Contents

• Introduction
• Oil and Natural Gas Production on Federal Lands
• 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 Policy Management Act (FLPMA; 43 U.S.C. §1701 et seq.) establishes statutory authority for BLM to manage the federal subsurface mineral estate. The onshore oil and natural gas programs are generally governed by the Mineral Leasing Act of 1920 (MLA; 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 from oil and gas leasing on federal lands are deposited into the Reclamation Fund, and states other than Alaska receive 50% of revenues from extraction operations in those states. Alaska 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 onshore 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 119^th Congress include measures to reduce royalty and rental rates or remove specific fees.

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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 domestic energy supply, employment opportunities in the sector, and federal revenues from these activities. 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 Department of the Interior (DOI), manages energy production and mineral development from these subsurface lands, including lands whose surface is managed by other federal agencies or for split estate lands.⁴ Oil and natural gas developments are considered mineral developments. Some federal lands—including most National Park Service units, designated wilderness areas, 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 in production on 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/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 onshore 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 12.6 million acres.¹⁰ In FY2023, BLM administered 23,641 oil and natural gas leases in producing status, covering 12.4 million acres.¹¹ Between FY2013 and FY2023, the number of producing leases increased by 0.6%, but the area covered by producing leases decreased 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 production data from nonfederal, federal offshore, and federal onshore regions as an index. The base year of the index is FY2013; the index values are equivalent to percentage values. These data highlight relative changes in each series. For example, onshore oil production on federal lands increased, as a percentage, more than oil production on nonfederal lands over the period 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 Energy Information Administration, https://www.eia.gov/dnav/ng/ng_prod_sum_a_epg0_fgw_mmcf_a.htm, and Department of the Interior, Office of Natural Resources Revenue, https://revenuedata.doi.gov/. Notes: FY2013 is the base year for the index; values are equivalent to percentages. 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.

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

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.

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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 to be disbursed to the state in which the lease is located,⁴⁷ and 40% are to be deposited in the Reclamation Fund.⁴⁸ The 10% of revenues remaining after these disbursements are to be credited to the General Fund (i.e., miscellaneous receipts) of the Treasury.⁴⁹ For rental revenues from oil and natural gas leases, 50% of the rental revenues are to be disbursed to the state in which the revenues occurred, and the remaining 50% are to be deposited in the BLM Permit Processing Improvement Fund (PPIF).⁵⁰ 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 disbursements to states resulting from oil and natural gas leases are to be reduced by the applicable sequestration rate for the given fiscal year.⁵¹ Two percent of funds disbursed 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.⁵² New onshore oil and natural gas leases on federal lands are also subject to a permit processing fee, to be submitted with the application for a permit to drill that is required for each well.⁵³ These revenues are deposited in the PPIF, with 75% of the revenues being transferred the state 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.

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 119^th 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 119^th 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 119^th 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 118^th Congress, would have made other changes to the fiscal terms listed above.⁶⁶

In the 118^th 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 119^th 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 119^th 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 118^th 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.

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.