The U.S. Securities and Exchange Commission (SEC) is rolling out major updates to its EDGAR (Electronic Data Gathering, Analysis, and Retrieval) system with the launch of EDGAR Next, a new account management platform. These changes will affect how public companies, investment companies, and individual filers access, manage, and secure their EDGAR accounts.

ALL FILERS MUST COMPLETE EDGAR NEXT ENROLLMENT BY SEPTEMBER 12, 2025, TO MAINTAIN UNINTERRUPTED SEC FILING ACCESS AND COMPLIANCE WITH DISCLOSURE OBLIGATIONS.

What is EDGAR Next?

EDGAR Next is the SEC’s modernization initiative designed to enhance security and control over the EDGAR filing process. It introduces a new login procedure via login.gov (with multi-factor authentication), role-based user access and administrator designation, and updated account management tools for all filers. These changes aim to enhance security, transparency, and administrative control over EDGAR access.

Who Must Enroll in EDGAR Next?

All public companies (including U.S. and foreign issuers), investment companies, Section 16 filers (such as officers, directors, and beneficial owners of more than 10% of a registered class), and any other entity or individual assisting with the submission of SEC filings must complete EDGAR Next enrollment.

Key EDGAR Next Enrollment Deadlines and Consequences

Enrollment Period Opens:	March 24, 2025
EDGAR Next opens for enrollment. Filers who have not been granted Form ID access by March 24, 2025 will be unable to submit filings until EDGAR Next enrollment is complete.
Compliance Deadline:	September 12, 2025
Filers who have not enrolled in EDGAR Next by September 12, 2025, will not be able to submit SEC filings until enrollment is complete.
Enrollment Period Ends:	December 19, 2025
After this date, to access existing EDGAR accounts, an amended Form ID will be required.

Beginning January 1, 2026, legacy EDGAR credentials will no longer be accepted, and filers who have not enrolled will be locked out of the system.

Failure to meet the SEC’s enrollment deadline will result in the loss of access to the EDGAR system and the inability to file required SEC reports. This may prevent your company from making required SEC filings, potentially resulting in compliance violations, penalties, reputational risk, and delayed closing of transactions.

Recommended Actions for EDGAR Next Enrollment

To ensure a smooth transition, we recommend clients take the following steps as soon as possible:

1. Designate an Account Administrator
   • Identify who in your organization will serve as an account administrator. If you use a filing agent, it will need to be added as an account administrator as well — contact your filing agent directly for assistance and its filing agent CIK.
2. Create Login.gov Accounts
   • All users who need EDGAR access (including administrators and signatories) must create a login.gov account with multi-factor authentication. Visit here for steps on how to create an account.
3. Gather Required Information
   • Prepare CIK numbers, CIK confirmation codes (CCCs), current EDGAR passphrase (if you have not reset your CCC or passphrase since September 2019, you must do so before enrolling — see here for more details), names and contact information for each account administrator (must match Login.gov accounts), and any relevant corporate details needed for enrollment. Note that no power of attorney or notarization is needed for enrollment (Form ID is not part of the EDGAR Next enrollment process).
4. Initiate and complete EDGAR Next Enrollment PROMPTLY
   • Follow the SEC’s instructions to transition your account to the new EDGAR Next system or, for new filers, to create a new EDGAR account, including setting up enhanced security features such as multi-factor authentication. We recommend that filers complete the enrollment process at least a week prior to the compliance deadline of September 12, 2025, to build a buffer for any unforeseen technical or administrative issues.
5. Verify Access After Enrollment
   • Ensure all authorized users can access the system and that account functionality is intact after enrollment.
6. Monitor SEC Communications
   • The SEC may release further instructions and updates; we will continue to track and inform you of key developments.

Stay Compliant — Act Now

The EDGAR Next transition will significantly affect your ability to meet SEC deadlines. We strongly encourage all clients to begin the EDGAR Next enrollment process as soon as possible to avoid potential disruptions.

For additional guidance or support, please reach out to a member of our Public Companies & Capital Markets group or another member of your Davis Graham team.

Additional EDGAR Next Enrollment Resources

• SEC – Enrolling in EDGAR Next (Video)
• SEC – “How Do I” Guides
• Toppan Merrill – Getting Started with EDGAR Next Filing
• DFIN – EDGAR Next Knowledge Hub
• Edgar Agents – EDGAR Next Resources

On August 1, 2025, the U.S. Environmental Protection Agency (EPA) issued a proposed rule to reconsider the 2009 Greenhouse Gas (GHG) Endangerment Finding (Endangerment Finding) and proposed to repeal all GHG emission standards for light-duty, medium-duty, and heavy-duty vehicles and engines promulgated under Section 202(a) of the Clean Air Act (CAA). See Reconsideration of 2009 Endangerment Finding and Greenhouse Gas Vehicle Standards, 90 Fed. Reg. 36,288 (Aug. 1, 2025) (Proposed Rule). EPA’s primary basis for the Proposed Rule is that EPA lacks statutory authority under CAA Section 202(a) to prescribe emission standards to address global climate change concerns in light of more recent Supreme Court decisions, and it also advances several alternative bases for the action. The Proposed Rule does not have any immediate impact on either the car manufacturing industry or any other industry, as it is not yet final. However, if finalized, the Proposed Rule would eliminate existing federal GHG requirements for new motor vehicles and engines, including compliance, reporting and certification obligations for manufacturers, importers, and regulated entities. Notably, the Proposed Rule does not impact the CAA provisions that support EPA’s fuel economy standards, Corporate Average Fuel Economy (CAFE) testing, and emission standards for criteria pollutants and hazardous air pollutants for motor vehicles and engines.

Clients should attentively track this rulemaking process, as EPA acknowledges that it has relied on the Endangerment Finding to promulgate regulations under other CAA provisions, and that it “ha[s] initiated or intend[s] to initiate separate rulemakings that will address any overlapping issues.”  Id. at 36,298.

The Proposed Rule includes several primary and alternative legal rationales for rescinding the Endangerment Finding and GHG emission standards for motor vehicles and engines, which are detailed below.

Lack of Authority under CAA Section 202(a). EPA’s primary argument for rescinding the Endangerment Finding is that it does not have the statutory authority under CAA Section 202(a) to prescribe emission standards to address global climate change concerns. CAA Section 202(a) allows EPA to prescribe regulations for the emission of any air pollutant from engines that “cause, or contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare.”  Previously, EPA interpreted statutory silence in CAA Section 202(a) regarding global climate change impacts to public health and welfare to mean that it had the discretion to prescribe GHG standards for motor vehicles and engines. Id. at 36,299. However, EPA now interprets CAA Section 202(a) as only authorizing it to identify and regulate air pollutants that cause or contribute to air pollution that endangers public health and welfare “through local and regional exposures.”  Id. at 36,300 (emphasis added). In doing so, EPA intends to distinguish “air pollution that impacts public health and welfare by its presence in the ambient air [(i.e., on a localized level)] from ‘air pollution’ consisting of six ‘well-mixed’ GHGs that, as conceptualized in the Endangerment Finding, impacts public health and welfare indirectly [(i.e., on a global level)] and not by its mere presence in the ambient air.” Id.

EPA relies on the recent Supreme Court decisions in Loper Bright Enterprises v. Raimondo, 603 U.S. 369 (2024), West Virginia v. EPA, 597 U.S. 697 (2022), and Utility Air Regulatory Group v. EPA, 573 U.S. 302 (2014) to support this change in interpretation. EPA reasons that the major questions doctrine set forth in West Virginia v. EPA and the overturning of Chevron deference in Loper Bright have led it to interpret the statutory silence in CAA Section 202(a) as a lack of clear authorization from Congress to regulate GHGs from motor vehicles and engines to address global climate change concerns. Id. at 36,305–36,306. EPA further explains that its change in interpretation is consistent with the “decades-long” implementation of CAA Section 202(a) and this recent Supreme Court precedent. Id. at 36,300.

Finally, EPA contends that it misinterpreted the Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007), which vacated EPA’s denial of a petition for rulemaking to regulate carbon dioxide and GHGs from motor vehicles and led to EPA’s Endangerment Finding in 2009. Id. at 36,302. The Proposed Rule explains that following Massachusetts v. EPA, EPA erroneously interpreted the decision to mean that it was required to find that GHGs are subject to regulation under CAA Section 202(a). Id. The Proposed Rule explains that while Massachusetts v. EPA held that GHGs could be considered “air pollutants” under the CAA’s definition of “air pollutants” in Section 302(g), and therefore subject to regulation under CAA Section 202(a), subsequent Supreme Court decisions have clarified that the Massachusetts v. EPA decision did not require EPA to regulate GHGs under CAA Section 202(a) or to make the Endangerment Finding. Id.

Unreasonable Application of Statutory Standards to the Scientific Record. As an alternative, EPA argues that even if CAA Section 202(a) authorized EPA to address GHG emissions based on global climate change impacts, EPA unreasonably exercised that authority by severing the regulatory action into separate “endangerment” and standard-setting proceedings. Id. By severing the proceedings, EPA failed to consider adaptation to climate change, mitigation of GHG emissions, and costs when it issued the Endangerment Finding and standards in separate proceedings. Id. at 36,303. EPA now asserts that CAA Section 202(a) is an “integrated regulatory provision” that requires EPA to make an endangerment finding and prescribe emissions standards to alleviate those impacts in the same proceeding. Id. at 36,302–36,304.

Scientific Uncertainty and New Evidence. As another alternative, EPA asserts that the Endangerment Finding acknowledged “significant uncertainties related to climate change.”  Id. at 36,308–36,310. And that new scientific evidence indicates that the Endangerment Finding was “unduly pessimistic” with respect to climate change and its impacts on public health and welfare. Id.

Lack of “Requisite Technology” to Address Identified Concerns. As a third alternative, EPA asserts that there is no “requisite technology” for light-, medium-, and heavy-duty vehicles that can meaningfully address global concentrations of GHGs in the upper atmosphere. Id. at 36,311. Moreover, “the impact of reducing all GHG emissions from motor vehicles and motor vehicle engines to zero would not result in a measurable impact on trends in climate change.”  Id. at 36,312. Accordingly, the Proposed Rule concludes that this fact alone serves as an independent and sufficient basis for repealing the relevant GHG emission standards, because even if GHGs from motor vehicles and engines were eliminated, such reductions would not have a meaningful impact on the dangers associated with global climate change that were identified in the Endangerment Finding. Id.

The Proposed Rule signals that the second Trump Administration’s EPA is taking aggressive steps to fulfill its deregulatory promises made in a March 12, 2025, press release titled “EPA Launches Biggest Deregulatory Action in U.S. History.”  In addition, the Proposed Rule appears to, at least initially, satisfy President Trump’s directive in Executive Order No. 14154 “Unleashing American Energy” for the EPA Administrator to provide recommendations to the Office of Management and Budget Director on the “legality and continuing applicability” of EPA’s prior Endangerment Finding, and attempt to further President Trump’s campaign promises to reduce the cost of living by “giving Americans the ability to purchase a safe and affordable car . . . while decreasing the cost of living on all products that trucks deliver.”  See Proposed Rule Press Release (July 29, 2025).

While the Proposed Rule is specific to the GHG emission standards for vehicles and engines, EPA is “reconsidering additional endangerment findings and GHG emission standards issued under distinct provisions of the CAA in separate rulemakings.”  90 Fed. Reg. at 36,293. Therefore, EPA may propose additional rules in the coming months or years to rescind or reconsider GHG regulations for other regulated industries.

EPA is accepting public comment on the Proposed Rule until September 15, 2025, and plans to hold public hearings on August 19–20, 2025. See Public Hearing for Reconsideration of 2009 Endangerment Finding and Greenhouse Gas Vehicle Standards, 90 Fed. Reg. 36,125 (Aug. 1, 2025). If you have any questions about EPA’s Proposed Rule or how to participate in this or future EPA rulemakings, please contact John Jacus, Melanie Granberg, Cole Killion, or Natalie Boldt.

On July 3, 2025, the Department of the Interior (the “Department”) published an interim final rule (“Interim Final Rule”) in the Federal Register, effective immediately, that largely rescinds the Department’s regulations at 43 C.F.R. part 46 implementing the National Environmental Policy Act (“NEPA”). The Department is soliciting public comments on the Interim Final Rule through August 4, 2025.

Key Regulatory Changes

The Interim Final Rule rescinds the majority of the Department’s NEPA regulations at 43 C.F.R. part 46, retaining and revising only select provisions. The remaining regulations now focus on emergency response procedures, categorical exclusions, and the preparation of environmental documents by project applicants and contractors. All other NEPA procedures will be retained in the Department’s NEPA Handbook, incorporated within the Departmental Manual at 516 DM 1.

Summary of Retained and Revised Regulations

• Emergency Responses (43 C.F.R. § 46.150). The Department maintains the provision allowing bureaus, in emergency situations, to bypass NEPA analysis for actions urgently needed to mitigate harm to life, property, or significant resources. For other emergency actions not immediately necessary to protect these interests, bureaus may utilize alternative NEPA compliance arrangements.

• Categorical Exclusions (43 C.F.R. §§ 46.205, 46.210, 46.215). The Department has revised its categorical exclusion framework as follows:

• Application of Multiple Categorical Exclusions. New provisions clarify that bureaus may apply multiple categorical exclusions to a single action and may rely on determinations made by other agencies or Department bureaus.

• Procedures for Categorical Exclusions. The process for establishing, modifying, or removing categorical exclusions is now specified, with explicit clarification that such modifications do not themselves trigger NEPA analysis.

• Removal of Certain Exclusions. Categorical exclusions for hazardous fuels reduction using prescribed fire and for post-fire rehabilitation activities have been eliminated.

• Extraordinary Circumstances. Three categories have been removed from the list of “extraordinary circumstances” that preclude the use of categorical exclusions: actions with highly controversial environmental effects; actions potentially violating environmental protection laws; and actions with disproportionately high and adverse effects on low-income or minority populations.

• References to Executive Orders. All references to Executive Orders in the list of categorical exclusions have been removed.

• Environmental Documents (43 C.F.R. §§ 46.106, 46.107). The Department has retained and revised the regulation governing environmental documents prepared by contractors and project applicants, and has added a new section addressing related procedures.

Transition to the NEPA Handbook

The Department will house most of its NEPA implementation procedures in an updated section of the Departmental Manual (516 DM 1), referred to as the NEPA Handbook. The Department justifies this move by characterizing NEPA as a “purely procedural statute” with requirements applicable solely to internal processes. The Handbook’s non-codified status is intended to provide greater flexibility and responsiveness to evolving legal and policy developments.

The 124-page Handbook follows a similar structure to the Council on Environmental Quality’s (CEQ) prior NEPA regulations at 40 C.F.R. part 1500 and is organized into several key sections:

• NEPA and Agency Planning
• Environmental Impact Statements (EIS)
• Efficient Environmental Reviews
• Agency Decision-Making
• Procedures for Applicant- and Contractor-Prepared Environmental Documents

Three appendices provide further detail:

• Actions Normally Requiring an Environmental Assessment (EA) or EIS
• Bureau Categorical Exclusions
• Implementation Guidance to Bureaus, which sets forth additional guidance on nine NEPA concepts, including scoping, public involvement, use of existing NEPA documents, analytical requirements, significance determinations, and documentation protocols.

Notable Handbook Provisions and Their Implications

• Alignment with Statutory Amendments. The Handbook incorporates statutory changes from the Fiscal Responsibility Act of 2023, including definitions at 42 U.S.C. § 4336e and new deadlines and page limits for EAs and EISs.

• Reduced Public Participation and Public Review. The Handbook narrows public participation requirements in the EIS process. Unlike prior CEQ regulations, which required public comment on both the Notice of Intent (NOI) and draft EIS, and mandated publication of a final EIS before a Record of Decision (ROD), the Handbook only requires public comment in response to the NOI, consistent with 42 U.S.C. § 4336a(c). Moreover, there is no requirement to release a draft or final EIS prior to issuance of a ROD.

• Applicant-Prepared NEPA Documents. Statutory amendments to NEPA allow project applicants and their contractors to prepare EAs and EISs. The Handbook further allows applicants and their contractors to prepare Findings of No Significant Impact (FONSIs) and decision documents. The Handbook then details the necessary independent review and evaluation of NEPA documents by the relevant bureau.

• Implementation of Supreme Court Precedent. In response to the Supreme Court’s decision in Seven County Infrastructure Coalition v. Eagle County, the Handbook limits the scope of effects that must be considered in NEPA documents. Bureaus are not required to analyze environmental effects from other projects that are (1) separate in time or place, (2) outside the bureau’s regulatory authority, or (3) independently undertaken by third parties.

Conclusion

The Department’s Interim Final Rule represents a significant restructuring of its NEPA compliance framework, with immediate implications for agency procedures, public participation, and the scope of environmental review. Legal and compliance professionals should review the revised regulations and Handbook to assess impacts on ongoing and future projects. Comments on the Interim Final Rule must be submitted by August 4, 2025.

On July 3, 2025, the U.S. Department of Agriculture (USDA) published an interim final rule (the “Interim Final Rule”) in the Federal Register, effective immediately. This rule significantly revises the USDA’s regulations at 7 C.F.R. part 1b, fundamentally altering how USDA agencies—including the U.S. Forest Service—implement the National Environmental Policy Act (NEPA). The USDA is currently soliciting public comments on the Interim Final Rule through July 30, 2025.

Background and Rationale

The Interim Final Rule is a direct response to three recent developments:

• The Council on Environmental Quality’s (CEQ) rescission of its NEPA regulations in April 2025;
• Congressional amendments to NEPA under the Fiscal Responsibility Act of 2023;
• The U.S. Supreme Court’s decision in Seven County Infrastructure Coalition v. Eagle County, 145 S. Ct. 1497 (2025), which reaffirmed that NEPA imposes procedural, not substantive, requirements.

Below are key takeaways from USDA’s updated NEPA procedures:

Department-Wide Consolidation and Revision of NEPA Procedures

• The Interim Final Rule rescinds separate NEPA regulations for the Forest Service and other USDA agencies, consolidating all NEPA procedures within 7 C.F.R. part 1b.
• Unified processes now govern environmental reviews across the Department, including categorical exclusions (CEs), environmental assessments (EAs), and environmental impact statements (EISs).
• The Interim Final Rule established streamlined processes to account for the Seven County decision and directions from President Trump to reduce regulatory burdens.
• While agency-specific NEPA rules are eliminated, personnel may continue to use categorical exclusions now incorporated into the revised USDA-wide list at 7 C.F.R. § 1b.4.

Streamlining and Statutory Alignment

• The Interim Final Rule incorporates statutory deadlines and page limits established by the Fiscal Responsibility Act of 2023. USDA must report annually to Congress on any EA or EIS that does not meet these deadlines.
• The Interim Final Rule adopts the statutory definition of “major Federal action” and clarifies circumstances where NEPA does not apply, such as non-discretionary decisions or projects with minimal federal involvement.
• The Interim Final Rule establishes procedures for EAs and EISs prepared by applicants or third parties.

Simplified Documentation and Enhanced Efficiency

• The definition of “effects” is now limited to environmental changes that are “reasonably foreseeable and have a reasonably close causal relationship” to the proposed action or alternatives. Consistent with Seven County, the Interim Final Rule excludes consideration of effects that are remote in time or geography, the result of a lengthy causal chain, or outside the agency’s regulatory authority.

• Agencies are no longer required to publish draft EISs and have discretion in structuring NEPA documents, provided statutory requirements are met.

• Final EISs need not be published before issuing Records of Decision (RODs); implementation may begin once notice of the final EIS is published in the Federal Register and the ROD is posted on a USDA website.

• Public comment is required only in response to a Notice of Intent, in line with 42 U.S.C. § 4336a(c). Agencies are not required to solicit public comment on EAs or EISs, but may do so at any reasonable point, with an emphasis on addressing substantive comments.

• The Interim Final Rule introduces the “Finding of Applicability and No Extraordinary Circumstance” (FANEC), requiring agencies to affirmatively determine that a CE applies and that no extraordinary circumstances exist.

Emergency Provisions

• The Interim Final Rule establishes streamlined NEPA procedures for emergency actions, distinguishing between immediate and urgent-but-not-immediate actions.

Next Steps

The USDA is accepting public comments on the Interim Final Rule until July 30, 2025. A final rule is anticipated later this year. In the interim, the Forest Service and other USDA agencies have discretion to implement the new procedures immediately or transition as appropriate, depending on the status of ongoing NEPA reviews.

Implications

Legal and compliance professionals should closely review the revised procedures, particularly the consolidation of NEPA processes, new documentation requirements, and changes to public participation. The streamlined approach and statutory alignment may affect the timing and structure of environmental reviews for USDA actions going forward.

On June 4, 2025, Colorado Governor Jared Polis signed SB 25-126, the Uniform Antitrust Pre-Merger Notification Act (the “Colorado Act”), into law. It is expected to take effect on August 6, 2025. The Colorado Act requires certain parties that submit filings under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the “HSR Act”) to submit copies of their respective HSR forms to the Colorado Attorney General (the “AG”). Although the AG may not charge a fee in connection with the pre-merger notification requirement, failure to submit the required filings to the AG can result in civil penalties of up to $10,000 for each day of noncompliance. While the Colorado legislature previously adopted notice requirements for certain healthcare transactions, the Colorado Act broadens the scope of mandatory pre-merger filings to all industries.

Who is Required to File?

The Colorado Act requires a “person” who submits an HSR filing to file a complete electronic copy of the HSR form with the AG if:

• the person has its principal place of business in Colorado, or
• the person, or any person it directly or indirectly controls, had annual net sales in Colorado of the goods or services involved in the transaction of at least 20% of the HSR filing threshold (with the current HSR threshold of $126.4 million, the Colorado threshold amounts to $25.28 million).

The Colorado Act defines a “person” as an individual, estate, business or nonprofit entity, government or governmental subdivision, agency, or instrumentality, or other legal entity. The Act provides no specific guidance on the meaning or calculation of “annual net sales” or “goods or services involved in the transaction.” However, as noted in the comments to the Uniform Law Commission’s Uniform Antitrust Pre-Merger Notification Act on which the Colorado Act is modeled, (i) annual net sales from income statements is a widely utilized measure of economic activity borrowed from the regulations under the HSR Act and (ii) “goods or services involved in the transaction” is intended to limit the filing obligation to circumstances where the filing party’s economic activity in the state is in the same business category as assets involved in the acquisition.

What Documents are Required?

All required filers must submit a copy of their HSR filing. Additionally, in certain circumstances, filers must submit all documents filed with the HSR form or submit such documentary material at the request of the AG. The filed information is exempt from disclosure under the Colorado Open Records Act, and the AG may not make public or disclose information relevant to the filing such as the HSR form, any documentary materials, the fact that materials have been filed with the AG, or the proposed transaction. However, the AG is authorized to disclose the information to federal agencies and attorneys general of other states that have enacted the Uniform Law Commission’s Uniform Antitrust Pre-Merger Notification Act or substantially similar legislation having comparable confidentiality protections, or as part of any administrative or judicial proceeding.

Other Similar Bills Across the Nation

The Colorado Act is one of many bills across the nation modeled on the Uniform Antitrust Pre-Merger Notification Act. California, Hawaii, Nevada, Utah, Washington DC, West Virginia, and New York have introduced bills based on the Uniform Act and, in some cases, have proposed to significantly expand the scope of the Uniform Act. The state of Washington has passed its own pre-merger notification law that becomes effective on July 27, 2025.

If you have any questions concerning the information discussed in this alert or the Colorado Act, please contact Jennifer Allen, Edward Shaoul, or a Davis Graham Partner.

On July 4, 2025, President Trump signed a reconciliation bill that contains numerous provisions affecting oil and gas leasing and development on onshore federal lands. Some provisions repeal elements of the 2022 Inflation Reduction Act (IRA), while other provisions react to administrative and regulatory efforts that constrain federal oil and gas leasing. 

Rollback of the IRA’s increased royalty rate on new federal onshore oil and gas leases.

The IRA had amended section 17(b)(1)(A) of the Mineral Leasing Act (MLA), 30 U.S.C. § 226(b)(1)(A), to increase the royalty rate on new onshore federal oil and gas leases from a minimum of 12.5% to 16 2/3%. Section 50101(a)(1) of the Reconciliation Act repealed this IRA provision and restored section 17(b)(1)(A) of the MLA “as if [the IRA] had not been enacted into law.”

The IRA also had established a baseline 16 2/3% royalty for reinstated leases. The Reconciliation Act similarly repealed this royalty rate applicable to reinstated leases.

Importantly, the Reconciliation Act did not undo all of the IRA’s changes to the terms of new onshore oil and gas leases. Section 50262(b) and (c) of the IRA amended the MLA at 30 U.S.C. § 226(b)(1)(B) and (d) to increase the minimum bid and annual rental rates for onshore oil and gas leases. The Reconciliation Act left these amendments intact.

Circumscription of the Secretary’s discretion to lease lands for oil and gas development.

Prior to the Reconciliation Act, the MLA afforded the Secretary of the Interior discretion to lease a given parcel of land for oil and gas development. Specifically, 30 U.S.C. § 226(a) provided that the Secretary “may” lease lands known or believed to contain oil and gas deposits. Courts had interpreted this statutory mandate as affording the Secretary broad discretion to determine whether to lease lands.

Section 50101(d) of the Reconciliation Act eliminated this discretion. The Reconciliation Act replaced 30 U.S.C. § 226(a) with a requirement that the Secretary must lease those lands for which the Secretary receives an expression of interest for leasing. The Secretary must make such lands available for leasing within 18 months of receiving the expression of interest, so long as those lands are designated as open to leasing under the applicable resource management plan (RMP) when the expression of interest is submitted.

The Reconciliation Act also amended 30 U.S.C. § 226(a) to provide that an ongoing RMP amendment “shall not” prevent or delay the Bureau of Land Management (BLM) from offering lands for lease.

Limitation on oil and gas lease stipulations.

Section 50101(d) of the Reconciliation Act amended 30 U.S.C. § 226(a) to prohibit BLM from attaching stipulations or mitigation requirements to oil and gas leases that are not included in the applicable RMP.

Promotion of quarterly onshore oil and gas lease sales.

The Reconciliation Act promotes quarterly onshore oil and gas lease sales, presumably in response to the Biden administration’s pause on onshore lease sales in 2021 and 2022.

The MLA requires that the Secretary, through BLM, hold lease sales “at least quarterly” in each State “where eligible lands are available.” 30 U.S.C. § 226(b)(1)(A). While the Reconciliation Act did not amend the MLA’s direction that BLM hold quarterly lease sales, section 50101(c) of the Reconciliation Act separately directs that the Secretary “shall conduct a minimum of 4 oil and gas lease sales of available land” each fiscal year, i.e., October 1 through September 30, in Wyoming, New Mexico, Colorado, Utah, Montana, North Dakota, Oklahoma, and Nevada.

Additionally, section 50101(b)(3) of the Reconciliation Act amended the MLA to define “eligible lands” as “all lands that are subject to leasing under [the MLA] and are not excluded from leasing by a statutory prohibition.” This change modifies BLM’s longstanding definition of “eligible” set forth in an agency handbook, which defined “eligible” as “available for leasing when all statutory requirements and reviews, including compliance with the National Environmental Policy Act (NEPA) of 1970, have been met.” With this change, Congress indirectly rebuked the Biden administration’s position that BLM could decline to hold quarterly lease sales when BLM had not completed NEPA reviews prior to leasing.

Furthermore, section 50101(b)(3) of the Reconciliation Act amended the MLA to define “available” lands as “designated as open for leasing under a land use plan developed under section 220 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1712) and that have been nominated for leasing through the submission of an expression of interest, are subject to drainage in the absence of leasing, or are otherwise designated as available pursuant to regulations adopted by the Secretary.”

To further promote quarterly sales, the Reconciliation Act directed that BLM:

• Conduct any lease sale required by the MLA “immediately on completion of all applicable scoping, public comment, and environmental analysis requirements” under the MLA and NEPA (§ 50101(b)(2)(A));
• Conduct the scoping, public comment, and environmental analysis requirements under the MLA and NEPA “in a timely manner” (§ 50101(b)(2)(B));
• Shall not offer less than 50 percent of available parcels nominated for lease under a given RMP (§ 50101(c)(2)(A));
• Shall not restrict parcels offered at a quarterly sale to those located in one BLM field office, unless all nominated parcels are in that one field office (§ 50101(c)(2)(B)). This prohibition prevents BLM from reinstituting a directive in a 2010 BLM instruction memorandum, No. 2010-117, that quarterly lease sales should rotate among field offices in a given state. The effect of this directive had been that BLM offered parcels for lease in given field office only once or twice a year.

Finally, section 50101(d) of the Reconciliation Act directed BLM to conduct replacement lease sales when a lease sale is cancelled, delayed, or deferred or when less than 25% of acreage offered a lease sale does not receive a bid.

Elimination of expression of interest fees.

The IRA had amended the MLA, 30 U.S.C. § 226(q), to impose a $5 per acre fee on expressions of interest. Section 50101(d) of the Reconciliation Act eliminated this fee.

Restoration of noncompetitive leasing.

Section 50262(e) of the IRA had eliminated noncompetitive onshore oil and gas leasing. Section 50101(a)(2) of the Reconciliation Act restored noncompetitive leasing.

Elimination of the royalty on extracted methane.

Section 50103 of the Reconciliation Act repealed the royalty on methane that the IRA imposed on federal onshore and offshore leases issued after August 16, 2022.

Authorization of commingling approvals.

Section 50101(d) of the Reconciliation Act amended the MLA, 30 U.S.C. § 226(p), to authorize the commingling of production from two or more federal leases or other sources. The amendment provides some relief from the stringent commingling regulations at 43 C.F.R. Part 3170, Subpart 3173, that BLM adopted in 2016.

The amendment requires BLM to approve commingling applications if the applicant agrees to:

• Install measurement devices for each source;
• Utilize a method to allocate production between sources that “achieves volume measurement uncertainty levels within plus or minus 2 percent during the production phase reported on a monthly basis,” or
• Utilize an approved periodic well testing methodology.

In a press release, the Department of the Interior announced it would initiate a rulemaking to implement this provision.

Adjustment of the duration of applications for permits to drill (APDs).

Section 50101(d) of the Reconciliation Act amended the MLA, 30 U.S.C. § 226(p), to establish a single, non-renewable four-year term for APDs approved on or after July 4, 2025. The amendment effectively supersedes BLM’s 2024 regulation at 43 C.F.R. § 3171.14(a) establishing a three-year term for AP.

UPDATE: On September 30, 2025, the United States Financial Crimes Enforcement Network announced that it will postpone reporting requirements of the Anti-Money Laundering Regulations for Residential Real Estate Transfers Rule until March 1, 2026. [7]

On August 29, 2024, the United States Financial Crimes Enforcement Network (“FinCEN”) promulgated a final rule, the “Anti-Money Laundering Regulations for Residential Real Estate Transfers” (the “Rule”), that takes effect on December 1, 2025.[1] The Rule requires certain reporting persons to file a Real Estate Report (the “Report”) to FinCEN on non-financed transfers of certain residential real estate when the transferee is an entity of a trust. Negligent violations of the Rule may result in civil penalties of $1,394 per violation and an additional civil penalty of up to $108,489 for a pattern of negligent violations (dollar amounts are calculated as of the date of publication of the Rule).[2] Willful violations of the Rule could result in criminal penalties of up to five years’ imprisonment and/or up to $250,000 in criminal fines and additional civil penalty of, as of the date of publication of the Rule, not more than the greater of the amount involved in the transaction (not to exceed $278,937) or $69,733.[3]

Covered Transfers

• Summary: The Rule covers non-financed transfers of RRE to Transferee Entities and Transferee Trusts regardless of the existence or amount of consideration for such transfer.
  
• Residential Real Estate (“RRE“): RRE includes real estate located in the United States that are: (1) residences intended for occupancy by one to four families, including single-family homes, townhouses, condominiums, and apartment buildings designed for occupancy by one to four families; (2) vacant land on which the transferee intends to build a structure intended for occupancy by one to four families; (3) a unit designed for one to four family occupancy within a structure (ex: a condo within a larger building or a single family dwelling in a mixed use building); or (4) a share in a cooperative housing corporation.
  
• Non-financed Transfers: Non-financed transfers are defined as transfers that do not involve an extension of credit to all transferees which is (1) secured by the subject property and (2) extended by a financial institution that is subject to an Anti-Money Laundering  program and Suspicious Activity Report obligations. Non-financed Transfers include non-bank private lenders.
  
• Transferee Entities: A Transferee Entity is a legal entity other than a Transferee Trust or an individual. This includes corporations, partnerships, estates, associations, or limited liability companies, both foreign and domestic.
  • However, certain highly regulated entities are exempt from the definition of Transferee Entities under the Rule such as:
    • Securities reporting issuers; governmental authorities; banks; credit unions; depository institution holding companies; money services businesses; brokers or dealers in securities; securities exchange or clearing agencies; other exchange act registered entities; insurance companies; state-licensed insurance producers; Commodity Exchange Act registered entities; public utilities; financial market utilities; registered investment companies; or subsidiaries of an exempted entity.
      
• Transferee Trusts: A Transferee Trust is any arrangement created where a grantor or settlor places assets under the control of a trustee for the benefit of one or more beneficiaries or for a specified purpose. This also includes similar foreign legal arrangements.
  • However, certain highly regulated trusts are exempt such as:
    • Securities reporting issuers; trustees that are a securities reporting issuer; statutory trusts (these trusts are treated as Transferee Entities, not Transferee Trusts); or subsidiaries of exempted trusts.

Exempt Transfers

• Summary: The Rule exempts certain transfers of RRE from reporting that FinCEN does not deem as high-risk transfers for money laundering, such as:
  • Easement transfers; transfers resulting from death by will, trust, contract, or operation of law; transfers incident to divorce; bankruptcy estate transfers; transfers to individuals; transfers supervised by a court in the United States; transfers for no consideration to certain trusts; transfers to a qualified intermediary as part of an exchange under Section 1031 of the Internal Revenue Code; and transfers lacking a Reporting Person.

Who is Responsible for Reporting

• Summary: “Reporting Persons” are the individuals deemed responsible for submitting the Report to FinCEN, and only one Reporting Person exists per any reportable transfer. Generally, settlement agents, title insurance agents, escrow agents, and attorneys will be obligated to file the Report. To determine who the Reporting Person is, one can use the “reporting cascade” or real estate professionals within the cascade can decide amongst themselves.
  
• Reporting Cascade: The reporting cascade is a list of seven functions where the individual who performs the highest order on the list (one being higher than seven) is deemed the Reporting Person. The list of seven functions proceeds as follows:
  • (1) The closing/settlement agent listed on the closing/settlement statement; (2) the person preparing the closing/settlement statement; (3) the person who submits the deed for recording; (4) the title insurance underwriter for the transferee’s owner’s policy; (5) the person who disburses the greatest amount of the funds; (6) the person who evaluates the status of title; and (7) the person who prepares the deed or other instrument transferring title.
    
• Real Estate Professional’s Discretion: Alternatively, the Rule allows for real estate professionals on any part of the reporting cascade to enter into a written Designation Agreement that designates another person within the reporting cascade as the Reporting Person.
  • These Designation Agreements transfer compliance liability to a designated Reporting Person in the cascade, and a separate agreement is required for each transaction. Third party contractors can be used to file the Report on the Reporting Person’s behalf; however, compliance liability is not transferred to that third party and the Reporting Person remains liable for a failure to file.

Reporting Information, Reasonable Reliance, and Reporting Deadlines

• Reporting Information:[4]
  • Generally, for Transfers to Transferee Entities/Trusts: (1) The Reporting Person’s identifying information; (2) the Transferee Entity/Trust receiving ownership of the RRE; (3) the beneficial owners of the Transferee Entity/Trust; (4) certain individuals signing documents on behalf of the Transferee Entity/Trust; (5) the transferor; (6) the RRE being transferred; and (7) total consideration and certain information about any payments made.
    
• Reasonable Reliance: Reporting Persons may rely on information provided by another person for purposes of reporting information or making necessary determinations to comply with the Rule. However, the Reporting Person may only utilize this reliance if they lack factual knowledge that would reasonably question the reliability of the information being relied upon.
  • The standard is more limited when a Reporting Person is reporting beneficial ownership information of Transferee Entities or Trusts. In those situations, reasonable reliance only applies to information provided by the transferee or their representative and only if the person providing the information certifies the information’s accuracy in writing to the best of their knowledge.
    
• Reporting Deadlines: The Report must be filed by the latter of:
  • The final day of the following month after which the closing occurred, or
  • Thirty calendar days after the date of closing.

Record Retention Requirements

• Requirements: The Reporting Person must keep a copy of the certification of the transferee’s beneficial ownership information signed by the transferee or transferee’s representative and a copy of the signed Designation Agreement for five years. The Report does not need to be retained.
  • Additionally, other parties to the Designation Agreement must also keep copies of the Designation Agreement for five years.

Note on Challenges

• It is important to note that certain legislative actions and legal challenges could affect or nullify the Rule. On February 5, 2025, a Senate Joint Resolution was introduced by Senator Mike Lee stating that Congress disapproves of the Rule and that the Rule shall have no force or effect. [5] On February 12, 2025, a House Joint Resolution was introduced by Representative Andrew Clyde also stating that Congress disapproves of the Rule and that the Rule shall have no force or effect.[6] However, as of June 20, 2025, neither resolution has been passed by a committee or either house of Congress. Further, a lawsuit to block the Rule has been filed in the US District Court for the Eastern District of Texas in Flowers Title Companies LLC v. Bessent.
  

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[1] 31 C.F.R. § 1031.320.

[2] 31 U.S.C. § 5321.

[3] 31 U.S.C. § 5321; 31 C.F.R. § 1010.821.

[4] Refer to the Rule regarding what is included in each category of reporting information. Also, note that information required for Transferee Entities is not the same as information required for Transferee Trusts.

[5] A joint resolution disapproving the rule submitted by the Financial Crimes Enforcement Network relating to “Anti-Money Laundering Regulations for Residential Real Estate Transfers”, S.J. Res. 15, 119th Cong. (2025-2026).

[6] Providing for congressional disapproval under chapter 8 of title 5, United States Code, of the rule submitted by the Financial Crimes Enforcement Network relating to “Anti-Money Laundering Regulations for Residential Real Estate Transfers”, H.J.Res.55 — 119th Congress (2025-2026).

[7] https://www.fincen.gov/news/news-releases/fincen-announces-postponement-residential-real-estate-reporting-until-march-1

On May 28, 2025, Colorado Governor Jared Polis signed HB-1165 into law. HB-1165 creates the Geologic Storage Stewardship Enterprise within the Department of Natural Resources to fund the state’s long-term stewardship of geologic storage facilities in the state and provides clarification for geothermal resource projects.

I. The Geologic Storage Enterprise

What is long-term stewardship of a geologic storage facility?

A geologic storage facility is a Class VI well that is used for long-term underground storage of carbon dioxide (CO₂) in deep rock formations. Sources of CO₂ vary and can include CO₂ captured from point sources before the CO₂ is emitted to the atmosphere or CO₂ captured from the atmosphere. As of the date of this publication, no Class VI wells are permitted in Colorado. The Governor’s GHG roadmap identifies geologic storage facilities as an essential tool for Colorado to achieve its statewide emission targets to reduce greenhouse gas emissions.[1] This legislation may attract geologic storage operators to Colorado while remaining protective of the state’s resources.  

Long-term stewardship occurs after a site is closed and includes monitoring and integrity maintenance of geologic storage facilities as well as the ability to take any associated action necessary to protect public health, safety, welfare, the environment, or wildlife resources.[2]

A site is closed after an operator permanently ceases injection of CO₂. Site closure requires an operator to properly plug the well, remove unnecessary equipment for long-term stewardship and install monitoring equipment for long-term monitoring, and reclaim the land.[3] A plan for site closure is included in an operator’s Class VI permit application, which is approved by the appropriate agency before injection [4]

Once the site is properly closed and such closure is approved by the appropriate agency, operators must continue to monitor the facility to show the position of the CO₂ plume and the pressure front and demonstrate that there is no endangerment to underground sources of drinking water.[5] This monitoring must occur for at least 50 years under Colorado rules, unless an alternative timeframe is approved by the appropriate regulatory authority.[6]^,[7] Under HB-1165, Colorado can take over this long-term monitoring.[8]

How is the Enterprise funded?

The Enterprise is funded primarily by payment of stewardship fees, which are assessed against geologic storage operators. [9] The Enterprise can also receive money from revenue bonds, gifts/grants/donations, and appropriated money from the General Assembly.[10]

What does the Enterprise have authority to do?

The Enterprise has the authority to hold title to property, including ownership of injection CO₂, hire professionals or contractors necessary for long-term site stewardship, collect money, and assess an orphaned geologic storage facility fee.[11]

The Enterprise can only collect an orphaned geologic storage facility fee if the Enterprise finds that geologic storage operations in the state are likely to create orphaned facilities in the future.[12] There are currently no orphaned geologic storage operations in the entire country and stringent financial assurance requirements are in place to prevent facilities from actually becoming orphaned.

Will HB25-1165 encourage geologic storage operations in Colorado?

There are many factors an operator may consider before pursuing a geologic storage operation in Colorado. Such factors include geologic suitability for long-term storage of CO₂, consent from pore space owners, and the political and regulatory climate for this industry. HB-1165 provides incentives to geologic storage operators to bring projects to Colorado because these operators can move on from a project after closure, freeing up capital for the operator to pursue new ventures.

II. Geothermal Resources

HB 25-1165 also makes several updates relating to geothermal resources. It also implements new notice requirements relating to proposed well applications for Deep geothermal operations and simplifies the jurisdictional division between ECMC and the State Engineer.

What notice is required for Deep geothermal operations?

As part of the permit issuance process for Deep geothermal operations, ECMC is now required to decide, based on available data, that such operations will not materially injure Prior geothermal operations.[13] Before ECMC can make this decision, the applicant must provide notice to all registered designated individuals of Prior geothermal operations within a quarter mile of the proposed Deep geothermal operations.[14]

Despite the more burdensome notice requirement, the revisions offer some protection for applicants from unknown operations because the owners or operators of Prior geothermal operations are required to register the location and designated individuals of such operations.[15] “Prior geothermal operation” is defined as “a geothermal well, operation, district, or unit authorized by [the State engineer or ECMC] pursuant to [] Article 90.5 or [] a historic hot spring.”[16]

Do I need to talk to the ECMC or State Engineer regarding a geothermal resource project?

Because the former law created overlapping jurisdiction with respect to some Deep geothermal operations, the revisions clarify that a well permit is not required from the State Engineer if the operator withdraws nontributary groundwater as part of Deep geothermal operations unless the operator will use such water for additional, unrelated beneficial uses.[17] “Deep geothermal operations” includes exploration for or production of (i) geothermal resources associated with nontributary groundwater or (ii) geothermal resources deeper than 2,500’ below the surface, in each case excluding withdrawal of groundwater in the Denver basin aquifers.[18]

If you have any questions, please contact John Jacus, Brian Annes, or Natalie Boldt.

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[1] See H.B. 25-1165 §§ 1(a), (c).

[2] Colo. Rev. Stat. § 34-60-144(2)(e).

[3] Id. at § 34-60-103(40.5)(a)(II)(b).

[4] ECMC Rule 1423(b)(1).

[5] ECMC Rule 1423(b).

[6] Id.

[7] ECMC has promulgated rules for Class VI wells and is currently seeking primacy for the Class VI program from EPA. EPA has jurisdiction over Class VI well permits in Colorado until primacy is granted.

[8] C.R.S. § 34-60-106(9.4)(c)(II).

[9] Id. at § 34-60-144(7)(a).

[10] Id.

[11] Id. at § 34-60-144(5).

[12] Id.

[13] CRS 37-90.5-106(1)(b)(III)(B).

[14] CRS 37-90.5-106(1)(b)(III)(C).

[15] CRS 37-90.5-106(7).

[16] CRS 37-90.5-103(14.5).   

[17] CRS 37-90-137(7.5).

[18] CRS 37-90.5-103(3).

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On May 29, 2025, the U.S. Supreme Court issued a landmark decision in Seven County Infrastructure Coalition v. Eagle County, Colorado, limiting the scope of environmental review required under the National Environmental Policy Act (NEPA). In an 8-0 decision, from which Justice Gorsuch recused himself, the Court reversed the D.C. Circuit’s decision vacating the Surface Transportation Board’s (STB) approval of an 88-mile railway in northeastern Utah. A majority of the Court held that the STB was not required to analyze the environmental effects of upstream oil development or downstream refining activity, because those projects were separate in both time and regulatory jurisdiction from the proposed railway. Three concurring justices, however, would have vacated the STB’s approval on entirely different grounds.

The decision narrows the range of indirect impacts that agencies must consider in environmental impact statements (EISs) and environmental assessments (EAs). The Court emphasized the role of agency discretion in determining the scope of NEPA review and warned against judicial interference that transforms NEPA into a tool for delaying or blocking infrastructure or other project development. Below are four key takeaways:

NEPA Does Not Require Agencies to Analyze Environmental Effects of Separate Projects

The majority held that the STB was not required to assess the environmental consequences of oil drilling in the Uintah Basin or refining activity along the coasts of Texas and Louisiana, even if those activities might increase as a result of the railway’s construction. The majority explained that NEPA focuses on the environmental effects of the proposed action, meaning the project under the agency’s jurisdiction. Agencies need not analyze the effects of “separate projects,” particularly when those projects fall under the jurisdiction of different regulatory bodies. The majority reasoned that, even though the effects of a separate project may be a “factually foreseeable” consequence of an agency action, NEPA does not obligate agencies to analyze these effects because “the causal chain is too attenuated.”

Underpinning this decision is the majority’s concern that courts are interfering with agency decision-making. The majority opined that “[a] relatively modest infrastructure project should not be turned into a scapegoat for everything that ensues from upstream oil drilling to downstream refining emissions.” The majority then chided courts to “strive, where possible, for clarity and predictability.” And, the majority took a swipe at litigants using NEPA to thwart agency approvals, stating that “[t]he political process, and not NEPA, provides the appropriate forum in which to air policy disagreements.”

Importantly, the majority acknowledged a potential and limited exception for projects that are closely connected in both time and location. In such cases, an agency may be required to treat the projects as a single action for purposes of NEPA review. Even in those circumstances, however, the agency’s judgment about whether two projects are sufficiently interrelated remains subject to deference. The majority warned that the existence of some potential relationship between projects is not enough to collapse them into a single NEPA analysis unless they are functionally and temporally linked.

Deference is Dead – Long Live Deference

Although the Court last year eliminated Chevron deference in Loper Bright Enterprises v. Raimondo, 603 U.S. 369 (2024), the majority in Seven County described deference as the “central principle of judicial review in NEPA cases” and held that agency NEPA decisions are entitled to “substantial deference.” The majority reasoned that NEPA’s procedural nature warrants such deference. Furthermore, the majority criticized courts that have second-guessed agency judgments about the content and structure of an EIS and emphasized that NEPA does not require courts to “micromanage” agency decisions or demand exhaustive discussion of every conceivable environmental effect. Instead, courts must “disaggregate” their role from an agency’s role and need only review whether the agency “reasonably considered” the environmental consequences of the specific project under review.

The Concurrence Rejects the Majority’s Broader Reasoning

Justice Sotomayor, joined by Justices Kagan and Jackson, concurred in the judgment but declined to adopt the majority’s sweeping holding that eliminated agencies’ obligation to analyze the impacts of separate projects and the majority’s criticism of judicial overreach. The concurrence focused instead on a narrower rationale: That the STB lacked legal authority to deny the railway project based on potential drilling or refining activity, and therefore was not required to analyze those effects under NEPA. The concurring justices expressed concern with the majority’s emphasis on policy and its broader reading of NEPA limitations. While the outcome appears unanimous, the concurring opinion’s analysis sharply diverged from the majority’s holding.

The Decision is a “Course Correction” at a Time When NEPA Implementation is Already in Flux

The majority described its decision as a “course correction” necessary “to bring judicial under NEPA back in line with the statutory text and common sense.” But the decision is also significant because it comes at a crossroads for NEPA implementation. At President Trump’s direction, the Council on Environmental Quality (CEQ) has rescinded its existing NEPA regulations. Further, the President has directed federal agencies to revise their NEPA procedures to expedite permitting approvals. And, voices on the political right and left increasingly cite NEPA as an obstacle to the federal government’s ability to move nimbly to approve projects and infrastructure. As agencies move forward with revising their NEPA procedures to expedite permitting, Seven County will certainly influence these procedures.

The Seven County decision will particularly impact NEPA analyses for fossil fuel development and infrastructure. The Bureau of Land Management (BLM) faced a series of judicial decisions, finding it failed to adequately analyze the “downstream” impacts of oil and gas leasing and development. Similarly, courts have found flaws with the Federal Energy Regulatory Commission’s (FERC) analysis of greenhouse emissions associated with natural gas pipelines. The Seven County holding eliminating the obligation to analyze the impacts of separate projects will streamline agencies’ analysis prepared in response to these judicial decisions and analysis prepared for new oil and gas leasing, development, and infrastructure. Moreover, the majority’s language criticizing courts that “micromanage” the NEPA process should provide federal agencies with the confidence to complete NEPA analyses timely and allow projects to move forward.

Notably, although the Seven County holding is significant, it only relates to one element of NEPA analysis—secondary effects from proposed projects. Seven County does not directly address other issues that arise in NEPA litigation, such as the adequacy of alternatives, public participation, and what impacts are “significant”—except to reinforce that agencies are entitled to deference on these issues.

In sum, the Court’s decision provides important clarification on the limits of NEPA’s scope. By affirming that agencies are not required to evaluate environmental effects arising from actions outside their regulatory authority, and by reinforcing that NEPA’s procedural nature, the decision is likely to reduce litigation risk for environmental reviews that are carefully framed and thoughtfully documented.

In a cautionary tale for renewable energy developers operating on split estates, the United States v. Osage Wind, LLC litigation continues to carry significant legal and practical implications. In late 2023, the U.S. District Court for the Northern District of Oklahoma issued a permanent injunction directing Osage Wind, LLC (“Osage Wind”) to dismantle its wind farm in Osage County, Oklahoma, after more than a decade of litigation.[1] In March 2025, Osage Wind obtained a temporary stay of that order while it challenges the decision on appeal.[2] Although the stay temporarily delays enforcement and the court’s findings remain subject to appeal, the case reinforces the legal risks that wind developers face when seeking to develop projects involving split surface and mineral estates.

Background: Surface Development and Mineral Rights Conflict

In 2010, Osage Wind and the affiliated Enel entities leased 8,400 acres in Osage County, Oklahoma for the construction of the Osage Wind Farm, which includes 84 turbines, underground and overhead transmission lines, and access roads.[3] The leases used for the Osage Wind Farm covered only the surface estate and did not include any mineral rights.[4] Under the Osage Allotment Act of 1906, Congress severed the mineral estate in Osage County and reserved it for the Osage Nation, to be held in trust by the United States.[5] As such, any mineral development (including excavation or use of minerals) requires a federal lease under 25 C.F.R. §§ 211 and 214.[6]

During construction, Osage Wind excavated subsurface materials, then crushed and reused the excavated rock as structural backfill for turbine foundations.[7] The Osage Minerals Council and the Bureau of Indian Affairs warned the company that these activities required a lease related to the mineral estate, but Osage Wind did not obtain such lease.[8]

Litigation followed after Osage Wind failed to obtain a mineral lease.[9] The district court initially ruled in favor of Osage Wind,[10] but in 2016, the Tenth Circuit reversed and held that Osage Wind’s excavation and reuse of minerals as foundation backfill qualified as “unauthorized mining and excavation” and that Osage Wind was required to obtain a lease under 25 C.F.R. 211 and 214.[11] On remand, the district court granted summary judgment for the United States and the Osage Minerals Council, finding Osage Wind liable for unauthorized mining, trespass, conversion, and continuing trespass.[12] In 2023, the court awarded $242,652.28 in damages for conversion, and $66,780.00 for trespass, and granted equitable relief for continuing trespass, citing the ongoing use of mineral materials beneath the turbines.[13] As part of that relief, the court issued a permanent injunction requiring Osage Wind to remove all 84 wind turbines and restore the land to its pre-construction condition.[14]

Temporary Stay Granted

In March 2025, the U.S. District Court for the Northern District of Oklahoma granted Osage Wind’s motion to stay enforcement of both the permanent injunction and the monetary judgment.[15] The court acknowledged that Osage Wind had not shown a strong likelihood of success on the merits of its appeal, but nonetheless found that forcing the company to remove the wind farm before appellate review could result in irreparable economic harm.[16] Osage Wind argued that dismantling the turbines would cost $36,000,000, jeopardize existing tax equity arrangements, result in damages and expenses related to the termination of the surface lease and other agreements, and eliminate ongoing revenue from the project, all of which are harms that could not be undone if the company ultimately prevailed on appeal.[17] To obtain the stay, the court required Osage Wind to post a supersedeas bond in the amount of $10,036,500 to cover the damages award, potential interest, and related costs during the appeal.[18]

Key Takeaways for Energy Developers

The Osage Wind litigation underscores the importance of understanding the legal framework governing severed mineral estates. Developers should recognize that even incidental use of subsurface materials, such as crushing and reusing excavated rock for turbine foundations, may constitute mineral development and trigger leasing and permitting requirements.[19] In addition, remedies for unauthorized mineral use may extend beyond monetary damages to include removal of infrastructure, especially if courts find continuing trespass or ongoing interference with the mineral estate. These considerations are particularly relevant in co-location or multi-use energy projects, where surface development may conflict with underlying mineral rights.

Osage Wind’s appeal of the district court’s ruling is pending. Although the injunction and payment of damages have been temporarily stayed, the court’s broader legal conclusions remain in effect. These include the finding that excavation and reuse of minerals on the site constituted mineral development requiring a federal lease. The case continues to serve as a reference point for energy developers, permitting authorities, and investors navigating the legal complexities of developing and operating on split estates.

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[1] U.S. v. Osage Wind, LLC, No. 4:14-cv-00704-JCG-JFJ, 2024 U.S. Dist. LEXIS 228482, at *4 (N.D. Okla. Dec. 18, 2024).

[2] U.S. v. Osage Wind, LLC, No. 4:14-cv-00704-JCG-JFJ, 2025 U.S. Dist. LEXIS 37050, at *3 (N.D. Okla. Mar. 3, 2025).

[3] Osage Wind, 2024 U.S. Dist. LEXIS 228482, at *4.

[4] Id.

[5] Id.

[6] U.S. v. Osage Wind, LLC, 710 F. Supp. 3d 1018, *1038 (N.D. Okla. 2023).

[7] Osage Wind, 2024 U.S. Dist. LEXIS 228482, at *5.

[8] Osage Wind, LLC, 710 F. Supp. 3d at *1040.

[9] Id.

[10] Osage Wind, LLC, 2024 U.S. Dist. LEXIS 228482, at *5.

[11] Id.

[12] Osage Wind, 2024 U.S. Dist. LEXIS 228482, at *107-08.

[13] Id. at *107.

[14] Id.

[15] Osage Wind, 2025 U.S. Dist. LEXIS 37050, at *5.

[16] Id. at *17.

[17] Id. at *19.

[18] Id. at *27.

[19] U.S. v. Osage Wind, 2024 U.S. Dist. LEXIS 228482, at *5.