Revenues and Disbursements from Oil and
September 22, 2020
Natural Gas Leases on Onshore Federal Lands
Updated April 23, 2025
(R46537)
Jump to Main Text of Report
Contents
Introduction
Oil and Natural Gas Production on Federal Lands
Brandon S. Tracy
Federal revenues arising from oil and natural gas leases on federal lands support a range of
Analyst in Energy Policy
federal and state policies and programs. The 116th Congress is considering proposed changes to
policies affecting the collection and disbursement of revenues from onshore federal lands. Some of the proposed changes would affect royalty collections, allocation of revenue, the leasing
process, and exemptions from royalty assessment.
Total domestic production (or withdrawal) of crude oil and natural gas in 2019 was the highest in the history of the United States for each commodity; a subset of this total, crude oil produced on federal lands was also a record value in 2019. Oil and natural gas production from onshore federal lands contributed 9% to each total in 2019. Revenues from oil and natural gas leases on onshore federal lands totaled $4.202 billion in FY2019, representing 86% of total federal revenues from energy and mineral leases on onshore federal lands. These revenues are composed of royalties, $2.931 billion; bonuses, $1.181 billion; other revenue (including settlement agreements, interest payments, Application for Permit to Drill fees), $67 million; and rents, $22 million. Disbursements of these revenues include $2.002 billion to states; $1.539 billion to the Reclamation Fund; $39 million to the Permit Processing Improvement Fund; $172 million to other accounts; and $444 million to the Treasury General Fund.
The decision to drill a given well represents the outcome of many factors facing an operator, including geologic considerations, regulations, costs associated with initial capital investments, access to infrastructure, and labor, among others. Differences within and among geologic formations suitable for oil and natural gas extraction can influence the decision by an operator considering well location, including whether to drill on federal lands. Of the 242 million acres associated with U.S. shale plays (a shale play is a geologic formation with active or expected oil and/or natural gas production; production from shale employs directional drilling and hydraulic fracturing), approximately 24 million acres, or 9.9% of the total, are in the federal mineral estate; 90.1% is on nonfederal lands.
Numerous provisions in law affect revenue collection and disbursements from oil and natural gas leases
Statutory Authorities and the Leasing Process
Federal Land Policy Management Act
Mineral Leasing Act of 1920
Leasing Process Under the Mineral Leasing Act of 1920
Revenues and Disbursements from Federal Oil and Gas Leases
Federal Revenues
Revenue Allocation Under the Mineral Leasing Act
Disbursements
Policy Topics and Legislative Activity
The Inflation Reduction Act (P.L. 117-169): Changes to Revenues
Royalties and Lease Terms
Other Fiscal Terms
Revenue Allocation
Noncompetitive Leasing
Natural Gas Losses: Venting and Flaring
Summary
Federal revenues from oil and natural gas production on federal lands support a range of federal and state programs and activities. The Bureau of Land Management (BLM) is the primary federal agency responsible for administering oil and gas leases and development on onshore federal lands. Over the years, Congress has passed various laws directing how BLM collects and administer these revenues. Trump Administration executive orders signed in 2025 prioritized increasing oil and gas leasing and production on federal lands. Secretarial orders implementing these executive orders require review of aspects of the current approach.
Total domestic production of crude oil and natural gas in FY2023—the most recent year for which data are available—was the highest in the history of the United States for each commodity. A subset of this total came from crude oil and natural gas produced on federal lands, which also saw record highs in FY2023. Oil and natural gas production from onshore federal lands contributed 12% and 9% to each total in FY2023, respectively.
Oil and gas producers must pay certain fees to develop and produce these commodities on federal lands. Numerous provisions in law affect revenue collection and disbursement from oil and natural gas leases and production on federal lands. The Federal Land . The Federal Land
Policy Management Act Policy Management Act
establishes statutory authority for the Bureau of Land Management(FLPMA; 43 U.S.C. §1701 et seq.) establishes statutory authority for BLM to manage the federal to manage the federal
subsurface mineral mineral
estate. estate.
OnshoreThe onshore oil and natural gas oil and natural gas
are defined as leasable minerals,programs are generally governed by the Mineral Leasing Act of 1920 (MLA governed by the Mineral Leasing Act of 1920 (MLA
). In FY2019, approximately 93% of revenues from oil and natural gas developments on federal lands were disbursed according to provisions in the MLA. Some key provisions in the MLA include a 12.5% minimum royalty rate;; 30 U.S.C. §§181 et seq.), as amended. The MLA, as amended, also governs how federal revenues from oil and gas production are collected and disbursed. In states other than Alaska, 40% of revenues arising 40% of revenues arising
from oil and gas leasing on federal lands from oil and gas leasing on federal lands
in states other than Alaska are deposited into the Reclamation Fundare deposited into the Reclamation Fund
;, and and
that states states
other than Alaska receive 50% of revenues from extraction operations in those statesother than Alaska receive 50% of revenues from extraction operations in those states
. (Alaska receives 90%). Disbursements to states are assessed a 2% administration fee, which is deposited in the Treasury. Leases are sold to the highest bidder (at or above the required minimum bid) during competitive auctions, or are obtained non-competitively.
Bills introduced in the 116th Congress would alter the minimum royalty rate assessed on newAlaska receives 90% of revenues from oil and gas leasing and extraction. The 10% remainder in all states goes to the General Fund of the U.S. Department of the Treasury (Treasury). Disbursements to all states are assessed a 2% administrative fee, which is deposited in the Treasury.
Revenues from oil and natural gas leases on oil and natural gas leases on
federal lands. Given the high percentage of revenue from royalties, changes to the minimum royalty rate represent the most direct means of altering revenues and disbursements from oil and natural gas leases, under normal market conditions. Some bills would require royalties to be collected for natural gas lost or used in production that is currently exempt from royalty assessment.
Some bills would alter the current revenue allocation scheme, allowing states to obtain the 2% administrative fee currently deposited in the Treasury. Other bills would amend minimum required bids, rental rates, and aspects of the current leasing process, including the elimination of non-competitive leasing.
Congressional Research Service
link to page 4 link to page 4 link to page 4 link to page 8 link to page 8 link to page 9 link to page 10 link to page 10 link to page 11 link to page 11 link to page 11 link to page 12 link to page 14 link to page 15 link to page 15 link to page 18 link to page 19 link to page 19 link to page 21 link to page 22 link to page 24 link to page 6 link to page 7 link to page 7 link to page 9 link to page 17 link to page 17 link to page 19 link to page 26 link to page 26 Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Contents
Introduction ..................................................................................................................................... 1
Oil and Natural Gas Production on Federal Lands .......................................................................... 1
Background and Production History ......................................................................................... 1
Factors Affecting Production Decisions .................................................................................... 5
Geology ............................................................................................................................... 5
Production Inputs ................................................................................................................ 6
Regulations ......................................................................................................................... 7
Statutory Authorities ................................................................................................................. 7
Federal Land Policy Management Act of 1976 .................................................................. 8
Mineral Leasing Act of 1920 .............................................................................................. 8
Authorities Related to Acquired Lands ............................................................................... 8
Key Statutory Provisions .................................................................................................... 9
Description of the Leasing Process .......................................................................................... 11
Federal Revenues and Disbursements ........................................................................................... 12
Federal Revenues .................................................................................................................... 12
Disbursements ......................................................................................................................... 15
Policy Topics and Legislative Activity .......................................................................................... 16
Royalties .................................................................................................................................. 16
Revenue Allocation ................................................................................................................. 18
The Leasing Process and Fair Market Value ........................................................................... 19
Natural Gas Losses .................................................................................................................. 21
Figures
Figure 1. U.S. Crude Oil Production ............................................................................................... 3
Figure 2. U.S. Natural Gas Production ............................................................................................ 4
Figure 3. Relative Changes in Crude Oil and Natural Gas Production ........................................... 4
Figure 4. Federal Lands and Shale Plays ......................................................................................... 6
Figure 5. Federal Oil and Natural Gas Revenues from Onshore Federal Lands ........................... 14
Figure 6. Federal Oil and Natural Gas Revenues from Native American Lands .......................... 14
Figure 7. Estimated Disbursements of Oil and Natural Gas Revenues from Federal Lands ......... 16
Appendixes
Appendix. Methodology to Create the Estimated Disbursements Dataset .................................... 23
Contacts
Author Information ........................................................................................................................ 23
Congressional Research Service
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Introduction
Mineral extraction, including that of oil and natural gas, from onshore federal lands is a topic often debated. Some argue in favor ofonshore federal lands totaled $8.497 billion in FY2023, representing 93% of total federal revenues from all types of energy and mineral leasing on onshore federal lands. These revenues are composed of royalties ($8.370 billion); bonuses ($97 million); other revenues, including settlement agreements, interest payments, and fees from applications for permits to drill ($15 million); and rents ($15 million). Disbursements of these revenues for FY2023 include $3.862 billion to states; $3.045 billion to the Reclamation Fund; $14.73 million to the Permit Processing Improvement Fund; and $850 million to the General Fund of the Treasury.
The law commonly known as the Inflation Reduction Act of 2022 (IRA; P.L. 117-169) amended the MLA's provisions for onshore oil and gas leasing, such as increasing the minimum royalty rate, assessing new royalties on flared or vented methane, increasing rental rates, eliminating noncompetitive leasing, and implementing a fee to nominate lands for consideration to lease. Since enactment of the IRA, Congress has considered further changes to policies affecting the collection and disbursement of revenues from oil and gas development on federal lands. Some of the proposed changes would reverse aspects of the IRA or would otherwise affect royalty collections. For example, some proposals would require royalties to be collected for natural gas lost or used in production that is currently exempt from royalty assessment. Given the high percentage of federal oil and gas revenues that comes from royalties, changes to the minimum royalty rate represent the most direct means of altering revenues and disbursements from oil and natural gas leases, under normal market conditions. Other proposals would alter the current revenue allocation scheme so that states would no longer be assessed the 2% administrative fee currently deposited in the Treasury. Other approaches would amend minimum required bids, rental rates, and aspects of the current leasing process. Bills introduced in the 119th Congress include measures to reduce royalty and rental rates or remove specific fees.
Introduction
Federal revenues from oil and natural gas leases support a range of federal and state programs and activities. Revenues from oil and natural gas leases on onshore federal lands totaled $8.497 billion in FY2023, the most recent year for which data are available.1 Those revenues are 93% of total federal revenues from all leasable minerals and geothermal resources on onshore federal lands.2 The sources of these revenues include bonus bids for leases, lease rental payments, and production royalties. These revenues are disbursed to states, federal programs, and the General Fund of the U.S. Department of the Treasury (Treasury) according to statutory requirements.
The development of onshore oil and natural gas on federal lands is a perennial topic of debate among Members of Congress and other stakeholders. Some stakeholders support increased development, with the intent of increasing increased development, with the intent of increasing
domestic energy supply, employment opportunities in the sector, and domestic energy supply, employment opportunities in the sector, and
federal revenues from these revenues from these
activities. Others argue in favor of decreased development, with the intent of reducing pollution (e.g., greenhouse gas emissions) and preserving access to federal lands for other uses.
Federal revenues from oil and natural gas leases provide income streams that support a range of federal and state policies and programs. Revenues from oil and natural gas leases on onshore federal lands totaled $4.202 billion in FY2019.1 Those revenues are 86% of total federal revenues from leasable minerals and geothermal resources on onshore federal lands.2 The sources of these funds include bonus bids for leases, lease rental payments, production royalties, and other payments. These funds are disbursed to states, federal programs, and the U.S. Department of the Treasury (Treasury). Production of oil and natural gas on federal lands is subject to various federal regulations, including those related to air pollution, water pollution, and land use considerations, among others.
This report provides background information related to onshore oil and natural gas production on federal lands and related statutory authorities. Federal revenues and disbursements from oil and natural gas production are presented and discussed, with a focus on factors that can impact these values. A discussion of legislative proposals follows.
Oil and Natural Gas Production on Federal Lands
Background and Production History
Onshore federal lands include all federal surface lands and 710 million acres of the federal subsurface mineral estate.3activities. For example, the second Trump Administration has issued several executive orders that aim to increase or promote oil and gas development on federal lands. These include executive orders titled "Unleashing American Energy," "Declaring a National Energy Emergency," and "Unleashing Alaska's Extraordinary Resource Potential."3 Other stakeholders are in favor of decreased development, with the intent of reducing pollution (e.g., greenhouse gas emissions) and preserving access to federal lands for other uses.
This report provides background information related to onshore oil and natural gas production on federal lands. This report may in some places include data from offshore oil and natural gas production for comparison to onshore data, but it generally does not address the topic of offshore oil and natural gas production. For more information on offshore oil and natural gas leasing, see CRS Report R44692, Five-Year Offshore Oil and Gas Leasing Program: Status and Issues in Brief, by Laura B. Comay, and CRS Report R46195, Gulf of Mexico Energy Security Act (GOMESA): Background and Current Issues, by Laura B. Comay.
Oil and Natural Gas Production on Federal Lands
Onshore federal lands include all federal surface lands and the federal mineral estate, covering 713 million acres. The Bureau of Land Management (BLM), an agency within the The Bureau of Land Management (BLM), an agency within the
Department of the Interior (DOI), manages energy production and mineral development from Department of the Interior (DOI), manages energy production and mineral development from
these subsurface lands, including these subsurface lands, including
for lands whose surface is managed by other lands whose surface is managed by other
federal agencies or for agencies or for
split estate lands.split estate lands.
44 Oil and natural gas developments are considered mineral developments. Some Oil and natural gas developments are considered mineral developments. Some
federal landsfederal lands
, —including most National Park Service units, designated wilderness areas, including most National Park Service units, designated wilderness areas,
military bases, and others, have been withdrawn from mineral exploration and development. BLM and the Forest Service (FS), an agency within the Department of Agriculture (USDA), also have the
1 Not including revenue from Native American lands. Oil and natural gas resources are commonly coproduced on federal lands. The total for oil and natural gas leases includes all revenues from the commodity categories Oil, Gas, Oil & Gas, and NGL (natural gas liquids). These data are from the Office of Natural Resources Revenue (ONRR), available at https://revenuedata.doi.gov. Total includes fees from Application for Permit to Drill, received and disbursed by the Bureau of Land Management (CRS calculations using Bureau of Land Management data).
2 Coal leases contributed 12% to the total; all other mineral leases combined contributed the remaining 2%. 3 Native American lands are excluded from the federal mineral estate acreage (Bureau of Land Management, Public
Land Statistics 2019, 2020, Table 1-3, pp. 7-8).
4 Electricity produced from geothermal resources on federal lands is an example of energy production from the federal mineral estate. If surface lands over the federal mineral estate are not federally owned (i.e., split estate), BLM works with private surface owners to manage the federal mineral estate.
Congressional Research Service
1
link to page 6 Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
authority to use their surface lands for energy production, typically from renewable sources, including wind and solar.5
Offshore federal lands refers to the approximately 1.7 billion offshore acres in federal waters on the U.S. outer continental shelf (OCS), where energy and mineral leasing is managed by DOI’s Bureau of Ocean Energy Management (BOEM). The OCS encompasses the Gulf of Mexico, Pacific, Atlantic, and Alaska regions, with offshore energy and mineral development predominantly occurring in the Gulf of Mexico. This report may in some places include data from offshore oil and natural gas production for comparison to onshore data, but it generally does not address the topic of offshore oil and natural gas production.6
In 2019, total U.S. crude oil production (on federal and nonfederal lands) was 4.471 billion barrels (12,248,000 barrels per day),7 and the United States imported 2.48 billion barrels (6,795,000 barrels per day) of crude oil during the same period.8 Prior to the COVID-19 pandemic, the U.S. Energy Information Administration (EIA) forecasted that the United States would be a net exporter of oil in 2020.9
EIA estimates that the United States produced 40,704 billion cubic feet (Bcf) of natural gas in 2019, and estimates of net exports were 1,914 Bcf; the United States has been a net exporter of natural gas since 2017.10 Crude oil production and natural gas production in 2019 were the highest in the country’s history.11
U.S. crude oil production has increased over the last 10 years. Figure 1 shows total domestic oil production and the contributions from sources on and military bases—have been withdrawn by statute or executive action from mineral exploration and development.5
Oil production has increased overall, with most of the production coming from nonfederal lands. That said, the amount produced on onshore federal lands more than tripled from 2013 to 2023. Figure 1 shows total domestic oil production and the contributions from sources on federal (onshore and offshore) and nonfederal lands from FY2013 through FY2023. Oil production on nonfederal lands increased 69%, from 1.988 billion barrels in FY2013 to 3.353 billion barrels in FY2023.6 In FY2023, oil production on nonfederal lands had decreased to 72% of total U.S. production, from 75% in FY2013. Onshore oil production on federal lands, including production from tribal lands, increased 231%, from 185 million barrels in FY2013 to 611 million barrels in FY2023.7 In FY2023, onshore oil production on federal lands was 13% of total U.S. production, compared to 7% in FY2013.
Figure 1. U.S. Crude Oil Production, FY2013-FY2023
Sources: Total from Energy Information Administration, "Petroleum and Other Liquids, Crude Oil Production," January 31, 2025, https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm. Federal Offshore from Department of the Interior, Office of Natural Resources Revenue (ONRR), https://revenuedata.doi.gov/query-data/, Data Type "Production," Period "Fiscal Year," Land Type "Federal Offshore," State/Offshore Region "All," Product "Oil (bbl)"; and Federal Onshore from ONRR, https://revenuedata.doi.gov/query-data/, Data Type "Production," Period "Fiscal Year," Land Type "Federal Onshore, Native American," State/Offshore Region "All," Product "Oil (bbl)."
Notes: Nonfederal values are calculated by CRS as the difference between the total and the combined federal onshore and offshore values. EIA data are reported in calendar years; to convert to fiscal years, CRS used monthly EIA data.
Like oil, U.S. natural gas production has also increased overall, with an increasing share of production coming from nonfederal lands. Figure 2 shows total domestic natural gas production and the contributions from federal (onshore and offshore) and nonfederal sources from FY2013 through FY2023. Federal onshore natural gas production increased about 9% from FY2013 to FY2023, compared to a 65% increase infederal (onshore and offshore) and nonfederal lands from 2010 through 2019. Oil production on nonfederal lands has increased 163%, from 1,288 million barrels in 2010 to 3,386 million barrels in 2019.12 In 2019, oil production on production on
nonfederal lands had increased to 76% of the total, compared to 64% of total production in 2010. Onshore oil production on federal lands13 has increased 207%, from 124 million barrels in 2010 to 381 million barrels in 2019.14 In 2019, onshore oil production on federal lands was 9% of the total, compared to 6% of total production in 2010.
5 These types of renewable energy developments on federal land are developed under Title V of the Federal Land Policy Management Act (43 U.S.C. §§1761 et seq.).
6 For more information on the legal framework of oil and gas development on offshore lands, see CRS Report RL33404, Offshore Oil and Gas Development: Legal Framework, by Adam Vann. For more information on offshore oil and natural gas leasing, see CRS Report R44504, Five-Year Program for Offshore Oil and Gas Leasing: History
and Program for 2017-2022, by Laura B. Comay, Marc Humphries, and Adam Vann; and CRS Report R44692, Five-
Year Offshore Oil and Gas Leasing Program for 2019-2024: Status and Issues in Brief, by Laura B. Comay.
7 Includes lease condensate and excludes natural gas liquids (Energy Information Administration (EIA), “Petroleum and Other Liquids, Crude Oil Production,” https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm).
8 EIA, “Petroleum and Other Liquids, Imports by Area of Entry,” nonfederal lands. Natural gas production on nonfederal lands, which was 82% of total U.S. natural gas production in FY2013, increased from 24,269 Bcf in FY2013 to 40,113 Bcf in FY2023.8 In FY2023, natural gas production on nonfederal lands accounted for 83% of total U.S. production. Onshore natural gas production on federal lands, including tribal lands, increased 9%, from 3,863 Bcf in FY2013 to 4,227 Bcf in FY2023.9 In FY2023, onshore natural gas production on federal lands accounted for 9% of total U.S. production.
Figure 2. U.S. Natural Gas Production, FY2013-FY2023
Sources: Totals from Energy Information Administration, "Natural Gas Gross Withdrawals and Production," January 31, 2025, https://www.eia.gov/https://www.eia.gov/
dnav/ng/ng_prod_sum_a_epg0_fgw_mmcf_a.htm; federal offshore values from Department of the Interior, Office of Natural Resources Revenue (ONRR), https://revenuedata.doi.gov/query-data/, Data Type "Production," Period "Fiscal Year," Land Type "Federal Offshore," State/Offshore Region "All," Product "Gas (mcf)"; and federal onshore values from ONRR, https://revenuedata.doi.gov/query-data/, Data Type "Production," Period "Fiscal Year," Land Type "Federal Onshore, Native American," State/Offshore Region "All," Product "Gas (mcf)."
Notes: Nonfederal values are calculated by CRS as the difference between the total and the combined federal dnav/pet/pet_move_imp_dc_NUS-Z00_mbbl_a.htm.
9 EIA, Annual Energy Outlook 2020, January 2020, p. 39. 10 Gross withdrawals, excluding lease condensate; data for 2019 are estimates (EIA, Monthly Energy Review July 2020, Table 4.1, p. 101).
11 For additional information on the history of oil and natural gas production in the United States, see CRS In Focus IF11036, U.S. Oil and Natural Gas Transformation and Effects, by Michael Ratner et al.; CRS Report R45493, The
World Oil Market and U.S. Policy: Background and Select Issues for Congress, by Heather L. Greenley; and CRS Report R45988, U.S. Natural Gas: Becoming Dominant, by Michael Ratner.
12 CRS calculations, based on EIA and ONRR data. 13 Includes production from Native American lands. 14 ONRR, https://revenuedata.doi.gov/.
Congressional Research Service
2
link to page 7 
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
U.S. natural gas production has seen a similar increase to that of crude oil production. Figure 2
shows total domestic natural gas production and the contributions from federal (onshore and offshore) and nonfederal sources from 2010 through 2019. Natural gas production on nonfederal lands, which was 76% of total production in 2010, has increased 77%, from 20,290 Bcf in 2010 to 35,913 Bcf in 2019.15 In 2019, natural gas production on nonfederal lands was 88% of the total. Onshore natural gas production on federal lands,16 which was 16% of total production in 2010, has decreased 11%, from 4,205 Bcf in 2010 to 3,730 Bcf in 2019.17 In 2019, onshore natural gas on federal lands production was 9% of the total.
In FY2010, BLM administered 22,676 oil and natural gas leases in producing statusonshore and offshore values. EIA data are reported in calendar years; to convert to fiscal years, CRS used monthly EIA data.
While oil and natural gas production on federal lands increased between FY2013 and FY2023, both areas of production (known as leases in producing status) and the number of leases (which can include leases that are not producing) remained relatively stable. In FY2013, BLM administered 23,507 oil and natural gas leases that produced oil and/or natural gas (i.e., leases in producing status), covering , covering
12.12.
26 million acres. million acres.
18 In FY201910 In FY2023, BLM administered , BLM administered
24,12723,641 oil and natural gas leases in oil and natural gas leases in
producing status, covering 12.4 million acres.producing status, covering 12.4 million acres.
1911 Between Between
FY2010 and FY2019FY2013 and FY2023, the number of , the number of
producing leases increased producing leases increased
6.4%, andby 0.6%, but the area covered by producing leases the area covered by producing leases
increased 1.6%.
Figure 1. U.S. Crude Oil Production
Source: Total from EIA, https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm; Federal Offshore and Federal Onshore from ONRR, https://revenuedata.doi.gov/. Notes: Nonfederal values are calculated by CRS as the difference between the total and the combined federal onshore and offshore values.
15 CRS calculations, based on EIA and ONRR data. 16 Includes production from Native American lands. 17 ONRR, https://revenuedata.doi.gov/. 18 BLM, Public Land Statistics 2010, 2011, Table 3-17, p. 126. 19 BLM, Public Land Statistics 2019, 2020, Table 3-17, p. 108.
Congressional Research Service
3
link to page 7 
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Figure 2. U.S. Natural Gas Production
Source: Total from EIA, https://www.eia.gov/dnav/ng/ng_prod_sum_a_epg0_fgw_mmcf_a.htm; Federal Offshore and Federal Onshore from ONRR, https://revenuedata.doi.gov/. Notes: Nonfederal values are calculated by CRS as the difference between the total and the combined federal onshore and offshore valuesdecreased by 1.4%. Because production of oil and natural gas on onshore federal lands also increased during this time (see Figure 1 and Figure 2), even though the area covered by leases decreased, producing leases in FY2023 were more productive, on average, than producing leases producing in FY2013. .
Figure 3 presents the oil and natural gas presents the oil and natural gas
production data from nonfederal, federal offshore, and federal data from nonfederal, federal offshore, and federal
onshore regions as an index. The base year of the index is onshore regions as an index. The base year of the index is
2010FY2013; the index values are equivalent ; the index values are equivalent
to percentage values. to percentage values.
This presentation of the data highlightsThese data highlight relative changes in each series. For relative changes in each series. For
example, onshore oil production on federal lands increasedexample, onshore oil production on federal lands increased
, as a percentage as a percentage
, more than oil more than oil
production on nonfederal lands over the period production on nonfederal lands over the period
2010 to 2019. from FY2013 to FY2023. Onshore oil production on federal lands increased by 231% from FY2013 to FY2023, while oil production on nonfederal lands increased by 69%. Over the same time period, federal offshore natural gas production decreased by about 45%, while federal onshore natural gas production increased by 9%.
Figure 3. Relative Changes in Crude Oil and Natural Gas Production
, FY2013-FY2023
Source: CRS calculations using data from CRS calculations using data from
EIA, Energy Information Administration, https://www.eia.gov/dnav/ng/https://www.eia.gov/dnav/ng/
ng_prod_sum_a_epg0_fgw_mmcf_a.htmng_prod_sum_a_epg0_fgw_mmcf_a.htm
, and and
ONRR, Department of the Interior, Office of Natural Resources Revenue, https://revenuedata.doi.gov/https://revenuedata.doi.gov/
. .
Notes: 2010FY2013 is the base year for the index; values are equivalent to percentages. is the base year for the index; values are equivalent to percentages.
Congressional Research Service
4
link to page 9 Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
The observed differences between oil and natural gas production on federal and nonfederal lands can raise questions about the source of the differences in production. The next section discusses factors that could affect production decisions, which then affect the resulting production data.
Factors Affecting Production Decisions
The decision to drill a given well represents the outcome of many factors facing an operator; 20 geology is arguably the predominant factor, as it influences the decision to drill in many ways. Loosely defined, an operator’s expected profit is the difference between the expected revenue and expected costs. The expected revenue represents the operator’s assessment of future revenues received for the commodity (or commodities, if more than one commodity is produced), sold at market prices, as it is produced over time. The expected costs associated with a given well, in addition to initial capital costs, can vary according to access to infrastructure (e.g., roads, water), characteristics of the given well (e.g., drilling depth, drilling costs), labor costs, resource costs (e.g., land purchase, land lease), and financial costs (e.g., taxes, debt financing, royalties), among others. An operator commonly incurs much of the costs associated with drilling a new well before drilling begins. These expenditures commonly result in financial pressures on the operator to bring the well into production as quickly as possible.
Onshore oil and natural gas production levels from federal lands are low compared to production from nonfederal lands. Some of the factors driving the difference can be grouped and discussed in three categories: geology, production inputs, and regulations.
Geology
Geologic factors are a major consideration facing an operator planning to drill a new well. Due to the limited presence of suitable geologic formations on federal lands, only in some cases can the operator choose between otherwise equal options of drilling on federal lands or on nonfederal lands.
Geologic formations likely to contain oil and natural gas resources are called basins. If exploration of a basin indicates economically recoverable quantities of oil and/or natural gas, and if the rock formation is shale, the area is called a shale play; one basin can contain multiple plays. Differences within and among shale plays influence operators’ decisions about well location, as some costs depend upon geologic characteristics. For example, some shale plays are deeper than others, which can result in a higher drilling cost per well.21 Some formations result in wells that produce only oil or natural gas; the majority of wells in the United States produce both oil and natural gas.22
While the federal mineral estate is over 700 million acres (mostly in the western half of the United States), the location of geologic formations in the United States containing oil and natural gas deposits suitable for extraction using current technology fall predominantly outside the federal mineral estate. Figure 4 shows the shale plays currently suitable for oil and natural gas
20 One definition of operator is “any person or entity, including, but not limited to, the lessee or operating rights owner, who has stated in writing to the authorized officer that it is responsible under the terms and conditions of the lease for the operations conducted on the leased lands or a portion thereof” (43 C.F.R. §3100.0-5(a)).
21 For more information on drilling oil and natural gas wells in shale plays, see CRS Report R45988, U.S. Natural Gas:
Becoming Dominant, by Michael Ratner.
22 For information on domestic oil and natural gas well production, see EIA, The Distribution of U.S. Oil and Gas Wells
by Production Rate, December 2019, available at https://www.eia.gov/petroleum/wells/.
Congressional Research Service
5
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
production within the United States, overlaid on a map showing federal lands. Of the 242 million acres associated with the indicated shale plays, approximately 24 million acres, or 9.9% of the total, are in the federal mineral estate.23
Figure 4. Federal Lands and Shale Plays
Source: Created by CRS using Tight Oil and Shale Gas Plays data from EIA, available at https://www.eia.gov/maps/layer_info-m.php, and the Protected Area Database of the U.S. (PADUS) from the U.S. Geological Survey, available at https://data.fs.usda.gov/geodata/edw/edw_resources/meta/S_USA.PADUS_Fee.xml. Notes: Shale plays on the borders of the United States may continue beyond national boundaries.
Production Inputs
Production inputs (i.e., costs) required to bring an oil or natural gas well into production can include land or legal inputs (e.g., obtain land or mineral rights), capital inputs (e.g., drilling equipment or services), labor inputs (e.g., equipment operators, geologists), and material inputs (e.g., water, concrete, fuel), among others. As operators attempt to maximize profits, they attempt to minimize the cost of inputs; such cost-minimizing behavior can explain some of the reasons for uneven development of oil and natural gas wells, including differences in production between federal and nonfederal lands.
Production of oil and natural gas does not occur evenly across all basins: some basins contain many producing oil and natural gas wells, while other basins with known resources are not producing at the same rate. To some degree, this observation stems from operators selecting the sites expected to result in the highest profit first, proceeding to the next highest site, and so on. Some basins have been under development for years, which can represent lower costs for some
23 Calculated by CRS using data from USA Contiguous Albers Equal Area Conic USGS version.
Congressional Research Service
6
link to page 14 Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
production inputs, for example, due to the availability of labor, equipment, and services. Moving to a new basin can result in higher costs, due to mobilizing or acquiring inputs in the new location. Additionally, drilling costs can vary between basins due to geologic differences.
Within a given basin, wells are typically found in clusters. New wells are commonly drilled on the frontiers of the clusters, rather than occurring uniformly or randomly across the basin. This observation also stems from cost-minimizing behavior of the operators: it is typically more cost-effective to drill a new well close to the most recently drilled well than to drill a well at a more distant location.
Regulations
Oil and natural gas basins often span multiple states. While applicable federal laws remain consistent across such basins (e.g., labor laws, environmental laws, federal tax law24), operators may face different regulations in different states (e.g., state taxes on oil and natural gas production).
One factor that affects the regulatory environment for a given well is whether it is drilled on federal land or on nonfederal land. Oil and natural gas leases on federal lands are regulated, in part, by federal authorities that may be different from leases on nonfederal lands. For example, the federal leasing process (described in “Description of the Leasing Process”) can affect the time before production begins when compared to production options on nonfederal lands; it may also affect the costs of bringing a well into production. In addition to the laws discussed in the next section, when an operator plans to drill on a federal lease, BLM must comply with the National Environmental Policy Act (NEPA), the Endangered Species Act (ESA), and the National Historic Preservation Act (NHPA), among others;25 these laws are not discussed further in this report.26
Statutory Authorities
This section presents a summary of the major statutory authorities that impact revenues and disbursements from oil and natural gas developments on federal lands. A discussion of key provisions follows these summaries.
24 A note on federal taxes on petroleum: A 9 cents per barrel excise tax is collected on domestic crude oil and imported petroleum products (26 U.S.C. §§4611 et seq.). Generally, the tax is levied on crude oil received at a refinery or petroleum products entering the U.S. for consumption or use. The tax applies whether the oil was extracted on federal lands or otherwise. Excise tax revenues are not included in the data in this report. Revenues from the tax finance the Oil Spill Liability Trust Fund (OSLTF), which is used to pay for damages resulting from oil spills or threats of oil spills. For background, see CRS In Focus IF11160, The Oil Spill Liability Trust Fund Tax: Background and Reauthorization
Issues in the 116th Congress, by Jonathan L. Ramseur. The tax is scheduled to expire on December 31, 2020. See CRS Report R46451, Energy Tax Provisions Expiring in 2020, 2021, 2022, and 2023 (“Tax Extenders”), by Molly F. Sherlock, Margot L. Crandall-Hollick, and Donald J. Marples.
25 BLM, “Operations and Production,” https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/operations-and-production.
26 For background information on NEPA, see CRS Report RL33152, The National Environmental Policy Act (NEPA):
Background and Implementation, by Linda Luther; for background information on ESA, see CRS Report RL31654, The Endangered Species Act: A Primer, by Pervaze A. Sheikh; and for background information on NHPA, see CRS Report R45800, The Federal Role in Historic Preservation: An Overview, by Mark K. DeSantis.
Congressional Research Service
7
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Federal Land Policy Management Act of 1976
The Federal Land Policy Management Act (FLPMA)27 establishes statutory authority for DOI and BLM management of federal lands, including the federal mineral estate. FLPMA directs the BLM to manage federal lands according to the principles of multiple use and sustained yield.28 FLPMA codifies the policy that public lands remain in federal ownership, unless DOI determines disposal of public lands is in the national interest, and that fair market value is to be obtained for use of federal lands. Under FLPMA, the BLM prepares resource management plans (or land use plans) through a defined process that incorporates public input, including environmental, historical, and societal values, from a variety of stakeholders.29 Where BLM is not the surface management agency of lands on which a mining operation is proposed, FLPMA directs BLM to coordinate with the surface management agency. FLPMA provides authority to DOI to withdraw lands from mineral entry (i.e., prohibit new mining).
Mineral Leasing Act of 1920
Multiple statutory authorities govern mineral development (i.e., mineral extraction) on onshore federal lands. The different authorities create different revenue and disbursement streams from mineral developments. Statutory authorities create three general categories of mineral development from onshore federal lands: locatable (or hardrock) minerals, mineral materials, and leasable minerals.30
Oil and natural gas are defined as leasable minerals, whose exploration and extraction are governed by the Mineral Leasing Act of 1920 (MLA).31 The MLA authorizes DOI, and subsequently BLM, to promulgate regulations for oil and natural gas leasing on federal lands. Mineral development of Native American lands are covered by other statutory authorities, which are not discussed in this report.32
Authorities Related to Acquired Lands
The MLA applies only to public domain lands; the Mineral Leasing Act for Acquired Lands (MLAAL)33 generally extends the MLA to acquired lands.34 Public domain lands are those ceded by the original states or obtained from a foreign sovereign (via purchase, treaty, or other means). Acquired lands are those obtained from a state or individual by exchange, purchase, or gift. Lands
27 P.L. 94-579. FLPMA is codified at 43 U.S.C. §§1701 et seq. For a background on FLPMA, see 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.
28 Ibid., pp. 2-3. 29 Ibid., p. 5. For more information on the BLM’s planning process, see https://www.blm.gov/programs/planning-and-nepa/what-informs-our-plans.
30 For more information on locatable minerals and mineral materials, see CRS Report R46278, Policy Topics and
Background Related to Mining on Federal Lands, by Brandon S. Tracy.
31 P.L. 66-146, codified at 30 U.S.C. §§181 et seq. Leasable minerals also include coal and some non-energy minerals, such as sodium, potassium, phosphate, gilsonite, and sulfur.
32 Statutory authorities regarding mineral developments on Native American lands are generally contained in 25 U.S.C. Chapter 12 and 25 U.S.C. Chapter 23.
33 P.L. 80-382, codified at 30 U.S.C. §§351 et seq. 34 About 90% of all federal lands are public domain lands, while the other 10% are acquired lands. For more information on federal lands, see CRS Report R42346, Federal Land Ownership: Overview and Data, by Carol Hardy Vincent and Laura A. Hanson.
Congressional Research Service
8
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
may have been or may be acquired through acts of Congress and under the authority of DOI, among other methods. When lands are acquired by legislation, provisions in the legislation may indicate treatment of mineral resources that differs from otherwise applicable law. If lands are acquired by purchase or exchange, existing mineral developments and leases may include terms that would be inconsistent with otherwise applicable laws.35
The MLAAL specifies that “all receipts derived from leases issued under the authority of this chapter shall be paid into the same funds or accounts in the Treasury and shall be distributed in the same manner as prescribed for other receipts from the lands affected by the lease.”36 This provision can allow for disbursements of revenues from oil and natural gas developments on acquired lands that do not follow the revenue allocations authorized by the MLA.
A number of other statutory authorities impact the collection and disbursement of revenues from oil and natural gas developments on federal land. For example, revenues from mineral developments on acquired lands managed by FS are allocated between FS and the state in which the mineral revenues originated, with 75% disbursed to FS and 25% disbursed to the state.37 Revenues from mineral developments on lands that were acquired for flood control purposes are allocated between Treasury and the state in which the mineral revenues originated, with 75% disbursed to the state and 25% remaining in the Treasury.38 Revenues from mineral developments on acquired lands managed by the Fish and Wildlife Service (FWS) are allocated (100%) to FWS.39
Key Statutory Provisions
In FY2019, approximately 93% of revenues from oil and natural gas development on federal lands were disbursed according to provisions in the MLA.40 Some provisions within FLPMA, MLA, MLAAL, and other authorities more directly affect federal revenue collection and allocation from oil and natural gas leases than others; a presentation of some of these provisions, primarily within the MLA, follows.
Royalties
The MLA defines the minimum royalty rate on oil and natural gas produced on federal lands to be 12.5%.41 Royalties (i.e., revenue from the application of the royalty rate to production) reflect the product of the royalty rate and the market value of the commodity produced.42 Royalty rates are defined in the terms of each lease and are not expected to change during the term of the lease.43
35 Phone call with Congressional Liaison, BLM, March 16, 2020. 36 30 U.S.C. §355(a). 37 16 U.S.C. §§499-500. 38 33 U.S.C. §701c-3. 39 16 U.S.C. §715s. 40 CRS calculations using ONRR and BLM data and the MLA provision that the Reclamation Fund receives 40% of bonuses, royalties, and other revenues; and the MLA provisions for Alaska.
41 30 U.S.C. §226(b)(1)(A). 42 For example, if an operator produces and sells $1,000 of oil on a federal lease during a given month, application of the minimum royalty rate of 12.5% would result in $125 royalties owed to the federal government for that month’s production.
43 Additional provisions apply to reinstatement of a lease after failure to comply with the terms of the lease, including higher rental and royalty rates (30 U.S.C. §187(c-e)).
Congressional Research Service
9
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
DOI has the authority to suspend, waive, or reduce royalties collected from oil and natural gas leases to ensure maximum production or to conserve natural resources.44
Revenue Allocation
The MLA indicates that for oil and natural gas leases on federal lands,45 in states other than EIA data are reported in calendar years; to convert to fiscal years, CRS used monthly EIA data.
Statutory Authorities and the Leasing Process
This section presents summaries of the major statutory authorities that impact revenues and disbursements from oil and natural gas developments on onshore federal lands. A discussion of key provisions follows these summaries.
Federal Land Policy Management Act
BLM administers federal lands and the subsurface estate under its jurisdiction pursuant to the Federal Land Policy Management Act (FLPMA).12 FLPMA directs BLM to manage lands under its jurisdiction 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."13 Although FLPMA places certain requirements and constraints on BLM's implementation of these "multiple use" and "sustained yield" directives, some discretion is left to the agency to interpret how best to comply with this statutory mandate.14
Under FLPMA, BLM prepares resource management plans (also called land use plans) through a statutorily required process that incorporates public input—including environmental, historical, and societal values—from a variety of stakeholders.15 Where BLM is not the surface management agency of lands on which an oil or natural gas operation is proposed, FLPMA directs BLM to coordinate with the relevant surface management agency. FLPMA also provides authority to withdraw lands from mineral entry (i.e., prohibit new oil and gas leasing).
Mineral Leasing Act of 1920
Multiple statutory authorities govern mineral development (i.e., mineral extraction) on onshore federal lands. The different authorities create different revenue and disbursement streams from mineral developments. Federal law creates three general categories of mineral development from onshore federal lands: locatable (or hardrock) minerals, leasable minerals, and mineral materials.16
Oil and natural gas are defined as leasable minerals whose exploration and extraction are governed by the Mineral Leasing Act of 1920 (MLA).17 The MLA authorizes DOI, and subsequently BLM, to promulgate regulations for oil and natural gas leasing on federal lands. Mineral development on tribal lands is administered pursuant to other statutory authorities, which are not discussed in this report.18
A summary of lease terms for federal oil and gas resources is found in Table 1. An explanation of the leasing process under the MLA follows.
Table 1. Summary of Lease Terms for Federal Oil and Gas Resources
Lease Term
Details
|
Citation
|
Primary lease length
|
10 years
|
30 U.S.C. §226(e)
|
Maximum lease acreage held by one entity in one state
|
States besides Alaska: 246,080 acres
Alaska: 300,000 acres in the northern leasing district and 300,000 acres in the southern leasing district
|
30 U.S.C. §184(d)(1)
|
|
Maximum area for single oil and natural gas lease
|
States besides Alaska: 2,560 acres
Alaska: 5,760 acres
|
30 U.S.C. §226(b)
|
|
Lease renewal
|
Lease continues as long as there is production of oil or gas in paying quantities. If drilling operations commenced before the end of the primary term, the lease can be extended for two years and any period thereafter during which oil and gas is produced.
|
30 U.S.C. §226(e)
|
Predrilling bond requirements
|
Lessee or operator must post a bond amounting to $150,000 for a single lease or $500,000 for all leases in a state.
|
30 U.S.C. §226(g); 43 C.F.R. 3104
Nomination fee
|
The Bureau of Land Management solicits nominations for lands for oil and gas leasing. Expressions of interest (EOIs) must include $5.00 per acre fee; 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 to date.
|
30 U.S.C. §226(q)
|
Competitive lease application fee
|
$3,100
|
43 C.F.R. §3000.120
|
|
Minimum bonus bid
|
$10.00 per acre for the 10-year period beginning on August 16, 2022. The national minimum acceptable bid may be increased after that period.
|
30 U.S.C. §226(b)
|
|
Rent
|
For the 10-year period beginning on August 16, 2022, no less than $3.00 per acre for the first 2 years, $5.00 per acre per year for the following 6-year period, and $15.00 per acre per year thereafter.
|
30 U.S.C. §226(d)
|
|
Royalty
|
16⅔% of the value of production during the 10-year period beginning on August 16, 2022, and no less than 16⅔% thereafter. The Secretary of the Interior is permitted to "waive, suspend or reduce the rental or minimum royalty" as a production incentive, at the Secretary's discretion.
|
30 U.S.C. §226(b); 30 U.S.C. §209; and 43 C.F.R. §3103.4-1(a)
|
|
Lease relinquishment
|
If all owed rentals and royalties have been paid, mineral lease owners can relinquish a lease at any time, subject to the termination obligations of the lease (e.g., perform site reclamation before the lease bond is released).
|
30 U.S.C. §187(b)
|
Source: CRS analysis.
Notes: The bonus bid (also known as the bonus or the bid) 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.
Leasing Process Under the Mineral Leasing Act of 1920
Under the MLA, BLM employs a competitive leasing process to issue leases to extract oil and natural gas from federal lands. The competitive leasing process begins with the identification of federal lands to be included in a lease sale.19 Federal land parcels can be nominated for inclusion in a lease sale by an expression of interest (EOI) submitted by a member of the public, or BLM can select the parcels to include in a lease sale. The EOI must include a $5.00 per acre nominating fee.20 These lands must be deemed suitable for oil and natural gas development, as determined by the BLM land use planning process mandated by FLPMA. The land use planning process is subject to requirements under the National Environmental Policy Act (NEPA), the Endangered Species Act (ESA), and the National Historic Preservation Act (NHPA).21 Federal lease sales are required to occur quarterly if parcels are available.22 After reviewing an EOI for conformity to the land use planning process, BLM may choose to include nominated parcels in a future lease sale.
A Notice of Competitive Lease Sale is posted at least 45 days before the lease sale is held. A competitive lease sale may be conducted by oral or internet auction. The lease is awarded to the qualified bonus bid offering the highest bonus payment. To qualify, a bonus bid must exceed the minimum acceptable bonus bid of $10.00 per acre.23
After the lease has been awarded and the lessee has agreed to the terms and stipulations of the lease, the lessee must pay the bonus bid, the first year's rent on the lease, and other filing fees (for nominated parcels, some of these fees must be submitted with the nomination application). The lessee must post a bond in an amount determined by BLM, to be released after production activities on the lease have stopped and the surface has been reclaimed to the satisfaction of BLM.24 Under a rule effective June 22, 2024, the minimum bonding amount for an oil and gas lease increased from $10,000 to $150,000 per lease bond, which covers all drilling operations on a single lease, and from $25,000 to $500,000 for a statewide bond, which covers all of an operator's wells in a single state.25 BLM is to adjust bond amounts for inflation every 10 years.26 Any nationwide bonds (which cover all federal leases nationwide) or unit operator bonds (which cover operations on all federal leases under a unit agreement) filed by the oil and gas unit operator in lieu of individual lease bonds must be replaced with individual lease or statewide bonds by June 22, 2025.27 A secretarial order announced on February 3, 2025, directed BLM to review the rule implementing the updated bonding amounts and structure.28
Before drilling can begin, the operator must submit a completed application for permit to drill (APD),29 including an application fee, for each well.30 This value is $12,515 for FY2025 and is indexed to inflation.31 Before production can begin, the operator must submit an acceptable plan of operations and receive approval from BLM, which includes completing a NEPA review.32 Once production begins, the lessee pays a royalty of 16⅔% on the value of production.33
|
The Mineral Leasing Act for Acquired Lands
The MLA applies only to public domain lands—those ceded by the original states or obtained from a foreign sovereign (via purchase, treaty, or other means). The Mineral Leasing Act for Acquired Lands (MLAAL)34 generally extends the MLA to acquired lands.35 Acquired lands are those obtained from a state or individual by exchange, purchase, or gift. Lands may have been or may be acquired through acts of Congress and under the authority of DOI, among other methods. When lands are acquired by legislation, provisions in the legislation may require treatment of mineral resources that differs from treatment under otherwise applicable laws. Similarly, Congress may legislate exceptions from the MLA and set different lease or disbursement terms for specific land.
In FY2023, leasing receipts from two categories of acquired lands were distributed differently than the MLA: acquired National Forest lands and acquired Flood Control lands.36 For acquired National Forest lands, states receive 25% of all energy leasing revenues and the Forest Service receives 75%.37 For acquired Flood Control lands, states receive 75% of all energy leasing revenues and 25% is disbursed to the Treasury.38 In FY2023, disbursements to states from acquired National Forest lands amounted to $7 million, and payments to states from acquired Flood Control lands amounted to $55 million. In comparison, MLA payments to states in FY2023 was $4,266 million.
|
Revenues and Disbursements from Federal Oil and Gas Leases
DOI's Office of Natural Resources Revenue (ONRR) collects and disburses most of the federal revenues from onshore and offshore energy and mineral development. ONRR maintains data on most energy and mineral production, revenues, and disbursements originating from leases on federal lands and waters. Some fees related to oil and natural gas leases on federal lands are paid to the administering agency (e.g., BLM, FS) rather than to ONRR.
The next two sections describe and discuss revenues, revenue allocation, and disbursements from oil and natural gas leases on onshore federal lands.
Federal Revenues
As maintained by ONRR, data on revenues collected from oil and natural gas development are categorized as "Bonus," "Rents," "Royalties," and "Other Revenues."39 The category "Other Revenues," as reported by ONRR, captures other revenues, including those from settlement agreements and interest payments.40 Revenue data do not indicate whether a lease is on public domain land or acquired land.
In FY2023, leasable minerals and geothermal resources resulted in total collections of $9.096 billion from onshore federal lands.41 Of these collections, $8.497 billion (93%) were from oil and natural gas resources, which are commonly coproduced on federal lands.42 Total oil and natural gas collections represent the sum of royalties ($8.370 billion), bonuses ($96.7 million), other revenues ($15 million), and rents ($15 million).43
Approximately 93% of federal onshore energy and mineral revenues in FY2023 came from oil and gas leasing.44 As royalties represent the largest share (98%) of revenues, changes in oil and gas prices have been among the major factors in revenue fluctuations from year to year; some other factors affecting revenues include changes in production and bonuses paid for leases. Federal law establishes the minimum royalty rate, but specific lease terms can vary. Current federal law establishing the minimum royalty may differ from prior federal law when some leases were issued; therefore, royalty rates on active leases may be different from royalty rates for newer leases (see royalty rate changes in Table 2).
Figure 4 shows the revenues collected from oil and natural gas developments on federal lands by revenue category, from FY2013 through FY2023. As royalties are partially determined by commodity prices, the reduction in royalties starting in FY2015 partly reflects a fall in the price of crude oil from 2014 to 2015. Another reduction in royalties in 2020 may reflect a collapse in crude prices in FY2020. Similarly, the increase in royalties from FY2020 to FY2023 partly reflects an increase in the price of crude oil over the same period. The "Bonuses" series reflects a collection of $976 million for October 2018 (in FY2019), resulting from a lease sale in New Mexico.45
Figure 4
. Federal Oil and Natural Revenues from Onshore Federal Lands,FY2013-FY2023
Figure is interactive in the HTML version of this report.
<script type="text/javascript">//Based on IAG in AP 7.4.1 (Revised 20240624)
$(function () {
$('#IAG-3062662095').bind('mousedown', function () { /* saveRptHighChartClick(); */ });
//#### HIGHCHART LIBRARIES ####//
var files = ["https://code.highcharts.com/highcharts.js","https://code.highcharts.com/highcharts-more.js","https://code.highcharts.com/modules/exporting.js","https://code.highcharts.com/modules/export-data.js","https://code.highcharts.com/modules/accessibility.js"],
loaded = 0;
if (typeof window["HighchartsEditor"] === "undefined") {
window.HighchartsEditor = {
ondone: [cl],
hasWrapped: false,
hasLoaded: false
};
include(files[0]);
} else {
if (window.HighchartsEditor.hasLoaded) {
cl();
} else {
window.HighchartsEditor.ondone.push(cl);
}
}
function isScriptAlreadyIncluded(src) {
var scripts = document.getElementsByTagName("script");
for (var i = 0; i < scripts.length; i++) {
if (scripts[i].hasAttribute("src")) {
if ((scripts[i].getAttribute("src") || "").indexOf(src) >= 0 || (scripts[i].getAttribute("src") === "http://code.highcharts.com/highcharts.js" && src === "https://code.highcharts.com/stock/highstock.js")) {
return true;
}
}
}
return false;
}
function check() {
if (loaded === files.length) {
for (var i = 0; i < window.HighchartsEditor.ondone.length; i++) {
try {
window.HighchartsEditor.ondone[i]();
} catch (e) {
console.error(e);
}
}
window.HighchartsEditor.hasLoaded = true;
}
}
function include(script) {
function next() {
++loaded;
if (loaded < files.length) {
include(files[loaded]);
}
check();
}
if (isScriptAlreadyIncluded(script)) {
return next();
}
var sc = document.createElement("script");
sc.src = script;
sc.type = "text/javascript";
sc.onload = function () {
next();
};
document.head.appendChild(sc);
}
function each(a, fn) {
if (typeof a.forEach !== "undefined") {
a.forEach(fn);
} else {
for (var i = 0; i < a.length; i++) {
if (fn) {
fn(a[i]);
}
}
}
}
var inc = {},
incl = [];
each(document.querySelectorAll("script"), function (t) {
inc[t.src.substr(0, t.src.indexOf("?"))] = 1;
});
function cl() {
if (typeof window["Highcharts"] !== "undefined") {
//#### HIGHCHART LIBRARIES END ####//
//##### CRS THEME START (v1.2, 20220510)#####//
Highcharts.theme = {
colors: ['#0C90FC', '#003865', '#F1B434', '#7060A8', '#6CC8BD', '#757048', '#B4C7D0', '#D36127'],
chart: {backgroundColor: 'white',},
title: {
style: {
color: 'black',
font: '15px "Calibri", Verdana, sans-serif',
fontWeight: 'bold'
}
},
subtitle: {
style: {
color: 'black',
font: '14px "Calibri", Verdana, sans-serif'
}},
credits: {
enabled: false
},
legend: {
itemStyle: {
fontFamily: '"Calibri", Verdana, sans-serif',
fontSize: '14px',
color: 'black',
"text-decoration": 'none !important'
},
verticalAlign: 'top',
itemMarginBottom: 7,
},
yAxis: {
title: {
style: {
font: '14px "Calibri", Verdana, sans-serif',
fontWeight: 'bold',
color: 'black'}
},
labels: {
style: {
font: '14px "Calibri", Verdana,sans-serif',
color: 'black'}},
},
xAxis: {
title: {
style: {
font: '14px "Calibri", Verdana, sans-serif',
fontWeight: 'bold',
color: 'black'},
y: 8
},
labels: {
style: {
font: '14px "Calibri", Verdana, sans-serif',
color: 'black'
},
},
lineColor: 'black',
lineWidth: 0.5
}
};
Highcharts.setOptions(Highcharts.theme);
Highcharts.setOptions({
lang: {thousandsSep: ','},
chart: {style: {fontFamily: 'Calibri'}},
exporting: { enabled: false }
});
//##### CRS THEME END #####//
//#### START chart elements before Highcharts container ####//
//#### END chart elements before the Highcharts container ####//
var options = {
//#### START code inside Highcharts.chart('container', { ####//
chart: {
type: 'column',
zoomType: 'xy',
height:600
},
title: {
text: null
},
subtitle: {
text: null
},
xAxis: {
categories: ['2013','2014','2015','2016','2017','2018','2019','2020','2021','2022','2023'],
tickmarkPlacement: 'on',
tickWidth: 1,
tickColor: 'black',
tickLength: 6,
title: {
enabled: false
}
},
yAxis: {
title: {
text: '$ in millions (nominal)',
rotation: -89.9
},
min: -2000,
max: 10000,
tickInterval: 2000,
labels: {
formatter: function () {
return '$' + Highcharts.numberFormat(this.value, 0, '.', ',');
}
}
},
legend: {
reversed: false,
align: 'right',
layout: 'vertical',
symbolRadius:0
},
tooltip: {
formatter: function () {
return (
this.key + '' +
'\u25CF ' +
this.series.name + '' +
'$' + Highcharts.numberFormat(this.y, 2, '.', ',') + ' million'
);
}
},
plotOptions: {
column: {
stacking: 'normal',
borderWidth: 0,
borderRadius: 0,
minPointLength: 1,
},
},
series: [{
name: 'Rents',
color: '#372E55',
data: [41.08, 36.60, 31.00, 21.54, 20.73, 19.12, 21.88, 22.97, 23.99, 21.64, 15.20],
index: 2,
zIndex: 2
}, {
name: 'Bonuses',
color: '#6CC8BD',
data: [189.01, 161.56, 112.67, 123.29, 320.53, 271.26, 1181.24, 92.92, 65.32, 12.81, 96.73]
}, {
name: 'Other Revenues',
color: '#E38E63',
data: [72.82, 86.73, -8.00, 8.53, 79.77, 104.79, 51.03, 76.30, 253.73, 470.22, 15.00]
}, {
name: 'Royalties',
color: '#226BB5',
data: [2753.00, 3075.29, 2338.91, 1446.47, 1824.19, 2363.16, 2931.17, 2271.31, 3732.94, 8137.44, 8369.95]
}]
//#### END container ####//
};
new Highcharts.Chart("IAG-3062662095", options);
}
}
});
</script>
Sources: Department of the Interior (DOI), Office of Natural Resources Revenue (ONRR), https://revenuedata.doi.gov/query-data/, Data Type "Revenue," Period "Fiscal Year," Land Type "Federal Onshore," State/Offshore Region "All," Commodity "Gas, Natural gas liquids, Oil, Oil & gas (pre-production)"; and DOI, Budget Justifications, Bureau of Land Management (BLM), in "Collections," Table BLM Collections, Application for Permit to Drill (APD) Processing Fees. Congressional offices may contact the author with inquiries.
Notes: In FY2015, Other Revenues were -$8.00 million (viewable in the interactive version of this figure). All APD fees are added to the ONRR category "Other Revenues." Bonuses (also known as bonus bids or bids) are the payments applicants offer to purchase the lease of public lands. Rents are payments made by lessees before production occurs. Royalties are required payments made by lessees to the federal government based on the value of the public resource involved. The category "Other Revenues," as reported by ONRR, captures other revenues, including those from settlement agreements and interest payments. Values exclude revenues from tribal lands. The amounts reflect 100% of APD fees collected by BLM (including the 15% that was subject to appropriation in FY2016-FY2019). See Appendix for a table of figure values.
Revenue Allocation Under the Mineral Leasing Act
The MLA requires collected revenues to be disbursed in certain ways. For oil and natural gas leases on federal lands,46 in states other than Alaska, 50% of bonuses, production royalties, and other revenues (e.g., settlements, interest) are Alaska, 50% of bonuses, production royalties, and other revenues (e.g., settlements, interest) are
to be disbursed to the state in which the lease is located,to be disbursed to the state in which the lease is located,
4647 and 40% are to be deposited in the and 40% are to be deposited in the
Reclamation Fund.Reclamation Fund.
47 After these disbursements, any of these funds remaining48 The 10% of revenues remaining after these disbursements are to be credited to are to be credited to
the General Fund (i.e., miscellaneous receipts) of the Treasury.the General Fund (i.e., miscellaneous receipts) of the Treasury.
4849 For rental revenues from oil and For rental revenues from oil and
natural gas leases, 50% of the rental natural gas leases, 50% of the rental
revenue isrevenues are to be disbursed to the state in which the to be disbursed to the state in which the
revenue occurredrevenues occurred, and the remaining 50% and the remaining 50%
isare to be deposited in the BLM Permit Processing Improvement to be deposited in the BLM Permit Processing Improvement
Fund (PPIF).Fund (PPIF).
4950 For leases in Alaska, 90% of revenues, including rental revenues, are to be For leases in Alaska, 90% of revenues, including rental revenues, are to be
disbursed to the state, with the remainder credited to the Treasury as miscellaneous receipts. All disbursed to the state, with the remainder credited to the Treasury as miscellaneous receipts. All
disbursements to states resulting from oil and natural gas leases are to be reduced by the disbursements to states resulting from oil and natural gas leases are to be reduced by the
applicable sequestration rate for the given fiscal year.applicable sequestration rate for the given fiscal year.
50 For all states, 2%51 Two percent of funds disbursed to of funds disbursed to
states states from bonuses, production royalties, and other revenues (and, for Alaska only, rental fees, in addition to bonuses, production royalties, and other revenues) are withheld as an administrative fee and deposited as miscellaneous receipts in the are withheld as an administrative fee and deposited as miscellaneous receipts in the
Treasury.Treasury.
5152 New onshore oil and natural gas leases on federal lands New onshore oil and natural gas leases on federal lands
also areare also subject to a permit subject to a permit
processing fee, to be submitted with the application for a permit to drillprocessing fee, to be submitted with the application for a permit to drill
, that is required for each well. required for each well.
52 53 These revenues are deposited in the PPIF, with 75% of the These revenues are deposited in the PPIF, with 75% of the
revenue being returned torevenues being transferred the state the state
BLM office that collected the fees.
Entry and Exit Requirements
The MLA defines the maximum lease acreage permitted to be held by any one entity in any one state to be 246,080 acres, in all states other than Alaska (600,000 acres are allowed in Alaska).53 The maximum area for each oil and natural gas lease is 2,560 acres in any state other than Alaska (5,760 acres are allowed per lease in Alaska).54 The minimum bid per acre of federal land included in an oil and natural gas lease is $2.55 Rent is to be paid on the leased land during the period before oil and natural gas production begins; the minimum rental rates are $1.50 per acre
44 This provision also applies to rents (30 U.S.C. §209). 45 These statutory allocations apply to all leasable minerals, including oil and natural gas. 46 In using the disbursements, states other than Alaska are to give “priority to those subdivisions of the State socially or economically impacted by development of minerals leased under this chapter, for (i) planning, (ii) construction and maintenance of public facilities, and (iii) provision of public service” (30 U.S.C. §191(a)). No provisions on prioritization are given for Alaska.
47 The Reclamation Fund was established in 1902 to develop and maintain irrigation systems in a number of western states (43 U.S.C. §391); see CRS Report R41844, The Reclamation Fund: A Primer, by Charles V. Stern.
48 30 U.S.C. §191(a). 49 The BLM Permit Processing Improvement Fund is to be used “for the coordination and processing of oil and gas use authorizations on onshore Federal and Indian trust mineral estate land”; see 30 U.S.C. §191(c).
50 For discussion of sequestration of mandatory spending, including mineral leasing revenues, see CRS Report R45941, The Annual Sequester of Mandatory Spending through FY2029, by Charles S. Konigsberg.
51 30 U.S.C. §191(b). 52 30 U.S.C. §191(d). See BLM Instruction Memorandum IM 2019-044 for the current fiscal year fee, available at https://www.blm.gov/policy/im-2019-044. The fee, indexed to inflation, is $10,230 for FY2020.
53 30 U.S.C. §184(d)(1). 54 30 U.S.C. §226(b). 55 30 U.S.C. §226(b)(1)(B).
Congressional Research Service
10
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
during the first five years and $2 per acre thereafter.56 Competitive bidding is to occur at least once per quarter, if parcels are available.57 Individual leases may include lease-specific stipulations.58 An operator must post a reclamation bond before surface-disturbing activities can begin on a given lease, among other requirements.59 If all owed rentals and royalties have been paid, mineral lease owners can relinquish a lease at any time, subject to the termination obligations of the lease (e.g., perform site reclamation before the lease bond is released).60
Description of the Leasing Process
FLPMA requires that BLM obtain fair market value for the use of public lands and disposition of its resources. Under the MLA, BLM employs a competitive leasing process to issue leases to extract oil and natural gas from federal lands. BLM also has authority to issue non-competitive leases.
The competitive leasing process begins with the identification of federal lands to be included in a lease sale.61 Federal land parcels can be nominated for inclusion in a lease sale by the public, or BLM can select the parcels to include in a lease sale. These lands must be deemed suitable for oil and natural gas development, as determined by the BLM land use planning process mandated by FLPMA, and subject to requirements under the National Environmental Policy Act (NEPA), the Endangered Species Act (ESA), and the National Historic Preservation Act (NHPA). Federal lease sales are required to occur quarterly if parcels are available, and leases are issued for an initial term of 10 years.
After notifying the public of an upcoming lease sale, BLM may issue a List of Lands Available for Competitive Nominations, and qualified bidders62 may nominate available parcels. Submitting a nomination requires payment of the minimum acceptable bid of $2 per acre, the first year’s rent, and required fees; a nomination is binding and the funds will be returned if the lease is awarded to another bidder.63 If the bidder is successful, these payments are retained and applied to the costs of the lease.
Alternatively, anyone can submit an expression of interest, which is an informal nomination of a parcel to be included in a future lease sale. An expression of interest is non-binding and requires no deposit or fee. After reviewing an expression of interest for conformity to the land use planning process, BLM may include such parcels in a future lease sale.
A Notice of Competitive Lease Sale is posted for at least 45 days before the lease sale is held. A competitive lease sale is conducted by oral or internet auction. The lease is awarded to the qualified bid offering the highest bonus payment.64 If a parcel was nominated by two or more
56 30 U.S.C. §226(d). 57 30 U.S.C. §226(b). Federal leases not awarded through the competitive leasing process are made available for non-competitive leasing for a period of two years (30 U.S.C. §226(c)). Non-competitive leases are awarded to the first received qualified applicant; no bonus payment is required. Non-competitive leasing regulations are found at 43 C.F.R. §§3110 et seq.
58 43 C.F.R. §3101.1-3. 59 30 U.S.C. §226(g). 60 30 U.S.C. §187(b). 61 43 C.F.R. Subpart 3120. 62 43 C.F.R. Subpart 3102. 63 43 C.F.R. §3120.3-2. 64 43 C.F.R. §§3120.4-3120.5.
Congressional Research Service
11
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
bidders, but no bids were received above the required minimum, the parcel can be offered competitively in the future. If no qualified bid is offered during a lease sale for a parcel included by BLM, including through an expression of interest, BLM offers that parcel for non-competitive leasing.65 Non-competitive leasing allows such parcels to be offered for lease for a period of two years to the first qualified applicant; no minimum bid payment is required.
After the lease has been awarded and the lessee has agreed to the terms and stipulations of the lease, the lessee must pay the bonus bid (if obtained through competitive leasing), first year’s rent on the lease, and other filing fees (for nominated parcels, some of these fees were submitted with the nomination application). Minimum rents on leases are $1.50 per acre for the first five years, and $2.00 per acre thereafter.66 The lessee must post a bond in an amount determined by BLM, to be released after production activities on the lease have stopped and the surface has been reclaimed to the satisfaction of BLM.67
Before drilling can begin, the operator must submit a completed Application for Permit to Drill (APD),68 including an application fee, for each well.69 Before production can begin, the operator must submit an acceptable plan of operations and receive approval from BLM.70
Federal Revenues and Disbursements
DOI’s Office of Natural Resources Revenue (ONRR) collects and disburses most of the federal revenue from onshore and offshore energy and mineral development. ONRR maintains data on energy and mineral production, revenues, and disbursements originating from leases on federal lands and waters. Some fees related to oil and natural gas leases on federal lands are paid to the responsible agency (e.g., BLM, FS), rather than to ONRR.
The next two sections describe and discuss the revenue and disbursements from oil and natural gas developments on onshore federal lands.
Federal Revenues
As maintained by ONRR, data on revenues collected from oil and natural gas development are categorized as Bonus, Rents, Royalties, and Other Revenues.71 Bonus, Rents, and Royalties indicate revenues from different stages of a given lease. The Bonus is the payment associated with the winning bid in a competitive lease sale, equal to or exceeding the required minimum of $2 per acre. Rents are collected from the lessee during the period between award of the lease and the start of production on the lease. Royalties are collected during production on the lease, at a minimum rate of 12.5% of the value of production. The category Other Revenues, as reported by ONRR, captures other revenues, including those from settlement agreements and interest payments.72 Companies have seven years to adjust their production data and amounts owed,
65 43 C.F.R. Subpart 3110. 66 43 C.F.R. Subpart 3103. 67 43 C.F.R. Subpart 3104. 68 43 C.F.R. Subpart 3162. 69 BLM, “Instruction Memorandum IM 2019-044,” https://www.blm.gov/policy/im-2019-044. This value is $10,230 for FY2020 and is indexed to inflation (30 U.S.C. §191(d)(2)).
70 43 C.F.R. Subpart 3170. 71 ONRR, “Revenue by Month,” https://revenuedata.doi.gov/downloads/revenue-by-month/. 72 CRS adds fees collected by BLM for APD to this category. The data for APD do not indicate if the lease is on public
Congressional Research Service
12
link to page 17 link to page 17 Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
which can result in negative values in some cases.73 Revenue data do not indicate whether the lease is on public domain land or acquired land.
In FY2019, leasable minerals and geothermal resources resulted in total collections of $4.882 billion from onshore federal lands.74 Of these collections, $4.202 billion were from oil and natural gas resources, which are commonly coproduced on federal lands.75 Total oil and natural gas collections represent the sum of royalties (the majority of collections), $2.931 billion; bonuses, $1.181 billion;76 other revenue, $67 million; and rents, $22 million.
Approximately 86% of federal onshore energy and mineral revenues come from oil and gas leasing. As royalties represent the largest share of revenues, changes in oil prices have been among the major factors in revenue fluctuations from year to year; some other factors affecting revenues include changes in production and bonuses paid for leases. Royalty rates are set by statute, regulation, or for specific leases, but the rates are rarely altered once a lease has been issued.
Figure 5 shows the revenues collected from oil and natural gas developments on federal lands by revenue category, from 2010 through 2019. As royalties are partially determined by commodity prices, the reduction in royalties starting in 2015 partially reflects a 52% fall in the price of crude oil from 2014 to 2015.77 The Bonuses series reflects an unusually large monthly collection of $976 million for October 2018, resulting from a lease sale in New Mexico.78 Figure 6 shows revenues from oil and natural gas developments on Native American lands by revenue category, from 2010 through 2019. This figure is included to allow comparisons between revenues from oil and natural gas developments on federal lands and Native American lands.
domain land or other land type; values exclude APD on Indian lands, and are available at https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/oil-and-gas-statistics.
73 For example, ONRR would indicate a negative royalty value for a given month if an operator had previously overpaid royalties and files an adjustment that results in an amount owed to the operator greater than the royalties due during that month.
74 Not including revenues from production on Native American lands. For more information on the treatment of revenues from Native American lands, see ONRR, “Revenue from Natural Resources on Native American Land,” at https://revenuedata.doi.gov/how-it-works/native-american-revenue/. Includes $32 million in fees collected by BLM for processing Applications for Permit to Drill (CRS calculations using BLM data).
75 Values include the ONRR categories of “Oil,” “Gas,” “Oil & Gas,” and “Natural Gas Liquids,” and APD fees collected by BLM.
76 The Bonuses series reflects an unusually large monthly collection of $976 million for October 2018. This value falls in calendar year 2018 and fiscal year 2019 (ONRR, “Revenue by Month,” https://revenuedata.doi.gov/downloads/revenue-by-month/).
77 Calculated by CRS using annual data for WTI-Cushing, Oklahoma (EIA, “Petroleum and Other Liquids, Spot Prices,” https://www.eia.gov/dnav/pet/pet_pri_spt_s1_a.htm). 78 ONRR, “Revenue by Month,” https://revenuedata.doi.gov/downloads/revenue-by-month/, and BLM, “Table 15 Competitive Oil and Gas Lease Sales by BLM State Offices,” https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/oil-and-gas-statistics.
Congressional Research Service
13
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Figure 5. Federal Oil and Natural Gas Revenues from Onshore Federal Lands
Source: ONRR, “Revenue by Year,” https://revenuedata.doi.gov/downloads/revenue/, and CRS calculations using BLM data for APD. Notes: All APD fees are added to the ONRR category “Other Revenues.” Excludes revenue from Native American lands.
Figure 6. Federal Oil and Natural Gas Revenues from Native American Lands
Source: ONRR, “Revenue by Year,” https://revenuedata.doi.gov/downloads/revenue/. Notes: Excludes revenue from non-Native American lands and APD fees. Rents and Bonuses are generally not visible on this graph.
Congressional Research Service
14
link to page 26 link to page 19 Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Disbursements
In FY2019, leasable minerals and geothermal resources from onshore federal lands resulted in total disbursements of $4.777 billion.79 Of these disbursements, $4.196 billion were from oil and natural gas leases, which included payments of $2.002 billion to states; $1.539 billion to the Reclamation Fund; $39 million to the PPIF; $172 million to other accounts; and $444 million to the Treasury General Fund.80 While not reflected in these values, all disbursements to states from leasable minerals are reduced by the applicable sequestration rate for the given fiscal year.81
Differences between collections and disbursements for any given period can be a result of timing differences, as a disbursement generally occurs in the month following its receipt, or it may be delayed for other reasons, including disputed values, challenged amounts, or adjustments.82 Disbursements are allocated according to the applicable statute (MLA, MLAAL, or other).
ONRR provides access to disbursement data by fiscal year, starting in 2003, and by month, starting in October 2018. The fiscal year data is relatively aggregated, indicating payments to individual states, major programs, and Treasury; payment by commodity type is not included. The monthly data indicate payments to individual states, programs (more disaggregated than the fiscal year dataset), and Treasury, by commodity type and disbursement category, where applicable.
Using provisions in the MLA and publicly available revenue data from ONRR, disbursements can be estimated. The Appendix provides details regarding the creation of estimated disbursements. Figure 7 shows the estimated disbursements by major account for FY2010 through FY2019. As royalties represent the largest source of funds disbursed to states and the Reclamation Fund, the estimated disbursements to these accounts fluctuate primarily according to royalty revenues. Disbursements to states also reflect revenues from bonuses and rents; disbursements to the Reclamation Fund also reflect revenues from bonuses. Disbursements to PPIF reflect revenues from rents paid on leases in states other than Alaska and APD fees collected by BLM in all states.
79 Not including disbursements to Native American tribes or accounts. This value is before sequestration of mandatory spending, as sequestration amounts (which vary by year) are not attributable to a given commodity in the ONRR data. All APD fees are included as disbursements. Disbursements to states are after deduction of the 2% administration fee; Treasury values include the administrative fee.
80 CRS calculations using disbursement data from ONRR, “Downloads / Disbursements by Month,” at https://revenuedata.doi.gov/downloads/disbursements-by-month/, and CRS calculations of APD fees using BLM data.
81 For discussion of sequestration of mandatory spending, including mineral leasing revenues, see CRS Report R45941, The Annual Sequester of Mandatory Spending through FY2029, by Charles S. Konigsberg.
82 Leasable minerals and geothermal resource disbursements are required to be made before the end of the month occurring 10 days after the revenues were received by the Treasury, see 30 U.S.C. §191(a).
Congressional Research Service
15
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Figure 7. Estimated Disbursements of Oil and Natural Gas Revenues from Federal
Lands
Source: CRS calculations using ONRR data, provisions from the MLA (30 U.S.C. §191), and BLM data. Notes: The estimation applies the MLA to all revenues, as available data do not identify revenues from acquired lands. This methodology al ocates all revenues from leases according to provisions in the MLA; see the Appendix for details. Years are fiscal years. PPIF is the Permit Processing Improvement Fund.
Policy Topics and Legislative Activity
Numerous bills have been introduced in the 116th Congress that could impact revenues and disbursements from oil and natural gas developments on federal lands. This section discusses selected bills and policy options related to these revenues and disbursements. The section focuses on bills that would have direct impact on revenues and disbursements. It does not consider bills that would indirectly impact revenues and disbursements through broader changes to the oil and natural gas sector (e.g., bills related to greenhouse gas emissions that could reduce demand for domestic oil and natural gas).
Royalties
Royalties constitute the largest source of federal government revenue collected from oil and natural gas leases, and consequently, they form the largest source of funds to be disbursed. Royalty collections averaged 87% of total oil and natural gas revenues from leases on federal lands between 2010 and 2019.83 In the absence of major changes in the oil and natural gas markets, changing the royalty rate is the most direct means of changing the amount of revenue collected from oil and natural gas leases. In the absence of changes to revenue allocation, changing the royalty rate would also be the most direct means of changing the amount of disbursements.
Oil and natural gas market conditions can affect royalty revenues, as higher (or lower) market prices result in higher (or lower) royalties paid for a given quantity of production. If market prices attain or are expected to attain certain levels, high or low, some operators may choose to alter
83 CRS calculations using ONRR revenue data and BLM data for APD fees.
Congressional Research Service
16
link to page 24 Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
their production. For example, if oil prices fall below a certain level, an operator may choose to terminate production at a given well, resulting in zero royalties collected from the well.
Some bills have been introduced in the 116th Congress that would alter the minimum royalty rate assessed on new oil and natural gas leases.84 The current royalty rate, 12.5%, was established in 1920.85 Changing the royalty rate for new leases would not be expected to affect an operator’s production from producing wells, but it could influence interest in future leases and impact bonus payments received during lease sales.
Expected changes to the leasing process and future revenues resulting from a change in the minimum royalty rate can be hard to predict. Some studies find that increases to the royalty rate would not have significant impacts on oil and natural gas production on federal lands.86 As an increase in the royalty rate can be viewed as an increase in costs to the operator, operations that would be marginally profitable under the current royalty rate may no longer be profitable under a higher royalty rate. This could reduce the number of new leases, but the increase in the royalty rate would be expected to result in greater collections for the affected leases once production begins. In a similar manner, a reduction in the royalty rate for new leases could increase the number of new leases, with each lease paying a lower rate on production.
Prior to changing the minimum royalty rate or in conjunction with such a change, Congress could require updated studies to inform the decision or ongoing studies to analyze the change over time. Such studies could attempt to identify the underlying causes driving changes in collections, taking into account changes in the oil and natural gas markets. The results of such studies could allow Congress to understand better the impacts of a change to the minimum royalty rate on the outcome of the leasing process and future royalty collection.
Some bills have been introduced in the 116th Congress that would change authorities related to royalties, including provisions addressing royalty relief and provisions changing how natural gas losses are treated. DOI has the authority to suspend, waive, or reduce royalty rates on federal onshore oil and natural gas leases “for the purpose of encouraging the greatest ultimate recovery ... whenever [the Secretary of the Interior judges] it is necessary to do so in order to promote development, or whenever in his judgment the leases cannot be successfully operated under the terms provided therein.”87 The existing authority may be useful for leases facing specific issues that risk the economic viability of the well. Some bills would repeal this authority.88
Some bills would require that all produced natural gas be assessed royalties, even if flared or vented. Existing provisions and regulations allow natural gas to be vented and flared without being assessed royalties. While closely related to the topic of royalties, this topic is discussed separately in “Natural Gas Losses.”
84 Example bills include H.R. 3225, H.R. 4364, H.R. 5435, and S. 3330. 85 41 Stat. 437. 86 The Government Accountability Office (GAO) published a report highlighting the findings from two studies that analyzed the impacts of possible changes to oil and natural gas royalty rates (GAO, Oil, Gas, and Coal Royalties, GAO-17-540, 2017). The report highlights many of the factors affecting the impacts of a change to the royalty rate, including royalty rates assessed by states, oil and natural gas prices, and other market conditions. The report also notes that the impacts are assumed to occur over a 25-year period, as new leases can require nearly 10 years before reaching production.
87 30 U.S.C. §209. 88 Example bills include H.R. 6289, H.R. 6707, and S. 3488.
Congressional Research Service
17
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Revenue Allocation
The revenues from oil and natural gas leases collected under the current statutory framework are allocated to the Treasury, federal programs, and states; state disbursements are assessed an administrative fee and are subject to sequestration. Congress could choose to alter the current allocation scheme to reflect different priorities.
Some examples of different allocation schemes for energy and mineral revenues include
In 1976, Congress amended the allocation of funds to states and the Reclamation
fund, allocating an additional 12.5% to states while reducing the Reclamation fund by an equal amount.89
The PPIF was created in 2005, receiving all of its funding from rents.90 In 2014, a
fee was established and allocated to the PPIF.91 A minimum of 75% of these fees are to be returned to the BLM office that received the fee.
The Geothermal Steam Act of 1970, which competitively leases geothermal
resources on federal lands, allocates 25% of revenues to the county in which the resource is located and does not allocate any funds to the Reclamation Fund.92
The MLA provision that assesses an administrative fee on disbursements to states has been amended multiple times.93 Some bills introduced in the 116th Congress would eliminate the 2% administrative fee assessed on disbursements to states.94 In addition to eliminating this fee, these bills contain provisions that would give the authorized state a greater role in managing oil and natural gas leases on federal lands. Two of these bills would allow the authorized state to issue Applications for Permit to Drill (APD) on federal lands, eliminating the associated revenue collected by BLM when an APD is submitted (authorized states would be allowed to charge an equivalent or lower fee). Allowing states to authorize drilling on federal lands could reduce the time between APD submission and production, resulting in earlier collections of royalties. It is not clear if and how an authorized state would conduct oversight of production and reclamation, ensuring adherence to applicable provisions of federal law.
A recently enacted law, the Great American Outdoors Act, is an example of amending the current allocation scheme.95 Provisions in this law allocate, for FY2021-FY2025, 50% of miscellaneous receipts from all energy development revenues to the National Parks and Public Land Legacy Restoration Fund, created by the act, up to a maximum of $1.9 billion per fiscal year. Aside from reducing the revenues remaining in the General Fund, this act does not alter other aspects of the current allocation scheme.
89 P.L. 94-377. 90 P.L. 109-58. 91 P.L. 113-291, §3021(b). 92 30 U.S.C. §§1001 et seq. 93 See “Amendments,” 30 U.S.C. §191. 94 Examples of bills include H.R. 998, H.R. 4294, S. 218, and S. 2418. 95 P.L. 116-152.
Congressional Research Service
18
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
The Leasing Process and Fair Market Value
FLPMA requires that BLM obtain fair market value for the use of public lands and disposition of its resources. Congress has debated whether the current leasing process (competitive and non-competitive) results in receipt of fair market value for federal oil and natural gas resources.
Pursuant to the MLA, BLM generally employs a competitive bidding process to issue leases to extract oil and natural gas from federal lands.96 BLM’s competitive bidding process can be described as an oral auction for common-value goods. A common-value good is a good that offers the same value to all bidders in the auction, but that value is not fully known to the bidders. Each parcel contained in a lease sale represents a common-value good, as geologic variations within a basin prevent the actual value of the oil and natural gas from being known before it is extracted.
Economic theory posits that the outcome of a competitive exchange is one manner of achieving economic efficiency.97 If the results of a lease sale are competitive economically, they could be deemed to represent the fair market value of the assets. However, market failures, including incomplete information, asymmetric information, and market power, can lead to outcomes that would not be equal to fair market value. A repeated auction for similar goods, where similar goods are available outside the auction, can result in strategic behavior by the bidders. Strategic behavior reduces the economic efficiency of the auction outcome.
Strategic behavior, which could be based on observed results of previous auctions, could result in BLM collecting less than fair market value for oil and natural gas leases. A given lease sale represents the momentary intersection of supply and demand for oil and natural gas leases. If the supply of leases exceeds the demand for leases, the price received (i.e., the winning bid, equal to or above the required minimum) is expected to be lower than if the supply of leases had been fewer. If the supply of leases were limited (therefore increasing demand for each lease), bidders would be expected to make offers only up to the point where they would expect to be able to profitably develop the lease; they would not bid above their expected value of the lease.
In FY2018, 24% of new onshore oil and natural gas leases were issued through non-competitive offers; for FY2019, 10% of such leases were issued through non-competitive offers.98 Using BLM data for competitive lease sales in FY2018 (the record-breaking year for bonus bids and the only year of data provided), the average bonus paid per acre was about $849.99 This average bonus is heavily skewed by the October lease sale in New Mexico: excluding that lease sale, the average bonus paid was about $135 per acre. Of the 28 lease sales held in FY2018, one sale did not receive any bids, and 18 sales received average bonuses of less than $40 per acre.100 The highest average bonus per acre for an individual lease sale was over $19,000. Of the 3,073 parcels
96 Approximately 90% of oil and natural gas leases were issued by competitive bidding in FY2019 (BLM, Public Land
Statistics 2019, 2020, Tables 3-13 and 3-14, pp. 91-99).
97 Economic efficiency and fair market value can be considered equivalent. One definition of fair market value, given for coal, is “that amount in cash, or on terms reasonably equivalent to cash, for which in all probability the coal deposit would be sold or leased by a knowledgeable owner willing but not obligated to sell or lease to a knowledgeable purchaser who desires but is not obligated to buy or lease” (43 C.F.R. §3400.0-5).
98 BLM, Public Land Statistics 2018, 2019, Tables 3-13 and 3-14, pp. 96-104 and BLM, Public Land Statistics 2019, 2020, Tables 3-13 and 3-14, pp. 91-99.
99 CRS calculations using data from BLM, “Table 15 Competitive Oil and Gas Lease Sales by BLM State Offices,” https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/oil-and-gas-statistics.
100 A report by the GAO states “According to Interior officials, most competitive bids for oil and gas are higher than the required minimum. For example, in fiscal year 2015, the average bonus bid per acre for all the acres leased (both competitive and noncompetitive leases) was $139, and for fiscal year 2016, the average bonus bid per acre was $213” (GAO, Oil, Gas, and Coal Royalties, GAO-17-540, 2017, p. 5).
Congressional Research Service
19
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
available for bids in FY2018, 1,336 parcels were leased (the 1,737 parcels not receiving bids will be offered for non-competitive leasing).
Economic and auction theory cannot definitively determine if the outcome of a given lease sale obtains fair market value. Each parcel in a lease sale is unique, and each bidder has private information affecting bidding behavior. Some may view the outcomes of the FY2018 lease auctions as obtaining fair market value. The variation in bids could be taken as an indication that the market for leases was efficient, with some parcels being more desirable than others. Others might argue that if some parcels can result in average bids of $19,000 per acre while other parcels receive no bids, the supply of leases is too high and fair market value is not obtained.
Aspects of the current leasing system could be changed to address the expected receipt of fair market value; some of these aspects include:
Leases Offered. The number of leases offered during any given lease sale could
be reduced, with the expectation of receiving higher bids for each lease; reduction beyond a certain level could curtail oil and natural gas production on federal land. The number of leases offered could be increased, with the expectation that buyers will purchase all desirable leases, resulting in increased revenue.
Lease Sale Frequency. Assuming the number of parcels available during a lease
sale is constant, reducing the frequency of lease sales would reduce the supply of leases, and could increase the value of each lease. Holding lease sales more frequently could allow interested bidders to obtain leases more quickly.
Minimum Bid. The current minimum bid of $2 per acre, amended to this value in
1987,101 could be increased, guaranteeing a higher minimum bid. An increase in the cost to obtain the lease may deter some or all bidders from bidding, potentially reducing the number of leases sold.
Rental Payments. Increasing the rental rate, currently $1.50 per acre for the first
five years, could deter bidders from holding leases for extended periods of time before developing the lease. Such behavior can be considered a form of speculation, as expected returns from the lease can change over time; additionally, such behavior can prevent others from developing the lease. Reducing rental payments could reduce financial burdens on operators facing high costs to develop a lease.
Some bills introduced in the 116th Congress would modify aspects of the current leasing process.
Provisions in S. 3330 would increase the minimum bid to $10 per acre, increase rental rates to $3 per acre for the first five years and $5 per acre thereafter, and require the payment of $15 per acre for lands included in the submission of an expression of interest. Provisions in S. 3202 would reduce the supply of parcels in a lease sale by requiring included parcels be rated above “low,” as indicated by a BLM assessment of the potential for oil and natural gas development. Provisions in S. 4223 would eliminate the option for non-competitive leasing; leases not sold competitively could be reoffered competitively at a later time.
Provisions in two bills would temporarily suspend lease sales for oil and natural gas. H.R. 5435 would suspend lease sales until USGS concludes that public lands have achieved a greenhouse gas emissions target set in the bill for the previous year. H.R. 6707 would suspend lease sales during the COVID-19 national emergency declaration. Provisions in H.R. 5435 would implement
101 P.L. 100-203, §5102(a).
Congressional Research Service
20
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
an additional fee on new leases during the period before production begins and an additional fee on new leases during production.
Natural Gas Losses
Most oil and natural gas wells in the United States, including wells on federal lands, produce some amount of natural gas. The production of natural gas requires specific safety and environmental precautions, as releases, or losses, of natural gas can pose safety and environmental hazards. These losses may contain pollutants, including, most prominently, methane (i.e., the principal component of natural gas), volatile organic compounds, and various forms of hazardous air pollutants, among others. To assist in managing these losses, the production of natural gas requires specific safety and environmental precautions, as releases of natural gas can pose safety and environmental hazards.102
According to the Environmental Protection Agency (EPA), natural gas emissions
occur through intentional venting and unintentional leaks. Venting can occur through equipment design or operational practices, such as the continuous bleed of gas from pneumatic devices (that control gas flows, levels, temperatures, and pressures in the equipment), or venting from well completions during production. In addition to vented emissions, methane losses can occur from leaks (also referred to as fugitive emissions) in all parts of the infrastructure, from connections between pipes and vessels, to valves and equipment. Methane emissions can also occur from the oil industry as result of ... venting of associated gas from oil wells and storage tanks [and] production-related equipment.103
Natural gas production may result in momentary, periodic, or continual releases of natural gas; flaring is one process that can mitigate some risks of these releases. Flaring converts waste gas and the pollutants it may contain into comparatively less polluting products, typically carbon dioxide, nitrogen oxides, less volatile hydrocarbons, and water vapor.104
Current provisions and regulations allow some quantities of natural gas to be vented, flared, and consumed during production; royalties are not assessed on these quantities.105 Royalties, which are not assessed on production losses that are deemed acceptable or necessary, are to be assessed on production losses due to negligence.106 Any production losses represent forgone revenue for the operator and reduced federal collections.
Congress has debated changes to current authorities and provisions regarding natural gas emissions. Congress could direct BLM to change the accepted uses, resulting in corresponding changes to operating costs and royalty collection. For example, BLM currently may allow oil well operators to flare up to 10 million cubic feet of associated nature gas per well per month without
102 For background and discussion of environmental impacts of natural gas emissions, see CRS Report R42986, Methane and Other Air Pollution Issues in Natural Gas Systems, by Richard K. Lattanzio.
103 EPA, “Primary Sources of Methane Emissions,” available at https://www.epa.gov/natural-gas-star-program/primary-sources-methane-emissions.
104 John L. Sorrels, Section 3.2—VOC Destruction Controls, Chapter 1 Flares, EPA, Air Pollution Control Cost Manual, August 2019, https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
105 For authorized venting and flaring for natural gas wells, see 43 C.F.R. §§3179.101-3179.104. For authorized venting and flaring for oil wells, see 43 C.F.R. §3179.201. For acceptable uses of natural gas for production activities, see 43 C.F.R. §3178.4.
106 30 U.S.C. §1756.
Congressional Research Service
21
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
assessing royalties on this natural gas.107 Congress could require operators to reduce production losses, which could increase revenues and royalty collection. Reducing production losses typically represents upfront costs (or retrofit costs) to operators.108 Given the high initial capital costs of developing a well, an operator may choose to avoid these costs, even if additional capital costs could lead to greater revenue over time.
Some bills introduced in the 116th Congress would require that some or all of currently flared or vented natural gas be assessed royalties.109 This could be achieved by measuring the quantity of natural gas consumed in venting or flaring, and assessing royalties accordingly. An operator choosing not to capture such natural gas would pay the assessed royalty without receiving the associated revenue. H.R. 2711 would encourage capture and sale of natural gas that would otherwise be vented or flared by prohibiting venting and flaring, with civil penalties charged to violators.
107 43 C.F.R. §3179.201. 108 EPA, “Recommended Technologies to Reduce Methane Emissions,” https://www.epa.gov/natural-gas-star-program/recommended-technologies-reduce-methane-emissions.
109 Examples of bills include H.R. 2711, H.R. 4364, and S. 2818.
Congressional Research Service
22
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Appendix. Methodology to Create the Estimated
Disbursements Dataset
Prior to FY2019, ONRR does not provide access to disbursement data by fiscal year that indicates payments to individual states, all federal programs, and Treasury, by commodity type and disbursement category, where applicable. ONRR provides access to disbursement data at this level of detail by month, starting in October 2018. As trends in detailed disbursement data may be of interest to some readers, a methodology to estimate disbursement data is defined and employed. The resulting estimates are subject to unknown deviations from actual disbursements.
In order to create a dataset of disbursements for FY2010 through FY2019 by major recipient or fund, the disbursement provisions of the MLA can be applied to publicly available data for revenues collected from onshore oil and natural gas developments on federal lands. However, this approach results in a dataset that only estimates disbursements. The resulting dataset includes estimated disbursements to states, the Reclamation Fund, the PPIF, and the amount remaining in Treasury. The application of the MLA to all revenue precludes the application of provisions from the MLAAL and revenue allocations from leases not subject to the MLA. The resulting estimations will differ from actual estimations by the unknown amounts that were not disbursed according to the MLA.
Data allow the accuracy of such estimates to be assessed for FY2019. The accuracy can be assessed by comparing the FY2019 disbursements from the monthly dataset to the estimates produced by application of the MLA to the same fiscal year dataset. Using the monthly dataset, in FY2019, approximately 93% of oil and natural gas revenues from federal lands were disbursed according to the MLA.110 This allocation resulted in 48% of total revenues being disbursed to states, 37% disbursed to the Reclamation Fund, 0.9% disbursed to PPIF, 11% remained in Treasury, and 4% disbursed to other accounts (e.g., FS, FWS). Using the approximation that all revenues are disbursed according to the MLA, the resulting disbursements would be 49% to states, 40% to the Reclamation Fund, 1% to PPIF, and 11% remained in Treasury; this approximation does not allocate funds to other accounts.111 This assessment of accuracy can only be conducted for FY2019; the accuracy of other years may not be the same. This approximation is used to create an estimated disbursements dataset from FY2010 through FY2019.
Author Information
Brandon S. Tracy
Analyst in Energy Policy
110 CRS calculations using ONRR data, BLM data, the MLA provision that the Reclamation Fund receives 40% of bonuses, royalties, and other revenues, and the MLA provisions for Alaska.
111 These percentages sum to more than 100% due to rounding.
Congressional Research Service
23
Revenues and Disbursements from Oil and Natural Gas Production on Federal Lands
Disclaimer
This document was prepared by the Congressional Research Service (CRS). CRS serves as nonpartisan shared staff to congressional committees and Members of Congress. It operates solely at the behest of and under the direction of Congress. Information in a CRS Report should not be relied upon for purposes other than public understanding of information that has been provided by CRS to Members of Congress in connection with CRS’s institutional role. CRS Reports, as a work of the United States Government, are not subject to copyright protection in the United States. Any CRS Report may be reproduced and distributed in its entirety without permission from CRS. However, as a CRS Report may include copyrighted images or material from a third party, you may need to obtain the permission of the copyright holder if you wish to copy or otherwise use copyrighted material.
Congressional Research Service
R46537 · VERSION 1 · NEW
24 BLM office that collected the fees. Figure 5 depicts MLA revenue allocation requirements.
Figure 5. Allocation of Onshore Federal Oil and Gas Revenues Under the Mineral Leasing Act
|
Source: Mineral Leasing Act (30 U.S.C. §191).
Notes: BLM = Bureau of Land Management. Treasury = U.S. Department of the Treasury. Bonuses (also known as bonus bids or bids) are the payments applicants offer to purchase the lease of public lands. Rents are payments made by lessees before production occurs. Production royalties are required payments made by lessees to the federal government based on the value of the public resource involved. Two percent of funds allocated to states from bonuses, production royalties, and other revenues (and, for Alaska only, rental fees, in addition to bonuses, production royalties, and other revenues) are withheld as an administrative fee and deposited as miscellaneous receipts in the Treasury.
|
Disbursements
Disbursements are monetary payments to a recipient. These monetary payments are determined by revenue generated by leasing. This revenue is paid to the federal government and then disbursed to different recipients.
In FY2023, leasable minerals and geothermal resources from onshore federal lands resulted in total disbursements of $9.199 billion.54 Of these disbursements, $7.771 billion was from oil and natural gas leases, according to ONRR. ONRR provides access to disbursement data by fiscal year. The fiscal year data are relatively aggregated, indicating payments to individual states, major programs, and the Treasury; payment by commodity type is not included.
Policy Topics and Legislative Activity
The law commonly known as the Inflation Reduction Act of 2022 (IRA; P.L. 117-169) increased the minimum bid requirements and royalty and rental rates for oil and gas leases issued under the MLA. These provisions, and others, are currently under review under a secretarial order announced on February 3, 2025, directing BLM to review the regulation implementing the IRA.55 Numerous bills have been introduced since the enactment of the IRA that would further amend revenue and disbursement requirements from oil and natural gas developments on federal lands. This section discusses the IRA oil and gas leasing provisions, as well as selected bills and policy options related to these revenues and disbursements. The section focuses on bills that would have direct impact on revenues and disbursements. It does not consider bills that would indirectly impact revenues and disbursements through broader changes to the oil and natural gas sector (e.g., bills related to greenhouse gas emissions that could reduce demand for domestic oil and natural gas, or bills that could incentivize oil and gas production by different methods including, for example, requiring more lease sales).
The Inflation Reduction Act (P.L. 117-169): Changes to Revenues
Among other provisions, the IRA increased the minimum bid requirements, rent, and royalty for onshore oil and gas leases on federal lands. See Table 2 for a summary of changes.
Table 2. Changes to Federal Oil and Gas Leasing Provisions 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; the Secretary can increase the minimum bid after August 16, 2032, to increase financial returns to the United States and to promote more efficient management of federal oil and gas.
|
|
Rent
|
No less than $1.50 per acre for years 1-5 and no less than $2.00 per acre thereafter.
|
No less than $3.00 per acre for years 1-2, no less than $5.00 per acre for years 3-8, no less than $15.00 per acre thereafter.
|
|
Royalty
|
At least 12½% of the value of production from the lease.
Royalties are not assessed on natural gas that is vented or flared.
|
16⅔% of the value of production from the lease for the 10 years beginning on August 16, 2022; no less than 16⅔% thereafter.
Royalties are assessed on natural gas that is vented or flared.
|
Sources: P.L. 117-169; Bid and Royalty—30 U.S.C. §226(b); Rent—30 U.S.C. §226(d); natural gas that is vented or flared—30 U.S.C. §1727.
Notes: Bid (also known as bonus or bonus bid) is the payment 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.
Since the passage of the IRA, bills have been introduced to repeal some or all of the changes the act made to revenue and leasing terms, such as H.R. 526 in the 119th Congress.56 Congress has also considered increasing rates to levels higher than those set by the IRA.57
Royalties and Lease Terms
Royalties constitute the largest source of federal revenues collected from oil and natural gas leases (see Figure 4) and, consequently, they form the largest source of funds to be disbursed. Given the high percentage of federal oil and gas revenues that comes from royalties, changes to the minimum royalty rate represent the most direct means of altering revenues and disbursements from oil and natural gas leases, under normal market conditions. In the absence of changes to revenue allocation, changing the royalty rate may also be the most direct means of changing the amounts of disbursements. Changes to leasing terms, changes to areas available for leasing, and other changes could indirectly affect revenue amounts, depending on how the industry would respond to any changes in these factors.
Oil and natural gas market conditions can affect royalty revenues, as higher (or lower) market prices result in higher (or lower) royalties paid for a given quantity of production. Additionally, if market prices attain or are expected to attain certain levels, high or low, some operators may choose to alter their production. For example, if oil prices fall below a certain level, an operator may choose to terminate production at a given well, resulting in zero royalties collected from the well.
The IRA increased the minimum royalty rate assessed on new oil and natural gas leases to 16⅔%.58 The royalty rate before the change, 12.5%, was established in 1920.59 In the 119th Congress, H.R. 526 would reverse the IRA royalty increase, resetting it to 12.5%.60
Changes to future revenues resulting from a change in the minimum royalty rate can be hard to predict. A change to the royalty rate for new leases would not be expected to affect an operator's production from currently producing wells, because changes in royalty rates typically only affect future leases. Some studies have predicted that raising royalty rates from 12.5% would not have a significant impact on oil and natural gas production on federal lands.61 The net effect on federal revenue would depend largely upon the balance between these two factors: the number of new leases and production volumes under a different royalty requirement and the level of the royalty rate. As an increase in the royalty rate can be viewed as an increase in costs to the operator, operations that are marginally profitable under the current royalty rate may no longer be profitable under a higher royalty rate. This could reduce the number of new leases, but the increase in the royalty rate would be expected to result in higher collections on each lease once production begins. Conversely, a reduction in the royalty rate for new leases could increase the number of new leases, but with lower collections on each lease.
Along with considering proposed changes to the minimum royalty rate, Congress could require BLM to provide updated studies to inform Congress or to conduct ongoing studies to analyze changes over time. Such studies could attempt to identify the underlying causes driving changes in collections, taking into account changes in the oil and natural gas markets. The results of such studies could allow Congress to better understand the potential impacts of a change to the minimum royalty rate on the outcome of the leasing process and future royalty collection.
Other Fiscal Terms
Other fiscal terms that Congress has debated changing include the nominating fee, the minimum bid, and rental payments.
- Nominating fee. Pursuant to the MLA, BLM employs a competitive bidding process to issue leases to extract oil and natural gas from federal lands.62 Parcels are typically nominated for inclusion in competitive lease sales by members of the public via expressions of interest (EOIs), which include a nonrefundable $5.00 per acre nominating fee.63 The Inflation Reduction Act implemented a $5.00 per acre nominating fee for EOIs.64 Increasing the fee could deter members of the public from nominating parcels. Decreasing or eliminating the fee may encourage speculation.
- Minimum bid. The Inflation Reduction Act increased the minimum bid from $2.00 per acre to $5.00 per acre. Comparing FY2021 and FY2023 shows that the percentage of acreage leased changed little in the year before and after the IRA: The percentage remained at about 54%. The current minimum bid could be further increased, resulting in an increase in bid revenues should leasing acreage and bidding remain constant. However, an increase in the cost to obtain the lease may deter some or all bidders from bidding, potentially reducing the number of leases sold.
- Rental payments. Current rental rates are set at $3.00 per acre for years 1-2, no less than $5.00 per acre for years 3-8, and no less than $15.00 per acre thereafter. Increasing rental rates could deter bidders from holding leases for extended periods of time before developing the lease. Holding leases without developing them can be considered a form of speculation, as expected returns from the lease can change over time; additionally, such behavior can prevent others from developing the lease. Reducing rental payments could reduce financial burdens on operators facing high costs to develop a lease.
Some bills introduced since the passage of the Inflation Reduction Act would modify aspects of the current leasing process. In the 119th Congress, H.R. 526 would eliminate the nominating fee and revert the minimum bid and rental rate back to their pre-IRA levels ($2.00 per acre, and no less than $1.50 per acre for years 1-5 and no less than $2.00 per acre thereafter, respectively).65
H.R. 6009, which passed the House in the 118th Congress, would have made other changes to the fiscal terms listed above.66
In the 118th Congress, H.R. 6009, the Restoring American Energy Dominance Act, would have required the withdrawal of the then-proposed Fluid Mineral Leases and Leasing rule.67 For example, the legislation contained provisions that would have reversed many of the changes to onshore federal oil and gas leasing, including lowering minimum bids back to $2.00 per acre, lowering rent, eliminating EOIs, and reinstating noncompetitive leasing.
Revenue Allocation
As discussed above, federal law dictates how the revenues from oil and natural gas leases collected under the current statutory framework are allocated to the Treasury, federal programs, and states; state disbursements are assessed an administrative fee and are subject to sequestration. Congress could maintain the status quo or choose to alter the current allocation scheme to reflect different priorities.
Some examples of changes Congress has made to allocation schemes for energy and mineral revenues are described below.
- In 1976, Congress amended the allocation of funds to states and the Reclamation Fund, allocating an additional 12.5% to states while reducing the Reclamation Fund by an equal amount.68
- Congress created the PPIF in 2005; initially, the PPIF received all of its funding from rents.69 In 2014, a fee was established and allocated to the PPIF.70 A minimum of 75% of PPIF fees are to be transferred to the BLM office that collected the fees.
The MLA provision that requires an administrative fee on disbursements to states has been amended multiple times.71 In the 119th Congress, S. 451 would eliminate the 2% administrative fee assessed on disbursements to states.72 Other approaches considered by previous Congresses include giving authorized states a greater role in managing oil and natural gas leases on federal lands;73 allowing authorized states to issue APDs on federal lands and eliminating the associated revenues collected by BLM when an APD is submitted;74 and allowing authorized states to collect a fee to cover administrative costs.75
Noncompetitive Leasing
Before the Inflation Reduction Act eliminated noncompetitive leasing, federal leases not awarded through the competitive leasing process were made available for noncompetitive leasing for a period of two years. Noncompetitive leases were awarded to the first received qualified application. No bonus payment was required.
The percentage of new onshore oil and gas leases issued through noncompetitive offers declined in the years leading up to the passage of the Inflation Reduction Act. In FY2018, 24% of new onshore oil and natural gas leases were issued through noncompetitive offers; for FY2019, 10%; for FY2020, 7%; and for FY2021, 2%.76
In an analysis of leases awarded in 2003-2019, the Government Accountability Office (GAO) found that leases awarded competitively produced more royalties than noncompetitive leases, thereby producing greater federal revenues through royalties than noncompetitive leases.77 Those greater royalty revenues add to revenues from the bonus to make competitive leases, on average, produce nearly three times greater revenue than noncompetitive leases. That said, leases obtained noncompetitively still generate revenue, including when they are not in producing status.
In the 119th Congress, H.R. 526 would reinstate noncompetitive leasing.78
Natural Gas Losses: Venting and Flaring
Most oil and natural gas wells in the United States, including wells on federal lands, release some amount of natural gas alongside intentional production. Natural gas released from oil wells is called associated gas. The production of natural gas requires specific safety and environmental precautions, because releases—or losses—of natural gas can pose safety and environmental hazards. These losses may contain air pollutants, including, most prominently, methane (i.e., the principal component of natural gas), volatile organic compounds, and various forms of hazardous air pollutants, among others.79
According to the U.S. Environmental Protection Agency (EPA), natural gas emissions
occur through intentional venting and unintentional leaks. Venting can occur through equipment design or operational practices, such as the continuous bleed of gas from pneumatic devices (that control gas flows, levels, temperatures, and pressures in the equipment), or venting from well completions during production. In addition to vented emissions, methane losses can occur from leaks (also referred to as fugitive emissions) in all parts of the infrastructure, from connections between pipes and vessels, to valves and equipment. Methane emissions can also occur from the oil industry as result of ... venting of associated gas from oil wells and storage tanks [and] production-related equipment.80
Natural gas production (from oil or gas wells) may result in momentary, periodic, or continual releases of natural gas; flaring is one process that can mitigate some risks of these releases. Flaring converts waste gas and the pollutants it may contain into safer and comparatively less-polluting products, typically carbon dioxide, nitrogen oxides, less-volatile hydrocarbons, and water vapor.81
The Inflation Reduction Act added new requirements for royalties on most quantities of natural gas that are consumed or lost by venting or flaring during production.82 As a result of this change, any vented or flared natural gas represents both forgone revenues for the operator and additional federal royalties paid.
Congress has debated changes to current authorities and provisions regarding natural gas emissions. In the 118th Congress, H.R. 6009, the Restoring American Energy Dominance Act, would have required the withdrawal of the then-proposed Fluid Mineral Leases and Leasing rule,83 including removing royalties assessed on natural gas that is vented or flared.84
Appendix. Data for Figure 4
Figure 4 shows Federal Oil and Natural Gas Revenues from Onshore Federal Lands from FY2013 to FY2023. Data for the figure is shown in Table 3. Negative values may come from the federal government paying out settlement agreements, repaying overpayments, or other adjustments. For example, Other Revenues for FY2015 were -$8.00 million.
Table 3. Federal Oil and Natural Gas Revenues from Onshore Federal Lands, FY2013-FY2023
($ in millions, nominal)
|
FY
|
Royalties
|
Other Revenues
|
Bonuses
|
Rents
|
|
2013
|
2,753.00
|
72.82
|
189.01
|
41.08
|
|
2014
|
3,075.29
|
86.73
|
161.56
|
36.60
|
|
2015
|
2,338.91
|
-8.00
|
112.67
|
31.00
|
|
2016
|
1,446.47
|
8.53
|
123.29
|
21.54
|
|
2017
|
1,824.19
|
79.77
|
320.53
|
20.73
|
|
2018
|
2,363.16
|
104.79
|
271.26
|
19.12
|
|
2019
|
2,931.17
|
51.03
|
1,181.24
|
21.88
|
|
2020
|
2,271.31
|
76.30
|
92.92
|
22.97
|
|
2021
|
3,732.94
|
253.73
|
65.32
|
23.99
|
|
2022
|
8,137.44
|
470.22
|
12.81
|
21.64
|
|
2023
|
8,369.95
|
15.00
|
96.73
|
15.20
|
Sources: Department of the Interior (DOI), Office of Natural Resources Revenue (ONRR), https://revenuedata.doi.gov/query-data/, Data Type "Revenue," Period "Fiscal Year," Land Type "Federal Onshore," State/Offshore Region "All," Commodity "Gas, Natural gas liquids, Oil, Oil & gas (pre-production)"; and DOI, Budget Justifications, Bureau of Land Management (BLM), in "Collections," Table BLM Collections, Application for Permit to Drill (APD) Processing Fees. Congressional offices may contact the author with inquiries.
Notes: All APD fees are added to the ONRR category "Other Revenues." The category "Other Revenues," as reported by ONRR, captures other revenues, including those from settlement agreements and interest payments. Excludes revenue from tribal lands.
Brandon S. Tracy, former CRS Analyst in Energy Policy, authored the original version of this report. Mari Lee, Visual Information Specialist, prepared the graphics for the report.
Footnotes
| 1.
|
Oil and natural gas resources are commonly coproduced on federal lands. Revenue data are from the Department of the Interior (DOI), Office of Natural Resources Revenue (ONRR), available at https://revenuedata.doi.gov/query-data/. The total for oil and natural gas leases includes all revenues from the commodity categories "Oil, Gas, Oil & Gas (Pre-Production)" and "Natural Gas Liquids." These revenues do not account for revenues from tribal lands.
This report uses the term federal lands as defined by ONRR. ONRR collects information about revenues from oil and natural gas activities on federal lands and defines federal lands as "all land and interests in land owned by the United States that are subject to mineral leasing laws, including mineral resources or mineral estates from public domain lands, acquired lands, and the Outer Continental Shelf" (ONRR, "Natural Resources Revenue Data—Glossary," https://revenuedata.doi.gov/glossary). ONRR separately collects data about revenues from lands associated with federally recognized Tribes. ONRR defines these areas as Native American lands, including "tribal lands held in trust by the federal government for a tribe's use, and allotments held in trust by the federal government for individual Native American use" (ONRR, "Natural Resources Revenue Data- Revenue," https://revenuedata.doi.gov/downloads/revenue/). The Bureau of Indian Affairs (BIA), within DOI, holds 56 million surface acres and 59 million acres of subsurface mineral estates in trust on behalf of federally recognized Tribes and individual tribal citizens (BIA, Budget Justifications and Performance Information Fiscal Year 2025, p. IA-TNR-3, https://www.bia.gov/sites/default/files/media_document/fy2025-508-bia-greenbook.pdf). For more information, see CRS In Focus IF11944, Tribal Lands: An Overview, by Mariel J. Murray.
|
| 2.
|
Coal leases contributed 5% to the total; all other mineral leases combined contributed the remaining 2%.
|
| 3.
|
Citations for executive orders and implementing secretarial orders are as follows: Executive Order (E.O.) 14154, "Unleashing American Energy," 90 Federal Register 8353, January 29, 2025, and Secretarial Order (S.O.) 3418, "Unleashing American Energy," February 3, 2025, https://www.doi.gov/document-library/secretary-order/so-3418-unleashing-american-energy; E.O. 14156, "Declaring a National Energy Emergency," 90 Federal Register 8433, January 29, 2025, and S.O. 3417, "Addressing the National Energy Emergency," February 3, 2025, https://www.doi.gov/document-library/secretary-order/so-3417-addressing-national-energy-emergency; and E.O. 14153, "Unleashing Alaska's Extraordinary Resource Potential," 90 Federal Register 8347, January 29, 2025, and S.O. 3422, "Unleashing Alaska's Extraordinary Resource Potential," February 3, 2025, https://www.doi.gov/document-library/secretary-order/so-3422-unleashing-alaskas-extraordinary-resource-potential.
|
| 4.
|
Electricity produced from geothermal resources on federal lands is an example of energy production from the federal mineral estate. If surface lands over the federal mineral estate are not federally owned (i.e., split estate), BLM works with private surface owners to manage the federal mineral estate. Split estate lands are included in federal lands data in this report.
|
| 5.
|
Legislation may overturn or make other changes to withdrawals. For more on changing withdrawals, which can also occur in offshore federal lands, see CRS Legal Sidebar LSB11259, Biden Administration Withdraws Offshore Areas from Oil and Gas Leasing: Can a Withdrawal Be Withdrawn?, by Adam Vann.
|
6.
|
CRS calculations, based on EIA and ONRR data at https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm and https://revenuedata.doi.gov/query-data/.
7.
|
ONRR, Natural Resources Revenue Data, https://revenuedata.doi.gov/. Sources and inputs for data are the same as in Figure 1.
8.
|
CRS calculations, based on EIA and ONRR data at https://www.eia.gov/dnav/ng/ng_prod_sum_a_epg0_fgw_mmcf_a.htm and https://revenuedata.doi.gov/query-data/.
9.
|
ONRR, Natural Resources Revenue Data, https://revenuedata.doi.gov/. Sources and inputs for data are the same as in Figure 2.
| 10.
|
BLM, Public Land Statistics 2013, 2014, Table 3-17, p. 121, https://www.blm.gov/sites/blm.gov/files/pls2013.pdf.
|
| 11.
|
BLM, Public Land Statistics 2023, 2024, Table 3-17, p. 114, https://www.blm.gov/sites/default/files/docs/2024-08/Public-Land-Statistics-2023_508.pdf.
|
| 12.
|
43 U.S.C. §§1701 et seq.
|
| 13.
|
43 U.S.C. §1702(c).
|
| 14.
|
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.
|
| 15.
|
43 U.S.C. §1712. Regulations governing BLM resource management planning are at 43 C.F.R. §1610. Additional policy sources include BLM, Land Use Planning Handbook, BLM Handbook H-1601-1, Release 1-1693, March 11, 2005, https://www.blm.gov/sites/blm.gov/files/uploads/Media_Library_BLM_Policy_Handbook_h1601-1.pdf.
|
| 16.
|
Locatable minerals, leasable minerals, and mineral materials are defined in statute by the following laws, as amended: the General Mining Act of 1872 (codified at 30 U.S.C. §§21-54), the Mineral Leasing Act of 1920 (codified at 30 U.S.C. §§181-196), and the Mineral Materials Act of 1947 (codified at 30 U.S.C. §§601-615). For more information on locatable minerals and mineral materials, see CRS Report R48166, The U.S. Mining Industry and the Rosemont Decision, by Emma Kaboli and Adam Vann.
|
| 17.
|
P.L. 66-146, codified at 30 U.S.C. §§181 et seq. Leasable minerals also include coal and some non-energy minerals, such as sodium, potassium, phosphate, gilsonite, and sulfur.
|
| 18.
|
Statutory authorities regarding mineral developments on tribal lands are generally contained in Title 25, Chapters 12, 23, and 37 of the U.S. Code. For more information, see CRS Report R47640, Energy Leasing and Agreement Authorities on Tribal Lands: In Brief, by Mariel J. Murray.
|
| 19.
|
43 C.F.R. Subpart 3120.
|
| 20.
|
30 U.S.C. §226(q). Statute requires adjustment of the expression of interest 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 as of this writing (43 C.F.R. §3103.1).
|
| 21.
|
BLM announced on April 10, 2025, that it will no longer require an environmental impact statement for leasing decisions for 3,244 oil and gas leases in Colorado, Montana, New Mexico, North Dakota, South Dakota, Utah, and Wyoming. As of this writing, BLM has not announced details on NEPA compliance for these leases. BLM, "Intent to Prepare an Environmental Impact Statement for the Oil and Gas Leasing Decisions in Seven States from February 2015 to December 2020; Rescission," 90 Federal Register 15470, April 11, 2025, https://www.federalregister.gov/documents/2025/04/11/2025-06241/intent-to-prepare-an-environmental-impact-statement-for-the-oil-and-gas-leasing-decisions-in-seven.
|
| 22.
|
30 U.S.C. §226(b).
|
| 23.
|
The minimum bid is $10.00 per acre for the 10-year period beginning on August 16, 2022. The national minimum acceptable bid may be increased after that period to increase federal revenues and promote efficient management of oil and gas resources (30 U.S.C. §226(b)).
|
| 24.
|
43 C.F.R. Subpart 3104.
|
| 25.
|
BLM, "Fluid Mineral Leases and Leasing Process," 89 Federal Register 30916, https://www.federalregister.gov/documents/2024/04/23/2024-08138/fluid-mineral-leases-and-leasing-process.
|
| 26.
|
43 C.F.R. Subpart 3104.1(a).
|
| 27.
|
30 U.S.C. §226(g); 43 C.F.R. Subpart 3104.90. A unit agreement is a cooperative development plan adopted by multiple lessees and approved by BLM; see 30 U.S.C. §226(m) and 43 C.F.R. §3101.3.
|
| 28.
|
S.O. 3418, "Unleashing American Energy," February 3, 2025, https://www.doi.gov/document-library/secretary-order/so-3418-unleashing-american-energy, and E.O. 14154, "Unleashing American Energy," 90 Federal Register 8353, January 29, 2025.
|
| 29.
|
43 C.F.R. Subpart 3162.
|
| 30.
|
30 U.S.C. §191(d)(2).
|
| 31.
|
BLM, "Fiscal Year 2025 Annual Adjustment Calculation," https://www.blm.gov/sites/default/files/docs/2024-09/FY2025-Annual-Adjustment-Calculation.pdf.
|
| 32.
|
43 C.F.R. Subpart 3170.
|
33.
|
The royalty amounts to 16⅔% of the value of production (30 U.S.C. §226(b)) during the 10-year period beginning on August 16, 2022, and no less than 16⅔% thereafter. 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) and 30 U.S.C. §209).
| 34.
|
P.L. 80-382, codified at 30 U.S.C. §§351 et seq.
|
| 35.
|
About 90% of all federal lands are public domain lands, while the other 10% are acquired lands. For more information on federal lands, see CRS Report R42346, Federal Land Ownership: Overview and Data, by Carol Hardy Vincent and Laura A. Hanson.
|
| 36.
|
As noted by DOI. See "Table 1: Permanent Appropriations," in DOI, Budget Justifications and Performance Information: Fiscal Year 2025, p. ELR-2, https://www.doi.gov/sites/default/files/documents/2024-03/fy2025-508-os-dwp-greenbook_1.pdf.
|
| 37.
|
16 U.S.C. §§499-500.
|
| 38.
|
33 U.S.C. §701c-3.
|
39.
|
ONRR, "Revenue," https://revenuedata.doi.gov/downloads/revenue-by-month/. Companies have seven years to adjust their production data and amounts owed; in some cases, this can result in negative values being reported in the ONRR data. For example, an operator who overpays royalties may later file an adjustment. If the adjustment results in an amount owed to the operator in a given month that is greater than the royalties due from the operator during that month, the ONRR data would indicate a negative royalty value for that month.
| 40.
|
In the revenue data provided in this report, CRS adds fees collected by BLM for applications for permits to drill (APDs) to the ONRR "Other Revenues" category. ONRR's data for APDs do not indicate if a lease is on public domain land or another land type; values exclude APD fees on tribal lands and are available at DOI, Budget Justifications, Bureau of Land Management, in "Collections," table BLM Collections, APD Processing Fees. Congressional offices may contact the author with inquiries.
|
41.
|
Not including revenues from production on tribal lands. For more information on the treatment of revenues from tribal lands, see ONRR, "Revenue from Natural Resources on Native American Land," https://revenuedata.doi.gov/how-it-works/native-american-revenue/.
42.
|
Values include the ONRR categories "Oil," "Gas," "Oil & Gas," and "Natural Gas Liquids" (https://revenuedata.doi.gov/how-it-works/native-american-revenue/) and APD fees collected by BLM.
| 43.
|
The category "Other Revenues," as reported by ONRR, captures other revenues, including those from settlement agreements and interest payments. Added to this amount is 100% of APD fees collected by BLM, available at DOI, Budget Justifications, Bureau of Land Management, in "Collections," Table BLM Collections, Application for Permit to Drill (APD) Processing Fees. Congressional offices may contact the author with inquiries.
|
44.
|
Total federal onshore energy and mineral revenues in FY2023 were $9,096,119,793.39 (ONRR, https://revenuedata.doi.gov/query-data/, Data Type "Revenue," Period "Fiscal Year," Land Type "Federal Onshore," State/Offshore Region "All," Commodity "All"). Federal onshore oil and gas revenues in FY2023 comprise $8,452,864,617.50 (ONRR, https://revenuedata.doi.gov/query-data/, Data Type "Revenue," Period "Fiscal Year," Land Type "Federal Onshore," State/Offshore Region "All," Commodity "Gas, Oil, Oil & gas (pre-production), Natural gas liquids") plus $44,021,000 in APD fees (DOI, Budget Justifications, Bureau of Land Management [BLM], in "Collections," Table BLM Collections, Application for Permit to Drill [APD] Processing Fees; Congressional offices may contact the author with inquiries). Values exclude revenues from tribal lands.
45.
|
ONRR, "Revenue," https://revenuedata.doi.gov/downloads/revenue-by-month/, and BLM, "Table 15. Competitive Oil and Gas Lease Sales by BLM State Offices," https://www.blm.gov/programs-energy-and-minerals-oil-and-gas-oil-and-gas-statistics. The lease sale was held in September 2018 for 142 parcels in Chaves, Eddy, and Lea counties. See BLM National NEPA Register, https://eplanning.blm.gov/eplanning-ui/project/103545/570.
| 46.
|
These statutory allocations apply to all leasable minerals, including oil and natural gas.
|
| 47.
|
In using the disbursements, states other than Alaska are to give "priority to those subdivisions of the State socially or economically impacted by development of minerals leased under this chapter, for (i) planning, (ii) construction and maintenance of public facilities, and (iii) provision of public service" (30 U.S.C. §191(a)). No provisions on prioritization are given for Alaska.
|
| 48.
|
The Reclamation Fund was established in 1902 to develop and maintain irrigation systems in a number of western states (43 U.S.C. §391); see CRS Report R41844, The Reclamation Fund: A Primer, by Charles V. Stern.
|
49.
|
30 U.S.C. §191(a).
50.
|
The BLM Permit Processing Improvement Fund is to be used "for the coordination and processing of oil and gas use authorizations on onshore Federal and Indian trust mineral estate land" (30 U.S.C. §191(c)).
| 51.
|
For discussion of sequestration of mandatory spending, including mineral leasing revenues, see CRS Report R42972, Sequestration as a Budget Enforcement Process: Frequently Asked Questions, by Megan S. Lynch.
|
52.
|
30 U.S.C. §191(b).
53.
|
30 U.S.C. §191(d). The fee for FY2025 is $12,515. See BLM, "Minerals Management: Annual Adjustment of Cost Recovery Fees," 89 Federal Register 77170, September 20, 2024, https://www.federalregister.gov/documents/2024/09/20/2024-21605/minerals-management-annual-adjustment-of-cost-recovery-fees.
54.
|
Total does not include disbursements to Tribes or individual tribal citizens. This value is before sequestration of mandatory spending, as sequestration amounts (which vary by year) are not attributable to a given commodity in the ONRR data. All APD fees are included as disbursements. Disbursements to states are after deduction of the 2% administrative fee; Treasury values include the administrative fee. Total disbursements from leasable minerals and geothermal resources are available from ONRR, https://revenuedata.doi.gov/query-data/, Data type "Disbursements," Period "Fiscal Year," Recipient "Other funds, Reclamation Fund, State and local governments, U.S. Treasury," Source "Onshore."
| 55.
|
S.O. 3418, "Unleashing American Energy," February 3, 2025, https://www.doi.gov/document-library/secretary-order/so-3418-unleashing-american-energy, and E.O. 14154, "Unleashing American Energy," 90 Federal Register 8353, January 29, 2025.
|
| 56.
|
Examples of bills from the 118th Congress include H.R. 9017 and H.R. 6009.
|
| 57.
|
See, for example, S. 624 in the 117th Congress.
|
| 58.
|
30 U.S.C. §226(b).
|
| 59.
|
41 Stat. 437.
|
| 60.
|
Examples of bills that would have reversed the royalty increase in the 118th Congress include H.R. 9017 and H.R. 6009.
|
| 61.
|
The Government Accountability Office (GAO) published a report highlighting the findings from two studies that analyzed the impacts of possible changes to oil and natural gas royalty rates (GAO, Oil, Gas, and Coal Royalties, GAO-17-540, 2017). The report highlights many of the factors affecting the impacts of a change to the royalty rate, including royalty rates assessed by states, oil and natural gas prices, and other market conditions. The report also notes that the impacts are assumed to occur over a 25-year period, as it may take nearly 10 years for new leases to reach production.
|
| 62.
|
Approximately 97% of oil and natural gas leases were issued by competitive bidding in FY2022 (BLM, Public Land Statistics 2022, 2023, Tables 3-13 and 3-14, pp. 90-104).
|
| 63.
|
30 U.S.C. §226(q).
|
| 64.
|
30 U.S.C. §226(q).
|
| 65.
|
Examples of bills from the 118th Congress that would have reinstated noncompetitive leasing include H.R. 9017 and H.R. 1335.
|
| 66.
|
Other legislation introduced in the 118th Congress would have made changes to fiscal terms. Provisions in H.R. 7375 would have restructured EOI payment by requiring the winning bidder to pay the EOI fee during the lease sale. If the EOI acreage submitted is not bid on during a lease sale, the person who first nominated the parcel would pay the fee. If the party that submitted the EOI did not win the lease, the fee amount would be reimbursed to the nominating party. H.R. 6481 would have stipulated that the nominating party be reimbursed if the EOI became inactive. Both bills would have stipulated that EOIs remain active for at least five years. H.R. 9017 contained provisions that would have reversed many of the changes to onshore federal oil and gas leasing, including lowering minimum bids back to $2.00 per acre, lowering rent, eliminating EOIs, and reinstating noncompetitive leasing.
|
| 67.
|
The Fluid Mineral Leases and Leasing rule is currently under review as of writing. S.O. 3418, "Unleashing American Energy," February 3, 2025, https://www.doi.gov/document-library/secretary-order/so-3418-unleashing-american-energy.
|
| 68.
|
P.L. 94-377.
|
| 69.
|
P.L. 109-58.
|
| 70.
|
P.L. 113-291, §3021(b).
|
| 71.
|
See "Amendments," 30 U.S.C. §191.
|
72.
|
Examples of bills in previous Congresses that would have eliminated the administrative fee include H.R. 913 in the 118th Congress; S. 2130 in the 117th Congress; and H.R. 998, H.R. 4294, S. 218, and S. 2418 in the 116th Congress.
| 73.
|
Examples of bills include S. 20 in the 118th Congress; H.R. 9535 in the 117th Congress; and H.R. 998, H.R. 4294, S. 218, and S. 2418 in the 116th Congress.
|
| 74.
|
H.R. 4294 and S. 218 in the 116th Congress.
|
| 75.
|
S. 20 in the 118th Congress.
|
| 76.
|
BLM, Public Land Statistics 2018, 2019, Tables 3-13 and 3-14, pp. 96-104; BLM, Public Land Statistics 2019, 2020, Tables 3-13 and 3-14, pp. 91-99; BLM, Public Land Statistics 2020, 2021, Tables 3-13 and 3-14, pp. 83-97; and BLM, Public Land Statistics 2021, 2022, Tables 3-13 and 3-14, pp. 86-100.
|
| 77.
|
GAO, Onshore Competitive and Noncompetitive Lease Revenues, GAO-21-138, 2020.
|
| 78.
|
Examples of bills from the 118th Congress that would have reinstated noncompetitive leasing include H.R. 9017 and H.R. 1335.
|
| 79.
|
For background and discussion of environmental impacts of natural gas emissions, see CRS Report R42986, Methane and Other Air Pollution Issues in Natural Gas Systems, by Richard K. Lattanzio.
|
| 80.
|
EPA, "Primary Sources of Methane Emissions," https://www.epa.gov/natural-gas-star-program/primary-sources-methane-emissions.
|
| 81.
|
John L. Sorrels et al., "Section 3.2—VOC Destruction Controls, Chapter 1—Flares," in EPA Air Pollution Control Cost Manual, August 2019, https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution.
|
| 82.
|
30 U.S.C. §1727. Royalties on vented or flared natural gas are assessed on leases issued after August 16, 2022. Exceptions include gas vented or flared for not longer than 48 hours in an emergency situation; gas used or consumed within the area of the lease for the benefit of the lease; or gas that is unavoidably lost. "Unavoidably lost" natural gas is defined at 43 C.F.R. §3179.41.
|
| 83.
|
The Fluid Mineral Leases and Leasing rule is currently under review as of writing. S.O. 3418, "Unleashing American Energy," February 3, 2025, https://www.doi.gov/document-library/secretary-order/so-3418-unleashing-american-energy.
|
| 84.
|
H.R. 9017, which was introduced in the 118th Congress, also would have removed royalties assessed on natural gas that is vented or flared.
|