Arctic National Wildlife Refuge: Background and Issues

Congressional research reportMay 15, 2003

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Report for Congress

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Arctic National Wildlife Refuge:

Background and Issues

Updated May 15, 2003

(nae redacted) (Coordinator)

Specialist in Natural Resources

Resources, Science, and Industry Division

Congressional Research Service ˜ The Library of Congress

Authors

Area of Expertise

CRS Division

(name redacted)

Legal issues

American Law

(name redacted)

Water and wetla nds issues

Resources, Science,

and Industry

(name redacted)

Overview; Fish and Wildlife

Service; biological resources

Resources, Science,

and Industry

Bernard Gelb

Economic issues; oil and natural gas

resources; pipeline issues

Resources, Science,

and Industry

James McCarthy

Air quality

Resources, Science,

and Industry

Wayne Morrissey

Glossary

Resources, Science,

and Industry

(name redacted)

Hazardous stes

Native American issues and

resource use

Resources, Science,

and Industry

Domestic Social

Policy

Arctic National Wildlife Refuge: Background and Issues

Summary

The rich biological resources and wilderness values of northeastern Alaska have

been widely known for about 50 years, and the rich energy resource potential for

much of that time. The future of these resources has been debated in Congress for

over 40 years. The issue for Congress is whether to open a portion of what is now

the Arctic National Wildlife Refuge (ANWR) to allow the development of

potentially the richest on-shore source of oil remaining in the United States, and if

so under what restrictions. Alternatively, Congress might choose to provide further

protection for the Refuge’s biological and wilderness resources through statutory

wilderness designation or to maintain the current status of the area. Under current

law, if Congress chooses not to act, the entire Refuge will remain closed to

development under provisions of the 1980 Alaska National Interest Lands

Conservation Act.

The coastal northern plain of the Refuge is the focus of debate. This remote and

largely untouched area is an example of an arctic ecosystem that, by virtue of being

essentially intact, is increasingly rare. It has been called “America’s Serengeti”, for

the vast herd of caribou, for the many nesting and feeding migratory birds, and for

its predators such as grizzly bears, polar bears, wolves, and golden eagles.

The area also is an immensely promising oil prospect, which some feel could

be as productive as Prudhoe Bay. It is heralded as a place which could help reduce

national dependence on foreign oil and keep the Alaskan oil pipeline in use for

decades. Advocates for development foresee benefits to the oil industry, the people

of Alaska, and the national economy.

For over 20 years, the debate over energy development in the Refuge has been

highly polarized and remains so. President George W. Bush is committed to opening

the Refuge to development, citing unrest in the Middle East among his reasons. And

opposition to development remains strong, as opponents point to other means of

achieving national energy goals.

This report does not analyze specific proposals to develop or protect the Refuge.

Rather, it provides basic material for analyzing possibilities and implications of the

major issues that have been the focus of the legislative debate over its fate. This

report will be updated as events warrant.

Contents

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

The Purpose of the Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

The Tradeoffs and Possible Alternatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

The Choices Before Congress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Exploring and Developing the Oil Resource . . . . . . . . . . . . . . . . . . . . . . . . . 4

Assessing the Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

ANWR Oil, U.S. Oil Consumption, and ANWR Gas . . . . . . . . . . . . . . 5

Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Physical Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Alaska Native Ownership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Special Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Secondary Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Future Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

The Decision Before Congress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Scope of the Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

The Setting: the Geography of Alaska’s North Slope . . . . . . . . . . . . . . . . . . . . . 13

History of the Refuge . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Land Orders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Alaska National Interest Lands Conservation Act . . . . . . . . . . . . . . . . . . . . 14

Section 1002 Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Legal Definition of the 1002 Area . . . . . . . . . . . . . . . . . . . . . . . . 16

Section 1003 Prohibition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

ANILCA and Native Claims . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

ANWR Consideration in the 101st to 107th Congresses . . . . . . . . . . . . . . . . 16

History of Related Energy Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

TransAlaska Pipeline System (TAPS) Authorization . . . . . . . . . . . . . . . . . 20

Alternative Routes Considered . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Export Restrictions in Original TAPS Law . . . . . . . . . . . . . . . . . . . . . 20

Exxon Valdez Oil Spill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Export Restrictions Loosened . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

NPR-A Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

New Assessment of Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Possible Development Sequence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Leasing Phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Frontier Variations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Leasing on National Wildlife Refuges . . . . . . . . . . . . . . . . . . . . . . . . . 28

Exploration Phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Development Phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Advanced Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Drill Pads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Roads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

The Meaning of Footprints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Production Phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Reclamation Phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Resources: Status, Current Regulation, and Potential Effects of Development . 36

Energy: Status and Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Oil Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Geology and Potential Petroleum Resources . . . . . . . . . . . . . . . . 36

1991 and 1995 Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

1998 Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Technically or Economically Recoverable? . . . . . . . . . . . . . 39

Possible Production Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Natural Gas Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Estimates of Prudhoe Bay Complex . . . . . . . . . . . . . . . . . . . . . . 43

Estimates of 1002 Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Native Lands and Adjacent State Waters . . . . . . . . . . . . . . . . . . . . . . . 44

Natural Gas Pipeline from North Slope . . . . . . . . . . . . . . . . . . . . . . . . 45

Alaskan Position on Northern Route . . . . . . . . . . . . . . . . . . . . . . 48

Canadian Position on Natural Gas Pipeline . . . . . . . . . . . . . . . . . 48

Economic Effects of Development . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Development Stimulus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Oil Market Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Macroeconomic Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Employment Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Other Job Impact Estimates . . . . . . . . . . . . . . . . . . . . . . . . . 54

Import Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Effects on the Alaskan Economy . . . . . . . . . . . . . . . . . . . . . . . . . 55

Relationship to Recent U.S. Energy Difficulties . . . . . . . . . . . . . . . . . 56

Biological Resources: Status and Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Caribou . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

Would Caribou Be Displaced from Calving in the 1002 Area? . 60

Would Caribou Be Displaced from Insect Relief Areas? . . . . . . 61

Polar Bears . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Musk Oxen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

Migratory Birds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Other Species . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

Special Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

Physical Environment: Status and Effects . . . . . . . . . . . . . . . . . . . . . . . . . . 65

Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

Emissions and Expected Air Quality . . . . . . . . . . . . . . . . . . . . . . 66

PSD Regulatory Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Arctic Haze . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Water Resources and Wetlands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

Description of the Resource . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

Effects of Oil Exploration and Development . . . . . . . . . . . . . . . . 69

Regulatory Setting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Waste Disposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

RCRA-Exempt Wastes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

Minimization and Recycling . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Land and Gravel Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

Changing Footprint Estimate: 1987 vs. 2001 . . . . . . . . . . . . . . . 77

Effects on Tundra Surfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

Port and Offshore Activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

Aircraft Use . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

Use of Resources by Non-Natives: Status and Effects . . . . . . . . . . . . . . . . 82

DEWLine and Kaktovik . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

Recreation Visits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

Migratory Birds: Hunting and Birdwatching . . . . . . . . . . . . . . . . . . . . 83

Use of Resources by Alaska Natives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Inupiat Use of ANWR and the 1002 Area . . . . . . . . . . . . . . . . . . . . . . 86

Gwich’in Use of ANWR and the 1002 Area . . . . . . . . . . . . . . . . . . . . 87

Alaska Native Lands and Rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

Canadian Interests in Traditional Native Rights . . . . . . . . . . . . . . . . . 90

Reclamation Issues After Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

Conditions for Rehabilitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

Human Population Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Removal of Roads and Gravel Structures . . . . . . . . . . . . . . . . . . 92

Restoration of Native Vegetation . . . . . . . . . . . . . . . . . . . . . . . . . 94

Site Phase-Out . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

Site Cleanup in the NPR-A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

Site Development and Facility Removal . . . . . . . . . . . . . . . . . . . 95

Retention of Facilities: the Other Option . . . . . . . . . . . . . . . . . . . 95

Legislative Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Alternatives to Developing 1002 Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Exploration Only . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

Compatibility with Refuge Purposes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Compliance with NEPA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

Environmental Direction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

Special Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 99

Expedited Judicial Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Project Labor Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Revenue Disposition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Federal/State Split . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Uses for Federal Share of Revenues . . . . . . . . . . . . . . . . . . . . . . . . . 102

Wilderness Designation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

No Action Alternative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

List of Figures

Figure 1. Shaded Relief Map of Northeastern Alaska . . . . . . . . . . . . . . . . . . . . . 2

Figure 2. Petroleum Accumulations in Northern Alaska

and Nearby Parts of Canada (1998) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Figure 3. Historical and Projected North Slope Production, 1978-2010. . . . . . . 19

Figure 4. Alpine Oil Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Figure 5. Petroleum Discoveries and Exploratory Wells of 1002 Area

and Adjacent Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Figure 6. Proposed Routes to Transport Alaskan and Canadian

Natural Gas to Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Box: Energy Leasing in National Wildlife Refuges . . . . . . . . . . . . . . . . . . . . . . 29

Box: What the Numbers Mean . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Box: Corporations and Boroughs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85

List of Tables

Table 1. Probability of the Presence of Given Quantities of Oil

and the Recoverability of the Oil in the 1002 Area . . . . . . . . . . . . . . . . . . . 39

Table 2. Approximate ANWR Peak Production Levels

Under Selected Discovery and Development Scenarios . . . . . . . . . . . . . . . 42

Table 3. Mean Estimates of the Amounts of Undiscovered Natural Gas and Natural

Gas Liquids in the 1002 Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Table 4. Comparison of the Estimated Number and Area of In-place Oil-related

Facilities: 1987 FLEIS and Modern Technologies . . . . . . . . . . . . . . . . . . . 79

Arctic National Wildlife Refuge: Background

and Issues

Executive Summary

From Alaska’s Prudhoe Bay eastward 200 miles to the Canadian border is an

area of unique natural wealth. An area teeming with wildlife, it has been called the

“Serengeti of the Arctic.” The eastern part of the region also contains one of

America’s best remaining onshore oil prospects, beneath the coastal plain of the

Arctic National Wildlife Refuge (ANWR). (See Figure 1.)

This remote and largely untouched area is an example of an arctic ecosystem

that, by virtue of being essentially intact, is increasingly rare. It is an important

habitat for musk oxen, migratory waterfowl, vast numbers of caribou, and predators

such as grizzly bears, polar bears, wolves, and golden eagles.

Moreover, the coastal plain is immensely promising for oil and natural gas,

possibly on the scale of Prudhoe Bay’s resources. Its development could help reduce

America’s energy dependence to some degree and keep the Alaska pipeline in use for

decades – benefitting the national economy, the oil industry, and people in Alaska.

The Purpose of the Report

When Congress expanded the boundary of ANWR in the Alaska National

Interest Lands Conservation Act (ANILCA) in 1980, it designated about 8 million

acres within the earlier boundaries of the refuge as wilderness – off-limits to any

form of development. However, in two sections of ANILCA, Congress postponed

a decision on wilderness designation of 1.5 million acres of the coastal plain (called

the 1002 area) – a portion of ANWR thought to be rich in oil and gas resources –

and required the Department of the Interior (DOI, or Interior) to prepare a detailed

study of the area and to recommend how it should be managed.

Interior finished its detailed analysis of oil potential, wildlife resources, impacts,

and mitigation measures in April 1987. In its report to Congress, DOI estimated then

that the chance of recovering economic quantities of oil at 19%, a figure that is very

high by industry standards. The report recommended that the entire area be made

available for leasing. The report and its recommendation generated controversy, as

have virtually all subsequent reports on this topic. In intervening years, estimates of

oil potential have varied, but enthusiasm for ANWR oil development remains strong,

particularly in Alaska. Likewise, opposition to energy development continues to be

strong, based on concern for the area’s wilderness values and wildlife.

CRS-2

Figure 1. Shaded Relief Map of Northeastern Alaska.

Source: U.S. Dept. of the Interior, Fish and Wildlife Service [http://www.r7.fws.gov/nwr/

arctic/shademap.html], Nov. 9, 2001. Minor modifications made to enhance clarity in

monochrome.

This report goes beyond reporting the opposing views of development versus

protection. Rather, it provides background and basic material for analyzing

possibilities and implications of emerging options.

The Tradeoffs and Possible Alternatives

Much is at stake in the ANWR decision, for U.S. energy interests, for

proponents of unspoiled wilderness, and for the State of Alaska. On the one side, if

oil were found and developed, the additional domestic supply would be seen as

enhancing national security (although some opponents of opening ANWR argue that

the vulnerability of the TAPS pipeline to sabotage diminishes the national security

argument). Further, oil development would create several thousand short-term jobs

in Alaska and elsewhere, and a substantial number of long-term jobs as well. The

state would benefit from additional royalty income, and many of Alaska’s Native

groups would benefit as well (though some would face threats to important

subsistence resources).

CRS-3

On the other side, many believe developing oil would irrevocably compromise

the area’s wilderness values – defined as an area “untrammeled by man.” Some

counter that the area has already been affected by man: there are a few remains of

DEWLINE construction and a capped oil well in the 1002 area. Some argue, too,

that the coastal plain itself is not of a wilderness quality most would expect. The area

is bounded on the south by the spectacular Brooks Range, but is itself mostly flat or

rolling – a treeless tundra laced with shallow streams, most of which flow only

during the brief arctic summer.

However, the apparently hostile nature of the area belies its national and

international significance as an ecological reserve. It protects a virtually undisturbed,

nearly complete spectrum of arctic ecosystems, and is one of the last places north of

the Brooks Range that remains legally closed to development. Those who favor

preservation argue that when the United States is serving as an international leader

in the protection of vanishing ecosystems, development of the 1002 area would not

set a good international example. Thus, if oil development occurred, the issue would

become how to ensure that development would be compatible, as far as possible,

with the purposes of the wildlife refuge.

Developing oil in the harsh, fragile arctic environment is expensive and risky.

Since oil was discovered at Prudhoe Bay in 1968, oil companies and government

agencies have done much to reduce environmental impacts, e.g., through reducing

the size of drill pads, numbers of roads, and size and location of support facilities;

and through improving waste management. Depending on statutory and regulatory

requirements, and with proper investment, monitoring, and enforcement, energy

companies could develop the 1002 area in ways that continue to reduce effects on

plants and animals.

The Choices Before Congress

In the context of these tradeoffs, the spectrum of alternatives before Congress

includes:

! No action, which would maintain the status quo, which prohibits drilling for

oil and gas throughout the refuge.

! Authorize leasing in the coastal plain of ANWR to proceed under the current

regulatory requirements and capabilities of DOI.

! Allow leasing in the coastal plain of ANWR to proceed, but with special

statutory and regulatory conditions, (which could be greater or less than

currently required). Among a variety of possibilities or proposals, these

conditions might include one or more of the following:

1. Limiting surface occupancy in the 1002 area to reduce environmental

impacts (recognizing evolving technology).

2. Requiring environmental controls, phasing, special area protection, or

enforcement mechanisms.

3. Requiring various measures for site restoration or removal of

infrastructure upon completion of oil operations and/or establishing

bonding mechanisms to ensure accomplishing these goals.

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4. Reducing requirements for environmental review under the National

Environmental Policy Act or limiting judicial review of executive actions.

5. Allowing different standards for environmental protection or

reclamation to prevail on Native lands than on the remainder of the coastal

plain.

! Designate the coastal plain as wilderness, thereby foregoing any energy

development and associated economic benefits, but maintaining existing

natural values and employment and subsistence opportunities.

Exploring and Developing the Oil Resource

Exploration does not necessarily mean that the coastal plain immediately would

be spread with drilling pads, service facilities, and pipelines. Companies may not

discover economic quantities of oil – or any oil at all. If they do find economic

quantities and development occurs, oil facilities likely would occupy only a small,

though dispersed, portion of the total area; and it is unlikely that oil would be

produced until 7 to 12 years after any congressional approval of exploration. Drilling

proponents argue that this long lead time is a reason for making a decision now.

Assessing the Potential. Parts of Alaska’s North Slope coastal plain have

proved abundant in oil reserves, and its geology holds further promise.1 The oilbearing strata extend eastward from the National Petroleum Reserve-Alaska (NPRA), past the prolific Prudhoe Bay field and a few smaller fields, and may continue

into and through ANWR’s 1002 area. Clearly, a key step in making a decision on

ANWR is estimating how much oil might be there. Drilling (both exploration and

confirmation), now prohibited, is the only method by which the 1002 area’s

petroleum potential can be ascertained with reasonable assuredness in the context of

the uncertainties of oil discovery.

On its part, the Department of the Interior, without drilling, has issued

assessments in 1987, 1991, 1995, and 1998 of the amount of oil and gas that might

be present in ANWR. Those prepared after 1987 have been based upon progressively

newer geological data from outside ANWR and upon reinterpretation of previous

information using improving techniques, and have changed estimates of ANWR’s

oil potential.

Two considerations might be noted at this point. One is that the projected price

of oil is a key factor in estimating the amount of oil that might be economically

recoverable. The second is that the larger the area open to leasing and resultant oil

company participation, the more likely that company bidding will give the

government (the people of the United States) a larger return for making resources

accessible to private entities.

For maps of existing discoveries along the North Slope, see the website of the Division of

Oil and Gas, Alaska Department of Natural Resources, at :

[http://www.dog.dnr.state.ak.us/oil/products/maps/northslope/northslope.htm]

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ANWR Oil, U.S. Oil Consumption, and ANWR Gas. Based upon the

results of the 1998 Interior Department assessment, the 1002 area contains some of

the most promising undrilled onshore geologic structures with petroleum potential

known in the United States. The U.S. Geological Survey (USGS) estimated that, at

$24/barrel (in 1996 dollars), there is a 95% chance that 2.0 billion barrels or more

could be recovered, and a 5% chance of 9.4 billion barrels or more. In comparison,

the Prudhoe Bay field originally was estimated at 11-13 billion barrels of

economically recoverable oil.

Many argue that this large potential should be explored and developed to offset

the decline in domestic oil production. Domestic production without ANWR is

projected by the U.S. Energy Information Administration (EIA) in its base case to be

down to 5.6 million barrels per day (bbl/d) by 2020 (from 5.8 million bbl/d in 2000),

while consumption is projected to rise from 19.7 million bbl/d to 26.7 million bbl/d.

Other things being equal, domestic output without ANWR would supply only about

one-fifth of U.S. consumption, with the rest coming from imports. Assuming a

higher price of $30 per barrel, it appears that potential peak output from USGS’s

“low” and “high” ANWR volumes of economically recoverable oil at 300,000 and

1,575,000 bbl/d, respectively. These would represent a 5% and a 28% rise in U.S.

output, respectively, at peak production.

Possibly of greater importance are the gathering and transportation economics

of both existing and prospective fields, which include the cost of shipment through

the TAPS pipeline. Combined production at Prudhoe Bay and other North Slope

fields is now at only about half of its peak and is projected to rise only slightly

between 2000 and 2020. Development of and production from ANWR would

improve the commercial viability of currently producing North Slope fields by

spreading the per barrel cost (maintenance and capital charges) of operating the

pipeline over a larger number of barrels.

The possibility of large amounts of natural gas in ANWR together with huge

amounts of proven gas reserves in the Prudhoe Bay area (not being produced

presently) may increase the appeal of oil and gas development of ANWR to energy

companies. For economic reasons, natural gas generally has not been emphasized,

but becomes more attractive as demand grows and prices rise. Construction of a

pipeline to transport natural gas to North American markets and/or a warm water port

for shipping liquefied natural gas would be a necessary element.

Controlling Impacts

If Congress decided to authorize development, then the issue would become

whether and how to minimize effects on wildlife and the coastal arctic ecosystem,

and – through them – on Native cultures. Changes in the ecosystem could result

from several facets of oil development. Major intrusions would include large

requirements for water and gravel; and the displacement and disturbance of land,

animals, and plants by pipelines, roads, airstrips, and other infrastructure. There is

particular concern for caribou migration routes; calving and insect relief areas;

migratory bird nesting and staging; effects of air and water pollutants; and direct and

indirect effects of human presence. In addition, because of mixed ownership in the

area, problems arise in how to establish and enforce controls on development.

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Infrastructure. The trend in North Slope energy development is toward

compactness, reduction in numbers and mileage of roads, centralization or reduction

of support facilities, reduction of hazardous wastes, and concentration of exploration

and early development activities in winter (when the frozen tundra makes crosstundra travel possible, and when roads can be built from ice). Industry

representatives now argue that the entire ANWR area can be developed with only a

2,000 acre “footprint.” Opponents argue that the 2,000 acres would be spread across

the entire 1002 area, is achievable only if one fails to count some major facilities, and

is misleading in any case, since effects of the area covered by gravel may extend well

beyond even a broadly defined footprint. Limitation of the footprint has begun to be

a major point of congressional debate.

Physical Environment. Much of the controversy over development of the

1002 area has focused on potential impacts on biological resources in the area.

However, if development occurs, there also would be impacts on the physical

environment and resources of the area – land, air, and water – as a result of

construction, operations, and human habitation. Currently, because the area is

uninhabited (except for Kaktovik), the condition of the physical environment has

been characterized as pristine and nearly unaffected by human activity.

Exploration and development activities would alter the existing physical

environment. For example, oil field operations would result in air pollution

emissions. There would be need for large amounts of water for drilling and ancillary

activities, including construction of roads, drill pads, and airstrips. There likely

would be impacts from both the mining and use of gravel as part of some of these

activities. Exploration and development also would result in the generation of

several types of waste streams, both from industrial operations and domestic wastes,

requiring disposal. At issue are the individual and cumulative effects of such

alterations and the ability of the natural environment to recover and be reclaimed

when oil-related activities have ceased.

Industry points out that companies use improved technology in the arctic today

(compared with that used in the past for development of existing sites in the arctic

region) which greatly reduces the “footprint” of operations and relies on practices

that minimize and provide for better disposal of wastes. The result is less direct and

indirect impact in terms of habitat loss and environmental contamination. Moreover,

numerous environmental protection requirements administered by federal and state

authorities are intended to govern and regulate activities that might take place.

Critics, however, are concerned about environmental effects of routine operations in

the fragile 1002 environment, as well as the possibility of leaks and spills of various

contaminating substances, and whether adequate safeguards would be adopted and

enforced by regulators. Moreover, critics argue that even careful development would

lead to lasting changes in the fragile arctic environment.

Alaska Native Ownership. Over 100,000 acres in ANWR are owned by

Alaska Natives. The surface of more than 90,000 acres is owned by the Kaktovik

Inupiat Corporation (KIC) and the subsurface of these acres is owned by the Arctic

Slope Regional Corporation (ASRC). The remaining 10,000 plus acres are owned

by individual Natives. Some of the 100,000 acres are within the legal description of

the 1002 area; some also lie along the coast but are legally described as outside the

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1002 area, and all 100,000 acres are within the Refuge as a whole. Regulation of

development on these lands is problematic and is often not considered explicitly in

legislative proposals. (See CRS Report RL31115, Legal Issues Related to Proposed

Drilling for Oil and Gas in the Arctic National Wildlife Refuge.)

Special Areas. Wildlife experts are particularly interested in threats of

development to several sensitive or special areas. For example, on the southern edge

of the coastal plain, Sadlerochit Spring is of great biological importance because it

never freezes. Other areas include the southeast portion of the coastal plain, where

caribou calving is particularly likely to occur; certain staging areas for snow geese;

riparian areas important to musk oxen; deep rivers and lakes important to

overwintering fish; and denning or nesting sites of bears and raptors, to name a few.

Secondary Development. Also of concern are the effects of possible spinoff development both in Kaktovik, an Alaska Native settlement and Distant Early

Warning Line (DEWLINE) station on Barter Island just off the coast, and on other

Native lands within the Refuge. Kaktovik could be a staging area for oil operations.

Such development could compromise wildlife and other environmental values.

Currently, Deadhorse (at Prudhoe Bay, the oldest support center), the Kuparuk

Industrial Center (west of Prudhoe Bay), and to some extent Alpine (a very modern

oil development west of the Kuparuk oil field, with much of its support activities

reduced or taking place elsewhere) offer alternate examples of how service support

areas might be handled. Deadhorse was left mostly to private decisions, and its

sprawl and contamination problems led to the more compact, controlled approach at

the Kuparuk Facility. Still later, the Alpine field essentially eliminated the need for

some kinds of additional support facilities, reduced the physical size of some of the

remaining facilities, and shifted still other operations to other sites by flying material

in and out or carrying other equipment in on winter ice roads. In the 1002 area,

facility reduction might continue, and some needs might be shifted to Native lands

within and near the 1002 area.

Future Recovery

Whether strict statutory and regulatory controls and strong government

enforcement could protect wildlife values to the satisfaction of those opposing

development is open to question. (Wilderness values, by definition, would be

compromised if full development occurred.) But for the long term, an equally

important question is whether, after oil production ceased, the area could be and

should be restored as nearly as possible to pre-development conditions.

If major oil reserves were found, energy companies might operate on the coastal

plain for decades. If natural gas were also found, it too might be developed. (There

is currently no means to send natural gas to market, either from the 1002 area or from

Prudhoe Bay.) Offshore oil fields might also be found, and might be developed with

onshore support in ANWR. Any of these outcomes could lead to significant human

activity in the area for a century or more.

Assuming eventual dissipation of industrial presence, would the area eventually

revert to something of its former condition? New data exist to show that such an

intensive presence could last many decades after activity ceases. Complete removal

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of all infrastructure seems unlikely, and resulting water flow patterns might not even

make it desirable. The short growing season and low precipitation make complete

revegetation of disturbed areas uncertain. Recovery of animal populations and

species diversity would depend on viable populations close enough to restock the

area or site, and possibly explicit controls limiting future presence so that the site or

area can recover. If Congress decides to open ANWR, it may include rehabilitation

requirements.

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Introduction

The debate over whether to open the coastal plain of the Arctic National

Wildlife Refuge (ANWR) to energy leasing has raged for decades, with the main

periods of controversy occurring in the late 1950s before the refuge was established;

the period 1977-1980 at the passage of the Alaska National Interest Lands

Conservation Act; 1987 when the Final Legislative Environmental Impact Statement

(FLEIS) was released; the early 1990s during the Persian Gulf War; and the current

debate, which began months before the attacks on New York and Washington, but

was certainly heated by those events.

The purpose of this report is to collect the background information and new

developments that have arisen since the 1987 FLEIS, and to discuss the possibilities

and implications of emerging approaches to development. The report does not focus

on any particular legislation.2 Rather, it provides background and basic material for

analyzing proposals and ideas about developing or not developing the 1002 area.

The Decision Before Congress

The portion of Alaska’s North Slope between Prudhoe Bay and the Canadian

border represents this country’s largest, most diverse remaining example of a largely

untouched arctic ecosystem.3 All major arctic species are relatively abundant in the

area. The coastal plain and adjacent areas are important habitat for caribou,

migratory waterfowl, and such predators as wolves, polar bears, and grizzly bears.

However, the coastal area is also very likely one of the nation’s best remaining oil

prospects, possibly containing quantities nearly as great as the fields at Prudhoe Bay.4

Congress recognized this conflict in values in 1980 when it expanded the

existing Arctic National Wildlife Range, and renamed it the Arctic National Wildlife

Refuge in the Alaska National Interest Lands Conservation Act (ANILCA, P.L. 98487). The major portion of the pre-existing Range was designated as wilderness, and

the remainder, which constituted most of the Range’s coastal plain, was hotly

contested because of its high biological value and potential oil resources. The

compromise reached in §1002 of ANILCA required that DOI intensively evaluate the

oil potential, environmental impacts, and alternative policies for future disposition

of 1.5 million acres of the coastal plain of ANWR. This “1002 area” is

approximately 100 miles wide, and is 10 to 25 miles from north to south, roughly to

the margin of the Brooks Range. (See Figure 2.) DOI was to

For a discussion of current legislative proposals on ANWR, see CRS Issue Brief IB10111

Arctic National Wildlife Refuge: Controversies for the 108th Congress, updated regularly.

Outside of Kaktovik, only a few physical artifacts reflect modern human presence. See Use

of Resources by Non-Natives: Status and Effects, below.

National Energy Policy: Reliable, Affordable, and Environmentally Sound Energy for

America’s Future, Report of the national Energy Policy Development Group, May 2001.

p. 5-9.

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Figure 2. Petroleum Accumulations in Northern

Alaska and Nearby Parts of Canada (1998).

Notes: “Locations of known petroleum accumulations and the TransAlaska Pipeline System (TAPS) are shown, as well as summaries

of known petroleum volumes in northern Alaska and the Mackenzie delta of Canada. Bbo = billion barrels of oil, included cumulative

production plus recoverable reserves; tcfg = trillion cubic feet of gas recoverable resources.” Source: Figure AO1, USGS, Oil and

Gas Potential of ANWR.

CRS-11

provide the report with its findings and recommendations to Congress, so that

decisions relating to development could be made with more information and with the

full participation of Congress. In the meantime, §1003 of ANILCA explicitly forbids

energy development throughout the Refuge until Congress acts.

The issue has been debated several times since 1980. Congressional interest has

been stimulated by fluctuating energy prices and by a favorable environment in

Congress and a strongly supportive President. The fluctuating oil prices, close

margins in control of the Senate, and concern over terrorism have all complicated the

outlook in recent months.

Congressional options can be divided into categories. A decision could be

postponed, thereby continuing the development prohibitions of §1003; the area could

be made permanent wilderness; development could be permitted under current laws

applicable to other federal lands; or development could be allowed subject to

specified restrictions.

Scope of the Report

It is unclear whether Congress will present the President with ANWR legislation

in the 108th Congress. The House passed an energy bill with an ANWR development

title in the 1st session of the 108th Congress. The Senate is taking up energy

legislation in the 1st session, but Chairman Domenici (Committee on Energy and

Natural Resources) has pledged to exclude ANWR development from a

comprehensive energy bill in light of an earlier failure to include ANWR

development provisions in a reconciliation bill. (For details of current legislation,

see CRS Issue Brief IB10111, Arctic National Wildlife Refuge (ANWR):

Controversies for the 108th Congress.) In light of the continuing debate, this seems

an appropriate time to review the history of the debate and what has been learned

about the complex issues surrounding this decision.

This report provides the background for such analysis. It summarizes and

integrates relevant information and points of view on the economic, legal,

environmental, management, and national energy concerns surrounding any decision

on ANWR. The report does not attempt to focus on specific legislative issues, bills,

or provisions, but rather attempts to provide a baseline for analyzing such proposals.

Congress faces several difficult questions in deciding whether to open the area

to energy development, and if so, under what conditions to do so. These include:

! How much oil might be recovered, and how quickly might it begin to supply

the country?

! What would be the economic benefits and costs of development to the nation?

To Alaska specifically?

! What role do Native lands on the coastal plain play in the development of any

energy resources and what environmental restrictions might apply to those

lands specifically in the event of development?

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! What environmental impacts are likely to occur if the area is opened and how

might these impacts be avoided, reduced, or mitigated?

! Is it possible for industry to limit the “footprint” of development, and if so

how widely scattered must the footprint be, in order to permit full

development?

! After completion of several decades of energy production, could the coastal

plain ever be restored to an approximation of its current condition?

! How should revenues be shared between the federal and the Alaska state

governments?

The following chapters provide background and analysis on the questions raised

above. Besides extensive information in the 1987 two volume FLEIS, other

information is now available in scientific reports, economic analyses, position papers,

and testimony. Many of these tend to be focused at one extreme or the other, but not

all. Wherever possible, additional materials or references are noted which treat the

issues in more depth than is possible in this report.

The report begins with background on the geography or setting of the refuge,

and continues with its history. The next portion is on the history of related energy

development issues. To set the scene, the likely development sequence if Congress

opens ANWR is presented next, followed by an extensive review of the resources of

the 1002 area, including the current status, regulations, and potential effects of

development of those resources. Finally, the report ends with a presentation of the

legislative issues which have arisen most frequently in recent years. A glossary is

included to define the key terms and acronyms.

Although the chapters of this report are not entirely independent, readers may

find it useful to consult them selectively as background, in order to follow the

evolving debate about the possible opening of the 1002 area to development.

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The Setting: the Geography of Alaska’s North Slope

Physically, what is called the North Slope of Alaska consists of those lands

north of the Brooks Range where waters drain into the Beaufort and Chukchi Seas.

Its area exceeds 100,000 square miles (64,000,000 acres), and includes the northern

side of the mountains, foothills, and a relatively flat coast plain. The western part of

the North Slope is very broad, with the crest of the Brooks Range being as much as

250 miles from the coast. The eastern part of the North Slope, which includes part

of the Refuge, is relatively narrow, with the crest of the range lying as little as 30

miles from the coast. (See Figures 1 and 2.)

The foothills of the Brooks Range merge gradually into the coastal plain of the

North Slope. The western portion of the plain is extremely flat, and much of it is

covered in small lakes. In the narrower eastern coastal plain, the topography is

sufficiently rolling that lakes are much less common in the Refuge.

Lying north of the Arctic Circle, darkness and extreme cold prevail much of the

year. The area is underlain by permafrost – a permanently frozen layer 1,000 to

2,000 feet thick. During the brief summer, about 3 feet of soil thaws, supporting

lichens, mosses, grasses, forbs, and other low shrubby plants that make up the tundra.

Although precipitation is low, flat areas become wetlands in summer. Most streams

and rivers are frozen in winter, flood in spring breakup, and meander in braided

channels of gravel until freeze-up. Because the 1002 area has more topographic

relief, its drainage is better established, and its vegetation is more woody than the

wetland grasses that dominate Prudhoe Bay and other developed areas. Foothills and

the hilly portions constitute 45% and 22%, respectively, of the ANWR coastal plain.

The foothills reach 1,250 ft, while the hills are mostly less than 100 ft above their

surroundings (FLEIS, p. 18-19).

However, conditions on the North Slope have changed somewhat since the

FLEIS was prepared in 1987. In recent decades, the climate of the North Slope, like

that of most of the area north of the Arctic Circle, has been warming, particularly

during winter.5 The warming has generally resulted in earlier greening of vegetation

in the spring and later die-back in the fall. (In 2000 and 2001, spring snowmelt

bucked this longer trend and was unusually late.) Arctic Natives, basing their claims

on traditional knowledge, have reported decreasing predictability of weather patterns,

more dangerous snow and ocean ice conditions, the appearance of insects and birds

new to the area, and similar phenomena.6

U.S. Dept. of the Interior. Geological Survey. Arctic Refuge Coastal Plain Terrestrial

Wildlife Research Summaries. 2002. USGS/BRD/BSR-2002-001. p. 11. (Hereafter

referred to as “USGS Wildlife Research Summaries, 2002.”

Brown, DeNeen L. “Signs of Thaw in a Desert of Snow.” Washington Post. May 28,

2002. p. A1.

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History of the Refuge

A chronology of the Refuge’s history might begin in 1956, with the visit to

northeastern Alaska by naturalists Olaus and Margaret Murie, who reported the vast

migrating herd of caribou that winter in the United States and Canada around the

Porcupine River. Upon their return, the Muries worked with other scientists to set

aside the area to protect the caribou herd and the whole relatively intact arctic

ecosystem of which they were a central part. However, the first group actually to

propose that the area become a national wildlife range, in recognition of the many

game species found in the area, was the Tanana Valley (Alaska) Sportsmen’s

Association.7 The following is a description, in chronological order, of major events

concerning the Refuge, and related energy development in northern Alaska since the

1950s.

Land Orders

All lands in the North Slope were withdrawn January 22, 1943 by Public Land

Order (PLO) 82 (8 Fed. Reg. 1,599 (February 4, 1943). In November, 1957, an

application for the withdrawal of lands to create an Arctic Wildlife Range was filed.

Under the regulations in effect at the time, this application “segregated” the lands in

question, removing them from disposal. This fact was important because on July 7,

1958, the Alaska Statehood Act was signed and on January 3, 1959, Alaska was

formally admitted to the Union. On December 6, 1960, after statehood, the Secretary

of the Interior issued PLO 2214 reserving the area as the Arctic National Wildlife

Range. (In Figure 1, the outer boundaries of the “1002 area”, plus the wilderness

boundaries, were the boundaries of the Range.) The Supreme Court has held that the

initial segregation of lands was sufficient to prevent the passage of ownership of

certain submerged lands within the Refuge to the State of Alaska at statehood.8

Alaska National Interest Lands Conservation Act

In 1980, Congress enacted the Alaska National Interest Lands Conservation Act

(ANILCA, P.L. 96-487, 94 Stat. 2371), which included several sections about

ANWR. The Arctic Range was renamed the Arctic National Wildlife Refuge, and

was expanded, mostly southward and westward, to include an additional 9.2 million

acres. Section 702(3) of ANILCA designated much of the original Refuge as a

wilderness area, but not the coastal plain.9 Instead, Congress postponed decisions on

the development or further protection of the coastal plain. ANILCA defined the

U.S. Congress, Senate, Committee on Interstate and Foreign Commerce. Arctic National

Wildlife Range - Alaska, Hearing, Part I. June 30, 1959. (Washington, DC, 1959). Also

see: U.S. Congress, House of Representatives, Committee on Merchant Marine and

Fisheries. Miscellaneous Fish and Wildlife Legislation, Hearing, July 1, 1959.

(Washington, DC, 1959).

United States v. Alaska, 521 U.S. 1 (1997). If this ruling had been in favor of Alaska,

certain lands beneath the rivers in the coastal plain might have belonged to the state, which

could have developed the oil and gravel in or under them.

Newer portions of the Refuge were not included in the wilderness system.

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“coastal plain” as the lands on a specified map.10 A later legal description of the

boundaries excludes most Alaska Native lands, even though these lands are

geographically part of the coastal plain. Three key sections of ANILCA are discussed

below.

Section 1002 Study. Section 1002 of ANILCA directed a study of the

“coastal plain” (which therefore is often referred to as the “1002 area”) and its

resources be completed within 5 years and 9 months of enactment. The executive

branch was to conduct a comprehensive baseline study of the fish and wildlife

resources of the coastal plain of the Refuge; to develop guidelines for, initiate, and

monitor an oil and gas exploration program; to prepare a report to the Congress on

the biological resources, the extent of hydrocarbon resources, the impacts of

development, transportation of oil and gas, and the need for them; and to make a

recommendation on whether exploration, development, and production should

proceed. The resulting “1002 report” or Final Legislative Environmental Impact

Statement (FLEIS)11 was issued in April 1987.

The FLEIS recommended full development of the 1002 area. It described the

1002 area as “the most outstanding petroleum exploration target in the onshore

United States” (FLEIS, p. vii), and estimated a 19% chance of finding economically

recoverable oil. Its mean estimate of economically recoverable oil was 3.2 billion

barrels, and the report predicted the area could supply about 4% of total U.S. demand

in 2005, and reduce imports by nearly 9%. (See Oil Potential, below, for updates of

these figures.) It estimated total national economic benefits of $79.4 billion and

federal revenues of $38.0 billion. It assumed that oil would be selling at $33/barrel

in 1984 dollars by 2000. (In actuality, West Texas Intermediate, a benchmark crude

oil, sold from about $25.50 per barrel to about $34.50 per barrel in 2000, which was

about $20.30 to $27.50 in 1984 dollars.)

The FLEIS also said the “1002 area is the most biologically productive part of

the Arctic Refuge for wildlife and is the center of wildlife activity.... The area

presents many opportunities for scientific study of a relatively undisturbed

ecosystem.” It analyzed the effects of the various development alternatives on the

plants and animals, and especially on the calving grounds of the Porcupine Caribou

Herd (PCH). It stated that “major effects on the PCH could result if the entire 1002

area were leased and all prospects contained economically recoverable oil” (p. 123).

It concluded that full leasing would lead to reductions in bird nesting habitat, loss of

over-wintering fish habitat, and loss of polar bear denning habitat. It also predicted

moderate effects on polar and grizzly (brown) bears due to direct mortality related

to human encounters; and recommended buffer zones of at least 0.5 miles around

known polar bear dens. It also noted the special sensitivity of snow geese to aircraft

disturbance.

This map apparently does not exist. See Legal Definition of the 1002 Area, below.

U.S. Dept. of the Interior, Fish and Wildlife Service, U.S. Geological Survey, and Bureau

of Land Management, Arctic National Wildlife Refuge, Alaska, Coastal Plain Resource

Assessment, Report and Recommendation to the Congress of the United States and Final

Legislative Environmental Impact Statement, (Washington, DC, 1987). 208 p. (Hereafter

referred to as the “FLEIS.”)

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Legal Definition of the 1002 Area. Section 1002 of ANILCA defines the

coastal plain as the area shown on a map dated August, 1980. However, the Bureau

of Land Management informs us that no such official map or maps with that date

depicting the coastal plain exist. The official 1980 maps of the Refuge as a whole,

less the area of designated wilderness might be said to indicate the coastal plain.

These maps show the Native lands in the Refuge with boundaries crossed out –

presumably to indicate they are included within the Refuge. However, the legal

description of the boundaries of the coastal plain that were published pursuant to

§103 of ANILCA (48 Fed. Reg. 16838, 16869 (April 19, 1983)) exclude the Native

lands as of that date from inclusion in the 1002 coastal plain.

Section 1003 Prohibition. In ANILCA, Congress also included §1003,

which prevents further development of energy resources, until Congress acts:

Production of oil and gas from the Arctic National Wildlife Refuge is prohibited

and no leasing or other development leading to production of oil and gas from

the range shall be undertaken until authorized by an Act of Congress.

Development opponents are well satisfied with the status quo under §1003. While

many development bills have been introduced since 1987, very few have been

reported out of a committee, despite considerable interest by various Members. In

the Senate, for example, a willingness to filibuster against development bills has

made it difficult for such bills to come to the floor; through the 106th Congress, the

sole exception (see ANWR Consideration in the 101th - 106th Congresses, below) was

in a reconciliation bill which was later vetoed. Development continues to be

prohibited.

ANILCA and Native Claims. ANILCA also contained provisions in §1431

that followed up on the previously enacted Alaska Native Claims Settlement Act

(ANCSA, P.L. 92-203), and gave the Native village corporation of Kaktovik rights

to make certain selections and to enter into certain land exchanges. The result is that

Kaktovik has surface rights to some lands inside and some lands outside the 1002

area. However, all of the Kaktovik lands are within the Refuge and are subject to the

current restrictions on oil and gas development of §1003 of ANILCA and to §22(g)

of ANCSA, which made Native lands conveyed in a refuge subject to the regulations

of the refuge. If Congress were to lift the restriction of §1003 on oil and gas

development in the Refuge, development of Native lands would be allowed to occur.

(See discussion of ANCSA provisions in Use of Resources by Alaska Natives,

below.)

ANWR Consideration in the 101st to 107th Congresses

After the FLEIS of 1987, and the Exxon Valdez oil spill of 1989 (see below),

congressional interest in the energy potential of the 1002 area has waxed and waned.

Bills to open the 1002 area to development or to designate it as wilderness have been

introduced repeatedly in both House and Senate. In the House, these bills were

referred to the Merchant Marine and Fisheries Committee or (beginning with the

104th Congress) to the Committee on Resources. In the Senate they have been

referred to the Committee on Environment and Natural Resources or the Committee

on Environment and Public Works. Whether they were development bills or

CRS-17

wilderness bills, they have rarely been reported from committees, much less received

floor consideration. From 1989 to 1994 (101st to 104th Congresses), no ANWR bill

received floor consideration.

In 1995, Congress passed the FY1996 budget reconciliation bill (H.R. 2491) in

which §§5312-5344 authorized the opening of ANWR, but the measure was vetoed.

President Clinton cited the ANWR sections as one of his reasons for vetoing the

measure.12 Key Senate votes occurred on May 24 and October 27, 1995, on motions

to table amendments that would have stripped ANWR development provisions from

the Senate version of the bill (Roll Call #190 and #525, respectively). Both motions

succeeded.

While bills were introduced, the ANWR issue was not debated in the 105th

Congress. In the 106th Congress, bills to designate the key northern portion of the

Refuge as wilderness, and others to open the 1002 area to energy development, were

introduced. The FY2001 budget resolution (S.Con.Res. 101) reported by the Senate

Budget Committee on March 31, 2000 included assumptions about federal revenues

that would be obtained if ANWR leasing were approved. An amendment to remove

the language was tabled (51-49) on April 6, 2000 (Roll Call #58); however, conferees

rejected the language. The conference report on budget reconciliation did not contain

this assumption, and the report was passed by both Houses on April 13.13 These three

roll call votes in two Congresses were all in the Senate, and were the only recorded

votes on Refuge development from the 101st through the 106th Congress.

Six bills were introduced in the 107th Congress that would have directly

affected the future of ANWR. Four of these (H.R. 4, H.R. 39, H.R. 2436, and S. 388)

would have opened the Refuge to development; they shared many overlapping

provisions. Two (H.R. 770 and S. 411) would have designated the coast of ANWR

as wilderness. The following actions were taken on these bills.

On July 25, 2001, the House Resources Committee reported H.R. 2436. Title

V would have opened ANWR to exploration and development. These provisions

were incorporated into H.R. 4, an omnibus energy bill. A floor amendment was

passed to limit some types of surface development to a total of 2,000 acres; another

amendment to strike Title V was defeated. H.R. 4 passed the House on August 2,

2001. The Senate Energy Committee held hearings on S. 388. H.R. 39, H.R. 770,

and S. 411 had no hearings.

A comprehensive energy bill, but one that lacked Refuge development

provisions, was offered in the second session by Senator Daschle as an amendment

(S.Amdt. 2917) to S. 517, the bill which served as the vehicle for Senate floor

consideration of omnibus energy legislation. An amendment package to open the

Refuge by Senators Murkowski and Stevens was filibustered; cloture motions on the

amendments lost, and the amendments were withdrawn. The text of S. 517

(amended) was passed in lieu of the House version of H.R. 4. Conferees met, but

For key provisions of that legislation, see archived CRS Issue Brief IB95071, The Arctic

National Wildlife Refuge. 16 p.

Budget resolutions do not require the signature of the President.

CRS-18

were unable to reconcile the two versions of H.R. 4, in many areas, including Refuge

development. The legislation lapsed at the end of the 107th Congress. (For more on

past actions, see CRS Report RL31725, Arctic National Wildlife Refuge: Legislative

Issues Through the 107th Congress.)

CRS-19

History of Related Energy Development

In 1967, oil was discovered on the North Slope of Alaska at Prudhoe Bay, about

60 miles west of ANWR. (See Figure 2.) Since that time, developments following

from that discovery have affected the economics, potential support facilities, and

understanding of proposed development of the Refuge. This section provides a short

history of related energy development on the North Slope and describes how that

development has influenced the ANWR debate.

As the years have passed, new fields in the area have been discovered,

developed, and produced. As production at the original giant field rose to a peak and

then fell again, additional fields have been brought on-line, though this has not

reversed a long term decline in North Slope production. (See Figure 3.)

Figure 3. Historical and Projected North Slope Production, 1978-2010. Source:

Alaska Department of Revenue, Tax Division. Revenue Sources Book. Forecast and

Historical Data. Spring 2002. Table H. (Amounts in millions of barrels/day.)

CRS-20

TransAlaska Pipeline System (TAPS) Authorization

The Prudhoe Bay discovery was a great distance from markets and/or a warm

water port from which to transport oil to markets. Development of the resource was

thwarted for several years by lack of agreement on how and by which route the crude

oil would be transported out of the area.

Alternative Routes Considered. Transporting the oil directly from the area

by tanker was considered briefly, but an experiment failed. Pipeline routes were seen

as the only viable option. Initially, three general pipeline routes were conceptualized.

Two never reached the stage of serious study: one was an easterly route into Canada,

to the McKenzie River Delta, then south to a Chicago-area destination, and the other

was a southeasterly route along the Alaskan Highway into Canada and then south

into the United States. The third was overland, south to the port of Valdez.

Proponents of the first two routes argued that the oil was needed most in the

Midwest, because it has no indigenous source of crude oil. Midwestern interests

favored it because of the prospective economic gain. Opponents contended that such

routes were very long, and therefore would cost more and take longer to build. Oil

prices had not reached levels sufficient to justify further investigation.

The third route was ultimately chosen: oil is shipped via TAPS south to the

seaport of Valdez on Prince William Sound, then loaded on tankers destined for other

ports. Proponents cited its shorter length, and therefore lower total cost and shorter

construction period. Some opponents were concerned that the proximity of Valdez

to Pacific Rim countries such as Japan and Korea presented too great a temptation

to export the oil; others were concerned about possible oil spills along the West

Coast.

Export Restrictions in Original TAPS Law. Much of the pipeline’s route

between the North Slope and Valdez is on federal lands, for which rights-of-way

were needed. The Mineral Leasing Act of 1920 prohibits export of oil transported

through pipelines granted rights-of-way over federal lands (30 U.S.C. 185(u)). There

was considerable opposition to the export of North Slope oil and many saw a

growing domestic need for the oil in late 1973 as a result of the Arab oil embargo

(imposed during the Arab-Israeli War of October 1973), and of the gasoline shortages

(resulting from petroleum allocation regulations). The increased concern over U.S.

dependency on foreign oil brought urgency to the pipeline debate. A compromise

was soon reached over whether to exempt North Slope oil from this prohibition.

The compromise was the Trans-Alaska Pipeline Authorization Act (P.L. 93-153,

87 Stat. 584, 43 U.S.C. 1651 et seq.), signed November 16, 1973. It specified among

its many provisions that oil shipped through the pipeline could be exported only

under certain restrictions.14 Subsequent legislation strengthened the export

Many opponents of the pipeline (or at least of its presence on federal lands) argued that

potential environmental damage was unjustified if the primary beneficiaries would be

Pacific Rim nations receiving the oil. Therefore, they wished to prevent export of the oil,

(continued...)

CRS-21

restrictions further.15 The restrictions proved to be, in effect, a complete ban on

exports of North Slope oil. However, the restriction was not to last, as market forces

created pressure to change the law. (See Export Restrictions Loosened, below.)

Exxon Valdez Oil Spill

The grounding of the Exxon Valdez on March 24, 1989, near the southern

terminal of the TAPS in Prince William Sound played a major role in placing the

development debate on hold. Environmental damage at the time included an

estimated 300,000 to 645,000 dead seabirds; 4,000 to 6,000 dead marine mammals;

and $100 million in other losses, including commercial fishing impacts. Some

cleanup methods were criticized as doing more harm than good. Lawsuits were

abundant.

Today, there is still disagreement over the impact of the spill. Some scientists

note the lack of toxicity of the water, and a visitor in the area would still see rugged

beauty on most beaches. But other observers stress the accumulation of oil in some

species, such as mussels (which filter sea water), and the effects on species that

consume contaminated organisms. For example, a 2001 study of seabirds in the area

showed that of the 17 groups (containing a total of 33 species) “most [groups] for

which injury was previously demonstrated are not recovering and others continue to

show potential population effects nine years after the spill.”16 The affected birds

included species of sea ducks, grebes, terns, murres, and gulls. Exxon Mobil

responded that bird populations may not be recovering due to a variety of other

environmental changes in the area, e.g., higher water temperatures.17

Export Restrictions Loosened

The Trans-Alaska Pipeline System was completed in 1977, and oil was being

shipped through by the end of the year. Continued oilfield development on the North

Slope resulted in a 10-year increase in production to a peak of 2.0 million barrels per

day (bbl/d) in 1988.

(...continued)

even though the oil would fetch higher prices if it could be sold on world markets.

These restrictions included the Energy Policy and Conservation Act of 1975 (P.L. 94-163),

the 1977 amendments to the Export Administration Act (P.L. 95-52 and P.L. 95-223), and

the Export Administration Act of 1979 (P.L. 96-72), which replaced the Export

Administration Act of 1969.

Brian K. Lance, et al., “An Evaluation of Marine Bird Population Trends Following the

Exxon Valdez Oil Spill, Prince William sound, Alaska,” Marine Pollution Bulletin, Vol. 42:

p. 298-309. Elsevier Science, Ltd. (April 2001). Species were considered to be recovering

if either (a) the populations in the oiled areas were increasing, or (b) if their trend was

similar to that of populations of the same species in areas without oil.

Unnamed ExxonMobil spokesperson, cited in Pearce, Fred. “Alaska’s oil spill may still

be hitting wildlife hard.” New Scientist. May 2, 2001. [http://www.newscientist.com].

CRS-22

With exports effectively banned, much of North Slope oil went to West Coast

destinations. The rest was shipped to the Gulf Coast via the Panama Canal or

overland across the Panamanian isthmus. Such Gulf Coast shipments reduce average

effective wellhead prices on the North Slope, which must absorb at least the cost of

transportation through the pipeline and by tanker, and therefore always are a few to

several dollars below Lower-48 wellhead prices.

In the early and mid-1990s, California – the nation’s third largest oil producing

state – was producing about 800,000 bbl/d on average. Another 150,000 bbl/d were

being produced in federal waters off the West Coast, and about 100,000 bbl/d of

crude oil were being imported. At the same time, total consumption of petroleum in

California was falling – 8% between 1989 and 1995. The combination of Californian

and federal offshore production, North Slope oil,18 and imports, resulted in such large

quantities relative to demand that prices of crude oil in California fell below those

elsewhere in the United States. Prices obtained by producers – from California and

North Slope – naturally suffered as well, and elicited concern and complaints from

those producers.

Attempts to obtain help were unsuccessful until 1995 despite arguments that the

gains of exporting would outweigh the losses. For example, a June 1994 Department

of Energy (DOE) study found that exporting Alaskan crude oil would increase prices

for both Californian and Alaskan producers and result in up to 100,000 bbl/d more

production in California and Alaska (combined) than would be the case with

continued export restrictions.19 As a result of avoiding the trip through Panama,

Alaskan oil would gain higher prices (net of transportation costs) if sold in Japan.

DOE predicted that higher resulting prices on the West Coast would spur additional

production. In addition, the study found, exporting North Slope oil would stimulate

imports of crude oil better suited to California’s petroleum product demand mix.

However, the study acknowledged, exporting Alaskan oil would divert cargoes away

from the U.S. domestic merchant marine fleet and workforce.20

These expected benefits and costs, less concern about petroleum in 1995 (after

three or four years of low world oil prices), relative calm in the Mideast, and

continued pleadings from West Coast producers (after two years of wellhead prices

averaging below $12 per barrel) helped open the way to repeal of the export

restrictions. The Clinton Administration was supportive, and bills in the House and

Senate (H.R. 70 and S. 395) passed by large margins. On November 28, 1995, the

President signed P.L. 104-58 (109 Stat. 557), Title II of which amended the Mineral

Leasing Act to provide that any oil transported through the Trans-Alaska Pipeline

may be exported unless the President finds, after considering stated criteria, that it is

not in the national interest (30 U.S.C. 185(s)). The President may impose terms and

North Slope oil production had fallen by 0.5 million bbl/d, to 1.5 million bbl/d by 1995 –

still a very large quantity.

U.S. Department of Energy. Exporting Alaskan North Slope Crude Oil, Benefits and

Costs, DOE/PO-0025 (Washington, DC, June 1994).

The Jones Act of the Merchant Marine Act of 1920 (P.L. 66-261; 46 U.S.C. 883) requires

that cargoes transported from one U.S. port to another be carried in U.S.-flag ships; export

cargoes (from a U.S. port to a foreign port) may be transported in foreign-flag ships.

CRS-23

conditions; and authority to export oil may be modified or revoked. Beginning with

36,000 bbl/d in 1996, ANS exports rose to a peak of 74,000 bbl/d in 1999. The latter

represented 7% of North Slope production. Exports of ANS oil ceased voluntarily

in May 2000.

NPR-A Developments

Almost concurrent with the push to allow export of North Slope oil, production

of North Slope oil began to fall, reducing if not eliminating the California oil surplus,

but also spurring discovery and development of other North Slope fields. The

successful exploration, although not sufficient to stop the production decline,

increased geological information and strengthened belief that there are commercial

quantities of oil in the National Petroleum Reserve - Alaska (NPR-A). (See Figure

2.)

Established in 1923 by President Harding as Naval Petroleum Reserve Number

4, the 33 million acre Reserve, together with other government petroleum reserves,

was intended to help assure availability of fuels for the Navy. Rationale for the

Reserves faded over time, however, as the likelihood of a sustained interruption in

oil supply declined, and markets showed a capacity to allocate and price petroleum

when supply was uncertain. In 1981, stewardship of the Reserve passed from the

Navy to the Department of the Interior (DOI), and its designation was changed to

National Petroleum Reserve - Alaska. Public Law 96-514 authorizes the Secretary

of the Interior to conduct oil and gas leasing and development in the NPR-A. Four

lease sales were held between 1981 and 1984. An exploratory well drilled in 1985

was dry; but none of these leases was developed and all have expired. The area

actually has been explored (including drilling) and/or mapped by various federal

government agencies or on their behalf on and off from 1901 through 1998.

By 1996, total Alaskan oil output had fallen below 1.4 million barrels per day.

Many Alaskans supported exploration of NPR-A, hoping that output from there

would help offset the drop in royalty payments from reduced Prudhoe Bay

production. Some argued that NPR-A might assure sufficient throughput to keep the

Trans-Alaskan Pipeline running. In addition, lease sales provide bonus bid revenue

to the U.S. Treasury; and the government collects royalties if there is production.

Leasing. In early 1997, the Department of the Interior (DOI) initiated a study

of potential drilling areas in a 4.6 million acre portion of the northeast part of the

Reserve, and of the steps that would be needed to protect wildlife. The discovery of

the commercially successful Alpine Field (discussed later in this report) adjacent to

the eastern boundary of NPR-A was important in spurring development of a leasing

proposal for NPR-A. On August 6, 1998, DOI released its Final Integrated Activity

Plan and Environmental Impact Statement (EIS), making 4 million acres available

for leasing, with surface pipelines banned on 20% of that area. The EIS was prepared

to meet National Environmental Policy Act requirements and to serve as the basis for

managing the area; its preferred option provided for a number of restrictions

intended to strike a balance between permitting exploration and protecting the

CRS-24

environment.21 DOI officials estimated that the quadrant under review for leasing

could hold 500 million to 2.2 billion barrels on an assumption of a crude oil price of

$18-30/barrel.22

A lease sale held in May 1999 drew 174 bids from six companies on 3.9 million

acres. More than 130 bids were accepted, totaling $105 million. ARCO initially

picked up the leases and then sold these holdings to Phillips Alaska Inc. as required

by the Federal Trade Commission for the takeover of ARCO by British Petroleum

(BP). In the spring of 2001, Phillips Alaska and minority partner Anadarko

Petroleum Corporation reported findings of oil and gas, and indicated the find might

be commercial.23 Phillips resumed exploration in the winter of 2001-2002.

Additional NPR-A lease sales are anticipated in late 2002.

New Assessment of Resources. Increasing interest in Alaska’s petroleum

potential spurred the USGS to initiate in 1998 a re-assessment of undiscovered oil

and gas resources in the NPR-A. The results, published in May 2002 suggest that

there is appreciably more crude oil and natural gas than indicated by previous

assessments.24 The new estimates are based upon field studies, well and geophysical

data analysis, and reinterpretation of previous exploration performed over the last

four years, plus analysis of the recent discoveries of oil just east of the NPR-A.

According to the new assessment, there is a 95% chance that 5.9 billion barrels

or more of crude oil are technically recoverable, a 5% chance that 13.2 billion barrels

are technically recoverable, with a mean estimate of 9.3 billion barrels. At an oil

price of $24 per barrel (1996 prices), 3.1 billion barrels would be economically

recoverable.25 USGS’s 1980 assessment indicated technically recoverable amounts

of from 0.3 billion barrels (95% chance) to 5.4 billion barrels (5% chance).26

U.S. Department of the Interior. Bureau of Land Management. Northeast National

Petroleum Reserve-Alaska. Final Integrated Activity Plan/Environmental Impact Statement.

August 1988.

Gee, Robert W., Asst. Secretary for Fossil Energy, U.S. Department of Energy.

Testimony before the U.S. House of Representatives, Committee on Energy. April 12, 2000.

Oil & Gas Journal, Phillips Makes Own Mark on North Slope with Alpine Start-up, NPRA Strikes. August 6, 2001. p. 68 et seq.

U.S. Department of the Interior. Geological Survey. U.S. Geological Survey 2002

Petroleum Resource Assessment of the National Petroleum Reserve in Alaska (NPRA), by

Kenneth J. Bird and David W. Houseknecht USGS Fact Sheet 045-02, 2002.

See Glossary and What the Numbers Mean (Box) for an explanation of the terms

technically recoverable, economically recoverable amounts, and mean estimate.

USGS did not estimate economically recoverable amounts in its 1980 assessment.

CRS-25

Possible Development Sequence

There are five phases of oil development on federal lands: the leasing process,

exploration, development, production, and reclamation. If economic quantities of oil

are not found, only three phases – leasing, exploration and reclamation – would

occur. In a large area with numerous tracts, all of these phases could be occurring

simultaneously: exploration in some fields, development in others and production in

still other fields. Exploration specialists might move from prospect to prospect for

several years, followed by construction and other workers carrying out development

where discoveries occurred, and so on. The following section describes these five

phases.27

Where newer technologies are used, they may reduce not only environmental

damage or risk, but also costs. Cost-effective technologies would likely be used

whether specified in legislation or not. Where savings are less likely, legislation

could be required to ensure use of advanced technologies or to ensure environmental

standards (with the latter perhaps driving development of still newer technologies).

However, any federal requirements to use advanced or environmentally friendly

technology may not necessarily apply to Native lands unless Congress explicitly

applies them. (See CRS Report RL31115, Legal Issues Related to Proposed Drilling

for Oil and Gas in the Arctic National Wildlife Refuge.)

Leasing Phase

Through §1003 of ANILCA, Congress has clearly reserved to itself the decision

on whether to lease the coastal plain. If it passes development legislation, it may

choose to deviate from the typical pattern of leasing on other federal lands or other

national wildlife refuges. This section highlights how the leasing process would

normally work, and some of the leasing issues that might be considered by Congress

in legislation to open ANWR.

In the leasing phase as it is carried out under the Mineral Leasing Act of 1920,28

BLM gathers information about an area of federal land, based on data from federal

agencies and industry submissions. The leasing phase involves a series of decisions

and actions by the federal government and by oil corporations, with each decision or

action influencing the next. Then BLM determines how much, and what specific

lands would be offered. Generally, BLM offers federal leases on a competitive basis,

though non-competitive leases may be offered in some circumstances. BLM solicits

bids on the tracts, selecting the winning companies based on these bids. Competitive

leases would probably be the norm in the 1002 area. The entire process, from initial

Aspects relating to the technology of ANWR petroleum development are treated more

extensively in CRS Report RL31022, Arctic Petroleum Development: Implications of

Advances in Technology, by Terry R. Twyman. June 19, 2001. 29 p. (Hereafter referred to

as CRS Report RL31022.)

For a slightly more detailed guide, see U.S. Department of the Interior. Bureau of Land

Management. The Federal Onshore Oil and Gas Leasing System. Washington, DC.

September, 1994. BLM/WO/GI-92/001+4110+REV94, 7 p. (Hereafter referred to as The

Federal Onshore Oil and Gas Leasing System.)

CRS-26

public notice, to sales, and to any production, with public input along the way,

generally requires several years. Broadly speaking, Congress may choose to pass

legislation which entirely replaces the normal processes for leasing on other federal

lands, or may selectively override, or substitute for, some of those processes. The

following is an abbreviated outline of the steps in a competitive oil or gas lease sale.

It indicates as well the areas in past bills where there were proposed changes from

current practices.

Leasing must be in accordance with relevant land management plans, such as

those for National Forests or for BLM lands, but an analogous plan does not exist for

ANWR, though the 1987 FLEIS carried out some of the same functions. These plans

are developed with public input and information, as did the FLEIS. Even if the

federal lands in question are not subject to general land management planning, the

NEPA processes or special statutory provisions may provide opportunity for public

participation. If ANWR were opened to leasing, Congress might choose to specify

that some of these planning steps, or measures for public participation, be included

in the ANWR leasing process. Alternatively, given past reviews such as the FLEIS,

it might override some or all of the NEPA process. (See Compliance with NEPA,

below.)

The Director of BLM may elect to accept formal or informal nominations of

lands to be leased. If nominations are to be accepted, a company would normally

nominate more land than those areas it felt most promising, in order to conceal its

intentions and avoid excessive attention by future competitors on what it believes are

the best prospects. In the case of ANWR, it seems highly likely that formal

nominations would be part of any leasing process, and measures to provide for

formal nominations have been included in bills in previous Congresses. In deciding

which (if any) nominations to make, companies would already be considering factors

such as likely operating costs, future oil prices, and alternative or perhaps more

attractive prospects in the United States or elsewhere. In Alaska, the North Slope’s

generally high operating costs would tend to be an especially important consideration

as companies decided which tracts to nominate. Those companies with past

experience elsewhere on the North Slope might be more interested in participating

than those lacking such experience.

BLM would use the nominations and other information to determine how much

land to offer (if this is not set in legislation) and in what tract sizes.29 For example,

the geology of the area is markedly different on either side of the Marsh Creek

anticline (see Figure 5), and the agency might wish to recognize that in some way in

its selection of tracts. In previous Congresses, bills have often directed a particular

schedule, usually setting a fairly fast pace for the initial and subsequent lease

offerings. BLM would not normally choose to offer millions of acres for bidding at

once, but instead offer portions over a number of years, using previous discoveries

and geologic information to determine future offerings.

The Mineral Leasing Act sets a maximum of 5,760 acres for tracts in competitive sales in

Alaska.

CRS-27

At the time of any offering, BLM would also specify terms or conditions that

may apply to particular tracts. These conditions might include, in the case of

ANWR, limits on surface occupancy, size of footprint, seasonal availability to

exploration, wildlife protection measures, reclamation standards, and the like.

Congress could also specify particular terms or conditions in legislation to open the

1002 area to development, and these terms and conditions could be a major vehicle

for environmental protection measures in the 1002 area. (Though these terms and

conditions might not necessarily apply to Native lands; see Alaska Native Lands and

Rights, below.) It would be essential for industry to have a firm idea of the terms and

conditions of a lease, since these provisions would likely affect the cost of operating

the lease, and therefore the amount a company might be willing to bid for the tract.

Leases under the Mineral Leasing Act are for 10 years and continue as long

afterwards as oil and gas is being produced commercially; Congress could choose

any length for the leases.

Under current law, on the date of a competitive sale, oral bidding takes place at

a specified location. Competition among companies is based on the size of their upfront offer, called the bonus bid. A bonus bid is required to be at least $2 per acre,

but bonus bids can total many millions of dollars for some tracts, while others may

receive no bid at all. Payment of the bonus bid will occur at a point when the

winning bidder cannot yet be certain that oil will be present. As a result, even an

ANWR utterly devoid of commercial oil deposits might still earn millions of dollars

for the federal government, whether oil is ever produced or not. According to BLM,

leases on other federal lands are granted “on the condition that the lessee will have

to obtain BLM approval before conducting any surface-disturbing activities.”30

Congress may choose to specify certain conditions or modifications on the

requirement for this final step after a lease is sold and before construction of roads

or drilling platforms.

In a typical lease under the MLA, a successful bidder must pay $1.50/acre in

rent for its tract(s) in the first 5 years, and $2.00/acre thereafter. The first year’s

rental payment, plus the minimum bonus bid and a $75 administrative fee is due on

the date of the sale. The remainder of the bonus bid must be received within 10 work

days. Subsequent rental payments are due on the anniversary date of the lease. In

addition, once production starts, companies pay a standard 12.5% royalty on the sale

of the oil they produce. Leases expire after 10 years unless production or specified

steps toward production are occurring. Lessees may also voluntarily surrender the

lease, subject to requirements concerning abandonment of wells, clean up, and any

final payments that may be owed. Generally speaking, few bills in previous

Congresses have treated an ANWR leasing program in this level of detail (save for

a willingness to specify a 12.5% royalty rate). Instead, development bills usually

direct the Interior Secretary to promulgate rules and regulations to carry out the

leasing program in order to carry out the provisions of the legislation.

Frontier Variations. In a typical frontier area, where energy leases have been

rare to non-existent, and geological knowledge is sparse, BLM might allow

companies to conduct seismic exploration in the general area before specific tracts

See p. 5, The Federal Onshore Oil and Gas Leasing System, previously cited.

CRS-28

are designated. (ANWR is not typical, however, because ANILCA had specific

exploration provisions for the 1002 area.) Once the sale tracts have been named,

further exploration might take place. Congress might specify whether additional

exploration could occur before nominations were required. However, due to the

seasonality of North Slope exploration, this choice could lengthen the time required

to make a first lease offering. In the NPR-A (which has its own distinct regulations),

this exploration occurred for the first lease sale; exploration took place during the

arctic winter, and companies focused on data analysis once melted tundra made the

area inaccessible. Far more exploration then took place on leased tracts, in order to

help the companies select specific drill sites.

In addition, in frontier areas such as NPR-A and elsewhere, the NEPA impact

assessment process is occurring both before and during preparation for the sales. A

full EIS can add substantially to the time required to carry out a sale, even if it occurs

concurrently. Congress has, in several ANWR development bills, shown a

willingness to modify or eliminate NEPA requirements, on the basis that the 1987

FLEIS fulfilled that function.

Thus, a leasing phase may overlap substantially with an exploration phase. In

the 1002 area, while both of these phases might be shortened by reducing

requirements for environmental review, for example, there is a limit to how much the

process might be truncated. Furthermore, in the arctic, current technology limits

exploration to the winter season only. Since BLM would wish to consider the views

of industry in selecting the tracts to be offered – views that will take time and further

exploration to develop – this too could lengthen the leasing process.

Leasing on National Wildlife Refuges. A factor which Congress might

consider, should it decide to open ANWR, would be the special circumstances that

apply to leasing part of a National Wildlife Refuge, since leasing would normally

have to be determined to be “compatible” with the major purposes of the National

Wildlife Refuge System and with the purposes of the particular unit of that System.

(See Compatibility with Refuge Purposes, below.) While energy leasing does occur

in the National Wildlife Refuge System, it occurs in less than 10% of refuges, and in

virtually no instance has leasing occurred after a compatibility determination. (See

Box for examples.) If Congress wished ANWR development to occur as

expeditiously as possible, it could override the compatibility test. In previous

Congresses, bills have expressly addressed the potential conflict by stating that

Congress has determined energy leasing to be compatible with the purposes for

which ANWR was designated.

CRS-29

Energy Leasing in National Wildlife Refuges

A survey by the General Accounting Office in 2000 found that of the 567 refuge

system units, 45 units had producing oil or gas wells, of which 19 units were in Texas

or Louisiana. (See Wildlife Refuge Oil and Gas Activity, Oct. 31, 2001. 16 p. GAO

Report GAO-02-64R.) In only eight of the units did the federal government own the oil

and gas rights. (Due to an apparent mis-communication with FWS, Kenai NWR (see

below) was not included among the eight, but should have been.) Where there are preexisting rights, FWS has little control over the determination to develop energy or

minerals, though it may determine its timing or manner. The refuges with energy

development had special features that make comparison with proposals to develop

ANWR difficult. However, there appear to be no instances to date in which FWS has

had full control of surface and subsurface rights, formally determined leasing to be

compatible with refuge purposes, and then allowed new leasing to proceed. The

examples below illustrate refuges in which leasing occurs.

In Medicine Lake (MT) and J. Clark Salyer and Upper Souris (ND) NWRs, BLM

offered leases because of “drainage” in which oil was being extracted on adjacent land

from oil fields which extended into the refuge. If no leases had been given, then adjacent

leases would have drained the (federally owned) oil underlaying the refuges. Oil

drainage from adjacent development is not occurring around ANWR at this time.

In one refuge (Delta, LA), some activity occurred due to privately owned

subsurface rights; and some federal government leases had been issued before the refuge

was created in 1935. In the 1002 area, while private subsurface rights are held by Alaska

Native corporations, their activities are governed by laws that do not apply at Delta

NWR.

At Hagerman NWR (TX), FWS has secondary jurisdiction on land owned by the

Army Corps of Engineers. As a result, FWS does not have control of leasing decisions

there. In ANWR, FWS has primary jurisdiction.

Bitter Lake NWR (NM) has several leases that were granted when the land was

owned by BLM. The lands were gained by FWS in an exchange of outlying FWS lands

for inholdings or adjacent parcels owned by BLM. The purpose of the exchange was to

increase administrative efficiency.

Kenai NWR (AK) has 12,000 acres under federal leases, with the refuge zoned into

leasing and non-leasing areas. The first oil leases were in 1956 under the Mineral

Leasing Act; no formal compatibility determination was required at that time, but the

Secretary of the Interior determined that leasing could proceed. As a result of a lawsuit,

FWS in 1994 determined that leasing was compatible. After passage of the National

Wildlife Refuge System Improvement Act (1997), this informal determination was

rescinded, with the approval of the Regional Administrator. While the decision does not

affect pre-existing leases, nor subsurface rights not owned by the federal government, it

would prevent future development where the federal government owns the mineral rights.

In addition, Cook Inlet Regional Corporation owns 3.58 townships of coal, oil, and gas

rights; and sand and gravel rights for use in the production of the energy rights. They

also have rights for other structures such as rights of way for roads, drill pads, pipelines

and other facilities necessary to produce these resources.

CRS-30

Exploration Phase

As the previous section makes clear, the leasing and exploration phases overlap.

The exploration phase is the time at which industry and the federal government

accumulate data about the area that will be, or has already been leased. Exploration

activity is most intense after leases have been purchased. Preliminary seismic

exploration, using two dimensional (2-D) imaging technology, continues to be used

in early exploration in new areas. It is carried out directly across frozen tundra

(without special ice roads) in widely spaced grid lines. Seismic exploration uses

trains of rolligons (large vehicles with enormous soft tires that spread their weight

evenly across the surface) for vibrating the surface and recording the result, plus

vehicles for carrying fuel, mechanical repair facilities, and a crew of 80 to 120

people. Damage in the area around Prudhoe is prevented by waiting until the tundra

is well-frozen, though tractors with heavy rubber treads are required to pull some of

the heavier equipment. For the much less expensive, but less precise 2-D surveys,

lines may be several miles apart, but for the high accuracy of 3-D seismic, lines are

about 1100 feet apart. More exploration using 3-D seismic technology becomes

economic in defining more precisely the boundaries of potential structures, though

drilling may occur based on 2-D alone. Under the more advanced 3-D technology,

finer grid lines are also run directly across the tundra. The better data resulting from

3-D increase the chance that a given well will be successful from 1 in 10 to perhaps

3 or 4 in 10.

Modern arctic exploration on the state-owned lands of the North Slope is carried

out in winter; while early phases involve travel across frozen open tundra, subsequent

exploration drilling uses a combination of ice roads, and ice pads. Each mile of ice

road uses an estimated one million gallons of liquid water, and road builders typically

transport liquid water no more than 10 miles, since it may freeze before it is used.

Technical solutions to water shortages could involve greater use of chipped ice

scraped from lakes to supplement liquid water, and/or development of new

technologies using a desalination plant and a heated elevated pipeline.31 Though such

technologies could prove feasible and some are already in use on the North Slope,

they could also change the economics of exploration and later development.

If data indicate economic quantities of oil may be present, a hole is drilled

entirely in winter, on thick insulated pads of frozen water. These pads melt in

summer, leaving the tundra in relatively good condition.32 If no commercial quantity

of oil is found, the pipe is plugged and temporarily or even permanently abandoned,

covered by a small cube-shaped building. Use of these methods, in comparison to

W. Wayt Gibbs, “The Arctic Oil and Wildlife Refuge”, Scientific American (May 2001),

pp. 62-69. (Hereafter referred to as Gibbs, “The Arctic Oil and Wildlife Refuge.”)

With insulating panels, ice pads can be maintained over the summer, allowing the drilling

rig to remain in place for additional drilling in the early winter, thereby eliminating the need

to remove the rig in spring and replace it in the next winter. Such a practice can increase

the drilling season 50 to 70 days. (See CRS Report 31022, p. 17, previously cited.)

CRS-31

the technology available in 1987, can substantially reduce impacts of exploration on

the landscape.33

Development Phase

In the development phase, companies construct the infrastructure needed to go

from a find to actual production; employment peaks in this phase. If economic

quantities of oil are found, a gravel drill pad is built and multiple wells are drilled

from the pad. The newest arctic development technology is demonstrated in the

Alpine field, at the extreme western edge of current oilfield development, on state

lands near the NPR-A. (See Figure 4, showing the Alpine field.) Two gravel pads,

linked by a 3-mile long combined road and runway, support 112 wells. Heavy

equipment to be used in the field was delivered to the nearest staging area in summer

via gravel road. Once winter ice roads were built, the equipment was transported to

the field. In summer, access to Alpine is by aircraft only. While no gravel roads link

Alpine with other North Slope development, pipelines connect the Alpine field to

collection lines from several fields and these in turn connect to TAPS to carry the oil

south.

Since the 1987 FLEIS, considerable advances have been made in the

technologies surrounding the development phase. These advances contribute to

efficiency and often to reduced environmental impacts, and some would likely be

used, required or not, due to cost savings. Others might be used if required by the

federal government or the state; such requirements could change the economics of

development. One clear improvement since 1987, as a result of improved data

analysis at the exploration phase, is that development can be more efficient, since

fewer “dry holes” are likely to be drilled. Other improvements are as follows.

Advanced Drilling. Drilling technology has evolved from a single hole

straight down into a prospect, to directional, extended reach, horizontal, multilateral,

and designer wells. All of these designs permit more efficient production of

hydrocarbon reserves, and allow easier connection to production facilities, with fewer

pipelines. They also reduce the number of wellheads. Drill bit technology has

improved, allowing wells to be drilled faster. Drilling muds are less toxic; cuttings

generated during drilling can be stored in temporary reserve pits and then used in

construction, or reinjected into special wells for waste disposal.34 Efforts are made

to avoid any surface discharge of wastes. Savings make it likely that these

technologies would be used if ANWR were opened; legislative provisions might

push further requirements.

Drill Pads. With this advanced drilling technology, more of the oil-bearing

structure can be tapped from a well head, and drill pads can be located, under very

favorable conditions, up to 7 miles in horizontal distance from a target. These

technologies reduce development’s footprint, as well as allow greater protection of

For more information on exploration technology, see CRS Report RL31022, previously

cited.

For more extensive discussion of these technologies, and for illustrations of types of

drilling methods, see CRS Report RL31022, previously cited.

CRS-32

surface features. Since each drill pad can develop a greater area, fewer drill pads are

needed than in the past. Technologies developed largely in the 1990s also permit

closer spacing of wells, and more wellheads can be placed on a smaller drill pad.

Drill pads in the 1970s were about 44 acres. In contrast, Alpine’s 2 drill pads are 36

acres and 10 acres.35 The larger pad is the main production pad, and includes a

central processing facility, housing, and storage area, along with wellheads. The

secondary pad contains only drilling facilities and wellheads; workers there commute

from the main pad. If the Prudhoe Bay oilfield and surrounding fields had been

developed using this technology, only 4,000 acres, instead of the present 12,000

acres, would be needed.36 Production facilities (like those at Alpine) would be

scattered in a network over producing fields, due to the 7-mile maximum reach of

horizontal drilling, and multiple pads could be needed for producing fields.

(Pipelines would carry oil from the pads to a collection line; see Production Phase.)

Roads. If a development phase followed the model at Alpine, heavy

equipment would be carried to a staging area as near as possible to the drill site and

accessible to the gravel road network that services the currently developed areas. As

soon as ice roads could be built, the equipment would be moved to the drill site,

where a gravel pad would have been constructed previously. All heavy equipment

would be transported to the site during the winter; equipment needed in the summer

would be flown in along with personnel to an adjacent airstrip. As at Alpine, gravel

roads might be constructed to link pads within the same field.

If this model were followed, the mileage of roads constructed in the 1002 area

would be far smaller than was expected in the 1987 FLEIS (for a given size and

location of discovery). Heavy reliance on ice roads could mean high demands for

water if the staging area were just to the west of the 1002 area and discoveries were

in the eastern portion of the 1002 area – a distance of roughly 100 miles.

Alternatively, staging areas could be located farther east, perhaps by off-loading

barged equipment at Kaktovik. Water demands might be further reduced, perhaps

by developing new technologies, or by placing gravel roads to transport heavy

equipment on Native lands. The feasibility of these options would also depend on

the extent to which Congress regulated development on Native lands (as opposed to

federally-owned land).

U.S. Army Corps of Engineers Alaska District, Permit Evaluation and Decision Document,

Alpine Development Project, Colville River 18 (2-960874), p. 2 (Feb. 13, 1998).

Stephen Taylor, retired director of environmental policy, BP Exploration (Alaska). Cited

by Janet Pelley, “Will Drilling for Oil Disrupt the Arctic National Wildlife Refuge?”

Environmental Science and Technology (June 1, 2001).

CRS-33

Figure 4. Alpine Oil Field.

Source: ARCO Alaska, Incorporated. Permit Application to U.S. Army District Engineer,

Alaska, Permit No. 2-960874, Colville River 18. Jan. 22 and 24, 1998. Map somewhat

simplified for clarity in monochrome.

The Meaning of Footprints. The footprint of development infrastructure

is the area within the outline of any structures on the surface of the land as these

features might be shown on an ordinary two dimensional map. In the case of arctic

energy development, most observers appear to include gravel drill pads, runways, and

roads in the total footprint of development. However, in the case of elevated

pipelines, some might choose to count only the base of the support arms holding aloft

the pipelines (footprint in the narrow sense), rather than the entire length and width

of the pipeline (footprint in the broad sense).37 Some would also count the surface

covered by gravel mines, ports, water impoundments, water treatment facilities and

the like (footprint in the broadest sense).

Arctic Power (a consortium of development proponents that includes industry)

has estimated that the 1.5 million acre 1002 area could be developed with a

maximum footprint of 2,000 acres.38 Some have assumed that the footprint would

be a single compact unit of 2,000 acres (equivalent to 3.125 square miles – about

0.13% of the 1002 area). However, full development would be impossible if the

footprint were a single compact unit. With advanced drilling technology (extended

reach drilling), under favorable circumstances, lateral drilling can reach 5 to 7 miles

from a drill site. Thus, if development were confined to a compact box of 3.125 mi2

(equivalent to a square 1.77 miles by 1.77 miles) and optimum conditions obtained,

up to 10.5% of the 1002 area could be developed. In contrast, full development of

the 1002 area would require the strategic placement of pads, connector roads (the

type of road at Alpine), and pipeline supports to be scattered about the 1002 area in

a network.

The difference could be likened to the choice between counting the actual area touched by

the supports of a highway overpass or the outline of the whole overpass, as the footprint.

For example, Arctic Power’s website [http://www.anwr.org/features/pdfs/tech-facts.pdf]

for January 9, 2002 makes this claim.

CRS-34

Most development advocates do not oppose a surface occupancy, or footprint,

limitation to 2,000 acres, apparently feeling that such a limit based on a definition

covering pads, airstrips and pipe supports would not hinder full development. Even

if the term footprint were expanded to include connector roads like that at Alpine

(where the road represents about 15% of the gravel surfaces), they do not appear to

consider a 2000-acre limit to be overly confining. If, however, gravel mines, water

catch basins, water treatment plants, ports, causeways, and other possible features

(FLEIS, p. 99), were to be built and included in a 2,000-acre limit on footprint (the

broadest definition of the term), and if geology of the fields required more numerous

or widespread wells, there appear to be three possible responses to the problem: (1)

facilities might be modified (perhaps through improved technology) in order to stay

within a 2,000-acre limit; (2) some otherwise economic prospects might be missed;

or (3) the footprint limitation might be modified in some way. Finally, if legislation

did not apply limitations to Native lands, some additional prospects on federal leases

might be developed from pads within these Native lands by using advanced drilling

technologies. Support facilities also could be located on the Native lands within the

Refuge and as a result avoid an acreage limitation, if legislation did not specifically

include such lands in the limitation.

Production Phase

In a production phase, drilling equipment would be removed, and small

buildings (housing oil pumps) would be installed and connected to pipelines and, for

the 1002 area, ultimately to TAPS. Fewer employees are necessary during the

production phase. Production facilities to extract hydrocarbons consist of drilling

equipment and rigs, central processing facilities (which include oil and gas separation

units, power plants, flowlines, and crew offices and living quarters), access roads,

gravel mines, airstrips, and possibly ports and desalination facilities. Should

commercial quantities of oil be discovered in ANWR, it is likely that the most

advanced production facilities would be used in order to contain costs and minimize

physical size and effect on the environment.

With current technologies, permanent drill sites would be constructed of gravel

or recycled cuttings from the exploration wells. Compact factory-manufactured

production facilities would be transported to the site instead of built on site.

Depending upon conditions, slim-hole or coiled tubing drilling would be used.39

Multilateral wells (wells with additional boreholes branching from a common hole)

might be used in restricted spaces and/or to share the same surface facility. When

wells not accessible to conventional rigs became old, the life of the reservoir may be

extended by using through-tubing rotary drilled wells, which go through existing

production tubing. Unmanned production facilities might be installed to exploit

accumulations in remote sites, precluding the need for crew facilities at those

locations. Together, these techniques reduce the amount of support facilities needed

and the amount of waste.

The Alpine development, at the far western edge of North Slope development,

uses these technologies, the most advanced currently available. The total Alpine

See CRS Report RL31022, previously cited, for a description of these technologies.

CRS-35

development, according to the U.S. Army Corps of Engineers, is permitted at 98.4

acres of gravel fill. The permit provides for 1 large drill pad (36.3 acres), 1 satellite

pad (10.1 acres), 1 airstrip (35.7 acres), 1 connector road of 3 miles (14.6 acres), and

other features (culverts, etc., 1.7 acres).40

Reclamation Phase

In the reclamation phase, lessees would remove the traces of their activities to

whatever standard was specified. Any authorization to develop the 1002 area could

include reclamation provisions.41 If oil production were to occur, industrial activity

would probably last decades, especially if natural gas resources could also be

developed, so reclamation would be decades in the future. Removal of gravel pads,

roads, and runways; pipelines; support centers; water treatment plants; etc., would

come as production (and therefore revenue) was declining. To ensure financial

resources to support this final industrial phase, some have suggested that companies

be required to post bonds. Even with consistent use of the best available

technologies, decades of disturbance could require more decades for the

disappearance of human intrusion in the slow-growing environment.42 It is unclear

whether local residents or Refuge managers would even wish to have roads or other

facilities removed once energy production ceases.

However, as noted above, new developments in production field facility

construction and maintenance and in drilling and production have reduced the size

of oil and gas field operations. And, since modern technology attempts to avoid any

surface discharge, the technical aspects of reclamation could be somewhat less

demanding than for older fields.

It appears that somewhat less acreage was actually occupied than called for in the permit:

the size of the Alpine complex is variously cited as 93, 94, 97, and 98 acres, depending on

the source. It is unclear exactly what portion of the development is reduced relative to the

permitted size.

If commercial quantities were not found, reclamation would occur after some years of

exploration. FWS or BLM (or other agencies given such responsibility) might condition

development permits on mitigation, reclamation, or rehabilitation of affected lands. If no

commercial quantities of oil were found, cleanup needs might be fairly minimal – although

with the slow growth rate of vegetation in the arctic, even minimal disturbance can take

decades to recover. See Reclamation Issues After Development, below.)

The response of arctic vegetation to disturbance is complex. Factors that tend to lengthen

recovery include greater dryness, changes in moisture conditions, and soil compaction.

Recovery is hastened by re-planting with native plants and careful, selective use of

appropriate fertilizers. Recovery is slower than in temperate habitats. See Jay D.

McKendrick, “Vegetative Responses to Disturbance,” in The Natural History of an Arctic

Oil Field, pp. 35-36.

CRS-36

Resources: Status, Current Regulation, and

Potential Effects of Development

While much is still unknown regarding both the biological and geological

resources of the 1002 area, much has also been learned during 40 years of debate

over the Refuge. Among the areas with improved information are estimates of the

oil and gas potential of the area and the ecology of several of the species that frequent

the area. Some of the specific resources are discussed below.43 This report will first

give background information, and then discuss potential effects of development on

Alaska Natives, the economy, and the Refuge.

Energy: Status and Effects

Potential energy resources are the attraction that drives the ANWR question.

From a long term and basic perspective, U.S. oil production has been declining for

three decades, petroleum consumption has been increasing, and oil imports fill the

growing gap. During 2001, the nation’s attention was drawn to energy issues by

successive jumps in the pump price of gasoline and by California’s serious electric

power problems.44 The potential for oil in the 1002 area has been a focus of that

attention.

Oil Potential. Parts of Alaska’s North Slope (ANS) coastal plain have proved

abundant in oil reserves, and its geology holds further promise. The oil-bearing strata

extend eastward from structures in the National Petroleum Reserve-Alaska (NPR-A),

to the 2 billion barrel Kuparuk River field, past the Prudhoe Bay field (originally 1113 billion barrels, now down to about 4 billion barrels), and a few smaller fields, and

may continue into and through ANWR’s 1002 area. Further east in Canada’s

Mackenzie River delta, once promising structures have not produced significant

amounts of oil. These smaller accumulations include some fields that have produced

intermittently and others that currently are noncommercial due mainly to lack of

transportation infrastructure. The 1002 area contains some of the most promising

undrilled onshore geologic structures with petroleum potential known in the United

States.

Geology and Potential Petroleum Resources. Estimates of ANWR oil

potential, both old and new, depend on limited data and numerous assumptions about

geology and economics. New geological data from outside ANWR and

reinterpretation (using new techniques) of the limited old FLEIS information have

changed estimates of ANWR’s oil potential. Another factor affecting resource and

recovery estimates is the projected price of oil, which the Bureau of Land

Management (BLM) in 1987 assumed would increase steadily (excluding inflation)

over coming decades. In actuality, except for short intervals of spiking, the price of

As noted above, many opponents of Refuge energy development focus less on the specific

resources (discussed below) that might be at risk if oil development is allowed, and more

on wilderness protection, or integrity of the ecosystem as a whole.

As discussed later, oil and gas development of ANWR essentially would not address these

current issues.

CRS-37

oil has not risen to the extent assumed by BLM until recently. A third factor is

falling production costs. As technology improves, once unprofitable structures may

become profitable; this has occurred repeatedly on the North Slope. (See Box, What

the Numbers Mean, for discussion of terms used below.) Three major studies are

reviewed below; due to changes in methods, assumptions, and goals of the studies,

comparisons among them must be done with caution.

1991 and 1995 Studies. In 1991, BLM reviewed its 1987 estimate of

ANWR’s recoverable petroleum resource, based on reprocessed geophysical data,

newly-acquired information on four wells drilled near ANWR, additional seismic

data from offshore areas near the coastal plain, and the characteristics of new

applicable technology (used in the development of the Endicott and Milne Point

fields on the ANS frontier). This review gave BLM a greater level of confidence that

ANWR is part of the North Slope oil province, and increased its estimates of the

probability of economic success. BLM reduced its estimate of the smallest field that

could be developed economically from 440 million to 400 million barrels,45 thereby

increasing the marginal probability of economic success from 19% to 46%; if such

a field is found, the mean estimate of economically recoverable oil would be 3.57

billion barrels – 0.37 billion bbl more than in 1987.

In June 1995, the U.S. Geological Survey (USGS) revisited the Bureau of Land

Management’s 1991 estimates, relying upon several new geologic studies and data

from a new well, the Tenneco Aurora, a federal offshore lease north of the 1002 area.

The USGS reduced its estimates of technically recoverable oil reserves in the 1002

area to between 148 million and 5.15 billion barrels. (The draft study, which was

never finalized, did not give a mean estimate.46 See Box What the Numbers Mean,

for the difference between “technically recoverable” and “economically

recoverable.”)

The seeming paradox of reduction constituting an improvement is analogous to taking two

tests, in which a passing score on the first is 70, while the passing score on the second is 60.

The probability of passing the test (finding an economic field) increases if the minimum

passing score (minimum economic field) decreases. This particular figure for field size was

applicable to western prospects in the 1002 area. The minimum field size for eastern

prospects, needing a longer pipeline to hook up with TAPS, was reduced from 600 million

to 550 million barrels.

U.S. Dept. of the Interior, Geological Survey. Implications of U.S. Geological Survey

Region Hydrocarbon Assessment of Northern Alaska to Oil Resource Potential of Arctic

National Wildlife Refuge 1002 Area. June 2, 1995. 6 p. (Issued in draft form only;

unnumbered report.)

CRS-38

What the Numbers Mean

There are many widely varying estimates of oil quantities in the 1002 area. Here

is a guide to these estimates and their meaning.

How much oil might be present? The amount that might be present or “in place”

is just a starting point, since it is not possible to extract all of the oil in a field.

Estimates are almost always given as a range of numbers. First, petroleum geologists

ask “what quantity of oil are we confident of finding?” There is a good change of

finding a small amount (or more), and a small chance of finding a large amount (or

more). The probability levels used are fixed (by tradition) at 95% (chance of at least

a certain small amount), and 5% (chance of at least a certain large amount). The third

number is the mean estimate – the average of all of the estimated amounts. The

numbers could change with better data or better technology.

How much oil is technically recoverable? This set of estimates does not take into

account the cost of recovery and price of oil, and assumes that only current technology

is used to recover the oil. Like the previous set of estimates, it states the large (95%)

chance that a certain small amount (or more) of oil is present, the small chance (5%)

that a large amount (or more) is present, and the mean estimate. These numbers always

are smaller than the estimates of oil that might be present. As technology advances,

this number also could change.

How much oil is economically recoverable? These numbers are often the most

useful. They reflect assumptions about oil prices, cost of production, etc. They also

are given as 95%, mean, and 5% estimates (of small or more, mean, and large or more

amounts). If technology later advances, costs decrease, or prices rise, then these

numbers could increase, and vice-versa. Estimates of economically recoverable oil

tend to increase over time.

Minimum field size is the smallest amount of oil that must be present in a prospect

for it to be commercial. Embedded in this concept are assumptions about future oil

prices, technology development, and costs of production and transportation; if these

change, this threshold will change. At ANWR, the minimum field size usually is

estimated at a few hundred million barrels. Many smaller fields very close together

might serve as well as a larger one in terms of potential profitability.

What area is being measured? Some estimates of oil in ANWR include the

inholdings of the Kaktovik Inupiat Corporation and those of the Arctic Slope Regional

Corporation, as well as state owned lands offshore. This report refers to estimates on

federal lands only, unless otherwise noted.

1998 Study. The most recent government study of oil and natural gas

prospects in ANWR, also by the USGS, was completed in 1998.47 USGS scientists

gathered new data from nearby fields both onshore and offshore and examined the

reprocessed seismic data collected in the Refuge in 1984-1985. (See Table 1 and

Figure 5; more detailed maps of results are given in the report.) The results of this

new study are based upon the assumption that at least one commercial-size field is

discovered.

U.S. Dept. of the Interior, Geological Survey. The Oil and Gas Potential of the Arctic

National Wildlife Refuge 1002 Area., Alaska. U.S.G.S. Open File Report 98-34.

(Washington, DC: 1999). Summary, and Table EA4. (Report available on 2-disk CD-ROM.)

(Hereafter cited as USGS, Oil and Gas Potential of ANWR.)

CRS-39

Table 1. Probability of the Presence of Given Quantities of Oil

and the Recoverability of the Oil in the 1002 Area

(billions of barrels)

95% Chance

This Much

or More

Mean

Estimate

5% Chance

This Much

or More

In place

11.59

20.73

31.52

Technically recoverable

4.25

7.69

11.80

Economically recoverable at

. . . a market price of $30/bbl

2.98

6.30

10.47

. . . a market price of $24/bbl

2.03

5.24

9.37

. . . a market price of $18/bbl

-0-

2.40

6.15

Crude Oil

Note: All calculations to estimate economically recoverable resources and the prices used

are in 1996 dollars.

Source: U.S. Dept. of the Interior, Geological Survey. The Oil and Gas Potential of the

Arctic National Wildlife Refuge 1002 Area, Alaska. U.S.G.S. Open File Report 98-34

(Washington, DC: 1999) Summary, and Table EA4. (Report available on 2-disk CD-ROM.)

According to USGS, there is an excellent chance (95%) that at least 11.6 billion

barrels are present on federal lands in the 1002 area. There also is a small chance

(5%) that 31.52 billion barrels or more are present. If cost were no object, USGS

estimates there is an excellent chance (95%) that 4.25 billion barrels or more are

technically recoverable. And there is a small chance (5%) that 11.80 billion barrels

or more are technically recoverable.48 (If state offshore lands and Native corporation

lands are included, these numbers become 5.7 and 16.0 billion barrels, respectively.)

It appears that natural gas is likely to be present as well. USGS estimates that there

is a 95% chance that 2.28 trillion cubic feet (tcf) associated with crude oil are

technically recoverable, and a 5% chance that 5.16 tcf are technically recoverable.

Technically or Economically Recoverable? However, cost inevitably comes

into play, whether in the extreme conditions of the North Slope or elsewhere. Thus,

the primary question is how much oil can be extracted profitably? Each company has

its own internal criteria for this. The higher the price of crude oil, the greater the

proportion that would be economically recoverable. High prices also could provide

incentives to improve extraction technology thereby reducing extraction costs. The

USGS estimated that, at $24/barrel (in 1996 dollars), there is a 95% chance that 2.03

billion barrels or more could be recovered, and a 5% chance of 9.37 billion barrels

The USGS technically recoverable figures in the 1998 assessment are based upon the

percentage of oil in place that was recoverable by the oil industry in the 1980s. Inasmuch

as recovery rates have improved since then, the USGS figures may underestimate recovery

rates in ANWR.

CRS-40

or more. For comparison, the spot price of West Texas crude oil ranged from an

average of $11.35 per barrel in December 1998, to $34.34 per barrel in November

2000, according to the Energy Information Administration (EIA). It was estimated

at $20 in November 2001. (In 1996 dollars, these were $10.95, $32.00, and $18.10,

respectively.)

The projected price of oil is only one of many factors entering into the decision

on bidding for a lease. Efforts to reduce exploration and production costs through

new technologies play a key role, for example. Each prospective bidder would do its

own analysis of the economic and physical factors of the areas offered for lease, and

company analyses historically have differed from one another and from government

analyses. With geological evidence pointing to the presence of recoverable oil and

gas, developers may be interested in bidding on ANWR leases.

Possible Production Levels. It is difficult to estimate the development

rates or production levels over time that would be associated with given volumes of

economically recoverable oil resources. Some of the various factors considered by

prospective bidders also would come into play in determining the rate of

development and levels of production. Oil prices (current and projected), geologic

characteristics such as permeability and porosity, cash flow, and any transportation

constraints would be among the most important.

The EIA estimated production “schedules” that would be associated with several

different volumes of technically recoverable resources at two development rates.49

(See Table 2.) At the faster development rate, a production peak would occur 15 to

20 years after the start of development, with maximum daily production rates of

roughly 0.00015 (0.015%) of the resource. Slower development rates would peak

about 25 years after the start of development at a daily production rate of roughly

0.000105 (0.0105%) of the resource. (Peak production associated with a resource of

5.0 billion barrels at the faster development rate would be 750,000 bbl/d.)

U.S. Dept. of Energy, Energy Information Administration, Potential Oil Production from

the Coastal Plain of the Arctic National Wildlife Refuge: Updated Assessment (Washington:

May 2000). The development rates are postulated with the implicit assumptions of

sufficiently high crude oil prices (current and projected) and constant technology.

CRS-41

Figure 5. Petroleum Discoveries and Exploratory Wells of 1002 Area and Adjacent Areas.

Notes: This map shows “petroleum discoveries and status of exploratory wells relative to the 1987 USGS [FLEIS] assessment.

...[D]ashed line marks approximate boundary between undeformed area, where rocks are generally horizontal, and deformed area,

where rocks are folded and faulted.” Source: Figure AO2 of USGS, Oil and Gas Potential of ANWR. Oil was found at Flaxman

Island, Hammerhead, Kuvlum, Badami, and Sourdough. Gas was found at Kavik and Kemik, and Point Thomson showed gas

condensate and oil.

CRS-42

It is not known if the development rates and production schedules developed by

EIA would apply to discoveries of economically recoverable oil in ANWR. If they

did, the peak production level in a scenario with the world price of oil at $24 per

barrel could range from 200,000 to 1,400,000 barrels per day depending upon the size

of the discovery (Table 2). For simplicity, it is assumed that oil prices do not

fluctuate during the lives of the fields being produced.

Table 2. Approximate ANWR Peak Production Levels

Under Selected Discovery and Development Scenarios

Oil Price

per

Barrel

(1996

dollars)

Hypothetical Volumes

of Economically

Recoverable Crude

Oila

(billions of barrels)

Approximate Peak Production

Associated With Respective Volumes

and Different Rates of Developmentb

(thousands of barrels per day)

95%

mean

95%

mean

$18

-0-

2.40

6.15

-0-

250 – 350

650 – 925

$24

2.03

5.24

9.37

200 – 300

550 – 775

975 –

1,400

$30

2.98

6.30

10.47

300 – 450

650 – 950

1,100 –

1,575

Note: Production levels (and implicit development rates) are based upon the assumption that

crude oil prices (current and projected) would be high enough to justify continued

development and production. For simplicity, it is assumed that oil prices do not fluctuate

during the lives of the fields being produced.

These volumes correspond to those shown in Table 1 as economically recoverable oil at

market prices of $18, $24, and $30 per barrel at different degrees of uncertainty.

Production volumes associated with a slower and a faster rate of development; thus at

$24/bbl, the mean expectation of economically recoverable oil is 5.24 billion bbl. This

would result in a production rate of 550,000 to 775,000 bbl/day in the slower and faster

production rates, respectively.

Sources: Energy Information Administration. Potential Oil Production from the Coastal

Plain of the Arctic National Wildlife Refuge: Updated Assessment. May 2000. Table 1 and

CRS estimates.

Natural Gas Potential. Not only crude oil but also large amounts of natural

gas are believed to exist in the 1002 area. This expectation together with huge

amounts of proven gas reserves in the Prudhoe Bay area may increase the appeal of

oil and gas development of ANWR to energy producers.50 For economic reasons,

See CRS Report RL31165, Natural Gas Reserves in Alaska: an Overview of Conventional

and Non-conventional Development and Transport Options, by Terry R. Twyman (Oct. 25,

(continued...)

CRS-43

natural gas was not emphasized in the 1980s, but has become more important in

recent years as demand has grown.

Estimates of Prudhoe Bay Complex. The Alaska Department of Natural

Resources estimated the original recoverable gas reserves of Prudhoe Bay at 30.5

trillion cubic feet (tcf), and estimates current overall North Slope reserves at 30.9 tcf

(including amounts in oil fields subsequently discovered).51 On an energy equivalent

basis, 30 tcf of natural gas is equivalent to about 5.3 billion barrels of crude oil.52

The Energy Information Administration originally counted all of the ANS gas

volumes noted above as proved reserves. Since 1988, however, the EIA has omitted

about 80% of those volumes on the basis that, without a pipeline or near-term

prospects of a pipeline, the gas has no market and therefore is not commercially

recoverable. EIA counts the remaining portion of the gas reserves because they are

used to power oilfield and transport operations. EIA estimates that proved natural

gas reserves in the entire state of Alaska totaled 9.7 tcf at the beginning of 2000.53

Most of the gas produced so far on the North Slope has been reinjected into the

ground by oil field operators to maintain pressure in the reservoir zones. Currently,

80-90% of the 8 to 9 billion cubic feet of natural gas produced per day are

reinjected.54 The remainder is used for lease operations, electric power generation,

and for powering oil flow through pipelines.

Estimates of 1002 Area. Natural gas is also estimated to be in the 1002

area, although seemingly not as much as so far discovered in the rest of the North

Slope. The USGS 1998 assessment of ANWR gas resources estimated a 5% chance

that there are 10.02 tcf or more of technically recoverable gas not associated with oil

in the 1002 area, with a mean “expected” amount of 3.48 tcf. The mean “expected”

amount of technically recoverable dissolved natural gas (i.e., associated with oil) was

3.56 tcf (Table 3). Non-associated gas probably would not be targeted until after oil

field infrastructure was in place.

(...continued)

2001), 23 p. (Hereafter referred to as CRS Report RL31165.)

“Original estimate” figure from Alaska Dept. of Natural Resources, as reported in Alaska

Oil and Gas, Energy Wealth or Vanishing Opportunity? (Final). Prepared for the U.S. Dept.

of Energy by EG&G Idaho, Inc. January 1991, p. 2-8. Current estimate from 2000 Annual

Report, Alaska Dept. of Natural Resources, Division of Oil and Gas, not dated, p. 12.

There are approximately 1,030 btu per cubic foot of natural gas, and 5.8 million btu per

barrel of crude oil. A btu, or British Thermal Unit, is the amount of heat required to raise

the temperature of a pound of water one degree Fahrenheit. (30 tcf x 1,030 btu/cf = 30.9

quadrillion btu. 30.9 quadrillion btu ÷ 5.8 million btu/bbl = 5.3 billion bbl.)

U.S. Dept. of Energy, Energy Information Administration, U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves, 1999 Annual Report, (Washington, DC) p. 28.

Alaska Dept. of Natural Resources. 2000 Annual Report, p. 8; and T. J. Glauthier, Deputy

Secretary, U.S. Dept. of Energy, “Testimony to the Senate Committee on Energy and

Natural Resources,” September 14, 2000.

CRS-44

Table 3. Mean Estimates of the Amounts of Undiscovered

Natural Gas and Natural Gas Liquids in the 1002 Area

Economically Recoverable

at a Market Price of . . .

Natural Gas Resource

Technically

Recoverable

$18 per $24 per

$30 per

bbl of oil bbl of oil bbl of oil

In Oil Fields

Associated dissolved gas (tcf)

(Crude oil equiv. (million bbl))

Natural gas liquids from

associated dissolved gas

(million bbl)

(Crude oil equiv. (million bbl))

3.56

(630)

N.A.

143

100

(92)

(6)

(45)

(64)

In Gas Fields

Non-associated gas (tcf)

(Crude oil equiv. (million bbl))

3.48

(616)

N.A.

Natural gas liquids from nonassociated gas (mil. of bbl)

(Crude oil equiv. (million bbl))

112

N.A.

(72)

Notes: Crude oil equivalents are based upon inherent heat content. The mean is the

arithmetic average of all the estimated amounts, and is sometimes called the “expected”

value, or amount.

bbl – barrel; N.A. – not applicable; tcf – trillion cubic feet.

Source: U.S. Dept. of the Interior, Geological Survey. The Oil and Gas Potential of Arctic

National Refuge: 1002 Area, Alaska. U.S.G.S. Open File Report 98-34. (Washington, DC:

1999). Tables EA4 and RS14.

In addition, the USGS estimated natural gas liquids extractable from the

technically recoverable gas in mean amounts of 143 million barrels from oil fields

and 112 million barrels from gas fields. With an energy content of about 3.8 million

btu per barrel, the former figure is roughly equivalent to 95 million barrels of crude

oil and the latter to about 75 million barrels. The mean amounts of natural gas

liquids economically recoverable at $18, $24, and $30 per barrel of oil would be 10

million, 70 million, and 100 million barrels, respectively.

Because, without a pipeline, there presently is no way of transporting natural gas

to markets and generating revenue streams with which to compare costs, it is not

possible to derive estimates of economically recoverable natural gas in the 1002 area.

Native Lands and Adjacent State Waters. Significant amounts of oil also

are believed to be under Native lands and lands beneath state waters adjacent to

CRS-45

ANWR – perhaps one third as much as in the federal 1002 area. In a March 2002

“preliminary” report, the USGS presented estimates that there is a 95% chance that

there are at least 1.5 billion barrels (bbls) and a 5% chance there are at least 4.2

billion bbls of technically recoverable oil in lands under state waters adjacent to the

Federal 1002 area and in Native lands, with a mean estimate of 2.7 billion bbls.55

The USGS estimated that, if the price of crude oil is $24 per barrel (1996 dollars),

there is a 95% chance of at least 0.9 billion bbls and a 5% chance of at least 3.7

billion bbls of economically recoverable oil in the non-federal 1002 portion of the

study area, with a mean estimate of 2.4 billion bbls.

While significant accumulations may exist under state waters and in Native

lands, they will be difficult to develop without access to Federal land. Alaska

Natives have various property interests and differing opinions related to the issue of

oil drilling in ANWR that may present complex legal issues for refuge management

if the coastal plain is opened to oil and gas exploration and development. Regulation

of development on these lands could be difficult, as discussed in Alaska Native Lands

and Rights, below.56

Natural Gas Pipeline from North Slope. Construction of a pipeline to

transport natural gas to North American markets and/or a warm-water port for

shipping liquefied natural gas (LNG) could enhance Prudhoe Bay economics – oil as

well as gas. The prospect of producing both oil and gas would also enhance the

commercial promise of the 1002 area. Until recently, estimated costs of transporting

the gas precluded serious consideration of pipeline construction. However, recent

steep increases in the price of natural gas and some projections of continued high

prices relative to the average of the past 15 years have suggested some improvement

in the relationship between market price and the cost of known gas resources in the

North Slope. Economic growth, environmental regulations, and gains in gas-fired

electric power generation have increased current and projected demand for natural

gas. In addition, the technology of converting gas into a liquid has advanced. As a

result, serious consideration is being given to building the means of transporting

“proven” gas and the prospective gas of the North Slope to markets.

There appear to be several route options. (See Figure 6.) One is a pipeline that

would parallel the existing TAPS from the North Slope to Fairbanks, then veer

eastward along the Alaska Highway through the Yukon Territory, northern British

Columbia, and into Alberta. This, the Alaska Natural Gas Transportation System

(ANGTS), was approved by the U.S. government in the 1970s and by the Canadian

U.S.G.S. Frontier areas and resource assessment: the Case of the 1002 Area of the Alaska

North Slope. by Emil D. Attanasi and John D. Scheunemeyer. Open File Report 02-119,

March 2002. The report is preliminary and has not been reviewed for conformity to USGS

editorial standards and stratigraphic nomenclature. The estimates in the 2002 report were

developed as part of the previously cited USGS 1998 study, which assessed and prepared

estimates for an area larger than the Federal 1002 area. The study covered adjacent lands

beneath Alaska state waters (to the 3-mile line) and Native lands “within the 1002 area,” as

well as the federal portion of the 1002 area.

For a more detailed discussion of legal complications, see CRS Report RL31115, Legal

Issues Related to Proposed Drilling for Oil and Gas in the Arctic National Wildlife Refuge.

CRS-46

government shortly after. Phase I of the ANGTS pipeline was completed in the early

1980s and is in operation. Its two legs, extending from a central collecting point in

Alberta in the direction of northern California and to the Chicago area, respectively,

deliver one-third of Canada’s total annual gas exports to the United States. The third

leg, connecting Phase I to the North Slope, has never been started. The legal

framework and permits are still in force. Another proposed gas pipeline, the

TransAlaska Gas System (TAGS), would move the gas via a buried route paralleling

TAPS all the way to slightly west of the TAPS terminal at Valdez. The gas would

be liquefied there for shipment to Asian markets. Various environmental and other

approvals have been obtained.

A northern pipeline route (Northern Gas Pipeline Project) would run eastward

from Prudhoe Bay buried under the Beaufort Sea and come ashore in the Mackenzie

Delta. It would then link with a pipeline running through the Mackenzie Valley into

northern Alberta, or with a pipeline running through the Yukon Territory, which

would then link with the ANGTS. It appears that the options have narrowed to the

northern route and the unbuilt leg of the ANGTS route.

Various factors would come into play in determining a route or routes.57 A

study prepared for the INGAA Foundation58 estimated that an overland pipeline route

would cost $100,000 per diameter-inch-mile, and an offshore pipeline route would

cost $150,000 per diameter-inch-mile in up front capital.59 According to this

estimate, a 30-inch, 500-mile overland pipeline would cost $1.5 billion. The

proposed northern pipeline route would be shorter, but the underwater nature may

subject it to technical and environmental risks, and whalers from Alaska Native

villages object. Environmental impact statements prepared 25 years ago may not be

accepted now.

In mid-2003, the economic viability of a natural gas pipeline appears uncertain.

But some recent industry engineering studies of prospective pipeline costs suggest

insufficient profit potential vis a vis the risks.60

For more on transportation options for natural gas, see CRS Report RL31165, previously

cited.

INGAA stands for “Interstate Natural Gas Association of America,” though the official

name of the Foundation uses the acronym.

Houston Energy Group, LLC and URS Corporation, Future Natural Gas Supplies from the

Alaskan and Canadian Frontier, Prepared for the INGAA Foundation, Inc. (2001), p. 22.

See, for example, “Producers Say Alaska Gas Line Not Feasible,” by Mark E. Heckathorn.

The Oil Daily, May 8, 2002.

CRS-47

Figure 6. Proposed Routes to Transport Alaskan and Canadian Natural Gas

to Markets.

Source: T.J. Glauthier, Deputy Secretary, U.S. Department of Energy, “Testimony to the

Senate Committee on Energy and Natural Resources,” September 14, 2000. Cited in

“SPECIAL TOPIC – Alaskan North Slope Gas: From Stranded Asset to a Prize of the

Decade: [http://www.eia.doe.gov/emeu/perfpro/chapter4.html]. Figure is slightly modified

for clarity in monochrome.

Advances in the technology of converting natural gas into a liquid could provide

another transportation option. A gas-to-liquids process (now being developed)

chemically converts natural gas into a diesel-like liquid that can be mixed with crude

oil for transportation and then refined in the lower 48 states.61 Converting the gas

Basically, a mixture of oxygen and the methane component of natural gas is passed

through a ceramic membrane containing a catalyst, producing a synthetic gas, that is then

reacted with another catalyst and converted to high-quality diesel and heavier oil liquids.

(continued...)

CRS-48

into a liquid at or near the oil and/or gas fields would eliminate the need for a

separate gas pipeline and potentially extend the economic life of the existing oil

pipeline. Oil produced from existing North Slope fields is projected to decrease and

fall below the minimum economic flow of the TAPS within a decade or two.

Alaskan Position on Northern Route. Alaska has enacted legislation that

bans construction of a gas pipeline in northern state waters. The Alaska state

legislature strongly supports proposals for a pipeline to the south. While the royalties

to the state (for those natural gas resources actually owned by the state) would be

higher under the shorter, less costly northern route, thereby making the wellhead

prices higher,62 state officials see a greater gain through the income multiplier effect

of construction within the state and greater access by Alaskan communities to the

new gas supplies. Also at issue is the fact that a Canadian route would likely serve

new Canadian gas fields, which would then compete with Alaska in U.S. markets.

This, together with the factors cited above, suggests a potential conflict between

maximizing energy company profits and benefits to the state.

Canadian Position on Natural Gas Pipeline. Canada supports a natural

gas pipeline that would travel from Alaska through Canada. The Canadian

government has not taken a stand on which of the two possible Canadian routes it

might prefer; affected provincial governments all support routes through their

jurisdictions. The over the top route could make some natural gas deposits in the

Yukon and Northwest Territories economically viable. In either case, Prime Minister

Chrétien has expressed Canada’s interest in selling more oil and natural gas to meet

U.S. energy needs. (Some have argued that this interest has intensified Canadian

opposition to ANWR development.)

However, the Canadian government has expressed deep concern that price

supports to encourage development of the pipeline could damage or even end

Canadian natural gas sales to the United States. The Premier of the Northwest

Territories, Stephen Kakfwi, fears that price supports might even flood western

Canada with sufficient cheap natural gas to shut down the area’s own natural gas

production.63 In addition, some Canadian critics reportedly claimed that price

supports could interfere with free trade and therefore violate NAFTA. (U.S.

domestic producers in the Lower 48 have also expressed reservations about potential

distortions in the natural gas market.)

Economic Effects of Development. The U.S. economy as a whole would

be affected by development and production of oil in the Arctic National Wildlife

(...continued)

Low levels of sulfur, metals, and nitrogen in either the pure product or the mixture make it

attractive in terms of reducing pollution.

The wellhead price of oil or gas obtained by Alaskan producers equals the delivered price

(per barrel or thousand cubic feet) less the cost of transportation, which increases according

to the length of the pipeline. State royalties and other revenues are proportionally affected.

Carlisle, Tamsin. “The Next U.S.-Canada Trade Spat? Canadian Oil Firms Object to

Proposed Tax Credits for Alaska Energy Project.” Wall Street Journal, May 10, 2002. p.

A9.

CRS-49

Refuge through the direct effects of the economic activity constituted by the

development and production itself. The economy would also be indirectly affected

by any change in oil prices resulting from ANWR production and any effects on the

amount spent on imported oil. A major unknown and driving factor is the amount

of economically recoverable oil discovered and eventually produced.64

Development Stimulus. Oil and gas development in ANWR would generate

primarily mining, construction, manufacturing, and transportation activity, but also

many types of other supply and support services such as food, fuel, power, and

management services. Such demand for goods and services equipment would be felt

in the lower 48 states as well as in Alaska.

Major determinants of the cost of developing ANWR, and its direct stimulus,

would be the size of any overall discovery of economically recoverable oil resources

and the sizes of the individual fields containing such resources. There are high

degrees of uncertainty in both areas. (See Table 2.)

The USGS estimates also have very wide ranges with respect to oil field sizes.

Among the larger sizes, which oil companies probably would consider first, the

estimates show a 95% chance of three or more fields and a 5% chance of six or more

fields with 256-512 million bbl of technically recoverable oil; a 95% chance of one

or more fields and a 5% chance of four or more fields with 512-1,024 million bbl;

and a 95% chance of a field of three-tenths of a field or more and a 5% chance of one

and a half fields or more with 1,024-2,048 million bbl.65 Each company would have

data on 1002 area prospects from its preliminary exploration and comparisons with

existing information; it would then select the most attractive prospects based upon

its own interpretation of geologic data, its own resource assessment, and its own

financial criteria. Smaller fields probably would become attractive if and when larger

fields were developed and infrastructure was in place.

Thus, if commercial oil fields were discovered, they most likely would be of

different sizes and the collective overall quantity of economically recoverable oil

could be in a very wide range. And, given that the size of a possible overall

discovery is unknown, estimations of the overall cost of developing ANWR are

hypothetical.

Advances in arctic oil and gas development technology, equipment, and facility

configuration reduce both the extensiveness of facilities and the development cost per

barrel of discovery.66 These advances have made such development more capital

intensive onsite and moved more labor offsite, to locations where data analysis is

performed. A very crude benchmark to use as a basis for estimating the outlays that

The economic effects of development are also discussed in CRS Report RS21030, ANWR

Development: Economic Impacts, by (name redacted), (Dec. 3, 2001). 6 p.

USGS, Oil and Gas Potential of ANWR. These are arithmetic means of distributions of

estimated field sizes; results can have numbers with fractions. The numbers of fields used

in the text are rounded.

For more detailed treatment of ANWR petroleum development technology in the arctic,

see CRS Report RL31022, previously cited.

CRS-50

would be entailed is the roughly $1 billion cost of developing the Alpine field, which

has about 430 million bbl of reserves.67 Alpine is a recently developed field on the

North Slope of Alaska that employs advanced arctic technologies. However, Alpine

is appropriate as a cost benchmark only to the extent that the geological conditions,

pristineness, and accessibility of the hypothetically discovered fields at ANWR were

similar to those at Alpine.68

Two illustrative hypothetical cases might be as follows: (1) A discovery of 2.40

billion bbl of economically recoverable oil in four 100-million bbl fields, three 200million-bbl fields, two 400-million-bbl fields, and one 800-million-bbl field. (2) 5.24

billion bbl of economically recoverable oil in six 200-million-bbl fields, four 400million-bbl fields, two 800-million-bbl fields, and one 1,200-million-bbl field.69

In the first case if, hypothetically, the fields associated with an overall 2.40billion-bbl discovery of economically recoverable oil are of the same nature and

degree of difficulty to develop as Alpine, and if, as is unlikely, development costs for

ANWR are proportional to field size (using Alpine as the benchmark), total

development cost of an ANWR discovery of that size would approximate $6.5

billion. With identical caveats for a 5.24-billion-bbl overall discovery, total

development cost of that overall discovery would approximate $14.0 billion.70 At

roughly $2.70 per barrel discovered ($14 billion ÷ 5.24 billion bbl), these

hypothetical estimate totals, which may well exclude exploration costs, appear low.

In recent years, major oil companies have experienced onshore finding costs of about

$5.25 per barrel (with exploration costs accounting for about one-third), based upon

Energy Information Administration (EIA) surveys,71 but such costs have been

declining over time.

Oil Market Response. Other things being equal, an increase in production,

or supply, would be expected to result in a price decline (or a lower price than would

occur otherwise). The size of the decline would depend to some extent on how close

world oil output would be in relation to world oil production capacity and upon the

reaction of other suppliers to the market.

Alan Petzet, “Alaska operators start Alpine field, take more leases,” The Oil and Gas

Journal, (December 4, 2000); Phillips Alaska, Inc., Fact Sheet (January 1, 2001).

Additional outlays for infrastructure, including the cost of connecting to the TransAlaska

Pipeline System, would be required if fields are distant from existing staging areas.

The hypothetical distributions of field sizes are based upon Figure EA2 in: USGS, Oil and

Gas Potential of ANWR, Chapter EA.

Using a ratio of $1 billion per 400-million-bbl field, the arithmetic is as follows. For the

smaller discovery: (4 x $250 million) + (3 x $500 million) + (2 x $1,000 million) + (1 x

$2,000) = $6.5 billion. For the larger discovery: (6 x $500 million) + (4 x $1,000 million)

+ (2 x $2,000 million) + (1 x $3,000 million) = $14.0 billion.

U.S. Dept. of Energy, Energy Information Administration, Performance Profiles of Major

Energy Producers, 1999. (Washington, DC) Table 20, Table B14.

CRS-51

As noted above, peak production from any economically recoverable volumes

of 2.03 billion and 9.37 billion bbl at $24 per barrel72 probably would be reached in

about 2020, and would range from roughly 300,000 to 1,400,000 bbl per day. EIA

projects world oil production to total 106.6 million bbl per day in 2015.73 Thus,

ANWR production (from the respective discovery volumes) at their peaks around the

years 2013-2015 would range from about 0.3% to 0.9% of world output.

Opponents of ANWR have suggested that potential ANWR resources are

equivalent to U.S. daily demand for oil for a matter of just months.74 This does not

consider the role which any incremental source of petroleum plays in markets, which

are dynamic. Consequently, the impact of ANWR production on world oil prices is

likely to be variable depending upon market and political factors prevailing in the

moment. For proponents of development, the oil shocks to the market in 1973-74,

1979-80, 1991, and 2000-2001 tend to loom large.

However, a review of the nearly thirty years since the time of the Arab oil

embargo and first oil price shock in 1973 suggests that it is more accurate to see this

nearly thirty-year period as one of general price and supply stability that is

periodically broken with shorter episodes when price became volatile and supplies

of fuel less certain. During any of these episodes, even an additional 100,000 bbl/day

of refined product in certain regional markets might have eased prices.75 In times of

uncertainty – and even at the low range of estimates of potential ANWR production

– these volumes might help contain a short-term spike in prices. In these moments,

it matters little whether the incremental supply comes from a field holding six

months’ national demand, or sixty years’ potential supply, because the price of

product at the pump will not discriminate between the two.

Some argue that ANWR production could result in lower world oil prices if

supply in the world market were relatively tight in 2015 and the market was

reasonably competitive. In a period of general stability and balance in supply and

demand, production from ANWR at the lower range of the estimates would probably

have a small effect on prices. There is also the prospect that, depending upon market

factors and their internal economies, OPEC and other producers could cut their

output to offset the supply effect of ANWR, as has occurred before. This would

depend upon the commitment of OPEC nations to try to support or defend a price

band for crude oil by cutting production, as they did three times in 2001. At the same

time, internal revenue needs have sometimes prompted producing nations to sell

EIA projects the average price of landed oil imports at $21.37 per barrel in 2010 and

$21.89 in 2015 (1999 dollars). International Energy Outlook 2001. (Washington, DC:

March 2001), p.41. EIA’s oil price, oil production, and economic growth projections used

here are its best-guess “reference case.”

International Energy Outlook 2001. p. 42.

Actual extraction of the oil would require decades.

Mention should be made that a shortage of refining capacity or configuration, and

transportation infrastructure were contributing factors to some of the observed increase in

price, and under these circumstances, the effect upon price of incremental crude production

will be perhaps more selective and regional.

CRS-52

output above their quotas. Additional oil supply from non-OPEC producers also

makes it more difficult for OPEC to affect prices.76

Macroeconomic Effects. In general, if energy prices fall, the drop would

tend to increase the amount of inputs afforded by businesses, boosting the overall

supply of goods and services. Higher aggregate income and lower prices would

enable households to buy more goods and services. Economic growth would speed

up; and, if the economy is not at full employment, more labor and capital would be

employed. Once the adjustment to lower prices is completed, growth would return

to its prior rate, but at a higher output level.

However, in analyzing the impact of changes in energy costs on the economy

as a whole or on individual sectors, one needs to be aware that the relative price of

oil has decreased since the oil price spikes of the 1970s and early 1980s, and energy

use per unit of output has fallen as well. The proportions of production costs

accounted for by energy have dropped across the economy; and energy costs as a

share of Gross Domestic Product (GDP) have declined. Consequently, the relative

impacts of energy price changes on the economy in general and on particular sectors

can be expected to be smaller than they were 20-25 years ago.

It appears also that any price effect would have to be considerable and sustained

for the macroeconomic effects to be reasonably noticeable. For example, the

Organization for Economic Cooperation and Development estimated that an increase

in oil prices of $10 per barrel above its baseline scenario would result in U.S. GDP

being 0.2% lower one year and two years after the shock.77 In contrast, as noted

above, the price effect of a 0.3%–0.9% addition to world oil supply resulting from

ANWR production probably would be small, although econometric research findings

suggest that the beneficial macroeconomic result of a price drop would not

necessarily be proportional.

Oil and gas producers that do not participate in ANWR development, their

suppliers, and their local economies in the contiguous 48 States would be harmed

should oil prices decline. Producers’ revenues would decline indirectly as well as

directly through reductions in output – both effects leading to cutbacks in

employment and in purchases of other goods and services.

With respect to ANWR development, hypothetical outlays of $6.5 billion and

$14.0 billion with an income multiplier of two78 applying to both would come to

For more on U.S. energy policies, see CRS Issue Brief IB10080, Energy Policy: Setting

the Stage for the Current Debate. 16 p.

Organization for Economic Cooperation and Development, Economic Outlook. (December

1999), p. 9. Macroeconomic simulations by o

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