This document provides a comprehensive contextual bill summary of the Bipartisan American Affordability and Jobs Act of 2026 (BAAJA, S.5653), as introduced by Sens. Shelley Moore Capito (R-W.Va.), Mike Lee (R-Utah), Sheldon Whitehouse (D-R.I.) and Martin Heinrich (D-N.M.) on September 30, 2026.
C2ES has produced this summary to provide an explanation of BAAJA and how it could affect federal permitting and infrastructure development. For selected provisions, the summary provides additional context on existing law and processes, the significance of the proposed changes, and their potential benefits, drawbacks, and broader implications.
Summary: This section would clarify the role of the National Environmental Policy Act (NEPA) as a statute that establishes a procedure for agencies to evaluate and inform the public about the reasonably foreseeable environmental effects of major federal actions. Major federal actions are actions taken by an agency that are subject to substantial federal control and responsibility, for example, granting a right-of-way across federal land for a transmission line; the definition excludes certain nonfederal projects with minimal federal funding or involvement. This section also states that NEPA is intended to inform federal decision-making and does not require agencies to choose a particular environmental outcome.
Context: This provision would reinforce in statute the legal understanding of NEPA as a procedural law. Before a federal agency takes or approves certain actions, it must consider the potential environmental consequences and, where required, reasonable alternatives. The level of review varies depending on the project: actions that normally do not have significant environmental effects may qualify for a categorical exclusion; projects with uncertain effects may require an environmental assessment (EA); and projects expected to have significant effects require the more detailed environmental impact statement (EIS). NEPA is intended to ensure that agencies and the public understand those effects before decisions are made, but it does not require an agency to choose the option with the least environmental impact identified in an EA or EIS.
Summary: This section would expand NEPA’s statutory definitions, including several terms that determine when agency action requires a NEPA review and the scope of that review. The following are some of the notable changes and are not an exhaustive list:
Authorization: This section would create a statutory definition of authorization; a term used in legislative text but not currently defined in NEPA’s definitions section. Under this definition, an authorization would be any federal administrative decision or interagency consultation required or authorized under federal law to implement a proposed agency action, including leases, rights-of-way, easements, licenses, permits, approvals, findings, and determinations.
Categorical exclusion: A categorical exclusion identifies a set of actions that normally do not significantly affect the human environment and therefore do not require preparation of an EA or EIS. Current law defines these as categories identified by federal agencies. This section would expand the definition to also include categories of actions that Congress designates as categorical exclusions by statute.
Major federal action: This section would add specific exclusions to the current definition of major federal action, such as maintenance of federal facilities costing no more than $10 million and proposed agency actions which was previously underwent NEPA review by another agency.
Record of stakeholder engagement: This section would create a new statutory definition of record of stakeholder engagement, defined as a document that summarizes a project sponsor’s preapplication engagement with federal, state, local, Tribal, and community stakeholders, including key feedback and how it was incorporated into the project. While the provision would require a record of engagement that occurred, it would not itself require the project sponsor to engage with every potentially affected stakeholder.
Summary: This section would require every federal agency to revise its regulations, procedures, or policies as needed to implement this title. The Chair of the Council on Environmental Quality (CEQ), referred to as the Chairman in this bill and throughout this summary, would work to standardize agency procedures to the maximum extent practicable and could provide agencies with technical assistance. CEQ is the White House entity responsible for coordinating and providing governmentwide guidance on NEPA.
Summary: This section would require agencies to develop methods for considering environmental values that are consistent with the requirements for minimum functional and data and technology standards for agency implementation of eNEPA technologies, meaning digital tools used for environmental reviews and permitting.
Summary: This section would expand the circumstances in which an agency may determine whether a proposed action requires the preparation of an environmental document (i.e., an EA or EIS).
Under this section, a proposed action could qualify for one or more categorical exclusions, whereas current law is written in terms of a single categorical exclusion. However, an agency could not repeatedly apply the same or similar exclusions for environmental review that are based on size, acreage, or dollar thresholds for the same proposed action. This limitation is intended to prevent agencies from stacking threshold-based exclusions to avoid preparing an EA or EIS for an action that exceeds the relevant threshold. The provision would also expressly recognize categorical exclusions established by Congress.
An environmental document would also not be required if the lead agency determines that a state or Tribal environmental review serves a similar function as NEPA compliance, or that compliance with another federal law serves a similar function for the action. This section would allow the project sponsor to ask the lead agency to stop the preparation of an EA and proceed directly to an EIS.
If the lead agency determines that no environmental document is required, no other federal agencies could prepare their own environmental document for the same proposed action.
Context: These changes could reduce duplicative environmental review and would allow projects to move more quickly through the permitting process when another review process or existing categorical exclusion already addresses the relevant environmental issues. The changes would also give the lead agency greater control over whether an additional environmental document is required, which could provide more consistency and certainty across multiagency projects.
Summary: This section would strengthen coordination of federal environmental reviews by clarifying the responsibilities of lead and cooperating agencies, establishing additional permitting deadlines, and creating new mechanisms to resolve interagency disputes and enforce deadlines.
Lead agency
A lead agency is the federal agency primarily responsible for managing and coordinating the NEPA review when multiple agencies are involved. The bill would retain the existing criteria for determining which agency serves as lead but would shorten the process for resolving disagreements over that designation.
This section would also expand the lead agency’s responsibilities by expressly granting it the authority to define and determine the project’s purpose and need, reasonable alternatives, and reasonably foreseeable environmental effects within its jurisdiction. In a NEPA review, “alternatives” are other ways of accomplishing the proposed agency action’s purpose and need, while the “no-action alternative” considers what would happen if the action was not taken. This section prevents the lead agency from considering alternatives, other than the no-action alternative, that do not fulfill the proposed agency action’s purpose and need or the goals of a project sponsor. For projects initiated by a Tribe involving Tribal trust resources, the lead agency would presume that the no-action alternative has negative effects.
If an environmental review or authorization is at risk of missing deadlines set by the project schedule, the lead agency would notify the Chairman of the reason for the potential delay.
Cooperating agencies
This section would limit cooperating-agency designation to agencies with jurisdiction by law and would establish deadlines for identifying and inviting cooperating agencies, accepting or declining an invitation, and bringing in agencies that were initially overlooked.
Cooperating-agency comments on the environmental review would be limited to matters within that agency’s jurisdiction, including environmental effects and authorizations for which it is responsible. Cooperating agencies would be bound by the lead agency’s purpose and need and could consider only alternatives the lead agency determines are reasonable, although they could assist in preparing the environmental document with the lead agency’s agreement.
Coordinated reviews
To the maximum extent possible, agencies would conduct their respective reviews and authorizations concurrently and establish procedures to keep the overall process coordinated and on schedule.
Scientific information
This section would provide that agencies are not required to consider scientific or technical research that becomes publicly available after the notice of intent or decision to prepare the environmental document. Agencies also could not delay an environmental document or authorization beyond its deadline while waiting for new research or information that was not yet available. However, this section would preserve applicable requirements under the Administrative Procedure Act concerning review of information received during public comment.
Public participation
This section would establish a 45- to 60-day public comment period following publication of a notice of intent to prepare an environmental impact statement in the Federal Register. The comment period would allow the public to provide input on potential alternatives, environmental impacts, and relevant information, studies, or analyses related to the proposed agency action. The lead agency and project sponsor could agree to extend the comment period, up to a maximum of 75 days.
Existing documents
At the project sponsor’s request, the lead agency would also have to consider and, where appropriate, adopt or incorporate analysis prepared under state or Tribal environmental-review processes that serve a similar function as NEPA.
Review and permitting deadlines
This section would create deadlines for issuing a record of decision and for completing outstanding permits and authorizations. After an environmental review is completed and made public, participating federal agencies would have 90 days to decide outstanding permits and authorizations, while other federal agencies would have 120 days. After an EIS is published, the lead agency would have 45 days to issue a record of decision. Extensions of the applicable review deadlines would require project-sponsor approval.
This section also builds on CEQ’s existing role in resolving interagency disputes by establishing a more specific process for project sponsors to elevate delays or disagreements that threaten applicable deadlines. The bill would set deadlines for CEQ to resolve those disputes, allow the Chairman to issue a binding determination if necessary, and create consequences when agencies fail to comply or continue to miss permitting deadlines. Those consequences could include requiring certain senior agency officials to spend at least 50 percent of their workweek addressing the delay and restricting official travel by the head of the agency until the agency comes back into compliance. The Chairman’s dispute-resolution order would be final and not subject to judicial review.
It would also strengthen judicial enforcement of permitting deadlines by establishing a specific process for project sponsors to seek expedited court review when an agency fails to act on time, subject to limited circumstances that may excuse the delay.
Agency oversight and reporting
This section would require agency heads to submit annual reports on deadline performance to the Chairman, including information on missed deadlines for environmental documents, reviews begun before the Fiscal Responsibility Act of 2023 that remain incomplete, each key permitting agency’s on-time completion rate, and its progress compared with the previous year.
The Chairman would then compile the agency reports, make recommendations for improving agency performance, and submit the consolidated report and recommendations to the House Committee on Natural Resources and the Senate Committee on Environment and Public Works.
Context: Federal environmental reviews and related permitting can take years to complete, particularly where a project requires approvals from several agencies.
Current law already provides for a lead agency, cooperating agencies, coordinated environmental reviews, and one- and two-year deadlines for EAs and EISs, respectively. This section would strengthen that existing framework by giving lead agencies more authority to coordinate reviews and manage deadlines. For projects that require approvals from several federal agencies, that change could reduce duplication, conflicting demands, and delays caused by agencies working on different timelines or reopening issues late in the process.
This section could also make overall project schedules more predictable by establishing enforceable timelines for permits and other federal authorizations beyond the environmental review itself. Compared with current law, project sponsors would have clearer mechanisms to address interagency delays and enforce missed deadlines, which could make project schedules more predictable and reduce prolonged permitting uncertainty.
The new limits on consideration of later scientific and technical information could also help prevent reviews from being prolonged by information introduced late in the process. A more stable administrative record could help agencies complete reviews on a predictable schedule and give project developers and investors greater confidence about when the process will conclude, which could help financing, investment, and construction planning decisions. However, limiting the consideration of new information could also prevent agencies from incorporating relevant scientific findings or newly identified environmental impacts that emerge during a lengthy review.
Summary: This section would extend from five to ten years the period during which agencies may rely on programmatic environmental analysis without additional review of that analysis, subject to the existing exception for substantial new circumstances or information. After that period, agencies could still rely on the analysis if they reevaluate it and determine that it remains valid. Programmatic reviews assess the environmental effects of a broader policy, program, or group of related actions and can provide a foundation for later project-specific reviews, reducing the need to repeat analysis that has already been completed.
Summary: This section would create a centralized system for sharing categorical exclusions across the federal government, which agencies would have to update when a new categorical exclusion is created or adopted.
Summary: This section would establish deadlines for an agency to determine whether an application is complete or whether additional information is needed. Once the application is complete, the agency would also face a separate deadline to determine whether the proposed agency action qualifies for a categorical exclusion, is not a major federal action, requires an environmental assessment, or requires preparation of an environmental impact statement.
Applicants for projects requiring NEPA review would also have to provide a list of known required federal, state, Tribal, and local authorizations; a record of pre-application stakeholder engagement meeting the requirements established earlier in the bill; and a brief description of the proposed agency action’s purpose and need, project location, and known alternatives.
Summary: Under this section, a NEPA claim would have to be filed within 150 days after the relevant authorization is published or otherwise made public. Where the agency provides a public-comment opportunity, the party bringing the challenge would have to have submitted a sufficiently detailed substantive comment raising the same issue. The plaintiff would also have to allege an actual or imminent injury amounting to direct harm.
Most claims would go directly to the relevant federal court of appeals, rather than beginning in federal district court. The appeals court would also have supplemental jurisdiction over related claims challenging the validity of the same authorization. Cases would, to the maximum extent practicable, be randomly assigned to judges and judgments would be issued as expeditiously as possible.
For a NEPA violation, remand without vacatur or an injunction would be the only remedy. This means the court would send the authorization back to the agency to correct the problem but would not vacate—or cancel—the authorization while the agency fixes it. The agency would have no more than 180 days to correct the deficiency, and both the authorization and the underlying project activity could remain in effect during that period.
Alternatively, and under limited circumstances, a court could issue a preliminary injunction, temporarily stopping an authorization while the lawsuit is still pending. To do so, the court would have to find a substantial likelihood that the authorization violates a federal law other than NEPA or the National Historic Preservation Act (NHPA); that an injunction is necessary to prevent irreparable harm; that the balance of equities favors the plaintiff, meaning the harm the plaintiff would face without an injunction outweighs the harm that temporarily stopping the authorization would cause to other parties; and that an injunction would be in the public interest. Any injunction could last only as long as reasonably necessary to correct the violation and prevent that harm.
When an agency prepares a supplemental or revised environmental document following a court order, a new 150-day challenge period would apply, but any subsequent lawsuit would be limited to new information contained in that supplemental document.
For actions authorizing use of lands, minerals, or other resources held in trust by the United States for a Tribe, NEPA-based administrative or judicial review would be barred. That restriction would not apply to challenges brought by the Tribe itself or challenges involving reasonably foreseeable effects outside the Tribal trust resources.
Courts reviewing NEPA claims would be required to give substantial deference to the agency regarding the scope and contents of the environmental document.
Finally, a final agency action could not be challenged under NEPA because the project sponsor omitted an engagement or other required information from the state, local, Tribal, and community portion of its record of stakeholder engagement.
The section would not create a cause of action or right to judicial review, limit claims alleging violations of an authorization’s terms, or affect the established deadline-enforcement review provided under NEPA.
Context: Under existing law, NEPA challenges to federal agency actions ordinarily proceed under the Administrative Procedure Act and are subject to a six-year limitations period after a claim accrues. This extended window can leave projects exposed to litigation long after permits are issued, creating uncertainty for project financing and development. This section would substantially shorten that period while preserving judicial review for parties that meet standing and participation requirements. Shortening that window could benefit project sponsors by reducing their exposure to new legal challenges. However, it could also limit the time communities and other potential challengers have to identify potential violations, develop legal claims, and seek judicial review.
Limiting courts to remand without vacatur as the remedy for NEPA violations would represent a significant shift from current law, under which courts may vacate an agency action, remand it without vacatur, or grant other appropriate relief depending on the circumstances. In its 8–0 decision in Seven County Infrastructure Coalition v. Eagle County, the Supreme Court recognized that deficiencies in environmental analysis do not necessarily require vacating a project approval. This provision would go further by requiring courts that find a NEPA violation to direct the agency to correct the deficiency within a specified deadline, without vacating the authorization or halting project activity. This could reduce the risk of construction or operations being interrupted while agencies correct procedural deficiencies, but would also limit courts’ ability to halt projects when they find that environmental reviews were inadequate.
This section would not eliminate legal challenges under other federal laws, which may provide different remedies, including vacatur. It would also allow a court to issue a preliminary injunction where there is a substantial likelihood that the authorization violates a federal law other than NEPA or NHPA and the plaintiff also satisfies the requirements relating to preventing irreparable harm to the plaintiff, the balance of equities, and the public interest. This exception would provide a pathway for projects to be temporarily halted based on likely violations of other laws, but a deficient NEPA analysis alone would not be enough to halt a project.
At the same time, removing the possibility of vacatur or an injunction based solely on a NEPA violation could reduce the consequences of inadequate review and therefore weaken one of the incentives for agencies to complete a thorough analysis before allowing a project to proceed. Additionally, the bill would require agencies to correct deficiencies identified by a court within the court-ordered deadline, but it does not expressly specify what remedies would be available if an agency repeatedly failed to adequately address those deficiencies. The lack of explicit remedies for repeated noncompliance leaves some uncertainty about how courts would respond if an agency repeatedly failed to adequately address deficiencies identified on remand.
Summary: This section would modernize federal environmental review and permitting systems by establishing government-wide data standards, digital tools, and a unified permitting platform for federal agencies. This section refers to these digital tools collectively as eNEPA technologies.
Data standards
This section would require the Chairman, in consultation with other federal technology and permitting officials, to establish and regularly update common standards for how agencies collect and organize permitting and environmental-review data. The standards would cover information such as projects, environmental documents, public comments, geospatial information, public engagement, case events, and project milestones. Key agencies would then implement the standards. The goal is to allow information to be more easily shared and used across agencies and reduce duplicative work.
Minimum technology requirements
This section would require the Chairman to issue guidance establishing minimum digital capabilities for agencies involved in environmental reviews and permitting. These include tools for: automatically sharing application data among agencies; screening applications for completeness and potential categorical exclusions; managing projects and documents; conducting geographic-information-system analysis; compiling and analyzing public comments; and maintaining administrative records. The provision would also allow artificial intelligence (AI) to assist with analysis and comment management where appropriate.
Agency implementation
This section would require each key permitting agency to assess its existing technology against the new standards, develop an implementation plan to meet those standards, and begin implementing the standards and minimum requirements. Agencies would report progress to CEQ and the Office of Management and Budget at least twice each year.
Development of digital permitting tools
This section would direct the Chairman, in consultation with other agencies, to develop prototype tools to help agencies meet the new requirements, prioritizing tools for project management, application submission and tracking, public-comment tracking, automated processing, interagency data exchange, and accelerated complex environmental reviews.
ePermit unified interagency data system
This section would require the Chairman and key permitting agencies to develop an interconnected federal data system for environmental reviews and authorizations. A central component of that system would be a common, cloud-based authorization portal through which project sponsors could submit materials, track reviews and authorizations, and collaborate with agencies. The portal would draw information from agency systems rather than necessarily replacing those systems with a single database.
The portal would also provide information to communities and the public, including project status, public meetings, environmental-review notices, timelines, project locations, environmental documents, and mitigation measures, while protecting sensitive or classified information.
The system would track metrics such as changes in permitting timelines, use of the portal, public comments and community meetings, litigation related to authorization deficiencies, and agency compliance with the new technology standards. Congress would receive access to aggregated agency-performance data for oversight purposes.
Agency and personnel performance
This section would require the Chairman to develop outcome-based measures for assessing the performance of both permitting agencies and agency personnel involved in environmental reviews and authorizations. The measures would be used to identify high-performing practices that could be replicated, areas of poor performance that may need additional oversight or support, and opportunities to direct resources from the Permitting Improvement Fund toward improving agency performance.
Reporting and safeguards
This section would require CEQ to report annually to Congress on development of the ePermit system and agency performance. This section would also specify that the new technology framework does not authorize CEQ or another agency to impose regulatory requirements beyond those already authorized by law.
This section would also authorize $5 million annually to carry out NEPA.
Context: Federal permitting currently relies on multiple agency-specific systems that do not always communicate easily with one another. Common data standards and interoperable digital tools could create a more coherent process, making it easier for agencies to share information while giving project sponsors and the public a clearer view of where a project stands. More broadly, modernizing and digitizing permitting systems could reduce reliance on fragmented or paper-based systems and make deadlines, responsibilities, and outstanding decisions easier to track.
Importantly, the resulting greater transparency could also improve public participation by making it easier to understand when and how to engage, allowing the public to surface potential conflicts earlier in the review process. These changes are particularly notable given the changes to judicial review in section 1110, which would shorten the period for bringing legal challenges and place greater emphasis on participation during the administrative review process. Digital tools could help make those opportunities for engagement more accessible and transparent. These changes would not alter the underlying environmental standards agencies must apply, but they could make the process of meeting those requirements more efficient, accessible, and predictable.
Summary: This section would define terms used throughout the Federal Permitting Improvement subtitle.
It would also create the term “transparency project” for projects that would be subject to the new public permitting tracker. This would include any project requiring an EIS and any project requiring an EA that remains incomplete 13 months after its applicable deadline.
Summary: This section would require the Chairman, in coordination with the General Services Administration, to maintain an online Environmental Review and Permitting Tracker showing the status of environmental reviews and federal authorizations for transparency projects.
Each project entry would include basic project information, the statement of purpose and need, project sponsor and lead-agency contacts, the status of any litigation related to the project, and quarterly updates on whether agencies are meeting the project schedule and statutory deadlines. If the schedule changes, the tracker would identify the reason for the change, including whether the delay was caused by an agency or the project sponsor.
Summary: This section would create a new Permitting Improvement Fund to improve the ability of key permitting agencies to complete environmental reviews and authorizations on time. The Chairman could transfer money from the Fund to agencies for activities including staff rotations between agencies, professional development, additional support for project managers, standardizing processes across regional and field offices, improving public engagement, or any other uses consistent with the Fund’s purpose as determined by the Chairman.
The bill would authorize $20 million annually from fiscal years 2027 through 2033 for the Fund.
Summary: This section would require the Environmental Protection Agency (EPA) to use formal notice-and-comment rulemaking when developing water quality criteria under section 304(a) of the Clean Water Act (CWA), which directs EPA to develop nationally recommended, science-based criteria for determining what levels of pollutants or other conditions are protective of human health, aquatic life, and other designated uses of surface waters. States and authorized Tribes may use these recommendations when developing their own enforceable water quality standards.
This section would also make EPA water quality criteria under section 304(a) and EPA actions defining the scope of “waters of the United States” (WOTUS) directly reviewable through CWA’s existing judicial-review framework. WOTUS is the term that determines the geographic scope of federal CWA jurisdiction.
Summary: This section would substantially revise section 401 of the CWA, which currently requires a certifying authority—a state, authorized Tribe, or EPA where no state or Tribe has authority—to certify that a federally licensed or permitted activity that may result in a discharge complies with applicable water quality requirements.
Scope of certification
This section would limit section 401 review to compliance with specified water quality requirements, including technology- and water-quality-based limits on pollutant discharges, state or Tribal water quality standards, standards for new sources, and requirements governing toxic pollutants and pretreatment. These requirements come from CWA sections 301–303 and 306–307.
A certifying authority could certify, deny, or conditionally certify a project. They could deny certification only if it finds by clear and convincing evidence that no reasonable modification or condition could allow the project to comply with section 401 requirements. For a certifying authority to certify the project with conditions, the conditions would have to be necessary for water quality compliance, the least burdensome means of achieving compliance, and consistent with the requirements of the underlying federal permit or license.
Application process
This section would establish a more detailed process for section 401 applications. Certifying authorities would be required to establish procedures for public notice, public hearings where appropriate, and optional prefiling meetings with applicants. The bill would also specify what information constitutes a complete application, including identification of the applicant and the federal license or permit subject to certification; the activity covered by that permit; the location and nature of any discharge and receiving waters; means to monitor, control, or manage the discharge; and other related federal, state, Tribal, interstate, or local authorizations.
Certifying authorities could promulgate regulations detailing additional requirements needed for application completeness. These additional requirements would have to be related to information needed to demonstrate compliance with water quality requirements and could reasonably be submitted at the time the application is submitted.
Certifying authorities would also have to promptly acknowledge applications and either determine that an application is complete or identify any missing information in writing, including the water quality requirement for which the information is needed. Applicants could seek judicial review if a certifying authority fails to follow these procedural requirements, with injunctive relief available where appropriate.
Denials
If certification is denied, the certifying authority would be required to identify the specific water quality requirements that present an issue and explain the basis for the denial. Certifying authorities could deny an application due to insufficient information. In those instances, the certifying authority would be required to describe the data or information required to evaluate compliance with water quality requirements.
Timelines
This section would require the federal licensing or permitting agency to establish a reasonable period for a certifying authority to issue a final action on an application, not to exceed one year from receipt of the certification application. The provision would not require the application to be complete for the timeline for action to start. That timeline could be extended only at the applicant’s written request and with the certifying authority’s written agreement. If an applicant voluntarily withdraws their application and submits a new certification application, the reasonable period of time would restart. Failure of the certifying authority to act by the deadline would waive the certification requirement.
A certifying authority could also affirmatively waive certification, and such a waiver would not be subject to judicial review.
Judicial review
In court challenges to a denial, the certifying authority would bear the burden of demonstrating by clear and convincing evidence that no reasonable modifications or conditions would allow the certification to be issued without violating water quality requirements. In the case of a challenge to certification conditions, the certifying authority would be required to demonstrate by clear and convincing evidence that the conditions are necessary to meet water quality requirements, are the least burdensome options, and are consistent with the underlying license or permit.
Interstate transmission and natural gas pipelines
This section would also establish a special rule for interstate electric transmission projects and interstate natural gas pipelines. For these projects, section 401 certification would apply only to a direct point-source discharge into WOTUS, rather than more broadly to the federally permitted activity.
The certification would still have to include any effluent limits, other discharge limitations, and monitoring requirements needed to ensure compliance with applicable water quality requirements, and those requirements would become enforceable conditions of the underlying federal license or permit. For facilities that are not subject to a separate federal operating license or permit, the certifying authority would also have an opportunity before operations begin to review how the facility will operate. If it determines that operation would violate applicable water quality requirements, the federal licensing or permitting agency could suspend the permit after a public hearing until compliance is assured.
If no applicable federal effluent limitation or performance standard exists for the direct point-source discharge, the certifying authority would certify that no such limitation or standard applies.
The review period for these certifications could not exceed nine months.
Context: Section 401 is an important part of the CWA’s cooperative-federalism framework, giving states and authorized Tribes a direct role in determining whether discharges associated with federally licensed activities comply with water quality requirements. Because a federal license or permit cannot be issued without certification or waiver, section 401 can also have significant implications for whether and how a project moves forward.
Both narrowing the water quality requirements considered during certification and establishing more demanding standards for denials and conditions could make the process more predictable for project sponsors. These changes could also reduce the risk that section 401 is used to address concerns only indirectly related to the discharge or water quality. This could be particularly consequential for large infrastructure projects crossing multiple jurisdictions, as projects involving discharges in multiple states may require separate certifications, increasing the opportunities for delays or denials. Interstate transmission lines and natural gas pipelines would receive additional streamlining because certification review would be expressly limited to direct point source discharges.
At the same time, these restrictions could limit the discretion of states and Tribes to respond to water quality concerns. In particular, the clear-and-convincing-evidence requirement and the least-burdensome-condition standard could make it more difficult to issue and sustain denials or protective conditions. Some observers have also raised concerns about the certification timeline because the review period would begin upon submission of an application without a prior determination that it contains all the information necessary to evaluate potential water quality impacts. This timeline could leave certifying authorities with insufficient time or information to conduct a thorough review, potentially resulting in certifications being waived or denied before outstanding water quality concerns are resolved.
Waivers would not be subject to judicial review, eliminating an avenue for outside parties to contest whether the certification requirement was properly waived.
Summary: This section would increase the maximum term for permits under the National Pollutant Discharge Elimination System (NPDES) from five years to ten years. NPDES permits regulate discharges of pollutants from point sources into waters covered by the CWA.
Summary: This section would make several changes to CWA section 404, which governs permits for discharges of dredged or fill material, such as soil, rock, or sediment, into WOTUS. The U.S. Army Corps of Engineers (Corps) generally administers the section 404 permitting program.
EPA authority
This section would limit the period during which EPA may use its authority under section 404(c) to prohibit, restrict, or withdraw the use of an area as a disposal site for dredged or fill material. EPA could exercise that authority only between submission of a complete section 404 permit application and issuance of the permit.
Section 404 general permits
General permits authorize categories of activities expected to have limited environmental effects, allowing qualifying projects to proceed without obtaining a separate individual permit. This section would extend the maximum term of section 404 general permits from five to ten years.
For general permits, this section would direct the Corps to consider only the effects of dredged or fill discharges on compliance with the same water quality requirements identified in section 401 and to treat discharges affecting less than two acres of navigable waters as having minimal adverse environmental effects.
Nationwide permits
Nationwide permits are a type of general permit that apply across the country to specified categories of activities, rather than only within a particular state or region. This section would require the Corps to maintain nationwide permits for activities currently covered by Nationwide Permits 12, 14, 43, 57, and 58 when the discharge affects less than two acres of navigable waters per single and complete project. These permits cover categories of infrastructure including oil or natural gas pipelines, linear transportation projects (such a highways), stormwater management facilities, electric utility lines and telecommunication activities, and utilities line activities for water and other substances. The Corps would retain authority to issue regional, state, and individual permits.
Reissuance of nationwide permits
This section would streamline reissuance of nationwide permits by providing that certain consultations under the Endangered Species Act and the NHPA would not be required. NEPA compliance could be satisfied through a programmatic EA, so long as the reissued permit does not make it easier for projects to proceed without additional preconstruction review by eliminating existing review requirements or increasing the thresholds that trigger them.
Context: EPA’s authority under section 404(c) serves as a backstop to prevent the discharge of dredged or fill material into specific waters that would cause unacceptable adverse environmental effects. Although EPA has rarely exercised this authority, it has used it to restrict certain activities outside the ordinary permit-review window. Limiting the period in which EPA can exercise this authority could give applicants more certainty by limiting EPA intervention to the period between a complete permit application and permit issuance. Some observers have expressed concern that limiting this authority to the permit-review window would reduce EPA’s ability to intervene to prevent substantial environmental harm.
Extending the maximum duration of section 404 general permits from five to ten years could reduce how often the Corps has to revisit and reissue them, providing greater predictability for recurring activities. Because these permits authorize categories of activities expected to have limited environmental effects, reducing the frequency of renewal could also lower administrative costs for the Corps and permit users. At the same time, less frequent reissuance could mean fewer opportunities to reconsider permit conditions in light of new environmental information or changing conditions.
The changes to nationwide permits would streamline permitting for infrastructure projects by allowing more activities to qualify for these permits rather than undergoing individual permitting reviews. The five nationwide permits identified in this section already exist, but currently have acreage limits of generally one-half acre of lost jurisdictional waters per single and complete project. This section would require the Corps to maintain these permits for qualifying activities involving discharges affecting less than two acres, potentially expanding their use. The existing acreage limits measure loss of jurisdictional waters, while this section refers to the area affected by discharges, so the change is not simply a numerical increase in the same threshold. This change could be particularly consequential for linear infrastructure, such as transmission lines and pipelines, which may cross numerous wetlands and waterways. Because separate water crossings can qualify as separate projects for nationwide permitting purposes, the two-acre threshold would not necessarily limit impacts along an entire route. However, acreage alone may not adequately capture environmental impacts, which can depend on factors such as habitat, hydrology, location, and cumulative effects. Requiring the Corps to treat discharges below two acres as having minimal adverse environmental effects could limit its ability to evaluate potentially significant impacts, particularly when multiple crossings collectively affect a larger area.
The changes to environmental review requirements for nationwide permit reissuances could also reduce administrative burdens and avoid repeated consultations when existing permits are renewed. However, these changes could limit opportunities to reassess environmental impacts under the ESA, NHPA, and NEPA, particularly as environmental conditions change over time. The exemptions would apply only to reissuances that preserve existing preconstruction notification requirements and thresholds, which could help maintain opportunities for project-level review. The provisions would not themselves eliminate otherwise applicable project-specific consultation requirements.
Summary: This section would create new judicial-review rules for section 404 permits, general-permit verifications, and state section 404 permitting programs. Under the CWA, a state may seek EPA approval to administer the section 404 permitting program instead of having those permits administered by the Corps
This section would also establish a 150-day statute of limitations for challenges to EPA approval of a state section 404 permitting program, the issuance of an individual or general section 404 permit, and a Corps verification that a particular activity is authorized under an existing general permit. The period would run from issuance of the approval, permit, or verification.
For challenges to EPA approval of a state permitting program or to the issuance of an individual or general permit, a plaintiff would be required to have participated in the relevant public-comment process and raised the issue being challenged with sufficient specificity. This requirement would apply only where a draft action was published in the Federal Register and the agency provided at least a 30-day public-comment period. It would not apply to challenges to Corps verifications that a particular activity qualifies under an existing general permit.
If a court finds that an individual or general permit was issued unlawfully, or that the agency acted arbitrarily and capriciously, the court would generally remand the matter to the Corps or state for further proceedings rather than invalidate or halt the permit. The court could vacate, revoke, enjoin, or otherwise restrict the permit only if it finds that the authorized activity would present an imminent and substantial danger to human health or the environment and that no other equitable remedy is available.
A similar standard would apply to challenges to Corps verifications under a general permit. If a court finds a verification unlawful, it could not enjoin or otherwise restrict the discharge unless the activity would present an imminent and substantial danger to human health or the environment and no other equitable remedy is available.
When a court remands a matter, it would be required to establish and enforce a reasonable schedule for the Corps, EPA, or state, as applicable, to respond to the court’s order. That deadline would not exceed 180 days.
Context: The judicial-review changes in this section broadly reflect the approach taken elsewhere in this bill for NEPA, including a shorter statute of limitations, participation requirements for certain claims, and a shift toward remand without vacatur as the default remedy.
For section 404 permits, this shift in remedies could be especially consequential because these permits directly authorize activities that may alter wetlands and other waters. Allowing a permit to remain in effect during remand could provide greater certainty for projects that have already received authorization, while courts would retain authority to halt activity that presents an imminent and substantial danger to human health or the environment. At the same time, some observers may view that threshold as too high in cases where environmental harm could occur before a permitting deficiency is corrected, particularly where those effects may be difficult to reverse.
Summary: To guide agency decisions, this section would create a statutory definition of “best scientific and commercial data available” and “best scientific data available,” terms used throughout the Endangered Species Act (ESA). This section would define these terms to include relevant and objective scientific and commercial information available at the time of the agency action, including credible and reliable data, models, and analyses that account for known or potential error and are applied using prevailing professional standards. It would also specify that information must be gathered and applied impartially, without presumptions or policy prescriptions that bias its use.
Summary: Section 7 consultation is the process through which a federal agency consults with the U.S. Fish and Wildlife Service or National Marine Fisheries Service when an action it authorizes, funds, or carries out may affect a listed species, meaning a species formally designated as threatened or endangered under the ESA, or its designated critical habitat. The consultation evaluates whether the action is likely to jeopardize the species or adversely modify its critical habitat.
This section would shorten the timeline for completing consultation and the existing thresholds governing when longer consultations require notice to, or consent from, a permit or license applicant. It would also establish that if consultation extends beyond the statutory deadline without the required notice or applicant consent, the applicant could seek judicial relief for the agency’s failure to act.
For projects that also require a NEPA environmental document, section 7 consultation generally would be required to be completed by the time the NEPA review is finished, unless extraordinary circumstances justify an extension.
Summary: This section exempts from ESA section 7 consultation projects that qualify for a NEPA categorical exclusion established in the Moving Ahead for Progress in the 21st Century Act. This exemption includes certain transportation projects in existing operational rights-of-way, such as resurfacing highways.
Summary: This section would create a new voluntary program allowing participating states to assume certain responsibilities currently carried out by the Interior Secretary under ESA section 7 responsibilities for projects or agency actions located within their borders. If the affected area extends into another state, the participating state would have to consult either with that state, if it also participates in the program, or with the Interior Secretary.
Projects or agency actions that cross state boundaries could not be assigned to a state under the program.
The Department of Interior would have to establish the program through rulemaking with a public-comment period. A state seeking to participate would have to demonstrate that it has sufficient legal, financial, and personnel resources, agree to waive sovereign immunity for the responsibilities it assumes (i.e., states could be sued for those responsibilities), and provide a public comment period on its participation before applying. The Interior Department could deny an application only if the state fails to demonstrate the necessary legal, financial, or personnel capability, and could receive technical assistance to address those deficiencies, if requested.
A participating state and the Interior Department would enter into a written agreement specifying the responsibilities being transferred. States would have to maintain sufficient capacity, comply with the same consultation and NEPA deadlines that apply to the federal government, provide information needed for federal oversight, and accept federal-court jurisdiction over their performance of the assumed responsibilities. Agreements could last up to ten years and be renewed.
Once responsibilities are assumed, the state would carry them out in place of the Interior Secretary without further federal approval. However, a permit or license applicant could still elect to consult with the Interior Secretary instead of the state.
The Interior Department would audit participating states annually during their first four years in the program and monitor compliance thereafter. Audits would be available for public comment. Audits could resume if there is reason to believe a state is not meeting its obligations. The Interior Department could terminate a state’s participation for inadequate performance after providing an opportunity to take corrective action, and a state could also withdraw voluntarily. The U.S. Fish and Wildlife Service would provide training and other capacity building initiatives to help states develop the capacity to participate in the program and to facilitate information sharing between states.
Context: Under current law, section 7 of the ESA directs federal agencies to consult with the U.S. Fish and Wildlife Service or NOAA Fisheries on the effects of federal actions on listed species and designated critical habitat, with states contributing information and expertise. Allowing participating states to assume Interior’s consultation responsibilities could give states a larger role in reviews for projects located within their borders, similar to approaches that give states implementation responsibilities under other federal environmental laws, such as CWA and NHPA. For states with sufficient staff and wildlife expertise, this could allow consultation to draw more on localized species and habitat information. Whether this reduces delays would depend largely on state capacity. The separate funding authorization could support state capacity, but actual funding would depend on appropriations.
At the same time, participating states vary in their staffing, scientific expertise, resources, wildlife laws, and approaches to species conservation. Shifting consultation responsibilities from federal wildlife agencies to participating states could therefore lead to greater variation in how section 7 consultations are administered nationwide, leading some observers to express concerns that the change could weaken species and habitat protection in some states relative to the status quo. That concern may be particularly relevant for species whose ranges cross state boundaries or for migratory species. In both cases, actions in one state can affect a species that is managed and protected across a much broader geographic area. The bill would require coordination with another participating state or the Interior Department in those circumstances, but would not require the Interior Department to approve each resulting consultation decisions.
This section’s qualification requirements, federal oversight, and interstate coordination requirements would likely address some of these risks.
Summary: This section would require challenges to biological opinions—the written conclusions of section 7 consultations evaluating whether federal actions are likely to jeopardize listed species or adversely modify critical habitat—to be filed in the U.S. Court of Appeals for the D.C. Circuit within 150 days after the biological opinion is made public.
Summary: This section would require the responsible federal agency to accept and integrate state-collected data when deciding whether to list or delist a species as threatened or endangered, provided the information meets this bill’s definition of the best scientific and commercial data available from section 1301.
Summary: This section would authorize $150 million annually from fiscal years 2027 through 2031 to support ESA section 7 consultation and state participation in the new state-assumption program.
Summary: This section would create a new grant program administered by the National Fish and Wildlife Foundation to support coastal state programs related to coastal resources, coastal natural infrastructure, and ecosystem services. Natural infrastructure would include features, such as wetlands, dunes, and reefs, that can provide flood protection, habitat, and other benefits. Funding would be allocated primarily equally among coastal states, with additional amounts based on tidal shoreline and coastal population density, and no state receiving more than five percent of total funding. The bill would authorize $50 million annually from fiscal years 2028 through 2032, subject to appropriations.
Summary: This section would limit federal agencies’ ability to revoke, suspend, modify, or otherwise interfere with federal authorizations or permits held by nonfederal project sponsors. This protection from interference would apply to a broad range of federal approvals in effect on or after September 16, 2026, including permits, rights-of-way, records of decision, findings of no significant impact, biological opinions, construction and operations plans, and other approvals necessary to construct or operate a project. For projects that have secured all necessary federal approvals, agencies also could not take other actions that interfere with construction or operation at full capacity.
Agencies could still take such action when required by a court; when the permit holder materially breaches the authorization or violates applicable law; when the authorization was obtained through fraud, intentional concealment, or material misrepresentation; at the request of the project sponsor or permit holder; or when necessary to prevent specific, urgent, substantial, and proximate harm to life, property, national security, or defense based on new information that was not considered when the in the underlying environmental review or final agency action. In the latter case, the agency action would be required to be reasonably limited to what is necessary to address the identified harm.
Before interfering with an authorization or project, the agency would have to provide the project sponsor with written notice explaining the action, the statutory authority supporting it, and the evidence on which it relies.
Affected project sponsors could challenge an agency action in court, and the federal agency would bear the burden of demonstrating by clear and convincing evidence that one of the statutory exceptions applies. If the agency fails to meet that burden, the project sponsor would be entitled to the reinstatement of the authorization and injunctive relief barring further agency interference with the project unless the agency first obtains an order from the same judge that heard the original case. The sponsor would also be entitled to monetary relief paid from the Judgment Fund—a U.S. Treasury account used to pay court judgments and settlements against the federal government—for attorney fees, litigation and delay costs, and additional monetary damages equal to between 25 and 50 percent of project costs incurred as of the date of the agency action, with the amount based in part on bad faith, patterns of similar federal interference, and the economic harm caused.
A special rule would apply to projects that received a federal stop-work order within the year before enactment that was subsequently enjoined by a court: that same judge would have jurisdiction over a challenge to subsequent federal interference with the project.
Context: Recent disputes over previously approved energy projects, including federal actions affecting offshore wind, have highlighted the risk that projects can secure permits, financing, and begin construction only to face later agency action that delays or reverses those approvals. Strengthening protections for issued federal authorizations could reduce that risk, improve investment certainty, and make it harder for administrations to target projects after permits have been issued.
The protections would apply across sectors and project types, meaning future administrations would face similar constraints when seeking to revisit previously issued approvals for both clean energy and fossil fuel projects. This could provide greater stability for long-term infrastructure investment, although it would also limit the ability of future administrations to change course after an authorization has been granted.
The breadth of the protections also raises questions about how much flexibility agencies would retain after an approval is issued. The section would prevent not only formal interference with issued authorizations, but also actions that interfere with construction or operation at full capacity of a fully permitted project. Some observers have expressed concern that this broad language could have unintended consequences—for example, inviting litigation claiming that subsequent regulatory actions (such as new health, safety, or environmental requirements) unlawfully interfere with an existing project. Agencies would retain authority under specified exceptions, but new information alone would not justify intervention. The exception for urgent harm would require a specific, substantial, and proximate threat to life, property, national security, or national defense. Environmental harm is not independently listed, although certain environmental risks could also threaten life or property.
The review standard and remedies would further reinforce those protections by shifting the burden to the federal agency to demonstrate by clear and convincing evidence that a statutory exception applies, and potentially exposing the government to substantial financial liability if the agency cannot justify its action under the section’s standards. The risk of significant financial penalties could deter unjustified federal interference, but it could also make agencies more cautious about revisiting existing approvals even where changed circumstances or new information may warrant action.
Summary: This section would create a new cause of action for applicants that can demonstrate that federal permits or authorizations have been improperly denied or unreasonably delayed as part of an intentional pattern of disparate treatment by the federal government against a specific type of energy project. The provision would apply to a broad, technology-neutral list of covered energy project types, including wind, solar, storage, fossil generation and production, nuclear, transmission, pipelines, mining, hydropower, geothermal, hydrogen, carbon management, and other energy-related projects.
To establish a pattern of disparate treatment, an applicant would have to show a substantial increase in the percentage of improper denials or unreasonable delays for that same type of project (e.g., wind, solar, transmission) compared with the five most recent calendar years of federal permitting data. The pattern would have to result from an intentional course of federal action undertaken to create the pattern. Applicants could rely on permitting statistics and, as supporting evidence, agency policies, executive orders, official guidance, or statements by executive branch officials that demonstrate bias in the permitting process specifically.
The cause of action would apply only to denials or delays occurring after enactment of this bill, meaning the provision would not be retroactive to permitting decisions made before enactment. A qualifying pattern of disparate treatment would be required to persist for at least 280 days for permits that require an EA or EIS, or 180 days for permits that do not require an EA or EIS. At least that many days of the pattern would have to occur after enactment, and claims could not be filed until the corresponding 280- or 180-day post-enactment waiting period had elapsed.
For a delay claim, an authorization or permit would have to be more than 60 days beyond the applicable statutory deadline. The applicant would also have to show that its application complies with applicable federal law and that the authorization, if granted, would not be subject to cancellation for the specified legal violations, fraud, intentional concealment, or material misrepresentation.
If an applicant successfully proves disparate treatment, a court would be entitled to provide injunctive relief, compensation from the Judgment Fund including attorney fees and litigation costs, economic damages associated with the denial or delay, and additional damages equal to 50 to 100 percent of the project’s reasonably expected construction costs. In determining those additional damages, the court would consider factors including bad faith, a pattern of similar federal interference, and the economic harm to the project sponsor. Applicants receiving relief would have to demonstrate the technical and financial ability to construct the project and, after securing all necessary federal approvals and absent force majeure, complete the project or repay all remedies received.
Additionally, for covered projects that require federal authorizations or permits but do not require an EA or EIS, all relevant federal agencies would also have to issue decisions on the applicable applications within one year after the latest application is determined complete.
Context: Federal permitting decisions can substantially affect whether energy projects move forward, raising concerns about the potential for administrations to favor or disadvantage particular technologies. This section seeks to deter administrations from systematically slowing or denying particular categories of energy projects for reasons unrelated to whether an individual project satisfies applicable law. This section would require applicants bringing claims to demonstrate both compliance with applicable federal law and an intentional pattern of disparate treatment affecting their project type.
The five-year comparison period would establish a baseline for evaluating whether a particular project type has experienced significantly different permitting treatment. However, the choice of baseline could influence which patterns are identified. Continued adverse treatment may therefore be difficult to challenge where the historical rate of denials or delays was already high, while substantially worse treatment of a previously favored project type could more readily support a claim, raising concerns that this baseline could put pressure on a later administration to maintain similar approval rates or timelines. Because the provision applies across covered project types, the same framework could protect clean energy projects from discriminatory treatment while also constraining similar treatment of fossil energy projects by a future administration.
The potential damages make this section particularly consequential. District court judges would determine whether the statutory requirements for unreasonable delay or improper denial have been met, including disputed questions, such as when an application became complete and when the applicable deadline began. The availability of substantial monetary damages could strengthen incentives for agencies to avoid intentional disparate treatment, while also encouraging litigation over contested permitting decisions, deadlines, and the application of the five-year baseline. The additional award would be based on expected construction costs rather than limited to the applicant’s demonstrated loss, so it could exceed the economic harm caused by the denial or delay. Bad faith would affect the amount awarded but would not be a separate prerequisite to liability; the intentional-pattern requirement would still apply.
These competing effects would depend in part on how courts interpret the provision’s standards and assess whether agencies acted with the required intent.
Summary: This section would allow applicants for covered projects that do not require an EA or EIS to seek judicial review if a federal agency misses the one-year permitting deadline established in section 1402 of this bill. The applicant could file in federal district court where the project is at least partially located.
An agency would not be considered in violation of the deadline if it demonstrates by clear and convincing evidence that the delay resulted from specified circumstances, including a natural disaster or war, a national emergency, fraud or material misrepresentation in the application, the applicant withholding necessary information, or a lapse in appropriations lasting more than 14 days.
If the court finds that the agency failed to comply with the deadline, it could issue injunctive relief and retain jurisdiction to ensure compliance. The court would be required to use expedited procedures and issue a decision within 120 days of filing. If relief is granted, the court would be required to order the agency to issue a decision on the application within 60 days.
Context: Statutory permitting deadlines may offer limited predictability when applicants lack an effective means of enforcing them. By establishing a process for seeking judicial relief when certain authorization deadlines are missed, this section would give the one-year deadline in section 1402 of this bill an enforcement mechanism. This change could provide greater certainty for projects that do not require an EA or EIS by reducing the risk that relatively straightforward federal authorizations remain pending indefinitely.
Summary: This section would substantially revise the federal backstop permitting framework for interstate transmission. Federal backstop authority allows the Federal Energy Regulatory Commission (FERC) to issue a federal construction permit for certain interstate transmission projects when a state lacks relevant siting authority, fails to act within the statutory timeframe, denies the project, or imposes conditions that make the project economically infeasible or undermine its transmission benefits. It would remove the current National Interest Electric Transmission Corridor (NIETC) designation process as a prerequisite to federal backstop permitting and instead allow qualifying transmission projects to access the federal process.
FERC would have to issue permits for projects in the national interest. Qualifying projects would be required to transmit electricity in interstate or foreign commerce; be consistent with the public interest; protect or benefit consumers and improve reliability; and operate at a voltage of at least 230 kV, with different voltage requirements to be determined by FERC for projects using advanced conductors. For transmission upgrades, such as reconductoring, the projects would also be required to reasonably and economically maximize the capacity of existing towers, structures, and rights-of-way.
This section would preserve states’ initial role in transmission siting but allows FERC-related prefiling to begin before a state application is submitted. For higher-voltage facilities (at least 345 kV), the applicant would be allowed to submit to FERC simultaneously with the state application, allowing the federal and state processes to proceed in parallel, although FERC would be unable to issue a permit unless one of the statutory conditions for backstop authority is ultimately met.
For projects that meet the eligibility criteria to be permitted under FERC’s backstop authority, utilities would be required to file tariffs allocating the costs of the new or modified transmission facilities. FERC would be required to ensure those tariffs are just and reasonable and allocate costs to benefiting customers in accordance with the cost-causation principle, that is, they are roughly commensurate with the benefits, including through: improved reliability; reduced congestion; reduced power losses; greater carrying capacity that delivers improved reliability or reductions in the cost of delivered power; reduced operating reserve requirements; and improved access to generation that achieves reductions in the cost of delivered power. Customers that receive no benefit or trivial benefits would not be involuntarily allocated any of the costs of those transmission facilities.
For coordinated federal authorizations, FERC would act as the lead agency in the case of facilities permitted under this section and the Interior Department would act as the lead agency in the case of facilities located on a lease, easement, or right-of-way granted by the Interior Secretary under the Outer Continental Shelf Lands Act.
This section would allow recovery of prudently incurred costs associated with payments to jurisdictions impacted by transmission facilities developed through the federal permitting and transmission-planning frameworks.
This section would also direct judicial review of covered federal authorizations, including specified state approvals required under federal law, to the courts designated for review of FERC orders. The FERC siting authority framework would exclude ERCOT and would contain an exemption for specified state and cooperative transmitting utilities unless they voluntarily submit to FERC jurisdiction for the purpose of FERC siting authority.
Context: Under current law, FERC’s backstop authority depends on DOE first designating a NIETC, meaning that even a transmission project that may otherwise warrant federal review cannot access FERC’s permitting process unless it falls within a federally designated corridor. In practice, that framework has not produced an effective pathway for transmission development.
Replacing that corridor-based prerequisite with project-specific eligibility criteria could provide a more direct and predictable route for transmission projects that have demonstrated national value while preserving states’ primary siting role. This change could be especially important for interregional transmission, where a single project may cross several states and can be delayed or prevented if one jurisdiction does not approve its portion of the line. A more accessible federal backstop could reduce that risk and increase the likelihood that projects with broad regional benefits are actually built. Greater interregional transmission could increase access to low-cost and clean power across planning regions, reduce congestion, provide savings for consumers, and improve reliability and resilience during extreme weather events.
However, some observers have raised concerns that expanding federal backstop authority could weaken state oversight of transmission development, particularly where states determine that a proposed project is unnecessary or its costs outweigh the benefits to their residents.
Summary: This section would create a new statutory framework for activities that maintain or increase grid capacity within existing rights-of-way or the minimum adjacent area necessary to complete the work. Covered activities would be categorically excluded from preparation of an environmental assessment or environmental impact statement under NEPA and would also be statutorily defined as not major federal actions under NEPA and not undertakings under section 106 of NHPA. Covered activities would include repair, maintenance, upgrades, reconductoring, use of advanced transmission technologies (ATTs), addition of energy storage near existing facilities, and other activities to maintain or increase the capacity of the electric grid. ATTs are technologies that increase the capacity of existing transmission lines.
This section would establish similar treatment for specified activities on existing interstate natural gas pipelines within previously authorized corridors. Covered activities that remain within the existing right-of-way, the footprint of previously authorized and environmentally reviewed construction, or the minimum adjacent area needed to complete the work would not be considered major federal actions under NEPA or undertakings under section 106 of NHPA. Covered activities would include repair, maintenance, replacement, upgrades, rebuilding, modification, optimization, minor relocation, looping, compression, capacity enhancement, and additions to existing pipeline facilities and associated infrastructure. The provision would not affect requirements under the CWA, CAA, or other federal laws not expressly addressed.
Summary: This section would require the Energy Department, in consultation with affected states and Tribes, to conduct a study of electric transmission capacity constraints and congestion within one year of enactment of this bill and issue an update at least every three years thereafter. The report could identify areas experiencing, or areas expected to experience, transmission constraints or congestion that adversely affect consumers. The Energy Secretary would be required to consult with affected transmission planning regions at least once every three years.
This section would also establish a new framework for regional and interregional transmission planning. Transmission planning is the process utilities and grid operators use to identify where new or upgraded transmission will be needed, evaluate potential projects, and determine which projects should be selected to meet future reliability, affordability, and system needs. For purposes of these planning requirements, FERC would have jurisdiction over transmitting utilities, including certain entities that are otherwise outside ordinary FERC public-utility jurisdiction. The Electric Reliability Council of Texas (ERCOT) would be excluded from this planning jurisdiction. State and municipal utilities and smaller electric cooperatives would also be excluded unless they voluntarily subject themselves to FERC jurisdiction for these purposes. Being subject to these requirements would not otherwise make those entities public utilities under the Federal Power Act.
FERC would be required to issue a rule that establishes mandatory regional and interregional transmission planning processes. Each transmission planning region would be required to establish and submit to FERC for approval a regional transmission planning process and one or more joint interregional transmission planning processes with neighboring regions. FERC would be required to also establish rate treatments for regional and interregional transmission planning and cost allocation.
Those planning processes would be required to include common assumptions and models on consistent timelines that allow regions to identify and select specific regional and interregional transmission facilities; consideration of reconductoring, advanced transmission conductors, and other modifications that can maximize the capability of existing towers, structures, and rights-of-way; a common set of transmission benefits; and selection criteria requiring projects chosen for construction or modification to improve reliability, protect or benefit consumers, and be consistent with the public interest.
This section would use the same transmission-benefit categories and cost-allocation principles that apply to projects permitted under FERC’s backstop authority. Benefits would include improved reliability, reduced congestion and power losses, greater carrying capacity, reduced operating reserve requirements, and improved access to lower-cost generation. Costs would be required to be allocated to customers that benefit, consistent with the cost-causation principle and roughly commensurate with those benefits, while customers receiving no or only trivial benefits could not be involuntarily allocated project costs.
Transmission planning regions would be required to submit these planning processes within two years of enactment of this bill and update them at least every four years. FERC would be required to review and approve the processes if they satisfy the statutory planning requirements, allocate costs in accordance with this section, ensure rates and terms are just and reasonable and not unduly discriminatory or preferential, and are consistent with the public interest. Compliance with previous FERC orders related to regional transmission planning would satisfy these regional planning and cost allocation requirements. FERC could grant an extension of up to six months if a region fails to submit a required planning process on time.
Projects selected through an approved regional or joint interregional transmission plan would also receive a streamlined path into FERC’s backstop permitting process. For purposes of obtaining a federal construction permit, those projects would be deemed to satisfy the substantive project-eligibility requirements, including the interstate-commerce, public-interest, consumer-benefit, reliability, and voltage criteria, as well as the requirement to maximize existing infrastructure where applicable. The project would still need to meet one of the state-related conditions that trigger FERC’s backstop authority.
Approval of a regional or interregional planning process would not itself be considered a major federal action under NEPA. However, a FERC backstop permit for a project selected through a joint interregional transmission plan would be considered a major federal action.
Context: Transmission planning is how utilities and regional planners determine what grid infrastructure will be needed in the future and which projects should be built to meet those needs. That planning is increasingly important as electricity demand grows, the generation mix changes, and more low-cost clean energy resources seek to connect to the grid. Because transmission projects can take many years to plan, permit, and construct, waiting until reliability problems or congestion are already severe can limit the options available to address those challenges and increasing costs. More forward-looking planning can help identify needs earlier, evaluate lower-cost solutions across a wider geographic area, and ensure that transmission investment supports reliability, affordability, and access to new generation.
FERC already requires regional transmission planning and interregional coordination through Orders No. 1000 and 1920. Order No. 1000 requires public-utility transmission providers to develop regional transmission plans and coordinate with neighboring regions to identify and evaluate potential interregional projects, but does not require them to develop a joint interregional transmission plan; Order No. 1920 requires long-term regional planning over a 20-year horizon. However, neither order requires neighboring regions to develop and submit a joint interregional transmission planning process comparable to the regional planning process. By establishing regional planning and cost-allocation requirements in statute, while recognizing compliance with existing FERC orders, the bill could make those requirements less dependent on future changes in FERC policy. It would also establish new requirements for joint interregional planning, where progress has historically been more limited.
Transmission lines that provide benefits across multiple regions can be difficult to advance when each region develops plans primarily around its own needs, assumptions, and cost-allocation rules. Requiring compatible assumptions and models, common benefit categories, and joint project selection could make it easier to identify projects whose reliability and consumer benefits are only apparent when regions are evaluated together.
However, requiring more coordinated transmission planning would not necessarily resolve disagreements over which projects should be selected or how their costs should be shared. States, utilities, and other stakeholders may disagree about how to measure a project’s benefits, particularly when the costs are concentrated in one region while the reliability or economic benefits extend across multiple regions. While this section would require costs to be allocated roughly in proportion to the benefits customers receive and protect customers receiving little or no benefit from being involuntarily assigned costs, determining those benefits could remain contentious. Cost allocation has already been a significant source of disagreement under FERC’s existing transmission-planning rules, and disputes over how the bill’s requirements are implemented could lead to further litigation, potentially delaying projects even after they have been selected through a planning process.
This section would also link planning more directly to permitting. A project selected through an approved regional or joint interregional planning process would be deemed to satisfy several of the substantive findings otherwise required for FERC backstop permitting. That would not itself authorize construction or eliminate the state-related conditions for federal backstop authority, but it would reduce the need to relitigate questions about a project’s reliability value, consumer benefits, and public-interest justification after those issues have already been considered through an approved planning process. This could create a smoother path from identifying a transmission need, to selecting a project, to ultimately permitting and building it.
Summary: This section would enhance FERC oversight of local transmission planning and development. FERC would be directed to establish procedures by which one or more states could refer a public utility for an investigation into the processes used by the public utility for planning and developing local transmission facilities. A local transmission facility would have to be located entirely within one public utility’s service territory, with its costs recovered entirely from transmission customers in that territory. A referral would be required to identify the planning practices at issue, potential harm to customers, and steps the state has already taken to address its concerns.
FERC would issue a notice for initial public comment and certify an investigative team that includes FERC enforcement staff and up to three representatives appointed by the state. If the investigation finds that a utility’s local planning is not producing efficient or cost-effective facilities, or is interfering with regional transmission planning, FERC could require changes to planning processes, reduce the utility’s return on equity for local facilities, eliminate the presumption that local investments are prudent, impose fines of up to $5 million per facility payable to the referring state, or issue any other appropriate remedy. The fine could apply only to a local facility developed or energized between 60 days before the referral and issuance of FERC’s order, where FERC finds that development or energization was imprudent and caused financial harm to customers in the referring state.
Summary: This section would prohibit a federal right of first refusal (ROFR) with respect to a transmission facility selected in a regional or interregional transmission plan for the purposes of cost allocation. An ROFR gives an incumbent transmission owner the first opportunity to build a project in its service territory before other developers can compete for it.
Context: Competition already exists for some regional transmission projects under FERC Order No. 1000, which requires the removal of federal ROFRs from certain regionally planned projects. Codifying this prohibition and expressly extending it to qualifying interregional projects would provide more regulatory certainty, making opportunities for nonincumbent transmission developers less dependent on future FERC policy changes. This section would not eliminate state ROFR laws, which can still limit competition in some jurisdictions.
Allowing qualified nonincumbent developers to compete with incumbent transmission owners could help lower project costs, encourage innovative project designs and financing structures, and expand the pool of developers able to build needed transmission. However, some observers argue that competitive selection processes can introduce delays and additional costs, and that existing transmission owners are better positioned to develop projects because of their familiarity with the grid, relationships with state regulators and communities, and responsibility for maintaining reliability.
Summary: This section would direct FERC to issue a rule requiring each transmission planning region to file a consolidated generation interconnection and regional transmission planning process. Interconnection is the process of connecting an electricity resource to the grid.
The planning process would be required to jointly evaluate electric transmission facilities and the generating capacity reasonably anticipated to be needed to meet future demand and forecasted generation over the next 20 years. Planning regions would be required to routinely identify and publish resource- and fuel-neutral planned interconnection locations and an upfront, fixed, zonal per-megawatt cost for each planned location, and it would establish a streamlined generator cluster study process with a single decision point, meaningful and nonrefundable financial security, and withdrawal penalties sufficient to deter speculative projects. Planning processes would be updated at least every two years. FERC would approve a process if it finds that the process ensures that the resulting rates, charges, terms, and conditions would be just and reasonable and not unduly discriminatory or preferential, and that the process would be consistent with the public interest.
Context: Generator interconnection studies assess the upgrades needed to connect proposed projects to the grid, while regional transmission planning evaluates broader infrastructure needs. Because these processes have historically been conducted separately, transmission upgrades needed to accommodate multiple generators may be identified later than necessary or planned on a project-by-project basis. Integrating interconnection and transmission planning through a proactive, 20-year process could allow shared transmission needs to be identified earlier, reduce interconnection delays, and avoid fragmented or redundant infrastructure, although the bill does not establish a specific deadline for completing interconnection studies.
Providing developers with upfront, fixed interconnection costs at planned connection locations could also help them assess where projects would be most economical to develop and help them make more informed investment decisions.
Summary: This section would establish new ratepayer protections related to computational loads, including data centers, AI facilities, cloud computing, and cryptocurrency mining. This section creates two related but distinct sets of requirements.
First, FERC would be required to revise its transmission pricing policy and rules for computational load sites connected to the bulk-power system, including facilities used for AI, cloud and software services, cryptocurrency mining, and other data-center computational activities. This portion is focused specifically on transmission service and does not include the 20-MW threshold used later in the section. Public utilities and transmitting utilities would be required to charge customers taking transmission service on behalf of computational load owners and operators both the embedded cost and incremental cost of transmission service, with the goal of minimizing or avoiding cost shifts to other consumers (e.g., residential ratepayers). Embedded costs are the existing transmission costs already reflected in applicable rates, while incremental costs are the additional costs of expanding the transmission system to serve the new load. Incremental payments would be credited against utilities’ transmission revenue requirements to prevent the same costs from being recovered from other customers. Computational loads that elect non-firm transmission service would be eligible for lower transmission costs. Non-firm transmission service allows customers to use available transmission capacity when it is not needed for higher-priority uses, but does not guarantee that capacity will always be available.
Second, this section would establish broader ratepayer protections for a defined covered load, meaning electricity demand attributable to one or more data centers or high-density computing facilities at a single site, or at multiple sites under common ownership or control, that equals or exceeds 20 MW or is expected to reach that level at full buildout. For these covered loads, this section defines incremental cost more broadly as the costs that would have been avoided if the load were not served, including the costs of constructing, owning, and operating generation or storage resources and transmission and distribution infrastructure associated with serving that load.
No portion of those incremental costs could be allocated to or recovered from other customers. A covered load would remain responsible for unrecovered incremental costs even if it stops taking service before those costs are fully recovered, and it would have to provide sufficient financial assurances or contributions before a utility constructs generation, transmission, or distribution facilities or upgrades needed to serve it.
States could charge these covered loads more than the embedded average cost and more than the incremental cost of serving them and use revenues collected above incremental cost to reduce rates for other retail customers. States could also use competitive solicitations or open seasons for covered loads to contract retail service, require a covered load to procure or contract for sufficient new generation to serve its demand, or condition service on a transmission-service arrangement that limits how much electricity the load can withdraw or the conditions under which it can do so.
States could treat covered loads as a separate customer class and establish rates, terms, and service priorities that are less favorable than those provided to other large industrial, manufacturing, or commercial customers.
The covered-load requirements in the second framework would apply to loads interconnecting on or after enactment of this bill. Arrangements approved by FERC or a state before enactment would remain in effect.
Context: Rapid growth in data-center electricity demand can require substantial investments in generation and transmission infrastructure, raising concerns that existing customers could bear costs associated with serving large new loads. The transmission-pricing provisions would create an exception to FERC’s longstanding prohibition on “and pricing,” under which a transmission customer generally cannot be charged both an embedded-cost rate and an incremental-cost rate for the same transmission service. For computational loads, this section would require both components to be charged, helping ensure that these loads pay both for use of the existing transmission system and for incremental transmission expansion attributable to serving their demand.
These changes reflect a broader effort to limit the risk of costs from qualifying large loads being passed to existing electricity customers. Giving states flexibility to determine how to implement these protections could allow them to account for differences in utility regulation and local grid conditions. However, due to the megawatt threshold, the requirements would not apply to every data center or computing facility, and determining which infrastructure costs are attributable to a particular covered load could remain complex, especially where upgrades also provide broader system benefits.
Summary: This section would create federal rules governing participation of qualifying behind-the-meter distributed energy systems (BTM DES) in wholesale electricity markets. A BTM DES is an energy storage system, a fuel cell system, a generator, located at a home, business, or other customer site on the customer’s side of the utility meter. It connects to the grid through the customer’s own electrical system, rather than through a separate direct grid connection.
To qualify to participate in the wholesale market, this energy resource would have to be able to come online within 15 minutes of being called upon and have output that can be dispatched and adjusted at the system operator’s signal, be located behind the meter of a retail customer of a distribution utility, have at least five kilowatts (kW) of rated capacity, and maintain metering and telemetry capabilities. Multiple BTM DES facilities could be combined into a qualifying BTM DES aggregation so that, together, they are large enough (at least 100 kW of combined capacity) to participate in wholesale markets.
This section would prohibit transmission organizations from using rates, terms, or practices that prevent a qualifying BTM DES aggregation from participating in wholesale electricity markets. That includes energy markets, where resources are paid for the electricity they supply; capacity markets, where resources are paid for being available when needed; and ancillary-services markets, where resources are compensated for services that help keep the grid balanced and reliable. Prohibited practices would include imposing inconsistent equipment requirements, requiring participation in the energy market as a condition of participating in the capacity market, or requiring a BTM DES resource to participate jointly with another resource located at the same site.
Participation in a retail market or program would not disqualify a qualifying BTM DES from participating in a wholesale market organized by a transmission organization. But payment from both retail and wholesale market for the same service during the same time period would be prohibited. Transmission organizations would have to establish metering, settlement, and reporting procedures to prevent that double compensation.
FERC would have to order repayment of double compensation. Knowing retention could also result in monetary penalties of up to three times the double compensation for each day it was knowingly retained, and suspension or termination of wholesale-market participation.
This section would require any distribution utilities within an organized wholesale market to interconnect eligible behind-the-meter resource in a timely fashion. State authority over distribution-level interconnection and retail billing would remain.
Additionally, this section would establish a DOE program to help state, Tribal, and local governments adopt voluntary streamlined permitting and inspection processes for distributed solar, batteries, electric-vehicle charging, hydrogen refueling, and similar technologies through online permitting, standardized inspections, technical assistance, certification, and prizes. It would authorize $20 million annually for fiscal years 2026 through 2031.
Context: BTM DES can provide flexible electricity supply on demand to stabilize the grid, lower energy costs, and provide backup power during outages. These resources can be aggregated into virtual power plants (VPPs) to reduce demand during extreme weather or high-load hours, in some cases helping prevent outages or defer the need for additional grid infrastructure. Some can also store electricity when prices are low and discharge it, or reduce electricity use, when prices are higher. Because BTM DES can be brought online far more quickly than other large-scale grid upgrades to meet surging local demand, enabling these resources to aggregate and participate in wholesale markets could create additional sources of flexible capacity and reliability services.
FERC Order No. 2222 already establishes a framework for aggregating distributed energy resources to participate in organized wholesale electricity markets. However, certain market rules and utility practices can still create barriers to participation. By establishing new statutory requirements for regional grid operators and distribution utilities, this section could expand opportunities for qualifying BTM DES to provide grid services and strengthen incentives for their deployment. The section’s separate local-permitting provisions could further support deployment by reducing administrative barriers to installing distributed energy technologies.
Summary: This section would direct FERC to require that public utilities use ATTs, including best-available transmission conductors, when constructing new or modifying existing transmission facilities under FERC’s jurisdiction. The statutory definition of ATTs would be expanded to include dynamic line rating, advanced power flow control, transmission topology optimization, and high-performance conductors.
In proceedings concerning recovery of ATT costs for covered projects, FERC would presume that using an ATT is prudent and that its associated costs are just and reasonable.
FERC would require that public utilities conduct recurring evaluations to determine whether the benefits associated with deploying ATTs, including benefits to the current transmission system of the applicable public utility, outweigh the costs. If the benefits outweigh the costs, the applicable utility would be required to deploy the ATTs on a timeline determined by FERC. FERC would also be required to establish penalties for failure to deploy qualifying technologies, potentially including reduced returns on equity. In the recurring evaluations, public utilities would be required to also evaluate planning and construction timelines for new transmission assets and the risks and impacts of potential delay. Those evaluations would also include a least-cost analysis and assess whether the costs reflect due care to minimize total project costs.
Context: ATTs expand transmission capacity, improving power flows and reducing congestion; this leads to lower power costs for consumers. ATTs can be deployed more quickly and at a lower cost than new transmission lines, as they make use of existing infrastructure (e.g., pylons, towers, and substations), bringing reduced power costs to consumers sooner. Existing law already directs FERC to encourage adoption of ATTs, this section would require their mandatory use and deployment. While this could accelerate adoption of cost-effective technologies, some observers may argue that a federal deployment mandate could limit utilities’ flexibility to account for differences in local geography, grid configurations, and operational needs, even with the bill’s required cost-benefit analysis.
Summary: This section would direct FERC to initiate a rulemaking to revise the Large Generator Interconnection Procedures to require public utility transmission providers to share and use queue management practices involving computing technologies, including AI, machine learning, and automation, to expedite the evaluation and processing of interconnection requests. FERC would be required to reopen this rulemaking every four years to assess additional steps to ensure public utility transmission providers are adequately deploying computing technologies.
Context: Interconnection procedures govern how transmission providers evaluate requests to connect large generating projects to the grid and identify necessary system upgrades. Improved data sharing and greater use of automation, machine learning, and other computing technologies could accelerate these procedures and help reduce interconnection backlogs. Faster processing could help new resources come online sooner to meet rising electricity demand, support reliability, and expand access to lower-cost generation, including clean energy. However, the extent of these benefits would depend on implementation, and faster studies alone would not resolve other barriers to interconnection, such as the need to construct transmission upgrades.
Summary: This section would establish requirements governing access to the grid data needed to conduct covered studies, including generation and load interconnection studies, feasibility studies, facilities studies, and affected-system studies. Transmission providers would have to obtain, assemble, maintain, and use the grid data that is necessary to conduct these studies and could request necessary information from other bulk-power-system owners, users, and operators. Recipients generally would have to provide requested data within 15 days, unless FERC establishes another timeline for the data category. Data would have to be usable or convertible, accurate, complete, and current, subject to confidentiality and security safeguards.
FERC would have authority to order compliance and address complaints alleging violations. If FERC finds a violation, it would have to issue a compliance order, including interim relief to prevent unreasonable delay in a covered study. Failure to comply would be treated as a matter affecting reliable operation of the bulk-power system, and noncompliance by a public utility could be subject to penalties.
FERC and DOE would also develop a reference specification identifying the data categories, formats or conversion standards, update frequencies, and validation standards needed to enable greater automation of interconnection studies. The specification could not be updated more frequently than every three years.
Context: Automated and faster interconnection studies depend on having complete, current, and machine-usable grid data. When inputs are missing, outdated, or incompatible, study teams may need to request additional information and reconcile data before completing their analysis. By establishing enforceable duties to provide accurate, current information in usable or convertible formats, this section could reduce such interruptions and support greater use of automated study tools.
Summary: This section would allow the administrator of each of the federal power marketing administrations to develop, implement, and annually review a compensation plan for employees of the federal power marketing administrations. Administrators would also receive greater flexibility to appoint and employ personnel, while retaining applicable merit-system principles.
Summary: This section would require FERC, at least once every five years, to review whether the fees and charges it assesses are sufficient to allow the Commission to handle its workload expeditiously and report the findings to Congress.
Summary: This section would direct the administrator of the Energy Information Administration (EIA) to revise Form EIA-861 to include data center load, including from facilities primarily used for AI, cloud computing, data hosting, cryptocurrency mining, and related computational activities. Form EIA-861 collects operational, structural, and financial data from distribution utilities and power marketers of electricity.
Summary: This section would make conforming amendments to the Federal Power Act to incorporate the new provisions created by this title. It would also expressly provide that nothing in the title gives FERC authority over retail electricity sales or local distribution of electricity.
Summary: This section would establish an expedited judicial-review process for federal authorizations for certain energy, mineral, carbon management, and wildfire-risk-reduction projects that also require a NEPA environmental document. Covered authorizations would include federal permits, lease sales, rights-of-way, and plans for energy and mineral projects under specified statutes; statements or permits under sections 7 and 10 of the ESA; and approvals for certain forest projects. Lawsuits challenging a final agency decision granting or denying a covered authorization would be required to be filed within 150 days after the decision is made public, unless a shorter federal period applies. The agency would have to make the decision public within three days of taking final action. Courts would be required to expedite their review and, if a decision is remanded to an agency, set a deadline of no more than 180 days for the agency to act, unless a longer period is necessary to comply with applicable law. If a supplemental or revised NEPA document leads to a new authorization decision, that decision would receive its own 150-day statute of limitations.
Context: Lengthy periods of exposure to litigation create uncertainty for infrastructure projects even after federal authorizations have been issued. For covered projects, the changes in this section could reduce that risk and provide clearer timelines for resolving disputes. The 150-day statute of limitations would shorten the period during which project sponsors face the risk of new legal challenges, while the 180-day remand deadline could limit how long a project remains in regulatory limbo if a court identifies a legal deficiency. Together, these provisions could make financing, construction planning, and project development more predictable by reducing prolonged litigation and permitting uncertainty. However, the shorter filing window would also limit communities’ and other potential challengers’ time to identify legal violations and prepare claims. The remand deadline could also place pressure on agencies to resolve complex deficiencies within too limited a period.
Summary: Under this section, federal drilling permits would no longer be required in certain cases where an oil and gas well is located on nonfederal land but involves federally owned oil and gas minerals. This exemption would apply when: the federal government owns less than 50 percent of the oil and gas minerals in the area associated with the well; a well on nonfederal surface and over nonfederal minerals enters and produces from federal minerals; or a well passes through federal minerals without producing from them.
Although a federal drilling permit would no longer be required in these circumstances, the Interior Secretary would still have to be notified of relevant state drilling applications and approvals involving federally owned oil and gas. The exemption would not apply to Indian lands, including lands held in trust or otherwise subject to federal restrictions on transfer.
The provision would not change the amount of royalties owed to the federal government for production from federal minerals, and the Interior Department would retain its other authorities under federal oil and gas royalty law. For wells covered by the exemption, the Interior Secretary’s authority under the Mineral Leasing Act would be limited; the Interior Secretary could not require a bond to protect the nonfederal surface, enter the land without the landowner’s consent, impose mitigation requirements, or require approval of surface reclamation.
Summary: This section would create a new process allowing Indian Tribes to grant rights-of-way across their land without approval from the Interior Secretary. The Interior Secretary would be required to approve a Tribal regulation governing the granting of rights-of-way. The regulations would be required to establish an environmental review process that identifies and evaluates significant environmental impacts, including a public comment period. The Interior Department’s decision approving a Tribal regulation would not be subject to review under NEPA, section 106 of the NHPA, or the ESA.
For a federally funded project, an Indian Tribe could rely on the federal agency’s environmental process rather than a Tribal review process.
The Interior Department would retain a backstop role. An interested party could ask the Interior Department to review whether the Indian Tribe followed its approved regulation. If the Interior Department finds a violation, it would be required to give notice to the Indian Tribe and an opportunity to respond before the Interior Department takes corrective action, including rescinding approval of the Tribe’s regulation and reassuming responsibility of right-of-way approvals.
Summary: This section would expand the Energy Act of 2020’s definition of an “eligible project,” which currently covers projects that generate energy from wind, solar, or geothermal energy on federal land, to also include projects that store energy generated from those sources. This section would then apply new processing requirements to rights-of-way for those eligible projects.
For rights-of-way for eligible projects on federal land, this section would create new statutory deadlines for the Departments of Interior or Agriculture to determine whether an application is complete, issue a notice of intent when an environmental impact statement is required, and issue any required cost-recovery agreement. It would also require the agency, once an application is complete, to either grant or deny the right-of-way if applicable legal reviews are finished or identify the remaining applicant and agency steps and the timelines for completing them.
The Interior and Agriculture Secretaries would be directed to develop or adopt one or more categorical exclusions for specified “low-disturbance” renewable energy projects. Low-disturbance activities would include surface disturbances under five acres previously analyzed under NEPA; repeat activities at the same location that have occurred within five years; activities on previously disturbed or developed land for which a land use plan or analysis under NEPA, which was approved within the prior five years, identified the activity as reasonably foreseeable; the installation, modification, operation, or removal of solar photovoltaic systems located on structures or previously developed or disturbed land of less than ten acres; minor maintenance; preliminary geotechnical investigations; and the construction or removal of meteorological evaluation towers. Categorical exclusions would have to allow for extraordinary circumstances under which they would not be available.
Finally, it would direct the Bureau of Land Management’s (BLM) National Renewable Energy Coordination Office to develop renewable-energy project review standards for use by regional renewable-energy coordination offices.
Context: Delays in federal right-of-way approvals can create uncertainty for clean energy and storage developers, particularly when application requirements or agency review timelines are unclear. The new right-of-way deadlines would give eligible renewable energy and storage project sponsors earlier information about application completeness, cost-recovery agreements, and outstanding requirements.
The categorical-exclusion requirements could eliminate the need to prepare an environmental assessment or environmental impact statement for qualifying low-disturbance activities. However, the agencies would first have to develop or adopt the exclusions, which would remain subject to extraordinary circumstance review. Extraordinary circumstances are conditions in which a proposed action that would normally qualify for a categorical exclusion may nevertheless have significant environmental effects and therefore require additional environmental review. Before applying a categorical exclusion, a federal agency must consider whether extraordinary circumstances are present that could result in significant environmental effects. Applying BLM’s standardized review requirements could also promote greater consistency across regional offices and help reduce permitting timelines.
Summary: This section would require the Interior and Agriculture Secretaries to each develop or adopt one or more categorical exclusions, subject to extraordinary circumstance review, for three categories of electric grid activity: placement of an electric transmission or distribution facility in an approved right-of-way corridor; any repair, maintenance, or modification of an existing electric transmission or distribution facility or associated infrastructure on existing rights-of-way or previously disturbed land; and construction, operation, upgrade, or decommissioning of a battery or other energy storage technology on previously disturbed or developed land. Work on existing electric grid infrastructure would explicitly include reconductoring and grid enhancing technologies (GETs).
Context: Many of the fastest and most cost-effective ways to add transmission capacity involve getting more out of infrastructure that is already in place. Reconductoring can replace existing wires with higher-capacity conductors, and GETs can increase the amount of electricity that existing lines can safely carry or improve system power flows. Because these upgrades often use existing rights-of-way and previously disturbed land, they can normally be deployed more quickly than building new transmission corridors.
By directing the Departments of Interior and Agriculture to establish categorical exclusions for these activities, this section could reduce the time and procedural burden associated with federal environmental review where impacts are expected to be limited and well understood. Those exclusions could help accelerate lower-impact grid upgrades, increase capacity on the existing system, and provide near-term reliability and congestion benefits while larger greenfield transmission projects continue through development. The inclusion of storage on previously disturbed land would also be important for clean energy efficiency because storage can absorb excess wind and solar generation when it is available and discharge it later when output falls or demand rises, helping integrate more variable renewable electricity that might otherwise be curtailed or wasted.
Summary: This section would revise federal mining claims to create a new category of “additional mill sites.” It would also define these mill sites as public lands reasonably necessary for activities related to mineral development or production, such as waste-rock or tailings disposal. A mining operator could include, in an approved plan of operations, and use, as many mill-site claims as are reasonably necessary for the operation, although each individual mill site would be limited to five acres. Mill sites would not convey mineral rights and could not be patented into private ownership. Qualifying public land could include land that is mineral in character, nonmineral land, or land whose mineral character has not been determined, including tracts where the operator maintains an existing mining claim.
This section would preserve existing federal authority to regulate mining and would not reopen lands withdrawn from mining. Operators would pay a $400 annual maintenance fee for each additional mill site.
This section would also add “hardrock minerals” to the minerals that could be leased on federally acquired lands—meaning lands the federal government obtained after they were previously in state, local, or private ownership. It would define hardrock minerals to include minerals found in sedimentary or other rocks, base and precious metals, industrial minerals, and precious and semi-precious gemstones and would exclude commodities already governed by other federal authorities, such as coal, oil, and gas.
This section would create an Abandoned Hardrock Mine Fund, which would receive revenue from the new mill-site maintenance fees and from hardrock-mineral leases on federally acquired lands. The Fund would be used to support abandoned hardrock-mine reclamation activities under the Infrastructure Investment and Jobs Act.
Context: Domestic hardrock mineral development depends on access to land for mining operations and associated infrastructure, including the facilities needed to manage waste rock and tailings. The Ninth Circuit’s 2022 ruling on Center for Biological Diversity v. U.S. Fish & Wildlife Service (i.e., the Rosemont decision) clarified limitations on using public lands for these activities without a valid legal basis, such as a mining claim or mill site. By expressly allowing as many additional mill sites as are reasonably necessary under an approved plan of operations, the bill would reduce uncertainty over access to land needed for tailings, waste rock, processing facilities, and other infrastructure necessary to operate a mine. However, some observers have raised concerns that expanding access to mill sites could allow mining companies to use substantially larger areas of public land for waste disposal and other activities, potentially increasing impacts on water quality, ecosystems, and nearby communities.
Allowing hardrock minerals on federally acquired lands to be leased could also expand access to deposits that are not available through the traditional Mining Law claim system. This change could be relevant for minerals used in batteries, transmission, renewable energy, and other clean energy technologies, and more broadly for efforts to expand domestic mineral supply chains. Moreover, a wide range of hardrock minerals are necessary for economywide electrification—a key strategy to reduce harmful emissions. However, expanding access to mineral development could also raise concerns about environmental impacts and competing uses of federal lands, particularly where mineral deposits overlap with ecologically or culturally sensitive areas.
The Abandoned Hardrock Mine Fund could provide an additional source of funding to address legacy environmental and public-safety problems from historic mining, including acid-mine drainage, contamination from heavy metals, unstable waste piles and mine openings, and degraded land and water resources.
Summary: This section would create a new permitting framework for geothermal observation test projects, which are relatively limited exploratory wells used to test or monitor geothermal resources before full development. Qualifying test projects would be required to meet restrictions on size, road construction, and surface disturbance, generally including no more than 10 acres of disturbance per test project and no more than 100 acres for multiple projects. The test project generally would be required to be completed within one year, while site restoration would be required within three years unless the site moves into subsequent geothermal development.
This section would also require the Interior and Agriculture Secretaries to establish a NEPA categorical exclusion for qualifying geothermal observation test projects. Activities involving only “casual use”—activities that ordinarily cause no or negligible disturbance—would not be considered major federal actions under NEPA but would require advance notice. Administration of the categorical exclusion would remain subject to applicable extraordinary circumstance review.
Context: Geothermal developers need information about subsurface conditions before deciding whether to pursue commercial development. Confirming the presence and quality of a geothermal resource is an early and uncertain stage of project development, and these activities generally involve less disturbance than construction of a commercial geothermal facility. By creating a categorical exclusion for qualifying observation projects and excluding casual-use activities from major federal action status under NEPA, this section could make it faster and less costly to determine whether a geothermal resource is viable before a developer commits to a larger project and more extensive environmental review.
The definition of major federal action, as amended by Section 1102, would separately exclude agency actions associated with qualifying geothermal observation test projects from NEPA’s definition of major federal action. How that exclusion would interact with this section’s categorical-exclusion procedure, including its extraordinary-circumstances safeguard, remains unclear.
Summary: This section would amend the royalty schedule for geothermal electric generation. For the first royalty period, instead of measuring the first ten years of production under the lease, it would measure the first ten years from the facility’s in-service date.
Summary: This changes the statutory minimum frequency of competitive geothermal lease sales from biennially to annually and requires the Interior Secretary to conduct a replacement sale in the same year if a scheduled sale is cancelled or delayed. It also establishes deadlines for considering and issuing geothermal drilling permits.
Summary: This section would create a new Geothermal Ombudsman position and would establish a Geothermal Permitting Task Force headed by this new role. The Geothermal Ombudsman would coordinate between BLM field, district, state, and national offices; provide dispute resolution services between BLM local and state offices and applicants for geothermal authorizations; monitor permitting practices and timelines; develop best practices for permitting and leasing for geothermal resources; and coordinate with the Federal Permitting Improvement Steering Council.
The Geothermal Permitting Task Force could temporarily assign qualified personnel among BLM offices to assist with geothermal authorizations. The Geothermal Ombudsman would report annually to Congress on the task force activities and the effectiveness of geothermal authorization processing during the preceding year.
Context: Geothermal projects can require multiple BLM approvals over several stages of development, and permitting delays can arise from limited agency capacity, inconsistent practices among field offices, or disputes between applicants and agency staff. These delays can increase project costs and make development timelines more difficult to predict, which in turn complicates financing and investment decisions. Improving coordination and providing a dedicated mechanism to resolve permitting issues could make federal geothermal permitting more coordinated, consistent, and predictable without changing the substantive standards projects must meet. Annual reporting could also make persistent problems more visible to Congress.
Summary: This section would eliminate the requirement for a federal drilling permit for geothermal exploration and production on non-federal surface land where the federal government owns less than 50 percent of the subsurface geothermal resource, provided the operator submits a state permit to conduct geothermal activities to the Interior Secretary. Operators must also notify the Interior Secretary of state drilling permit applications and approvals affecting federally owned oil and gas resources. This exemption would not apply to Indian lands. It would not affect federal royalties, and the Interior Department could conduct inspections to ensure accurate production accounting and royalty payments.
Summary: This section would direct the Interior Department to continue processing authorizations for geothermal projects under valid existing geothermal leases, even when litigation affecting the application is pending. After all applicable federal legal requirements are completed, the Interior Secretary would be required to approve or deny the permit within 60 days unless a federal court vacates or provides injunctive relief.
Summary: From this bill’s enactment through September 30, 2033, the Interior Secretary could require applicants for, or holders of, geothermal leases to reimburse the United States for all reasonable costs associated with processing leases associated permit, plan, and other approval applications and inspecting and monitoring activities associated with the geothermal lease. The Interior Department could reduce reimbursement where full payment would cause economic hardship or where a reduction would promote greater use of geothermal resources. The reimbursements should be spent, as appropriated, on geothermal permitting leasing and oversight activities. Within five years of enactment of the bill, the Interior Secretary would have to assess how the program affected the BLM geothermal program and any recommendations for updates and reauthorization of the program.
Summary: Under this section, the Interior Secretary would have one year to identify standard procedures and guidelines for geothermal leasing and permitting that are not adequately addressed in BLM’s fourth-edition Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development (i.e., Gold Book). The Interior Secretary would have to publish an updated version of the Gold Book, incorporating procedures for ensuring the efficient review and approval of environmentally responsible geothermal development, and rename the book accordingly. The Interior Department would be required to review the guidelines at least every five years and update it when necessary. Each updated version would include exploration and geophysical operations, permitting lease operations, legal compliance, construction and maintenance, and drilling, production, and utilization.
Summary: This section would exclude certain federal-land management actions related to the exploration or development of oil, gas, and geothermal resources from being considered major federal actions under NEPA. It would also extend several existing oil and gas activities that receive this treatment to geothermal development. For the activities receiving this treatment, the bill would expand the existing provision for pipelines placed in approved rights-of-way by allowing the corridor approval to be up to ten years old, rather than five. It would also add a geothermal-specific activity covering transmission or distribution lines of up to 20 miles in an approved right-of-way corridor that was approved within the previous ten years.
The section would preserve applicable drilling-permit requirements under the Mineral Leasing Act and Geothermal Steam Act, while providing that covered activities requiring such permits are not major federal actions under NEPA.
Context: Section 390 of the Energy Policy Act of 2005 establishes a rebuttable presumption that certain oil and gas activities on federal lands qualify for categorical exclusions under NEPA. Examples include drilling at sites used within the previous five years and placing pipelines in rights-of-way approved within the previous five years. Although categorical exclusions can streamline review, they remain part of NEPA’s framework. Ordinary agency categorical exclusions generally require consideration of extraordinary circumstances that could make the exclusion unavailable. However, the treatment of statutory categorical exclusions established under section 390 has shifted over time, including changes in whether BLM requires extraordinary-circumstance review in implementing regulations.
Designating these activities as not constituting major federal actions would more definitively remove them from NEPA review, rather than relying on the categorical-exclusion framework. This could reduce uncertainty associated with changes in agency interpretations and implementation over time.
This section would also extend this streamlined treatment beyond oil and gas to geothermal activities, including certain drilling and development activities and short transmission or distribution lines serving geothermal projects. For oil and gas and geothermal developers, this could reduce permitting time and uncertainty for covered activities; however, excluding these activities from NEPA review does not necessarily establish that they have insignificant environmental effects.
Summary: This section would direct FERC to submit a report to Congress on market barriers affecting the development and proper compensation of conventional, storage, conduit, and emerging hydropower technologies. The would be required to examine barriers related to transmission organization rules, FERC and Federal Power Act policies, and federal and state laws unique to hydropower development, operation, and regulation relative to other electricity sources. The report would be required to also include recommendations for reducing market barriers, identify potential regulatory, market, procurement, cost-recovery, ownership, and development models and solicit public input through a technical conference and comments on a draft report.
Summary: This section would require conditions imposed on FERC hydropower licenses for projects located within federal reservations to be reasonably related to the effects of the project.
Summary: This section would require prior FERC approval for substantial alterations or additions to hydropower project work or operation that significantly depart from approved project plans. Routine maintenance, repair, or replacement necessary to maintain a project would not require approval or a license amendment. Prior approval also would not be required for qualifying temporary operational variances necessitated by circumstances beyond the licensee’s reasonable control, including extreme weather, natural disasters, or equipment failures.
Summary: This section would create a new expeditated licensing process for micro hydrokinetic energy projects. A micro hydrokinetic project would be defined as a project that has an installed capacity of no more than 5 MW, generates electricity from waves, tides, currents, and does not impound water to generate electricity.
FERC could issue a license for 10 to 20 years for the construction, operation, and maintenance of these projects. FERC would have one year after the application is filed to take final action; FERC and other applicable conditioning or permitting agencies should establish a joint schedule for all applicable federal decisions and authorizations that is consistent with the one-year deadline.
FERC would be required to create at least one categorical exclusion for low-disturbance activities associated with these projects.
FERC would also have to submit a report to Congress on the environmental, economic, and reliability and affordability effects of the projects licensed under this section.
Summary: This section would expand the types of FERC employees eligible for special compensation intended to help the Commission recruit and retain hard-to-fill staff. Current law allows this authority for scientific, technological, engineering, and mathematical positions; the bill would add economic and legal positions. It would also remove the requirement that the FERC Chairman consult with the director of the Office of Personnel Management when using this compensation authority.
Summary: This section would update the funding rules for the Pacific Northwest Electric Power and Conservation Planning Council, a regional body that develops power and conservation plans for the Pacific Northwest. The bill would reset the inflation adjustment for the Council’s funding cap to only account for inflation occurring after enactment of the bill.
Summary: This section would allow FERC employees to perform law enforcement duties for the safety of the FERC Chairman and Commissioners.
Summary: This section would change an offshore energy siting standard from “preventing interference with reasonable uses of the Outer Continental Shelf” to “preventing unreasonable interference with other uses.” It would allow the Interior Secretary, in consultation with the Commerce Secretary, to grant rights-of-way within a national marine sanctuary for electricity transmission. Permits issued under the National Marine Sanctuaries Act for transmission cables on those rights-of-way would last for the same term as the underlying right-of-way.
Summary: This section would establish a federal planning and permitting framework for offshore energy transmission. The Interior and Energy Secretaries would be required to identify preferred Outer Continental Shelf routes for transmission cables and sub-seabed infrastructure where routes have not been already identified, including routes between offshore generation facilities and routes connecting offshore generation to onshore electric grids. The secretaries would revisit these routes at least every three years to identify any additional necessary routes. When identifying routes, they would be required to consider existing rights-of-way and infrastructure, optimal points of interconnection between offshore generation facilities and onshore electric grids, and impacts on the marine environment and other ocean users.
The Interior Department would serve as the lead agency for coordinating all applicable federal authorizations and related environmental review for offshore transmission facilities. The Interior Secretary would also be required to issue regulations governing federal authorizations for offshore transmission facilities, including processes for identifying and assessing interest in rights-of-way, issuing rights-of-way on a competitive or noncompetitive basis, and addressing environmental review requirements.
Context: Offshore generation depends on transmission to deliver electricity to the onshore grid, and a project-by-project approach can lead to duplicative infrastructure and less coordinated interconnection decisions. Planning offshore transmission routes in advance and establishing a more coordinated federal approval process could help address these challenges by allowing transmission needs and potential conflicts with other ocean uses to be considered across multiple projects.
By identifying preferred routes in advance and creating a framework that can accommodate shared or “backbone” transmission connecting multiple offshore projects, this section could reduce permitting uncertainty, avoid unnecessary infrastructure, and support more coordinated offshore grid development. Coordinated planning could also help identify and address conflicts with other ocean uses earlier in the development process
Title III—Historic Preservation
Summary: This section would substantially revise the scope of review, consultation procedures, and judicial review requirements under the National Historic Preservation Act, while also changing oversight of state and Tribal historic preservation programs. NHPA is a federal law that protects historic and culturally significant properties. Section 106 of the law requires federal agencies to consider how federal or federally connected projects may affect historic properties before approving them. Agencies conduct these reviews in consultation with state historic preservation officers (SHPOs), Tribal historic preservation officers (THPOs), Indian Tribes, Native Hawaiian organizations, local governments, and other consulting parties.
State and Tribal Historic Preservation Programs
This section would define a “property of traditional religious or cultural importance” for purposes of National Register eligibility and would strengthen federal oversight of state and Tribal historic preservation programs. State and Tribal programs would be evaluated by the Interior Secretary, in consultation with the Advisory Council on Historic Preservation, at least every two years, and repeated failure to meet statutory consultation timelines could result in a finding that a program is not complying with the law. In some circumstances, federal funding or agreements could be suspended, and the federal government could temporarily assume SHPO or THPO functions if deficiencies are not corrected.
Scope of Section 106 Review
This section would define key terms that determine the scope of a section 106 review, including “undertaking,” “adverse effect of the undertaking,” “reasonably foreseeable,” and “area of potential effects.” An undertaking would have to require a federal permit, license, or approval and be subject to substantial federal control and responsibility. The definition would exclude, among other things, portions of a larger project over which a federal agency does not exercise substantial control or responsibility, as well as projects for which the federal government’s only involvement is most forms of financial assistance. An adverse effect of the undertaking would have to be reasonably foreseeable and directly alter characteristics that contribute to a historic property’s integrity. Consideration of visual, atmospheric, and audible effects would be limited to effects that directly and significantly affect the characteristics that make a historic property eligible for the National Register. Speculative or attenuated effects, as well as effects associated with unrelated projects, would also be excluded. The definition of adverse effect would also exclude temporary alterations limited to the time needed to complete an undertaking. The undertaking definition would exclude specified post-approval implementation and operation activities, while treating a subsequent discrete federal decision to amend or materially modify a determination as an undertaking to the specified extent.
Consultation Timelines and Coordination
This section would place enforceable deadlines on various stages of the consultation and reporting process for federal agencies, SHPOs, THPOs, and other consulting parties. When more than one federal agency has authority over a project, the agencies would designate a lead federal agency to manage section 106 compliance. If a lead agency has already been designated for purposes of NEPA, that agency generally would also serve as the lead agency for section 106, unless the agencies jointly determine that another agency is better suited. For projects subject to NEPA, section 106 consultation would begin no later than the start of the NEPA review and would have to conclude by the time the NEPA environmental document is completed. A draft NEPA document could also satisfy certain section 106 reporting requirements if it contains the required information.
This section would specify findings through which an agency could satisfy its responsibilities without reaching an agreement with consulting parties, including that adverse effects would not diminish a property’s integrity enough to make it ineligible for the National Register or that other considerations outweigh historic preservation. If an agreement is not reached, the bill would provide for additional consultation and, where necessary, formal comments from the Advisory Council on Historic Preservation. Separately, agencies could proceed with their determinations if specified consulting parties do not respond or raise substantive objections within 30 days of receiving a report or finding. If timely substantive objections are submitted, the agency would have 30 days to respond, explaining how it considered those objections. Providing that response would fulfill its consultation obligation concerning the report, without requiring agreement with the consulting parties.
Programmatic Agreements
This section would require federal agencies, in consultation with the Advisory Council on Historic Preservation, to develop and implement programmatic agreements for categories of undertakings that normally have no adverse effects, are similar and repetitive in nature, or involve routine management activities at federal installations, facilities, or other land management units. Programmatic agreements are existing section 106 tools that establish standardized procedures for reviewing categories of similar or recurring undertakings, reducing the need to conduct the full process separately for each individual activity.
Judicial Review and Finality
This section would substantially revise judicial review of section 106 decisions. Claims would have to be filed within 150 days after the later of public availability of the final agency action and notification of the applicable SHPO or THPO.
Plaintiffs would have to show direct harm and, when a public comment period was available, would have to have submitted a substantive and unique comment that sufficiently identified the issue being challenged. These requirements would not apply to claims involving sufficiently detailed written notice of the issue provided during consultation by a SHPO, THPO, Tribe, Native Hawaiian organization, or local government. Courts would be required to give substantial deference to the agency. If a court finds that an agency did not comply with the historic preservation requirements, the only remedy for that violation would be to send the decision back to the agency to correct the problem without vacating the agency action or stopping the project, with a deadline of no more than 180 days for the agency to act. A preliminary injunction could still be issued in more limited circumstances where there is a substantial likelihood of a violation of a federal law other than NHPA or NEPA, along with irreparable harm and the other traditional requirements for an injunction. Any such injunction could remain in place only as long as the court finds reasonably necessary to correct the violation and prevent the irreparable harm. Most section 106 challenges would also go directly to a federal court of appeals.
This section would provide additional finality once a section 106 review is underway. A property newly identified, nominated to, or listed on the National Register after an agency begins its review would not require the agency to delay, reopen, supplement, or otherwise modify the review.
Parties that did not sign a programmatic agreement would be prohibited from bringing lawsuits challenging how the agreement is implemented, and courts would not have jurisdiction to hear those challenges.
Cases would, to the maximum extent practicable, be randomly assigned to judges, and judgments would be issued as expeditiously as possible.
Context: Section 106 of the NHPA is intended to ensure that federal agencies consider the effects of their decisions on historic and culturally significant properties before approving projects. However, consultation can be a lengthy and complex process, particularly for large infrastructure projects such as transmission lines and pipelines that cross multiple jurisdictions and may affect numerous historic or culturally significant sites. Although existing regulations establish response periods for certain consultation steps, there is no overarching statutory deadline for completing the process. This can make overall project timelines difficult to predict, particularly when disagreements over potential impacts remain unresolved.
The changes to the scope of review could make the process more predictable by focusing consideration on reasonably foreseeable effects directly connected to the federally authorized activity. This could be particularly consequential for transmission projects, where visual impacts may extend well beyond the project footprint and trigger extensive review of historic properties. Narrowing the consideration of visual, atmospheric, and audible effects could reduce the geographic scope and complexity of reviews, while limiting review to portions of a project under substantial federal control could prevent a relatively narrow federal authorization from triggering review of an entire project. However, some observers have expressed concern that these changes would exclude impacts that are meaningful to affected communities, particularly where a property’s cultural or religious significance depends on its surrounding landscape, viewshed, or traditional setting.
Establishing enforceable consultation deadlines and coordinating section 106 reviews with NEPA could reduce duplicative work and allow agencies to identify and resolve historic-preservation concerns earlier in project development. Requiring programmatic agreements for categories of similar or routine activities could further streamline reviews by establishing consistent procedures rather than repeating the full consultation process for each activity. However, tighter deadlines and stronger federal oversight could place additional pressure on state and Tribal historic preservation offices, many of which face staffing and resource constraints. The potential suspension of Tribal historic preservation programs or transfer of their responsibilities to federal authorities has also raised concerns about Tribal sovereignty and self-governance. Additionally, some observers may also be concerned that strict consultation deadlines could reduce the time available for Tribes and other consulting parties to identify and evaluate historic and culturally significant properties, particularly where disagreements over potential impacts remain unresolved. Allowing agencies to conclude consultation without reaching agreement with consulting parties could reduce their influence over decisions affecting historic and culturally significant properties.
The judicial review changes could provide greater predictability by shortening the period for bringing legal challenges and reducing the circumstances in which litigation could halt a project. Shorter filing deadlines and limiting courts to correcting NHPA violations without vacating approvals or halting project activity on that basis could reduce financing risks and allow construction to continue while agencies address identified problems. However, limiting access to judicial review and remedies could also make it more difficult for affected communities and Tribes to challenge inadequate reviews or prevent damage to historic and culturally significant properties. Unlike some environmental impacts, the destruction of a historic or sacred site may be irreversible, meaning that correcting a procedural violation after construction has begun may not fully address the harm. Similarly, preventing newly identified historic properties from reopening an ongoing review could improve project certainty but limit opportunities to protect significant resources discovered later in the process.
Summary: This section would authorize $200 million annually from fiscal years 2027 through 2036 to be appropriated for deposit in the Historic Preservation Fund, the federal fund that supports state, Tribal, and local historic preservation programs and related preservation grants, and would make those funds available beginning in fiscal year 2028 without further appropriation or fiscal-year limitation.
It would also authorize $20 million annually from fiscal years 2027 through 2030 for competitive grants to THPOs to develop online databases of Tribal historic preservation records and culturally significant properties that can support federal and state consultation. This section would not require public disclosure of specified sensitive property information where disclosure could cause significant harm or risk to the property’s integrity or impede traditional religious or cultural use.
