pechman (eds), Brookings institution, Washington, DC, 1981, p. 85-128, Debt ratios are from

Don Fullerton andRogerGordon, “Afle-examination of Tax Distortions in General Equilibrium Models;’ Behaviora/Simu/ation &fethods lnTax Po/icyAna/ySIS, 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 value

as a percent of initial investment)

Producing region and type of operator

Initial year and Permian Basin, Powder River Basin, Anadarko Basin, Offshore Louisiana, Unweighted

price scenario Independent Major Independent Independent Major average

1972 . . . . . . . . . . . . . . . . . . . . . . 7 0 0 – 4 16 4

1981A . . . . . . . . . . . . . . . . . . . . . 74 113 113 86 97 97

1981 B . . . . . . . . . . . . . . . . . . . . . 74 114 114 84 97 97

1985 . . . . . . . . . . . . . . . . . . . . . . 60 119 120 72 142 103

Old Tax Law:

1986 A . . . . . . . . . . . . . . . . . . . . . 21 49 50 13 66

1986 B . . . . . . . . . . . . . . . . . . . . . 14 39 40 6 51 28

1986 C . . . . . . . . . . . . . . . . . . . . . 1 24 24 – 7 29

New Tax Law:

1986A . . . . . . . . . . . . . . . . . . . . . 25 59 60 14 79

1986B . . . . . . . . . . . . . . . . . . . . . 17 46 48 6 60 33

1986 C . . . . . . . . . . . . . . . . . . . . . 1 28 29 –10 34

NOTE Real discount rate assumed to be 10 percent,

SOURCE: Congressional Research Service, 1987
wells, but the regional detail provided by the CRS

analysis yields some interesting insights. The expected profitability of the hypothetical prospects

in mid-1986 was lower than the expected profitability in 1981 or 1985, but generally higher than

in 1972—precisely as in the OTA analysis. Even

if future oil prices are assumed to rise quite rapidly (8 percent per year in real dollars, as in price

scenario 1986A), and despite a sharp drop in

drilling costs between 1985 and 1986, expected

profitability in 1986 is appreciably lower than in

1985 for all five prospects. However, in the Permian and Anadarko Basins, under the 1986B

prices (identical to those used in the OTA analysis), the expected profitability for 1986 is only

modestly better than it was in 1972, If the $14

oil price is assumed to hold, except for rising with

the cost of living, the 1986 prospects are slightly

inferior to the 1972 prospects in these basins.

The Permian and Anadarko Basins correspond

to regions JS and JN in table 24 (in the next

section), which displays the relative development

prospects computed by GRI’s Hydrocarbon

Model. That model calculated the prospects for

both these regions to be quite good. These results are not necessarily contradictory, because

the Hydrocarbon model runs incorporated relatively optimistic assumptions about oil prices.

In addition to the cases discussed above, CRS

examined the effects on prospect profitability of

the Tax Reform Act of 1986 (which will take effect starting in 1987). A most surprising result is

that the new tax rules show a small but significant improvement in profitability over the current tax law in every prospect, for every price scenario. Apparently, the lower tax rates in the new

law override the effects of losing the investment

tax credit. This conclusion would likely not hold

for a company that had excess tax credits or an

actual net loss under the current law (because

the lower tax rates under the new law would be

irrelevant), nor does it account for any adverse

effects of the alternative minimum tax in the new

code. It will hold, however, for situations where

the decision to pursue the prospect is at the margin where the company is deciding whether to

pursue one more prospect, and the company

does not have excess tax credits or a net loss for

the year. I n OTA’s view, this is the decision most

57

worth examining, since it is the one faced by most

companies trying to decide whether to increase

their rate of drilling . . . and thus it is the decision that, made in the aggregate, will determine

whether a drilling rebound is likely to occur.

CRS also examined the effects of a $10/bbl and

$20/bbl expected (real) price, an assumed repeal

of all State severance taxes, a 20 percent refundable tax credit for driIling costs (costs which are

currently in the nature of intangible drilling costs,

and which exclude depreciable equipment and

depletable geological and geophysical costs), and

a 27.5 percent oiI depletion allowance.14 The results are displayed in table 21.

The results for the $10 and $20 oil price and

the cut in severance taxes are pretty much the

same as those arrived at in the OTA analysis. The

$10 price–which is particularly significant since ,

conservative industry analysts may use this price

as a “hurdle” price for profitability—creates a disastrous drop in profitability. The $20 price, which

simulates a variable import tariff set at this value,

boosts profitability substantially. (However, it

drilling costs were to increase as a result of revived activity, the boost in profitabiIity wouId be

partially offset. ) The cut in severance taxes has

only a modest beneficial effect in most regions

(the Louisiana offshore prospect is an exception),

and does not appear capable by itself of making

a substantial difference i n industry activity.

An interesting exercise is to compare the results of the $20 price case to the 1981 and 1985

results, because drilling in these two years was

at a high level (even though the 1985 rig count

was somewhat depressed). The net present values

at $20 oil were back to 1981-85 levels for all regions but the Anadarko, implying that an import

tariff set at this level might spur a significant

drilling rebound if the oil companies trusted the

Federal Government to leave the tariff in place

AND if sufficient capital were made available

to the independent producers. Of course, confidence in such a result would require an examination of a far wider set of cases than was accomplished here. Also, we stress that this result does

not imply that a return to a free market price of

14All ot the cases incorporate the new tax rules.
58

Table 21 .—Estimated Anticipated Profitability of U.S. Oil Prospects, Under Specified Price and Policy

Alternatives (net present value as a percent of initial investment)

Producing region and type of operator

Permian Basin, Powder River Basin, Anadarko Basin, Offshore Louisiana, Unweighted

Price or policy alternative Independent Major Independent Independent Major average

$10/bbl constant pricea 

. . . . . . –14 6 7 –25 6 – 4

Variable import tax setting

price at $20/bbla 

. . . . . . . . . . 53 102 103 44 120 84

20°/0 drilling cost creditb

1986A . . . . . . . . . . . . . . . . . . . 41 73 74 26 93

1986 B . . . . . . . . . . . . . . . . . . . 32 61 62 18 74 47

1986 C . . . . . . . . . . . . . . . . . . . 17 42 43 2 48

No State severance taxes

1986A . . . . . . . . . . . . . . . . . . . 30 65 66 24 106

1986B . . . . . . . . . . . . . . . . . . . 21 52 54 15 85 42

1986C . . . . . . . . . . . . . . . . . . . 5 29 31 – 3 54

27.5°/0 depletion allowance

1986A . . . . . . . . . . . . . . . . . . . 39 76 77 29 105

1986 B . . . . . . . . . . . . . . . . . . . 29 64 65 20 84 49

1986 C . . . . . . . . . . . . . . . . . . . 11 44 45 1 53

27.5°/0 depletion allowance, with old tax law

1986A . . . . . . . . . . . . . . . . . . . 40 76 77 33 103

1986 B . . . . . . . . . . . . . . . . . . . 31 64 65 25 84 51

1986 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 year

CUnder 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. It

is the expectations of future prices as much as

the current price that drives industry activity, and

the current volatility of prices will tend to undermine industry confidence.

The 20 percent drilling credit, an idea not explored in the OTA prospect analysis, does produce a moderate improvement in profitability in

all cases, and could prove interesting to policymakers who favor using the tax code to boost

E&D activity.

The 27.5 percent depletion allowance also provides a moderate improvement in profitability in

all cases. in general, it boosts profitability slightly

more than the 20 percent drilling credit.

Inclusion of lease acquisition costs in the analyses will tend to make the 1985 and 1986 results

look more favorable in comparison to the 1981

results, because 1981 was the height of the

drilling boom and lease acquisition costs were

especially inflated. As evident from table 17, these

costs have come down considerably in recent

years, especially in the offshore.

Table 22 presents the net present values for the

same cases as in table 20, as well as for the $20

oil case, with the lease acquisition costs incorporated in the analysis. Inclusion of these costs

changes none of the basic conclusions obtained

from examining table 20, but the results do demonstrate more decisively than the original analysis that 1985 was actually a very attractive time

to drill, that reduced oil revenues were often

more than compensated for by reduced costs.

Analyses by the Gas Research

Institute (G RI)

GRI operates an energy supply and demand

forecasting system called the Hydrocarbon Model

that incorporates a detailed description of the

United States Lower 48 oil and gas resource base,

on a field-by-field basis, and an economic analysis model that assesses the expected profitability of exploratory and development drilling based

on the characteristics of the resource opportunities. GRI’s Strategic Analysis and Energy Forecasting Division has recently conducted a spe-
59

Table 22.—Estimated Anticipated Profitability of U.S. Oil Prospects 1972, 1981, 1985, and 1986 With

Lease 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 Major

1972 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . –12 –18 –18 –21 –46

1981A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 64 64 43 58

1981 B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 65 65 42 58

1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 80 80 41 125

1986A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 27 28 – 4 58

1986 B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – 3 18 19 – l o 43

1986 C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . –14 5 5 –21 26

$20 Constant Price .. ... ... ...... . . . 30 72 73 22 109

SOURCE Office of Technology Assessment based on Congressional Research Service analysis, 1987

cial run of the Hydrocarbon Model aimed at

evaluating the effects on oil and gas production

of low oil prices. 15

The primary assumptions used for the analysis

were:

● oil price (1986$) of $11.76/bbl in 1986, rising 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 1985

levels; and

. producers accept a minimum real rate of return, after tax, of 7 percent.

Some characteristics of the model and the assumptions used will tend to drive the estimates

of oil and gas production both above and below

a “most likely” level. For example, factors that

would tend to overestimate supply include:

● The minimum rate of return, 7 percent, appears low. This rate is lower than the rate

used by GRI in its baseline (higher price)

runs. Most industry analysts expect that the

perceived instability of oil prices will raise

the minimum rate of return acceptable to the

industry.

. The drilling model does not consider the

availability of capital as a constraint, implicitly assuming that capital will be made

available to the industry if there are acceptable drilling prospects to pursue. For at least

‘;T, J. Woods and P.D. Holtberg, “Hydrocarbon Activity In an

Era of Low Oil Prices, ” 61st Annual Technical Conference and Exhlbltlon 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 important constraint on industry activity, especially

among independent producers.

Factors that would tend to underestimate supply

●

●

include:

The model does not include the effects on

supply of enhanced oil recovery and other

activities to improve the recovery of oil- or

gas-in-place.

Actual 1986 drilling costs may be as much

as 30 percent below- 1985 level’s, and not the

10 percent assumed in the model run (however, many operators do not expect costs to

remain this low for long).

The results of the model run, displayed in table 23, show oil production declining at a 5 percent/yr rate through 1990, then 3.1 percent/yr

rate through 1995, and a 1 percent/yr rate

through 2000. Gas production holds constant

through 1990 and then declines at about 1.2 percent per year through 2000. Development drilling

is projected to dip considerably and remain at

levels substantially lower than those of the early

Table 23.—Lower-48 Oil and Gas Production

(excluding increased recovery from old fields)

O i l

a Gas

Year (million bpd ) (tcf) b

1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.63 16.1

1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.13 16.1

1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.36 15.1

2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.16 14.3

aDoeS riot inclurje lease condensate

bTrilllon cubic feet

SOURCE T J Woods and P D Holtberg, “Hydrocarbon Activity in an Era of Low

Oil PrlCeS, ” 61st Annual Technical Conference and Exhibition of the

Society of Petroleum Engineers, New Orleans, Louisiana, Oct. 5-8, 1!386

SPE Paper 15355 Congressional Research Service, 1986.
1980s—e.g., 32,500 total development wells in

1990 versus the rate of 50,000 to 70,000 wells

per year sustained during the first half of the

1980s, (Part of this dip may be attributed to the

model’s exclusion of drilling designed to increase

recovery efficiency in known fields.) On the other

hand, exploratory drilling is projected to dip initially and then recover sharply, to nearly 14,000

wells/yr in 1990 and 23,000 wells/yr in 1995

versus 13,000 to 17,000 wells/yr during the early

1980s. This latter result is surprising because of

the greater costs generally associated with exploratory drilling and the widely held industry

opinion that most future drilling will focus on field

development and away from exploration.

The model shows Lower 48 crude oil (not including lease condensates) production declining

by 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 expectations of stable oil prices in the low-to-mid $20s

for the remainder of the 1980s, the most pessimistic—the EIA Energy outlook—projected a 0.9

mmbd reduction in total United States crude plus

condensate production16 by 1990, with only 0.7

mmbd attributable to Lower 48 production. The

Chase “Consensus” forecast projected only a 0.6

mmbd drop for the United States as a whole. The

EIA projection for 1995 is for a 2.4 mmbd drop

in total United States production, with 1.9 mmbd

attributable to Lower 48 production, whereas the

Chase projection for the total United States is for

I a 2 mmbd drop. Thus, on the surface, the GRI

results imply a substantial decline in future oil

production attributable solely to the projected

difference in prices between the moderate 1985

expectations and a lower price scenario based

on an extension of 1986 price levels. However,

the authors of the GRI papers describing this analysis do not themselves interpret these results so

pessimistically, because they believe that greater

recovery of oil-in-place—not incorporated in the

model—will compensate for much of the projected reduction in “standard” oil production.

They attribute the current drilling decline prima rlbpresumably, lease condensate production will decline when natural gas production declines, so that the projected total decrease

in crude plus condensate production implies a lesser decrease in

crude alone.

ily to the immediate effects of the large drop in

the oil industry’s cash flow and conclude that the

overall resource economics of drilling have not

been greatly affected by the price drop.

Aside from the overall production projections,

the GRI model exercise yields interesting insights

into other potential changes associated with the

1986 price drop. In particular, the exercise yields

insights into the viability of new drilling activity,

and the profits likely to be gained from earlier

activity, in different portions of the country. For

example, the model results indicate that the extensive drilling in the early 1980s to all depths

in southern Louisiana, to 5 to 15,000 feet in the

Texas gulf coast, and to 10 to 15,000 feet in the

Permian Basin are yielding poor economic returns, and new drilling in these area/depth combinations should drop sharply with continuing expectations for unacceptable rates of return or

even outright losses. On the other hand, prospects for new drilling in many region/depth combinations remain surprisingly good despite the

lower prices, including offshore California, especially in shallow water (less than 600 ft), onshore

California to O to 10,000 ft, the Rocky Mountains

and Northern Great Plains to all depths above

15,000 ft, and several other regions. Table 2 4

shows the economic prospects for drilling in the

Hydrocarbon Model regions based on the low

price exercise.

MMS Analysis of the Effect of Lower Oil

Prices on OCS Recoverable Resources

A reduction in oil exploration activity on the

Outer Continental Shelf (OCS) and the statements

of industry planners imply that many OCS exploration prospects that were economic in the early

1980s at oil prices in the $25 to $35 price range

are not economic at $15 or $18. This in turn indicates that the total recoverable oil resource was

diminished by the recent oil price decline.

The Minerals Management Service (MMS) of

the Department of the Interior has evaluated the

effect of varying oil price on the magnitude of

the undiscovered “leasable resources” in the

Outer Continental Shelf (leasable resources are

resources that would be profitable to explore for

and 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

JS

L

EGO

LO

(Ohio, Kentucky, Tennessee, Georgia

further 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, New

Mexico)

(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, Mississippi

deep Norphlet)

(Offshore California and Pacific North

West)

excellent* at 0-10,000 ft (established depths), good to poor at

greater depth

good to excellent shallow and deep, poor at 5,000-10,000 ft (most

common drilling interval)

marginal

good at 0-10,000 ft (most common drilling interval), marginal to

poor below

poor at 0-15,000 ft, marginal at greater depth

good to excellent at 0-5,000 ft (high past active drilling), marginal

5,000-15,000 ft (most common drilling interval), poor at greater

depths

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 at

5,000-10,000 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 to

marginal at greater depths

good at all water depths except uncertain in Norphlet trend

excellent at 0-600 ft. water depths (most common drilling

good 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 for

United States Gulf of Mexico oil prices of $17,

$23, $28, and $34/bbl 17 in January 1987.

The analysis indicates that a 50 percent drop

in price yielded a 34 percent decrease in leasable resources overall, but that, in some basins

(Beaufort Sea, St. Georges Basin, Chukchi Sea,

and others), 100 percent of the resource was rendered uneconomic. Presumably, some of the basins were lost because the level of recoverable

resources dropped below levels necessary to support the costs of required transportation systems

or other minimum fixed costs.

A reliable evaluation of the effect of the OCS

resource “loss” on U.S. oil production requires

a detailed examination of the individual basins

and the various governmental and industry plans

for developing these basins. However, it appears

likely 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 small

within this century, because of the long time

lag–generally a decade or so–between OCS initial leasing and initial production, and because

generally the higher cost resources would not be

foremost on most development schedules anyway. Of course, this conclusion will not hold

when the total loss in leasable resources becomes

larger . . . as will certainly happen at prices substantially below $17.

OTA does not believe that the MMS analyses

are necessarily relevant to projecting the incentives for exploratory drilling aimed at very large,

long-term frontier prospects. Many or most major companies will pursue such prospects regardless of current prices because they cannot project

prices for the time frame of actual development

of any potential discoveries (in most cases, beyond 10 years) and they cannot pass up the

chance of discovering a field that is so large it can

be profitably developed at almost any conceivable oil price.
62

Table 25.—Sensitivity of Leasable Resource Amounts

to 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 .. .3,790

Central Gulf of Mexico. .. .3,930

Southern California. . . . . . . 540

Navarin Basin. . . . . . . . . . . . 0

Middle Atlantic . . . . . . . . . . 90

South Atlantic . . . . . . . . . . . 250

St. George Basin . . . . . . . . . 0

Eastern Gulf of Mexico . . . 180

Chukchi Sea. . . . . . . . . . . . . 0

Beaufort Sea . . . . . . . . . . . . 0

Northern California . . . . . . . 150

North Atlantic . . . . . . . . . . . 10

Central California . . . . . . . . 110

Washington/Oregon . . . . . . 50

Gulf of Alaska . . . . . . . . . . . 0

North Aleutian Basin . . . . . 0

Norton Basin . . . . . . . . . . . . 0

Kodiak . . . . . . . . . . . . . . . . . . 0

Florida Straits . . . . . . . . . . . 0

Hope Basin. . . . . . . . . . . . . . 0

Shumagin . . . . . . . . . . . . . . . 0

Cook Inlet . . . . . . . . . . . . . . . 0

Total . ................9,10 0

4,490

4,070

730

180

110

410

0

330

0

0

280

30

180

50

0

0

0

0

10

0

0

0

4,630

4,110

880

720

230

680

260

420

0

250

410

30

220

60

0

0

0

0

10

0

0

0

4,630

4,110

880

790

230

770

260

470

400

310

410

70

220

60

30

20

20

0

10

0

0

0

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-Year

Outer Continental Shelf Oil and Gas Leasing Program for January

1987-December 1991, app. F, draft

costs

The cost components relevant to a particular

decision about exploration, development, or coni tinued production depend on the precise circumstance of that decision:

I

● I n deciding whether to continue production

from an existing well in good operating order, only the net production costs–called

the “lifting costs’’—are considered. The cost

of acquiring the lease, finding the oil, drilling

the production well, and building the necessary infrastructure such as pipelines are important to the company’s profit and loss

sheet, but these costs are “sunk” and should

not enter the specific production decision;

production will continue as long as the net

revenues from the well’s production exceed

the lifting costs. For wells needing significant

repairs, the amortized cost of these repairs

must be added to Iifting costs, and the sum

balanced against revenues.

●

●

Decisions to expand production by drilling

new wells in known fields need to consider

the expected lifting costs plus the cost of

drilling the well, including a risk factor to account for the possibility that the well could

be dry. If the well is drilled outside the

known boundaries of a reservoir, i.e., a new

pool test or an extension test, the risk component could be quite substantial.

Adding production from a new (as-yet-undiscovered) field requires considering the costs

of acquiring the lease, drilling a number of

exploratory wells to discover the field, drilling development wells, and, at times, adding significant infrastructure.

Finally, many decisions must be made at stages

intermediate to these cases . . . for example, the

decision whether to drill exploratory wells after

the lease is acquired. Such intermediate decisions

are forced on producers when economic conditions change suddenly, disrupting the previous

calculations that led to the initial phases of oilfield activity.

In other words, at any instant, the oil industry

has a large “inventory” of potential investment

opportunities ranging from unleased, unexplored

land with potential oil reserves that are only a

gleam in a geologist’s eye, to older fields with a

few remaining undrilled sections, or with some

potential for infill drilling (drilling at a closer spacing than was initially planned) or other production-enhancing investments. For the older fields,

most or all of the leasing, exploration, and infrastructure costs have already been incurred. Thus,

it is inherently cheaper to pursue a prospect in

the most developed areas, and becomes progressively more expensive—i n terms of incurring expenses for lease bonuses, seismic exploration, laying pipelines, etc.—to pursue prospects at earlier

and earlier stages of the production cycle. The

only reasons why undeveloped prospects are pursued at all are because the inventory of prospects

in known and partially developed fields is limited

and must be replenished, and because the company believes it will find more profitable oil or

gas wells–with more reserves, higher production

rates, higher quality oil, with less water cut and

lower operating expenses–than in the more developed areas.
63

Lifting Costs.—As noted above, decisions to

continue production from existing wells are dependent on lifting costs remaining below the revenues flowing to the producer, that is, total revenues less royalties and taxes18 must exceed costs.

Thus, when oil prices are $15/bbl, royalties are

one-sixth, and taxes are 5 percent, lifting costs

must be less than $ (15 - 15/6) * .95, or $11.88/bbl

for the well to remain profitable to operate.

According to the “standard reference” for lifting costs—the Joint Association Survey19-average

lifting costs for oil and gas in the United States

have been well below “per barrel” oil prices,

even with taxes and royalties factored in. Average U.S. lifting costs were between 60 and 70

cents per barrel between 1959 and 1970, and did

not rise above $2 per barrel until 1980. The 1982

Annual Survey of Oil and Gas shows 1982 lifting costs (without taxes) for oil and gas to be

about $3.40 per barrel of oil equivalent (BOE),

with average costs for Alaska at $0.97/BOE,20 the

Lower 48 onshore at $4.03/BOE, and the offshore

at $2.81/BOE. Lifting costs for oil alone should

be a bit higher because operating costs are generally higher for oil wells than for gas wells. The

averages conceal a wide range, especially for the

Lower 48; for onshore production, wells with

high water production or in high cost secondary

and tertiary recovery operations may have lifting costs exceeding $15/bbl, whereas certain high

output wells may produce oil at less than $1/bbl.

Estimates of U.S. lifting costs at values considerably higher than the values reported in the Joint

Association Survey have been reported in the media and elsewhere. The reasons for the discrepancies are not clear, although they may include

definitional problems (the estimates may include

excise taxes, although these are unlikely to add

much more than $1.00/bbl to the total, or may

refer onIy to higher cost wells without specifying that this is so). Some examples of higher reported 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 sharply by their collectors If the alternative IS a massive shutdown ot’

drllllng and production. For example, see the writings of M. Adelman dnd A. Tusslng. Thus tar, there is little indication that major

reductions I n roya]tles and taxes are takl ng place.

I gjoi nt Assoclatlon SUrvey, 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 development

of resources with high I Ittl ng costs,

●

●

●

●

“Average United States lifting costs, including taxes” reported to be just above $10/bbl

for the oil and gas system as a whole, in testimony of Dr. Alan Greenspan, President,

Townsend-Greenspan & Co., Inc.

The lifting cost of bringing oil to the surface

is reported as varying from $7 to $15/bbl at

onshore wells by R. Stanfield in National

Journal, 3/29/86.

Operating costs (including royalties and

severance taxes) for different U.S. regions are

presented as: Texas, $4 to $8/bbl except

strippers, Gulf of Mexico $8 to $10/bbl, Arctic North Slope $14 to 24/bbl, in N. Barakat

and S.M. Chronowitz, “Crude Oil: Nearing

and Equilibrium, ” Smith Barney Financial

Services, Futures Special Report, Vol. 8 No.

5, spring 1986.

Average lifting costs in sample lower 48 fields

estimated as- $6.80/bbl, in J. L. Copeland,

Presentation to the Keystone Energy Futures

Project on United States Liquid Fuel Policy,

July 14, 1986, Copeland, Wickersham, Wiley

& Co., Inc.

In general, OTA is skeptical of estimates of lifting costs well above those of the Joint Association Survey. However, the Copeland, Wickersham, Wiley, & Co. estimates were derived from

a field-by-field survey of production costs and

cannot be dismissed so lightly.

To what extent might lifting costs decline further in response to low oil prices?

Operating costs for specific categories of wells

have begun to trend slightly downward during

the past few years as a result of reductions in

energy costs and some reductions in the costs of

services and equipment for well maintenance. In

particular, costs for fuel have declined in parallel with oil prices; this is an important cost component for enhanced oil recovery projects, but

generally is less important for ordinary production because pumping energy often is electric and

electricity costs have not fallen significantly. In

general, the very substantial cost reductions seen

in drilling services have not been matched by similar reductions in operating costs, nor are they

likely to be. The drilling cost reductions have

been driven primarily by the very large decreases

in demand for these services; for example, the
64

i

t

I

[

I

1

1

t

I

I

I

I

[

number of operating rigs has declined from over

4,000 in 1981 to about 700 in 1986. The number of wells, on the other hand, will not decline

drastically, and may even increase, so maintenance services will not have to face the enormous

idle capacity faced by the drilling service industry. However, many well operators will defer

maintenance, lessening the overall demand for

these services, and certain categories of services—

e.g., workovers for offshore wells—will face competition from equipment formerly devoted to

drilling new wells. Other costs–e.g., electricity

costs—may face downward pressure from State

governments concerned about the potential for

well closings. For example, the Oklahoma Corporation Commission has asked Oklahoma electric utilities to lower rates for well operations.

Therefore, operating costs seem likely to remain

stable or perhaps decline slightly in the near future, assuming oil prices stay low.

In addition to some moderate reductions in

technical operating costs, there is some potential for reductions in royalties and taxes. In general, most royalty reductions are likely to be concentrated on new operations where operators

can take advantage of the dropoff in competition

for new properties to pressure property owners

for concessions. There is less potential for royalty

reductions with properties that have already been

leased. For them, the property owners may be

particularly reluctant to accept a lower royalty

rate because their royalties have already been

slashed because of the lower oil prices. Also, further development of producing properties will

often remain quite attractive even at low oil prices

because the major capital expenditures have already been made, so there will be less economic

pressure on the owners of such properties to

grant royalty concessions. However, on the most

marginal properties, those most likely to be shut

in, some property owners may be faced with the

choice of accepting a lower royalty rate or losing their royalties entirely as the production shuts

down.

The potential for lower tax rates is uncertain.

The primary oil-producing States face a considerable dilemma in assessing tax strategy for oil

production. A major portion of their operating

revenues are derived from taxes on oil production, and the substantial dropoff in collections

associated with the price drop has caused considerable budgetary problems. Reductions in tax

rates probably would save some wells from shutting down. Given the low average lifting costs for

oil wells, however, it seems likely that any reduction would lead to a further significant drop in

State revenues, because the revenues “saved”

because of the few wells prevented from shutting in would be overwhelmed by revenue losses

associated with wells that would have continued

to produce without a tax break. However, each

shut-in well costs the State jobs, reduced taxes

associated with employment, and costs associated with added needs for social services.

From the above, OTA concludes that pressures

for reductions in lifting costs from existing wells

are 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 environment may tend to avoid areas and geologic situations known to yield high operating costs, even

though operating costs are not the primary factor considered in drilling decisions; this would

tend to hold down the average lifting costs of new

wells. Finally, the wells being shut in and thus

removed from the U.S. inventory of producing

wells are those with the highest costs. Thus, OTA

expects the U.S. average lifting cost to decline

in the coming years if oil prices remain low, although most of this decline will result from a shift

in the distribution of physical characteristics in

the U.S. inventory of wells rather than from a substantial lowering of costs for particular services

and types of wells.

“Finding” Costs.– Finding costs are the full

range of costs—including the cost of lease acquisition, seismic surveying, exploratory drilling,

reservoir modeling, and development drilling—

needed to bring oil and gas reserves to the point

where they can be produced.

As explained above, decisions to drill new wells

or otherwise develop new production depend on

expected finding costs, or on components of

these costs, depending on the stage of development the proposed activity is in. For example, the

decision to buy a lease and drill new field wildcats should consider every component of find-
65

ing costs as well as expected lifting costs if oil and

gas are discovered. The decision to drill a development well should consider only the components of finding cost beginning with the cost of

planning that particular well, since all previous

costs 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 in

finding costs over the past decade and a half, first

during the drilling surge that followed the 1972

embargo and then during the decline accompanying the oil price declines that began in 1981.

The major factors affecting these costs include:

● The hyperinflation associated with the rapid

increases in demand for drilling services,

land, and other factors of production. The

inflation was caused by a growing inefficiency 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

NOTES

1 “Surrogate finding costs” match reserves booked in a year to expenditures

made in that same year, even though actual costs to find and develop

reserves are spread out over a number of years “Ultimate finding costs” attempt to match exploration and development costs to reserves by assuming

typical lag times and levels of field growth.

2 The conversion to 1985 dollars was based on the GNP price deflator

SOURCES

A—L T Byrd, (The Keplinger Companies) and D.L. Moore (Arther Anderson &

Co ), “U S Oil and Gas Flndlng and Development Costs, 1973-1982, Lower

48 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 to

Shell 011 Co , June 1985 For lower 48 States

●

●

greater “economic rent” collected by providers of these services . . . and the turnaround in costs was caused by the overall

drop in oilfield activity. Similarly, the costs

of the other “factors of production” —including land and seismic analysis—rose with the

drilling boom and have deflated with the

slide in drilling activity.

Changes in drilling targets, with operators

expanding their driIling efforts towards marginal targets and targets in difficult-and high

cost—environments during the period of rising oil prices (driving finding costs up), then

adjusting during the price slide by withdrawing from higher cost targets and focusing primarily on targets in less difficuIt environments with lower finding costs. Some of the

movement towards marginal targets, however, reflected not economics but resource

depletion, that is, a declining availability of

low-cost opportunities.

Technological improvements in drilling, seismic surveying, and other components of exploration and development.

There currently is no consensus on how finding costs will vary in the future. Although many

analysts expected finding costs to continue a

downward trend, established in late 1982, into

1985, the 1985 finding costs appear to have

trended upwards.21 In all probability, a substantial part of any future changes will be the result

of changes in drilling patterns, as these patterns

continue to adjust to the new economic conditions caused by the lower oil prices. Effects of

technological change are difficult to predict because lower research budgets would tend to slow

change whereas the radicalIy new price environment might act to spur it on.

There also is no consensus on how the basic

costs of services and other factors of production

will behave in the future, although changes in

these costs were a primary driver of past changes

in finding costs. Right now, certain of these

costs—especially drilling costs—are so low that

the providers of the services are barely surviving,

I I According to the Arthur Andersen & Co. Oil and Gas Reserve

Disclosures, 1981-1985, 1985 finding costs per barrel were $11.85

(without revisions) and $9.39 (wtth revisions) compared to $9.94

and $8.29 In 1984.
66

I

I

I

I

I

I

I

I

,

#

I

,

I

I

deferring equipment maintenance and actually

losing money in many operations. 22 For these

services, any tightening of supply will surely lead

to price increases, but the extent of such increases

and their timing is not readily predictable (certainly, the overhanging surplus of equipment will

limit cost increases in the near term). For factors

that need not involve risk or investment on the

provider’s part—such as lease acquisition—it

seems more likely that costs can remain extremely low until there is a substantial recovery

of drilling activity.

Capital Availability and the

Permanence of Capital Flight

Many industry analysts point to a shortage of

capital to finance investments in exploration and

development as a major factor in the severe depression that is rocking the upstream sectors of

the oil industry, especially the independent producers. The severity and duration of this capital

shortage would appear to be a critical determinant of future U.S. oil reserve additions and

production.

During the late 1970s and early 1980s massive

amounts of capital flowed into the oil industry

as oil prices and corporate revenues soared amid

ZZFor example, certain types of drilling services can now be obtained at less than the cash cost of providing these services. The

providers are willing to accept the loss because the cost of mothballing 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. Between 1978 and 1985 over $300 billion was invested in petroleum exploration and development (see table 26). Annual expenditures peaked

at $57.7 billion in 1981 and then declined to $33

billion in 1985. In the wake of the 1985-86 price

drop, industry spending on E&D dropped sharply

to half the 1985 leveI.23 As can be seen from table

26, much of the increased E&P spending up to

the early 1980s came from the independent

sector.

The original wave of investment in exploration

was funded from several sources: from rapidly

expanding internal cash flows generated by

higher oil prices; from private investors seeking

high returns on publicly traded stocks and bonds

or tax sheltered investments in oil and gas drilling

funds, partnerships and trusts; from conventional

bank loans secured by equipment or reserves;

and from private placements by banks, other financial institutions, and large investors. Table 27

shows the sources of funds for the Chase Manhattan Group of large oil companies. Similar aggregate information is not available for independents.

Since the 1981 peak in the exploration boom,

several trends have combined to limit internal

and external capital availability for new exploration:

ZJOII and Gas Journal, Feb. 23, 1987.

Outlays for 1973 to 1985 (billions of dollars)

Larger firmsaIndependents b

Total

Year $ Billions ‘/0 Change ‘/0 Total $ Billions % Change % Total $ Billions % Change

1973 . . . . . . . . 5.3 25 65 2.9 27 35 8.1 26

1974 . . . . . . . . 8.6 62 69 3.8 33 31 12.4 52

1975 . . . . . . . . 6.4 –25 62 3.4 –10 33 10.3 –17

1976 . . . . . . . . 8.6 36 60 5.7 66 39 14.5 42

1977 . . . . . . . . 10.3 19 62 6.2 9 38 16.5 14

1978 . . . . . . . . 11.3 9 58 8.0 30 42 19.3 17

1979 . . . . . . . . 15.0 33 56 11.8 46 44 26.8 39

1980 . . . . . . . . 20.6 37 57 15.6 33 43 36.2 35

1981 . . . . . . . . 29.8 45 53 26.7 71 47 56.5 56

1982 . . . . . . . . 30.0 1 54 25.4 – 5 46 55.4 – 2

1983 . . . . . . . . 22.7 –25 55 18.2 –28 45 40.9 –26

1984 . . . . . . . . 22.1 – 3 53 19.4 6 47 41.5 1

1985 . . . . . . . . NA NA NA NA NA NA 33.0 –20

Exploration 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 oilcompanies 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 industry 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 term

Year earnings debt issued issued Other b Total expenditures Dividends debt repaid Other c

Total Internal funds External funds Total funds

1975 . . . . . . . 22,714

1976 . . . . . . . 25,828

1977 . . . . . . . 29,003

1978 ....., 33,184

1979 . . . . . . . 55,844

1980 . . . . . . . 66,859

1981 . . . . . . . 63,207

1982 ..., . . . 60,884

1983 . . . . . . . 60,256

1984 . . . . . . . 53,549

1985 (est.) . 63,600

10,129

10,310

8,678

4,930

8,568

11,900

16,585

14,980

8,704

22,168

19,100

a

a

a

a

a

a

a

450

300

179

500

1,217

2,426

4,424

5,226

6,984

5,862

1,723

6,283

6,706

–4,738

14.200

34,060

38,564

42,105

43,340

71,396

82,821

81,515

82,597

75,669

71,158

97,400

24,205

26,036

27,156

28,770

42,229

53,776

63,976

64,538

49,521

43,182

47.900

4,819

5,208

5,995

6,781

8,127

10,305

11,068

11,265

11,057

10,297

12,600

5,316

5,230

5,954

6,885

8,249

9,728

10,020

9,281

7,524

8,280

22.600

1,740

829

1,508

1,562

2,473

2,613

4,867

3,731

4,507

21,671

19,500

36,080

37,303

40,613

43,998

61,078

76,422

89,931

90,019

72,609

83,430

102.600

23,931

28,254

33,427

38,410

62,828

70,721

64,930

67,167

66,962

48,811

77.800

10,129

10,310

8,678

4,930

8,568

11,900

16,585

15,430

8,707

22,347

19.600

34,060

38,564

42,105

43,340

71,396

82,621

81,515

82,597

75,669

71,158

97.400

alncluded in Long Term Debt Issued.

bothe r Includes sales of assets and other transactions

cother Includes investments and advancements and preferred and common stock retired

a Included In Long Term Debt Issued

SOURCE. The Chase Manhattan Bank, Flnanclal Analysts of a Group of Petroleum Compan]es
68

●

●

I ●

I

I

I ●

,

●

●

,

●

The windfall profits tax cut sharply into the

majors’ earnings from oil production at

prices over $20/bbl, removing an additional

source of funds that might have been available for exploration and production (E&P)

spending and perhaps deterring additional

investments. (Countering the effects of the

WPT, however, were tax incentives such as

the investment tax credit. )

Lower wellhead oil and gas prices meant

lower revenues and earnings for many of the

independent producers, who carried a lower

WPT burden, and thus reduced internal cash

flows that could be available for exploration.

Federal income tax law changes in 1982

diminished the attractiveness of oil and gas

tax shelters for private investors at the same

time as the overall rate of return on oil industry investments began to decline in relation to the rate for manufacturing industries.

The price-related decline in the value of oil

and gas reserves and drilling equipment also

reduced the value of assets that could be

used as CO I lateral for bank loans.24

The high debt levels incurred by many independents to fund the boom in exploration

in 1979 to 1981 began to take an increasing

share of available cash flow as prices fell and

cut into discretionary capital spending.

Similarly, the increased debt levels incurred

by 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 Southwest

which had heavily financed E&P spending

came u rider pressure from the simultaneous

poor performance of loans to the oil and gas

drilling services and equipment sectors and

the agriculture and real estate sectors. With

a rise in problem loans, many of these banks

were less willing to lend their available funds

for risky drilling ventures.

zdf3anks were commonly using a rule of thumb that required POsting of collateral that had at least twice the value of the secured

loans under several price scenarios. Oil prices have fallen as much

as 60 percent in 1986. Moreover, some analysts believe that proven

011 reserves have declined in average price from $9 to $5 per barrel as of late 1986 and the value of loans that they could be used

to secure has gone down correspondingly.

Even as the amount of capital available was

constrained by these trends, disappointing exploration results and a decline in both oil and natural gas prices deterred investments of available

funds in many high risk plays by oil companies

and private investors. Exploration no longer enjoyed a privileged status among the major integrated oil companies and larger independents,

as management weighed various options for enhancing shareholder values, and some opted instead to use available internal and external funds

to pursue acquisitions, share buy backs, and other

investments.

The sharp drop in oil production revenues and

earnings that followed the 1985-86 price drop

drastically increased the entire industry’s capital

availability problems by dramatically reducing the

cash flow available to fund exploration and capital investment. The decline in capital availability has affected sectors of the industry differently,

however, with the drilling and service companies

and the smaller independent producers suffering

the most. The high debt loads incurred by these

companies, which funded much of the boom,

placed them at greater risk during the initial price

decline and the 50 percent fall in drilling activity

between 1981 and 1985. By 1985, many of these

firms were under financial stress, some were

forced into default and were liquidated, and some

sought protection under the bankruptcy laws. Of

the remaining operators, many saw their financial condition weakened as a higher share of their

cash flows went to debt service and the value of

assets that could be used as collateral plunged.

This reduction in collateral values also caused

some loans to go into technical default, even

though operators remain able to meet scheduled

payments. As noted above, the regional banks

which had financed their efforts were also u rider

pressure from poor performance in the agriculture and real estate sectors, and were less likely

to lend their available funds for risky drilling ventures. Although there are no reliable sources of

information on private financing, which is a major source of funds for independent operators,

many industry analysts believe that availability of

private funds has declined because of current

conditions in the industry and uncertainties over
the implementation of the 1986 tax law. With

fewer willing investors, companies may have to

offer better terms to acquire funds, and combined

with uncertain oiI prices, this provides a strong

incentive to avoid the high risk exploration ventures that often represent the best opportunities

for reserve replacement.

Also hard hit were larger companies that were

highly leveraged due to corporate acquisitions or

anti-takeover strategies. These firms cut E&P

spending first in 1985, with only a modest decline

in world oil prices. They took even larger cuts

in 1986 as cash flow was diverted to meet or reduce debt obligations and to maintain key financial indicators. These companies have less flexibility in the use of their available cash, and their

ability to borrow further may be impaired by the

high level of existing debt and uncertainty over

future revenues. Perhaps because of this concern,

several of these highIy leveraged companies have

devoted substantial efforts to reduce their high

debt levels and/or to refinance the debt at more

attractive interest rates.

In general, however, the larger companies—

and especially those companies that did not incur sizable debt loads during the boom years—

do not appear to have suffered nearly as much

from capital availability problems. In particular,

the integrated companies’ downstream earnings

helped to cushion some of their upstream losses

as refinery margins increased and demand for

gasoline and residual fuel oil increased. For example, as table 27 shows, total funds available

from internal and external sources declined by

only about $11 billion in 1982 to 1984, while capital spending (excluding acquisitions) dropped

over $20 billion. Rather than a capital shortage,

there appears to have been a deliberate shift away

from E&P spending towards other uses of capital, such as acquisitions and debt repayment.

Statements in company annual reports and congressional testimony generally attribute the reduced capital spending to a lack of profitable opportunities and not a lack of funds from internal

or external sources. Also, the 1985 annual and

1986 quarterly reports of many major integrated

oil companies and larger independents continue

to show new long-term debt, indicating that their

access to financing has not been substantially im69

paired. In 1985 to 1986, the use of borrowed

funds changed; with limited exceptions, these

funds have been largely used to refinance existing obligations, to repurchase shares, and to acquire assets of other companies rather than to

fund new oil and gas development.

Even with the most recent drop in revenues,

large oil companies remain among the largest

cash flow generators in the United States and the

world. Table 28 shows changes i n revenues and

earnings for selected major U.S. oil companies

for the first 9 months of 1986. Not all of the earnings losses in the exploration and production segments this year will translate into lower cash availability, as many companies took one-time paper

writeoffs against earnings.

Even the problems of the independent sector

must be evaluated carefully. According to Energy

Performance Review, independent oil and gas

producers and oil field service companies suffered sharp declines in revenues and earnings in

1986; a group of 126 independent producers

posted losses of $1.8 billion for the first 9 months

of 1986. However, more than 100 percent of year

to date losses were attributable to noncash charges

against income.25 The size of the noncash charges

indicates that many companies likely posted net

gains on their continuing operations that were

then reduced by noncash charges against earnings to reflect such things as writedowns in the

values of reserves because of lower prices, and

losses on the sale of operations.

The critical question for determining the future

of industry investments in exploration and development is: To what extent is the current pattern

of the domestic oil and gas industry a transitional

phase, and to what extent is it essentially stable

so long as prices do not rise?

Many industry observers believe that uncertainty over oil prices and the factors noted above

virtually ensure that, in the short run, little outside capital will flow into oil exploration and development. In the longer run, however, the relative importance of these factors is less clear. Other

industries 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 income

Company Million $ % Change Million $ % Change Million $ Million $ Million $ 85-86 1986 1985

* Exxon 57,470

● Mobi l 37,233

● Chevron 21,685

● Texaco 24,800

● Shel l 12,841

● Amoco 15,394

● ARCO 11,368

Conoco 7,495

● Sun 8,230

● Phillips 7,642

Ashland 7,300

* Occidenta l 1,175

● Unocal 6,297

Texas Oil & Gas 732

Louisiana Land & Exp 620

Murphy 1,048

Coastal 48

Marathon 6,100

Pennzoil ., 1,414

American Petrofina 1,493

● Tennec o 10,930

● Diamond Shamrock 1,951

Amerada Hess 3,139

Kerr– McGe e 1,946

* Standar d 7,750

Tota 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

1,204

801

675

628

582

551

331

315

217

209

161

127

38

25

13

(1)

(1)

(30)

(42)

(73)

(278)

(301)

(376)

8,660

8,649

27

96

– 1 5

– 2 7

– 3 7

– 6 3

—

– 2 7

179

–33

42

– 7 5

– 7 3

– 8 7

– 6 7

– 7 9

– 9 5

—

—

—

—

—

—

—

—

– 2 8

—

3,065

615

946

926

998

1,563

—

—

—

—

147

643

460

—

—

—

94

—

—

—

—

—

105

109

1,079

10,751

10,295

5,627

2,179

2,019

1,601

2,131

2,114

—

—

—

—

281

687

666

—

—

—

125

—

—

—

—

—

184

230

1,380

19,224

18,404

7,144

2,436

2,914

2,005

2,636

3,372

—

—

—

—

290

749

1,100 —

—

—

219

—

—

—

—

—

427

325

2,115

25,731

24,471

to economic shocks by writing off bad investments, selling capital stock to new investors who

can make a profit because they are buying at bargain prices, restructuring to reduce costs, rethinking their investment strategies, and developing

new technologies that can better deal with a

changed business environment. For larger integrated companies and independents without sizable debt loads, bank loans and private financing appear to remain available. Even though these

funds have been largely used to refinance existing obligations, to repurchase shares, and to acquire assets of other companies rather than to

fund new exploration ventures, it is by no means

certain that this spending pattern will continue.

It may be overly pessimistic to assume that the

oil industry’s level of investment in exploration

and development will not improve without a rise

in oils prices that will restore some of the profitability of prior investments and boost cash flows.

In the long run, the level of investment in E&D

–21

–11

31

– 2 0

–19

– 3 7

—

—

—

—

– 3

– 8

–40

—

—

—

–43

—

—

—

—

—

– 5 7

–298

–35

–25

—

145

181

252

237

339

363

—

—

—

—

135

427

526

—

—

—

2655

—

—

—

—

—

—

—

—

263

213

233

396

308

217

264

216

—

—

—

—

198

116

239 —

—

—

233 —

—

—

—

—

405

298

196

239

238

may be determined primarily by the basic economics of exploration and development, as defined by the question: How much return on investment can be gained by an additional dollar

of investment? If new investments in oil exploration and development appear profitable, companies may once again plow back more of their

funds into those ventures, and either new sources

of capital could appear or else the old sources

could 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 investment

capital to return. Given the rapidity of projected

production declines, an uncertainty of a year or

more in a recovery from the industry’s capital

flight translates into a substantial uncertainty in

the amount of any actual production decline. Furthermore, it is probable that any initial injection

of capital into the industry will tend to gravitate

to the lowest-risk opportunities. For a time, these
71

opportunities may be the purchase of reserves

and producing properties.26 Only after the inventory of available properties shrinks is capital likely

to flow primarily to the exploration and development activities needed to revitalize the industry.

Premature Loss of Existing

Production: Stripper Wells

There is widespread concern that low oil prices

wilI force many of the Nation’s “stripper” oil

wells, wells averaging 10 barrels or less per day,

to shut down, with many or most never to reopen, their reserves lost. This concern is magnified by the importance of stripper wells to the

U.S. oil supply, Approximately 1.3 mmbd–14

percent of total domestic oil production—are

produced by stripper wells. There are over

400,000 of these wells in operation, producing

an average 2.8 barrels daily .17 U.S. oil reserves

associated with stripper wells total about 4.5 billion barrels,28 16 percent of current U.S. reserves

of 28.4 billion barrels .29

A large shutdown, were it to occur, would affect a few States disproportionately. Between

them, Texas and Oklahoma have a bit over half

the Nation’s stripper well production. Adding

stripper production from California and Kansas

incorporates fully three-fourths of the Nation’s

stripper production .30

The concern about shutdowns stems from the

wells’ physical characteristics as well as from the

State and Federal regulations that govern them.

Many of the wells have high per barrel operating costs because their maintenance costs are

spread over so few barrels of production and also

because, in many areas, the well production includes 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 quarter

of 1986. Source: Strevlg & Associates, In Business Week, Dec. 1,

198b, p. 114.

“AS of Dec. 31, 1984, from Interstate 011 Compact Commission

and National Stripper Well Association, “National Stripper Well

Sur\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 Natural 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, revenues from oil sales may drop below operating

costs for many wells. For other wells with small

positive cash flows during ordinary operation, the

onset of any extraordinary repair costs may signal an impending well closure. And even without closure, many operators are likely to delay

needed repairs and thus forfeit the additional production rates these repairs would allow.

If the oil production from shut-in stripper wells

could be restarted, there wouId be no impact on

national security. in many cases, however, production shutdowns will be permanent. For example, for “water-drive” wells—wells where formation water pressure moves oil to the well bore

—a prolonged production shutdown may ruin the

well, i.e., renewed pumping would produce only

water. For all stripper wells, the time period during which a well’s production can be shut in is

limited by State and Federal regulations to prevent contamination of groundwater aquifers

penetrated by the wells. Prior to the current price

drops, most State and Federal regulations limited

shut-ins to 90 days, with requirements that the

well either be returned to production or be permanently plugged (with a concrete seal) after that

time. With current well-plugging techniques,

reentering a well is said to be little different i n

cost from drilling a new well. For wells with particularly low production rates, it seems unlikely

that production would ever be restarted, and

plugging these wells would likely result in a permanent loss of the reserves associated with the

wells. Because of the concerns about a widespread loss of both production and reserves,

some States have lengthened their shut-in grace

period to a year or more.31

There is little disagreement with the thesis that

oil prices at levels near or below $15 per barrel

will have a significant adverse effect on stripper

well closure rates and U.S. oil production rates.

Unfortunately, however, a general lack of data

on stripper wells makes it quite difficuIt to estimate 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 must

be plugged, The Department of the Interior also has lengthened

its 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 sudden price drop have altered operating and other

costs and may have affected the business strategies followed by the well operators.

Estimates of production losses generally assume

that traditional operating costs and business practices still apply. These estimates will likely overestimate the effect of lower oiI prices. The lower

oil prices have been accompanied by small but

significant reductions in day-to-day operating

costs and large reductions in costs for major items

such as well reworking. Operators are negotiating with their service companies for lower prices

or switching to alternative services. They are cutting labor to the bone and deferring maintenance.32

In some States, authorities are pressuring utilities

to grant lower rates of service to well operators.

For example, the Oklahoma Corporation Commission has ordered the State’s utilities to develop

lower electricity rates for oil wells, with reported

rate reductions ranging up to 22 percent. 33 And,

in the face of declining oil production and threats

of extensive well closures, States may take ameliorative actions such as cutting taxes to prevent

the loss of jobs and the other economic hardships

that the closures would create.

Before the price drop, stripper well operators

generally would abandon wells as soon as the incoming oil revenues could not cover cash costs.

Unless fracturing or some other production enhancement treatment (most of which are expensive) could boost production, there was little

likelihood that the well would be profitable again

soon enough to justify continuing to operate it

at a loss. In the current situation, however, many

operators are likely to believe that there is a fairly

high probability that prices will rise sufficiently

quickly, and to high enough levels to justify continuing production for (currently) unprofitable

wells. Indeed, many stripper well owners view

their wells as a family inheritance, one that has

provided the means to keep family farms or educate their children. These owners are especially

unlikely to give up their wells in the face of what

~zof Course, deferring maintenance wi II cause production problems sooner or later,

~~fnergy Da;/y, JU!Y 21, 1986.

many see as a short-lived attempt by OPEC to

eliminate its competitors, to be followed by an

inevitable price hike.

OTA knows of two analyses of the potential

stripper oil production lost to low oil prices. One

widely quoted analysis was sponsored by the Interstate Oil Compact Commission and conducted

by The RAM Group, Ltd. of Oklahoma City.34 This

study first computes the stripper well production

at different oil prices in Oklahoma using data obtained for that State’s wells, and assumes that

other States will sustain the same percentage stripper well production loss at each price level as

Oklahoma. The study also assumes that wells will

shut down when cash flows become negative,

that is, when operating expenses exceed oil revenues.

35

The results of the study for the United States

as a whole are shown in table 29. At a $15 oil

price, the study predicts a first year production

loss of 277,000 barrels per day (bbl/day), or 3 percent of U.S. production.

The general approach of this analysis seems

reasonable given the limited data, although OTA

believes that the focus on cash flow and the inability to account for still-continuing changes in

operating costs will tend to lead to an overestimate

of the likely production loss. Also, the pattern of

results as shown in table 29 does not appear realistic. Taken together with the data problems, the

problems with the trends shown in the published

results may limit the usefulness of the results as

the basis for policymaking. OTA’s overall objections are explained in more detail in box B.

The second analysis was conducted by the

Dallas Field Office of the Energy Information

Administration as part of their short-term oil production forecasts.36 In this analysis, EIA used data

on oil, water, and gas production from Dwight’s

Energy 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 communication, 1986.

36 Energy Information Administration, Short-Term Energy Outlook

ju/y 1986, DOE/ElA-0202(86/3 Q), August 1986, updated by letter

of Apr, 7, 1987, John Wood, Dallas Field Office, EIA to Steve Plotkin, Office of Technology Assessment.
73

Table 29.—Effect of Falling Oil Prices on Stripper Wells*

Gross value of

Percentage 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 operating cost data37 to construct a distribution of

stripper wells according to their oil production

(and, given an oil price, their revenues) and operating expenses, by State. The primary data problems were the unavailability of water production

data (critical to determining well operating costs)

for some States and the overaggregation of much

of the production data, some of which was available only at the field level.

The EIA analysis estimates that first year production losses will be 148,000 bbl/day at an oil

price of$15/bbl, with additional losses of 77,500

bbl/day a year or two in the future as more wells

are abandoned when major expenditures become necessary, for a total loss of 225,000

bbl/day. At $18/bbl, first year losses are 85,000

bbl/day, with additional losses of 4,300 bbl/day

later, yielding a total loss of 89,300 bbl/day. For

the $15/bbl case, the major State losses occur in

Texas (73,900 bbl/day total, or 18 percent of State

stripper 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 5

percent), New Mexico (1 2,400 bbl/day, or 30 percent), and Kansas (6,200 bbl/day, or 5 percent).

Overall, the EIA estimates of first year stripper

well losses are about half the IOCC/RAM estimates. However, although the difference between the two sets of estimates may appear great,

in OTA’s view the differences in the national total are not at all unusual given the lack of data.

I~\’,T, Funk a n~ T,C. Anderson, Dal Ias Field C)ttice, Energy IntormatlonAdmtnlstration, Costs and /rrdices for Dornestlc 0;/ and

Gas Fle/d Equjpment and Production Operations 1985, DOE/EIA0185(85), April 1986.

The EIA analysis’ wide State-to-State differences

among the fraction of total production that is

abandoned is, however, quite different from the

RAM analysis.

More recently, an IOCC survey of California,

Kansas, New Mexico, North Dakota, Oklahoma,

Texas, and Wyoming indicated that 110,000 wells

in these States, with 307,000 bbl/day of oil production, were shut in during 1986, with 12 percent of the wells permanently abandoned. * These

values do not break out the production lost solely

because of low oil prices (each year, thousands

of wells are abandoned even at high oil prices),

and thus they are not strictly comparable to the

projections above. However, most of the production loss is likely to be attributable to the price

drop, and the survey appears to add credibility

to the (higher) IOCC projections. However, the

state-by-state breakdowns show a wide variation

among the States in the percentage of production lost (range: 3.6 to 11.1 percent), contrary to

the assumption of interstate uniformity in the

IOCC analysis.

As noted above, warnings about impending reductions in stripper well production invariably include the prediction that the reserves associated

with the abandoned wells will be lost, either forever or until oil prices reach $50 to $100 per barrel. This is undoubtedly true for older wells that

have depleted a major share of their original recoverable oil, or for newer wells that have been

fractured and have already passed through the

initial production surge associated with fracturing, assuming the use of current well abandonment techniques and well drilling technology.

*Oil and Gas Journal, Apr. 27, 1987, p. 24.
74

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75

However, much of the drilling during the recent

boom was aimed at geologic targets that promised stripper-type production levels. This implies

that, where a substantial level of depletion has

not occurred, a return to the economic conditions of the late 1970s to early 1980s may allow

recovery of the “lost” reserves through new

drilling. in addition, previously there was no incentive to devise well plugging techniques that

would allow a relatively inexpensive reentry into

the well. If such techniques could be devised, or

if advances in drilling technology substantially decreased drilling costs, stripper abandonment

could be reversed more readily.

The Nature of the Resource Base

The nature of the oil exploration and development prospects available to the industry and, in

particular, the distribution of high- and low-cost

oil is a primary determinant of future supply, and

a critical uncertainty. Future development prospects, for example, range from a variety of enhanced recovery operations, to infill drilling and

extensions, to high cost development in the Arctic

and deep offshore; exploration prospects similarly range from new pools in old fields, to large

numbers of small onshore fields, to the search

for giant fields in difficult frontier areas. There is

substantial controversy about the number of viable prospects in each category, and thus a similar degree of controversy about the true replacement costs of oil and the likely supply response

at any price.

There are three types of prospects that represent the critical sources of uncertainty in considering the ability of the remaining U.S. oil resource

base to support continuing development and production, especially in a low price environment.

These are:

●

●

●

the range of conventional drilling prospects

that create field growth,

exploration for small fields. and

exploration for large fields including frontier

giants.

The Prospects for Continued High Levels

of Field Growth

The basic argument that continuing low oil

prices will devastate future U.S. oil production

hinges on the conception of the U.S. oil resource

base as a mature, high cost resource base. According to this concept, most of the United States’

low-cost oil has been found and produced; increasingly, new production must come from oil

finds in hostile, expensive frontier areas or from

high technology, high cost enhanced oil recovery operations, and neither of these sources can

be developed at world oil prices of $15/bbl.

The recent history of the oil industry’s efforts

to regenerate the United States’ oil reserves implies that this conception of a high cost resource

base may be somewhat misleading. It is true that

the geographic and technological frontiers—complex enhanced oil recovery technologies, drilling

in the deep waters of the Outer Continental Shelf,

onshore drilling to depths well below 15,000 feet,

and exploring and producing in the extreme conditions of the arctic–have captured the major

publicity. However, the great majority of oil reserves added to the U.S. inventory during recent

times has come from non-glamorous sources.

Fully 70 percent of the total U.S. reserve additions during 1979 to 1984 came from drilling

thousands and thousands of extension and infield

wells in the United States’ large inventory of discovered oilfields. If Alaska and the offshore are

subtracted, extensions and infield drilling from

previously discovered fields accounted for 76 percent of reserve additions during the last decade,

up from 66 percent during the 1950s and 1960s.38

The potential for continuing high rates of reserve

growth in discovered oilfields at relatively low

cost is one key to the future of U.S. domestic oil

production in a low price environment.

When new fields are discovered, their reserves

are “booked” according to the geologic information gained from the discovery well and other

initial delineation wells. For most fields, the initial 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

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only with those wells drilled in the discovery year.

Afterwards, as the field is developed, the reserve

estimates change, and most often grow. Reserves

grow as additional wells are drilled to delineate

the field’s outer boundaries (extension wells) or

to find additional reservoirs associated with the

field (new pool tests). If prices rise or more efficient recovery technologies are developed, areas

of the field that were previously subeconomic will

be developed with additional development wells.

Further knowledge of the reservoirs gained by

production histories may lead to revisions in the

reserve estimates, or may indicate that the existing well spacing is not recovering all of the recoverable oil, leading to an infill drilling program

that can add to total recovery and thus to reserves. Rising prices may change the “abandonment” point (when the well is shut in because

operating expenses overwhelm revenues) of the

existing wells, leading to further positive reserve

revisions. I n some cases, for example when the

reservoir rock has low permeability, well stimulation techniques such as fracturing may allow

increased recovery, further adding to reserves.

Finally, the portion of the oil-in-place that would

not normally flow to the wellbore might be recovered with enhanced oil recovery (EOR) techniques that loosen the oil’s bonds to the rock by

heating or chemical means or that drive the oil

to the well using a fluid or gas.

How will U.S. fields grow in the future? The

historical record of reserve additions suggests that

older oilfields have “grown” by a factor of about

7 to 8 and gas fields by a factor of about 4 over

the 60-year period from 1920 to 1979.39 Thus, the

potential for further reserves from field growth

will depend on the extent to which these old

fields will continue to grow, and the extent to

which more recently discovered fields, and new

fields, will duplicate the growth potential of the

older fields.

The primary argument for a relatively high reserve growth in new fields and continuing growth

in older fields is that the volumes of “mobile

oil’’—oil that can be recovered with conventional

drilling and well stimulation techniques–have

been consistently underestimated, and that large

amounts of this oil can be recovered with more

intensive drilling even in the Nation’s most mature oil basins. Proponents of this view point to

the 1978 USGS estimate, based on a statistical

analysis of past field growth, of potential reserve

growth in Texas. The estimated ultimate growth

of 4 billion barrels has already been virtually

achieved in the 8 years since the original estimate

was made,40 and growth is continuing at a steady

pace.

A high estimate of the volume of mobile oil in

existing oilfields is based on the proposition that

the so-called “macroscopic” heterogeneity of

hydrocarbon reservoirs is “the least studied, the

least 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 in

reservoir characteristics that can partially or

wholly isolate significant volumes of the reservoir,

extending a few acres a realIy or a few feet vertically, from the remainder of the reservoir. lsoIated compartments or layers of this nature would

be obvious targets for infill drilling and multiplezone completions.

A recent study of the potential volumes of mobile oil over and above that recoverable with

normal field development suggests a “target” on

the order of 80 billion barrels of mobile oil-inplace for the total United States, with an unknown but possibly high fraction of that being

economically recoverable.42 Continued advancement of the state-of-the-art of reservoir modeling and engineering, it is hoped, will allow infill

drilling and well stimulation programs to be

undertaken with relatively low technical risk. Assuming that this is so, the potential profitability

of investments aimed at recovering additional

mobiIe oiI wiII depend on the trade-off between

drilling and stimulation cost, on the one hand,

‘qD. H. Root, “Estimation of Inferred Plus Indicated Reserves for

the United States, ” app, F In G, L. Dolton, et al Estimates of’ the

Undi$co\ered Reco~erable Conventional Resources of oil and Gas

In 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’ Economic

Geology, The Unlverslty of Texas at Austin, 1983.

~~Lewi n & Associates, I nC. , Op. L It.
77

and the additional oil volumes recovered. The

referenced study43 gives some examples of infill

projects that appear, on the basis of the reserves/

well recovered, to have some economic potential even at today’s low oil prices if drilling costs

can be sustained at current low levels. However,

there is little guarantee that these examples are

reflective of the actual resource potential; it is

worth noting that the analysts primarily responsible for raising the issue of mobile oil are acutely

pessimistic of the potential for continuing high

rates of field growth at current low prices .44

To place this potential for field growth in further perspective, it is important to note that there

is by no means a consensus that heterogeneities

within known field boundaries will yield large

quantities of additional oil. Controversy about the

ability of infill drilling to add substantively to

reserves—rather than just to speed production—

has continued for years. In 1967, a massive study

of 312 reservoirs by the American Petroleum Institute’s Subcommittee on Recovery Efficiency

could not determine a relationship between well

spacing and ultimate recovery .45 And a recent review i n the Journal of Petroleum Technology

reiterated that:

A key question in the debate is: “What portion

of the additional oil recovered by infill drilling results from accelerated production of old reserves

and what portion resuIts from increased reserves?”

This relationship is hard to quantify, and assessments differ.46

OTA’s past work supports an optimistic view

of the potential for infill drilling to add significantly

to recoverable oil reserves. In a previous study,

OTA examined the question of infill drilling’s ability to add substantially to domestic gas reserves.47

As part of this examination, OTA conducted a

series 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, Novemher 1983,

47u, S. Congre55,Office ot’ Technology Assessment, Energy and

Materials Program, S(a~l’Mernorandurn on the EfYects of’ Decontro/

on (lid Gas Recovery, February 1984.

drilling and reservoir analysis. OTA found a definite majority in favor of the view that infill drilling

could add substantially to gas reserves, not only

in fields that were widely known to be heterogeneous, but also in fields that were generally

considered to have relatively homogeneous,

blanket-type reservoirs. This majority favored the

view that recent experience supported the view

of oilfields as more heterogeneous than previously understood, that this led to a substantial

potential for increasing ultimate recovery through

carefully selected infill drilling, and that this experience applied to gasfields as well.

Aside from the technical argument about reservoir heterogeneity, many producers argue that

the large amount of infill drilling conducted in

the 1970s and early 1980s has used up most of

the infill potential in the Nation’s stock of older

fields, or at least that portion of the potential that

was economic at the earlier oil prices. Furthermore, these producers argue that today’s “less

favorable” drilling economics reduce the current

infill potential still further. The investigations of

infill potential have not as yet produced detailed

evaluations of the distribution of drilling prospects

that would allow an economic analysis. As implied by OTA’s analyses of some limited drilling

ventures, however, low risk drilling prospects

may be less attractive to producers at prices of

$14/bbl or so than were identical ventures a few

years ago, but prices closer to $18 or $20/bbl

could turn this around; lower drilling costs have

lowered significantly the “minimum required

price” for most prospects.

Pessimists about the role of future field growth

also believe that new fields may have less ultimate growth potential beyond their first year reserve estimates than the older fields. For one

thing, the size distribution of new fields is

weighted more heavily towards the smaller end

of the spectrum, both because the largest fields

tended to be discovered first and because recent

higher prices had allowed fields to be developed

in a size range that would have been termed uneconomic in earlier times. Most analysts would

expect field growth to be highest for large fields,

because the first year’s discovery and delineation

wells 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 fields

in the offshore or frontier areas far from established pipelines demanded better delineation of

field size before the reserves could be booked

and transportation systems developed.49 Our improved seismic technology and understanding of

reservoir behavior also would tend to yield better

—and generally higher—initial reserve estimates

for newly discovered fields.

Exploration for Smaller Fields

A second important resource issue concerns

the extent to which smaller fields–many of which

might have been considered “dry” under previous economic/technological conditions—could

provide substantial reserve additions, and production, in the coming decades. This issue hinges

on both the magnitude of resources contained

in small fields and the economic viability of pursuing small fields as a major exploration target.

Historically, small fields have played a minor

role in oil and gas development. Fully 80 percent

of all discovered oil and gas resources were found

in fields of at least 50 million barrels of oil equivalent, whereas 1 million BOE is considered the cutoff point for “significant” field size. The size distribution of discovered oil and gasfields is shown

in figure 7. As shown in the figure, as one moves

to smaller field sizes, the number of discovered

fields increases steadily down to about AAPG

Field Size D and then rapidly levels off. At least

a portion of this “truncation, ” or leveling off, of

the field size distribution is undoubtedly due to

past economics. Many small finds were too small

to be economically developed and consequently

were reported as dry holes rather than added to

the 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 argument 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 volume

than large volumes), and thus may have more potential for extensions. 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 major 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 has

increased steadily from the 1950s to the present.

search for additional fields in a productive area

when it appeared that most or all remaining finds

would be small. Thus, it has been argued that a

field size distribution of all fields, discovered and

undiscovered, would look more like the dark bars

in figure 8. This distribution assumes that the

progression of field sizes established by the discovered larger fields would continue for the smaller

field sizes if economics did not intrude.

Arguments about the number of small fields

that may be available for exploitation are necessarily speculative because they are based on extrapolation only; no petroleum basin has experienced the intensity of drilling that would be

required to find the postulated number of small

fields. Some past experience with field size distributions supports the general principal that at

least part of the dropoff in the number of small

fields is caused by economic rather than geologic

forces, however. For example, USGS studies of

field size distributions in the Gulf of Mexico, the

Denver Basin, and the Permian Basin show that

the “truncation point” of the distribution moves

to larger field sizes when exploration and development costs are higher, which would be expected if the truncation were economically determined. 50 On the other hand, some analysts

argue that certain types of petroleum basins—

containing a significant portion of U.S. petroleum

resources—show a dropoff in the number of discovered fields at a field size level that is too high

to be explained by economics.51

If the most optimistic field size distribution

postulated in figure 8 is correct, or largely correct, there may be a substantial oil and gas resource residing in small undiscovered fields. in

many instances, these fields would be in producing areas with an existing pipeline and processing plant infrastructure, so development costs

would be low. However, the small size of these

fields implies that the costs of discovery will be

5oJ. H. Scheunemeyer and L.j. Drew, “A Procedure To Estimate

the Parent Population of the Size of Oil and Gas Fields As Revealed

by 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 by

Field 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 Intervals

AAAA >3000

AAA 1200-3000

AA 600-1200 2

300-600 3

150-300 4

60-150 5

6-60 6

<6

9

10

11

12

13

14

15

16

17

18

bcf

76,800-153,600

38,400- 76,800

19,200- 38,400

9,600- 14,200

4,880- 9,600

2,400- 4,800

1,200- 2,400

600- 1,200

3oo- 600

150- 300

75- 150

37.5-

18.75- 37.5

9.38- 18.75

4.69- 9.38

2.34- 4.69

1.17- 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 be

cessful new field wildcats. Past studies of the economics of oil and gas recovery from the Permian

Basin show that the number of exploration wells

that will be drilled is extremely sensitive to oil

prices, with as many as 38,000 exploration wells

drilled at $40/BOE wellhead prices but only 5,000

drilled 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\i

Mexfco, Interagency oil and Gas Supply Project, 1980, It should

be noted, however, that the economic model used In this study

does not capture the effect on drtlltng rates and resource economics

ot the dependency of drilling costs on 011 prices

recovered from small fields at low oiI prices depends primarily on the potential to lower the

costs of discovering these fields by improving discovery technology and raising the success rate

of exploratory drilling.

Finding New Large Fields

A third key to the continuation of high rates

of reserve replenishment and the maintenance

of long-term oil production is the extent to which

U.S. oil explorers can continue to find large new

fields at rates comparable to those of the past dec-
,

I

I

:

i

80

Figure 8.— Known and Projected Size Distributions of Discovered Oil and Gas

Fields in the Lower 48 States

40,000

30,000

20,000

10,000

5,000

100

50

20

0

20 18 17

Intervals bcf

bcf

AAAA >3000 1 76,800-153.600

14 13

Field size

AAA

AA

A

D

E

1200-3000 2 38,400- 76,800

3 19,200- 38,400

4 9,600- 14,200

5 4.880- 9,600

4.800

150-300

60-150

6-80

<6

6 2,400-

1,200-

600-

9 3oo10 150-

75-

37.5-

13 18.75-

14 9.38-

4.69-

16 2.34-

17 1.17-

18 .59-

.29-

20 .15-

2,400

1,200

600

300

150

37%

18.75

9.38

4.69

2.34

1.17

.59

.29

65432 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 remaining prospects of extremely large size will be

successfuI.

Since the early 1970s, the industry has discovered between 200 and 250 “significant” oil and

gas fields (of size greater than 1 million BOE)

every year.53 In addition, the per well “finding

rate” of exploratory drilling, which had been falling for decades, stabilized during the same time

period and now appears to be relatively flat

at about 470,000 BOE per exploratory well.54

Nevertheless, this finding rate has not been sufficient to allow new field discoveries to play a really

crucial role in reserve replacement during the

past decade. For example, during 1979 to 1984

new field discoveries (with expected field growth)

have added only about 2.4 billion barrels of reserves to the U.S. total, out of a total of approximately 15 billion barrels added during this

period.

55 The reason for this is that very few of

the new fields found have been the “giants” that

played 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 disappointing, with the well-publicized Mukluk dry

hole being only one of a string of failures. Recent

exploration efforts in the Gulf of Alaska, East

Coast Jurassic Reef Play, Georges Bank, Beaufort

Sea, St. Georges Basin, and the Norton and Navarin Basins have been either outright faiIures or

have produced far fewer discoveries than anticipated, and recent assessments of U.S. recoverable petroleum resources are said to have severely downgraded prospects for frontier oil and

gas. During the past decade, only six “one billion BOE’’-size plays have been discovered–’’the

Barrow Arch oil and gas trend in Alaska, the

Northwest Santa Barbara Channel oil trend in

California, the overthrust Mesozoic oil and gas

play 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. Oil

Supp/les, op. cit., based on Energy Information Administration, U.S.

Crude VII, Natural Gas and Natural Cab Liquids Reserves, 7984

Annual/ Report, DOE/E IA-021 6(84), September 1985,

81

offshore Louisiana, and the Pleistocene Shelf and

Slope trends offshore Louisiana and Texas.” 56

In the continuing search for large fields, the intersection of resource base issues and prospect

economics comes into sharp focus. There still are

sufficient geologic opportunities to continue the

“baseline” discovery of 200 to 250 significant

fields yearly if the exploration effort aimed at finding these fields holds up . . . but it is precisely in

the area of exploration for new fields that industry analysts are most pessimistic about continuing the previous level-of-effort. Many companies

are telling their stockholders that the focus of their

reserve replacement efforts wiII be shifting away

from exploration in the United States and towards

field development. On the other hand, the “low

oil price” run of the Gas Research Institute’s Hydrocarbon Model, discussed elsewhere, indicated

that, on a resource economics basis, exploratory

drilling could hoId up quite well. An accurate

forecast of the level of exploratory drilling is critical to obtaining a credible forecast of reserve

replacement and future U.S. production.

For the very most promising areas—those that

appear to have real prospects for supergiant

fields–arguments about current resource economics may be somewhat meaningless because

the only remaining areas with such promise are

in the deep offshore and Arctic regions, with time

lags between leasing and production of a decade or more. It does not appear likely that the

more aggressive majors wouId pass u p opportunities to explore in these areas, because oil prices

at the time of any production are unlikely to bear

any relationship to today ’s.

Two such prospective areas critical to longer

term U.S. oil production potential are the unleased California offshore and the coastal plain

of Alaska’s Arctic National Wildlife Refuge (ANWR).

Both these areas boast structures that could hold

reserves of supergiant size, although the recent

Mukluk disappointment should serve as a warning that there often is a long distance between

potential 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 report, Nov. 3, 1986, quoted with permission.
82

resources. Both areas are extremely controversial leasing targets as well, California because of

the remembrance of the Santa Barbara spill and

a longstanding aversion among many of the

State’s residents to offshore development, and

Alaska because of the wildlife and wilderness

Issues.

Because the ANWR is considered by many geologists to represent the most prospective remaining frontier area in the United States, and because

it is today embroiled in controversy, OTA thought

it useful to discuss it here in greater detail.

I

The Arctic National Wildlife Refuge

ANWR was established in the extreme northeast corner of Alaska in 1960 as the Alaska National Wildlife Range. It is the part-time residence

, of approximately 180,000 caribou and millions

of waterfowl and home to such species of animals as musk oxen, Dall sheep, wolves, arctic

foxes, wolverines, brown bears, polar bears, and

, arctic ground squirrels and other rodents. Originally comprising 8.9 million acres, the Range was

I expanded in 1980 to 19 million acres (about half

the size of the State of Washington) with the

1 adoption of the Alaska National Interest Lands

Conservation Act (ANILCA). In all, ANILCA added more than 106 million acres to Federal conservation systems in Alaska. ANWR was redesignated as a refuge at this time, and 8 million acres

1 of it were added to the wilderness system. At the

behest of Senator Stevens of Alaska, 1.5 million

i acres on the coastal plain, which were considered to have significant oil and gas potential, were

set aside for further study. The area is known as

the 1002 area, since Section 1002 of ANILCA required the Secretary of the Interior to prepare a

report to Congress on the fish and wildlife resources and oil and gas potential of the area and

to recommend whether further exploration, development, and production of oil and gas should

be allowed. A draft of the study was released in

December 1986, and the final report was delivered in April 1987.

Petroleum Resources

The western boundary of ANWR lies approximately 60 miles east of the giant Prudhoe Bay

oilfield—the largest in the United States. Prudhoe

Bay was discovered in 1968 and was estimated

to contain over 10 billion barrels of recoverable

oil. Once in full production, the field produced

about 1.5 million barrels of oil daily —approximately 12 percent of the crude oil processed

through U.S. refineries each day. The so-called

1002 area of ANWR, which is being considered

for possible future mineral leasing, is located in

the coastal plain as is Prudhoe Bay and shares

many of the geological features of that highly

productive field. For this reason it is believed that

large recoverable oil and gas resources may also

occur in ANWR.

All of the oil production from the Prudhoe Bay

and the smaller adjacent Kuparuk River field is

from sandstone rocks of the Ellesmerian sequence. At the time the Ellesmerian sequence

was formed, conditions prevailed for the accumulation of potential petroleum-producing sediments which are believed to have later undergone transformation into hydrocarbons. The

porous Ellesmerian sandstone is believed to have

permitted the petroleum to migrate through the

formation until intercepted and trapped by impervious, folded basement rocks. Geologists believe that the petroleum potential of the 1002 area

will largely depend on the extent that the Ellesmerian sequence underlies the ANWR coastal

plain.

Other parts of the 1002 area are underlain by

the younger Brookian sandstone sequence which

is producing oil in the Endicott oilfield offshore

Prudhoe Bay and in the Point Thomson field near

ANWR. A number of offshore wells in the Canadian portion of the Beaufort Sea north of Mackenzie Bay are also producing oil from Brookian

rocks. Geologists expect fewer sealed traps to exist in areas underlain by the Brookian sequence,

hence the prospect for large quantities of petroleum to exist in such areas is less than for the

Ellesmerian sequence. Oil seeps on the coast near

Kaktovic, Point Thomson, and Demarcation Point

are additional evidence of oil potential in the

1002 area.

In preparing its Section 1002 resource report

for Congress, the Department of the Interior collected seismic information over 1,300 miles of the

ANWR coastal plain. Interpretation of the seismic

data by the U.S. Geological Survey identified 26
83

potential hydrocarbon traps. Underground features or structures in the northwest quarter of the

1002 area appear to dip gently to the northeast

with comparatively little deformation, in a manner similar to the Prudhoe Bay structures. The

southeastern portion of the 1002 area is much

more complex and contains many folded and

faulted structures. Complex geology of this kind

makes interpretation of the existing seismic data

more difficult, but several very large structural

closures that couId contain oil have been identified. Similar overthrust structures in the Canadian

and U.S. Rocky Mountains have produced significant amounts of oil and gas.

The 26 identified possible hydrocarbon traps

are located in 7 plays (areas with similar geologic

characteristics that share common geological elements). Resource estimates for the 1002 area are

based on geologists’ judgment about the geologic

factors necessary for formation and retention of

oil and gas and evaluation of the properties that

couId determine the size of a petroleum deposit.

Based on such expert judgment, statistical analyses are used to determine probability estimates

of possible in-place oil and gas resources. Finally,

economic analyses are applied to the geological

estimates to determine the volume of oil that

could be removed from the deposit using current technology.

Because of the inexactness of resource estimates based largely on seismic data, geological

analogies, and future cost-price assumptions, petroleum resource estimates such as those assigned

to the 1002 area should be considered as “relative indicators” for comparison with other potential resource-rich areas rather than as absolute

volumes of recoverable petroleum. A shift in assumed oil prices can significantly change the economics of the minimum field size, which in turn

can increase or decrease estimates of recoverable

oil. Changes in the geologic assessment can dramatically change the estimates of economically

recoverable oil. In the final analysis, estimates of

both in-place and recoverable oil and gas resources should be considered more “guesstimates” than scientific assessments. Exploratory

drilling remains the only certain and totally objective way to determine the presence and extent of oil and gas resources.

it is clear that ANWR ranks high among the

range of potential petroleum-producing prospects

remaining in the United States either onshore or

in the Outer Continental Shelf. Even though the

resource potential for the 1002 area is considered

to be great, however, USGS geologists give odds

of only one in five (20 percent) that a commercial discovery will be made in the entire area

should it be explored. This so-called “marginal

probability” for discovering an economic deposit

seems surprisingly low for an area with such

favorable geological attributes and demonstrated

oil production close by. However, the National

Petroleum Reserve in Alaska (NPRA), which lies

to the west of Prudhoe Bay about 50 miles in a

similar coastal setting, has thus far failed to yield

a commercially important oilfield after substantial drilling, although the U.S. Geological Survey

estimated in 1979 that 7 billion barrels of oil inplace (not gauged by its recoverability) could be

expected.

DOI’s resource estimates for the 1002 area of

ANWR are shown in table 30.

Table 30.—Estimated Oil and Gas Resources in the Arctic National Wildlife Refuge

Section 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 >64.5

Conditional 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 wholly

on geological factors

bEconomlcal[y recoverable 011 that may be available If an economic deposit occurs The odds are one In five (20 Percent) that

this WIII be the case

cThe estimate of ConciitlonallyRecoverable 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 frequently

result in confusion during debates over resource

development on public lands. Petroleum geologists express oil and gas resource statistics in three

different ways:

1.

2.

3

“In-Place” resources–the total volume of

petroleum expected to occur without regard

to economic recoverability or the chances

that petroleum may not occur at all.

“Conditional, Economically Recoverable

resources’’—the volume of oil or gas that

could be recovered under assumed economic conditions and levels of technology,

ignoring the possibility that resources may

not occur at all.

“Recoverable Risked Mean’’–the conditional economically recoverable resource

estimate adjusted downward by the probability that oil or gas may not occur in commercial quantities in the area.

Each type of estimate has its uses, but one must

be careful about the interpretation lest he be

misled. In-place resource estimates have not been

subjected to the vagaries of economic and technological assumptions and predictions that determine how much of the oil in place can be economically recovered. Should oil actually be

discovered in economic quantities in the ANWR

1002 area, in-place estimates can provide an insight to a field’s ultimate potential as technologies

or economics improve. This is important for longrange planning in anticipation that drilling and

production technologies may improve or that

energy prices may change in the future.

Conditional economically recoverable oil and

gas estimates, on the other hand, provide information useful in determining the economic and

strategic potential of a prospect based on existing or foreseen economic and technological

trends. It provides a basis for evaluating the worstcase scenario for environmental and socioeconomic impacts that could result from development of the ANWR 1002 area should commercially important discoveries occur. The chance

that commercial-scale deposits may not occur in

the area is not a factor considered in the conditional estimate.

Risked mean economically recoverable oil and

gas estimates factor in the possibility that no economically recoverable resources exist in the 1002

area. This reduces the conditional estimates of

recoverable oil in proportion to the risk that no

commercially recoverable oil exists in the area.

In the case of ANWR, 3.2 billion barrels of economically recoverable oil is reduced by 80 percent (the probability that no commercial discoveries of oil will occur in the 1002 area) to

determine the risked mean estimate of about 640

million barrels of oil. Natural gas was not considered currently economically recoverable,

hence no estimates of gas were included in either the conditional and risked mean estimates,

although a mean of 31 trillion cubic feet are estimated to occur in-place.

The risked mean resource estimate accounts

for the realities of exploring for oil and gas in frontier regions where few exploratory or stratigraphic

wells have been drilled. It is most useful for estimating regional and national oil and gas resources, where estimates of the potential resources in several unexplored areas must be

combined, or for comparing areas. In the offshore

frontier OCS areas, the marginal probability that

oil might occur ranges from one percent in the

Hope Basin to 70 percent in the Beaufort Sea off

the north coast of Alaska. Why the marginal probability of oil in commercially recoverable volumes

is 20 percent for the ANWR 1002 area and increases to 70 percent in the Beaufort Sea offshore

area immediately north of ANWR, where even

less is known about the subsurface geology, was

not addressed in the U.S. Geological Survey’s resource estimates of the 1002 area.

ANWR is one of the few remaining unexplored

major onshore prospects in the United States. Although much of Alaska remains unexplored for

oil and gas, ANWR holds the most promise for

the discovery of giant fields. Most of the other

highly prospective oil and gas areas are offshore

in the Outer Continental Shelf. When risked

mean resource estimates of oil for the ANWR

1002 area are compared with the frontier OCS

oil and gas lease planning areas, it ranks third,

behind the Navarin Basin (1.3 billion barrels), and

the Beaufort Sea (0.9 billion barrels). Furthermore, when the results of recent drilling disap-
85

pointments in the Navarin are formally factored

into resource calculations, ANWR might rank still

higher. Risked mean resource estimates for

ANWR nearly match those expected for the entire Atlantic OCS Region (0.68 billion barrels).

Both the Navarin Basin (upper Bering Sea) and

the Beaufort Sea, being in offshore Arctic waters,

are located in difficuIt operating environments

which must contend with sea ice, severe weather

conditions, extremely low temperatures and long

winter periods of near total darkness. Offshore

exploration and development is extremely expensive under these conditions, and the distances

that oil would have to be transported will likely

require very high per-barrel prices ( >$32 per barrel) and giant fields of 250 to 500 million barrels

to warrant development. The Department of the

Interior determined that the most likely minimum

economic field size in ANWR would be 440 million barrels at $33/bbl (1 984$). This appears to

be somewhat larger than might be expected

when compared to more expensive offshore development. However, the determination of economic field size depends on many assumed economic factors, in addition to location onshore or

offshore, which cannot be determined in frontier regions until a field is delineated.

ANWR Petroleum Resources

in Perspective

The economics of any exploration and development of oil and gas resources that may occur

in the ANWR 1002 area are closely tied to the

existence of the Trans-Alaska Pipeline System

(TAPS) which originates at Prudhoe Bay. TAPS has

the capacity to transport about 2.2 mmbd of oil

from the North Slope to its marine terminal at Valdez on the southern coast of Alaska. Prudhoe Bay

throughput has ranged between 1.5 and 1.8

mmbd since the field came on line at maximum

production. However, with Prudhoe Bay production soon to be declining and increases in oil reserves through field extension not keeping pace

with drawdown, there will likely be ample excess pipeline capacity to accommodate as much

as 1 mmbd of oil from ANWR by the time that

maximum production could possibly occur,

While the cost of a feeder pipeline from ANWR

to Pump Station No. 1 at Prudhoe Bay would be

substantial, the existence of TAPS and its potential excess future capacity boosts the economic

outlook for ANWR. However, the potential resource base is not equally distributed throughout the 1.5 million acres of the ANWR 1002 area.

Over three-quarters of the in-place oil is expected

to occur in the extreme western portions and the

extreme eastern portions, with the central area

having the lowest potential. Resources that may

be discovered in the eastern blocks of ANWR

would require almost double the length of feeder

pipeline required for resources occurring in the

western block.

Although natural gas was not considered by the

Department of the Interior in determining the estimates of economically recoverable resources, its

potential as a future resource cannot be wholly

ignored. Prudhoe Bay gas is currently reinfected

into the producing formations to maintain pressure and conserve the resource. Production in

ANWR would follow a similar course. But the uncertainty of the U.S. energy future suggests that

Alaskan natural gas may evolve into a future economic resource of considerable value. Although

no credible analysis could be devised to prove

this point, sufficient uncertainties about energy

pricing and hydrocarbon supplies exist so that the

possibility of future economic viability should not

be discounted.

Current prices in the depressed world oil market logically raise questions about the feasibility

of exploring for petroleum in the high-cost Arctic Tundra. But today’s oil prices are not a reasonable measure of economic feasibility for investment in exploration and development that

may require decades to complete. From the time

the Secretary of the Interior forwarded the ANWR

report to Congress (in April 1987), at least 3 to

5 years may be necessary for the enactment of

leasing legislation. Unless Congress approved

administrative shortcuts, at least an additional 3

to 4 years would be needed to promuIgate regulations, prepare an environmental impact statement, and process leases.

If exploration and development were to begin

between 1992 and 1995–6 to 9 years after the

legislative process begins–it would not be until
86

2002 to 2005 that production would likely begin in ANWR assuming 10 years from the beginning of exploration to development and first production. Recent experience with erratic changes

in energy prices and the course of the national

economy suggests that it is foolhardy to speculate on economic conditions 15 to 18 years in

the future.

Exploration costs in the coastal plain of ANWR

would be considerably cheaper than any comparable offshore exploration program in the OCS

with the highest prospects for the discovery of

very large oilfields. The cost of drilling an exploratory well onshore in the Arctic is generally estimated to be in the range of about $10 to $25 million. An exploratory well in the frontier Navarin

Basin in the Bering Sea is estimated to cost about

$55 million. Exploratory wells in the Beaufort Sea

are estimated to cost on the order of $30 million

for ice-free conditions and up to about $50 million for ice conditions. The Mukluk exploration

well on an artificial island in the Beaufort northwest of Prudhoe Bay, when abandoned as a dry

hole, cost an estimated $140 million, although

part of the high cost has been said to be due to

the need to maintain a very fast pace.

The Department of the Interior foresees the

need for about 25 exploratory wells for the

ANWR 1002 area under its full leasing scenario

and 16 under a scaled-down alternative centered

on the best drilling prospects. If drilling costs can

be held to the low side of the range for onshore

Arctic drilling, total cost for exploratory drilling

(not including general support facilities) on

ANWR could range between $160 million and

$250 million. Compared with the costs for drilling

exploratory wells at single locations in the best

offshore prospects of Alaska ($30 to $50 million

and up, for most situations), ANWR may offer the

cheapest and perhaps the most direct way to determine whether another giant oilfield lies below

lands under the jurisdiction of the United States.

However, before ANWR is leased and explored,

formidable environmental issues must be resolved.

Environmental Issues

Background.–A major battle is expected between development-oriented and environmental

groups over the issue of whether or not to proceed with oil and gas exploration and eventual

development in ANWR. The oil industry, as well

as many elected officials from the State of Alaska,

key personnel from the U.S. Department of the

Interior, and several native Alaskan organizations,

view the coastal plain of the ANWR as having the

most promising oil and gas potential of any region in the country. Environmental groups contend that the wilderness value and wildlife habitat the area provides are unparalleled and that

development would threaten the animals (particularly the Porcupine caribou herd) that spend

all or part of their time in the Refuge.

The Fish and Wildlife Service (FWS) was designated by the Department of the Interior to conduct the 1002 study on the fish and wildlife resources and petroleum potential of the ANWR

coastal plain. The study is essentially a response

to the question of whether or not oil and gas development can coexist with wilderness and wildlife in the ANWR area, or, alternatively, a determination of the relative importance with respect

to national needs of oil development and preservation of the refuge. FWS found that “long-term

losses of fish and wildlife resources, subsistence

uses, and wilderness values would be inevitable

consequences of a long-term commitment to oil

and gas development, production, and transportation, ”57 and also that leasing of the 1002 area

“could contribute billions of barrels of additional

oil reserves toward the national need for domestic

sources. ’ ’58 Based on its findings, FWS has recommended that Congress authorize the Secretary of the Interior to lease the entire 1002 area

for oil and gas exploration and development. 59

Key Environmental and Socioeconomic Concerns.–The entire ANWR, including the coastal

plain, is in fact if not in name a wilderness area,

that is, an area essentially untouched by development. Although the area considered for leasing (1.5 million acres) is only a fraction of the refuge, it includes virtually the entire coastal plain

of northeast Alaska.

szu .S.Depaflrnent of the Interior, ArctK National W//d/ife Refuge, 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 development

in ANWR would not only diminish the wilderness nature of the coastal plain but would eventually make it easier to explore adjacent offshore

areas and the remaining State land between Prudhoe Bay and the ANWR for oil and gas potential. All of these developments would have additional negative environmental impacts on the

Arctic coastal plain. A bill to designate the coastal

plain of the ANWR as wilderness has already

been submitted to Congress by Congressman

Morris Udall and was recently reintroduced in

the 10Oth Congress.

A key concern is the impact that development

wiII have on the approximately 180,000 caribou

of the porcupine herd that use the refuge. One

part of the coastal plain is particularly important

as a calving area for the Porcupine herd. The

coastal plain also offers relief to the herd from

insects. Before actual exploration and development occurs, it is difficult to say what the impact

of oil and gas development on the herd will be.

Those in favor of development point out that the

Central Arctic caribou herd, whose range includes the Prudhoe Bay area, has actually increased in size since development began. The

Porcupine herd, however, spends less time on

the coastal plain than the Central Arctic herd, and

the question of whether the Porcupine herd can

be acclimated to development like the Central

Arctic herd is open to debate.

The U.S. Fish and Wildlife Service has concluded that it is reasonable to assume that development can proceed with minimal adverse impacts on the herd. In the draft 1002 report, FWS

proposed that the most sensitive area (an area

of approximately 242,000 acres) be leased last—

after determining how the caribou respond and

what mitigation measures would be most effective. The final version of the draft, however, recommended that the entire coastal plain be

opened to leasing. Most environmental groups

are not convinced that oil and gas development

is compatible with the health of the caribou herd.

Also, although the focus of attention has been

on caribou, other wildlife in the area could b e

affected by development.

Of particular concern to some environmentalists is construction of a haul road and pipeline

connecting Prudhoe Bay with the ANWR. The

presence of either would disqualify the coastal

plain for wilderness status. in addition, the pipeline could be a barrier to caribou migration, and

some worry that it could eventually be extended

to the MacKenzie Delta area in the Canadian Arctic, 60 thereby eliminating more wilderness.

Socioeconomic consequences for the native lnuit population (especially in the village of Kaktovik) are also expected to be significant. The Inuit

have subsurface rights to a considerable amount

of acreage and can be expected to profit from

development. Two native corporations, the Kaktovik Inupiat Corp. and the Arctic Slope Regional

Corp., are involved, and have generally been supportive of controlled development. Other native

groups–particularly those dependent on the Porcupine herd but unlikely to share in the direct

economic benefits of oil development—have opposed development.

Development would bring changes in the traditional subsistence lifestyle of most natives, as

more Inuit would have the opportunity to work

for cash in the oilfields. Introduction to 20th century culture has proven to be a two-edged sword

to Inuit in other parts of the Arctic, however.

Modern conveniences benefit Inuit just as they

benefit others, but development is also at least

partly responsible for the increase of such social

problems as alcoholism. While happy to have additional income, many Inuit regret the decline of

traditional culture.

The Effects of the Natural

Gas Surplus

Since the early 1980s, natural gas production

capacity has been in substantial surplus, primarily because of declining demand in the electric

utility and heavy industry sectors but also because

of a surge in gas deliverability. This surplus has

been remarkably persistent, and it has created

a situation in which producers in some parts of

the country cannot be assured of markets for new

gas production. The disincentive for gas drilling

fJJAlthOugh there appears to be I ittle reason for such an extension, because the TAPS plpellne should have adequate excess capacity in the appropriate timeframe to handle any ANWR production.
88

created by poor markets has affected overall

drilling patterns of the past few years. The overall economic effect on oil drilling is mixed: on

the one hand, because many oil wells produce

gas and because some drilling seeks hydrocarbons rather than oil or gas in particular, the slack

gas market can hurt oil drilling; on the other

hand, the reduction in total drilling caused by the

poor gas market was one of the causes of the

large reduction in drilling costs between 1981 and

the present, and this reduction in turn improved

the economics of oil drilling. Most probably, an

I end to the surplus and reestablishment of firm

without a very large increase in drilling—an unlikely event if oil prices remain low. However,

the two determinants of the date of an end to the

surplus—gas supply and gas consumption—are

quite uncertain. Consumption is greatly affected

by fuel switching to oil, which in turn is dependent on uncertain oil prices and the ability of gas

pipelines to compete with oil on price. Future gas

supply is the subject of a substantial divergence

of opinion, even more so than is future oil supply, although most forecasts agree that U.S. domestic production will decline in the 1990s and

will 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 Industry

Affecting U.S. Oil Production

Changes in the Climate for Oil

Investments in the United States

and Overseas

The United States represents the most “mature, ” most intensively drilled of the world’s petroleum regions, yet continues to attract a lion’s

share of exploration and development expenditures. The raw statistics—70,000 barrels found per

U.S. wildcat well v. 7 million per wildcat for the

rest of the world—paint too extreme a picture of

the United States’ geologic inferiority, because

the nature of its infrastructural development

makes economic many low-payoff driIling ventures that could not be attempted elsewhere. It

is nevertheless true that geological prospects generally are far superior overseas than in the United

States, particularly the Lower 48 States, yet the

major oil companies, most based in the United

States, continue to spend most of their capital domestically.

An important reason for this appears to be the

greater stability and security available within the

United States. The major oil companies learned

a harsh lesson when the Middle East OPEC nations nationalized their oil production and transformed these companies from producers to

buyers. Also, the governments of many oilbearing countries offered only relatively harsh

terms for development of their oil resources.

Their strategy was stimulated by the belief that

oil prices would continue to rise, so that they

could benefit by withholding their resources for

later development (at much higher prices).1 In

addition, until recently, hostility to foreign, private investment of any sort was common among

the developing nations.

Industry analysts claim that the business climate

for overseas oil investment is improving relative

‘See MA. Adelman, “World Oil: Availability and Price: The Next

Ten Years, ” AsIan Development Bank, Regional Meeting on Energy Policy, Dec. 11-12, 1986.

to that of the United States and that, in response,

oil company attitudes towards overseas investment are shifting. Industry experts at an OTA

workshop unanimously agreed that the large oil

companies were shifting their attention to overseas drilling prospects. A recent Salomon Bros.

survey found that U.S. oil companies expect to

spend 29 percent of their 1987 budgets outside

the United States compared to 12 percent in

1986.2

Presumably, the reasons for the improving climate are twofold. First, the developing nations

have become more sophisticated both economically and politically. They have come to appreciate the potential benefits of private and foreign

investments and do not fear as much as previ- 1

ously the accusation that they are selling out to

foreign interests. Second, they have come to rec- *

ognize, in light of falling prices, that the delay of

oil and gas development has created a substantial loss, rather than a gain, in investment value. I

These shifts in attitude and understanding have

been translated into a variety of concrete actions .

designed to attract oil and gas investment, including:

●

●

●

●

●

●

●

●

removal or raising of former caps on prices

paid to foreign producers (Angola, Color-n- ‘

bia, Morocco, Canada, Turkey);

contractors now paid in dollars rather than

local currency (Argentina, Chile);

removal or reduction of prior oil taxes (Canada, Morocco, Trinidad, United Kingdom);

reduction of royalty rates (Canada, China,

Morocco, United Kingdom);

easing of requirements for training and employing nationals (China);

flexibility in shifting lease areas (China);

tax or royalty relief for areas deemed difficult to explore (Chile, it-eland);

customs taxes waived for imported materials 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, exploratory drilling, etc. (Korea); and

● a variety of more favorable tax and cost recovery rules and other incentives.3

Oil industry spokesmen claim that the United

States, in contrast to most other countries competing for oil investment, has enacted tax and regulatory changes that substantially worsen the

business climate for oil and gas investment,4 and

weaken the Nation’s ability to attract such investment. For example, the American Petroleum Institute claims that the 1986 Tax Law will cost the

industry $10 billion over the next 5 years, and

that the potential reclassification of drilling wastes

to the hazardous category by the Environmental

Protection Agency could cost the industry up to

$8 billion annually.5

Evaluating the relative “business climate” for

petroleum investments of the United States versus

competing foreign nations is difficult. It is dependent on the type of investment being contemplated, the differences in geologic situations, the

complex tax, royalty, and regulatory structures

i n the United States and abroad, differences in

the availability of skilled labor and other factors

of production, and impossible-to-measure differences in political stability and physical security.

In general, we are impressed with the failure of

most discussions of the opposing climates to deal

with the above factors in a careful fashion, and

we warn against drawing simplistic conclusions.

Also, overseas oil investment can be beneficial

to U.S. national security because increased reserves and production outside of the Middle East

increases market stability and diffuses the potential for embargoes and price shocks. Thus, although it probably is fair to claim that the relative attractiveness of overseas investment is

improving vis-a-vis domestic investment, it is not

clear whether this shift is towards or away from

a desirable balance of overseas and domestic investment.

3Barrows Company Inc., New York, NY, “World Incentives for

Petroleum Investment, 1980-1 986, ” prepared for the United Nations Department of Technical Cooperation for Development.

4See, for example, American Petroleum Institute, Two Energy Futures: 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&D

activity have declined in the face of sharply lower

oil prices, the results of that activity, in new fields

discovered, volumes of oil added to reserves, and

added production capacity also would be expected to decline. However, it is unlikely that

these results will drop precisely in lock step with

the declines in activity levels, because the “efficiency” of this activity is likely to change also.

Understanding how the various measures of efficiency might change is important to projecting

future oil reserve additions and production levels.

Few if any of the measures of efficiency in exploration and development have remained stable over the past decade and a half. Such efficiency measures as finding costs (reserves added

per dollar spent on exploration and development), rig efficiency (annual footage or wells

drilled per active rig), finding rate (reserves added per well or per foot drilled), and completion

rate (successfuI wells/total wells drilled) have varied substantially as oil prices and overall industry activity has ridden a cycle of boom and bust.

Because these measures have in the past been

so sensitive to changes in economic conditions

and especially to changes in oil prices, they are

likely to have shifted dramatically–and possibly

to continue to shift-in the face of the severe economic dislocations of the past several months.

As an example, finding costs escalated rapidly

during the 1970s and very early 1980s, peaked

in 1982 at $13.53/bbl (including revisions) and

then have slid substantially in the face of declining oil prices.6 Reliably projecting future finding

costs is critical to projecting future production,

and especially critical to production projections

that rely on first predicting capital spending and

then calculating reserve additions by using the

equation:

Reserves added = (Capital Spending) /(Finding Costs)

To project likely future finding costs, it is necessary both to understand the relationship bebAflhUr AnderSen & Co., op. cit. Note that the authors Cal! these

values “surrogate” finding costs because they combine expenditures made and reserves added in the same year, whereas true finding costs would match expenditures to the actual reserves these

expenditures created, usually a few years later.
91

tween finding costs and the variables affecting

them, and to predict the future values of these

variables. Unfortunately, finding costs—like the

other efficiency measures—are functions of several variables, some of which cannot be easily

tracked. These variables, which are not independent of each other, include oil prices, drilling

and other service costs, drilling strategies (especially the relative emphasis on deep drilling and

other high cost drilling), resource depletion, the

availability of promising exploratory acreage, and

the technical efficiency of exploration and production technologies. In general, rising oil prices

have led to rising finding costs, and vice versa,

largely because higher prices stimulate activity

aimed at smaller reserve targets or higher cost

environments, and lower prices force operators

to focus on higher quality (lower finding cost) targets. The past few years have seen sharply decreased finding costs. A fair expectation is that

finding costs will remain low if oil prices remain

depressed. However, this is not certain, and it

wiII be difficuIt to predict the magnitude of finding costs with any precision. For example, the

energy economist Arlon Tussing, in his testimony

of March 6, 1986 to the House Energy and

Commerce Committee, predicted that the slide

in finding costs that began in 1982 would be

found to have continued into 1985, with costs

declining about $1.50/bbl from their 1984 value.

The recently published Arthur Andersen survey

found, however, that 1985 finding costs had gone

up from 1984’s costs by about $1/bbl, presumably because of the relatively low reported 1985

reserve additions as well as a 7 percent increase

in completed well costs.

Another efficiency measure, so-called “rig efficiency” (footage and wells drilled per rig per

year), declined from the middle 1970s to the early

1980s as oil prices rose and oilfield activity accelerated. Part of this decline was due to the use

of inexperienced personnel and marginal equipment, made possible by the inability of the supply of services to keep up with the demand. Part

was due to the spread of drilIing activity to more

marginal prospects, with lower reserves and perhaps more difficult drilling conditions, and to high

payoff but high cost prospects–like deep gas–

that required more rig time; this was partly a result of the improved economics of these

prospects, and partly an effect of resource depletion as the best prospects were used up,

As oil prices began to decline in 1981, drilling

became more efficient as the number of inexperienced drilling crews declined, inefficient rigs

were dropped from service, footage and turnkey

contracts replaced contracts that paid drillers by

the day (day rate contracts offered little incentive for efficiency), and drilling technology improved . . . and thus rig efficiency increased sharply between 1981 and 1985: the industry drilled

89,000 wells in 1981 with nearly 4,000 rotary rigs

active; 84,000 wells in 1982 with 3,100 rigs active; and 85,000 in 1984 with 2,400 rigs. Unfortunately, however, the precise dimensions of the

actual increase in efficiency are obscured by

other factors that also affect measured rig efficiency. These factors include: the proportion of

total drilling devoted to exploration, because exploratory drilling is more time-consuming than

development drilling; possible changes in the

number 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 time

than oil wells; and shifts in the geographic distribution of drilling, because drilling in some areas,

such as the gulf coast, is more rapid than in

others, e.g., the Midcontinent and Rocky Mountain Overthrust Belt, because of different rock

conditions and other physical factors. Although

OTA is not aware of analyses that have systematically isolated the effects of the various factors influencing rig efficiency, several of our reviewers

believe that shifts in drilling targets areas important as actual changes in drilling equipment and

operational efficiency as causes of the changes

in rig efficiency over the past decade and a half.

Another measure critical to many forecasting

methods is the “finding rate” of drilling, measured in reserves added per well drilled. s The decline in drilling now occurring, and expected to

7Commonly used rig counts include only so-called rotary drilling rigs, rigs that drill by rotating a drill bit and Its attached drllli ng

pipe.

aThere are other measures of fi ndl ng rate, for example, reserves

added per exploratory well. Problems In tying together “reserves

added’ and the specific activities that ‘‘created” these reserves are

endemic to oil and gas analysis, and no particular measure of finding rate can escape these problems,
92

continue, will certainly not be so uniform as to

leave the finding rate untouched; a 50 percent

decline in drilling is unlikely to yield a 50 percent decline in reserve additions except by some

unlikely coincidence.

Figure 9 shows the change in oil finding rate

from 1960 to 1983, with “reserves found” computed by assuming a time lag between exploratory drilling and reserve development of 4 years

for onshore drilling and 7 years for offshore.9 The

drop in finding rate beginning in the early 1970s

may be partly because of resource depletion, but

common sense implies that, because of improved

economics associated with higher oil prices, a

substantial role must have been played by increased drilling of marginal prospects within each

region, as well as increased drilling in less productive regions. The role of shifting drilling patterns

is complicated by the observation that, during the

same period, some explorers responded to the

price increases by drilling in expensive, high risk

regions that promised very high returns per well.

However, the lack of exploration success in many

of the new drilling areas and the huge number

of new marginal wells that were drilled sustain

the above interpretation.

OTA believes that the average finding rate

achieved by the smaller number of wells being

drilled in 1986 might be somewhat higher than

recent historical rates; in other words, OTA believes that the finding rate is likely to swing back

up the curve in figure 9. Some insight into the

potential increase in finding rate can be gained

by examining recent regional shifts in drilling.

Short-term changes in drilling patterns, as projected by the Oil and Gas Journal,10 imply that

drilling declines will be greatest in areas with relatively low finding rates. Because finding rates differ greatly from region to region, such a shift has

great potential to change the national finding rate.

For example, adopting the assumption that 1980

to 1984 regional finding rates will still be

reflected in 1986 drilling will result in an estimated national finding rate for 1986 that is 40 per-

‘A. T. Guernsey, Profitability Study. Crude Oil and Natural Gas

Exploration, 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 per

Oil Well)

1960 1970 1980

Year

SOURCE: A T Guernsey, Profltabf/lty Study, Crude 0// arrd Natura/ Gas .Exp/orat~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. This

in turn would yield 1986 reserve additions for the

United States that would be considerably higher

than would be projected assuming a 1 -to- 1 relationship between reserves and drilling rates: specifically, 2.2 billion barrels for the regionally adjusted value versus 1.6 billion barrels without the

adjustment, assuming that 46,000 wells (including dry holes) are drilled in 1986. ’

OTA does not believe that the “regionally adjusted” estimate of 2.2 billion barrels is the

“right” value for 1986 reserve additions. A variety of other factors, such as intraregional shifts

in drilling, must still be accounted for. In particular, oil companies are predicting a significant shift

away from exploratory drilling towards low risk

development drilling; such a shift would tend to

lower finding rates and thus lower reserve additions. Also, in the years following 1986, drilling

patterns will continue to change even if prices

do 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 tor

1986.
93

present lease and other commitments, and these

will expire. Company strategies will change, especially since current drilling behavior is affected

substantially by its nearness in time to the recent

price shock and the turmoil it created. As discussed above, the industry is in a period of transition, and it is far from clear what its exploration and development strategies will look like a

few years from today.

Despite the uncertainties created by these factors, it is useful to project future domestic oil production levels by using a “what if” scenario that

assumes a continuation of the projected 1986

drilling levels and the optimistic value for reserves/well that reflects only the new geographic

distribution of drilling without accounting for factors that might reduce the reserves/well value.

The results of just such a projection are discussed

in detail in chapter 7.

Changing Oilfield Technology

Continuing evolution of the technology of oil

exploration, development, and production is

likely to play an important role in the basic economics of oil exploration and development and

the size and rate of exploitation of the recoverable oil resource base. For example, advancements in seismic technology that allow for both

finer resolution and significant reductions in data

collection and analysis costs will be crucial in

finding and producing the many thousands of

small oil and gasfields. Technological advancements that will substantially decrease production

costs—e.g., subsea production systems—are critical to developing offshore fields at today’s low.

oil prices.

Unfortunately, analysts have had little success

at trying to quantify the effects of technological

change on oil development. For one thing, there

is enormous variability of technical requirements

across different prospects, so patterns of technological use are difficult to track. Also, technical

capability varies widely among oilfield operators,

so that different operators working in the same

field and same physical conditions may choose

different technical approaches. In our interviews

with oilfield operators, OTA was struck by their

differing assessments of the importance of technological changes in the past and the potential

for such changes in the future. Some describe the

past decade and a half as a time of only modest

technological change; others describe “tremendous advances in exploration and extraction technologies.” 12 It is OTA’s impression, however, that

the majority of oilmen are pessimistic about the

potential for technology to make a big difference

in costs in most situations. in particuIar, oilmen

point to the failure of new exploration technology to cause a measurable change in dry hole

risk, and the steady downward progression of

performance measures such as reserves added

per well.

OTA believes that technological change has

played an important role in oil exploration and

development during the past decade or two, but

that other forces affecting oil markets, especially

the price shocks following the Yom Kippur War

and the Iranian revolution, obscured the effects

of technology. Most importantly, the hyperinflation of oilfield services starting in the middle

1970s simply overwhelmed any statistical evidence of the many cost-cutting effects of new and

evolved technologies, Nevertheless, the following technological changes clearly played a significant role in stimulating the movement of resources into the recoverable range, whether by

affecting the economics of prospects that previously could have been recovered but had insufficient profit potential, or by moving resources out

of the technically unrecoverable range to the recoverable:

●

●

●

●

significant improvements in the longevity of

drill bits;

movement of seismic interpretation from

strict reliance on mainframe computers to

widely available minicomputers, and the development and spreading use of 3-D seismic

techniques;

numerous advances in enhanced oil recovery technologies;

development of subsea completion and

floating production systems, that both allow

‘2H. R. Linden, “Impact of Advances in Science, Technology and

i n the Understanding of the Terrestrial Origin of Hydrocarbons on

the Role of Natural Gas and Crude Oil in Meeting Future Primary

Energy Needs,” Gas Research Institute, july 18, 1986.
94

●

●

●

●

●

●

●

the exploitation of smaller offshore fields and

lower the risk of certain high-risk large fields;

improvements in offshore platforms, especially movement to lighter, less expensive designs (e.g., the tension leg platform);

development of measurement-while-drilling

techniques 13 that help avoid mishaps, permit more accurate directional drilling, and

reduce the probability of missing productive

zones;

continuing evolution of various subsystems,

e.g., drilling mud systems;

development and/or improvement of sophisticated nonseismic exploration techniques,

including remote sensing techniques and

geochemical techniques;

vast improvement in fracturing techniques

for low-permeability reservoirs, especially

critical for gas recovery;

development of horizontal drilling techniques that allow economic recovery from

thin pay zones and promote full field development at lower costs; and

development of more sophisticated mathematical models for reservoir simulation that

allow better design of well placement for

field development.

OTA has become aware of several recent technological improvements that demonstrate the potential of advanced technology to make important changes in the economics of exploration and

development:

●

●

●

A factor of two improvement in the resolution capability of seismic imagery, which has

important implications for development well

placement and exploration for small fields.

The recent development of improved nuclear logging tools that can detect oil and gas

behind well casing. This will allow the identification of producing zones that were

missed during initial exploration, with particular implications for increasing production

from existing wells.

The development of so-called stratigraphicseismic techniques which can improve exploratory well success.

13Measurement of rock permeability and porosity, hydrocarbon

presence, and other important variables without shutting down drilling and removing the drill “string. ”

●

●

●

●

●

●

New methods of 3-D seismic mapping of

reservoirs that provide similar detail at half

the cost of previous approaches. Although

3-D seismic is a powerful exploratory and development drilling tool, its use has been

limited because of its cost.

New developments in chemical enhanced

oil recovery (EOR) that have lowered the

threshold of profitable application from $25

to $30/bbl to about $20/bbl for this type of

EOR. This will offer major opportunities for

implementing EOR more widely than previously expected, with higher recovery efficiencies.

New techniques for three-phase flow measurements of oil, water, and gas that will allow the elimination of expensive test separators in offshore platforms, lowering

somewhat the economic threshold for offshore recovery.

Substantial decreases in the cost of multicomponent seismic imagery, which uses

standard compressional waves in combination with shear waves to allow higher spatial resolution, direct identification of rock

types, measurement of porosity and permeability and direct hydrocarbon detection. A

new multicomponent seismic source costs

only about 50 percent more than compressional seismic, which will open this technology to practical application.

The initial uses of CAT scanning to observation of flow inside porous rocks. Continued

research should lead to improved mathematical modeling of non-uniform flow inside

reservoirs, critical to optimizing EOR design.

The first Alaskan well using “extended reach

horizontal drilling” was drilled by Standard

Oil and tripled the output of conventional

drilling in the same formation. By allowing

the development of areas where the pay is

too thin to develop with conventional

drilling, it is hoped that this technique will

allow increased recovery at Prudhoe Bay.14

The continuing development of new and improved technologies, especially focusing on cutting costs, will be a crucial determinant of the fu1 gArlOn R. TUSSing & Associates, Inc., The PrOPeffY- Tax Base of

the North Slope Borough, Alaska, May 1, 1986.
95

ture success of the industry in reducing the

decline in oil reserves and production rates expected to accompany lower oil prices. Although

the level of effort in oilfield R&D is difficult to track

because it is hidden in many different accounting “cub byholes,” most industry observers feel

that it has been cut back substantially. For example, the former president of Exxon Research &

Engineering Co. has estimated that research, development, and engineering within the industry

has been cut by at least 30 to 40 percent in the

last 3 years.15

If the observers are correct, and if the industry wishes to be able to prevent large production

drops, the industry probably is doing the opposite of what it should be doing, despite its need

to economize in response to drastic cuts in revenues. I n the face of drastic changes in their economic environments, other industries have

achieved large cuts in production costs. It seems

reasonable to project that the oil industry would

stand a good chance of achieving the same.

According to the French Petroleum Institute (lnstitut Francais du Petrole, or IFP), potential nearterm improvements in oilfield technology can offer very substantial cost savings. IFP identifies key

advances as:

● optimization and automated control and

management of drilling, based on the most

sophisticated use of measurement-whiledrilling, offering a potential reduction in

drilling cost of 30 to 35 percent;

● optimization of the understanding of reservoirs as the result of progress in the modeling of their dynamic behavior, leading to better well placement and the need for fewer

development wells;

● further development of seismic imagery to

help in understanding reservoir behavior, including increasing its power of resolution to

provide detailed images of the reservoir; development of seismic devices that can operate inside the well bore, leading to the same

result as above as well as a higher success

rate for exploration wells;

1 ~Edward E, David, quoted In the “News and Comment’ section of Science, vol. 232, June 27, 1986.

● improvement in enhanced recovery techniques, including drilling techniques such as

horizontal drilling; and

● continued improvement i n offshore platforms for shallower waters, and development

of “all on the bottom” systems for deeper

waters. 16

IFP estimates that full success of such a technology development program and its successful

implementation couId create substantial savings

in the overall technical costs of production (including exploration and development costs),

namely:

Onshore fields .......................... savings of 20 to 25 percent

Conventional offshore fields savings up to 30 percent

Deep offshore fields:...................... savings of 30 to 50 percent’ 7

If the IFP estimates are valid, then technological advances could move a large share of petroleum resources from the subeconomic to the economic range at $15 to $20 oil prices. The majority

of industry reviewers of the draft version of this

report were quite skeptical of the IFP estimates

and felt they were substantially overoptimistic.

There were, however, a minority of “technology

optimists, ” some of whom are familiar with current research and development programs, who

are hopeful about the potential for achieving cost

savings of this magnitude. These hopes are, of

course, dependent on the industry somehow

resisting the current trend towards reduced R&D

expenditures and focusing a substantial effort on

cost-saving technology.

Deteriorating Industry Infrastructure

and the Potential for a Rebound in

Oil Production

Introduction

Although the current decline in U.S. domestic

oil production and the expected further production declines are dismaying in and of themselves,

the declines translate into problems for U.S. national security and economic stability only to the

extent 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,” presented

at 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 oil

or a large increase in its price. In fact, if production could rebound in this way, future disruptions

might be less probable.

In general, a decline in domestic production

will not be easily reversible. it is true that some

of the wells that are shut in can be placed back

in production (although the number of such wells

will diminish sharply after a few years). I n addition, some EOR projects that are moth balled can

be restarted (although it may take a few months

for additional production to start flowing and the

production response to the EOR may be reduced). In general, however, significant amounts

of incremental production can be added only by

reworking old wells, by drilling new ones, both

exploratory and development, and by developing new EOR projects or expanding existing

projects. All of these activities are capital-,

manpower-, and equipment-intensive, and gaining significant increments of production—which

will require tens of thousands of individual drilling

and other projects—will be time-consuming even

if capital, equipment, and manpower are

plentiful.

There are now substantial doubts as to whether

capital, equipment, and manpower will be plentiful, given the deterioration of the industry’s infrastructure that has occurred over the past few

years and the loss of the confidence in steadily

rising oil prices that marked the rapid buildup of

industry infrastructure that took place in the

1970s, Many in the oil industry are arguing that,

once U.S. oil production declines to levels well

below those of today, a production rebound in

response to a sudden price hike would be extremely slow, would be accompanied by massive

inflation in equipment and manpower costs (as

well as inflation in associated costs such as leasing bonuses), and would likely fall well short of

recapturing the losses in production rates. Examining this hypothesis requires an evaluation of the

factors of production and the timetables for each

phase of the production cycle.

People

There is widespread concern in the industry

that the current depression in E&D activity and

the accompanying layoffs, company failures, and

crippled hiring programs will rob the industry of

a major portion of its most valuable personnel.

Overall industry employment has dropped from

its 1982 high of 708,000 to 425,000 in August of

1986. Oilfield service company employment

dropped from 435,000 to 206,000 in the same

period, indicating that this sector has absorbed

the brunt of the layoffs. A special concern is that

the very pessimistic perception on college campuses of the industry’s future and the virtual halt

of industry recruitment efforts will decimate wellestablished university programs in petroleum geology and engineering. Another concern is that

many of the employee reduction programs are

focusing on the older, more experienced (and

more highly paid) professionals, and that the industry is thus losing its most effective workers.

This concern is intensified by the 3-year training

period said to be necessary for skilled oil service

workers and the 7- to 10-year period needed for

professionals.

The seriousness of these concerns is by no

means settled. For one thing, the drilling boom

of the late 1970s and early 1980s attracted very

large numbers of students to petroleum-related

programs. For example, the Society of Petroleum

Engineers reports that a large oversupply of petroleum engineering graduates has existed since

1980-81, and expects this condition to last at least

through the end of the decade. This situation

probably exists in other petroleum fields as well.

Although many of these graduates as well as the

laid off engineers, geologists, and other professionals and skilled workers will find work in other

fields, it is by no means certain that they will be

“lost” to the industry. Previous experience with

other industries—e.g., in aerospace technologies

—implies that many of these trained personnel

can be recaptured by the industry in the event

of a sudden leap in oilfield activity, at least if there

is convincing evidence that the new jobs will be

stable. Further, the possibility of “recapture”

should be strongly influenced by the attractiveness of replacement jobs. Although OTA is not

aware of data on the success of laid-off oilfield

workers in finding employment, and on the relative salary levels of replacement jobs, laid-off

manufacturing workers in simiIar situations have

tended to take substantial salary cuts, and oilfield

workers would likely have to do the same.
Capital Availability

The opportunity for a rapid rebound in oil production will be possible only with a large increase

in cash flow, presumably from a substantial oil

price increase, or a massive influx of outside capital into exploration and development activities.

During the drilling boom of the 1970s and early

1980s, attracting such capital was relatively easy

because of favorable tax policies and because of

a widespread perception that inexorable increases in oiI prices would rescue even weak investments so long as some producible oil was

found. In contrast, capital availability to fuel a potential production rebound is likely to depend primariIy on skeptical analyses of the economic fundamentals of the individual oil prospects using

conservative assumptions about future price

growth. Investors will have to be convinced that

the economic conditions appearing to favor new

oilfield investment are stable, or else that their

investment wiII be safeguarded against a return

to low prices. Consequently, the potential for a

successful rebound in U.S. oil production will depend strongly on the precise geopolitical circumstances—and the perceptions of these circumstances—that accompany the events driving the

oil market towards shortages and/or sharply higher

prices. Also, because perceptions and reality

clearly do not have to—and often do not—agree,

and because a variety of unpredictable factors

fuel perception, considerable uncertainty exists

about the potential response of capital markets

to an oil market situation in which a rebound

might be attempted.

Some analysts, seeing that the independent

producers’ supply of outside capital (from banks

and private and public driIling funds) has virtually disappeared, and recognizing that internal

cash flow was the primary source of the industry’s investment dollars even when outside capital was readily available, assume that any rebound will have to be funded from internal funds.

In OTA’s view, this is unrealistic. The current

withdrawal by banks and funds from oil investment seems a logical short-term response to the

large financial losses sustained by these capital

sources and the widespread perception of massive instability in oil prices. Eventually, however,

a portion of these capital sources will return to

97

the industry if profitable investment opportunities are perceived to be available. The timing of

this return, however, being as much a psychological event as a financial one, is highly uncertain.

It is also important to recognize that the drying up of internal capital is not universal to the

industry, because many of the integrated companies retain substantial cash flows from their

downstream operations, and even the reduced

cash flows from production can buy considerably more drilling services than would have been

possible in the early 1980s, because of the substantial reductions in oilfield costs.

Equipment

Equipment availability is an additional concern

in the event of any attempt at a rapid restoration

of lost U.S. oil production. As noted above, such

a restoration will involve the drilling and equipping of many thousands of new wells in addition

to the completion of thousands of other production-related and equipment-intensive projects.

Although the industry has expressed substantial concern about equipment availability, there

currently is a substantial surplus of oilfield equipment both in a ready status and in storage. At the

peak of the drilling boom in 1981 there were over

5,000 land drilling rigs available in the United

States, the majority of them constructed within

a few years of that date. Although utilization rates

were high during the boom (79 percent in 1981,

for example), most industry observers will agree

that rig efficiency was low. Indeed, the industry

drilled nearly 86,000 wells in 1984 using only

2,400 rigs, whereas nearly 4,000 rigs drilled

89,000 wells in 1981.18 Also, many of the wells

drilled in 1981 were drilled with only marginal

prospects for success. A more efficient industry

could have added the same volume of reserves

with 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 depth

declined by only 250 feet during tbe period, however. other factors aside from actual improvements in equipment and operationa I efficiency that may have contributed to rig efficiency changes

include shifts in the locational distribution of drllllng and changes

in the proportion of exploratory drilling.
98

Although a “target” rig count for a successful

rebound is a speculative figure at best, a return

to a 3,000- or 4,000-rig onshore fleet seems excessive. If a 2,500 rig count is a reasonable target level for a production rebound, it appears

likely that the capability for quickly assembling

that size fleet will remain viable for at least several years. Although some of the used equipment

has been sold to foreign operators, overseas activity levels seem unlikely to expand sufficiently to

warrant concern over additional losses. Other

areas of concern include the cannibalization of

rigs to keep the current fleet operating, the potential for scrappage, and the potential for deterioration due to improper storage. Cannibalization is occurring and will eat into rig availability,

but there are so many excess rigs that this should

not 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 scrap

steel is low, and dismantling is expensive. Finally,

although concerns about proper storage are well

founded, much of the equipment now out of

service is simple and durable (see table 31), and

the best rigs are the most likely to be properly

moth balled and maintained. An indication of industry recognition of the value of proper storage

is the formation of services designed to handle

some or all aspects of storage for rig owners.19

In conclusion, although an attempt to add

quickly to drilling rates will likely run into some

bottlenecks, especially in high volume goods

such as drill pipe and drill bits, for the next few

years equipment should not be a major constraint

on a drilling revival.

The Resource Base and Availability of

E&D Opportunities

The turnaround in U.S. oil production that took

firm hold in the late 1970s owed much to the

large “inventory” of potential drilling opportunities amassed during the previous decades of

low oil prices. By going back to old well logs and

field records, geologists and engineers could

identify many thousands of opportunities that

were uneconomic at $3/bbl yet low-risk, profita19L. 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, and

should 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 done

to the fleet’s mud pumps in 1983 to 1984, and most should

be in good condition.

Drill pipe: Drill pipe is quite likely to be sold off and may

represent a high potential for a short-term shortage in case

of a rebound in drilling activity.

Draw works: Draw works are vulnerable to the elements, but

still relatively easy to store properly.

Prime movers: Engines are most likely to be sold to other industries, and could be in shortage in a rebound.

Drill bits: Since drill bits do not last long, a rebound will require substantial bit manufacturing capability. This capability is being rapidly diminished, and drill bits may be in

shortage in a rebound.

SOURCE Office of Technology Assessment, based on discussions with equip.

ment suppliers.

ble producers at $10 and up. Although most were

modest producers, in the aggregate they made

a significant contribution to total U.S. production.

In addition, Alaskan production was just beginning to start up in the early 1970s and provided

an additional, massive boost to U.S. production

levels.

Prospects for a rebound in production following a substantial price increase will depend in

large measure on whether or not a similar inventory exists now of drilling and other productionrelated opportunities. Without such an inventory,

a substantial boost in production would have to

wait a number of additional years to work

through the early stages of the production cycle

. . . stages that are bypassed when low risk opportunities in discovered fields can be identified.

The importance of such an inventory is further

enhanced by the imminent decline of Alaskan

production and the lack of any replacement producing province.

The issue of whether or not the inventory of

oil opportunities will be adequate to support

moderate levels of drilling activity for a number

of years is basically the same issue of continued

field growth that appears in Section Vd on the

Resource Base. As discussed in that section, there

remains substantial controversy about the potential for field growth through conventional drilling

of the existing U.S. oil and gas fields. Two im-
portant questions are whether many opportunities remain to attain additional reserves through

extension wells and infill drilling designed to produce mobile oil that would not have bee n

produced at previous levels of well spacing, and

whether or not recently discovered fields, which

are on the average smaller than their predecessors, will grow at historical rates. The former question remains controversial because of continuing disagreements about the actual level of

heterogeneity existing in many of the Nation’s oilfields.

The Restructuring of the U.S.

Oil Industry

Introduction

During the 1980s the U.S. oil industry has been

undergoing a transition that has left virtually no

segment of the industry unchanged. “Restructuring” is the overall term commonly used to describe the fundamental shifts in the size and composition of the domestic oil industry as a whole

and the changes in internal organization and

direction of individual companies. The current

restructuring is reflected in the increasing consolidation of the industry and in widespread,

often drastic adjustments in the operational and

financial structures of individual companies and

their petroleum investment strategies. This chapter describes some of the recent changes in the

U.S. oil industry and the possible future implications for continued investment in domestic exploration and production.

Well before the 1986 oil price plunge, many

of the major and independent oil companies embarked on ambitious operational and financial

restructuring efforts in response to conditions creating increased uncertainty about oil’s future profitability. Restructuring has taken varied forms including:

1.

2.

corporate mergers, acquisitions, and major

asset sales and purchases;

operational and organizational changes to

streamline business divisions and cut costs

by combining or eliminating functions and,

often, reducing the number of employees;

3.

4.

5.

6.

asset “redeployments” with companies expanding in operating segments and geographic areas where they perceive an advantage and eliminating less profitable

operations through sales, asset writedowns,

and liquidations;

adoption of financial strategies designed to

enhance the market value of the company

by increasing dividends, buying back stock,

changing debt levels, or creating new equity

investment opportunities (e. g., maste r

limited partnerships);

increased use of joint ventures and other risk

spreading arrangements for exploration and

development projects; and in some extreme

cases,

reorganization of assets and liabilities under

the protection of bankruptcy proceedings.

There is general agreement that the current restructuring was prompted by prevailing conditions

in the industry following the 1981 boom :20

1.

2.

3.

There was a worldwide surplus in oil production capacity and excess capacity in

refining and marketing operations as a result of the higher oil prices and industry expansion in the 1970s.

Oil consumption declined from 1979 to 1983

due to higher prices and conservation efforts

and the recession; many industry forecasts

predicted that annual growth in oil demand

would be less than 1 percent per yea r

through the year 2000.

Excess oil production capacity, reduced demand, and the breakdown of OPEC set oft

a steady decline in oil prices in 1981. By

1983 there was a growing consensus that oil

prices would remain low, and perhaps decline 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// to

Amend the Mineral [.]nci% Lea~ln<qAct of 1920 and for Other Purposes Before the Subcommittee. on Energ) and Mineral Resources

of the Senate Comm. on Energy and Natural Resources, 98th Cong.,

2d sess. 320 (1984), and supplementary material provided by Frank

W. Bradley of Chevron Corp., Id. at 536. (These hearings are hereafter referred to as Leg/slat;on Atiectjng 0)1 Merger Proposals. ) See

also Impact of Oil Company Mergers: Report to the United State>

Senate, Prepared by the Majority Staft”otthe Senate Committee on

Energy and Natural Resources, S. Prt. 98-206, 98th Cong., 2d sess.

( 1984).
100

4. Many oil industry managers and investors

were disappointed by the relatively high

finding costs and the difficulty in finding and

producing new domestic oil reserves, particularly in the light of the massive investments in exploration. There was a growing

perception among some major oil companies that because of the past extensive onshore exploration in the United States, there

were now fewer “good” U.S oil prospects

remaining.

Some industry analysts wouId add to the foregoing conditions: concern over possible changes i n

Federal tax and oil and gas leasing policies, the

pressures on companies from increasingly aggressive institutional investors demanding greater

short-term returns from their holdings, and the

fear of possible hostile takeover offers by corporate raiders.

Although changes in capital structures,

mergers, acquisitions, liquidations, and bankruptcies are not unusual in the oil industry, recent

years have seen a high level of these activities.21

These widespread occurrences, coupled with the

general conditions of overcapacity, reduced demand, and declining prices suggested to some

observers that the domestic industry had entered

a period of fundamental structural change before

it began to experience the adverse effects of the

plunge in world oil prices in 1986.22 If the current restructuring is indeed symptomatic of the

J 1,Vaterla13prepared for the Senate Banking Cornrn Ittee Indicate

that the number of mergers and acquisitions from 1983 to 1985

has been much higher than during the 1970s and has involved substantially more funds than ever before. According to Mergers and

AcquIsItIorrs, oiler $122 billlon was spent on completed transactions

In 1984; oil and gas industry transactions probably were one third

to one halt’ ot that total. See Impact otCorpor,]te Takeo~er$: Hearings on the Eifects otMergers on Management Practices, Cost, AL allabliity ot Credit, and the Long-Term Vi.]bil@ oiAmer/c.]n Indu$tr]’

Before the Subcommittee on Secur~ties oi [he Senate Committee

on 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 industry 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 Methodist

Unl\erslty concludes that current trends In the oil industry are characteristic ot the mature phase of an ind us.try life cycle: excess capacity, low growth, business failures and consolidation. The study

compared the oil industry to other “distressed” mature domestic

I nd ustrles I n transition such as steel, textiles, automobl Ies, and agricu Itu re.

maturity of the U.S. oil industry, rather than the

result of cyclical influences of world oil prices,

this further suggests that a return to the slightly

higher oil price levels preceding the price slide

will not stem the eventual contraction of the industry and the decline in U.S. oil production. But

there are others in the oil business who do not

share the view that the U.S. industry is in inevitable decline. To them restructuring is desirable,

but marks a normal and healthy evolution of the

industry in response to changing conditions. They

point out that the oil industry has been through

similar periods of expansion and contraction in

the past.

Restructuring has already had profound effects

on the industry and on oil companies and their

investment decisions. The success of their restructuring efforts and other strategies adopted by individual companies in response to low oil prices

may well determine their economic viability in

a new era of more volatile oil prices and stronger

competition from foreign oil imports. The cumulative result may be oil’s transformation into a

smaller, more efficient industry with fewer companies and a different approach to business. But

a smaller industry may not conduct as extensive

or aggressive an exploration program to replace

domestic reserves and this could increase U.S.

reliance on foreign oil. Moreover, there is concern that the sharp increase in corporate indebtedness associated with recent mergers, acquisitions, and internal restructuring, coupled with

declining earnings due to low oil prices, will

mean sharply reduced expenditures for exploration and development in the short term as available cash flow is diverted to debt repayment. In

the long term, this trough in exploration expenditures could contribute to a decline in oil production.

Conditions Causing Restructuring

World oil trends in the 1980s began to raise

concerns about the future profitability of the domestic industry. Even as oil revenues soared in

1979-82, present and future earnings were being undermined by growing worldwide overcapacity in upstream and downstream operations,

lower oil prices, declining demand, and changes

in domestic tax policies. AdditionalIy, the indus-
101

try was becoming more vulnerable than in the

past to rapid changes in oil prices as more and

more oil was sold on the spot market or at spotmarket-related prices.

One clear implication of these trends was that

the majors could no longer rely on rising prices

and expanding product sales to assure future

profits growth. The earnings of major U.S. oil

companies did not reflect much of the initial oil

price drop in 1981 to 1985 because most of the

excess price over $20/bbl was taxed away by the

windfall profits tax (WPT). The contribution to

cash flow in dollars per barrel of crude oil equivalent for major U.S. companies after deducting the

WPT fell only 1.6 percent between 1981 to

1984.23 The independents, who generally carried

a smaller WPT burden, however, were more seriously affected by the steady slide in oil prices.

By 1985, many independents were already in financial difficulty because of the combined effects

of lower oil prices and lower prices for natural

gas. But as the price fell below $20/bbl in 1986,

cash flows for both majors and independents

were squeezed.

The prospects of slow demand growth and

declining oil prices forced managements to reformulate their long-term business plans to decide

how best to protect the future profitability of their

companies. This reassessment accompanied the

emergence of a management philosophy that

places greater emphasis on financial performance

and short-term returns to shareholders than on

finding oil. With world oil industry conditions

largely beyond their control, companies began

to look inward for ways to cut costs and maintain profits and to reexamine the assumptions

underlying their business strategies. Restructuring and a move away from continued heavy investment in domestic oil exploration have been

two results.

Many integrated companies began to shift away

from their past emphasis on maintaining a secure

source of domestic reserves to supply their refining and marketing operations and to end the

traditional 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 21

and 22.

proportion of their production revenues back into

exploration and development activities. The cutback in domestic exploration also marks a reevaluation of the potential for finding additional large

oilfields in domestic frontier areas. Oil industry

observers and company annual reports indicate

that several companies appear to have altered

their views on the economic viability of conducting a broad-based exploration and development

program in the Lower 48 States at prices experienced in recent years. For example, Lodwrick C.

Cook, the Chairman of the Board and Chief Executive Officer of ARCO, told his shareholders:

[I]n the lower 48 we intend to maximize

productivity of existing fields and not try to replace production through further exploration in

this declining region—though we will buy reserves when good opportunities come a long... Essentially we’ve shifted away from the high-risk,

major-stakes emphasis of recent years and toward

projects that can be expected to produce economic results more reliably. As the price of crude

oil increases we can step up exploration again,

although not on the large scale of recent years.

Results of the industry’s late 1970s, early 1980s

drilling boom weren’t that encouraging—at any

predictable price. (Emphasis added. )24

Many majors and independents have not been

able to replace their U.S. oil and gas production

with new reserves despite heavy investment in

domestic exploration, and the reserves they did

find came at a high cost. For example, as shown

in table 32, oil and gas reserve additions for many

major oil companies, excluding purchased reserves, felI short of replacing annual production

over the period 1979 to 1985. Even when purchased reserves are taken into account, many

companies still did not replace depleted reserves.

Over the same period, the U.S. industry replaced

about 92 percent of its liquids production.

The poor success of some exploration efforts

is also reflected in the relatively high implied finding costs incurred by some firms over the years

1979 to 1985. The average weighted implied finding cost for the major oil companies shown i n

table 32 was $10.58 per equivalent barrel in 1979

24 Remark~ of Chairman Lodwrlck c, cook at the 1986 annual

shareholders meeting, reprinted in Atlantic Richfield Co. 1986 First

Quarter Report, at 12, 15.
102

Table 32.—U.S. Oil and Gas Reserves Replacement as Percentage of Production, 1979-85, and

Domestic Implied Finding Costs

Production replacement

excluding purchases and sales

(weighted average 1979-85)a

Major integrated oil companies:

Amoco Corp. 109.0%

Arc o 103.9

Shell Oil Co. 99.2

Chevron Corp . 81.4

Murphy Oil Co. 75.9

Exxon Corp . 75,6

Mobil Corp . 72.1

Phillips Petroleum Co. 69.5

Unocal Corp . 65.6

Sun Co. 58.1

Kerr-McGee Corp. 51.7

Standard 011 Corp. 22,2

Texaco, Inc. Neg.

Independent producing companies:

Noble Affiliates, 150.7

Mitchell Energy & Development Co. ., 1423

Pogo Producing Co. 93.6

Sabine Corp. 88.5

Pennzoil Co , 86.4

Louisiana Land & Exploration Co. ... 39.8

Production replacement

including purchases and sales

(weighted average 1979-85)b

11 2,8%

108,5

147.6

169.3

77.8

77.2

121.3

98.3

66.25

79.3

62.4

23.0

47.8

151.6

146.7

93.8

1 17.4d

102.3

40.7e

Implied finding costs

$/Bbl oil equivalent

(weighted average 1979-85)C

$7.9 1

7.05

7.46

9.48

15.19

9.93

10.18

9.53

9.62

11.05

21.09

26.61

Neg.

9.04

1041

1417

1204

8.91

21.91

ar.@pl’C8m8flt {ncludes reserves added through dlscoverles, extensions Improved recovery and revlslons of PrevfrJus estimates

bReplacement ln~ludes rese~es added through dlscoverles, extensions, improved recovery and rewons Of prewous t? StlmateS Plus the effects of reserves purchases and sales

CFlndlng cost excludes proven rese~es purchases e~’ept where properfy acquisition COSIS @ not break out proven and unproven acreage

dExcludes reserves dlsmbuted to the Sabme Royalty Trust

eExc~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 finding costs among these companies, from $7 to

over $26/bbl. Several companies had extremely

poor results in their domestic exploration programs with implied finding costs well above the

$5 to $9/bbl average purchase cost of proven reserves over the same period .25

High finding costs translate into a low profit

margin per barrel (or even a loss) if prices do not

rise. The declining profitability of newly added

reserves was becoming apparent even at prices

over $20/bbl. This trend is reflected in several

commonly used indirect measures of the profitability of exploration and production activities:

● Discounted Future Net Cash FIows.—A

measure of the present value of all proven

oil and gas reserves derived by applying yearend 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 estimates

provided by Strevig & Associates in “ Prices for Reserves Purchases

on the Upswing, ” Oi/ & Gas Journal, Feb. 16, 1987, at 46.

●

●

production to yield expected production revenues flows, then subtracting estimated future production and development costs and

future income taxes, and discounting the resulting annual future net cash flows by an

annual discount rate (usually 10 percent).

Present Values Added Through Exploration

and Development.—The present value of

new reserves added as a result of exploration and development activities in a given

year. This measure is calculated for newly

discovered reserves in the same manner as

discounted future net cash flows above.

Value-Added Ratios.–Two measures of the

returns on exploration and development investments. The value-added ratio for exploration and development is expressed by

comparing the present value of new reserves

added by exploration and development

activities with the costs incurred to acquire,

explore and develop the reserves. The value-

-added ratio for all sources compares the

present values of reserves added through ex-
103

 ploration, revisions, and reserves purchases

(less sales) to the total costs incurred to obtain the reserves including amounts paid to

buy proven properties.

The above measures are calculated assuming

that all future production is at year-end prices and

lifting costs; the year-end prices are not escalated

u n less the reserves are covered by a contract provision requiring such an adjustment. The measures are recalcuIated each year to reflect changes

in prices and costs and are required by the Securities and Exchange Commission (SEC) to be included i n many oil company annual reports. Although companies generally disclaim the

accuracy of these measures as indicators of future E&P profitability, the measures do allow for

comparison between companies and for identification of industry trends.

According to an Arthur Andersen & Co. analysis, shown in table 33, projected future net cash

flows for 375 of the largest publicly held oil and

gas companies remained fairly steady in 1981 to

1984, with the initial price decline offset somewhat by lower lifting costs and taxes.26 In 1985

future net cash flows dropped 8 percent at yearend prices of about $25/bbl. At mid-1986 prices

of $15/bbl and less, the future cash flows from

proven reserves will likely be substantially less.

Some analysts believe that the increases in reserve values experienced as a result of the price

increase in 1979 to 1981 will probably be wiped

out by the 1986 price fall.

Moreover, the values of new reserves added

through exploration and development by major

oil companies worldwide declined between 1981

to 1985 as shown in table 34. The Arthur Andersen study attributed the decline to the fact that

much of the majors’ new reserves came from

costly improved recovery techniques and exploration in high cost remote areas .27 The value added on a per-equivalent barrel basis for the 375

companies analyzed in the study has also declined since 1982. The majors generally posted

the lowest added value per barrel from exploration. The profitability of these low value reserves

is expected to be highly sensitive to price

changes.

The troubling outlook for the profitability of exploration investments is indicated when the

values of reserves added are compared to the

costs of discovering and developing the new reserves. As shown in table 35, since 1981, companies have spent more looking for oil and gas

(the “costs incurred for exploration and development”) than the present value of the reserves

found. Only in 1985 did new reserves values exceed costs incurred, primarily because the costs

declined more than the net decrease in the value

of reserves added. The value added from all new

reserve sources, including exploration, development, revisions and net purchases and sales,

however, significantly exceeded the related costs

incurred 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 reserves posted by the majors is that many of these d Iscoveries haj,e

long lead times before commercial production anci cash inflows

begin, In contrast, many of the non-majors’ reserie acfdltions have

relatively 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 1981

Majors . . . . . . . . . . . . . . . . . . . . . . . . ..$109.2 $118.9 $115.0 $120.9 $122.5 $167.4 $172.8 $169.9 $176.1 $181.1

Independent . . . . . . . . . . . . . . . . . . . . . 13.8 14.8 14.8 14.7 13.2 17.2 15.0

Pipeline/utility 7.3 7.3 6.8 6.3 5.6 9.1 9.1 8.6 8.8 7.6

Diversified . . . . . . . . . . . . . . . . . . . . . . . 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 $244.8

aBa~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 $22,071

Independents . . . . . . . . . . . . . . . . . . 2,007 2,672 2,362 3,221 3,447

Pipeline/utility ........ . . . . . . . . 1,850 2,009 1,576 1,597 1,583

Diversified . . . . . . . . . . . . . . . . . . . . 6,677 7,927 5,988 7,712 8,262

Per equivalent barrel

1985 1984 1983 1982 1981

$5.83 $5.24 $5.65 $7.61 $ 7.3 9

8.38 10.71 10.41 11.67 11.38

8.61 9.91 10.37 5.66b9.40

8.44 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-year

Exploration and development average 1985 1984 1983 1982 1981

Majors . . . . . . . . . . . . . i . . . . . . . . . . . . . . 91 “/0 100% 780/o 920/o 890/o 95 ”/0

Independents . . . . . . . . . . . . . . . . . . . . . . 99 92 133 106 92 84

Pipeline/utility . . . . . . . . . . . . . . . . . . . . . 87 102 101 90 73a

71a

Diversified . . . . . . . . . . . . . . . . . . . . . . . . . 103 119 130 100 91 87

Weighted average ., . . . . . . . . . . . . . . 93 ”/0 103 ”/0 890/o 94 ”/0 890/o 920/o

Ail sources

Majors . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144”/0 b

177”/0 b

145”/0 1300/0 1lOO/o 1620/o

Independents . . . . . . . . . . . . . . . . . . . . . . 127 96 147 116 127 141

Pipeline/utility . . . . . . . . . . . . . . . . . . . . . 132 131 152 140 183a

51a

Diversified . . . . . . . . . . . . . . . . . . . . . . . . . 145 125 184 123 115 176

Weighted average . . . . . . . . . . . . . . . . 143%b158%b150% 1280/o 1160/0 1590/0

aprlncipallyreflectsone company’s downward revisions In 1981, subsequently reflected as upward revisions in 1982

blncludes 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 industry:

1. that lower future cash flows would mean less

internal capital available to replace depleted

reserves; and

2. that under existing price expectations, domestic exploration was proving to be a disappointing and costly means of replacing reserves.

These prospects led some companies to conclude

that their limited exploration funds should be

spent elsewhere—e.g., more intensive development drilling, more foreign exploration, or acquiring other companies or buying proven properties, or investing internally by buying back shares

or boosting dividends.

Mergers and Acquisitions

The recent wave of mergers and acquisitions

has reordered the domestic industry and thinned

the ranks of majors and independents alike. The

sheer size of some of the transactions involved

and the controversial tactics of corporate raiders

and target company managers have attracted

headlines and raised concerns over the potentially adverse effects of “merger mania” on the

domestic oil industry. Among the concerns were

the effects on competition in the industry and the

impacts on capital spending and exploration of

the massive increase in merger-related debt.

During the period 1979 to 1986 over $75 billion was spent on the acquisition of publicly

traded oil and gas companies. Table 36 lists some

of the largest transactions involving oil producers. 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 compdnles during the same period. Among the more notable of these transactions 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 011

companws. Other multl-billlondollar transactions Include IBM’$

purchase of Rolm, Nestle’s acquisition of Carnation, General Electrlc’s takeover of RCA, and Capital Cities Communlcatmns’ buyout of ABC. See Impact ot Corporate Takeover5, $upra note 2.
105

Table 36.—Mergers and Acquisitions in the U.S. Oil Industry

Year

1979

1979

1979

1980

1980

1981

1981

1981

1982

1982

1982

1982

1983

1983

1983

1983

1983

1983

1984

1984

1984

1984

1984

1984

1984

1984

1985

1985

1985

1985

1985

1985

1985

1986

1986

1986

1986

1986

Acquiring company Target Millions of dollars

Broken Hill Proprietary Ltd. . . . . .

Houston Natural Gas ..

Mobil Oil Corp. . . . . . . .

Getty Oil Co.

Mobil Oil Corp.

Shell Oil Corp. 

Mobil Oil Corp

The Sun Co., Inc. 

E.l. du Pent de Nemours & Co.

Occidental Petroleum Corp .

Tennec o

Ashland Oil Co ,

Ashland Oil Co 

Occidental Petroleum Corp. .

U.S. Stee l

Burlington Northern

CSX Corp. 

Diamond.

Freeport McMoRa n

Internorth (Enron )

Phillips Petroleum .

Chevron Corp. 

Damson Oi l

Freeport McMoRan

Mobil 011 Corp. 

Phillips Petroleum

Texaco, Inc.

The Sun Co , Inc.

U.S. Steel 

BHP Petroleum America s

Burlington Northern .

Coastal Corp .

Enron (Internorth )

Freeport McMoRa n

Midcon Corp .

Union Texas Petroleu m

Freeport McMoRan

Louisiana Land & Exploration Co. 

Mesa Limited Partners

Occidental Petroleum Corp. 

U.S. Steel

Energy Reserves Grou p

Florida Exploratio n

Vickers Energy ., . ,

Reserve Oil and Ga s

General Crude Oil .

Belridge Oil ., ... . .

Trans Ocean Oil .. .

Texas Pacific Oil & Gas

Conoco, Inc.

Crestmont Oil & Ga s

Houston Oil & Mineral s

The Tresler Oil Co .

Scurlock Oil Co, ., . ,

Cities Service ... .,

Marathon Oi l

El Paso Natural Gas ., .,

Texas Gas Resources .,

Shamrock Natomas. . , . : ........

Stone Exploratio n

Belco Petroleum .., : : :::::...

General American Oil.. .

Gulf Oil Corp. ...,.. ,

Dorchester Gas . .., . .. .

Midlands Energy. . . . . .

Superior Oil. . . . .

Aminoil USA, . . . , .

Getty Oil. . . . . . . . . . . . . . . .. . . .

Exeter Oil . . . . . .

Husky Oil USA . . .

Montsanto Oil...

Southland Royalty . . . . .

American Natural Resource s

Houston Natural Gas. .

Pel-Tex Oil.. .

United Energy Resource s

Union Texas Petroleum. .

Petro-Lewis & American Royalty Trust:

Inexco Oil ., .,

Pioneer Production Co. .. .:

Midcon Corp. . . . . . . . .

Texas Oil and Gas

n.a

n.a

n.a

620,0

792.0

3,660.0

715.0

2,300.0

7,800.0

82.3

1,650.0

90.0

13.0

3,984.0

5,950.0

1,300.0

1,100.0

1,500.0

112.0

800.0

1,100.0

13,300.0

400.0

294.0

5,720.0

1,600.0

10,200.0

75.0

488,0

575.0

2,400.0

2,200.0

70.5

1,200.0

n.a

440.0

470.0

1,575.0

3,700.0

Remarks

From Esmark

From International Paper

Properties acquisition only

Stock for stock

Cash plus stock

From R.J. Reynolds

Asset acquisition

From Monsanto

Assets acquisition only

LBO from Allied-Signal Corp.

jointly with Kidder Peabody

Mesa Units and Debt

Cash 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 Companies

January 1981 through February 1984. ”

quiring other companies in their core energy and The largest of the mergers were in 1984 as

chemical 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 and

diversify into other areas to cushion themselves acquisitions trend continued in 1985 to 1986, the

from the uncertainties of world oil markets. For transactions frequently involved the absorption

example, ARCO bought Anaconda Minerals, a of a smaller ailing company into a larger, more

major copper producer, and Mobil bought Mont- financial sound company. (For example, Louigomery Ward Department Stores. For many ma- siana Land & Exploration’s acquisition of Inexco

jor oil companies, the diversifications have been Oil, and Freeport-McMoRan’s bid for Petrodisappointing and now, as part of restructuring Lewis.) Major asset purchases have also conprograms, they are selling, spinning off, or li- tinued. Some larger independents, such as Murquidating these subsidiaries to return to their core phy Oil and Noble Affiliates, have told their shareenergy and chemical businesses. holders that they are aggressively seeking
106

acquisitions as a means of adding reserves at low

cost. Takeovers and consolidations can be expected to continue as lower prices undercut the

financial viability of many independent producers.

The recent mergers and acquisitions raised a

number of major criticisms:

1.

2.

3.

4.

5.

that massive merger-related borrowing by oil

companies could crowd out other industries

in capital markets;

that acquisitions would divert funds from exploration and development and other capital investment;

that the mergers eliminate viable competitors and contribute to the harmful consolidation of the industry;

that companies that acquired new reserves

would be less likely to maintain an aggressive exploration program to replace production; and

that the massive new long-term debt assumed by some companies to successfully

fend off hostile tender offers would seriously

impair their ability to fund future exploration activities.

These concerns are countered with the arguments offered by those who strenuously defended

all or some of the merger activities:

1.

2.

3.

4.

5.

6.

merger-related borrowing by oil companies

was only a small portion of total loans outstanding and did not deprive other borrowers

of credit;

in the past, oil industry merger-related loans

were paid down within a few years out of

asset sales and cash flow;

the funds paid for the acquired company did

not disappear from the economy, but were

returned to shareholders who could then

reinvest them;

the merged firms will have to continue and

even expand exploration programs to support the combined production levels;

investments in exploration are determined

by expectations of future oil prices and profitability and are not influenced by the separate and independent considerations pertaining to mergers and acquisitions;

mergers and acquisitions are the market7.

8.

place’s natural mechanisms for weeding out

inefficient companies, moving assets to more

efficient operators, and providing opportunities for new entrants into the industry and

for expansion of existing firms;

newly merged firms are stronger competitors, both nationally and internationally; and

finally

even unsuccessful takeovers contribute to

the necessary restructuring of the industry

because, to avert takeovers, target managements are forced to make changes in capital and operating structures that enhance

shareholder values.

Reasons for Oil Industry Merger Mania

There have been many explanations offered in

congressional hearings for the wave of ‘‘merger

mania” that struck the oil industry; some are summarized below. Many of the differences in viewpoint are not factual disputes, but represent contrasting values, policies, and theories. These

reasons can be divided into two categories: those

that relate to mergers and acquisitions in general,

and those that reflect the special circumstances

of the U.S. oil industry in the 1980s.

Among the general conditions resulting in merger

and acquisition activity are:

● Mergers and acquisitions are the marketplace’s

natural remedies for inefficient corporate

management and are the means for assets

to flow to more productive use by stronger,

more efficient companies. To the extent that

the market value of oil companies is less than

their book value, this reflects the stock market’s correct assessment of their performance.

● Even a profitable company with competent

managers can become a takeover target, if

another company believes that the target’s

assets might be more valuable and profitable in its hands or if the target has some special expertise or capabilities that cannot easily be reproduced. The purchaser can thus

afford to offer a premium over the market

price to acquire the target to realize an increase in value of the assets under different

management or as a means of entry into a

new market or industry.
107

Federal income tax benefits made corporate

acquisitions attractive investments because

of the deductibility of interest payments on

merger-related debt, the stepped up basis in

the acquired assets, and accelerated depreciation.

Some recent takeover attempts were profitable for some companies and their financial

backers, even if they did not succeed, for

several reasons. To avert a threatened takeover the defending management sometimes

brought the hostile offerors’ shares at a substantial premium over the original purchase

price. For example, Mesa Petroleum netted

$214 million on its unsuccessful offer for

Gulf, $4 I million from its offer for Phillips Petroleum, and an additional $83 million from

its Unocal offer before the sale of another

14.6 million shares of Unocal it still held in

1986.29 In other circumstances, the takeover

threat caused the target management to initiate programs to return greater value to all

shareholders, which the takeover group then

shared. Once a takeover attempt was announced, the target company’s stock often

rose. Because securities laws only require

public notification when an individual or

company acquires more than a threshold

percent, the takeover group could “accumulate” a substantial position in the target’s

stock on the open market before the announcement and then gain from selling the

stock at a higher post-announcement price

without ever completing the takeover bid.30

Some critics contend that raiders and their

investment bankers put companies “in play”

by announcing a takeover bid without ever

intending to complete the bid just to profit

from “greenmail” offered by the target companies and from the runup in the stock’s

price.

Conditions in the oil industry in the 1980s also

tended to favor mergers and acquisitions activity:

29Mesa petroleum, Annual Report 1985, P. 24.

~~TakeOVer C3fi’ers can be annou need ‘‘contingent on ii nanClng. ”

The target and offeror stock prices often rise following the an -

nouncement and the offeror could later withdraw the offer without ever purchasing any tendered stock and still benefit from the

Increase In value of the shares already held. In adcJitton to gatns

on the sale ot stock, the backers of a takeover group often receive

commitment tees, commissions and legal fees.

●

●

●

The mergers and acquisitions could be seen

as part of a larger trend in the restructuring

of the oil industry. Mergers and acquisitions

are symptomatic of the structure of a “mature” or “declining” industry. The consolidation reflects the expectation that the mature industry has only modest growth

prospects and may have entered a period of

inevitably declining production as remaining reserves are depleted.31

The high debt levels and interest rates assumed by many independent oil companies

to expand rapidly during the 1979-82 boom

placed them in severe financial difficulty

when oil prices began to decline. In order

to survive, many of these businesses sought

buyouts or mergers with other, stronger

companies .32

Some recent takeover attempts were profitable for some companies and their financial

backers, even if they did not succeed, for

several reasons. To avert a threatened takevalue as the underlying oil and gas reserves

after oil prices tripled in 1979 to 1980. Oi l

company stocks sold for less than their pershare appraised value and for considerably

less than the per-share breakup value. Several stocks sold for less than the per share

book value of the company’s assets. 33 This

disparity made the companies attractive

takeover 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 were

selling at an average 43.9 percent of their ).S. Herold appraised

value. Of the group, Gulf, which was later acquired by SoCal, was

selling at 57.2 percent of it’s appraised value, the highest of the

group. See testimony of Mark Gilman, in Od /ndustry Mergers: Hearings on H.R. 5153, H.R. 5175, and H.R. 5452, Bills to Amend the

Federal Trade Commission Act to Require a Study of Mergers, Acquisitions, and Joint Ventures in the Auto and 011 Industnes, and

for Other Purposes Before the Subcommittee on FOSSII and Synthetic 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 comparative

stock values and book values of major oil companies appended

to testimony of Claude Brinegar of Unocal in /rnpact o~corporare

Takeovers, supra note 2, at 82, 89-90. In his testimony Brinegar

noted that the stocks of three companies that had previously restructured were selling at a lower percent of appraised value than

companies that had not.
108

●

by aggressive institutional investors, Wall

Street investment bankers and arbitrageurs,

and often financed by “junk bonds, ” put increasing pressure on oil companies to improve their return to investors or to become

takeover targets.

Acquisitions also were a more attractive investment alternative than some high risk exploration ventures for the huge revenues

generated from oil production during the

period of higher prices. Acquisitions also

offered a quick and effective means of

replacing reserves depleted through production. Some companies believed it was more

financially attractive and less risky to “drill

for oil on Wall Street” (by buying other companies for their proven reserves) than to continue to invest in risky exploration activities.

Buying a company also offered the prospects

of an immediate cash infusion from its producing reserves and from the sale of unwanted assets. In contrast, it is often years

before there is any return from investments

in long-term exploration and development

projects .34

Effects of Mergers and Acquisitions

Mergers and acquisitions are claimed to be

beneficial overall for stockholders and economy.

Among the positive effects generally cited are:

improved efficiency and lower costs for the

merged entity, lower costs to consumers, and increased returns on investments in the stock of

publicly held companies either from the premium

over market value offered in the takeover, or from

the correction in discounted stock prices. 35

Jqsee responses of Mobil Oil Co. to Committee questions i n Legislation 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 complementary factors such as the combination of a reserves-rich firm with

a reserves-poor company with extensive refining, marketing and

petrochemical operations; iii) rationalization of production facilities by, for example, maintaining the most efficient facilities of the

combined operations and eliminating others; iv) replacement of

weak management; and v) economical technology transfer. See Testimony of Joseph j. Wright, Office of Management and Budget, in

Impact of Corporate Takeovers, supra note 2, at 610-612. See also

statement of Morgan Stanley & Co., Inc. in Legislation Affecting

Merger Proposa/s, supra note 1, at 516, and testimony of Professor Edward j. Mitchell, Graduate School of Business, University of

Michigan in Oi/ /rrdustry Mergers, supra note 13, at 359-60.

Another claimed benefit of mergers among major oil companies is that the larger combined

companies will be stronger technically and financially and, thus, better able to sustain the increasing costs and risks of developing reserves in frontier areas and to compete with large foreign oil

companies, often supported by their governments, in acquiring and developing concessions

abroad. 36 Except for the gains realized on the sale

of stock in the acquired companies, it is still too

early to determine whether the recent mergers

wiII in fact have these effects over the long term.

At the same time that mergers may prove beneficial to individual companies there remains the

possibility that they could contribute to a net reduction in domestic petroleum production in the

long term. The most obvious short-term results

of the mergers have been an increased consolidation of the oil industry, a significant increase

in long-term debt, and an apparent reduction in

capital spending on exploration and production.

For many industry observers, fewer companies

and less exploration spending means fewer wells

drilled, fewer reserves discovered, and eventually lower oil production.

OTA has reviewed the financial performance

of 26 major and independent oil companies to

assess the impacts of mergers and other restructuring changes in recent years. Table 37 presents

aggregate information on these companies from

their annual reports in 1983 to 1985. The companies are also subdivided into those that were

involved in major corporate acquisitions (both

successful and unsuccessful) in 1982 to 1986 and

those that were not.37 They include two groups,

14 major integrated oil companies, and 12 smaller

independent oil companies. Measuring the impacts of mergers on these companies is complicated by the fact that most of the companies have

ongoing restructuring programs that are intended

to have some of the same results as some

mergers. Nevertheless, OTA found some clear

differences between companies involved in

takeovers and other companies. There were also

clear differences in expenditures for combined

Jbsupplernentary material submitted by Standard Oi I CO. Of California 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-mCcgg

w.

r=-o1 -
110 I
111

companies before and after the mergers. For example, as discussed later, OTA found that the

large post-merger firms spent a smaller portion

of available cash flow for exploration and other

capital expenditures and devoted a higher level

of cash flow for debt reduction than did firms that

were not involved in acquisitions.

Several of the large company mergers have resulted in a retrenchment and contraction of resulting entities into something significantly less

than the sum of the combined pre-merger companies with fewer employees, fewer total reserves, and less totaI production than before.

While some downsizing reflects efficiency gains

in the reduction of redundant overhead, other

shrinkages are the results of asset sales and additional cost-cutting so that cash can be

redirected to paying down debt.

There has also been a redistribution of oil and

gas assets through post-merger asset sales. This

may resuIt in properties being transferred to new

owners who can make more efficient and profitable use of them. Some major oil companies are

selling off less profitable wells in smaller producing oilfields with high overhead levels. These

properties could be attractive to other companies with extensive holdings in the same field that

could benefit from economies of scale, or to independent producing companies with lower

overhead. Some new owners have made or announced planned investments to expand production in their newly acquired properties. These asset sales are also coming at a time when the price

for proven properties is much lower than it has

been, so that companies buying reserves can

often do so for much less than average finding

costs.

Mergers and the Consolidation of

the Oil Industry

The new combinations arising from the recent

mergers reordered the rankings of the major oil

companies. Table 38 shows the top 20 petroleum

companies ranked by assets, liquids reserves, and

liquids production in 1980 and 1985. By 1985,

9 of the top 30 oil companies in 1980 had been

acquired. The primary changes in the rankings

are the disappearance of some “second tier” independent integrated companies and the elevation of smaller companies into the ranks of the

majors. As shown in table 39, the relative holdings of the top 8 firms have increased through

the Gulf-Chevron merger and the absorption of

several of the larger independents, Getty, Marathon, and Superior.38 At the same time the concentration levels of the largest 20 oil companies

have declined relative to the rest of the industry.

Consolidation has also been significant among

the independents. Mergers and acquisitions, as

well as bankruptcies, dissolutions, and liquidations have also contributed to a thinning and consolidation in the ranks of the independents.

According to the 0il and Gas Journal annual

reports on the 400 largest publicly held oil and

gas producers, the year-end value of assets

needed to place on its list dropped from $2.37

million in 1983 to $276,000 in 1984, to $179,000

in 1985.39 Among the smaller public and private

independents, there has also been a severe

shrinkage which has been estimated at about 25

to 30 percent of the independent exploration and

production companies. While detailed information on the disappearance of the independents

is not readily available, the estimated number of

independents, as presented in testimony on behalf of the Independent Petroleum Association

of America (IPAA), declined from over 15,000 in

1984 to about 12,000 in mid-1986.40 Some believe that the majors could be a more dominant

influence in domestic exploration and production than before 1980 as a result of the consolidation among the larger companies and the disappearance of so many independent operators.

Some industry observers believe that the contraction of the majors could create more opportunities for independents in some niches. With

smaller exploration staffs and less money to spend

on drilling, the majors may be willing to do more

~BTh.e table does not fully reflect the acquislt!ons announced In

1986; when these transactions are taken into account they will turther 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 tlearirrgs on the Domestic and /nternationdJ Petroleum Situation and

the 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 Legislation 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 assets

Rank 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. . . . . . . . . . . . . . . . . . . . . . . . . . .

69.16

41.75

38.90

37.70

26.53

25.20

20.44

20.28

18.33

14.05

12.92

11.59

10.80

10.07

9.90

9.89

8.29

6.22

5.84

5.81

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. . . . . . . . . . . . . . . . . . . . . . . . . . .

56.58

32.71

26.43

22.16

20.17

18.64

17.62

16.60

13.85

12.08

11.04

10.96

9.84

8.27

6.77

6.63

5.90

5.36

5.04

4.11

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 production

1955 1960 1965 1970 1975 1980 1983 1984 1985

4-Firm . ....................18. 1 20.8 23.9 26.3 26.0 25.3 25.0 26.1 26.20/o

8-Firm . . . . . . . . . . . . . . . . . . . . . 30.3 33.5 38.5 41.7 41.2 40.8 38.4 44.5 43.6

15-Firm . . . . . . . . . . . . . . . . . . . . 41.0 44.2 50.3 56.9 57.0 56.1 53.5 56.4 53.2

20-Firm . . . . . . . . . . . . . . . . . . . . 46.3 49.1 55.0 61.1 61.2 60.6 57.6 59.4 55,8

Concentration ratio-U.S. Iiquids reserves

1975 1980 1983 1984 1985

4-Firm . . . . . . . . . . . . . . . . . . . . . 36.3 31.1 29.0 29.6 29.10/o

8-Firm . . . . . . . . . . . . . . . . . . . . . 55.6 46.3 43.2 48.6 41.7

15-Firm . . . . . . . . . . . . . . . . . . . . 70.4 59.5 56.1 59.1 47.3

20-Firm . . . . . . . . . . . . . . . . . . . . 74.5 62.7 59.4 61.2 58.9

SOURCE: 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 Independent Petroleum Association of America, Petroleum Statistics 1985.

farmouts with independents and may even be

willing to share some of the costs rather than

merely contributing drilling rights.41 Moreover,

if the merged companies cut back their unproven

property acquisitions and exploration efforts, independents may be more successful in obtain-

~lRemarksof Ray Hunt, at SMU-lSM conference on Lower World

011 Prices in Dallas, September 1986.

ing some of the better prospects with reduced

competition from the majors.

There has been concern expressed that the

new combinations will diminish competition

within the domestic industry. But, by several

commonly 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 table 39). The Federal Trade Commission has characterized the oil and gas production industry as

“not highly concentrated.” 42 Applying the current antitrust enforcement guidelines used by the

Department of Justice and Federal Trade Commission to the market for crude oil, no merger

between competing oil companies is likely to be

challenged based on its effects in the overall

crude market. I n several large mergers, the Federal Government found significant downstream

antitrust problems and ordered divestitures of certain downstream marketing and refining operations before approving the mergers.

In testimony before Congress, several witnesses

questioned the adequacy of the standard measures for assessing mergers among large oil companies. Concentration ratios, HHI and other indices are primarily concerned with measuring the

effects on market share of horizontal mergers

(combinations between competing companies),

and do not adequately reflect the true impacts

on competition of mergers in the vertically integrated oil industry. For example, it was noted

that the six largest oil companies could combine

into a single giant company without exceeding

the HHI indices triggering enforcement review.43

Moreover, they noted, traditional antitrust and

competition considerations were not the only

areas of economic or social concern raised by

the mergers.

qzsee testimony of Timothy j. Muris, Director, Bureau ot’ Competition, Federal Trade Commission in Legislation Affecting Oi/

Merger Proposa/s, supra note 1, at 71, citing a 1982 FTC study on

concentration in the 011 Industry. See also, American Petroleum

Institute, Market Shares and Individual Company Data for U.S.

Energy Markets: )950- 1984, Dlscusslon Paper, October 1985. Estimates of 4-firm and 8-firm concentration ratios in the oil industry

have been fairly steady, varying only a few percentage points either way since 1970. The 1982 Department of justice Merger Guidelines use numerical standards to ascertain whether a proposed

merger between competl ng companies may tend to affect competition adversely—the Herfindahl-H lrschman n Index or HH 1. The government IS most likely to challenge a proposed merger if the postmerger H H I Index IS above 1,000 or If It increases the post-merger

HHI IS increased by more than 100 points to above the 1800 level.

“The HHI measured In terms of U.S. production is only about 270

and In terms of U.S. crude oil reserves is approximately 329. All

Oi these values are well below the 1,000 HHI level lhdl ~0[/7kl//y

triggers potential antitrust concern with a merger between competitors. ” Testimony of Timothy j. Murris in 0;/ /ndustry Mergers,

supra note 13 at 234-237.

4 30 1 1 /ndu5fry Mergers, supra note 13, at 204.

Increase in Long-Term Debt

The wave of acquisitions and anti-takeover

defensive tactics added substantially higher levels

of debt for the oil industry as a whole, as well

as for individual companies. The Department of

Energy found an increase in debt equity ratio

among the Financial Reporting System (FRS) companies from 34.8 to 49.5 percent in 1984 alone,

with much of this increase attributable to the effects of the Chevron-Gulf, Texaco-Getty, and

Mobil-Superior takeovers. 44 OTA’s review of a

group of oil companies also shows higher debt

levels for most merged companies (see table 37).

Total long-term debt of the companies studied

more than doubled between 1983 and 1985. The

largest increases were by firms involved in

takeovers; their debt levels nearly tripled in 1983

to 1984 but repayments in 1985 lowered their

overall long-term debt to 21⁄2 times the 1983

levels. The heavier debt loads, at least in the short

term, have been accompanied by lower total expenditures by the combined companies on exploration and capital investment in 1985 than in

1984. Among the companies not involved in

takeovers, new long-term debt was used to retire prior debt at higher interest rates, to repurchase shares, to buy assets, and to provide additional capital for investment. The highest debt to

debt plus equity ratios, a common measure of

debt load or leverage, was shown by the two

companies that successfully averted hostile

takeover offers—increasing from 0.23: 1 in 1983

to 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 required

to file detailed annual reports. The FRS companies were selected

from the top 50 publlcly owned domestic crude oil producers in

1976 who had at least 1 percent of either the production or reserves of oil, gas, coal or uranium, or 1 percent of refining capacity 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 Petroleum

Co.; 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 acquired

companies, Cities Service, Gulf, Getty, and Superior, all filed separate FRS reports for 1984 because the mergers were not fully

complete.
114

Many of the corporate acquisitions followed intense, and sometimes bitter, battles for corporate

control. The impacts on corporate finances of

defensive tactics adopted to fend off unwanted

or “hostile” takeover offers raised concerns about

the targets’ future ability to fund exploration activities. In several successful takeover defenses, the

target companies averted the takeover by buying the offerors’ shares at a premium. In others,

the target merged with a friendly “white knight”,

which often outbid the original offerors. The

defending company was left with much higher

debt. The unsuccessful offeror was left with a sizable gain on the stock transaction. Results such

as this have led some raiders and other critics to

contend that the target managements were motivated more by concern over protecting their own

jobs than in advancing the shareholders interests.

An increase in long-term corporate debt is not

by itself reflective of a weakened financial position. Debt and equity are the two principal means

of raising capital for acquisitions and for capital

spending. Increased debt has some risks, however. Debt brings with it a requirement to pay

interest that, unlike dividends, generally cannot

be deferred. High debt levels among oil companies raise two concerns: reduced flexibility in

deciding how to spend its available cash flow;

and reduced commitments to exploration and

production as assets are sold and capital expenditures are cut to pay off debt.45

Effects on Exploration

The pattern of reduced exploration expenditures following recent mergers tends to contradict

some of the earlier studies and examples cited

in 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 have

increased. But these results predated the more

recent round of mergers and both the U.S. Steel

and Du Pent acquisitions involved essentially new

entrants into the oil business that operated their

purchases 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 considered

high, but not unmanageable, however debt levels of 70 percent

of capitalization or more are a matter for concern.

mergers have involved the disappearance by absorption of one energy company into another and

the overall contraction of the combined entity,

with lower production levels, reserves, and exploration expenditures.

During the debate over the effects of mergers

and acquisitions in the oil industry, many of the

representatives of acquiring companies, their investment bankers, and their defenders strongly

denied that exploration efforts would be reduced. 46 Some company executives even suggested that exploration could be expanded because of efficiency gains and the stronger cash

flows and asset bases of the merged companies.

However, others inside and outside the industry

argued as strongly that exploration would be cut

because the newly purchased reserves reduced

the incentive to look for more oil and repayment

of the new long-term debt would divert cash flow

that otherwise might be used for E&D.

The available evidence strongly suggests that

the short-term results of the merger activity for

the U.S. oil industry as a whole are reduced

spending on exploration, fewer wells drilled, and

less R&D than there was before the mergers and,

arguably, than there might have been had these

firms continued as separate entities. The amount

of this change is not possible to quantify, but is

probably much less than the losses attributable

to the decline in prices. The merger-related expenditure declines are probably less than those

caused by low prices because the 1986 spending cuts by all companies tended to be as large

or larger than the 1985 cuts by merged companies. The fact that merged companies took cuts

in E&P and capital expenditures in 1985, while

others were still spending at previous levels or

higher, suggests that the mergers have significantly decreased exploration expenditures below

levels that might have been maintained by independent entities. If, for example, Gulf, Superior,

46FOr examples, See: supplernentay material submitted by Standard Oil Company of California in Legidation Affecting Oi/ Merger

Proposa/s, supra note 1, at 540; response of Chevron U.S.A. to Committee questions, id. at 539; statement of Morgan Stanley & Co.,

Inc., id. at 516; and material submitted by the Department of the

Interior, id. at 529. See also, Testimony of Joseph j. Wright, Office

of 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 in

Oil Industry Mergers, supra note 13, at 359-60.
115

Getty, and Cities Service had remained separate

and continued their active exploration programs

and if these programs were cut at the industry

average, the separate exploration expenditures

added to the baseline expenditures for Chevron,

Mobil, Texaco, and Occidental, respectively,

wouId likely exceed the totals for the merged entities.

The merged companies typically cut combined

capital spending significantly in 1984 to 1985,

while other large oil companies were maintaining or increasing their investments. This pattern

is also seen in other surveys of U.S. exploration

and development expenditures shown in table

40 for 1983 to 1985. Table 41 shows a similar pattern in different, but comparable data on domestic exploration expenditures in 1986 to 1987.

When oil prices fell in 1986, the merged companies reduced exploration budgets that were already constricted, and the share of their cash flow

directed at debt reduction is undoubtedly much

higher than was anticipated when the mergers

occurred.

There are others who maintain that it is purely

coincidental that exploration expenditures of

some combined companies were cut substantially

after the mergers. In their view the reasons for

the cuts were related solely to the anticipated future oil prices and the quality of the available exploration prospects. There are of course other facTable 40.—Capital and Exploration Expenditures for Selected Oil Companies

1983-1985 (thousands of dollars)

1985 1984 1983

capital capital capital

and and and

exploration Percent change exploration Percent change exploration

spending 1984-85 spending 1983-84 spending

Exxon Corp 10,339,000

Amoco Corp 5,306,000

Shell 011 Co 4,080,000

Mobil Corp 3,513,000

Superior 0 1 1 —

Combine d 3,513,000

Texaco, Inc 2,824,000

Getty 011 —

Combined 2,824,000

Atlantic Richfield Co 3,595,000

Chevron Corp 4.035,000

Gulf 011 —

Combine d 4,035,000

Sun Co Inc. 1,748,000

Standard 011 Co. 4,277,000

Unocal Cor p . 1,847,400

Tenneco, In c 1,719,000

Conoco Corp. 1,402,000

Phillips Petroleum ., 1,060,000

Amerada Hess Corp. ... 929,000

Occidental Petroleum Corp. ., 1,151,70 0

MidCon Corp . 354,869

Combined a

. .. . —

Marathon Oil Co. . . 1,165,000

Texas Oil & Gas Corp. . . . 739,400

Internorth, Inc . 591,200

Houston Natural Gas Corp. ., –

Combined 591,200

Diamond Shamrock Corp 679,900

Pacific Lighting Corp. ., 527,114

Coastal Corp. 341,300

American Natural Resources —

Combined ., 341.300

6.0

14.6

3.9

– 7,7

—

–7 7

–24 6

—

–24 6

10,4

– 15.7

.

– 15,7

–26, 5

83.6

–5. 0

– 1,7

1.1

–23. 6

– 16,5

5.5

● 8.2

.

60.2

–3. 8

–8. 8

—

–44, 3

7,0

–7, 1

122

—

–38. 9

9,755,000

4,630,000

3,927,000

3,806,000—

3,806,000

3,744,000—

3,744,000

3,257,000

4,786,000—

4,786,000

2,377,000

2,329,000

1,944,800

1,748,000

1,387,000

1,387,000

1,112,161

1,091,240

327,951—

727,000

768,679

648,548

413,652

1,062,200

635,500

567,335

153,542

404,600

558,142

8 4

13,2

37,8

–12 4

—

–12 4

–26 O

—

– 26.0

–2. 9

– 18.0

—

– 18,0

83.7

1.3

11.1

8.6

–20. 5

21,6

53.1

14.7

8.9

—

–25. 0

16,1

155,2

33.0

88.0

36.1

– 10.8

34.8

34.4

34.5

9,000,000

4,091,000

2,850,000

3,330,000

1,016,855

4,346,855

3.833,000

1,223,319

5,056,319

3,355,384

3,067,000

2,770,000

5,837,000

1,294,000

2,298,000

1,751,000

1,609,000

1,744,700

1,141,000

726,365

951,019

301,229

969,000

662,332

254,152

310,971

565,123

466,853

636,013

113,893

301,100

414,993

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 change

1985 budget 1985-86 1986 est. budget 1986-87

Major oil companies:

Amerada Hess Corp. 310 120 –61 95 75 –21

Amoco Corp . 3,170 1,650 – 4 8 1,300 1,300 0

Atlantic Richfield Co. 2,300 1,035 – 5 5 1,000 750 – 2 5

Chevron Corp.a

. . 1,800 1,200 – 3 3 1,050 975 – 7

El. du Pent de Nemours a

700 420 – 4 0 500 550 10

Exxon Corp . . 4,700 3,050 – 3 5 2,700 2,565 – 5

Kerr-McGee . . 140 75 – 4 6 75 70 – 7

Mobil Corp.a . . 1,460 1,020 – 3 0 1,020 1,020 0

Occidental Petroleum Corp. a

375 260 –31 260 235 – 1 0

Pennzoi l . , 270 175 – 3 5 140 120 – 1 4

Phillips Petroleum Co a

455 335 – 2 6 200 240 20

Shell Oil Co. . 1,800 1,350 – 2 5 1,645 1,520 – 8

Standard 1,700 1,000 – 4 1 1,250 1,150 – 8

Sun Co., Inc. 820 625 – 2 4 430 430 0

Tenneco, Inc. 565 240 – 5 8 310 235 – 2 4

Texaco, Inc. a

1,670 1,100 – 3 4 1,000 900 – 1 0

Union Pacifi c 400 200 – 5 0 195 185 – 5

USX Corp. a . . 1,255 725 – 4 2 560 480 – 1 4

Unocal Corp .

a

945 680 – 2 8 600 640 7

Total majors . .......24,835 15,26 0 – 3 9 14,330 13,440 – 6

Selected independents:

Apache. 120 80 – 3 3 65 25 – 6 2

Burlington Northerna

430 95 – 7 8 100 100 0

Diamond Shamroc k

a

190 90 – 5 3 105 130 24

Enro n

a 200 100 – 5 0 100 91 – 9

Enserc h 250 140 – 4 4 158 103 – 3 5

Freeport-McMoRan a

122 55 – 5 5 55 52 – 5

Louisiana Lan d

a

. .. . 260 155 – 4 0 155 147 – 5

Mitchell Energy ... 130 89 – 3 2 65 65 0

Murph y . 113 60 – 4 7 50 50 0

Pogo Producing . . 115 70 – 3 9 65 40 – 3 8

Santa Fe Souther n

a

195 145 – 2 6 100 95 – 5

Transco Exploratio n 280 125 – 5 5 125 120 – 4

Total independents. 2,405 1,204 –50 1,143 1,018 –11.

‘Companies lrlVOlv@ In major takeovers 1982-86

SOURCES OTA from Oil & Gas Journal July 21, 1986, and Jan 19. 1987

tors that contributed to lower exploration

expenditures in recent years, such as lower property acquisition costs because of reduced offerings of Federal offshore leases and lower bonuses,

cost deflation in drilling and services, and deferrals of major projects because of price uncertainty. These factors affected both merged and

non merged firms alike, however.

Oil production may actually increase if the purchaser can exploit the acquired reserves more

efficiently. The classic example of this was Shell

Oil Co.’s acquisition of Belridge Oil in 1979. Following the merger, Shell invested in enhanced

recovery to expand heavy oil production from

Belridge’s California reserves. More recently, a

good geographic “fit” of acquiring and acquired

companies was cited as an advantage in the Phillips’ takeovers of General American Oil and

Aminoil, and in Louisiana Land & Exploration

Co.’s purchase of Inexco Oil. These transactions

involved complementary reserves holdings in

areas where the purchasers were already active

and allowed expansion into other areas where

they were not represented.

Some major acquisitions may have been motivated primarily by reserves replacement, rather

than as a means of corporate expansion. Several

companies that bought other firms for their re-
117

serves had not been particularly successful in

replacing their reserves through exploration .47

This motivation is suggested by the shrinkage of

the post-merger companies as many unwanted

producing properties and operations are sold or

abandoned. The acquiring company may be successful in maintaining its production level in the

future out of its purchased reserves, but it may

support a production level that is less than the

combined companies before the acquisition. Cumulatively, overall domestic production could

drop because of reduced total spending on exploration.

It has been argued that mergers need not result in reduced exploration and fewer reserves

added. For example, a merger might create a new

entity that is more efficient and successful at finding oil than its predecessors. Moreover, the combined firm would still face the need to replace

the reserves lost through production (assuming

it maintains the same production level after the

merger) and would still be subject to requirements to drill many of its leases or lose them. The

combination might lead to improved economies

of scale by eliminating or reducing duplicative

overhead and nondevelopment-related expenditures allowing more productive use of the combined financial resources and technical people.48

The Department of the Interior has suggested that

even if the merged company only conducted the

same amount of exploration as before, it could

combine information on geology, and geophysics

of exploration prospects and select the best

drilling sites from a larger menu and it might actually improve its exploration results with less

overall spending on exploration and fewer holes

drilled than might have been spent by the firms

separately. 49 (This suggested result is questionable, however, since high grading would not necessarily increase the amount of reserves found,

particularly if the acquired company was no more

successful at finding oil than the acquiring company 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 note

1, 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 laid

off or leaves. )

Others doubt that there are any added efficiencies in oil exploration to be gained through the

mergers among large oil companies. Historically,

the range of finding costs posted by both first and

second tier major oil companies have been similar. The biggest companies did not necessarily

have the lowest finding costs. Moreover, most of

the anticipated savings would come from cutting

staff, which may lead to long-term inefficiencies

in exploration from the lack of experienced technical people. so

it is too soon to tell whether the mergers will

mean a net increase or decrease in exploration

and production in the long term. Several merged

companies, e.g., Chevron and Mobil, have made

substantial efforts to pay down debt even with

lower oil prices. In a few years, they maybe ready

to reallocate resources to exploration and research from a stronger financial and resource position.

In the longer term, even at lower oil prices,

many of the larger merged companies wiII again

have cash available that could be used for E&P

after reducing their long-term debt. It will then

become more apparent whether the added debt

burden, asset sales, and restricted exploration

activities assumed to undertake the merger will

have produced a sounder, more efficient enterprise better suited to an era of uncertain oil prices.

Table 41 shows preliminary 1987 exploration

budgets for some firms, and it is notable that several of the merged firms are slightly increasing

their exploration budgets.

Other Restructuring Activities

Oil companies have adopted a variety of restructuring strategies which they believe will help

them to compete in the current era of volatile

energy prices. Mergers and acquisitions have

been perhaps the most public aspect of the restructuring, but they have been only part of a

range of industry responses to changing conditions.

~~see, for exam Pie, the testimony of Howard W. Pifer, I I 1, Managing Director, Putnam, Hayes & Bartlett, Inc., In Oi/ /ncfustry

Mergers, supra note 13, at 211.
118

Segmentation and 66Dis-integration”

Changes in the world oil industry following the

OPEC price shocks of the 1970s have contributed

to the modification of the traditional integrated

structure of some major companies. Maintenance

of a secure source of crude supply is no longer

a priority for many integrated companies because

of: 1 ) current world overcapacity in oil production; 2) a greater diversity of sources for crude

oil with decreased reliance on mideast OPEC oil;

and 3) the widely shared expectation that oil demand (and hence sales) will grow only modestly

through the end of the century.

The process of buying and selling of crude oil

has also changed. Oil prices now can fluctuate

much more rapidly than before. The traditional

long-term contracts for crude, which used to account for 90 percent of U.S. supplies, have largely

been abandoned, and in 1986 up to 90 percent

of supplies from outside the United States were

obtained on the spot market or at spot-marketrelated prices. Netback arrangements with foreign producers are a part of this trend .51 Many

companies have turned to options trading to

moderate the risks of volatile oil prices.

Increasingly, segments of the oil industry are

being separated vertically and operationally.

Some integrated companies no longer depend on

their own reserves to supply their refining and

marketing 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 barrel

that the seller receives is tied to the sales price of refined products. This arrangement guarantees the refiner a minimum margin

on product sales. Netback pricing was implemented by Saudi Arabia [n late 1985 as part of Its drive to regain market share. The terms

of netback pricing arrangements are highly confidential, but by

spring 1986 it was estimated that 3.5 to 4.5 million barrels of 011

per day were sold under these terms by the Saudis and others. Arthur Andersen & Co., Oil and Gas Reserves Disclosures: 1981-1985

Survey of 375 Pub/ic Companies, 1986 at s-9. It should be noted

that in early 1987, the Aramco Companies were reported to have

signed a long-term fixed price agreement with the Saudis. Whether

this marks a shift away from netback pricing is not yet known, since

the terms of these agreements are confidential.

‘

2

’’ Crude oil production and crude oil refining and marketing are

almost completely unrelated aspects of the petroleum business.

Crude oil today is a fungible commodity in trade. Petroleum companies sell most of their crude to third parties and buy most of their

crude for refining purposes from third parties. This is the very nature of the business. There is not a direct tie between the wellhead

and the gasoline pump within a company. ’ Statement submitted

by Gulf Oil Corp. in response to Committee questions in Oi/ /ndustry Mergers, supra note 13, at 426.

are frequently seen as separate from upstream exploration and production activities. The downstream activities are now treated as independent

and important profit centers rather than as an outlet for a company’s crude. In the early 1980s, this

shift led to the closing of many company-owned

retail outlets and a net reduction in domestic

refining capacity as refineries were upgraded and

outmoded facilities were closed. Some companies have begun to redeploy their resources to

their most profitable segments functionally and

geographically instead of maintaining an integrated nationwide operation from exploration

and production to shipping, refining, distributing, and marketing. For example, Ashland Oil

soId many of its producing oil properties and relies more heavily on crude purchases to supply

its refineries. Arco has pulled out of the retail oil

market in the northeast. The cost-cutting and upgrading in refining operations as part of the early

restructuring of downstream operations appear

to have benefited some companies during the

price plunge, with higher profit margins in refining helping to offset upstream losses.

According to some industry analysts, the growing segregation of upstream and downstream

activities has contributed to a decline in the

proportion of production revenues “plowed

back” into acquiring and developing unproven

properties. The 60 percent “plowback” in 1985

was the lowest in at least 5 years (see table 42).

As noted earlier, a primary factor driving these

changes has been the mediocre result of much

of the E&D activity of the last 10 years reflected

in the extremely high finding costs reported by

much of the industry and the serious disappointments in exploration on the frontiers.

Cost-Cutting

Many restructuring programs were announced

as efforts to cut costs and conserve capital and

cash flow in anticipation of a prolonged period

of low oil prices and sluggish demand. Although

these changes were announced in early to mid1985, most companies underestimated how sharply, and quickly, oil prices would actually fall in

1986 so that these programs were not fully in

place to offset potential losses.
119

Table 42. —Reinvestment in Oil and Gas Exploration and Production (375 publicly held oil & gas producers)

Plowback ratios

Us. 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 60 104 133

Pipeline/utillty 74 78 83 107 106 51 63 81 90 94 68 75 79 104 103

Diversified 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 87 130 144

Pipeline/utillty 113 90 107 108 106 74 63 162 92 94 107 84 111 105 104

Diversified 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 costs

blncludes proved propefly aCqulSltlOn costs

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 exploration

and 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 eliminate duplicative functions and streamline activities. As part of accompanying changes in investment priorities and philosophies, many firms have

made sharp reductions in exploration and development budgets. Within E&D programs, capital

spending has been directed away from unproven

property acquisition and frontier-wildcat drilling

toward more development drilling and intensive

development of existing fields. (These shifts are

in addition to the increases in development

spending that would normally follow the high

levels of exploratory activity in the early 1980s.)

Although more development drilling generally

leads to more production, over the longer term,

lower exploration expenditures eventually will

lead to lower production unless reserves are

replaced from other sources. A continuation of

these trends implies less overall exploration and

development expenditures, as well as less R&D

spending in an industry with historically low R&D

spending.

With less exploration activity, exploration and

production staffs have been slashed. Corporationwide personnel reductions have been achieved

through early retirements, hiring freezes, layoffs,

and voluntary and involuntary separations. Oil

industry employment is down by about 25 percent from 1980 levels according to early 1986 estimates. personnel cuts have meant one-time

charges against earnings for severance benefits

at many companies, but may mean lower costs

in the future. Of course, the risk inherent in the

loss of so many experienced people is that they

will not return to the industry if oil prices and exploration activity rebound.

Financial Strategies

Pressures from large investors and a general

shift in corporate management philosophy have

given greater emphasis to “enhancing shareholder values” in addition to the bottom line

profit or loss as a measure of financial performance. Restructuring activities have included strategies to alter a corporation’s capital structure and

to improve key indicators of financial performance (e.g., earnings per share, assets per share,

return on assets, return on equity). These strategies include buying-back shares, increasing or decreasing long-term debt, major asset sales,

spinoffs, and writedowns. Companies have sometimes increased or maintained dividends to increase shareholder returns even when it was necessary to borrow money to do so.

Share Buybacks.–Some companies have

elected to make strategic investments to reduce

the number of their outstanding shares through

share buyback programs to boost indicators such
120

as assets per share, cash flow per share, and earnings per share. Share buy backs are also seen as

a means of increasing the return to shareholders,

but the cash benefits only accrue to those disposing of their shares. Before the 1986 tax law

changes, share repurchase programs were generally preferable for tax reasons to increasing dividends because of the capital gains treatment on

any increase in share value. The 1986 tax law

changes and sharply restricted cash flows probably have reduced or eliminated most current

buyback programs, but should financial conditions improve, such programs will again compete

with exploration as an alternative use of discretionary cash flow.

It has been widely thought that the announcement of a buyback program also benefits those

who retain shares, because share prices generally go up following such an announcement.

However, the long-term effect of this share price

boost is less clear; there is no evidence showing

that stocks of companies participating in buyback

programs outperform industry averages.

Share repurchases by oil companies are part

of a broader trend in the economy, the replacement of equity with debt. Total equity retirement

from mergers, buy backs, and leveraged buyouts

exceeded new equity offerings of nonfinancial

corporations by almost $160 billion in 1984-85

and by $35 billion during the first half of 1986.53

Oil company buy backs have been financed out

of internally generated funds, and in some instances through new long-term debt. Many of the

buyback programs were directed at open market purchases, but some were undertaken to

eliminate certain classes of preferred stock, or to

acquire the shares held by hostile tender offerors.

Phillips petroleum and Unocal went heavily into

debt to buy back their own shares to thwart

takeover bids.

As shown in table 43, share repurchases absorbed billions of dollars in oil company funds

in 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

Amount

Company Year (millions) Remarks

Phillips Petroleum Co. . . . . . . . . . . . . 1985

Texaco, Inc. . . . . . . . . . . . . . . . . . . . . . 1984

1983

ARCO . . . . . . . . . . . . . . . . . . . . . . . . . . 1985

1984

Exxon, Corp. . . . . . . . . . . . . . . . . . . . . . 1985

1984

1983

Sun Co., Inc.. . . . . . . . . . . . . . . . . . . . . 1985

1984

1983

Standard Oil Co. . . . . . . . . . . . . . . . . . 1986

1985

1983-84

Mobil Oil Corp. . . . . . . . . . . . . . . . . ..1982-83

Amoco Corp. . . . . . . . . . . . . . . . . . . . . 1985

1984

Mitchell Energy & Dev., Inc. . . . . . . . 1986

Louisiana Land & Exploration Co. . . 1986

1985

1984

1983

Shell Oil Co. . . . . . . . . . . . . . . . . . . . . . 1984

$4,972

$1,282

74

3,489

781

$2,687

2,631

762

221

203

$100

561

70

482

806

1,191

3.7

16.4

10.8

11.6

212.8

$5,900

Exchange offer of debt securities of $4.5 billion for 72.58 million shares of common stock in 1985

Purchase of common stock

Bought back 28°/0 of outstanding common stock before suspending program in January 1986 because of lower oil prices

54 million shares

164 million shares

21 million shares

Purchase of common stock for treasury

Authorized for share purchase

Includes $523 million for 11 million shares repurchased in Aug.

1984 tender offer

Open market purchase of 1.5 million shares.

Repurchase of shares for treasury

Net increase in treasury shares

Purchase of 218,400 shares

Repurchase of 604,700 shares before suspending authorized

repurchase of 2 million shares in 1985-86

Purchase of 10.7 million shares 1983-85

Parent company Royal Dutch Shell purchased remaining 31 0

/0 of

publicly held shares.

SOURCE: Office of Technology Assessment, based on company annual and quarterly reports 1984-87
121

backs raise the same concerns as mergers and

acquisitions because substantial funds that could

have been used for oil exploration were returned

to shareholders. In the companies analyzed by

OTA, share buy backs generally increased as a

portion of discretionary cash expenditures relative to investment in E&P in recent years. In 1985,

among large oil companies i n the OTA group not

involved in takeovers, share repurchase programs

absorbed 23 percent of internal cash flow and

domestic E&P spending 53 percent.

Changes in Debt Levels.–The oil industry had

been historically cautious in using debt financing before the late 1970s, with the majors generally carrying lower debt loads than the independents. Many companies increased their debt

levels in the early 1980s because debt financing

was seen as more cost effective than equity

financing to raise capital for expanded exploration activities. Also, interest payments, unlike dividends, are tax deductible, and an increase in

debt, unlike an increase in shares, doesn’t dilute

shareholder values.

The oil industry has not been alone in increasing debt; all U.S. industries carried substantially

higher long-term debt in 1986 than they did in

1980. Business Week estimates that the debt to

equity ratio of the Nation’s nonfinancial corporations soared from 35 percent in 1980 to an all

time high of 47 percent in mid-1986.54 Some Wall

Street analysts view a rise in oil company debt

and a corresponding decrease in equity as beneficial. They believe that U.S. oil companies are

“overcapitalized” and thus, “too quick to make

investments that might not have been very carefully worked out.”55 Greater reliance on external debt financing might, in their view, assure that

exploration funds were invested in potentially

more profitable areas and only after a rigorous

review. Equity capital should not continue to be

invested in oil and gas projects with below average returns, they reason, but rather should be

returned to shareholders who might put it to

541 bld

55see ‘‘ Restructu r! ng Shifts FOCUS of (3I I Industry, ~;/ 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 is

one reason for the trend in share repurchases discussed above.

Increased leverage has also been seen as a

means to repel hostile takeovers. An SEC study

of recent U.S. corporate takeovers found that

companies that successfully fended off hostile

takeovers tended to have higher debt loads than

companies that were acquired.56

As noted previously, after initially increasing

debt, many merged oil companies are now paying down or refinancing long-term debt to improve their leverage position. Chevron, Texaco,

and Mobil have made significant progress in reducing the massive debt loads incurred in acquisitions of other companies, redirecting available

cash flow to pay debt by slashing capital expenditures, cutting overhead, and selling assets.

Reducing the Asset Base.—Many companies

have adopted strategies to downsize or reduce

the asset base of the company, There are various sound business reasons for making a company smaller—to concentrate on core businesses,

to remove subsidiaries that might create large

losses in order to make the balance sheet stronger

and to increase the percent return on assets. The

asset shrinkage has been accomplished through

a combination of spinoffs, sales, abandonments,

and writedowns. Writedowns, reductions in the

value of the assets carried on corporate books,

were often taken to reflect price-related changes

in the values of reserves and other assets, such

as drilling rigs.57 Asset sales bring cash directly

to the company, while tax writeoffs yield some

offsetting tax benefits.

In a move to improve other indicators of financial performance, some oil companies have

resorted to spinoffs of unprofitable mining or

drilling contractor subsidiaries to remove their imIGsee John pound, Kenneth Lehn, and Gregg Jarrell, ‘‘Are

Takeovers Hostile to Economic Performance?” Regu/at/on, September/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 full

cost accounting method, mostly Independent oil companies, require writedowns in the value of 011 and gas reserves to reflect lower

prtces.
122

pacts on earnings. Other spinoffs involved the

nonenergy businesses that oil companies bought

during the 1970s diversification trend. When

these subsidiaries are “spun off” or sold, the assets of the parent company are adjusted downward by an amount reflecting the value assigned

to the newly separated entity. Interests in the

newly independent entities are distributed to

shareholders and then can be separately traded,

creating additional opportunities to realize value

on corporate assets. Examples of this trend include: Amoco’s spinoff of Cyprus Mining; Arco’s

sale or liquidation of most nonenergy activities

of its Anaconda Minerals subsidiary; and Noble

Affiliates’ spinoff of its drilling services subsidiary.

Oil and gas writedowns have generally been

of very high cost reserves in remote frontier areas,

e.g., Arco’s writeoff of North Slope gas reserves.

Other writedowns reflect discontinued operations

or anticipated losses on asset divestitures, such

as Mobil’s writedowns in preparation for its

planned divestiture of Montgomery Ward Department Stores.

Looking for New Internal Sources of Funds.–

As companies look internally for new ways to

generate cash flow, some have turned to employee pension funds as a potential source of

funds. Exxon and Phillips have announced plans

to tap overfunded employee pension plans by

closing out the existing plans, purchasing annuities for participants and taking the excess funds,

and starting a new employee pension plan. (The

plans have “excess” funds over their anticipated

liabilities because their investments have performed well.) Exxon anticipates that it will recapture about $1 billion from its employee pension

fund, an amount equal to roughly one-third of

its domestic E&P spending in 1986. This option

may appear attractive to other large companies.

Creation of New Financial lnstruments/lnvestment Arrangements. —The 1980s saw the creation and the expanded use of new financial instruments and investment vehicles, such as royalty

trusts and master limited partnerships (MLPs), as

ways to attract investment dollars and return

value to shareholders. These arrangements

offered several advantages over traditional stock

ownership and previous investment devices. For

example, MLPs pay no corporate income tax and

thus pass through income to the partners or “unit

holders” along with a share of partnership deductions that can be applied on the partners’ personal income tax returns. (As discussed below,

the 1986 tax law changes have limited some tax

aspects of oil and gas MLPs.) The MLPs and

royalty trust units also can be freely traded on

stock exchanges and are thus more liquid than

previous vehicles.

MLPs have also become an attractive mechanism for both small and large oil companies to

return value to shareholders in response to pressures from aggressive investors or takeover

threats. Some companies transferred many of

their producing oil and gas properties to MLPs

and royalty trusts and distributed interests to

shareholders. The interests in the partnerships

and trusts can be separately traded, perhaps resulting in a greater return to investors, while the

parent company retains a managing interest and

control over the properties. Some companies

have also offered shares in the partnerships and

royalty trusts to the public to raise exploration

funds as an alternative to issuance of new common stock or long-term debt. (Some examples

include Mesa Petroleum’s Mesa Energy Partners,

Sun Co. ’s Sun Energy Partners, and Transco

Energy’s Transco Exploration Partners.)

Royalty trusts were a popular vehicle for independents to attract funds from outside investors

for development drilling. But the creation of

royalty trusts by converting existing corporate oil

operations drew much criticism because they

were seen essentially as a liquidation of a company’s reserves position. Royalty trusts were said

to reduce the availability of internally generated

cash flow for exploration because income from

the producing reserves in the trust and related

corporate tax incentives were transferred to investors, who might not reinvest them in the oil

industry.

58

These vehicles drew billions to petroleum investments, but their future attractiveness is

clouded 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 Attecting Oi/ Merger Proposa/s, wpra note 1, at 374.
123

investment, the currently poor oil price outlook,

and the prospect of lower overall tax rates. Although the tax bill maintained some of the tax

advantages of oil and gas investments, there is

concern that with lower tax rates, high-income

investors will be less likely to invest in risky oil

and gas ventures without a significant risk

premium.

The 1986 tax law changes preserved many of

the tax benefits for oil and gas exploration that

can still be passed through to the unitholders.

They did, however, limit the deductibility of “passive” losses from the partnerships, which could

further diminish their attractiveness. Such passive

losses can only be charged against similar passive income and cannot be used to shelter other

income unless the partner shares in the risk of

the venture at a level in excess of the investment.

To continue the tax shelter aspect of oil and gas

investments, investors must share liability exposure. Some industry tax experts have suggested

that new investment packages will be created to

overcome the passive loss restriction—perhaps

a combination of a partnership interest and an

insurance policy to cover losses in excess of the

participation.

Effects of Restructuring

The long-term effectiveness of these restructuring efforts wiII not be known for several more

years. Many cost-cutting moves will not provide

immediate actual savings, and the sudden price

drop and slide in revenues this year appears to

have caught many companies by surprise. In

addition, because major restructuring is unlikely

to have been undertaken at random—each kind

of restructuring was more likely to be undertaken

by those companies most in need of the potential benefits it offered, or most vulnerable to it

if the restructuring was imposed—the results of

industrywide surveys of financial performance

will be ambiguous about the “success” of restructuring. For example, many companies absorbed by hostile takeovers were vulnerable to

such takeovers because of financial weakness;

these companies may have been expected to undergo significant budget cutting with or without

mergers, perhaps at levels greater than industry

norms. Thus, post-merger statistics showing reduced investment levels beyond industry averages must be interpreted carefuIly to separate the

effects of the takeover from other market effects.

Nevertheless, it is quite telling that extensive

assurances about the positive effects of mergers

were given to Congress in hearings held to explore the effects of the wave of mergers on the

industry, and the more easily measured of these

positive effects (increased E&D activity) have

clearly not materialized. It seems clear that the

short-term effects of mergers on E&D spending,

and probably on R&D as well, have been negative. The short-term effects of mergers on less easily measured characteristics, such as the “efficiency” of E&D activity, and the effects of other

restructuring activities have not been carefully

measured.
Chapter 7

Production Loss From Reduced Drilling

All oil wells experience a declining production

rate as reservoir pressures decline and as the oil

closest to the wellbore is produced. Although

different geologic conditions, production strategies, and oil characteristics yield different decline

rates, in all cases production in a field can only

be maintained by proceeding with secondary and

tertiary recovery and by drilling additional producing wells. And as production rates in some

fields inevitably decline, discovery wells must find

new fields to exploit if national production is to

be maintained.

As noted above, one source of lost domestic

oil production resulting from low oil prices is the

early abandonment of stripper wells and other

marginal wells. Additional production will be lost

as existing wells continue their natural declines

and too few additional wells are drilled to compensate for these declines. As discussed earlier,

declines may be expected in all aspects of drilling,

from shallow, low-cost development wells to the

most expensive offshore and arctic wells on the

frontier. The reduced level of development drilling will affect production the soonest, because

some of these wells can often be producing

weeks or a few months after they are “spudded”

(drilling has begun). At the opposite end of the

spectrum, exploration wells in frontier areas may

precede production by a decade or more as infrastructure is built and, in some deep offshore

cases, as new production technology is designed

and tested.

In order to evaluate accurately the effect of low

oil prices on drilling and, eventually, on production, it is necessary to understand how the oil

price change and other factors associated with

it will change the level of drilling activity, the distribution of drilling (geographically, by the nature

of the target, etc.), and the likely success of the

drilling in adding to reserves and production. In

OTA’s view, there are strong uncertainties with

all of these factors.

The Level of Drilling Activity

From 1981 to 1985, oil drilling rates remained

very high despite declining prices and a decline

in the number of operating drilling rigs (from

3,970 rotary rigs in 1981 to 1,980 in 19851

); during these years, the number of oil well completions ranged between 37,000 and 43,000 wells

per year, with 1984 being the peak year.2 Apportioning dry holes between oil and gas according

to the ratio of oil to gas completions, the total

wells drilled “for oil, ” successful and dry, ranged

between 55,000 and 60,000 thousand wells per

year.

The rig count hovered around 700 for much

of 1986, and, around mid-year, analysts expected

the industry to drill somewhat over 30,000 “oil

wells” (successful and dry)3 during that year. Assuming that prices remain low, it is by no means

clear whether drilling activity in 1987 and after

will rise, fall, or remain at the same general level.

Some of the 1986 activity is a short-term continuation of activity planned and begun before the

price drop, with much of the capital investment

sunk. For some of these projects, there will be

no replacement upon their conclusion. Some additional projects will be continued because they

are necessary to hold leases or fulfill contractual

obligations, and these too may have no replacements. Finally, some industry analysts argue that

the list of viable drilling prospects at 1986 oil

prices is a very limited one, so that a continuation of those low prices for any length of time

would exhaust the industry’s inventory of drillable prospects and force down the drilling rate.

T Independent Petroleum Association of America, ‘‘U n Ited States

Petroleum Statistics, 1986. ”

‘Ibid.

lln industry usage, an oil well is a Successfully CO Mp[eted 011-

producing well, In fhjs secljon, 07A added a proportional number of dry holes–unsuccessful wells that are abandoned–to the

number ot completed wells, and thus our terminology will not correspond to the standard usage.

125
126

On the other hand, there are many independent drillers who claim that they have access to

drilling prospects that are economic, but cannot

drill because of a lack of capital. Although capital availability has seemingly evaporated from the

oil market, it seems unlikely that this will continue for long if there are reasonable prospects

for profitable investments. As discussed in chapter S, there are substantial disagreements about

the number of economic prospects still available

to the industry.

The Distribution of Drilling Targets,

and the Likely Success at Adding

Reserves and Production

As discussed in chapter 6, “The Efficiency of

E&D Activities,” reductions in exploration and development activity because of the price drop will

not be uniform, since changing economics affects

different regions, geologic targets, and activity

types differently. For example, most of OTA’s industry contacts expect drilling activity to focus

on low risk prospects, with shallow development

activity to sustain only a moderate decline and

high-risk exploratory and deep drilling activity to

suffer a substantial decline. A sign that this is beginning to happen is the downward shift in average depth of new wells; for the first 8 months of

1986, the average well depth was 4,153 v. 4,440

feet for 1985.4 This shift in activity probably would

tend to increase well success rates but decrease

the reserves found per well drilled. On the other

hand, some geographic shifts will tend to favor

those areas that traditionally have paid off more

handsomely in terms of reserves added per well.

Table 44, which shows the 1980-1984 average

reserves per oil well driIled for the nine regions

in the United States, amply illustrates why a regional shift in drilling can greatly affect overall

drilling results in terms of reserve additions.

Projections of regional drilling rates for 1986

made in JuIy of that year by the Oil and Gas Journal,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 well

Region (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. . . . . . . . . . . .

2,524,000

177,000

78,00 0

49,000

71,000

14,000

5,000

62,000

6,000

50.000

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.

that drilling will tend to favor regions with high

historic rates of reserve additions per well, though

not uniformly. For example, 1986 drilling in Alaska

is expected to be higher than normal, about 265

wells drilled compared to an average of 150 wells

drilled per year during 1980-84. California drilling

also is expected to be high, about 2,460 wells,

only slightly lower than recent levels. (However,

in both these States, much of this drilling requires

lengthy planning and considerable advance capital investment, and thus the 1986 drilling level

may not reflect the price drop as much as activity levels in other areas.) The Gulf Coast, another

“high reserves per well” area, also holds up well

at about 6,700 wells, one-third under recent average levels. On the other hand, activity in the

Rocky Mountains and Northern Great Plains

(2,1 50 wells) and Michigan Basin (380 wells), the

two other “high reserves per well” areas, is projected to decline at about the national rate.

The implication of this nonuniformity in the reduction of drilling activity is that 1986 oil reserve

additions are not likely to be as low as might be

expected from the percentage fall in the national

drilling rate. Had the reduction been uniform and

had the overall rate of reserve additions per well

remained at recent levels, the expected 1986 reserve additions would have been 1.6 billion barrels. Applying the historic per well reserve rates

to the regional drilling breakdown gives expected

1986 reserve additions of about 2.2 billion barrels, a value only slightly below the average for
1 2 7

the 1980s. Note, however, that the latter value

is not the “correct” value either, because:

● wide year-to-year swings in regional finding

rates virtually guarantee that any individual

year’s average will vary considerably from

the historic rate;

● the changes in drilling patterns caused by the

lower oil prices occur within regions as well

as across them, and applying the regional

finding rates does not take intraregional shifts

into account;

● i n some key States—California, in particuIar

–past increases in reserves depend significantly on enhanced oil recovery (EOR) in

addition to exploratory and development

drilling, and using such simple measures as

‘‘reserves per well” cannot capture the effects of drastic changes in the attractiveness

of EOR investments; b and/or

● the drilling mix is said to be shifting towards

development drilling and away from exploratory drilling; such a change in the drilling mix

would tend to lower overall finding rates.

Projecting Oil Reserve Additions and

Production Based on Extrapolating

Regional Drilling Patterns and Per

Well Reserve Additions

Joseph Riva of the Science Policy Research Division, Congressional Research Service has projected regional and U.S. oil reserve additions and

production to the year 2000

7 by using the average reserve additions achieved per oil well drilled

for each of nine regions during the 5-year period

1980-84, as discussed above, and assuming that

projected low rates of drilling for 19868 will continue indefinitely. As noted previously, an “equilibrium” in drilling has by no means been reached,

and thus an assumption of constant drilling in

each region is clearly a risky one . . . as is the asbAlt hough most E(>R projects req u I re d ri I II ng for I njectlon and

otlen for prod uctlon.

“j, P. Rlva, jr,, “Domestic (II Production and Reser\es Projected

to 2000 cm the Bdsls O( Reglona/ Drl//ing and Per w’e~~ Reserve Additions, ” 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 remain steady at the 1980 to 1984 average. Nevertheless, this is a useful “What if. . .“ analysis that

can act as a counterpoint to similar analyses that

postulate a considerably lower rate of reserve additions based on alternative assumptions that

OTA considers overly pessimistic.

Tables 45 through 53 present the past and projected production, proved reserves, and reserves

to production (R/P) ratios for the nine regions. Table 54 presents similar projections for the United

States.

The regional tables show extremely interesting

variations in the projected year 2000 production

rates as compared to current rates. By the year

2000, Alaska and California production rates are

projected to increase by 2 and 25 percent respectively. This is contrary to current expectations.

According to virtually all industry sources, Alaskan

production, although it is actually somewhat higher

this year than last, is expected to begin a long

decline beginning around 1989. The source of

the decline will be the supergiant Prudhoe Bay

field, which is expected to fall from its present

production rate of 0.55 billion barrels per year

(1.5 million barrels per day) by more than onehalf by 1995 and more than three-quarters by

year 2000.9 In this case, extrapolation of historic

reserve additions and current drilling rates does

not appear to work. Although recent development of new reservoirs at Prudhoe has been quite

successful, there are few such opportunities left,

and the recent exploratory drilling record has

been disappointing: it may be that the primary

possibility for a substantial recovery, after production has begun its decline, lies with the Arctic

National Wildlife Refuge, discussed in chapter S.

And were the Arctic National Wildlife Refuge to

be successfully explored and developed, production is unlikely to begin before the year 2000.

In California’s case, maintaining or increasing

production depends on offshore development

and exploration and on enhanced oil recovery.

Between 1980 and 1985, almost half of California’s oil reserve additions came from enhanced

9J.f’. Riva Jr., O P. cit.
128

Table 45.-Past and Projected Alaska Oil Status

Reserve additions

Product ion Proved reserves Average oil 1 0

9 bbls/well

Year 1 0

9 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. . . . . . . .

0.083

0.070

0.591

0.592

0.627

0.665

0.638

0.667

0.67

0.67

0.68

0.68

10.149

10.037

8.751

8.283

7.406

7.307

7.563

7.056

7.060

7.060

7.050

7.050

122/1

143/1

15/1

14/1

12/1

11/1

12/1

11/1

11/1

11/1

10/1

10/1

72

61

122

159

201

159

157

20

245 est.

13

13

14

22

21

14

14

20

5.5

4.7

8.7

7.2

9.6

11.4

11.2

1.0

0.136111

0.000213

0.003828

0.000780

–0.001244b

0.003560

0.005694

0.008000

aproved resemes/annual production.

bNegativevalue5 for reserve additions perwe~o~cur~henIarge 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, ” Congresslonai

Research Service, 1986.

Table 46.— Past and Projected California Oil Status

Production

Year 1 0

9 bbls/yr

1970 . . . . . . . .

1975 . . . . . . . .

1980 . . . . . . . .

1981 . . . . . . . .

1982 . . . . . . . .

1983 . . . . . . . .

1984 . . . . . . . .

1985 . . . . . . . .

1986 . . . . . . . .

1990 . . . . . . . .

1995 . . . . . . . .

2000 . . . . . . . .

0.372

0.322

0.360

0,383

0.394

0,400

0.415

0.417

0.42

0.44

0.48

0.52

Proved reserves

1 0

9 bbls

3.984

3.648

5.470

5.441

5.405

5.348

5.707

5.801

5.820

5.830

5.700

5.360

R/Pa

11/1

11/1

1 5/1

14/1

14/1

1 3/1

1 4/1

14/1

14/1

13/1

1 2/1

10/1

Total oil wells

1,970

2,184

2,416

3,011

2,464

2,242

3,259

2,959

2,460 est.

Average oil

rig count

50

78

116

152

125

103

104

81

Reserve additions

1 0

9 bbls/well

Wells per rig per oil well

39.4 0.000057

28.0 0.000189

20.8 0.000234

19.8 0.000118

19.7 0.000145

21.7 0.000153

31.3 0.000237

36.5 0.000173

aprovedresewes/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,” Congressional

Research Service, 1986.

Table 47.—Past and Projected Rocky Mountains and Northern Great Plains Oil Status

Reserve additions

Production Proved reserves Average oil 1 0

9 bbls/well

Year 1 0

9 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 0.000070

1975 . . . . . . . . 0.259 1.849 7/1 2,835 177 16.0 0.000046

1980 . . . . . . . . 0.258 1.777 7/1 3,478 283 12.3 0.000122

1981 . . . . . . . . 0.257 1.660 6/1 5,501 432 12.7 0.000025

1982 . . . . . . . . 0.249 1.709 7/1 4,135 355 11.6 0.000072

1983 . . . . . . . . 0.252 1.900 8/1 3,693 209 17.7 0.000120

1984 . . . . . . . . 0.254 1.889 7/1 4,555 267 17.1 0.000053

1985 . . . . . . . . 0.255 2.014 8/1 3,211 212 15.1 0.000116

1986 . . . . . . . . 0.25 1.930 8/1 2,154 est.

1990 . . . . . . . . 0.23 1.640 7/1

1995 . . . . . . . . 0.20 1.430 7/1

2000 . . . . . . . . 0.18 1.320 7/1

aproved 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 additions

Product ion Proved reserves Average oil 1 0

9 bbls/well

Year 1 0

9 bbls/yr 109 bbls R/Pa

Total oil wells rig count Wells per rig per oil well

1970 . . . . . . . . 0.792 7.876 10/1 4,54 2 1 8 7 24. 3 0.00024 5

1975 . . . . . . . .

1980 . . . . . . . .

1981 . . . . . . . .

1982 . . . . . . . .

1983. . . . . . . .

1984. . . . . . . .

1985. . . . . . . .

1986. . . . . . . .

1990. . . . . . . .

1995. . . . . . . .

2000. . . . . . . .

0.809

0.670

0.645

0.625

0.620

0.608

0.620

0.62

0.59

0.53

0.48

6.496

6.240

6.272

5.977

5.923

6.052

6.454

6.21

5.32

4.45

3.85

8/1

9/1

10/1

10/1

10/1

10/1

10/1

1o11

9/1

8/1

8/1

6,933 276 25.1 0.000035

9,948 379 26.2 0.000070

13,112 520 25.2 0.000052

12,768 337 37.9 0.000026

12,563 357 35.2 0.000045

14,490 394 36.8 0.000051

12,946 457 28.3 0.000079

7,703 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,” Congressional

Research Service. 198

Table 49.— Past ad Projected Gulf Coast Oil Status

Reserve additions

Production Proved reserves Average oil 1 0

9 bbls/wel l

Year 1 0

9

bbls/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 0.000231

1975. . . . . . . . 1.118 8.470 8/1 4,613 303 15.2 0.000055

1980. . . . . . . . 0.812 5.643 7/1 7,370 584 12.6 0.000100

1981 . . . . . . . . 0.774 5.707 7/1 10,036 831 12.1 0.000083

1982. . . . . . . . 0.755 5.273 7/1 8,891 514 17.3 0.000036

1983. . . . . . . . 0.773 5,214 7/1 9,989 509 19.6 0.000072

1984. . . . . . . . 0.803 5.148 6/1 11,957 561 21.3 0.000062

1985. . . . . . . . 0.786 5,012 6/1 9,987 410 24.4 0.000065

1986. . . . . . . . 0.78 4.71 6/1 6,727 est.

1990. . . . . . . . 0.65 3.75 6/1

1995. . . . . . . . 0.55 3.24 6/1

2000. . . . . . . . 0.51 3.03 6/1

aproved reswveslannual 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.

Table 50.—Past and Projected Midcontinent Oil Status

Reserve additions

Production Proved reserves Average oil 1 0

9 bbls/well

Year 109 bbls/yr 1 0

9 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 0.000053

1975. . . . . . . . 0,231 1.759 8/1 5,512 197 28.0 0.000035

1980. . . . . . . . 0.200 1.329 7/1 12,852 418 30.7 0.000003

1981 . . . . . . . . 0.218 1.428 7/1 17,695 748 23.7 0.000018

1982. . . . . . . . 0.224 1.493 7/1 15,617 626 24.9 0.000016

1983. . . . . . . . 0.221 1.380 6/1 14,195 396 35.8 0.000010

1984. . . . . . . . 0.233 1.425 6/1 13,331 388 34.4 0.000021

1985. . . . . . . . 0.223 1.503 7/1 9,616 290 33.2 0.000031

1986. . . . . . . . 0.22 1.37 6/1 6,637 est.

1990. . . . . . . . 0.16 .98 7/1

1995. . . . . . . . 0.12 .79 7/1

2000. . . . . . . . 0.10 .71 7/1

aproved reserves/annual production

SOURCEJP Riva, Jr. “Domestic Oti Production and Resemes Projected to20000n the Baslsof Regional Drilling and Per Well Reserve Additions,” Congressional

Research Service, 1!3S6
130

Table 51 .—Past and Projected Eastern Interior Oil Status

Reserve additions

Production Proved reserves Average oil 1 0

9 bbls/well

Year 109 bbls/yr 1 0

9 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 0.000003

1975 . . . . . . . . 0.038 0.224 6/1 2,159 18 120 0.000019

1980 . . . . . . . . 0.027 0.171 6/1 4,859 27 180 –0.000001 b

1981 . . . . . . . . 0.027 0.181 7/1 6,802 45 151 0.000005

1982. . . . . . . . 0.030 0.214 7/1 7,321 84 87 0.000009

1983. . . . . . . . 0.030 0.204 7/1 7,591 67 113 0.000003

1984. . . . . . . . 0.032 0.227 7/1 6,458 49 131 0.000009

1985. . . . . . . . 0.034 0.218 6/1 4,263 33 129 0.000006

1986. . . . . . . . 0.03 0.21 7/1 3,423 est.

1990. . . . . . . . 0.03 0.17 6/1

1995. . . . . . . . 0.02 0.14 7/1

2000. . . . . . . . 0.02 0.14 7/1

aproved rese~eslmrlual production.

bNegatlve val

u e s for re~erve additions per Well o~~ur~hen large negative revisions are recorded forttle 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 Resewe Addltlons,” Congressional

Research Service, 1986

Table 52.—Past and Projected Michigan Basin Oil Status

Reserve additions

Production Proved reserves Average oil 109 bbls/well

Year 109 bbls/yr 1 0

9 bbls R/Pa

Total oil wells rig count Wells per rig per oil well

1970 . . . . . . . . 0.012 0.046 4/1 201 8 25 0.000030

1975 . . . . . . . . 0.024 0.093 4/1 439 23 19 0.000080

1980 . . . . . . . . 0.037 0.205 6/1 530 25 21 0.000157

1981 . . . . . . . . 0.034 0.240 7/1 650 31 21 0.000106

1982 . . . . . . . . 0.029 0.184 6/1 773 27 29 – 0.000035b

1983 . . . . . . . . 0.031 0.209 7/1 671 26 26 0.000083

1984 . . . . . . . . 0.027 0.180 7/1 902 28 32 –0.000002b

1985 . . . . . . . . 0.030 0.191 6/1 638 28 23 0.000064

1986 . . . . . . . . 0.03 0.18 6/1 382 est.

1990 . . . . . . . . 0.03 0.14 5/1

1995 . . . . . . . . 0.02 0.14 7/1

2000 . . . . . . . . 0.02 0.14 7/1

aproved 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,” Congressional

Research Serwce, 19S6

Table 53.—Past and Projected Appalachians Region Oil Status

Reserve additions

Production Proved reserves Average oil 1 0

9 bbls/well

Year 109 bbls/yr 1 0

9 bbls R/Pa

Total oil wells rig count Wells per rig per oil well

1970 0.018 0.243 14/1 1,323 20 66 0.000010

1975 0.017 0.210 12/1 1,550 17 91 0.000006

1980 0.016 0.181 1 1/1 4,336 55 79 0.000008

1981 0.015 0.174 12/1 4,928 71 69 0.000002

1982 0.019 0.196 10/1 3,490 45 78 0.000012

1983 0.024 0.228 10/1 2,926 31 94 0.000016

1984 0.025 0.232 9/1 3,217 38 85 0.000012

1985 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 6/1

1995 0.01 0.08 8/1

2000 0.01 0.08 8/1

aprovedresemeslannual 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,” Congressional

Research Service, 1966.
131

recovery operations in the large heavy oilfields

of the San Joaquin basin, and an additional third

came from large oiIfields discovered offshore.10

Further activity in the offshore may be restricted

by California’s environmental aversion to offshore

drilling. Further development of EOR operations

may require higher prices than today’s, and there

are air quality restrictions as well; however, the

rather basic techniques used in many of the California fields are not at the high end of the cost

spectrum for EOR,11 and price might not be as

much of a constraint here as it would be elsewhere. An important source of uncertainty is the

potential for technological improvements that

could reduce production costs. In conclusion, fulfilling the projection for California production will

require success in two difficult areas—not impossible, but surely requiring considerable good

fortune.

Year 2000 production rates in all other regions

are projected to decline from 1985 rates, as

follows:

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 demonstrate the fragility of domestic oil production,

especially given the uncertainty associated with

our ability to maintain production levels in Alaska

and California.

Table 54 shows that the projected decline in

total U.S. production associated with the drop

in drilling activity is 17 percent by the year 2000.

This is a modest decline when compared to the

projected declines discussed in chapter 2. However, this projection does not account for the possibility that large numbers of existing wells may

be abandoned as uneconomic, as discussed in

the previous section. Although there appear to

be problems with the analysis of stripper well

abandonments conducted by the interstate oil

Compact Commission (IOCC), it is worthwhile

to incorporate their projections into the drilling

projections above. Table 55 illustrates how future

production might change if the IOCC’s projected

production losses at oil prices of $15/bbl were

to occur. The primary effect would be to increase

the expected year 2000 production loss from 17

to 22 percent.

Furthermore, a less optimistic–and many

would say more realistic—projection of Alaskan

and Californian production would substantially

affect the national estimate. For example, assuming that only about half the Prudhoe decline can

be replaced with production from other fields (as

Table 54.—Past and Projected United States Oil Status

Product ion Proved reserves Average oil

Year 109 bbls/yr 1 0

9 bbls R/Pa

Total oil wells rig count Wells per rig

1970 . . . . . . . . 3.328

1975 . . . . . . . . 2.901

1980 . . . . . . . . 2.975

1981 . . . . . . . . 2.949

1982 . . . . . . . . 2.950

1983 . . . . . . . . 3.020

1984 . . . . . . . . 3.037

1985 . . . . . . . . 3.052

1986 . . . . . . . . 3.04

1990 . . . . . . . . 2.82

1995 . . . . . . . . 2.61

39.001

32.682

29.805

29.426

27.858

27.735

28.446

28.416

27.65

25.01

23.02

12/1

11/1

10/1

10/1

9/1

9/1

9/1

9/1

9/1

9/1

9/1

21,522

26,253

45,316

60,940

55,600

52,577

61,399

48,489

32,234 est.

832

1,102

1,901

2,852

2,134

1,712

1,843

1,574

26

24

24

21

26

31

33

31

Reserve additions

1 0

9 bbls/well

per oil well

0.000590

0.000051

0.000066

0.000042

0.000025

0.000055

0.000061

0.000062

2000 . . . . . . . . 2.52 21.68 9/1

a prove d reseffes/annual production

SOURCE: J.P. Riva, Jr., “Domestic Oil Production and Resetves Projected to 2000 on the Basis of Regional Drilling and Per Well Reserve Additions. ” Congressional

Research Service, 1986.
132

Table 55.—impact of Increased Stripper Well

Abandonment on Low Drilling Scenario Production

and Reserves Projections

Production Proved reserves

Year (billion bbl/yr) (billion bbls)

1985 . . . . . . . . . . . 3.052 28.416

1986 . . . . . . . . . . .3.04 – .10 = 2.94a 27.65 –.73 = 26.92b

1990 . . . . . . . . . . . 2.76 24.33

1995 . . . . . . . . . . . 2.52 22.35

2000 . . . . . . . . . . . 2.38 21.26

aThat 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 Prudhoe Bay production is expected by 2000), the

year 2000 production rate would be about 2.17

billion barrels per year, a 29 percent decline from

1985 production. An important-and sobering–

note about this computation is that much of

Alaska’s expected production decline is not price

but geology dependent. Although lower prices

will stifle some development and exploration, and

some production also will be dependent on technology development, much of the production decline was expected at higher prices.

o