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.

On April 23, 2025, the Department of the Interior announced it will “accelerate” permitting procedures for energy projects by fast-tracking reviews under the National Environmental Policy Act (NEPA), Endangered Species Act (ESA), and National Historic Preservation Act (NHPA). “Accelerate” is an understatement, because the Department will compress reviews that otherwise may take years into a few weeks or months. The Department cited President Trump’s declaration of a national energy emergency as justification for the accelerated procedures.

What projects are eligible for these accelerated procedures?

Authorizing bureaus within the Department of the Interior may use the accelerated procedures for projects that will identify, lease, site, produce, transport, refine, or generate the following resources: domestic crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, coal, biofuels, geothermal heat, the kinetic movement of flowing water, and critical minerals, as defined by 30 U.S.C. § 1606(a)(3).

Project proponents must request in writing that the authorizing bureau use the accelerated procedures for each statute and, further, may be required to agree to certain conditions.

What do the accelerated NEPA procedures involve?

Expedited environmental assessments. For projects that likely will not have significant environmental impacts, the authorizing bureau must issue an environmental assessment (EA), finding of no significant impact (FONSI), and decision record within 14 days of submission of a complete application.

Expedited environmental impact statements. For projects that likely will have significant environmental impacts, the authorizing bureau must prepare an environmental impact statement (EIS) within 28 days of publishing a notice of intent. The accelerated procedures do not, however, mandate a timeline in which the authorizing bureau must publish the notice of intent after receiving a request to use accelerated procedures.

The notice of intent must be published on a public website, rather than in the Federal Register. The notice of intent must solicit comments and announce a virtual or in-person public meeting. Most comment periods should be approximately 10 days.

Within 28 days of the notice of intent, the authorizing bureau must publish a final EIS and submit it to the Environmental Protection Agency. No draft EIS is required, and the bureau will not solicit public comment on the EIS once published. The accelerated procedures do not specify a deadline for the authorizing bureau to issue a record of decision.

No expedited procedures for other forms of NEPA compliance. The Department does not provide any expedited procedures for the use of categorical exclusions or Determinations of NEPA Adequacy.

Process to request accelerated procedures. Only projects for which a plan of operations, application for permit to drill, or other application has been submitted are eligible for the accelerated procedures. A project proponent must submit a written request that the authorizing bureau use the accelerated procedures to comply with NEPA, on a form attached to the emergency procedures. The proponent must attach its plan of operations or application to the written request.

Proponent commitments. With its request for accelerated procedures, the proponent must agree to (1) operate in accordance with the approved application; (2) take measures to mitigate reasonably foreseeable significant adverse effects on the quality of the human environment; and (3) abide by applicable federal, state, and local environmental laws. Notably, with respect to No. 2, the accelerated procedures suggest, but do not state, that the project proponent rather than the authorizing bureau identifies appropriate mitigation measures.

What do the accelerated ESA procedures involve?

Deferred section 7 compliance. Section 7 of the ESA requires federal agencies to consult with the U.S. Fish and Wildlife Service (FWS) to ensure that federal actions are not likely to jeopardize the continued existence of any endangered or threatened species or result in the destruction or adverse modification of their critical habitat. The accelerated procedures require the authorizing bureau to, first, inform FWS about the proposed action and decision to use the alternative consultation procedures and, then, to “coordinate” with FWS. The authorizing bureau may then proceed to approve the proposed action.

Once the national emergency has terminated, the authorizing bureau must initiate section 7 consultation with the FWS. FWS must deliver either a biological opinion or letter of concurrence to the authorizing bureau, as appropriate, in accordance with the timeframes set forth in the ESA section 7 implementing regulations at 50 C.F.R. part 402.

Process to request accelerated procedures. Only projects for which a plan of operations, application for permit to drill, or other application has been submitted are eligible for the accelerated procedures. A project proponent must submit a written request that the authorizing bureau use the accelerated procedures to satisfy its Section 7 obligations, on a form attached to the emergency procedures. The proponent must attach its application to the request. Unlike a request to use accelerated NEPA procedures, a request to use accelerated ESA procedures does not require any applicant committed measures.

What do the accelerated NHPA procedures involve?

Expedited section 106 consultation. Section 106 of the NHPA requires federal agencies to consider the effects of their actions on historic properties. Regulations at 36 C.F.R. part 800 set forth a detailed process for agencies to comply with section 106. The accelerated NHPA procedures allow authorizing bureaus to bypass these procedures.

To use accelerated procedures, the authorizing bureau must notify the Advisory Council on Historic Preservation, the relevant State Historic Preservation Officer (SHPO), any relevant Tribal Historic Preservation Officer(s), and interested Tribes of the specific energy project for which the bureau intends to use the accelerated procedures. The authorizing bureau must invite their comments within seven days of the notice.

Notably, if a Bureau of Land Management (BLM) programmatic agreement (PA) or state protocol contains specific emergency procedures, BLM must follow those procedures. BLM has entered into state protocols or PAs with state SHPOs in most western states.

Process to request accelerated procedures. Only projects for which a plan of operations, application for permit to drill, or other application has been submitted are eligible for the accelerated procedures. A project proponent must submit a written request that the authorizing bureau use the accelerated procedures to comply with the NHPA, on a form attached to the emergency procedures. The proponent must attach its application to the request.

Proponent commitments. With its request for accelerated procedures, the proponent must agree to implement “to the extent prudent and feasible” measures that avoid or minimize harm to historic properties. The accelerated procedures suggest, but do not state, that project proponent rather than the authorizing bureau identifies the appropriate avoidance and minimization measures.

What should project proponents expect from these accelerated procedures?

These accelerated procedures are bold and untested interpretations of NEPA, the ESA, and the NHPA, as well as the President’s emergency powers. These procedures will be a lightning rod for litigation, inviting challenges to both the procedures themselves and any projects that they authorize. Therefore, project proponents should think critically about whether and when to use these accelerated procedures.

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If you have any questions, please contact Kathleen C. Schroder, Randy Hubbard, Almira Moronne, or Lindsay Dofelmier.

On April 17, 2025, the U.S. Fish and Wildlife Service (FWS) and the National Marine Fisheries Service (NMFS) (together, the “Services”) published a proposed rule to rescind the current regulatory definition of “harm” under the Endangered Species Act (ESA) at 50 C.F.R. § 17.3. The existing definition, which includes “significant habitat modification or degradation” that actually kills or injures listed species, has long been a point of legal and policy contention. The Services now conclude that the definition does not reflect the best meaning of the statutory term “take” and is inconsistent with the ESA’s text, structure, and historical understanding. Public comments are due by May 19, 2025.

The ESA prohibits the “take” of endangered species, which the statute defines as including a range of actions such as “harass, harm, pursue, hunt, shoot, wound, kill, trap, capture, or collect.” Since 1975, the Services have interpreted “harm” to include indirect actions—such as habitat degradation—that significantly impair essential behavioral patterns. In Babbitt v. Sweet Home, 515 U.S. 687 (1995), the Supreme Court upheld the Services’ interpretation under Chevron deference, which allowed courts to defer to an agency’s permissible interpretation of an ambiguous statute. Justice Scalia, joined by Chief Justice Rehnquist and Justice Thomas, dissented, arguing that the definition stretched the meaning of “take” beyond its historical usage and violated established canons of statutory interpretation.

In 2024, the Supreme Court overruled Chevron deference in Loper Bright Enterprises v. Raimondo, 603 U.S. 369 (2024), holding that agencies must adopt the “single, best meaning” of a statute, rather than merely a permissible one. Relying on Loper Bright and Justice Scalia’s Sweet Home dissent, the Services in the proposed rule take the position that the current regulatory definition of “harm” extends the ESA beyond what the statute authorizes. They emphasize that “take” historically referred to affirmative acts directed at individual animals, such as killing or capturing, not to habitat changes with incidental effects.

In the proposed rule, the Services stress that the rescission would be prospective only and would not affect existing permits. Nor would it alter the statutory definition of “take,” which remains broad and continues to encompass “harm.” However, by eliminating the current regulatory definition of “harm,” the Services aim to realign their interpretation of “take” with what they believe to be its narrowest and most textually faithful reading. The Services do not propose a new definition to replace the rescinded one.

The proposed rule represents a significant departure from longstanding agency practice. By excluding habitat modification from the definition of “harm,” the Services would effectively narrow the scope of activities subject to incidental take prohibitions. This change could ease regulatory burdens for landowners, project developers, and other regulated entities whose activities may affect listed species indirectly through habitat impacts.

The proposed rule is consistent with the Trump administration’s efforts to narrow wildlife protection statutes’ applicability. On April 11, 2025, the Acting Solicitor of the Department of the Interior issued Memorandum No. M-37085 reinstating a 2017 Solicitor’s Opinion that concluded that the Migratory Bird Treaty Act does not prohibit the accidental or incidental taking or killing of migratory birds.

If you have any questions, please contact Katie Schroder or Cormac Bloomfield.

On March 31, 2025, the Colorado Department of Public Health and Environment’s (CDPHE) Water Quality Control Division (“Division”) revised the CW-14 policy related to reporting and permitting of discharges from dewatering systems for select activities. This policy outlines applicable activities for a which a long-term dewatering permit is not required and the criteria, conditions, and control measures that must be met to avoid permitting requirements and enforcement.

Under the Revised Policy, Qualifying Discharges from Certain Foundation Dewatering Activities May Not Require a Permit

The most substantial change to CW-14 is that it now applies to gravity-flow or foundation dewatering systems that are installed to displace groundwater to protect or maintain underground parking garages, elevator shafts, and similar subterranean features associated with buildings.[i] Under the revised CW-14, no permit is required for long-term foundation dewatering activities[ii] that meet the criteria, conditions, and control measures of the revised policy. For a full list of policy-applicable discharges, please refer to the revised policy.

The Division made this change after it determined that (1) there is a low risk of environmental harm to receiving waters from the discharges from applicable activities and (2) administering and enforcing discharge permit coverage or reporting requirements for the significant number of foundation dewatering systems would be impracticable and an inefficient use of the Division’s resources.

However, the revised policy makes clear that the Division’s decision to expand the applicability of CW-14 to long-term foundation dewatering systems is a “time-limited” and “short-term solution” to be implemented while the Division investigates long-term solutions to address these discharges. The current policy has a scheduled review date of March 31, 2030.

Categories of Activities Not Applicable to CW-14

The updated policy also expands the list of non-applicable discharges for which the policy does not apply and may, therefore, still require a permit. The revised CW-14 is not applicable to discharges from an area associated with “Industrial Activity”[iii] or to discharges that have come into contact with active Construction Activities.[iv] Nor does the revised policy apply to discharges from any short-term (less than two years) dewatering activities, including those eligible for coverage under general permits COG080000, Discharges From Short-Term Construction Dewatering Activities, and COG317000, Discharges from Short-Term Remediation Activities (or the equivalent renewed general permits). It also does not apply to discharges from well development and pumping tests that are eligible for coverage under general permit COG608000 (or the equivalent renewed general permit). For a full list of non-applicable discharges, please refer to the revised policy.

What does this mean for current COG318000 permit holders?

If an existing COG318000 permit holder has not submitted a permit renewal application by May 31, 2025, the permit will expire on that date. After expiration, the Division “does not intend” to pursue enforcement action against an owner or operator of a previously authorized dewatering system while the updated policy is in force, provided the discharge meets the conditions, criteria, or control measures of the policy. 

If, however, an existing COG318000 permit holder’s dewatering discharges will not comply with the updated policy (either because the discharges are from ineligible activities or do not meet the conditions, criteria, or control measures), the permit holder should submit its renewal application for permit coverage of these discharges. The Division will determine the appropriate response for unpermitted or unreported discharges for which the revised policy does not apply.

Owners and operators of dewatering discharges currently covered by the updated CW-14 policy should periodically ensure that their activities remain covered by the policy since the Division has indicated that the extension of the policy is not meant to be a long-term solution for long-term foundation dewatering discharges.

Owners and operators are responsible for identifying sources of groundwater contamination at the dewatering location and conducting source water sampling and analysis to determine whether the discharge will cause serious environmental harm, adverse impacts to the beneficial uses of state waters, or whether it poses an imminent or substantial endangerment to public health and/or the environment. 

If you have any questions about the updated policy or how it may affect your permitting needs, please contact Melanie Granberg or Ixchel Parr-Culver.

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[i] The updated policy expands the list of CW-14 applicable dewatering activities although as before, non-applicable discharges may exist within the permit-exempted categories.

[ii] Foundation dewatering systems to which the revised policy applies are pumping systems that are installed to displace groundwater to protect or maintain the underground portions of buildings, drinking water impoundments, and transportation-related infrastructure such as bridges/over-passes, and similar subterranean features.

[iii] The definition of “Industrial Activities” was expanded to include: activities at recycling stations; activities with groundwater contamination at hazardous waste treatment, storage, or disposal facilities operating under an administrative or court order or permit; activities with groundwater contamination at CERCLA sites or facilities; sites required to remediate groundwater contamination from leaking underground storage tanks; and activities at sites where institutional controls prohibit access to or consumption of groundwater.

[iv] “Construction Activities” are defined as “[g]round surface disturbing and associated activities (land disturbance), which include, but are not limited to, clearing, grading, excavation, demolition, installation of new or improved haul roads and access roads, staging areas, stockpiling of fill materials, and borrow areas.”

The U.S. Department of the Treasury (the “Treasury Department”) and the Financial Crimes Enforcement Network (“FinCEN”) have recently made significant announcements that impact the enforcement and scope of the Corporate Transparency Act (the “CTA”). These developments are expected to reduce compliance burdens for many businesses, particularly domestically formed companies.

Key Takeaways

• Recent announcements from FinCEN and the Treasury Department have suspended enforcement of the CTA’s beneficial ownership information (“BOI”) reporting rule under the current FinCEN deadlines, for both domestic reporting companies and foreign reporting companies.^[1]
• The March 2, 2025 announcement from the Treasury Department indicates that the CTA reporting rules will be modified such that only foreign reporting companies will be subject to the CTA following implementation of such rules.

CTA Scope Expected to be Narrowed

As previously reported in our February 20th legal alert, on February 18, 2025, CTA compliance again became mandatory – albeit not for long –  following the stay of a nationwide preliminary injunction that was in effect prior to that time. FinCEN issued a release at that time modifying reporting deadlines and, notably, stating that it would be initiating a process to revise the BOI reporting rule to reduce the burden for lower-risk entities, including many U.S. small businesses. FINCEN stated that this revised approach aligns with broader government efforts to reduce the regulatory burden on businesses while maintaining the integrity of anti-money laundering frameworks.

On February 27, 2025, FinCEN released another announcement, stating that it would not issue fines, penalties, or take enforcement actions against any company for failing to file or update BOI reports by the then-current deadlines. The Treasury Department followed up on FinCEN’s release with its own announcement on March 2, 2025, stating that “with respect to the Corporate Transparency Act, not only will it not enforce any penalties or fines associated with the beneficial ownership information reporting rule under the existing regulatory deadlines, but it will further not enforce any penalties or fines against U.S. citizens or domestic reporting companies or their beneficial owners after the forthcoming rule changes take effect either.” The release goes on to say the Treasury Department “will further be issuing a proposed rulemaking that will narrow the scope of the rule to foreign reporting companies only.” The rules, if finalized in line with such announcement, are expected to remove all CTA obligations for domestic reporting companies.

This temporary non-enforcement policy, and the potential modifications to the reporting rule previewed by the Treasury Department, provide businesses with much-needed relief and additional time to understand potential future rule changes.

Subject to additional developments and final rulemaking, the status of the CTA is now as follows:

For U.S. Citizens, Domestic Reporting Companies and Their Beneficial Owners	– No enforcement for failure to meet current BOI reporting deadlines. – Proposed Treasury Department rulemaking expected to eliminate CTA obligations completely.
For Foreign Reporting Companies	– No enforcement actions for failure meet current BOI reporting deadlines. – FinCEN Interim final rule for revised reporting deadlines expected to be issued prior to March 21, 2025. – Proposed Treasury Department rulemaking expected to narrow application of the CTA to foreign reporting companies only.

Next Steps

Domestic reporting companies can expect to no longer have filing obligations under the CTA, absent rulemaking that is inconsistent with the Treasury Department’s announcement.

Foreign reporting companies should monitor regulatory developments and expect to potentially have to file some form of BOI reports in accordance with the forthcoming regulations referenced by FinCEN and the Treasury Department.

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For more information on the CTA and certain key developments leading up to this point, please refer to Davis Graham’s past CTA legal alerts:

• The Corporate Transparency Act – Basics That Every Business Formed or Registered in the U.S. Needs to Know (released on November 16, 2023)
• Corporate Transparency Act – Reporting Deadline (January 1, 2025) for Established Reporting Companies Approaching (released on November 7, 2024)
• Corporate Transparency Act – Nationwide Injunction Temporarily Stays Reporting Deadline (released on December 6, 2024)
• Corporate Transparency Act – Reporting Again Required Following Stay of Preliminary Injunction (released on December 24, 2024)
• Update: Corporate Transparency Act Back in Force (released on February 20, 2025)

Contact Nathan Goergen, Sheila Forjuoh, or Erin Mooney with any questions.

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[1] A “domestic reporting company” is defined under the CTA as any corporation, limited liability company, and any other form of entity created by filing with a secretary of state or similar office under the laws of a state or Indian tribe.

A “foreign reporting company” is defined under the CTA as a corporation, limited liability company, or other entity formed under the law of a foreign country that is registered to do business in the United States. Additional clarifications on this definition may be forthcoming as part of the Treasury Department’s proposed rulemaking.

Following the stay of the last-remaining nationwide injunction, the reporting obligations of the Corporate Transparency Act (“CTA”) have been re-instated, with a new deadline of March 21, 2025, for most non-exempt reporting companies.

On February 18, 2025, the U.S. District Court for the Eastern District of Texas in Smith et al. v. U.S. Department of Treasury stayed its nationwide preliminary injunction that prohibited the enforcement of the CTA. The Texas district court’s decision came after the Supreme Court stayed a similar injunction in the McHenry v. Texas Top Cop Shop, Inc. case. Smith was the last remaining nationwide injunction of general applicability prohibiting enforcement of the CTA’s requirements. As a result, CTA reporting is again mandatory, subject to certain revised reporting deadlines.

FinCEN’s Response and New Reporting Deadlines

On February 18, 2025, FinCEN responded to the ruling in the Smith case by publishing an alert notifying reporting companies that beneficial ownership information (“BOI”) reporting requirements are once again back in effect, subject to the below extended deadlines:

Type of Non-Exempt Reporting Company	Extended Deadline
Reporting companies created/registered on or prior to February 19, 2025	March 21, 2025
Reporting companies previously given a reporting deadline later than March 21, 2025	The later deadline*
Reporting companies created/registered after February 19, 2025	30 days after formation

_{* For example, if a reporting company previously qualified for one of FinCEN’s disaster relief extensions that would have extended such reporting company’s filing deadline to a date after March 21, 2025, then such reporting company will still be subject to such later reporting deadline, rather than the March 21, 2025 deadline}.

Potential for Additional Revisions

The CTA and the currently effective reporting deadlines continue to be the subject of pending litigation and legislative and regulatory focus. FinCEN explicitly noted in its latest alert that it continues to assess its options to further modify deadlines, and a number of legal challenges and legislative actions remain active at various stages of the judicial or legislative process, respectively. For the latest on CTA enforcement requirements, visit FinCEN’s CTA landing page, or reach out to your Davis Graham attorney.

In the waning days of the Biden administration, two significant developments arose affecting federal onshore oil and gas leasing. First, the United States Court of Appeals for the Ninth Circuit vacated leases sold at the June 2018 Wyoming oil and gas lease sale but reversed a district court decision vacating other leases. Second, the Bureau of Land Management (BLM) announced an environmental impact statement (EIS) to analyze the greenhouse gas impacts of issuing more than 3,200 leases that have been the subject of litigation brought by the citizens’ group WildEarth Guardians.

In a Long-Awaited Decision, the Ninth Circuit Upholds Vacatur of the June 2018 Wyoming Lease Sale but Leaves Other Sales Intact

On January 17, 2025, a three-judge panel of the Ninth Circuit issued a 98-page decision on appeals of two decisions by the U.S. District Courts for the Districts of Montana and Idaho in Montana Wildlife Federation v. Haaland, No. 18cv69-BMM (D. Mont. May 22, 2020), and Western Watersheds Project v. Haaland, No. 18cv187-REB (D. Idaho Feb. 27, 2020). In those decisions, the district courts vacated oil and gas leases sold at multiple lease sales in multiple states.

The Ninth Circuit largely upheld the district courts’ decisions that BLM violated the National Environmental Policy Act (NEPA) and Federal Land Planning and Management Act (FLPMA) when selling the leases. With respect to the Montana Wildlife Federation decision, two members of the three-judge panel found that, for the June 2018 Wyoming lease sale, BLM did not properly implement an objective in the 2015 greater sage-grouse resource management plans (RMPs) to prioritize oil and gas leasing outside of greater sage-grouse habitat. One member of the panel dissented on this issue.

Then, the Ninth Circuit upheld the Montana Wildlife Federation court’s decision to vacate leases sold at the June 2018 Wyoming lease sale. The court determined that the district court appropriately vacated the leases because the seriousness of BLM’s failure to apply the prioritization objective outweighed the disruptive consequences of vacatur.

With respect to the Western Watersheds Project decision, the Ninth Circuit agreed with the district court that BLM violated FLPMA by shortening the public protest period for leases sold at the June and September 2018 Wyoming lease sales, the June and September 2018 Nevada lease sales, and the September 2018 Utah lease sale. The court further held that BLM violated NEPA by shortening the public comment period for leases sold at the September 2018 Wyoming, Utah, and Nevada lease sales.

The Ninth Circuit, however, held that the Western Watersheds Project court erred in vacating leases sold at the June and September 2018 Wyoming lease sales, the June and September 2018 Nevada lease sales, and the September 2018 Utah lease sale. The court reasoned that, with respect to the procedural NEPA and FLPMA errors, a likelihood existed that BLM could substantiate its decision. The court directed the district court to remand the leasing decisions to BLM for further proceedings in compliance with NEPA and FLPMA but to enjoin BLM from “permitting any surface disturbing activity in the interim.”

The Ninth Circuit’s decision does not necessarily mark the end of this appeal. Parties may seek en banc review of the panel’s decision (i.e., review by the full appeals court.

If no party seeks en banc review, or if en banc review does not produce a different result, then the consequences of the decision are significant with respect to the Montana Wildlife Federation litigation. Although the Ninth Circuit only upheld vacatur of one lease sale, the district court in Montana Wildlife Federation has issued a second decision finding similar error as the appealed decision due to BLM’s application of the prioritization objective in the greater sage-grouse RMPs. In the second decision, the district court vacated the December 2017, March 2018, and June 2018 Nevada lease sales, and the December 2017 and March 2018 Wyoming lease sales. The Montana Wildlife Federation plaintiffs likely will argue that vacatur of those leases should be affirmed in light of the Ninth Circuit’s decision. Furthermore, the Montana Wildlife Federation plaintiffs have brought similar challenges to leases sold at the February, September, and December 2019 and December 2020 Wyoming lease sales and the December 2017, March 2018, and March and December 2019 Montana lease sales. The district court has not yet issued a ruling on those lease sales.

With respect to the Western Watersheds Project litigation, the impacts of the decision are less significant. Although the Western Watersheds Project plaintiffs have also challenged additional lease sales in that litigation (i.e., leases in “Phases Two and Three”),  their grounds for challenge differ from those at issue in the appeal. Additionally, the district court has declined to vacate the leases that were the subject of a second phase of that litigation.

Lessees who have leases that are the subject of the Montana Wildlife Federation and Western Watersheds Project litigation should assess the impacts of the Ninth Circuit’s decision on their leases and development plans.

BLM Announces an Intent to Prepare an EIS to Analyze the Impacts of Leasing on Greenhouse Gas Analysis

On January 16, 2025, BLM published in the Federal Register a Notice of Intent to prepare an EIS analyzing the potential impacts of issuing 3,224 oil and gas leases on greenhouse gas emissions. The Federal Register notice stated that the EIS may also analyze other “common impacts” to resources such as wildlife, water resources, and night skies.

The leases to be analyzed in the EIS were the subject of multiple lawsuits, including:

• WildEarth Guardians v. BLM, 19–cv–00505 (D.N.M.), 20–2146 (10th Cir.) (challenging leasing decisions in New Mexico);
• WildEarth Guardians v. Bernhardt, 16–cv–01724 (D.D.C.) (challenging leasing decisions in Colorado, Utah, and Wyoming);
• WildEarth Guardians v. Bernhardt, 20–cv–00056 (D.D.C.) (challenging leasing decisions in Colorado, Montana, New Mexico, North Dakota, South Dakota, Utah, and Wyoming);
• WildEarth Guardians v. Bernhardt, 21–cv–00175 (D.D.C.) (challenging leasing decisions in Colorado, New Mexico, Utah, and Wyoming); and
• WildEarth Guardians v. Bernhardt, 21–cv–00004 (D. Mont.) (challenging leasing decisions in Montana, North Dakota and South Dakota).

In September 2022, BLM had prepared a draft supplemental environmental assessment (EA) analyzing the potential greenhouse gas impacts from certain leasing decisions; however, BLM never finalized that EA. In the Federal Register notice, however, BLM explained that it had elected to prepare an EIS because of “new science and information related to greenhouse gas emissions, climate change, and the social cost of greenhouse gases . . . and the number of oil and gas leases under consideration.” BLM particularly pointed to the Department of the Interior’s estimates of the social cost of greenhouse gases related in October 2024.

The Federal Register notice provided a timeframe for preparation of the EIS. In total, BLM estimated the EIS would take a minimum of approximately a year and a half to complete. The Federal Register notice did not address whether BLM would approve development on the subject leases while the EIS was ongoing.

Publication of the Notice of Intent opened the scoping process for the EIS. BLM is accepting public comment until March 17, 2025.

Whether the incoming presidential administration will pursue the EIS has not been determined, although the “Unleashing American Energy” Executive Order announced yesterday calls the EIS into question. Lessees should closely watch the status of this EIS and assess its potential impact on their development activities.

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Please contact Katie Schroder with any questions.