Considerations for Federal Leasing of Onshore Energy: Oil and Gas and Geothermal Power

May 10, 2024 R48064

Considerations for Federal Leasing of Onshore May 10, 2024
Energy: Oil and Gas and Geothermal Power
Morgan Smith
Both oil and gas (O&G) and geothermal power are longstanding energy sectors for the United
Analyst in Energy Policy
States. The two sectors have many similar characteristics including accessing subsurface

resources, having similar development timelines, using similar technologies and processes, and
Lexie Ryan
having similar types of environmental impacts. The technologies also have significant
Analyst in Energy Policy
differences. O&G is more mature, with more investment potential and more potential for

competition for leases, but it depends on finite, carbon-intensive resources. Geothermal power
has growth potential due to developing technologies like enhanced geothermal systems and the
Omar M. Hammad
potential to deliver lower-carbon electricity. But geothermal power also has challenges to greater
Analyst in Environmental
deployment, including high capital costs, difficult operating conditions, lower profit margins on
Policy
electricity compared to fossil fuels, and other market challenges. These similarities and

differences influence how current onshore federal leasing and permitting laws and regulations
impact each sector and can inform what changes might be relevant for the future management

and development of federal lands and resources.
The Bureau of Land Management (BLM) manages onshore federal lands pursuant to the Federal Land Policy and
Management Act (FLPMA; 43 U.S.C. §1701 et seq.). In accordance with FLPMA, BLM develops Resource Management
Plans to manage federal lands for multiple uses and to ensure a sustained yield of those lands and resources in perpetuity.
One of those uses is for energy development, including, among other commodities, O&G and geothermal energy. The leasing
authority for these resources comes from the Mineral Leasing Act of 1920 (MLA; 30 U.S.C. §§181 et seq.) and the
Geothermal Steam Act of 1970 (30 U.S.C. §§1001 et seq.), respectively. Additionally, leasing activities by BLM and
development activities by the lessee are subject to other federal laws such as the National Environmental Policy Act of 1969
(NEPA; 42 U.S.C. §4321 et seq.), the Clean Air Act (42 U.S.C. §7401 et seq.), and the Clean Water Act (33 U.S.C. §1251 et
seq.), as well as state and local laws governing resource use and protection. With respect to NEPA compliance for O&G and
geothermal development on onshore federal lands, some categorical exclusions (CXs) have been established in statute or
administratively that identify activities that normally do not have a significant impact on the quality of the human
environment and thus do not require further environmental reviews under NEPA.
Federal leasing terms and requirements may vary between O&G and geothermal development on federal lands. However,
both sectors have periodic competitive bidding processes (geothermal also has noncompetitive options) that require the lessee
to pay bids, rents (paid prior to energy production, based on the amount of land), and royalties (paid once production begins,
generally based on the value of the resource being accessed or extracted). Some of the lease terms are set by law at fixed
values, have established minimums, or may be left to BLM to determine based on agency objectives and best-use
determinations. The initial lease terms for both sectors are 10 years for the initial development, with total lease duration
subject to successful production and lease extension options. These leasing and permitting requirements and related costs
may result in under- or over-development of resources or in a resource development mix that does not best serve various
federal priorities. These priorities include BLM’s mission to ensure multiple-use and sustained yield of federal resources or
broader federal goals of providing a reliable electricity supply, ensuring energy security, reducing greenhouse gas emissions,
or providing for fiscal security through federal leasing revenue.
Congress has reviewed and may further consider a variety of topics associated with federal leasing and use of O&G and
geothermal resources. These topics could include:
• guidance or requirements for financial bonding—often used to support site reclamation after project
completion;
• lease terms to address non-productive leases and/or intermediate land uses;
• conditions for when competitive and noncompetitive leasing opportunities could be allowed;
• how much authority BLM has to set lease terms; whether such terms should be fixed values, minimum
values, or ranges of values; and their timeframes;
• requirements on applications for drilling permits and timelines for reviewing and deciding on them; and
appropriateness of the CXs available to O&G or geothermal projects to support resource development and/or to ensure proper
evaluation of environmental impacts.
Congressional Research Service

Federal Leasing of Onshore Energy: Oil and Gas and Geothermal Power

Oil and Gas and Geothermal Power Sectors
Congress plays a role in energy development on federal lands, including by providing authority
and guidance to federal agencies, such as the Bureau of Land Management (BLM), that are
responsible for resource management. BLM and other federal agencies support development of
both non-renewable and renewable resources on federal lands, which contribute significantly to
federal revenues, the energy supply for the U.S. economy, and other national priorities.
Oil and gas (O&G) and geothermal energy are two such resources. They have a variety of
similarities and differences that can affect their contributions to the U.S. economy and their
management as a resource. Review of these similarities and differences could help inform
Congress on whether to maintain the current laws and regulations or to make changes to best
serve federal priorities for managing and developing the lands and resources.
The federal government may seek to regulate and support both sectors’ development similarly
because these two energy resources share many general physical and operational characteristics.
These include similar subsurface location of resources; similar development processes and
timelines; similar resource identification, access, and production technologies; similarities in the
types of potential environmental impact considerations from their development; and similar
workforce knowledge and skillsets.
The federal government may seek to regulate and support these resources differently because of
different goals for their exploitation or because of the differences between the resources. These
differences include challenges related to accessing resources and their production (including
potential development risks, costs, and timelines as well as the need for technology development
and adaptations); the degree of emissions and other environmental impacts from development;
industry size, investment opportunities, and maturity including the long-term profit and
development potential; and how each resource can contribute to different national priorities or
future development scenarios.
The following sections describe how processes for leasing and permitting on onshore federal
lands are applied to O&G and geothermal energy. These sections note how these two resource
types are treated similarly or differently and provide context for federal O&G and geothermal
energy development regulations. The final section of this report discusses several issues for
potential congressional consideration, including bonding and project reclamation, productive and
non-productive leases, BLM authority to set lease terms, and application review processes.
The report does not cover development of other onshore energy resources on federal lands (such
as solar, wind, or coal) or of offshore energy resources. Conservation, environmental protection,
and other aspects of BLM’s multi-use mission are also outside the scope of the report, as are
commercial considerations including labor and access to capital. The intersection between leasing
and other environmental statutes outside of NEPA is not covered. Multiple other federal, state,
and local laws also may require permitting or other procedures for the approval and operation of a
O&G or geothermal project on federal lands, depending on the scope and nature of the activities,
potential environmental impacts, and other factors. This report focuses on select BLM processes.
Aside from NEPA, other applicable federal laws and regulations, as well as those at the state
level, are not covered.
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Federal Leasing of Onshore Energy: Oil and Gas and Geothermal Power

Development of Oil and Gas and Geothermal Resources in the
United States
O&G and geothermal power are two long-operating energy sectors in the United States. The first
successful well intended to produce natural gas was dug in 1821 in Fredonia, New York.1 The
first American natural gas company was formed in Fredonia in 1858. The first commercial well
drilled specifically for oil in the United States was the Drake Well near Titusville, PA in 1859.2
John Rockefeller invested in his first oil refinery near Cleveland, OH, in 1863, leading to the
creation of Standard Oil in 1870.3 O&G contributes 69% of total U.S. primary energy
consumption and supplies energy and products to a variety of industries including electricity
generation, heating, industrial and chemicals manufacturing, and transportation fuels.4 Even with
continued policy and market trends toward lower-carbon energy sources, O&G will likely
continue to play an important role for decades.
The world’s first geothermal district heating system was created in Boise, ID, in 1892,5 with the
first small-scale geothermal power plant (250 kilowatts) at The Geysers in California in 1922, and
the first large-scale commercial power plant (11 megawatts) in 1960.6 Geothermal power
contributes 0.2% of U.S. primary energy consumption in the form of electricity and direct use
(heating and cooling). Supporters of expansion of geothermal power identify it as a renewable
resource that could provide baseload electricity generation to support the changing electrical
grid.7 Additionally, new drilling and power generation technologies, including enhanced
geothermal systems (EGS), are enabling access to significant new amounts of geothermal power.8
The U.S. Department of Energy projects that geothermal power could provide 90 gigawatts of
electricity generation capacity by 2050 (3.9% of total projected U.S. 2050 capacity providing
12.0% of U.S. electricity).9

1 U.S. Energy Information Administration, “Energy Timelines—Natural Gas,” accessed April 24, 2024,
https://www.eia.gov/kids/history-of-energy/timelines/natural-gas.php.
2 American Chemical Society, “Development of the Pennsylvania Oil Industry,” https://www.acs.org/education/
whatischemistry/landmarks/pennsylvaniaoilindustry.html.
3 Keith Poole, “Biography: John D. Rockefeller, Senior,” accessed October 2, 2023, https://www.pbs.org/wgbh/
americanexperience/features/rockefellers-john/.
4 Energy Information Administration, “U.S. Energy Facts Explained,” August 16, 2023, https://www.eia.gov/
energyexplained/us-energy-facts/.
5 U.S. Department of Energy, “Energy Saver History Timeline: Geothermal Energy,” accessed October 2, 2023,
https://www.energy.gov/energysaver/energy-saver-history-timeline-geothermal-energy.
6 U.S. Department of Energy, “Energy Saver History Timeline: Geothermal Energy,” accessed October 2, 2023,
https://www.energy.gov/energysaver/energy-saver-history-timeline-geothermal-energy.
7 Energy Information Administration, “What is energy?” August 16, 2023, https://www.eia.gov/energyexplained/what-
is-energy/sources-of-energy.php.
8 Fervo Energy started operation of a 3.5 megawatt (MW) enhanced geothermal system (EGS) plant in Nevada in
November 2023. Other plants and demonstration projects are being developed at several sites in the United States. For
more details on EGS, see CRS Report R47256, Enhanced Geothermal Systems: Introduction and Issues for Congress,
by Morgan Smith; and U.S. Department of Energy, Geothermal Technologies Office, GeoVision: Harnessing the Heat
Beneath Our Feet, May 2019, https://www.energy.gov/sites/default/files/2019/06/f63/GeoVision-full-report-opt.pdf.
9 With 90 gigawatts (GW) of projected capacity, geothermal power could generate approximately 675 terawatt-hours
(TWh) of electricity. The U.S. Energy Information Administration’s 2050 projections for U.S. electricity supply are
2,172 GW of capacity and 5,520 TWh of electricity generation. Chad Augustine, Sarah Fisher, Jonathan Ho, Ian
Warren, and Erik Witter, “Enhanced Geothermal Shot Analysis for the Geothermal Technologies Office,” National
Renewable Energy Laboratory, January 2023, https://www.nrel.gov/docs/fy23osti/84822.pdf; Energy Information
Agency, Annual Energy Outlook 2023, 2023, https://www.eia.gov/outlooks/aeo/tables_ref.php.
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Federal Leasing of Onshore Energy: Oil and Gas and Geothermal Power

These two energy sectors share some general operational characteristics, including the subsurface
location of resources, general development timelines, technologies, and the types of potential
environmental impacts from drilling.10
• Both sectors access underground energy resources tied to specific geographical
locations. Accessing either resource involves many similar types of risks and
challenges, including lengthy project development timelines, difficult-to-access
resources, and potential well development failures.
• The two sectors use similar technologies and techniques, including drilling and
well-completion technologies, underground resource assessment technologies,
and power plant technologies (common to many thermal power generation
applications).
• Their workforces employ similar skill sets and knowledge bases. Development
requires related knowledge and understanding of geology and resource potentials.
• The two sectors can affect the environment similarly during drilling, including
that both have potential for ground water impacts; induced seismicity; and other
impacts from the use of drilling rigs and the construction of access roads, power
plants, and pipelines.11
The two energy sectors also have significant differences, including industry size and investment,
long-term profit and development potential, the degree of emissions and other environmental
impacts, and the applications for each energy type.
• Geothermal power is largely used for environmental heating or electricity
generation. Since geothermal power is renewable, the sustainable operation of
geothermal plants and the potential for expanded applications—from the
continuing electrification of industrial and residential markets—means
geothermal projects have the potential for long-term operations and sustained
profits.
• The knowledge of geothermal resources—including their location and subsurface
conditions—is generally more limited than fossil fuel resources.
• Geothermal projects—while facing some of the same general challenges as O&G
development—have unique operating conditions which generate different risks
and different chances of failure. In addition to navigating more uncertainty in
location and subsurface conditions compared to O&G, geothermal drilling
generally requires larger diameter wells with higher temperatures, faces harder
rock, and accesses deeper resources than O&G drilling. Additionally, geothermal
power plants tend to have higher capital costs than other similarly sized thermal
power projects, such as natural gas-fired plants, due to operational and plant
design factors—geothermal systems generally pump higher fluid volumes,
manage more challenging reservoir conditions (e.g., reservoir geochemistry, and
geofluid mechanics), and incorporate more complex plant designs to maximize
efficiency.
• Geothermal power produces low to no carbon emissions. Geothermal projects
also generate fewer byproducts or other wastes requiring handling and disposal.

10 For more details on comparison of these two industries, see CRS Report R47405, Oil and Gas Technology and
Geothermal Energy Development, by Morgan Smith.
11 The magnitude of these risks and impacts vary between energy types, as noted in the following section on
differences.
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Federal Leasing of Onshore Energy: Oil and Gas and Geothermal Power

• The O&G sector is larger, more mature, and generally better understood by
potential investors, developers, and other partners, which can decrease risks and
support more and/or easier project development. O&G has more capital available
for investment due to high productivity and high profit levels. Potential investors
and developers are more familiar with O&G risks, investments, benefits, and
markets. O&G also has a larger workforce and more extensive experience with,
and knowledge of, its underground resources.
• Some recent policy and social trends, such as environmental, social, and
governance (ESG), cast O&G resources as finite, fossil-fuel-based, carbon-
intensive energy sources, with the potential for a variety of negative
environmental and human impacts. Geothermal resources are renewable, low-
carbon energy sources, with more limited degrees of negative environmental and
human impacts. Some trends in corporate, social, and governmental policy and
markets such as greenhouse gas reduction goals, are pushing U.S. energy
development to include more renewable, carbon-free sources, which may include
geothermal energy.12
Bureau of Land Management’s Role in Energy and
Mineral Development
Leasing, exploration, and development of O&G and geothermal resources on federal lands is
managed by BLM. BLM, within the Department of the Interior (DOI), manages energy
production and mineral development from all federal surface lands and the federal subsurface
mineral estate, and assists in energy development projects on certain tribal lands (though it does
not lease those lands). BLM derives its general statutory authority for the management of federal
lands from the Federal Land Policy and Management Act (FLPMA).13 FLPMA directs BLM to
manage federal lands for “multiple use and sustained yield,” which encompasses “a combination
of balanced and diverse resource uses that takes into account the long-term needs of future
generations for renewable and nonrenewable resources, including, but not limited to, recreation,
range, timber, minerals, watershed, wildlife and fish, and natural scenic, scientific and historical
values.”14 Although FLPMA places some requirements and constraints on BLM’s implementation
of these “multiple use” and “sustained yield” directives, some discretion is left to the agency for
interpreting how best to comply with this statutory mandate.15
FLPMA requires BLM to develop, maintain, and—when appropriate—revise land use plans
(which BLM refers to as resource management plans—RMPs) for all managed lands in
accordance with the “multiple use and sustained yield” principle.16 An RMP describes the desired
outcomes, allowable uses, and anticipated management actions for a given area. BLM must
consider environmental impacts while developing RMPs, and therefore RMPs are developed

12 For more information on trends in energy, see CRS Report R46723, U.S. Energy in the 21st Century: A Primer,
coordinated by Melissa N. Diaz.
13 43 U.S.C. §§1701 et seq. For a background on the Federal Land Policy and Management Act (FLPMA), see Bureau
of Land Management (BLM), The Federal Land Policy and Management Act of 1976, as amended, September 2016,
available at https://www.blm.gov/sites/blm.gov/files/AboutUs_LawsandRegs_FLPMA.pdf.
14 43 U.S.C. §1702(c).
15 For more information on BLM’s interpretation of these directives, see CRS Legal Sidebar LSB10982, Federal Land
Management: When “Multiple Use” and “Sustained Yield” Diverge, by Adam Vann.
16 43 U.S.C. §1711.
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concurrently with National Environmental Policy Act of 1969 (NEPA; 42 U.S.C. §4321 et seq.)
reviews.17 Part of BLM’s management of federal lands under its multiple use directive is
determining the best use of the land, including where and when multiple simultaneous uses are
possible without interfering with each other. For example, grazing or recreation are often allowed
on federal lands in conjunction with other designated uses. However, though an RMP for a given
area of land may designate multiple possible uses, an individual project may affect or prevent the
other potential uses of the land.
After the RMP is developed, BLM may also develop activity-level and/or project-specific plans
and decisions that describe the on-the-ground implementation of certain actions, programs, or
projects for a given area. BLM may revise any of its plans based on new information, newly
developed technologies, new policy goals, or other changing circumstances. Any proposed
development activity, such as for O&G or geothermal, must comport with the RMP and activity
plans for the parcel of land.
Federal Lease Terms
O&G and geothermal development allowed by RMPs are managed through leasing processes that
share many similarities in requirements but also have many differences. Differences between
O&G and geothermal leasing include fiscal terms, frequency of lease sales, and operator
responsibilities specific to the resource type. These differences in requirements may result in
under- or over-development of resources or in a resource development mix that does not best
serve various federal priorities, such as BLM’s mission to ensure multiple-use and sustained yield
of federal resources or more general federal goals of providing a reliable electricity supply,
ensuring energy security, reducing greenhouse gas emissions, or providing for fiscal security
through federal leasing revenue.
Leases for onshore O&G development are administered pursuant to the Mineral Leasing Act of
1920 (MLA; 30 U.S.C. §§181 et seq.). Leases for geothermal projects are administered pursuant
to the Geothermal Steam Act of 1970 (30 U.S.C. §§1001 et seq.).18 Table 1 provides a summary
of lease terms for O&G and geothermal power. Both have bonding requirements prior to drilling:
$10,000 for a single lease, or options to pay a flat amount to cover all leases within a single state
($25,000 for O&G and $50,000 for geothermal) or nationwide ($150,000).19 Both also have some
similar lease terms, including the duration of the primary lease and opportunities for renewals.
Both require a nomination fee, but with different terms: O&G expressions of interest require a flat
fee of $5 per acre (adjusted for inflation), and geothermal nomination fees amount to $140 plus
$0.14 per acre. The application fee for competitive leases for both O&G and geothermal is $195;
the application fee for noncompetitive geothermal leases is $505. The budget reconciliation
measure often referred to as the Inflation Reduction Act (IRA) (P.L. 117-169) eliminated
noncompetitive O&G leases. Both leasing processes similarly require the payments of bids (also
known as bonuses), rents, and royalties.

17 Bureau of Land Management, “Types of Plans,” accessed June 1, 2023, https://www.blm.gov/programs/planning-
and-nepa/planning-101/types-of-plans; Bureau of Land Management, “What Informs Our Plans,” accessed June 22,
2023, https://www.blm.gov/programs/planning-and-nepa/what-informs-our-plans.
18 30 U.S.C §§181-287.
19 Under a rule finalized on April 12, 2024, minimum bonding amounts for an O&G lease increase to $150,000 per
lease bond, and $500,000 for statewide bonds. Nationwide and unit bonds are eliminated. This rule is effective 60 days
after it is published in the Federal Register. This has not occurred as of April 17, 2024. Fluid Mineral Leases and
Leasing Process, RIN 1004–AE80, https://www.blm.gov/sites/default/files/docs/2024-04/BLM-Fluid-Minerals-
Leasing-FinalRule.pdf.
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Differences also exist in lease terms. O&G leases require a minimum bid of $10 per acre;
geothermal leases do not require a minimum bid. The statutes define ranges (minimum and
maximum rates) for the royalties for geothermal production based on years from production
start,20 but for the 10-year period until 2032 the law establishes a single set rate for royalties for
O&G (after which time that value becomes a minimum).21 For rents, minimum rates are
established by statute for both resource types. Additionally, the minimum rent and royalty rates
are higher for O&G than geothermal. As a result of these terms, payments from lessees may be a
greater percentage of sales or higher value per project for O&G compared to geothermal.
In addition to the terms summarized in Table 1, both O&G and geothermal leasing processes are
subject to land use decisions documented in BLM’s RMPs, activity plans, and NEPA reviews.
Project operators for both resource types also must comply with requirements of site-specific and
project-specific permits and other applicable requirements of federal, state, and local laws and
regulations.
Table 1. Summary of Lease Terms for Federal Oil and Gas and Geothermal
Resources

Oil and Gas
Geothermal
Primary lease length 10 years (30 U.S.C. §226(e))
10 years (30 U.S.C. §1005(a))
Lease renewal
Lease continues as long as there is
Lease may be extended for two five-year
production of oil or gas in paying
periods provided work toward
quantities. If dril ing operations commenced development, or required payments, are
before the end of the primary term, the
made. If geothermal production and use
lease can be extended for two years and
commenced before the end of the primary
any period thereafter during which oil and
term, the lease can be extended for 35 years
gas is produced (30 U.S.C. §226(e)).
with a preferential renewal option after that
(30 U.S.C. §1005).
Pre-dril ing bond
Lessee or operator must post a bond
Lessee or operator must post a bond
requirements
amounting to $10,000 for a single lease,
amounting to $10,000 for a single lease,
$25,000 for all leases in a state, or
$50,000 for all leases in a state, or $150,000
$150,000 for all operations nationwide (43
for all operations nationwide (43 C.F.R.
C.F.R. 3104).
3214).
Nomination fee
BLM solicits nominations for land for oil
$140 plus $0.14 per acre (43 C.F.R.
and gas leasing. Expressions of interest
§3000.12).
must include $5 per acre fee (30 U.S.C.
§226(q)); statute requires adjustment of
this fee for inflation not less frequently than
every four years. Established by the
Inflation Reduction Act (P.L. 117-169) in
2022, this fee has not been adjusted.
Application fee
$195 application fee (competitive only; 43
$195 application fee (competitive leases) or
C.F.R. §3000).
$505 (noncompetitive leases) (43 C.F.R.
§3000).
Minimum bid
$10 per acre for the 10-year period
n/a
beginning on August 16, 2022. The national
minimum acceptable bid may be increased
after that period (30 U.S.C. §226(b)).

20 The Geothermal Steam Act of 1970, Section 5, as amended through the Energy Act of 2005 (P.L. 109-58).
21 The Mineral Leasing Act of 1920, Section 17, as amended through the Inflation Reduction Act of 2022 (IRA; P.L.
117-169).
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Oil and Gas
Geothermal
Rent
Competitive leases: For the 10-year period
Competitive leases: Not less than $2 per
beginning on August 16, 2022, no less than
year per acre for year 1, $3 per year per
$3 per acre for the first two years, $5 per
acre for years 2-10, and $5 thereafter (30
acre per year for the fol owing six-year
U.S.C. §1004).
period, and $15 per acre per year
Noncompetitive leases: $1 per year per acre
thereafter (30 U.S.C. §226(d)).
for years 1-10, and $5 per year per acre
thereafter (30 U.S.C. §1004).
Royalty
16⅔% of the value of production (30
Not less than 1% and not more than 2.5% of
U.S.C. §226(b)) during the 10-year period
the gross proceeds of electricity produced
beginning on August 16, 2022, and no less
in years 1-10; not less than 2% and not more
than 16⅔% thereafter. The Secretary is
than 5% thereafter; or 10% of the gross
permitted to “waive, suspend or reduce
value for an “arms-length” sale to a
the rental or minimum royalty” as a
developer (30 U.S.C. §1004). For direct use
production incentive (43 C.F.R. §3103.4-
(i.e., heat), royalties are based on a schedule
1(a)).
of fees (30 C.F.R. §1206.356). The Secretary
is permitted to “waive, suspend or reduce
the rental or royalty” for conservation
purposes, to encourage the greatest
recovery of resources, if necessary to
promote development, or if the lease cannot
be operated under those terms (30 U.S.C.
§1012).
Source: U.S. Code and federal regulations as indicated in text.
Notes: Among other provisions, the Inflation Reduction Act of 2022 (P.L. 117-169) eliminated noncompetitive
leases, increased the minimum bid and rental requirements, and increased the royalty rates for O&G. Bid (aka
bonus) is the payment that an applicant offers to purchase the lease of public lands. Rent is the payment made by
a lessee before production occurs. Royalty is a required payment made by a lessee to the federal government
based on the value of the public resource involved.
Under a rule finalized on April 12, 2024, minimum bonding amounts for an O&G lease increase to $150,000 per
lease bond, and $500,000 for statewide bonds. Nationwide and unit bonds are eliminated. Unit operator bonds
are bonds filed by the oil and gas unit operator in lieu of individual lease bonds. This rule is effective on June 22,
2024. Fluid Mineral Leases and Leasing Process, RIN 1004–AE80, https://www.blm.gov/sites/default/files/docs/
2024-04/BLM-Fluid-Minerals-Leasing-FinalRule.pdf.
The U.S. Government Accountability Office (GAO) identified deficiencies with some of these
elements of BLM’s onshore federal leasing program including noncompetitive leasing, royalty
relief, data collection, fair return on federal resources, and bonding and reclamation processes,
and recommended actions for BLM to improve the related agency policies.22 In 2021, in response
to Executive Order 14008, “Tackling the Climate Crisis at Home and Abroad,” DOI produced a
report identifying many of these same issues and a number of recommendations to address
them.23 See the section “Issues for Congress” for more information on addressing these issues.

22 See, for example, the following GAO reports: Oil and Gas: Onshore Competitive and Noncompetitive Lease
Revenues (GAO-21-138), November 19, 2020; Federal Oil and Gas Revenue: Actions Needed to Improve BLM’s
Royalty Relief Policy (GAO-21-169T), October 6, 2020; Oil and Gas: Interior Should Strengthen Management of Key
Data Systems Used to Oversee Development on Federal Lands (GAO-21-209), May 27, 2021; Federal Energy
Development: Challenges to Ensuring a Fair Return for Federal Energy Resources (GAO-19-718T), September 24,
2019; and Oil and Gas: Bureau of Land Management Should Address Risks from Insufficient Bonds to Reclaim Wells
(GAO-19-615), September 18, 2019.
23 U.S. Department of the Interior, “Report on the Federal Oil and Gas Leasing Program,” November 2021,
https://www.doi.gov/sites/doi.gov/files/report-on-the-federal-oil-and-gas-leasing-program-doi-eo-14008.pdf.
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Recent Changes to Federal Lease Terms
The MLA was amended by the IRA. Among other provisions, O&G revenue requirements were
increased. See Table 2 for a summary of the 2022 revenue changes.
Table 2. Changes to Federal Oil and Gas Revenue in the Inflation Reduction Act
(P.L. 117-169)
Revenue Type Before the Inflation Reduction Act
Inflation Reduction Act Change
Bid
Minimum $2.00 per acre.
Minimum $10.00 per acre; can increase after August
16, 2032.
Rent
No less than $1.50 per acre for years
No less than $3.00 per acre for years 1-2, no less than
1-5 and no less than $2.00 per acre
$5.00 per acre for years 3-8, no less than $15.00 per
thereafter.
acre thereafter.
Royalty
At least 12½% of the value of
16⅔% of the value of production from the lease for
production from the lease.
the 10 years beginning on August 16, 2022; no less
than 16⅔% thereafter.
Source: 30 U.S.C. §226(b); 30 U.S.C. §226(d); P.L. 117-169.
Notes: Bid (aka bonus) is the payment that an applicant offers to purchase the lease of public lands. Rent is the
payment made by a lessee before production occurs. Royalty is a required payment made by a lessee to the
federal government based on the value of the public resource involved.
The IRA made other changes to onshore O&G leasing. These changes include eliminating the
option for noncompetitive leases, adding a royalty on gas that is lost (such as by venting and
flaring), and increasing bonding requirements.24
Congress amended the Geothermal Steam Act of 1970 by the Energy Policy Act of 2005 (P.L.
109-58). Changes enacted in 2005 include adding two potential 5-year extensions to the initial
10-year lease term, increasing the maximum acreage of a single lease, and increasing the total
acreage a single entity may lease in any one state.
Federal Permitting and Leasing Process
The federal permitting and leasing processes are largely similar for both O&G and geothermal
projects. BLM identifies land available for leasing through an RMP, identifies high- and low-
preference parcels, holds competitive lease sales, and conducts NEPA reviews at different stages
during the processes as required. Individuals, companies, or contractors are able to nominate
lands for BLM to consider including for either O&G or geothermal lease sales. Operator
responsibilities include submitting specific permits at similar points in the drilling timeline for
both O&G and geothermal projects. For example, operators submit an Application for Permit to
Drill (APD) before drilling for O&G projects; operators submit Geothermal Drilling Permit
(GDP) before drilling for geothermal projects. Both APDs and GDPs contain plans for drillpad
location, surface reclamation, and other surface uses.
Despite these similarities, there are significant differences; for example, noncompetitive lease
sales are available for geothermal but not O&G resources, and operator responsibilities for
exploration and drilling differ due to differences inherent to the resources. Table 3 compares
BLM permitting and leasing processes for O&G and geothermal resources and provides examples

24 For non-competitive leases, see Section 50262, Mineral Leasing Act Modernization, (e) Elimination of
Noncompetitive Leasing; for flaring, see Section 50263, 30 U.S.C. §1727.
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of similarities and differences. The table is intended to be illustrative and not comprehensive in
identifying all similarities and differences that may arise in implementation.
Table 3. Selected BLM Permitting and Leasing Processes for Geothermal and Oil
and Gas Resources

Oil and Gas
Both
Geothermal
Land
RMP identifies lands open
BLM creates a Resource
RMP identifies lands available
management
under standard lease terms, Management Plan (RMP) (43
for leasing and lands not
lands open with
U.S.C. §1712).
available (43 U.S.C. §3201).
restrictions, and lands
closed to leasing.
Applicability of

BLM and operator comport

federal and state
with state and federal laws and
laws and
regulations through entire
regulations
process.
How land is
BLM can select parcels to
BLM prepares Leasing Analysis.
A qualified entity may
chosen for
include in a lease sale, but
nominate lands for
evaluation and
typically, industry submits
competitive sale by
leasing
expressions of interest
submitting an applicable BLM
(EOIs) to nominate lands
nomination form. BLM may
for leasing (43 U.S.C.
include land in a lease sale on
§3120). Nominated lands
its own initiative (30 U.S.C.
must align with lands
§3203). BLM must have
designated as open for
information on potential
development by the RMP.
lands that indicate
geothermal resources that
could be produced are
present.
Competitive sales Held in states with eligible
Competitive sales required.
Must be offered once every
and frequency
lands on at least a quarterly
two years for states that
basis (30 U.S.C. §226).
have nominations (30 U.S.C.
§1003).
Noncompetitive
Not allowed (P.L. 117-169).
If a lease is offered but no bid
sales
qualifies, the land becomes
available for noncompetitive
leasing for a two-year period
(30 U.S.C. §1003).
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Oil and Gas
Both
Geothermal
Operator
Operator must submit an
Operator must meet
Operator must submit a
responsibilities
Application for Permit to
requirements of site-specific
Notice of Intent to Conduct
before various
Dril (APD) (43 C.F.R.
and project-specific permits
Geothermal Exploration
activities
§3162.3-1). The APD form
including state regulations.
Operations (NOI) (43 C.F.R.
(BLM Form 3160-3) must
§3251) including planned well
include, among other
characteristics and dril ing
things, a dril ing plan, a
and completion procedures.
surface use plan, and
Operator must secure a
evidence of bond/surety
Geothermal Dril ing Permit
coverage. The surface use
(GDP) (43 C.F.R. §3261)
plan should contain
including a complete
information on dril pad
operations plan and a
location, pad construction,
complete dril ing program
the method for
including information on
containment and waste
plans for well pads, roads,
disposal, and plans for
facilities, water sources,
surface reclamation. The
environmental protection
APD is valid for two years
procedures, and surface
or until the lease expires,
reclamation.
whichever occurs first, but
the BLM may grant a two-
Operator must submit a Plan
year extension to allow the
of Utilization (POU) and a
operator more time to
facility construction permit
dril .
to be approved by BLM (43
C.F.R. §3271). The POU
Operator may also need to
must include anticipated
secure permits based on
environmental impacts and
project-specific needs to
mitigations. The construction
transport the product such
permit must address any
as right-of-way or pipelines,
pipelines or facilities.
or to flare gas.
Before other operations
that wil result in additional
surface disturbance, the
operator submits a new
surface use plan of
operations (APD Form
3160-5) (43 C.F.R. §3162.3-
3).
Source: U.S. Code and federal regulations as indicated in text.
Notes: Though there are differences, for the purposes of this analysis, CRS is treating Geothermal Dril ing
Permits (GDPs) and Applications for Permit to Dril (APDs) as analogous. Laws and requirements listed in this
table are not exhaustive; additional requirements may apply depending on the type of project, its location, and
other factors.
Multiple other federal, state, and local laws also may require permitting or other procedures for
the approval and operation of a O&G or geothermal project on federal lands, depending on the
scope and nature of the activities, potential environmental impacts, and other factors. Depending
on the site-specific circumstances, examples of other federal laws that may apply to a project
include, but are not limited to, the Clean Water Act (33 U.S.C. §1251 et seq.), Endangered
Species Act (16 U.S.C. §1531 et seq.), National Historic Preservation Act (54 U.S.C. §§300101 et
seq.), Wild and Scenic Rivers Act (16 U.S.C. §1271 et seq.), and Native American Graves
Protection and Repatriation Act (25 U.S.C. §3001 et seq.). As discussed below, NEPA authorizes
a procedural framework for evaluating the potential effects of proposed actions and potential
alternatives to inform agency decisions under other laws, but the NEPA process itself does not
provide permitting or other regulatory approvals to carry out a project.
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Developing Projects: Productive and Non-Productive Leases
While O&G and geothermal projects are being developed—basically any time before production
starts—their leases are classified as non-productive. O&G and geothermal projects generally have
longer project development timelines—compared to some other energy types—due, in part, to
their potential for environmental impacts and the related requirements for NEPA reviews.25 O&G
and geothermal power also have operational factors that extend development time such as
challenges related to drilling wells, confirming resources, and—for geothermal projects—the
complexities in designing and constructing power plants. The base federal lease periods of 10
years—longer than some other federal energy lease periods such as for solar or wind testing—
reflect these development challenges.26
While longer initial lease terms may allow the successful development of many O&G and
geothermal projects, both successful and unsuccessful projects can result in leased parcels being
non-producing for extended amounts of time. For a variety of reasons including the operational
challenges mentioned above as well as market fluctuations or other business decisions, some
O&G and geothermal lease parcels are non-productive for several years or may never become
productive. Of all onshore O&G leases held in 2022, 10,778 out of 34,409 (31%) were not
producing—covering 11,341,950 out of 23,771,097 leased acres (48%).27 Out of all geothermal
leases held in 2022, 454 out of 538 (84%) were not producing—covering 1,019,167 out of
1,121,238 leased acres (91%).28 Additionally, BLM has noted a variety of reasons for non-
productivity—including “speculative leasing,” projects which are non-productive likely pending
market changes, or projects which are ultimately unsuccessful—that often inhibit those lands
from being managed for other purposes, such as conservation or recreation.29
NEPA Environmental Review Process
BLM has generally considered its decisions for the preparation and implementation of RMPs,
including BLM permitting and leasing decisions for geothermal, O&G, and other resources, to be
major federal actions subject to NEPA. Related federal agency decisions under other applicable
laws also may be considered major federal actions subject to NEPA. Section 102(2)(C) of NEPA
requires the preparation of an environmental impact statement (EIS) for major federal agency

25 The length of the NEPA review process for each of these types of energy projects is dependent on the number of
major federal actions with the potential for significant effects, as well as the availability of CXs that cover those
actions. According to a 2014 U.S. Department of Energy graphic, the NEPA review process for geothermal projects
was estimated at five to seven years; for O&G projects, three to five years; and wind and solar projects, approximately
1.5 years. Geothermal Energy Association Blog, “Leading News: Geothermal Needs Level Playing Field; GEA
Celebrates ‘Honors’ Winners,” July 30, 2014, https://geoenergist.wordpress.com/2014/07/30/leading-news-geothermal-
needs-level-playing-field-gea-celebrates-honors-winners/.
26 For example, BLM right-of-way grants for solar and wind testing—which are used to determine whether an area’s
energy potential is adequate for development—have a maximum initial term of three years with an option for a three-
year renewal if accompanied by a development application (43 C.F.R. §2805.11).
27 Not all of these projects will be non-producing by the end of their initial lease period; this is a snapshot of 2022
conditions. U.S. Bureau of Land Management, “Public Land Statistics 2022,” June 2023, https://www.blm.gov/sites/
default/files/docs/2023-07/Public_Lands_Statistics_2022.pdf.
28 U.S. Bureau of Land Management, “Public Land Statistics 2022,” June 2023, https://www.blm.gov/sites/default/
files/docs/2023-07/Public_Lands_Statistics_2022.pdf.
29 U.S. Department of the Interior, “Report on the Federal Oil and Gas Leasing Program,” November 2021,
https://www.doi.gov/sites/doi.gov/files/report-on-the-federal-oil-and-gas-leasing-program-doi-eo-14008.pdf.
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actions of a discretionary nature that would “significantly” affect the quality of the human
environment.30
Pursuant to Title II of NEPA, the Council on Environmental Quality (CEQ) promulgated
regulations to establish procedures that federal agencies must follow in preparing an EIS.31 These
procedures include an evaluation of the “reasonably foreseeable” effects of a proposed action and
a range of “reasonable” alternatives to carry out the purpose and need of the action, identification
of applicable requirements of other federal, state, and local laws, mitigation of potential effects
that may be warranted, and certain additional considerations. Agencies are required to document
the selection of a preferred alternative under an EIS in a record of decision (ROD). A ROD
discloses an agency decision, but a ROD does not constitute regulatory approval to carry out a
project that is authorized under another law. The preparation of an EIS also includes the
opportunity for public involvement at various stages of the NEPA process.
CEQ regulations also established procedures for an environmental assessment (EA) if an agency
may not be certain whether the effects of a proposed action would be significant.32 If an agency
determines under an EA that the effects would be significant, the agency would be required to
prepare an EIS pursuant to Section 102(2)(C) of NEPA. If an agency determines that the effects
would not be significant, the agency would issue a finding of no significant impact (FONSI).33
Agencies may provide the opportunity for public involvement in the preparation of an EA, but are
not required to do so by statute.
The scope of effects that an agency must consider under NEPA is relatively broad. CEQ
regulations define the term environmental “effects or impacts” for the purpose of NEPA to
include “aesthetic, historic, cultural, economic, social, or health effects, whether direct, indirect,
or cumulative.”34 Depending on the breadth of potential effects and potentially applicable laws,
numerous federal, state, local, or tribal agencies may be involved in the preparation of analyses
for NEPA reviews. CEQ regulations outline procedures for identifying lead, cooperating, and
participating agencies, and coordination of their respective roles in the NEPA process.35 CEQ
regulations also direct federal agencies to establish NEPA procedures for actions covered under
their respective jurisdictions.36 Agency-specific NEPA procedures are generally supplemental to
CEQ regulations.37
CEQ regulations also established procedures for agencies to categorically exclude specific types
of actions from the preparation of an EIS or EA if those actions typically would not significantly
affect the quality of the human environment under normal circumstances, referred to as a
categorical exclusion (CX).38 CEQ regulations also direct agencies to identify “extraordinary

30 42 U.S.C. §4332(2)(C).
31 Council on Environmental Quality (CEQ) regulations that establish procedures for the preparation of EISs and other
elements of the National Environmental Policy Act (NEPA) process are codified at 40 C.F.R. Chapter V, Subchapter A,
Parts 1500-1508. For a chronology of rulemaking for these regulations, see Council on Environmental Quality, “CEQ
NEPA Regulations,” https://ceq.doe.gov/laws-regulations/regulations.html.
32 40 C.F.R. §1501.5.
33 40 C.F.R. §1501.6.
34 40 C.F.R. §1508.1.
35 40 C.F.R. §1501.7 and 40 C.F.R. §1501.8.
36 40 C.F.R. Part 1507.
37 For a list of references to agency-specific procedures, see Council on Environmental Quality, “Agency NEPA
Implementing Procedures,” January 27, 2023, https://ceq.doe.gov/laws-regulations/
agency_implementing_procedures.html.
38 40 C.F.R. §1501.4 outlines procedures for agencies to establish categorical exclusions (CX, also referred to as CE or
CATEX). CEQ defines the term “categorical exclusion” in 40 C.F.R. §1508.1.
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circumstances” to address situations in which a specific action that usually may be categorically
excluded could require an EA or EIS if the effects may be significant. For example, certain
resources protected under federal, state, or local laws may be present at a site that could cause the
effects of an agency action to be significant at that location. CXs therefore may be a starting
point, and not necessarily an end point, in identifying whether a specific action may require
further review under NEPA.
Federal agencies have established numerous CXs and exceptions for extraordinary circumstances,
pursuant to these CEQ regulations.39 Some of these exclusions and extraordinary circumstances
are listed in agency regulation, and others are listed in agency guidance. Congress also has
established CXs in statute for specific types of agency actions. These statutory exclusions vary in
terms of whether an agency is required to consider extraordinary circumstances to determine if
further review under NEPA may be warranted on a case-by-case basis for specific actions.
Section 321 of the Fiscal Responsibility Act of 2023 (FRA, P.L. 118-5) amended NEPA, among
other provisions, to alter various elements of the NEPA process and authorize project sponsors to
petition a review of agency compliance with general deadlines for the preparation of an EIS (two
years) or an EA (one year).40 The CEQ regulations contained these deadlines prior to the passage
of the FRA.41 The FRA did not establish any new CXs in statute and codified the definition of a
CX found in the CEQ regulations.42 The FRA also expressly authorized an agency to adopt a CX
of another agency, if appropriate.43 On July 31, 2023, CEQ published a notice of proposed
rulemaking “Bipartisan Permitting Reform Implementation Rule” to revise its regulations for
implementing the amendments to NEPA enacted in the FRA.44 The public comment period closed
on September 29, 2023. That rule was finalized on May 1, 2024, and takes effect July 1, 2024.45
Agencies also may revise their NEPA procedures consistent with these amendments to NEPA and
CEQ regulations to implement changes to statutory requirements.
BLM NEPA Procedures
DOI regulations establish department-wide procedures for implementing the requirements of
NEPA and CEQ regulations to carry out the federal environmental review process.46
Departmental guidance outlines more detailed NEPA procedures of BLM and other agencies of
the department.47 BLM also has issued supplemental guidance for carrying out NEPA reviews for
actions within the agency’s jurisdiction.48 These regulations and guidance were issued prior to the

39 For a consolidated list as of May 2021, see Council on Environmental Quality, “Categorical Exclusions,”
https://ceq.doe.gov/nepa-practice/categorical-exclusions.html.
40 For a summary of FRA amendments to NEPA, see Council on Environmental Quality, “Fiscal Responsibility Act of
2023 (FRA),” https://ceq.doe.gov/laws-regulations/fra.html.
41 40 C.F.R. §1501.10.
42 42 U.S.C. §4336e(1).
43 42 U.S.C. §4336c.
44 Council on Environmental Quality, “National Environmental Policy Act Implementing Regulations Revisions Phase
2,” 88 Federal Register 49924, July 31, 2023.
45 Council on Environmental Quality, “National Environmental Policy Act Implementing Regulations Revisions Phase
2,” 89 Federal Register 35442, May 1, 2024.
46 43 C.F.R. Part 46.
47 U.S. Department of the Interior, Departmental Manual (DM), Environmental Quality Programs, Part 516: National
Environmental Policy Act of 1969, “Chapter 11: Managing the NEPA Process—Bureau of Land Management,” June 2,
2020, 516 DM 11, https://www.doi.gov/sites/doi.gov/files/elips/documents/516-dm-11-signed-508.pdf.
48 Bureau of Land Management, National Environmental Policy Handbook, H-1790-1, January 2008,
https://www.blm.gov/sites/blm.gov/files/uploads/Media_Library_BLM_Policy_Handbook_h1790-1.pdf.
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amendments to NEPA enacted in P.L. 118-5 and may be revised to reflect changes to statutory
requirements.
BLM land use planning regulations also specify that the preparation of an RMP under FLPMA “is
considered a major Federal action significantly affecting the quality of the human environment”
requiring an EIS under NEPA.49 These regulations require the publication of an RMP and the
related EIS in a single document “whenever possible.”
BLM permitting or leasing decisions for land uses approved under an RMP also would be subject
to the preparation of an EIS if the effects of the proposed action would be significant, or the
preparation of an EA if the significance of the effects may be uncertain. Some O&G and
geothermal activities of a more limited scope are categorically excluded from the preparation of
an EA or EIS under NEPA. Some of these CXs are authorized in statute. BLM also has
administratively established some CXs through agency guidance, with exceptions for
extraordinary circumstances. Selected examples of these statutory and administrative CXs related
to onshore geothermal and O&G activities are listed below.
Statutory Categorical Exclusions
Section 390 of the Energy Policy Act of 2005 (P.L. 109-58) authorized five CXs for certain O&G
activities, including the drilling of new wells within a developed field.50
1. “Individual surface disturbances of less than 5 acres so long as the total surface
disturbance on the lease is not greater than 150 acres and site-specific analysis in
a document prepared pursuant to NEPA has been previously completed.”
2. “Drilling an oil and gas well at a location or well pad site at which drilling has
occurred previously within 5 years prior to the date of spudding the well.” 51
3. “Drilling an oil or gas well within a developed field for which an approved land
use plan or any environmental document prepared pursuant to NEPA analyzed
such drilling as a reasonably foreseeable activity, so long as such plan or
document was approved within 5 years prior to the date of spudding the well.”
4. “Placement of a pipeline in an approved right-of-way corridor, so long as the
corridor was approved within 5 years prior to the date of placement of the
pipeline.”
5. “Maintenance of a minor activity, other than any construction or major
renovation of a building or facility.”
Section 390 did not specify any extraordinary circumstances in which these CXs may not apply to
specific actions. BLM guidance outlines the agency’s interpretation that these statutory exclusions
do not require a review of extraordinary circumstances, if the action meets the criteria of one of
the exclusions in Section 390.52 BLM guidance acknowledges that requirements of other statutes
may apply to these actions: “Energy Policy Act CXs do not require review for extraordinary
circumstances. This is because these CXs are established by statute, and their application is
governed by that statute. However, other procedural requirements still apply, such as consultation

49 43 C.F.R. §§1601.0-6.
50 42 U.S.C. §15942—NEPA Review.
51 Spudding is the first step in drilling a well.
52 Bureau of Land Management, National Environmental Policy Handbook, H-1790-1, January 2008, p. 18.
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under the Endangered Species Act and National Historic Preservation Act.”53 Section 390 also did
not exempt applicable regulatory requirements of other federal, state, or local laws.
The Infrastructure Investment and Jobs Act (P.L. 117-58) authorized several criteria for the
Secretary of the Interior to apply a NEPA CX for certain gathering lines.54 The CX would apply in
some situations for issuing sundry notices and right-of-way decisions on certain federal and
Indian lands.55 Activities covered by this CX include locating gathering lines and associated field
compression or pumping units that service a well for the transport of oil or natural gas from a
processing plant to a common carrier pipeline or facility, or to transport-related constituents or
produced waters.56 This exclusion generally would apply in situations that would reduce the “total
quantity of methane that would otherwise be vented, flared, or unintentionally emitted from the
field or unit,” or that would reduce “vehicular traffic that would otherwise service the field or
unit.”57 This exclusion does not apply to issuing sundry notices or right-of-way decisions for
common carrier pipelines that would be installed on or cross federal or Indian lands.
Administrative Categorical Exclusions
BLM NEPA procedures outlined in DOI guidance list six CXs related to O&G and geothermal
activities. One of these exclusions applies only to geothermal activities. Three apply to certain
administrative or fiscal decisions, such as lease adjustments and royalty rate reductions. One
exclusion applies to approvals for suspending operations and production. Another exclusion
applies to exploration for O&G or geothermal resources, if no temporary or new road
construction is proposed. These six CXs are listed below.58 These exclusions generally would
apply unless one or more extraordinary circumstances listed in DOI regulations would cause the
effects of a specific action to be significant and require further NEPA review.59
• “Issuance of future interest leases under the Mineral Leasing Act for Acquired
Lands, where the subject lands are already in production.”
• “Approval of mineral lease adjustments and transfers, including assignments and
subleases.”
• “Approval of unitization agreements, communitization agreements, drainage
agreements, underground storage agreements, development contracts, or
geothermal unit or participating area agreements.”

53 Bureau of Land Management, National Environmental Policy Handbook, H-1790-1, January 2008, p. 18.
54 Gathering lines are “a pipeline that is installed to transport oil, natural gas and related constituents, or produced
water from 1 or more wells drilled and completed to produce oil or gas.” See U.S. Department of the Interior, “National
Environmental Policy Act Implementing Procedures for the Bureau of Land Management (516 DM 11),” 89 Federal
Register 14087-14090, February 26, 2024.
55 The sundry notice is Bureau of Land Management Form 3160-5, which is used to request changes to the Surface Use
Plan of Operations (SUPO). This includes changes to the SUPO during permitting and any subsequent new
construction, reconstruction, or alteration of existing facilities, roads, lines, or other production facilities after the well
has been permitted. For more information, see Bureau of Land Management Form 3160-5, “Sundry Notices and
Reports on Wells,” https://www.blm.gov/sites/blm.gov/files/uploads/Services_National-Operations-
Center_Eforms_Fluid-and-Solid-Minerals_3160-005.pdf.
56 42 U.S.C. §15943—Certain gathering lines located on Federal land and Indian land.
57 42 U.S.C. §15943.
58 U.S. Department of the Interior, Departmental Manual (DM), Environmental Quality Programs, Part 516: National
Environmental Policy Act of 1969, “Chapter 11: Managing the NEPA Process—Bureau of Land Management, 11.9
Actions Eligible for a Categorical Exclusion (CX),” June 2, 2020, 516 DM 11, p. 8.
59 Ibid., p. 7. The list of extraordinary circumstances in Department of the Interior NEPA regulations is codified at 43
C.F.R. §46.215.
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• “Approval of suspensions of operations, force majeure suspensions, and
suspensions of operations and production.”
• “Approval of royalty determinations, such as royalty rate reductions.”
• “Approval of Notices of Intent to conduct geophysical exploration of oil, gas, or
geothermal, pursuant to 43 CFR 3150 or 3250, when no temporary or new road
construction is proposed.”
Additional administrative CXs in U.S. Forest Service NEPA regulations are related to O&G
exploration and investigation activities and geothermal investigation activities.60 The first
exclusion applies to unleased lands under the jurisdiction of the U.S. Forest Service for short-term
(one year or less) “mineral, energy, or geophysical investigations and their incidental support
activities that may require cross-country travel by vehicles and equipment, construction of less
than 1 mile of low standard road, or use and minor repair of existing roads,” if there are no
extraordinary circumstances related to the proposed action.61 These Forest Service regulations list
several examples of such investigations that may qualify for this CX. An additional CX applies to
the approval of a “Surface Use Plan of Operations” for O&G exploration and initial development
activities, associated with or adjacent to a new O&G field or area, so long as the approval will not
authorize activities in excess of one mile of new road construction; or one mile of road
reconstruction; or three miles of individual or co-located pipelines and/or utilities disturbance; or
four drill sites.62
Issues for Congress
The following section discusses some options Congress could consider when addressing federal
leasing and permitting issues related to O&G and geothermal energy development. While some
issues are specific to one resource or the other (due to the technical, environmental, or market
considerations for that resource), the majority of issues discussed could potentially impact both.
Congress has considered a variety of changes to BLM leasing and permitting for O&G and
geothermal projects, some of which have been implemented in law, and others which are still
being considered.
Oil and Gas Leasing
Bonding and Project Reclamation
Congress could consider amending current law to clarify statutory requirements for bonding on
federal public lands. Some Members of Congress have argued that current bonding requirements,
particularly for O&G operations, are sometimes insufficient to incentivize lease holders to
complete site reclamation.63 Representatives of the O&G industry have argued that the majority

60 For energy development on Forest Service lands, “the BLM administers the lease but the Forest Service has more
direct involvement in the leasing process for lands it administers.” BLM, About the BLM Oil and Gas Program,
accessed August 14, 2023, https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/about.
61 36 C.F.R. §220.6(e)(8).
62 36 C.F.R. §220.6(e)(17).
63 Senator Michael Bennet, “Bennet Urges Secretary Haaland to Reform Outdated Oil and Gas Bonding Rates to
Ensure Companies, Not Taxpayers, Pay Cleanup Costs of Wells Drilled on Federal Lands,” December 22, 2022,
https://www.bennet.senate.gov/public/index.cfm/2022/12/bennet-urges-secretary-haaland-to-reform-outdated-oil-and-
gas-bonding-rates-to-ensure-companies-not-taxpayers-pay-cleanup-costs-of-wells-drilled-on-federal-lands.
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of developers clean up their projects and that setting bonding requirements higher will depress oil
production on federal lands.64 In the 117th Congress, bills introduced in the House and Senate
would have amended current law to change bonding amounts for O&G operations.65 In the 118th
Congress, H.R. 4301, referred to the House Committee on Natural Resources, would do similarly.
In July 2023, BLM proposed a rulemaking to update their regulations to address aspects of
leasing management, including increasing bonding amounts.66 That rule was finalized on April
12, 2024, and takes effect June 22, 2024.67
With the enactment of the Infrastructure Investment and Jobs Act (P.L. 117-58), Congress
provided $4.68 billion in supplemental appropriations for the federal reclamation program and
grants to state and tribal programs to complete reclamation within their respective
jurisdictions.68 Congress could consider evaluating the implementation of that program and the
adequacy of funding to meet the objectives of the reclamation program on federal public lands.
BLM Authority to Set Leasing Terms
Congress could reconsider the O&G royalty rate, set by statute at a fixed percentage (16⅔%)
through 2032. General BLM land management purposes are to maintain or increase revenue,
simplify administration, or incentivize or disincentivize development—and a set rate prevents
BLM from modifying lease conditions to adjust to administrative priorities or market or
technology conditions.69 In April 2022, BLM implemented a new royalty rate of 18.75%—for the
first time setting it above the minimum then established (12.5%) under the MLA.70 This was a
significant step-change increase. In August 2022, Congress, through P.L. 117-169, set the royalty
rate at exactly 16⅔% for all new projects for the following 10 years. If BLM determines a new
rate is warranted in 2032, that could result in (1) a significant step change in rates (not dissimilar
to the change in April 2022) with potential disruption to energy project development, or (2) a
phased change in rates which might not fully address BLM’s other land management purposes
(for example, resulting in either under- or overutilization of land or energy resources). After

64 Heather Richards, “Biden Unveils Aggressive Rules for Public Land Oil Drilling,” E&E News, July 20, 2023,
https://www.eenews.net/articles/biden-unveils-aggressive-rules-for-public-land-oil-drilling/.
65 BLM’s authority to issue regulations including bonding requirements is codified at 30 U.S.C. §1023 for geothermal
operations and 30 U.S.C. §226(g) for O&G operations. Some example bills from the 117th Congress include H.R. 2415,
which was reported amended by the House Committee on Natural Resources, and S. 2177, which was referred to the
Senate Committee on Energy and Natural Resources.
66 U.S. Department of the Interior, “Interior Department Takes Steps to Modernize Oil and Gas Leasing on Public
Lands, Ensure Fair Return to Taxpayers,” July 20, 2023, https://www.doi.gov/pressreleases/interior-department-takes-
steps-modernize-oil-and-gas-leasing-public-lands-ensure-fair; Bureau of Land Management, “Fluid Mineral Leases and
Leasing Process,” 88 Federal Register 47562, July 24, 2023, https://www.federalregister.gov/documents/2023/07/24/
2023-14287/fluid-mineral-leases-and-leasing-process.
67 U.S. Bureau of Land Management, “Fluid Mineral Leases and Leasing Process,” 89 Federal Register 30916, April
23, 2024, RIN 1004–AE80, https://www.blm.gov/sites/default/files/docs/2024-04/BLM-Fluid-Minerals-Leasing-
FinalRule.pdf.
68 For more information on wells and reclamation, see CRS In Focus IF12134, The Federal Role in Orphan Oil and
Gas Well Reclamation, by Lance N. Larson, and CRS Report R47263, Ecosystem Restoration in the Infrastructure
Investment and Jobs Act: Overview and Issues for Congress, coordinated by Anna E. Normand and Pervaze A. Sheikh;
U.S. Department of the Interior, “Through President Biden’s Bipartisan Infrastructure Law, 24 States Set to Begin
Plugging over 10,000 Orphaned Wells,” June 5, 2023, https://www.doi.gov/pressreleases/through-president-bidens-
bipartisan-infrastructure-law-24-states-set-begin-plugging.
69 The Secretary is permitted to “waive, suspend or reduce the rental or minimum royalty” as a production incentive (43
C.F.R. §3103.4-1(a)).
70 U.S. Bureau of Land Management, “June 2022 Oil & Gas Lease Sale: Set a Royalty Rate of 18.75 Percent,” April
18, 2022, https://eplanning.blm.gov/eplanning-ui/project/2017575/510.
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August 2032, the rate becomes a minimum rate. BLM will be able to set higher rates for leases as
needed, but not lower rates.
Geothermal Leasing
The 117th Congress’s Enhancing Geothermal Production on Federal Lands Act (H.R. 5350) would
have addressed multiple elements relating to geothermal testing, CXs, and designated leasing
areas. The broad goal of this bill of enhancing geothermal development was supported by BLM,
though BLM recommended allowing these definitions and decisions to be made
administratively.71 The Fiscal Responsibility Act of 2023 (P.L. 118-5) allows federal agencies,
including BLM, to adopt the CXs of other agencies where appropriate.
Issues for Both Oil and Gas and Geothermal Leasing
In the 118th Congress, the Lower Energy Costs Act (H.R. 1) would change leasing and NEPA
compliance for O&G and geothermal development and requirements for lease offerings, decisions
on drilling permit applications, and many other leasing and permitting elements.
Other efforts at permitting reform such as H.R. 5376 (117th Congress) continue in more recent
bills such as the Building American Energy Security Act of 2023 (S. 1399).
BLM Authority to Set Leasing Terms
Congress could consider changing how much authority BLM has to set the terms and conditions
for O&G and geothermal leasing. As an example of alternative authority levels, the Energy Act of
2020 (P.L. 116-260) modified FLPMA to give BLM the ability to set the rates (for acreage rents
and capacity fees) for solar and wind rights-of-way “to promote the greatest use” of those energy
resources.72 Since then, BLM has made multiple revisions to the solar and wind rates including
setting uniform capacity fees regardless of the technology deployed and has a proposed rule
change adjusting those fees to be based on the actual electricity generated and its current market
value (rather than on the prior basis of the potential maximum capacity of the project). Congress
could decide to grant BLM similar flexibility to support policy goals and to support lower-carbon
and renewable energy sources, or to promote energy development in general (such as expanded
O&G development or more widely available geothermal power deployment potentially enabled
by EGS). Authority could be given to BLM to set minimum bid values or set rates for rents or
royalties for O&G and geothermal leases.73 BLM might, for example, establish state- or zone-
based rates (similar to those for solar and wind leasing) to account for regional differences in
project costs and energy values. However, Congress could also decide that the current terms and
authorities for leasing are suitable to support the various federal goals and make no changes.

71 See testimony from Michael Nedd, Deputy Director, Operations, Bureau of Land Management, to the House
Committee on Natural Resources, Subcommittee on Energy and Mineral Resources, on July 19, 2022, at
https://www.doi.gov/ocl/hr-5350.
72 BLM typically issues leases for the development of O&G and geothermal resources. In contrast, BLM issues rights-
of-way grants for certain wind and solar projects. Similarly, BLM charges royalties to geothermal and O&G producers
based on the value of production from the lease. For wind and solar leases, BLM charges a capacity fee based on the
estimated capacity of electricity that could be generated. For the purposes of this comparison, CRS has treated these
terms as analogous.
73 Congress, through P.L. 117-169, mandates the rate for O&G at 16⅔% until 2032.
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Productive and Non-Productive Leases
Congress could consider modifications of leasing terms or requirements related to non-productive
leases to allow BLM to implement its multiple-use mission and potentially make additional use of
the lands and resources involved. Congress could decide to shorten the initial lease periods for
either resource to reduce non-productive periods, to maintain the initial lease durations as
sufficient to support development, or to lengthen the initial lease periods to support development
of these energy resources. Congress could consider modifying requirements for BLM’s regular
review of non-productive leases, requirements for lessees to show progress, and/or requirements
relating to the termination or re-competition of non-productive leases. Congress could also decide
whether adjusting rent rates (which are paid by lessees prior to achieving production) would be
useful. For example, higher rent rates or rates that increase over time could further disincentivize
extended non-productive lease periods. Partial rent rebates for projects that ultimately become
productive could incentivize leases of lands with the best resource development potential.
Congress could also consider guidance to BLM on the development of RMPs or activity plans
that specifically accommodates and encourages intermediate uses during non-productive lease
periods, as appropriate.
Congress could consider changing whether noncompetitive lease offerings are available for either
O&G or geothermal leases. Some critics of noncompetitive leases say that those leases are
wasteful and unnecessary and some Members of Congress criticize them as being leases on land
that the “market has determined have little or no potential for … development.”74 Congress,
through the IRA, eliminated noncompetitive offerings for O&G but not for geothermal leases.
Congress could determine that noncompetitive leases are still appropriate for the geothermal
industry due to its smaller size—meaning there is generally less competition or potential funding
for project development—or because of other development or operational challenges.
Additionally, as the geothermal industry develops, Congress could determine these challenges are
no longer decisive and thus noncompetitive leases should be eliminated as well. Congress could
determine that the effects of some markets and policy trends—for example those that support
lower-carbon and renewable energy projects—may once again support the suitability of
noncompetitive leases to O&G.
Drilling Activities and Review Processes
Congress could consider changes to applications for permits to drill (APDs, or geothermal drilling
permits (GPDs) for geothermal) and the timelines associated with reviewing, processing, and
deciding upon applications, notifying applicants, and issuing permits. APDs/GPDs can contribute
to the administrative overhead and to the length of the development timeline for O&G or
geothermal projects.75 The Energy Policy Act of 2005 (P.L. 109-58) provided timeline
requirements and introduced a pilot program in an attempt to streamline the permitting process.
Following the act’s passage, BLM noted the NEPA processing time (one step in the overall

74 Senator Jon Tester, “Tester Announces Bill to End Wasteful Non-Competitive Oil and Gas Leasing, Increase
Government Efficiency,” July 16, 2020, https://www.tester.senate.gov/newsroom/press-releases/pr-7584/; for
additional commentary, see Kate Kelly, Jenny Rowland-Shea, and Nicole Gentile, “Backroom Deals: The Hidden
World of Noncompetitive Oil and Gas Leasing,” The Center for American Progress, May 23, 2019,
https://www.americanprogress.org/article/backroom-deals/.
75 After a geothermal or O&G lease has been obtained, a geothermal drilling permit (GDP) or an application for a
permit to drill (APD) must be approved for each well to be drilled. For more information on GDPs/APDs see the
following BLM pages: https://www.blm.gov/programs/energy-and-minerals/renewable-energy/geothermal-energy/
geothermal-guidance and https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/operations-and-production/
permitting/applications-permits-drill.
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process) for APDs and rights-of-way applications fell from 81 to 61 days, or roughly 25%, due to
“colocation” of agency staff.76 BLM reported mixed results at specific field offices. While some
of the offices processed more permits in 2007 than they did in 2005, all the pilot sites reported
more completed environmental inspections.77 Funding for the pilot program was made permanent
under the FY2015 National Defense Authorization Act (P.L. 113-291).
Despite the changes made in the Energy Act of 2005 and other administrative efforts within
BLM, average APD processing times have been increasing. As shown in Figure 1, APD
processing times have varied significantly between FY2005 and FY2023, with an average time of
218.7 days.78 BLM had stated in its budget justification for FY2012 that overall processing times
per APD rose to such levels in FY2011 and other years because of the complexity of the process,
but that they expected shorter time frames in the future. Since then, the average has been lower at
215.5 days (FY2012-FY2023) than the previous average of 224.3 days (FY2005-FY2011).
However, both average BLM-dependent days and average overall days since FY2005 have
trended upward, and the average processing time hit a new high in FY2023.
Figure 1. Average Time to Complete an APD
Federal and Indian Projects

Source: BLM Oil and Gas Statistics, 2017, Table 12, https://www.blm.gov/sites/blm.gov/files/
Table12_Time_to_Complete_an_APD1.pdf ; BLM Oil and Gas Statistics, 2023, Table 12, https://www.blm.gov/
programs-energy-and-minerals-oil-and-gas-oil-and-gas-statistics.

76 Booz Allen Hamilton, Section 365 of the Energy Policy Act of 2005: Year Two Report for the Pilot Project to
Improve Federal Permit Coordination, a report prepared for the Department of the Interior’s Bureau of Land
Management (Washington, DC: February 2008).
77 Bureau of Land Management, BLM Year Two Report, Section 365 of the Energy Policy Act of 2005 Pilot Project to
Improve Federal Permit Coordination, February 2008.
78 The average total time required to approve an APD includes both days waiting on operators and BLM-dependent
days. BLM Oil and Gas Statistics, 2017, Table 12, https://www.blm.gov/sites/blm.gov/files/
Table12_Time_to_Complete_an_APD1.pdf; BLM Oil and Gas Statistics, 2023, Table 12, https://www.blm.gov/
programs-energy-and-minerals-oil-and-gas-oil-and-gas-statistics.
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Notes: APD is application for permit to dril . The average total time required to approve an APD includes both
days waiting on operators and BLM-dependent days.
Bills in both prior Congresses and the current 118th Congress would have established statutory
deadlines for the approval or rejection of APDs/GPDs or otherwise sped up leasing and project
approval via modified processes, technology, or funding. S. 2151 from the 115th Congress would
have streamlined the O&G permitting process by removing drilling permit requirements under the
Federal Oil and Gas Royalty Management Act of 1982 (P.L. 97-451) for an action occurring
within an O&G drilling or spacing unit under certain circumstances. H.R. 1449 from the 118th
Congress would increase the frequency of lease sales under the Geothermal Steam Act of 1970
and would establish deadlines for consideration of geothermal drilling permits. H.R. 1 from the
118th Congress would put 30-day requirements on BLM to notify applicants of whether
geothermal drilling applications are complete, to issue a final decision on completed geothermal
drilling applications, and to complete all requirements and issue permits for completed O&G
APDs, as well as other requirements on permitting deferrals, processing, and reporting.
Other bills, from previous Congresses, would have exempted certain drilling activities on already
producing sites from some review processes or otherwise adjusted regulations related to
environmental review to speed up development. H.R. 6106 from the 115th Congress would have
clarified the CXs authorized under the Energy Policy Act of 2005 and would have allowed the use
of additional CXs to expedite O&G permitting. It also included provisions that would have
allowed more flexibility in skipping the environmental review or an environmental impact
statement if the action has only minimum impact on the human environment. H.R. 6088 from the
115th Congress would have allowed for an applicant to submit an existing notification of permit to
drill to the Secretary of the Interior in lieu of an APD for developed fields, for existing wells, and
with an approved land use plan and an environmental review prepared within the last 10 years
under NEPA.
Critics, including some Members of Congress and environmental groups, argue that these and
similar proposals to reduce review overhead and shorten review timelines could limit public input
into land use decisions and may overlook significant environmental impacts, which in some cases
potentially could have the effect of lengthening the time to project completion if the impacts and
applicable requirements are not identified earlier in the process.
Following the enactment of the Fiscal Responsibility Act of 2023 (P.L. 118-5, FRA) CEQ issued
a rulemaking to implement the FRA’s amendments to NEPA.79 The FRA codified some CEQ
regulations and altered various elements of the NEPA process.80 The outcome of the FRA
amendments on the NEPA environmental review process would depend on the applicability of the
amendments to specific agency actions and project-specific considerations. Congress may
oversee CEQ’s implementation of the FRA amendments to NEPA and how these amendments
may affect BLM (and other agency) NEPA procedures.
In its rule, CEQ recommended giving agencies the ability to establish CXs using additional
mechanisms and flexibilities outside of their general NEPA procedures to promote more efficient
and transparent development of CXs that may be tailored to specific environmental contexts or
project types. CEQ also replaced its provisions that would allow an agency to adopt a CX listed in
another agency’s NEPA procedures. The rule would allow an agency to immediately begin to
implement new programs and new activities based on another agency’s CX for similar actions

79 CEQ, “National Environmental Policy Act Implementing Regulations Revisions Phase 2,” 89 Federal Register
35442-35577, May 1, 2024.
80 For a summary of FRA amendments to NEPA, see Council on Environmental Quality, “Fiscal Responsibility Act of
2023 (FRA),” https://ceq.doe.gov/laws-regulations/fra.html.
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without the need to first develop a CX to cover them.81 In addition, CEQ created a standalone
definition of extraordinary circumstances and provided several examples that CEQ intended for
the standalone definition to improve clarity when this term is used for actions that normally may
be categorically excluded.82 It remains to be seen how BLM (or other agencies) may utilize this
additional flexibility. Congress may oversee the CEQ amendments and their impacts on BLM’s
NEPA procedures and BLM’s use and adoption of CXs.
If Congress seeks to authorize additional CXs through legislation, policy considerations could
include what types of projects normally would not have significant environmental effects but are
not currently categorically excluded either through agency-specific procedures or in existing law.
Additional policy considerations could include whether a CX would be appropriate for certain
other types of projects regardless of the significance of the environmental effects, and whether
Congress seeks to waive the preparation of an EA or EIS under NEPA because of other federal
priorities. Regardless, project operation still may be affected in such instances if potentially
applicable requirements are not identified through other means early in the process and regulatory
compliance under other laws becomes an issue. Whether a CX or a broader exemption from
NEPA may reduce the timing and cost of project operation would potentially depend on multiple
project-specific and site-specific circumstances that may vary among projects and locations.
Potential impacts on the opportunity for public input would be an additional consideration.

Author Information

Morgan Smith
Omar M. Hammad
Analyst in Energy Policy
Analyst in Environmental Policy

Lexie Ryan

Analyst in Energy Policy

81 Current provisions in 40 C.F.R. §1507.3(f)(5) allow agency procedures to establish a process that allows the agency
to use a categorical exclusion listed in another agency’s NEPA procedures. On April 15, 2024, BLM announced it
would publish a Federal Register notice and adopt that “in considering permits for notices of intent to explore for
geothermal resources, the BLM may use either the Forest Service or Navy categorical exclusion to support its
decision.” Bureau of Land Management, “BLM Adopts Categorical Exclusions to Expedite Geothermal Energy
Permitting,” April 15, 2024, https://www.blm.gov/press-release/blm-adopts-categorical-exclusions-expedite-
geothermal-energy-permitting.
82 This list of examples would not be exclusive, and agencies would continue to have the discretion to identify
extraordinary circumstances in their NEPA implementing procedures that are specific and appropriate to their particular
actions and categorical exclusions consistent with 40 C.F.R. §1507.3.
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under the direction of Congress. Information in a CRS Report should not be relied upon for purposes other
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