2024-08138. Fluid Mineral Leases and Leasing Process

AGENCY:

Bureau of Land Management, Interior.

ACTION:

Final rule.

SUMMARY:

The Bureau of Land Management (BLM) is revising its oil and gas leasing regulations. Among other changes, the final rule implements provisions of the Inflation Reduction Act (IRA) pertaining to royalty rates, rentals, and minimum bids; updates the bonding requirements for leasing, development, and production; and revises some operating requirements. The final rule will improve the BLM's leasing process by ensuring proper stewardship of public lands and resources.

DATES:

The final rule is effective on June 22, 2024.

FOR FURTHER INFORMATION CONTACT:

Yvette M. Fields, Division Chief, Fluid Minerals Division, telephone: [phone], email: [e-mail], or by mail 1849 C St. NW, Washington, DC 20240, for information regarding the substance of this final rule.

Individuals in the United States who are deaf, deafblind, hard of hearing, or have a speech disability may dial 711 (TTY, TDD, or TeleBraille) to access telecommunications relay services. Individuals outside the United States should use the relay services offered within their country to make international calls to the point-of-contact in the United States. For a summary of the final rule, please see the final rule summary document in docket BLM-2023-0005 on www.regulations.gov.

SUPPLEMENTARY INFORMATION:

I. List of Acronyms

II. Executive Summary

III. Discussion of Public Comments on the Proposed Rule

IV. Overview of Modifications to the Proposed Rule

V. Procedural Matters

List of Acronyms

APD = Application for Permit to Drill

BLM = Bureau of Land Management

BOEM = Bureau of Ocean Energy Management

CA = Communitization Agreement

CD = Certificate of Deposit

CFR = Code of Federal Regulations

DOI = Department of the Interior

E.O. = Executive Order

EOI = Expression of Interest

FLPMA = Federal Land Policy and Management Act

GAO = Government Accountability Office

GHG = Greenhouse Gas

IBLA = Interior Board of Land Appeals

IIJA = Infrastructure Investment and Jobs Act of 2021

IM = Instruction Memoranda

IRA = Inflation Reduction Act of 2022

LOC = Letter of Credit

MLA = Mineral Leasing Act of 1920, as amended (MLA is also referred to as “Act” in the regulations.)

MLAAL = Mineral Leasing Act for Acquired Lands of 1947, as amended

MLRS = Mineral and Land Records System

NAICS = North American Industry Classification System

NEPA = National Environmental Policy Act

OIG = Office of the Inspector General

ONRR = Office of Natural Resources Revenue

PRA = Paperwork Reduction Act

RIA = Regulatory Impact Analysis

RMP = Resource management plan

ROW = Right-of-way

SBA = Small Business Administration

U.S.C. = United States Code

Executive Summary

On July 24, 2023, the BLM published a proposed rule to amend the regulations in 43 CFR parts 3000, 3100, 3110, 3120, 3130, 3140, 3150, 3160, 3170, and 3180 in the Federal Register (88 FR 47562), with a 60-day comment period. Generally, the comments supported this rulemaking and expressed the view that the changes outlined by the proposed rule will be helpful. Comments on specific sections of the proposed rulemaking opposed certain provisions and recommended changes. Within this preamble, the BLM discusses those comments and the BLM's responses.

Overall, this rule will enhance the BLM's administration of oil and gas-related activities on America's public lands and reflects Congress's changes to the oil and gas program in the IRA. Specifically, the rule will reflect requirements of the IRA by increasing royalty rates, rentals, and minimum bids for BLM-issued oil and gas leases, and by imposing a fee for the submittal of an expression of interest (EOI) for leasing Federal oil and gas. The rule also updates the bonding requirements for leasing, development, and production to address shortcomings identified in reports by the Government Accountability Office (GAO) and the Department of the Interior's (DOI's) Office of Inspector General (OIG). Collectively, the BLM proposed these changes to bring the regulations into compliance with the IRA and the Infrastructure Investment and Jobs Act (IIJA) mandates and to ensure that reclamation costs are not borne by the American public. The BLM is also adjusting its cost recovery mechanisms so that project applicants provide a more appropriate share of the BLM's up-front costs for processing these applications. Finally, the BLM is implementing several changes to focus leasing on areas with fewer resource conflicts. The BLM's final rule will be the first comprehensive update to the Federal onshore oil and gas program's regulatory framework since 1988.

The Secretary of the Interior manages the Federal onshore oil and gas program pursuant to the requirements of various statutes, including the Federal Land Policy and Management Act of 1976, as amended (43 U.S.C. 1701 et seq.) (FLPMA); the Mineral Leasing Act of 1920, as amended (30 U.S.C. 181 et seq.) (MLA or Act); and the Mineral Leasing Act for Acquired Lands of 1947, as amended (30 U.S.C. 351 et seq.) (MLAAL), as well as the recently enacted IRA (Pub. L. 117-169 (2022)) and IIJA (Pub. L. 117-58 (2021)). Under section 102 of FLPMA (43 U.S.C. 1701(a)(7)), the BLM manages approximately 245 million acres of public lands and approximately 700 million acres of federally owned subsurface minerals “on the basis of multiple use and sustained yield.” FLPMA's definition of “multiple use” in section 103 (43 U.S.C. 1702(c)) requires the BLM to achieve “a combination of balanced and diverse resource uses that takes into account the long-term needs of future generations for renewable and non-renewable resources.” Oil and gas-related activities are one of the multiple uses that FLPMA authorizes and which the BLM administers in accordance with the MLA and MLAAL. Both of those Acts govern the leasing of public lands to explore for and develop oil, natural gas, coal, and other hydrocarbons, amongst other mineral deposits.

Discussion of Public Comments on the Proposed Rule

The public comment period for the proposed rule ended on September 22, 2023. During the 60-day public comment period, the BLM received over 215,000 comments submitted by Federal, State, and local governments, local agencies, Tribal organizations, industry representatives, individuals, and other external stakeholders. The vast majority of submissions were form letters. Commenters also submitted roughly 1,000 unique letters. From all submissions, the BLM identified approximately 1,200 unique comments raising specific issues on the proposed rule.

The BLM carefully reviewed all comments received on the proposed rule. Certain comments suggesting that the BLM address issues outside the scope of this rulemaking are discussed in Section III.A.

The BLM categorized the remaining comments received and provides an overview of those categories and associated responses in Section III.B. The BLM provides more detailed discussions of those comments in Section IV.B. The Federal Government posts all comments at the Federal eRulemaking portal: http://www.regulations.gov. To access the comments at that website, enter 1004-AE80 in the Search box and select the Fluid Mineral Leases and Leasing Process proposed rule.

A. Comments Outside the Scope of This Rulemaking

The BLM received many comments directed at matters outside of the scope of this rulemaking, including those regarding: project-specific considerations; the BLM's existing website or computer application programs ( e.g., Automated Fluid Mineral Support System, National Fluid Lease Sale System, etc.); additional rulemaking or programmatic environmental impact statements specific to greenhouse gas (GHG) emissions; geothermal or helium leasing activities; and additional operational provisions in 43 CFR part 3160 or additional unit provisions in 43 CFR part 3180 that were not part of the proposed rule. Other commenters recommended changes to national energy policies and priorities, such as to halt all oil and gas leasing activities due to climate change, or discussed matters not specific to the BLM's administration of oil and gas leasing. Many comments expressed general statements of support or opposition to the rule. The BLM has not responded to these comments in detail, because these myriad matters were not encompassed in the proposed rule and are best addressed, if at all, through future rulemakings.

A commenter stated that the BLM failed to write this entire rule in a manner that is easily understood without providing any examples to support the assertion. When drafting the proposed and final rules, the BLM reviewed the rule text to identify areas where the regulations could be written more clearly and made changes as necessary.

B. Categorized Public Comments on the Proposed Rule

This section of the preamble summarizes the major categories of public comments that the BLM received in response to the proposed rule, as well as the BLM's responses.

1. Comments Recommending Additional Oil and Gas Rulemaking, or Policy Development

Summary of comments: Multiple commenters recommended that the BLM initiate additional rulemaking efforts or develop additional policy that are beyond the scope of this rulemaking. These recommendations include: (1) a rule to update the BLM's unitization process in part 3180; (2) a rule to update the BLM's permitting process in 43 CFR part 3160; (3) development of “The Bureau of Land Management's Blueprint for 21st Century Outdoor Recreation”; (4) updated policy related to oil and gas lease suspension; (5) updated policy related to oil and gas unitization; (6) a similar joint rulemaking between the BLM and the Bureau of Indian Affairs; and (7) a bureau-wide review of its standard stipulation lists.

Response: The BLM reviewed these comments and determined that the requested changes are outside the scope of this rulemaking. With respect to the comments recommending the BLM update the unitization portion of the regulations at part 3180, the BLM made changes to the final rule to implement the increased royalty rate mandated by Congress in the IRA but did not propose any changes to the remaining unitization provisions. As the BLM did not propose any changes in the proposed rule, the public was not provided with a chance to comment on any other changes to the regulations governing unitization. As it reviews its current policy in light of this rule's changes, the BLM will determine whether to implement any changes to its approval process for lease suspensions. Although a comment requested that the BLM review and standardize a list of lease stipulations, in addition to the terms and conditions in the BLM's standard form oil and gas lease, the BLM develops lease stipulations as part of its resource management planning process (which includes analysis under NEPA and other statutes), in which the public has opportunities to comment, and those stipulations apply to oil and gas leases issued within each RMP area. Any site-specific concerns can be addressed through the NEPA process for a particular sale or through conditions of approval at the Application for Permit to Drill (APD) stage.

During the comment period, the BLM received comments requesting additional updates to parts 3160 and 3170. As part of its review under Executive Order (E.O.) 14008, issued on January 27, 2021, the Department reviewed the onshore oil and gas leasing program and published the Report on the Federal Oil and Gas Leasing Program on November 26, 2021. The Report on the Federal Oil and Gas Leasing Program recommended that the BLM should reform its royalty rate, minimum bonus bids, rental rates, and bonding amounts; establish new requirements for bidders; and take steps to discourage nominations of low-potential lands. When the BLM drafted the proposed rule, the BLM considered any critical permitting or operational changes to parts 3160 and 3170 that were needed in response to the Report's recommendation to reduce speculation but did not propose any changes to the remaining provisions. As the BLM did not propose any changes to parts 3160 and 3170, outside of the limited changes in the proposed rule, the public was not provided with a chance to comment on any other changes to the regulations governing permitting or operations.

As noted above in the summary of comments outside the scope of this rulemaking effort, the BLM received a comment requesting the development of a blueprint for outdoor recreation. Such a revision is beyond the scope of this rulemaking as it would involve revising regulations in Title 43 of the CFR, Subchapter H, and those regulations do not pertain to oil and gas leasing and development, which is the focus of this effort. Finally, a joint rulemaking between the BLM and the Bureau of Indian Affairs is outside the scope of this rulemaking effort.

2. Comments on Greenhouse Gas Emissions and Climate Change

Summary of comments: In the proposed rule, the BLM requested comment on whether the preference criteria in § 3120.34 or other portions of the proposed rule should be expanded, or new provisions added, to discuss analysis of GHG emissions and related decision making based on that analysis. The BLM received many comments recommending different approaches, including:

• Not changing the rule to address GHG emissions and climate change on the grounds that the NEPA review process at the project level provides a sufficient review for climate change issues, and that refraining from leasing Federal minerals will not change the demand for oil and gas production;

• Amending the rule to forgo future leasing based upon the need to avoid exceeding the world's pre-industrial global temperature level by 1.5 degree Celsius;
• Setting lease rates based on the Social Cost of Carbon calculated by the U.S. Environmental Protection Agency in November 2022 at a discount rate of 1.5 percent;
• Aligning the oil and gas program with President Biden's climate goals;
• Limiting GHG emissions via emissions monitoring;
• Implementing a three-stage leasing process to prioritize lands for leasing with a final climate screening;
• Creating a carbon budget for the Federal onshore oil and gas program;
• Requiring climate change mitigation, analyzing climate impacts across BLM-managed lands, or implementing a rule to ensure climate protection for all new leasing and permitting decisions;
• Initiating a programmatic environmental impact statement for the onshore oil and gas program to assess the potential GHG impacts;
• Establishing a quantitative climate test tool to evaluate the relative impact and significance of GHG emissions at the project level; and
• Expanding the competitive leasing preference criteria for conformity with State policies on GHG emissions.

Response: Climate change is a global process that is affected by the sum total of GHGs in the Earth's atmosphere. The BLM acknowledges the views and suggestions reflected in these comments and recognizes that GHG emissions from the Federal onshore oil and gas program contributes to climate change. After reviewing the comments received, the BLM did not make any changes to the final rule to address GHG emissions and climate change. In this rule, the BLM implements regulatory modifications required by Congress in the IRA and other revisions that aim to improve the leasing process and ensure proper management of public lands and resources. These reforms are not focused on climate change. For example, the majority of these regulations cover the administration of an oil and gas lease, such as changes to the fixed filing fees, the fiscal terms mandated by Congress, the type of lease the BLM can issue (eliminating noncompetitive leases as mandated by Congress), and the method by which the public requests lands to be considered for leasing (formal nominations vs. expressions of interest). In implementing the MLA's requirement to hold quarterly lease sales when lands are eligible and available, the BLM will continue to use the NEPA review process and guidance issued by the Council on Environmental Quality to evaluate GHG emissions that result from oil and gas leasing and development and its effects on climate change. The BLM understands the commenters' suggestions and may proceed with those suggestions in future rulemakings that more directly address GHG emissions. Further responses to comments related to the preference criteria specifically are addressed in section IV.B.12 of the preamble.

3. Comments Recommending the BLM Stop All Oil and Gas Lease Sales and Permitting

Summary of comments: Multiple commenters recommended that the BLM stop, or phase out, all oil and gas lease sales, the issuance of leases, as well as permitting and development, due to climate change and the GHG emissions from oil and gas development.

Response: Pursuant to the IRA, the BLM is required to conduct lease sales in order to permit wind and solar energy development projects on public lands. The approach suggested by the commenters thus would require the BLM to stop desirable wind and solar development. In implementing the MLA's requirement to hold quarterly lease sales when lands are eligible and available, the BLM will continue to use the NEPA review process to evaluate GHG emissions that result from oil and gas leasing and development and its effects on climate change.

4. Comments on Public Participation

Summary of comments: Tribes, States, and local governments submitted comments requesting that the BLM update the rule to provide additional consultation and outreach to them on oil and gas leasing and development. Some comments encouraged the BLM to coordinate with the relevant State and county agencies when land-use actions are taken or if the BLM is considering leasing lands adjacent to State-owned or managed lands. Other comments requested that the BLM explore opportunities for Tribal cultural site protection and co-stewardship to ensure the BLM fully advances opportunities for the incorporation of Indigenous Knowledge, respect for Tribal sovereignty and treaty rights, and the protection of Tribal cultural sites. Comments also recommended that the BLM consult the State or local government's land use plans to ensure the BLM applies the appropriate provisions to responsibly manage natural resources, climate, and environmental quality issues during the decision making and planning efforts for oil and gas leasing.

Response: The BLM will continue to engage with the public, Tribes, Federal, State, and local government partners on the BLM's management of its public lands, as appropriate. Subsequent actions that the BLM may take will be subject to the applicable policies, laws, and regulations pertaining to that action, including those for consultation and environmental review. The BLM added language into the competitive leasing process (see § 3120.42) to include scoping, comment, and protest periods to ensure that the BLM provides adequate time to evaluate the views of a wide range of partners, stakeholders, and landowners in any future decisions. Furthermore, in formulating or amending its resource management plans (RMPs), the BLM complies with FLPMA, NEPA, and its regulations providing for public participation, coordination of planning efforts, and consistency. See 43 CFR 1610.2, 1610.3-1, 1610.3-2. The RMPs serve as blueprints to enable the BLM to sustain the health, diversity, and productivity of public lands for the use and enjoyment of present and future generations. Under an RMP, the BLM will identify the lands closed to leasing of Federal oil and gas, the lands open to leasing of Federal oil and gas, and the appropriate stipulations to apply to a Federal oil and gas lease based upon the location of the lease. These decisions are not made as part of this rulemaking and will continue to be made through the BLM's land use planning process, which involves cooperating with State and local governments, consulting with Tribes, and robust public engagement.

The BLM takes its responsibilities to Tribes seriously and respects Tribal sovereignty and treaty rights. Where there are such opportunities, the BLM is committed to exploring co-stewardship opportunities with Tribes. However, co-stewardship is outside the scope of this rulemaking.

5. Comments on the BLM's Discretion To Offer Parcels for Lease Sales

Summary of comments: Multiple commenters stated that the rule improperly limits and discourages exploration or closes off lands to leasing outside of the NEPA process. These commenters pointed to different aspects of the rule to support their claim that the rule limits and discourages exploration. Some comments stated that the rule violates, or evades, the multiple-use mandate of FLPMA or exceeds the authority of the BLM under the MLA. Other comments stated that when a person requests the BLM include certain lands in an upcoming competitive oil and gas lease sale (via EOI) the BLM should offer all lands described in the EOI in the next available sale based on and consistent with the management decisions made in the relevant RMPs. Multiple comments stated that the new preference criteria (see § 3120.32) will create uncertainty, conflicts among stakeholders and uses, and will hinder the BLM's ability to achieve the congressional mandates such as offering enough acreage for oil and gas leasing in order to allow wind and solar right-of-way (ROW) permit issuance.

Response: With respect to contentions that the BLM's proposed regulations exceed the Secretary's authority to select lands for leasing, the BLM notes that the MLA, 30 U.S.C. 226(a), by providing that the Secretary “may” lease lands, necessarily provides the BLM with broad discretion in determining precisely which lands and parcels the BLM will offer at an oil and gas lease sale. Accordingly, the agency has, since at least 1988, consistently applied a public interest determination to any such decisions. See53 FR 22828 (June 17, 1988) (“It is Bureau policy prior to offering the lands to determine whether leasing will be in the public interest.”). The MLA does not specify how and when this decision is to be made, and both the Supreme Court and the U.S. Court of Appeals for the Tenth Circuit have recognized the Secretary's discretion in this sphere. See Udall v. Tallman, 380 U.S. 1, 4 (1965); W. Energy All. v. Salazar, 709 F.3d 1040, 1044 (10th Cir. 2013).

Comments asserting that the application of the preference criteria will result in the closure of any lands to oil and gas leasing are incorrect. The BLM has and will continue to make land use decisions at the land use planning stage and document those decisions in the applicable RMP. The preference criteria, on the other hand, were proposed consistent with the MLA to direct the BLM's administrative resources to leasing tracts most likely to be developed, to reduce conflicts between oil and gas development and other public land uses that were not resolved in the resource management plans, and to “take[ ] into account the long-term needs of future generations for renewable and nonrenewable resources,” 43 U.S.C. 1702. These criteria may be considered on a case-by-case basis in light of specific circumstances. Even if the BLM were to apply such criteria and decide to defer including particular lands from any particular lease sale, nothing in this rule prevents those lands from being offered in future sales. The RMPs do not always resolve all conflicts, especially those that may be unforeseen or arise due to a change in circumstances. In many cases, this calls for a more specific site review, and the MLA provides the necessary discretion, apart from FLPMA, to engage in this type of site-specific review.

6. Comments Recommending BLM Processes Should Be Addressed in Policy and Not Regulations

Summary of comments: The BLM received multiple comments stating that many of the BLM processes in the proposed rule should instead be expressed in policy documents and that the rule goes beyond the authority of the BLM under the IRA and IIJA. Comments expressed the view that the function of regulations is to inform and instruct the public with regard to actions that they may or may not take while policy interprets those regulations and provides guidance to the agency in implementing them. The commenters stated that inserting existing policy guidance, which applies only to the BLM's actions, into the regulations, rather than leaving it in Instruction Memoranda (IM), is inappropriate. For example, commenters suggested that the preference criteria and the details regarding lease suspensions belong in BLM guidance documents and not in the regulations as these do not impose any requirements on the oil and gas industry. Finally, the commenters stated that the BLM does not need to update the existing regulations governing the BLM's discretionary functions under the existing regulations, since those regulations are adequate to protect the fiscal interests of the American public. These commenters recommended that the BLM only make the changes required by the IRA.

Response: By incorporating provisions such as the preference criteria and lease suspensions into the regulations, the BLM makes those provisions legally binding and provides greater certainty and transparency to the public on the decision-making processes the BLM will use when it processes EOIs (see § 3120.32) and the timeframes for lease suspensions (see § 3165.1). These regulatory criteria may influence a person's decision-making when deciding whether they will submit an EOI or may influence lessees when they are deciding whether to seek a lease suspension. Therefore, the BLM declines to make any changes to the final rule based upon concerns that the changes could be characterized as guidance.

7. Comments on Environmental Justice

Summary of comments: Multiple commenters stated that the BLM should ensure that the final rule includes environmental and social justice considerations as part of the oil and gas leasing process. Comments stated that many of the fluid mineral resources are located in underserved rural areas and on Tribal lands where the fluid mineral industry has a large economic impact. These comments alleged that the rule could undercut environmental justice goals by reducing the economic benefits that would otherwise flow to disadvantaged communities as a result of onshore Federal oil and gas activities. One comment stated that jobs in extractive industries, such as oil and gas development, are not going to the members of the communities burdened by the fossil fuel industry and therefore that the BLM should end the Federal fossil fuel leasing program. Another comment stated that the BLM should solicit the knowledge and experience of those in underserved communities and ensure that these communities' perspectives are meaningfully incorporated into and actively shape planning and decision-making, and the BLM should take into account community-driven and localized health impact assessments and relevant local health and demographic data as part of this process. Another comment recommended that the BLM incorporate environmental justice as part of § 3120.32.

Response: The BLM reviewed the comments recommending changes to the rule to address environmental justice concerns and determined that no changes were necessary. The BLM believes environmental justice concerns are initially addressed through the land use planning process when the BLM is evaluating whether lands should be open to leasing and what stipulations should be imposed, and then at the more site-specific level when identified parcels are being evaluated for possible inclusion in a lease sale. Both of these processes also involve an evaluation under NEPA, which provides an opportunity for considering environmental justice concerns, which are dependent on the specific conditions and history pertaining to each area and the communities potentially impacted. In addition, the preference criteria that the BLM is including in this final rule will provide a tool for the BLM to assess environmental justice concerns through government-to-government consultation and through scoping comments received from the public. To the extent a comment noted a specific environmental-justice-related concern with a particular section of the rule, the BLM has also addressed such comments in the following Section-by-Section Discussion.

8. Comments on the Impact of the Rule on Indian Leases

Summary of comments: The BLM received a comment stating that the proposed rule preamble incorrectly stated that the rule “will not impact the leasing of Indian minerals.” The comment asserted that the rule would impact Indian interest, lands, and minerals, and that the BLM needs to clarify this in the final rule. The BLM also received comments stating that the rule should be revised to clarify that public lands managed by the BLM under FLPMA and do not include Indian lands; that the rule should eliminate BLM activities on Indian lands; and, that the BLM lacks authority to manage activities on Indian lands.

Response: The BLM does not make leasing decisions for Indian lands. However, the BLM does make recommendations for oil and gas operations that may impact Indian lands. Existing regulations at 43 CFR part 3100 outline the BLM's authority over offering lands to lease under the BLM's jurisdiction, which does not include Indian lands. The changes made in this rulemaking clearly fall within the BLM's existing statutory authorities. The BLM acknowledges that some of the proposed changes may affect Indian lands when the BLM makes recommendations for oil and gas operations to the Bureau of Indian Affairs under the Standard Operating Procedures between agencies for the leases they manage under their respective jurisdictions. While the majority of the changes in the final rule impact the leasing of Federal minerals and not Indian leases, there are some provisions that will apply to Indian leases: the operational changes for shut-in and temporarily abandoned wells at § 3162.3-4 and the changes to the APD timeframe at § 3171.14. The BLM has also increased filing fees to account for inflation for applications such as APDs, as required by 30 U.S.C. 191. The BLM considers these updates critical for both Federal and Indian minerals because these changes will give the BLM the ability to complete operator-diligence reviews, ensure that wells are producing on Indian leases as required by law, and to recover its costs to process applications.

9. Comments on the Rule Potentially Discouraging Federal Exploration and Development

Summary of comments: Multiple commenters expressed concerns that the proposed rule would discourage or eliminate future oil and gas exploration and development on Federal lands or would force production from Federal lands onto State or private lands. The BLM also received comments asserting that the combination of proposed § 3120.32 (reflecting the BLM's authority to defer certain parcels) and the increased fees, royalties, and bonding would result in the BLM violating its statutory requirements to prevent waste of the oil and gas resource. Specifically, the commenter claimed that provisions in this rule, such as the competitive leasing preference criteria at § 3120.32, could result in delays in or the complete exclusion of the development of non-Federal minerals in addition to the loss in Federal bonuses and royalties. These commenters also asserted that this rule fails to recognize studies indicating that the United States will continue to need fossil fuels for the foreseeable future. The commenters urged the BLM to look for ways to increase energy development. Commenters also stated that the proposed rule ignored the economic benefit provided by oil and gas development to local schools, hospitals, and infrastructure.

Response: The GAO and the DOI OIG reviewed and audited the BLM's Federal onshore oil and gas program to identify problematic areas in this program and recommended actions to address them. Both the GAO's and OIG's audits ^[1] highlighted weaknesses in the onshore program's fiscal framework and recommended that the BLM take steps to ensure that the American public receives a fair return from oil and gas activities on public lands. The DOI and the BLM concurred with these recommendations in the Report on the Federal Oil and Gas Leasing Program  ^[2] issued in November 2021.

Accordingly, the BLM is adjusting its oil and gas bonding requirements, including by increasing minimum bond amounts for the first time in decades. The BLM is proposing to adjust its cost recovery mechanisms to account for changes in the leasing process since the fees were initially set in 2005. The BLM drafted the proposed rule to: (1) reflect the requirements of the IRA; and (2) enhance the administration of the onshore program, to direct leasing to lands with a higher development potential, and in response to the GAO's and OIG's numerous reports identifying shortcomings in the program, as discussed in the November 2021 Report on the Federal Oil and Gas Leasing Program.

The BLM did not make any changes to the final rule based upon the comments expressing concerns that the increased bonding and fees could result in the potential movement of production from Federal to State or private lands. The royalty rates on State and private lands are often higher than those for Federal lands as are the rental rates.^[3] Given this, the BLM does not believe the increased rates will have the asserted affect and instead will bring the rates more in line with one another across jurisdictions. Moreover, § 3120.32 does not affect longstanding BLM policies that prioritize leasing parcels subject to drainage (from adjacent State and private minerals); the BLM will continue to work towards leasing lands that will allow for logical development of the minerals by giving preference to lands after accounting for expected yields of oil and gas, fair return for U.S. taxpayers, and decisions embodied by the BLM's RMPs. This will provide for continued development of Federal, State, and private minerals.

IV. Overview of Modifications to the Proposed Rule

A. Summary of Notable Changes

The BLM made changes to the rule in response to comments and for accuracy, clarity, or grammar.

The BLM received numerous comments on the proposed changes to the bonding regulations under subpart 3104, and in response to these comments, the BLM reinstated an operators' ability to post personal bonds secured with letters of credit (LOCs) and certificates of deposit (CDs). The proposed rule requested comments on if and how the BLM should adjust the minimum bond amounts in the future. After review of the comments, bond amounts will be adjusted for inflation every 10 years so that the minimum bond amounts do not become outdated as they have in the past.

The BLM deleted the existing and proposed sections governing the formal lease nomination process under part 3120.

The BLM revised the final rule to clarify that it will consider the preference criteria in § 3120.32 as part of the scoping process and will apply the criteria after the conclusion of scoping but before issuing the draft NEPA document for the lease sale, consistent with the BLM's existing policy and implementation of IM 2023-007, Evaluating Competitive Oil and Gas Lease Sale Parcels for Future Lease Sales.^[4]

The BLM also revised the final rule to extend an approved APD's term based on a lease suspension.

These revisions are discussed in more detail in the Section-by-Section Discussion.

B. Section-by-Section Discussion

Sections that did not receive any comments, or that only received comments in support of the proposed changes, are not discussed in this Section-by-Section analysis and are adopted in the final rule as proposed. In addition, throughout the final rule, the BLM replaced the words “he,” “she,” or “he/she” with the appropriate title or entity to comply with Executive Order 13988, Preventing and Combating Discrimination on the Basis of Gender Identity or Sexual Orientation.

1. Section-by-Section Discussion for Changes to 43 CFR Part 3000

Section 3000.5 Definitions

The BLM received a number of comments on the definition of the terms “Acreage for which expressions of interest have been submitted,” “Person,” and “Surface Management Agency.”

With respect to the phrase “Acreage for which expressions of interest have been submitted,” a comment stated the BLM should change the definition to “acreage that is identified in an EOI on land eligible and available for leasing” to ensure that the BLM accurately determines which EOIs have been properly submitted. No further changes are made to the final rule as the definition already states, “and for which the BLM may lawfully issue an oil and gas lease.”

Comments on the term “Person” recommended that the BLM use the definition in the Federal Oil and Gas Royalty Management Act, 30 U.S.C. 1702, to avoid any unnecessary confusion. The BLM adopts this recommendation and has revised the definition of the term “person” in the final rule accordingly.

Comments on the term “surface management agency” focused on the assertion that the definition improperly required the BLM to obtain consent from other agencies within the DOI in order to lease lands managed by those agencies, and therefore, that the BLM should not adopt the proposed changes to this definition. Based on these comments, the BLM made additional changes to § 3101.51 to provide that public domain and acquired lands that are open to the operation of the Mineral Leasing Act will be leased only with the consent of the surface managing agency, which, upon receipt of a description of the lands from the authorized officer, can report to the authorized officer that it consents to leasing with stipulations, if any, or withholds consent or objects to leasing.

Section 3000.40 Appeals

The existing § 3000.4 details the appeal rights and exceptions for parts 3000 through 3930. The BLM received suggestions that this section be amended to include State Director Reviews, with an option to further appeal to the Interior Board of Land Appeals (IBLA). The commenters asserted that, without the intermediary appeal to the State Director, there would effectively be no opportunity to appeal in light of average times for IBLA decisions. The BLM does not believe any change to this section is needed. Decisions that are signed at the state office level, which are usually decisions that affect the administration of a lease under parts 3100 and 3120, are signed on behalf of the State Director, meaning that State Director review is not applicable. In addition, 43 CFR subpart 3165 already states that onshore oil and gas operational decisions made under the authority of part 3160 are subject to the State Director Review process and any decision of the State Director is appealable to the IBLA.

Section 3000.41 Severability

This is a new section that the BLM has added in response to comments. The BLM received comments suggesting that it should include a severability clause in the final rule similar to that found in the BLM's realty regulations (43 CFR 2801.8). The final rulemaking adopts this recommendation by adding a new section addressing severability. This section will read, “If a court holds any provisions of the regulations in parts 3000 through 3180 or their applicability to any person or circumstances invalid, the remainder of these rules and their applicability to other people or circumstances will not be affected.” The BLM published the proposed rule, in large part, to address the changes required by the IRA, various reports by the GAO and OIG, and the Department's report in response to section 208 of E.O. 14008. Those sections implementing the IRA can and do function separately from those sections proposing new bonding amounts or the competitive leasing preference criteria.

One commenter stated that the courts will determine if a provision is or is not severable from the rule. The comment is correct in that a court will ultimately determine whether portions of the rule can be severed from others in the event a court determines a provision was improperly promulgated. This section is designed to aid that review by demonstrating that the BLM intends the various components of the rule, with various provenances and independent functions, to continue to operate even if one or more of the provisions is declared unlawful.

Section 3000.50 Limitations on Time To Institute Suit To Challenge a Decision of the Secretary

The existing § 3000.5 reiterates the 90-day statute of limitations for judicial challenges to certain BLM decisions under the MLA. The BLM received comments on this section suggesting that the BLM clarify that the regulation does not apply to claims brought under statutes other than the MLA. The final rule does not adopt this recommendation, as this section also applies to other minerals management programs, such as mining claims, which are managed under the general mining laws (see part 3800).

Section 3000.60 Filing of Documents

The existing § 3000.6 specifies where and when documents filed under these regulations must be submitted and provides for filing by electronic means in addition to the hard copy or delivery service, as was previously authorized. Commenters generally supported the proposed changes to this section. Commenters suggested revising the provision to include a requirement that each BLM office designate an email address for filing, and that an e-filing should be deemed timely if it is received by 11:59 p.m. local time in the appropriate BLM office. These changes were recommended to ensure that the appropriate official receives the e-filing and to avoid any risk of default as a result of e-filing with the wrong person in a BLM office. The BLM does not support the use of emails for electronic filings for many of the same reasons stated in the comment, i.e., the potential to be directed to the wrong person and/or wrong office. In addition, the BLM will not incorporate the recommendation to state a specific local time, since the time by which a filing needs to be made is already addressed in 43 CFR 1821.11. The regulation at 43 CFR 1821.11 is entitled, “During what hours may I file an application?” and specifically states, “You may file applications or other documents or inspect official records during BLM office hours. Each BLM office will prominently display a notice of the hours during which that particular office will be open. Except for offices which are open periodically, for example, every Wednesday or the 3rd Wednesday of the month, all offices will be open Monday through Friday, excluding Federal holidays, at least from 9 a.m. to 3 p.m., local time.” Those instructions necessarily depend upon and encompass the local time at particular BLM offices.

Section 3000.100 Fees in General

The existing § 3000.10 provides general information on the types of fees the BLM may assess, how the fees are calculated, when the fees must be paid and how and when the BLM will adjust any fees. The BLM received a comment recommending a change to paragraph (c), which addresses adjustment of fees, recommending that any adjustments to fixed fees be subject to notice and comment. The BLM declines to make this change as further explained in the discussion of § 3000.120 below.

Section 3000.120 Fee Schedule for Fixed Fees

The existing § 3000.12 lists the fixed fees that must be paid for each transaction requiring a fixed fee and includes transactions that previously did not require a fee, such as the designation of a successor operator; unit agreement applications; subsurface storage agreement applications; unit agreement expansion applications; and formal lease nominations. The final rule removes the formal lease nominations process, consistent with the changes made under § 3120. The BLM received several comments on this section. Some comments supported the BLM's proposal to incorporate processing fees for new actions that were not previously subject to a fee, stating that the fees were appropriate given the BLM's limited resources, or stating that the proposed fees were not sufficient to cover the BLM's costs. Other comments opposed the increased fees, asserting they were excessive, disproportionate, unwarranted, and designed to be a deterrent to Federal oil and gas leasing activities. In addition, some commenters stated that the analysis in the preamble to the proposed rule failed to comprehensively analyze the BLM's fee system, and, specifically, failed to compare the fees to the increased bonus bids, rentals, and bonding. Another comment objected to the application of the new filing fees, royalty, and rental provisions to leases sold before the enactment of the IRA but issued after the IRA.

The preamble to the proposed rule outlined the processing steps considered by the BLM in calculating each of the fees. The general comments only criticized the processing steps associated with the BLM's review of a competitive lease application fee, as discussed below. No comments criticized the processing steps for the other application fees; therefore, the BLM will implement the proposed fixed filing fees as stated in the preamble to reimburse the BLM for its processing costs. With respect to the fixed filing fees, the preamble specifically stated that the BLM would not charge a new fixed filing fee under this rule for processing a document that the BLM received before the effective date of the rule. Documents submitted before the effective date of the final rule will be processed based on the fee that was in effect when the document was submitted.

One comment recommended that the competitive lease application fee, which includes the cost for the BLM to undertake any necessary NEPA review, should not be a fixed fee and instead should be determined on a case-by-case basis under § 3000.110, or, alternatively, that the cost should be fixed but that the applicant should have the option to request a case-by-case fee determination to establish a fee for a particular lease application. Although the BLM understands the impetus for suggesting that the fee be determined for a particular lease, the BLM cannot adopt the proposed change, because the NEPA analysis prepared for each lease sale covers all of the parcels offered in a given sale and is not for each individual parcel. Moreover, the competitive lease application fee is collected after the NEPA review has been completed, and after the lease sale has been held. Therefore, the applicant would not be able to help pay for the preparation of any BLM NEPA document before performing any case processing on a parcel-by-parcel basis.

Other comments stated that the BLM should charge fixed filing fees for compensatory royalty agreements and communitization agreements (CAs). The final rule includes a fixed fee for compensatory royalty agreements under ROW pursuant to subpart 3109 where the processing steps are the same for leases. The BLM added the following clarifying language to this provision in the final rule: “Leasing and compensatory royalty agreements applications under right-of-way pursuant to subpart 3109.” The BLM does not adopt the recommendation to require a fixed filing fee for CAs. The BLM explained in the preamble to the proposed rule that new fixed filing fees were considered for Federal CAs (§ 3105), Federal participating area applications (§ 3180), and royalty rate reduction applications (§ 3103), but it ultimately declined to propose these fees due to the low value and the public benefit related to these items.

The BLM received suggestions that the Bureau clarify requirements for the fixed filing fee for designation of successor operator for Federal agreements, such that the fee would not be required when a successor operator is designated for contracted unit agreements that do not contain Federal lands. The BLM adopts the suggestion and has revised the Processing and Filing Fee table in this section of the final rule to include the following language: “Designation of successor operator for all Federal agreements, except for contracted unit agreements that contain no Federal lands.”

The BLM also received several comments stating the BLM erred in adding the fee for EOIs to the fixed filing fee table, because these fees are adjusted for inflation every year; and section 50262(d) of the IRA expressly authorizes the Secretary to only adjust the EOI fee “not less frequently than every 4 years . . . to reflect the changes in inflation.” The BLM concurs with this comment and has moved the EOI fee to the new § 3103.1(a) where it will be adjusted based on inflation every 4 years.

Another comment stated that the BLM did not explain its authority to impose an annual inflation adjustment and that for the annual inflation adjustment, the BLM must re-apply all of the factors set out in section 304(b) of FLPMA, make a new determination as to whether the fee warrants an adjustment, and similarly codify the determination via rulemaking every time a fee is adjusted. A similar comment asked the BLM to consider the disproportionate impact continued increases have on the total cost to develop Federal minerals.

Section 304 of FLPMA, 43 U.S.C. 1734, authorizes the BLM to establish fees intended to reimburse the government for reasonable costs and authorizes the Secretary to change or abolish such fees. The BLM establishes fees based upon the reasonableness factors at section 304(b) of FLPMA, which include “actual costs (exclusive of management overhead), the monetary value of the rights or privileges sought by the applicant, the efficiency to the government processing involved, that portion of the cost incurred for the benefit of the general public interest rather than for the exclusive benefit of the applicant, the public service provided, and other factors relevant to determining the reasonableness of the costs.” Once the BLM establishes a fee, the BLM adjusts the fees for inflation annually to effectively keep fees in line with current costs. This process comports with the broad authority given to the BLM in section 304 to set reasonable fees. The BLM did not propose changes to this method, or how the fees are adjusted annually for inflation in this proposed rule. The BLM will not use an alternative method for annual fee adjustments as it would require collecting data periodically for each fee, which is inefficient, costly, and impractical. However, as recommended by the GAO,^[5] the BLM did review the six factors, commonly known as “FLPMA reasonableness factors” in section 304(b), to account for changes in the leasing process since the fees were initially set. For the proposed rule, the BLM: (1) contacted each office with this type of application (the 10 state offices or all of the 40 field/district and state offices depending on the application type); (2) requested the offices to provide the average processing time for each type of application and the employee completing this work; (3) received the estimates from each office; (4) calculated the weighted average for each type of application; (5) reviewed the monetary value of the right or privilege that the applicant seeks; (6) evaluated how efficiently the BLM processes a document based upon the processing times; (7) reviewed the public benefit factor for the application; and (8) reviewed the public service factor for the application. The preamble to the proposed rule reflects this analysis of its fixed filing fees. Without the inflation adjustment that has existed since 2005, the BLM would instead be required to complete the same burdensome, eight step review under FLPMA for every subsequent update.

Furthermore, to verify the accuracy of the BLM's method for determining fees, the BLM reviewed a common oil and gas fixed filing fee—assignments and transfers—which has not experienced changes to the process since 2005. The BLM intentionally selected the assignment and transfer fixed filing fee as the most representative filing fee to review because (1) assignments and transfers are the most common application received by the BLM; (2) the other applications that require filing fees are more rarely used; and 3) all state offices are familiar with the assignment and transfer application. After completing the review of the assignment and transfer fixed filing fee for the proposed rule, the BLM compared the outcome of that review with the inflation adjustments (86 FR 54636 (Oct. 4, 2021)). The review identified that the assignment and transfer fixed filing fee should be $100 in FY2022 based upon the FLPMA factors. This amount matched the inflation-adjusted fixed filing fee for FY2022, which was also $100. Therefore, the FY2022 inflation adjustment matched the calculated fixed filing fee based upon the FLPMA factors in FY2022. If the BLM's review process changes for an application, and thus there is the potential that reasonable costs may change outside of the cost of inflation, the BLM would update the fixed filing fees based upon the FLPMA factors and provide the opportunity for notice and comment.

Finally, the BLM requested comments related to changing its current process, which requires publishing the annual fee adjustments as a final rule in the Federal Register and then incorporating the new fees in the Code of Federal Regulations (CFR). Instead, the BLM proposed to post the updated table on the BLM's web page with the historical fees posted in the same location.

Commenters stated that since the fixed filing fees are not subject to appeal, the BLM should remove this provision; that adjustment of the fees should include a notice and comment period; and that the BLM should continue to publish the annual fee adjustments in the Federal Register .

The BLM is updating the final rule to state that the BLM will “announce annually in the Federal Register ” revised fees, as well as posting the fees to the website. The BLM initially promulgated the fixed filing fees in 2005 after conducting a notice-and-comment rulemaking. Each year since, the fees have been adjusted for inflation through a final rule without further notice and comment. This is because the BLM included the method used to calculate inflation in its proposal in 2005, and the same method has been used for each subsequent increase. As stated in the proposed rule, the BLM will follow this same procedure for any new fees. For example, the BLM will: (1) publish a proposed rule with information on the proposed fee and propose to adjust the fee based on inflation; (2) review the comments received on the proposed rule for the new fixed filing; (3) publish a final rule with the new fixed filing fee; and (4) adjust the new fixed filing fee based upon inflation without notice and comment for any subsequent increases. This process negates the need for notice and comment every time the BLM adjusts the fee solely for inflation. These periodic inflation adjustments are not subject to appeal.

Additionally, as stated above, if the BLM's review process for any application changes, and thus there is the potential that the BLM's reasonable costs may change outside of the cost of inflation, the BLM would review the FLPMA factors to update the fixed filing fees and provide the opportunity for notice and comment.

The BLM adopts the proposed change to publish the fixed filing fees on the BLM's web page and to publish the adjusted fees each year in the Federal Register to provide additional public notice. The table in this section will still contain a list of the types of applications that require a fixed filing fee, but the fee itself will be removed from the table so it does not become outdated as each subsequent adjustment for inflation is made. In addition, the BLM modified the regulatory text to reflect that the table in 3000.120 does not include the actual fee amounts. When fees are added, deleted, or need to be adjusted due to changes in the processing steps for the application or a change to the method to calculate the inflation adjustment amount, the BLM will do so by a notice and comment rulemaking.

Section 3000.130 Fiscal Terms of New Leases

The provisions within § 3000.130 only apply to oil and gas leasing; therefore, the BLM moved the fiscal terms for new leases to a new section under subpart 3103 for Fees, Rentals and Royalty in the final rule in response to comments stating that failure to specify the rental amounts, within the context of the regulation on annual rentals, would be a disservice, detracting from the regulations' value as an orderly source for basic information.

2. Section-by-Section Discussion for Changes to 43 CFR Subpart 3100

The BLM received a recommendation to reference its legal authority and duties under FLPMA and NEPA in all authority citations in the regulation. The BLM concurred in part and added a full reference to FLPMA into the authority introduction to the regulatory text, which changes “43 U.S.C. 1732(b), 1733, and 1740” to now state, “43 U.S.C. 1701 et seq. ” This update was only made to part 3100 since the other authority references already include a reference to FLPMA. The BLM did not add NEPA into the authority section, as NEPA does not provide the BLM with any authority for leasing.

Section 3100.3 Authority

The existing § 3100.0-3 sets out the BLM's authority for leasing on various types of lands, such as public domain land and acquired lands. During the comment review period, the BLM decided to add clarifying language in the final rule on Wild and Scenic Rivers to comply with the Wild and Scenic Rivers Act (16 U.S.C. 1280). Therefore, the final rule makes the following adjustments to the language for the Wild and Scenic Rivers exceptions listed under both Public Domain and Acquired lands: “subject to valid existing rights,” is moved to the beginning of the sentence to clarify that this applies to all types of National Wild and Scenic Rivers Systems lands. The following clarifying language is added to the end of the sentence “lands within designated Wild and Scenic Rivers System that constitute the bed or bank or are situated within one-quarter mile of the bank of certain rivers designated as scenic or recreational, and in some cases, designating legislation may apply a different boundary extent. Lands within the National Wild and Scenic Rivers System that constitute the bed or bank or are situated within one-half mile of the bank of any river designated a wild river by the Alaska National Interest Lands Conservation Act (16 U.S.C. 3148).”

The BLM received a comment on paragraphs (a)(1) and (b)(1), suggesting that the BLM change the phrase “are subject to lease” to “may be subject to lease” to align with the discretion afforded the Interior Secretary under the MLA, 30 U.S.C. 226(a), that lands “may be leased.” The final rule does not adopt this recommendation. In 1920, Congress enacted the MLA to facilitate the exploration and development of oil and gas and other federally owned minerals. The MLA specifies the lands that are subject to the statute, and then provides discretion to the Secretary to determine which of those lands may be leased. The first step in exercising that discretion is making decisions in the BLM's resource management plans under FLPMA. The BLM declines to change this phrase so as not to confuse this section on the authority to lease, including the exceptions listed under both public domain and acquired lands, where there is no discretion to lease ineligible lands.

A comment recommended that paragraphs (a)(2) and (b)(2) rely solely on the subhead—Exceptions—to indicate what the provisions in the sections mean and, for clarity, that the BLM should consider inserting language to the effect of: “The following lands are not subject to lease.” The final rule adopts this recommendation.

The BLM received a comment requesting that the BLM identify additional exceptions for both public domain and acquired lands. This exception would specify that the BLM cannot lease lands identified in the land use plans as unavailable for oil and gas leasing or otherwise determined by the authorized officer to be inappropriate for leasing to protect other multiple use resources and values. The final rule does not adopt this recommendation. As stated in the proposed rule, the purpose of this section is to describe lands subject to leasing, and changes proposed to this section were made to provide clarity and to conform the regulations to exceptions identified in various other laws. The change requested by the comment does not meet this requirement, as the comment addresses discretionary decisions regarding leasing. Moreover, the concerns represented by this comment are already addressed in the BLM's land use planning process, NEPA reviews, and other processes that identify suitable areas for leasing.

Section 3100.5 Definitions

The existing § 3100.0-5 sets out the definitions applicable to part 3100. The BLM added new proposed definitions for “competitive auction,” “exception,” “modification,” “oil and gas agreement,” “qualified bidder,” “qualified lessee,” “responsible bidder,” “responsible lessee,” and “waiver.” The BLM received several comments on this section requesting additional definitions for “bad actors,” “current land use plan,” “exclusion area,” “mitigation,” “permanent impairment,” and “preferred leasing area.” Since these terms are not used in parts 3000, 3100, and 3120, the BLM has not adopted these recommendations.

In addition, a comment recommended adding a definition for “restoration.” The BLM declines to make this change given that § 3104.10, where this term is used, specifically states that the restoration is to be “in accordance with, but not limited to, the standards and requirements set forth in 43 CFR 3162.3 and 3162.5 and orders issued by the authorized officer.” This flexible definition does not warrant modification at this time.

Some comments recommended that the BLM expand the definitions in this section to include the terms “eligible” and “available.” The BLM declines to define those terms by regulation at this time and may revisit the issue in future rulemakings.

One commenter requested that the BLM remove the definition for “modification” to avoid confusion where this term is used in contexts other than changes to lease stipulations. The BLM agrees there is a potential for confusion given the numerous different contexts in which the word “modification” is used and has therefore revised the definition to clarify that it only applies to lease stipulations. For similar reasons, the BLM has made changes to “exception” and “waiver” in the final rule. Each definition now includes the phrase “as used for lease stipulations.”

A comment recommended modifying the term “oil and gas agreement” to reflect the fact that an agreement may in some instances include unleased lands. The BLM adopts this recommendation.

The BLM received a comment suggesting that the term “operator” should be revised to explicitly state that the operator holds operating rights and thus has the same obligations as the operating rights owners to plug wells and remediate the well sites. The BLM does not concur with the recommendation, as an operator could be a lessee and may or may not own operating rights. The current definition for “operator” states, “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.” Therefore, the BLM kept the existing definition of “operator” in the final rule.

The BLM received several comments on the proposed definitions for the terms “qualified bidder,” “qualified lessee,” “responsible bidder,” and “responsible lessee.” Those comments that supported the inclusion of these new definitions suggested modifications that would also exclude from those terms anyone with a history of failing to make timely rental or royalty payments; failing to meet a diligent development obligation; maintaining a significant number of inactive wells; engaging in repeated or ongoing environmental, worker safety, or labor violations; violating State reclamation requirements on other leases; or engaging in lease speculation, such as failing to drill approved APDs, or holding large quantities of undeveloped leases.

The BLM declines to include this language, which is too vague and overlooks existing enforcement tools. For example, when a company fails to make timely payments, such as rental payments, the Act already dictates that the lease will automatically terminate through operation of law. In addition, if a company fails to make royalty payments after being notified such payments are due and exhausting its legal remedies, the Office of Natural Resources Revenue (ONRR) may refer an entity to the Federal suspension and debarment list. It is the BLM's policy to check SAM.gov (the Federal suspension and debarment site) before issuing a lease or approving an entity to acquire a lease interest through an assignment or transfer of operating rights. The BLM may also take enforcement actions when lessees violate the terms of a lease, including environmental, worker safety, or labor standards. The BLM does not agree that a company's decision to not drill a well or develop leases should determine if they are responsible or qualified, because such fact-specific business decisions do not, by themselves, determine whether a lessee has acted irresponsibly or incompetently. The BLM generally lacks the capacity to investigate and evaluate State law reclamation violations; however, the current definition for responsible lessee provides for the lessee to be in compliance with statutes applicable to oil and gas development. While it is not the BLM's practice to investigate a person's compliance with State law reclamation requirements, the BLM would not ignore a person's noncompliance when it has been brought to the BLM's attention for consideration if a person is a responsible lessee prior to lease issuance.

Other comments suggested that, in connection with these definitions, the BLM should: (1) create a public registry of individuals and companies currently identified as not being responsible bidders and/or lessees, and make the list of “Entities in Noncompliance with Reclamation Requirements of section 17(g) of the MLA” public and updated on a regular basis; (2) clarify, in § 3108.30, that leases are subject to cancellation if the lessee is found not to be a “qualified lessee” or a “responsible lessee”; and (3) implement a system that allows States, local government, Tribal governments, and individuals to report behavior or conduct that warrants investigation.

The BLM updates the list of “Entities in Noncompliance with Reclamation Requirements of section 17(g) of the MLA” on an as needed basis, and then forwards the names of the entities to the Federal Government's suspension and debarment program. SAM.gov is a publicly available website. In turn, when a company returns to compliance, the BLM notifies the suspension and debarment program that the entity should be removed from SAM.gov. The cancellation provisions in § 3108.30 contains language for entities that fail to comply with the laws and regulations. The BLM also notes that any entity or individual can contact the BLM to report behavior or conduct that warrants investigation, and the BLM declines to create a separate regulatory system for this purpose at this time.

The BLM also received comments regarding the new definitions for “qualified bidder,” “qualified lessee,” “responsible bidder,” and “responsible lessee.” One comment suggested that the term “qualified bidder” does not take into account that brokers or non-operating partners bid on leases, and that the new term could substantially impede bidding if it were to mandate that bonding or similar bidder requirements that historically only applied to a lessee be in place prior to bidding. The BLM considered the involvement of brokers or non-operating partners when it drafted these definitions, which is evidenced by the separate definitions for “qualified bidder” and “responsible bidder”, as well as to whom the lease is issued (“qualified lessee” and “responsible lessee”), since these may not be the same entities. In addition, there is no mandate, in either the proposed or final rules, for bonding or similar requirements prior to bidding.

Another comment suggested that the BLM should clarify in the definitions (and in proposed § 3102.51) that it will continue to adhere only to the factors in MLA section 17(g), 30 U.S.C. 226(g), in determining who may hold a lease. The BLM disagrees. The MLA, 30 U.S.C. 226(b)(1)(A), refers to responsible qualified bidders and specifically states that: “[a]ll lands to be leased which are not subject to leasing under paragraph (2) shall be leased as provided in this paragraph to the highest responsible qualified bidder by competitive bidding under general regulations in units of not more than 2,560 acres, except in Alaska, where units shall be not more than 5,760 acres.” The MLA also states that “[t]he Secretary shall accept the highest bid from a responsible qualified bidder which is equal to or greater than the national minimum acceptable bid, without evaluation of the value of the lands proposed for lease.” The BLM's regulations reiterate and rely on these statutory terms. Specifically, because a person who bids on a lease is not necessarily the same person to whom the lease is issued, it is appropriate to include definitions for “qualified bidder” and “responsible bidder,” as well as definitions for whom the lease is issued, i.e., “qualified lessee” and “responsible lessee.”

Another comment on the definitions for “responsible bidder” and “responsible lessee” questioned the inclusion of the phrase “history of noncompliance” with applicable regulations and lease terms, stating that the meaning of a “history of noncompliance” is unclear. The comment suggested that the phrase could be construed broadly to mean that, if a person ever was found to have been in noncompliance with the terms of its Federal oil and gas lease or applicable regulations, that person could be precluded from obtaining future Federal lease interests, even if they corrected the alleged noncompliance or disputed the alleged violation and won.

The BLM agrees the term is imprecise and has revised the definitions by changing the phrase “does not have a history of noncompliance” to “is in compliance.” A lessee would not be precluded from obtaining future Federal lease interests if it corrected the noncompliance. A lessee's noncompliance ends: (1) when the entity has paid all civil penalties and performed the required reclamation; (2) the BLM accepts the required reclamation performed under contract, and the entity reimburses the U.S. for all costs associated with the required reclamation, including the costs associated with the BLM's issuing and overseeing the performance contract during its life; and (3) if the bond is collected and is insufficient to cover the total costs, the entity pays the entire amount due to the U.S. and the BLM accepts compliance. This is outlined in the BLM handbook H-3120-1, Competitive Leases, Appendix 4.^[6]

The BLM proposed to separate the definitions for “assignment” and “sublease” from the current definition of “transfer” in the existing regulations. One comment stated that a greater understanding of the differences between assignment and transfer of operating rights is long overdue. Another comment stated that the BLM's definitions for “assignment” and “transfer” have corresponding, but different, meanings; that the Bureau of Ocean Energy Management (BOEM) recently issued a proposed rule stating that the terms are interchangeable; and that the BLM should ensure consistency and clarity in use of these terms between the two bureaus regulating Federal oil and gas leasing onshore and on the Outer Continental Shelf. The BLM reviewed its definitions and believes the two terms are distinct and should remain separate. An assignment of record title conveys both record title and operating rights and is limited under § 3106.10 to certain restrictions that do not apply to transfers. The BOEM regulations do not have this distinction, which is why the BLM is retaining the separate definitions.

Comments recommended adding a definition for “unnecessary or undue degradation.” The BLM declines to define this phrase in this rule because it is used only once, in § 3120.32, and such a definition would benefit from public input before promulgation. As used in § 3120.32, the phrase reflects the ordinary meaning of the terms used in section 302(b) of FLPMA.

Section 3100.22 Drilling and Production or Payment of Compensatory Royalty

The existing § 3100.2-2 addresses drainage protection, an express covenant of the lease agreement. Under the terms of Federal leases, the lessee has the obligation to protect the leased land from drainage by drilling and producing any well that is necessary to protect the lease from drainage, or, in lieu thereof and with the consent of the authorized officer, by paying a compensatory royalty assessment to the Federal government. The BLM did not propose changes to this section but did receive a comment stating that the BLM should consider using this opportunity to amend this section to (1) clarify when drainage involving two Federal leases with different fund distribution codes occurs; and (2) specify that the lessee may resolve drainage by creating a federally approved agreement for sharing production among the affected leases. These proposals already reflect current policy; refer to the BLM Manual Section 3160, Drainage Protection Manual.^[7] The Drainage Protection Manual provides guidelines, standards, and procedures to prevent the loss of oil and gas resources and any resulting loss of royalty revenues from drainage on leased and unleased public domain, acquired, and Indian lands. The BLM does not believe changes are needed to this section since these proposals are already allowed under the current regulations to address possible solutions to drainage.

Section 3100.40 Public Availability of Information

The proposed rule stated that the BLM was considering adding language that would provide notice that names and addresses of the nominator, lessee, operating rights holders, and operators would be made public on the BLM's Mineral & Land Records System (MLRS). The BLM's lease and agreement case files are already public records, and any change to the existing § 3100.4 would merely reflect the BLM's current practice. The BLM received comments supporting additional changes to this section, stating that it should be made clear to nominators, lessees, operating rights holders, and lessees that their identities will be made public through the MLRS rather than the current practice, which requires a member of the public to be at the BLM state office to submit a paper request to document the case file. The BLM will continue to release the names and addresses of nominators, lessees, operating rights holders, and lessees to the extent allowed by the Privacy Act to ensure there is a transparent onshore leasing process and does not believe any further changes to this section are needed. The names and addresses of individuals were redacted from all reports, including Serial Register Pages, as a result of a recent privacy review. The redacted information only applies to individuals (MLRS personal accounts) and not companies (MLRS business accounts). Specifically, the privacy review determined that all personal accounts regardless of type of case are considered to contain Personally Identifiable Information (PII). In order to release this PII—specifically names and addresses that are collected of our applicants/interest holders—the BLM must meet two requirements. First, the BLM must establish and disclose a routine use for the information—which, in other words, is establishing that the public need and benefit outweighs the need for the protection of the privacy information and notifies that the PII may potentially be released. This has been completed by disclosing the routine uses contained in BLM System of Records Notice (SORN) LLM32 in accordance with the Privacy Act. The SORN LLM32 is for Lands & Minerals Authorization Tracking System and covers the data from both LR2000 and MLRS. Most requests made in the Information Access Center at the state offices fall under routine use number “(2) to Federal, State, or local agencies or a member of the general public in response to a specific request for pertinent information.” Second, to meet Privacy Act requirements, the BLM must be able to track who received the information, when, and for what purpose to satisfy the Privacy Act's requirement that the information was released in accordance with a “specific request for pertinent information.” A member of the public can create an MLRS account to view unredacted information. This log in method allows for the BLM to meet this requirement through a logging system.

The BLM received a comment stating that the BLM provides no justification for publishing information on all entities registered to bid during a lease sale, rather than providing this information only for issued leases. Publishing participants in oil and gas lease sales has been a long-standing Bureau policy to provide transparency in the competitive leasing process. Refer to H-3120-1 Competitive Leases handbook, published February 2013.^[8] This policy specifically states, “Names of bidders/high bidders remain confidential until the end of the sale.” In addition, each Notice of Competitive Lease Sale provides adequate notice that the names and addresses of bidders will be released and no further changes to the lease sale process are needed.

Another comment stated that the final rule should also authorize researchers to use lease and production data to analyze market-level royalty, bid, and rental rates. The comment then stated that independent, professional analysis would provide the BLM with critical data on the appropriate market-level rates for Federal mineral charges. In addition, the commenter also stated that the final rule should authorize the BLM to provide a quarterly report to the public on all revenues received from leasing and mineral production on Federal lands on a lease-by-lease basis, and as the ultimate owners of the lands and minerals being leased, the public has a right to know this information. The BLM makes lease information, including lease terms such as rental rates and royalty rates, available through the MLRS; however, because the amount of royalty is a function of production and proprietary data is confidential, the royalty amount the Federal government receives cannot be released on a lease-by-lease basis. The public may obtain general information on production data, rental, and royalty payments from the ONRR.

Section-by-Section Discussion for Changes to 43 CFR Subpart 3101

Section 3101.12 Surface Use Rights

The proposed rule revised the existing § 3101.1-2, which was originally promulgated in 1988, to provide that the BLM could impose reasonable measures under the lease terms to avoid, minimize, or mitigate adverse impacts to other resource values, land uses or users, federally recognized Tribes, and underserved communities. Those reasonable measures include site-specific minimum siting and timing parameters that the BLM may impose on lessees to protect the public interest.

The BLM received numerous comments on this section, including: (1) support for the proposed changes, and statements that the changes are critical to mitigate impacts when the relevant RMP is outdated; (2) requests for clarification that leases are contingent on NEPA analysis and not a lessee's expectation; (3) requests for clarification that a lessee's surface use rights are subject to a land use plan's term, including terms provided for by land use plans either revised or amended after a lease is issued; and (4) requests for the BLM to clarify that the agency retains its full authority to condition development and production on leases after the lease is issued in order to respond to findings of site-specific NEPA analyses or changing conditions between the time a lease is issued and when it is developed. These changes are unwarranted as the BLM has the authority to impose measures that are more stringent than those in the regulations as long as they constitute reasonable measures to minimize adverse impacts, Yates Petroleum, 176 IBLA 144, 156 (2008). Therefore, the BLM is not revising this section further based on these comments, many of which request unwarranted or unnecessary clarification or specificity that would exceed the scope of this rulemaking.

Some comments opposed the proposed changes to this section, including by asserting that: (1) distance/siting requirements could lead to the BLM exceeding its authority to regulate air quality; (2) the BLM did not reference a lease provision that grants the agency the proposed new authority to constrain or deny lease operations; and (3) the BLM should consider public welfare when determining which measures may be reasonable. The BLM has the authority to use terms and conditions under Section 6 of the standard lease form to control site-specific environmental or public welfare impacts on leaseholds, as opposed to using lease-specific protective measures in lease stipulations from the RMPs.^[9] Section 6 of the standard lease form authorizes the BLM to require “reasonable measures” to the extent that such measures would be consistent with the lessee's lease rights. The existing regulation has been misconstrued as limiting the BLM's authority to establish reasonable measures to protect resources and to establish minimum parameters within which the BLM can specify site-specific mitigating measures that are consistent with the lease rights granted a lessee.

Comments requested (1) the removal of language that arguably suggests that the BLM could require a lessee to “avoid” or “mitigate” all adverse impacts of developing mineral rights; and (2) that the final rule specify how water sources will be protected. The BLM has revised this section by clarifying that not all surface impacts must be mitigated and by clarifying the distance the BLM may require operations to be moved. The final rule strikes the words “avoid, minimize, or” since this is not needed as avoidance and minimization are integral to mitigating adverse impacts.

Some comments requested changes to require the relocation distances to be either a maximum of or be at least 1 mile and requested the BLM to prohibit new surface disturbing operations. The language in this section has been in place since at least 1988 and does not prohibit new surface disturbance. The BLM proposed to change only the minimum siting and timing parameters to account for changes in technology. The BLM declines to further increase or set a maximum parameter as this would not allow the flexibility that may be required to avoid resource conflict. The final rule amends the last sentence of the section to clarify the intent of the proposed rule. The proposed rule removed the phrase “At a minimum” from the existing regulations but retained the phrase “by more than.” The final rule is amended to state, “At a minimum, modifications that are consistent with lease rights include, but are not limited to, requiring relocation of proposed operations by up to 800 meters,”, which allows the BLM to require a lessee to relocate proposed operations by up to 800 meters to avoid a resource conflict that may not have been identified at the time the BLM issued the lease. For example, the BLM may need to move operations to avoid a sage grouse lek, a contingency that may not be encompassed by standard lease terms. In that circumstance, this provision would allow the BLM to move the operations up to 800 meters to minimize the impacts to the sage grouse lek. As stated in the 1988 final rule preamble for the existing regulations, “Similarly, the authority of the BLM to prescribe “reasonable,” but more stringent, protection measures is not affected by the final rulemaking,” see 53 FR 17341 (May 16, 1988). This section does not apply to the protection of resource values that are already addressed in lease stipulations.

Comments requested that the BLM strike the word “specific” as a modifier for “nondiscretionary statutes” that provide post-lease restrictions on surface use rights. The final rule adopts the recommendation to strike the word “specific” as a modifier to nondiscretionary statutes.

Comments stated that the language explicitly allowing a BLM officer to restrict the development of a project to proactively avoid impacts to “land users” or “underserved communities,” is improper because, the commenter contended, such language is vague and would improperly expand the BLM's authority, potentially encroach upon a lessee's lease rights, and cause uncertainty. Other comments requested that the BLM add “overburdened and” before “underserved communities” in the final rule, and that the BLM better specify procedures the BLM could use to protect multiple use standards and Native Americans' land rights in areas near reservations. For the reasons explained below, the BLM does not agree with these comments and retains its proposed language to proactively avoid impacts to “land users” or “underserved communities.”

The term “land users” is already used in the existing 43 CFR 3101.1-2 and is specifically included in Section 6 of the standard lease form. This term identifies segments of the public that use the land for recreation or for economic growth in the community. Like the term, “resource values”—which the BLM's regulations do not define—the term “underserved communities” has a straightforward and commonly understood meaning that would not benefit from elaboration here, and the BLM has an obligation under the MLA and APA to articulate a rational connection between underserved communities and the proposed operations, as modified by the BLM. Based on the above, the BLM declines to modify or remove either “land users” or “underserved communities.”

Section 3101.13 Stipulations and Information Notices

The BLM proposed to split the existing § 3101.13 into two separate provisions and add a new paragraph (a), stating the BLM would consider the sensitivity and importance of a resource when developing stipulations without regard to the restrictiveness of the stipulation.

One comment on this section recommended that the consideration of affected resources and potential uncertainty be made mandatory by substituting “shall” or “must” for “may” in the final rule text to remove any uncertainty. The BLM declines to make this change so as to maintain discretion when considering potential stipulations. The BLM requires this discretion because the BLM need not consider every potentially affected resource for each parcel. Instead, the BLM will use its discretion to determine, based on the sensitivity, importance, and any uncertainty, which resources should be considered, and will then assess whether those resources are adequately protected by stipulation.

Some comments stated that the BLM should delete the proposed paragraph (a) ^[10] , arguing that the language is subjective and would allow the inclusion of new stipulations that were not addressed in the underlying planning documents. Some comments stated that proposed paragraph (a), and in particular the phrase “without regard to the restrictiveness of the stipulation,” disregards the principle of multiple use by elevating certain uses or allows the BLM to essentially prevent oil and gas operations. Another comment recommended changing the phrase “without regard” to “along with consideration.”

As stated in the proposed rule, the BLM added this paragraph to more explicitly recognize its mandate to manage the Federal lands for multiple use. Stipulations do not prevent oil and gas operations from occurring under a lease. Rather, stipulations that allow, but control, surface use are a valuable management tool to achieve balanced multiple resource use, including oil and gas development. As stated above, the BLM retains discretion in this section and will rely on its expertise when making these site-specific decisions regarding stipulations. Consistent with these objectives, the BLM agrees that the bureau should consider the restrictiveness of a stipulation on operations. In the final rule, the BLM deletes the phrase “without regard for” and inserts instead “while considering” to recognize the BLM's mandate to manage the Federal lands for multiple use and to provide for the protection of the resources on those lands.

The BLM also received a comment on proposed paragraph (c), which specified that the BLM may attach an information notice to the lease. That comment requested that the BLM remove the last sentence in the paragraph—which reads, “Information notices may not be a basis for denial of lease operations”—because it undermines the BLM's management authority. Another comment recommended that this paragraph incorporate a requirement that information notices highlight potential conflicts with other resource values and be accompanied by full lease stipulations specifying how those conflicts will be resolved. The final rule does not adopt these recommendations, as the information notice is a method of informing lessees of requirements that may be imposed by an existing law or regulation, not of imposing new requirements.

Finally, the BLM received comments recommending the development of specific stipulations and considerations for all leases, including a no surface occupancy within 2 miles of developed recreation sites and a 1-mile no surface occupancy from key recreation areas. The BLM disagrees and declines to adopt one-size-fits-all stipulations for all leases. The BLM historically has identified the appropriate stipulations through RMPs, ensuring that the BLM ties the appropriate stipulations to the lease under consideration. That approach allows the BLM to develop and set forth lease stipulations in the land-use planning documents/RMPs so that the public is aware of the balance that will exist between environmental protection and opportunities for development of oil and gas resources in advance of offering the lands for lease.

Section 3101.14 Modification, Waiver, or Exception

This section describes the standards that the BLM will use when evaluating modifications, waivers, or exceptions. The BLM proposed changes to the existing § 3101.14 to more explicitly recognize its mandate to manage the Federal lands for multiple use and to provide for the protection of the resources on those lands. The proposed rule also split the existing provision into two components: one to address modifications prior to lease issuance and one for modifications after lease issuance.

The BLM received multiple comments on the BLM's proposed approach. For example, comments: (1) expressed concern that the language broadened the ability of surface management agencies to object to the inclusion of parcels in an oil and gas lease sale; (2) requested a revision to paragraph (a) to state that requests for modification, waivers, or exceptions would not be posted for public comment; (3) suggested the BLM should clarify that this paragraph does not alter or affect criteria for modification, waivers, and exceptions of stipulations in the BLM's RMPs; (4) suggested that the proposed rule introduced new subjective standards, such as a “major concern to the public;” and (5) recommended that the BLM should not remove the language “or if proposed operations would not cause unacceptable impacts,”, since, in the commentors' view, that edit would curtail the BLM's flexibility for addressing circumstances where the BLM's granting of the modification or waiver would not result in unacceptable impacts.

After consideration of these comments, the final rule splits paragraph (a) into two paragraphs for clarity. The first sentence in proposed paragraph (a) now appears at the end of the section in new final paragraph (d), since modifications, waivers, and exceptions to a stipulation are considered later at the APD stage, not at the leasing stage. The restructuring of this provision addresses concerns that the paragraph alters or affects criteria for modification, waivers, and exceptions of stipulations in the BLM's RMPs.

As stated in the proposed rule, the BLM removed the existing provision—allowing the granting of modifications, waivers, or exceptions to lease stipulations if the authorized officer determines that the “proposed operations would not cause unacceptable impacts”—because this authority has been overused ^[11] and has potentially led to unnecessary adverse environmental impacts.

The BLM has concluded that it is appropriate to exempt situations based on time-sensitive information from the review requirement. For example, if a survey is completed for nesting raptors and it can be confirmed that there are no raptors present, then an exception from a timing stipulation based on the presence of nesting raptors would be appropriate. However, if the 30-day review period applied, the conditions would no longer be in effect to support the exception. Final paragraph (a), which applies to lease terms and stipulations, now states, “If the authorized officer determines that a change to a lease term or stipulation is substantial or a stipulation involves an issue of major concern to the public, except time-sensitive exceptions based on verified data, the changes will be subject to public review for at least 30 calendar days.” As stated in the proposed rule, the BLM would consider a change to the lease terms to be substantial if the change would have an important, considerable, consequential, major, or meaningful effect on the environment that was not previously considered, thus requiring public notification (30-day public review) of a lease term or stipulation.

The language in this section does not broaden surface management agencies' ability to object to the inclusion of parcels in an oil and gas lease sale, because lands requiring the consent of other surface management agencies is addressed under § 3101.51. This rulemaking does not introduce new subjective standards. Language such as a “major concern to the public” appears in existing regulations and has not caused issues.

One commenter stated paragraph (b) presents potential disruption to the competitive lease sale process as all lease conditions or stipulations must be disclosed prior to a lease sale. The BLM revised this paragraph to reflect IBLA decisions, which have stated that if a lease is issued without prior notice of an additional stipulation, the stipulation is not binding on the potential lessee and is without effect in the absence of the potential lessee's acceptance of the stipulation, see Emery Energy, Inc, 64 IBLA 175 (1982). While this rarely occurs, the purpose of this section is to allow the BLM to correct errors made when preparing the Notice of Competitive Lease Sale. Moreover, the MLA vests the Secretary with broad discretion to decide, up until the time of lease issuance, whether particular parcels of Federal land “may be leased” for oil and gas development, see 30 U.S.C. 226(a). Under the final rule, the BLM may decide not to issue a lease if the modification of a stipulation could increase the value of a parcel. For example, if the Notice of Competitive Lease Sale incorrectly listed a parcel as subject to a no-surface-occupancy stipulation, and it is then realized that the parcel should not have been subject to that limitation, but this mistake is not caught until after the sale, this could increase the value of the lease. To ensure a fair return to the public, the BLM would decline to issue the lease and would offer the parcel in a future lease sale. The competitive bidding process would ensure that the BLM receives the appropriate bid for the parcel with the modified stipulation.

One comment on paragraph (c) recommended striking the phrase “was inadvertently omitted,” and adding “to comply with a nondiscretionary legal requirement, or to address an adverse effect that was not reasonably foreseeable at the time of lease issuance or whose analysis was otherwise expressly deferred to the site-specific proposal stage,” and changing “may” to “will” in reference to lease cancellation. These recommendations would substantially change the meaning of the paragraph, which was intended to address situations when the BLM inadvertently omits a stipulation when preparing parcels for a lease sale. The intent of the modified language is to reflect IBLA decisions on this issue. The BLM has not made any changes based on this comment.

Section 3101.21 Public Domain Lands

The BLM did not propose any changes to the existing § 3101.2-1; however, the BLM received a comment stating that the BLM should not only rely on the section title to convey to readers that the language in the section applies to public domain lands (whereas the next section applies to acquired lands). The BLM concurs with this recommendation and inserts in final paragraph (a) “on public domain lands.”

Section 3101.22 Acquired Lands

The BLM did not propose any changes to the existing § 3101.2-2; however, the BLM received a comment stating that the BLM should not only rely on the section title to convey to readers that the language applies to acquired lands. Another comment stated that the BLM should specify that the acquired lands limitation is separate from, and in addition to, the limitation for public domain lands. The BLM concurs with these recommendations and inserts in final paragraph (a) “on acquired lands” as well as “separate from, and in addition to, the limitation for public domain lands.”

Federal Lands Administered by an Agency Other Than the Bureau of Land Management

Because of other proposed changes to part 3100, the BLM proposed to redesignate and consolidate the provisions under this heading. The BLM received several comments suggesting that the new definition for “surface management agency” under § 3000.5 of this chapter, which includes Interior agencies such as the Fish and Wildlife Service and the Bureau of Reclamation, conflicts with and causes confusion with the provisions under this heading. The BLM concurs and changes the title of this heading from “Federal Lands Administered by an Agency Outside of the Department of the Interior” to “Federal Lands Administered by an Agency Other than the Bureau of Land Management.”

Section 3101.51 General Requirements and Section 3101.52 Action by the Bureau of Land Management

The BLM received numerous comments on proposed revisions, which, collectively, would replicate several paragraphs in the existing regulations requiring the BLM to seek and, in some cases, obtain the consent of surface management agencies prior to leasing acquired or public domain lands into one paragraph. Some comments supported the change. Several comments opposed the change, asserting that it expands the authority of some surface managing agencies, such as the Fish and Wildlife Service and the Bureau of Reclamation, beyond that which is provided under the applicable statute.

The BLM disagrees that the proposed change improperly expands the authority of certain surface management agencies, such as the Fish and Wildlife Service. Instead, this change merely consolidates and clarifies the BLM's duties with respect to prohibitions provided elsewhere in statute or regulation. The BLM has a longstanding practice of consultation with all Federal surface management agencies before authorizing subsurface mineral leasing. For example, the existing regulation at 43 CFR 3101.7-1 recognizes that in some cases the Secretary may lease over the objection of the surface management agency and in other cases the Secretary may not. Moreover, even where consent is statutorily required, such as on Forest Service lands, the MLA directs that the Secretary of the Interior the Secretary of the Interior ultimately must apply their independent judgement before any leasing may occur. The proposed regulation merely supplies the BLM with the uniform procedures necessary to facilitate these preexisting prohibitions and grants of discretion; it does not enlarge or restrict the BLM's authority. The BLM has added a clause to § 3101.52(b) to clarify that a lack of consent or concurrence will preclude leasing only where provided by law. The BLM has also made certain minor changes for clarity.

Commentors stated that, under the MLAAL, 30 U.S.C. 352, only the head of an executive department has the authority to consent to leasing covered by that statute, such that it necessarily does not embrace “consent” by subdivisions of the DOI. The BLM agrees, particularly because the Department's sub-agencies ordinarily enjoy their authority only be virtue of delegation from the Secretary. As set forth above, the proposed text does not alter the balance of authority and discretion among agencies within the Department, but instead simply clarifies that the BLM shall, as a procedural matter, confer with surface management agencies.

Section-by-Section Discussion for Changes to 43 CFR Subpart 3102

Section 3102.20 Non-U.S. Citizens

The BLM proposed to revise the existing § 3102.2 to remove the reference to the outdated term “alien.” The BLM received a comment stating that this section should be amended to include more stringent language that would require prospective, non-U.S. citizen bidders, lessees, or interest holders to submit to the BLM a certification of compliance with Federal foreign ownership laws and procedures, including the final rule from the Office of Investment Security, Department of the Treasury, implementing the provisions relating to real estate transactions in section 721 of the Defense Production Act of 1950, as amended by the Foreign Investment Risk Review Modernization Act of 2018, prior to the BLM granting such entities a lease. The BLM declines to adopt this change, which is unnecessary. In 1982, the BLM eliminated the requirement for entities to submit documents substantiating their qualifications to hold a lease or an interest in a lease and now requires entities to certify their compliance, including those relating to foreign investment in Federal land, on the lease or assignment application. Any false statements on these documents are subject to the criminal sanctions in 18 U.S.C. 1001 (see 47 FR 8544, February 28, 1982).

Section 3102.40 Signature

The BLM proposed changes to the existing § 3102.4 to clarify that it applies to all applications submitted to the BLM and to allow for electronic signatures. The BLM received a comment in support of the proposal to remove paragraph (b) from this section. The commenter also said the BLM erred, as the submission of three hard copies of any transfer of record title or operating rights is required by the MLA. 30 U.S.C. 187a. The BLM agrees and makes the appropriate changes to the final § 3106.41. The BLM declines to reinstate paragraph (b) in this section to avoid confusion when the BLM starts accepting transfers electronically.

Section 3102.51 Compliance

The BLM proposed revising the existing § 3102.5-1 to clarify who is entitled to hold a lease and that the reclamation obligations under the lease reside with the lessee, operating rights owners, and operators, and not the American taxpayer. The BLM received comments in support of the proposed changes to this section and a recommendation in a comment that the BLM publish and regularly update the list of entities that are not in noncompliance with reclamation requirements of section 17(g) of the MLA. Many comments opposed the proposed changes, citing a lack of due process, fairness, the BLM's ability to take enforcement actions to address any compliance deficiencies, and the need to provide entities the ability to remedy any alleged compliance issues before the BLM turns to cancelling a lease, among other concerns.

To address the comments, the BLM is revising the phrase “will be subject to cancellation” to “may be subject to cancellation” to clarify that cancellation is only one of the enforcement tools the BLM could apply and allows for due process. As provided under § 3000.40 of this chapter, any decision issued by the BLM pursuant to this section would be subject to appeal. In addition, the BLM updates the list of “Entities in Noncompliance with Reclamation Requirements of section 17(g) of the MLA” on an as-needed basis, and then forwards the names of the entities to the Federal Government's suspension and debarment program. SAM.gov is a publicly available website that contains the list of suspended or debarred entities. Likewise, when a company returns to compliance, the BLM notifies the suspension and debarment program that the entity should be removed from SAM.gov. The BLM declines to publish a duplicate list of these entities. Thus, no further changes are warranted.

Section 3102.52 Certification of Compliance

The BLM proposed a minor change to the existing § 3102.5-2: the removal of the word “offer” to reflect Congress' elimination of the noncompetitive leasing process. The BLM received a comment on this section recommending additional language to explicitly state that any false certification is subject to the criminal penalties contained in 18 U.S.C. 1001. The BLM declines to adopt this proposal, which is unnecessary. Section 3000.20 of this chapter already informs all entities that they are subject to criminal penalties if they provide false statements to the BLM. In addition, the standard forms used by the BLM under these regulations, such as the bid form (3000-002), assignment of record title form (3000-003) and the transfer of operating rights (3000-003a), and the lease form (3100-011), all include similar statements and references to 18 U.S.C. 1001 for any false statements.

5. Section-by-Section Discussion for Changes to 43 CFR Subpart 3103

Section 3103.1 Fiscal Terms

The BLM removes the proposed § 3000.130 from the final rule and moves the information in that section into final § 3103.1, since this section addresses oil and gas fiscal terms and does not impact other minerals management programs. Therefore, the BLM determined that it is more appropriate to codify this section in subpart 3103 instead of part 3000. As a result of this change, the BLM updated all cross references in the final rule from § 3000.130 to § 3103.1.

Based upon the comments received, the BLM also incorporates additional updates that include: (1) adding the EOI filing fee from the IRA to this section and (2) changing the timeframe that the BLM will adjust the fees for inflation from annually to once every 4 years.

First, the BLM moved the new EOI filing fee, established by the IRA, from proposed § 3000.120 to final § 3103.1(a). The BLM cannot update the EOI fee annually. The MLA at 30 U.S.C. 226(q)(2)(B) states, “The Secretary shall, by regulation, not less frequently than every 4 years, adjust the amount of the fee under subparagraph (A) to reflect the change in inflation.” Therefore, the final rule moves the EOI fee to paragraph (a). Second, the EOI fee will be adjusted every 4 years by way of a final rule as part of the new Fiscal Terms Table. The BLM also changed the adjustment for minimum bonus bids and rentals to be adjusted every 4 years for inflation by way of a final rule. This change will allow the final rule to update these terms to occur at the same time and minimize the public's costs for these inflation adjustments. The BLM also renamed the title of this section from “Fiscal terms of new leases” to “Fiscal terms.”

One commenter stated that the BLM should tie all costs and returns associated with oil and gas leasing to an inflation index. The BLM did not make any changes in response to this comment, as all fees in § 3000.120, the fiscal terms in § 3103.1, and the minimum bond amounts are tied to changes in the Implicit Price Deflator for Gross Domestic Product, which is published quarterly by the U.S. Department of Commerce. Finally, a comment stated that the BLM should clarify that the inflation adjustment as described in this section will include adjustments for inflation occurring over any period of multiple years after August 16, 2022, during which bid and rental rates were left unchanged despite inflation. The BLM concurs with this recommendation, which is reflected in the existing regulations and its use of the Implicit Price Deflator for Gross Domestic Product.

Another commentor stated that the proposed rule references no authority that would support annual inflation adjustments for the rental and bonus as the IRA precludes the adjustment of these fiscal terms until after August 16, 2032. The BLM agrees that the rental and minimum bonus bids must remain at the current rate until August 16, 2032; however, after this date, the IRA changes these amounts to minimums. Therefore, the BLM proposed and is implementing inflation adjustments for rental amounts and minimum bonus bids after August 16, 2032. To reduce confusion, the BLM updates paragraph (a) by adding the sentence, “Per the Inflation Reduction Act, the BLM will not adjust the rental nor the minimum bonus bids until after August 16, 2032.”

Section 3103.12 Where Remittance is Submitted

The BLM proposed to update the existing § 3103.1-2 to clarify that fees set out in the fee schedule in § 3000.120 of this chapter and all first-year rentals and bonuses for leases issued under 43 CFR part 3100 must be paid to the proper BLM office. This final section also removes outdated references to the former Minerals Management Service and mailing address for payments. The BLM received a related comment on lease reinstatements, in which the commenter stated that references in the BLM regulations to rental payments through the ONRR's online system should also acknowledge ONRR's continuing practice of accepting non-electronic rental payments in some circumstances. The BLM concurs and changes the language in paragraph (a)(2) from “through its online system” to “refer to 30 CFR 1218.51” that lists the methods by which lessees and operators may submit payments to the ONRR.

Section 3103.21 Rental Requirements

The BLM requested comments on adding a new requirement for diligent development obligations.

Comments that supported a diligent development provision included recommendations that the BLM: (1) implement further leasing reforms, such as increasing production from existing leases by ensuring diligent development, implementing specific diligent operations standards, and adopting a mechanism to hold private companies accountable when they fail to meet the requirements; (2) tie the diligent development requirement to the definitions of “qualified lessee,” “responsible bidder,” and “responsible lessee;” and (3) impose a diligent operator standard with reporting requirements, and absent a rental rate increase, clarify what consequences an operator may face when it fails to operate diligently including lease termination. Comments also asserted that the proposed lease rentals are insufficient and leases that are not pursued for development within 5 years should be permanently revoked and should not be transferable to another entity.

Comments that opposed a diligent development provision included statements that: (1) failure to act diligently to develop a lease has no adverse impacts on the environment; (2) adding diligent development obligations would result in additional work for the BLM and an unnecessary burden on lessees; (3) the increased rental rates prescribed by Congress in the IRA and adopted in the final regulations will encourage diligent development on their own and encourage prudent development or lease surrender; (4) the diligent development obligations would impact business decisions that are based on markets, investment capital, supply chains, labor and equipment availability, and other factors; (5) geophysical exploration does not always result in lease development; (6) new diligent development terms would impose large cost increases on many leases and inhibit operator flexibility to properly evaluate and commence operations in a responsible developmental situation and economic manner consistent with lease requirements; (7) a diligent development requirement could exacerbate the climate crisis; (8) the BLM should consider delays that are out of an operator's control, such as the time certain Federal processes or lawsuits can take; (9) the proposed rule's list of alternatives is overly lenient and promotes speculative ventures; and (10) the BLM should not apply too broad an interpretation of diligent development.

After careful consideration of the comments received, the BLM did not implement a diligent development requirement with an escalating rental rate in the final rule. The BLM believes the existing increasing rental rates prescribed by Congress in the IRA will encourage diligent development on their own by incentivizing lessees and operators to develop a lease to avoid the increased costs. The BLM will continue to assess the oil and gas leasing program, and if the BLM determines Congress' rental rate increases are not as effective as expected at encouraging diligent development, the BLM may consider additional rulemaking. The BLM further clarifies final paragraph (a) by adding, “for that lease” after the words “total acreage” to clarify the basis for calculating the first-year rental. No further changes have been made to this section.

Section 3103.22 Annual Rental Payments

The BLM proposed changes to the existing § 3103.2-2 to implement changes made by Congress in the IRA and clarify what constitutes a timely payment of rental by tying the payment to the lease anniversary date. The BLM received numerous comments on this section. The comments encouraged the BLM to: (1) set out the actual required rental amounts, as provided by the current regulations, rather than referring to the lease terms; (2) set a policy determining when rental rates should be higher than the statutory minimums; (3) implement the regular rate increases; and (4) further increase the rental rates, on the theory that the rental rates in the IRA are too low.

In the IRA, Congress set rentals at $3 per acre, or fraction thereof, for lease years 1 and 2; $5 per acre, or fraction thereof, for years 3 through 8; and $15 per acre, or fraction thereof, thereafter. Ten years after the enactment of the IRA, those rental rates become minimums and are subject to increase, as discussed in § 3103.1. The BLM agrees with the comments that the section in the proposed rule was not clear and adds the following clause at the end of paragraph (a) “the annual rental for all new leases will be as specified in 43 CFR 3103.1.” 43 CFR 3103.1 sets out the actual required rental rate, provides details on when the BLM will increase the rental rate, and implements a rate increase every 4 years. The BLM cannot increase the rental until August 16, 2032, based upon Congress' direction in the IRA.

Another comment objected to the application of these rentals to leases sold before the passage of the IRA but issued after the IRA was signed into law. The commenter explained that companies bid on those parcels relying on the rental and royalty rates that were in effect at the time of the lease sale and contended that lease issuance was only delayed due to the BLM's failure to timely resolve protests.

As explained in the preamble to the proposed rule, the IRA amended the rental rate for all new oil and gas leases issued in the next 10 years. Because the statute ties the new rates to lease issuance, the BLM does not have the authority to exempt leases sold but not issued prior to the enactment of the IRA from its terms.

Section 3103.31 Royalty on Production

The BLM proposed changes to the existing § 3103.3-1 to implement the requirements of the IRA and received numerous comments.

Supportive comments recommended that the final rule address plans, specify criteria, or include a procedure for increasing the royalty rate after 2032. These comments suggested various ways to implement this recommendation, including codifying a higher royalty rate of at least 18.75 percent, or 20 percent; increasing the royalty rate consistent with the previous 10-years' worth of inflation, but not deflation, and indexing the royalty rate to raise at prescribed intervals; or adjusting all rates to market levels on a regular basis to better ensure fair return. Supportive comments also requested a termination provision, similar to that for failure to pay rentals, for the failure to pay royalties. Other supportive comments stated that the BLM should limit changes to just those required by the IRA, as the new rate could affect the competitiveness of the U.S. minerals program.

Comments that opposed the changes included statements that: (1) higher royalty rates have consistently led to increased revenues without discouraging oil and gas development and the new rate of 16.67 percent is still well below the rate that is charged for offshore drilling in Federal waters (18.75 percent) and imposed by leading oil-and gas-producing States, including Texas (20-25 percent), Colorado (20 percent), and New Mexico (18.75 to 20 percent); (2) the final rule should refrain from setting a minimum rate because the cost of operating on Federal lands is higher than on State or private lands, and a higher royalty will make it uneconomic to operate on most Federal lands; (3) the higher minimum, and any increased royalty rate, will disincentivize operations on Federal lands, harming small business, local governments, and States; (4) the BLM failed to provide a justification for making the royalty rate the minimum, and the bureau should consider establishing 16.67 percent as the maximum with a mechanism for determining a lower rate when the 10-year statutory requirement expires; (5) the BLM should not comply with the IRA's mandate or adopt a permanent royalty relief rule for onshore production; (6) raising oil and gas royalty rates will directly reduce well operators' revenue margins, risking well closures and deliberate attempts to devalue oil fields; (7) higher royalty rates affect long term project economics by reducing the expected revenue and making them less financially feasible; (8) higher rates will deter small operators from investing in expensive enhanced oil recovery methods that can extend the productive life of a well; and (9) raising the Federal royalty rate encourages cheating and requires greater Federal investment in compliance enforcement at taxpayer expense.

As stated in the proposed rule, the BLM updated this section to implement IRA section 50262, which set royalty rates at 16.67 percent for the 10 years following the Act's enactment. Final paragraph (a)(3) of the regulation states that for leases issued after the 10-year period following the passage of the IRA, the royalty rate will be not less than 16.67 percent, which is the rate Congress required in the IRA. The BLM declines to set post-2032 rates now (or to implement associated procedures) so far in advance of any authorized increase. However, the BLM may consider further adjustments after 2032. The BLM also declines the suggestion to implement an automatic termination provision for the nonpayment of royalties. The procedures for lease forfeiture and cancellation are set forth in section 31(a) of the Act (30 U.S.C. 188) and § 3108.30(b) of the regulations. The BLM adopts this section into the final rule without any further changes.

Section 3103.41 Royalty Reductions

The BLM proposed revising the existing § 3103.4-1 to clarify that production in paying quantities is a prerequisite to obtaining royalty relief under this section. The BLM also solicited feedback to improve the royalty rate reduction section.

Comments recommended that the BLM: (1) describe the specific circumstances for justifying a reduction and clarify that the reductions will terminate as soon as the conditions justifying the reduction have passed; (2) explicitly state that a royalty rate reduction would transfer to the new lessee when a lease is assigned; (3) provide specific criteria for lowering the rate; (4) set a limit on the lower end of the reduced rate; (5) limit the period for the reduction to apply; (6) specify that reduced royalties transfer to assignees only on a case-by-case basis; (7) extend royalty relief to all producers at any point of production; (8) extend the royalty relief to any field where operators are seeking to conduct or are conducting waterfloods or other enhanced oil recovery methods; (9) not set a floor for royalty reductions because a universal rate, even a low one, cannot account for the varying productivity within a formation; (10) determine the royalty relief by the field productivity and the crude grade produced; (11) determine the appropriate royalty rate reductions based upon a critical review of the economic data for reasonableness and clearly enumerate the costs that are allowed for the economic evaluation to ensure operators send unbiased data; (12) closely monitor any approved royalty reduction; (13) clearly define under what circumstance/criteria royalty reduction terminates; (14) revise the phrase “royalty reductions at the discretion of the Secretary” to convey that reductions are the exception, not the norm; and (15) add language to require notification to the State when royalty reductions take place, given the State's interest in the royalty rate and the economic health of the industry and local communities.

The BLM rarely grants royalty rate reductions, and after careful review of the comments, has decided against making any further changes. The regulation states that the Secretary may waive, suspend, or reduce the rental or royalty upon a “determination that it is necessary to promote development or that the leases cannot be produced in paying quantities under the terms provided therein.” Thus, the BLM only grants a reduction in royalty rate if the operating costs exceed the gross income. Otherwise, the BLM would deny the royalty rate reduction. The regulatory requirements reflecting these parameters come directly from the statutory authorization for royalty reductions at 30 U.S.C. 209. Additionally, if the operating costs would still exceed the gross income with a royalty rate reduction, the BLM must consider terminating the lease for no longer being capable of production in paying quantities under 43 CFR 3107.22.

The factors the BLM considers when evaluating a reduction are case-specific, and the BLM must review each application. Given this and the exceptional nature of circumstances that may warrant royalty reductions, the BLM declines to further specify the circumstances or specific criteria for lowering a royalty rate in the regulation in order to retain the discretion of the authorized officer to address case specific situations that may occur. The BLM is committed to adhering to the existing rules and policy and will ensure that they are consistently and faithfully applied to future royalty relief applications.

Second, the BLM declines to codify language stating that a royalty rate reduction would transfer to a new lessee when a lessee assigns its lease. The operating costs for the lease may change with the new lessee; therefore, the BLM would need to complete a new review to determine if the royalty rate reduction is appropriate.

Third, some commenters opposed and some supported implementing a lower limit for royalty reductions, but no lower limit was proposed. The BLM has decided not to implement a lower limit and will instead continue to rely on the economics of each lease to determine the appropriate royalty reduction, if warranted.

Fourth, the BLM will not provide royalty relief based only upon operators conducting or seeking to conduct waterfloods or other enhanced oil recovery methods. These operations will return a profit to the operators and in most cases a royalty reduction would not be appropriate as the gross income exceeds the operating costs.

Fifth, the requirements to monitor royalty rate reductions or to send notice to States are better suited to be addressed through policy as these requirements would apply only to the BLM and not the regulated community. The BLM already tracks royalty rate reductions in MLRS and will continue to closely monitor reductions. Given how rare royalty rate reductions are, the BLM has not established a requirement to notify the States. The BLM will consider whether a notification to the States should become a matter of policy in the future.

Sixth, the existing regulations and Bureau policy reserve the BLM's right to terminate a royalty reduction, re-adjust the amount of reduction, or restore the royalty rate to the rate required by the lease terms and/or regulations at any time for the entire lease or for any portion thereof. Given that the grant of a royalty rate reduction is uncommon, the BLM is declining to add any blanket provisions to the regulations that would remove this flexibility. For example, the BLM may need to terminate relief retroactively if such relief was based on manipulation of normal production or adulteration of oil sold.

Sections 3103.42 Stripper Well Royalty Reductions and 3103.4-3 Heavy Oil Royalty Reductions

The BLM proposed to eliminate both of §§ 3103.4-2 and 3103.4-3 in their entirety because they are obsolete for the reasons described below. The BLM received a comment stating the BLM's removal for obsolescence ignores the fact that over the next decade, the number of stripper wells on Federal lands will rise along with necessary oil exploration and production.

As stated in the proposed rule, the BLM revised both sections on October 6, 2010 (75 FR 61624), to eliminate these types of royalty relief, because Congress enacted separate relief in section 343 of the Energy Policy Act of 2005 (42 U.S.C. 15903). However, the BLM retained the regulations because, while these types of royalty relief were no longer available for current production, prior production subject to this relief continued to be subject to audits. This is no longer the case; therefore, these provisions serve no purpose. To the extent relief is required in the future, the BLM would promulgate any necessary regulations under section 343 of the Energy Policy Act of 2005 rather than relying on these provisions. In addition, the BLM has the authority under section 39 of the MLA to waive, suspend, or reduce the royalty for a lease.

Section 3103.42 Suspension of Operations and/or Production

The BLM proposed redesignating this section from 43 CFR 3103.4-4 to 43 CFR 3103.42 and clarifying how a lease term will be adjusted once the suspension ends.

The BLM received a comment on paragraph (a) stating that the BLM should broaden the circumstances for which a lease would be eligible for a suspension of operations only or a suspension of production only beyond force majeure, or at a minimum should acknowledge that the BLM's own delays constitute such a force majeure for the purposes of these types of suspensions. The regulations clarify that a force majeure is “matters beyond the reasonable control of the lessee.” Because this encompasses an administrative delay, the BLM already takes such delays into consideration when evaluating a suspension. The BLM is not revising the regulation to further specify instances that may be considered force majeure; BLM Manual 3160-10, Suspension of Operations and or Production, provides further examples of acts constituting force majeure.

Some comments stated that lease suspensions, whether requested by the lessee or directed by the BLM, should be made public as soon as they are submitted and should be subject to public review and comment in accordance with NEPA. The BLM disagrees with this recommendation. NEPA is only triggered if there is a proposal for a major Federal action that potentially affects the environment. Although the approval or direction of a suspension is a Federal action, lease suspensions are categorically excluded from NEPA review as administrative actions taken on an already existing authorized lease. See the BLM's National Environmental Policy Act Handbook H-1790-1, Appendix 4.^[12]

Some comments stated that the BLM should clarify that both the suspension request and the decision by the BLM must be made in writing and published on a BLM website, and that the proposed rule fails to provide the transparency and public access to information about lease suspensions that is guaranteed by the Administrative Procedure Act. The BLM disagrees with this comment, as suspension decisions have always been publicly available through review of the case file located in the relevant BLM state offices or through the BLM's reporting application at https://reports.blm.gov/​reports/​MLRS.

Another comment stated that the BLM should clarify in paragraph (d) that any lease production is prohibited while a suspension of operations and production is in effect. The BLM agrees, and it is BLM policy that production from a lease is prohibited if there is a suspension of operations and production. See BLM Manual Section 3160-10, Suspension of Operations and/or Production. ^[13] The rule provides that “if there is any production sold or removed during the suspension, the lessee must pay royalty on that production.” This statement covers instances where there are no operations or production, but the operator sells already existing product captured prior to when the suspension went into effect; it does not supersede the ordinary bar on production during suspensions, and merely ensures the lessees pay royalty on that sold production.

Multiple commenters stated that the BLM should: (1) clarify that lease suspensions are the exception and not the rule; (2) provide limited and specific criteria that would justify a suspension; and (3) offer guidance on how the BLM plans to deal with existing lease suspensions. The BLM declines to modify the regulations as detailed in the three comments above. The MLA provides direction, and the BLM has set guidance on when a lease suspension is appropriate. First, the BLM currently has approximately 3,000 suspended leases of the over 33,000 authorized onshore oil and gas leases. While suspensions are not a common occurrence, the number of lease suspensions has increased based upon the large number of leases litigated in court after lease issuance over the past decade. Second, the BLM declines to provide limited and specific criteria in the regulations. The BLM provides guidance to its employees in IMs and MS-3160-10, Suspension of Operations and/or Production.^[14] The BLM declines to make this change at this time to retain the discretion of the authorized officer to address unique situations that may occur. Third, the BLM already established guidance on how the BLM plans to deal with existing lease suspensions in Permanent IM 2019-007, Monitoring and Review of Lease Suspensions;  ^[15] therefore, the BLM declines to add this information into the regulations. The existing regulations require evaluation of lease suspensions on a lease-by-lease basis. Reviews of existing lease suspensions are currently addressed in the BLM's policy IM 2023-012, Suspension of Operations and/or Production  ^[16] . No changes have been made in the final rule to avoid limiting the discretion of the authorized officer to address unique situations that may occur. For example, litigation or actions of Federal or State agencies that prevent commencement or continuation of operations may be applied to suspensions granted under section 17(i) or section 39 of the MLA depending on the unique circumstances of the case.

A commenter was concerned that changing the word “terminating” in existing paragraph (e) to “lifting” in final paragraph (g) will be interpreted by lessees and others to require the BLM to take affirmative action to end a suspension. The comment states that a lease suspension should lift automatically—without any subsequent administrative action by the BLM—when certain regulatory events occur or as otherwise stated in the approval letter, and the BLM should avoid any change that would increase the administrative burden on the agency. The BLM disagrees with this comment. While it is true that, in some cases, the BLM's decision to suspend a lease will document a particular event or action that will eventually lift a suspension, the BLM always issues a decision for the official record when lifting a suspension, allowing for the expiration date of the lease to be properly adjusted and facilitating any reconciliation of the rental amount that may be due, see C.W. Trainer, 69 I.D. 81 (1962). A copy of that decision is sent to ONRR to notify it of a change in the status of the lease. The final rule did not change this process. Based upon a review of the comments received, the BLM did not make any changes for this section from the proposed rule: the process described above is consistent with the term “lifting” as the term avoids confusion and leads to an understanding that the BLM takes an action to end a suspension.

Section-by-Section Discussion for Changes to 43 CFR Subpart 3104

In subpart 3104, the BLM proposed to revise its bonding regulations by increasing the minimum amount of bonds, removing nationwide and unit operator bonds, adding surface owner protection bonds, and removing letters of credit (LOCs) and CDs as options that lessees can use to secure the required bond amounts. The BLM received several comments on the proposed bond amounts. Some comments supported the higher amounts, with some stating these amounts do not reflect the full reclamation costs of oil and gas wells. Other commenters recommended the final rule establish a full-liability, individual lease bond or tie the bond amount to the number of wells covered by a bond. The MLA does not require the BLM to impose full cost reclamation bonds but does require the Secretary to ensure the bonding is adequate to ensure reclamation. Requiring a full liability bond would require increased staffing at the field and state offices to manage increased workloads for the review of changing conditions and the adjudication of additional bond riders to either raise or reduce the bond amount. In addition, the BLM's APD processing time would slow due to waits for additional bond riders. The BLM has opted to keep to a higher minimum bond amount and depend upon its policy guidance and future adjudications for increasing the bond amount for specific operations that pose additional risk, which will allow the BLM to direct its limited resources to where they can have the most impact.

Comments also recommended that the BLM review its average costs for reclaiming orphaned wells, noting that the States have identified a higher average cost for their orphaned wells. The BLM reviewed its costs related to cleaning up orphaned wells that were plugged since the BLM calculated the average cost as part of this rulemaking effort. Due to the limited number of additional orphaned wells that have been plugged in that time, there is not enough additional data to warrant a recalculation. Therefore, the BLM did not adjust the minimum bond amount based on a new average orphaned well cost.

Some comments stated the BLM should not have used the median number of wells to determine the new minimum bond amounts but rather should have considered the probability of the number of wells to be orphaned. The BLM is unable to predict whether any particular well will become an orphan well due to many factors that can lead to a well becoming orphaned ( e.g., operator's revenue stream, operator's cost stream, current regulatory framework within the State, remaining oil and gas reserves, etc.) and the lack of data for each of these factors. Therefore, the BLM lacks the necessary information to determine the probability of a well to become orphaned and thus did not use it as a basis to calculate bond costs.

Several comments opposed the higher minimum bond amounts and requested that the BLM remove the proposed bonding changes, explaining that the BLM rarely needs to access a bond to plug a well. Comments also asserted that the BLM's own statistics do not justify the bonding provisions in light of the MLA's requirement for an adequate bond. As stated in the proposed rule, the minimum bond amounts have not been increased since 1951 (for statewide and nationwide bonds) and 1960 (for lease bonds), have been repeatedly found inadequate by the GAO and the OIG, and are no longer adequate to provide the requisite funding for reclamation when a lessee defaults on its obligations.

The BLM received several comments stating that the higher minimum bond amounts will be a significant financial burden on operators and small businesses, because sureties often require companies to post cash or security collateral. The BLM disagrees. The Small Business Administration (SBA) helps small businesses guarantee performance bonds issued by certain surety companies, which allows the companies to offer surety bonds to small businesses that might not meet the criteria for other sureties. The SBA's website states that all performance bond guarantees require small businesses to pay SBA a fee of 0.6% of the contract price. The operator would need to make a payment of $900 for an individual bond or $3,000 for a statewide bond to SBA, which would allow the small entity to obtain a surety bond without requiring the company to post cash or security collateral. The BLM encourages small businesses and operators to reach out to the resources available to them including those provided by the SBA and visit their web page: https://www.sba.gov/​funding-programs/​surety-bonds.

In addition, the BLM conducted a review of small entities operating on Federal oil and gas leases based upon public data. If these companies paid sureties 3% of the additional bonding cost annually, their overall cost-to-revenue ratios would increase by less than one-tenth of one percent. If these companies instead chose to fund the full bonding amount out of revenues, their cost-to-revenue ratio would increase by at most 1.4% for one year. Based upon our analysis, the BLM certifies that there will not be a significant economic impact on small entities in the RFA; refer to section V.B. Please also review the RIA for more information.

Section 3104.1 Bond Amounts

Based upon the comments received, the BLM decided to implement inflation adjustments for minimum bond amounts. The BLM completed this action by (1) adding the minimum bond amounts to this section to provide for inflation adjustments; (2) moving the phase-in period for lease and statewide bonds into this section; (3) providing a longer implementation for small operators to increase or replace their bonds; and (4) providing information to operators on the penalties they could incur if they fail to increase or replace existing bonds that do not meet the new minimum bond amounts.

First, the BLM requested comments on whether it should adjust the minimum bond amounts to keep up with inflation. The BLM received multiple comments recommending the BLM periodically adjust the minimum bond amounts to better protect the taxpayer's interests in adequate reclamation. The BLM agrees with these comments and updates the final rule to include inflation adjustments to bond amounts by way of a final rule and titled this § 3104.1 “Bond amounts.” This update will allow the BLM to periodically update bond amounts based upon the rates of inflation.

Second, the BLM moved the phase-in period for statewide and individual bonds from proposed § 3104.90 to final § 3104.1(c). The phase-in period for lessees to replace unit and nationwide bonds remains in final § 3104.90. This change allows the BLM to easily update the phase-in periods for individual or lease bonds and statewide bonds upon adjusting the minimum bond amounts for inflation. The BLM anticipates that when the minimum bond amounts are adjusted for inflation in the future, the phase-in periods will occur over 2 years:

• One year for statewide bonds, and
• Two years for individual bonds.

This phase-in follows the initial proposed timeframes. The BLM has calculated the staffing needs required to process all bond increases for a 1-year phase-in period and concluded the BLM will require 2 years to provide sufficient time to ensure all bonds are brought into compliance.

Third, the BLM considered comments regarding the impact to small operators from increasing the minimum bond amounts. Larger companies usually hold nationwide or statewide bonds, while smaller companies usually hold individual bonds. Initially, the BLM proposed to require individual bond holders to come into compliance with the new bond amounts first. Commenters expressed concerns that the higher minimum bond amounts may force small operators out of business. To alleviate some of the concerns expressed by commenters with respect to the impact on small operators and given the large number of individual bonds, the BLM has revised the final paragraph (c) to give those with individual bonds more time by phasing in this requirement over a 3-year period, instead of over a 2-year period. The longer phase-in period for individual bonds will provide more time for smaller operators, who predominantly rely on individual bonds, to research and obtain the appropriate bond amount. When minimum statewide and individual bond amounts are adjusted for inflation in the future, the BLM anticipates the shorter phase-in periods (2 years for individual bonds) will be sufficient for all bond holders to come into compliance because the bond amount increase will not be as significant a change.

A comment expressed concern regarding which penalties could accrue to lessees who do not increase the bond amounts within the time allowed. The BLM reviewed its existing regulations and added a new paragraph (d) to this section to address this comment. Paragraph (d) now refers to the existing regulations that the BLM may use if an operator fails to increase or replace an existing bond as required by the regulations. The potential penalties include shut down of operations under 43 CFR 3163.1(a)(3), lease cancellation under 43 CFR 3108.30, or referral of the obligor or principal to the Department's Suspension and Debarment Program under 2 CFR part 1400.

The BLM considered shorter timeframes for inflation adjustments to the minimum bond amounts, including annual adjustments, but concluded that shorter timeframes are unworkable given the BLM's workload associated with possible enforcement. Instead, the BLM has opted to update the minimum bond amounts in the final § 3104.1 table every 10 years. The final rule for the updated bond amounts in the 3104.1 table will also indicate the new deadlines for compliance. This 10-year timeframe will provide sufficient time for entities to come into compliance, for adjudication of the financial assurances, and for the BLM to ensure such compliance prior to the implementation of new minimum bond amounts.

The BLM received other comments related to adjusting the fiscal terms for inflation. One commenter stated that the BLM should not attempt to automatically adjust existing bonds for inflation without the surety's consent. The phase-in periods will provide time for the bonded principal to work with the surety to increase the amount or replace the bond. Another commenter recommended that the BLM conduct annual reviews and commit to increases in line with larger economic trends and not just inflation. The BLM will move forward with updating the minimum bond amounts based upon inflation every 10 years as part of the final rule; however, the BLM maintains the right to conduct reviews of bonds to determine if additional increases are necessary and in the public interest.

Section 3104.10 Bond Obligations

The BLM requested comments on the proposed revisions to § 3104.1 along with any supporting information on whether the final rule should provide for any other types of financial arrangements that the BLM should consider.

The BLM received several comments stating the BLM should not eliminate CDs and LOCs from the options available to satisfy bonding requirements, reasoning that the elimination would impose an unwarranted burden on lessees and operators, particularly small operators, and that the BLM should provide more options to post the bonds rather than eliminating options.

Based on the comments, the BLM has decided to reinstate CDs and LOCs as acceptable forms of security for a personal bond. To resolve some of the issues that led the BLM to propose eliminating the securities, the BLM made changes to the regulations for CDs and LOCs. Given that CDs are now issued electronically by banks, they do not meet the existing requirement that Secretarial approval be indicated on the face of the document. Therefore, the BLM modifies paragraph (c)(1) for CDs by inserting “or through assignment” to provide for Secretarial approval prior to any redemption.

The BLM modifies paragraph (c)(5) for LOCs to change “shall” to “must” or “will” as appropriate and consistent with the similar changes made in the proposed rule. The BLM also removes the language “the deposits of which are federally insured,” as this phrase in the existing regulation has caused confusion to both operators submitting a bond and BLM staff who review bonds and their associated securities. The $250,000 Federal deposit insurance limit for deposits that a person may have with a financial institution does not apply to LOCs, because the guarantee of payment under a LOC is made by the financial institution directly to the BLM by demand, see 31 CFR part 28.204-3(b). LOCs are not depositor accounts to which the Federal Deposit Insurance Corporation (FDIC) insurance applies. Therefore, the BLM is not concerned with FDIC insurance when the amount of a LOC exceeds the FDIC limit.

Paragraph (c)(5)(ii) is modified to appropriately reference the types of bonds as “an individual lease or statewide bond,” and to change the term “attachment” to “collection” for clarity.

Paragraph (c)(5)(v) is modified to state, “In the event the BLM is notified of the financial institution's intent not to renew the letter of credit, the principal must extend the letter of credit or provide an adequate replacement bond with an assumption of liability rider. If the BLM does not receive an adequate notice or replacement bond with rider, the BLM will collect the letter of credit within 30 days of the expiration without further notification to the obligor.” The BLM is including this language to ease the administrative burden that results if an entity fails to maintain the LOC. Previously, when an entity failed to pay the premiums to the bank, the BLM, in turn, had to notify the obligor (the bonded party) to replace the bond within 60 days; monitor the timeframes to ensure the LOC is extended or replaced; adjudicate an acceptable form of replacement security or bond; and send a demand to collect on the letter of credit when all else fails. The new language will reduce the BLM's workload by obviating the initial notice to the obligor to replace the bond. To be clear, the BLM will send a demand to the bank to collect the funds from the LOC 30 days prior to the expiration date without further notice of the action from the BLM when the obligor fails to take corrective action on their own accord.

For other types of financial guarantees, one commenter recommended that the oil and gas program review the bonding requirements and language of the BLM's solar and wind energy regulations in 43 CFR 2801.5(b) for consistency, especially language regarding whether corporate guarantees are an acceptable or unacceptable bond instrument. Another commenter stated that alternative financial arrangements could include insurance policies as both an alternative and to complement surety bonds such as insurance accounts to pre-fund decommissioning costs, where sureties direct a portion of their annual premiums and payouts could be made to the operator or the BLM upon default.

The BLM carefully considered the comments and other forms of financial assurance to secure bonding and is declining to include any other forms of financial assurance because the BLM believes the current list, with the retention of LOCs and CDs, is sufficient. The BLM reviewed BOEM regulations, which provide for corporate guarantees, insurance, decommissioning accounts, and other forms of security approved by the Regional Director. The BLM also reviewed the solar and wind energy regulations, which provide for the same financial assurances listed in this final rule as well as insurance. As discussed below, the BLM has decided not to allow corporate guarantees and insurance as means to satisfy the bond requirements. The BLM has determined that corporate guarantees are not an acceptable form of bond security given the need to continually confirm the viability of the corporate guarantee. The BLM does not have the staff or expertise to perform this function, and, without the ability to closely monitor the financial stability of the corporation providing the guarantee, there is a risk the company may default or go bankrupt during the term of a lease, before plugging and reclamation of the existing well(s) and disturbance. To secure a replacement bond at that time would be difficult, if not impossible, thereby potentially leaving the Federal taxpayer to foot the bill for any necessary reclamation.

While insurance is an acceptable form of bond security used in other BLM programs, the BLM declines to use insurance for the oil and gas program given the risks and increased administrative workload for the following reasons.

First, the basic principle of insurance is the transfer of risk. It transfers the risk of financial losses as a result of specified but unpredictable events to an insurer in return for a fee or premium. While insurance is acceptable for unforeseen events such as spills or accidents, the BLM's performance bond secures the promise to fulfill a known, contractual obligation an entity has undertaken to perform at some point in the future.

Second, an insurance policy is usually a written contract between two parties, the policyholder (the person or company that gets the policy) and the insurer (the insurance company). The BLM would be a third-party beneficiary under this scheme, and considered appropriate language to that effect, but this arrangement is still significantly different from surety bonds where there is a contract between three parties (the BLM, the principal (or bonded party), and the surety where the BLM is a party to the agreement). Therefore, the BLM would hold more risk because it is not a party to the insurance.

Third, generally, either party to an insurance contract may cancel the contract unilaterally. To address this, the BLM considered regulatory language stating, e.g., that policy must be non-cancellable. However, this could cause confusion with cancellation of a bond since existing § 3104 does not provide for canceling or releasing oil and gas bonds and the only time a bond is canceled is by a court order. The regulations only provide for terminating the period of liability on the bond.

The BLM believes the revised regulations provide sufficient options for the regulated community to meet the bonding requirements, and, for all the reasons stated above, the BLM has determined not to rely on insurance for bonding.

As mentioned above, BOEM's bonding regulations at 30 CFR 556.900 allow for the provision of “Another form of security approved by the Regional Director.” 30 CFR 556.902(e)(3). The BLM recognizes this option provides a level of flexibility that is not present in the BLM's regulations. However, the BLM has decided to refrain from including a similar provision in its regulations because the BLM does not have staff to implement such a provision. As of May 1, 2021, BOEM managed about 2,287 active oil and gas leases on approximately 12.1 million acres, while the BLM managed 35,871 leases on approximately 24.9 million acres. The BLM manages significantly more leases and significantly more bonds with no staff solely dedicated to bond adjudication. Instead, the BLM staff adjudicate both bonds and post-leasing actions. Therefore, the BLM does not have the staff nor expertise to implement a provision similar to 30 CFR 556.900.

The BLM considered decommissioning, abandonment, or trust accounts that can only be drawn upon to cover decommissioning expenses. Similar to corporate guarantees, allowing the use of these types of accounts would require continual review of constantly changing conditions and the expertise that BLM staff lack.

Some comments stated the BLM should require additional criteria for surety companies to ensure that bonded amounts will be available to the regulator if, and when, the operator defaults. The commenter recommended that the BLM should adopt additional criteria that (1) consider a surety's existing aggregate risk when determining whether that surety qualifies for certification, and (2) impose an underwriting limitation on the aggregate risk of all bonds issued by a surety. The BLM declines to make this change because the Department of Treasury already reviews the underwriting limitation and requires an excess risk reinsurance to protect the Federal Government. Please see Department of the Treasury Circular 570 for more information.

Section 3104.20 Lease Bond

For the existing § 3104.2, the BLM proposed changing the specifications regarding who must post a bond to state that the operator must be covered by a bond in its name as principal or obligor. The BLM received a comment urging the BLM to analyze the bonding regime of the host State jurisdiction and decline further bond requirements where that State provides for bonding inclusive of Federal leases and wells. The BLM declines to adopt this proposal. Including such a provision in the BLM's rules would require the BLM to execute separate agreements between the BLM and the State to allow the BLM to access any funds available. Moreover, for such arrangements to work, the State bonding requirements must, at a minimum, cover all of the terms and conditions of a Federal lease, including the amount of uncollected royalties due to ONRR, plus the amount of money owed to the BLM, as the lessor, due to previous violations remaining outstanding. In the BLM's experience, these characteristics are uncommon. The BLM would be in favor of such an alternate bonding option if any State is interested in pursuing adequate arrangements, but the BLM cannot make or assume the existence of such commitments in this rulemaking.

A commenter stated that the BLM should modify this section because it is inconsistent with other sections and is confusing. For example, § 3104.10 states that, before the start of any surface disturbing activities, the lessee, operating rights owner, or operator must submit a bond, whereas this section states only that the operator must provide a bond in its name. The comment then stated that the BLM's primary concern should be that at least one person post the required financial assurance for a lease, and should leave it to the operator, lessee, and operating rights owner to determine among themselves who will provide the required bonding for a particular lease. The BLM concurs that its primary concern is that at least one person must post the required financial assurance for a lease and that the proposed changes to this section may cause confusion. Therefore, the BLM revised final § 3104.20 to be consistent with final § 3104.10, so that an operator, a lessee, or an owner of operating rights (sublessee) must be covered by a bond in its own name as principal or obligor. In order to be consistent with existing § 3171.9(a), the BLM added the following sentence to the final rule § 3104.20: “The operator shall be covered by a bond in his/her own name as principal, or a bond in the name of the lessee or sublessee, provided that a consent of the surety, or the obligor in the case of a personal bond, to include the operator under the coverage of the bond is furnished to the BLM office maintaining the bond.”

One commenter expressed concern that the proposed rule did not consider related operators or subsidiaries operating under a parent company and could cause a parent company to be required to provide multiple bonds with significantly greater total bonding. The BLM disagrees. Under the existing and final regulations, the BLM allows for co-principals to submit a bond or to be added through bond riders. Bond riders can accompany the original bond or be filed subsequent to the acceptance of the bond. Therefore, the BLM is not making any changes to the final rule based on this comment.

A commenter urged the BLM to require that an individual lease bond be increased if it is to cover more than two wells, and, in determining the lease bond amount to be posted, that the BLM must take into account a number of variables including the well depth, the presence of other resources, the number of wells, the number of low-producing or inactive wells, the capability of any responsible party to carry out the reclamation, the anticipated condition of the well site, the extent of reclamation and remediation to be required, and compliance with the laws. The BLM declines to make any changes based on this comment, which, if accepted, would require the BLM to calculate each bond amount based on constantly changing conditions. That practice is unworkable given the number of bonds the BLM is required to maintain. The BLM already prescribes when a bond will be increased in § 3104.50.

Section 3104.30 Statewide Bonds

In the proposed rule, the BLM renamed the existing § 3104.3 due to the proposed elimination of nationwide bonds and proposed increase in the amount of statewide bonds to $500,000. The BLM received numerous comments suggesting a larger statewide bond amount if the bond: (a) covers more than seven wells; (b) is based on a number of variables; or (c) should be a set amount for each additional well. Another commenter recommended eliminating both nationwide and statewide bonds. The BLM declines to adopt these suggestions, which would require the BLM to calculate each bond amount based on constantly changing conditions; that practice is unworkable given the number of bonds the BLM is required to maintain. The regulations in § 3104.50 already specify when an increase might be required and provides the BLM with sufficient authority to review and ensure bond amounts are adequate.

Nationwide Bonds

The BLM proposed to remove nationwide bonding as an option due to the administrative burden they impose on the agency.

The BLM received comments supporting the removal of nationwide bonds. Those comments generally asserted that no nationwide option can fulfill the purposes of incentivizing operator reclamation and ensuring availability of adequate funds. Comments that opposed the removal of nationwide bonding stated there are benefits to continuing the nationwide tier for companies. Comments asserted that this change would deprive lessees and operators of a financial tool currently available to mitigate bonding costs by spreading them over a larger universe of leases and that the BLM's analysis that these bonds are administratively inefficient is not by itself a reason to remove nationwide bonds. Commenters pointed to language in a draft version of the IRA bill that included nationwide bonds, which Congress ultimately removed before the law was enacted.

The majority of the commenters who wanted the BLM to maintain nationwide bonds did not understand why the BLM considered nationwide bonds more difficult to manage and why the BLM proposed eliminating nationwide bonds. As stated in the proposed rule, for bond adequacy reviews, the BLM state office, which manages the nationwide bond, must coordinate with every field and state office with wells covered by this type of bond. The BLM administrative state office will usually contact between 4 (2 field offices and 2 state offices) and 40 (32 field offices and 8 state offices) offices and request these offices to conduct a bond adequacy review, which entails pulling the operator's well and inspection records. This is needed as the environmental and development situations may vary between offices. The administrative state office, while familiar with its field offices, would not be familiar with field offices in other administrative state offices. This will result in staff spending approximately 1 hour per office conducting the bond adequacy review and the administrative state office spending approximately 10 hours consolidating the reviews. With coordination required with between 4 and 40 offices, this would result in approximately $700 to $2,500 per bond adequacy review (assuming $50 hourly cost). Annually, this results in total costs of $33,740 to $120,500.

With this change, the BLM will no longer manage nationwide bonds and instead will have additional statewide bonds. The BLM estimates that the 243 nationwide bonds would become approximately 143 additional statewide bonds (see the Regulatory Impact Analysis for more information).^[17] The BLM estimates that each administrative state office would be able to review one statewide bond using 10 hours of staff time ($500 per bond adequacy review). The administrative state office requires less time to compile the review from the field offices as there will be fewer field office reviews to compile, so any time needed by field offices within the state office would come out of the assumed 10 hours of staff time. This would result in an annual cost of $14,300, which is a reduction of $19,440 to $106,200 annually. Overall, the BLM sees significant administrative benefits with the elimination of nationwide bonds.

Additionally, the elimination of nationwide bonding in favor of the proposed increase in the amount of the statewide and lease bonds will allow the agency to focus on specific areas and fields to ensure the bonds are adequate to cover reclamation costs in the event an operator fails to complete proper plugging and abandonment. As of March 1, 2024, the BLM has identified 35 unplugged orphaned wells that were covered by nationwide bonds. The bonds covering these wells were insufficient, so the BLM must seek funds under the IIJA to plug these wells. Localized bonding to the individual or statewide level will allow the agency to ensure improved bonding reviews, reduces the administrative burden, and the BLM anticipates additional environmental benefits from this regulatory change. As discussed in the RIA, the BLM expects that the expedited timing for reclamation of orphaned wells from increased bonding could provide benefits related to wildlife, vegetation, soil erosion, climate change (reduced greenhouse gas emissions from unplugged orphaned wells), visual and aesthetic resources, ground water, and allowing the surface land to be utilized for other uses sooner (for example, for grazing purposes). The BLM cannot currently quantify these benefits using the information available to the BLM.

Finally, the BLM reviewed the concerns from some commenters that eliminating nationwide bonds would deprive lessees and operators of one financial tool for mitigating bonding costs. No additional data or support was provided beyond a statement that nationwide bonds mitigate bonding costs by spreading these costs over a larger number of leases. The BLM does not anticipate a large impact to lessees and operators from this change, given the other options available, such as reinstating CDs and LOCs. The RIA provides additional details on the impact of eliminating nationwide bonds.

Therefore, the BLM does not adopt the recommendation to reinstate nationwide bonds and is not making any further changes to this section. As stated in the proposed rule, the BLM will be able to better tailor statewide bond amounts to the local conditions and State-specific requirements when reviewing a bond for adequacy.

Section 3104.4 Unit Operator's Bond

The BLM proposed eliminating operator bonds because they are seldom used and because the bonds are obsolete. The BLM has been treating and managing these bonds like statewide bonds and eliminating them would create efficiencies in the program. The BLM received several comments that supported the elimination of unit operator bonds for the reasons the BLM provided. The BLM also received a comment stating the BLM should keep unit operator bonds without providing a reason why these should be kept. The final rule eliminates unit operator bonds.

Section 3104.40 Surface Owner Protection Bond

The BLM proposed adding this new surface owner protection bond section, which is cross-referenced to 43 CFR 3171.19, to provide for an additional type of acceptable bond that can be submitted when the operator is unable to reach a surface access agreement with the surface owner. The BLM requested comments on whether the BLM should increase the minimum bond amount. The BLM received numerous comments on § 3104.40.

The BLM received comments opposing the inclusion of this provision on the basis that it duplicates State law and should only apply to lands where the surface is private, or that the BLM also should address the interplay between existing § 3171.19(b)(2) that allows for an “agreement” with the surface owner in lieu of bonding, noting such an agreement does not necessarily require payment of “compensatory damages” as proposed in § 3104.40. Comments also stated the BLM should clarify that such bonds are not intended to cover reclamation, but rather only compensate a surface owner for inadvertent, limited purpose, “reasonable and foreseeable damages to crops and tangible improvements,” as stated in the proposed rule.

Some comments supported the proposed $1,000 minimum bond amount, while others stated the minimum bond amount must be raised to at least $10,000 per well to support adequate remediation, plus an additional $2,000 per acre of disturbed land, and the impacts covered under the surface owner protection bond must be expanded beyond “the reasonable and foreseeable damages to crops and tangible improvements.”

As stated in the proposed rule, the BLM promulgated the current requirements for surface owner protection bonds through Onshore Order 1 in 2007 and subsequently codified these requirements in 43 CFR subpart 3171. This bond is for the limited purpose of ensuring a private surface owner's crops and other tangible improvements are protected. In response to comments, the BLM has revised final paragraph (a) to remove the phrase “to pay compensatory damages to the surface owner,” to clarify the purpose of these bonds and added the phrase “under 43 CFR 3171.19” to encompass the situation where an agreement is reached with the surface owner. The BLM reviewed the surface owner protection bond amount and determined it appropriate for the narrow purposes of the bond. This bond covers “the payment of such damages to the crops or tangible improvements ( i.e., agricultural, residential and commercial improvements, including improvements made by residential subdividers) of the entryman or owner.” See 43 U.S.C. 299(a). The BLM has not made any changes to the minimum bond amount. Paragraph I provides a process to increase the bond if the surface owner objects to the sufficiency of the bond. This mechanism adequately addresses the unique cases where the minimum bond amount may need to be increased.

Finally, the BLM declines to incorporate a provision that requires the BLM to defer to State bonding requirements for surface owner protection bonds. First, not all States require a surface owner protection bond if the surface owner and Federal lessee cannot complete a surface use agreement for operations. In addition, a State's surface owner protection bond provisions may not provide the same coverage as required in the BLM's surface owner protection bond because the State bonds are required under the State's law and not under Federal law. See Wyoming Stat Ann. section 30-5-402, Colorado Code Regs. section 404-1-704, or New Mexico Stat. section 70-12-6. Therefore, the BLM declines to incorporate a provision that requires the BLM to defer to State bonding requirements for surface owner protection bonds.

Section 3104.50 Increased Amount of Bonds

Although the BLM did not propose any changes to the existing § 3104.5, it did receive the following comments and recommendations for the BLM to: (1) require an increase in the bond amount when the wells covered by the bond exceeds the number of wells that the BLM originally used to determine the new minimum bond amounts; (2) incorporate the BLM's bond adequacy review policy into the regulations; (3) require a bond review when an operator temporarily abandons or shuts-in a Federal well; (4) change or expand the risk factors described in paragraph (b); (5) state that an operator may satisfy a demand for an increased bond amount by providing another form of security; (6) state that any person aggrieved by a decision to increase bond amounts may seek review of a decision through State Director review and appeal to the IBLA; (7) remove “uncollected royalties due,” alleging that the bond amount should not include amounts demanded, payment of which is stayed pending appeals under 30 CFR part 1243; (8) explicitly state that operators do not need to provide a full liability bond; and (9) require bonds from record title and operating rights holders for unpaid royalty payments.

The MLA requires the Secretary to ensure that bonding is adequate, and, after review of the comments, the BLM has determined that no changes are needed to this section at this time. The BLM's proposed changes and additions in 43 CFR 3104.1 and existing regulations are sufficient to ensure compliance with the lease terms. Bonds given to the BLM are performance bonds to guarantee performance of the lease requirements. The performance bond protects the BLM, and ultimately the taxpayers, from financial loss should the operator fail to perform and comply with the regulations and laws governing lease operations. This financial loss includes unpaid royalty amounts; however, the BLM will first use the funds to address all outstanding plugging and reclamation costs. The BLM did not make any changes to the appeal language that already exists in the regulations and provides for both IBLA appeals in 43 CFR 3000.40 and State Director review when BLM staff recommend increased bond amounts pursuant to 43 CFR 3165.3(b).

In the proposed rule, the BLM requested comments on whether to require a bond adequacy review when a well is temporarily abandoned. The BLM received comments in support and opposition to this proposal. After reviewing the comments, the BLM has decided not to require a bond adequacy review for a change in well status, including temporary abandonment of a well. The BLM can review the adequacy of a bond at any time, and the new reporting and operational requirements for operators of temporarily abandoned wells will allow enhanced oversight of these wells. The BLM considers the discretionary authority to review a bond, combined with the new reporting and operational requirements, sufficient to effectively manage any risks to the environment associated with these types of wells without needing to require a bond adequacy review.

The BLM declines to change or expand the risk factors described in paragraph (b). The BLM considers the existing risk factors to provide an adequate basis for reviewing and identifying the appropriate bond amount. In addition, the BLM may consider additional risk factors on a case-by-case basis due to the language, which states, “including, but not limited to,” in the existing regulations and in the final rule.

Further, the BLM may need to require an entity to provide a full liability bond. It is the BLM's responsibility to take proactive measures to minimize the liability associated with high-risk operators. To mitigate the public's risk with a high-risk operator, the BLM may need to require a full liability bond on a case-by-case basis; therefore, the BLM declines to explicitly state that operators do not need to provide a full liability bond.

The BLM also declines to require bonds from record title and operating rights holders, in addition to operators, for unpaid royalty payments. The BLM's bonds required for operations cover both environmental liabilities and unpaid royalty payments. At one point, the BLM did require bonds from lessees; however, the BLM moved away from this practice in the 1980's due to the administrative burden related to requiring lessees and operators to maintain a bond. The BLM declines to require bonds from record title and operating rights holders, in addition to operators, for unpaid royalty payments.

While the BLM used the median number of wells to determine the new minimum bond amounts, an increase to the bond based solely on the number of wells is unwarranted. The BLM will capture the need for any bond increases based on its bond adequacy reviews. It is the BLM's responsibility to take proactive measures to minimize the liability associated with high-risk operators, which may include full liability bonding in certain circumstances. The current BLM policy outlined in IM 2024-014, Oil and Gas Bonds Adequacy Reviews,^[18] supplements the requirements in this section by directing reviews of existing Federal bond amounts and requesting increases to the bond amounts based on the potential risk or liability posed by the operators. As stated in the proposed rule, similar bond adequacy review policy has been in place for the past decade, and the BLM has periodically revised that policy to account for changing risk factors including, critically, the status of the well(s) and the operator's compliance history. The BLM declines to incorporate risk factors into the regulation in order to retain flexibility in bond reviews and allow it to adapt guidance more quickly to changing needs. If the BLM issues a decision requiring an increase in the bond amount, the regulations do not prohibit the operator from satisfying this by providing another form of security.

Section 3104.70 Default

To improve clarity, the BLM proposed to divide the existing § 3104.7 into three separate paragraphs and included language to address what happens in the event a party fails to comply with the requirements. The BLM received a comment objecting to paragraph (b)(2), stating that the paragraph effectuates the equivalent of suspension or debarment even if the BLM does not pursue that route—with its corresponding procedural protections—under paragraph (b)(3). The BLM is not proceeding with proposed paragraph (b)(2), which refers to preventing the bonded principal from acquiring additional Federal leases, at this time. The BLM prefers to continue to address this situation through policy, as an operator can still come back into compliance even after the bond is collected once all reclamation has been completed and all monies owed the U.S. have been paid.

Because the BLM is deleting the proposed paragraph (b)(2), proposed (b)(3) is now redesignated as (b)(2) in the final rule.

Section 3104.80 Termination of Period of Liability

The BLM did not propose any changes to existing § 3104.8 but did receive comments urging the BLM to revise the section to clarify that any new bond supersedes and replaces any prior bonds, and that the liability of the prior surety is terminated. The current language addresses this comment by stating the period of liability for a previous bond will terminate once the BLM receives a new bond meeting the regulatory requirements.

Section 3104.90 Unit Operator and Nationwide Bonds Held Prior to June 22, 2024

The BLM proposed this new section to address the elimination of unit operator and nationwide bonds and to provide the timeline by which entities must comply with the new bonding requirements. The BLM received a number of comments recommending that the BLM adjust the minimum bond amounts for inflation. The BLM has addressed comments directed at increasing bond amounts for inflation in § 3104.1.

A comment asked how the BLM plans to terminate the liability of sureties under unit operator and nationwide bonds that are being eliminated. After the final rules goes into effect, the BLM will send a notice to the principals maintaining the bond explaining the new requirement to replace their bond. Once an acceptable replacement bond is received, the period of liability will be terminated on the prior bond under § 3104.80. A replacement bond is not considered acceptable unless it also has an assumption of liability rider which assumes any outstanding liability accrued by the prior bond.

Multiple commenters requested that the BLM exempt existing operations and bond amounts as part of the final rule or provide more time to meet the increased bond amounts. The BLM declines to exempt existing bond amounts. The BLM, GAO, and OIG have concluded that the BLM's current bond amounts are inadequate to protect the Federal resources. If the BLM were to exempt those bonds covering existing operations, the problems identified by the GAO and the OIG would persist. The GAO, in report GAO-11-292, Oil and Gas Bonds: BLM Needs a Comprehensive Strategy to Better Manage Potential Oil and Gas Well Liability,^[19] recommended that the BLM develop a strategy to increase the regulatory minimum bonding amounts over time and to more clearly define the conditions that warrant a bond increase beyond the minimum bond amounts. The BLM implemented these recommendations in policy; however, the GAO, in report GAO-19-615, Oil and Gas: Bureau of Land Management Should Address Risks from Insufficient Bonds to Reclaim Wells,^[20] went on to recommend that the BLM should take steps to adjust bond levels, for all bonds, to more closely reflect expected reclamation costs. Reading these two reports, it is clear that the BLM should not exempt bonds covering existing operations. Similarly, the OIG, in Report No. OI-OG-12-0085-I, BLM Oil and Gas Bonding Procedures,^[21] recommended that the BLM conduct and support bond adequacy reviews and bond increases periodically and do so before problems arise. If the BLM exempted the increased bond amounts for existing operations, the BLM would not be able to increase the bonds before problems arise for the existing operations. Further, increasing the bonds for all operators maintains a level playing field.

While the BLM declines to expand the phase-in periods overall, swapping them in final § 3104.1 to give individual bonds the longer phase-in periods will allow additional time for smaller operators with individual bonds to come into compliance. The holders of nationwide bonds are larger companies, which have increased staff and can more easily comply with the updated phase-in period to convert their nationwide bonds to statewide and/or individual bonds. The BLM updated the phase-in period in the final rule by requiring lessees and operators that currently use nationwide and unit bonds to come into compliance within 1 year of the effective date of the final rule. This phase-in period provides time for the BLM and its staff to process the increased and new bond amounts expected. The BLM has a total of 3,234 bonds: 975 individual or lease bonds, 1,987 statewide bonds, 19 collective (unit) bonds, and 253 nationwide bonds. Upon identifying that the majority of the bonds are statewide and individual bonds, the BLM determined that it made more sense to revise the phase-in period by requiring current nationwide bonds to be brought into compliance first and the others as follows:

• 1 year for nationwide and unit bonds,
• 2 years for statewide bonds, and
• 3 years for individual bonds.

Specifically, this phase-in period will provide individual lease bond holders—the majority of those affected by the provision of the rule, many of which are small businesses—more time to prepare for compliance, and, likewise, will allow the BLM to prepare for the associated workload.

Section-by-Section Discussion for Changes to 43 CFR Subpart 3105

Communitization Agreements

Section 3105.21 Where Filed

The BLM proposed to remove the requirement in the existing § 3105.2-1 to file the agreement in triplicate and to specify the minimum contents for such an agreement. The BLM received comments on this section stating that the BLM should include a fixed filing fee for CAs. As previously stated, the BLM considered proposing new fixed filing fees for Federal CAs but ultimately declined to add a fee due to the public benefit of allowing Federal and State minerals that might otherwise be wasted to be developed.

A commenter stated that paragraph (c), which recommends that an application be submitted at least 90 days prior to first production, overlooks that CAs are commonly submitted only after production has been obtained, and are usually effective retroactively to the date of first production. The BLM's proposed language did consider this fact, which is why the proposed section says “should” instead of “must.”

The final rule does not make further changes in response to these comments. The final rule did remove the acronym “CA” from the final regulatory text and replace it with “communitization agreement” for clarity and consistency.

Subsurface Storage of Oil and Gas

Section 3105.42 Purpose

The BLM revised the existing the existing § 3105.4-2 to clarify that gas storage agreement applications must include a bond. The BLM received a comment stating that such agreements should also be subject to a significant rental fee and bond. No additional changes are warranted in response to this comment because this section already covers the rental and bonding requirements. A fee is also required in § 3105.41.

Section-by-Section Discussion for Changes to 43 CFR Subpart 3106

The BLM proposed to add one section, remove two sections, and update the headings of each section to remove the outdated question and answer format that appears in the existing regulations. The BLM received a comment on this subpart stating the BLM should, as a matter of transparency, codify the policies and procedures that the authorized officer is required to follow with regard to approving and overseeing lease transfers. The BLM did not make any changes to this subpart based on this comment. The BLM has a handbook, H-3106-1, Transfers by Assignment, Sublease, or Otherwise, that provides the necessary guidance to the BLM to adjudicate these transfers. The public may obtain copies of this handbook, which is not currently available online, from any BLM state office.

Section 3106.10 Transfers, General

The BLM proposed splitting the existing § 3106.1 paragraph (a) to provide clarity, added a new paragraph (b) clarifying that the BLM will deny a transfer in certain situations, and added a new paragraph (c) limiting the transfer of operating rights. The BLM received a comment recommending the BLM address the impact of the severance of operating rights from record title interest. The BLM agrees with this comment. The BLM receives a multitude of transfers of operating rights that are unnecessary because those rights have never been severed from the record title. The final rule includes a new paragraph (b) to state that a record title assignment conveys both record title and operating rights unless operating rights have been previously severed. The remaining paragraphs are redesignated accordingly.

The BLM received comments on the proposed paragraph (b), which is final paragraph (c). The BLM added this paragraph to state an assignment of a separate zone, deposit, depth, formation, specific well, or of part of a legal subdivision, will be denied. One commenter supported this language, while another commenter stated that wellbore assignments are not ambiguous, because wellbores have API numbers that include bottom hole data and that are within approved drilling and spacing units specifying the acreage being drained by the wellbore. Wellbore rights are private agreements between private parties and need not be reported to the BLM. If the intent is to transfer a specific legal surface area and/or depth of the operating rights for a lease, a legal description of that area and depth is required.

A commenter stated that the language in the proposed paragraph (c), which is final paragraph (d), providing that operating rights interests may only be divided with respect to legal subdivisions is ill-advised, as it implicitly would preclude transfers of operating rights as to parts of legal subdivisions. The BLM disagrees with this comment. The paragraph must be read in conjunction with paragraph (a) that specifically states, “Leases may be transferred by assignment or sublease as to all or part of the acreage in the lease or as to either a divided or undivided interest therein.” The final rule adopts the proposed paragraph unchanged.

Section 3106.20 Qualifications of Assignees and Transferees

The BLM proposed revisions to the existing § 3106.2 to clarify that entities to whom record title or operating rights are being transferred must be qualified to hold a lease. The BLM received one comment on this section, requesting that the BLM revise the section to clarify that the new bonding requirements apply only to operators and not all lessees, assignees, and transferees. The BLM is not making any changes to the section in the final rule, because the bonding requirements may apply to any entity to whom an interest is being transferred and not just an operator.

Forms

Section 3106.41 Transfers of Record Title and of Operating Rights (Subleases)

The BLM proposed revising the existing § 3106.4-1 to require the use of an approved form to accomplish these transfers and to reduce the required number of copies the transferee must file with the BLM from three to two. The BLM received a comment on this section stating the BLM could not change from triplicate to duplicate filings as laid out in the proposed rule, because the required number of originally executed transfer forms is fixed at three by statute.

The BLM proposed this change in accordance with the Government Paperwork Elimination Act (GPEA), Public Law 105-227. Section 1707 of the GPEA specifically states, “Electronic records submitted or maintained in accordance with procedures developed under this title, or electronic signatures or other forms of electronic authentication used in accordance with such procedures, must not be denied legal effect, validity, or enforceability because such records are in electronic form.” After reviewing the comment and 30 U.S.C. 187a, the BLM determined that it should reinstate the triplicate filing until the BLM implements an electronic filing method. At that time, the BLM would only require one electronic filing per the GPEA. Therefore, the BLM reinstated the triplicate-filing requirement in this final section; however, the final rule also states the BLM will not require triplicate copies of the assignment or transfer when it is electronically submitted.

Section 3106.42 Transfers of Other Interests, Including Royalty Interests and Production Payments

The BLM proposed revising the existing § 3106.4-2 to require transfers of overriding royalty interest to be submitted on the BLM's approved form. The BLM received a comment asserting that the use of a BLM-approved form should not be required, since the transfer is not subject to BLM approval.

Although transfers of overriding royalty interest do not require the BLM's approval, an overriding royalty interest is an interest in a Federal oil and gas lease. By requiring such transfers to be on an approved BLM form, the transferee is certifying that they are qualified to hold the interest. The BLM adopts this section in the final rule without further changes.

Section 3106.60 Bond Requirements

The BLM proposed changes to existing § 3106.6 to clarify that an entity to whom an interest in the lease is being transferred has the requisite level of bonding. The BLM received a comment questioning why—if the previous lessee is only transferring a portion of its leases—the transferee must maintain the same level of bonding in cases where the previous entity had many more leases and other reasons for an increased bond amount. A commenter stated, for example, that the proposed rule provision would result in a new lessee, record title owner, or operating rights owner being required to maintain a full statewide bond when the assignor or transferor only transferred a portion of its Federal wells.

The BLM does not intend to require such results. Therefore, the final rule removes the phrase “(including a statewide bond)” as a statewide bond may not be necessary. When a lessee or operating rights owner maintains a bond for a lease, the BLM expects the transferee or assignee to maintain the same level of bonding for operations on the transferred lease(s). If previous lessees or operating rights owners held a statewide bond, the BLM will work with the new owner to identify the appropriate level of bonding for that lease.

The BLM received a comment recommending a revision to this provision to include the following language: “to the same extent as the assignor's or transferor's bond, or to a greater amount if deemed necessary following a bond adequacy review.” This addition was recommended to ensure the adequacy of bonds at the time of lease transfer. The commenter also requested that the BLM adopt additional requirements expressly requiring bond adequacy review at the time of transfer. The comment went on to state that such a rule should require the assignor or transferor to furnish the BLM with information on the number, type, and depth of all wells existing on the lease to be transferred, and should require the BLM to use this information—and any other relevant information—to assess whether the existing bond amount is adequate to ensure prompt and complete reclamation of all existing wells and any new wells that may be drilled by the assignee or transferee.

The BLM received a comment stating the BLM should harmonize this section with § 3104.20, which places the bonding obligation for a lease on the operator. The BLM primarily requires bonds from the operator instead of the lease interest owners (record title or operating rights owner). However, the BLM will require a bond from the lessees when the operator's bond is insufficient.

The BLM received a comment stating the BLM should include a requirement that the assignee's or transferee's bond be in place prior to the approval of the assignment or transfer. The BLM concurs and already requires the bond to be in place prior to approving the assignment or transfer and therefore sees no need for the change.

The BLM received a comment recommending that the BLM examine and certify the transferee's or assignee's financial viability before approving the transfer or assignment. This recommendation is not adopted in the final rulemaking as the BLM does not currently have the staff or expertise to perform this function.

Approval of Transfer or Assignment

Section 3106.72 Continuing Obligation of an Assignor or Transferor

The BLM proposed revising the existing § 3106.7-2 by removing the question-and-answer format in the title and clarifying the responsibilities of the assignee or transferee. The BLM received a comment recommending that the BLM change the language in paragraph (b) to delete the references to “operating rights” and make it clear that in the case of the transfer of any interest in a lease, the transferor must maintain financial assurances subsequent to the approval of the transfer and that all transferors should be required to maintain financial assurances for a predetermined suitable period after a transfer is approved.

The BLM is not making any changes to the final rule based on this comment, as the proposed regulations already address the concerns expressed by the commenter. Under § 3104.80, when the BLM terminates the “period of liability” on a bond, this action sets an exact date after which no new liability may accrue under that bond. In addition, the BLM prefers to keep the phrases “assignment or transfer,” so it is clear this section applies to both.

The BLM received a comment on paragraph (b) requesting clarification on the obligations described. The BLM has revised this paragraph in the final rule to clarify the obligations of the assignor or transferor once the BLM approves an assignment or transfer. The last sentence in paragraph (b) now states “It also includes responsibility for plugging wells drilled and removing facilities installed or used before the effective date of the assignment or transfer.” The BLM has added this sentence to provide a more comprehensive list of lease obligations; however, this is not a complete list. The assignor or transferor will continue to be responsible for other lease obligations, not limited to the items enumerated in § 3106.72(b).

Section 3106.73 Lease Account Status

The BLM proposed changes to the existing § 3106.7-3 to remove the passive voice and to clarify that the lease account must be in good standing with all royalties paid and lease obligations met. The BLM received a comment recommending a change to this provision by providing 60 days to allow a transferor whose account is delinquent to remedy the delinquency before the BLM rejects a transfer.

This recommendation is not adopted in the final rule. While some state offices suffer from a backlog of transfers, the BLM aims to adjudicate transfers within 60 days as required by the MLA. Adding the suggested language would prolong the time it takes the BLM to adjudicate an assignment or transfer. The denial of a transfer for this reason does not preclude the assignor or transferor from filing a new transfer with the appropriate filing fee after the lease account has been brought into good standing.

Section 3106.76 Obligations of Assignee or Transferee

The BLM proposed changes to the existing § 3106.7-6 to remove the question-and-answer format in the title and to update the language to be consistent with other changes being proposed. The BLM received a comment stating the regulation should also mandate the maintenance of financial assurances by the assignor of record and the transferor of operating rights for a suitable amount of time after the transfer or assignment to ensure the continued protection of the Federal resource: (1) during the transition to a new lessee or operator; and (2) in the event of a latent issue that was not reasonably identified at the time of the transfer or assignment and for which the transferee or assignee refuses to accept responsibility.

No changes to the rule are necessary because an assignor or transferor remains liable for reclamation of wells during the period of liability. The period of liability is fixed under § 3104.80, when the BLM terminates the “period of liability” on a bond. After this date, which is an exact date, no new liability may accrue under the bond. Even if the liability is not apparent at the time the liability terminates, the assignor or transferor would remain liable.

Other Types of Transfers

Section 3106.81 Heirs and Devisees

The BLM proposed to split the existing § 3106.8-1 paragraph (a) into two separate paragraphs for clarity and included a reference to the new filing fee in paragraph (b). The BLM received a comment on the proposed § 3106.81 stating the proposed rule should be revised to state that the deceased party's rights will be assigned or transferred to the appropriate successors, which implies an affirmative act—whereas such a transfer in fact takes place by operation of law, and so the term “assignment” is misused in this context.

The BLM agrees and has revised the final paragraph (a) to update the phrase “their rights will be assigned” and inserts instead “their rights would be assigned.” The BLM also removed the word “assignment” from paragraph (b) and inserted “transfer” instead.

Section 3106.83 Corporate Mergers and Dissolution of Corporations, Partnerships, and Trusts

The BLM proposed to revise and update the title of the existing § 3106.8-3 and proposed splitting the existing paragraph into three to improve clarity. The BLM received a comment on § 3106.83 stating the requirement for a filing fee is noted only as to corporate mergers, whereas the fee schedule in the proposed rules under § 3000.120 of this title lists a fee that covers corporate merger and corporate dissolution.

The BLM agrees with this comment and in the final rule has updated the phrase in paragraph (d) from “the processing fee for corporate merger” to “the processing fee for corporate merger or dissolution of corporation, partnership, or trust.”

9. Section-by-Section Discussion for Changes to 43 CFR Subpart 3107

Section 3107.10 Extension by Drilling

The proposed rule revised the existing § 3107.1 for clarity by splitting the first paragraph into two and adding a new paragraph to address directional or horizontal wells drilled off lease. One commenter stated language should be added to confirm that a lease is held by production from a directional or horizontal well.

The BLM has not made any changes based on this comment, because this application is already clear. As stated in § 3107.21, a “lease will be extended so long as oil or gas is being produced in paying quantities.” This language is clear that production on and attributed to any lease will be held by production from a directional or horizontal well. In addition, the BLM's Handbook H-3107-1, Continuation, Extension, or Renewal of Leases, states that “for a lease to be continued by production, it must contain a well capable of producing oil and/or gas in paying quantities.” The public may obtain copies of this handbook, which is not currently available online, from any BLM state office. This direction will include all leases that the directional or horizontal wells drilled into and producing from a Federal lease.

Production

Section 3107.22 Cessation of Production

The BLM proposed changes to the existing § 3107.2-2 in response to IBLA decisions holding that the section conflicted with the MLA. In this final rule, the section now states that a lease in its extended term expires 60 days after production ceases, and not after the lessee receives notice from the BLM. A comment expressed concern that this change may cause confusion and unintended consequences, as the operator of the well may not be the same as the record title owner and timely notice of a cessation of production may not be received to remedy the non-production and preserve the lease.

The BLM understands this concern; however, as explained in the preamble to the proposed rule, multiple IBLA cases have held that the existing regulation directly conflicts with section 17(i) of the MLA (30 U.S.C. 226(i)).

The BLM received a comment stating the last sentence in this paragraph should be amended to clarify this section. The BLM agrees and has revised the final rule by inserting the word “paying” prior to “production”.

Extension of Leases Within Agreements

The BLM received a comment stating that the undesignated center heading that appeared immediately above proposed § 3107.31 is misleading and could easily be interpreted to mean the extension of agreement terms as opposed to the extension of leases within agreements.

The BLM agrees and the final rule adopts this recommendation and changes the heading from “Extension for Terms of Agreements” to “Extension of Leases Within Agreements.”

Section 3107.31 Leases Committed to an Agreement

The BLM proposed to update the title of the existing § 3107.3-1, remove a reference to a provision that is no longer applicable, and add a new paragraph to address IBLA decisions pertaining to production in paying quantities. A comment stated the rule should clarify that unitized leases in an extended term cannot be further extended unless it is through production. The comment requested that the BLM clarify that the mere commitment of a lease to an agreement would not extend the Federal lease. No further changes are warranted to the final rule, because paragraph (a) already states “ provided, that there is production of oil or gas in paying quantities under the agreement prior to the expiration date of such lease.”

Finally, the BLM deleted the second “for” to clarify that both conditions must exist for the leases to continue to receive the extension. For the leases to receive this extension, (1) the leases must be committed to the authorized unit agreement and (2) the well must continue to be capable of production in leasing paying quantities (able to pay out the operating costs of the well).

Other Extension Types

A comment stated that the undesignated center heading that appeared immediately above proposed § 3107.71 is meaningless and should be changed. The final rule adopts this recommendation and changes the title from “Other Types” to “Other Extension Types.”

10. Section-by-Section Discussion for Changes to 43 CFR Subpart 3108

Termination by Operation of Law and Reinstatement

Section 3108.21 Automatic Termination

The BLM proposed changes to the existing § 3108.2-1 to reflect policy changes by ONRR and to address IBLA decisions. The changes included adding a new paragraph (c) clarifying when the automatic lease termination would apply. Some comments supported the addition of paragraph (c). Other comments stated the preamble to the proposed rule included a misleading example referencing lease suspensions that may require additional rentals when they are lifted that could result in conflict and confusion if left uncorrected.

That criticism is misplaced for the reasons discussed in the context of § 3103.42 in this preamble. To be clear, such a notice will depend on the timing of the lifting of the suspension in relation to the lease anniversary date. Consider the following hypothetical example: A lease is issued effective 7/1/90 with a five-year primary term, so it will expire on 6/30/95. The lessee paid the rental timely for the fourth lease year which ended on 6/30/94. The BLM granted a suspension of operations and production effective 4/1/94. The suspension was lifted effective 9/1/94. The revised expiration date of the lease is therefore 11/30/95, because the lease is extended an additional five months to account for the five months in which the suspension was in place. The rental paid for the 1993-94 lease year covers the remaining three-month period of the fourth lease year from 9/1/94 to 11/30/94. The prorated rental is to be requested from the lessee for the seven months from 12/1/94 through 6/30/95 (to bring the regular rental due date back to the lease anniversary date). No changes were made to the final rule based on this comment.

Section 3108.22 Reinstatement at Existing Rental and Royalty Rates: Class I Reinstatements

The BLM proposed changes to the existing § 3108.2-2 to reflect the fact that ONRR accepts rental payments through its online system. The BLM received a comment on paragraph (a)(2), asserting the change in this subparagraph would narrow the definition of “reasonable diligence” to include only rental payments made through ONRR's online system on or before the lease anniversary date and disregards ONRR's continuing practice of accepting non-electronic rental payments in some circumstances that would effectively eliminate reasonable diligence as grounds for Class I reinstatement. The BLM agrees and has revised the final rule by removing the phrase “through its online rental payment system” from paragraph (a)(2).

The BLM received a comment on paragraph (a)(3) stating that increasing the filing fee for Class I reinstatements from $90 to $1,260 is disproportionate to the administrative fee for Class II reinstatements which would remain at $500. As stated in the preamble to the proposed rule, the BLM considered moving the existing fee for Class II reinstatements to § 3000.120 for inclusion alongside the other fixed filing fees, increasing the fee to reflect the processing costs, and then adjusting the fee annually for inflation. However, the MLA, at 30 U.S.C. 188(e), specifically states for Class II lease reinstatements that “[t]he lessee of a reinstated lease shall reimburse the Secretary for the administrative costs of reinstating the lease, but not to exceed $500.” Accordingly, the BLM does not have the authority to increase this fee. The BLM also considered reducing the Class I reinstatement fee to $500 for parity with the Class II reinstatement fee and concluded that doing so would be insufficient to cover the BLM's administrative costs.

Section 3108.30 Cancellation

The BLM proposed revising the existing § 3108.3 to remove language in paragraph (a) that repeatedly called for the BLM to provide notice to the lessee prior to cancellation. The BLM received a comment stating that a provision should be added stating leases are subject to cancellation if the lessee is found not to be a “qualified lessee” or a “responsible lessee.” No changes have been made to the final rule as the BLM does not have the authority under the MLA to cancel a lease for these reasons. 30 U.S.C. 188. Further, the existing requirements at § 3102 would be applied prior to the issuance of a lease, and these requirements address this concern.

11. Section-by-Section Discussion for Changes to 43 CFR Subpart 3109

Section 3109.15 Compensatory Royalty Agreement or Lease

The BLM revised the existing § 3109.1-5 to align the terms of a lease issued under a ROW to those for a competitive lease. A commenter caught a technical error in subparagraph (c)(1) of the provisions of 43 CFR part 3100, where the BLM referenced a regulatory section number that does not exist (§ 3101.20). The BLM proposed and is removing the regulatory section numbers for headings that have no text associated with them, which included § 3101.2 in the previous regulations, and changed these sections to undesignated center headings. Therefore, the final rule makes a minor technical change to correct this error. The statement of “except § 3101.20” in paragraph (c)(1) has changed to “except §§ 3101.21, 3101.22, 3101.23, 3101.24, and 3101.25.”

Sections 3109.21-3109.22 [Reserved]

In the final rule, the BLM removes the existing reserved §§ 3109.2-1 and 3109.2-2 as these sections do not need to be reserved. In the previous regulations, the BLM reserved § 3109.2-1 for the “Authority to lease” and § 3109.2-2 for the “Area subject to lease.” The BLM incorporated the authority to lease in 43 CFR 3100.3 and provides the area to lease in § 3109.20; therefore, the BLM no longer needs to reserve these sections in the final rule.

12. Section-by-Section Discussion for Changes to 43 CFR Part 3110

The final rule removes the existing 43 CFR part 3110 in its entirety. Multiple commenters expressed support for the elimination of 43 CFR 3110 to comply with Congress' repeal in the IRA of noncompetitive leasing for Federal onshore oil and gas minerals.

13. Section-by-Section Discussion for Changes to 43 CFR Part 3120

The BLM proposed to add two new sections and remove four sections from part 3120 to provide clarity and to ensure these provisions are consistent with other changes being made. The BLM received several comments on part 3120. Some comments specifically requested that the BLM not issue new leases in certain areas of the country. Some comments recommended additional paragraphs such as including denial criteria based on consideration of localized conditions and lands already subject to various types of adverse impacts. These comments are directed at the land use planning process, which is when the BLM evaluates whether lands should be open or not to leasing. Because these regulations govern the leasing and development process, these comments are outside the scope of this rulemaking.

Section 3120.11 Lands Available for Competitive Bidding

The BLM proposed changes to the existing § 3120.1-1 to reflect Congress' repeal of noncompetitive leasing in the IRA and revised the language in the introductory paragraph such that it more closely aligns with the Act.

Some comments argued that the proposed changes give the BLM more discretion for leasing than granted by the MLA; however, these arguments were made in reference to the timing of holding quarterly lease sales and not with respect to the BLM's discretion regarding what lands may be offered for lease. The introductory paragraph in this section states, “All lands eligible and available for leasing may be offered for competitive auction.” The BLM changed the “shall” to “may” to clarify that the Secretary retains the discretion to decide, even after lands have been determined to be eligible and available, what lands will ultimately be offered for lease. Timing of any lease sales is addressed in final § 3120.12(a) which was modified to state, “Each BLM state office will hold sales at least quarterly if eligible lands are available for competitive leasing.”

One commenter objected to the addition of the term “eligible” to this section. The BLM has not made any changes based on this comment as the proposed language merely reflects the language in the MLA at 30 U.S.C 226(a) and (b).

Another comment recommended that the BLM consider issuing a protective lease covering open Federal acreage located in an existing drilling block to provide a mechanism for a unit operator to develop its drilling block, including the unleased Federal minerals. The BLM cannot issue a protective lease, as proposed in the comment, under the MLA. The BLM may only issue a protective lease through a competitive lease sale based upon the law at 30 U.S.C. 226 and due to drainage of the Federal minerals (see 43 U.S.C. 1457; see also Attorney General's Opinion of April 2, 1941 (Vol. 40 Op. Atty. Gen. 41)). The BLM did not make any changes to the final rule based on this comment.

One commenter recommended removing “including but not limited to” from the introductory paragraph and inserting a new subparagraph (a) to state “lands that have been identified as preferred leasing areas in a current land use plan as well as lands identified as exclusion areas in a current land use plan shall not be available for leasing.” The BLM did not make any changes to this section of the final rule. The BLM already identifies the lands closed to leasing or open to leasing in its land use plans. In addition, the BLM does not identify “preferred leasing areas” within its land use plans. Since the BLM did identify that the lands must be available for leasing at the beginning of the statement, the BLM declines to make the changes proposed by the comment.

Section 3120.12 Requirements

The BLM proposed changes to the existing § 3120.1-2 to reflect current practices in holding lease sales via the internet, a new paragraph (c) to strengthen and revise the bidding process, the redesignation of paragraph (c) to (d), and inclusion of the new minimum bid amount. One comment recommended that the BLM add language clarifying that the BLM's discretion also applies to the timing of lease sales, and, specifically, that a sale need not be held if there are no eligible or available lands. The BLM has not made any changes to the final rule based on this comment, because paragraph (a) already states “Each BLM state office will hold sales at least quarterly if eligible lands are available for competitive leasing.”

The BLM received a comment stating that paragraph (d) should state the minimum bid amount instead of referring to the BLM's website and changes to the bid amount should be made through the regulatory process. The final rule does not adopt this recommendation, as the minimum is stated in regulation: the BLM has moved the minimum bid amount required to the Fiscal Terms Table at § 3103.1, and all of the fiscal terms will be adjusted every 4 years through the regulatory process. Please note that the BLM will not adjust the minimum bonus bid until the amount set by the IRA becomes a minimum after August 16, 2032.

Section 3120.30 Nomination Process

The BLM requested comments on whether the formal nomination process should be retained in regulations and, if so, what changes to the formal nomination process should be made. The BLM received comments supporting the retention of the nomination process to promote leasing in areas with greater potential for fluid minerals to be produced. The BLM received comments stating the BLM should implement a single nominations process that combines elements of formal nominations and expressions of interest. These commenters contended that, by exercising its authority at the front end regarding what public lands it will consider for leasing, the BLM would reduce land speculation, save time and resources, and create greater certainty for all parties. The BLM received comments supporting the elimination of § 3120.30 stating this section is unclear, confusing, would only be used to limit lease areas, and that the BLM does not have the level of technical expertise required to adequately analyze lands for expected yields of oil and gas.

The final rule removes the formal nomination, existing §§ 3120.3 through 3120.3-7 and proposed §§ 3120.30 through 3120.33, which the BLM has never used and which generally increases the time and resources necessary to hold lease sales.

Expression of Interest

The BLM proposed adding a new section to address the process for EOIs, which previously had not been codified in regulation. The proposed rule also included the new filing fee requirement for EOIs in paragraph (d) as required by Congress in the IRA (see also the Fiscal Terms Table in final § 3103.1). The final rule redesignates the citation numbers throughout this section consistent with the removal of sections that pertained to the nomination process. The BLM received several comments on this section. Based on the BLM's review of the comments, the final rule splits the proposed § 3120.41 into two new sections. The first section describes the requirements for an EOI (proposed paragraphs (a) through (e), and (g)) and a new section is created for the preference criteria (proposed paragraph (f)).

Section 3120.31 Expression of Interest Process

The final rule renames the proposed section from “Process” to “Expression of interest process” and redesignates § 3120.31 from proposed § 3120.41 to final § 3120.31 as doing so will provide consistency with the previous regulations. This section contains paragraphs (a) through (d) of the proposed § 3120.41. Proposed paragraph (g) has been redesignated as paragraph (e).

One comment objected to the requirement that, for split estate lands under paragraph (b)(6), an EOI submitter must submit the private surface owner's name and address, even though there is no explicit and corresponding statutory requirement, and even though the information is often difficult and time consuming for submitters to obtain. The BLM has not made any changes to the regulation based on this comment. Under section 1835 of the Energy Policy Act of 2005 (43 U.S.C. 15801), Congress directed the Secretary of the Interior to review current policies and practices with respect to management of Federal subsurface oil and gas development activities and their effects on the privately owned surface. The Split Estate Report to Congress, submitted in December 2006, documents the findings resulting from consultation on the split estate issue with affected private surface owners, the oil and gas industry, and other interested parties. In the Report, the BLM identified in Issue 4 that “surface owners would like to be contacted when the BLM is leasing Federal mineral estate underlying their property. Notification is requested when parcels are nominated and offered on a competitive lease sale.” As a result of work done to implement portions of the Energy Policy Act of 2005 relating to split estate lands, the BLM asked individuals submitting EOIs to provide the name of the private surface owner. This is outlined in BLM Handbook H-3120-1, Competitive Leases.^[22] This information allows the BLM to notify the surface owner when the BLM initiates a lease sale that contains a parcel with minerals underlying the owner's surface. The BLM will require this information under paragraph (b)(6) to ensure the BLM provides adequate outreach to the private surface owners overlying Federal minerals.

The BLM received a number of comments on paragraph (d), which requires payment of the per acre fee required by Congress in the IRA. Some commenters recommended that the BLM should require the fee to be payable by the winning bidder instead of the individual that submitted the EOI or that the fee should be refunded if: (1) the lands are not included in a sale; (2) the individual that submitted the EOI does not obtain the parcel at the lease sale; or (3) the individual submitted an EOI covering lands already submitted on a prior EOI submittal. The BLM cannot make any of these changes as Congress did not provide the Secretary with this discretion in the IRA. That Act requires the assessment of a nonrefundable fee payable by any person submitting an EOI.

In proposed paragraph (e), the BLM included language allowing the BLM to include lands in a sale on its own initiative. The BLM received comments objecting to the provision, asserting it would allow the BLM to include lands it knows to be unattractive and does not account for the BLM's policy on unleased lands within CAs. That policy directs the BLM to offer such lands for competitive leasing as soon as possible, such that the lands should not be subject to nomination limitations or EOI criteria set forth in the proposed rule. After reviewing these comments, the BLM is removing proposed paragraph (e) from the final rule. That paragraph is unnecessary because § 3120.11(f) already gives the BLM the option to include lands selected by the authorized officer in a sale. The removal of paragraph (e) from this section clarifies that Bureau motions are not considered or counted as EOIs for purposes of calculating the percent of EOI acreage offered on oil and gas lease sales during the past year for renewable development under 43 U.S.C. 3006.

As a final note, the BLM is clarifying that it only self-nominates lands to protect the Federal minerals and the public interest. The BLM calls self-nominated lands a Bureau motion. The BLM creates a Bureau motion to protect the Federal mineral estate from drainage or when there are unleased Federal minerals within an approved oil and gas agreement. The BLM tracks information on which parcels originate from an EOI or a Bureau motion within the BLM's National Fluid Lease Sale System. As of December 14, 2023, approximately 92 percent of the lands under review came from an EOI. The BLM identified that from the nominations received in calendar year 2023, the BLM has a total of 83,917.23 acres of pending lands under review with only 6,815.36 acres created from Bureau motions. The remaining 77,101.87 acres under review for future oil and gas leasing are created from EOIs.

The proposed paragraph (g) has been redesignated to paragraph (e) in the final rule and reflects the BLM's long-standing authority to determine which lands will ultimately be offered for sale. Therefore, the BLM makes no changes to this paragraph.

Section 3120.32 Expression of Interest Leasing Preference

The BLM revised the final rule by creating new § 3120.32, which had appeared in proposed § 3120.41(f). Both the proposed and final sections address the preference criteria that the BLM may use when determining whether, when, and in what order certain lands specified in an EOI should be processed and offered in a lease sale. Creating the new section required certain redesignations and reorganizations.

The BLM received many comments on this proposed section. Most of the comments were generally supportive of the preference criteria, though some commenters were opposed to the use of the criteria. Some comments that expressed support for the preference criteria requested additional criteria be considered or requested an expansion of the proposed criteria to include greater specificity. As discussed in Section III.B.2 and III.B.7 of this preamble, these comments recommended revising the criteria to better account for impacts on GHG emissions and climate change, environmental justice, the environment (often suggesting criteria for specific habitat, natural resource areas, land or aquatic conditions, species, or other factors), cultural and Tribal resources, specific recreational uses, and protected areas such as special conservation areas, parks, and wilderness areas.

Other comments opposed the consideration of any criteria by: (1) stating that adding preference criteria to preliminary leasing decisions will lead to delays, create uncertainty, and detract from the predictability of the process; (2) expressing concern that the application of the preference criteria would exclude lands that would be considered exploratory and that such exploratory actions benefit the public at large; and (3) stating that the proposed criteria process was duplicative of other statutory processes, such as those under the Endangered Species Act and FLPMA.

Many commenters also expressed views on the proposed process for considering criteria before offering parcels. Some comments stated the application of the criteria is not a transparent process or could be subjective. Some commenters expressed concern that the BLM lacks the technical expertise and resources needed to apply some of the preference criteria and sought clarifying language to ensure consistent consideration of the criteria by BLM offices, including identifying the sources of information that offices are expected to use. Specifically, for example, some comments stated that the proposed rule does not explain how the criteria will be used when conflicts between development and other uses occur or how the preferences will be weighted. Commenters offered varied approaches for how the criteria should be applied. For example, some comments stated that lands with a low preference should be excluded from leasing, and other commenters suggested that an EOI should represent compelling evidence of some potential for development. Additionally, some comments stated the preference criteria should not be applied to lands administered by another Federal agency.

After careful consideration of the comments received, the BLM is clarifying in the regulatory text that the BLM will consider the preference criteria as part of the scoping process for leasing. During the leasing process, the BLM will apply the criteria after the conclusion of the scoping process but before issuing a draft NEPA document for a lease sale. As such, the BLM has revised the last sentence in the introductory paragraph. The BLM is inserting the phrase “In evaluating the lands to be offered, as part of the scoping process.”

Applying the preference criteria after scoping but before publication of the NEPA document allows the BLM to consider public comment on the environmental analysis for the lease sale at the outset of the leasing process and to better manage its workload by directing its resources towards tracts that are most likely to be developed. Since BLM New Mexico's May 25, 2023, oil and gas lease sale, the BLM has been applying the preference criteria in this way through the BLM's policy IM 2023-007, Evaluating Competitive Oil and Gas Lease Sale Parcels for Future Lease Sales.^[23] This process enables the BLM to conduct preference criteria review while the public and industry provides scoping comments, which the BLM will incorporate into its determination in the NEPA compliance documentation.

This procedural clarification also addresses many of the comments received. First, considering the criteria at the conclusion of the scoping process will allow the public to provide input that the BLM should consider when applying the criteria to the preliminary list of lands for a lease sale. Consistent with § 3120.42, the BLM will provide at least 30 calendar days for public comment on the preliminary parcel list as part of the scoping process. During this public scoping period, commenters can raise site-specific considerations that should be considered in selecting parcels. These could include many of the concerns commenters raised as potential additional criteria, such as the potential for development, environmental justice considerations, and other important uses or resources like watershed vitality. Public input also will help ensure that the BLM has the necessary data and information to evaluate the criteria. In response to public input, the BLM will be able to consider new information raised and announce its initial conclusions on the preference criteria in the draft NEPA document. Second, these steps provide transparency for the public to see how the BLM is considering the criteria on a case-by-case basis. For example, in some scenarios, it may allow the public to understand why low preference parcels are being offered for leasing or to recognize when there is a conflict between resources. This increased transparency and ability for public input are responsive to the comments received, including those that urged the BLM to add additional criteria that should be considered for the localized area and those that expressed concern that the process lacked clarity or transparency. At the same time, the BLM will more efficiently manage the process by applying the criteria before publishing the draft NEPA document. If the BLM applied the criteria to the parcels after publishing the draft NEPA document, the BLM may need to re-work or apply amendments and changes to both the draft NEPA documents and the competitive lease sale notice.

The BLM moved the statement “at minimum” to the end of the final sentence in § 3120.32. Consistent with the original wording in the proposed rule that directed the BLM to consider “at a minimum” the listed criteria, this language allows the BLM's authorized officer to consider other unenumerated criteria specific to local circumstances, including those raised in public comments. As such, the BLM declines to add, modify, or remove the preference criteria that were proposed. On a case-by-case basis, stakeholders and the public will be able to provide the BLM with pertinent information on the criteria or additional criteria to consider.

In addition, the BLM will not promulgate a specific weighting for the different criteria within § 3120.32 as the weighting will depend on the specific location and conditions in relation to local circumstances. Instead, the BLM will use the scoping process to inform the weighting for the different criteria. This will allow the BLM to incorporate public feedback on the parcels to be offered on the sale and ensure the BLM appropriately weighs the critical uses or resources. This will also allow the BLM to move forward with parcels that could be considered exploratory. The operator for the area can inform the BLM during the scoping period that it is interested in exploring for oil and gas in this area, which would provide for the BLM to weight the potential development criteria lower. The BLM disagrees that consideration of the preference criteria increases uncertainty or will lead to delays; rather, considering the criteria at the beginning of the leasing process will allow the BLM to more efficaciously select parcels for which to conduct environmental analysis and to offer at the lease sale. Ultimately, this will increase certainty and efficiency in the leasing process by decreasing the number of parcels offered that would not be leased, and relatedly, the number of parcels that are leased but never developed. By considering parcels that make the most sense to lease in terms of expected yields of oil and gas, the BLM is addressing concerns expressed in GAO's report, GAO 21-138, Onshore Competitive and Noncompetitive Lease Revenues.^[24] The improved management of agency workflow will better use the BLM's time and resources and will not result in delay.

Additionally, rather than duplicating provisions under other statutes, the preference criteria will provide the BLM with an additional tool, consistent with the Secretary's broad discretion to lease lands for oil and gas development, to direct leasing and better avoid or manage conflicting uses of public lands at the outset of the leasing process. Because scoping is part of the NEPA process, application of the criteria will not be duplicative of the NEPA process.

The MLA vests the Secretary with broad discretion to decide, up until the time of lease issuance, whether particular parcels of Federal land “may be leased” for oil and gas development, see 30 U.S.C. 226(a). The MLA does not specify how and when this decision is to be made, and courts have consistently recognized the Secretary's discretion. E.g., Udall v. Tallman, 380 U.S. 1, 4 (1965) (“The [MLA] gave the Secretary of the Interior broad power to issue oil and gas leases on public lands”)  United States ex rel. McLennan v. Wilbur, 283 U.S. 414, 419 (1931) (“there is ground for a plausible, if not conclusive, argument that so far as it relates to the leasing of oil lands [the MLA] goes no further than to empower the Secretary to execute leases which, exercising a reasonable discretion, he may think would promote the public welfare”). The preference criteria fit squarely within this discretion by aiding the BLM in directing leasing towards areas that are more likely to produce oil and gas and that are less likely to have conflicts with other uses.

Additionally, some comments sought clarification regarding the BLM's policy in IM 2023-007, Evaluating Competitive Oil and Gas Lease Sale Parcels for Future Lease Sales.^[25] The BLM will continue to use this policy to guide the BLM's consideration of the preference criteria to evaluate parcels for competitive lease sales. The BLM's application of the IM as part of scoping has worked well for the 13 sales held in calendar year 2023, which resulted in over $158 million of total receipts.

During the BLM's review of the final rule, the BLM identified an error in the proposed rule for § 3120.32(c). The language in the proposed rule described the evaluation of “the presence of historic properties, sacred sites, and other high value leasing lands, giving preference to lands that would not impair the cultural significance of such resources.” In its guidance, however, the BLM described the evaluation of “the presence of historic properties, sacred sites, or other high value cultural resources, giving preference to lands that do not contribute to the cultural significance of such resources.” To avoid any implication that “high value leasing lands” were akin to historic properties, rather than an independent consideration, “other high value leasing lands,” the BLM has changed § 3120.32(c) to read “other high value cultural resources.”

Finally, the BLM concurs that the other surface management agencies will have extensive knowledge on the relevant parcels and the BLM should give deference to those agencies. Therefore, the BLM is not changing the language in the regulation; however, the BLM's policy going forward will be for the BLM to provide its proposed application of the preference criteria to the surface management agency when requesting consent. The surface management agency can use the information provided by the BLM to determine if it will grant consent. For a parcel with the surface management agency's consent, the BLM may move forward to offer the parcels on a lease sale, irrespective of the preference the BLM would otherwise afford the parcels. As noted above, the Secretary retains full authority under the Mineral Leasing Act to determine which parcels are offered for sale.

Section 3120.33 Agency Inventory of Leasing

The BLM proposed this new § 3120.33 (redesignated from § 3120.42 in the proposed rule) to address the IRA's requirement (section 50265 ^[26] ) that the Department offer leases for a certain amount of land for oil and gas development as a prerequisite to permitting any new solar or wind energy projects. Some of the comments supported the inclusion of this section, stating it is essential that the BLM take this leasing inventory to determine compliance with the IRA.

Some comments noted the new provision provides no calculation method and requested that the BLM consider codifying some of the calculation process set forth in IM 2023-006, Implementation of section 50265 in the Inflation Reduction Act for Expressions of Interest for Oil and Gas Lease Sales.^[27] Others requested that the BLM should not rely upon IM 2023-006 for the calculation method. The BLM has not made any changes to this provision in the final rule and will continue to rely on the policy as set forth in IM 2023-006 to calculate the acreage.

Some comments suggested the rule be revised to require calculations to be performed on a quarterly basis, rather than leaving it unclear in the rule when to run such calculations. These comments asserted quarterly calculations would allow the BLM to determine the amount of public land acreage needed to be offered to allow wind and solar ROW permit issuance on an ongoing basis. Further, the comments suggested the BLM should only allow parcels receiving a low preference to be leased to allow wind or solar ROW issuance if additional acreage was needed based on the quarterly calculations. These calculations are only required on the day that the BLM would issue a wind or solar energy right-of-way; therefore, the BLM has not made any changes to the final rule based on this comment. The BLM will look at providing a mechanism for both the BLM and the public to generate reports and such calculations on demand.

Multiple comments stated the BLM should clarify in the final regulation that “the 1-year period refers to the year before the wind or solar energy right-of-way is issued.” The final rule adopts this recommendation and clarified that the 1-year period refers to the year before the BLM issues the wind or solar energy right-of-way in the final rule.

One comment stated the BLM should require that, before offering any parcel that receives a low preference designation for lease, the agency demonstrate that doing so is necessary to allow issuance of wind or solar ROW permits to comply with the IRA's provisions. The BLM declines to make any changes to the final rule based on this comment as it would needlessly restrict the BLM's discretion to determine which parcels to offer.

Notice of Competitive Lease Sale

The BLM did not receive comments on its proposal to redesignate the following two sections based on the other changes made in the proposed rule.

Section 3120.42 Posting Timeframes

The BLM proposed changes to the existing § 3120.4-2 to clarify its process for identifying parcels for a sale, the public's comment opportunities, and the timing of the BLM's posting of a notice prior to a sale.

Some comments recommended that the rule should: (1) require NEPA compliance documents to be made publicly available at the time the Notice of Competitive Lease Sale is posted; (2) specify that comment periods close at 11:59:59 p.m. (local time) on the last day of the comment period; (3) require key documents and information be translated into those languages that are the primary languages of communities impacted by the particular lease sale; (4) revise the rule to provide schedules for making data and information available to the public; and (5) require parcels to be in a format that both geographic information system (GIS) users and non-GIS users can easily understand. The BLM does not adopt these recommendations as these are provisions best addressed in a handbook as BLM policy guidance. The BLM will continue to allow the BLM state offices to manage the lease sales in a manner that works best for each office. The BLM already implements some of these recommendations and is committed to posting and making the NEPA compliance documents publicly available online. In addition, the BLM is continuing to develop the MLRS such that it will be capable of providing information spatially. Mapped views of the parcels are also displayed from the BLM's internet auction provider.

One commenter stated the key component of environmental justice is meaningful involvement of those most affected by a proposed project, agency action, or decision, while other commenters expressed the opinion that these changes are unwarranted and only serve to invite additional rounds of protests further delaying the leasing process. One commenter stated the BLM should issue the final NEPA documents prior to the lease sale to allow protests to be lodged before leases are sold. The BLM has not made any changes based on these comments. The BLM believes its codification of the opportunities for public comment on parcels to be included in a lease will allow for the meaningful involvement of those potentially most affected. Rather than providing for an additional round of protests, the changes to the regulation merely codify the BLM's current policy.

The final rule makes a minor technical change to include “or appeals” at the end of paragraph (a), which is consistent with the text of paragraph (b), and replaces the acronym “NEPA” with “National Environmental Policy Act” to assist readability of the final rule.

Competitive Auction

The final rule redesignated the following section numbers consistent with the removal of the nomination process from the final rule.

Section 3120.51 Competitive Auction

The BLM proposed changes to the existing § 3120.5-1 paragraph (a) to remove references to formal nominations, and to delete paragraph (c) for the same reason. The first sentence in paragraph (a) has been rewritten from “Parcels shall be offered by oral or internet-based bidding” to “Parcels will be offered by competitive auction” in the final rule. One commenter recommended that the BLM change its online auction format to allow parcels to remain open until bidding ceases, as under the current system the parcel is awarded to the highest bidder at the time the parcel times out.

The final rule does not adopt this recommendation. In the online bidding process, bidders are given ample time to review the parcels before a sale period opens for bidding. The bidding time is published, which will vary from sale to sale depending on the number of parcels offered, however the bid open and close time is clearly stated throughout the sale notice and in the auction. In the BLM's experience, most of the bidding occurs in the last few minutes of a parcel closing regardless of how long the bidding window is open. The BLM has found no data to support the assertion that the BLM will receive higher bids if the auction is allowed to run longer. Those bidding have a maximum amount they are willing to spend for a parcel and the amount of time allowed for bidding whether online or in person does not affect this.

Section 3120.52 Payments Required

The BLM proposed changes to the existing § 3120.5-2 to reflect changes enacted by Congress in the IRA and to be consistent with other changes made. The BLM received a comment recommending a change to paragraph (b) to clarify that the authorized officer can select a date other than the day of the sale for the payment.

The final rule adopts this recommendation and moves the phrase “on the day of the sale for the parcel” to earlier in the sentence to provide clarity. The final paragraph (b) now reads, “Each winning bidder must submit, by the close of official business hours on the day of the sale for the parcel, or such other time as may be specified by the authorized officer.”

Some comments expressed the belief that the minimum bid was still too low or should be at least $20 per acre. The final rule does not adopt this recommendation. As previously explained, the minimum bid was changed to reflect the IRA, which requires $10 per acre.

The final rule makes a technical change to the cross reference for the minimum bonus bid in paragraph (b)(1) consistent with other changes in this rulemaking.

Section 3120.53 Award of Lease

The BLM proposed changes to the existing § 3120.5-3 to remove references to the noncompetitive lease process. The BLM received a comment recommending the BLM revise paragraph (b) to state that a “lease will be awarded to the highest responsible and qualified bidder unless contrary to the public interest.” The final rule does not adopt this recommendation. The BLM has historically used a public interest requirement in its oil and gas agreements, which require a drilling of a well into the target formation for a CA or drilling of the obligation well for an exploratory unit agreement. Adding a public interest requirement to this section may cause confusion related to the use of this same phrase with agreements. The Secretary still has the discretion to consider the public interest in the ultimate decision of which lands to lease.

A commenter stated that paragraph (d) should be revised to state that the lease will not be issued until all appeals are resolved in addition to the resolution of all protests. The final rule does not adopt this recommendation, because the MLA requires all leases to be issued within 60 days following the payment of any remaining bonus bid and rentals for the first year.

Comments opposing the inclusion of paragraph (e) stated that the BLM should not reject a lease offer without the bidder's consent if the protest is not timely resolved. In this section of the regulations, the BLM may reject a bid if the BLM cannot issue the lease within 60 days as required under 30 U.S.C. 226(b)(1)(A). However, the BLM concurs that it should not reject the bid without the successful bidder confirming that it would prefer its bid to be rejected rather than waiting longer than 60-days for the lease to be issued. Based on this comment, the BLM has revised this section in the final rule by inserting the phrase “with the consent of the bidder” to clarify the BLM's intent.

14. Section-by-Section Discussion for Changes to 43 CFR Subpart 3137

The final rule does not make any revisions to the section designations or the headings that appeared in the proposed 43 CFR subpart 3137 regulations. The BLM did not receive any comments on these sections and adopts the proposed changes in the final rule.

15. Section-by-Section Discussion for Changes to 43 CFR Subpart 3138

The final rule does not make any revisions to the section designations or the headings from the proposed rule for the 43 CFR subpart 3138 regulations. The BLM did not receive any comments on these sections and adopts the proposed changes in the final rule.

16. Section-by-Section Discussion for Changes to 43 CFR Subpart 3140

The final rule does not make any revisions to the section headings in the existing 43 CFR subpart 3140 regulations. It does redesignate the sections to make them conform to current Office of the Federal Register (OFR) Document Drafting Handbook requirements.

Section 3140.13 Exploration Plans

The BLM identified that paragraph (c) contained a technical error and referenced an outdated section number of the regulations. The final rule corrects the reference to § 3140.23. The BLM did not receive any comments on § 3140.13 and did not make any other changes to the final rule.

Section 3140.14 Other Provisions

The BLM proposed changes to the existing § 3140.1-4 to update the rental and royalty provisions. The BLM identified that existing paragraph (a) contained a technical error and referenced an outdated section of the regulations. The final rule corrects the references to 43 CFR 3101.21 and 3101.22. One comment suggested that the current rule set out the actual required rental amounts to ensure the regulations serve as an orderly source for basic information. The BLM revised paragraph (b) to provide this reference.

The BLM received a comment on paragraph (d) referencing the unitization provisions in 43 CFR part 3180. The commenter recommended that the BLM revise the final rule to provide that a lease, or part of a leasehold, having been made part of a unitized area will not be sufficient to extend the primary term of the entire leasehold and if the lessee fails to take actions to extend those portions of the lease outside of the unitized portion of the leased lands, the lease should expire as to those excluded lands. The BLM reviewed this comment and determined the suggested revision is unnecessary as it is already addressed inf 43 CFR 3107.32.

17. Section-by-Section Discussion for Changes to 43 CFR Subpart 3141

The final rule does not make any revisions to section headings in the existing 43 CFR subpart 3141 regulations. It does redesignate the sections to make them conform to current OFR Document Drafting Handbook requirements.

Section 3141.8 Other Applicable Regulations

The BLM did not receive any comments on the existing § 3141.0-8. However, when the BLM reviewed the regulations during drafting of the final rule, it identified that it needed to update § 3141.8(a)(1)(ii) to reflect the provisions in § 3140.14(a). Under 30 U.S.C. 226(b)(2)(A)(iv), “no lease issued under this paragraph shall be included in any chargeability limitation associated with oil and gas leases.” Therefore, the BLM updated this paragraph after reviewing the law and the applicable Federal Register notices that established these two sections of the regulations. See 48 FR 7420 (February 18, 1983), 47 FR 25720 (June 14, 1982), 47 FR 8734 (March 1, 1982), and 47 FR 22474 (May 24, 1982). Paragraph (ii) contained a technical error as it incorrectly applied the chargeable acreage and acreage limitations to combined hydrocarbon leases. Therefore, the BLM revises § 3141.8(a)(1)(ii) in the final rule to provide that all of 43 CFR 3101 applies to combined hydrocarbon leases, except for the chargeability limitation associated with oil and gas leases.

In addition, the BLM corrected an incorrect cross reference in proposed § 3141.8(a)(1)(iv). This final rule changes the cross references in this section to §§ 3103.21, and 3103.31(a), (b), and (c).

In addition, the BLM updated the cross reference in § 3141.8(a)(1)(vii) because the final rule adds another paragraph, which changed the reference to § 3106.10(j).

Finally, the BLM updated the cross reference in § 3141.8(c)(1)(ii) because the proposed rule referenced an incorrect citation. The final rule will correct the references to §§ 3103.31 and 3103.32 instead of § 3103.30.

Section 3141.53 Royalties and Rentals

The BLM proposed changes to the existing § 3141.5-3 mainly to address changes required by Congress in the IRA. One commenter objected to royalty rate reductions for tar sand leases and recommended that the royalty rate not be reduced. The BLM understands the concern but cannot make this change as the reduction is allowed by the statute, see 30 U.S.C. 226(b)(2)(D).

Section 3141.63 Conduct of Sales

The BLM proposed eliminating paragraph (a) and updating (b) to provide a consistent approach for combined hydrocarbon leases and tar sand leases. One commenter objected to the noncompetitive leasing of additional lands for tar sand development. The BLM can no longer issue noncompetitive tar sand leases after the passage of the IRA ^[28] and does not include a provision in the final rule that provides for noncompetitive leasing; therefore, the BLM did not make any changes to the final rule based upon this comment.

18. Section-by-Section Discussion for Changes to 43 CFR Subpart 3142

The final rule does not make any revisions to the numbering or section headings from the proposed rule for the 43 CFR 3142 regulations. The BLM did not receive any comments on these sections and adopts the proposed changes in the final rule.

19. Section-by-Section Discussion for Changes to 43 CFR Subpart 3151

The final rule does not revise the proposed section designations or their headings in the 43 CFR subpart 3151 regulations.

Section 3151.30 Collection and Submission of Data

The BLM proposed revising the existing § 3151.30 to require a permittee to submit to the BLM all data and information collected under a geophysical exploration permit. A commenter expressed concern related to the potential release of geophysical exploration data to competitors through a Freedom of Information Act (FOIA) request. The BLM understands the concern that geologic data be kept confidential. Geological and geophysical data is exempt from release under FOIA pursuant to exemption 9, 5 U.S.C. 552(b)(9). Although exemption 9 under FOIA would allow this information to be exempt from release, the BLM also updated the final regulations to ensure it is clear that the BLM would not release this information to the public by including new paragraph (b), which adds the statement that all information submitted under this section “is presumptively confidential business information.”

The commenter also stated that the BLM provided no basis for why the BLM needs this information, how it will be used, or with whom it will be shared. Such data will support the BLM's review and analysis of oil and gas agreement applications and oil and gas leasing decisions. The BLM will use this data to inform an area's oil and gas development potential. In addition, the geophysical exploration data will allow the BLM to make better decisions related to an exploratory unit agreement's boundary by ensuring that the unit area encompasses only those lands necessary for the proper development of the unitized resources. This information is exempt from release to the public under exemption 9 of FOIA, and the BLM will respect and maintain the confidentiality of the information.

20. Section-by-Section Discussion for Changes to 43 CFR Subpart 3160

The final rule does not make any revisions to the section designations or their headings in the existing 43 CFR subpart 3160 regulations.

Section 3160.0-5 Definitions

The BLM proposed revising existing definitions and added some new definitions. The final rule does not make any changes from the proposed rule for the definitions within the existing § 3160.0-5.

One commenter requested that the BLM defer to the definitions and analysis from State regulatory bodies for what constitutes temporarily abandoned and shut-in wells, because the proposed regulations do not match State standards and could lead to inconsistency and confusion, particularly on Federal wells that are communitized with State or fee leases. The BLM understands the concern; however, the BLM declines to adopt this change because the BLM's definitions are in keeping with its statutory authority. For example, 30 U.S.C. 226(i) states that a lease will not expire if it contains a well capable of producing oil or gas in paying quantities. The BLM's proposed definition reflects this statutory requirement by defining “temporary abandoned well” as “a nonoperational well that is not physically or mechanically capable of production or injection without additional equipment or without servicing the well, but that may have future beneficial use.” Thus, a temporarily abandoned well would not be considered capable of production. This differs from, for example, the Wyoming Oil and Gas Conservation Commission's definition for “temporarily abandoned” that would not comport with the statutory framework. That definition is “a well in which the completion interval has been isolated from the wellbore above and the surface. The completion interval may be isolated by a retainer, bridge plug, cement plug, tubing and packer with tubing plug, or any combination thereof.” In addition, each State has different definitions for temporarily abandoned wells and shut-in wells. If the BLM deferred to State regulatory body definitions, the BLM would have internal inconsistencies related to well status definitions, which would result in inconsistent regulatory and policy implementation based on different definitions for temporarily abandoned wells and shut-in wells. Therefore, the BLM declines to adopt this recommendation.

A commenter requested that the rule provide a definition of “temporarily abandoned well” that includes a reference to a well that may have “future beneficial use” and provided a recommended definition of “a well that has the potential to produce oil and natural gas in the future as deemed by a reasonable operator including after recompletion, workover, and other maintenance activities. It also includes wells that have potential for geothermal, carbon management, scientific applications, technological advances, or other exploration and production related activities.” The BLM declines to provide the definition as proposed by the commenter in the final rule and notes that reuse or conversion of wells for other purposes is not the subject of this rule. Moreover, the commenter's proposed definition varies significantly from the BLM's current policy regarding whether a well is producing or is abandoned, as found in Attachment 4 of IM 2020-006, Idled Well Reviews and Data Entry,^[29] which provides guidance to BLM personnel about whether they should take any action with respect to wells that are not currently producing in an effort to prevent such wells from becoming orphan wells. Attachment 4 states the BLM “will consider a well to have future beneficial use if the operator will be able to use the well to generate royalties in lease paying quantities or will support the operator's efforts to generate royalties from other wells on the lease.” Therefore, the BLM did not make any changes to the definitions based upon this comment.

Another commenter recommended that the BLM define idled well, orphaned well, and inactive wells. The BLM declines to define these terms because the BLM does not use these in the regulations. In addition, the law defines both idled wells at 42 U.S.C. 15907(a)(2) and orphaned wells at 42 U.S.C. 15907(a)(5).

Finally, a comment recommended updating the definition of maximum ultimate economic recovery to include references to the BLM's responsibilities under FLPMA. The BLM declines to update this definition at this time. The BLM uses this definition in parts 3160 and 3170 to identify the maximum amount of oil and gas that could be produced from the reservoir using existing technology. This definition already is used in conjunction with the FLPMA requirements in part 3160 (see 43 CFR 3162.1(a)). In part 3170, the term is used to determine if a variance is appropriate (see 43 CFR 3173.14(b)(4)) and in relation to off-lease measurement. Based upon a review of the usage of the maximum ultimate economic recovery in the regulations, the BLM determined that it was unnecessary to include references to the BLM's responsibilities under FLPMA as part of this definition.

21. Section-by-Section Discussion for Changes to 43 CFR Subpart 3162

The final rule does not make any revisions to the section designations or their headings in the existing 43 CFR 3162 regulations.

Section 3162.3-4 Well Abandonment

The BLM received many comments both in support of and expressing concern on the proposed revision of the requirements for operators to monitor, track, and report on shut-in and temporarily abandoned wells. After reviewing the comments, the BLM has made the following changes:

(1) Reorganized paragraphs (c) and (d) pertaining to temporarily abandoned wells to ensure they are easy to read;

(2) Matched the plugging requirement between shut-in and temporarily abandoned wells in paragraph (d);

(3) Clarified in paragraph (e) that an onshore operator will only need to report a well as shut-in if the well will be shut-in for 90 consecutive days; and

(4) Required mechanical integrity tests every 3 years after a well is shut-in or temporarily abandoned in paragraph (f).

For paragraph (b), one commenter objected to the requirement that “[a]ll costs over and above the normal plugging and abandonment expense will be paid by the party accepting the water well.” The commenter recommended that the BLM revise this paragraph to allow the operator of the well, the State, a grazing association, or any other non-Federal entity to pay the additional costs if a well is being conditioned into a water supply source. The BLM did not propose any changes to this paragraph and disagrees with the commenter. If the operator does not need the water well and it is not supporting on-lease activity, the BLM cannot require the operator to cover any additional costs related to setting up the well as a water well. If the operator of the well, the State, a grazing association, or any other non-Federal entity agrees to pay the additional costs for a well to be conditioned into a water supply source, the BLM will work with the funding entity and the party accepting the water well. In general, this would be a private arrangement between the party accepting the water well and the other entity. The BLM did not make any changes to the final rule based upon this comment.

In reviewing the final rule for clarity, the BLM identified that the requirements for temporarily abandoned wells were included in a single paragraph at paragraph (c) in the proposed rule and were difficult to follow. Therefore, the BLM split paragraph (c) into two paragraphs (c) and (d) in the final rule and re-structured paragraph (d) to match the format for the requirements for shut-in wells in the final rule with the format for the requirements for temporarily abandoned wells.

Although a few commenters expressed support for the 4-year requirement to plug temporarily abandoned wells, one commenter recommended a 2-year requirement, and other commenters expressed concerns that the 4 years proposed was too short. The BLM reviewed these comments and identified that there are legitimate reasons why a well may need to remain temporarily abandoned for longer than 4 years. For example, an operator may be looking at converting a field for enhanced recovery. Until the operator has constructed the infrastructure to support the operations, multiple wells may need to be temporarily abandoned since they will not be used until the operator starts injections. Based upon this scenario and other considerations expressed in the comments, the BLM updated the final rule in paragraph (d) (paragraph (c) in the proposed rule) to match the requirements for shut-in wells and temporarily abandoned wells for final abandonment. The final rule now provides an option to “provide the authorized officer with a detailed plan and timeline for future beneficial use of the well. If the authorized officer determines that there is a legitimate future beneficial use for the well, the officer may allow the operator to delay permanent abandonment by an additional 1 year. The authorized officer may grant additional delays in 1-year increments, provided that the operator confirms the future beneficial use of the well and is making verifiable progress on returning the well to a beneficial use.” This language matches the requirements for shut-in wells.

In revising the regulation to allow a well to be temporarily abandoned for longer than 4 years, the BLM determined that it needed to ensure that these nonoperational wells maintain their mechanical integrity. Therefore, the BLM added paragraph (f) to require mechanical integrity tests every 3 years, after the first mechanical integrity test is done. This section states, “All wells that are temporarily abandoned or shut-in must have mechanical integrity verified as required in (d)(1) and (e)(2) and must ensure that mechanical integrity is verified every 3 years thereafter. The operator must submit the results of each verification of mechanical integrity to the Authorized Officer within 30 days of the mechanical integrity test.”

One commenter requested that a provision be added to the regulations that allows recreational access to the reclaimed locations. Once the lands have been reclaimed and the BLM has accepted an abandonment notice, the public may use the lands for recreation, provided the applicable RMP allows for such use.

One commenter expressed concerns related to the proposed rule's requirement that “no well may be temporarily abandoned for more than 30 days without the prior approval of the authorized officer.” The commenter requested that the BLM extend the temporary abandonment period for which a notice and prior approval is required from 30 days to 90 days. The thirty-day period has been in place since 1988, and the BLM is unaware of evidence showing that it or operators have experienced hardship from the period. Therefore, the BLM kept the current requirement of 30 days for notice and prior approval.

The BLM requested comments on whether to require a bond adequacy review when a well is temporarily abandoned. The BLM received comments in support and opposition to this proposal. After reviewing the comments, the BLM has decided not to require a bond adequacy review for a change in well status, including temporary abandonment of a well. The BLM can review the adequacy of a bond at any time, and the new reporting and operational requirements for operators of temporarily abandoned wells will allow enhanced oversight of these wells. The BLM considers the discretionary authority to review a bond, combined with the new reporting and operational requirements, sufficient to effectively manage any risks to the environment associated with these types of wells without needing to require a bond adequacy review.

Commenters expressed concerns that the extra administrative requirements related to temporarily abandoned and shut-in wells will become overly burdensome for the BLM to administer and will result in contradictory guidance and confusion for operators balancing between State and Federal regulations. One commenter also mentioned the number of orphaned wells that have been identified on Federal lands. Another commenter suggested the BLM should not require operators to report a well status change to the BLM because ONRR requires operators to report on ONRR Form-4054 (“OGOR”) the well status (Well Status codes 12 (OSI) and 13 (GSI)) beginning with the last month of drilling and continuing until the operator abandons the well. Another commenter stated that the BLM should accept all sundry notices for temporarily abandoned or shut-in wells as prima facia rationale and timing parameters for these nonoperational wells. After reviewing the comments, the BLM identified that paragraph (d)(1) in the proposed rule required operators to report whenever a well is shut-in. The BLM did not intend for an operator to report each time a well is shut-in. Instead, the BLM need only be notified if the well would be shut-in for 90 consecutive days. Therefore, the BLM revised this section to state, “Notify the authorized officer of the well's shut-in status, if the well will be shut-in for 90 or more consecutive days, and provide the date the well was shut-in within 90 days of well shut-in.” As for the administrative burden concerns, the BLM has reduced the operator's administrative burden with this change since the operator would not need to submit a notice for each shut-in well. Instead, the operator will only submit a notice for each well shut-in for 90 or more consecutive days. The final rule will also reduce the BLM's burden as the BLM can use the notifications to update well status instead of requiring the BLM to inspect wells or review ONRR or State agency data on well status. The BLM will review notification of shut-in or temporarily abandoned status to determine if the rationale for shutting-in or temporarily abandoning the well are supported by the information provided in the notice. The BLM will accept the sundry notice and update the well status in its system; however, the BLM will not provide a guarantee that it will consider each sundry notice as prima facia rationale for the status change. The BLM has a responsibility to the American public to ensure that unplugged non-operational wells are still necessary to support lease operations. If the unplugged non-operational well will not support future lease production, then the BLM will request that the operator plug and abandon the well.

Finally, the BLM reorganized this section in the final rule. The BLM removed the requirements for temporarily abandoned wells from paragraph (d) and left the reclamation requirements for all wells permanently abandoned within paragraph (c). The BLM reorganized paragraph (d) for temporarily abandoned wells to add subparagraphs and ensure the language in the final rule was clear. The BLM redesignated the section for shut-in wells to paragraph (e). The BLM also added paragraph (f) to cover the requirements for mechanical integrity tests. The BLM makes these changes in the final rule to more clearly inform the regulated community of the requirements.

22. Section-by-Section Discussion for Changes to 43 CFR Subpart 3164

The final rule does not make any revisions to the section designations or their headings in the existing 43 CFR subpart 3164 regulations.

Section 3164.1 Onshore Oil and Gas Orders

The BLM changed the existing paragraph (b) to clarify that there are no Onshore Oil and Gas Orders currently in effect. Since the BLM codified the Onshore Oil and Gas Orders in 43 CFR part 3170,^[30] the BLM wants to ensure the regulated community is aware that they must follow 43 CFR subpart 3171. Therefore, the BLM removes the references to the Onshore Orders in this section. All of the Onshore Oil and Gas Orders are now codified in 43 CFR subparts 3171, 3172, 3176, and 3177. See 88 FR 39514 (June 16, 2023).

23. Section-by-Section Discussion for Changes to 43 CFR Subpart 3165

The proposed rule revised the heading for 43 CFR 3165.1 from “Relief from operating and producing requirements” to “Relief from operating and/or producing requirements.” The BLM did not receive any comments on this change and did not make any other changes in the final rule.

Section 3165.1 Relief From Operating and/or Producing Requirements

The BLM revised the existing § 3165.1 to encourage diligent development of leased lands and to ensure that any lease suspensions are justified and have a clearly stated end date. The BLM received many comments on the proposed rule related to changes to oil and gas lease suspensions. The final rule revises paragraph (c) to add the word “only” before “cites” and replace the acronym “APD” with “application for permit to drill.”

A commenter expressed concerns regarding the proposed changes in light of the BLM's own delays in processing APDs and lease suspensions and with agency policy against “premature suspensions.” The commenter asked the BLM to clarify its intent so that lessees can clearly understand the appropriate time by which they should submit any requests for suspensions. The BLM agrees and drafted paragraph (c) to specify the timeframe for a submission of an APD such that a lessee could seek a suspension based upon a pending APD. The BLM does not believe any other changes are necessary.

For paragraphs (a) and (b), one commenter recommended that the final rule should require the “full statement” to include a showing of leaseholder diligence, 2and absent a showing of diligence, the BLM would be required to deny the request for relief. The BLM's existing policy in Manual Section 3160-10, Suspension of Operations and/or Production,^[31] already suggests the BLM ensures that a lessee is diligently developing its lease prior to granting a suspension. The manual states, “Suspension of operations may be directed or consented to by the authorized officer in cases where a lessee is prevented from operating on the lease, despite the exercise of care and diligence, by reason of force majeure, that is, by matters beyond the reasonable control of the lessee.” ( Emphasis added). The manual has similar guidance for suspensions of production. In addition, the BLM also not infrequently grants suspensions when litigation precludes development on an undeveloped lease. In these cases, the lessee could not provide a showing of leaseholder diligence when requesting a lease suspension because the BLM recently issued the lease. Therefore, the BLM did not make any changes in the final rule further specifying requirements for the full statement.

One commenter stated that the BLM should not add paragraph (c) into the final regulations, but instead leave the substance of the paragraph in guidance. Additionally, multiple commenters claimed that the authorized officer should have flexibility to approve a lease suspension in spite of the timing of the APD, if the officer believes it would be appropriate given the circumstances. The commenter then stated that the BLM should not push the operator towards diligent development, as the submission of an APD is a business decision based on markets, investment capital, supply chains, labor and equipment availability, and other factors and that the failure to act “diligently” to develop a lease has no adverse impacts on the environment. This is outlined in existing policy at Instruction Memorandum 2023-012, Suspensions of Operations and/or Production,^[32] and the BLM agrees that the submission of an APD is a business decision for the lessee. The BLM has opted to incorporate this requirement in regulation, however, to ensure that BLM offices apply this requirement in the same way to promote fairness to all operators. The proposed changes provide definitive notice to operators and the BLM's authorized officers on processing these types of lease suspension, and therefore, the BLM did not make any changes based upon this comment.

Other commenters stated that the 90-day threshold proposed by the BLM is arbitrary, because there is no recorded evidence that the BLM can approve an APD in 90 days. The BLM proposed the 90 days based upon the BLM's average processing time for an APD across all BLM offices. The BLM provided this information in the preamble. In fiscal year 2022, the BLM's average processing time did increase to 162 days; however, the BLM decided to keep with the 90-day limit as it represents an average over a period of 3 years.

The commenters also recommended that instead of a set timeframe, the BLM should deny suspension requests based on a proposed action necessitating NEPA analysis, which cannot reasonably be completed prior to the lease expiration date; based on events the lessee could have and should have foreseen or avoided; and based on unknown, speculative, and or future events. Finally, the commenters recommended that the BLM should deny suspensions based upon adjacent unleased lands as the commenter considered these types of suspensions ripe for abuse and mismanagement. The BLM declines to make any changes to the rule based on these recommendations given the existing discretion of the authorized officer. For example, if the operator nominates adjacent unleased lands that are needed for development and are scheduled to be offered on an upcoming lease sale within the few months, the BLM does not see this as an unreasonable request.

Comments demonstrated confusion with the application of paragraph (c), seemingly believing that the APD submission requirement applies to all suspensions. This provision only applies when the applicant cites the pending APD as the sole basis for the suspension. If a lease needs to be suspended in the interest of conservation or for force majeure due to reasons other than a pending APD, then the BLM will not require an APD to be filed at least 90 calendar days prior to the expiration date of the lease. To remove the confusion, the BLM modifies the final rule by inserting the word “only” prior to the word “cites.” In addition, to increase readability, the BLM replaced the acronym “APD” with the words “application for permit to drill” as the BLM has not defined the acronym “APD” in part 3160.

In addition, one commenter stated that approving suspensions for only 1 year is arbitrary. The 1-year time frame ensures that suspensions are not granted for a longer period than necessary, and it provides a clear and easily trackable timeframe for both the BLM and lessees, which allows both parties to ensure compliance with applicable lease terms, such as the resumption of paying rentals or royalties. The BLM implemented an annual review of lease suspensions in Permanent Instruction Memorandum 2019-007, Monitoring and Review of Lease Suspensions,^[33] after receiving GAO's recommendations in report GAO-18-411, Oil and Gas Lease Management: BLM Could Improve Oversight of Lease Suspensions with Better Data and Monitoring Procedures.^[34] The BLM determined the 1-year timeframe was appropriate in this rulemaking because it conforms with BLM's existing policy. If, after a year, there is still a valid need for a suspension, a lessee may request a further extension.

Other commenters supported approving suspensions for 1 year; however, they also recommended that the BLM modify the final regulations to allow for only one extension to an oil and gas lease suspension. One commenter stated that the BLM should only grant additional suspensions in those situations where the lessee or operator is prevented from operating or producing due to force majeure. The BLM declines to accept this suggestion to limit suspensions to those based on force majeure because the MLA allows for suspensions of operations and production in the interest of conservation. The BLM will evaluate requests for suspension extensions to ensure the bases for the suspension remain valid, the operator has met any diligence requirements or other conditions of approval in the original approval, and the suspension is authorized by the MLA.

The BLM received several comments on paragraph (e) urging the BLM to modify this provision to only allow a directed suspension to last 1 year. The commenters claimed that long-term suspensions do not further the public interest or properly conserve natural resources and instead encumber public lands by making them unavailable for other uses and for other potential leaseholders, as well as fail to provide taxpayers with a fair return for the lease of public lands. The BLM declines to make this change. Given the reasons for which the BLM is authorized to issue a directed suspension, such as a court order, the suspension must remain in effect until the court allows operations.

24. Section-by-Section Discussion for Changes to 43 CFR Subpart 3171

The final rule does not make any revisions to the section designations or their headings in the existing 43 CFR subpart 3171 regulations.

Section 3171.14 Valid Period of Approved APD

The BLM received many comments on the proposed rule related to changing the term of an approved APD from the current 2 years with an optional 2-year extension to a 3-year term without extensions. The BLM received comments both in support and with concerns related to the proposed changes. After reviewing the comments, the BLM has made the following changes: (1) omitted the word “ordinarily” from paragraph (a); (2) clarified that the APD term in the regulations only applies to APDs approved after the effective date of the final rule; (3) clarified that the well must be drilled to total measured depth in paragraph (b); (4) clarified that paragraph (b)(1) includes wells drilled to approximate total measured depth and not yet completed; (5) stated that paragraph (b)(3) will only apply if the operator set the surface casing for the well and submits a plan to finish drilling and complete the well; (6) provided that the plan in paragraph (b)(3) must include the timeframe for continuously drilling and completing the well and any extenuating circumstances that may delay the continuous drilling and completion of the well; (7) specified that earthwork for reclamation must be completed within 6 months of the approved APD's expiration; and (8) added paragraph (e) to provide for the extension of an APD's term when the underlying lease is suspended.

Many commenters supported the BLM's proposal to extend the initial term of an approved APD from 2 to 3 years; however, multiple commenters recommended that the BLM establish a 4-year term for approved APDs. Commenters stated that a 4-year term for an approved APD would enable the BLM to process APDs efficiently and would provide consistency for industry. The BLM rejected this change, since approximately 95 percent of the approved APDs drilled under the existing regulations have been drilled within 3 years from the date of approval. By providing a set term without the option to extend, the BLM is providing more certainty for the industry to allow it to properly plan any operations. The remaining five percent may submit a new APD. Given the small percentage of operators who do not normally drill a well within 3 years of approval of an APD, the BLM believes the administrative burden on an operator of filing a new APD is justified in light of the BLM's interest in ensuring the public lands subject to an oil and gas lease are diligently developed.

One commenter encouraged the BLM to modify the rule and keep the current 2-year period for an approved APD with allowable extensions, stating the rule would have negative effects by increasing the BLM's administrative burden and requiring additional environmental review. The BLM disagrees. Currently, the BLM spends approximately 3,800 hours annually on processing APD extension requests. In some cases, the NEPA analysis is stale, and the BLM must complete a new analysis on the APD to verify that the impacts identified have not changed. This rule will reduce the administrative burden on both the BLM and the operator as extension requests would no longer be needed. The burden on the BLM would be further reduced by obviating the need for any potential additional NEPA analysis to support an extension. In addition, the 3 years in which to use an APD will provide sufficient time for 95 percent of the operators. Therefore, the BLM did not make any changes based upon this comment.

A commenter stated that changing the term of an approved APD from 2 years to 3 years without the possibility of an extension would kill many oil and gas projects before they ever get off the ground. The commenter supported this statement citing the length of time required to comply with NEPA. Without recourse to an extension, an operator is left without any means to maintain a lease. Often an operator is prevented from drilling due to circumstances completely out of their control. The comment encouraged the BLM to examine the negative effects the rule will have in this regard. The BLM believes the comment is confusing oil and gas lease suspensions and approved APD extensions. The BLM will still grant lease suspensions, which will allow an operator to maintain its lease if the suspension requirements are met, and which toll the running of the term of any previously issued permit to drill. This provision only addresses extensions for APDs. Moreover, even if a well is not drilled within the 3-year time period, as noted above, an operator can submit a new APD.

Another commenter recommended that the BLM omit the word “ordinarily” from paragraph (a) to avoid confusion. The comment stated that since “ordinarily” implies there is an exception, it is unnecessary with the “notwithstanding” clause, which is already addressed in paragraph (b). The BLM concurred with this recommendation and deleted the word “ordinarily” from paragraph (a).

In addition, one commenter requested that any change in terms to approved APDs only apply to the APDs approved and issued subsequent to the publication of a final rule. The BLM concurs with this recommendation. The BLM modified the final rule to clarify that the 3-year term only applies to APDs approved after the effective date of the rule. Consistent with general principles of retroactivity, any APD approved prior to the effective date of this rule will be eligible for a 2-year extension in accordance with the regulations in place when the BLM approved the APD.

For paragraph (b), a commenter requested that the rule specify either total vertical depth or total measured depth in the final rule. The BLM specifies total measured depth in the final rule as measured depths matches the requirements in an approved APD. A horizontal well drilled to total vertical depth would likely not be productive in paying quantities and would not meet the plans in the approved APD.

For paragraph (b)(1), a commenter requested that the BLM specify in the regulations that drilling, but not completing, would provide for the APD approval to remain valid. The BLM intended as much and has clarified the final rule by adding the statement “including wells drilled to approximate total measured depth and not yet completed” to paragraph (b)(1).

For paragraphs (b)(1) and (b)(2), a commenter recommended that the BLM set a time limit of one-year for any extensions beyond the initial term of the APD based on the criteria outlined in the proposed regulation. The BLM declines to provide for a further extension of an APD under either (b)(1) or (b)(2). In both of these scenarios, a well has already been drilled to the approximate total measured depth as authorized by the APD. Instead, the BLM will administer the wells as shut-in or temporarily abandoned if the well is not yet producing at the expiration of the APD. This allows the BLM to track and manage these wells under 43 CFR 3162.3-4. Therefore, there is no need to set a limit of one-year for paragraphs (b)(1) and (b)(2) in this section.

The BLM received multiple comments on paragraph (b)(3). Some commenters considered the requirement for the plan to be vague and that the regulatory language leaves the authorized officer with no guidance for approving such a plan. A separate comment recommended that the BLM accept reasonable plans to complete drilling any well to total depth if the operator has set surface casing prior to the APD expiring. The BLM reviewed the many comments on the plan required by this section and recognized that more information on the plan should be added to the regulations. Based on these comments, the BLM has revised paragraph (b)(3) to specify that the “plan must include the timeframe for continuously drilling and completing the well and any extenuating circumstances that may delay the continuous drilling and completion of the well.”

In addition, multiple commenters encouraged the BLM to delete paragraph (b)(3). They asserted that paragraph (b)(3) would allow APD extensions based only on submission of a drilling plan to the BLM, with no requirement that on-the-ground activity have taken place, undermining the goal of diligent development. They further contended it may risk further waste of public lands and resources. The BLM concurs that the operator should be pursing diligent development with a showing of on-the-ground activity. The BLM modified paragraph (b)(3) to require that on-the-ground activity has taken place to ensure the operator has started development under the APD. For the final rule, the BLM updated paragraph (b)(3) to require the operator to have set the surface casing for the well and to have submitted a plan. This will ensure the operator is working towards developing its lease with a real effort to begin development. In addition, as noted above, one comment recommended the BLM accept reasonable plans to complete drilling any well to total depth if the operator has set surface casing prior to the APD expiring. Therefore, the BLM considered requiring surface casing for the BLM to consider a plan as a reasonable approach for paragraph (b)(3).

For paragraph (c), a commenter expressed concern that an operator may not be able to submit an APD to finish drilling the well during the time allowed under the proposed regulations, and the regulations would then require the operator to immediately comply with all applicable plugging, abandonment, and reclamation requirements. This was not the intent in the proposed rule; therefore, the BLM updated the final rule to provide two options for an expired APD. The “operator or lessee must either comply with all applicable plugging, abandonment, and reclamation requirements or submit a new APD covering the existing disturbance.”

The BLM received a comment on paragraph (d) suggesting that the BLM should specify the timeframe by which reclamation must start once an APD expires. The BLM's existing regulations require earthwork for reclamation to begin within 6-months of well completion or well plugging under 43 CFR 3171.25(b)(2). To be consistent with 43 CFR 3171.25(b)(2), the final rule updates paragraph (d) to state, “Earthwork for reclamation must be completed within 6 months of APD expiration (weather permitting).”

Multiple commenters expressed concern that the BLM proposes to no longer grant extensions to an APD's term. Some commenters expressed a concern that the lack of an APD extension would disadvantage project proponents in situations where drilling was delayed for a variety of on-the-ground reasons and there is not a way to seek an APD extension. Another commenter mentioned the need for extensions when there is litigation challenging the NEPA compliance for the lease or APD because the BLM cannot take any action on an APD when there is ongoing litigation. Upon review of the comments, the BLM recognizes that there is a valid concern related to litigation challenging the issuance of leases; therefore, the BLM added paragraph (e), which will allow the BLM to adjust an APD's term when the lease is suspended. The new paragraph (e) states, “The valid period for an approved APD on a lease suspended under subpart 3103 will be adjusted to account for the suspension. Beginning on the date the suspension is lifted, the valid period of the approved APD will be extended by the time that was remaining on the term of the approved APD on the effective date of the suspension.” This addition will allow the BLM to extend the term of an approved APD based upon an oil and gas lease suspension of operations and/or production. The BLM will not grant general extensions as the 3-year APD term will provide sufficient time for the Federal operator to drill a well under an approved APD.

25. Section-by-Section Discussion for Changes to 43 CFR Subpart 3181

The BLM identified that 43 CFR 3181.5 should be updated to recognize the changes to royalty made by the IRA. The BLM has revised the existing § 3181.5 in the final rule to reflect the increased royalty rate.

Finally, the rule will not make any revisions to the section designations or their headings in the existing 43 CFR subpart 3181 regulations.

Section 3181.5 Compensatory Royalty Payment for Unleased Federal Land

During the public comment period, the BLM discovered that § 3181.5 of the current regulations still references a royalty rate of 12.5 percent. As discussed earlier, in the IRA, Congress changed the royalty rate for onshore Federal oil and gas leases to 16.67 percent, a rate that will last until August 2032, at which time, the royalty rate becomes not less than 16.67 percent and subject to further increases. Therefore, the BLM is replacing the 12.5 percent royalty in § 3181.5 with the language “the current royalty percentage for leases offered on onshore oil and gas lease sales.” This will allow BLM offices to enter the appropriate royalty rate based upon the latest onshore oil and gas lease sales for the area.

26. Section-by-Section Discussion for Changes to 43 CFR Subpart 3186

During the comment period, BLM employees identified that a section in the model onshore unit agreement for unproven areas should be updated to recognize the changes Congress made to royalty rates in the IRA.

Section 3186.1 Model Onshore Unit Agreement for Unproven Areas

Section 17(b) of the model onshore unit agreement for unproven areas still references the old royalty rate of 12.5 percent. Because Congress changed the royalty rate in the IRA for onshore Federal oil and gas leases to 16.67 percent, the BLM is replacing the 12.5 percent royalty in Section 17(b) of the model onshore unit agreement for unproven areas with the language “(current royalty for leases offered on onshore oil and gas lease sales).” This will allow BLM offices to enter the appropriate royalty rate based upon the latest onshore oil and gas leases.

The BLM is republishing the revised model onshore unit agreement for unproven areas in the final rule in its entirety because the OFR is unable to make a piecemeal edit to the document. The document is not regulatory and, in conformance with current OFR Document Drafting Handbook requirements, cannot be given section numbers. Instead, the model onshore unit agreement for unproven areas must be redesignated in the final rule as Appendix A to Part 3180. The BLM uses this model form to identify where new unit agreements do not match the model form and ensures any differences from the model form are in the public interest.

Likewise, at the direction of the OFR, the BLM is redesignating four other models and exhibits that comprise the remainder of existing subpart 3186. These items will appear in the final rule as follows: (1) § 3186.1-1 Model “Exhibit A” will appear as Appendix B to Part 3180; (2) § 3186.1-2 Model “Exhibit B” will appear as Appendix C to Part 3180; (3) § 3186.3 Model for designation of successor unit operator by working interest owners will appear as Appendix D to Part 3180; and (4) § 3186.4 Model for change in unit operator by assignment will appear as Appendix E to Part 3180. The final rule does not revise the contents of Appendices B through E.

Cross refences in §§ 3107.10(a), 3181.1 and 3183.4(a) are revised in the final rule to reflect the redesignated appendices.

Procedural Matters

A. Regulatory Planning and Review (E.O. 12866, E.O. 14094, E.O. 13563)

E.O. 12866, as amended by E.O. 14094, provides that the Office of Information and Regulatory Affairs (OIRA) within the Office of Management and Budget (OMB) will review all significant rules. OIRA has determined that this final rule constitutes a “significant regulatory action” within the scope of section 3(f)(1) of E.O. 12866, as amended by E.O. 14094.

During the comment period for the proposed rule, some commenters suggested that the proposed rule would cause adverse effects on the economy, the energy sector of the economy, and all communities that rely on fluid mineral development as their major economic driver. Commenters pointed to the language in the preference criteria for leasing under § 3120.42, asserting it could severely restrict the amount of oil and gas leasing on Federal lands. The BLM disagrees. Codifying the preference criteria will ensure that oil and gas leasing on public lands focuses development where there is the most potential for recovery and allows the agency to manage public lands for other uses. The BLM completed an RIA and determined that the net costs to the economy range from a cost of $8.0 million to a cost of $13.2 million, depending on the cost of bonds (1 percent or 2 percent) and the number of wells the BLM reclaims (15 wells or 24 wells). As discussed in the RIA, the BLM expects that the expedited timing for reclamation of orphaned wells from increased bonding could provide benefits related to wildlife, vegetation, soil erosion, climate change (reduced greenhouse gas emissions from unplugged orphaned wells), visual and aesthetic resources, ground water, and allowing the surface land to be utilized for other uses sooner (for example, for grazing purposes). The BLM cannot currently quantify these benefits using the information available to the BLM.

Other benefits of the final rule include ensuring that costs reside with oil and gas lessees, operating rights owners, and operators, and not the American public. This includes adjusting the BLM's cost recovery mechanisms so that project applicants provide a more equitable share of the BLM's up-front costs for processing these applications. Finally, the BLM implements several changes to provide a transparent leasing process that focuses leasing on areas with a greater likelihood of being developed with fewer resource conflicts and ensuring transparency in these processes. Overall, shifting the financial responsibility for leasing to industries and ensuring transparency in the decision-making process will result in a more effective, fair, and accountable regulatory framework that benefits both businesses and society as a whole.

E.O. 13563 reaffirms the principles of E.O. 12866 while calling for improvements in the Nation's regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. The E.O. directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas.

This final rule replaces the BLM's current rules governing oil and gas leasing, which are contained in 43 CFR 3100 through 3140, and revises some regulations governing oil and gas operations, which are contained in 43 CFR 3150 through 3171.

For any regulatory action that OIRA determines is a significant regulatory action under section 3(f)(1) of E.O. 12866, section 6(a)(3)(C) of E.O. 12866 requires Federal agencies to provide an assessment, including the underlying analysis, of costs and benefits of potentially effective and reasonably feasible alternatives to the planned regulation, identified by the agencies or the public (including improving the current regulation and reasonably viable non-regulatory actions), and an explanation why the planned regulatory action is preferable to the identified potential alternatives. 58 FR 51735, 51741. The BLM developed this final rule in a manner consistent with the requirements in E.O. 12866 and E.O. 13563.

For more detailed information on the BLM's analysis, as required by the referenced Executive Orders, see the RIA prepared for this final rule. The RIA has been posted in the docket for the final rule on the Federal eRulemaking Portal: https://www.regulations.gov. In the Searchbox, enter “RIN 1004-AE80”, click the “Search” button, open the Docket Folder, and look under Supporting Documents.

B. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) (5 U.S.C. 601 et seq.) requires that Federal agencies prepare a regulatory flexibility analysis for rules subject to the notice-and-comment rulemaking requirements under the Administrative Procedure Act (5 U.S.C. 500 et seq.), if the rule would have a significant economic impact, whether detrimental or beneficial, on a substantial number of small entities. See 5 U.S.C. 601-612. Congress enacted the RFA to ensure that government regulations do not unnecessarily or disproportionately burden small entities. Small entities include small businesses, small governmental jurisdictions, and small not-for-profit enterprises.

The BLM reviewed the Small Business Administration's (SBA) size standards for small businesses and the number of entities fitting those size standards as reported by the U.S. Census Bureau in the Economic Census. The number of small businesses in States where there are existing Federal oil and gas leases is estimated to be 20,975 for the Crude Petroleum Extraction and Natural Gas Extraction industries (North American Industry Classification System (NAICS) codes 211120 and 21130, respectively). The BLM concludes that the vast majority of entities operating in the relevant sectors are small businesses as defined by the SBA. As such, the final rule will likely affect a substantial number of small entities.

In addition, the rule will have a distributional and positive impact on the Direct Property and Casualty Insurance Carriers Industry (NAICS 524126). Additional premiums will be paid by lessees in the oil and natural gas extraction industries to surety companies who will be providing the coverage to meet the proposed bonding requirements. The number of small businesses in the oil and gas industry in States where there are existing Federal oil and gas leases is estimated to be 476,687. This is because the SBA defines a small business for purposes of the Crude Petroleum Extraction and Natural Gas Extraction industries (NAICS codes 211120 and 21130, respectively) as one which has 1,250 or fewer employees.

Finally, the BLM received multiple comments expressing concerns related to impacts that the proposed rule would have on small entities. Specifically, the comments stated that: (1) the BLM should have included the changes from the IRA in its analysis for the Regulatory Flexibility Act (RFA); (2) the BLM should have mailed notification of the proposed rule to the affected small businesses under the RFA; (3) the BLM should have considered alternatives as required by the RFA; and (4) this rule requires the preparation of an initial and final Regulatory Flexibility Analysis. The BLM reviewed the final rule and has determined that, although the final rule will likely affect a substantial number of small entities, that effect will not be significant. The basis for this determination is explained in more detail in the RIA.

Because the increased royalty amounts, bonus bids, and rentals, and the EOI fee, are non-discretionary, the BLM is not required to include these increases in its evaluation of the impacts on small businesses. Congress passed the RFA “to establish as a principle of regulatory issuance that agencies shall endeavor, consistent with the objectives of the rule and of applicable statutes, to fit regulatory and informational requirements to the scale of the businesses, organizations, and governmental jurisdictions subject to regulation. To achieve this principle, agencies are required to solicit and consider flexible regulatory proposals and to explain the rationale for their actions to assure that such proposals are given serious consideration.” Public Law 96-354, section 2(b), 94 Stat. 1164 (1980). The RFA requires agencies to analyze alternatives to their rules with an eye towards minimizing significant impacts on small entities. 5 U.S.C. 603(c), 604(a)(6). In this case, the BLM cannot consider alternatives to mandatory instructions in the IRA. The nondiscretionary changes include the increased minimum bonus bid, rental, and royalty rate, and the new EOI fee. The only discretionary cost increases at issue in this final rule are the increased bonding amounts and filing fees, which are fully analyzed. Aside from assessing alternatives to the statutorily mandated provisions of this rule, however, the BLM has provided the analysis the RFA requires.

Based on the BLM's review of the costs associated with the increased bonding, the BLM has determined that the incremental costs that a company must pay to meet the increased bonding amounts are unlikely to deter a company from obtaining a lease and developing it. As discussed in the RIA, sureties offer both new and existing operators the ability to cover the increased bond amount at an estimated cost of only 1 to 2 percent per year of the additional bond amount.

While there were multiple comments stating that small operators will be forced to shut in wells, will be at higher risk of going bankrupt, or will go bankrupt due to the increased costs, the comments did not provide the well- or lease-level financial information needed to support these claims. The BLM reviewed available data and reported statistics on the sensitivity of low-producing wells to changes in wellhead prices and concluded that, given the range of recent and expected oil prices, even low-producing wells generate sufficient revenue to fund the increased level of bonding. The economic data provided from the public comment period did not provide the necessary detail to support a more detailed analysis. For example, one commenter provided a report on the economic benefits of oil and gas leasing. This report supported our baseline in the RIA; however, it did not change the BLM's estimates of the impacts from this rule.

Notably, the BLM has only limited access to financial data of the small businesses themselves, since most of those small businesses are privately held and are not required to report their financial information to the BLM or any other public forum. Even if a company is public, those covered under the NAICS codes for Crude Petroleum and Natural Gas Extraction are often partnerships or limited liability companies, which frequently merge and split, making it difficult to determine if a firm composed of partners and subsidiaries are sufficiently affiliated to be considered small businesses or if they are functionally a subsidiary of a larger firm. Even when financial statements are available for review, those statements are designed to standardize overall reporting of an entity's finances and do not specify income and expenditures associated with production from Federal wells. Nor is it possible to obtain the requisite information on both Federal production volume and the production costs of this Federal production from any Federal database. For example, ONRR reports production volumes but not production costs. Constructing the needed data on Federal production and financial costs requires cross-referencing several data sources that are not readily available.

Therefore, based on the BLM's review, the BLM lacks the data to determine whether the rule will impact small businesses in the manner the commenters assert. Nor is such information reasonably available to the BLM such that it could undertake such analysis. The BLM has, nevertheless, reaffirmed its finding that the rule will not have a significant impact on a substantial number of small entities for the reasons described above in this section.

In summary, the per-entity, annualized compliance costs associated with this final rule are estimated to represent only a small fraction of the annual net incomes of the companies likely to be impacted. Because the final rule will not have a “significant economic impact on a substantial number of small entities,” neither an initial nor a final regulatory flexibility analysis is required.

The Secretary of the Interior certifies under 5 U.S.C. 605(b) that this rule will not have a significant economic impact on a substantial number of small entities.

C. Congressional Review Act

The Congressional Review Act (5 U.S.C. 804(2)) requires certain procedures for “any rule that the Administrator of the Office of Information and Regulatory Affairs of the Office of Management and Budget finds has resulted in or is likely to result in—

a. an annual effect on the economy of $100 million or more;

b. a major increase in costs or prices for consumers, individual industries, Federal, State, or local government agencies, or geographic regions;

c. significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of United States-based enterprises to compete with foreign-based enterprises in domestic and export markets.

DOI will report to Congress on the promulgation of this rule prior to its effective date. The report will state that the Office of Information and Regulatory Affairs has determined that this rule meets the criteria set forth in 5 U.S.C. 804(2).

D. Unfunded Mandates Reform Act (UMRA)

The final rule will not have a significant or unique effect on State, local, or Tribal governments or the private sector. The rule contains no requirements that apply to State, local, or Tribal governments. The rule revises requirements that otherwise apply to the private sector participation in a voluntary Federal program. The compliance costs associated with the rule are below the monetary threshold established at 2 U.S.C. 1532(a). The rule updates the BLM's existing regulations to reflect the IRA's changes to lease terms. Those provisions (which became effective with the enactment of the IRA and which the BLM has no discretion to modify) will result in additional transfer payments made from the private sector to the U.S. Treasury, which then distributes portions to State governments and various funds, such as the Land and Water Conservation Fund. The BLM estimates the transfer payments will total $210 million per year, but these payments are not a result of action taken by the BLM and are instead Congressionally mandated. Since the discretionary provisions of the rule impose compliance costs that are below the $100,000,000 threshold established at 2 U.S.C. 1532(a), a statement containing the information required by the Unfunded Mandates Reform Act (UMRA) (2 U.S.C. 1531 et seq.) is not required for the final rule. This final rule is also not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments, because it contains no requirements that apply to such governments, nor does it impose obligations upon them. In any event, this rule and the accompanying Regulatory Impact Analysis provide all the information the UMRA requires.

E. Governmental Actions and Interference With Constitutionally Protected Property Right—Takings (E.O. 12630)

This final rule will not effect a taking of private property or otherwise have taking implications under E.O. 12630; therefore, a takings implication assessment is not required. The final rule replaces the BLM's current rules governing oil and gas leasing, which are contained in 43 CFR 3100 through 3140, and some governing oil and gas operations, which are contained in 43 CFR 3160 and 3171. Therefore, the rule will impact future leases on Federal land; however, it will not impact current leases. All other terms in the regulations are not considered a taking of private property as such operations are subject to the existing lease terms which expressly require that subsequent lease activities be conducted in compliance with subsequently adopted Federal laws and regulations.

This final rule conforms to the terms of the existing leases and applicable statutes and, as such, the rule is not a government action capable of interfering with constitutionally protected property rights. Therefore, the BLM has determined that the rule will not cause a taking of private property or require further discussion of takings implications under E.O. 12630.

F. Federalism (E.O. 13132)

Under the criteria in section 1 of E.O. 13132, this final rule does not have any federalism implications to warrant the preparation of a federalism summary impact statement.

The final rule will not have a substantial direct effect on the States, on the relationship between the Federal Government and the States, or on the distribution of power and responsibilities among the levels of government. It does not apply to States or local governments or State or local governmental entities. The rule will affect the relationship between operators, lessees, and the BLM, but it does not directly impact the States. Therefore, in accordance with E.O. 13132, the BLM has determined that this final rule does not have sufficient federalism implications to warrant preparation of a Federalism Assessment.

Several commenters suggested that the BLM should make substantial changes to the rule to allow for better cooperation with States and local governments when their jurisdictions overlap. For example, one comment stated that the BLM must respect local governments' regulatory authority over State, private, and trust mineral and water resources within each State. Another comment stated that the proposed rule would have significant direct impacts on the States and local communities, and that, if the BLM does not offer Federal lands for lease, that omission will prevent State and private lessees from developing their leases due to the mixed ownership for horizontal wells. Some comments stated the rule is inconsistent with State laws that expedite the processing, granting, and streamlining of mineral and energy leases and permits.

The BLM developed this rule based on its statutory authority to offer federally owned lands and minerals for oil and gas leasing and development. The BLM has evaluated the federalism implications of this rule as required by E.O. 13132. Although the final rule will affect the relationship between operators, lessees, and the BLM, it will not directly impact the States' leasing ability. Local governments and the public may submit information to the BLM on how the development of nominated lands may affect the development of adjacent non-Federal lands when the BLM is considering lands for leasing. This could occur either when the EOI is submitted or during the scoping and public comment periods for the lease sales.

G. Civil Justice Reform (E.O. 12988)

This final rule complies with the requirements of E.O. 12988. More specifically, this final rule meets the criteria of section 3(a), which requires agencies to review all regulations to eliminate errors and ambiguity and to write all regulations to minimize litigation. This final rule also meets the criteria of section 3(b)(2), which requires agencies to write all regulations in clear language with clear legal standards.

H. Consultation and Coordination With Indian Tribal Governments (E.O. 13175 and Departmental Policy)

The Department strives to strengthen its government-to-government relationship with Indian Tribes through a commitment to consultation with Indian Tribes and recognition of their right to self-governance and tribal sovereignty.

The BLM evaluated this final rule under the Department's consultation policy and under the criteria in E.O. 13175 to identify possible effects of the rule on federally recognized Indian Tribes. Since the changes to leasing only apply to Federal lands, the final rule will not impact the leasing of Indian minerals. The final rule could impact Tribal minerals as the BLM will require operators on both Federal and Tribal minerals to comply with the requirements within Parts 3160 and 3170, including the changes for shut-in and temporarily abandoned wells and approved APDs.

In August of 2021, the BLM sent a letter to each registered Tribe informing them of certain rulemaking efforts, including the development of this final rule. The letter offered Tribes the opportunity for individual government-to-government consultation regarding the rulemaking.

In June 2023, the BLM sent another letter to each registered Tribe informing them of the proposed rule. During the comment period for the proposed rule, a commenter, who is not from a Tribe, stated that the BLM should fulfill its Federal trust obligation to Tribes to protect their interest and further the government-to-government relationships with Tribes. The BLM concurs and worked to inform the Tribes of the changes proposed in this rulemaking. The BLM did receive comments from a Tribe as previously discussed in Section III.B.4. and III.B.8. of this preamble.

I. Paperwork Reduction Act

The Paperwork Reduction Act (PRA) (44 U.S.C. 3501-3521) generally provides that an agency may not conduct or sponsor, and not withstanding any other provision of law, a person is not required to respond to a collection of information, unless it displays a currently valid OMB control number. Collections of information include any request or requirement that persons obtain, maintain, retain, or report information to an agency, or disclose information to a third party or to the public (44 U.S.C. 3502(3) and 5 CFR 1320.3(c)).

This final rule contains information-collection requirements that are subject to review by OMB under the PRA. OMB has generally approved the existing information collection requirements contained in the regulations that will be affected by this final rule under the following OMB Control Numbers:

• 43 CFR 3100, 3120, and subpart 3162—OMB Control Number 1004-0185;
• 43 CFR 3106—OMB Control Number 1004-0034;
• 43 CFR part 3130—OMB Control Number 1004-0196;
• 43 CFR 3150—OMB Control Number 1004-0162; and
• 43 CFR 3160—OMB Control Number 1004-0137.

The BLM plans to transfer the information collection requirements contained in 43 CFR 3106 from OMB control number 1004-0034 to OMB Control Number 1004-0185 in order to keep similar information collections requirements together under the same OMB Control Number. Additionally, the BLM plans to transfer information collection requirements contained in 43 CFR 3160 from OMB Control Number 1004-0137 to a new OMB Control Number. Once approved by OMB, the new OMB Control Number will be 1004-0220. The new and revised information collection requirements are discussed as follows, along with the resulting changes in public burdens.

1. Changes Impacting Information Collections Previously Under OMB Control Number 1004-0137

The final rule will result in new information collection requirements that will require OMB approval under a new OMB control number (previously, 1004-0137). This final rule is estimated to result in 33,621 annual responses, 260,928 annual burden hours, $35,400,000 non-hour cost burdens under this new OMB Control Number.

The new information collection requirements are described as follows.

43 CFR 3162.3-4 Well Abandonment. The final rule requires that no well may be abandoned for more than 30 days unless the operator provides adequate and detailed justifications and verification of the mechanical integrity of the wells and isolation of the perforations. The new information collection requirements include:

• Justification for Temporary Well Abandonment—43 CFR 3162.3-4(d);
• Reporting Shut-in Status—43 CFR 3162.3-4(e);
• Verification of Mechanical Integrity—43 CFR 3162.3-4(e)(2) and 3162.3-4(f); and
• Plan and Timeline for Future Beneficial Use—43 CFR 3162.3-4(e)(3)(iii).

The BLM believes these new requirements with yearly interval checks will help operators stay on top of shut-in wells, thus preventing them from becoming orphaned in the future. The addition of these information collection requirements will result in an addition of 5,500 annual responses, 52,000 annual burden hours.

Currently, there are 301,663 annual responses, 1,835,888 annual burden hours, and $31,080,000 annual non-hour cost burdens inventoried under the OMB Control Number 1004-0137. This final rule will create a new OMB Control Number and moves 28,121 annual responses, 208,298 annual burden hours, and $31,080,000 annual non-hour cost burdens inventoried under OMB Control Number 1004-0137 into this OMB Control Number.

In addition, there is an adjustment of $4.3 million in annual non-hour cost burdens (from $31 million to 35.4 million). This adjustment results from the annual inflation adjustment of filing fees and do not result from the final rule. The resulting new estimated total burdens for this new OMB Control Number are provided as follows.

Title of Collection: Onshore Oil and Gas Operations and Production (43 CFR parts 3160 and 3170).

OMB Control Number: 1004-0220.

Form Numbers: BLM Form 3160-003; BLM Form 3160-004; and BLM Form 3160-005 (these forms will not change).

Type of Review: Revision of a currently approved collection of information.

Respondents/Affected Public: Oil and gas operators on public lands and some Indian lands.

Total Estimated Number of Annual Respondents: 7,500.

Total Estimated Number of Annual Responses: 33,621.

Estimated Completion Time per Response: Varies from 4 to 32 hours, depending on activity.

Total Estimated Number of Annual Burden Hours: 260,928.

Respondent's Obligation: Required to obtain or retain a benefit.

Frequency of Collection: On occasion; One-time; and Monthly.

Annual Burden Cost: $35,400,000.

2. Changes Impacting OMB Control Number 1004-0162

Currently, there are 68 annual responses, 26 annual burden hours, and $25 annual non-hour cost burdens inventoried under OMB Control Number 1004-0162. It is not anticipated that the final rule will change the results to the annual responses, annual burden hours, or non-hour cost burdens under this OMB Control Number. The revised information collection requirement is described as follows.

43 CFR 3151.30—Collection and submission of data. The final rule adds a new requirement for the permittee to provide the BLM with all data and information obtained in carrying out the exploration plan, matching the requirement for geophysical exploration permits in Alaska. This does not change the existing burden for what applicants to submit to the BLM.

Title of Collection: Onshore Geophysical Exploration (43 CFR part 3150 and 36 CFR parts 228 and 251).

OMB Control Number: 1004-0162.

Form Number: BLM 3150-4/FS 2800-16; BLM 3150-5/FS 2816a (these forms will not change).

Type of Review: Revision of a currently approved collection of information.

Respondents/Affected Public: The respondents for this collection of information are businesses that seek to conduct geophysical exploration on Federal lands.

Respondent's Obligation: Required to Obtain or Retain a Benefit.

Frequency of Collection: On occasion.

Estimated Completion Time per Response: Varies from 20 minutes to 1 hour, depending on activity.

Number of Respondents: 68.

Annual Responses: 68.

Annual Burden Hours: 26.

Annual Burden Cost: $1,150.

3. Changes Impacting OMB Control Number 1004-0185

Currently, there are 9,132 annual responses, 37,695 annual burden hours, and $751,415 annual non-hour cost burdens inventoried under OMB Control Number 1004-0185. This final rule is estimated to result in 16,340 annual responses, 29,410 annual burden hours, $3,766,184, non-hour cost burdens under this OMB Control Number. The final rule will result in new, revised, and removed information collection requirements. Additionally, as discussed earlier, the BLM will also be transferring certain information collection requirements, along with the associated burdens from OMB Control Number 1004-0034 to OMB Control Number 1004-0185. These changes are discussed blow.

Revised Information Collection Requirements

43 CFR 3100.31(b)—Option Enforceability. The final rule revises this requirement to clarify that a statement of the number of acres and the type and percentage of interest to be conveyed and retained by the parties to the option. This does not change the burden requirement. The existing regulation already states the interest to be conveyed and retained in exercise of the option. The BLM needs to understand if the type of interest is referring to record title or operating rights and the percentage to be conveyed and retained by the option holder.

43 CFR 3105.21—Where to File Communitization Agreements. The final rule removes the triplicate filing requirement. The final rule adds a new paragraph (b) to this section to require that all applications to form a CA be filed with a statement as to whether the proposed CA deviates from the BLM's current model CA form, and a certification that the applicant received the required signatures. Further, all applications to form a CA shall include an Exhibit A displaying a map of the agreement and the separate agreement tracts and all applications to form a CA shall include an Exhibit B displaying the separate tracts and ownership. The new paragraph (c) states that all applications to form a CA should be submitted at least 90 calendar days prior to first production to ensure correct reporting to the ONRR. These requirements codify existing policy requirements and does not change the existing burden for what applicants to submit to the BLM. The information is needed to understand all the parties that share in the production of a well due to State spacing orders.

43 CFR 3105.31—Where filed. (Operating, Drilling or Development Contracts). The final rule removes the requirement for five copies of an operating, drilling or development contract to be submitted when these contracts are submitted to the BLM for approval. This reduces the burden to respondents.

43 CFR 3105.41—Where filed. (Subsurface storage application (previously, 3105.5)). The final rule designates the existing 43 CFR 3105.5 for gas storage agreements to the redesignated 43 CFR 3105.41. This redesignation is due to the elimination of the section on the combination for joint operations or for transportation of oil. The final rule updates paragraph (a) to include designation of successor operators for gas storage agreements among the applications to be filed in the proper BLM office. The final rule updates paragraph (b) to remove the requirement for five copies of a gas storage agreement to be submitted when these are filed with the BLM. A new paragraph (c) requires that all applications for a gas storage agreement or a designation of a successor operator must include the new processing fee found in the fee schedule in 43 CFR 3000.120. The new processing fee is intended to reimburse the BLM for processing the applications.

43 CFR 3105.50—Consolidation of Leases (formerly, 3105.6). Leases may be consolidated upon written request of the lessee filed with the proper BLM identify each lease involved by serial number and shall explain the factors that justify the consolidation and requires that each request for a consolidation of leases the processing fee found in the fee schedule in 43 CFR 3000.120. The final rule splits the single paragraph under this section into several paragraphs for clarity, however these are not new requirements and does not change the existing burden.

43 CFR 3106.81—Heirs and devisees. The updates this information collection requirement to state that the lease interest will be transferred to the heirs, devisees, executor or administrator of the estate, as appropriate, upon the filing of a court order, death certificate, or other legal document demonstrating that transferee is to be recognized as the successor of the deceased. These requirements codify existing policy requirements and does not change the existing burden for what applicants currently submit to the BLM to show proof on how the lease interest transferred to another party.

43 CFR 3106.82—Change of name. The current regulation requires a notice of the name change to be accompanied by a list of the serial numbers of the leases affected by the name change. This requirement is removed as it is outdated and unenforceable. This lessens the burden to respondents. In practice, the BLM generates a report of the leases affected by the name change and returns that list to the lessee with a notice that recognizes the name change that occurred through operation of law. This section is updated to require that, for a corporate name change, the request should include the Secretary of State's Certificate of Name Change along with the Articles of Incorporation, or Amendment, if available. This is consistent with the BLM's current approach for processing these types of documents. These requirements codify existing policy requirements and does not change the existing burden for what applicants currently submit to the BLM to show proof on how the lease interest transferred to another party.

43 CFR 3106.83—Corporate mergers and dissolution of corporations, partnerships and trusts. The final rule updates the title of this section from “Corporate merger” to “Corporate mergers and dissolution of corporations, partnerships and trust”. The goal of the renaming of this section is to incorporate these other types of transfers that have the same process. The current regulation requires a notification of merger to be accompanied by a list of the serial numbers of the leases affected by the merger. This requirement is eliminated as it is outdated and unenforceable. This lessens the burden to respondents. In practice, the BLM does not rely on a list of leases provided by a lessee and instead generates its own report of the leases affected by the merger. The BLM returns that list to the lessee with a notice that recognizes the merger that occurred through operation of State law. This section is updated to require that, for a merger, the request should include the Secretary of State's Certificate of Merger along with the Articles of Incorporation, or Amendment, if available. This is consistent with the BLM's current approach for processing these types of documents. These requirements codify existing policy requirements and does not change the existing burden for what applicants currently submit to the BLM to show proof on how the lease interest transferred to another party.

43 CFR 3108.23—Reinstatement at higher rental and royalty rates: Class II reinstatements. The final rule eliminates the existing paragraph (b)(1) in its entirety. This provision addresses the timeliness of Class II reinstatement petitions for leases that terminated on or before August 8, 2005, and is no longer applicable. This does not change an existing burden since a petition to reinstate a lease that terminated on or before August 8, 2005, would have already been received by an applicant.

43 CFR 3109.12—Application. The final rule also adds a new requirement that the applicant must include a map of the applicable lands which will support the bidding process related to the lease or compensatory royalty agreement. These requirements codify existing policy requirements and does not change the existing burden for what applicants to submit to the BLM.

New Information Collection Requirements

43 CFR 3106.84—Sheriff's sale/deed. The final rule adds a new section under other types of transfers to include sheriff's sales. The BLM accepts these types of transfers to recognize lease interests transferred to other parties through foreclosure actions. The final rule states that where a notice of sale of the leasehold interest is published pursuant to State law applicable to the execution of sales of real property, the purchaser shall submit a copy of the Sheriff's Certificate of Sale after any redemption period has passed to the proper BLM office. Additional paragraphs under this new section include a filing fee requirement, a qualification statement, and bonding requirements. These requirements are consistent with the BLM's current approach for processing these types of documents. These documents are already submitted and recognized by the BLM when changes in ownership of interests in Federal oil and gas leases occur without any intention by the holder of interest to assign or transfer interest. The addition of this information collection will result in an addition of 1 annual response, 1 annual burden hour, and $55.80 annual non-hour cost burdens.

43 CFR 3120.31—Expression of Interest (EOI) Process. The final rule adds a new section titled “Expression of Interest” to codify the current process of receiving EOIs for competitive leasing to the BLM's online leasing system. An EOI is a description of lands that an applicant seeks to include in a competitive auction. The expression must provide a description of the lands identified by legal land description and identify the U.S. mineral ownership percentage. This information collection will result in an addition of 395 annual responses (average of 1,000 acres per response), 3,160 annual burden hours, and $1,975,000 annual non-hour cost burdens (calculated by average acreage per response).

Removed Information Collection Requirements

43 CFR 3101.2-6—Ad Hoc Acreage Statement. At any time, the BLM may require a lessee or operator to file a statement showing as of the specified date, the serial number and the date of each lease in which the lessee or operator has any interest, in the particular State, setting forth the acreage covered thereby. The BLM uses the information to determine whether or not a lessee is in compliance with the law with respect to statutory acreage limitations. This revision results in the reduction of 1 response and 1 burden hour, annually.

43 CFR 3105.4—Combination for joint operations or for transportation of oil. The final rule eliminates the section on the combination for joint operations or for transportation of oil. These provisions are not used by the BLM or operators and are outdated. This revision results in the reduction of 1 response and 1 burden hour, annually.

43 CFR 3107.8—Renewal leases. The final rule eliminates the provisions on renewal leases in their entirety because they are outdated. Renewal leases that had an expiration date after November 15, 1990, were eligible for one last renewal under the provisions of the November 15, 1990, Act, i.e., for 10 years, and for so long thereafter as oil and gas is produced in paying quantities. If a lease was renewed after the 1990 amendment and was not producing oil or gas at the end of its 10-year renewal term, the lease expired with no further option for renewal. The removal of this information collection will result in a reduction of 1 annual response, 1 annual burden hour, and $475 annual non-hour cost burdens.

Class III reinstatement petition (43 CFR 3108.2-4). The requirement is removed from the final rule resulting in a reduction of one annual response and one burden hour as well as $651 in non-hour cost burden.

Information Collection Requirements Transferred From OMB Control Number 1004-0034

The following two information collections will be moved into OMB Control Number 1004-0185 to keep information collection requirements in subpart 3106 under the same OMB Control Number:

1. 43 CFR 3106.41, Transfers of record title and of operating rights (subleases) and 3106.42, Transfers of other interests, including royalty interests and production payments. This transfer will result in 3,852 annual responses, 1,926 annual burden hours, and $404,460 non-hours cost burdens being added to this OMB Control Number.

2. 43 CFR 3106.43 Mass transfers. This transfer will result in 4,944 annual responses, 2,472 annual burden hours, and $519,120 non-hours cost burdens being added to this OMB Control Number.

The resulting new estimated total burdens for OMB Control Number 1004-0185 are provided as follows.

Title of Collection: Onshore Oil and Gas Leasing, and Drainage Protection (43 CFR parts 3100, 3120, and 3150, and subpart 3162).

OMB Control Number: 1004-0185.

Form Number: None.

Type of Review: Revision of a currently approved collection of information.

Respondents/Affected Public: Holders of onshore oil and gas lease and public lands and Indian lands (except on the Osage Reservation), operators of such leases, and holders of operating rights on such leases.

Respondent's Obligation: Required to Obtain or Retain a Benefit.

Frequency of Collection: Varies from 1 hour to 24 hours per response, depending on activity.

Number of Respondents: 16,339.

Annual Responses: 16,340.

Annual Burden Hours: 29,410.

Annual Burden Cost: $3,766,184.

4. Changes Impacting OMB Control Number 1004-0196

Currently, there are there are 21 annual responses and 220 annual burden hours associated with this OMB control number. There are also no non-hours cost burden currently associated with this OMB control number. The final rule is not projected to result in any new annual responses. The additional requirements in 43 CFR 3170.80(b) include description of the anticipated PA(s) size and define the proposed PAs in the unit designation agreements required by 43 CFR 3137.21, and 3137.23 is not projected to result in additional burden for that information collection.

43 CFR 3000.120 introduces new filing fees for the following information collections, resulting in a new total estimated annual non-hour burden cost of $1,320;

• $120 for Statement of change of unit operator (43 CFR 3137.61); and
• $1,200 for Application for storage agreement (43 CFR 3138.11);

Additionally, the existing 43 CFR 3137.86, New information demonstrating that the participating area should be larger or smaller than previously determined, contains the following three information collection requirements for which the burden has not been previously captured in this OMB control number:

• Information demonstrating that a participating area should be larger than previously determined (43 CFR 3137.86(a)(1));
• Application to enlarge participating area outside of existing boundaries (43 CFR 3137.86(a)(2)); and
• Statement for additional committed tract or tracts are added to the unit under paragraph (a)(2) (43 CFR 3137.86(a)(3)).

The resulting new estimated total burdens for OMB Control Number 1004-0196 are provided as follows.

Title of Collection: Oil and Gas Leasing: National Petroleum Reserve—Alaska (43 CFR part 3130).

OMB Control Number: 1004-0196.

Form Number: None.

Type of Review: Revision of a currently approved collection of information.

Respondents/Affected Public: Participants within the oil and gas leasing program within the National Petroleum Reserve—Alaska.

Respondent's Obligation: Required to Obtain or Retain a Benefit.

Frequency of Collection: On occasion.

Estimated Completion Time per Response: Varies from 15 minutes to 80 hours, depending on activity.

Number of Respondents: 24.

Annual Responses: 24.

Annual Burden Hours: 223.

Annual Burden Cost: $1,320.

If you want to comment on the information-collection requirements in this rule, please send your comments and suggestions on this information-collection request within 30 days of publication of this final rule in the Federal Register to OMB at www.reginfo.gov. Click on the link, “Currently under Review—Open for Public Comments.”

J. National Environmental Policy Act

The BLM received comments on this section. One commenter stated the BLM properly issues the rule pursuant to a categorical exclusion. Other comments recommended that the BLM use an environmental assessment for the rule. Commenters stated the rule affects decisions in RMPs, because the preference criteria would guide the BLM's decision making and direct oil and gas leasing to appropriate locations. Another commenter stated that the economic burden that the proposed rule would cause for oil and gas operators and State economies would require the BLM to perform a NEPA analysis on the portions of the proposed rule that are beyond the scope of changes required by Congress in the IRA. As previously stated, this rule does not close additional lands for oil and gas leasing and the MLA has vested the Secretary with broad discretion to decide, up until the time of lease issuance, whether particular parcels of Federal land “may be leased” for oil and gas development, see 30 U.S.C. 226(a). The BLM completed an RIA and an extraordinary circumstances review and determined that the BLM can issue this rule under the applicable Departmental categorical exclusion.

A detailed environmental analysis under NEPA is not required, because the final rule is covered by a categorical exclusion (see 43 CFR 46.205). This final rule meets the criteria set forth at 43 CFR 46.210(i) for a Departmental categorical exclusion in that this final rule is “of an administrative, financial, legal, technical, or procedural nature.” The BLM also has determined that the final rule does not involve any of the extraordinary circumstances listed in 43 CFR 46.215 that would require further analysis under NEPA.

K. Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use (E.O. 13211)

Under E.O. 13211, agencies are required to prepare and submit to OMB a Statement of Energy Effects for significant energy actions. This statement is to include a detailed statement of “any adverse effects on energy supply, distribution, or use (including a shortfall in supply, price increases, and increase use of foreign supplies)” for the action and reasonable alternatives and their effects.

Section 4(b) of E.O. 13211 defines a “significant energy action” as “any action by an agency (normally published in the Federal Register ) that promulgates or is expected to lead to the promulgation of a final rule or regulation, including notices of inquiry, advance notices of proposed rulemaking, and notices of proposed rulemaking: (1)(i) that is a significant regulatory action under E.O. 12866 or any successor order, and (ii) is likely to have a significant adverse effect on the supply, distribution, or use of energy; or (2) that is designated by OIRA as a significant energy action.”

The BLM believes that the final rule may affect the locations that operators choose for future oil or gas development but will have little impact on an entity's decision to invest in energy development, the size of that development, or the production from that development. As a result of this rule, an entity holding existing nonproducing leases may choose to shift more future development to those existing leases or to develop non-Federal acreage instead of securing new Federal leases, and some entities may be relatively less likely to choose a new Federal lease to a comparable non-Federal lease. Also, any incremental changes in oil or gas production estimated to result from the rule's enactment would constitute a small fraction of total U.S. gas production, and any potential and temporary deferred production of oil would likewise constitute a small fraction of total U.S. oil production. Some commenters disagreed and pointed to the preference criteria as increasing the risk for litigation, which could shift development off Federal land and increase the cost to produce gas or oil. The BLM disagrees. The preference criteria under § 3120.32 support the BLM's existing policy and direction to make a public interest determination, which has existed at least since 1988. See53 FR 22828 (June 17, 1988) (“It is Bureau policy prior to offering the lands to determine whether leasing will be in the public interest and to identify stipulation requirements, obtain surface management agency leasing recommendations and consent where applicable and required by law”). It will not have the impact stated in these comments. For these reasons, we do not expect that the final rule will significantly impact the supply, distribution, or use of energy. As such, the rulemaking is not a “significant energy action” as defined in E.O. 13211.

VI. Authors

The principal authors of this final rule include: Peter Cowan, Senior Mineral Leasing Specialist in BLM Headquarters; Jennifer Spencer, Mineral Leasing Specialist in BLM Headquarters; William Lambert, Petroleum Engineer in BLM Headquarters; Natalie Eades, Attorney Advisor in DOI Office of the Solicitor. Technical support provided by: Scott Rickard, Economist in BLM Headquarters; Travis Kern, Program Analyst in BLM Headquarters; and Erik Vernon, Air Resources Program Lead in BLM Utah State Office. Assisted by: Duane Spencer, Deputy State Director of Minerals and Land in BLM Wyoming State Office; JulieAnn Serrano, Supervisory Land Law Examiner in BLM New Mexico State Office; and Darrin King, Senior Regulatory Analyst in BLM Headquarters.

List of Subjects

43 CFR Part 3000

• Public lands-mineral resources
• Reporting and recordkeeping requirements

43 CFR Part 3100

• Government contracts
• Mineral royalties
• Oil and gas reserves
• Public lands-mineral resources
• Reporting and recordkeeping requirements
• Surety bonds

43 CFR Part 3110

• Government contracts
• Oil and gas exploration
• Public lands-mineral resources
• Reporting and recordkeeping requirements

43 CFR Part 3120

• Government contracts
• Oil and gas exploration
• Public lands-mineral resources
• Reporting and recordkeeping requirements

43 CFR Part 3130

• Alaska
• Government contracts
• Mineral royalties
• Oil and gas exploration
• Oil and gas reserves
• Public lands-mineral resources
• Reporting and recordkeeping requirements
• Surety bonds

43 CFR Part 3140

• Government contracts
• Hydrocarbons
• Mineral royalties
• Oil and gas exploration
• Public lands-mineral resources
• Reporting and recordkeeping requirements

43 CFR Part 3150

• Administrative practice and procedure
• Alaska
• Oil and gas exploration
• Public lands-mineral resources
• Reporting and recordkeeping requirements
• Surety bonds

43 CFR Part 3160

• Administrative practice and procedure
• Government contracts
• Indians-lands
• Mineral royalties
• Oil and gas exploration
• Penalties
• Public lands-mineral resources
• Reporting and recordkeeping requirements

43 CFR Part 3170

• Administrative practice and procedure
• Flaring
• Immediate assessments
• Indians-lands
• Mineral royalties
• Oil and gas exploration
• Oil and gas measurement
• Public lands-mineral resources
• Reporting and record keeping requirements
• Royalty-free use
• Venting

43 CFR Part 3180

• Government contracts
• Mineral royalties
• Oil and gas exploration
• Public lands-mineral resources
• Reporting and recordkeeping requirements

For the reasons set out in the preamble, the Bureau of Land Management amends 43 CFR parts 3000, 3100, 3110, 3120, 3130, 3140, 3150, 3160, 3170, and 3180 as follows:

1. Revise part 3000 to read as follows:

PART 3000—MINERALS MANAGEMENT: GENERAL

3000.5

Definitions.

3000.10

Nondiscrimination.

3000.20

False statements.

3000.30

Unlawful interests.

3000.40

Appeals.

3000.41

Severability.

3000.50

Limitations on time to institute suit to challenge a decision of the Secretary.

3000.60

Filing of documents.

3000.70

Multiple development.

3000.80

Management of Federal minerals from reserved mineral estates.

3000.90

Enforcement actions under the United States Code.

3000.100

Fees in general.

3000.110

Processing fees on a case-by-case basis.

3000.120

Fee schedule for fixed fees.

PART 3000—MINERALS MANAGEMENT: GENERAL

Authority: 16 U.S.C. 3101 et seq.;30 U.S.C. 181 et seq., 301-306, 351-359, and 601 et seq.;31 U.S.C. 9701; 40 U.S.C. 471 et seq.;42 U.S.C. 6508; 43 U.S.C. 1701 et seq.; and Pub. L. 97-35, 95 Stat. 357.

§ 3000.5

Definitions.

As used in 43 CFR parts 3000 and 3100, the term:

Acquired lands means lands which the United States obtained by deed through purchase or gift, or through condemnation proceedings, including lands previously disposed of under the public land laws including the mining laws.

Acreage for which expressions of interest have been submitted means acreage that is identified in an expression of interest received by the BLM, that has not been proposed for leasing in any pending sale or other expression of interest pending BLM disposition, and for which the BLM may lawfully issue an oil and gas lease.

Acres offered for lease means all acres that the BLM has offered for oil and gas lease, regardless of whether those acres are acreage for which expressions of interest have been submitted.

Act or MLA means the Mineral Leasing Act of 1920, as amended and supplemented (30 U.S.C. 181 et seq.).

Anniversary date means the same day and month in succeeding years as that on which the lease became effective.

Authorized officer means any BLM employee authorized to perform the duties described in parts 3000 and 3100.

BLM or Bureau means the Bureau of Land Management.

Director means the Director of the Bureau of Land Management.

Gas means any fluid, either combustible or noncombustible, which is produced in a natural state from the earth and which maintains a gaseous or rarefied state at ordinary temperatures and pressure conditions.

Interest means ownership in a lease, or prospective lease, of all or a portion of the record title, working interest, operating rights, overriding royalty, payments out of production, carried interests, net profit share or similar instrument for participation in the benefit derived from a lease. An interest may be created by direct or indirect ownership, including options. Interest does not mean stock ownership, stockholding or stock control in an application, offer, competitive bid or lease, except for purposes of acreage limitations in 43 CFR 3101.20 and qualifications of lessees in 43 CFR subpart 3102.

Oil means all nongaseous hydrocarbon substances other than those substances leasable as coal, oil shale or gilsonite (including all vein-type solid hydrocarbons).

ONRR means the Office of Natural Resources Revenue.

Party in interest means a party who is or will be vested with any interest under the lease as defined in this section. No one is a sole party in interest with respect to an application, offer, competitive bid or lease in which any other party has an interest.

Person means any individual, firm, corporation, association, partnership, consortium, or joint venture.

Proper BLM office means the Bureau of Land Management state office having jurisdiction over the lands subject to the regulations in parts 3000 and 3100.

(See 43 CFR 1821.10 for office location and area of jurisdiction of Bureau of Land Management offices.)

Properly filed means a document or form submitted to the proper BLM office with all necessary information and payments, as provided in 43 CFR subpart 1822.

Public domain lands means lands, including mineral estates, which never left the ownership of the United States, lands which were obtained by the United States in exchange for public domain lands, lands which have reverted to the ownership of the United States through the operation of the public land laws and other lands specifically identified by the Congress as part of the public domain.

Secretary means the Secretary of the Interior.

Surface managing agency means any Federal agency, other than the BLM, having management responsibility for the surface resources that overlay federally owned minerals.

§ 3000.10

Nondiscrimination.

Any person acquiring a lease under this chapter must comply fully with the equal opportunity provisions of Executive Order 11246 dated September 24, 1965, as amended, and the rules, regulations and relevant orders of the Secretary of Labor (41 CFR part 60 and 43 CFR part 17).

§ 3000.20

False statements.

As provided in 18 U.S.C. 1001, it is a crime punishable by imprisonment or a fine, or both, for any person knowingly and willfully to submit or cause to be submitted to any agency of the United States any false or fraudulent statement(s) as to any matter within the agency's jurisdiction.

§ 3000.30

Unlawful interests.

No member of, or delegate to, Congress, or Resident Commissioner, and no employee of the Department of the Interior, except as provided in 43 CFR part 20, is allowed or entitled to acquire or hold any Federal lease, or interest therein. (Officer, agent or employee of the Department—see 43 CFR part 20; Member of Congress—see R.S. 3741; 41 U.S.C. 22; 18 U.S.C. 431-433.)

§ 3000.40

Appeals.

Except as provided in 43 CFR 3000.120, 3101.53(b), 3103.1, 3165.4, and 3427.2, any party adversely affected by a decision of the authorized officer made pursuant to the provisions of 43 CFR parts 3000 or 3100 has a right of appeal pursuant to 43 CFR part 4.

§ 3000.41

Severability.

If a court holds any section or its paragraphs of the regulations in parts 3000 through 3180 or their applicability to any person or circumstance invalid, the remainder of these rules and their applicability to other persons or circumstances will not be affected.

§ 3000.50

Limitations on time to institute suit to challenge a decision of the Secretary.

No action challenging a decision of the Secretary involving any oil or gas lease (including decisions on offers or applications to lease) can be maintained unless such action is commenced or taken within 90 days after the final decision of the Secretary relating to such matter.

§ 3000.60

Filing of documents.

All necessary documents must be filed in the proper BLM office. Documents may be submitted to the BLM using hard-copy delivery services, in-person delivery, or by electronic filing. When using hard-copy delivery services or in-person delivery, the document will be considered filed only when received during regular business hours in the proper BLM office. See 43 CFR part 1820, subpart 1822.

§ 3000.70

Multiple development.

The granting of a permit or lease for the prospecting, development or production of deposits of any one mineral does not preclude the issuance of other permits or leases for the same lands for deposits of other minerals with suitable stipulations for simultaneous operation, nor the allowance of applicable entries, locations or selections of leased lands with a reservation of the mineral deposits to the United States.

§ 3000.80

Management of Federal minerals from reserved mineral estates.

Where nonmineral public land disposal statutes provide that in conveyances of title all or certain minerals are reserved to the United States together with the right to prospect for, mine and remove the minerals under applicable law and regulations as the Secretary may prescribe, the lease or sale, and administration and management of the use of such minerals will be accomplished under the regulations of 43 CFR parts 3000 and 3100. Such mineral estates include, but are not limited to, those that have been or will be reserved under the authorities of the Small Tract Act of June 1, 1938, as amended (43 U.S.C. 682(b)) and the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1701 et seq.).

§ 3000.90

Enforcement actions under the United States Code.

The United States Department of Justice is the agency responsible for the enforcement actions described in 30 U.S.C. 195, which makes it unlawful for any person to organize or participate in any scheme, arrangement, plan, or agreement to circumvent or defeat the provisions of the MLA or its implementing regulations; or to seek to obtain or to obtain any money or property by means of false statements of material facts or by failing to state materials facts concerning the:

(a) Value of any lease or portion thereof issued or to be issued under the MLA;

(b) Availability of any land for leasing under the MLA;

(c) Ability of any person to obtain leases under the MLA; or

(d) Provisions of the MLA and its implementing regulations.

§ 3000.100

Fees in general.

(a) Setting fees. Fees may be statutorily set fees, relatively nominal filing fees, or processing fees intended to reimburse the BLM for its reasonable processing costs. For processing fees, the BLM takes into account the factors in section 304(b) of the Federal Land Policy and Management Act of 1976 (FLPMA) (43 U.S.C. 1734(b)) before deciding a fee. The BLM considers the factors for each type of document when the processing fee is a fixed fee and for each individual document when the fee is decided on a case-by-case basis, as explained in § 3000. 110.

(b) Conditions for filing. The BLM will not accept a document that the applicant submits without the proper filing or processing fee amounts except for documents where the BLM sets the fee on a case-by-case basis. Fees are not refundable except as provided for case-by-case fees in § 3000. 110. The BLM will keep the fixed filing or processing fee as a service charge even if the BLM does not approve the application or the applicant withdraws it completely or partially.

(c) Periodic adjustment. The BLM will periodically adjust fees established in this subchapter according to changes in the Implicit Price Deflator for Gross Domestic Product, which is published quarterly by the U.S. Department of Commerce. Because the fee recalculations are simply based on a mathematical formula, the BLM will change the fees in final rules without opportunity for notice and comment.

(d) Timing of fee applicability. (1) For a document that the BLM received before June 22, 2024, the BLM will not charge a fixed fee or a case-by-case fee under this subchapter for processing that document, except for fees applicable under then-existing regulations.

(2) For a document that the BLM receives on or after June 22, 2024, the applicant must include the required fixed fees with the documents filed, as provided in § 3000.120(a) of this chapter, and the applicant is subject to case-by-case processing fees as provided in § 3000.110 and under other provisions of this chapter.

§ 3000.110

Processing fees on a case-by-case basis.

(a) Fees in this subchapter are designated either as case-by-case fees or as fixed fees. The fixed fees are established in this subchapter for specified types of documents. However, if the BLM decides at any time that a particular document designated for a fixed fee will have a unique processing cost, such as the preparation of an Environmental Impact Statement, the BLM may set the fee under the case-by-case procedures in this section.

(b) For case-by-case fees, the BLM measures the ongoing processing cost for each individual document and considers the factors in section 304(b) of FLPMA on a case-by-case basis according to the following procedures:

(1) The applicant may request the BLM's approval to do all or part of any study or other activity according to standards the BLM specifies, thereby reducing the BLM's costs for processing the document, in accordance with all other applicable laws and regulations.

(2) Before performing any case processing, the BLM will give the applicant a written estimate of the proposed fee for reasonable processing costs after the BLM considers the FLPMA section 304(b) factors.

(3) The applicant may comment on the proposed fee.

(4) The BLM will then give the applicant the final estimate of the processing fee amount after considering the applicant's comments and any BLM-approved work that the applicant will do.

(i) If the BLM encounters higher or lower processing costs than anticipated, the BLM will re-estimate the reasonable processing costs following the procedure in paragraphs (b)(1) through (4) of this section, but the BLM will not stop ongoing processing unless the applicant does not pay in accordance with paragraph (b)(5) of this section.

(ii) If the fee the applicant would pay under this paragraph (b)(4) is less than the BLM's actual costs as a result of consideration of the FLPMA section 304(b) factors, and the BLM is not able to process the document promptly because of the unavailability of funding or other resources, the applicant will have the option to pay the BLM's actual costs to process the document.

(iii) Once processing is complete, the BLM will refund to the applicant any money that the BLM did not spend on processing costs.

(5)(i) The BLM will periodically estimate what its reasonable processing costs will be for a specific period and will bill the applicant for that period. Payment is due to the BLM 30 days after the applicant receives its bill. The BLM will stop processing the document if the applicant does not pay the bill by the date payment is due.

(ii) If a periodic payment turns out to be more or less than the BLM's reasonable processing costs for the period, the BLM will adjust the next billing accordingly or make a refund. Do not deduct any amount from a payment without the BLM's prior written approval.

(6) The applicant must pay the entire fee before the BLM will issue the final document.

(7) The applicant may appeal the BLM's estimated processing costs in accordance with the regulations in 43 CFR part 4, subpart E. The applicant may also appeal any determination the BLM makes under paragraph (a) of this section that a document designated for a fixed fee will be processed as a case-by-case fee. The BLM will not process the document further until the appeal is resolved, in accordance with paragraph (b)(5)(i) of this section, unless the applicant pays the fee under protest while the appeal is pending. If the appeal results in a decision changing the proposed fee, the BLM will adjust the fee in accordance with paragraph (b)(5)(ii) of this section.

§ 3000.120

Fee schedule for fixed fees.

(a) The table in this section lists the services that require payment of fixed fees to the BLM. The fixed fee amounts are posted on the BLM website ( https://www.blm.gov) and published in a Federal Register notice. These fees are nonrefundable and must be included with documents filed under this chapter. Fees will be adjusted annually according to the change in the Implicit Price Deflator for Gross Domestic Product since the previous adjustment and will subsequently be posted on the BLM website ( https://www.blm.gov) and announced annually in the Federal Register before October 1 each year. Revised fees are effective each year on October 1.

Document/action

Oil & Gas (parts 3100, 3110, 3120, 3130, 3150, 3160, and 3180):

Competitive lease application

Leasing and compensatory royalty agreements under right-of-way pursuant to subpart 3109.

Lease consolidation

Assignment and transfer of record title or operating rights

Overriding royalty transfer, payment out of production

Name change; corporate merger; sheriff's deed; dissolution of corporation, partnership, or trust; or transfer to heir/devisee

Lease reinstatement, Class I

Geophysical exploration permit application—all states

Renewal of exploration permit—Alaska

Final application for Federal unit agreement approval, Federal unit agreement expansion, and Federal subsurface gas storage application

Designation of successor operator for all Federal agreements, except for contracted unit agreements that contain no Federal lands.

Geothermal (part 3200):

Noncompetitive lease application

Competitive lease application

Assignment and transfer of record title or operating rights

Name change, corporate merger or transfer to heir/devisee

Lease consolidation

Lease reinstatement

Nomination of lands

plus per acre nomination fee

Site license application

Assignment or transfer of site license

Coal (parts 3400, 3470):

License to mine application

Exploration license application

Lease or lease interest transfer

Leasing of Solid Minerals Other Than Coal and Oil Shale (parts 3500, 3580):

Applications other than those listed below

Prospecting permit application amendment

Extension of prospecting permit

Lease modification or fringe acreage lease

Lease renewal

Assignment, sublease, or transfer of operating rights

Transfer of overriding royalty

Use permit

Shasta and Trinity hardrock mineral lease

Renewal of existing sand and gravel lease in Nevada

Public Law 359; Mining in Powersite Withdrawals: General (part 3730):

Notice of protest of placer mining operations

Mining Law Administration (parts 3800, 3810, 3830, 3860, 3870):

Application to open lands to location

Notice of location *

Amendment of location

Transfer of mining claim/site

Recording an annual FLPMA filing

Deferment of assessment work

Recording a notice of intent to locate mining claims on Stockraising Homestead Act lands

Mineral patent adjudication

Adverse claim

Protest

Oil Shale Management (parts 3900, 3910, 3930):

Exploration license application

Application for assignment or sublease of record title or overriding royalty

Onshore Oil and Gas Operations and Production (parts 3160, 3170):

Application for Permit to Drill

* To record a mining claim or site location, this processing fee along with the initial maintenance fee and the one-time location fee required by statute 43 CFR part 3833 must be paid.

(b) The amount of a fixed fee is not subject to appeal to the Interior Board of Land Appeals pursuant to 43 CFR part 4, subpart E.

2. Revise part 3100 to read as follows:

PART 3100—OIL AND GAS LEASING

Subpart 3100—Oil and Gas Leasing: General

3100.3

Authority.

3100.5

Definitions.

3100.9

Information collection.

3100.10

Helium.

Drainage

3100.21

Compensation for drainage.

3100.22

Drilling and production or payment of compensatory royalty.

Options

3100.31

Enforceability.

3100.32

Effect of option on acreage.

3100.33

Option statements.

3100.40

Public availability of information.

Subpart 3101—Issuance of Leases Lease Terms and Conditions

3101.11

Lease form.

3101.12

Surface use rights.

3101.13

Stipulations and information notices.

3101.14

Modification, waiver, or exception.

Acreage Limitations

3101.21

Public domain lands.

3101.22

Acquired lands.

3101.23

Excepted acreage.

3101.24

Excess acreage.

3101.25

Computation.

3101.30

Leases within unit areas, joinder evidence required.

3101.40

Terminated leases.

Federal Lands Administered by an Agency Other Than the Bureau of Land Management

3101.51

General requirements.

3101.52

Action by the Bureau of Land Management.

3101.53

Appeals.

3101.60

State's or charitable organization's ownership of surface overlying federally owned minerals.

Subpart 3102—Qualifications of Lessees

3102.10

Who may hold leases.

3102.20

Non-U.S. Citizens.

3102.30

Minors.

3102.40

Signature.

Compliance, Certification of Compliance and Evidence

3102.51

Compliance.

3102.52

Certification of compliance.

3102.53

Evidence of compliance.

Subpart 3103—Fees, Rentals, and Royalty

3103.1

Fiscal terms.

Payments

3103.11

Form of remittance.

3103.12

Where remittance is submitted.

Rentals

3103.21

Rental requirements.

3103.22

Annual rental payments.

Royalties

3103.31

Royalty on production.

3103.32

Minimum royalties.

Production Incentives

3103.41

Royalty reductions.

3103.42

Suspension of operations and/or production.

Subpart 3104—Bonds

3104.1

Bond amounts.

3104.10

Bond obligations.

3104.20

Lease bond.

3104.30

Statewide bonds.

3104.40

Surface owner protection bond.

3104.50

Increased amount of bonds.

3104.60

Where filed and number of copies.

3104.70

Default.

3104.80

Termination of period of liability.

3104.90

Unit operator and nationwide bonds held prior to June 22, 2024.

Subpart 3105—Cooperative Conservation Provisions

3105.10

Cooperative or unit agreement.

Communitization Agreements

3105.21

Where filed.

3105.22

Purpose.

3105.23

Requirements.

3105.24

Communitization agreement terms.

Operating, Drilling, or Development Contracts

3105.31

Where filed.

3105.32

Purpose.

3105.33

Requirements.

Subsurface Storage of Oil and Gas

3105.41

Where filed.

3105.42

Purpose.

3105.43

Requirements.

3105.44

Extension of lease term.

3105.50

Consolidation of leases.

Subpart 3106—Transfers by Assignment, Sublease, or Otherwise

3106.10

Transfers, general.

3106.20

Qualifications of assignees and transferees.

3106.30

Fees.

Forms

3106.41

Transfers of record title and of operating rights (subleases).

3106.42

Transfers of other interests, including royalty interests and production payments.

3106.43

Mass transfers.

3106.50

Description of lands.

3106.60

Bond requirements.

Approval of Transfer or Assignment

3106.71

Failure to qualify.

3106.72

Continuing obligation of an assignor or transferor.

3106.73

Lease account status.

3106.74

Effective date of transfer.

3106.75

Effect of transfer.

3106.76

Obligations of assignee or transferee.

Other Types of Transfers

3106.81

Heirs and devisees.

3106.82

Change of name.

3106.83

Corporate mergers and dissolution of corporations, partnerships, and trusts.

3106.84

Sheriff's sale/deed.

Subpart 3107—Continuation and Extension

3107.10

Extension by drilling.

Production

3107.21

Continuation by production.

3107.22

Cessation of production.

3107.23

Leases capable of production.

Extension of Leases Within Agreements

3107.31

Leases committed to an agreement.

3107.32

Segregation of leases committed in part.

3107.40

Extension by elimination.

Extension of Leases Segregated by Assignment

3107.51

Extension after discovery on other segregated portions.

3107.52

Undeveloped parts of leases in their extended term.

3107.53

Undeveloped parts of producing leases.

3107.60

Extension of reinstated leases.

Other Extension Types

3107.71

Payment of compensatory royalty.

3107.72

Subsurface storage of oil and gas.

Subpart 3108—Relinquishment, Termination, Cancellation

3108.10

Relinquishment.

Termination by Operation of Law and Reinstatement

3108.21

Automatic termination.

3108.22

Reinstatement at existing rental and royalty rates: Class I reinstatements.

3108.23

Reinstatement at higher rental and royalty rates: Class II reinstatements.

3108.30

Cancellation.

3108.40

Bona fide purchasers.

3108.50

Waiver or suspension of lease rights.

Subpart 3109—Leasing Under Special Acts Rights-of-Way

3109.11

Generally.

3109.12

Application.

3109.13

Notice.

3109.14

Award of lease or compensatory royalty agreement.

3109.15

Compensatory royalty agreement or lease.

3109.20

Units of the National Park System.

3109.30

Shasta and Trinity Units of the Whiskeytown-Shasta-Trinity National Recreation Area.

Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and 1751; 43 U.S.C. 1701 et seq.; and 42 U.S.C. 15801.

Subpart 3100—Onshore Oil and Gas Leasing: General

§ 3100.3

Authority.

(a)(1) Public domain. Oil and gas in public domain lands and lands returned to the public domain under 43 CFR part 2370 are subject to lease under the Mineral Leasing Act of 1920, as amended and supplemented (30 U.S.C. 181 et seq.), by acts, including, but not limited to, section 1009 of the Alaska National Interest Lands Conservation Act (16 U.S.C. 3148).

(2) Exceptions. The following lands are not subject to lease.

(i) Units of the National Park System, including lands withdrawn by section 206 of the Alaska National Interest Lands Conservation Act, except as provided in paragraph (g)(4) of this section;

(ii) Indian reservations;

(iii) Incorporated cities, towns and villages;

(iv) Naval petroleum and oil shale reserves;

(v) Lands north of 68 degrees north latitude and east of the western boundary of the National Petroleum Reserve—Alaska;

(vi) Lands recommended for wilderness allocation by the surface managing agency;

(vii) Lands within the BLM's wilderness study areas;

(viii) Lands designated by Congress as wilderness study areas, except where oil and gas leasing is specifically allowed to continue by the statute designating the study area;

(ix) Lands within areas allocated for wilderness or further planning in Executive Communication 1504, Ninety-Sixth Congress (House Document numbered 96-119), unless such lands are allocated to uses other than wilderness by a land and resource management plan or have been released to uses other than wilderness by an Act of Congress;

(x) Lands within the National Wilderness Preservation System, subject to valid existing rights under section 4(d)(3) of the Wilderness Act (16 U.S.C. 1133) established before midnight, December 31, 1983, unless otherwise provided by law;

(xi) Subject to valid existing rights, lands within the National Wild and Scenic Rivers System and that constitute the bed or bank or are situated within one-quarter mile of the bank of any river designated as a wild river under the Wild and Scenic Rivers Act (16 U.S.C. 1280), lands within the National Wild and Scenic Rivers System that constitute the bed or bank or are situated within one-quarter mile of the bank of certain rivers designated as scenic or recreational, and in some cases, designating legislation may apply a different boundary extent. Lands within the National Wild and Scenic Rivers System that constitute the bed or bank or are situated within one-half mile of the bank of any river designated a wild river by the Alaska National Interest Lands Conservation Act (16 U.S.C. 3148); and

(xii) Wildlife refuge lands, which are those lands embraced in a withdrawal of lands of the United States for the protection of all species of wildlife within a particular area. Sole and complete jurisdiction over such lands for wildlife conservation purposes is vested in the Fish and Wildlife Service even though such lands may be subject to prior rights for other public purposes or, by the terms of the withdrawal order, may be subject to mineral leasing. No expressions of interest covering wildlife refuge lands will be considered for oil and gas leasing, except as provided by applicable law.

(b)(1) Acquired lands. Oil and gas in acquired lands are subject to lease under the Mineral Leasing Act for Acquired Lands of August 7, 1947, as amended (30 U.S.C. 351 et seq.).

(2) Exceptions. The following lands are not subject to lease.

(i) Units of the National Park System, except as provided in paragraph (g)(4) of this section;

(ii) Incorporated cities, towns and villages;

(iii) Naval petroleum and oil shale reserves;

(iv) Tidelands or submerged coastal lands within the continental shelf adjacent or littoral to lands within the jurisdiction of the United States;

(v) Lands acquired by the United States for development of helium, fissionable material deposits or other minerals essential to the defense of the country, except oil, gas and other minerals subject to leasing under the Act;

(vi) Lands reported as excess under the Federal Property and Administrative Services Act of 1949;

(vii) Lands acquired by the United States by foreclosure or otherwise for resale;

(viii) Lands recommended for wilderness allocation by the surface managing agency;

(ix) Lands within the BLM's wilderness study areas;

(x) Lands designated by Congress as wilderness study areas, except where oil and gas leasing is specifically allowed to continue by the statute designating the study area;

(xi) Lands within areas allocated for wilderness or further planning in Executive Communication 1504, Ninety-Sixth Congress (House Document numbered 96-119), unless such lands are allocated to uses other than wilderness by a land and resource management plan or have been released to uses other than wilderness by an Act of Congress;

(xii) Lands within the National Wilderness Preservation System, subject to valid existing rights under section 4(d)(3) of the Wilderness Act (16 U.S.C. 1133) established before midnight, December 31, 1983, unless otherwise provided by law;

(xiii) Subject to valid existing rights, lands within the National Wild and Scenic Rivers System and that constitute the bed or bank or are situated within one-quarter mile of the bank of any river designated as a wild river under the Wild and Scenic Rivers Act (16 U.S.C. 1280), lands within the National Wild and Scenic Rivers System that constitute the bed or bank or are situated within one-quarter mile of the bank of certain rivers designated as scenic or recreational, and in some cases, designating legislation may apply a different boundary extent. Lands within the National Wild and Scenic Rivers System that constitute the bed or bank or are situated within one-half mile of the bank of any river designated a wild river by the Alaska National Interest Lands Conservation Act (16 U.S.C. 3148); and

(xiv) Wildlife refuge lands, which are those lands embraced in a withdrawal of lands of the United States for the protection of all species of wildlife within a particular area. Sole and complete jurisdiction over such lands for wildlife conservation purposes is vested in the Fish and Wildlife Service even though such lands may be subject to prior rights for other public purposes or, by the terms of the withdrawal order, may be subject to mineral leasing. No expressions of interest for wildlife refuge lands will be considered except as provided in applicable law.

(c) National Petroleum Reserve—Alaska is subject to lease under the Department of the Interior Appropriations Act, Fiscal Year 1981 (42 U.S.C. 6508).

(d) Where oil or gas is being drained from lands otherwise unavailable for leasing, there is implied authority in the agency having jurisdiction of those lands to grant authority to the BLM to lease such lands (see 43 U.S.C. 1457; also Attorney General's Opinion of April 2, 1941 (Vol. 40 Op. Atty. Gen. 41)).

(e) Where lands previously withdrawn or reserved from the public domain are no longer needed by the agency for which the lands were withdrawn or reserved and such lands are retained by the General Services Administration, or where acquired lands are declared as excess to or surplus by the General Services Administration, authority to lease such lands may be transferred to the Department in accordance with the Federal Property and Administrative Services Act of 1949 and the Mineral Leasing Act for Acquired Lands, as amended.

(f) The Act of May 21, 1930 ( 30 U.S.C. 301-306), authorizes the leasing of oil and gas deposits under certain rights-of-way to the owner of the right-of-way or any assignee.

(g)(1) Certain lands in Nevada. The Act of May 9, 1942 (56 Stat. 273), as amended by the Act of October 25, 1949 (63 Stat. 886), authorizes leasing on certain lands in Nevada.

(2) Lands patented to the State of California. The Act of March 3, 1933 (47 Stat. 1487), as amended by the Act of June 5, 1936 (49 Stat. 1482) and the Act of June 29, 1936 (49 Stat. 2026), authorizes leasing on certain lands patented to the State of California.

(3) National Forest Service Lands in Minnesota. The Act of June 30, 1950 (16 U.S.C. 508(b)) authorizes leasing on certain National Forest Service Lands in Minnesota.

(4) Units of the National Park System. The Secretary is authorized to permit mineral leasing in the following units of the National Park System if the Secretary finds that such disposition would not have significant adverse effects on the administration of the area and if lease operations can be conducted in a manner that will preserve the scenic, scientific and historic features contributing to public enjoyment of the area, pursuant to the following authorities:

(i) Lake Mead National Recreation Area —The Act of October 8, 1964 (16 U.S.C. 460n et seq.).

(ii) Whiskeytown Unit of the Whiskeytown-Shasta-Trinity National Recreation Area —The Act of November 8, 1965 (79 Stat. 1295; 16 U.S.C. 460q et seq.).

(iii) Ross Lake and Lake Chelan National Recreation Areas —The Act of October 2, 1968 (82 Stat. 926; 16 U.S.C. 90 et seq.).

(iv) Glen Canyon National Recreation Area —The Act of October 27, 1972 (86 Stat. 1311; 16 U.S.C. 460dd et seq.).

(5) Shasta and Trinity Units of the Whiskeytown-Shasta-Trinity National Recreation Area. Section 6 of the Act of November 8, 1965 (Pub. L. 89-336; 79 Stat. 1295), authorizes the Secretary of the Interior to permit the removal of leasable minerals from lands (or interest in lands) within the recreation area under the jurisdiction of the Secretary of Agriculture in accordance with the Mineral Leasing Act of February 25, 1920, as amended (30 U.S.C. 181 et seq.), or the Acquired Lands Mineral Leasing Act of August 7, 1947 (30 U.S.C. 351 et seq.), if the Secretary finds that such disposition would not have significant adverse effects on the purpose of the Central Valley project or the administration of the recreation area.

(h) Under the Recreation and Public Purposes Act, as amended (43 U.S.C. 869 et seq.), all lands within Recreation and Public Purposes leases and patents are subject to lease under the provisions of this part, subject to such conditions as the Secretary deems appropriate.

(i)(1) Coordination lands are those lands withdrawn or acquired by the United States and made available to the States by cooperative agreements entered into between the Fish and Wildlife Service and the game commissions of the various States, in accordance with the Fish and Wildlife Coordination Act (16 U.S.C. 661), or by long-term leases or agreements between the Department of Agriculture and the game commissions of the various States pursuant to the Bankhead-Jones Farm Tenant Act (50 Stat. 525), as amended, where such lands were subsequently transferred to the Department of the Interior, with the Fish and Wildlife Service as the custodial agency of the United States.

(2) Representatives of the BLM and the Fish and Wildlife Service will, in cooperation with the authorized members of the various State game commissions, confer for the purpose of determining by agreement those coordination lands which will not be subject to oil and gas leasing. Coordination lands not closed to oil and gas leasing may be subject to leasing on the imposition of such stipulations as are agreed upon by the State Game Commission, the Fish and Wildlife Service and the BLM.

(j) No lands within a refuge in Alaska open to leasing will be available until the Fish and Wildlife Service has first completed compatibility determinations.

§ 3100.5

Definitions.

As used in this part, the term:

Actual drilling operations includes not only the physical drilling of a well, but also the testing, completing or equipping of such well for production.

Assignment means a transfer of all or a portion of the lessee's record title interest in a lease.

Bid means an amount of remittance offered as partial compensation for a lease equal to or in excess of the national minimum acceptable bonus bid set by statute or by the Secretary, submitted by a person for a lease parcel in a competitive lease sale. For leases or compensatory royalty agreements issued under 43 CFR subpart 3109, “bid” means an amount or percent of royalty or compensatory royalty that the owner or lessee must pay for the extraction of the oil and gas underlying the right-of-way.

Competitive auction means an in-person or internet-based bidding process where leases are offered to the highest bidder.

Exception means (as used for lease stipulations) a limited exemption, for a particular site within the leasehold, to a stipulation.

Lessee means a person holding record title in a lease issued by the United States.

Modification means (as used for lease stipulations) a change to the provisions of a lease stipulation for some or all sites within the leasehold and either temporarily or for the term of the lease.

National Wildlife Refuge System Lands means lands and water, or interests therein, administered by the Secretary as wildlife refuges, areas for the protection and conservation of fish and wildlife that are threatened with extinction; wildlife management areas; or waterfowl production areas.

Oil and gas agreement means an agreement between lessees and the BLM to govern the development and allocation of production for existing leases and unleased lands, including, but not limited to, communitization agreements, compensatory royalty agreements, unit agreements, secondary recovery agreements, and gas storage agreements.

Operating right (working interest) means the interest created out of a lease authorizing the holder of that right to enter upon the leased lands to conduct drilling and related operations, including production of oil or gas from such lands in accordance with the terms of the lease. Operating rights include the obligation to comply with the terms of the original lease, as it applies to the area or horizons for the interest acquired, including the responsibility to plug and abandon all wells that are no longer capable of producing, reclaim the lease site, and remedy environmental problems.

Operating rights owner means a person holding operating rights in a lease issued by the United States. A lessee also may be an operating rights owner if the operating rights in a lease or portion thereof have not been severed from record title.

Operator means any person, 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.

Primary term of lease subject to section 4(d) of the Act prior to the revision of 1960 (30 U.S.C. 226-1(d)) means all periods of the life of the lease prior to its extension by reason of production of oil and gas in paying quantities; and

Primary term of all other leases means the initial term of the lease, which is 10 years.

Qualified bidder means any person in compliance with the laws and regulations governing a bid.

Qualified lessee means any person in compliance with the laws and regulations governing the BLM issued leases held by that person.

Record title means a lessee's interest in a lease, which includes the obligation to pay rent and the ability to assign and relinquish the lease. Record title includes the obligation to comply with the lease terms, including requirements relating to well operations and abandonment. Overriding royalty and operating rights are severable from record title interests.

Responsible bidder means any person who has not defaulted on the payment of winning bids for BLM-issued oil and gas leases, is capable of fulfilling the requirements of onshore BLM oil and gas leases, and is in compliance with statutes and regulations applicable to oil and gas development or with the terms of a BLM-issued oil and gas lease. The term “responsible bidder” does not include persons who bid with no intention of paying a winning bid or persons who default on a winning bid.

Responsible lessee means any person who has not defaulted on previous winning bids, is capable of fulfilling the requirements of onshore Federal oil and gas leases, and is in compliance with statutes applicable to oil and gas development or the terms of a BLM-issued oil and gas lease.

Sublease means a transfer of a non-record title interest in a lease, i.e., a transfer of operating rights is normally a sublease, and a sublease also is a subsidiary arrangement between the lessee (sublessor) and the sublessee, but a sublease does not include a transfer of a purely financial interest, such as overriding royalty interest or payment out of production, nor does it affect the relationship imposed by a lease between the lessee(s) and the United States.

Transfer means any conveyance of an interest in a lease by assignment, sublease or otherwise. This definition includes the terms: Assignment and Sublease.

Unit operator means the person authorized under the unit agreement approved by the Department of the Interior to conduct operations within the unit.

Waiver means (as used for lease stipulations) a permanent exemption from a lease stipulation.

§ 3100.9

Information collection.

(a) Authority:44 U.S.C. 3501-3520

(b)(1) Purpose. The Paperwork Reduction Act of 1995 generally provides that an agency may not conduct or sponsor, and notwithstanding any other provision of law, a person is not required to respond to a collection of information, unless the collection displays a currently valid Office of Management and Budget (OMB) Control Number. This part displays OMB control numbers assigned to information collection requirements contained in the BLM's regulations at 43 CFR part 3100. This section aids in fulfilling the requirements of the Paperwork Reduction Act to display current OMB Control Numbers for these information collection requirements. Interested persons should consult https://www.reginfo.gov for the most current information on these OMB control numbers; including among other things, the justification for the information collection requirements, description of likely respondents, estimated burdens, and current expiration dates.

(2) Table 1 to Paragraph (b)—OMB control number assigned pursuant to the Paperwork Reduction Act.

43 CFR part or section	OMB control No.
§§ 3100, 3103.41, 3120, and Subpart 3162	1004-0185
§§ 3106, 3135, and 3216	1004-0034
Part 3130	1004-0196
Subpart 3195	1004-0179
§ 3150	1004-0162
§§ 3160,* 3171, 3176, and 3177	1004-0220
§§ 3172, 3173, 3174, 3175	1004-0137
§§ 3162.3-1, 3178.5, 3178.7, 3178.8, 3178.9 and Subpart 3179 *	1004-0211
* Information collection requirements for onshore oil and gas operations are generally accounted for under OMB Control Number 1004-0220; however, information collection requirements pertaining to particular to waste prevention, production subject to royalties, and resource conservation are accounted for under OMB Control Number 1004-0211.

§ 3100.10

Helium.

The ownership of and the right to extract helium from all gas produced from lands leased or otherwise disposed of under the Act have been reserved to the United States.

Drainage

§ 3100.21

Compensation for drainage.

Upon a determination by the authorized officer that lands owned by the United States are being drained of oil or gas by wells drilled on adjacent lands, the authorized officer may execute agreements with the owners of adjacent lands whereby the United States and its lessees will be compensated for such drainage. Such agreements must be made with the consent of any lessee affected by an agreement. Such lands may also be offered for lease in accordance with 43 CFR part 3120.

§ 3100.22

Drilling and production or payment of compensatory royalty.

Where lands in any leases are being drained of their oil or gas content by wells either on a Federal lease issued at a lower rate of royalty or on non-Federal lands, the lessee must both drill and produce all wells necessary to protect the leased lands from drainage. In lieu of drilling necessary wells, the lessee may, with the consent of the authorized officer, pay compensatory royalty in accordance with 43 CFR 3162.2-4.

Options

§ 3100.31

Enforceability.

(a) No option to acquire any interest in a lease is enforceable if entered into for a period of more than 3 years (including any renewal period that may be provided for in the option).

(b) No option or renewal thereof is enforceable until a signed copy or notice of the option has been filed in the proper BLM office. Each such signed copy or notice must include:

(1) The names and addresses of the parties thereto;

(2) The serial number of the lease to which the option is applicable;

(3) A statement of the number of acres and the type and percentage of interests to be conveyed and retained by the parties to the option, including the date and expiration date of the option.

(c) The signatures of all parties to the option or their duly authorized agents. The signed copy or notice of the option required by this paragraph must contain or be accompanied by a signed statement by the holder of the option that entity is the sole party in interest in the option; if not, the entity must set forth the names and provide a description of the interest therein of the other interested parties, and provide a description of the agreement between them, if oral, and a copy of such agreement, if written.

§ 3100.32

Effect of option on acreage.

The acreage to which the option is applicable will be charged both to the grantor of the option and the option holder. The acreage covered by an unexercised option remains charged during its term until notice of its relinquishment or surrender has been filed in the proper BLM office.

§ 3100.33

Option statements.

Each option holder must file in the proper BLM office within 90 days after June 30 and December 31 of each year a statement showing:

(a) Any changes to the statements submitted under § 3100.31(b); and

(b) The number of acres covered by each option and the total acreage of all options held in each State.

§ 3100.40

Public availability of information.

(a) All data and information concerning Federal and Indian minerals submitted under this part 3100 and parts 3120 through 3190 of this chapter are subject to 43 CFR part 2, except as provided in paragraph (c) of this section. 43 CFR part 2 includes the regulations of the Department of the Interior covering the public disclosure of data and information contained in Department of the Interior records. Certain mineral information not protected from public disclosure under 43 CFR part 2 may be made available for inspection without a Freedom of Information Act (FOIA) (5 U.S.C. 552) request.

(b) When you submit data and information under this part 3100 and parts 3120 through 3190 of this chapter that you believe to be exempt from disclosure to the public, you must clearly mark each page that you believe includes confidential information. The BLM will keep all such data and information confidential to the extent allowed by 43 CFR 2.26.

(c) Under the Indian Mineral Development Act of 1982 (IMDA) (25 U.S.C. 2101 et seq.), the Department of the Interior will hold as privileged proprietary information of the affected Indian or Indian Tribe—

(1) All findings forming the basis of the Secretary's intent to approve or disapprove any Minerals Agreement under IMDA; and

(2) All projections, studies, data, or other information concerning a Minerals Agreement under IMDA, regardless of the date received, related to:

(i) The terms, conditions, or financial return to the Indian parties;

(ii) The extent, nature, value, or disposition of the Indian mineral resources; or

(iii) The production, products, or proceeds thereof.

(d) For information concerning Indian minerals not covered by paragraph (c) of this section:

(1) The BLM will withhold such records as may be withheld under an exemption to FOIA when it receives a request for information related to tribal or Indian minerals held in trust or subject to restrictions on alienation;

(2) The BLM will notify the Indian mineral owner(s) identified in the records of the Bureau of Indian Affairs (BIA) and give them a reasonable period of time to state objections to disclosure, using the standards and procedures of 43 CFR 2.28, before making a decision about the applicability of FOIA exemption 4 to:

(i) Information obtained from a person outside the United States Government; when

(ii) Following consultation with a submitter under 43 CFR 2.28, the BLM determines that the submitter does not have an interest in withholding the records that can be protected under FOIA; but

(iii) The BLM has reason to believe that disclosure of the information may result in commercial or financial injury to the Indian mineral owner(s) but is uncertain that such is the case.

Subpart 3101—Issuance of Leases

Lease Terms and Conditions

§ 3101.11

Lease form.

A lease will be issued only on the standard form approved by the Director.

§ 3101.12

Surface use rights.

A lessee will have the right to use only so much of the leased lands as is necessary to explore for, drill for, mine, extract, remove and dispose of all the leased resource in a leasehold subject to applicable requirements, including stipulations attached to the lease, restrictions deriving from nondiscretionary statutes, and such reasonable measures as may be required and detailed by the authorized officer to mitigate adverse impacts to other resource values, land uses or users, federally recognized Tribes, and underserved communities. Such reasonable measures may include, but are not limited to, relocation or modification to siting or design of facilities, timing of operations, specification of interim and final reclamation measures, and specification of rates of development and production in the public interest. At a minimum, modifications that are consistent with lease rights include, but are not limited to, requiring relocation of proposed operations by up to 800 meters and prohibiting new surface disturbing operations for a period of up to 90 days in any lease year.

§ 3101.13

Stipulations and information notices.

(a) The BLM may consider the sensitivity and importance of potentially affected resources and any uncertainty concerning the present or future condition of those resources and will assess whether a resource is adequately protected by stipulation while considering the restrictiveness of the stipulation on operations.

(b) The authorized officer may require stipulations as conditions of lease issuance. Stipulations will become part of the lease and will supersede inconsistent provisions of the standard lease form. Any party submitting a bid under part 3120 will be deemed to have agreed to stipulations applicable to the specific parcel as indicated in the Notice of Competitive Lease Sale available from the proper BLM office.

(c) The BLM may attach an information notice to the lease. An information notice has no legal consequences, except to give notice of existing requirements, and may be attached to a lease by the authorized officer at the time of lease issuance to convey certain operational, procedural or administrative requirements relative to lease management within the terms and conditions of the standard lease form. Information notices may not be a basis for denial of lease operations.

(d) Where the surface managing agency is the Fish and Wildlife Service, leases will be issued subject to stipulations prescribed by the Fish and Wildlife Service as to the time, place, nature and condition of such operations in order to minimize impacts to fish and wildlife populations and habitat and other refuge resources on the areas leased. The specific conduct of lease activities on any refuge lands will be subject to site-specific stipulations prescribed by the Fish and Wildlife Service.

§ 3101.14

Modification, waiver, or exception.

(a) If the authorized officer determines that a change to a lease term or stipulation is substantial or a stipulation involves an issue of major concern to the public, except for changes to stipulations governing time of year restrictions (such as those related to protected species) supported by data showing that the restrictions are unnecessary, the changes will be subject to public review for at least 30 calendar days.

(b) Prior to lease issuance, if the BLM determines that an additional stipulation will be added to the lease or a modification to an existing stipulation is required, the potential lessee must be given an opportunity to accept the additional or modified stipulation. If the potential lessee does not accept the additional or modified stipulation, the BLM may reject the bid, and may include the lands in the next Notice of Competitive Lease Sale. If the change in stipulation(s) increases the value of the parcel, the BLM will reject the bid, and will include the lands in the next Notice of Competitive Lease Sale.

(c) After lease issuance, if a lessee does not accept an additional or modified stipulation, that additional or modified stipulation is not binding on the lessee and is without effect. When a stipulation is required by the relevant Resource Management Plan, or surface management agency land management plan, and was inadvertently omitted, a lessee's failure to sign and accept changes in the stipulations when requested by the authorized officer may subject the lease to cancellation.

(d) A stipulation included in an oil and gas lease will be subject to modification, waiver, or exception if the authorized officer determines, in conjunction with the applicable surface management agency, that the factors leading to its inclusion in the lease have changed sufficiently to make the specific protections provided by the stipulation no longer justified.

Acreage Limitations

§ 3101.21

Public domain lands.

(a) No person may take, hold, own or control more than 246,080 acres of Federal oil and gas leases on public domain lands in any one State at any one time. No more than 200,000 acres of such acres may be held under option.

(b) In Alaska, the acreage that can be taken, held, owned or controlled is limited to 300,000 acres in the northern leasing district and 300,000 acres in the southern leasing district, of which no more than 200,000 acres may be held under option in each of the two leasing districts. The boundary between the two leasing districts in Alaska begins at the northeast corner of the Tetlin National Wildlife Refuge as established by section 302(8) of the Alaska National Interest Lands Conservation Act, at a point on the boundary between the United States and Canada, then northwesterly along the northern boundary of the refuge to the left limit of the Tanana River (63°9′38″ north latitude, 142°20′52″ west longitude), then westerly along the left limit to the confluence of the Tanana and Yukon Rivers, and then along the left limit of the Yukon River from said confluence to its principal southern mouth.

§ 3101.22

Acquired lands.

Separate from, and in addition to, the limitation for public domain lands, no person may take, hold, own or control more than 246,080 acres of Federal oil and gas leases on acquired lands in any one State at any one time. No more than 200,000 acres of such acres may be held under option. Where the United States owns only a fractional interest in the mineral resources of the lands involved in a lease, only that part owned by the United States will be charged as acreage holdings. The acreage embraced in a future interest lease will not be charged as acreage holdings until the lease for the future interest becomes effective.

§ 3101.23

Excepted acreage.

(a) The following acreage will not be included in computing acreage limitations:

(1) Acreage under any lease any portion of which is committed to any federally approved oil and gas agreement;

(2) Acreage under any lease for which royalty (including compensatory royalty or royalty in-kind) was paid in the preceding calendar year; and

(3) Acreage under leases subject to an operating, drilling or development contract approved by the Secretary, as provided in 43 CFR 3105.30.

(b) Acreage subject to offers to lease, overriding royalties and payments out of production will not be included in computing acreage limitations.

§ 3101.24

Excess acreage.

(a) Where, as the result of the termination or contraction of an oil and gas agreement or the elimination of a lease from an operating, drilling, or development contract, a party holds or controls excess accountable acreage, that party will have 90 calendar days from the date of termination, contraction or elimination, to reduce the holdings to the prescribed limitation and to file proof of the reduction in the proper BLM office. Where, as a result of a merger or the purchase of the controlling interest in a corporation, a party acquired acreage in excess of the amount permitted, the party holding the excess acreage will have 180 calendar days from the date of the merger or purchase to divest the excess acreage. If additional time is required to complete the divestiture of the excess acreage, a petition requesting additional time, along with a full justification for the additional time, may be filed with the authorized officer prior to the termination of the 180 days provided herein.

(b) If any person is found to hold accountable acreage in violation of the provisions of these regulations, lease(s) or interests therein will be subject to cancellation or forfeiture in their entirety, until sufficient acreage has been eliminated to comply with the acreage limitation. Excess acreage or interest will be cancelled in the inverse order of acquisition.

§ 3101.25

Computation.

The accountable acreage of a party owning an undivided interest in a lease will be the party's proportionate part of the total lease acreage.

§ 3101.30

Leases within unit areas, joinder evidence required.

Before issuance of a lease for lands within an approved unit, the lease offeror must file evidence with the proper BLM office that it has joined in the unit agreement and unit operating agreement or a statement giving satisfactory reasons for its failure to enter into such agreement. If such statement is satisfactory to the authorized officer, the lessee may be permitted to operate independently but will be required to conform to the terms and provisions of the unit agreement with respect to such operations.

§ 3101.40

Terminated leases.

(a) The authorized officer will not issue a lease for lands which have been covered by a lease which terminated automatically until 90 calendar days after the date of termination.

(b) The authorized officer will not, after the receipt of a petition for reinstatement, issue a new lease affecting any of the lands covered by the terminated lease until all action on the petition is final.

Federal Lands Administered by an Agency Other Than the Bureau of Land Management

§ 3101.51

General requirements.

Public domain and acquired lands will be leased only after seeking concurrence from the surface managing agency, which, upon receipt of a description of the lands from the authorized officer, may report to the authorized officer that it consents to leasing with stipulations, if any, or withholds consent or objects to leasing.

§ 3101.52

Action by the Bureau of Land Management.

(a) Where the surface managing agency has consented to leasing with required stipulations, and the Secretary decides to issue a lease, the authorized officer will incorporate the stipulations into any lease which it may issue. The authorized officer may add other appropriate stipulations.

(b) The authorized officer will not issue a lease on lands to which the surface managing agency objects or withholds consent and for which consent or concurrence is required by law.

(c) The authorized officer will review all recommendations of the surface managing agency and will accept all reasonable recommendations.

(d) Where the surface managing agency is the Fish and Wildlife Service, there will be no drilling or prospecting under any lease heretofore or hereafter issued on lands within a wildlife refuge, except with the consent and approval of the Secretary with the concurrence of the Fish and Wildlife Service as to the time, place and nature of such operations in order to give complete protection to wildlife populations and wildlife habitat on the areas leased, and all such operations must be conducted in accordance with BLM stipulations.

§ 3101.53

Appeals.

(a) The decision of the authorized officer to reject an offer to lease or to issue a lease with stipulations recommended by the surface managing agency may be appealed to the Interior Board of Land Appeals under 43 CFR part 4.

(b) Where, as provided by statute, the surface managing agency has required that certain stipulations be included in a lease or has consented, or objected or refused to consent to leasing, any appeal by an affected lease offeror will be subject to the administrative remedies if provided for by the particular surface managing agency.

§ 3101.60

State's or charitable organization's ownership of surface overlying federally owned minerals.

Where the United States has conveyed title to, or otherwise transferred the control of the surface of lands to any State or political subdivision, agency, or instrumentality thereof, or a college or any other educational corporation or association, or a charitable or religious corporation or association, with reservation of the oil and gas rights to the United States, such party will be given an opportunity to suggest any lease stipulations deemed necessary for the protection of existing surface improvements or uses, to set forth the facts supporting the necessity of the stipulations and also to file any objections it may have to the issuance of a lease. Where a party controlling the surface opposes the issuance of a lease or wishes to place such restrictive stipulations upon the lease that it could not be operated upon or become part of a drilling unit and hence is without mineral value, the facts submitted in support of the opposition or request for restrictive stipulations may be given consideration and each case will be decided on its merits. The opposition to lease or necessity for restrictive stipulations expressed by the party controlling the surface affords no legal basis or authority to refuse to issue the lease or to issue the lease with the requested restrictive stipulations for the reserved minerals in the lands; in such case, the final determination whether to issue and with what stipulations, or not to issue the lease depends upon whether or not the interests of the United States would best be served by the issuance of the lease.

Subpart 3102—Qualifications of Lessees

§ 3102.10

Who may hold leases.

Leases or interests therein may be acquired and held only by citizens of the United States; associations (including partnerships and trusts) of such citizens; corporations organized under the laws of the United States or of any State or Territory thereof; and municipalities.

§ 3102.20

Non-U.S. Citizens.

(a) Leases or interests therein may be acquired and held by non-U.S. Citizens only through stock ownership, holding or control in a present or potential lessee that is incorporated under the laws of the United States or of any State or territory thereof, and only if the laws, customs or regulations of their country do not deny similar or like privileges to citizens or corporations of the United States. If it is determined that a country has denied similar or like privileges to citizens or corporations of the United States, it would be placed on a list available from any BLM State office.

(b) The Committee on Foreign Investment in the United States is authorized to review covered real estate transactions and to mitigate any risk to the national security of the United States that arises as a result of such transactions. Covered real estate transactions may include certain transactions involving the Federal mineral estate (see 31 CFR part 802).

§ 3102.30

Minors.

Leases must not be acquired or held by someone considered to be a minor under the laws of the State in which the lands are located, but leases may be acquired and held by legal guardians or trustees of minors on their behalf. Such legal guardians or trustees must be citizens of the United States or otherwise meet the provisions of 43 CFR 3102.10.

§ 3102.40

Signature.

Signatures on all applications and BLM forms certify acceptance of lease terms and stipulations, as well as compliance with the regulations under 43 CFR part 3100. Refer to § 3102.50 for certification of compliance and evidence. The BLM also accepts electronic signatures and submissions.

(a) A bid to lease must be made on a current form approved by the Director. Copies must be exact reproductions of the official approved form, without additions, omissions, or other changes. When the bid is filed in person at the proper BLM office, the bid must be typed or printed plainly, signed, and dated by the offeror or an authorized agent on behalf of the present or potential lessee. Bids may be made to the BLM by other arrangements, such as electronically signed and filed, when specifically authorized by the BLM.

(b) Documents signed by any party other than the present or potential lessee must be rendered in a manner to reveal the name of the present or potential lessee, the name of the signatory and their relationship. A signatory who is a member of the organization that constitutes the present or potential lessee ( e.g., officer of a corporation, partner of a partnership, etc.) may be requested by the authorized officer to clarify his/her relationship, when the relationship is not shown on the documents filed.

Compliance, Certification of Compliance and Evidence

§ 3102.51

Compliance.

Only responsible and qualified bidders and lessees may own, hold, or control an interest in a lease or prospective lease. Responsible and qualified bidders and lessees, including corporations, and all members of associations, including partnerships of all types, will, without exception, be qualified and in compliance with the Act. Compliance means that the persons are:

(a) Citizens of the United States (see § 3102.10) or non-U.S. citizens who own stock in a corporation organized under State or Federal law (see § 3102.20);

(b) In compliance with the Federal acreage limitations (see § 3101.20);

(c) Not minors (see § 3102.30);

(d) Except for an assignment or transfer under 43 CFR subpart 3106, in compliance with section 2(a)(2)(A) of the Act (30 U.S.C. 201(2)(A)), in which case the signature on a bid or lease constitutes evidence of compliance. A lease issued to any person in violation of this paragraph (d) will be subject to the cancellation provisions of 43 CFR 3108.30.

(e) Not in violation of the provisions of section 41 of the Act (30 U.S.C. 195); and

(f) In compliance with section 17(g) of the Act (30 U.S.C. 226(g)), in which case the signature on an offer, lease, assignment, or transfer constitutes evidence of compliance that the signatory and any subsidiary, affiliate, or person, association, or corporation controlled by or under common control with the signatory, as defined in 43 CFR 3400.0-5(rr), has not failed or refused to comply with reclamation requirements with respect to all leases and operations thereon in which such person has an interest. A person is noncompliant with section 17(g) of the Act when they fail to comply with their reclamation obligations or other standards established under 30 U.S.C. 226 in the time specified in a notice from the BLM. A lease issued, or an assignment or transfer approved, to any such person in violation of this paragraph (f) may be subject to the cancellation provisions of 43 CFR 3108.30, notwithstanding any administrative or judicial appeals that may be pending with respect to violations or penalties assessed for failure to comply with the prescribed reclamation standards on any lease holdings. Noncompliance will end upon a determination by the authorized officer that all required reclamation has been completed and that the United States has been fully reimbursed for any costs incurred due to the required reclamation.

(g) In compliance with 43 CFR 3106.10(d) and section 30A of the Act (30 U.S.C. 187(a)). The authorized officer may accept the signature on a request for approval of an assignment of less than 640 acres outside of Alaska (2,560 acres within Alaska) as acceptable certification that the assignment would further the development of oil and gas, or the authorized officer may apply the provisions of 43 CFR 3102.53.

(h) Not excluded or disqualified from participating in a transaction covered by Federal non-procurement debarment and suspension (2 CFR parts 180 and 1400), unless the Department explicitly approves an exception for a transaction pursuant to the regulations in those parts.

§ 3102.52

Certification of compliance.

Any party(s) seeking to obtain an interest in a lease must certify that it is in compliance with the Act as set forth in 43 CFR 3102.51. A corporation or publicly traded association, including a publicly traded partnership, must certify that constituent members of the corporation, association or partnership holding or controlling more than 10 percent of the instruments of ownership of the corporation, association or partnership are in compliance with the Act. Execution and submission of a competitive bid form or request for approval of a transfer of record title or of operating rights (sublease), constitutes certification of compliance.

§ 3102.53

Evidence of compliance.

The authorized officer may request at any time further evidence of compliance and qualification from any party holding or seeking to hold an interest in a lease. Failure to comply with the request of the authorized officer will result in adjudication of the action based on the incomplete submission.

Subpart 3103—Fees, Rentals and Royalty

§ 3103.1

Fiscal terms.

(a) The table in this section shows the fiscal terms, that the BLM will adjust every 4 years by a final rule. The BLM will adjust the amounts according to the change in the Implicit Price Deflator for Gross Domestic Product since the previous adjustment. The fiscal terms displayed below are effective on June 22, 2024. Per the Inflation Reduction Act, the BLM will not adjust the rental nor the minimum bonus bids until after August 16, 2032.

Table 1 to Paragraph ( a )—Fiscal Terms Table

Oil and gas (parts 3100, 3110, 3120, 3130, 3140):	Fiscal term
Competitive oil and gas, tar sand, and combined hydrocarbon leases	Rental of $3 per acre, or fraction thereof, per year during the first 2-year period beginning upon lease issuance, $5 per acre per year, or fraction thereof, for the following 6 years, and then $15 per acre, or fraction thereof, per year thereafter.
Competitive lease reinstatement, Class II	Rental of $20 per acre, or fraction thereof.
Competitive combined hydrocarbon leases	Minimum bonus bids of $25 per acre, or fraction thereof.
Competitive oil and gas and tar sand leases	Minimum bonus bids of $10 per acre, or fraction thereof.
Expression of interest filing fee	$5 per acre.

(b) The amounts in the fiscal terms table are not subject to appeal to the Interior Board of Land Appeals pursuant to 43 CFR part 4, subpart E.

Payments

§ 3103.11

Form of remittance.

All remittances must be by personal check, cashier's check, certified check, or money order, and must be made payable to the Department of the Interior—Bureau of Land Management or the Department of the Interior—Office of Natural Resources Revenue, as appropriate. Payments made to the BLM may be made by other arrangements such as by electronic funds transfer or credit card when specifically authorized by the BLM. In the case of payments made to the ONRR, such payments may also be made by electronic funds transfer.

§ 3103.12

Where remittance is submitted.

(a)(1) All processing fees for the respective lease applications, nominations, or requests for approval of a transfer found in the fee schedule in § 3000.120 of this chapter and all first-year rentals and bonuses for leases issued under 43 CFR part 3100 must be paid to the proper BLM office.

(2) All second year and subsequent rentals, except for leases specified in paragraph (b) of this section, must be paid to the ONRR, refer to 30 CFR 1218.51.

(b) All rentals and royalties on producing leases, communitized leases in producing spacing units, unitized leases in producing unit areas, leases on which compensatory royalty is payable and all payments under subsurface storage agreements must be paid to the ONRR.

Rentals

§ 3103.21

Rental requirements.

(a) Each competitive bid submitted in response to a Notice of Competitive Lease Sale must be accompanied by full payment of the first year's rental based on the total acreage for that lease in the Notice of Competitive Lease Sale.

(b) If the acreage is incorrectly indicated in a Notice of Competitive Lease Sale, payment of the rental based on the error is curable within 15 calendar days of receipt of notice from the authorized officer of the error.

(c) Rental will not be prorated for any lands in which the United States owns an undivided fractional interest and must be paid for the full acreage in such lands.

§ 3103.22

Annual rental payments.

Rentals must be paid on or before the lease anniversary date. A full year's rental must be submitted even when less than a full year remains in the lease term, except as provided in 43 CFR 3103.42(d). Failure to make the required payment on or before the lease anniversary date will cause a lease to terminate automatically by operation of law. If the designated ONRR office is not open on the anniversary date, payment received on the next day the designated ONRR office is open to the public will be deemed to be timely made. Payments made to an improper BLM or ONRR office will be returned and will not be forwarded to the designated ONRR office. Rental must be paid at the following rates:

(a) The annual rental for all leases is as stated in the lease, and the annual rental for all new leases will be as specified in 43 CFR 3103.1;

(b) Rental will not be due on acreage for which royalty or minimum royalty is being paid, except on nonproducing leases when compensatory royalty has been assessed in which case annual rental as established in the lease will be due in addition to compensatory royalty;

(c) For leases that are reinstated under § 3108.23, the annual rental will be as specified in 43 CFR 3103.1 beginning with the termination date upon the filing of a petition to reinstate a lease; and

(d) Each succeeding time a specific lease is reinstated under § 3108.23, the annual rental on that lease will increase by an additional $10 per acre or fraction thereof.

Royalties

§ 3103.31

Royalty on production.

(a) Royalty on production will be payable only on the mineral interest owned by the United States. Royalty must be paid in the amount or value of the production removed or sold as follows:

(1) For leases issued before August 16, 2022, the rate prescribed in the lease or in applicable regulations at the time of lease issuance;

(2) For leases issued between August 16, 2022, and August 16, 2032, the royalty rate will be 16.67 percent;

(3) For leases issued on or after August 16, 2032, a rate of not less than 16.67 percent on all leases issued under the Act;

(4) A minimum of 16.67 percent on all leases issued under 43 CFR subpart 3109;

(5) For reinstated leases, the rate used for royalty determination that applies to new leases at the time of the reinstatement plus 4 percentage points, plus an additional 2 percentage points for each succeeding reinstatement. In no case will royalties on the reinstated lease be less than 20 percent.

(b) Leases that qualify under specific provisions of the Act of August 8, 1946 (30 U.S.C. 226c) may apply for a limitation of a 12 1/2 percent royalty rate.

(c) The average production per well per day for oil and gas will be determined pursuant to 43 CFR 3162.7-4.

(d) Payment of a royalty on the helium component of gas will not convey the right to extract the helium from the gas stream. Applications for the right to extract helium from the gas stream will be made under 43 CFR part 16.

§ 3103.32

Minimum royalties.

(a) A minimum royalty must be paid at the expiration of each lease year beginning on or after a discovery of oil or gas in paying quantities on the lands leased, except on unitized leases that lack production, the minimum royalty must be paid only on the participating acreage, at the following rates:

(1) On leases issued on or after August 8, 1946, and on those issued prior thereto if the lessee files an election under section 15 of the Act of August 8, 1946, a minimum royalty of $1 per acre or fraction thereof in lieu of rental, except as provided in paragraph (a)(2) of this section; and

(2) On leases issued from offers filed after December 22, 1987, and on competitive leases issued after December 22, 1987, a minimum royalty in lieu of rental of not less than the amount of rental which otherwise would be required for that lease year.

(b) Minimum royalties will not be prorated for any lands in which the United States owns a fractional interest and must be paid on the full acreage of the lease.

(c) Minimum royalties and rentals on non-participating acreage must be paid to the ONRR.

(d) The minimum royalty provisions of this section are applicable to leases reinstated under 43 CFR 3108.23.

(e) If the royalty paid during any year aggregates to less than the minimum royalty, then the lessee must pay the difference at the end of the lease year.

Production Incentives

§ 3103.41

Royalty reductions.

(a) In order to encourage the greatest ultimate recovery of oil or gas and in the interest of conservation, the Secretary, upon a determination that it is necessary to promote development or that the leases cannot be produced in paying quantities under the terms provided therein, may waive, suspend or reduce the rental or minimum royalty or reduce the royalty on an entire leasehold, or any portion thereof.

(b)(1) An application for the benefits under paragraph (a) of this section must be filed by the operator/payor in the proper BLM office. The application must contain the serial number of the leases, the names of the record title holders, operating rights owners (sublessees), and operators for each lease, the description of lands by legal subdivision and a description of the relief requested.

(2) Each application must show the number, location and status of each well drilled, a tabulated statement for each month covering a period of not less than 6 months prior to the date of filing the application of the aggregate amount of oil or gas subject to royalty, the number of wells counted as producing each month and the average production per well per day.

(3) Every application must contain a detailed statement of expenses and costs of operating the entire lease, the income from the sale of any production and all facts tending to show whether the wells can be produced in paying quantities upon the fixed royalty or rental. Where the application is for a reduction in royalty, complete information must be furnished as to whether overriding royalties, payments out of production, or similar interests are paid to others than the United States, the amounts so paid and efforts made to reduce them. The applicant must also file agreements of the holders to a reduction of all other royalties or similar payments from the leasehold to an aggregate not in excess of one-half the royalties due the United States.

(c) Petition may be made for a reduction of royalty for leases reinstated under 43 CFR 3108.23. Petitions to waive, suspend or reduce rental or minimum royalty for leases reinstated under 43 CFR 3108.23 may be made under this section.

§ 3103.42

Suspension of operations and/or production.

(a) A suspension of all operations and production may be directed or consented to by the authorized officer only in the interest of conservation of natural resources. A suspension of operations only or a suspension of production only may be directed or consented to by the authorized officer in cases where the lessee is prevented from operating on the lease or producing from the lease, despite the exercise of due care and diligence, by reason of force majeure, that is, by matters beyond the reasonable control of the lessee. Applications for any suspension must be filed in the proper BLM office. Complete information showing the necessity of such relief must be furnished.

(b) The term of any lease will be adjusted to account for the suspension. Beginning on the date the suspension is lifted, the term will be extended by the time that was remaining on the term of the lease on the effective date of the suspension. No lease will expire during any suspension.

(c) A suspension will take effect as of the time specified in the direction or assent of the authorized officer, in accordance with the provisions of 43 CFR 3165.1.

(d) Rental and minimum royalty payments will be suspended during any period of suspension of all operations and production directed or assented to by the authorized officer beginning with the first day of the lease month in which the suspension of all operations and production becomes effective, or if the suspension of all operations and production becomes effective on any date other than the first day of a lease month, beginning with the first day of the lease month following such effective date. However, if there is any production sold or removed during the suspension, the lessee must pay royalty on that production.

(e) Rental and minimum royalty payments will resume on the first day of the lease month in which the suspension of all operations and production is lifted. Where rentals are creditable against royalties and have been paid in advance, proper credit may be allowed on the next rental or royalty due under the terms of the lease.

(f) Rental and minimum royalty payments will not be suspended during any period of suspension of operations only or suspension of production only.

(g) Where all operations and production are suspended on a lease on which there is a well capable of producing in paying quantities and the authorized officer approves resumption of operations and production, such resumption will be regarded as lifting the suspension, including the suspension of rental and minimum royalty payments, as provided in paragraph (e) of this section.

(h) The relief authorized under this section also may be obtained for any Federal lease included within an approved oil and gas agreement. Oil and gas agreement obligations will not be suspended by relief obtained under this section but will be suspended only in accordance with the terms and conditions of the specific agreement.

Subpart 3104—Bonds

§ 3104.1

Bond amounts.

(a) The table in this section shows the minimum bond amounts, that the BLM will adjust every 10 years by a final rule. The BLM will adjust the amounts according to the change in the Implicit Price Deflator for Gross Domestic Product since the previous adjustment. The minimum bond amounts displayed below are effective on June 22, 2024.

Table 1 to Paragraph ( a )—Minimum Bond Amount Table

Oil and gas (parts 3100, 3110, 3120, 3130, 3140):	Minimum bond amount
Lease Bond	$150,000
Statewide Bond	500,000

(b) The Minimum Bond Amount are not subject to appeal to the Interior Board of Land Appeals pursuant to 43 CFR part 4, subpart E.

(c) Principals must increase or replace all bonds not meeting the appropriate minimum bond amount in paragraph (a) by:

(1) June 22, 2026, for statewide; and

(2) June 22, 2027, for lease bonds.

(d) Failure to increase or replace an existing bond that does not meet the minimum bond amount may:

(1) Subject all wells covered by the bond(s) to shut down under the provisions of 43 CFR 3163.1(a)(3);

(2) Subject all leases covered by the bond(s) to cancellation under the provisions of 43 CFR 3108.30; and

(3) Result in the BLM referring the bond obligor or principal to the Department's Suspension and Debarment Program under 2 CFR part 1400 to determine if the person will be suspended or debarred from doing business with the Federal Government.

§ 3104.10

Bond obligations.

(a) Prior to the commencement of surface disturbing activities related to drilling operations, the lessee, operating rights owner (sublessee), or operator must submit a surety or a personal bond, conditioned upon compliance with all of the terms and conditions of the entire leasehold(s) covered by the bond, as described in this subpart. The bond amounts must be not less than the minimum amounts described in this subpart in order to ensure compliance with the Act, including complete and timely plugging of the well(s), reclamation of the lease area(s), and the restoration of any lands or surface waters adversely affected by lease operations after the abandonment or cessation of oil and gas operations on the lease(s) in accordance with, but not limited to, the standards and requirements set forth in 43 CFR 3162.3 and 3162.5 and orders issued by the authorized officer.

(b) Surety bonds must be issued by qualified surety companies approved by the Department of the Treasury (see Department of the Treasury Circular No. 570).

(c) Personal bonds must be accompanied by a:

(1) Certificate of deposit issued by a financial institution, the deposits of which are federally insured, explicitly granting the Secretary full authority to demand immediate payment in case of default in the performance of the terms and conditions of the lease. The certificate will explicitly indicate on its face, or through assignment, that Secretarial approval is required prior to redemption of the certificate of deposit by any party;

(2) Cashier's check;

(3) Certified check; or

(4) Negotiable Treasury securities of the United States of a value equal to the amount specified in the bond. Negotiable Treasury securities must be accompanied by a proper conveyance to the Secretary of full authority to sell such securities in case of default in the performance of the terms and conditions of a lease.

(5) Irrevocable letter of credit issued by a financial institution, for a specific term, identifying the secretary as sole payee with full authority to demand immediate payment in the case of default in the performance of the terms and conditions of a lease. Letters of credit must be subject to the following conditions:

(i) The letter of credit must be issued only by a financial institution organized or authorized to do business in the United States;

(ii) The letter of credit must be irrevocable during its term. A letter of credit used as security for any lease upon which drilling has taken place and final approval of all abandonment has not been given, or as security for an individual lease or statewide bond, will be forfeited and will be collected by the authorized officer if not replaced by other suitable bond or letter of credit at least 30 days before its expiration date;

(iii) The letter of credit must be payable to the Bureau of Land Management upon demand, in part or in full, upon receipt from the authorized officer of a notice of collection stating the basis therefore, e.g., default in compliance with the lease terms and conditions or failure to file a replacement in accordance with paragraph (c)(5)(ii) of this section;

(iv) The initial expiration date of the letter of credit must be at least 1 year following the date it is filed in the proper BLM office; and

(v) The letter of credit must contain a provision for automatic renewal for periods of not less than 1 year in the absence of notice to the proper BLM office at least 90 days prior to the originally stated or any extended expiration date. In the event the BLM is notified of the financial institution's intent not to renew the letter of credit, the principal must extend the letter of credit or provide an adequate replacement bond with an assumption of liability rider. If the BLM does not receive an adequate notice or replacement bond with rider, the BLM will collect the letter of credit within 30 days of the expiration without further notification to the obligor.

§ 3104.20

Lease bond.

The operator, a lessee, or an owner of operating rights (sublessee) must be covered by a bond in its own name as principal or obligor in an amount of not less than the amount specified in 43 CFR 3104.1 for each lease conditioned upon compliance with all of the terms of the lease. Where two or more lease interest holders have interests in different formations or portions of the lease, separate bonds may be posted. The operator shall be covered by a bond in his/her own name as principal, or a bond in the name of the lessee or sublessee, provided that a consent of the surety, or the obligor in the case of a personal bond, to include the operator under the coverage of the bond is furnished to the BLM office maintaining the bond.

§ 3104.30

Statewide bonds.

In lieu of lease bonds, lessees, owners of operating rights (sublessees), or operators may furnish a bond in an amount of not less than the amount specified in 43 CFR 3104.1 covering all leases and operations in any one State.

§ 3104.40

Surface owner protection bond.

(a) If a good-faith effort by the Federal lessee, its operator, or representatives has not resulted in an agreement with the surface owner under 43 CFR 3171.19, the authorized officer will require an adequate surface owner protection bond in an amount sufficient to indemnify the surface owner against the reasonable and foreseeable damages to crops and tangible improvements from the proposed operations that would not otherwise be covered by a bond held by the BLM. This surface owner protection bond is not part of the bond obligations under lease or statewide bonds.

(b) The surface owner protection bond must be provided on a BLM-approved form.

(c) The surface owner protection bond may be a personal or surety bond and must be not less than $1,000.

(d) The BLM will notify the surface owner of the proposed surface owner protection bond amount.

(e) If the surface owner objects to the sufficiency of the surface owner protection bond, the BLM authorized officer will determine the sufficiency of the bond necessary to indemnify the surface owner for the reasonable and foreseeable damages to crops and tangible improvements.

§ 3104.50

Increased amount of bonds.

(a) When an operator desiring approval of an APD has caused the BLM, or a surface management agency, to make a demand for payment under a bond or other financial guarantee within the 5-year period prior to submission of the APD, due to failure to plug a well or reclaim lands completely in a timely manner, the authorized officer will require, prior to approval of the APD, a bond in an amount equal to the costs, when higher than the minimum bond amounts, as estimated by the authorized officer of plugging the well and reclaiming the disturbed area involved in the proposed operation, or in the minimum amount as prescribed in this subpart, whichever is greater.

(b) The authorized officer may require an increase in the amount of any bond whenever it is determined that the operator poses a risk due to factors, including, but not limited to, a history of previous violations, a notice from the ONRR that there are uncollected royalties due, or the total cost of plugging existing wells and reclaiming lands exceeds the present bond amount based on the estimates determined by the authorized officer. The increase in bond amount may be to any level specified by the authorized officer, but in no circumstances will it exceed the total of the estimated costs of plugging and reclamation, the amount of uncollected royalties due to the ONRR, plus the amount of money owed to the lessor due to previous violations remaining outstanding.

§ 3104.60

Where filed and number of copies.

All bonds must be filed in the proper BLM office on a current form approved by the Director. A single copy executed by the principal or, in the case of surety bonds, by both the principal and an acceptable surety is sufficient. A bond filed on a form not currently in use will be acceptable, unless such form has been declared obsolete by the Director prior to the filing of such bond. For purposes of 43 CFR 3104.20 and 3104.30, bonds or bond riders must be filed in the BLM State office having jurisdiction over the lease or operations covered by the bond or rider.

§ 3104.70

Default.

(a) Where, upon a default, the surety makes a payment to the United States of an obligation incurred under a lease, the face amount of the surety bond or personal bonds and the surety's liability thereunder will be reduced by the amount of such payment.

(b) After default, where the obligation in default equals or is less than the face amount of the bond(s), the principal must either post a new bond or restore the existing bond(s) to the amount previously held or a larger amount as determined by the authorized officer. In lieu thereof, the principal may file separate bonds for each lease covered by the deficient bond(s). Where the obligation incurred exceeds the face amount of the bond(s), the principal must make full payment to the United States for all obligations incurred that are in excess of the face amount of the bond(s) and must post a new bond in the amount previously held or such larger amount as determined by the authorized officer. The restoration of a bond or posting of a new bond must be made within 6 months or less after receipt of notice from the authorized officer. Failure to comply with these requirements may:

(1) Subject all leases covered by such bond(s) to cancellation under the provisions of 43 CFR 3108.30; and

(2) Result in the bond obligor or principal being referred to the Department's Suspension and Debarment Program under 2 CFR part 1400 to determine if the person will be suspended or debarred from doing business with the Federal Government.

§ 3104.80

Termination of period of liability.

The authorized officer will not give consent to termination of the period of liability of any bond unless an acceptable replacement bond has been filed or until all the terms and conditions of the lease have been met.

§ 3104.90

Unit Operator and nationwide bonds held prior to June 22, 2024.

Unit operator and nationwide bonds accepted by the BLM prior to June 22, 2024, must be replaced with individual lease or statewide bonds by June 22, 2025. The BLM will not accept any new unit operator or nationwide bonds.

Subpart 3105—Cooperative Conservation Provisions

§ 3105.10

Cooperative or unit agreement.

(a) The suggested contents of such an agreement and the procedures for obtaining approval are contained in 43 CFR part 3180.

(b) An application to form a unit agreement, a unit expansion, or a designation of a successor operator must include the processing fee found in the fee schedule in § 3000.120 of this chapter.

Communitization Agreements

§ 3105.21

Where filed.

(a) An application to form a communitization agreement or modify an existing agreement must be filed with the proper BLM office for final approval.

(b) An application for a communitization agreement must include:

(1) A statement as to whether the proposed communitization agreement deviates from the BLM's current model communitization agreement form, and a certification that the applicant received the required signatures;

(2) An Exhibit A displaying a map of the area covered by the proposed agreement and the separate agreement tracts; and

(3) An Exhibit B displaying the separate tracts and ownership;

(c) To ensure accurate reporting to ONRR, an application for a communitization agreement should be submitted at least 90 calendar days prior to first production.

(d) An application for designations of successor operator for a communitization agreement must include the processing fee found in the fee schedule in § 3000.120 of this chapter.

§ 3105.22

Purpose.

When a lease or a portion thereof cannot be independently developed and operated in conformity with an established well-spacing or well-development program, the authorized officer may approve a communitization agreement for such lands with other lands, whether or not owned by the United States, upon a determination that it is in the public interest. Operations or production under such an agreement will be deemed to be operations or production as to each lease committed thereto.

§ 3105.23

Requirements.

(a) The communitization agreement must describe the separate tracts comprising the drilling or spacing unit, must show the apportionment of the production or royalties to the several parties, the name of the operator, and contain adequate provisions for the protection of the interests of the United States. The agreement must be signed by or on behalf of all necessary parties and must be filed prior to the expiration of the Federal lease(s) involved in order to confer the benefits of the agreement upon such lease(s).

(b) The agreement will be effective as to the Federal lease(s) involved only if approved by the authorized officer. Approved communitization agreement are considered effective from the date of the agreement or from the date of the onset of production from the communitized formation, whichever is earlier, except when the spacing unit is subject to a State pooling order after the date of first sale, then the effective date of the agreement will be the effective date of the order.

(c) The public interest requirement for an approved communitization agreement will be satisfied only if the well dedicated thereto has been completed for production in the communitized formation at the time the agreement is approved or, if not, that the operator thereafter commences and/or diligently continues drilling operations to a depth sufficient to test the communitized formation or establishes to the satisfaction of the authorized officer that further drilling of the well would be unwarranted or impracticable. If an application is received for voluntary termination of a communitization agreement during its fixed term or such an agreement automatically expires at the end of its fixed term without the public interest requirement having been satisfied, the approval of that agreement by the authorized officer will be invalid and no Federal lease included in the communitization agreement will be eligible for an extension under 43 CFR 3107.40.

§ 3105.24

Communitization agreement terms.

The communitization agreement will remain in effect for a period of 2 years from the effective date or approval date, whichever is later, and so long thereafter as communitized substances may be produced in paying quantities, or as otherwise specified in the agreement.

Operating, Drilling, or Development Contracts

§ 3105.31

Where filed.

A contract submitted for approval under this section must be filed with the proper BLM office.

§ 3105.32

Purpose.

Approval of operating, drilling or development contracts will be granted only to permit operators or pipeline companies to enter into contracts with a number of lessees sufficient to justify operations on a scale large enough to justify the discovery, development, production or transportation of oil or gas and to finance the same.

§ 3105.33

Requirements.

The contract must be accompanied by a statement showing all the interests held by the contractor in the area or field and the proposed or agreed plan for development and operation of the field. All the contracts held by the same contractor in the area or field must be submitted for approval at the same time and full disclosure of the projects made.

Subsurface Storage of Oil and Gas

§ 3105.41

Where filed.

(a) Applications for subsurface storage or designations of successor operator must be filed in the proper BLM office.

(b) The final gas storage agreement signed by all the parties in interest must be submitted to the BLM.

(c) Applications for subsurface storage agreements or designations of successor operator must include the processing fee found in the fee schedule in § 3000.120 of this chapter.

§ 3105.42

Purpose.

To avoid waste and to promote conservation of natural resources, the Secretary, upon application by the interested parties, may authorize the subsurface storage of oil and gas, whether or not produced from lands owned by the United States. Such authorization will provide for the payment of such storage fee or rental on the stored oil or gas as may be determined adequate in each case, or, in lieu thereof, for a royalty other than that prescribed in the lease when such stored oil or gas is produced in conjunction with oil or gas not previously produced. The BLM will require a bond as provided under § 3104 for operations conducted in a subsurface storage agreement.

§ 3105.43

Requirements.

The agreement must disclose the ownership of the lands involved, the parties in interest, the storage fee, rental or royalty offered to be paid for such storage and all information demonstrating such storage would avoid waste and promote the conservation of natural resources.

§ 3105.44

Extension of lease term.

Any lease used for the storage of oil or gas will be extended for the period of storage under an approved agreement. The obligation to pay annual lease rent continues during the extended period.

§ 3105.50

Consolidation of leases.

(a) Leases may be consolidated upon written request of the lessee filed with the proper BLM office. The request must identify each lease involved by serial number and justify the consolidation. Each request for a consolidation of leases must include the processing fee found in the fee schedule in § 3000.120 of this chapter.

(b) All parties holding any undivided interest in any lease involved in the consolidation must agree to enter into the same lease consolidation.

(c) Leases containing different types of lands (public domain lands vs. acquired lands), mixed fractional mineral interest, or provisions required by law that cannot be reconciled, will not be consolidated.

(d) Consolidation of leases will not exceed acreage limits of 2,560 acres for competitive leases and 10,240 acres for noncompetitive leases.

(e) The effective date, the anniversary date, and the primary term of the consolidated lease will be those of the oldest original lease included in the consolidation. The term of a consolidated lease may be extended beyond the primary lease term under subpart 3107.

(f) The highest royalty and rental rates of the each of the leases to be consolidated will apply to the consolidated lease.

(g) Lease stipulations and other terms and conditions of each original lease, except as noted in paragraphs (e) and (f) of this section, will continue to apply to that lease or any portion thereof regardless of the lease becoming a part of a consolidated lease.

Subpart 3106—Transfers by Assignment, Sublease, or Otherwise

§ 3106.10

Transfers, general.

(a) Leases may be transferred by assignment or sublease as to all or part of the acreage in the lease or as to either a divided or undivided interest therein.

(b) An assignment of the record title conveys both record title and operating rights, unless operating rights have been severed from the record title through an approved transfer of operating rights. Thereafter, the operating rights and record title may each be subject to further transfers.

(c) An assignment of a separate zone, deposit, depth, formation, specific well, or of part of a legal subdivision, will be denied.

(d) Within the boundaries of a Federal lease, operating rights may only be divided with respect to legal subdivisions, depth ranges, and formations.

(e) An assignment of less than 640 acres outside Alaska or of less than 2,560 acres within Alaska will be denied unless the assignment constitutes the entire lease or is demonstrated to further the development of oil and gas to the satisfaction of the authorized officer. Reference 43 CFR 3102.51(g) for certification of compliance.

(f) The rights of the transferee to a lease or an interest therein will not be recognized by the Department until the transfer has been approved by the authorized officer.

(g) A transfer may be withdrawn in writing, signed by the transferor and the transferee, if the transfer has not been approved by the authorized officer.

(h) A request for approval of a transfer of a lease or interest in a lease must be filed within 90 days from the date of its execution. The 90-day filing period will begin on the date the transferor signs and dates the transfer. If the transfer is filed after the 90th day, the authorized officer may require verification that the transfer is still in force and effect.

(i) A transfer of production payments or overriding royalty or other similar payments, arrangements, or interests must be filed in the proper BLM office but will not require approval.

(j) No transfer of an offer to lease or interest in a lease will be approved prior to the issuance of the lease.

§ 3106.20

Qualifications of assignees and transferees.

Assignees and transferees must comply with the provisions of 43 CFR subpart 3102 and post any bond that may be required. Only responsible and qualified lessees may own, hold, or control an interest in a lease.

§ 3106.30

Fees.

(a) Each transfer of record title or of operating rights (sublease) for each lease must include payment of the processing fee for assignments and transfers found in the fee schedule in § 3000.120 of this chapter.

(b) Each transfer of overriding royalty or payment out of production must include payment of the processing fee for overriding royalty transfers or payments out of productions found in the fee schedule in § 3000.120 of this chapter for each lease to which it applies.

Forms

§ 3106.41

Transfers of record title and of operating rights (subleases).

Each transfer of record title or of an operating right (sublease) must be filed with the proper BLM office on a current form approved by the Director. A separate form for each transfer, in triplicate, must be filed for each lease out of which a transfer is made. The BLM does not require triplicate copies of the assignment or transfer when it is electronically submitted. Copies of documents other than the current form approved by the Director must not be submitted. However, reference(s) to other documents containing information affecting the terms of the transfer may be made on the submitted form.

§ 3106.42

Transfers of other interests, including royalty interests and production payments.

(a) Each transfer of overriding royalty interest, payment out of production or similar interests created or reserved must be described for each lease on the current assignment or transfer form when filed.

(b) A single executed copy of each such transfer of other interests for each lease must be filed with the proper BLM office.

§ 3106.43

Mass transfers.

(a) A mass transfer may be utilized in lieu of the provisions of 43 CFR 3106.41 and 3106.42 when an assignor or transferor transfers interests of any type in more than one Federal lease to the same assignee or transferee.

(b) The mass transfer must be filed with each proper BLM office administering any lease affected by the mass transfer. The transfer must be on a current form approved by the Director with an exhibit attached to each copy listing the following for each lease:

(1) The serial number;

(2) The type and percent of interest being conveyed; and

(3) A description of the lands affected by the transfer in accordance with 43 CFR 3106.50.

(c)(1) One duplicate copy of the form must be filed with the proper BLM office for each lease involved in the mass transfer. A copy of the exhibit for each lease may be limited to line items pertaining to individual leases as long as that line item includes the information required by paragraph (b) of this section. The BLM does not require a duplicate copy of the assignment or transfer when it is electronically submitted.

(2) When the BLM does not receive the requisite number of copies, the applicant must reimburse the BLM for the full costs incurred to make the required number of copies. The BLM will waive fees under one dollar.

(d) A mass transfer must include the processing fee for assignments and transfers found in the fee schedule in § 3000.120 of this chapter for each such interest transferred for each lease.

§ 3106.50

Description of lands.

Each assignment of record title must describe the lands involved in the same manner as the lands are described in the lease, except no land description is required when 100 percent of the entire area encompassed within a lease is conveyed.

§ 3106.60

Bond requirements.

Where the lessee or operating rights owner (sublessee) maintains a bond covering the lease, the assignee of record title interest or transferee of operating rights in such lease must furnish, if bond coverage continues to be required, a proper bond that will cover any obligations arising under the lease to the same extent as the assignor's or transferor's bond.

Approval of Transfer or Assignment

§ 3106.71

Failure to qualify.

The BLM will not approve any assignment of record title or transfer of operating rights (sublease) if any party in interest is not a qualified lessee, or if the bond is insufficient. The BLM approves assignments and transfers for administrative purposes only. Approval does not warrant or certify that either party to a transfer holds legal or equitable title to a lease.

§ 3106.72

Continuing obligation of an assignor or transferor.

(a) The lessee or sublessee remains responsible for performing all obligations under the lease until the date the BLM approves an assignment of record title interest or transfer of operating rights.

(b) After the BLM approves the assignment or transfer, the assignor or transferor will continue to be responsible for lease obligations that accrued before the approval date, whether or not such obligations were identified at the time of the assignment or transfer. This includes paying compensatory royalties for drainage. It also includes responsibility for plugging wells drilled and removing facilities installed or used before the effective date of the assignment or transfer.

§ 3106.73

Lease account status.

The BLM will not approve a transfer if the lease account is delinquent with respect to: royalty payments; lease obligations, such as, but not limited to, rent and minimum royalty; or production reporting to ONRR for a lease in non-terminable status.

§ 3106.74

Effective date of transfer.

The signature of the authorized officer on the official form will constitute approval of the assignment of record title or transfer of operating rights (sublease) which will take effect as of the first day of the lease month following the date of filing in the proper BLM office of all documents and statements required by this subpart and an appropriate bond, if one is required.

§ 3106.75

Effect of transfer.

An assignment of record title to 100 percent of a portion of the lease segregates the transferred portion and the retained portion into separate leases. Each resulting lease retains the anniversary date and the terms and conditions of the original lease. An assignment of record title to less than 100 percent of a portion of the lease or a transfer of operating rights (sublease) will not segregate the transferred and retained portions into separate leases.

§ 3106.76

Obligations of assignee or transferee.

(a) The assignee of record title agrees to comply with the terms of the original lease during the lease tenure. The assignee assumes the responsibility to plug and abandon all wells which are no longer capable of producing, reclaim the lease site, and remedy all environmental problems in existence and that a purchaser exercising reasonable diligence should have known existed at the time of the transfer. When required, the record title holder must also maintain an adequate bond to ensure performance of these responsibilities.

(b) The transferee of operating rights agrees to comply with the terms of the original lease as it applies to the area or horizons for the interest acquired. The transferee assumes the responsibility to plug and abandon all wells that are no longer capable of producing, reclaim the lease site, and remedy all environmental problems in existence and that a purchaser exercising reasonable diligence should have known existed at the time of the transfer. When required, the operating rights holder must also maintain an adequate bond to ensure performance of these responsibilities.

Other Types of Transfers

§ 3106.81

Heirs and devisees.

(a) If an offeror, applicant, lessee or transferee dies, their rights would be assigned or transferred to the heirs, devisees, executor or administrator of the estate, as appropriate, upon the filing of legal documents demonstrating that the assignee or transferee is recognized as the successor of the deceased.

(b) The filing must include the processing fee for the transfer to an heir/devisee found in the fee schedule in § 3000.120 of this chapter with the request to assign lease rights.

(c) The filing must include a qualification statement demonstrating qualification to hold an interest in a lease in accordance with 43 CFR subpart 3102. Any ownership or interest otherwise forbidden by the regulations in this part which may be acquired by descent, will, judgment or decree may be held for a period not to exceed 2 years after its acquisition. Any such forbidden ownership or interest held for a period of more than 2 years after acquisition may be subject to cancellation.

(d) A bond rider or replacement bond may be required for any bond(s) previously furnished by the decedent.

§ 3106.82

Change of name.

(a) A legally recognized change of name of a lessee or sublessee must be reported to the proper BLM office. The notice of name change must be submitted in writing with adequate information concerning the name change. For a corporate name change, the request must include the Secretary of State's Certificate of Name Change, along with the Articles of Incorporation, or Amendment, if available.

(b) An entity must include with the notice of name change the required processing fee listed in the fee schedule in § 3000.120 of this chapter.

(c) If a bond(s) has been furnished, a change of name on the bond may be made by surety consent or a rider to the original bond or by a replacement bond.

§ 3106.83

Corporate mergers and dissolution of corporations, partnerships, and trusts.

(a) In the event a corporate merger affects leases where property of the dissolving corporation to the surviving corporation is accomplished by operation of law, an assignment of any affected lease interest is not required. An entity must notify the BLM of the merger and provide copies of the Secretary of State's Certificate of Merger, along with the Articles of Incorporation, or Amendment, if available, to the BLM.

(b) The BLM will not recognize any transfers provided by the Articles of Dissolution unless an entity has filed with the BLM a Certificate of Dissolution of an incorporated entity, certified as accepted by the State where the entity was incorporated.

(c) An entity must file with the BLM a dissolution of a partnership or trust through an order or decree that authorizes settlement, discharge, and distribution of the lease holdings and/or interests for official recognition of the assignment of lease interests.

(d) An entity must include the processing fee for corporate merger or dissolution of corporation, partnership, or trust found in the fee schedule in § 3000.120 of this chapter.

(e) The authorized officer may require a bond rider or replacement bond for all affected corporations, partnerships or trusts.

§ 3106.84

Sheriff's sale/deed.

(a) Where a notice of sale of the leasehold interest is published pursuant to State law applicable to the execution of sales of real property, the purchaser must submit a copy of the Sheriff's Certificate of Sale to the proper BLM office after any redemption period has passed.

(b) When submitting the certificate described in paragraph (a), an entity must include the processing fee for sheriff's deed found in the fee schedule in § 3000.120 of this chapter.

(c) The purchaser(s) must file a qualification statement to hold an interest in a lease in accordance with 43 CFR subpart 3102. Failure to provide a qualification statement after 2 years will result in the BLM cancelling the lease or interest.

(d) If a bond has been furnished by the previous interest holder, the authorized officer may require a new bond.

Subpart 3107—Continuation and Extension

§ 3107.10

Extension by drilling.

(a) Any lease on which actual drilling operations were commenced prior to the end of its primary term and are being diligently prosecuted at the end of the primary term or any lease which is part of an approved oil and gas agreement upon which such drilling takes place, will be extended for 2 years subject to the rental being timely paid as required by 43 CFR 3103.20, and subject to the provisions of 43 CFR 3105.23 and appendix A to part 3180, if applicable. The BLM will not grant a drilling extension for a lease in its extended term.

(b) Actual drilling operations must be conducted in a manner that a reasonable person seriously looking for oil or gas could be expected to make in that particular area, given the existing knowledge of geologic and other pertinent facts. In drilling a new well on a lease or for the benefit of a lease under the terms of an approved agreement, it must be taken to a depth sufficient to penetrate at least one formation recognized in the area as potentially productive of oil or gas, or where an existing well is reentered, it must be taken to a depth sufficient to penetrate at least one new and deeper formation recognized in the area as potentially productive of oil or gas. The authorized officer may determine that further drilling is unwarranted or impracticable.

(c) When a BLM-approved directional or horizontal well is drilled within the leased area from an off-lease location with the intent to produce from the leased area, the BLM will consider drilling to have commenced on the leased area when drilling is commenced at the off-lease location.

Production

§ 3107.21

Continuation by production.

A lease will be extended so long as oil or gas is being produced in paying quantities.

§ 3107.22

Cessation of production.

A lease in its extended term because of production (and lacking a well capable of production in paying quantities) will not expire upon cessation of production, if, within 60 calendar days of cessation of production, reworking or drilling operations on the leasehold are commenced and are thereafter conducted with reasonable diligence during the period of nonproduction. If these reworking or drilling operations fail to result in production in paying quantities, the lease will expire by operation of law, effective as of the date paying production ceased.

§ 3107.23

Leases capable of production.

No lease for lands on which there is a well capable of producing oil or gas in paying quantities will expire because the lessee fails to produce the same, unless the lessee fails to place the lease in production within a period of not less than 60 calendar days as specified by the authorized officer after receipt of notice by certified mail from the authorized officer to do so. Such production must be continued unless and until suspension of production is granted by the authorized officer.

Extension of Leases Within Agreements

§ 3107.31

Leases committed to an agreement.

(a) Any lease or portion of a lease committed to an oil and gas agreement that contains a general provision for allocation of oil or gas will continue in effect so long as the lease or portion thereof remains subject to the agreement; provided, that there is production of oil or gas in paying quantities under the agreement prior to the expiration date of such lease.

(b) A well that is drilled and completed on a lease committed to a unit agreement, and that is capable of production in paying quantities on a lease basis, will extend the term of all expiring Federal leases committed to the unit agreement for the term of the unit agreement and so long as the well is capable of production in paying quantities.

§ 3107.32

Segregation of leases committed in part.

(a) Any lease committed after July 29, 1954, to any unit agreement, which covers lands within and lands outside the area covered by the agreement, will be segregated, as of the effective date of commitment to the unit, into separate leases; one covering the lands committed to the agreement, the other lands not committed to the agreement. For unproven areas, such segregation will occur only when the public interest requirement is satisfied pursuant to 43 CFR 3183.4(b). Upon satisfaction of the public interest requirement, the BLM will deem the segregation to have been effective as of the date of commitment of the lands to the unit.

(b)(1) The segregated lease covering the non-unitized portion of the lands will continue in force and effect for the term of the lease or for 2 years from the date of segregation, whichever is longer.

(2) If a partially committed lease is in an extended term because of production, the segregated, non-producing lease will continue in effect so long as the producing lease exists and rentals are paid, and so long thereafter as oil or gas is produced from the committed lease.

§ 3107.40

Extension by elimination.

Any lease eliminated from any approved or prescribed oil and gas agreement authorized by the Act and any lease in effect at the termination of such agreement, unless relinquished, will continue in effect for the original term of the lease or for 2 years after its elimination from the agreement or after the termination of the plan or agreement, whichever is longer, and for so long thereafter as oil or gas is produced in paying quantities. No lease will be extended if the public interest requirement for an approved oil and gas agreement has not been satisfied, as determined by the authorized officer.

Extension of Leases Segregated by Assignment

§ 3107.51

Extension after discovery on other segregated portions.

Any lease segregated by assignment, including the retained portion, will continue in effect for the primary term of the original lease, or for 2 years after the date a well capable of production in paying quantities is established upon any other portion of the original lease, whichever is the longer period.

§ 3107.52

Undeveloped parts of leases in their extended term.

Undeveloped parts of leases retained or assigned out of leases which are in their extended term will continue in effect for 2 years after the effective date of assignment, provided the parent lease was issued prior to September 2, 1960.

§ 3107.53

Undeveloped parts of producing leases.

Undeveloped parts of leases retained or assigned out of leases which are extended by production, actual or suspended, or the payment of compensatory royalty will continue in effect for 2 years after the effective date of assignment and for so long thereafter as oil or gas is produced in paying quantities.

§ 3107.60

Extension of reinstated leases.

Where a reinstatement of a terminated lease is granted under 43 CFR 3108.20 and the authorized officer finds that the reinstatement will not afford the lessee a reasonable opportunity to continue operations under the lease, the authorized officer may extend the term of such lease for a period sufficient to give the lessee such an opportunity. Any extension will be subject to the following conditions:

(a) No extension will exceed a period equal to the unexpired portion of the lease or any extension thereof remaining at the date of termination.

(b) When the reinstatement occurs after the expiration of the term or extension thereof, the lease may be extended from the date the authorized officer grants the petition, but in no event for more than 2 years from the date the reinstatement is authorized and so long thereafter as oil or gas is produced in paying quantities.

Other Extension Types

§ 3107.71

Payment of compensatory royalty.

The payment of a compensatory royalty will extend the term of any lease for the period during which such compensatory royalty is paid and for a period of 1 year from the discontinuance of such payments.

§ 3107.72

Subsurface storage of oil and gas.

Any lease used for the storage of oil or gas will be extended for the period of storage under an approved agreement.

Subpart 3108—Relinquishment, Termination, Cancellation

§ 3108.10

Relinquishment.

The lessee(s) may relinquish the lease or any legal subdivision of the lease at any time. The lessee(s) must file a written relinquishment with the BLM State Office with jurisdiction over the lease. All lessees holding record title interests in the lease must sign the relinquishment. A relinquishment takes effect on the date the lessee filed it with the BLM. However, the lessee(s) and the party that issued the bond will continue to be obligated to:

(a) Make payments of all accrued rentals and royalties, including payments of compensatory royalty due for all drainage that occurred before the relinquishment;

(b) Place all wells to be relinquished in condition for suspension or abandonment as the BLM requires; and

(c) Complete reclamation of the leased sites after stopping or abandoning oil and gas operations on the lease, under a plan approved by the BLM or the appropriate surface management agency.

Termination by Operation of Law and Reinstatement

§ 3108.21

Automatic termination.

(a) Except as provided in paragraph (b) of this section, any lease on which there is no well capable of producing oil or gas in paying quantities will automatically terminate by operation of law (30 U.S.C. 188) if the lessee fails to pay the rental at the designated ONRR office on or before the lease anniversary date. However, if the designated ONRR office is closed on the anniversary date, a rental payment received on the next business day the ONRR office is open to the public will be considered timely made.

(b) If the rental payment due under a lease is paid on or before its anniversary date but the amount of the payment is deficient and the deficiency is nominal as defined in this section, or the amount of payment made was determined in accordance with the rental or acreage figure stated in a decision rendered by the authorized officer, and such figure is found to be in error resulting in a deficiency, such lease will not have automatically terminated unless the lessee fails to pay the deficiency within the period prescribed in the Notice of Deficiency provided for in this section. A deficiency will be considered nominal if it is not more than $100 or more than 5 percent of the total payment due, whichever is less. The designated ONRR office will send a Notice of Deficiency to the lessee. The Notice will allow the lessee 15 days from the date of receipt or until the due date, whichever is later, to submit the full balance due to the designated ONRR office. If the payment required by the Notice is not paid within the time allowed, the lease will have terminated by operation of law as of its anniversary date.

(c) The automatic termination provision does not apply where, due to other contingencies, additional rental is due on a date other than the lease anniversary date and where the lessee did not receive notice that the obligation had accrued, unless the lessee fails to pay the rental within the period prescribed in the BLM Notice.

§ 3108.22

Reinstatement at existing rental and royalty rates: Class I reinstatements.

(a) Except as hereinafter provided, the authorized officer may reinstate a lease which has terminated for failure to pay on or before the anniversary date the full amount of rental due, provided that:

(1) Such rental was paid or tendered within 20 days after the anniversary date; and

(2) It is shown to the satisfaction of the authorized officer that the failure to timely submit the full amount of the rental due was either justified or not due to a lack of reasonable diligence on the part of the lessee (reasonable diligence includes a rental payment that is paid to the ONRR on or before the lease anniversary date. If the designated ONRR office or payment system is not operational on the anniversary date, payment received on the next business day in which the designated ONRR office or payment system is operational to the public will be deemed timely); and

(3) A petition for reinstatement and the processing fee for lease reinstatement, Class I, found in the fee schedule in § 3000.120 of this chapter, are filed with the proper BLM office within 60 days after receipt of Notice of Termination of Lease due to late payment of rental. If a terminated lease becomes productive prior to the time the lease is reinstated, all required royalty that has accrued must be paid to the ONRR.

(b) The burden of showing that the failure to pay on or before the anniversary date was justified or not due to lack of reasonable diligence is on the lessee.

(c) Under no circumstances will a terminated lease be reinstated if:

(1) A valid oil and gas lease has been issued prior to the filing of a petition for reinstatement affecting any of the lands covered by that terminated lease; or

(2) The oil and gas interests of the United States in the lands have been disposed of or otherwise have become unavailable for leasing.

§ 3108.23

Reinstatement at higher rental and royalty rates: Class II reinstatements.

(a) The authorized officer may, if the requirements of this section are met, reinstate a competitive oil and gas lease which was terminated by operation of law for failure to pay rental timely when the rental was not paid or tendered within 20 calendar days of the termination date, and it is shown to the satisfaction of the authorized officer that such failure was justified or not due to a lack of reasonable diligence, or no matter when the rental was paid, it is shown to the satisfaction of the authorized officer that such failure was inadvertent.

(b)(1) Such leases may be reinstated if the required back rental and royalty at the increased rates accruing from the date of termination, together with a petition for reinstatement, are filed on or before the earlier of:

(i) Sixty calendar days after the last date that any lessee of record received Notice of Termination by certified mail; or

(ii) Twenty-four months after termination of the lease.

(2) After determining that the requirements for filing of the petition for reinstatement have been timely met, the authorized officer may reinstate the lease if:

(i) No valid lease has been issued prior to the filing of the petition for reinstatement affecting any of the lands covered by the terminated lease, whether such lease is still in effect or not;

(ii) The oil and gas interests of the United States in the lands have not been disposed of or have not otherwise become unavailable for leasing;

(iii) Payment of all back rentals and royalties at the rates established for the reinstated lease has been made;

(iv) An agreement has been signed by the lessee and attached to and made a part of the lease specifying future rentals at the applicable rates specified for reinstated leases in 43 CFR 3103.22 and future royalties at the rates set in 43 CFR 3103.31 for all production removed or sold from such lease or shared by such lease from production allocated to the lease by virtue of its participation in an oil and gas agreement;

(v) A notice of the proposed reinstatement of the terminated lease and the terms and conditions of reinstatement has been published in the Federal Register at least 30 days prior to the date of reinstatement for which the lessee must reimburse the BLM for the full costs incurred in the publishing of said notice; and

(vi) The lessee has paid the BLM a nonrefundable administrative fee of $500.

(c) The authorized officer will furnish to the Chairpersons of the Committee on Natural Resources of the House of Representatives and of the Committee on Energy and Natural Resources of the Senate, at least 30 days prior to the date of reinstatement, a copy of the notice, together with information concerning rental, royalty, volume of production, if any, and any other matter which the authorized officer considers significant in making the determination to reinstate.

(d) If the authorized officer reinstates the lease, the reinstatement will be effective as of the date of termination, for the unexpired portion of the original lease or any extension thereof remaining on the date of termination, and so long thereafter as oil or gas is produced in paying quantities. Where a lease is reinstated under this section and the authorized officer finds that the reinstatement of such lease either:

(1) Occurs after the expiration of the primary term or any extension thereof; or

(2) Will not afford the lessee a reasonable opportunity to continue operations under the lease, the authorized officer may extend the term of the reinstated lease for such period as determined reasonable, but in no event for more than 2 years from the date of the reinstatement and so long thereafter as oil or gas is produced in paying quantities.

§ 3108.30

Cancellation.

(a) Whenever the lessee fails to comply with any of the provisions of the law, the regulations issued thereunder, or the lease, the lease may be canceled by the Secretary, if the leasehold does not contain a well capable of production of oil or gas in paying quantities, or if the lease is not committed to an approved oil and gas agreement that contains a well capable of production of unitized substances in paying quantities. The lease may be canceled only if the default continues for 30 calendar days after a notice of default has been delivered in accordance with 43 CFR 1810.2.

(b) Whenever the lessee fails to comply with any of the provisions of the law, the regulations issued thereunder, or the lease, and if the leasehold contains a well capable of production of oil or gas in paying quantities, or if the lease is committed to an approved oil and gas agreement that contains a well capable of production of unitized substances in paying quantities, the lease may be canceled only by court order in the manner provided by section 31(a) of the Act (30 U.S.C. 188).

(c) If any interest in any lease is owned or controlled, directly or indirectly, by means of stock or otherwise, in violation of any of the provisions of the Act, the lease may be canceled, or the interest so owned may be forfeited, or the person so owning or controlling the interest may be compelled to dispose of the interest, only by court order in the manner provided by section 27(h)(1) of the Act (30 U.S.C. 184).

(d) Leases will be subject to cancellation if improperly issued.

§ 3108.40

Bona fide purchasers.

A lease or interest therein may not be cancelled to the extent that such action adversely affects the title or interest of a bona fide purchaser even though such lease or interest, when held by a predecessor in title, may have been subject to cancellation. All purchasers will be charged with constructive notice as to all pertinent regulations and all BLM records pertaining to the lease and the lands covered by the lease. Prompt action may be taken to dismiss as a party to any proceedings with respect to a violation by a predecessor of any provisions of the Act, any person who shows the holding of an interest as a bona fide purchaser without having violated any provisions of the Act. No hearing will be necessary upon such showing unless prima facie evidence is presented that the purchaser is not a bona fide purchaser.

§ 3108.50

Waiver or suspension of lease rights.

If, during any proceeding with respect to a violation of any provision of the regulations in 43 CFR parts 3000 and 3100 or the Act, a party thereto files a waiver of his/her rights under the lease to drill or to assign his/her lease interests, or if such rights are suspended by order of the Secretary pending a decision, payments of rentals and the running of time against the term of the lease involved will be suspended as of the first day of the month following the filing of the waiver or the Secretary's suspension until the first day of the month following the final decision in the proceeding or the revocation of the waiver or suspension.

Subpart 3109—Leasing under Special Acts

Rights-of-Way

§ 3109.11

Generally.

The Act of May 21, 1930 (30 U.S.C. 301-306), authorizes either the leasing of oil and gas deposits under railroad and other rights-of-way to the owner of the right-of-way or the entering of a compensatory royalty agreement with adjoining landowners. This authority will be exercised only with respect to railroad rights-of-way and easements issued pursuant either to the Act of March 3, 1875 (43 U.S.C.934 et seq.), or pursuant to earlier railroad right-of-way statutes, and with respect to rights-of-way and easements issued pursuant to the Act of March 3, 1891 (43 U.S.C. 946 et seq.). The oil and gas underlying any other right-of-way or easement is included within any oil and gas lease issued pursuant to the Act which covers the lands within the right-of-way, subject to the limitations on use of the surface, if any, set out in the statute under which, or permit by which, the right-of-way or easement was issued, and such oil and gas will not be leased under the Act of May 21, 1930.

§ 3109.12

Application.

(a) No approved form is required for an application to lease oil and gas deposits underlying a right-of-way.

(b) The right-of-way owner or his/her transferee must file the application in the proper BLM office.

(c) Include the processing fee for leasing under right-of-way found in the fee schedule in § 3000.120 of this chapter.

(d) An application must include:

(1) Facts as to the ownership of the right-of-way, and of the transfer if the application is filed by a transferee;

(2) An executed transfer of the right to obtain a lease, if necessary;

(3) A description of the development of oil or gas in adjacent or nearby lands, the location and depth of the wells, the production and the probability of drainage of the deposits in the right-of-way;

(4) A description of each legal subdivision through which a portion of the right-of-way desired to be leased traverses; however, a description by metes and bounds of the right-of-way is not required; and

(5) A map of the applicable lands.

§ 3109.13

Notice.

After the BLM has determined that a lease of a right-of-way or any portion thereof is consistent with the public interest, either upon consideration of an application for lease or on its own motion, the authorized officer will serve notice on the owner or lessee of the oil and gas rights of the adjoining lands. The adjoining landowner or lessee will be allowed a reasonable time, as provided in the notice, within which to submit a bid for the percent of compensatory royalty, the owner or lessee must pay for the extraction of the oil and gas underlying the right-of-way through wells on such adjoining lands. The owner of the right-of-way will be given the same time period to submit a bid for the lease.

§ 3109.14

Award of lease or compensatory royalty agreement.

Award of lease to the owner of the right-of-way, or a contract for the payment of compensatory royalty by the owner or lessee of the adjoining lands will be made to the bidder whose offer is determined by the authorized officer to be to the best advantage of the United States, considering the amount of royalty to be received and the better development under the respective means of production and operation.

§ 3109.15

Compensatory royalty agreement or lease.

(a) The lease or compensatory royalty agreement will be on a form approved by the Director.

(b) The primary term of the lease will be for a period of 10 years.

(c) The following provisions of 43 CFR part 3100 apply to the issuance and administration of leases for oil and gas deposits underlying a right-of-way issued under this part:

(1) All of subpart 3101, except §§ 3101.21, 3101.22, 3101.23, 3101.24, and 3101.25; and

(2) All of subparts 3102 through 3108;

§ 3109.20

Units of the National Park System.

(a) Oil and gas leasing in units of the National Park System will be governed by 43 CFR part 3100 and all operations conducted on a lease or permit in such units will be governed by 43 CFR parts 3160 and 3180.

(b) Any lease or permit respecting minerals in units of the National Park System may be issued or renewed only with the consent of the Regional Director, National Park Service. Such consent will only be granted upon a determination by the Regional Director that the activity permitted under the lease or permit will not have significant adverse effect upon the resources or administration of the unit pursuant to the authorizing legislation of the unit. Any lease or permit issued will be subject to such conditions as may be prescribed by the Regional Director to protect the surface and significant resources of the unit, to preserve their use for public recreation, and to the condition that site specific approval of any activity on the lease will only be given upon concurrence by the Regional Director. All lease applications received for reclamation withdrawn lands will also be submitted to the Bureau of Reclamation for review.

(c) The units subject to the regulations in this part are those units of land and water which are shown on the following maps on file and available for public inspection in the office of the Director of the National Park Service and in the Superintendent's Office of each unit. The boundaries of these units may be revised by the Secretary as authorized in the Acts.

(1) Lake Mead National Recreation Area—The map identified as “boundary map, 8360-80013B, revised February 1986.

(2) Whiskeytown Unit of the Whiskeytown-Shasta-Trinity National Recreation Area—The map identified as “Proposed Whiskeytown-Shasta-Trinity National Recreation Area,” numbered BOR-WST 1004, dated July 1963.

(3) Ross Lake and Lake Chelan National Recreation Areas—The map identified as “Proposed Management Units, North Cascades, Washington,” numbered NP-CAS-7002, dated October 1967.

(4) Glen Canyon National Recreation Area—the map identified as “boundary map, Glen Canyon National Recreation Area,” numbered GLC-91,006, dated August 1972.

(d) The following excepted units will not be open to mineral leasing:

(1) Lake Mead National Recreation Area. (i) All waters of Lakes Mead and Mohave and all lands within 300 feet of those lakes measured horizontally from the shoreline at maximum surface elevation;

(ii) All lands within the unit of supervision of the Bureau of Reclamation around Hoover and Davis Dams and all lands outside of resource utilization zones as designated by the Superintendent on the map (602-2291B, dated October 1987) of Lake Mead National Recreation Area which is available for inspection in the Office of the Superintendent.

(2) Whiskeytown Unit of the Whiskeytown-Shasta-Trinity National Recreation Area. (i) All waters of Whiskeytown Lake and all lands within 1 mile of that lake measured from the shoreline at maximum surface elevation;

(ii) All lands classified as high-density recreation, general outdoor recreation, outstanding natural and historic, as shown on the map numbered 611-20,004B, dated April 1979, entitled “Land Classification, Whiskeytown Unit, Whiskeytown-Shasta-Trinity National Recreation Area.” This map is available for public inspection in the Office of the Superintendent;

(iii) All lands within section 34 of Township 33 north, Range 7 west, Mt. Diablo Meridian.

(3) Ross Lake and Lake Chelan National Recreation Areas. (i) All of Lake Chelan National Recreation Area;

(ii) All lands within 1/2 mile of Gorge, Diablo and Ross Lakes measured from the shoreline at maximum surface elevation;

(iii) All lands proposed for or designated as wilderness;

(iv) All lands within 1/2 mile of State Highway 20;

(v) Pyramid Lake Research Natural Area and all lands within 1/2 mile of its boundaries.

(4) Glen Canyon National Recreation Area. Those units closed to mineral disposition within the natural zone, development zone, cultural zone and portions of the recreation and resource utilization zone as shown on the map numbered 80,022A, dated March 1980, entitled “Mineral Management Plan—Glen Canyon National Recreation Area.” This map is available for public inspection in the Office of the Superintendent and the office of the BLM State Offices, Arizona and Utah.

§ 3109.30

Shasta and Trinity Units of the Whiskeytown-Shasta-Trinity National Recreation Area.

Section 6 of the Act of November 8, 1965 (Pub. L. 89-336), authorizes the Secretary to permit the removal of oil and gas from lands within the Shasta and Trinity Units of the Whiskeytown-Shasta-Trinity National Recreation Area in accordance with the Act or the Mineral Leasing Act for Acquired Lands. Subject to the determination by the Secretary of Agriculture that removal will not have significant adverse effects on the purposes of the Central Valley project or the administration of the recreation area.

PART 3110 [REMOVED]

3. Under the authority of 30 U.S.C. 189, part 3110 is removed.

4. Revise part 3120 to read as follows:

PART 3120—COMPETITIVE LEASES

General

3120.11

Lands available for competitive leasing.

3120.12

Requirements.

3120.13

Protests.

Lease Terms

3120.21

Duration of lease.

3120.22

Dating of leases.

3120.23

Lease size.

Expressions of Interest

3120.31

Expression of interest process.

3120.32

Expression of interest leasing preference.

3120.33

Agency inventory of leasing.

Notice of Competitive Lease Sale

3120.41

General.

3120.42

Posting timeframes.

Competitive Auction

3120.51

Competitive auction.

3120.52

Payments required.

3120.53

Award of lease.

3120.60

Parcels not bid on at auction.

Future Interest

3120.71

Expression of interest to make lands available for competitive lease.

3120.72

Future interest terms and conditions.

3120.73

Compensatory royalty agreements.

PART 3120—COMPETITIVE LEASES

Authority: 16 U.S.C. 3101 et seq.;30 U.S.C. 181 et seq. and 351-359; 40 U.S.C. 471 et seq.;43 U.S.C. 1701 et seq.;Pub. L. 113-291, 128 Stat. 3762; and the Attorney General's Opinion of April 2, 1941 (40 Op. Atty. Gen. 41).

General

§ 3120.11

Lands available for competitive leasing.

All lands eligible and available for leasing may be offered for competitive auction under this subpart, including but not limited to:

(a) Lands that were covered by previously issued oil and gas leases that have terminated, expired, been cancelled or relinquished;

(b) Lands for which authority to lease has been delegated from the General Services Administration;

(c) If, in proceeding to cancel a lease, interest in a lease, option to acquire a lease or an interest therein, acquired in violation of any of the provisions of the Act, an underlying lease, interest or option in the lease is cancelled or forfeited through a bankruptcy or otherwise to the United States and there are valid interests therein that are not subject to cancellation, forfeiture, or compulsory disposition, such underlying lease, interest, or option may be sold to the highest responsible and qualified bidder by competitive bidding under this subpart, subject to all outstanding valid interests therein and valid options pertaining thereto. If less than the whole interest in the lease, interest, or option is cancelled or forfeited, such partial interest may likewise be sold by competitive bidding. If no satisfactory bid is obtained as a result of the competitive offering of such whole or partial interests, such interests may be sold in accordance with 30 U.S.C. 184(h)(2) by such other methods as the authorized officer deems appropriate, but on terms no less favorable to the United States than those of the best competitive bid received. Interest in outstanding leases(s) so sold will be subject to the terms and conditions of the existing lease(s);

(d) Lands which are otherwise unavailable for leasing but which are subject to drainage (protective leasing);

(e) Lands included in any expression of interest submitted to the authorized officer;

(f) Lands selected by the authorized officer; and

(g) Lands that were offered on a previous sale for which no bid was accepted or received.

§ 3120.12

Requirements.

(a) Each BLM state office will hold sales at least quarterly if eligible lands are available for competitive leasing.

(b) Lease sales will be conducted by a competitive auction process.

(c) The BLM may issue a lease only to the highest responsible and qualified bidder. If a person does not pay the minimum monies owed the day of the sale, the BLM may refer that person to the Department of the Interior's Office of the Inspector General, Administrative Remedies Division, for appropriate action, including potential suspension and debarment.

(d) The national minimum acceptable bid will be as specified in § 3103.1 of this chapter and payable on the gross acreage and will not be prorated for any lands in which the United States owns a fractional interest.

§ 3120.13

Protests.

(a) No action pursuant to the regulations in this subpart will be suspended under 43 CFR 4.21(a) due to a protest from a notice by the authorized officer to hold a lease sale.

(b) Notwithstanding paragraph (a) of this section, the authorized officer may suspend the offering of a specific parcel while considering a protest against its inclusion in a Notice of Competitive Lease Sale.

(c) Only the Assistant Secretary for Land and Minerals Management may suspend a lease sale for good cause after reviewing the reason(s) for a protest.

Lease Terms

§ 3120.21

Duration of lease.

Competitive leases will be issued for a primary term of 10 years.

§ 3120.22

Dating of leases.

All competitive leases will be considered issued when signed by the authorized officer. Competitive leases, except future interest leases issued under § 3120.80, will be effective as of the first day of the month following the date the leases are signed on behalf of the United States. A lease may be made effective on the first day of the month within which it is issued if a written request is made prior to the date of signature of the authorized officer. Leases for future interest will be effective as of the date the mineral interests vest in the United States.

§ 3120.23

Lease size.

Lands may be offered in leasing units of not more than 2,560 acres outside Alaska, or 5,760 acres within Alaska, which may be as nearly compact in form as possible.

Expressions of Interest

§ 3120.31

Expression of interest process.

(a) A party submitting an expression of interest in leasing land available for disposition under section 17 of the Mineral Leasing Act must include the submitter's name and address and must submit the expression of interest through the BLM's online leasing system.

(b) The expression must provide a description of the lands identified by legal land description, as follows:

(1) For lands surveyed under the public land survey system, describe the lands to the nearest aliquot part within the legal subdivision, section, township, range, and meridian;

(2) For unsurveyed lands, describe the lands by metes and bounds, giving courses and distances, and tie this information to an official corner of the public land surveys, or to a prominent topographic feature;

(3) For approved protracted surveys, include an entire section, township, range, and meridian. Do not divide protracted sections into aliquot parts;

(4) For lands that have water boundaries, describe the lands based on the initial survey or deed acquiring ownership;

(5) For fractional interest lands, identify the United States mineral ownership by percentage;

(6) For split estate lands, where the surface rights are in private ownership and the rights to develop the oil and gas are managed by the Federal Government, submit the private surface owner's name and address.

(7) For lands where the acquiring agency has assigned an acquisition or tract number covering the lands applied, submit the number in addition to any description otherwise required by this section. If the authorized officer determines that the acquisition or tract number, together with identification of the State and county, constitutes an adequate description, the authorized officer may allow the description in this manner in lieu of other descriptions required by this section.

(c) A submitter may submit more than one expression of interest, so long as each expression separately satisfies the requirements of paragraph (b) of this section.

(d) Each expression of interest must include a filing fee, as found in the fee schedule in § 3103.1 of this chapter.

(e) The BLM may offer for sale all or some of the lands specified in an expression of interest and may offer those lands as part of a parcel that includes lands not specified in the expression of interest.

§ 3120.32

Expression of interest leasing preference.

When determining whether the BLM should offer lands specified in an expression of interest at lease sales, the BLM will evaluate the Secretary's obligations to manage public lands for multiple use and sustained yield and to take any action required to prevent unnecessary or undue degradation of the lands and their resources, along with other applicable legal requirements. In evaluating the lands to be offered, as part of the scoping process, the BLM will consider, at minimum:

(a) Proximity to oil and gas development existing at the time of the BLM's evaluation, giving preference to lands upon which a prudent operator would seek to expand existing operations;

(b) The presence of important fish and wildlife habitats or connectivity areas, giving preference to lands that would not impair the proper functioning of such habitats or corridors;

(c) The presence of historic properties, sacred sites, and other high value cultural resources, giving preference to lands that would not impair the cultural significance of such resources;

(d) The presence of recreation and other important uses or resources, giving preference to lands that would not impair the value of such uses or resources; and

(e) The potential for oil and gas development, giving preference to lands with high potential for development.

§ 3120.33

Agency inventory of leasing.

Until August 16, 2032, the BLM will from time to time calculate, for the preceding 1-year period before it issues a wind or solar energy right-of-way, the acreage for which expressions of interest have been submitted to the BLM and the sum total of acres offered for lease.

Notice of Competitive Lease Sale

§ 3120.41

General.

(a) The lands available for competitive lease sale under this subpart will be described in a Notice of Competitive Lease Sale.

(b) The time, date, and place of the competitive lease sale will be stated in the notice.

(c) The notice will include an identification of, and a copy of, stipulations applicable to each parcel.

§ 3120.42

Posting timeframes.

(a) After identifying a preliminary list of lands for a lease sale, the BLM will provide a scoping period, of not less than 30 calendar days, for public comment on the preliminary parcel list for the upcoming lease sale. The preliminary parcel list is not subject to protests or appeals.

(b) After drafting a National Environmental Policy Act document for a lease sale, the BLM will provide a comment period, of not less than 30 calendar days, for public comment on the National Environmental Policy Act document for the upcoming lease sale. The draft National Environmental Policy Act document is not subject to protests or appeals.

(c) At least 60 calendar days prior to conducting a competitive auction, the BLM will make available to the public a list of lands to be offered for competitive lease sale in a Notice of Competitive Lease Sale.

(d) After posting the Notice of Competitive Lease Sale notice, the BLM will provide a protest period, of not less than 30 calendar days, for public input on the upcoming lease sale.

(e) The BLM will make available the final National Environmental Policy Act compliance documents prior to issuing a lease from the lease sale.

Competitive Auction

§ 3120.51

Competitive auction.

(a) Parcels will be offered by competitive auction.

(b) A winning bid will be the highest bid by a responsible and qualified bidder, equal to or exceeding the national minimum acceptable bid. The decision of the auctioneer will be final.

§ 3120.52

Payments required.

(a) Payments must be made in accordance with 43 CFR 3103.11.

(b) Each winning bidder must submit, by the close of official business hours on the day of the sale for the parcel, or such other time as may be specified by the authorized officer:

(1) The minimum bonus bid as specified in § 3103.1 of this chapter;

(2) The total amount of the first year's rental; and

(3) The processing fee for competitive lease applications found in the fee schedule in § 3000.120 of this chapter for each parcel.

(c) The winning bidder must submit the balance of the bonus bid to the proper BLM office within 10 business days after the last day of the competitive auction.

§ 3120.53

Award of lease.

(a) A bid will not be withdrawn and will constitute a legally binding commitment to execute the lease bid form and accept a lease, including the obligation to pay the bonus bid, first year's rental, and processing fee. Execution by the high bidder of a competitive lease bid form approved by the Director constitutes certification of compliance with 43 CFR subpart 3102, will constitute a binding lease offer, including all terms and conditions applicable thereto, and must be submitted when payment is made in accordance with § 3120.62(b). Failure to comply with § 3120.62(c) will result in rejection of the bid and forfeiture of the monies submitted under § 3120.62(b).

(b) A lease will be awarded to the highest responsible and qualified bidder. A copy of the lease will be provided to the lessee after signature by the authorized officer.

(c) If a bid is rejected, the land may be reoffered competitively under this subpart.

(d) The BLM will not issue a lease until it resolves all protests covering the lands to be leased.

(e) Leases will be issued within 60 calendar days, following payment by the successful bidder of the remainder of the bonus bid, if any, and the annual rental for the first lease year. If the BLM cannot issue the lease within 60 days, the BLM, with the consent of the bidder, may reject the offer.

§ 3120.60

Parcels not bid on at auction.

Lands offered at the competitive auction that received no bids may be offered in a future competitive auction.

Future Interest

§ 3120.71

Expression of interest to make lands available for competitive lease.

An expression of interest for a future interest lease must be filed in accordance with this subpart.

§ 3120.72

Future interest terms and conditions.

(a) No rental or royalty will be due to the United States prior to the vesting of the oil and gas rights in the United States. However, the future interest lessee must agree that if, he/she is or becomes the holder of any present interest operating rights in the lands:

(1) The future interest lessee transfers all or a part of the lessee's present oil and gas interests, such lessee must file in the proper BLM office an assignment or transfer, in accordance with 43 CFR subpart 3106, of the future interest lease of the same type and proportion as the transfer of the present interest; and

(2) The future interest lessee's present lease interests are relinquished, cancelled, terminated, or expired, the future interest lease rights with the United States also will cease and terminate to the same extent.

(b) Upon vesting of the oil and gas rights in the United States, the future interest lease rental and royalty will be as for any competitive lease issued under this subpart, as provided in 43 CFR subpart 3103, and the acreage will be chargeable in accordance with 43 CFR 3101.20.

§ 3120.73

Compensatory royalty agreements.

The terms and conditions of compensatory royalty agreements involving acquired lands in which the United States owns a future or fractional interest will be established on an individual case basis. Such agreements may be required when leasing is not possible in situations where the interest of the United States in the oil and gas deposit includes both a present and a future fractional interest in the same tract containing a producing well.

PART 3130—OIL AND GAS LEASING: NATIONAL PETROLEUM RESERVE ALASKA

5. The authority citation for part 3130 continues to read as follows:

Authority: 42 U.S.C. 6508, 43 U.S.C. 1733 and 1740.

6. Revise § 3137.23 to read as follows:

§ 3137.23

NPR-A unitization application.

The unitization application must include:

(a) The proposed unit agreement;

(b) A map showing the proposed unit area;

(c) A list of committed tracts including, for each tract, the:

(1) Legal land description and acreage;

(2) Names of persons holding record title interest;

(3) Names of persons owning operating rights; and

(4) Name of the unit operator.

(d) A statement certifying:

(1) The operator invited all owners of oil and gas rights (leased or unleased) and lease interests (record title and operating rights) within the external boundary of the unit area described in the application to join the unit;

(2) That there are sufficient tracts committed to the unit agreement to reasonably operate and develop the unit area;

(3) The commitment status of all tracts within the area proposed for unitization; and

(4) The operator accepts unit obligations under § 3137.60 of this subpart.

(e) Evidence of acceptable bonding;

(f) A discussion of reasonably foreseeable and significantly adverse effects on the surface resources of the NPR-A and how unit operations may reduce impacts compared to individual lease operations;

(g) A discussion of the proposed methodology for allocating production among the committed tracts. If the unit includes non-Federal oil and gas mineral estate, you must explain how the methodology takes into account reservoir heterogeneity and area variation in reservoir producibility; and

(h) Other documentation that the BLM may request. The BLM may require additional copies of maps, plats, and other similar exhibits.

(i) The processing fee found in the fee schedule in § 3000.120 of this chapter.

7. Revise § 3137.61 to read as follows:

§ 3137.61

Change in unit operators.

(a) To change unit operators, the new unit operator must submit to the BLM:

(1) Statements that:

(i) The new operator accepts unit obligations; and

(ii) The percentage of required interest owners consented to a change of unit operator;

(2) Evidence of acceptable bonding ( see § 3137.60(b)); and

(3) The processing fee found in the fee schedule in § 3000.120 of this chapter.

(b) The effective date of the change in unit operator is the date the BLM approves the new unit operator.

8. Revise § 3138.11 to read as follows:

§ 3138.11

Applications for a subsurface storage agreement.

(a) An application for a subsurface storage agreement must include:

(1) The reason for forming a subsurface storage agreement;

(2) A description of the area to be included in the subsurface storage agreement;

(3) A description of the formation to be used for storage;

(4) The proposed storage fees or rentals. The fees or rentals must be based on the value of the subsurface storage, injection, and withdrawal volumes, and rental income or other income generated by the operator for letting or subletting the storage facilities;

(5) The payment of royalty for native oil or gas (oil or gas that exists in the formation before injection and that is produced when the stored oil or gas is withdrawn);

(6) A description of how often and under what circumstances the operator and the BLM intend to renegotiate fees and payments;

(7) The proposed effective date and term of the subsurface storage agreement;

(8) Certification that all owners of mineral rights (leased or unleased) and lease interests have consented to the gas storage agreement in writing;

(9) An ownership schedule showing lease or land status;

(10) A schedule showing the participation factor for all parties to the subsurface storage agreement;

(11) Supporting data (geologic maps showing the storage formation, reservoir data, etc.) demonstrating the capability of the reservoir for storage; and

(12) The processing fee found in the fee schedule in § 3000.120 of this chapter.

(b) The BLM will negotiate the terms of a subsurface storage agreement with the operator, including bonding, and reservoir management.

(c) The BLM may request documentation in addition to that which the operator provides under paragraph (a) of this section.

9. Revise part 3140 to read as follows:

PART 3140—LEASING IN SPECIAL TAR SAND AREAS

Subpart 3140—Conversion of Existing Oil and Gas Leases and Valid Claims Based on Mineral Locations

3140.1

Purpose.

3140.3

Authority.

3140.5

Definitions.

General Provisions

3140.11

Existing rights.

3140.12

Notice of intent to convert.

3140.13

Exploration plans.

3140.14

Other provisions.

Applications

3140.21

Forms.

3140.22

Who may apply.

3140.23

Application requirements.

Time Limitations

3140.31

Conversion applications.

3140.32

Action on an application.

Conversion

3140.41

Approval of plan of operations (and unit and operating agreements).

3140.42

Issuance of the combined hydrocarbon lease.

3140.50

Duration of the lease.

3140.60

Use of additional lands.

3140.70

Lands within the National Park System.

Subpart 3141—Leasing in Special Tar Sand Areas

3141.1

Purpose.

3141.3

Authority.

3141.5

Definitions.

3141.8

Other applicable regulations.

3141.10

General.

Prelease Exploration Within Special Tar Sand Areas

3141.21

Geophysical exploration.

3141.22

Exploration licenses.

3141.30

Land use plans.

Consultation

3141.41

Consultation with the Governor.

3141.42

Consultation with others.

Leasing Procedures

3141.51

Economic evaluation.

3141.52

Term of lease.

3141.53

Royalties and rentals.

3141.54

Lease size.

3141.55

Dating of lease.

Sale Procedures

3141.61

Initiation of competitive lease offering.

3141.62

Publication of a notice of competitive lease offering.

3141.63

Conduct of sales.

3141.64

Qualifications.

3141.65

Rejection of bid.

3141.66

Consideration of next highest bid.

3141.70

Award of lease.

Subpart 3142—Paying Quantities/Diligent Development for Combined Hydrocarbon and Tar Sand Leases

3142.1

Purpose.

3142.3

Authority.

3142.5

Definitions.

3142.10

Diligent development.

Minimum Production Levels

3142.21

Minimum production schedule.

3142.22

Advance royalties in lieu of production.

3142.30

Expiration.

PART 3140—LEASING IN SPECIAL TAR SAND AREAS

Authority: 30 U.S.C. 181 et seq.;30 U.S.C. 351-359; 43 U.S.C. 1701 et seq.; Pub. L. 97-78, 95 Stat. 1070; 42 U.S.C. 15801, unless otherwise noted.

Subpart 3140—Conversion of Existing Oil and Gas Leases and Valid Claims Based on Mineral Locations

§ 3140.1

Purpose.

The purpose of this subpart is to provide for the conversion of existing oil and gas leases and valid claims based on mineral locations within Special Tar Sand Areas to combined hydrocarbon leases.

§ 3140.3

Authority.

These regulations are issued under the authority of the Mineral Lands Leasing Act of February 25, 1920 (30 U.S.C. 181 et seq.), the Mineral Leasing Act for Acquired Lands (30 U.S.C. 351 et seq.), and the Combined Hydrocarbon Leasing Act of 1981 (Pub. L. 97-78).

§ 3140.5

Definitions.

As used in this subpart, the term:

Combined hydrocarbon lease means a lease issued in a Special Tar Sand Area for the removal of gas and nongaseous hydrocarbon substances other than coal, oil shale or gilsonite.

Complete plan of operations means a plan of operations that is in substantial compliance with the information requirements of 43 CFR part 3592 for both exploration plans and mining plans, as well as any additional information required in this part and under 43 CFR part 3593, as may be appropriate.

Owner of an oil and gas lease means all of the record title holders of an oil and gas lease.

Owner of a valid claim based on a mineral location means all parties appearing on the title records recognized as official under State law as having the right to sell or transfer any part of the mining claim, which was located within a Special Tar Sand Area prior to January 21, 1926, for any hydrocarbon resource, except coal, oil shale or gilsonite, leasable under the Combined Hydrocarbon Leasing Act.

Special Tar Sand Area means an area designated by the Department of the Interior's orders of November 20, 1980 (45 FR 76800), and January 21, 1981 (46 FR 6077) referred to in those orders as Designated Tar Sand Areas, as containing substantial deposits of tar sand.

Unitization means unitization as that term is defined in 43 CFR part 3180.

General Provisions

§ 3140.11

Existing rights.

(a) The owner of an oil and gas lease issued prior to November 16, 1981, or the owner of a valid claim based on a mineral location situated within a Special Tar Sand Area may convert that portion of the lease or claim so situated to a combined hydrocarbon lease, provided that such conversion is consistent with the provisions of this subpart. The application time period ended on November 15, 1983.

(b) Owners of oil and gas leases in Special Tar Sand Areas who elect not to convert their leases to a combined hydrocarbon lease do not acquire the rights to any hydrocarbon resource except oil and gas as those terms were defined prior to the enactment of the Combined Hydrocarbon Leasing Act of 1981. The failure to file an application to convert a valid claim based on a mineral location within the time herein provided will have no effect on the validity of the mining claim nor the right to maintain that claim.

§ 3140.12

Notice of intent to convert.

(a) Owners of oil and gas leases in Special Tar Sand Areas which were scheduled to expire prior to November 15, 1983, could have preserved the right to convert their leases to combined hydrocarbon leases by filing a Notice of Intent to Convert with the BLM Utah State Office.

(b) A letter, submitted by the lessee, notifying the BLM of the lessee's intention to submit a plan of operations constituted a notice of intent to convert a lease. The Notice of Intent must have contained the lease number.

(c) The Notice of Intent must have been filed prior to the expiration date of the lease. The notice would have preserved the lessee's conversion rights only until November 15, 1983.

§ 3140.13

Exploration plans.

(a) The authorized officer may grant permission to holders of existing oil and gas leases to gather information to develop, perfect, complete or amend a plan of operations required for conversion upon the approval of the authorized officer of an exploration plan developed in accordance with 43 CFR 3592.1.

(b) The approval of an exploration plan in units of the National Park System requires the consent of the Regional Director of the National Park Service in accordance with § 3140.70.

(c) The filing of an exploration plan alone will be insufficient to meet the requirements of a complete plan of operations as set forth in § 3140.23.

§ 3140.14

Other provisions.

(a) A combined hydrocarbon lease will be for no more than 5,760 acres. Acreage held under a combined hydrocarbon lease in a Special Tar Sand Area is not chargeable to State oil and gas limitations allowable in 43 CFR 3101.21 or 3101.22.

(b) The annual rental rate for all combined hydrocarbon leases will be as stated in the lease, and the annual rental for all new leases will be as specified in 43 CFR 3103.1. The rental rate for a combined hydrocarbon lease will be payable upon conversion and annually, in advance, thereafter.

(c)(1) The royalty rate for a combined hydrocarbon lease converted from an oil and gas lease will be that provided for in the original oil and gas lease.

(2) The royalty rate for a combined hydrocarbon lease converted from a valid claim based on a mineral location will be 16.67 percent.

(3) A reduction of royalties may be granted either as provided in § 3103.40 or, at the request of the lessee and upon a review of information provided by the lessee, prior to commencement of commercial operations if the purpose of the request is to promote development and the maximum production of tar sand. A reduction of royalties for the tar sand will not apply to the oil and gas resource. A reduction of royalties for the oil and gas will not apply to the tar sand resource.

(d)(1) Existing oil and gas leases and valid claims based on mineral locations may be unitized prior to or after the lease or claim has been converted to a combined hydrocarbon lease. The requirements of 43 CFR part 3180 will provide the procedures and general guidelines for unitization of combined hydrocarbon leases. For leases within units of the National Park System, unitization requires the consent of the Regional Director of the National Park Service in accordance with § 3140.41(b).

(2) If the plan of operations submitted for conversion is designed to cover a unit, a fully executed unit agreement will be approved before the plan of operations applicable to the unit may be approved under § 3140.20. The proposed plan of operations and the proposed unit agreement may be reviewed concurrently. The approved unit agreement will be effective after the leases or claims subject to it are converted to combined hydrocarbon leases. The plan of operations will explain how and when each lease included in the unit operation will be developed.

(e) Except as provided for in this subpart, the regulations set out in 43 CFR part 3100 are applicable, as appropriate, to all combined hydrocarbon leases issued under this subpart.

Applications

§ 3140.21

Forms.

No special form is required for a conversion application.

§ 3140.22

Who may apply.

Only owners of oil and gas leases issued within Special Tar Sands Areas, on or before November 16, 1981, and owners of valid claims based on mineral locations within Special Tar Sands Areas, are eligible to convert leases or claims to combined hydrocarbon leases in Special Tar Sands Areas.

§ 3140.23

Application requirements.

(a) The BLM stopped accepting conversion applications on November 15, 1983. The applicant must have submitted to the BLM Utah State Office, a written request for a combined hydrocarbon lease signed by the owner of the lease or valid claim which must be accompanied by three copies of a plan of operations which must meet the requirements of 43 CFR 3592.1 and which must have provided for reasonable protection of the environment and diligent development of the resources requiring enhanced recovery methods of development or mining.

(b) A plan of operations may be modified or amended before or after conversion of a lease or valid claim to reflect changes in technology, slippages in schedule beyond the control of the lessee, new information about the resource or the economic or environmental aspects of its development, changes to or initiation of applicable unit agreements or for other purposes. To obtain approval of a modification or amended plan, the applicant must submit a written statement of the proposed changes or supplements and the justification for the changes proposed. Any modifications will be in accordance with 43 CFR 3592.1(c). The approval of the modification or amendment is the responsibility of the authorized officer. Changes or modification to the plan of operations will have no effect on the primary term of the lease. The authorized officer will, prior to approving any amendment or modification, review the modification or amendment with the appropriate surface management agency. For leases within units of the National Park System, no amendment or modification will be approved without the consent of the Regional Director of the National Park Service in accordance with § 3140.70.

(c) The plan of operations may be for a single existing oil and gas lease or valid claim or for an area of proposed unit operation.

(d) The plan of operations must identify by lease number all Federal oil and gas leases proposed for conversion and identify valid claims proposed for conversion by the recordation number of the mining claim.

(e) The plan of operations must include any proposed designation of operator or proposed operating agreement.

(f) The plan of operations may include an exploration phase, if necessary, but it must include a development phase. Such a plan can be approved even though it may indicate work under the exploration phase is necessary to perfect the proposed plan for the development phase as long as the overall plan demonstrates reasonable protection of the environment and diligent development of the resources requiring enhanced recovery methods of mining.

(g)(1) Upon determination that the plan of operations is complete, the authorized officer will suspend the term of the Federal oil and gas lease(s) as of the date that the complete plan was filed until the plan is finally approved or rejected. Only the term of the oil and gas lease will be suspended, not any operation and production requirements thereunder.

(2) If the authorized officer determines that the plan of operations is not complete, the applicant will be notified that the plan is subject to rejection if not completed within the period specified in the notice.

(3) The authorized officer may request additional data after the plan of operations has been determined to be complete. This request for additional information will have no effect on the suspension of the running of the oil and gas lease.

Time Limitations

§ 3140.31

Conversion applications.

A plan of operations to convert an existing oil and gas lease or valid claim based on a mineral location to a combined hydrocarbon lease must have been filed on or before November 15, 1983, or prior to the expiration of the oil and gas lease, whichever was earlier, except as provided in § 3140.12.

§ 3140.32

Action on an application.

The authorized officer will take action on an application for conversion within 15 months of receipt of a proposed plan of operations.

Conversion

§ 3140.41

Approval of plan of operations (and unit and operating agreements).

(a) The owner of an oil and gas lease, or the owner of a valid claim based on a mineral location will have such lease or claim converted to a combined hydrocarbon lease when the plan of operations, filed under § 3140.23, is deemed acceptable and is approved by the authorized officer.

(b) The conversion of a lease within a unit of the National Park System will be approved only with the consent of the Regional Director of the National Park Service in accordance with § 3140.70.

(c) A plan of operations may not be approved in part but may be approved where it contains an appropriately staged plan of exploration and development operations.

§ 3140.42

Issuance of the combined hydrocarbon lease.

(a) After a plan of operations is found acceptable, and is approved, the authorized officer will prepare and submit to the owner, for execution, a combined hydrocarbon lease containing all appropriate terms and conditions, including any necessary stipulations that were part of the oil and gas lease being converted, as well as any additional stipulations, such as those required to ensure compliance with the plan of operations.

(b) The authorized officer will not sign the combined hydrocarbon lease until it has been executed by the conversion applicant and the lease or claim to be converted has been formally relinquished to the United States.

(c) The effective date of the combined hydrocarbon lease will be the first day of the month following the date that the authorized officer signs the lease.

(d) The authorized officer will issue one combined hydrocarbon lease to cover the existing contiguous oil and gas leases or valid claims based on mineral locations which have been approved for conversion within the special tar sand area.

§ 3140.50

Duration of the lease.

A combined hydrocarbon lease will be for a primary term of 10 years and for so long thereafter as oil or gas is produced in paying quantities. If the applicant withdraws the combined hydrocarbon lease application or the BLM denies the conversion application, the suspension on the oil and gas lease will be lifted and the term will be extended by the time remaining on the term of the lease.

§ 3140.60

Use of additional lands.

(a) The authorized officer may noncompetitively lease additional lands for ancillary facilities in a Special Tar Sand Area that are needed to support any operations necessary for the recovery of tar sand. Such uses include, but are not limited to, mill site or waste disposal. Application for a lease or permit to use additional lands must be filed under the provisions of 43 CFR part 2920 with the proper BLM office having jurisdiction of the lands. The application for additional lands may be filed at the time a plan of operations is filed.

(b) A lease for the use of additional lands will not be issued when the use can be authorized under 43 CFR parts 2800 and 2880. Such uses include, but are not limited to, reservoirs, pipelines, electrical generation systems, transmission lines, roads, and railroads.

(c) Within units of the National Park System, permits or leases for additional lands will only be issued by the National Park Service. Applications for such permits or leases must be filed with the Regional Director of the National Park Service.

§ 3140.70

Lands within the National Park System.

The BLM stopped accepting conversion applications on November 15, 1983. Conversions of existing oil and gas leases and valid claims based on mineral locations to combined hydrocarbon leases within units of the National Park System will be allowed only where mineral leasing is permitted by law and where the lands covered by the lease or claim proposed for conversion are open to mineral resource disposition in accordance with any applicable minerals management plan. (See 43 CFR 3100.3(h)(4)). In order to consent to any conversion or any subsequent development under a combined hydrocarbon lease requiring further approval, the Regional Director of the National Park Service must find that there will be no resulting significant adverse impacts on the resources and administration of such areas or on other contiguous units of the National Park System in accordance with 43 CFR 3109.20(b).

Subpart 3141—Leasing in Special Tar Sand Areas

§ 3141.1

Purpose.

The purpose of this subpart is to provide for the competitive leasing of lands and issuance of combined hydrocarbon leases, oil and gas leases, or tar sand leases within special tar sand areas.

§ 3141.3

Authority.

The regulations in this subpart are issued under the authority of the Mineral Leasing Act of February 25, 1920 (30 U.S.C. 181 et seq.), the Mineral Leasing Act for Acquired Lands (30 U.S.C. 351 et seq.), the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1701 et seq.), the Combined Hydrocarbon Leasing Act of 1981 (95 Stat. 1070), and the Energy Policy Act of 2005 (Pub. L. 109-58).

§ 3141. 5

Definitions.

As used in this subpart, the term:

Combined hydrocarbon lease means a lease issued in a Special Tar Sand Area for the removal of any gas and nongaseous hydrocarbon substance other than coal, oil shale or gilsonite.

Oil and gas lease means a lease issued in a Special Tar Sand Area for the exploration and development of oil and gas resources other than tar sand.

Special Tar Sand Area means an area designated by the Department of the Interior's Orders of November 20, 1980 (45 FR 76800), and January 21, 1981 (46 FR 6077), and referred to in those orders as Designated Tar Sand Areas, as containing substantial deposits of tar sand.

Tar sand means any consolidated or unconsolidated rock (other than coal, oil shale or gilsonite) that either:

(1) Contains a hydrocarbonaceous material with a gas-free viscosity, at original reservoir temperature greater than 10,000 centipoise, or

(2) contains a hydrocarbonaceous material and is produced by mining or quarrying.

Tar sand lease means a lease issued in a Special Tar Sand area exclusively for the exploration for and extraction of tar sand.

§ 3141.8

Other applicable regulations.

(a) Combined hydrocarbon leases. (1) The following provisions of 43 CFR part 3100, as they relate to competitive leasing, apply to the issuance and administration of combined hydrocarbon leases issued under this part.

(i) All of 43 CFR subpart 3100;

(ii) All of 43 CFR subpart 3101, with the exception of §§ 3101.21, 3101.22, 3101.23, 3101.24, and 3101.25;

(iii) All of 43 CFR subpart 3102;

(iv) All of 43 CFR subpart 3103, with the exception of §§ 3103.21, and 3103.31(a), (b), and (c);

(v) All of 43 CFR subpart 3104;

(vi) All of 43 CFR subpart 3105;

(vii) All of 43 CFR subpart 3106, with the exception of § 3106.10(j);

(viii) All of 43 CFR subpart 3107;

(ix) All of 43 CFR subpart 3108; and

(x) All of 43 CFR subpart 3109, with special emphasis on § 3109.20(b).

(2) Prior to commencement of operations, the lessee must develop either a plan of operations as described in 43 CFR 3592.1 which ensures reasonable protection of the environment or file an application for a permit to drill as described in 43 CFR part 3160, whichever is appropriate.

(3) The provisions of 43 CFR part 3180 will serve as general guidance to the administration of combined hydrocarbon leases issued under this part to the extent they may be included in unit or cooperative agreements.

(b) Oil and gas leases. (1) All of the provisions of 43 CFR parts 3100, and 3120 apply to the issuance and administration of oil and gas leases issued under this part.

(2) All of the provisions of 43 CFR parts 3160 and 3170 apply to operations on an oil and gas lease issued under this part.

(3) The provisions of 43 CFR part 3180 apply to the administration of oil and gas leases issued under this part.

(c) Tar sand leases. (1) The following provisions of 43 CFR part 3100, as they relate to competitive leasing, apply to the issuance of tar sand leases issued under this part.

(i) All of 43 CFR subpart 3102;

(ii) All of 43 CFR subpart 3103 with the exception of §§ 3103.21, 3103.22(d), 3103.31, and 3103.32;

(iii) All of 43 CFR 3120.50; and

(iv) All of 43 CFR 3120.60.

(2) Prior to commencement of operations, the lessee must develop a plan of operations as described in 43 CFR 3592.1 which ensures reasonable protection of the environment.

§ 3141.10

General.

(a) Combined hydrocarbons or tar sands within a Special Tar Sand Area will be leased only by competitive bonus bidding.

(b) Oil and gas within a Special Tar Sand Area will be leased by competitive bonus bidding as described in 43 CFR part 3120.

(c) The authorized officer may issue either combined hydrocarbon leases, or oil and gas leases for oil and gas within such areas.

(d) The rights to explore for or develop tar sand deposits in a Special Tar Sand Area may be acquired through either a combined hydrocarbon lease or a tar sand lease.

(e) An oil and gas lease in a Special Tar Sand Area does not include the rights to explore for or develop tar sand.

(f) A tar sand lease in a Special Tar Sand Area does not include the rights to explore for or develop oil and gas.

(g) The minimum acceptable bid for a lease issued for tar sand will be as specified in § 3103.1 of this chapter.

(h) The acreage of combined hydrocarbon leases or tar sand leases held within a Special Tar Sand Area will not be charged against acreage limitations for the holding of oil and gas leases as provided in 43 CFR 3101.21.

(i)(1) The authorized officer may noncompetitively lease additional lands for ancillary facilities in a Special Tar Sand Area that are shown by an applicant to be needed to support any operations necessary for the recovery of tar sand. Such uses include, but are not limited to, mill siting or waste disposal. An application for a lease or permit to use additional lands must be filed under the provisions of 43 CFR part 2920 with the proper BLM office having jurisdiction of the lands. The application for additional lands may be filed at the time a plan of operations is filed.

(2) A lease for the use of additional lands will not be issued under this part when the use can be authorized under 43 CFR part 2800. Such uses include, but are not limited to, reservoirs, pipelines, electrical generation systems, transmission lines, roads and railroads.

(3) Within units of the National Park System, permits or leases for additional lands for any purpose will be issued only by the National Park Service. Applications for such permits or leases must be filed with the Regional Director of the National Park Service.

Prelease Exploration Within Special Tar Sand Areas

§ 3141.21

Geophysical exploration.

Geophysical exploration in Special Tar Sand Areas will be governed by 43 CFR part 3150. Information obtained under a permit must be made available to the BLM upon request.

§ 3141.22

Exploration licenses.

(a) Any person(s) responsible and qualified to hold a lease under the provisions of 43 CFR subpart 3102 and this subpart may obtain an exploration license to conduct core drilling and other exploration activities to collect geologic, environmental and other data concerning tar sand resources only on lands, the surface of which are under the jurisdiction of the BLM, within or adjacent to a Special Tar Sand Area. The application for such a license must be submitted to the proper BLM office having jurisdiction over the lands. No drilling for oil or gas will be allowed under an exploration license issued under this subpart. No specific form is required for an application for an exploration license.

(b) The application for an exploration license will be subject to the following requirements:

(1) Each application must contain the name and address of the applicant(s);

(2) Each application must be accompanied by a nonrefundable filing fee based on the coal exploration license application fee found in the fee schedule in § 3000.120 of this chapter;

(3) Each application must contain a description of the lands covered by the application according to section, township and range in accordance with the official survey;

(4) Each application must include an exploration plan which complies with the requirements of 43 CFR 4392.1(a); and

(5) An application must cover no more than 5,760 acres, which will be as compact as possible. The authorized officer may grant an exploration license covering more than 5,760 acres only if the application contains a justification for an exception to the normal limitation.

(c) The authorized officer may, if the authorized officer determines it necessary to avoid impacts resulting from duplication of exploration activities, require applicants for exploration licenses to provide an opportunity for other parties to participate in exploration under the license on a pro rata cost sharing basis. If joint participation is determined necessary, it will be conducted according to the following:

(1) Immediately upon the notification of a determination that parties will be given an opportunity to participate in the exploration license, the applicant must publish a “Notice of Invitation,” approved by the authorized officer, once every week for 2 consecutive weeks in at least one newspaper of general circulation in the area where the lands covered by the exploration license are situated. This notice must contain an invitation to the public to participate in the exploration license on a pro rata cost sharing basis. Copies of the “Notice of Invitation” must be filed with the authorized officer at the time of publication by the applicant for posting in the proper BLM office having jurisdiction over the lands covered by the application for at least 30 days prior to the issuance of the exploration license.

(2) Any person seeking to participate in the exploration program described in the Notice of Invitation must notify the authorized officer and the applicant in writing of such intention within 30 days after posting in the proper BLM office having jurisdiction over the lands covered by the Notice of Invitation. The authorized officer may require modification of the original exploration plan to accommodate the legitimate exploration needs of the person(s) seeking to participate and to avoid the duplication of exploration activities in the same area, or that the person(s) should file a separate application for an exploration license.

(3) An application to conduct exploration which could have been conducted under an existing or recent exploration license issued under this paragraph may be rejected.

(d) The authorized officer may accept or reject an exploration license application. An exploration license will become effective on the date specified by the authorized officer as the date when exploration activities may begin. The exploration plan approved by the BLM will be attached and made a part of each exploration license.

(e) An exploration license will be subject to these terms and conditions:

(1) The license will be for a term of not more than 2 years;

(2) The annual rental rate for an exploration license will be as stated in the license;

(3) The licensee must provide a bond in an amount determined by the authorized officer, but not less than $5,000. The authorized officer may accept bonds furnished under 43 CFR subpart 3104, if adequate. The period of liability under the bond will be terminated only after the authorized officer determines that the terms and conditions of the license, the exploration plan and the regulations have been met;

(4) The licensee must provide to the BLM, upon request, all required information obtained under the license. Any information provided will be treated as confidential and proprietary, if appropriate, at the request of the licensee, and will not be made public until the areas involved have been leased or if the BLM determines that public access to the data will not damage the competitive position of the licensee.

(5) Operations conducted under a license will not unreasonably interfere with or endanger any other lawful activity on the same lands, must not damage any improvements on the lands, and will not result in any substantial disturbance to the surface of the lands and their resources;

(6) The authorized officer will include in each license requirements and stipulations to protect the environment and associated natural resources, and to ensure reclamation of the land disturbed by exploration operations;

(7) When unforeseen conditions are encountered that could result in an action prohibited by paragraph (e)(5) of this section, or when warranted by geologic or other physical conditions, the authorized officer may adjust the terms and conditions of the exploration license and may direct adjustment in the exploration plan;

(8) The licensee may submit a request for modification of the exploration plan to the authorized officer. Any modification will be subject to the regulations in this section and the terms and conditions of the license. The authorized officer may approve the modification after any necessary adjustments to the terms and conditions of the license that are accepted in writing by the licensee; and

(9) The license will be subject to termination or suspension as provided in 43 CFR 2920.9-3.

§ 3141.30

Land use plans.

No lease will be issued under this subpart unless the lands have been included in a land use plan which meets the requirements under 43 CFR part 1600 or an approved Minerals Management Plan of the National Park Service. The decision to hold a lease sale and issue leases will be in conformance with the appropriate plan.

Consultation

§ 3141.41

Consultation with the Governor.

The Secretary will consult with the Governor of the State in which any tract proposed for sale is located. The Secretary will give the Governor 30 days to comment before determining whether to conduct a lease sale. The Secretary will seek the recommendations of the Governor of the State in which the lands proposed for lease are located as to whether or not to lease such lands and what alternative actions are available and what special conditions could be added to the proposed lease(s) to mitigate impacts. The Secretary will accept the recommendations of the Governor if the Secretary determines that they provide for a reasonable balance between the national interest and the State's interest. The Secretary will communicate to the Governor in writing and publish in the Federal Register the reasons for his/her determination to accept or reject such Governor's recommendations.

§ 3141.42

Consultation with others.

(a) Where the surface is administered by an agency other than the BLM, including lands patented or leased under the provisions of the Recreation and Public Purposes Act, as amended (43 U.S.C. 869 et seq.), all leasing under this subpart will be in accordance with the consultation requirements of 43 CFR subpart 3100.

(b) The issuance of combined hydrocarbon leases, oil and gas leases, and tar sand leases within special tar sand areas in units of the National Park System will be allowed only where mineral leasing is permitted by law and where the lands are open to mineral resource disposition in accordance with any applicable Minerals Management Plan. In order to consent to any issuance of a combined hydrocarbon lease, oil and gas lease, tar sand lease, or subsequent development of hydrocarbon resources within a unit of the National Park System, the Regional Director of the National Park Service will find that there will be no resulting significant adverse impacts to the resources and administration of the unit or other contiguous units of the National Park System in accordance with 43 CFR 3109.20(b).

Leasing Procedures

§ 3141.51

Economic evaluation.

Prior to any lease sale for a combined hydrocarbon lease, the authorized officer will request an economic evaluation of the total hydrocarbon resource on each proposed lease tract exclusive of coal, oil shale, or gilsonite.

§ 3141.52

Term of lease.

(a) Oil and gas leases in special tar sand areas will have a primary term of 10 years and will remain in effect so long thereafter as oil or gas is produced in paying quantities.

(b) Tar Sand leases will have a primary term of 10 years and will remain in effect so long thereafter as tar sand is produced in paying quantities.

§ 3141.53

Royalties and rentals.

(a) The royalty rate on all combined hydrocarbon leases or tar sand leases is 16.67 percent of the value of production removed or sold from a lease. The ONRR will be responsible for collecting and administering royalties.

(b) The lessee may request the Secretary to reduce the royalty rate applicable to a tar sand lease prior to commencement of commercial operations in order to promote development and maximum production of the tar sand resource in accordance with procedures established by the BLM for oil shale leases and may request a reduction in the royalty after commencement of commercial operations in accordance with 43 CFR 3103.41.

(c) The annual rental rate for a combined hydrocarbon lease will be as stated in the lease.

(d) The annual rental rate for a tar sand lease will be as stated in the lease.

(e) Except as explained in paragraphs (a) through (c) of this section, all other provisions of 43 CFR 3103.20 and 3103.30 apply to combined hydrocarbon leasing.

§ 3141.54

Lease size.

Combined hydrocarbon leases or tar sand leases in Special Tar Sand Areas will not exceed 5,760 acres.

§ 3141.55

Dating of lease.

A combined hydrocarbon lease will be effective as of the first day of the month following the date the lease is signed on behalf of the United States, except where a prior written request is made, a lease may be made effective on the first of the month in which the lease is signed.

Sale Procedures

§ 3141.61

Initiation of competitive lease offering.

The BLM may, on its own motion, offer lands through competitive bidding. A request or expression(s) of interest in tract(s) for competitive lease offerings must be submitted in writing to the proper BLM office.

§ 3141.62

Publication of a notice of competitive lease offering.

Combined Hydrocarbon Leases, Tar Sand Leases or Oil and Gas Leases. At least 45 days prior to conducting a competitive auction, lands to be offered for a competitive lease sale, as in a Notice of Competitive Lease Sale, will be made available to the public. The notice will specify the time and place of sale; the manner in which the bids may be submitted; the description of the lands; the terms and conditions of the lease, including the royalty and rental rates; the amount of the minimum bid; and will state that the terms and conditions of the leases are available for inspection and designate the proper BLM office where bid forms may be obtained.

§ 3141.63

Conduct of sales.

(a) Oil and gas leases. Lease sales for oil and gas leases will be conducted using the procedures for oil and gas leases in 43 CFR 3120.60.

(b) Combined hydrocarbon leases and tar sand leases. (1) Parcels will be offered by competitive auction.

(2) The winning bid will be the highest bid by a responsible and qualified bidder, equal to the minimum bonus bid amount as specified in § 3103.1 of this chapter or for hydrocarbon leases, the minimum bonus bid amount determined under § 3141.51, whichever is larger.

(3) Payments must be made as provided in 43 CFR 3120.62.

§ 3141.64

Qualifications.

Each bidder must submit with the bid a statement over the bidder's signature with respect to compliance with 43 CFR subpart 3102.

§ 3141.65

Rejection of bid.

If the high bid is rejected for failure by the successful bidder to execute the lease forms and pay the balance of the bonus bid, or otherwise to comply with the regulations of this subpart, the minimum bonus payment accompanying the bid will be forfeited.

§ 3141.66

Consideration of next highest bid.

The Department reserves the right to accept the next highest bid if the highest bid is rejected. In no event will an offer be made to the next highest bidder if the difference between that bid and the bid of the rejected successful bidder is greater than the minimum bonus payment forfeited by the rejected successful bidder.

§ 3141.70

Award of lease.

After determining the highest responsible and qualified bidder, the authorized officer will send the lease on a form approved by the Director, and any necessary stipulations, to the successful bidder. The successful bidder must, not later than the 30th calendar day after receipt of the lease, execute the lease, pay the balance of the bid and the first year's rental, and file a bond as required in 43 CFR subpart 3104. Failure to comply with this section will result in rejection of the lease.

Subpart 3142—Paying Quantities/Diligent Development for Combined Hydrocarbon and Tar Sand Leases

§ 3142.1

Purpose.

This subpart provides definitions and procedures for meeting the production in paying quantities and the diligent development requirements for tar sand in all combined hydrocarbon leases and tar sand leases.

§ 3142.3

Authority.

These regulations are issued under the authority of the Mineral Leasing Act of 1920, as amended and supplemented (30 U.S.C. 181 et seq.), the Mineral Leasing Act for Acquired Lands (30 U.S.C. 351-359), the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1701 et seq.) and the Combined Hydrocarbon Leasing Act of 1981 (95 Stat. 1070).

§ 3142.5

Definitions.

As used in this subpart, the term:

Production in paying quantities for combined hydrocarbon leases means:

(1) Production, in compliance with an approved plan of operations and by nonconventional methods, of oil and gas which can be marketed; or

(2) Production of oil or gas by conventional methods as the term is currently used in 43 CFR part 3160.

Production in paying quantities for oil and gas leases means production of oil or gas by conventional methods that meets the definition of “production in paying quantities” in 43 CFR 3160.0-5.

Production in paying quantities for tar sand leases means production of shale oil quantities that provide a positive return after all costs of production have been met, including the amortized costs of the capital investment.

§ 3142.10

Diligent development.

A lessee will have met its diligent development obligation if:

(a) The lessee is conducting activity on the lease in accordance with an approved plan of operations; and

(b) The lessee files with the authorized officer, not later than the end of the eighth lease year, a supplement to the approved plan of operations which must include the estimated recoverable tar sand reserves and a detailed development plan for the next stage of operations;

(c) The lessee has achieved production in paying quantities, as that term is defined in § 3142.5(a), by the end of the primary term; and

(d) The lessee annually produces the minimum amount of tar sand established by the authorized officer under the lease in the minimum production schedule which will be made part of the plan of operations or pays annually advance royalty in lieu of this minimum production.

Minimum Production Levels

§ 3142.21

Minimum production schedule.

(a) Upon receipt of the supplement to the plan of operations described in § 3142.10(b), the authorized officer will examine the information furnished by the lessee and determine if the estimate of the recoverable tar sand reserves is adequate and reasonable. In making this determination, the authorized officer may request, and the lessee must furnish, any information that is the basis of the lessee's estimate of the recoverable tar sand reserves. As part of the authorized officer's determination that the estimate of the recoverable tar sand reserves is adequate and reasonable, the authorized officer may consider, but is not limited to, the following: ore grade, strip ratio, vertical and horizontal continuity, extract process recoverability, and proven or unproven status of extraction technology, terrain, environmental mitigation factors, marketability of products and capital operations costs. The authorized officer will then establish as soon as possible, but prior to the beginning of the eleventh year, based upon the estimate of the recoverable tar sand reserves, a minimum annual tar sand production schedule for the lease or unit operations which will start in the eleventh year of the lease. This minimum production level will escalate in equal annual increments to a maximum of 1 percent of the estimated recoverable tar sand reserves in the twentieth year of the lease and remain at 1 percent each year thereafter.

(b) The minimum annual tar sand production schedule for the lease or unit operations will be set at a level for paying quantities. If the operator or lessee cannot establish production in paying quantities, the lease will terminate at the end of the lease's primary term.

§ 3142.22

Advance royalties in lieu of production.

(a) Failure to meet the minimum annual tar sand production schedule level in any year will result in the assessment of an advance royalty in lieu of production which will be credited to future production royalty assessments applicable to the lease or unit.

(b) If there is no production during the lease year, and the lessee has reason to believe that there will be no production during the remainder of the lease year, the lessee must submit to the authorized officer a request for suspension of production at least 90 days prior to the end of that lease year and a payment sufficient to cover any advance royalty due and owing as a result of the failure to produce. Upon receipt of the request for suspension of production and the accompanying payment, the authorized officer may approve a suspension of production for that lease year and the lease will not expire during that year for lack of production.

(c) If there is production on the lease or unit during the lease year, but such production fails to meet the minimum production schedule required by the plan of operations for that lease or unit, the lessee must pay an advance royalty within 60 days of the end of the lease year in an amount sufficient to cover the difference between such actual production and the production schedule required by the plan of operations for that lease or unit and the authorized officer may direct a suspension of production for those periods during which no production occurred.

§ 3142.30

Expiration.

Failure of the lessee to pay advance royalty within the time prescribed by the authorized officer, or failure of the lessee to comply with any other provisions of this subpart following the end of the primary term of the lease, will result in the automatic expiration of the lease as of the first of the month following notice to the lessee of its failure to comply. The lessee will remain subject to the requirement of applicable laws, regulations and lease terms which have not been met at the expiration of the lease.

PART 3150—ONSHORE OIL AND GAS GEOPHYSICAL EXPLORATION

10. The authority citation for part 3150 continues to read as follows:

Authority: 16 U.S.C. 3150(b) and 668dd; 30 U.S.C. 189 and 359; 42 U.S.C. 6508; 43 U.S.C. 1201, 1732(b), 1733, 1734, 1740.

11. Revise subpart 3151 to read as follows:

Subpart 3151—Exploration Outside of Alaska

3151.10

Notice of intent to conduct oil and gas geophysical exploration operations.

3151.20

Notice of completion of operations.

3151.30

Collection and submission of data.

Subpart 3151—Exploration Outside of Alaska

§ 3151.10

Notice of intent to conduct oil and gas geophysical exploration operations.

Parties wishing to conduct oil and gas geophysical exploration outside of the State of Alaska must file a Notice of Intent to Conduct Oil and Gas Exploration Operations, referred to herein as a notice of intent. The notice of intent must include the filing fee required by 43 CFR 3000.120 and must be filed with the authorized officer of the proper BLM office on the form approved by the Director. Within 5 business days of the filing date, the authorized officer will process the notice of intent and notify the operator of practices and procedures to be followed. If the notice of intent cannot be processed within 5 business days of the filing date, the authorized officer will promptly notify the operator as to when processing will be completed, giving the reason for the delay. The operator must, within 5 business days of the filing date, or such other time as may be convenient for the operator, participate in a field inspection if requested by the authorized officer. Signing of the notice of intent by the operator will signify agreement to comply with the terms and conditions contained therein and in this part, and with all practices and procedures specified at any time by the authorized officer.

§ 3151.20

Notice of completion of operations.

Upon completion of exploration, the permittee must file with the District Manager a Notice of Completion of Oil and Gas Exploration Operations. Within 30 days after this filing, the authorized officer will notify the permittee whether rehabilitation of the lands is satisfactory or whether additional rehabilitation is necessary, specifying the nature and extent of actions to be taken by the permittee.

§ 3151.30

Collection and submission of data.

(a) The permittee must submit to the authorized officer all data and information obtained in carrying out the exploration plan.

(b) All information submitted under this section is presumptively confidential business information and is subject to 43 CFR part 2, which sets forth the rules of the Department of the Interior relating to public availability of information contained in Departmental records, as provided at § 3100.40 of this chapter.

PART 3160—ONSHORE OIL AND GAS OPERATIONS

12. The authority citation for part 3160 continues to read as follows:

Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and 1751; 43 U.S.C. 1732(b), 1733, 1740; and Sec. 107, Pub. L. 114-74, 129 Stat. 599, unless otherwise noted.

13. Revise § 3160.0-5 to read as follows:

§ 3160.0-5

Definitions.

As used in this part, the term:

Authorized representative means any entity or individual authorized by the Secretary to perform duties by cooperative agreement, delegation or contract.

Drainage means the migration of hydrocarbons, inert gases (other than helium), or associated resources caused by production from other wells.

Federal lands means all lands and interests in lands owned by the United States which are subject to the mineral leasing laws, including mineral resources or mineral estates reserved to the United States in the conveyance of a surface or nonmineral estate.

Fresh water means water containing not more than 1,000 ppm of total dissolved solids, provided that such water does not contain objectionable levels of any constituent that is toxic to animal, plant or aquatic life, unless otherwise specified in applicable notices or orders.

Knowingly or willfully means a violation that constitutes the voluntary or conscious performance of an act that is prohibited or the voluntary or conscious failure to perform an act or duty that is required. It does not include performances or failures to perform that are honest mistakes or merely inadvertent. It includes, but does not require, performances or failures to perform that result from a criminal or evil intent or from a specific intent to violate the law. The knowing or willful nature of conduct may be established by plain indifference to or reckless disregard of the requirements of the law, regulations, orders, or terms of the lease. A consistent pattern of performance or failure to perform also may be sufficient to establish the knowing or willful nature of the conduct, where such consistent pattern is neither the result of honest mistakes or mere inadvertency. Conduct that is otherwise regarded as being knowing or willful is rendered neither accidental nor mitigated in character by the belief that the conduct is reasonable or legal.

Lease means any contract, profit-share arrangement, joint venture or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, extraction of, or removal of oil or gas.

Lease site means any lands, including the surface of a severed mineral estate, on which exploration for, or extraction and removal of, oil or gas is authorized under a lease.

Lessee means any person holding record title or owning operating rights in a lease issued or approved by the United States.

Lessor means the party to a lease who holds legal or beneficial title to the mineral estate in the leased lands.

Major violation means noncompliance that causes or threatens immediate, substantial, and adverse impacts on public health and safety, the environment, production accountability, or royalty income.

Maximum ultimate economic recovery means the recovery of oil and gas from leased lands which a prudent operator could be expected to make from that field or reservoir given existing knowledge of reservoir and other pertinent facts and utilizing common industry practices for primary, secondary, or tertiary recovery operations.

Minor violation means noncompliance that does not rise to the level of a major violation.

New or resumed production under section 102(b)(3) of the Federal Oil and Gas Royalty Management Act means the date on which a well commences production, or resumes production after having been off production for more than 90 days, and is to be construed as follows:

(1) For an oil well, the date on which liquid hydrocarbons are first sold or shipped from a temporary storage facility, such as a test tank, or the date on which liquid hydrocarbons are first produced into a permanent storage facility, whichever first occurs; and

(2) For a gas well, the date on which gas is first measured through sales metering facilities or the date on which associated liquid hydrocarbons are first sold or shipped from a temporary storage facility, whichever first occurs.

Notice to lessees and operators (NTL) means a written notice issued by the authorized officer. NTLs implement the regulations in this part and operating orders, and serve as instructions on specific item(s) of importance within a State, District, or Area.

Onshore oil and gas order means a formal numbered order issued by the Director that implements and supplements the regulations in this part.

Operating rights owner means a person who owns operating rights in a lease. A record title holder may also be an operating rights owner in a lease if it did not transfer all of its operating rights.

Operator means 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.

Paying well means a well that is capable of producing oil or gas of sufficient value to exceed direct operating costs and the costs of lease rentals or minimum royalty.

Person means any individual, firm, corporation, association, partnership, consortium or joint venture.

Production in paying quantities means production from a lease of oil and/or gas of sufficient value to exceed direct operating costs and the cost of lease rentals or minimum royalties.

Protective well means a well drilled or modified to prevent or offset drainage of oil and gas resources from its Federal or Indian lease.

Record title holder means the person(s) to whom the BLM or an Indian lessor issued a lease or approved the assignment of record title in a lease.

Shut-in well means a nonoperational well that can physically and mechanically operate by opening valves or activating existing equipment.

Superintendent means the superintendent of an Indian Agency, or other officer authorized to act in matters of record and law with respect to oil and gas leases on restricted Indian lands.

Surface use plan of operations means a plan for surface use, disturbance, and reclamation.

Temporarily abandoned well means a nonoperational well that is not physically or mechanically capable of production or injection without additional equipment or without servicing the well, but that may have future beneficial use.

Waste of oil or gas means any act or failure to act by the operator that is not sanctioned by the authorized officer as necessary for proper development and production and which results in:

(1) A reduction in the quantity or quality of oil and gas ultimately producible from a reservoir under prudent and proper operations; or

(2) Avoidable surface loss of oil or gas.

14. Revise § 3162.3-4 to read as follows:

§ 3162.3-4

Well abandonment.

(a) The operator must promptly plug and abandon, in accordance with a plan first approved in writing or prescribed by the authorized officer, each newly completed or recompleted well in which oil or gas is not encountered in paying quantities or which, after being completed as a producing well, is demonstrated to the satisfaction of the authorized officer to be no longer capable of producing oil or gas in paying quantities, unless the authorized officer approves the use of the well as a service well for injection to recover additional oil or gas or for subsurface disposal of produced water. In the case of a newly drilled or recompleted well, the approval to abandon may be written or oral with written confirmation.

(b) Completion of a well as plugged and abandoned may also include conditioning the well as a water supply source for lease operations or for use by the surface owner or appropriate Government Agency, when authorized by the authorized officer. All costs over and above the normal plugging and abandonment expense will be paid by the party accepting the water well.

(c) Upon the removal of drilling or production equipment from the well site which is to be permanently abandoned, the surface of the lands disturbed in connection with the conduct of operations must be reclaimed in accordance with a plan first approved or prescribed by the authorized officer.

(d) Operators of temporarily abandoned wells must:

(1) Receive prior approval from the authorized officer for any well temporarily abandoned for more than 30 days. The authorized officer may authorize a delay in the permanent abandonment of a well for a period of up to 1 year. The operator must provide:

(i) Adequate and detailed justification for the temporary abandonment;

(ii) Verification of the mechanical integrity of the well; and

(iii) Isolate the completed interval(s) prior to temporary abandonment.

(2) Receive prior approval from the authorized officer for any additional delays to permanently abandon a well beyond 1 year. The authorized officer may authorize additional delays, none of which may exceed an additional 1-year period. Each request for additional delay must provide adequate and detailed justification for continued temporary abandonment.

(3) Within 4 years of temporary abandonment of a well, complete one of the following actions:

(i) Permanently abandon the well;

(ii) Resume production in paying quantities or commence using the well for injection or disposal;

(iii) Provide the authorized officer with a detailed plan and timeline for future beneficial use of the well. If the authorized officer determines that there is a legitimate future beneficial use for the well, the officer may allow the operator to delay permanent abandonment by 1 additional year. The authorized officer may grant additional delays in 1-year increments, provided that the operator confirms the future beneficial use of the well and is making verifiable progress on returning the well to a beneficial use.

(e) Operators of shut-in wells must:

(1) Notify the authorized officer of the well's shut-in status, if the well will be shut-in for 90 or more consecutive days, and provide the date the well was shut-in within 90 days of well shut-in;

(2) Within 3 years of well shut-in, provide the authorized officer with verification of the mechanical integrity of the well and confirmation that the well remains capable of producing in paying quantities; and

(3) Within 4 years of well shut-in, complete one of the following actions:

(i) Permanently abandon the well;

(ii) Resume production in paying quantities; or

(iii) Provide the authorized officer with a detailed plan and timeline for future beneficial use of the well. If the authorized officer determines that there is a legitimate future beneficial use for the well, the officer may allow the operator to delay permanent abandonment by 1 year. The authorized officer may grant additional delays in 1-year increments, provided that the operator confirms the future beneficial use of the well and is making verifiable progress on returning the well to a beneficial use.

(f) All wells that are temporarily abandoned or shut-in must have mechanical integrity verified as required in paragraphs (d)(1) and (e)(2) of this section and must ensure that mechanical integrity is verified every 3 years thereafter. The operator must submit the results of each verification of mechanical integrity to the authorized officer within 30 days of the mechanical integrity test.

15. Revise § 3164.1 to read as follows:

§ 3164.1

Onshore Oil and Gas Orders.

(a) The Director is authorized to issue Onshore Oil and Gas Orders when necessary to implement and supplement the regulations in the part. All orders will be published in final form in the Federal Register .

(b) These Orders are binding on operating rights owners and operators, as appropriate, of Federal and restricted Indian oil and gas leases which have been, or may hereafter be, issued. There are no current Onshore Oil and Gas Orders currently in effect.

Note: Numbers to be assigned sequentially by the Washington Office as proposed Orders are prepared for publication.

16. Revise § 3165.1 to read as follows:

§ 3165.1

Relief from operating and/or producing requirements.

(a) Applications for relief from either the operating or the producing requirements of a lease, or both, must be filed with the authorized officer, and must include a full statement of the circumstances that render such relief necessary.

(b) The authorized officer will act on applications submitted for a suspension of operations or production, or both, filed pursuant to 43 CFR 3103.42. The application for suspension must be filed with the authorized officer prior to the expiration date of the lease; must be executed by all operating rights owners or by the operator on behalf of the operating rights owners; and must include a full statement of the circumstances that makes such relief necessary.

(c) The authorized officer will not approve an application for a suspension of a lease where the applicant only cites, as the basis for the suspension, a pending application for permit to drill filed less than 90 calendar days prior to the expiration date of the lease.

(d) If approved, a suspension of operations and production will be effective on the first of the month in which the completed application was filed or the date specified by the authorized officer in the approval. Approved suspensions will not exceed 1 year. If the circumstances warrant all operating rights owners, or the operator on behalf of the operating rights owners, may submit a request to extend the suspension prior to the end of the suspension.

(e) BLM-directed suspensions may exceed 1 year.

(f) Suspensions will lift when the basis provided for the suspension no longer exists, when lifting the suspension is in the public interest, or as otherwise stated by the authorized officer in the approval letter.

PART 3170—ONSHORE OIL AND GAS PRODUCTION

17. The authority citation for part 3170 continues to read as follows:

Authority: 25 U.S.C. 396d and 2107; 30 U.S.C. 189, 306, 359, and 1751; and 43 U.S.C. 1732(b), 1733, and 1740.

18. Revise § 3171.6 to read as follows:

§ 3171.6

Components of a complete APD package.

Operators are encouraged to consider and incorporate Best Management Practices into their APDs because Best Management Practices can result in reduced processing times and reduced number of Conditions of Approval. An APD package must include the following information that will be reviewed by technical specialists of the appropriate agencies to determine the technical adequacy of the package:

(a) A completed Form 3160-3; and

(b) A well plat. Operators must include in the APD package a well plat and geospatial database prepared by a registered surveyor depicting the proposed location of the well and identifying the points of control and datum used to establish the section lines or metes and bounds. The purpose of this plat is to ensure that operations are within the boundaries of the lease or agreement and that the depiction of these operations is accurately recorded both as to location (latitude and longitude) and in relation to the surrounding lease or agreement boundaries (public land survey corner and boundary ties). The registered surveyor should coordinate with the cadastral survey division of the appropriate BLM state office, particularly where the lands have not been surveyed under the Public Land Survey System.

(1) The plat and geospatial database must describe the location of operations in:

(i) Geographical coordinates generated by an electronic navigation system, and document the datum referenced to generate these coordinates; and

(ii) In feet and direction from the nearest two adjacent section lines, or, if not within the Rectangular Survey System, the nearest two adjacent property lines, generated from the BLM's current Geographic Coordinate Data Base.

(2) The surveyor who prepared the plat must sign it, certifying that the location has been staked on the ground as shown on the plat.

(3) Surveying and staking are necessary casual uses, typically involving negligible surface disturbance. The operator is responsible for making access arrangements with the appropriate Surface Managing Agency (other than the BLM and the FS) or private surface owner. On tribal or allotted lands, the operator must contact the appropriate office of the BIA to make access arrangements with the Indian surface owners. In the event that not all of the Indian owners consent or may be located, but a majority of those who can be located consent, or the owners of interests are so numerous that it would be impracticable to obtain their consent and the BIA finds that the issuance of the APD will cause no substantive injury to the land or any owner thereof, the BIA may approve access. Typical off-road vehicular use, when conducted in conjunction with these activities, is a necessary action for obtaining a permit and may be done without advance approval from the Surface Managing Agency, except for:

(i) Lands administered by the Department of Defense;

(ii) Other lands used for military purposes;

(iii) Indian lands; or

(iv) Where more than negligible surface disturbance is likely to occur or is otherwise prohibited.

(4) No entry on split estate lands for surveying and staking should occur without the operator first making a good faith effort to notify the surface owner. Also, operators are encouraged to notify the BLM or the FS, as appropriate, before entering private lands to stake for Federal mineral estate locations.

19. Revise § 3171.14 to read as follows:

§ 3171.14

Valid Period of Approved APD.

(a) For APDs approved after June 22, 2024, an APD approval is valid for 3 years from the date that it is approved, or until lease expiration, whichever occurs first.

(b) Notwithstanding paragraph (a) of this section, if an APD approval expires by reason other than lease expiration, the APD approval shall remain valid if the operator or lessee:

(1) Has drilled the well to the approximate total measured depth in the approved APD, including wells drilled to the approximate total measured depth and not yet completed;

(2) Is drilling the well with a rig capable of drilling the well to the proposed total measured depth in the approved APD; or

(3) Has set the surface casing for the well and has submitted a plan, approved by the BLM prior to expiration of the APD approval, for continuously drilling the well to reach the proposed total measured depth in the approved APD. The plan must include the timeframe for continuously drilling and completing the well and any extenuating circumstances that may delay the continuous drilling and completion of the well.

(c) If, upon expiration of the approved APD, the operator created surface disturbance or began drilling the well under the approved APD, the operator or lessee must either comply with all applicable plugging, abandonment, and reclamation requirements or submit a new APD covering the existing disturbance.

(d) The operator is responsible for reclaiming any surface disturbance that resulted from its actions, even if a well was not drilled. Earthwork for reclamation must be completed within 6 months of APD expiration (weather permitting).

(e) The valid period for an approved APD on a lease suspended under subpart 3103 will be adjusted to account for the suspension. Beginning on the date the suspension is lifted, the valid period of the approved APD will be extended by the time that was remaining on the term of the approved APD on the effective date of the suspension.

PART 3180—ONSHORE OIL AND GAS UNIT AGREEMENTS: UNPROVEN AREAS

20. The authority citation for part 3180 continues to read as follows:

Authority: 30 U.S.C. 189.

§ 3181.1

[Amended]

21. Amend § 3181.1 by removing the phrase “§ 3186.1 of this title” wherever it appears and adding in its place the phrase “appendix A to this part”.

22. Revise § 3181.5 to read as follows:

§ 3181.5

Compensatory royalty payment for unleased Federal land.

The unit agreement submitted by the unit proponent for approval by the authorized officer will provide for payment to the Federal Government of the current royalty percentage for leases offered on onshore oil and gas lease sales on production that would be attributable to unleased Federal lands in a PA of the unit if said lands were leased and committed to the unit agreement. The value of production subject to compensatory royalty payment will be determined pursuant to 30 CFR part 206, provided that no additional royalty will be due on any production subject to compensatory royalty under this provision.

§ 3183.4

[Amended]

23. Amend § 3183.4 in paragraph (a) by removing the phrase “§ 3186.1 of this title” and adding in its place the phrase “appendix A to this part”.

§ 3186.1

[Redesignated as Appendix A to Part 3180]

24. Redesignate § 3186.1 as appendix A to part 3180 and revise it to read as follows:

Appendix A to Part 3180—Model onshore unit agreement for unproven areas.

Introductory Section

1 Enabling Act and Regulations.

2 Unit Area.

3 Unitized Land and Unitized Substances.

4 Unit Operator.

5 Resignation or Removal of Unit Operator.

6 Successor Unit Operator.

7 Accounting Provisions and Unit Operating Agreement.

8 Rights and Obligations of Unit Operator.

9 Drilling to Discovery.

10 Plan of Further Development and Operation.

11 Participation After Discovery.

12 Allocation of Production.

13 Development or Operation of Nonparticipating Land or Formations.

14 Royalty Settlement.

15 Rental Settlement.

16 Conservation.

17 Drainage.

18 Leases and Contracts Conformed and Extended.

19 Covenants Run with Land.

20 Effective Date and Term.

21 Rate of Prospecting, Development, and Production.

22 Appearances.

23 Notices.

24 No Waiver of Certain Rights.

25 Unavoidable Delay.

26 Nondiscrimination.

27 Loss of Title.

28 Nonjoinder and Subsequent Joinder.

29 Counterparts.

30 Surrender.^[1]

31 Taxes.^[1]

32 No Partnership.^[1]

Concluding Section in witness whereof.

General Guidelines.

Certification—Determination.

Unit Agreement for the Development and Operation of the

Unit area

County of

State of

No.

This agreement, entered into as of the __ day of ____ , 19__ by and between the parties subscribing, ratifying, or consenting hereto, and herein referred to as the “parties hereto,”

Witnesseth:

Whereas, the parties hereto are the owners of working, royalty, or other oil and gas interests in the unit area subject to this agreement; and

Whereas, the Mineral Leasing Act of February 25, 1920, 41 Stat. 437, as amended, 30 U.S.C. 181 et seq., authorizes Federal lessees and their representatives to unite with each other, or jointly or separately with others, in collectively adopting and operating under a unit plan of development or operations of any oil and gas pool, field, or like area, or any part thereof for the purpose of more properly conserving the natural resources thereof whenever determined and certified by the Secretary of the Interior to be necessary or advisable in the public interest; and

Whereas, the parties hereto hold sufficient interests in the __ Unit Area covering the land hereinafter described to give reasonably effective control of operations therein; and

Whereas, it is the purpose of the parties hereto to conserve natural resources, prevent waste, and secure other benefits obtainable through development and operation of the area subject to this agreement under the terms, conditions, and limitations herein set forth;

Now, therefore, in consideration of the premises and the promises herein contained, the parties hereto commit to this agreement their respective interests in the below-defined unit area, and agree severally among themselves as follows:

1. ENABLING ACT AND REGULATIONS. The Mineral Leasing Act of February 25, 1920, as amended, supra, and all valid pertinent regulations including operating and unit plan regulations, heretofore issued thereunder or valid, pertinent, and reasonable regulations hereafter issued thereunder are accepted and made a part of this agreement as to Federal lands, provided such regulations are not inconsistent with the terms of this agreement; and as to non-Federal lands, the oil and gas operating regulations in effect as of the effective date hereof governing drilling and producing operations, not inconsistent with the terms hereof or the laws of the State in which the non-Federal land is located, are hereby accepted and made a part of this agreement.

2. UNIT AREA. The area specified on the map attached hereto marked Exhibit A is hereby designated and recognized as constituting the unit area, containing __ acres, more or less.

Exhibit A shows, in addition to the boundary of the unit area, the boundaries and identity of tracts and leases in said area to the extent known to the Unit Operator. Exhibit B attached hereto is a schedule showing to the extent known to the Unit Operator, the acreage, percentage, and kind of ownership of oil and gas interests in all lands in the unit area. However, nothing herein or in Exhibits A or B shall be construed as a representation by any party hereto as to the ownership of any interest other than such interest or interests as are shown in the Exhibits as owned by such party. Exhibits A and B shall be revised by the Unit Operator whenever changes in the unit area or in the ownership interests in the individual tracts render such revision necessary, or when requested by the Authorized Officer, hereinafter referred to as AO and not less than four copies of the revised Exhibits shall be filed with the proper BLM office.

The above-described unit area shall when practicable be expanded to include therein any additional lands or shall be contracted to exclude lands whenever such expansion or contraction is deemed to be necessary or advisable to conform with the purposes of this agreement. Such expansion or contraction shall be effected in the following manner:

(a) Unit Operator, on its own motion (after preliminary concurrence by the AO), or on demand of the AO, shall prepare a notice of proposed expansion or contraction describing the contemplated changes in the boundaries of the unit area, the reasons therefor, any plans for additional drilling, and the proposed effective date of the expansion or contraction, preferably the first day of a month subsequent to the date of notice.

(b) Said notice shall be delivered to the proper BLM office, and copies thereof mailed to the last known address of each working interest owner, lessee and lessor whose interests are affected, advising that 30 days will be allowed for submission to the Unit Operator of any objections.

(c) Upon expiration of the 30-day period provided in the preceding item (b) hereof, Unit Operator shall file with the AO evidence of mailing of the notice of expansion or contraction and a copy of any objections thereto which have been filed with Unit Operator, together with an application in triplicate, for approval of such expansion or contraction and with appropriate joinders.

(d) After due consideration of all pertinent information, the expansion or contraction shall, upon approval by the AO, become effective as of the date prescribed in the notice thereof or such other appropriate date.

(e) All legal subdivisions of lands ( i.e., 40 acres by Government survey or its nearest lot or tract equivalent; in instances of irregular surveys, unusually large lots or tracts shall be considered in multiples of 40 acres or the nearest aliquot equivalent thereof), no parts of which are in or entitled to be in a participating area on or before the fifth anniversary of the effective date of the first initial participating area established under this unit agreement, shall be eliminated automatically from this agreement, effective as of said fifth anniversary, and such lands shall no longer be a part of the unit area and shall no longer be subject to this agreement, unless diligent drilling operations are in progress on unitized lands not entitled to participation on said fifth anniversary, in which event all such lands shall remain subject hereto for so long as such drilling operations are continued diligently, with not more than 90-days time elapsing between the completion of one such well and the commencement of the next such well. All legal subdivisions of lands not entitled to be in a participating area within 10 years after the effective date of the first initial participating area approved under this agreement shall be automatically eliminated from this agreement as of said tenth anniversary. The Unit Operator shall, within 90 days after the effective date of any elimination hereunder, describe the area so eliminated to the satisfaction of the AO and promptly notify all parties in interest. All lands reasonably proved productive of unitized substances in paying quantities by diligent drilling operations after the aforesaid 5-year period shall become participating in the same manner as during said first 5-year period. However, when such diligent drilling operations cease, all nonparticipating lands not then entitled to be in a participating area shall be automatically eliminated effective as the 91st day thereafter.

Any expansion of the unit area pursuant to this section which embraces lands theretofore eliminated pursuant to this subsection 2(e) shall not be considered automatic commitment or recommitment of such lands. If conditions warrant extension of the 10-year period specified in this subsection, a single extension of not to exceed 2 years may be accomplished by consent of the owners of 90 percent of the working interest in the current nonparticipating unitized lands and the owners of 60 percent of the basic royalty interests (exclusive of the basic royalty interests of the United States) in nonparticipating unitized lands with approval of the AO, provided such extension application is submitted not later than 60 days prior to the expiration of said 10-year period.

3. UNITIZED LAND AND UNITIZED SUBSTANCES. All land now or hereafter committed to this agreement shall constitute land referred to herein as “unitized land” or “land subject to this agreement.” All oil and gas in any and all formations of the unitized land are unitized under the terms of this agreement and herein are called “unitized substances.”

4. UNIT OPERATOR. ____ is hereby designated as Unit Operator and by signature hereto as Unit Operator agrees and consents to accept the duties and obligations of Unit Operator for the discovery, development, and production of unitized substances as herein provided. Whenever reference is made herein to the Unit Operator, such reference means the Unit Operator acting in that capacity and not as an owner of interest in unitized substances, and the term “working interest owner” when used herein shall include or refer to Unit Operator as the owner of a working interest only when such an interest is owned by it.

5. RESIGNATION OR REMOVAL OF UNIT OPERATOR. Unit Operator shall have the right to resign at any time prior to the establishment of a participating area or areas hereunder, but such resignation shall not become effective so as to release Unit Operator from the duties and obligations of Unit Operator and terminate Unit Operator's rights as such for a period of 6 months after notice of intention to resign has been served by Unit Operator on all working interest owners and the AO and until all wells then drilled hereunder are placed in a satisfactory condition for suspension or abandonment, whichever is required by the AO, unless a new Unit Operator shall have been selected and approved and shall have taken over and assumed the duties and obligations of Unit Operator prior to the expiration of said period.

Unit Operator shall have the right to resign in like manner and subject to like limitations as above provided at any time after a participating area established hereunder is in existence, but in all instances of resignation or removal, until a successor Unit Operator is selected and approved as hereinafter provided, the working interest owners shall be jointly responsible for performance of the duties of Unit Operator, and shall not later than 30 days before such resignation or removal becomes effective appoint a common agent to represent them in any action to be taken hereunder.

The resignation of Unit Operator shall not release Unit Operator from any liability for any default by it hereunder occurring prior to the effective date of its resignation.

The Unit Operator may, upon default or failure in the performance of its duties or obligations hereunder, be subject to removal by the same percentage vote of the owners of working interests as herein provided for the selection of a new Unit Operator. Such removal shall be effective upon notice thereof to the AO.

The resignation or removal of Unit Operator under this agreement shall not terminate its right, title, or interest as the owner of working interest or other interest in unitized substances, but upon the resignation or removal of Unit Operator becoming effective, such Unit Operator shall deliver possession of all wells, equipment, materials, and appurtenances used in conducting the unit operations to the new duly qualified successor Unit Operator or to the common agent, if no such new Unit Operator is selected to be used for the purpose of conducting unit operations hereunder. Nothing herein shall be construed as authorizing removal of any material, equipment, or appurtenances needed for the preservation of any wells.

6. SUCCESSOR UNIT OPERATOR. Whenever the Unit Operator shall tender his or its resignation as Unit Operator or shall be removed as hereinabove provided, or a change of Unit Operator is negotiated by the working interest owners, the owners of the working interests according to their respective acreage interests in all unitized land shall, pursuant to the Approval of the Parties requirements of the unit operating agreement, select a successor Unit Operator. Such selection shall not become effective until:

(a) a Unit Operator so selected shall accept in writing the duties and responsibilities of Unit Operator, and

(b) the selection shall have been approved by the AO.

If no successor Unit Operator is selected and qualified as herein provided, the AO at his election may declare this unit agreement terminated.

7. ACCOUNTING PROVISIONS AND UNIT OPERATING AGREEMENT. If the Unit Operator is not the sole owner of working interests, costs and expenses incurred by Unit Operator in conducting unit operations hereunder shall be paid and apportioned among and borne by the owners of working interests, all in accordance with the agreement or agreements entered into by and between the Unit Operator and the owners of working interests, whether one or more, separately or collectively. Any agreement or agreements entered into between the working interest owners and the Unit Operator as provided in this section, whether one or more, are herein referred to as the “unit operating agreement.” Such unit operating agreement shall also provide the manner in which the working interest owners shall be entitled to receive their respective proportionate and allocated share of the benefits accruing hereto in conformity with their underlying operating agreements, leases, or other independent contracts, and such other rights and obligations as between Unit Operator and the working interest owners as may be agreed upon by Unit Operator and the working interest owners; however, no such unit operating agreement shall be deemed either to modify any of the terms and conditions of this unit agreement or to relieve the Unit Operator of any right or obligation established under this unit agreement, and in case of any inconsistency or conflict between this agreement and the unit operating agreement, this agreement shall govern. Two copies of any unit operating agreement executed pursuant to this section shall be filed in the proper BLM office prior to approval of this unit agreement.

8. RIGHTS AND OBLIGATIONS OF UNIT OPERATOR. Except as otherwise specifically provided herein, the exclusive right, privilege, and duty of exercising any and all rights of the parties hereto which are necessary or convenient for prospecting for, producing, storing, allocating, and distributing the unitized substances are hereby delegated to and shall be exercised by the Unit Operator as herein provided. Acceptable evidence of title to said rights shall be deposited with Unit Operator and, together with this agreement, shall constitute and define the rights, privileges, and obligations of Unit Operator. Nothing herein, however, shall be construed to transfer title to any land or to any lease or operating agreement, it being understood that under this agreement the Unit Operator, in its capacity as Unit Operator, shall exercise the rights of possession and use vested in the parties hereto only for the purposes herein specified.

9. DRILLING TO DISCOVERY. Within 6 months after the effective date hereof, the Unit Operator shall commence to drill an adequate test well at a location approved by the AO, unless on such effective date a well is being drilled in conformity with the terms hereof, and thereafter continue such drilling diligently until the __ formation has been tested or until at a lesser depth unitized substances shall be discovered which can be produced in paying quantities (to wit: quantities sufficient to repay the costs of drilling, completing, and producing operations, with a reasonable profit) or the Unit Operator shall at any time establish to the satisfaction of the AO that further drilling of said well would be unwarranted or impracticable, provided, however, that Unit Operator shall not in any event be required to drill said well to a depth in excess of __ feet. Until the discovery of unitized substances capable of being produced in paying quantities, the Unit Operator shall continue drilling one well at a time, allowing not more than 6 months between the completion of one well and the commencement of drilling operations for the next well, until a well capable of producing unitized substances in paying quantities is completed to the satisfaction of the AO or until it is reasonably proved that the unitized land is incapable of producing unitized substances in paying quantities in the formations drilled hereunder. Nothing in this section shall be deemed to limit the right of the Unit Operator to resign as provided in Section 5, hereof, or as requiring Unit Operator to commence or continue any drilling during the period pending such resignation becoming effective in order to comply with the requirements of this section.

The AO may modify any of the drilling requirements of this section by granting reasonable extensions of time when, in his opinion, such action is warranted.

^[2]  9a. MULTIPLE WELL REQUIREMENTS. Notwithstanding anything in this unit agreement to the contrary, except Section 25, UNAVOIDABLE DELAY, __ wells shall be drilled with not more than 6-months time elapsing between the completion of the first well and commencement of drilling operations for the second well and with not more than 6-months time elapsing between completion of the second well and the commencement of drilling operations for the third well, . . . regardless of whether a discovery has been made in any well drilled under this provision. Both the initial well and the second well must be drilled in compliance with the above specified formation or depth requirements in order to meet the dictates of this section; and the second well must be located a minimum of __ miles from the initial well in order to be accepted by the AO as the second unit test well, within the meaning of this section. The third test well shall be diligently drilled, at a location approved by the AO, to test the __ formation or to a depth of __ feet, whichever is the lesser, and must be located a minimum of __ miles from both the initial and the second test wells. Nevertheless, in the event of the discovery of unitized substances in paying quantities by any well, this unit agreement shall not terminate for failure to complete the __ well program, but the unit area shall be contracted automatically, effective the first day of the month following the default, to eliminate by subdivisions (as defined in Section 2(e) hereof) all lands not then entitled to be in a participating area.

Until the establishment of a participating area, the failure to commence a well subsequent to the drilling of the initial obligation well, or in the case of multiple well requirements, if specified, subsequent to the drilling of those multiple wells, as provided for in this (these) section(s), within the time allowed including any extension of time granted by the AO, shall cause this agreement to terminate automatically. Upon failure to continue drilling diligently any well other than the obligation well(s) commenced hereunder, the AO may, after 15-days' notice to the Unit Operator, declare this unit agreement terminated. Failure to commence drilling the initial obligation well, or the first of multiple obligation wells, on time and to drill it diligently shall result in the unit agreement approval being declared invalid ab initio by the AO. In the case of multiple well requirements, failure to commence drilling the required multiple wells beyond the first well, and to drill them diligently, may result in the unit agreement approval being declared invalid ab initio by the AO;

10. PLAN OF FURTHER DEVELOPMENT AND OPERATION. Within 6 months after completion of a well capable of producing unitized substances in paying quantities, the Unit Operator shall submit for the approval of the AO an acceptable plan of development and operation for the unitized land which, when approved by the authorized officer, shall constitute the further drilling and development obligations of the Unit Operator under this agreement for the period specified therein. Thereafter, from time to time before the expiration of any existing plan, the Unit Operator shall submit for the approval of the AO a plan for an additional specified period for the development and operation of the unitized land. Subsequent plans should normally be filed on a calendar year basis not later than March 1 each year. Any proposed modification or addition to the existing plan should be filed as a supplement to the plan.

Any plan submitted pursuant to this section shall provide for the timely exploration of the unitized area, and for the diligent drilling necessary for determination of the area or areas capable of producing unitized substances in paying quantities in each and every productive formation. This plan shall be as complete and adequate as the AO may determine to be necessary for timely development and proper conservation of the oil and gas resources in the unitized area and shall:

(a) Specify the number and locations of any wells to be drilled and the proposed order and time for such drilling; and

(b) Provide a summary of operations and production for the previous year.

Plans shall be modified or supplemented when necessary to meet changed conditions or to protect the interests of all parties to this agreement. Reasonable diligence shall be exercised in complying with the obligations of the approved plan of development and operation. The AO is authorized to grant a reasonable extension of the 6-month period herein prescribed for submission of an initial plan of development and operation where such action is justified because of unusual conditions or circumstances.

After completion of a well capable of producing unitized substances in paying quantities, no further wells, except such as may be necessary to afford protection against operations not under this agreement and such as may be specifically approved by the AO, shall be drilled except in accordance with an approved plan of development and operation.

11. PARTICIPATION AFTER DISCOVERY. Upon completion of a well capable of producing unitized substances in paying quantities, or as soon thereafter as required by the AO, the Unit Operator shall submit for approval by the AO, a schedule, based on subdivisions of the public-land survey or aliquot parts thereof, of all land then regarded as reasonably proved to be productive of unitized substances in paying quantities. These lands shall constitute a participating area on approval of the AO, effective as of the date of completion of such well or the effective date of this unit agreement, whichever is later. The acreages of both Federal and non-Federal lands shall be based upon appropriate computations from the courses and distances shown on the last approved public-land survey as of the effective date of each initial participating area. The schedule shall also set forth the percentage of unitized substances to be allocated, as provided in Section 12, to each committed tract in the participating area so established, and shall govern the allocation of production commencing with the effective date of the participating area. A different participating area shall be established for each separate pool or deposit of unitized substances or for any group thereof which is produced as a single pool or zone, and any two or more participating areas so established may be combined into one, on approval of the AO. When production from two or more participating areas is subsequently found to be from a common pool or deposit, the participating areas shall be combined into one, effective as of such appropriate date as may be approved or prescribed by the AO. The participating area or areas so established shall be revised from time to time, subject to the approval of the AO, to include additional lands then regarded as reasonably proved to be productive of unitized substances in paying quantities or which are necessary for unit operations, or to exclude lands then regarded as reasonably proved not to be productive of unitized substances in paying quantities, and the schedule of allocation percentages shall be revised accordingly. The effective date of any revision shall be the first of the month in which the knowledge or information is obtained on which such revision is predicated; provided, however, that a more appropriate effective date may be used if justified by Unit Operator and approved by the AO. No land shall be excluded from a participating area on account of depletion of its unitized substances, except that any participating area established under the provisions of this unit agreement shall terminate automatically whenever all completions in the formation on which the participating area is based are abandoned.

It is the intent of this section that a participating area shall represent the area known or reasonably proved to be productive of unitized substances in paying quantities or which are necessary for unit operations; but, regardless of any revision of the participating area, nothing herein contained shall be construed as requiring any retroactive adjustment for production obtained prior to the effective date of the revision of the participating area.

In the absence of agreement at any time between the Unit Operator and the AO as to the proper definition or redefinition of a participating area, or until a participating area has, or areas have, been established, the portion of all payments affected thereby shall, except royalty due the United States, be impounded in a manner mutually acceptable to the owners of committed working interests. Royalties due the United States shall be determined by the AO and the amount thereof shall be deposited, as directed by the AO, until a participating area is finally approved and then adjusted in accordance with a determination of the sum due as Federal royalty on the basis of such approved participating area.

Whenever it is determined, subject to the approval of the AO, that a well drilled under this agreement is not capable of production of unitized substances in paying quantities and inclusion in a participating area of the land on which it is situated is unwarranted, production from such well shall, for the purposes of settlement among all parties other than working interest owners, be allocated to the land on which the well is located, unless such land is already within the participating area established for the pool or deposit from which such production is obtained. Settlement for working interest benefits from such a nonpaying unit well shall be made as provided in the unit operating agreement.

12. ALLOCATION OF PRODUCTION. All unitized substances produced from a participating area established under this agreement, except any part thereof used in conformity with good operating practices within the unitized area for drilling, operating, and other production or development purposes, or for repressuring or recycling in accordance with a plan of development and operations that has been approved by the AO, or unavoidably lost, shall be deemed to be produced equally on an acreage basis from the several tracts of unitized land and unleased Federal land, if any, included in the participating area established for such production. Each such tract shall have allocated to it such percentage of said production as the number of acres of such tract included in said participating area bears to the total acres of unitized land and unleased Federal land, if any, included in said participating area. There shall be allocated to the working interest owner(s) of each tract of unitized land in said participating area, in addition, such percentage of the production attributable to the unleased Federal land within the participating area as the number of acres of such unitized tract included in said participating area bears to the total acres of unitized land in said participating area, for the payment of the compensatory royalty specified in section 17 of this agreement. Allocation of production hereunder for purposes other than for settlement of the royalty, overriding royalty, or payment out of production obligations of the respective working interest owners, including compensatory royalty obligations under section 17, shall be prescribed as set forth in the unit operating agreement or as otherwise mutually agreed by the affected parties. It is hereby agreed that production of unitized substances from a participating area shall be allocated as provided herein, regardless of whether any wells are drilled on any particular part or tract of the participating area. If any gas produced from one participating area is used for repressuring or recycling purposes in another participating area, the first gas withdrawn from the latter participating area for sale during the life of this agreement shall be considered to be the gas so transferred, until an amount equal to that transferred shall be so produced for sale and such gas shall be allocated to the participating area from which initially produced as such area was defined at the time that such transferred gas was finally produced and sold.

13. DEVELOPMENT OR OPERATION OF NONPARTICIPATING LAND OR FORMATIONS. Any operator may with the approval of the AO, at such party's sole risk, costs, and expense, drill a well on the unitized land to test any formation provided the well is outside any participating area established for that formation, unless within 90 days of receipt of notice from said party of his intention to drill the well, the Unit Operator elects and commences to drill the well in a like manner as other wells are drilled by the Unit Operator under this agreement.

If any well drilled under this section by a non-unit operator results in production of unitized substances in paying quantities such that the land upon which it is situated may properly be included in a participating area, such participating area shall be established or enlarged as provided in this agreement and the well shall thereafter be operated by the Unit Operator in accordance with the terms of this agreement and the unit operating agreement.

If any well drilled under this section by a non-unit operator that obtains production in quantities insufficient to justify the inclusion of the land upon which such well is situated in a participating area, such well may be operated and produced by the party drilling the same, subject to the conservation requirements of this agreement. The royalties in amount or value of production from any such well shall be paid as specified in the underlying lease and agreements affected.

14. ROYALTY SETTLEMENT. The United States and any State and any royalty owner who is entitled to take in kind a share of the substances now unitized hereunder shall be hereafter be entitled to the right to take in kind its share of the unitized substances, and Unit Operator, or the non-unit operator in the case of the operation of a well by a non-unit operator as herein provided for in special cases, shall make deliveries of such royalty share taken in kind in conformity with the applicable contracts, laws, and regulations. Settlement for royalty interest not taken in kind shall be made by an operator responsible therefor under existing contracts, laws and regulations, or by the Unit Operator on or before the last day of each month for unitized substances produced during the preceding calendar month; provided, however, that nothing in this section shall operate to relieve the responsible parties of any land from their respective lease obligations for the payment of any royalties due under their leases.

If gas obtained from lands not subject to this agreement is introduced into any participating area hereunder, for use in repressuring, stimulation of production, or increasing ultimate recovery, in conformity with a plan of development and operation approved by the AO, a like amount of gas, after settlement as herein provided for any gas transferred from any other participating area and with appropriate deduction for loss from any cause, may be withdrawn from the formation into which the gas is introduced, royalty free as to dry gas, but not as to any products which may be extracted therefrom; provided that such withdrawal shall be at such time as may be provided in the approved plan of development and operation or as may otherwise be consented to by the AO as conforming to good petroleum engineering practice; and provided further, that such right of withdrawal shall terminate on the termination of this unit agreement.

Royalty due the United States shall be computed as provided in 30 CFR Group 200 and paid in value or delivered in kind as to all unitized substances on the basis of the amounts thereof allocated to unitized Federal land as provided in Section 12 at the rates specified in the respective Federal leases, or at such other rate or rates as may be authorized by law or regulation and approved by the AO; provided, that for leases on which the royalty rate depends on the daily average production per well, said average production shall be determined in accordance with the operating regulations as though each participating area were a single consolidated lease.

15. RENTAL SETTLEMENT. Rental or minimum royalties due on leases committed hereto shall be paid by the appropriate parties under existing contracts, laws, and regulations, provided that nothing herein contained shall operate to relieve the responsible parties of the land from their respective obligations for the payment of any rental or minimum royalty due under their leases. Rental or minimum royalty for lands of the United States subject to this agreement shall be paid at the rate specified in the respective leases from the United States unless such rental or minimum royalty is waived, suspended, or reduced by law or by approval of the Secretary or his duly authorized representative.

With respect to any lease on non-Federal land containing provisions which would terminate such lease unless drilling operations are commenced upon the land covered thereby within the time therein specified or rentals are paid for the privilege of deferring such drilling operations, the rentals required thereby shall, notwithstanding any other provision of this agreement, be deemed to accrue and become payable during the term thereof as extended by this agreement and until the required drilling operations are commenced upon the land covered thereby, or until some portion of such land is included within a participating area.

16. CONSERVATION. Operations hereunder and production of unitized substances shall be conducted to provide for the most economical and efficient recovery of said substances without waste, as defined by or pursuant to State or Federal law or regulation.

17. DRAINAGE. (a) The Unit Operator shall take such measures as the AO deems appropriate and adequate to prevent drainage of unitized substances from unitized land by wells on land not subject to this agreement, which shall include the drilling of protective wells and which may include the payment of a fair and reasonable compensatory royalty, as determined by the AO.

(b) Whenever a participating area approved under section 11 of this agreement contains unleased Federal lands, the value of __ (current royalty for leases offered on Federal onshore oil and gas lease sales) __ percent of the production that would be allocated to such Federal lands under section 12 of this agreement, if such lands were leased, committed, and entitled to participation, shall be payable as compensatory royalties to the Federal Government. Parties to this agreement holding working interests in committed leases within the applicable participating area shall be responsible for such compensatory royalty payment on the volume of production reallocated from the unleased Federal lands to their unitized tracts under section 12. The value of such production subject to the payment of said royalties shall be determined pursuant to 30 CFR part 206. Payment of compensatory royalties on the production reallocated from unleased Federal land to the committed tracts within the participating area shall fulfill the Federal royalty obligation for such production, and said production shall be subject to no further royalty assessment under section 14 of this agreement. Payment of compensatory royalties as provided herein shall accrue from the date the committed tracts in the participating area that includes unleased Federal lands receive a production allocation, and shall be due and payable monthly by the last day of the calendar month next following the calendar month of actual production. If leased Federal lands receiving a production allocation from the participating area become unleased, compensatory royalties shall accrue from the date the Federal lands become unleased. Payment due under this provision shall end when the unleased Federal tract is leased or when production of unitized substances ceases within the participating area and the participating area is terminated, whichever occurs first.

18. LEASES AND CONTRACTS CONFORMED AND EXTENDED. The terms, conditions, and provisions of all leases, subleases, and other contracts relating to exploration, drilling, development or operation for oil or gas on lands committed to this agreement are hereby expressly modified and amended to the extent necessary to make the same conform to the provisions hereof, but otherwise to remain in full force and effect; and the parties hereto hereby consent that the Secretary shall and by his approval hereof, or by the approval hereof by his duly authorized representative, does hereby establish, alter, change, or revoke the drilling, producing, rental, minimum royalty, and royalty requirements of Federal leases committed hereto and the regulations in respect thereto to conform said requirements to the provisions of this agreement, and, without limiting the generality of the foregoing, all leases, subleases, and contracts are particularly modified in accordance with the following:

(a) The development and operation of lands subject to this agreement under the terms hereof shall be deemed full performance of all obligations for development and operation with respect to each and every separately owned tract subject to this agreement, regardless of whether there is any development of any particular tract of this unit area.

(b) Drilling and producing operations performed hereunder upon any tract of unitized lands will be accepted and deemed to be performed upon and for the benefit of each and every tract of unitized land, and no lease shall be deemed to expire by reason of failure to drill or produce wells situated on the land therein embraced.

(c) Suspension of drilling or producing operations on all unitized lands pursuant to direction or consent of the AO shall be deemed to constitute such suspension pursuant to such direction or consent as to each and every tract of unitized land. A suspension of drilling or producing operations limited to specified lands shall be applicable only to such lands.

(d) Each lease, sublease, or contract relating to the exploration, drilling, development, or operation for oil or gas of lands other than those of the United States committed to this agreement which, by its terms might expire prior to the termination of this agreement, is hereby extended beyond any such term so provided therein so that it shall be continued in full force and effect for and during the term of this agreement.

(e) Any Federal lease committed hereto shall continue in force beyond the term so provided therein or by law as to the land committed so long as such lease remains subject hereto, provided that production of unitized substances in paying quantities is established under this unit agreement prior to the expiration date of the term of such lease, or in the event actual drilling operations are commenced on unitized land, in accordance with provisions of this agreement, prior to the end of the primary term of such lease and are being diligently prosecuted at that time, such lease shall be extended for 2 years, and so long thereafter as oil or gas is produced in paying quantities in accordance with the provisions of the Mineral Leasing Act, as amended.

(f) Each sublease or contract relating to the operation and development of unitized substances from lands of the United States committed to this agreement, which by its terms would expire prior to the time at which the underlying lease, as extended by the immediately preceding paragraph, will expire is hereby extended beyond any such term so provided therein so that it shall be continued in full force and effect for and during the term of the underlying lease as such term is herein extended.

(g) The segregation of any Federal lease committed to this agreement is governed by the following provision in the fourth paragraph of sec. 17(m) of the Mineral Leasing Act, as amended by the Act of September 2, 1960 (74 Stat. 781-784) (30 U.S.C. 226(m)):

“Any [Federal] lease heretofore or hereafter committed to any such [unit] plan embracing lands that are in part within and in part outside of the area covered by any such plan shall be segregated into separate leases as to the lands committed and the lands not committed as of the effective date of unitization: Provided, however, That any such lease as to the nonunitized portion shall continue in force and effect for the term thereof but for not less than 2 years from the date of such segregation and so long thereafter as oil or gas is produced in paying quantities.”

If the public interest requirement is not satisfied, the segregation of a lease and/or extension of a lease pursuant to 43 CFR 3107.32 and 43 CFR 3107.40, respectively, shall not be effective.

^[3] (h) Any lease, other than a Federal lease, having only a portion of its lands committed hereto shall be segregated as to the portion committed and the portion not committed, and the provisions of such lease shall apply separately to such segregated portions commencing as of the effective date hereof. In the event any such lease provides for a lump-sum rental payment, such payment shall be prorated between the portions so segregated in proportion to the acreage of the respective tracts.

19. COVENANTS RUN WITH LAND. The covenants herein shall be construed to be covenants running with the land with respect to the interests of the parties hereto and their successors in interest until this agreement terminates, and any grant, transfer or conveyance of interest in land or leases subject hereto shall be and hereby is conditioned upon the assumption of all privileges and obligations hereunder by the grantee, transferee, or other successor in interest. No assignment or transfer of any working interest, royalty, or other interest subject hereto shall be binding upon Unit Operator until the first day of the calendar month after Unit Operator is furnished with the original, photostatic, or certified copy of the instrument of transfer.

20. EFFECTIVE DATE AND TERM. This agreement shall become effective upon approval by the AO and shall automatically terminate 5 years from said effective date unless:

(a) Upon application by the Unit Operator such date of expiration is extended by the AO, or

(b) It is reasonably determined prior to the expiration of the fixed term or any extension thereof that the unitized land is incapable of production of unitized substances in paying quantities in the formations tested hereunder, and after notice of intention to terminate this agreement on such ground is given by the Unit Operator to all parties in interest at their last known addresses, this agreement is terminated with the approval of the AO, or

(c) A valuable discovery of unitized substances in paying quantities has been made or accepted on unitized land during said initial term or any extension thereof, in which event this agreement shall remain in effect for such term and so long thereafter as unitized substances can be produced in quantities sufficient to pay for the cost of producing same from wells on unitized land within any participating area established hereunder. Should production cease and diligent drilling or reworking operations to restore production or new production are not in progress within 60 days and production is not restored or should new production not be obtained in paying quantities on committed lands within this unit area, this agreement will automatically terminate effective the last day of the month in which the last unitized production occurred, or

(d) It is voluntarily terminated as provided in this agreement. Except as noted herein, this agreement may be terminated at any time prior to the discovery of unitized substances which can be produced in paying quantities by not less than 75 per centum, on an acreage basis, of the working interest owners signatory hereto, with the approval of the AO. The Unit Operator shall give notice of any such approval to all parties hereto. If the public interest requirement is not satisfied, the approval of this unit by the AO shall be invalid.

21. RATE OF PROSPECTING, DEVELOPMENT, AND PRODUCTION. The AO is hereby vested with authority to alter or modify from time to time, in his discretion, the quantity and rate of production under this agreement when such quantity and rate are not fixed pursuant to Federal or State law, or do not conform to any Statewide voluntary conservation or allocation program which is established, recognized, and generally adhered to by the majority of operators in such State. The above authority is hereby limited to alteration or modifications which are in the public interest. The public interest to be served and the purpose thereof, must be stated in the order of alteration or modification. Without regard to the foregoing, the AO is also hereby vested with authority to alter or modify from time to time, in his discretion, the rate of prospecting and development and the quantity and rate of production under this agreement when such alteration or modification is in the interest of attaining the conservation objectives stated in this agreement and is not in violation of any applicable Federal or State law.

Powers is the section vested in the AO shall only be exercised after notice to Unit Operator and opportunity for hearing to be held not less than 15 days from notice.

22. APPEARANCES. The Unit Operator shall, after notice to other parties affected, have the right to appear for and on behalf of any and all interests affected hereby before the Department of the Interior and to appeal from orders issued under the regulations of said Department, or to apply for relief from any of said regulations, or in any proceedings relative to operations before the Department, or any other legally constituted authority; provided, however, that any other interested party shall also have the right at its own expense to be heard in any such proceeding.

23. NOTICES. All notices, demands, or statements required hereunder to be given or rendered to the parties hereto shall be in writing and shall be personally delivered to the party or parties, or sent by postpaid registered or certified mail, to the last-known address of the party or parties.

24. NO WAIVER OF CERTAIN RIGHTS. Nothing contained in this agreement shall be construed as a waiver by any party hereto of the right to assert any legal or constitutional right or defense as to the validity or invalidity of any law of the State where the unitized lands are located, or of the United States, or regulations issued thereunder in any way affecting such party, or as a waiver by any such party of any right beyond his or its authority to waive.

25. UNAVOIDABLE DELAY. All obligations under this agreement requiring the Unit Operator to commence or continue drilling, or to operate on, or produce unitized substances from any of the lands covered by this agreement, shall be suspended while the Unit Operator, despite the exercise of due care and diligence, is prevented from complying with such obligations, in whole or in part, by strikes, acts of God, Federal, State, or municipal law or agencies, unavoidable accidents, uncontrollable delays in transportation, inability to obtain necessary materials or equipment in the open market, or other matters beyond the reasonable control of the Unit Operator, whether similar to matters herein enumerated or not.

26. NONDISCRIMINATION. In connection with the performance of work under this agreement, the Unit Operator agrees to comply with all the provisions of section 202 (1) to (7) inclusive, of E.O. 11246 (30 FR 12319), as amended, which are hereby incorporated by reference in this agreement.

27. LOSS OF TITLE. In the event title to any tract of unitized land shall fail and the true owner cannot be induced to join in this unit agreement, such tract shall be automatically regarded as not committed hereto, and there shall be such readjustment of future costs and benefits as may be required on account of the loss of such title. In the event of a dispute as to title to any royalty, working interest, or other interests subject thereto, payment or delivery on account thereof may be withheld without liability for interest until the dispute is finally settled; provided, that, as to Federal lands or leases, no payments of funds due the United States shall be withheld, but such funds shall be deposited as directed by the AO, to be held as unearned money pending final settlement of the title dispute, and then applied as earned or returned in accordance with such final settlement.

Unit Operator as such is relieved from any responsibility for any defect or failure of any title hereunder.

28. NONJOINDER AND SUBSEQUENT JOINDER. If the owner of any substantial interest in a tract within the unit area fails or refuses to subscribe or consent to this agreement, the owner of the working interest in that tract may withdraw the tract from this agreement by written notice delivered to the proper BLM office and the Unit Operator prior to the approval of this agreement by the AO. Any oil or gas interests in lands within the unit area not committed hereto prior to final approval may thereafter be committed hereto by the owner or owners thereof subscribing or consenting to this agreement, and, if the interest is a working interest, by the owner of such interest also subscribing to the unit operating agreement. After operations are commenced hereunder, the right of subsequent joinder, as provided in this section, by a working interest owner is subject to such requirements or approval(s), if any, pertaining to such joinder, as may be provided for in the unit operating agreement. After final approval hereof, joinder by a nonworking interest owner must be consented to in writing by the working interest owner committed hereto and responsible for the payment of any benefits that may accrue hereunder in behalf of such nonworking interest. A nonworking interest may not be committed to this unit agreement unless the corresponding working interest is committed hereto. Joinder to the unit agreement by a working interest owner, at any time, must be accompanied by appropriate joinder to the unit operating agreement, in order for the interest to be regarded as committed to this agreement. Except as may otherwise herein be provided, subsequent joinders to this agreement shall be effective as of the date of the filing with the AO of duly executed counterparts of all or any papers necessary to establish effective commitment of any interest and/or tract to this agreement.

29. COUNTERPARTS. This agreement may be executed in any number of counterparts, no one of which needs to be executed by all parties, or may be ratified or consented to by separate instrument in writing specifically referring hereto and shall be binding upon all those parties who have executed such a counterpart, ratification, or consent hereto with the same force and effect as if all such parties had signed the same document, and regardless of whether or not it is executed by all other parties owning or claiming an interest in the lands within the above-described unit area.

^[4] 30. SURRENDER. Nothing in this agreement shall prohibit the exercise by any working interest owner of the right to surrender vested in such party by any lease, sublease, or operating agreement as to all or any part of the lands covered thereby, provided that each party who will or might acquire such working interest by such surrender or by forfeiture as hereafter set forth, is bound by the terms of this agreement.

If as a result of any such surrender, the working interest rights as to such lands become vested in any party other than the fee owner of the unitized substances, said party may forfeit such rights and further benefits from operations hereunder as to said land to the party next in the chain of title who shall be and become the owner of such working interest.

If as the result of any such surrender or forfeiture working interest rights become vested in the fee owner of the unitized substances, such owner may:

(a) Accept those working interest rights subject to this agreement and the unit operating agreement; or

(b) Lease the portion of such land as is included in a participating area established hereunder subject to this agreement and the unit operating agreement; or

(c) Provide for the independent operation of any part of such land that is not then included within a participating area established hereunder.

If the fee owner of the unitized substances does not accept the working interest rights subject to this agreement and the unit operating agreement or lease such lands as above provided within 6 months after the surrendered or forfeited, working interest rights become vested in the fee owner; the benefits and obligations of operations accruing to such lands under this agreement and the unit operating agreement shall be shared by the remaining owners of unitized working interests in accordance with their respective working interest ownerships, and such owners of working interests shall compensate the fee owner of unitized substances in such lands by paying sums equal to the rentals, minimum royalties, and royalties applicable to such lands under the lease in effect when the lands were unitized.

An appropriate accounting and settlement shall be made for all benefits accruing to or payments and expenditures made or incurred on behalf of such surrendered or forfeited working interests subsequent to the date of surrender or forfeiture, and payment of any moneys found to be owing by such an accounting shall be made as between the parties within 30 days.

The exercise of any right vested in a working interest owner to reassign such working interest to the party from whom obtained shall be subject to the same conditions as set forth in this section in regard to the exercise of a right to surrender.

^[4] 31. TAXES. The working interest owners shall render and pay for their account and the account of the royalty owners all valid taxes on or measured by the unitized substances in and under or that may be produced, gathered and sold from the land covered by this agreement after its effective date, or upon the proceeds derived therefrom. The working interest owners on each tract shall and may charge the proper proportion of said taxes to royalty owners having interests in said-tract, and may currently retain and deduct a sufficient amount of the unitized substances or derivative products, or net proceeds thereof, from the allocated share of each royalty owner to secure reimbursement for the taxes so paid. No such taxes shall be charged to the United States or the State of ____ or to any lessor who has a contract with his lessee which requires the lessee to pay such taxes.

^[4] 32. NO PARTNERSHIP. It is expressly agreed that the relation of the parties hereto is that of independent contractors and nothing contained in this agreement, expressed or implied, nor any operations conducted hereunder, shall create or be deemed to have created a partnership or association between the parties hereto or any of them.

In witness whereof, the parties hereto have caused this agreement to be executed and have set opposite their respective names the date of execution.

Unit Operator

Working Interest Owners

Other Interest Owners

General Guidelines

1. Executed agreement to be legally complete.

2. Agreement submitted for approval must contain Exhibit A and B in accordance with models shown in Appendix B to part 3180 and Appendix C to part 3180.

3. Consents should be identified (in pencil) by tract numbers as listed in Exhibit B and assembled in that order as far as practical. Unit agreements submitted for approval shall include a list of the overriding royalty interest owners who have executed ratifications of the unit agreement. Subsequent joinders by overriding royalty interest owners shall be submitted in the same manner, except each must include or be accompanied by a statement that the corresponding working interest owner has consented in writing to such joinder. Original ratifications of overriding royalty owners will be kept on file by the Unit Operator or his designated agent.

4. All leases held by option should be noted on Exhibit B with an explanation as to the type of option, i.e., whether for operating rights only, for full leasehold record title, or for certain interests to be earned by performance. In all instances, optionee committing such interests is expected to exercise option promptly.

5. All owners of oil and gas interests must be invited to join the unit agreement, and statement to that effect must accompany executed agreement, together with summary of results of such invitations. A written reason for all interest owners who have not joined shall be furnished by the unit operator.

6. In the event fish and wildlife lands are included, add the following as a separate section:

“Wildlife Stipulation. Nothing in this unit agreement shall modify the special Federal lease stipulations applicable to lands under the jurisdiction of the United States Fish and Wildlife Service.”

7. In the event National Forest System lands are included within the unit area, add the following as a separate section:

“Forest Land Stipulation. Notwithstanding any other terms and conditions contained in this agreement, all of the stipulations and conditions of the individual leases between the United States and its lessees or their successors or assigns embracing lands within the unit area included for the protection of lands or functions under the jurisdiction of the Secretary of Agriculture shall remain in full force and effect the same as though this agreement had not been entered into, and no modification thereof is authorized except with the prior consent in writing of the Regional Forester, United States Forest Service, __, ____.”

8. In the event National Forest System lands within the Jackson Hole Area of Wyoming are included within the unit area, additional “special” stipulations may be required to be included in the unit agreement by the U.S. Forest Service, including the Jackson Hole Special Stipulation.

9. In the event reclamation lands are included, add the following as a new separate section:

“Reclamation Lands. Nothing in this agreement shall modify the special, Federal lease stipulations applicable to lands under the jurisdiction of the Bureau of Reclamation.”

10. In the event a powersite is embraced in the proposed unit area, the following section should be added:

“Powersite. Nothing in this agreement shall modify the special, Federal lease stipulations applicable to lands under the jurisdiction of the Federal Energy Regulatory Commission.”

11. In the event special surface stipulations have been attached to any of the Federal oil and gas leases to be included, add the following as a separate section:

“Special surface stipulations. Nothing in this agreement shall modify the special Federal lease stipulations attached to the individual Federal oil leases.”

12. In the event State lands are included in the proposed unit area, add the appropriate State Lands Section as separate section. (See § 3181.4(a)).

13. In the event restricted Indian lands are involved, consult the AO regarding appropriate requirements under § 3181.4(b).

Certification—Determination

Pursuant to the authority vested in the Secretary of the Interior, under the Act approved February 25, 1920, 41 Stat. 437, as amended, 30 U.S.C. 181, et seq., and delegated to (the appropriate Name and Title of the authorized officer, BLM) under the authority of 43 CFR part 3180, I do hereby:

A. Approve the attached agreement for the development and operation of the __, Unit Area, State of ____. This approval shall be invalid ab initio if the public interest requirement under § 3183.4(b) is not met.

B. Certify and determine that the unit plan of development and operation contemplated in the attached agreement is necessary and advisable in the public interest for the purpose of more properly conserving the natural resources.

C. Certify and determine that the drilling, producing, rental, minimum royalty, and royalty requirements of all Federal leases committed to said agreement are hereby established altered, changed, or revoked to conform with the terms and conditions of this agreement.

Dated _____.

(Name and Title of authorized officer of the Bureau of Land Management)

Notes

^[1]  Optional sections (in addition the penultimate paragraph of Section 9 is to be included only when more than one obligation well is required and paragraph (h) of section 18 is to be used only when applicable).

^[2]  Provisions to be included only when a multiple well obligation is required.

^[3]  Optional paragraph to be used only when applicable.

^[4]  Optional sections and subsection. (Agreements submitted for final approval should not identify section or provision as “optional.”)

§ 3186.1-1

[Redesignated as Appendix B to Part 3180]

25. Redesignate § 3186.1-1 as appendix B to part 3180.

§ 3186.1-2

[Redesignated as Appendix C to Part 3180]

26. Redesignate § 3186.1-2 as appendix C to part 3180.

§ 3186.2

[Removed]

27. Remove § 3186.2.

§ 3186.3

[Redesignated as Appendix D to part 3180]

28. Redesignate § 3186.3 as appendix D to part 3180.

§ 3186.4

[Redesignated as Appendix E to part 3180]

29. Redesignate § 3186.4 as appendix E to part 3180.

This action by the Principal Deputy Assistant Secretary is taken pursuant to an existing delegation of authority.

Steven H. Feldgus,

Principal Deputy Assistant Secretary, Land and Minerals Management.

Footnotes

1.   See, e.g., OIG, “Inspector General's Statement Summarizing the Major Management and Performance Challenges Facing the U.S. Department of the Interior” (Nov. 2022); GAO, “OIL AND GAS LEASING—BLM Should Update Its Guidance and Review Its Fees” (Nov. 2021); GAO, “OIL AND GAS—Onshore Competitive and Noncompetitive Lease Revenues” (Nov. 2020); GAO, “FEDERAL ENERGY DEVELOPMENT—Challenges to Ensuring a Fair Return for Federal Energy Resources” (Sept. 2019); GAO, “OIL AND GAS—Bureau of Land Management Should Address Risk from Insufficient Bonds to Reclaim Wells” (Sept. 2019); GAO, “OIL AND GAS LEASE MANAGEMENT—BLM Could Improve Oversight of Lease Suspensions with Better Data and Monitoring Procedures” (June 2018); OIG, “Bureau of Land Management's Idle Well Program” (Jan. 2018).

2.  DOI, “Report on the Federal Oil and Gas Leasing Program” (Nov. 2021). https://www.doi.gov/​sites/​doi.gov/​files/​report-on-the-federal-oil-and-gas-leasing-program-doi-eo-14008.pdf.

3.  DOI, “Report on the Federal Oil and Gas Leasing Program” (Nov. 2021).

4.   https://www.blm.gov/​policy/​im-2023-007.

5.  GAO. GAO-22-103968: OIL AND GAS LEASING BLM Should Update Its Guidance and Review Its Fees. https://www.gao.gov/​assets/​gao-22-103968.pdf.

6.   https://www.blm.gov/​sites/​blm.gov/​files/​uploads/​Media_​Library_​BLM_​Policy_​h3120.pdf.

7.  BLM. MS-3160, Drainage Protection Manual (Public). https://www.blm.gov/​sites/​blm.gov/​files/​uploads/​mediacenter_​blmpolicymanual3160.pdf.

8.  BLM: H-3120-1, Competitive Leases handbook. https://www.blm.gov/​sites/​blm.gov/​files/​uploads/​Media_​Library_​BLM_​Policy_​h3120.pdf.

9.  Stipulations are additional specific terms and conditions that change the manner in which operations may be conducted on a lease or modify the lease rights granted.

10.  Proposed regulation text at 43 CFR 3101.13(a): “The BLM may consider the sensitivity and importance of potentially affected resources and any uncertainty concerning the present or future condition of those resources and will assess whether a resource is adequately protected by stipulation without regard for the restrictiveness of the stipulation on operations.”

11.  See, e.g., GAO-17-307, https://www.gao.gov/​products/​gao-17-307.

12.   https://www.blm.gov/​sites/​blm.gov/​files/​uploads/​Media_​Library_​BLM_​Policy_​Handbook_​h1790-1.pdf.

13.   https://www.blm.gov/​sites/​default/​files/​docs/​2022-03/​MS-3160-10%20Rel.%203-150.pdf.

14.   https://www.blm.gov/​sites/​default/​files/​docs/​2022-03/​MS-3160-10%20Rel.%203-150.pdf.

15.   https://www.blm.gov/​policy/​pim-2019-007.

16.   https://www.blm.gov/​policy/​im-2023-012.

17.  The BLM reviewed its bonds and found many bonds tied to no existing liability or operations. The BLM expects to terminate the period of liability for many of the nationwide bonds without liability, which is why the 243 nationwide bonds would become approximately 143 statewide bonds.

18.   https://www.blm.gov/​policy/​im-2024-014.

19.   https://www.gao.gov/​products/​gao-11-292.

20.   https://www.gao.gov/​products/​gao-19-615.

21.   https://www.doioig.gov/​sites/​default/​files/​2021-migration/​BLM%2520Oil%2520and%2520Gas%2520Bonding%2520Procedures.pdf.

22.   https://www.blm.gov/​sites/​blm.gov/​files/​uploads/​Media_​Library_​BLM_​Policy_​h3120.pdf.

23.   https://www.blm.gov/​policy/​im-2023-007.

24.   https://www.gao.gov/​products/​gao-21-138.

25.   https://www.blm.gov/​policy/​im-2023-007.

26.   https://www.congress.gov/​bill/​117th-congress/​house-bill/​5376/​text.

27.   https://www.blm.gov/​policy/​im-2023-006.

28.  Inflation Reduction Act, Section 50262(e), https://www.congress.gov/​bill/​117th-congress/​house-bill/​5376/​text.

29.   https://www.blm.gov/​policy/​im-2020-006.

30.  Onshore Oil and Gas Operations; Federal and Indian Oil and Gas Leases; Codification of Onshore Orders 1, 2, 6, and 7 (88 FR 39514, June 16, 2023). https://www.federalregister.gov/​documents/​2023/​06/​16/​2023-11742/​onshore-oil-and-gas-operations-federal-and-indian-oil-and-gas-leases-codification-of-onshore-orders.

31.   https://www.blm.gov/​sites/​default/​files/​docs/​2022-03/​MS-3160-10%20Rel.%203-150.pdf.

32.   https://www.blm.gov/​policy/​im-2023-012.

33.   https://www.blm.gov/​policy/​pim-2019-007.

34.   https://www.gao.gov/​products/​gao-18-411.