Arctic National Wildlife Refuge: Background and Issues

Report for Congress
Arctic National Wildlife Refuge:
Background and Issues
Updated May 15, 2003
M. Lynne Corn (Coordinator)
Specialist in Natural Resources
Resources, Science, and Industry Division

Congressional Research Service ˜ The Library of Congress

AuthorsArea of ExpertiseCRS Division
Pamela BaldwinLegal issuesAmerican Law
Claudia CopelandWater and wetlands issuesResources, Science,
and Industry
M. Lynne CornOverview; Fish and WildlifeResources, Science,
Service; biological resourcesand Industry
Bernard GelbEconomic issues; oil and natural gasResources, Science,
resources; pipeline issuesand Industry
James McCarthyAir qualityResources, Science,
and Industry
Wayne MorrisseyGlossaryResources, Science,
and Industry
Mark ReischHazardous wastesResources, Science,
and Industry
Roger WalkeNative American issues andDomestic Social
resource usePolicy

Arctic National Wildlife Refuge: Background and Issues
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.

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
In troduction ......................................................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................................16stth
ANWR Consideration in the 101 to 107 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

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

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 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.

Figure 1. Shaded Relief Map of Northeastern Alaska.
Source: U.S. Dept. of the Interior, Fish and Wildlife Service [
arctic/shademap.html], Nov. 9, 2001. Minor modifications made to enhance clarity in
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).

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
!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.

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
!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 oil-
bearing strata extend eastward from the National Petroleum Reserve-Alaska (NPR-
A), 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.

1For maps of existing discoveries along the North Slope, see the website of the Division of
Oil and Gas, Alaska Department of Natural Resources, at :
[ ts/maps/northslope/northslope.htm]

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.

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 cross-
tundra 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

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 spin-
off 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

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

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. 98-
487). 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

2For a discussion of current legislative proposals on ANWR, see CRS Issue Brief IB10111
Arctic National Wildlife Refuge: Controversies for the 108th Congress, updated regularly.
3Outside of Kaktovik, only a few physical artifacts reflect modern human presence. See Use
of Resources by Non-Natives: Status and Effects, below.
4National 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.

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.

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?

!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
!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
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.

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 birds6

new to the area, and similar phenomena.
5U.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.”
6Brown, DeNeen L. “Signs of Thaw in a Desert of Snow.” Washington Post. May 28,

2002. p. A1.

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


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

7U.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).
8United 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.
9Newer portions of the Refuge were not included in the wilderness system.

“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
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

10This map apparently does not exist. See Legal Definition of the 1002 Area, below.
11U.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.”)

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, thethth
sole exception (see ANWR Consideration in the 101 - 106 Congresses, below) was
in a reconciliation bill which was later vetoed. Development continues to be
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,
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

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
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

12For key provisions of that legislation, see archived CRS Issue Brief IB95071, The Arctic
National Wildlife Refuge. 16 p.
13Budget resolutions do not require the signature of the President.

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.)

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.)

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
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 only14
under certain restrictions. Subsequent legislation strengthened the export

14Many 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,

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
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.

even though the oil would fetch higher prices if it could be sold on world markets.
15These 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.
16Brian 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.
17Unnamed ExxonMobil spokesperson, cited in Pearce, Fred. “Alaska’s oil spill may still
be hitting wildlife hard.” New Scientist. May 2, 2001. [].

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

18North Slope oil production had fallen by 0.5 million bbl/d, to 1.5 million bbl/d by 1995 –
still a very large quantity.
19U.S. Department of Energy. Exporting Alaskan North Slope Crude Oil, Benefits and
Costs, DOE/PO-0025 (Washington, DC, June 1994).
20The 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.

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


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

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
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 amounts26

of from 0.3 billion barrels (95% chance) to 5.4 billion barrels (5% chance).
21U.S. Department of the Interior. Bureau of Land Management. Northeast National
Petroleum Reserve-Alaska. Final Integrated Activity Plan/Environmental Impact Statement.
August 1988.
22Gee, 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.
23Oil & Gas Journal, Phillips Makes Own Mark on North Slope with Alpine Start-up, NPR-
A Strikes. August 6, 2001. p. 68 et seq.
24U.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.
25See Glossary and What the Numbers Mean (Box) for an explanation of the terms
technically recoverable, economically recoverable amounts, and mean estimate.
26USGS did not estimate economically recoverable amounts in its 1980 assessment.

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
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

27Aspects 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.)
28For 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.)

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,
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.

29The Mineral Leasing Act sets a maximum of 5,760 acres for tracts in competitive sales in

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 up-
front 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

30See p. 5, The Federal Onshore Oil and Gas Leasing System, previously cited.

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.

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 pre-
existing 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
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.

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

31W. 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.”)
32With 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.)

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
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 in34
construction, or reinjected into special wells for waste disposal. 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

33For more information on exploration technology, see CRS Report RL31022, previously
34For more extensive discussion of these technologies, and for illustrations of types of
drilling methods, see CRS Report RL31022, previously cited.

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).

35U.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).
36Stephen 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).

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.

37The 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.
38For example, Arctic Power’s website []
for January 9, 2002 makes this claim.

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

39See CRS Report RL31022, previously cited, for a description of these technologies.

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.

40It 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.
41If 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.)
42The 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.

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
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 11-
13 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
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

43As 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.
44As discussed later, oil and gas development of ANWR essentially would not address these
current issues.

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
recoverabl e.”)

45The 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.
46U.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.)

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

47U.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.)

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% Chance5% Chance
This MuchMeanThis Much
Crude Oilor MoreEstimateor More
In place11.5920.7331.52
Technically recoverable4.257.6911.80
Economically recoverable at2.986.3010.47
. . . a market price of $30/bbl
. . . a market price of $24/bbl
. . . a market price of $18/bbl - 0 -2.406.15
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

48The 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.

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,
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.)

49U.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.

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.

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
Hypothetical VolumesApproximate Peak Production
of EconomicallyAssociated With Respective Volumes
Recoverable Crudeaand Different Rates of Developmentb
Oil PriceOil(thousands of barrels per day)
per(billions of barrels)
(1996 95% mean 5% 95% mean 5%
$18- 0 -2.406.15- 0 -250 – 350 650 – 925
$ – 300 550 – 775 975 –
$302.986.3010.47300 – 450 650 – 9501,100 –
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.
aThese 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.
bProduction 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,

50See 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,

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 tcf51
(including amounts in oil fields subsequently discovered). 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 natural53
gas reserves in the entire state of Alaska totaled 9.7 tcf at the beginning of 2000.
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.


2001), 23 p. (Hereafter referred to as CRS Report RL31165.)

51“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.
52There 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.)
53U.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.
54Alaska 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.

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 ResourceRecoverable$18 per$24 per$30 per
bbl of oilbbl of oilbbl of oil
In Oil Fields
Associated dissolved gas (tcf)3.56N.A.N.A.N.A.
(Crude oil equiv. (million bbl))(630)
Natural gas liquids from
associated dissolved gas1431070100
(million bbl)
(Crude oil equiv. (million bbl))(92)(6)(45)(64)
In Gas Fields
Non-associated gas (tcf)3.48N.A.N.A.N.A.
(Crude oil equiv. (million bbl))(616)
Natural gas liquids from non-112N.A.N.A.N.A.
associated gas (mil. of bbl)
(Crude oil equiv. (million bbl))(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

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

55U.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.
56For 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.

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

57For more on transportation options for natural gas, see CRS Report RL31165, previously
58INGAA stands for “Interstate Natural Gas Association of America,” though the official
name of the Foundation uses the acronym.
59Houston 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.
60See, for example, “Producers Say Alaska Gas Line Not Feasible,” by Mark E. Heckathorn.
The Oil Daily, May 8, 2002.

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: []. 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 crude61
oil for transportation and then refined in the lower 48 states. Converting the gas

61Basically, 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.

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 wellhead62
prices higher, 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 gas63
production. 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

Low levels of sulfur, metals, and nitrogen in either the pure product or the mixture make it
attractive in terms of reducing pollution.
62The 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.
63Carlisle, 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.

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
Advances in arctic oil and gas development technology, equipment, and facility
configuration reduce both the extensiveness of facilities and the development cost per66
barrel of discovery. 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

64The economic effects of development are also discussed in CRS Report RS21030, ANWR
Development: Economic Impacts, by Bernard A. Gelb, (Dec. 3, 2001). 6 p.
65USGS, 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.
66For more detailed treatment of ANWR petroleum development technology in the arctic,
see CRS Report RL31022, previously cited.

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 200-
million-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 400-
million-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 2.40-
billion-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.

67Alan 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).
68Additional outlays for infrastructure, including the cost of connecting to the TransAlaska
Pipeline System, would be required if fields are distant from existing staging areas.
69The hypothetical distributions of field sizes are based upon Figure EA2 in: USGS, Oil and
Gas Potential of ANWR, Chapter EA.
70Using 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.
71U.S. Dept. of Energy, Energy Information Administration, Performance Profiles of Major
Energy Producers, 1999. (Washington, DC) Table 20, Table B14.

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

72EIA 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.”
73International Energy Outlook 2001. p. 42.
74Actual extraction of the oil would require decades.
75Mention 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.

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. GDP77
being 0.2% lower one year and two years after the shock. 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

76For more on U.S. energy policies, see CRS Issue Brief IB10080, Energy Policy: Setting
the Stage for the Current Debate. 16 p.
77Organization for Economic Cooperation and Development, Economic Outlook. (December

1999), p. 9. Macroeconomic simulations by other organizations have had similar results.

78Changes in investment spending have a magnified impact on the economy as a result of
the ripple effects on the income and spending of other businesses and of households.
Income multiplier is the term used to denote the total impact of the initial spending. Such
multipliers differ depending upon the sector of the economy in which the investment takes
place. A multiplier of two is generally considered reasonable for the type of spending

roughly 0.12% and 0.26% of projected GDP for the year 2002 (on the unlikely
assumption that all the outlays occur in one year).79 If the outlays are spread over
more than one year, the impact in each year would be less, but the total effect would
be about the same. The percentages would be much lower in 2020, when the
economy is projected to be about 45% larger.80 If there is some spare capacity in the
oil and gas industry, producers and their suppliers would benefit. However, if the
economy is at full employment, the multiplier effect would be transitory.
Employment Effects. Oil and gas development in ANWR would generate
additional jobs in the national economy to the extent that development resulted
directly and indirectly in a net economic stimulus. A key factor would be whether
the economy is at full employment or less than full employment. The direct effects
are clearer than the indirect, given the uncertainty of the effects of ANWR oil on
world oil prices and any consequent beneficial effects of lower energy prices on the
economy as a whole.
Rough estimates can be made for jobs generated by the hypothetical
development outlays by using the national averages of 3.89 jobs directly and
indirectly generated per $1 million of sales by oil and gas producers and 16.53 jobs
per $1 million of sales by oil and gas field service companies, as estimated by the81
Bureau of Labor Statistics (BLS). Adjusting for price increases since 1992 and
assuming that half of the outlays are attributable to each group, $6.5 billion in outlays
would lead to about 60,000 jobs, and $14.0 billion would lead to about 130,000
If the economy were at full employment, however, investment in ANWR may
crowd out other spending in the economy; moreover, ANWR development may draw
oil industry resources (capital and labor) from oil prospects elsewhere in the country.
In the long run, the unemployment rate is determined by the structure of the labor
market, and, at full employment, any jobs generated by ANWR development would
come at the expense of an equal number of jobs lost in the rest of the economy.

discussed here.
79DRI-WEFA, U.S. Economic Outlook, (August 2001) p. 9. The projection is in current
80EIA, Annual Energy Outlook 2001, p. 152.
81U.S. Bureau of Labor Statistics. Web site []. While
in terms of sales in 1992 dollars, the ratios (which BLS calls “employment requirements”)
are based upon 1998 productivity relationships.
82Hypothetical $6.5 billion scenario: ($3.25 billion by oil producing companies ÷ 1.097
(deflator)) x 3.89 (jobs per million $) = 11,525 jobs; ($3.25 billion by oil field service
companies ÷ 1.097 (deflator)) x 16.53 (jobs per million $) = 48,975 jobs. Together, the
result would be 60,500 jobs.
Hypothetical $14.0 billion scenario: ($7.0 billion by oil producing companies ÷ 1.097
(deflator)) x 3.89 (jobs per million $) = 24,825 jobs; ($7.0 billion by oil field service
companies ÷ 1.097 (deflator)) x 16.53 (jobs per million $) = 105,475. Together, the result
would be 130,300 jobs.

Because the impact of ANWR oil on world oil prices would be uncertain, and
any decrease would have to be considerable and sustained for the macroeconomic
effects to be reasonably noticeable, the effects on employment would be highly
uncertain. Any gain in employment from beneficial macroeconomic effects of a drop
in oil prices, however, may be offset by the harm to oil producers elsewhere in the
United States, who may reduce their operations and workforce.
Other Job Impact Estimates. Some proponents of ANWR development
assert that such development would result in a gain of more than 700,000 jobs in the
economy. This is based upon a 1990 report by The WEFA Group83 that estimated
that the economic impact of oil development in ANWR would result, through direct
and indirect effects, in a net gain in employment of 735,000 in the peak year of job
creation. The major portion of WEFA’s employment gain results from large
estimated beneficial macroeconomic effects of lower world oil prices caused by an
increase in world oil supply attributable to ANWR oil. WEFA based that increase
upon an oil discovery near the high end of the 1987 FLEIS estimates.
The study’s estimates of effects on GNP84 and employment appear large in the
context of WEFA’s essentially full employment base case. They are large also
compared with actual economic consequences of oil price changes, and in view of
decreased importance of energy inputs in the economy compared with the 1970s
(noted above). It may have been reasonable for WEFA to posit that the world oil
supply situation in 2005 would be much tighter than in 1990, and that an injection
of an additional 1.7 million barrels per day would tend to lower prices somewhat; and
the model used by WEFA allowed for some response by OPEC. The estimated price
effect is large nevertheless. In general, the report tended to select the more or most
optimistic of underlying scenarios when there was a choice to be made in the
sequential analysis required in estimating efforts of this type.85
A recent report by Dean Baker of the Center for Economic and Policy Research
(CEPR) examined The WEFA Group study and re-estimated the employment effects.
It followed WEFA’s paradigm but applied different assumptions about some basic
data, the degree of response by the market and by OPEC to ANWR oil, and the
degree to which the economy responds to an oil price decline. CEPR estimated that
oil production in ANWR would result in the creation of 46,300 jobs.86 The CEPR
report, however, does not purport to be a full-fledged estimate of job effects under
current oil market, oil industry, and economic conditions.

83The WEFA Group merged with DRI, forming DRI-WEFA. DRI had been a subsidiary of
Standard & Poor’s.
84Before 1991, the main indicator of total economic output used by the U.S. Department of
Commerce was Gross National Product, rather than the Gross Domestic Product now used.
85A 1992 CRS report, which examines the economic impact question, judged that, overall,
the WEFA estimates were generous. See ANWR Development: Analyzing Its Economic
Impact, Report 92-169 E, by Bernard Gelb (Feb. 12, 1992), 6 p.
86Baker, Dean. Hot Air Over the Arctic? An Assessment of the WEFA Study of the Economic
Impact of Oil Drilling in the Arctic National Wildlife Refuge. Center for Economic and
Policy Research. September 4, 2001. 11 pp.

Import Reduction. As any ANWR oil would be the marginal source of
petroleum for the United States, net imports (total imports minus exports) probably
would be reduced by virtually one barrel for every barrel of ANWR output. This is
true regardless of the amount of exports of North Slope oil (now nil), which would
affect gross imports. The economy would benefit temporarily through a reduction
in the income transferred overseas to pay for the oil. Using the EIA’s projection of87
refiners’ acquisition cost of foreign crude oil of about $21.50 per barrel in 2015, the
oil import bill would be cut by $2.4 billion to $11.0 billion in that year, improving
the U.S. merchandise trade balance in the short run.
The relative reduction in dollars flowing abroad, however, could cause the dollar
to appreciate. This would tend to reduce other exports and expand other imports to
some extent, reversing the initial improvement. A possibly greater increase in
demand for imports of other goods and services could result from the higher level of
economic activity caused by lower oil prices. Basically, the trade deficit reflects the
desire of Americans to borrow abroad versus the desire of foreigners to invest or
borrow in the United States. Assuming that oil development of ANWR did not
influence this dynamic, it would likely have no permanent effect on the trade balance.
Effects on the Alaskan Economy. The Alaskan economy could be
affected substantially by development and production of oil in ANWR through the
direct effects of the exploration, development, and production, and indirectly through
the ripple effects of the money spent in Alaska by the producing companies and their
workers. A major unknown is the amount of oil that might eventually be produced.
Oil and gas production already is a major industry in Alaska, directly accounting88
for about 4,500 jobs and $425 million in annual payroll, and about 20% of state
gross product on average.89 ANWR development would affect primarily the oil and
gas industry, but also construction, telecommunications, manufacturing,
transportation, and other mining, as well as employment in these industries. Many
types of other supply and support services such as food, fuel, power, and
management services would also benefit. A study of the current economic impact
of the oil and gas industry on Alaska indicates substantial effects of the industry on
individual regions in the state. And it found indirect and “induced” employment90

impacts equal to six times employment in the industry itself.
87EIA, Annual Energy Outlook 2000, p. 133.
88Employment and payroll figures are calculated from data in U.S. Dept. of Commerce,
Bureau of the Census, 1999 County Business Patterns, Alaska and Information Insights, Inc.
and McDowell Group, Economic Impact of the Oil and Gas Industry on Alaska, (Fairbanks,
AK: January 15, 2001).
89U.S. Dept. of Commerce, Bureau of Economic Analysis at [].
State gross product is the total market value of the goods and services produced in the state.
Gross product originating in oil and gas extraction varies widely with crude oil prices and
the consequent effects on oil company profits, which are a component of gross product.
90Economic Impact of the Oil and Gas Industry in Alaska. op. cit. The study is based upon
a survey of state oil and gas producers and businesses in the state that sell them goods and
services. CRS observes that while there are indirect effects, frequently studies of this type

The direct stimulus of the outlays for exploration, development, and production
would be felt more in Alaska than elsewhere in the United States – the amount of
economically recoverable oil discovered and eventually produced being a key factor.
However, much of the equipment and other goods required would be manufactured
in the lower 48 states as well as in Alaska. Working with the hypothetical outlays of
$6.5 billion and $14.0 billion for wells, pipeline extension, and other facilities, and
making the simplifying assumption that half of these outlays would be spent for
goods and services (including labor) in Alaska, they would come to $3.25 billion and
$7.0 billion. Again adjusting for price increases since 1992 and assuming that oil
producing companies and oil field service companies each accounted for half of the
outlays, it would lead to about half of the hypothetical jobs estimated for the United
States as a whole – 30,000 and 65,000, respectively.
The ratios used, however, are national averages, and oil and gas industry wages
in Alaska are higher than average. While the latter is beneficial in one respect, it may
translate into a smaller number of jobs per billion dollars of outlays. Also, advances
in oil and gas development technology and facilities since 1990, reducing the size of
facilities, may also reduce the number of jobs generated by such development.
Furthermore, if there were some slack in the Alaskan economy if or when
ANWR energy development occurs, jobs created by ANWR could result in a
reduction in Alaskan unemployment. If the Alaskan economy were at full
employment, the job gain could be transitory. Moreover, as noted earlier, any jobs
generated by ANWR development could come at the expense of an equal number of
jobs lost in the rest of the economy. This could include drawing oil industry
resources (capital and labor) from oil prospects elsewhere in the country to some
The Alaskan state government, and ultimately Alaskan citizens, could benefit
substantially from ANWR development via its share of potentially billions of dollars
of revenues from bonuses, rents, and royalties. Alaskan citizens receive annual
distributions from the state’s Permanent Fund, which is endowed by revenues from
mineral lease rentals, royalties, and bonuses, and the states’s share of federal mineral-
derived revenues. The distribution in 2000 was $1,963.86 per resident.
Regarding only royalties, a discovery sufficient to produce the modest amount
of 750,000 barrels per day with a wellhead price of $20 per barrel and a royalty rate
of 12.5% could yield about $700 million per year for Alaska’s 627,000 residents. As
discussed subsequently in this report, however, it is uncertain at this point what
Alaska’s share of the various revenue streams might be.
Relationship to Recent U.S. Energy Difficulties. The current interest in
oil exploration and development in ANWR was at least partly prompted by the
increase in the retail prices for refined petroleum products that began with gasoline
in early 1999, and California’s electric power problems. Any energy and/or
economic benefits that would accrue from oil and gas development of ANWR

use estimating approaches that tend to overstate indirect impacts.

essentially would not address the power difficulties experienced in California –
which were related to insufficient generation capacity, natural gas price spikes, and
the electric power market deregulation plan adopted by the state.
Similarly, some of the increase in the prices for gasoline, diesel and home
heating oil were a function of insufficiently available refining capacity, and a brittle
petroleum supply infrastructure. Much of this effect has now been mitigated. Under
these circumstances, the effect upon price of incremental crude production from
ANWR might have been partly muted, or at least more selective and regional.
Biological Resources: Status and Effects
At a House hearing on July 1, 1959, testimony was provided by Ross L. Leffler,
Assistant Secretary of the Interior for Fish and Wildlife, on H.R. 7045 to authorize
the establishment of the Arctic National Wildlife Range. Speaking of the entire area
of the proposed refuge, he said:
The great diversity of vegetation and topography . . . in this compact area,
together with its relatively undisturbed condition, led to its selection as the
most suitable opportunity for protecting a portion of the remaining wildlife
and its frontiers. The area included within the proposed range is a major
habitat, particularly in summer, for the great herds of Arctic caribou, and
the countless lakes, ponds, and marshes found in this area are nesting
grounds for large numbers of migratory waterfowl that spend about half of
each year in the rest of United States; thus, the production here is of
importance to a great many sportsmen.... The proposed range is restricted
to the area which contains all of the requisites for year-round use. The
coastal area is the only place in the United States where polar bear dens are
Twenty-eight years later, the FLEIS echoed these remarks with the following:
“The Arctic Refuge is the only conservation system unit that protects, in an
undisturbed condition, a complete spectrum of the arctic ecosystems in North
America” (p. 46). It also said “The 1002 area is the most biologically productive part
of the Arctic Refuge for wildlife and is the center of wildlife activity” (p. 46). The
biological value of the 1002 area rests on the very intense productivity in the short
arctic summer; many species arrive or awake from dormancy to take advantage of
this richness, and leave or become dormant during the remainder of the year. Caribou
have long been the center of the debate over the biological impacts of Refuge
development, but other species have also been at issue. Among the other species
most frequently mentioned are polar bears, musk oxen, and the 135 species of
migratory birds that breed or feed there. To some extent, the effects of development
on animals in the Refuge can be estimated by examining past effects on the same

91U.S. House of Representatives, Committee on Merchant Marine and Fisheries,
Miscellaneous Fish and Wildlife Legislation, 86th Congress, First Session, July 1, 1959,
(Washington, DC:1959), p. 140.

species as they exist in developed areas on the coastal plain.92 However, these
comparisons must be made with some caution for several reasons:
!The coastal plain in the 1002 area is much narrower (as little as 15 miles) than
around Prudhoe (roughly 100 miles) or the NPR-A (as much as 130 miles).
!The form development takes in the 1002 area would likely be quite different
from earlier development, with fewer roads and more overflights, for example.
!Conditions have changed since Prudhoe Bay development began nearly 30
years ago: winters tend to be milder; tundra thaws earlier and freezes later; and
vegetation patterns have already begun to change in response to these
changes.93 Animal life would be expected to respond to these changes, sooner
or later.
This section presents background information on various species as it might
relate to energy development in the Refuge and the potential effects of development
on these species.
Caribou. In 1987, the Porcupine caribou herd (PCH) was estimated at 180,00094
animals, and is now estimated at 129,000 animals. The herd winters south of the
Brooks Range in central Alaska and northwestern Canada. Its winter range is
centered on the Porcupine River in Canada and Alaska. In the spring, the males and
yearlings migrate north first, followed by the cows, who move north with the
retreating snow line; the entire herd calves in only a few days. In most years, the
cows reach the 1002 area and give birth there, concentrating their activity in areas
that are greening most rapidly and that offer the high protein content required by
growing calves and lactating cows.95 If snowfall has been heavy, or if a cool spring
delays snowmelt, the cows are delayed, and drop their calves short of the 1002 area.
(Maps of the distribution of radio-collared caribou throughout their annual cycle can
be found at [] and annual calving
maps at [].)
Much has been made of the failure of caribou cows to calve in the 1002 area in
some years, notably 1986, 1987, 2000, and 2001. In these years, heavy snowfall or
cool spring temperatures slowed the northern migration, so that when calving
occurred, most cows had not yet crossed large flooding rivers or passed the Brooks

92Development of Native lands may operate under different legal authorities or management
goals, depending on existing laws and such changes as Congress might make in legislation
to open the 1002 area to development. Such differences could affect not only these lands
themselves but also surrounding federal lands.
93Margie Mason, “Increased Shrubbery Found in Arctic,” Reuters (May 30, 2001); Zaz
Hollander, “Global climate changes rule Senate hearing,” Anchorage Daily News (May 30,


94Like many arctic species, caribou (Rangifer tarandus) population numbers are highly
variable, and the causes of these “boom and crash” cycles are not well-understood. The
Central Arctic Herd calves closer to the existing oil fields, and is about 20-25% the size of
the PCH. The PCH has shown a sustained decline from its peak in 1989. (USGS Wildlife
Research Summaries, 2002. p. 14.)
95Gibbs, “The Arctic Oil and Wildlife Refuge,”pp. 62-69.

Range. Many newborn calves died in river crossings or fell prey to the golden eagle,
wolf, and grizzly populations in the Brooks Range. For radio collared cows in 2000,
the June calf survival rate and the July calf to cow ratio were the lowest ever
recorded. 96
Even if migration is delayed, the cows continue on to the 1002 area, where they
continue to forage. As June days lengthen and become warmer, mosquitos, bot flies,
and warble flies can reach tremendous numbers on the coastal plain. While the
blood-sucking habits of mosquitos are well-known, the flies present major health
problems as well. These flies deposit their eggs in the nasal passages of the caribou
or in wounds; larvae feed and migrate through the skin, making holes in the skin
when ready to emerge. Severely infested animals, or those in weakened condition
(e.g., injured or older animals, young calves, lactating cows) have restricted breathing
or are otherwise weakened. They may die or fall to predators. When these flies are
numerous, herds may appear panicked, seeking relief in areas where flies are less
Mosquitos become active earlier in the summer and are deterred by cool, windy,
humid conditions. When they are numerous, caribou congregate near the coast,
where breezes are typically stronger, temperatures lower, and mosquitos
consequently rarer. The larger bot and warble flies tolerate somewhat higher winds,
but not shade; they too prefer warmer temperatures, and become active later in the
summer.97 Consequently, after calving is over and the herd has reached the 1002
area, the herd generally moves to the coast to escape mosquitos; as mosquito
populations decline and fly populations increase, the herd may return to inland areas
where patches of snow, gravel bars, or hills offer less favorable conditions for the
increasing numbers of bot and warble flies. At this time of year, cows are at their
lowest energy levels, and according to the FLEIS, “[a]ccess to insect-relief habitat
and forage during this period may be critical to herd productivity” (p. 25).
The effects of exploration, production, and development in the 1002 area on
caribou cannot be known with certainty unless such events actually occur, and even
then will undoubtedly be debated. When the 1987 FLEIS was released, debate
centered on the potential for displacement of the herd from (a) its preferred calving
area and (b) the coastal areas needed for relief from clouds of biting insects. These
remain the primary concerns. A major point of debate has been the comparison of
effects of development on the Central Arctic Herd (CAH), whose range is partly in
the developed areas west of the Refuge, and the potential effects of development on
the PCH, whose summer range is primarily in the 1002 area. Comparisons of the two
herds must be made cautiously, since the PCH is about 5 times larger than the CAH,
calves in about 1/5 the area of the CAH, and annually migrates to overwinter south
of the Brooks Range, while the CAH generally remains year-round in the much
broader coastal plain in and south of the existing oil fields.

96Stephen M. Arthur, “Porcupine Caribou Herd Calving Survey, June 2000,” unpublished
memorandum, (July 12, 2000), 7 p.
97Warren B. Ballard, Matthew A. Cronin, and Heather A. Whitlaw, “Caribou and Oil Fields”
in The Natural History of an Arctic Oil Field. (New York, NY: Academic Press, 2000), p.

91. (Hereafter cited as The Natural History of an Arctic Oil Field.)

Would Caribou Be Displaced from Calving in the 1002 Area? This
question can be divided into two parts: would the PCH likely be displaced from the
1002 area at calving time? And more importantly, if it were displaced, would
displacement have harmful effects on calving success? For the first question, the
answer for the herd as a whole, based on the Prudhoe Bay experience, appears
initially to be a qualified “no.” Individual animals, especially adult males, habituate
to the disturbance, and sometimes seek out gravel pads and roads, where insect
attacks may be less severe. The CAH has grown since development began, from
5,000 to about 27,000. However, warning signs exist. For instance, Brad Griffiths
and Ray Cameron and their students at the University of Alaska (Fairbanks) have
shown that for the western portion of the CAH, cows have shifted their calving
southward, out of the development area, and return to this rich foraging area only
after their calves are older. These studies also show that “the greatest incremental
impacts are attributable to initial construction of roads and related facilities” and that
“the extent of avoidance greatly exceeds the physical ‘footprint’ of an oilfield
complex.”98 Thus, it is possible that habituation could occur, especially with males
and yearlings, but some displacement of cows with young calves also seems likely.
The second question is the most crucial, since displacement to another area is
inconsequential only if calving success is equally good in the alternative area(s).
More precisely, if the herd is significantly less productive in the alternative area(s),
the difference serves not to show the availability of alternatives but rather to highlight
the importance of the preferred area. For clues, scientists have examined the
reproductive success both of displaced cows in the CAH, and of the PCH in years
when natural events prevented it from calving in the 1002 area. Griffiths and
Cameron have shown a correlation of calf survival in the CAH with the amount of
high-protein food in the calving area. In the much narrower coastal plain of the 1002
area, any cows displaced southward would calve in or nearer the Brooks Range,
where golden eagles, grizzly bears, and wolves (all calf predators) are more abundant
than on the plain. Cows displaced to the east and calving in Canada tend to eat
mosses and evergreens there, rather than the more digestible cottongrass and other
plants available in the 1002 area.99 As noted above, in 2000, when snows delayed100
migrating cows, effects on calf survival were severe.
In sum, calving can – and in some years does – occur in areas other than the
preferred 1002 area. However, evidence exists to suggest that calving success will
be reduced when this occurs. At present, displacement from areas of the most
nutritious forage is a rare event; if it were to become common, reduced fecundity
could be expected. Smaller drill pads and fewer roads could combine to reduce
displacement, and with directional drilling, pads might be sited to avoid areas of high
quality forage. Even then, the naturally cyclic nature of caribou populations might
conceal all but large effects for a considerable time.

98C. Nellemann and R. D. Cameron, “Cumulative impacts of an evolving oil-field complex
on the distribution of calving caribou,” Canadian Journal of Zoology, Vol. 76 (1998): p.


99USGS Wildlife Research Summaries, 2002. p. 21.
100Stephen M. Arthur, “Porcupine Caribou Herd Calving Survey, June 2000,” unpublished
memorandum (July 12, 2000). 7 p.

Attempting to address this question of calf survival, USGS scientists used
existing field data on caribou displacement elsewhere and combined it with five
possible development scenarios (described in previously published literature) ranging
from development only at the periphery of the northern and western portion of the
1002 up to one scenario that included most of the 1002 area and two full
development scenarios. Then they examined the hypothetical outcomes that would
have occurred had those areas been developed at that level with the actual data on the
distribution of cows from 1980 to 1995. In effect, they asked where would PCH
cows have gone in each of those 16 years of data, if that level of development had
been in place and if PCH cows responded as other caribou cows do to various kinds
of disturbance. With this empirical model, they then predicted PCH calf survival in
the areas to which the cows would have been displaced. “The simulations indicated
that a substantial reduction in calf survival during June would be expected under full
development of the 1002 area.”101
Would Caribou Be Displaced from Insect Relief Areas? Relief from
massive mosquito populations and then fly populations can be critical to the herd.
Given the particular aversion of cows with young calves to developed areas, the
potential for conflict with development seems likely to be more important early in the
calving season. Immediately along the coast, breezes deter mosquitos. Any shore
facilities or activities that block access to the coast could be most significant in this
potential conflict. Later, when bot and warble fly populations are peaking and calves
are older, cows with calves are likely to leave the coast and move inland. In the
CAH, they may join the rest of the herd when it rests on drill pads or under pipelines
or other structures, where shade discourages fly populations. Studies by Pollard et
al. have shown that temperatures were lower and wind speeds higher on gravel pads,102
and mosquitos and flies were less common on gravel pads than on tundra. Thus,
gravel drill pads could join other features in providing fly relief to the PCH, once
caribou become accustomed to the facilities. However any such benefit is likely to
be marginal for the PCH, since the herd tends to leave the 1002 area before the bot103
and warble fly populations have reached their peaks.
Polar Bears. Polar bears (Ursus maritimus) probably rank right after caribou
in generating attention in the ANWR debate. The Beaufort Sea population is
estimated at about 2000-2500 bears and ranges along the Alaskan and northwestern
Canadian coasts. Bears spend most of their adult lives at sea on the ice, feeding
primarily on seals. Female bears give birth about once every three years (or less, if
previous cubs died young) as they hibernate. While some females den on the ice
pack, other adult females come ashore. In either case, they give birth to one to three
cubs. In the spring, the females and cubs leave the dens; those with onshore dens
return to join the rest of the population on the ice pack. As a result of this pattern,
only a small part of the population is on shore at any one time. The Refuge has the
highest density of onshore dens of any area along the Alaskan coast. Researchers

101USGS Wildlife Research Summaries, 2002. p. 31.
102Cited in The Natural History of an Arctic Oil Field, p. 91.
103USGS Wildlife Research Summaries, 2002. p. 29

have shown that female polar bears are very sensitive to disturbance and will
abandon their dens and young cubs if sufficiently disturbed (FLEIS, p. 129-130).
The shift to winter for virtually all exploration and certain other activities during
development and production benefits many species. However, for polar bears this
activity would occur at the times when female bears would be denning. To the west,
industry has worked to avoid known den sites, but fewer dens are present in that area
than in the 1002 area. Paradoxically, one new technology may present more
difficulties. Use of 2-D seismic exploration can be accomplished with crews
working at considerable intervals between survey lines. But for finer analysis of
geological data, industry may find 3-D seismic exploration to be a cost-effective and
preferable supplement. However, 3-D crews must work at much closer spacing than
2-D, thereby increasing the potential for conflict with denning bears. However, more
recent studies suggest that denning polar bears may not be as seriously disturbed by
human activities as previously thought: certain dens exposed to high levels of activity
did not suffer a detectable reduction in productivity.104
Other possible conflicts include inhibition of bears coming ashore for denning,
and the habituation of polar bears to human presence, and the subsequent risk to
human life. Protected under the Marine Mammal Protection Act, and an international
agreement (though not under the Endangered Species Act), polar bears are hunted
relatively infrequently in Alaska (for subsistence), and some may lose their fear of
humans. If human presence increases in the 1002 area as a result of development,
conflicts with scavenging bears might become more common in the 1002 area. Polar
bears are attracted now to the Kaktovik area (especially on occasions when whale
carcasses have been landed). Generally, when such conflicts have occurred on the
North Slope, habituated nuisance bears are relocated or destroyed.
The FLEIS suggested buffer zones of at least 0.5 miles around known dens in
order to prevent abandonment. It also recommended orienting facilities to permit
inland access for pregnant polar bears, relocating problem bears, and as a last resort,
humane killing to protect human welfare. These actions continue to be the primary
forms of mitigation.
Musk Oxen. Musk oxen were hunted to extinction in the area in the late

1800s, but 64 animals were re-introduced into the 1002 area in 1969-1970, and the105

population peaked at about 400 animals in 1986. About twice that many are
present during spring calving. They survive brutal winters protected by their thick
fur, and conserve energy by moving little from their preferred riparian habitats. River
corridors are used both for feeding and for travel all through the year, particularly in
western portions of the 1002 area. Limited hunting of bulls is permitted by the
Alaska Department of Fish and Game.
The high demand for water could create conflicts with the needs of musk oxen.
The preferred habitat for musk oxen is riparian areas; if riparian areas are heavily

104USGS Wildlife Research Summaries, 2002. p. 69.
105USGS Wildlife Research Summaries, 2002. p. 54. Some data suggest that the decline
from the peak is associated with lower calf production and increased grizzly bear predation.

mined for gravel, or altered for capture of spring runoff, this species could be
affected. In addition, the extreme metabolic slowdown that this species undergoes
to survive the harsh winter could be threatened if herds are forced to flee frequent
disturbances. The latter seems more easily mitigated than habitat alteration, since
knowledge of the specific whereabouts of herds through radio collars could permit
workers to avoid them.
Migratory Birds. A variety of bird species nest or forage in the 1002 area,
taking advantage of the explosion of insect life and rapid plant growth that occurs in
the short summer. Compared to birds breeding in temperate areas, these species
cycle from spring arrival, to nesting, to southern migration at a furious pace. A large
variety of birds, both familiar and rare in the lower 48 states, breed or fatten for
migration in the Refuge. (See FWS web site: [
wildlife.html].) Among these are many popular game species: snow geese, Canada
geese, white-fronted geese, brant, pintails, widgeons, and others. A wealth of
shorebirds (plovers, dunlin, sandpipers, turnstones, phalaropes, and others) also
frequent the area. Population data on most ANS bird species come from studies done
in or near developed areas around Prudhoe Bay. The populations of many species
oscillate, as is common in the arctic. Among shorebirds, only dunlin have shown
long term declines, though this trend is shown in other arctic areas, and may be due106
to losses in their wintering habitat in east Asia. Only 6 bird species are regularly
found in the 1002 area in winter: snowy owls, gyrfalcons, rock and willow107
ptarmigans, common ravens, and American dippers.
The spectacled eider, a large sea duck, is a rare to uncommon breeder along the
coast of ANWR. It is listed as threatened under the Endangered Species Act (ESA).
(See FWS fact sheet, including distribution map, at
Reasons for the decline are unclear and may vary in different parts of the bird’s
range, but increased lead poisoning from ingested lead shot, hunting, and increased
predation due to augmented predator populations near human development and
garbage dumps are thought to play a role.
Steller’s eider is a casual visitor along the coast of the Refuge. It too is listed
as threatened under ESA. (See FWS fact sheet, including distribution map, at Reasons for the decline of this species are
also unclear, but may be similar to those for the spectacled eider.
In comparing likely environmental effects of potential energy development on
the birds of the 1002 area under a modern scenario and under that envisioned in

1987, only one feature seems to have changed markedly: much greater reliance on

106Declan M. Troy, “Shorebirds” in The Natural History of an Arctic Oil Field, p. 283.
107Additional species may come to frequent the North Slope as the area shares in the
warming trend that is now observed in much of the rest of the high arctic region. (See
“Habitat Trends During the Study Period”, p. 11-13 in USGS Wildlife Research Summaries,
2002.) In northern Canada even a robin (a bird for which there is no name in Inuit) was
recently seen in the high arctic, boldly going where no robin apparently had gone before.
(DeNeen L. Brown, “Signs of Thaw in a Desert of Snow,” Washington Post, May 28, 2002.
p. A1.

aircraft. Many more airstrips are now likely to be built, and many more flights made,
especially in summer when more birds are present, than seemed likely in 1987. The
species most likely to be affected by these flights is the snow goose, since their huge
feeding flocks are highly sensitive to overflights, and are easily startled away from
foraging sites. Mitigation measures suggested in the FLEIS were “careful facilities
siting and controls on surface activities, air transportation, and hunting” (p. 133).
These remain important, and it seems likely that a reduced number of facilities could
make siting easier, but controls on air traffic seem more likely to be difficult than was
assumed then. Protection of eiders, which were not listed under ESA at that time,
could also be an issue in the western part of the Refuge where these rare birds are
more likely to occur. Measures to protect both species of eiders could include
restrictions on certain activities such as vehicular traffic, noise, construction within
about 200 meters (660 feet) of active nests, and habitat alteration.
Other Species. Arctic fox populations and brown (grizzly) bear populations
on the coastal plain have increased from development due to increased scavenging.
The FLEIS noted that the increased population of foxes had damaging effects on their
normal prey species, such as young birds, on which they continue to feed.
Scavenging arctic grizzlies can become habituated to humans, as they do elsewhere,
and become dangerous to human life. As noted in the FLEIS, careful control of trash
can mitigate both problems.
Special Areas. If Congress opened ANWR, it could choose to afford special
protections to special areas. Four areas within the coastal plain are commonly
considered to have exceptional ecological value and were identified as such in the
!By far the most frequently mentioned is Sadlerochit Spring in the
southernmost part of the 1002 area. The spring maintains a flow of water at
50°-58°F year-round, and keeps the river open for nearly 5 miles, even in
winter. It represents the extreme northern range of some plants and birds, and
provides wintering habitat for fish; muskoxen frequent the area. During the
research leading up to the Section 1002 study, 4,000 acres around the spring
were closed to exploration. There are individual Native allotments in the
Sadlerochit area, which could complicate attempts to set it aside.
!The Kongakut River lies between the 1002 area and the Canadian border, and
flows into the Beaufort Lagoon. Because of the unusual and diverse offshore
ecosystem, and the presence of some of the North Slope’s very rare trees in
the upper part of the watershed, the area is considered ecologically valuable.
About 25,000 acres of this system are included in the extreme northeastern
part of the 1002 area.
!The Angun Plains are in the eastern part of the 1002 area, where evidence of
Pleistocene glaciation is considered special. It comprises 36 square miles
(23,040 acres).
!Parts of the Jago River drainage were identified in the FLEIS as nominees for
“a system of ‘Ecological Reserves.’” The river flows from the Brooks Range,
into the 1002 area, and to the sea east of Kaktovik. The report notes that the
drainage “contains a complete array of tundra and flood-plain vegetation types
and provides habitat for a cross-section of all Arctic Slope wildlife species”

(p. 20). The particular areas suitable for such ecological reserves were not
named by proponents of the idea, and the FLEIS gave no acreage figure for it.
Physical Environment: Status and Effects
Much of the attention and controversy over exploration and development of the

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

However, if development occurs, there also will 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 largely
uninhabited, the condition of the physical environment is almost pristine (although
rugged and challenging for man’s use) and essentially unaffected by human activity.
Especially in terms of land and water, the dominant physical characteristic is
permafrost, the permanently frozen layer which starts between 1 and 2 feet below the
surface and has been found at a depth of 2,000 feet, that impedes drainage and creates
saturated soil conditions in most areas of the entire North Slope. Permafrost and the
surface layer on top of it are fragile, and special construction techniques (such as ice
roads and structures built on pilings) have been devised to protect them.
It is undisputed that exploration and development activities will alter the
existing physical environment. Oil field operations will result in air pollution
emissions. There will be a need for large amounts of water for drilling and ancillary
activities, including construction of roads, drill pads, and airstrips. Some amount of
gravel will be mined as part of some of these activities, and there likely will be
impacts from both the mining and use of gravel. Exploration and development
activities will result in the generation of several types of waste streams, both wastes
from industrial operations and domestic wastes, requiring disposal technologies. 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
The industry strongly believes that the 1002 area can be explored and developed
in an environmentally sensitive manner. Industry points out that companies use
improved technology (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, there are numerous environmental protection
requirements administered by federal and state authorities that are intended to govern
and regulate activities that might take place. Critics, however, are concerned about
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 will be included in legislative proposals, and adopted and
enforced by regulators.
Air Quality. Air quality on the North Slope of Alaska, including that in
ANWR, currently meets all National Ambient Air Quality Standards (NAAQS) and
would likely continue to do so even with ANWR development. Areas such as
ANWR (i.e., those that meet the NAAQS) are regulated under the Prevention of
Significant Deterioration (PSD) requirements of the Clean Air Act. The PSD

program requires pre-construction review and permitting of major new sources of
pollution to determine the impact of projected emissions, and the imposition of Best
Available Control Technology on emission sources.
Emissions and Expected Air Quality. Oil field operations – and the
natural-gas-fired turbines and heaters associated with them in Alaska – generate
significant amounts of air pollution. The power facilities needed to support
operations on the North Slope are quite large: according to BPAlaska, the Central
Compression Plant at Prudhoe Bay has turbines capable of generating the equivalent
of 429 megawatts of electric power – enough power for a city of 150,000 people.108
Even though it burns relatively clean fuel (natural gas), the North Slope complex
emits an estimated 63,786 tons of air pollution per year.109 Nitrogen oxide emissions,
which account for more than two-thirds of the total, are “2-3 times the amount
emitted by Washington, DC.”110
Despite these emissions, as noted, air quality on the North Slope of Alaska,
including that in ANWR, currently meets all National Ambient Air Quality
Standards. Annual concentrations of nitrogen dioxide, measured at three monitoring
stations in the Prudhoe Bay field, were, in fact, 70% to 90% below the NAAQS in
each of the years 1996-2000. Emissions of other criteria pollutants were also within111
Potential emissions from ANWR sources were discussed in the Final Legislative
Environmental Impact Statement (completed in 1987, and not subsequently updated).
The FLEIS concluded that the likely effect on air quality of the full leasing and
development alternative would be minor.112 It also noted that while “it is difficult to
predict the impacts on air quality in the 1002 area without knowing the scope, timing,
and location of oil development,” which is impossible to predict without further
exploratory activity, “The maximum annual emissions from the 1002 area would
probably be analogous with present North Slope operations.”113
PSD Regulatory Structure. Facilities in the 1002 area would be subject to
the Clean Air Act’s Prevention of Significant Deterioration rules. The PSD program
is designed to protect air quality where ambient concentrations of pollutants are
better than required by National Ambient Air Quality Standards. Pollutants subject
to PSD requirements are particulate matter, sulfur oxides, and nitrogen oxides. Of

108BP Environmental Performance Report, 2001, Part 3, Status of Environmental Protection,
p. 3-19, available at [].
109Personal communication, Don Bodron, Alaska Department of Environmental
Conservation, January 9, 2002.
110Steven Brooks, atmospheric scientist, National Oceanic and Atmospheric Administration,
Oak Ridge, TN, as cited in Janet Pelley, “Will Drilling for Oil Disrupt the Arctic National
Wildlife Refuge?” Environmental Science & Technology, June 1, 2001, p. 244A.
111BP Environmental Performance Report, 2001, previously cited.
112U.S. Department of the Interior, ANWR FLEIS, previously cited, p. 166.
113Ibid., pp. 198, 112.

these, only the nitrogen oxide increment114 is expected to pose any challenge to the
development of the 1002 area.
Under the PSD program, the type of area affected by a proposed facility’s
emissions determines the amount of air quality degradation to be allowed. All
international parks, national parks larger than 6,000 acres, and most wilderness areas
larger than 5,000 acres are mandatory Class I areas – those for which the least
increment of pollution is allowed. Facilities affecting Class I areas may increase
annual ambient concentrations of NOx by only 2.5 :g/m3 – 2.5% of the NAAQS.
ANWR, and specifically the 1002 area, are not Class I areas, however: the 1002
area has not been designated wilderness, and the remainder of ANWR, while it is
officially wilderness, was not designated so until after the statute establishing the
PSD program was enacted. Thus, like most other areas of the United States, ANWR
is a Class II area. In such areas, new facilities may increase concentrations of NOx
by 25 :g/m3, 25% of the NAAQS – 10 times the amount allowed if the area were
designated Class I.
Even this allowed increment could pose constraints for full ANWR
development. In establishing the PSD increments for nitrogen oxides in 1988, the
Environmental Protection Agency (EPA) made specific note of their potential impact
on the North Slope, stating that “certain Class II areas such as Prudhoe Bay, Alaska,
have ambient concentrations as much as 40 :g/m3 higher than in 1980,”115 which
exceeds the 25 :g/m3 increment adopted. If the FLEIS is accurate in projecting NOx
emissions from full development of ANWR as analogous to levels observed at
Prudhoe Bay, emissions might exceed allowed levels unless additional pollution
control measures are adopted.
Major new sources of air pollution in PSD areas must undergo preconstruction
review and must install Best Available Control Technology (BACT). State
permitting agencies (in this case, the Alaska Department of Environmental
Conservation) determine BACT on a case-by-case basis, taking into account energy,
environmental, and economic impacts. More stringent controls can be required if
modeling indicates that BACT is insufficient to avoid violating an allowable PSD
increment or the NAAQS itself. Thus, the permitting process should ensure that
ambient concentrations of NOx increase no more than 25% of the NAAQS level.
Arctic Haze. Another air quality concern that was much discussed when
ANWR development was first considered in the 1980s is a phenomenon known as
arctic haze. Beginning in the 1950s, arctic observers have noted the presence in late
winter and early spring of persistent bands of haze that reduce visibility and change
the color of clear skies from deep blue to a pale blue or hazy gray. The haze consists
of suspended particles, primarily sulfates, that originate in Europe and the former

114Allowed levels of pollution in the PSD program are termed “increments” because the
standards specify maximum incremental concentrations of pollution to be allowed. The
specific increments for NOx are discussed later in this section.
115Prevention of Significant Deterioration for Nitrogen Oxides, Proposed Rule, 53 Federal
Register 3706, February 8, 1988.

Soviet Union.116 The arctic’s cold, dry air, with little precipitation and weak sunlight,
produces remarkably stable air masses in winter and early spring, allowing the
particles to remain airborne for weeks at a time and to spread thousands of miles
from their point of origin.
Arctic haze appears to be less of a concern at present than it was in the 1980s.
With the breakup of the former Soviet Union and the closure of many of the most
heavily emitting industrial facilities in Eastern Europe and Russia, the haze has
declined by as much as 50% since the mid-1980s.117 Emissions from Alaska’s North
Slope appear to contribute relatively little to the problem.
Water Resources and Wetlands. Issues of concern for potential oil
exploration and development in the 1002 area are the availability of water supplies
and the impacts of production activities on the water and wetland resources of the
area. Large amounts of water are needed for drilling and ancillary activities, such as
ice roads and airstrip construction, as well as domestic use.
Description of the Resource. According to the 1987 FLEIS, free water is
limited in the 1002 area and is confined to the surface and the shallow zone of soil
located above the impermeable permafrost layer. The refuge receives an average of
6 inches of precipitation annually. A study done in 1989 found 255 lakes, ponds, and
puddles within the 1002 area. Most lakes are shallow and freeze solid in winter.
Less than 25% were deeper than 7 feet, and only 8 contained enough unfrozen water
to build a mile or more of ice road.118 A number of rivers and streams exist in the
1002 area, most draining to the coast and the Beaufort Sea; these too are also usually
According to the FLEIS, 99% of the 1002 area is classified as wetlands, which
are transitional lands found between terrestrial and aquatic systems where the water
table usually is at or near the surface, or the land is covered by shallow water. Arctic
wetlands are different from those in the Lower 48 states, however. In warmer areas
outside of Alaska, wetlands play a significant role in floodwater storage, lateral water
movement, groundwater recharge, and sediment and erosion control. But in the
arctic area, the permafrost layer impedes drainage and prevents many of the processes
normally attributed to wetlands from occurring, because most arctic wetlands are not
hydrologically linked to underground aquifers. However, this thin surface layer of
soil and rock, located above the permanently frozen layer, is the area where the
processes that sustain life in the arctic occur, including the cycle of freezing in winter
and thawing in the brief summer and where biological activity of micro-organisms

116Leonard A. Barrie and Jan W. Bottenheim, “Sulphur and Nitrogen Pollution in the Arctic
Atmosphere,” in W.T. Sturges (ed.), Pollution of the Arctic Atmosphere (New York:
Elsevier Science Publishers, 1991), p. 173, 177.
117John Ogren, NOAA Climate Monitoring and Diagnostics Laboratory, Boulder, CO,
“Measurements of the Climate-forcing Properties of Atmospheric Aerosols,” Slide 18, at
[ ht t p: / / www.cmdl aer o/ pubs/ s em/ ogr en/ M exi c o_980123/ sl m] .
118Gibbs, “The Arctic Oil and Wildlife Refuge,” p. 68.

and growth of plant roots take place.119 Plants that grow in the perpetually saturated
soils of the area include sedges, grasses in flat areas, and tiny shrubs and dwarf trees
in the foothills and uplands.
Water availability is cyclical during the year. In the spring, rapid snowmelt
occurs throughout the area, and melting snow flows to rivers because it does not
penetrate the permafrost. Rivers run full, riverbanks are severely eroded by ice and
snow, and there is extensive spring flooding. Turbidity from suspended sediments
is high, which impairs water quality. In summer and fall, rain follows, which can
also lead to flooding. But at the time of freezeup in the fall, low water supply
conditions prevail. Most rivers go dry or freeze to the bottom, and streamflow ceases
during winter except below a few warm springs.
Currently, water quality conditions in the 1002 area are not affected by human
activity. While the state does not have extensive information about water quality in
the vast majority of Alaska’s watersheds, because they are not actively monitored,
most are presumed to be in relatively pristine condition – including the 1002 area –
due to the state’s size, sparse population, and general remoteness. As of 1987, no
data were available on water quality below the permafrost in the 1002 area, but the
water beneath it is probably brackish, according to the FLEIS.
Effects of Oil Exploration and Development. The 1987 FLEIS identified
the use of limited fresh water sources for industrial purposes as having the potential
for major adverse effects, if exploration and development of the 1002 area occur. It
estimated that one exploratory well could require 15 million gallons of water: 7 to 8
million gallons for construction and maintenance of an airstrip; 1.2 to 1.5 million
gallons per mile for road construction and maintenance; and 1.7 to 2 million gallons
for drilling operations and domestic use. Despite technological improvements and
a smaller “footprint” for oil and gas operations in the arctic today (discussed below),
estimates of water requirements are generally the same as presented in the FLEIS.
These water supply needs result from the fact that ice is the construction
material of choice for the winter exploration season to make temporary roads, winter
airstrips, and drill pads, in preference to mining of gravel (discussed below). This
is done by spreading 6 inches of chipped ice from rivers and lakes, then spraying the
area with fresh water to make temporary roads and pads that melt in the spring.
When they melt, they leave no significant damage to the tundra. Road construction
techniques have evolved since early days of oil activity in the arctic. Temporary ice
roads now allow construction of oil field pipelines during the winter months, thus
largely eliminating the need for permanent gravel roads adjacent to pipelines.120
A source of water for ice roads, airstrips, and drill pads would need to be
located, but there is little evidence on whether North Slope rivers and lakes can
support the amount of water used by oil fields. One FWS hydrologist suggests that

119British Petroleum Corp. “Exploring Alaska: Alaska’s Terrestrial Environment.”
[ ronment/env.htm]
120British Petroleum Corp. “Exploring Alaska: Ice Roads and Pads.”
[] .

drawing too heavily from deep lakes would diminish the aquatic species that are food
for migratory waterfowl; heavy withdrawals from the Canning River, which flows
freely in winter for many miles below warm springs, could harm overwintering
fish.121 The deepest river basins are near the mouths of the Canning and Jago Rivers;
if the brackish water from these basins were used for ice roads, the result could be
harm to tundra vegetation when the ice melts in the spring.
Because the Refuge has few deep lakes or lakes that do not freeze solid in
winter, it is believed that there is only enough water in the 1002 area for less than 50
miles of ice roads.122 To meet water needs, alternatives that might be considered
include creating water reservoirs by excavating deep pools in conjunction with gravel
removal. Overflow during spring runoff would fill the basins, and the accumulated
water could be used for construction. With sufficiently deep basins, habitat could be
created for overwintering fish. If economic quantities of oil were not found, basins
might be left in place, or it would be necessary to find clean gravel to fill in the
basins. Riparian habitat is heavily used by musk oxen in winter, and siting of
facilities in riparian areas (with or without oil discovery) would likely to be an issue.
Companies might also melt lake and river ice and snow, or desalinate marine
water. Oil companies also might consider transporting water by truck from existing
developed areas, such as Prudhoe Bay, although the economics of doing so for long
distances could be impractical. Another possibility is that oil companies might revert
to building gravel roads for exploration and production, as in the past elsewhere on
the North Slope.
On the North Slope today, most wastes associated with drilling, as well as
sewage and garbage, are injected in dedicated disposal wells, rather than in waste
pits, which greatly reduces surface impacts and water pollution incidents. The oil
industry has improved both technology and practices to prevent and clean up
accidental releases that could harm the surface layer and water. However, critics are
concerned about the possibility of spills of various substances, including waste oil,
acid, ethylene glycol, and drilling fluids, especially given the relatively few lakes and
streams in the 1002 area. Even small spills, if not cleaned up, can affect lakes and
streams, for example if a spill on an ice pad melts in the spring. The primary impact
of contaminated water is its potential to reduce oxygen availability in receiving
waters, plus possible toxicity of the waste.123 Critics also are concerned that leaks
and spills of oil, fuel, chemicals, or brine could contaminate soils, thus killing
vegetation and resulting in scattered small habitat loss. In addition, they are
concerned about the environmental standards which would have to be met for
development on these federal lands.

121ANWR chief hydrologist Steve Lyons, cited in Gibbs, “The Arctic Oil and Wildlife
Refuge,” p. 68.
122Pelley, Janet. “Will Drilling for Oil Disrupt the Arctic National Wildlife Refuge?”
Environmental Science & Technology, June 1, 2001: 244A. (Hereafter referred to as Pelley,
“Will Drilling for Oil Disrupt ANWR?”)
123British Petroleum Corp. “Water.”
[ hs e_perform/env/water/index.asp]

Regulatory Setting. If oil exploration and development were to occur in the
1002 area under current law, a regulatory regime that is carried out both by federal
and state agencies would apply to water quality protection. Federal laws applicable
to activities taking place in the 1002 area include the Clean Water Act, Safe Drinking
Water Act, Rivers and Harbors Act, Coastal Zone Management Act, and the Ocean
Dumping Act. In Alaska, permits required by federal laws are issued by federal
agencies, especially the Environmental Protection Agency (EPA) and the U.S. Army
Corps of Engineers (Corps).
The state of Alaska has limited separate regulatory authorities and requirements.
One important role that the state plays is in establishing water quality standards to
protect waters within its jurisdiction, as required by the federal Clean Water Act
(CWA). Alaska’s statewide standards apply to surface waters and to groundwater,
at the state’s discretion, and include specification of designated uses (such as use for
water supply or recreational purposes), numeric and narrative criteria, and general
policies to ensure protection of the designated uses. State standards do currently
apply to waters throughout the state, including the 1002 area. Any permits written
by federal or state agencies must provide that state water quality standards will not
be violated. In addition, the state requires development of oil discharge prevention
and contingency plans for exploration or production facilities and proof of financial
responsibility to ensure that owners and operators maintain adequate financial
resources to respond to any spill and mitigate environmental damages. The state’s
Department of Fish and Game also would conduct a review of any proposed project
for possible impacts on anadromous fish.
There is little public information available concerning oil industry compliance
with state water quality standards, permits, and other environmental requirements.
The industry believes that as a result of improved technology and operating practices
– especially in recent years – its environmental performance in the arctic is good.
Critics, however, point out that data compiled by the Alaska Department of
Environmental Conservation demonstrate that on average several hundred spills of
hazardous substances, refined oil products, and crude oil occur each year at existing
North Slope operations, and some argue that the oil industry should not be allowed
into the 1002 area until it fixes chronic problems with leaky and poorly maintained124
physical structures.
The Clean Water Act requires that facilities must obtain permits which authorize
discharge of processed wastewater. These permits, issued in Alaska by EPA,
establish specific limitations on pollutants in industrial waste or sewage that may be
discharged from any facility to waters of the United States, as well as general
requirements such as monitoring and reporting. CWA permits for oil and gas
operations in the arctic typically require Best Management Practices (BMP) plans
which focus on pollution prevention rather than end-of-pipe discharge limits through
specification of structural and operational controls, maintenance, and inspections.
Outside of the 1002 area, EPA has issued a general permit for onshore and offshore

124Pelley, “Will Drilling for Oil Disrupt ANWR?” p. 43A. Reports and data on spills can
be found at:
[ ht t p: / / www.s t a t e .a / l oc a l / a kpa ge s / ENV .CONSERV / ds pa r / pe r p/ da t a ne ws .ht ml ]

oil and gas extraction in Alaska that covers rest of the North Slope Borough. It
provides general authorization to different facilities having similar discharges for
such activities as discharges from ice roads constructed of gravel pit water,
discharges of sanitary and/or domestic wastewater from covered facilities, and
construction dewatering. The general permit application process is streamlined,
because individual sources covered by a general permit do not need to apply to EPA
for a source-specific permit; if they file a Notice of Intent and meet certain other
qualifications, they can be covered by the general permit. The current general permit
was issued in 1997 and extends to April 10, 2002. It is possible that EPA would also
choose to issue a general permit for any activities in the 1002 area.
EPA also issues CWA permits for stormwater discharges of uncontaminated
rainwater and snowmelt. Arctic drilling and production pads do not have
conventional storm drains, as in other parts of the country, so stormwater discharges
are in the form of surface runoff during the spring thaw season. Stormwater permits
focus on plans to prevent releases of contaminated runoff to waters of the United
The Safe Drinking Water Act (SDWA) authorizes a program to protect
underground sources of drinking water (USDWs) from contamination by injection
through wells. In Alaska, primary responsibility for regulation of injection wells
through this program is split between EPA and the Alaska Oil and Gas Conservation
Commission (AOGCC). EPA issues permits authorizing subsurface injection of non-
hazardous industrial wastes associated with oil exploration and development, while
the AOGCC issues permits for wells used for injection of fluids brought to the
surface from oil and gas production operations or liquid hydrocarbons which are
stored underground. Injection of fluid wastes which cannot be recycled is preferred
to the discharge to surface disposal pits or ponds. Underground injection is to be
conducted so as to protect USDWs. However, in existing oil production areas on the
North Slope, EPA has determined that there are most likely not any aquifers beneath
the permafrost which are fresh enough to qualify for protection as USDWs. Thus,
the agency has granted several waiver requests from oil companies authorizing
underground injection with less stringent requirements than normal. This could be
a precedent for ANWR, as well.
Separate from the CWA discharge permit program administered by EPA, §404
of the CWA also contains a permit program administered by the U.S. Army Corps
of Engineers under which advance approval must be obtained for discharges from
any project that involves dredging or filling of the nation’s waters, including adjacent
wetlands. Because of the extent of wetlands in the 1002 area, these requirements are
likely to apply to nearly all oil exploration and development activities that might
occur onshore. In addition, the Rivers and Harbors Act of 1899 requires permits
from the Corps for construction of any dam or dike in a navigable waterway or any
structure in or over any navigable waterway, if the structure affects the course,
location, or condition of the waterbody.125 If docks or offshore navigational
components of facilities to transport people and materials to and from the 1002 area

125Given the rapid snowmelt and high streamflow in rivers that occurs in the spring,
constructing bridges could present significant challenges.

were constructed, permits under this authority as well as the CWA would likely be
Another permit provision that could arise is contained in the Marine Protection
Research and Sanctuaries Act (Title I known as the Ocean Dumping Act), which
requires a permit from the Corps for the disposal of dredged material in the territorial
seas, for example, for disposal of material dredged in the construction of channels in
open seas needed to get to shore facilities. In carrying out its regulatory
responsibilities, the Corps evaluates projects through a public interest balancing
process, considering the public benefits and detriments of all relevant factors
including conservation, economics, aesthetics, wetlands, cultural values, fish and
wildlife values, and navigation. Further, the Corps shares jurisdiction with other
agencies. For example, the Corps uses environmental guidelines issued by EPA to
evaluate impacts of a proposed discharge and consults with other federal and state
agencies before issuing permits.
The Coastal Zone Management Act (CZMA) requires certification by states that
projects to be located in a state’s coastal zone are consistent with the state’s coastal
zone management program. The CWA requires a similar state certification
concerning compliance with state water quality standards. Both would presumably
apply to oil exploration and development activities. According to EPA officials,
however, in part because of resource limitations, the state of Alaska frequently
waives CZMA and CWA certification, rather than using that authority to impose
environmental conditions on projects.126
Waste Disposal. Oil exploration and drilling result in the generation of
several waste streams. There are also small quantities of solid and hazardous wastes
associated with daily living activities and with running an industrial complex. The
Resource Conservation and Recovery Act (RCRA) governs the generation, storage,
transportation and disposal of hazardous wastes, and in Alaska the program is carried
out by the U.S. EPA. Nonhazardous and RCRA-exempt solid wastes are regulated
by the Alaska Department of Environmental Conservation (ADEC).
The hazardous wastes come from maintenance shops, laboratories, and other
support activities. The largest categories are paint wastes, solvents, miscellaneous
chemicals (particularly from laboratories), crushed light bulbs and bases, and rags,
sorbents, and filters. There are no commercial facilities in the state for disposal of
hazardous wastes, and they must be stored in secure areas before shipment to RCRA-
permitted facilities in the lower 48 states.
RCRA-Exempt Wastes. EPA has determined that oil and natural gas
exploration and production wastes constitute a high-volume, low-toxicity waste
stream that would be better managed outside the RCRA hazardous waste regime.
The ADEC regulates these drilling fluids, produced waters, and other wastes.

126Personal communication with Ted Rockwell, U.S. EPA, Anchorage, Alaska, Dec. 19,


In the past, drilling wastes were placed in surface impoundments called “reserve
pits,” but they have several disadvantages: they take up a great deal of space, making
the well pad’s footprint larger; they require continuous fluid management,
maintenance, and monitoring to prevent releases of metals, salts, and other
contaminants into the environment; and, when closed down, may require years of
environmental monitoring. Today these wastes are ground up and injected into
dedicated disposal wells 5,000 - 8,000 feet deep.127 The ADEC regulates
underground injection wells, as discussed above in Water Resources and Wetlands.
The wells are only allowed in areas where there is no underground source of drinking
water, or where aquifers are too deep or briny for development. Grind and inject
technology has ended the use of reserve pits for permanent disposal.
Minimization and Recycling. The companies on the North Slope employ
waste minimization and recycling programs to reduce the volume of solid waste.128
One of the waste streams is drilling muds – mixtures of natural clays and weighting
materials with small amounts of specialized additives that serve to lubricate the drill
bit, remove cuttings from the well bore, and control the pressure in the well. As the
mud circulates back to the surface, cuttings and other solids are removed, and the
muds are reused; this recycling can reduce mud requirements by 50 % or more.
During drilling operations, each well can generate up to 8,000 barrels of muds and
cuttings. Cuttings from the upper strata are washed and used as gravel for
construction of roads and pads. The remaining cuttings are ground fine and injected
in a slurry in a permitted disposal well along with other production wastes.
Surface discharges of sanitary and domestic wastewater (black and gray water)
have been eliminated at some facilities by injecting them in disposal wells or using
them for enhanced oil recovery (EOR). Other nonhazardous and RCRA-exempt
liquids that might otherwise be discarded may also be used for EOR. Used oil from
vehicles and equipment is collected at several North Slope facilities. It is blended
into the crude oil and sent to refineries.
In conjunction with the Federal Trade Commission’s approval of the sale of
ARCO Alaska to the Phillips Petroleum Company in 2000, an agreement between
the State of Alaska and the companies operating on the North Slope was reached.
Called the “Charter for the Development of the Alaskan North Slope,” it contained,
among other things, several environmental provisions committing British Petroleum
and Phillips Petroleum to clean up selected existing and abandoned sites, retrieve and
dispose of abandoned empty barrels, and close inactive reserve pits.129

127Pelley, “Will Drilling for Oil Disrupt ANWR?” p. 243A.
128British Petroleum Corp. “BP and the Environment on Alaska’s North Slope.”
129“Alaska at Peace with BP Amoco Concessions,” Gas Daily, December 3, 1999; Mary
Pemberton, “DEC: BP and Phillips Keeping Environmental Promises on North Slope,”
Associated Press State & Local Wire, March 28, 2001; and Alaska. DEC. Alaska
Department of Environmental Conservation’s Report on the Charter for Development of the
Alaskan North Slope. March 2001. 8 p. Available at:
ht t p : / / at l o cal / a kp ages/ ENV .CONSERV / pubs/ c har t er 7web.pdf

These cleanup activities are testament to the uneven environmental record of the
past. And as recently as the year 2000 British Petroleum (BP) paid $7 million in civil
and criminal penalties and agreed to spend $15 million to carry out a nationwide
environmental management system as a result of a contractor’s illegally disposing
hazardous waste for at least 3 years, and of BP’s failing to report it immediately on
discovery.130 Technical advances and heightened sensitivity on the part of the
operators to the need for careful operation in the arctic environment offer an
optimistic outlook, but the possibility of an accident or deliberate violation of a waste
disposal permit or regulation always exists.
Land and Gravel Use. Gravel is a necessary component of exploration and
development activities on the North Slope, and gravel suitable for these activities is131
a relatively valuable resource there. However, with the higher velocities of rivers
in the narrow coastal plain of the 1002 area, gravel is more abundant than in the
broader, developed portion of the coast plain to the west. Gravel roads and pads are
constructed by piling gravel on top of tundra to provide a base for aboveground
structures and to insulate the permafrost that lies just below the surface. The mining
of gravel from streambeds and floodplains for such purposes can alter natural river
drainage and cause increased erosion and sedimentation. Vegetation covered with
layers of gravel dies, subtracting its resources from the food web of the ecosystem.
In addition, dust blown from the gravel structure may affect freezing and thawing of
nearby vegetation, as may any material washed from the gravel surface. The blown
dust might convey some unexpected benefits: dust kicked up from gravel structures
may cause earlier snow melt. Early melting stimulates plant growth, and could
provide earlier foraging areas for waterfowl. Possible contamination of the dust with
wastes might counter benefits, however.
The need for gravel for activities in the 1002 area, if development occurs, is
likely to be much less than that for earlier years of oil development in existing areas
for several reasons. First, gravel previously was used as the base for nearly all road
and pad construction, but today it is likely to be used only for permanent roads and
pads because ice is the preferred construction material for temporary roads and pads
(although the availability of adequate supplies of water is an issue for development
of the 1002 area; see Water Resources and Wetlands, above). Second, gravel
previously was mined to create reserve pits that held drilling muds and other
produced wastes. Today, however, nearly all wastes are recycled, reused or disposed
by underground injection, thus greatly reducing the need for reserve pits. Third, even
where used for drilling pads, the amount of gravel needed will be less because of the
smaller overall footprint of sites.
If development in the 1002 area followed the pattern at Alpine, it would be, if
not entirely roadless, then road-reduced, compared to older developments. Alpine
is not connected by road to older facilities, but the development includes a 3-mile

130U.S. Environmental Protection Agency. “British Petroleum (BP) Exploration Alaska
Sentenced in Hazardous Waste Case.” February 10, 2000. See: CM .NSF/28100b370f14993688256500005dcdf2/1eff2f

7433b0da66882568b000745a01?OpenDocume nt.

131BP Environmental Performance Report, 2001, previously cited: 3-39.

road (14.6 acres) and a 36.3-acre airstrip. (See Figure 4.) The latter forms part of the
road connecting the 2 pads.132 The road and airstrip constitute about 52% of the total
permitted acreage. If anything like this pattern holds in a modern scenario, it would
represent a very substantial reduction in the miles of roads relative to earlier
However, it is not clear whether roadless development along the Alpine model
would be economic in ANWR. According to a recent report, current leaseholders at
the Badami oil field (25 miles further east than the current easternmost permanent
road on the North Slope, and about 25 miles west of the 1002 area) are seeking a
permanent road to field.133 The leaseholders argue that the leases are not economic
without a year-round road. They seek state funding for the creation of this road. If
such a road were built, the Badami area would represent the nearest staging area to
the 1002 area. Thus depending on whether the Badami road is built, development in
the 1002 area would require either construction of an additional 25 or 50 miles of
gravel road up to the refuge boundary, plus ice roads into the 1002 exploration sites.
Proponents of state construction of the Badami road estimate that it would cost $50-
60 million. Similarly, the three most extensive of 5 development scenarios in one
recent model assume the presence of a road, parallel to a pipeline, as well as a
connector road to Kaktovik, in the 1002 area.134 The absence of a gravel road linked
to currently developed areas would add to the cost of development of ANWR,
potentially making some prospects uneconomic or adding to pressure to build gravel
roads outside or inside the 1002 area. (On the other hand, a variety of factors,
including higher oil prices, could mean that such costs would not be prohibitive.)
Caribou cows in existing oil fields with calves younger than a few weeks old
(roughly, during June in most years) are known to avoid roads, pads, and other areas
around human activity; avoidance during this early period extends well beyond the
footprint of facilities, especially in early years of oil development.135 (See also
Caribou, above.) If road mileage were reduced, impacts on calves at this sensitive
time could be lowered. In ANWR, as calving ends in early June, and as the
Porcupine Caribou Herd (PCH) tends to move to the coast and the western portion
of the 1002 area for insect relief, roads or runways oriented across the path of travel
could be expected to disrupt the cows’ movement more than those oriented roughly
parallel to it. If calving were displaced to the foothills, greater predation would
apparently result; if foraging is displaced from prime areas, weight loss in cows could

132U.S. Army Corps of Engineers, Alaska District, Permit Evaluation and Decision
Document, Alpine Development Project, Colville River 18 (2-960874) p. 2 (February 13,


133Cashman, Kay. “Winstar wants year-round road to Badami; ice roads too costly”,
Petroleum News Alaska. April 7, 2002. p. 1.
134Tussing, Arlon R. and Sharman Haley. “Drainage pierces ANWR in Alaska study
scenario.” Oil and Gas Journal, July 5, 1999. p. 71-85.
135C. Nelleman and R. D. Cameron, “Cumulative impacts of an evolving oil-field complex
on the distribution of calving caribou,” Canadian Journal of Zoology, Vol. 76 (1998): p.


result in reduced survival rates in calves.136 On the other hand even in June, some
animals (primarily males and yearlings) use pads, roads, and runways for insect
relief, and so may congregate in these areas. Later in the summer, when calves are
older, some cow-calf pairs may join them.
Consequently, interpretations of impacts based on the CAH must be made
cautiously, due to the differing concentrations of the herds and the differing
availability of similar calving areas.137 If road mileage were limited, impacts would
probably be lowered. Conversely, if roads were not limited, or if economic necessity
later resulted in a change in this restriction, impacts on the PCH or other species,
such as tundra swans (which tend to avoid nesting within 200 meters (about 650 feet)
of roads), could be greater. (See also Biological Resources: Status and Effects,
Changing Footprint Estimate: 1987 vs. 2001. There has been
considerable focus in recent years on the reduced footprint that seems likely in any
1002 development, given advances in exploration, development, and production
technologies, as well as the possibility of added congressional restrictions on
environmental impacts. It may be useful to compare those features considered in the
footprint as described in the 1987 FLEIS, and how that might differ from a scenario
predicated on modern technologies. In 1987, the FLEIS described the assumptions
built into its full development scenario:
For the sake of maintaining data confidentiality, [the full development
scenario] shows a highly generalized placement of production and
transportation facilities based on typical North Slope prospect
characteristics for three localities within the 1002 area. This assumes
successful exploration in all three localities. Actual placement of oil
production facilities and marine facilities on the 1002 area, or location of
the trunk pipeline from producing fields to TAPS Pump Station 1, depends
upon site-specific geotechnical, engineering, environmental, and economic
data that can be determined only after a specific prospect has been drilled,138
and a discovery made and confirmed.
The features considered in the FLEIS (on p. 99) are shown in Table 4, along
with the estimate given at that time for the space or miles that would be occupied by
the feature in a full development as hypothesized by the FLEIS. The third column
shows, in qualitative terms, how modern technology would probably change the
estimate provided in 1987, assuming the same full development scenario. The
highlights of the comparison are as follows.
Some features would very likely or probably be reduced in total acreage or
mileage; a few might even be eliminated. These are:
!spur roads with collecting lines, connecting (fewer) pads in a given oil field,

136Gibbs, “The Arctic Oil and Wildlife Refuge”, p. 69.
137Gibbs, “The Arctic Oil and Wildlife Refuge”, p. 69.
138FLEIS, p. 98. The full set of assumptions is given on pp. 97-98.

!large permanent airfields (supporting an entire area, as at Deadhorse or
!permanent drill pads,
!pits for gravel mines (borrow pits),
!major river or stream crossings (given fewer roads),
!main road paralleling main pipeline (possibly no such road), and
!large central processing facility, as at Deadhorse or Kuparuk (possibly no such
In other instances, new technology might actually increase the demand for
acreage devoted to some features:
!marine and saltwater treatment facilities, due to greater modern demand for
water (but possibly substituted with smaller plants for fields near coast), and
!small permanent airfields, enough for each cluster of pads not supplied by a
permanent road.
Assuming the same full development scenario as the FLEIS, some features
would probably remain the same:
!main oil pipeline within the 1002 area, and
!collecting lines from drill pads to main oil pipeline.
Finally, in some instances, it is simply unclear whether some features would be
!marine port facilities, to off-load barges and other heavy equipment,
!main road from marine facility.
In 1987, the FLEIS, in its hypothetical full development scenario, estimated that
the total acreage covered would be 5,330 to 5,980 acres. A comparison with a
scenario using modern technology suggests that the footprint (as defined by the
FLEIS in its table) would be smaller, but perhaps not markedly so. If, as suggested
by Arctic Power (a pro-development group cited earlier), full development of the
1002 area could be accomplished by building no more than 2,000 acres of facilities
(scattered appropriately around developed oil fields, and assuming the same oil fields
as the FLEIS), then either its definition of “footprint” is different from that used in
the FLEIS, or additional technological improvements may be required. It is the pads,
airstrips, pad supports, and connector roads that are typically considered when
development proponents have recently referred to limiting surface impacts to 2,000
acres; other features, such as pipelines, gravel mines and the like typically are not.139
While the technologies used would be affected by economics, direction by
Congress could specify higher or lower standards than those assumed in the table.
Moreover, development on Native lands is not considered in the table, since different

139Some development advocates do not include roads connecting the pads. For example,
Rep. Sununu, in an editorial discussing his amendment to H.R. 4 (adopted Aug. 1, 2001),
to limit total surface occupancy in future development of the 1002 area to 2,000 acres, said
his language did not include roads, saying that most roads in the 1002 area would be made
of ice (Manchester Union Leader, Aug. 20, 2001).

standards could apply. (For legal issues related to Native lands, see Alaska Native
Lands and Rights, below.)
Table 4. Comparison of the Estimated Number and Area of
In-place Oil-related Facilities: 1987 FLEIS and Modern
FacilityFLEIS FullSame finds, assuming Alpine-
Leasinglike technologies
Scenario (p. 99)
Main oil pipeline within100 mi (610probably similar for similar
1002 areaacres)locations of oil
Main road paralleling120 mi (730possibly 0 miles (0 acres)a
main pipeline (see noteacres)
Main road from marine(Included inUnclear if marine facilities
facilitiesabove row, nowould be builta
separate figure
Spur roads with160 mi (980Uncertain – fewer pads in a
collecting lines withinacres)production field, therefore
production fieldsprobably fewer in-field spur
roads for similar locations of
oila; collecting lines probably
Marine and salt-water2 facilities (200Unclear how many would be
treatment facilitiesacres)built, but demands on fresh
water sources possibly greater
than assumed in 1987
Large central production7 facilities (6300? (facilities incorporated into
facilitiesacres)one pad in each production
Small central production4 facilities (1600? (facilities incorporated into
facilitiesacres)one pad in each production
Large permanent2 airfields (2600?b
Small permanent2 airfields (60Many more – probably one for
airfieldsacres)each production fieldb

Permanent drilling pads50-60 padsProbably fewer per production
(1,200-1,600area, given greater reach of
acres) [averagemodern wellsb; most recent 2
size: 20-32pads (at Alpine) were 10 acres
acres]and 36 acres each.
Borrow sites (i.e., gravel10-15 pits (500-Uncertain, but probably fewer,
mine pits)750 acres)given fewer roads and fewer
pads c
Gravel for construction,40 - 50 millionUncertain, but probably less
operation, andcu yds
Major river or streamMaximum 25Uncertain, but likely fewer, due
crossingsto fewer roads
Total acres of surface5,330 - 5,980Probably less
Notes: Columns 1 and 2 are reproduced from the FLEIS with the modifications noted.
Column 3 assumes the same hypothetical oil fields as the FLEIS, and the use of modern,
Alpine-like technologies or better. The FLEIS table gave one figure for all main roads; this
number is broken into two parts here, since an Alpine-like scenario is assumed not to have
a main road for a pipeline, but such technology may not necessarily preclude a marine
facility or roads associated with it.
a Facilities which at least some observers would likely count in current proposals to restrict
development to 2,000 acres (see text); unclear in some of the marked cases whether any such
structure would actually be built. Some argue that economics (cost of long-distance
transportation of heavy equipment or cost of repeated construction of ice roads) could force
eventual construction of a main road, especially if world oil prices do not increase.
b Facilities which most observers would likely count in proposals to restrict development to
2,000 acres (see text); unclear in some of the marked cases whether any such structure
would actually be built.
c In association with the Alpine development, the Corps of Engineers issued a permit to
Nuiqsut Contractors for a 150-acre gravel pit, though some portion of the gravel met needs
in the village of Nuiqsut, and the size of the permitted pit may have been designed to allow
expansion of the Alpine development to 2 additional satellite pads and associated connector
roads. It is unclear precisely what size of gravel mine would have been required to construct
only the current facilities at Alpine. Consolidation of gravel pits might occur, by digging
fewer, deeper pits, but no information was found on this possibility.
Sources: U.S. Dept. of the Interior, Fish and Wildlife Service, 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. p. 99.
U.S. Army Corps of Engineers, Alaska District, Permit Evaluation and Decision Document,
Alpine Development Project, Colville River 18 (2-960874). February 13, 1998. p. 2.
U.S. Army Corps of Engineers, Alaska District, Colville River 17 (2-960869). Alpine
Gravel Pit, Nuiqsut Contractors. June 23, 1997.

Effects on Tundra Surfaces. The 1002 area has a higher proportion of
rolling terrain than the flat, pond-rich Prudhoe Bay area. Vegetation may be exposed
by the wind and damaged as it is run over, especially where more hilly terrain could
make rolligon use difficult. In a more temperate environment, vegetation might
recover fairly quickly, but the intense cold and the freezing and thawing cycles of the
arctic environment can make recovery rates much slower. However, there is no
research to show whether this type of vegetational damage would affect foraging
The vegetation under ice roads and ice pads may be damaged, partly by
compaction, but also by being delayed in its spurt of growth in the brief summer.
Where all debris is removed and no spills have occurred, little effect has been141
observed. Where insulation is used to maintain an ice pad over a single summer,
damage appeared to be confined to areas around the edges of the pad, where some
thawing had occurred but no sunlight had reached the plants; evidence of
recolonization began to appear in two growing seasons.142
Port and Offshore Activity. The FLEIS assumed that 2 ports would be built
to support development in the 1002 area. It is unclear whether that assumption is still
likely. If water for ice roads is at a premium, port development could reduce the need
for long ice roads from the west. If port facilities were carefully sited and built
offshore, and connected to shore via causeways, and in turn to ice roads, they may
prove attractive for the staging and movement of heavy equipment. Offshore
facilities may also be considered for placement of heavy equipment such as water
treatment plants, since such placement could put them outside any 2,000 acre limit
on surface occupancy (if Congress were to impose such a limit). The reduction in
surface impacts would be traded for potential offshore impacts; in the FLEIS, the
focus of impacts from causeways was on fish migration. If ports were to be located
on Native lands, their regulation is unclear.
Aircraft Use. At Alpine, 6 to 8 aircraft, including large cargo planes, arrive143
daily. Reliance on aircraft for summer transport is essential if connecting roads are
to be eliminated. Effects on bird populations vary. Tundra swans appear to be144
affected only minimally by aircraft. According to the FLEIS (p. 132), snow geese
are “highly sensitive to aircraft disturbance” from flights at 100 ft to 10,000 ft, and
at 0.5 to 9 miles away. The geese appeared to habituate after several passes by
helicopters or fixed wing aircraft. The report also noted evidence that snow geese are
disturbed by traffic, noise, or other human activities and respond by taking flight en
masse. Regardless of source, sufficient disturbance would reduce available feeding
time, weight gain, and resulting vigor for the fall migration. The FLEIS cited control

140Gibbs, “The Arctic Oil and Wildlife Refuge.”
141Jay D. McKendrick, “Vegetative Responses to Disturbance”, in The Natural History of
an Arctic Oil Field. p. 43.
142Ibid. p. 43.
143Gibbs, “The Arctic Oil and Wildlife Refuge”, p. 68.
144Robert J. Ritchie and James G. King, “Tundra Swans,” in The Natural History of an
Arctic Oil Field, pp. 197-220.

of aircraft traffic as potential mitigation, but the development design examined in the
FLEIS did not contemplate the heavy reliance on aircraft (and assumed that only 2
large permanent airfields would be built under full development) that would be
essential if road mileage were substantially reduced.
Use of Resources by Non-Natives: Status and Effects145
The village of Kaktovik on Barter Island (see Figures 1 and 4) is the only
currently occupied human settlement in the coastal plain of ANWR. Aside from
Barter Island, topographic maps of the area146 show that it also contains 5 cabins, 2
ruins, 2 landing strips, 2 towers, 1 grave site, and 6 tractor trails. Of these 18
features, all are within 5 miles of the coast, except for one trail. Some of these sites
are the remains of facilities run by the Defense Department as part of the Distant
Early Warning Line (DEWLine; see below). In addition, as discussed below, the
remains of the drill pad and a protruding pipe mark the site of a closed exploratory
well on lands of the Kaktovik Inupiat Corporation (KIC well; see Alaska Native
Lands and Rights, below).
DEWLine and Kaktovik. Starting in the 1950s, the Defense Department
constructed a system along the arctic coasts of Alaska and Canada to provide early147
warning of a Soviet attack. Barrow served as a base for construction. Kaktovik
was designated as the site of a major installation, resulting in three relocations of the
village to accommodate the military facility, and concentration of the previously
more scattered Inupiat seeking job opportunities. Intermediate stations along the
coast in what is now the ANWR 1002 area were constructed (from west to east) at
Brownlow Point on the Staines River; Camden Bay, about 30 miles west-southwest148
of Kaktovik; and Beaufort Lagoon, about 30 miles southeast of Kaktovik. Only
the station at Kaktovik remained open in 1986. USGS maps (cited above) indicate
one tower, one landing strip, and both a landing strip and tower at these three sites
respectively. According to a 1986 report, “[a]bandoned materials include numerous
rusting steel fuel drums located primarily at Camden Bay and Beaufort Lagoon, but
also scattered along the coast and inland within the boundaries of ANWR.”149
Recreation Visits. There have never been large numbers of recreational visits
to this very remote Refuge. The peak was 886 visiting the entire Refuge in 1990,

145In addition, see Use of Resources by Alaska Natives, below.
146U.S. Dept. of the Interior, Geological Survey, maps for Demarcation Point, Mt.
Michelson, Beechey Point, and Flaxman Island. Scale: 1:250,000.
147The following history is condensed from U.S. Dept. of the Interior, Fish and Wildlife
Service, Final Report Baseline Study of the Fish, Wildlife, and Their Habitats, Vol. II
(Washington, DC: December, 1986), pp. 436-437.
148A fifth site in ANWR, Demarcation Point, lies between the 1002 area and the Canadian
149U.S. Dept. of the Interior, Fish and Wildlife Service, Final Report Baseline Study of the
Fish, Wildlife, and Their Habitats, Vol. II (Washington, DC: December, 1986), p. 437,
citing a 1979 memo by A. S. Thayer.

when development of the 1002 area was most recently broadly debated; visitor
numbers for 2001 are also high.150 Trips, starting from Fairbanks, usually cost
$2,000-$3,000, and may last 1 or 2 weeks. Usually, small groups of visitors are
ferried in light planes to a river bank where they are dropped off, traveling with or
without professional guides. Either way, they walk along or raft one of the many
rivers flowing northward to the coast where another plane picks them up, often
followed by a stop in Kaktovik before returning south to Fairbanks. In the right
season, the migrating caribou are part of the attraction and, in all seasons, so is the
solitude. One outfitter stated, “Where else can you spend 10 days floating a river,
and not see anyone at all?”151 In 2001, with the increase in controversy over the
Refuge’s coastal plain, the number of visitors has increased, but statistics are not yet
available. Under current conditions, given the remoteness of the Refuge’s coastal
plain, the solitude seems likely to remain one of the principal attractions for visitors,
while migrating caribou and other species will attract others.
Migratory Birds: Hunting and Birdwatching. As noted below, birds are
used by Inupiat subsistence hunters. Beyond the immediate ANWR area, use falls
into 2 additional categories: direct taking by hunters in many states of a number of
species, and “use” by birdwatchers in other states. It is difficult to assess the
economic impact of such uses and tie them to populations breeding or staging for
migration in the 1002 area specifically, since these species breed and stage in other
places as well. The tremendous number of snow geese breeding elsewhere, but
staging in the 1002 area, make the Refuge especially important to hunters of this
species. (A map showing annual migration routes of some birds nesting in ANWR
is at
Use of Resources by Alaska Natives
Alaska Natives are both participants in and subjects of the debate over ANWR.
Alaska Natives include Eskimos (Inuit and Yupik), Aleuts, and American Indians,
and make up over 15% of Alaska’s population. Alaska Natives participate in the
debate through many different groups and organizations. They are members of the
state’s 229 federally-recognized Indian152 tribes, which are political entities; they are
also citizens of the state and of their boroughs and municipalities (where organized);
and they are shareholders in Native village and regional corporations, which in some
villages and regions may include both non-profit and for-profit corporations. (See
box: Corporations and Boroughs, for a discussion of their origins.)
Among and within these groups and organizations, there is disagreement over
whether to open ANWR and the 1002 area to oil and gas exploration and

150FWS statistics, cited by Sam Howe Verhovek, “Mention Drilling, and Tourists Rush to
Alaska,” New York Times (June 10, 2001), pp. 1 and 24.
151Ibid. Carol Kasza, co-owner, Arctic Treks; quoted on p. 24.
152The federal government generally considers the terms Indian and Indian tribe to include
Alaska Natives.

One set of Alaska Native groups and organizations favors oil and gas
development in the 1002 area. This set is centered around North Slope Inupiat, who
are Alaskan Inuit. In northern Alaska, this pro-development set includes (1)
Kaktovik, the only Native village in ANWR, and its municipal government; (2)
Kaktovik Inupiat Corporation (KIC), the Native village corporation; (3) Arctic Slope
Regional Corporation (ASRC), the Native regional for-profit corporation for North
Slope Inupiat; and (4) the North Slope Borough government, the organized borough
within which Kaktovik is located.
Another set of Alaska Native groups and organizations opposes oil and gas
development in the 1002 area. This set is centered around a group of Gwich’in
Indian villages. The Gwich’in (also known as Kutchin) are Athabaskan Indians and
are situated in east-central Alaska and neighboring areas of northwestern Canada.
The anti-development set includes (1) two Gwich’in villages, Venetie and Arctic
Village, which are located in the Doyon region (an Athabaskan Indian Native region,
which overlaps the southern portion of ANWR), and the two villages’ tribal
government, called the Native Village of Venetie Tribal Government; (2) the
Gwich’in Steering Committee, composed of Venetie, Arctic Village, and 13 other
Gwich’in villages of Alaska and Canada; and (3) the Native regional non-profit
corporation for the Doyon region, the Tanana Chiefs Conference, Inc. However, the
Native regional for-profit corporation, Doyon, Ltd., favors oil and gas development
of the 1002 area.153 Unlike Kaktovik, the Gwich’in villages are not within an
organized borough.
The pro- and anti-development sets of Alaska Natives are of course not
monolithic. Not all Inupiat or North Slope Borough residents support oil and gas
development in ANWR or the 1002 area, and not all Gwich’in or Athabaskans
oppose it. Other local, regional, statewide, and national Native and Indian groups
and organizations support the position of one set or the other. The Alaska Federation
of Natives (AFN), the major statewide Alaska Native organization, favors oil and gas
development in ANWR and the 1002 area. Some Native critics of the AFN position
claim that the organization tends to represent the position of the for-profit Native
corporations, who are generally more supportive of 1002 development. The National
Congress of American Indians (NCAI), a major nationwide organization representing
Indian tribes, opposes oil and gas development in ANWR, but many Alaska Native
entities are not NCAI members.
The disagreement between the two sets of Alaska Natives often centers on the
effects of energy development on subsistence resources, especially the Porcupine
caribou herd. Both Kaktovik and the two Gwich’in villages make significant use of
the PCH. (See also Biological Resources: Status and Effects: Caribou, above.) In
both Inupiat and Gwich’in cultures, the millennia of dependence on subsistence
animals have created a complex set of practices and beliefs linking well-being and
identity to subsistence in general and to certain animals in particular. Threats to these
animals may thus be seen as threats to the very basis of Inupiat and Gwich’in

153See [], Nov. 1, 2001.

The disagreement is also greatly affected by ANILCA, which had several
provisions that ultimately allowed KIC to acquire surface lands – and ASRC to
acquire subsurface rights under these KIC lands – in the 1002 area and elsewhere on
the coastal plain within ANWR. (For fuller discussions, see Alaska National Interest
Lands Conservation Act, above, and Alaska Native Lands and Rights, below.) An
oil or gas discovery under KIC/ASRC land would enormously increase ASRC
revenues and hence the material benefits to Inupiats.

Corporations and Boroughs
The existence of Alaska Native corporations and boroughs, and their role in the
Native debate, is the result of the intersection of the Alaska Native Claims Settlement
Act of 1971 (ANCSA, P.L. 92-203, 85 Stat. 688, 42 Stat. 1601 et seq.) and Alaska state
law. ANCSA was enacted to settle Alaska Natives’ aboriginal land claims. The act
established 12 for-profit Native regional corporations and several hundred for-profit or
non-profit Native village corporations. Natives were to own shares in both regional and
village corporations. The regions were to be “composed as far as practicable of Natives
having a common heritage and sharing common interests” and especially were to follow
the regions represented by 12 existing Native associations. (Many of these 12 Native
associations became today’s non-profit regional corporations. At least one – the Inupiat
Community of the Arctic Slope – became a federally recognized tribe. Other regional
non-profits have been established since 1971.)
Both regional and village corporations were to own surface lands selected under
ANCSA. Only regional corporations, however, could own subsurface interests in
regional or village lands. Seventy percent of revenues flowing to regional corporations
from subsurface rights (and timber) were to be shared with other regional corporations.
ANCSA also abolished all but one of the few reservations that then existed in Alaska,
but village corporations on these few reservations could opt to forego regional
shareholdings and instead take direct fee title to the surface and subsurface of their
former reservations.
Today, many regional Native corporations have subsidiaries in the oil supplies and
services industries, as well as in other industries. Successful Native corporations have
been able to pass benefits on to their members in the form of employment and dividends.
Boroughs are county-like political units that originated from Alaska’s state
constitution and the state’s Borough Acts of 1961 and 1963. These laws required that
Alaska be divided into boroughs, which could be either “organized,” with varying levels
of powers, or “unorganized.” In 1972, a year after the passage of ANCSA, the North
Slope Borough was organized, with the power to levy property taxes. The North Slope
Borough’s subsequent tax income from oil and gas property has enabled it to carry out
a borough-wide capital improvement program, constructing schools, utilities, housing,
public buildings, and other facilities, and has also allowed it to provide extensive
services and to become one of the largest employers on the North Slope. Since the Arctic
Slope Native region nearly corresponds with the North Slope Borough, most Inupiat have
benefitted from North Slope Borough activities, and the Borough has been perhaps the
major conduit for oil development benefits flowing to the Inupiat. The Gwich’in,
however, have had no parallel source of benefits. Much of the Doyon Native region,
including the Gwich’in area, is not in an organized borough; the unorganized borough
has no taxing power and gets its services and public investment chiefly from the state.

Inupiat Use of ANWR and the 1002 Area. Kaktovik, the only Native
village in ANWR, depends greatly for subsistence resources directly on the 1002
area, the coastal plain in general, and other parts of ANWR, as well as on marine
resources off the coast of ANWR. Residents of the Inupiat village of Nuiqsut, about

175 miles west of ANWR, also make some subsistence use of the 1002 area.

Nonetheless, Kaktovik is the only Alaska Native village whose residents depend so
much on subsistence resources taken on the 1002 area. The FLEIS, citing studies
from the late 1970s and early 1980s, found that most Kaktovik households depended
on hunting, fishing, and gathering in ANWR for food, and that caribou, Dall sheep,
and bowhead whales (taken off the coast of ANWR) were their chief sources of meat,
although they also hunted numerous other types of mammals, birds, and fish.
Whaling has such great cultural and subsistence importance among Inupiat –
especially Kaktovik, which, under special rules for subsistence, is allowed to take one
to three endangered bowhead whales a year – that they oppose offshore oil and gas
exploration because they fear it may endanger their whaling. Kaktovik’s take of
caribou was estimated in the FLEIS to be about 100 caribou a year, 50-80% from the
PCH and the rest from the Central Arctic Herd (CAH) to the west. Most Kaktovik
caribou harvesting occurs in summer, during the PCH postcalving time, and much
of the harvest is in the 1002 area.
Some recent observers have suggested that Kaktovik has become somewhat less
dependent on subsistence hunting, even though the activity is still significant. They
suggest that paid employment has become so important that it restricts time for
subsistence hunting.154 Statistics from the 1990 census show that 72% of Kaktovik’s155
adults were in the labor force. Like other Arctic Slope villages, Kaktovik has
benefitted from the North Slope Borough’s programs, which has funded a modern
high school, housing, street lighting, a community hall, a power plant, and other
capital improvements.156 Kaktovik also benefits from state government activities
funded by North Slope oil development.
Many Kaktovik residents worry that a reduction in oil and gas development and
production will reduce their present standard of living, and most of them favor oil

154See, e.g., Impact Assessment, Inc., Subsistence Resource Harvest Patterns: Kaktovik:
Final Special Report (Anchorage, AK: U.S. Dept. of the Interior, Minerals Management
Service, Alaska Outer Continental Shelf Region, 1990); and Norman A. Chance, The Iñupiat
and Arctic Alaska: An Ethnography of Development (Fort Worth: Holt, Rinehart and
Winston, 1990).
155Go to [
1990_STF3_DP3&_geo_id=16000US021560] for these statistics. The Census Bureau
classifies persons who are either employed or unemployed but seeking work as being “in the
labor force.” Census respondents who list their occupation as “subsistence hunter” may be
classified by the Bureau in its “hunters and trappers” occupational classification, but no
persons were counted in this occupation in the Kaktovik data.
156Earl Lane, “Living in the Cold: Two Native Villages Differ on Oil Drilling; Both Share
a Harsh Existence,” Seattle Times, (May 21, 2001), p. A3; and David Foster, “Mixing Oil
and Wilderness,” Alaska (August 2001), pp. 30-37.

exploration and development in the 1002 area.157 Moreover, because they are
shareholders in KIC and ASRC, because they would be the closest Native village to
oil development in the 1002 area, and because exploration of the 1002 area may even
reveal oil in lands where ASRC owns the subsurface rights, Kaktovik residents might
be expected to benefit more than any other Alaska Natives from 1002 oil and gas
development. Moreover, through the actions by which ASRC acquired subsurface
rights to KIC lands in ANWR (see Alaska Native Lands and Rights, below), ASRC
was found by arbitration to be exempted from ANCSA’s requirement to share
subsurface revenues with other regional corporations, so dividends to ASRC
shareholders, including Kaktovik, might be even greater.
Kaktovik residents and other Inupiat supporting oil and gas development in the
1002 area argue that they are as concerned about the dangers to subsistence as the
opponents, but that they are experienced in caring for wildlife and the environment
and believe that development can be carried out without endangering subsistence
animals, including especially the PCH. Alaskan Inupiat who support ANWR leasing
have in their turn opposed or remained cool to offshore leasing on the grounds that
it might harm or drive off the bowhead whales on which they depend for cultural and
subsistence reasons.158 That is, both sets of Natives have opposed leasing in areas
commonly used by the resources on which they depend.
Gwich’in Use of ANWR and the 1002 Area. The Gwich’in do not hunt
within the 1002 area. They take caribou from the Porcupine herd in areas south of
the Brooks Range, inside and outside ANWR, during the fall, winter, and spring.
According to the FLEIS, Arctic Village in Alaska and Old Crow in Canada are the
two Gwich’in villages most involved in caribou harvesting (recent information
suggests Fort McPherson in Canada may now have a larger harvest than Old
Crow159). Other Alaska Gwich’in villages hunting PCH caribou are Venetie, Fort
Yukon, and Chalkyitsik; some of these also trade for much of their caribou meat.
These Gwich’in villages harvest more caribou than does Kaktovik. Caribou is the
main food source for Arctic Village, Venetie, and other Gwich’in villages. Arctic
Village, according to the FLEIS, harvested 200-1,000 caribou per year in the 1970s,
as did Old Crow, while the other Alaskan Gwich’in villages together took 300-400
a year and the other Canadian villages 100-2,100 a year. The Gwich’in also harvest
other animals as well as fish and birds. For the Gwich’in, caribou are by far the most
culturally important subsistence animal. They speak of themselves as “people of the
deer,” and traditionally the Gwich’in believed that people and caribou each had a bit
of the other’s heart in theirs.160

157Foster, ibid.
158Yereth Rosen, “Alaska Natives sue to block Phillips oil project.” Reuters (Dec. 19, 2000)
at [].
159[ ht t p: / / www.t a i / car i bou/ pch/ sl i des/ ml ] .
160Richard Slobodin, “Kutchin,” in Handbook of North American Indians, Vol. 6, Subarctic,
June Helm, vol. ed.; William C. Sturtevant, genl. ed. (Washington: Smithsonian Institution,

1981), pp. 514-532.

Arctic Village and Venetie have benefitted from Alaska’s oil and gas
development, but to a much lesser extent than Kaktovik. Arctic Village and Venetie
elected, under ANCSA, to forego regional corporation shareholdings and take private
fee title to their 1.8-million-acre reservation. After 1971, the reservation was first
held in joint ownership by the two villages’ village corporations, but in 1979 the
corporations transferred title to the villages’ tribal government, the Native Village of
Venetie Tribal Government (the land was not, however, restored thereby to the status
of an Indian reservation). Hence, because they had no shareholdings in Doyon, Ltd.,
the regional for-profit corporation, Arctic Village and Venetie residents have not
shared in any dividends flowing to Doyon shareholders. Moreover, the Alaskan
Gwich’in villages are not in an organized borough, so their benefits from North Slope
development have come chiefly through state government activities. Their
community facilities are less prosperous and extensive than those of North Slope
Borough villages.161 Paid employment in Arctic Village and Venetie is not as
widespread as it is in Kaktovik. Census statistics for 1990 show that 54% of Arctic
Village’s adults and 48% of Venetie’s adults were in the labor force.162
The Gwich’in argue that oil and gas development in the 1002 area will endanger
the PCH by threatening the herd’s calving areas, and that because of their dependence
on the PCH they will suffer subsistence loss and harm to their culture. When critics
from the pro-development set of Alaska Natives argue that Arctic Village and
Venetie in the 1980s sold oil development leases (ultimately unsuccessful) on their
lands, and that the villages seemed unconcerned about endangering the PCH then, the
Gwich’in respond that the lease areas were not calving or postcalving areas and thus
were not as sensitive for the herd’s survival.
Alaska Native Lands and Rights. Alaska Natives have various property
interests related to the issue of oil drilling in ANWR that may present complex legal163
issues for refuge management if the coastal plain is opened to oil development. In
1971, Congress enacted ANCSA to resolve all Native aboriginal land claims against
the United States. ANCSA provided for monetary payments and also created village
corporations that received the surface estate to approximately 22 million acres of
lands. Village selection rights included the right to choose the surface estate in a
certain amount of lands within the National Wildlife Refuge System, in which case,
under §22(g) of ANCSA, the lands were to remain subject to the laws and regulations

161Lane, “Living in the Cold,” op. cit.
162For these census statistics, go to [
lang=en&_vt_name=DEC_1990_STF3_DP3&_geo_id=16000US020200] for Arctic Village
and [
DEC_1990_STF3_DP3&_geo_id=16000US023480] for Venetie. As was the case with
Kaktovik, no persons were counted in the “hunters and trappers” occupation in the Arctic
Village and Venetie data.
163See CRS Report RL31115, Legal Issues Related to Proposed Drilling for Oil and Gas in
the Arctic National Wildlife Refuge.

governing use and development of the Refuge.164 KIC received rights to three
townships165 along the coast of ANWR.
ANCSA also created regional corporations which could select subsurface rights
to some lands and full title to others. Subsurface rights in National Wildlife Refuges
were not available, but in-lieu selections to substitute for such lands were provided.
Section 1431 of ANILCA (1980) followed up on the previously enacted
ANCSA and gave KIC rights to make certain selections and to enter into certain
exchanges. ANILCA (§1002(b)) also defined the 1002 area by reference to a map
dated August 1980, which has been interpreted as excluding the KIC lands. As a
result, Kaktovik has its previous surface rights to three townships along the coast that
are outside the 1002 area and one township inside that area. Geographically, the KIC
lands are all on the coastal plain and are indistinguishable from surrounding lands in
their importance to wildlife. However, all of the Kaktovik lands are within the
Refuge as a whole and hence are subject to the restrictions on oil and gas
development of §1003 of ANILCA and, under §22(g) of ANCSA and §1431(g) of
ANILCA, they are subject to the laws and regulations governing the Refuge.
Section 1431(o) of ANILCA also authorized the Arctic Slope Regional
Corporation (ASRC), whose shareholders are Inupiat, to obtain rights in the Refuge
through exchanges, if lands in the National Petroleum Reserve-Alaska (NPR-A) or
ANWR within a certain proximity to village lands were ever opened for commercial
oil and gas development within 40 years of the date of ANILCA. However, under
a different ANILCA exchange authority (§1302(h)), an exchange was executed on
August 9, 1983, between then Secretary of the Interior James Watt and ASRC.
Under this “Chandler Lake Agreement” the United States received certain ASRC
lands in the Gates of the Arctic National Park and ASRC received the subsurface
rights to the KIC lands – which, it will be recalled, are three townships within the
Refuge on the coastal plain but outside the 1002 area, and one township within the

1002 area. Congress appears to have ratified the Agreement in later legislation (P.L.

98-366, §5; 98 Stat. 468, 470-471).

Also as part of the Chandler Lake Agreement, ASRC was given the contractual
right to drill up to three exploratory wells on the KIC lands that are outside the 1002
area within a certain window of time. One test well was drilled, but the results of
that well have been kept confidential.
In addition to the KIC and ASRC Native lands, there are also some individual
Native “allotments” within the coastal plain. These typically are surface rights
belonging to a particular individual. The conveyance of some lands has been
completed; other lands have been applied for, but final rulings have not been made.
BLM currently is compiling the exact locations and acreage of these allotments, but
preliminary data indicate that these allotments and applications appear to be clustered
along the coast and near Sadlerochit Spring, both of which are important wildlife
areas. (See Special Areas, below.) Allotments already conveyed total over 10,000

164See 50 C.F.R. Parts 25 and 26.
165A township is about 36 square miles - roughly 23,000 acres.

acres. Use of allotments appears not to be subject to §22(g) ANCSA controls, nor
to other restrictions or regulations unless Congress enacts same.
The 1983 Agreement and its appendices address oil exploration and
development on the KIC/ASRC lands and their terms will govern the development
and oil production on those lands unless they are superseded by statutory provisions.
Appendix 2, part 9 of the 1983 Agreement states that development and production
activities undertaken on ASRC lands “shall be in accordance with the substantive
statutory and regulatory requirements governing oil and gas exploration, including
exploratory drilling, and development and production that are designed to protect the
wildlife, its habitat, and the environment of the coastal plain, or the ASRC Lands, or
both.” Other provisions in the Agreement purport to survive subsequent legislation
(which is to say they likely would unless Congress acts to expressly negate them),
and would affect the applicability of any environmental controls Congress might
otherwise enact. If Congress repeals the current prohibition against oil development
in the Refuge, development could occur on the more than 100,000 acres of Native
lands that are comprised of KIC/ASRC lands and individual Native allotments.
Canadian Interests in Traditional Native Rights. The Canadian
government has consistently opposed development in the 1002 area, citing risks to
the PCH and consequently to the Gwich’in people found on both sides of the
international border.166 It also points to a 1987 U.S.-Canada “Agreement on the
Conservation of the Porcupine Caribou Herd” under which each nation agreed to
protect the PCH and its habitat. If one country plans to carry out an activity that may
result in significant long term adverse impacts on the PCH, the other is to be notified,
and given the opportunity to consult before any final decision. Canada cites evidence
of its commitment to the herd in its creation of Ivvavik and Vuntuk National Parks
on the Canadian side, which prevent development in important calving and migration
areas on its side of the border. The embassy website notes: “... the 1002 Area of
ANWR contains the core of the critically important calving area for the Porcupine
Caribou Herd, and Canada is convinced that only permanent protection of the plain
will assure the herd’s long-term sustainability.”167
Development proponents often claim that the Canadian position borders on
hypocrisy, since a significant portion of the PCH range in Canada was leased for oil
and gas development in decades past. But commercial quantities of hydrocarbons
were not found, and leases have been allowed to lapse. Thus, this argument goes,
Canadian opposition arose only after it became clear that commercial quantities of
oil were not found in the PCH range in Canada. In response, Canadians (and
Gwich’in on both sides of the border) argue that the portion of the calving area on the

166Canada could also be affected by a proposed natural gas pipeline route from the North
Slope (whether the gas was from the 1002 area or not). Two of the three main options for
the route would pass through Canada before reaching U.S. markets. Canada has generally
supported a gas pipeline through its territory. (See Figure 6 and Natural Gas Pipeline from
North Slope, above.)
167From Statement by Canadian Environment Minister David Anderson on Arctic National
Wildlife Refuge on August 3, 2001; cited on [

U.S. side is the most frequently used, and that at the time the Canadian leases were
offered, the importance of the proposed leasing areas to caribou was unclear. Indeed,
some Canadian industry officials now complain of government hostility to
development in the northern areas of the country, based on what they perceive as
overzealous environmental concerns.
Reclamation Issues After Development
If the 1002 area were opened to exploration, and if energy development did
occur, then even under the most stringent requirements for environmental protection,
a major question would remain: what should be done after the oil and/or natural gas
are depleted? The FLEIS seemed to be of two minds. It speaks of “rehabilitation”168
and says that effects on wildlife could be “very long-term [but] would not be
considered irreversible once the life of the producing fields in the 1002 area was
over.”169 Yet it also speaks of “the long-term commitment of this area to industrial
use based on oil and gas development”170 and of “long-term changes in the wilderness
environment, wildlife habitats, and native community activities currently existing,
resulting instead in an area governed by industrial activities.”171 And it notes that
“complete restoration [of disturbed sites] may not be possible, inasmuch as
construction activities dramatically alter surface features which determine plant
species composition in the natural habitat.”172 These comments raise the question as
to whether the 1002 area, upon initiation of development, remains an integral part of
a wildlife refuge with a temporary (albeit long) interlude of industrial activity, or an
area whose fundamental purpose has changed, but continues to lie within the
boundaries of a national wildlife refuge.
Whatever development might be permitted, should it be seen as essentially
temporary – serving immediate energy needs and then being removed, followed by
restoring the 1002 area habitat to a condition as near as possible to its pre-
development state? The answers to questions about rehabilitation of the 1002 area,
and the confidence in the response, will crucially affect not only any development of
the area, but also will likely affect views on whether the 1002 area should be opened
to exploration and production in the first place.
Conditions for Rehabilitation. Total rehabilitation after development could
be defined as restoration to a state which a trained ecologist could not distinguish
from the original ecosystem. So defined, total rehabilitation of the 1002 area might
require centuries and could be impossible, since it might be confounded by other
long-term changes: global warming, changes in sea level, expansion or contraction
of the polar ice cap, changes in the northern polar hole in the ozone layer or in CO2
levels, etc. On the other hand, if “substantial” rehabilitation were defined as

168For example, pp. 86, 114, 116, and 139.
169FLEIS, p, 164.
170FLEIS, p. 165.
171FLEIS, p. 165.
172FLEIS, p. 116.

restoration of the area to a state approximating the original, with a full complement
of pre-development species (if not all at pre-development population levels), so that
at least untrained observers could not easily or frequently detect human influences,
then such a level might be an achievable but very difficult goal. Such a goal would
probably require not merely the removal of structures and equipment and stringent
pollution control, including the safe disposal of hazardous and other wastes, but also
the return to pre-development human population levels, the removal of gravel roads,
and the restoration of native vegetation.
As yet no major operating oil fields anywhere are known to have been shut
down permanently, and many have kept producing long beyond initial expectations,
due to enhanced recovery techniques. Thus there is little relevant experience to guide
a total closure of potential 1002 area development. Interestingly, in 1988 ARCO
Alaska said with respect to Prudhoe Bay that “Large scale rehabilitation/restoration
is neither currently practical nor required by Federal or State regulations.”173 Thus,
rehabilitation and restoration could be an important feature in congressional debate
concerning the 1002 area.
Human Population Levels. In an oil field, human population levels reach
a peak during the construction phase, once a producible field has been confirmed.174
In 1987, the FLEIS estimated 1,500 workers at the peak of construction. After
major construction projects are completed, personnel levels drop to those needed for
operations – perhaps a few hundred workers – or for smaller construction projects
such as the addition of new drill pads.
Once energy production ceases, it is hard to imagine what incentives would hold
workers in the 1002 area, since few other industries seem likely to seek the high cost
of North Slope operations. An important exception would be Alaska Natives,
presumably those in Kaktovik especially. With an increasing reliance on a monetary
economy, both for personal and local government income, there may be pressure to
maintain development to support (possibly subsidized) alternative local industries,
including tourism. The North Slope Borough has stated that its support for 1002
development stems partly from a concern over declining Prudhoe Bay revenues,
which are used for schools, fire stations, and other facilities. Over the years, little
debate has focused on the post-development status of permanent human populations
– a reflection, in part, of a lack of debate on the long-term fate of the 1002 area in
Removal of Roads and Gravel Structures. There is a striking distinction
between the access policies around development areas in the North Slope versus
those in the 1002 area as it is currently managed. In the former, a road network
provides relatively easy transportation, but its use is largely restricted to authorized

173ARCO Alaska, Inc. NRDC/Trustees for Alaska/National Wildlife Federation Report “Oil
in the Arctic: The Environmental Record of Oil Development on Alaska’s North Slope” –
Comments and Critique. 1988. p. 21.
174FLEIS, p. 85. Considerable advances in technology have occurred since then, so this
number should probably be considered a maximum; no newer local employment figures are

persons. In the latter, the lack of roads requires aircraft for most travel, but the
journey is relatively unrestricted. If Congress decides to authorize 1002 area
development, the fate of roads could have far-reaching environmental effects.175
Under the scenario for development based on current technologies, fewer roads
would be built than with older technology. However, if oil prices fall, or operating
costs rise, the cost of reliance on expensive aircraft might make construction of haul
roads seem attractive, especially for movement of heavy equipment. In addition, it
is unclear whether any restrictions on road construction would apply to Native lands,
and still less whether requirements for road removal would apply on Native lands.
In any event, under all current scenarios, it is likely that at least some roads would be
built. If these are in unconnected small segments, as at Alpine, their effects on
human access would probably be quite small. Experience in national parks, national
forests, and national wildlife refuges has shown that reducing human access can
benefit sensitive species, in such matters as preventing illegal hunting, or reducing
disturbance of nesting sites, calving areas, or spawning streams.
Removing millions of tons of gravel from roads (and pads) – some of it
contaminated with oil or other toxins – would be expensive, but so would continued
gravel maintenance to preserve culverts and other flow control measures. Costs
would likely prevent either the total removal of roads once production ceased, or the
indefinite maintenance of the full network. Unless otherwise specified or required,
rehabilitation of gravel structures would likely include removal of culverts and
bridges to ensure natural drainage, grading and scoring of the road or pad surfaces,
and seeding of grasses and forbs. Care would be required to minimize erosion,
sedimentation, and ponding. Probably, only if there were a need for gravel elsewhere
would some portion of the gravel be removed from abandoned roadbeds.
Thus, if leasing is allowed and production is achieved, there appear to be several
options, depending on the gravel structure and congressional policy. First, some may
wish to see certain useful structures retained even if all production ceases. Examples
of such structures are water treatment plants and some airfields. Others, such as drill
pads, seem unlikely to be useful in a post-production setting, and would likely be
priority candidates for removal. Finally, for roads, there appear to be two basic
options: maintain some roads while rehabilitating rights of way for the rest; or
abandon all of the roads and rehabilitate the rights of way in an effort to return to pre-
development conditions. If development were to result in increased tourism (e.g.,
visitor centers or visitor cabins), there might be considerable pressure to keep at least
some roads open, especially if tourism were seen as a continuing source of income
for Natives after development ceased. Continuing access could be expected to
prolong habitat disturbance and delay rehabilitation.

175Under ANILCA (Title XI), an applicant for a permanent structure affixed to the ground
(e.g., a gravel road or pad) has to apply for a right of way to cross federal land. The re-use
of the structure after development would have to be compatible with the purposes of the
refuge. If Congress authorizes development, it could choose a different procedure, more or
less strict than the standard process, for applicants in the 1002 area.

Restoration of Native Vegetation. Once production ceased, restoration of
the correct species and adequate numbers of native plants would be a key factor in
restoration of animal populations. There is a key distinction between the 1002 area
and the developed areas to the west: the rolling hills of much of the 1002 area support
more shrubby, woody vegetation, while the wetlands of the developed areas are
dominated by herbaceous vegetation. Thus, restoration experience around Prudhoe
Bay and environs may provide useful techniques for only part of the 1002 area.
Moreover, recent research has shown that “none but the smallest and wettest patches
on level ground ... recovered unassisted to something approaching their original state
in the medium term (20-75 years).”176 In larger, drier, or more sloping sites,
revegetation (where it occurred) often resulted in a species composition that differed
from the original state. “A wide range of small disturbances resulted in alternative177
vegetation states with reduced species diversity.” If roads and other gravel
structures were not removed, revegetation on these structures would be particularly
difficult, due to drying, loss of seeds, and erosion. On the other hand, revegetation
at the edges of the pads would be less difficult, due to wetter conditions and
protection from wind.
Site Phase-Out. The requirement to remove all facilities and to rehabilitate
the site is generally a term or condition of a lease sale. Thus far, there is relatively
limited experience in the arctic from which to judge the effectiveness of this
requirement. North Slope fields that have been developed are still active and only
a relatively small number of drilling sites have been abandoned. These abandoned
sites include a few artificial drilling islands in the Beaufort Sea and a number of
onshore sites, several of which are in the NPR-A. At the abandoned island sites,
facilities and slope protection have been removed and the artificial islands were left
to erode away. The NPR-A example is particularly relevant to ANWR development.
Site Cleanup in the NPR-A. Before the recent return to NPR-A prospects,
there were two rounds of drilling in the NPR-A. The most recent was between 1974
and 1981, when 28 wells were drilled in a federal program under the supervision of
USGS. In that round, each exploratory site included a drill pad, airstrip, and source
of water supply. Buildings and equipment were located on the drilling pad, often on
pilings to prevent thawing of the permafrost. The pad design included a fuel storage
pit, a reserve pit for drilling fluids and cuttings, and a flare pit.
Cleanup included removing miscellaneous debris, cutting off pilings below
ground level, and filling the pits by grading off and contouring the gravel pads. Then
revegetation of the sites was attempted using grass seed mixtures and fertilizer. The
program for revegetating the pads met with mixed success. Generally, the least
success was found at some coastal sites where pads were constructed of relatively
brine-rich clay silts excavated from the reserve pits. Considering the somewhat
experimental nature of the revegetation program and the variability of individual

176Bruce C. Forbes, James J. Ebersole, and Beate Strandberg, “Anthropogenic Disturbance
and Patch Dynamics in Circumpolar Arctic Ecosystems”, Conservation Biology, Vol. 15
(August, 2001), p. 966. (Hereafter referred to as “Forbes, et al.”)
177Forbes, et al., p. 966.

sites, revegetation was thought to progress at reasonable to excellent rates by 1986.178
In the interim, pad construction techniques elsewhere on the North Slope have
evolved, and exploration pads such as those in the USGS program at NPR-A would
be built of ice.
However, as with roads, the return of vegetation is not identical to recovery of
the tundra to its previous condition. Even if organic matter is left intact after a
disturbance, “significant and essentially permanent change [in] both vegetation and
soils” may still occur.179 Nonetheless, a manager may be satisfied if a site simply
returns to a plant-covered, stable surface.180
Site Development and Facility Removal. Facility removal really begins
as soon as drilling a well is finished. At that point, the drill rig is removed, leaving
only pipe valves and gages for each well and any operational facilities on the pad.
When a field is depleted or a well is abandoned, the well is plugged with cement
plugs at various points and at the surface. Surface facilities are removed, and the pad
would be graded and revegetated. The FLEIS full development scenario estimated
that 5,650 acres scattered around the 1.5 million acre 1002 area would be physically
covered with gravel (less than 0.4%). As noted previously (see Land and Gravel
Use, above), somewhat less would probably be covered with the use of modern
technologies, though these features would still be scattered in various spots around
the 1002 area. Until the affected areas were restored and revegetated, the impacts
would remain visible (at least as long as they were not concealed by snow and
darkness). As different requirements for rehabilitation might apply to Native lands,
their inholdings might retain various structures or pads might remain for a
considerably longer period.
Retention of Facilities: the Other Option. The alternative to removing
all drilling pads, roads, buildings, airstrips, and other facilities would be a judgment
that some of the development may be of longer term and/or broader benefit than the
oil and gas development in the immediate area. In remote regions of a hostile
environment, emergency shelters can be life-savers. A building or other recognizable
structure, such as a road or airstrip, in a featureless region can serve as a visual aid
to navigation, which can also save lives. In addition, if it were necessary to re-
develop a location, it would likely be less disruptive to the environment to reopen a
closed facility than to construct a new one. In any event, carrying out the actual
restoration requirements in ANWR would probably not arise for many years; thus a
tension might exist between those preferring that a goal of restoration be made a
condition of development and those preferring that the decisions on some facilities
be considered on a case-by-case basis later. In the later case, it could be difficult to

178Phillip D. J. Smith, “Final Wellsite Cleanup on National Petroleum Reserve – Alaska.”
U.S. Geological Survey Contract no. 14-08-001-21787. Anchorage Alaska: Nuera
Reclamation Company, 1986. Vol. 1, p. 43.
179Forbes, et al., p. 965.
180“[I]f a manager simply wants a green, stable surface, then a measure of vascular cover –
usually provided by graminoids [grass-like plants] – may be all that is feasible under the
most severe conditions.” Forbes, et al., p. 960, citing 1999 work by Forbes and Jeffries.

enforce a cleanup measure that was not originally specified as regulation, or a term
or condition of the lease.

Legislative Issues
The ANWR debate has continued for such a long time that most issues have a
long history of debate. Some of the issues that have been raised most frequently are
described briefly below. (For specific legislative provisions of current bills, see CRS
Issue Brief IB10111.)
Alternatives to Developing 1002 Area
Opponents of energy development in ANWR argue that a variety of other
options could provide the energy equivalent of most projections of ANWR oil
production, especially if one assumes the high energy prices necessary to reach the
most generous assumptions regarding Refuge resources. More succinctly, the high
energy prices that would make Refuge oil economic would make a variety of other
energy options attractive as well. Recognizing the great importance of oil in the
transportation market, opponents most frequently mention increases in fuel economy
for cars and light trucks, and production of ethanol from cellulose.181 Increases in
efficiency in other sectors (heating and cooling especially) are also mentioned.
Others have argued that developing ANWR oil, thereby continuing a national
reliance on TAPS, is harmful to U.S. energy security, especially with respect to
terrorist attacks. One author called TAPS “among the gravest threats to U.S. energy
security,” due to the vulnerability of the pipeline, lack of alternatives if it were
seriously damaged, and the difficulty of repairing the aging pipeline.182 Addition of
any ANWR oil would continue that risk, in this line of reasoning.
Consequently, for not only environmental, but also economic and security
reasons, opponents of ANWR oil development believe that other options (especially
in the transportation sector) are preferable to development of the Refuge. Proponents
downplay the economic rationale and practicality of the alternatives, but have only
recently begun to focus on continued reliance on TAPS as a security argument.
Exploration Only
Some have argued that the 1002 area should be opened to exploration first,
before a decision is made on whether to proceed to leasing. Those with this view
hold that with greater certainty about the presence or absence of energy resources, a
better decision could be made about whether to open the coastal plain for full leasing.
This idea has had relatively little support over the years. For those opposed to energy
development, the reasons are fairly clear: if there were economic discoveries, support
for further development might be unstoppable. And even if exploration resulted in

181For an analysis of energy alternatives, see CRS Report RL31033. Energy Efficiency and
Renewable Energy Fuel Equivalents to Potential Oil Production from the Arctic National
Wildlife Refuge (ANWR), by Fred Sissine.
182Amory B Lovins and L. Hunter Lovins, “Frozen Assets? Alaskan Oil’s Threat to National
Energy Security”, RMI Solutions, Spring, 2001. [].

no or insufficient economic discoveries, any damage from exploration (e.g., soil
compaction, erosion, or altered drainage patterns) would remain.
Those who support leasing see unacceptable risks in such a proposal. First, who
would be charged with carrying out exploration, who would pay for it, and to whom
would the results be available? Second, if no economic discoveries were made,
would that be because the “best” places (in the eyes of whatever observer) were not
examined? Third, might any small discoveries become economic in the future?
Fourth, if discoveries did occur, could industry still be foreclosed from developing
the area, or might sparse but promising data elevate bidding competition to
unreasonable levels? Fifth, if exploration were authorized, what provisions should
pertain to Alaska Native lands? In short, various advocates see insufficient gain from
such a proposal. In the 108th Congress, no bill supporting exploration only has been
Compatibility with Refuge Purposes
As a general rule, activities may be allowed in federal wildlife refuges if they
are compatible with the major purposes of the National Wildlife Refuge System and
with the purposes of any particular unit of that System.183 Long-term uses of a refuge
may be allowed if compatible with all of the purposes of the particular refuge and the
System.184 The mineral leasing laws apply to lands within the System to the same
extent they applied prior to October 15, 1966 (the date of the first general refuge
management statute), unless lands are subsequently withdrawn.185
A new compatibility policy and new regulations were published on October 18,
2000, effective November 17, 2000.186 “Compatible use” is defined as “a proposed
or existing wildlife-dependent recreational use or any other use of a national wildlife
refuge that, based on sound professional judgment, will not materially interfere with
or detract from the fulfillment of the National Wildlife Refuge System mission or the
purpose(s) of the national wildlife refuge.” Lands within Alaska refuges are subject
to the regulations on compatibility.
More specifically as to mineral leasing, Public Land Order 2214, which
withdrew lands to create the original Range, withdrew the lands from operation of
the mining laws, but not the mineral leasing laws. Congress, of course, in §1003 of
ANILCA reserved to itself the decision of whether to lease the coastal plain area.
Any legislation that ultimately permitted oil and gas leasing in that area would
answer the question of compatibility by authorizing leasing, and probably would
expressly address the compatibility of that leasing, and might set limits on such

18316 U.S.C. 668dd(d)(1)(A) (emphasis added).
18416 U.S.C. 668dd(d)(1)(B).
18516 U.S.C. 668dd(c).
18665 Federal Register 62484 and 65 Federal Register 62458, respectively. See 50 C.F.R.
§§25 and 26 for compatibility materials.

Compliance with NEPA
Some question whether the existing FLEIS, prepared in 1987 in compliance
with the National Environmental Policy Act (NEPA), is adequate to support
development, or whether an updated or new EIS needs to be prepared. A court in a
declaratory judgment action in 1991187 held that the Department of the Interior should
have prepared a Supplemental Environmental Impact Statement (SEIS) at that time
to encompass new information about the 1002 area in connection with the
Department’s recommendation that Congress legislate to permit development.
Therefore, it is likely that either an SEIS or a new EIS would have to be prepared
before development, unless Congress changed or waived this requirement.
Environmental Direction
Congress could choose to leave environmental matters to administrative
agencies under existing laws. Alternatively, Congress could impose a higher
standard of environmental protection because the area is in a national wildlife refuge
or because of the fragility of the arctic environment, or it could legislate a lower
standard to facilitate development. One issue would be the use of gravel and water
resources essential for oil exploration and development. Other potential legislative
issues include extent and regulation of gravel structures, gravel mines, or other
development; limitations on miles of roads or other surface occupancy; the adequacy
of existing air and water pollution standards; research needs; monitoring; prevention
and treatment of spills; the adequacy of current waste disposal requirements;
prohibitions on landfills; aircraft overflights; reclamation; and concerns over shared
liability that can make consolidation of facilities unattractive to oil companies.
Of the various bills introduced over the years, few had provisions that mandated
specific technologies. Rather, the focus was on requirements to use “best available”
or “best practicable” technologies or similar phrases. In recent debates on the issue,
limitations on surface occupancy have been also considered. These limitations are
generally focused on those features covered by gravel structures (e.g., drill pads,
runways, and connector roads). Debates over surface occupancy have tended to omit
features that require no laying of gravel or could be built offshore, e.g., gravel mines,
pipelines (as opposed to pipeline pier supports), culverts, altered drainage patterns,
water treatment plants, ports, causeways, and the like.
Special Areas
Congress could decide to set aside certain special areas for their ecological or
cultural values. This could be done either by designating the areas specifically, in
legislation, or by authorizing the Interior Secretary to set aside areas to be selected
after enactment. A few bills have named specific areas (especially Sadlerochit
Spring) within the 1002 area for set-asides. A number of bills in the past have
chosen the latter course, with a cap of around 45,000 acres in which surface
occupancy (a term not usually defined) could be limited. Depending on the meaning
of “surface occupancy,” such areas might be open to seismic exploration (which

187NRDC v. Lujan, 768 F. Supp. 870 (D.D.C. 1991)

requires no roads of any type) or to (temporary) ice roads. Such areas could also still
be accessible for leasing, if developed from drill pads outside these areas. The four
special areas named in the FLEIS together total more than 52,000 acres, so some
choices would be necessary if the set-aside acreage available to the Secretary were
too low to accommodate the identified areas.
Expedited Judicial Review
Leasing proponents urge that any ANWR leasing program be put in place
promptly; expediting judicial review may be one means to that goal. Judicial review
can be expedited through procedural changes such as time limits within which suits
must be filed, or by avoiding some level of review. The scope of the review also
could be curtailed, or the burden imposed on a challenger could be increased. Bills
before Congress have combined all of these elements.
Project Labor Agreements
A continuing issue in federal and federally-funded projects is whether project
owners or contractors effectively should be required, by “agreement,” to use union
workers. In the past 10 years, President George Bush, President Bill Clinton, and
President George W. Bush have issued executive orders pertaining to the question,
with President Clinton favoring their use and Presidents Bush opposing their use.
Members of Congress have become involved when they objected to a presidentialth
action. In the 108 Congress, the issue has come up in the context of proposed oil
and gas development of ANWR.
Project labor agreements (PLAs) are agreements between a project owner or
main contractor and the union(s) representing the craft workers for a particular
project. PLAs establish the terms and conditions of work that will apply for the
particular project. The agreement may also specify a source (such as a union hiring
hall) to supply the craft workers for the project. Typically, the agreement is binding
on all contractors and subcontractors working on the project, and specifies wage rates
and benefits, discusses procedures for resolving labor and jurisdictional disputes, and
includes a no-strike clause.
Proponents of PLAs argue that they ensure a reliable, efficient labor source and
help keep costs down. Opponents contend that PLAs inflate project costs and
decrease competition. There is little independent information and data to sort out
these conflicting assertions and demonstrate whether PLAs contribute to lower or
higher project costs. Construction and other unions and their supporters strongly
favor PLAs because they believe that PLAs help ensure access for union members
to federal and federally funded projects. Nonunion firms and their supporters believe
that PLAs unfairly restrict their access to federal and federally-funded projects.188

188For discussion of PLAs, see CRS Report 98-965 E, Project Labor Agreements in Federal
Construction Contracts: An Overview and Analysis of Issues, by Gail McCallion (Aug. 24,

1999). 8 p.

Revenue Disposition
A recurring issue in the ANWR debate is that of disposition of possible
revenues, not only from oil but also from sale of gravel or water resources. There are
two parts to the disposition question: (a) how would revenues be split between the
federal government and the state; and (b) how would the federal portion be used?
Federal/State Split. The Mineral Leasing Act (MLA)189 governs the leasing
of oil and gas and certain other minerals from federal public lands. Under §35 of the
MLA, certain western states receive directly 50% of revenues received. An
additional 40% goes to those states indirectly through the construction and190
maintenance of irrigation projects under the Reclamation Act of 1902. Before
1976, these percentages were 37½% and 52½% respectively. Because the territory
of Alaska did not benefit from the Reclamation Act, it received only a 37½% share
of federal leasing revenues. Before enactment of the Alaska Statehood Act, Congress
amended the MLA to provide that the territory would receive an additional 52½%
share, thereby putting Alaska on the same footing as the other states.191 Section 28(b)
of the Alaska Statehood Act again amended the MLA to change the references from
territory to State of Alaska.192 Section 317 of the Federal Land Policy Management
Act of 1976 amended the revenues section of MLA to direct payment of 90% to
Alaska, rather than the separate percentages previously stated.193 The committee
report accompanying the 1976 change states that the action was intended to clarify
that Alaska was to continue to receive 90% of the mineral revenues taken in from194
federal lands in Alaska.
Alaska has asserted that the 90% total referenced in the Statehood Act cannot
be changed and must always be paid to the state because the Statehood Act is a
compact between the prospective state and the federal government. Others assert that
the Statehood Act provision was a technical one, meant to recognize that Alaska
should receive a share comparable to that of other states under the MLA, but does not
preclude the Congress from changing the MLA or at times making special provision
for leasing certain areas under a different regimen.
Alaska sued in the U.S. Court of Federal Claims, asserting that because the
United States had an obligation under the Statehood Act both to maximize mineral
leasing in Alaska and to always pay a 90% share of gross receipts to Alaska, the

189Act of February 25, 1920, ch. 85, 41 Stat. 450, 30 U.S.C. 191.
190This money is available only if Congress subsequently appropriates it from the
Reclamation Fund – it is not permanently appropriated.
191P.L. 85-88, 71 Stat. 282 (1957). The 37½% was to be spent for the construction and
maintenance of public roads or for the support of public schools or other public educational
institutions as the legislature of the territory may direct. The 57½% was to be paid to the
territory to be disposed of as the legislature directed in general.
192P.L. 85-508, 71 Stat. 339, 351.
193P.L. 94-579, 90 Stat. 2743, 2770-2771.
194H.Rept. 94-1724, p.62 (1976).

United States had either breached the contract established by the Statehood Act, or
“taken” property of Alaska by withdrawing some lands in Alaska from leasing
(notably ANWR) and by deducting administrative costs prior to the disbursement of
the 90% revenues to the State. The court found that the Statehood Act and the
previous statute providing the territory of Alaska with the same shares as the other
states “simply plugged [Alaska] into the MLA, along with the other States.”195
Therefore, Congress could amend the MLA, e.g., to provide a different way of
calculating receipts, and the changes would lawfully pertain to Alaska. Furthermore,
the court concluded that the United States did not promise in the Statehood Act to
make federal mineral lands produce royalty revenues for the State, and that the
United States therefore retained discretion over leasing decisions.196 Because of these
findings, the court also granted the government’s motion for summary judgment on
the takings claim, dismissing Alaska’s claim.
If the Statehood Act simply means that Alaska will be treated like other states
under the MLA, the question may be asked whether Congress may legislate specially
as to ANWR and prescribe different revenue-sharing provisions. Congress has done
so in the past, e.g., with respect to the National Petroleum Reserves, in which
situation all of the revenues go into the federal Treasury,197 except for the National
Petroleum Reserve in Alaska, in which instance the revenue sharing is 50/50.198
Therefore, arguably Congress has flexibility in legislating regarding oil and gas
leasing in the Refuge, including providing for the disposition of revenues from any
such leasing.
Uses for Federal Share of Revenues. Proponents of opening ANWR for
oil production point out that the federal share of any revenues could be made
available for various conservation purposes, including ameliorating impacts,
providing funds for research on renewable energy sources, or assisting other refuges
and conservation areas. While additional funding for these purposes would
undoubtedly cheer many environmental groups, it is difficult to name any such group
whose views on ANWR development have been swayed by such proposals.
Wilderness Designation
In each Congress since 1980, bills have been introduced in both House and
Senate statutorily to designate the coastal plain of the Refuge as wilderness. Energy
development is not permitted in wilderness areas, unless there are pre-existing rights
or unless Congress specifically allows it or later reverses the designation.
Development of the surface and subsurface holdings of Native corporations would
be precluded inside wilderness boundaries (although compensation might be owed).
This choice would preserve existing recreational opportunities and jobs, as well as
the existing level of protection of subsistence resources, including the Porcupine

195Alaska v. United States, 35 Fed. Cl. 685, 701 (1996).
196Ibid., at 706.
19710 U.S.C. 7433.
198P.L. 96-514, 94 Stat. 2964.

Caribou Herd, while of course foregoing any energy resources that might be
No Action Alternative
Because current law prohibits development unless Congress acts, this option
also prevents energy development. Those supporting delay often argue that not
enough is known about either the probability of discoveries or about the
environmental impact if development is permitted. Others argue that oil deposits
should be saved for an unspecified “right time.”

Key Features, Terms, Acronyms, and Abbreviations

1002 area –

A portion of the coastal plain of ANWR north of the Brooks Range along
the Beaufort Sea. Section 1002 of ANILCA defined the area with respect
to a “map dated August 1980" but the area was later defined by a published

1002 report –

Alaska Department of Environmental Conservation; regulates
nonhazardous and RCRA-exempt solid wastes and underground injection
Alaska Department of Fish and Game.
Alaska Department of Natural Resources.
Alaska Federation of Natives; the major statewide Alaska Native
Alaska Natives –
Eskimos (Inuit and Yupik), Aleuts, and American Indians in Alaska, who
together make up over 15% of Alaska’s population. Included by the federal
government in the terms Indians and Indian tribe.
Alpine Corporation Oil Field –
A 40,000 acre oil field originally owned by ARCO Alaska, Inc., and now
owned by Phillips Petroleum Co. Originally permitted at 98 acres for
development, its current footprint is slightly smaller. It is situated west of
the Kuparuk Oil Field, and is accessible only by aircraft or winter ice road.
Oil development facilities here are considered state-of-the-art arctic
(energy) technology.
Alaska Native Claims Settlement Act of 1971 (P.L. 92-203). Provides for
selection and conveyance of property title and monetary award to Alaska
Natives in settlement of their aboriginal claims; authorizes establishment
of native regional and village corporations; also contains various
provisions regarding federal land management in Alaska.

Alaska Natural Gas Transportation System (surface pipeline).
Angun Plains –
One of several “special areas” in ANWR defined in the FLEIS, where
evidence of Pleistocene glaciation is considered special. It comprises
about 36 square miles.
Alaska National Interest Lands Conservation Act of 1980 (P.L. 96-487):
Among other things, it expanded the boundaries of ANWR, designated the
1002 area, prohibited energy development in the Refuge unless authorized
by Congress, and established numerous federal conservation system units
(National Parks, Wildlife Refuges, etc.) on federal lands in Alaska;
amended several provisions of ANCSA and included various provisions
regarding federal land and resource management in Alaska.
Arctic National Wildlife Refuge; also called “the Refuge.”
Alaska Oil and Gas Conservation Commission. The state agency regulates
extraction of oil and gas on non-federal lands. It also has primary
responsibility for regulation of subsurface injection of fluids brought to the
surface from oil and gas production operations or liquid hydrocarbons
which are stored underground through a permit program under the Safe
Drinking Water Act (SDWA). AOGCC’s responsibilities under the
SDWA are split with EPA. (See SDWA.)
ARCO Alaska –
Formerly a subsidiary of Atlantic Richfield Company; operated the eastern
half of the Prudhoe Bay field until April 2000, when the company’s Alaska
businesses were bought by Phillips Petroleum Co. ARCO Alaska was the
original developer of the Alpine field near the border of the NPR-A; like
other ARCO Alaska holdings, Alpine is now owned by Phillips Petroleum.
Arctic Power –
A consortium of proponents of energy development in ANWR, whose
members include, among others, petroleum industry representatives, the
State of Alaska, and various Native corporations.
Arctic Slope Regional Corporation. Established under ANCSA, a Native
regional corporation for essentially all of the Alaskan North Slope. ASRC
owns the subsurface rights beneath the lands within the coastal plain of
ANWR owned by the Kaktovik Inupiat Corporation.
Best Available Control Technology, required to be imposed on major
sources of specified pollutants in areas subject to the Prevention of

Significant Deterioration Program of the Clean Air Act. BACT
requirements would apply to ANWR.
Barter Island –
A coastal island within ANWR; the site of the Native Village of Kaktovik
and a DEWLine station. Currently, only occupied human habitation on the
coastal plain of the Refuge.
bbl –
Barrel; barrels (of oil); 42 gallons.
Bureau of Economic Analysis; part of the U.S. Department of Labor.
Beaufort Lagoon –
A small lagoon on the eastern edge of the 1002 area.
Beaufort Sea –
Portion of the Arctic Ocean adjacent to central and eastern Alaska
(including ANWR), as well as northwestern Canada.
Bureau of Labor Statistics; part of the U.S. Department of Labor.
Bureau of Land Management in DOI. Among other responsibilities, BLM
administers the federal mineral estate, including oil leases, on federal
Best Management Practices. In petroleum energy development, those
development plans which focus on pollution prevention rather than
end-of-pipe discharge limits through specification of structural and
operational controls, maintenance, and inspections.
Bonus bids –
The up-front payment made by a successful bidder to the federal
government for tract of federal land on which to explore, and if any energy
reserves are found, to produce it. The size of this payment is the vehicle
by which companies compete to obtain a federal energy lease.
BPAlaska –
Formerly a division of British Petroleum Company, it became a major
North Slope operator in 1968. BPAlaska was sold to Standard Oil Co.
(Ohio) in 1978. In 1987, British Petroleum Company acquired complete
control of Standard Oil Co., its U.S. associate. British Petroleum
Company became BP Amoco p.l.c. after 1998, and then became BP p.l.c.
in May 2001, and it currently operates in the western half of the Prudhoe
Bay field, as well as other parts of the North Slope, and it is vested in the
Trans-Alaska Pipeline.

Brooks Range –
An east-west trending mountain range in northern Alaska, running from
the Chukchi Sea eastward into northwestern Canada; north of this Range,
water drains to the Arctic Ocean; southward, to the Yukon River in Central
btu –
British Thermal Unit. The amount of heat required to raise the
temperature of a pound of water one degree Fahrenheit.
Central Arctic Herd; caribou whose range is partly in the developed areas,
including Prudhoe Bay, west of the Refuge; they occupy an area about one-
fifth the size of the Porcupine Caribou Herd (PCH).
Center for Economic and Policy Research. An economic and social
welfare policy research organization, aimed at promoting debate on
economic and social issues through conducting research and presenting the
findings of its own and others’ studies. (In September 2001, CEPR
reanalyzed the 1990 WEFA study of the economic impact of the possible
development of ANWR.)
Chandler Lake Agreement –
The 1983 land exchange agreement between DOI and ASRC, under which
the U.S. received lands in Gates of the Arctic National Park and ASRC
received subsurface rights to KIC lands in ANWR in return.
Coastal Plain –
When used in lower case, the relatively flat area between the foothills of
the Brooks Range and the north coast of Alaska; much of it is wetland,
especially around Prudhoe Bay. When used with upper case (“Coastal
Plain”), the term is used as defined pursuant to §1002 of ANILCA and
excludes Native lands in the coastal area.
U.S. Army Corps of Engineers. Approves permits affecting wetlands,
subject to EPA guidelines.
Compatible Use –
Defined as “A proposed or existing wildlife-dependent recreational use or
any other use of a National Wildlife Refuge that, based on sound
professional judgment, will not materially interfere with or detract from the
fulfillment of the National Wildlife Refuge System mission or the
purpose(s) of the National Wildlife Refuge.” (50 C.F.R. §25.12). Lands
within Alaska refuges are subject to the regulations on compatibility in 50
C.F.R. §§25 and 26.
Corps –
See COE.

Clean Water Act; among other things, the CWA requires permits for oil
and gas operations in the arctic that typically require the use of best
management practices to protect water resources. The CWA also requires
a state certification that energy development activities requiring federal
permits or licenses will comply with state water quality standards.
Coastal Zone Management Act. Among other things, requires certification
by states that projects to be located in a state’s coastal zone are consistent
with the state’s coastal zone management program. For ANWR, this
would apply to oil exploration and development activities on the coastal
plain (ANILCA §1002).
Deadhorse –
The oldest support center for oil exploration in the Prudhoe Bay field;
includes offices, depots, repair and service facilities, and housing for
Denning –
The act of a wild, usually predatory animal taking to its lair or taking
shelter. Often associated with bears and other animals which hibernate
during the winter, and with females of the species when they are giving
DEWLine –
Distant Early Warning Line. Series of stations used by U.S. and Canadian
military for detection of possible national security threats from the former
Soviet Union; usually a surveillance post and telecommunications relay at
each station. In the case of ANWR, one is situated on Barter Island just off
the north coast of Alaska, adjacent to the village of Kaktovik.
U.S. Department of the Interior.
Doyon, Ltd. –
Regional for-profit Native corporation for central Alaska Natives (chiefly
Athabascan Indian), established under ANCSA.
Economically Recoverable Oil –
Estimated amount of oil that could be feasibly extracted under the
assumption of a particular level of crude oil prices. If Congress were to
allow for energy development in ANWR, the price of oil would come into
play in the decision to explore for and develop resources in the extreme
conditions of the North Slope. (See technically recoverable oil and oil in
The Energy Information Administration in DOE. Responsible for
inventorying and forecasting U.S. Energy Resources.

Endicott –
Small oil field located offshore from Prudhoe Bay; contains 375,000
barrels of recoverable oil. Formerly operated by Standard Alaska
Production Company; acquired as part of Standard Oil Co. (Ohio) holdings
by British Petroleum Company in 1987; now belongs to BP p.l.c..
Enhanced Oil Recovery. A technique used to increase petroleum recovery
from known deposits, e.g., permeability of rocks may be increased by
deliberate fracturing, using explosives or water under very high pressure;
carbon dioxide gas under pressure can be used to force out more oil; and
hot water or steam may be pumped underground to warm thick, viscous
oils so that they flow more easily and be extracted more completely.
Environmental Protection Agency. Independent U.S. agency which
conducts environmental research, promulgates national environmental
criteria and standards, regulates a wide variety of activities which may
affect the environment, assists states in administering environmental
programs and funding municipal water infrastructure projects, remediates
and cleans up hazardous waste and enforces most environmental protection
laws. EPA has commented on DOI’s proposed leasing of ANWR and the
adequacy of mitigation measures.
Endangered Species Act; 16 U.S.C. 1531ff.
Exxon-Mobil –
A major oil company with substantial North Slope holdings, including oil
fields in Prudhoe Bay. Exxon Corporation and Mobil Corporation merged
in 1998.
Final Legislative Environmental Impact Statement; in the ANWR context,
the final report published under §1002 of ANILCA on April 1987 by
FWS/DOI on alternatives for preserving, managing, and/or developing the

1002 area. Also called 1002 report.

Footprint –
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, there is debate over exactly what
features might be counted in assessing the total size of the footprint.
Fish and Wildlife Service in DOI. Among other things, manages federal
wildlife refuges, including ANWR.

Gross Domestic Product. Main indicator of total output in the economy
used by the U.S. Department of Commerce; before 1991, GNP was used.
Gross National Product. Before 1991, the main indicator of total output
in the economy used by the U.S. Department of Commerce.
Gwich’in –
Athabaskan Indians, situated in east-central Alaska and neighboring areas
of northwestern Canada.
Infrastructure –
Physical facilities. In oil development, these include roads, pipelines,
drilling pads and structures associated with wells, pumps, facilities for
handling the oil and gas, housing and offices, gravel mines, airports, docks,
waste disposal facilities, support services, and others.
INGAA Foundation –
A Foundation of the Interstate Natural Gas Association of America; the
official name of this foundation uses the acronym. It reported original cost
estimates of developing a natural gas pipeline for Alaska (the Trans-Alaska
Inholdings –
Non-federal lands within a federal area. For ANWR, inholdings include
Native lands such as those owned by such Native corporations as the
Kaktovik Inupiat Corporation and the Arctic Slope Regional Corporation.
Inupiat –
Eskimo (specifically, Inuit) people of the Alaska North Slope and
bordering areas.
Jago River –
Large north-flowing river in the eastern third of the 1002 area.
Kaktovik –
Native village (population between 200 and 300) located in ANWR on
Barter Island; part of the North Slope Borough. Also the site of a U.S.
DEWLine station.
Kaktovik Inupiat Corporation –
Native Village Corporation of Kaktovik. (KIC.)
Kaktovik Inupiat Corporation.
Kongakut River –
River that lies between the 1002 area and the Canadian Border in the ANS
frontier, and flows into the Beaufort Lagoon.

Kuparuk –
Large oil field located west of Prudhoe Bay. Field formerly operated by
ARCO, now by Phillips Petroleum. Also, Kuparuk Oil Industrial Center.
Liquefied natural gas.
Milne Point –
Oil field located northwest of Prudhoe Bay, operated by BP Exploration
(Alaska) Inc., a subsidiary of BP p.l.c.. Drilled and operated briefly by
Conoco, Inc; once shut-in because of low world oil prices, and now re-
Mineral Leasing Act. Federal law that generally governs the leasing of oil
and gas and certain other minerals from federal public lands and revenue
sharing from these resources. However, Congress has authorized leasing
some federal lands under other statutory provisions.
National Ambient Air Quality Standards. Health-based standards
established by EPA for concentrations of ozone, sulfur dioxide, nitrogen
oxides, particulate matter, carbon monoxide, and lead in outdoor air.
National Petroleum Reserve-Alaska (NPR-A) –
Reserve of approximately 37,000 square miles located on the North Slope,
west of Prudhoe Bay, and originally set aside to provide oil for federal
military use. Early exploration did not reveal any potential commercial oil
resources, and exploration sites were abandoned. Recently reopened to
leasing with most recent lease sale held May 1999, and 130 bids totaling
$105 million accepted. This name replaced the earlier “Naval Petroleum
Reserve No. 4.”
National Wildlife Refuge System –
A network of lands and waters managed by the Fish and Wildlife Service
in all 50 states and most territories. As of Sept. 30, 2000, it consisted of
93.96 million acres in 530 refuges, 201 waterfowl production areas, and 50
wildlife coordination areas. Of these, 76.99 million acres were in Alaska.
Native –
When capitalized, used synonymously with “Alaska Native.”
Native Corporation –
Any regional, village, urban, or group corporation established under
ANCSA. (See also Regional and Village Corporation.)
Native Village –
Any tribe, band, clan, group, village, community, or association in Alaska
composed of Alaska Natives. (Here, also includes “Native Groups”,
defined in ANCSA as having less than 25 Natives.) The Bureau of Indian

Affairs in DOI recognizes over 220 such Native villages, irrespective of
National Congress of American Indians; major nationwide organization
representing Indian tribes.
National Environmental Policy Act. Requires that certain analyses of
possible environmental effects of proposed federal actions be completed.
Preparation of an updated version of the FLEIS or Supplemental
Environmental Impact Statement under NEPA might be necessary before
energy development in ANWR could proceed, unless Congress specified
North Slope –
A geographic area of Alaska on the north side of the Brooks Range,
exceeding 100,000 square miles (64,000,000 acres) and including foothills
and the relatively flat coastal plain, where the waters drain to the Chukchi
and Beaufort Seas. Reaches from roughly Point Lisburne on the Chukchi
Sea across NPR-A, oil development areas, the 1002 area, and east into
North Slope Borough –
Local North Slope government established in 1972 under Alaska state law;
boundaries are roughly similar to those of the North Slope itself.
Equivalent to a county, it has power to tax property.
Nitrogen oxides, one of the principal air pollutants likely to be emitted by
oil field operations in ANWR.
Ocean Dumping Act –
Title I of the Marine Protection Research and Sanctuaries Act (also known
as the Ocean Dumping Act). Requires the COE to issue a permit for the
disposal of dredged material at designated sites in any ocean waters
including the (U.S.) territorial seas, e.g., for disposal of material dredged
in the construction of channels in open seas needed to get oil/gas tankers
to shore facilities.
Organization for Economic Cooperation and Development.
Organization of Petroleum Exporting Countries.
Oil in place –
The amount that might be present or “in place” in a given field or area.
This figure 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

and probabilities. (See economically recoverable oil and technically
recoverable oil.)
Porcupine (River) Caribou Herd. Herd of caribou (variable population
levels – from about 120,000 to over 180,000) that winters in central Alaska
and Canada and migrates to ANWR in spring and summer; in most years
PCH calving is concentrated in the 1002 area; foothills, plain, and coast of
1002 area are used for feeding and insect relief. The PCH herd is
estimated to be about five times as large as the Central Arctic (caribou)
Herd (CAH).
Phillips Petroleum –
Major operator on North Slope (in addition to BP). Operates the eastern
half of the Prudhoe Bay field as well as other North Slope fields (e.g.,
PLAs –
Project labor agreements. Agreements between a project owner or main
contractor and the union(s) representing the craft workers for a particular
project that establish the terms and conditions of work that will apply for
the particular project.
Public Land Order. An administrative action relating to public lands taken
by the Secretary of the Interior. PLO 2214 withdrew federal lands in the
territory of Alaska to create the original Arctic National Wildlife Range.
Although it withdrew the lands from operation of the mining laws, it did
not withdraw the lands from mineral leasing.
Prospect –
In petroleum exploration, a site which is believed to have the potential for
containing a petroleum accumulation of sufficient size to be of commercial
Prudhoe Bay –
Bay on the north coast of Alaska, between the 1002 area and the NPR-A.
Also, the adjacent on-shore site of the largest oil field ever found in the
U.S. Originally estimated to contain 9.6 billion bbl of proven reserves,
then revised upward to 13 billion bbl; an estimated 3 billion bbl of reserves
are thought to remain. This field is operated by Phillips Petroleum and BP.
(The term often is used loosely to refer to all developed areas on the North
Prevention of Significant Deterioration: a regulatory program established
by the Clean Air Act to protect air quality in areas that meet National
Ambient Air Quality Standards.

Resource Conservation and Recovery Act. Governs the generation,
storage, transportation and disposal of hazardous wastes; in Alaska the
program is carried out by the U.S. EPA.
Regional Corporations –
Alaska Native Regional Corporation established under ANCSA and the
laws of the State of Alaska. After 1971, the DOI Secretary divided Alaska
into 12 geographic regions, as defined in §1606 of ANCSA, with each
region composed as far as practicable of Natives having a common
heritage and sharing common interests.
Reinjection –
Process by which most of the natural gas produced so far on the North
Slope has been put back into the ground by oil field operators to maintain
pressure in the oil reservoir zones.
Rent –
The annual payment made by a lessee to the federal government for the
right to a tract obtained for energy production under the Mineral Leasing
Act of 1920. Rates are $1.50 per acre per year for the first 5 years and
$2.00 per acre per year thereafter.
Riparian –
Areas alongside streams and rivers; in the 1002 area these are often
vegetated with low brush that is attractive habitat to a number of species.
Frequently serve as corridors for wildlife movement.
Rolligon –
Large vehicles with enormous soft tires that spread their weight evenly
across the surface.
Royalty –
A payment by a lessee to the federal government under the Mineral
Leasing Act of 1920 for oil or gas produced on federal land. Currently, the
royalty rate is set at 12.5%.
Sadlerochit Spring –
A “special area” in the southernmost part of the 1002 area. During the
section 1002 study, 4,000 acres around the spring were closed to
exploration. The spring maintains a flow of water at 50°-58°F year-round,
and keeps the river open for nearly 5 miles downstream, even in winter.
It represents the extreme northern range of some plants and birds, and
provides wintering habitat for fish; muskoxen frequent the area.
Safe Drinking Water Act. Manages a permit program to protect
underground sources of drinking water (USDWs) from contamination by
injection through wells. In Alaska, U.S. EPA has primary responsibility
to issue permits authorizing subsurface injection of nonhazardous

industrial wastes associated with oil exploration and development. The
Alaska Oil and Gas Conservation Commission shares regulatory authority
over underground injection wells. (See AOGCC).
Supplemental Environmental Impact Statement; in a declaratory judgment
action in 1991, a judge held that DOI should have prepared a SEIS at that
time to encompass new information about the 1002 area in connection with
the Department’s recommendation that Congress legislate to permit
Special Area –
Areas of natural beauty or prolific wildlife areas, habitats, and ecosystems
in the 1002 area. Five special areas were specifically named in the FLEIS
as potential set-asides; these total more than 52,000 acres.
TransAlaska Gas System. Proposed subsurface pipeline delivery system
to supply natural gas to LNG processing facilities on the North coast of
Trans-Alaska Pipeline System. Transports oil Prudhoe Bay to Valdez, a
port on Alaska’s south coast. The pipeline was completed and opened in


tcf –
Trillions of cubic feet, e.g., of natural gas.
Technically recoverable oil –
Oil which has been successfully prospected and may be extracted given the
scientific and technological knowhow, resources, infrastructure, etc.;
however, its extraction is limited by such factors as the market price of oil,
which is related to its supply and demand. (See economically recoverable
oil and oil in place.)
Trans-Alaska Pipeline Authorization Act –
Federal law which authorized construction of TAPS and by granting a right
of way over federal lands (P.L. 93-153, 87 stat. 584, 43 U.S.C. 1651 et
seq.). In addition, federal law had generally prohibited the export of oil
transported through pipelines which had been granted a right of way over
federal lands (30 U.S.C.§185(u)). However, an amendment enacted in
1996 permits oil shipped through the pipeline to be exported though only
under certain very restrictive conditions (30 U.S.C.§185(s)).
Tundra –
Major ecological community of the arctic and high elevation alpine areas,
characterized by usually waterlogged soil sitting on permafrost, and by low
growing plants such as mosses, lichens, and dwarf forms of woody plants.

Underground source of drinking water.
U.S. Geological Survey. A DOI agency that, among other things, conducts
mineral and energy resource assessments of the U.S. and the world;
advises on prospecting and extraction of petroleum and mineral resources
on federal lands; evaluates national water resources.
Village Corporation –
Alaska Native Village Corporation organized under ANCSA and the laws
of the State of Alaska as a business corporation (for profit or non-profit)
to hold, invest, and/or distribute lands, property, funds, and other rights
and assets on behalf of a Native village (as defined in ANCSA).
WEFA Group, The –
Economic consulting group, now merged with “DRI” (not an acronym),
forming DRI-WEFA. In 1990, published a study of the economic impact
of the possible development of ANWR (See also CEPR.)
Wellhead Price –
The price paid a producer in the producing field. It is often calculated
based on the delivered or first sale price, less the cost of associated
transport. Transport tariffs are generally related to pipeline length. In the
case of North Slope oil (or gas) – where there pipeline cost is (or would be)
substantial, the implied price at the wellhead would be commensurately


1002 area..8, 1, 3-7, 9, 12-17, 25, 27-29, 32-39, 41-45, 49, 57-72, 75-79, 81-95,

97, 99, 104-106, 109, 110, 112-115
1002 report..............................................15, 104, 109
Alaska Department of Environmental Conservation.........66, 67, 71, 73, 104
ADEC...............................................73, 74, 104
Alaska Department of Fish and Game.............................62, 104
ADF&G ...................................................104
Alaska Department of Natural Resources........................4, 43, 104
ADNR ....................................................104
Alaska Federation of Natives....................................84, 104
AFN...................................................84, 104
Alaska National Interest Lands Conservation Act...........3, 1, 9, 14, 85, 105
ANILCA........1, 9, 11, 14-16, 25, 28, 85, 89, 93, 98, 104, 105, 107-109
Alaska Native Claims Settlement Act..........................16, 85, 104
ANCSA...................16, 85, 88-90, 104, 105, 108, 111, 114, 116
Alaska Natives................6, 16, 36, 45, 82-84, 87, 88, 92, 104, 108, 111
Alaska Natural Gas Transportation System.........................45, 105
ANGTS.............................................45, 46, 105
Alaska Oil and Gas Conservation Commission..................72, 105, 115
AOGCC............................................72, 105, 115
Aleuts......................................................83, 104
Alpine Corporation Oil Field.......................................104
American Indians...................................83, 84, 87, 104, 112
Angun Plains................................................64, 105
ARCO Alaska.....................................33, 74, 92, 104, 105
Arctic Power.............................................33, 78, 105
Arctic Slope Regional Corporation...................6, 38, 84, 89, 105, 110
ASRC................................6, 84, 85, 87, 89, 90, 105, 107
Barter Island.......................................7, 82, 106, 108, 110
Beaufort Lagoon.......................................64, 82, 106, 110
Beaufort Sea....................................46, 61, 68, 94, 104, 106
Best Available Control Technology............................66, 67, 105
BACT..............................................67, 105, 106
Best Management Practices.................................71, 106, 108
BMP...................................................71, 106
Bonus bids..................................................27, 106
BPAlaska...................................................66, 106
Brooks Range........................3, 9, 13, 58-60, 64, 87, 104, 107, 112
Bureau of Economic Analysis...................................55, 106
BEA...................................................55, 106
Bureau of Labor Statistics......................................53, 106
BLS...................................................53, 106
Bureau of Land Management.....................15, 16, 24, 25, 36, 80, 106
BLM.......................................25-29, 35-37, 89, 106
Center for Economic and Policy Research..........................54, 107
CEPR..............................................54, 107, 116
Central Arctic Herd.....................................58, 59, 86, 107

CAH......................................59-61, 77, 86, 107, 113
Chandler Lake Agreement......................................89, 107
Clean Water Act..............................................71, 108
CWA...............................................71-73, 108
Coastal Plain...1, 3, 4, 7, 9, 11-16, 25, 36, 37, 40, 42, 45, 58-60, 64, 75, 80, 82,
83, 85, 86, 88-90, 97, 98, 102, 104-108, 112
Coastal Zone Management Act...............................71, 73, 108
CZMA.................................................73, 108
Compatible Use..............................................98, 107
Corps....................................29, 32, 35, 71-73, 76, 80, 107
Deadhorse................................................7, 78, 108
Denning...............................................7, 15, 62, 108
Department of Energy.......................................22, 24, 47
Department of the Interior.........................1, 4, 23-25, 66, 99, 108
DOI...........................1, 3, 9, 23, 24, 106-109, 112, 114-116
Distant Early Warning Line...................................7, 82, 108
DEWLine...................................3, 7, 82, 106, 108, 110
Doyon, Ltd...............................................84, 88, 108
Economically Recoverable Oil...5, 15, 37, 38, 40, 42, 45, 49, 50, 56, 108, 113,
Endangered Species Act.....................................62, 63, 109
ESA................................................63, 64, 109
Endicott....................................................37, 109
Energy Information Administration....................5, 40, 42, 43, 50, 108
EIA.............................5, 40, 42, 43, 47, 50, 51, 53, 55, 108
Enhanced Oil Recovery........................................74, 109
EOR...................................................74, 109
Environmental Protection Agency..........................67, 71, 75, 109
EPA..........................67, 71-73, 75, 105, 107, 109, 111, 114
Eskimos....................................................83, 104
Exxon-Mobil ...................................................109
Final Legislative Environmental Impact Statement...........9, 15, 66, 80, 109
FLEIS.9, 12, 13, 15, 16, 26, 28, 31, 32, 34, 36, 54, 57, 59, 62, 64-69, 77-82,
86, 87, 91, 92, 95, 99, 100, 104, 105, 109, 112, 115
Fish and Wildlife Service.........................2, 2, 15, 80, 82, 109, 111
FWS..................................2, 29, 35, 58, 63, 69, 83, 109
Footprint......................6, 12, 27, 31, 33, 34, 65, 69, 74-78, 104, 109
Gross Domestic Product....................................52, 54, 110
GDP................................................52, 53, 110
Gross National Product........................................54, 110
GNP...................................................54, 110
Gwich’in.......................................84, 85, 87, 88, 90, 110
Infrastructure..............3, 5, 6, 8, 31, 33, 36, 43, 49-51, 57, 109, 110, 115
INGAA Foundation...........................................46, 110
Inholdings.............................................29, 38, 95, 110
Inuit.............................................63, 83, 84, 104, 110
Inupiat......................................6, 38, 82-87, 89, 105, 110
Jago River..................................................64, 110
Kaktovik....6, 7, 9, 16, 32, 38, 62, 64, 76, 82-84, 86-89, 92, 105, 106, 108, 110
Kaktovik Inupiat Corporation.......................6, 38, 82, 84, 105, 110

KIC...............................6, 82, 84, 85, 87, 89, 90, 107, 110
Kongakut River..............................................64, 110
Kuparuk...........................................7, 36, 78, 104, 111
Liquefied natural gas........................................5, 45, 111
LNG...............................................45, 111, 115
Milne Point.................................................37, 111
Mineral Leasing Act.......................20, 22, 25-27, 29, 101, 111, 114
MLA...........................................27, 101, 102, 111
National Ambient Air Quality Standards....................65, 66, 111, 113
NAAQS.............................................65-67, 111
National Congress of American Indians...........................84, 112
NCAI..................................................84, 112
National Environmental Policy Act..........................4, 23, 99, 112
NEPA............................................26, 28, 99, 112
National Petroleum Reserve-Alaska.........................4, 24, 36, 111
NPR-A...............4, 23, 24, 28, 31, 36, 58, 89, 94, 95, 105, 111-113
National Wildlife Refuge System...................28, 29, 88, 98, 107, 111
Native..2, 2, 4-7, 11, 15, 16, 25, 27, 29, 32, 34, 35, 39, 44-46, 58, 64, 78, 79, 81-
95, 98, 102, 104-108, 110-112, 114, 116
Native Corporation........................................39, 108, 111
Native Village.............................16, 83-88, 106, 110, 111, 116
North Slope...7, 4-6, 9, 13, 14, 19-24, 26, 28, 30, 31, 34, 36, 37, 39, 43, 45-48,

50, 55, 62, 63, 65-72, 74-77, 84-86, 88, 90, 92, 94, 95, 105, 106, 108-

114, 116
North Slope Borough..........................72, 84, 85, 88, 92, 110, 112
NOx.......................................................67, 112
Ocean Dumping Act........................................71, 73, 112
Oil in place..........................................39, 108, 112, 115
Organization for Economic Cooperation and Development............52, 112
OECD .....................................................112
Organization of Petroleum Exporting Countries........................112
OPEC................................................51, 52, 54
Phillips Petroleum................................74, 104, 105, 111, 113
PLO 2214...................................................14, 113
Porcupine Caribou Herd....................15, 58-60, 76, 84, 90, 103, 107
PCH.......................15, 58-61, 76, 77, 84, 86-88, 90, 107, 113
Prevention of Significant Deterioration.....................65-67, 106, 113
PSD................................................65-67, 113
Project labor agreements......................................100, 113
PLAs.................................................100, 113
Prospect...................................3, 25, 31, 38, 45, 51, 77, 113
Prudhoe Bay.3, 1, 3-5, 7, 9, 13, 19, 20, 23, 32, 36, 42, 43, 45, 46, 58, 60, 63, 66,
67, 70, 81, 92, 94, 105-109, 111, 113, 115
Public Land Order.........................................14, 98, 113
PLO...................................................14, 113
Regional Corporations................................83, 85, 87, 89, 114
Reinjection .....................................................114
Rent.......................................................27, 114
Resource Conservation and Recovery Act..........................73, 114
RCRA...........................................73, 74, 104, 114

Riparian...............................................7, 62, 70, 114
Rolligon....................................................81, 114
Royalty.........................................2, 23, 27, 56, 102, 114
Sadlerochit Spring....................................7, 64, 89, 99, 114
SDWA.............................................72, 105, 114
Safe Drinking Water Act................................71, 72, 105, 114
Special Area..............................................3, 114, 115
Supplemental Environmental Impact Statement.................99, 112, 115
SEIS...................................................99, 115
Technically recoverable oil.......................37, 45, 49, 108, 113, 115
Trans-Alaska Pipeline Authorization Act.............................115
Trans-Alaska Pipeline System...................................21, 115
TAPS................2, 5, 10, 20, 21, 31, 34, 37, 45, 46, 48, 77, 97, 115
TransAlaska Gas System.......................................46, 115
TAGS..................................................46, 115
Tundra................3, 6, 13, 28, 30, 58, 61, 64, 69, 70, 75, 77, 81, 95, 115
U.S. Army Corps of Engineers...................32, 35, 71, 72, 76, 80, 107
COE..................................................107, 112
U.S. Geological Survey.............................5, 15, 24, 37, 95, 116
USGS....5, 10, 13, 24, 37-39, 41, 43-45, 49, 50, 58, 60-63, 82, 94, 95, 116
Underground source of drinking water............................74, 116
USDW ....................................................116
Village Corporation................................16, 84, 110, 111, 116
WEFA Group................................................54, 116
Wellhead Price............................................48, 56, 116
Yupik......................................................83, 104