Oil and Gas Exploration and Development on Public Lands

CRS Report for Congress
Oil and Gas Exploration and
Development on Public Lands
March 26, 2004
Marc Humphries
Analyst in Energy Policy
Resources, Science, and Industry Division

Congressional Research Service ˜ The Library of Congress

Oil and Gas Exploration and Development on Public
The U.S. Congress and the Administration are involved in a major policy debate
over oil and gas development from federal lands and from federal mineral estate
underlying certain privately owned lands. Within the framework of U.S. public lands
policy, restrictions and withdrawals have affected the amount of land that can be
developed. The Energy Policy and Conservation Act Amendments of 2000 (EPCA)
mandated a study which was released in January 2003 to assess the oil and gas
resource potential underlying restricted federal lands. It concluded that although the
amount of land prospected for natural gas that was completely “off-limits” for
development was 35.6%, other restrictions and lease stipulations are in place. The
conference report to the Energy Policy Act of 2003 (H.R. 6) as well as the scaled-
back Senate version of the bill (S. 2095) contains provisions that would address
restrictions and impediments to oil and gas development on public lands. The Bush
Administration has its own initiatives to expedite the permitting process —
considered by some to be a major impediment — on federal lands.
As part of the oil and gas leasing system, lessees must file an application for a
permit to drill (APD) for each well. The Bureau of Land Management (BLM) is
required to process the APD in 30 days but delays may occur, extending the average
approval time to over 120 days. Some approvals have taken over three years. A new
process to expedite the APDs has been established at the BLM that includes, among
other features, the processing and conducting of environmental analyses on multiple
permit applications with similar characteristics.
Energy and mineral industry representatives maintain that federal withdrawals
and/or restrictions inhibit mineral exploration and limit the reserve base even when
conditions are favorable for development. They further contend that sufficient
environmental standards are in place to protect public lands. Critics who oppose
opening up more federal lands or the mineral estate under private lands argue that the
general environmental requirements are not adequate and that some forms of
development threaten water quality and quantity; therefore, certain restrictions and
withdrawals are appropriate.
Concern exists regarding natural gas supply and declining production rates. As
a result, there is increased interest in potential gas supplies in the Rocky Mountain
region. Several resource estimates suggest significant amounts of natural gas on
public and private lands in the region, and Rocky Mountain natural gas may become
much more important to the overall supply picture.
Elsewhere, the outlook is mixed for increased oil and natural gas production on
U.S. public lands. While domestic natural gas production and natural gas imports are
expected to rise, it is unclear whether much of the domestic supply will come from
public lands that are currently restricted or off-limits. This report will not be updated.

In troduction ......................................................1
Oil and Gas Leasing on Public Lands..................................3
Land Use Planning.............................................3
Drilling Permits...............................................4
Delays in the Permitting Process..................................5
Leasing Restrictions on Oil and Gas Resources..........................6
Rocky Mountain Region ........................................7
Significance of Access Restrictions...............................10
Oil and Gas Resources and Production on Public Lands...................11
Federal Onshore Oil and Gas Production..........................11
U.S. Oil and Gas Reserves and Resources .........................13
Growing Role of Coalbed Methane...................................15
CBM Environmental Issues.....................................17
Outlook for Oil and Gas Development on Public Lands...................19
Appendix A. Terms of an Oil and Gas Lease...........................20
Appendix B. History of Public Land Withdrawals.......................21
Sources of Withdrawal Authority................................21
Withdrawals Under FLPMA....................................22
List of Tables
Table 1. Rocky Mountain Natural Gas Resources........................9
Table 2. U.S. Oil Production, 2002...................................12
Table 3. U.S. Natural Gas Production, 2002...........................12
Table 4. U.S. Proved Oil and Gas Reserves and Production, 1993-2002......13
Table 5. U.S. Proved Oil and Gas Reserves, by State, 2002................14
Table 6. Rocky Mountain Proved Reserves (Five major basins).............15
Table 7. Total Onshore Technically Recoverable Resources, 2002..........15
Table 8. Oil and Natural Gas Production in U.S.
Onshore Federal Lands, 1991-2000

Oil and Gas Exploration and Development
on Public Lands
Significant amounts of technically recoverable oil and gas resources are
projected to be on federal public lands (see Table 7). However, energy development
on some of these lands has been restricted because they are considered
environmentally sensitive or unique. These restricted areas may contain sizable
amounts of oil and natural gas, according to the U.S. Geological Survey (USGS) and
the Energy Information Administration (EIA).
The conflict between environmental concerns and the need for increased
domestic energy production from public lands is a major policy issue. For example,
the conference report on the omnibus energy bill (H.R. 6) and the Senate substitute,
S. 2095 has provisions that would examine restrictions and impediments to oil and
gas development on public lands, including an evaluation of the current permitting
process. Reportedly, reflecting its Energy Task Force recommendations, the Bush
Administration has its own initiative to expedite the oil and gas permitting process
on federal lands.
Oil and gas development practices have generated considerable debate in
Congress since the early years of the industry. Originally, oil and gas resources on
public lands could be transferred to private ownership (patented) under the Mining
Law of 1872 — essentially, lands containing oil were sold at a fixed price per acre
to the first claimant.1 Conservationists contended that there was widespread abuse of
the Mining Law that led to wasteful use of public lands. In 1909 President Taft
withdrew 3 million acres of lands prospective for oil in Wyoming and California
from availability under the Mining Law of 1872. Taft requested congressional
approval for his action, leading to the Pickett Act of 1910 (43 U.S.C. 141-143),
which explicitly recognized executive branch authority to make such public lands
wi t hdrawal s. 2

1Enactment of the Oil Placer Act of 1897 (29 Stat. 526) resolved the question of whether
petroleum or other mineral oils were to be governed by the laws relating to other placer
claims. Placer claims are those located on the ground, not fixed to below surface rock.
2The Pickett Act was repealed by the Federal Land Policy and Management Act of 1976
(FLPMA) which also modernized the law regarding withdrawals. Under FLPMA (43 USC
1702 (j)), a land withdrawal is defined as “withholding an area of federal land from
settlement, sale, location, or entry under some or all of the general land laws, for the purpose
of limiting activity under those laws in order to maintain other public values in the area or
reserving the area for a particular public purpose or program; or transferring jurisdiction

Congress eventually decided that defense-related minerals — including oil and
gas — should remain under federal ownership. As a result, the Mineral Lands
Leasing Act of 1920 (30 U.S.C. 181, et. seq.) removed oil and gas from the patenting
process and placed it under a leasing system. Under the leasing system, the federal
government has raised billions of dollars in revenues from royalties, rents and bonus
Minerals owned by the federal government under lands held privately (patented)
creates a “split-estate.” There are other split-estate situations as well: surface and
mineral rights held by different private interests, or state owned mineral rights and
privately held surface rights. Three major federal statutes4 allowed the federal
government to issue patents to land but reserve the right to the minerals. Under these
statutes the mineral estate became the dominant estate and the surface use servient.
There are specific policies and procedures that must be followed by the mineral estate
holder in order to develop minerals. Generally, for oil and gas, a federal lessee must
meet one of the following conditions: a surface agreement; written consent or a
waiver from the private surface owner for access to the leased lands; payment for loss
or damages; or the execution of a bond not less than $1,000. 5 About 11% of the
public lands are under the split-estate category. However, in Wyoming 50% of the
lands are split-estate and in Montana about 57%.6
Environmentalists have supported public land withdrawals and other restrictions
because of concern that the Mining Law of 1872 and then the Mineral Leasing Act
of 1920 provided inadequate environmental protection. Recently, ranchers and other
groups have expressed similar concerns specifically about the impact of development
on water and land. Conversely, development supporters contend that numerous
environmental laws are now in place to regulate oil and gas development on public
lands. They note that the federal government must comply with the National
Environmental Policy Act (NEPA) in leasing oil and gas and that the oil and gas
industry must comply with applicable requirements of the Clean Water and Clean Air
Acts, Safe Drinking Water Act, the Resource Conservation and Recovery Act, and
state and federal reclamation standards, among other laws. The industry complains
that environmental and other reviews often create long delays in drilling exploratory
and production wells on leased lands.
The proposed conference report on a comprehensive energy bill (H.R. 6) and S.

2095 addresses some of the industry and Bush Administration concerns over

2 (...continued)
over an area of federal land from one department, bureau or agency to another department,
bureau or agency.”
3 A bonus bid is an amount paid by the lessee to the lessor for obtaining a lease.
4 The Coal Lands Act of 1909, 30 U.S.C. 81; the Agricultural Entry Act of 1914, 30 U.S.C.

121-123 and the Stock-Raising Homestead Act of 1916, 43 U.S.C. 291-301.

5This information was provided in a BLM Instructional Memorandum, No. 2003-131. Also
see 43 CFR 3104, 43 CFR 3814 and 48 FR 48916 (1983) for further details.
6Public Lands, Onshore Federal and Indian Minerals in Lands of the U.S., Appendix 7, Sie
Ling Chiang, Bureau of Land Management, DOI, December 1, 2000.

increasing domestic oil and natural gas supplies. Title III of H.R. 6 and S. 2095, if
enacted, would establish a White House Office of Federal Project Coordination to
help expedite permitting on public lands and identify restrictions and impediments
to resource development on public lands. Environmentalists and other public land
users argue that these provisions would cause harm to the environment and prevent
the land from being used in other productive ways. The conference report has been
approved by the House but not in the Senate as a result of a cloture motion on
November 21, 2003 that did not get the required 60 votes, (57- 40). The Senate’s
scaled-back substitute bill, S. 2095 is awaiting action.
This report provides a general overview of the oil and gas leasing system on
U.S. public lands, including information on permitting, production, and reserves.
The report describes the contribution of onshore oil and gas towards meeting U.S.
energy demand and discusses current estimates of reserves in restricted areas. An
Appendix provides some historical background on lands withdrawn from mineral
development, the role of the Bureau of Land Management (BLM), and application
of the Federal Land Policy and Management Act (FLPMA) in the context of oil and
gas development.
For information on U.S. offshore oil and gas development, see CRS Report
RL31521, Outer Continental Shelf Oil and Gas: Energy Security and Other Major
Issues, by Marc Humphries.
Oil and Gas Leasing on Public Lands
Leasing of onshore federal public lands for oil and gas development is based on
multiple-use/ sustained yield Resource Management Plans (RMPs) developed by the
Bureau of Land Management in the Department of the Interior. In accordance with
those land-use plans, tracts of public land with oil and gas potential are offered for
competitive leasing each quarter. After a lease is awarded, a drilling permit is
required for each exploratory or production well. Industry has long complained that
this process is too lengthy.
In FY2002, the federal government issued 1,765 new oil and gas leases on
public lands totaling about 1.4 million acres. Through the end of FY2002, about 18.6
million acres of public lands had been leased for oil and gas development.
Land Use Planning
Under the Federal Land Policy and Management Act (FLPMA), Resource
Management Plans or Land Use Plans (43 USC 1712) are required for tracts or areas
of public lands prior to development. The Bureau of Land Management (BLM) must
consider environmental impacts during land-use planning when RMPs are developed
and implemented. RMPs can cover large areas, often hundreds of thousands of acres
across multiple counties.
FLPMA requires that RMPs reflect diverse uses — such as timber, grazing,
wildlife conservation, recreation, and energy — and consider the needs of present and

future generations.7 Impacts of various uses are identified early in the process so that
they can be weighed equitably against one another. The plans are also intended to
weigh the various benefits associated with public lands to best serve the community.
RMPs must be consistent with environmental regulations and allow meaningful
public participation. Through the land-use planning process, the BLM determines
which lands with oil and gas potential will be made available for leasing.
The Mineral Leasing Act of 1920, as amended, requires that all public lands
available for lease be offered initially to the highest responsible qualified bidder by
oral competitive bidding. These auctions are held quarterly by the BLM. The
objective of the competitive bid is to provide a “fair market value” return to the
federal government for its resources. If no bids are received or the highest bid is less
than the $2/acre national minimum acceptable bid, oil and gas leases on these lands
are offered on a noncompetitive basis within 30 days. The tracts remain available on
a noncompetitive basis for two years.
Tracts available for noncompetitive leasing may be obtained by the first
qualified applicant upon payment of a nonrefundable application fee of at least $75.
Simultaneous (SIMO) noncompetitive lease applications filed on the day following
the competitive lease sale are prioritized through a lottery system. Lease applicants
filing on subsequent days are given priority according to the time of filing. (For more
details on leasing terms, see Appendix A.)
Geophysical exploration permits on unleased public lands may be issued by
BLM. Such exploration does not include drilling for core samples or drilling for oil
and gas. The permittee must file a notice of intent with the BLM and must comply
with specific practices and procedures spelled out by the surface managing agency
(SMA).8 Once a lease is obtained, the lessee is given exclusive rights to further
explore, develop, and produce on that land.
Drilling Permits
After a lease has been obtained, either competitively or noncompetitively, an
Application for a Permit to Drill (APD) must be approved for each oil and gas well.9
As noted in the Mineral Leasing Act, section 226 (g), “no permit to drill on an oil and
gas lease issued under this chapter may be granted without the analysis and approval
by the Secretary concerned of a plan of operations covering proposed surface-
disturbing activities within the lease area.”
The application form (APD form 3160-3) must include a drilling plan, a
surface use plan, and evidence of bond/surety coverage. The surface use plan should

7See 43 U.S.C. 1702(c) for the definitions of “multiple-use” and “sustained yield.”
8The surface managing agency or private surface owner has jurisdiction over surface
activities including surface disturbance. A surface managing agency may be the U.S. Forest
Service, or the state in which the leasing is going to take place. A private surface owner may
be an institution or an individual.
943 CFR 3162.3-1, Drilling Application and Plans.

contain information on drillpad location, pad construction, the method for
containment and waste disposal, and plans for surface reclamation.
The APD is posted for review for 30 days. Within 5 working days after the 30-
day period, the BLM consults with the surface managing agency, whose consent is
also required, then notifies the applicant of the results. BLM is required to process
the application within the 35-day period. The application may be approved, approved
with stipulations, rejected, or delayed for additional analysis or information. The
applicant is informed when final action is expected.
Despite the 35-day review requirement, a recent study by a trade association,
the Independent Petroleum Association of Mountain States (IPAMS), found that in
its region it took an average of 137 days to approve an APD in 2002, up from an
average of 84 days in 2001.10
Delays in the Permitting Process
One of the major reasons for delays in the issuance of drilling permits cited by
both BLM and IPAMS is the need to rewrite outdated RMPs because the surface
disturbance anticipated under approved activities may exceed the limits in the old
plan because increased natural gas leasing and development is taking place. In these
cases, oil and gas leases may have been awarded under an old RMP that must be
revised before a drilling permit can be issued. According to the BLM, there are
several such plans currently being revised.
Under FLPMA, section 1712, regarding Land Use Plans: “the Secretary [of the
Interior] shall with public involvement and consistent with the terms and conditions
of this Act, develop, maintain and, when appropriate, revise land use plans which
provide by tracts or areas for the use of the public lands.” Current planning
regulations require preparation of an environmental impact statement (EIS) under the
National Environmental Policy Act (43 C.F.R. 1601.06).
After a draft EIS is issued for public comment, an RMP can be approved by the
BLM State Director and published with an EIS and record of decision and filed with
the Environmental Protection Agency (EPA).
In testimony before the House Committee on Resources, IPAMS asserted that
rewriting RMPs can take as long as three years, when less than a decade ago the
average time was less than one year. The Association contends that the usefulness
of an RMP is now seven years, when in the past they may have been in place for as
long as 20 years.11 The rapid pace of coalbed methane (CBM) development, in
particular, has generated new land use concerns that some argue have not been
previously incorporated in the RMPs. Environmentalists contend that 20-year-old

10 Harvesting Energy: A Report on Natural Gas and Oil Development in the Inter-Mountain
West, IPAMS, February 2003.
11Testimony of Marc W. Smith, Independent Petroleum Association of Mountain States
(IPAMS), Public Lands Advocacy, before the U.S. House Committee on Resources,
Subcommittee on Energy and Mineral Resources, March 7, 2001.

plans are not a good basis for land management decisions. The need for a
revised/amended RMP would necessarily delay any site-specific analysis conducted
in the drilling permit process by the BLM and the surface managing agency. Thus,
even when an application for a permit to drill (APD) is in process, the BLM often
waits until the new RMP and EIS are complete before proceeding to any site-specific
analysis needed to grant the permit.
In April 2003, BLM announced new strategies to expedite the APD process.
These include processing and conducting environmental analyses on multiple permit
applications with similar characteristics, implementing geographic area development
planning for an oil or gas field or an area within a field, establishing a standard
operating practice agreement that identifies surface and drilling practices by oil and
gas operators, allowing for a block survey of cultural resources, promoting consistent
procedures, and revising relevant BLM manuals.12
Leasing Restrictions on Oil and Gas Resources
The availability of public lands for oil and gas leasing can be divided into three
categories: lands open under standard lease terms, open to leasing with restrictions,
and closed to leasing. Areas are closed to leasing pursuant to land withdrawals or
other mechanisms. Much of this withdrawn land consists of wilderness areas,
national parks and monuments, and other unique and environmentally sensitive areas
that are unlikely to ever be reopened to oil and gas leasing.13 Some lands are closed
to leasing pending land use planning or NEPA compliance, while other areas are
closed because of federal land management decisions on endangered species habitat
or historical sites. Some of those restricted areas may be opened by future
administrative decisions.
A BLM study14 determined that of the approximately 700 million acres of
federal subsurface minerals under the agency’s jurisdiction in 2000, approximately

165 million acres have been withdrawn from mineral entry, leasing, and sale, subject15

to valid existing subsurface mineral rights. Lands in the National Park System
(except National Recreation Areas), Wilderness Preservation System, and the Arctic
National Wildlife Refuge (ANWR) are among those that are statutorily withdrawn.
Also of the 700 million acres, mineral development on another 182 million acres was
subject to the approval of the surface management agency, and must not be in
conflict with land designations and plans, according to the BLM. Wildlife refuges

12DOI/BLM Instruction Memorandum No. 2003-152, Application for Permit to Drill (APD)
Process Improvement #1 — Comprehensive Strategies, 4/14/03.
13Statutory and other types of withdrawals are discussed in greater detail in Appendix B.
14Public Lands, Onshore Federal and Indian Minerals in Lands of the U.S., Responsibilities
of the BLM, by Sie Ling Chiang, U.S. DOI /BLM, December 1, 2000.
15When valid existing rights are in place, producers are sometimes allowed to continue or
begin production on these lands. Sometimes they are provided compensation either through
a buyout or a land swap by the federal government.

(except ANWR), wilderness study areas, and roadless areas are examples of lands in
this category, although many other wildlife refuges also are withdrawn from leasing.
Public lands that are open to leasing may be subject to a variety of restrictions
imposed by the Department of the Interior. Such restrictions include leasing with no
surface occupancy, areas generally off-limits with the exception of directional
drilling; leasing with timing limitations, which protect wildlife during certain times
of the year; and leasing with controlled surface use, which requires a mitigation plan
for specific areas under the lease. Industry sources claim some of these lease
stipulations are so stringent that they constitute “de facto” closures to oil and gas
development. However, development has proceeded under some of these
Energy and mineral industry representatives maintain that federal withdrawals
inhibit exploration and limit the reserve base even when conditions are favorable for
production. The industry argues that substantial amounts of public land have been
unnecessarily withdrawn through administrative actions to pursue preservation goals.
However, environmental groups and others generally contend the withdrawals are the
most effective protection for the non-mineral values of public lands.
Rocky Mountain Region
The Rocky Mountain region accounts for 37% of the natural gas and 17% of the
crude oil projections of the technically recoverable resource base on public lands in
the lower 48 states.16 According to the EPCA study noted below, 60% of the
undiscovered resource base in the five basins studied in the Rocky Mountain region
is on public lands and about 40% of that amount is not accessible or is subject to
lease stipulations and restrictions.17 Because of increased interest in access to natural
gas, the protection of public lands and Bush Administration policies, the Rocky
Mountain region has become a focal point for U.S. oil and gas policy.
Three recent reports have studied restrictions on natural gas in the Rocky
Mountain region:
!Natural Gas, Volume 1 Summary Report by the National Petroleum Council
(NPC); 1999.
!Energy Policy and Conservation Act Amendments (EPCA) study, 2003;18

16U.S. Natural Gas Markets, Mid-Term Prospects for Natural Gas Supply: Analysis of
Federal Access Restrictions, DOE/EIA, 2001
17 Of the total federal land base used in the EPCA study, 36% is closed and 26% available
with restrictions.
18The EPCA study, Scientific Inventory of Onshore Federal Lands’ Oil and Gas Resources
and Reserves and the Extent and Nature of Restrictions or Impediments to their
Development, was required by the Energy Policy and Conservation Act Amendments of

2000, P.L. 106-469 section 604, prepared by the U.S. Departments of Interior, Agriculture,

and Energy, January 2003.

!U.S. Natural Gas Markets: Mid-term Prospects for Natural Gas Supply, 2001,
by the EIA.
While the EIA and NPC studies include data for total domestic natural gas
supplies, the EPCA Report more narrowly confines itself to five major geologic
basins within the Rocky Mountain region.19 The most direct comparison of data on
the Rocky Mountain region would be between the EIA and NPC studies because they
define the region as essentially the same.20
Even though the resource base was different in each of the three studies, the
relative amounts of natural gas on federal lands found to be either closed, restricted,
or open to development was about the same.
Data from the 1999 NPC study indicate the natural gas resource base in the
Rocky Mountain region is 335 trillion cubic feet (tcf). More recent data from EIA
estimates technically recoverable21 natural gas resources, excluding reserves, to be
293.6 tcf.22 The EPCA study found 138.5 tcf in the five major geologic basins in the
Although oil and gas reserves are not included in the EIA report, the relative
amounts of natural gas closed and restricted is similar to the amounts found in the
other studies. For example, the NPC reports that 9% of the region’s natural gas
resource base is closed and 32% restricted, while the EIA data shows that 11.5% is
closed and 37% restricted (see Table 1). The NPC and EIA studies report a more
significant difference between the amount of natural gas open to leasing: 60% and
51.5% respectively, also shown in Table 1. This difference is probably because a
larger portion of the proven reserves (excluded from the EIA report) are available for
leasing. For instance, the EPCA study found that about 26 tcf of proven reserves are
on federal lands out of 43 tcf total in the five major geologic basins. Of this total,
63% is open under standard lease terms. If the Rocky Mountain reserves were
included in the EIA report, then the percentage of natural gas open under standard
lease terms would likely increase, and the percentage of natural gas characterized as
under restrictions would likely decline.
Oil resources in the Rocky Mountains that were examined in the EPCA study
have somewhat less significance relative to U.S. oil supply. The study concludes that
about 600 million barrels of oil resources (about 30 days of total U.S. consumption)
fall under the “no access” category. Another 3.2 billion barrels would be available

19The five major geologic basins in the interior West are as follows: the Paradox San Juan
Basins in Colorado, Utah, and New Mexico; Uinta/Piceance Basins in Colorado and Utah;
the Greater Green River Basin in Wyoming, Colorado, and Utah; the Powder River Basin
in Montana and Wyoming; and the Montana Thrust Belt in Montana.
20The Rocky Mountain region includes the following states: Arizona, Colorado, Idaho,
Montana, Nevada, western New Mexico, North Dakota, Utah, and Wyoming.
21These are in-place resources that are producible using current recovery technology but
without reference to economic profitability.
22U.S. Natural Gas Markets: Mid Term Prospects for Natural Gas Supply, EIA, Department
of Energy, 2001.

for leasing, of which one-third have restrictions. About 2.5 billion barrels of oil are
estimated to be available on non-federal lands in the basins studied. The total oil
resource included in the EPCA study represents about 7% of all technically
recoverable oil in the United States.
As mentioned earlier, the numbers in the EPCA study are based on a much more
selective area of the Rockies that included the five major geologic basins, and thus
the numbers were smaller. However, as shown in Table 1, the relative rate with no
access was similar to the other reports (11.6%), the amount of restricted gas was less
(26%), and the amount of natural gas under standard lease terms was slightly higher
Both the NPC and EIA studies conclude that development of natural gas in the
restricted land use category would be — at a minimum — likely to face costly delays.
The EIA also concludes that if there were greater flexibility in some of the federal
regulations, about 29 tcf could become immediately available from this restricted
category. Additionally, if certain lease stipulations were removed, about 51 tcf would
be less costly to develop, thus freeing up a total of 80 tcf, according to the EIA report.
Environmental groups argue that there is an ecological basis for most of these
restrictions and that environmental assessments or impact statements are incomplete.
From this perspective, to relax these development restrictions would put the
environment at greater risk.
Table 1. Rocky Mountain Natural Gas Resources
NPC, 199923EIA, 2001EPCA, 2003
TCF% ofTCF% ofTCF% of
Rocky Mtn.335a 293.3138.5
Natural Gas(federal)(federal,(federal)
Closed to
oil and gas 29933.611.51611.6
Restricted 108 32 108.5 37 36 26
Open, no
restrictions 198 59 151.2 51.5 86.5 62.4
a The NPC study estimates that 41% (137 tcf) of the total amount of gas resources in the
Rocky Mountain region is either closed (29 tcf) or restricted (108 tcf). Thus, 335 tcf would
be the estimated total amount of natural gas resources in the region as of 1999.

23 A more recent NPC study: Balancing Natural Gas Policy Fueling the Demands of a
Growing Economy, Volume 1 September 25, 2003, concluded that 69 tcf were “effectively”
off-limits and an additional 56 tcf (125 tcf total) were affected by regulatory requirements
which could lead to development delays or plan cancellations.

Significance of Access Restrictions
Substantial oil and gas reserves are located on public lands, but there are major
policy disagreements about the potential importance of those reserves in meeting
U.S. energy needs. The Rocky Mountain region represents an estimated 37% (293
tcf/788 tcf) of the unproved technically recoverable natural gas resource base in the
United States, onshore lower 48.24 If the estimated 108 tcf of natural gas in the
Rocky Mountain region currently restricted were produced, it could last between 20-
30 years, assuming a production rate of about 4 tcf to 5 tcf per year, according to the
EIA; this would meet about 15% of projected annual U.S. demand. Currently, U.S.
natural gas demand is being met with supplies from the outer continental shelf (OCS)
(25%), imports (15%), the Rocky Mountain region (15%) and other onshore (45%).25
Testimony by The Wilderness Society (TWS) before the House Subcommittee
on Energy and Mineral Resources, March 15, 2001, based on the NPC report,
asserted that the United States has sufficient natural gas supply to meet domestic
needs for the next 40 years.26 This conclusion was based on annual demand growing
from 22 tcf in 2001 to 31 tcf in 2015. Also, based on the NPC figure of 1,466 trillion
cubic feet as “technically recoverable resources in the U.S.,”27 of which 115 tcf is
classified as off-limits (39 tcf onshore, 76 tcf offshore), TWS concludes that 1,351
tcf of natural gas could be available for development in the future. In other words,
from this perspective ample supply is available now and possibly in the future
without disturbing the resources in restricted or no-access areas. The NPC report
estimated that about 16% of the 1,351 tcf cited by TWS is subject to restrictions that
may prevent development.28
The NPC argues that 70 tcf of Rocky Mountain natural gas is under restriction
or lease stipulations and otherwise could be brought into production in the near term.
The NPC contends that there are a number of impediments that could be resolved to
ensure access to this gas in a timely fashion, and proposes relaxing certain land-use
constraints that would allow for more drilling on federal lands in the intermountain
west. Among these constraints include the use of “no surface occupancy”designations
that make resources “effectively” off-limits, use of stipulations to protect
environmental resources that it believes are too restrictive, and old access restrictions

24U.S. Natural Gas Markets: Mid-Term Prospects for Natural Gas Supply, EIA/DOE, 2001.
25Annual Energy Outlook, 2004 DOE/EIA -0383, January 2004, p.90.
26Testimony of David Alberswerth, The Wilderness Society, regarding “Domestic Natural
Gas Supply and Demand: The Contribution of Public Lands & the OCS,” before the U.S.
House Resources Committee’s Subcommittee on Energy and Mineral Resources, March 15,


27 Defined as discovered and undiscovered oil and gas resources expected to be producible
given current technology without regard to economic viability.
28This is based on 137 tcf restricted in the Rocky Mountain region and another 76 tcf
restricted in the OCS. See NPC Summary Report, Volume I, December 1999, pages 12-13.

that do not consider new technology that could minimize damage to the
The RAND Corporation produced an Issue Paper in 200230 asserting that the
debate needs to be more focused on the reserve category of the resource base.
RAND’s view is that access restrictions should be considered only for the resource
category that is most viable — or most likely to be produced. Under this view, the
amount of the resource considered to be restricted becomes much less. However, the
analysis would be complicated by the rate at which oil and gas resources were
assumed to be converted to reserves during the next 15-20 years.
Oil and Gas Resources and Production on Public
Federal Onshore Oil and Gas Production
Total U.S. oil production was nearly 1.9 billion barrels in 2002, down from 2.5
billion barrels in 1991. Oil production is forecast to fall by 0.4% annually, from 5.8
million barrels per day (mbd) in 2002 to 5.3 mbd in 2025. And oil imports are
estimated to account for nearly 65% of total U.S. supply in 2025. Total production
of natural gas was 19.4 tcf in 2002, up from 17.8 tcf in 1993.31
In 2002, oil production from federal onshore leases was estimated at 5.4% of all
U.S. oil production (see Table 2).32 Federal onshore oil production is concentrated
in three states which produce 79% of onshore federal oil: Wyoming (33%), New
Mexico (29%), and California (17%). Oil production from onshore federal leases has
fluctuated over the years but has generally been in decline over the past 10 years,
falling from 133.5 million barrels in 1992 to about 100 million barrels in 2002.
According to the EIA, U.S. production of natural gas varied between 18-20 tcf
annually between the years 1993-2002. Various projections show U.S. natural gas
production reaching between 20 tcf - 24.3 tcf by 2025.33 Imports from Canada are
forecast to rise to 3.7 tcf in 2010, then fall to 2.6 tcf in 2025. Higher EIA forecasts
of Canadian natural gas for the year 2025 were adjusted downward because of
Canadian reports of declining gas production, less certain offshore supplies and
greater use domestically in the production of oil sands, expected to triple by 2025.

29Natural Gas, Volume I Summary Report by the National Petroleum Council, 1999, P. 28.
30A New Approach to Assessing Gas and Oil Resources in the Intermountain West, IP-225-
WFHF, RAND Corporation, February 2002.
31U.S. DOE/EIA, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2002
Annual Report. p. D.-18.
32U.S. Department of Energy, Energy Information Administration, U.S. Crude Oil, Natural
Gas and Natural Gas Liquids Reserves, 2001
33DOE, Annual Energy Outlook, 2004, p. 112.

Imports of liquefied natural gas (LNG) were projected to rise from 170,000 bcf in

2002 to 4.8 tcf in 2025, according to the EIA.34

Table 2. U.S. Oil Production, 2002
Million Barrels% of U.S. Total
Federal Onshore*1005.4
Private/State Onshore 1,26167.3
Federal Offshore 48325.7
State Offshore311.6
U.S. Total1,875100
Source: EIA, 2002, p. 22.
* Based on an Minerals Management Service (MMS) estimate for FY2003.
Gas production on public lands has increased to 2.2 tcf in 2002 from 1.7 tcf in
1993 and accounts for 11.5% of all U.S. production (see Table 3). Of the 2.2 tcf
total, New Mexico accounts for 50% and Wyoming 35%; these rank as the top two
states in natural gas production on public lands, accounting for 85% (1.87 tcf) of the
total. The federal onshore share of total U.S. domestic oil and gas production is not
expected to change significantly in the near term.35
Table 3. U.S. Natural Gas Production, 2002
Trillion Cubic Feet% of U.S. Total
Federal Onshore*2.211.5
Private/State Onshore 12.564.5
Federal Offshore 4.523.0
State Offshore.21
U.S. Total19.3100
* Based on MMS FY2003 estimate from Mineral Revenues Report..
Source: EIA Annual, 2002, p. 30.

34DOE, EIA , Annual Energy Outlook, 2002.
35DOE/EIA, U.S. Crude Oil, Natural Gas and Natural Gas Liquids Reserves, 2001.

U.S. Oil and Gas Reserves and Resources
Proved U.S. oil reserves36 were 22.7 billion barrels of oil (BBO) as of December

31, 2002; natural gas liquids were estimated at 8 billion barrels and natural gas (dry)

reserves are 187 tcf37 according to EIA (see Table 4). Texas leads the United States
in both oil and natural gas reserves (see Table 5). U.S. oil reserves have declined by
1.2 billion barrels over the past 10 years, while U.S. production declined by 500
million barrels.
The 2.5 billion barrels of recoverable oil discovered in 2001 was three times38
greater than the average annual discovery since 1976 (890 million barrels).In 2002,
the discoveries were about 950 million barrels or 6% over the annual discovery
average since 1976. There are still substantial amounts of oil available and likely to
be produced from existing fields and from undiscovered reserves in the United
States, but the rate of production will likely continue declining over the long term.
As indicated by EIA, technically recoverable onshore and state offshore oil resources39
are estimated at 92 billion barrels, not all of which is likely to be recoverable.
Table 4. U.S. Proved Oil and Gas Reserves and Production,
Billion barrels of oil (BBO)Trillion cubic feet
Oil ReservesOil ProductionGas ReservesGas Production40
1993 22.9 2.3 162.4 17.8
1994 22.4 2.3 163.8 18.3
1995 22.3 2.2 165.1 17.9
1996 22.0 2.2 166.5 18.9
1997 22.5 2.1 167.2 19.2
1998 21.0 2.0 164.0 18.7
1999 21.7 1.9 167.4 18.9
2000 22.0 1.9 177.4 19.2
2001 22.5 1.9 183.5 19.8
2002 22.6 1.9 187.0 19.4
Source: EIA, U.S. Crude Oil and Natural Gas, Annual Report, 2002.

36Proved reserves are defined by the EIA as the estimated quantities which geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions.
37DOE, EIA 2003, p. 4.
38EIA, 2001, p. 7.
39DOE/EIA, U.S. Crude Oil, Natural Gas and Natural Gas Reserves, November 2002.
40Coalbed methane production is included in these totals. CBM production increased from

348 bcf in 1992 to 1.6 tcf in 2001.

Table 5. U.S. Proved Oil and Gas Reserves, by State, 2002
Leading States: OilBBOLeading States: Natural Gas41tcf
T e xas 5.0 T e xas 44.3
Alaska 4.7 Wyoming 20.5
California3.6New Mexico17.3
Federal Offshore5.0Oklahoma14.9
Other 4.4 Colorado 13.9
Federal Offshore25.2
U.S. Total22.7U.S. Total186.9
Source: EIA, U.S. Crude Oil and Natural Gas and NGL Reserves 2002, Annual Report.
The natural gas story may be different, as the United States has seen its gas
reserves increase by 16.5 tcf (10%) since 1991; production has also risen. At the
same time, U.S. gas imports have risen to 17% from about 9% in 1991.42 Annual
discoveries were up 70% above the average since 1976 (i.e., 22.8 tcf compared
to12.7 tcf). Technically recoverable gas resources onshore and state offshore are
estimated by the EIA to be about 1,000 tcf, over five times the amount of current
proved reserves. Over two-thirds of the total amount of onshore natural gas (proven
and undiscovered) is on nonfederal land and may be available for exploration and
The 2002 oil and gas resource assessment records an estimated 1.9 billion
barrels of oil, 183 tcf of natural gas and 3.1 billion barrels of natural gas liquids as
undiscovered resources located within five priority basins in the Rocky Mountain
West. Over 90% of the undiscovered gas is classified as unconventional; 25% (42
tcf) is coalbed methane. Of the proven reserves in five major basins in the Rocky43
Mountain region, oil and natural gas liquids on public lands accounted for 53.6%,
while 60.1% of natural gas was on public lands (see Table 6).

41Coalbed methane accounts for 17.5 tcf or 9.5% of the total.
42 DOE. EIA 2002 Annual Report G 3. For more historical data on oil and gas reserves and
production (from 1977-2002) see Appendix D in the EIA report.
43 Natural Gas Liquids are usually the heavier hydrocarbons separated out of natural gas,
such as propane.

Table 6. Rocky Mountain Proved Reserves (Five major basins)
Oil and Natural Gas% FederalNatural Gas% Federal
(million bbl)
799.3 53.6 42.9 60.1
Source: EPCA Study, p. A6-18, January 2003.
Recent estimates by the EIA indicate that federal onshore oil is 12.5% of all
technically recoverable oil. Natural gas on public lands is estimated to account for
22.3% of all technically recoverable gas. EIA estimates undiscovered conventional
oil to be 30.1 billion barrels and undiscovered conventional natural gas resources at
319.7 trillion cubic feet. The estimate for undiscovered unconventional natural gas
is even greater at 358.7 tcf (see Table 7).
Table 7. Total Onshore Technically Recoverable Resources,
OilNatural GasNatural Gas Liquids
(BBO)(tcf)(billion barrels)
Undiscovered Conventional30.1319.78.1
Undiscovered Unconventional2.1358.72.1
Discovered Ultimate Recovery60322.013.4
T otal 92.2 1,000.0 23.6
Percent Federal2432.034.7
Source: EIA, Annual Report, 2002.
Growing Role of Coalbed Methane
Coalbed methane gas is natural gas dissolved in water and trapped in a coalbed.
There are several important variables that determine the quantity of methane gas,
including the depth of coal, pressure, temperature, thickness, and composition.
To extract coalbed methane (CBM), water must be removed from the coal by
pumping, which drops the water pressure that traps the gas and allows the gas to
flow. Some operators fracture coal formations and allow water and gas to move out
of the coal. Concerns have arisen concerning groundwater contamination. The USGS
reports that the water pumped out of coal beds can vary in quality. Some water can
be discharged near the surface for reuse if “sufficiently fresh,” or if the water does
not meet reuse standards, it can be disposed of by subsurface injection or surface

discharge into wetlands, streams, or impoundments.44 Water quality and water
disposal have become central concerns in the production of CBM.
A 1980 tax credit (section 29) for unconventional fuel production provided a
major incentive for CBM development. Significant production of CBM began in
1987. Production has increased four-fold since 1991, and coalbed gas accounted for
about 8% (1.6 tcf) of the 18.8 tcf of natural gas produced in 2002 in the United
States.45 In 2002 there were 10,000 CBM wells also producing 1.65 million barrels
of water46 per day. The leading producers are in New Mexico, Colorado, and
Wyoming. Production rates vary widely because of the heterogenous geology of
coalbeds. DOE estimates that out of the 39,000 new wells anticipated by 2010,

23,900 will be on federal lands.47

CBM reserves are still largely undeveloped. Of the estimated 700 tcf of coalbed
methane in the United States, only about 100 tcf are classified as economically
recoverable. The previously discussed EIA study of U.S. oil and gas resources found
that of the 293 tcf of unproved technically recoverable unconventional fuels in the
Rocky Mountain region, about 46 tcf are coalbed methane, of which about 20%
would fall under the “no access” category. Coalbed methane proved reserves were
18.5 tcf in 2001, which was 10% of U.S. dry gas reserves. CBM reserves have more
than doubled since 1991. Two states, Colorado and New Mexico, account for more
than half of U.S. CBM reserves. Wyoming, Utah, and Alabama also have significant
reserves. The San Juan Basin48 is the most productive. It contains 65% of known
reserves and 80% of production. The Warrior Basin in Alabama is the second most
productive, claiming 9% of U.S. production and 8% of reserves.49 USGS estimates
CBM resources in the Powder River Basin (PRB) at 39 tcf.50
The federal government owns over half the mineral rights in the PRB, while the
majority of the surface rights are held privately, resulting in spilt-estates. However,
most of the current production of CBM is taking place on private lands. Over 80%

44Coal-Bed Methane: Potential and Concerns, USGS Fact Sheet FS — 123 — 00, October


45USGS Fact Sheet, FS-110-01 Coalbed Gas Resources of the Rocky Mountains, 11/01.
46 One barrel is equal to 31.5 gallons. Thus, about 52 million gallons of water were produced
each day.
47Powder River Basin Coalbed Methane Development and Produced Water Management
Study, U.S. Department of Energy, Office of Fossil Energy, DOE/NETL 2003/1184,
November 2002.
48The San Juan Basin is located in northeastern New Mexico, parts of southwestern
Colorado, and southern Utah.
49The Orderly Development of Coalbed Methane Resources From Public Lands, Oversight
Hearing before the Subcommittee on Energy and Mineral Resources of the Committee on
Resources , U.S. House of Representatives, Statement of Dr. Gene Whitney, U.S. geological
Survey, September 6, 2001.
50Powder River Basin Coalbed Methane Development and Produced Water Management
Study, U.S. Department of Energy, Office of Fossil Energy and National Energy Technology
Laboratory Strategic Center for Natural Gas, DOE/NETL-2003/1184, November 2002.

of the land overlying of CBM wells is privately or state held in Wyoming, and some
surface owners oppose development and others contend they are not compensated
fairly for surface use.51 A number of concerns has come up regarding surface use
agreements between the surface owner and the mineral lessee or mineral owner. The
central concern for the surface owner is receiving adequate compensation for
damages from CBM or production from other extractive industries. In Wyoming,
stakeholders such as the Petroleum Association, ranchers and the Farm Bureau
Federation established the Wyoming Split-Estate Initiative in 2002. They have
created a new framework to help resolve conflicts between surface owners and
mineral owners or lessees.52
CBM Environmental Issues
Environmental concerns about CBM production focus primarily on land
disturbance and water — both surface and ground water issues. Production of CBM
can involve not only wells but also access roads, power lines, compressor stations,
and waste water impoundments. Major issues include surface infrastructure, the net
amount of water removed, effects on the water table, and the salinity levels and
disposal of the water removed, which may affect wildlife, land and surface water
The process of hydraulic fracturing53 for CBM production has come under closer
scrutiny because of concerns over the possible impact of the injected fluids (such as
diesel fuel) used in the process on underground drinking water. A draft EPA report54
concluded that there is no evidence of contamination of drinking water wells from
CBM hydraulic fracturing. However, the EPA did express concern over the use of
diesel fuel as an injection fluid because it contains many of the EPA’s “constituents
of concern”, (chemicals). Thus, the EPA and the major companies using diesel fuel
entered into an Memorandum of Agreement (MOA) in December 2003, to end the
use of diesel fuel as an injecting fluid. Proposed energy legislation (H.R. 6 and S.
2095) include provisions that would prohibit EPA from regulating underground
injection of fluids for hydraulic fracturing purposes under the Safe Drinking Water
Act. (See CRS Report RS21673.)
Dennis Hemmer of the Wyoming Department of Environmental Quality
explained in an energy newsletter that most water from CBM production does not

51 Oversight Hearings before the Subcommittee on Energy and Mineral Resources of the
Committee on Resources, U.S. House of Representatives, Orderly Development of Coalbed
Methane Resources from Public Lands, September 6, 2001.
52Pamphlet on the Wyoming Split-Estate Initiative, (see [http://www.wysei.com] for details).
53 The technique of hydraulic fracturing consists of pumping fluids into a well until the coal
formation cracks. This process allows for the easy flow of natural gas from the coal seam
into the production well.
54Draft Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic
Fracturing of Coal bed Methane Reservoirs, EPA 816-D-O2-006, U.S. Environmental
Protection Agency, August 2002.

flow to surface supplies but rather seeps into underground aquifers and formations.55
As a result, wells being used for drinking water may become polluted with sodium-
tainted water.
CBM production resulted in water discharges of 602 million barrels annually
or 1.65 million barrels per day in 2002, typically into surface waters or holding
ponds. Water is also reinjected underground. Environmentalists contend that holding
ponds are like wastewater treatment ponds that are unlined and leak into
groundwater. There is concern about the lowering of the water table and the effects
on wells and water sources used by wildlife. The Wildlife Management Institute of
Washington D.C. argues that CBM production and the disposal of high volumes of
water may lead to, among others things, the depletion of underground aquifers, the
loss of natural vegetation, and aquatic life within waterways that receive CBM water.
Further, the infrastructure required by CBM production may threaten wildlife
In response to concerns over the impact of CBM on groundwater quality and
quantity, BLM has required CBM producers to drill two monitoring wells per
township with CBM leases since 1992. The cost of drilling each well is about
$50,000, plus an additional $5,000 for monitoring equipment. After BLM review, it
was established that one set of wells (one shallow and one deep) is required per four
townships with CBM leases. The wells monitor both the water quality and water
levels from CBM production. On private lands, monitoring wells are not required57.
The Interior Board of Land Appeals (IBLA) invalidated three leases in April

2002 because environmental issues related to CBM production, as discussed above,

were not evaluated sufficiently. Supplemental environmental assessments (EA) were
prepared for the Powder River Basin to help determine where to develop CBM in
areas already approved for leasing.58 Generally, the results have allowed more CBM
drilling to occur; however, there have been new conditions imposed upon some
An environmental group, the Wyoming Outdoor Council (WOC), sued BLM to
withdraw additional leases — four parcels totaling 3,800 acres — from a June 2002
sale in Wyoming because it violated an April 26, 2002, IBLA ruling that directed the
BLM to update a 1985 resource management plan (RMP) before offering CBM
leases in the Powder River Basin. After the suit, BLM did not proceed with any lease
sales on public lands with high CBM content, including the four parcels that
prompted the suit, while the IBLA ruling was being interpreted by Bureau attorneys.
The IBLA dismissed the case December 18, 2003. The Wyoming BLM office
finalized a new EA and RMP and reportedly is anticipating approving 39,000 permits

55 Inside Energy/with Federal Lands, September 10, 2001, p.10.
56The Orderly Development of Coalbed Methane Resources from Public Lands, Oversight
Hearings before the Subcommittee on Energy and Mineral Resources, September 6, 2001.
57Personal communication with the BLM Field Office, Casper WY. January 2004.
58 Inside Energy, June 3, 2002, p. 12

for new wells over a 10- year period. A decision to begin issuing permits was made
by the DOI in July 2003.59
Outlook for Oil and Gas Development on Public
Demand for oil is forecast to rise 1.6% annually to 28 mbd by 2025 in the EIA
reference case. Because consumption would rise faster than domestic production,
imports are projected to reach nearly 65%. U.S. demand for natural gas is forecast to
rise 1.4% annually, reaching 31.4 tcf by 2025.
The outlook is mixed for increased oil and natural gas production from leases
on U.S. public lands or areas where the United States holds mineral rights. While
domestic natural gas production and natural gas imports are expected to rise, it is
unclear how much of the domestic supply will come from public lands that are
currently restricted or off-limits. The Bush Administration has initiated actions to
ease restrictions in instances where this can be done administratively. How much
opposition these initiatives will generate is unclear. The media has reported
challenges based on alleged violations of BLM’s multiple-use mandate. Areas
statutorily removed would require congressional action to change their status. On
available lands, production of conventional natural gas is expected to remain steady,
even though significantly more wells and higher-cost deeper wells will be drilled.
Onshore unconventional natural gas (over 70% located in the Rocky Mountain
region) is forecast to increase its share from 32% in 2002 to 43% of production in
the lower 48 by 2025. The central concern for industry is to have greater access to
federal lands believed to possess oil and gas potential and to expedite the permitting
process. Environmental groups and some surface owners are concerned that drilling
and production would damage sensitive lands, wildlife habitat and surface water and
groundwater quality and quantity.
Meeting U.S. energy demand will likely occur by using a mix of increased
domestic output plus higher imports. The Rocky Mountain region might account for
as much as 40% of U.S. natural gas production in 2025, up from about 25% in
2002.60 The United States will likely rely more on natural gas imports, primarily LNG
from stable countries, as well as increased production from the deepwater OCS. A
proposed Alaskan natural gas pipeline, if built, could provide 2.71 tcf by 2025.
Oil and gas firms continue worldwide exploration and development seeking
the best return for their investment; a significant resource base, political stability,
and financing are factors considered when making investment decisions. The
United States scores well for political stability and its resource endowment is still
attractive, but other concerns such as the impact on the environment, on residents
and society must be weighed in making public land use decisions.

59Inside Energy August 25, 2003, p.1.
60Annual Energy Outlook, 2004, DOE/EIA-0383, U.S. Department of Energy, January 2004.

Appendix A. Terms of an Oil and Gas Lease
The terms for a competitive lease are:
!Maximum acreage — 2,500 acres, except Alaska — 5,760 acres
!$2/acre minimum bonus bid five-year term
!Bond requirement — $10,000
For noncompetitive leases, the terms are:
!Maximum acreage — 10,240 acres in all states
!No minimum bonus bid
!10-year term
!$75 application filing fee
!Bond requirement — $10,000
Rents and royalties on competitive and noncompetitive leases are:
!Rentals — not less than $1.50/acre for 1-5 years
!Rentals — not less than $2/acre each year thereafter
!Royalty — not less than 12.5% in amount or value of the production
removed or sold from the lease
Table 8. Oil and Natural Gas Production in U.S.
Onshore Federal Lands, 1991-2000
YearOilGasRoyaltiesBonus Bids
in milliontcf$ (millions) ($ millions)
1991 133.1 1.2 518 41.5
1992 133.5 1.3 524 18.8
1993 126.7 1.7 583 22.8
1994 119.2 1.8 525 41.4
1995 121.6 1.7 443 47.3
1996 121.5 1.9 542 32.0
1997 117.3 1.94 691 58.5
1998 111.6 1.92 553 77.2
1999 103.9 1.96 565 169.6
2000 108.2 2.1 968 52.3
Source: MMS, Mineral Reserves, 2000, p.80.

The onshore leasing program brings in significant annual revenues to the U.S.
Treasury. Revenues include bonus bids, rents and royalties (see Table 8). The
revenues are collected by the Minerals Management Service (MMS, an agency within
the Interior Department) and distributed to states, the General Fund of the U.S.
Treasury, and other designated programs. All states except Alaska receive 50% of the
revenues collected from public land oil and gas leases within their boundaries.
Alaska receives 90% of all revenues collected. Revenues from federal leases vary
widely over the years because of price fluctuations; for example, revenues increased
significantly in 2000 over 1999 because of higher oil and gas prices. The number of
federal oil and gas leases stood at 23,000 and encompassed over 17 million acres of
federal public lands in 2001.
Appendix B. History of Public Land Withdrawals
The first public lands withdrawal took place in 1872 to establish Yellowstone
National Park, and since that time Congress has created other national parks at
regular intervals.61 The National Park System (NPS) was created in 1916 to
“conserve the scenery and the natural and historic objects and the wild life [in
national parks] and to provide for the enjoyment of the same in such a manner and
by such means to leave them unimpaired for the enjoyment of future generations” (16
U.S.C. 1).62 In the early days of the NPS, its philosophy was not synchronized with
the Forest Service (FS). The FS philosophy was that “all the resources of the forest
reserves are for use and where conflicting interests exist the issue will be resolved
based on the greatest good for the greatest number of people in the long run.” Early
tension arose between “conservationists” promoting National Parks and “utilitarians”
promoting National Forests.63
Sources of Withdrawal Authority
During the early 1900s the focus of the public lands withdrawal debate was on
whether the Commander-in-Chief had authority to make the withdrawal order based
on national security. Withdrawals were defined as an administration action/order that
changed the designation of a specific parcel of land from available to unavailable for
activities ranging from homesteading to resource exploitation. The President acted
as chief custodian of the public lands and with tacit approval of Congress withdrew
public land from entry or location by the private sector. The Constitution vests
authority over public lands in Congress rather than with the Executive, but Presidents
have repeatedly exercised “an inherent power to withdraw” or reserve some lands.
A prime example is the establishment of military reservations out of public lands.

61Federal Public Lands and Resources Law, George Cameroon Coggins, et. al., Third
Edition, 1992, p. 116.
62Federal Public Land and Resources Law, p. 116.
63 Ibid. p. 117.

Withdrawals also occurred under the Antiquities Act of 1906 (16 U.S.C.A. 88,
433-431), the Taylor Grazing Act of 1934 (43 U.S.C. 315 et. seq.), the Organic Act
of 1897 (16 U.S.C.A. 473), the Alaska Native Claims Settlement Act of 1971 (43
U.S.C.A. 1601 et. seq.) and the Wilderness Act of 1964 (16 U.S.C.A. 1131-36).
National monuments can be created by the executive branch through statutory
delegation under the Antiquities Act. The President can reserve the “smallest area
compatible with the proper care and management” of the protected sites on federal
lands that contain historic landmarks, prehistoric structures, and other objects of
scientific interest. Under the Taylor Grazing Act, 140 million acres were withdrawn
from homesteading laws. The Organic Act was used to regulate and designate
recreation and “primitive areas.” Under FLPMA, withdrawals can be made by the
executive branch or the Congress.
Congressional designations as “wilderness” were later considered essential by
many because an administrative wilderness designation could be revoked
administratively any time. The Alaska Native Claims Settlement Act withdrew large
areas of Alaska from availability for resource use or development pending
congressional disposition. The Wilderness Act required that the Forest Service study

5.4 million acres of designated primitive areas and report on wilderness suitability.

Wilderness is generally defined as an area “off limits to development to avoid
destruction of pristine characteristics of nature.”64 The Wilderness Act states that “no
federal lands shall be designated as wilderness areas except as provided for in the
Wilderness Act or by an Act of Congress” (16 U.S.C. 1131 (a)).
Currently, there are four types of withdrawal: First, there are instances where
Congress has the sole authority to withdraw or reserve public lands. For example,
creating National Parks and wilderness areas and in some cases national wildlife
refuges can only be done by an act of Congress. Second, the executive branch has
used power delegated to it by Congress under the previously mentioned Antiquities
Act of 1906 and the Pickett Act of 1910. Third, Congress may withdraw specific
resources such as when oil, gas, coal, and like minerals were removed from the
General Mining Law of 1872. Lastly, there is the “general congressional”
withdrawal,65 which allows lands to be removed from potential development pending
“final disposition.”66
Withdrawals Under FLPMA
Modern executive withdrawals are governed by FLPMA.67 FLPMA68 established
a federal land use management policy that includes land use planning based on a
multiple-use approach that allows for significant public and congressional input.
Sections of FLPMA detail procedures (see 43 U.S.C. 1714 (d)) for the sales and
acquisition of public lands, withdrawals, and exchanges of public lands. Under

64Federal Public Lands and Resources Law, p. 1015.
65Federal Public Lands and Resources Law, p. 286
66 Ibid.
67 See footnote 2.
6843 U.S.C. 1701 et. seq.

FLPMA, withdrawals can be made by the executive or the Congress. The withdrawal
can be temporary or permanent.
FLPMA replaced the implied authority of the executive branch to withdraw
public lands with specifically defined procedures. Withdrawals of parcels exceeding
5,000 acres require congressional approval. The land can be withdrawn for 20 years
subject to renewal. Proposed withdrawals must be submitted to Congress with a
report explaining the reasons for the withdrawal in detail, effects on the economy and
environment, alternatives to withdrawal, how BLM is consulting with other agencies
and groups, and the geological and mineral potential of the areas proposed. The
Secretary of the Interior, however, can make emergency withdrawals of any size for
up to three years. A report must be available three months following a withdrawal.
FLPMA mandated a review of public land withdrawals in 11 Western states to
determine whether, and for how long, existing withdrawals should be continued (43
U.S.C. 1714(l)). There were millions of acres withdrawn prior to FLPMA. Under the
law, the Secretary of the Interior can determine whether and for how long the
continuation of existing withdrawals are consistent with statutory objectives of the
programs under which lands were dedicated in the first place.
BLM continues to review approximately 70 million withdrawn acres, giving
priority to about 26 million acres that are expected to be returned by another agency
to BLM, or, in the case of BLM withdrawals, become available for one or more uses.
As of November 2000, BLM had completed reviewing approximately 7 million
withdrawn acres, mostly BLM and Bureau of Reclamation land; the withdrawals on
more than 6 million of these acres have been revoked. According to the BLM
Manual, retention of a withdrawal requires a compelling show of need, and an agency
manager “recommending that lands not be opened to multiple use, particularly
mining and mineral leasing. That manager must convince the BLM Director, the
Secretary, and watchful segments of the public, that there is no reasonable alternative
to continued withdrawal or classification.” The review process is continuous over
the next several years, in part because the withdrawals must be considered in BLM’s
planning process and be supported by documentation under the National
Environmental Policy Act (NEPA).
Some lands, through revocation and terminations, could be developed for oil
and gas resources. Other areas deemed not suitable for mineral development, will
likely remained closed or restricted.