Bipartisan American Affordability and Jobs Act of 2026 Proposes Sweeping Reform for Energy and Infrastructure Projects

On Sept. 30, 2026, the Senate Environment and Public Works and Energy and Natural Resources Committees reached agreement on the text of the Bipartisan American Affordability and Jobs Act of 2026, a major effort to overhaul federal permitting for energy and infrastructure projects. The package combines broad permitting and environmental review reforms with significant changes impacting electric transmission, large-load growth and energy project development.

The 417-page bill addresses three major themes. First, it would make it easier to permit and build energy infrastructure, such as natural gas pipelines and geothermal, hydropower and wind projects.  Second, it would reform how electric transmission is planned and how its costs are allocated. Third, it would establish ways to ensure AI data centers, other computational loads and cryptocurrency mining operations get access to the grid and pay the costs they incur, while protecting other ratepayers.

More specifically, the proposed legislation streamlines federal environmental reviews and establishes clearer deadlines for projects seeking federal permits and approvals. Furthermore, the proposed legislation provides new protections for projects that have already received federal approvals and limits the circumstances in which agencies could later revoke, suspend or otherwise interfere with those approvals. These protections could be particularly consequential for large, capital-intensive energy projects, including offshore wind and other generation, transmission, pipeline and energy infrastructure projects by allowing projects with valid federal approvals to continue moving forward while certain legal or administrative issues are resolved.

Among the most consequential provisions are those addressing large-load growth and electric transmission. The package would establish new cost-responsibility rules for data centers and other computational loads, while giving states substantial flexibility over how those customers receive and pay for electric service. It would also make significant changes to transmission siting; local, regional and interregional planning; cost allocation; generator interconnection; and deployment of advanced grid technologies.

The agreement is a major step forward following months of negotiations, but the legislation is not final. A Senate floor vote is not expected until after Congress returns from its preelection recess on Nov. 9, 2026, and any Senate-passed bill would still need to clear the House before going to the president. The text could change as it moves through Congress, and many provisions would require subsequent rulemakings or state regulatory action before taking full effect.

I. Large-Load Growth and Ratepayer Protections

The bill includes several provisions that address growing electricity demand from data centers and other large computational loads, including who pays for the infrastructure needed to serve them and how their demand can be managed.

Transmission Pricing for Computational Loads

Section 2107(a)

• The Federal Energy Regulatory Commission (FERC) would require that transmission service for computational loads cover both the embedded cost of the existing system and any incremental expansion costs needed to serve the load. Incremental payments would be credited against the utility’s transmission revenue requirement, helping ensure those additional costs are not passed on to other customers.
• FERC would have to offer a lower rate to computational loads that choose non-firm transmission service. This gives loads that can accept interruptions an incentive to do so.
• The provision covers facilities connected to the bulk-power system that are primarily used for AI, cloud and software services, cryptocurrency mining and other data center computing. It has no minimum load threshold.

Ratepayer Protections for Data Centers and High-Density Computing

Section 2107(b)

A separate framework would apply to data centers and high-density computing facilities with electric demand of at least 20 megawatts (MW). It would also cover phased developments expected to reach that level and certain sites under common ownership or control.

The framework would govern how the costs of serving these loads are assigned:

• Covered loads would be responsible for the full incremental cost of serving them, including generation, storage, transmission and distribution infrastructure that would not otherwise have been needed. Those costs could not be shifted to other customers.
• Customers would remain responsible for unrecovered incremental costs if they terminate service early.
• Utilities would have to obtain sufficient financial assurances or contributions before building facilities or making upgrades needed to serve the load.
• States could direct revenues collected from covered loads above their incremental costs to reduce rates for other retail customers.

The framework would also confirm several state authorities over retail service to these loads:

• States could set separate rates and service arrangements for covered loads, including rates above the incremental cost of service.
• States could use an open season or competitive process to decide which covered loads receive available electric service, with awards based on the greatest benefit to other ratepayers on a present-value basis rather than the order in which applications are received.
• States could require a project to provide or contract for new generation, or to accept limits on when or how much electricity it may draw from the grid.
• States could place covered loads in a separate service class. The rates, terms or service priorities for that class could differ from, and be less favorable than, those for other large commercial and industrial customers.

These provisions would generally apply to covered loads that interconnect after enactment, while previously approved arrangements would remain in effect. The bill does not give FERC authority over retail sales or local distribution.

II. Electric Transmission and Grid Modernization

The transmission portion of the bill covers how interstate lines are sited, planned, paid for and connected, along with new requirements for grid technologies and market access. Several provisions are aimed at speeding transmission development and making greater use of existing grid capacity.

Federal Transmission Siting

Section 2101

• The bill would broaden FERC’s existing backstop transmission siting authority, allowing FERC to permit qualifying interstate transmission facilities directly, without a prior Department of Energy (DOE) national interest electric corridor designation. Qualifying projects generally would have to operate at 230 kilovolts (kV) or above and meet public interest, consumer benefit and reliability requirements.
• For facilities of at least 345 kV, federal and state siting reviews could proceed in parallel. FERC could issue a permit only if the project meets one of the statutory conditions that allow federal siting authority to apply. States, landowners, affected tribes and other interested parties would maintain a role in the federal review process.
• Costs of lines permitted by FERC would have to be allocated to the customers who benefit, roughly commensurate with those benefits. Customers who receive no benefit, or only a trivial one, could not be involuntarily charged.

Upgrades Within Existing Rights-of-Way

Section 2102(a)

• Work that maintains or increases grid capacity within existing transmission and distribution rights-of-way would be categorically excluded from National Environmental Policy Act (NEPA) review. This includes reconductoring, voltage increases, advanced technologies, storage and parallel circuits.

Regional and Interregional Planning

Section 2103

• DOE would regularly assess transmission congestion and capacity constraints, while FERC would establish a more structured regional and interregional planning framework that considers common benefits such as reliability, reduced congestion and power losses, increased carrying capacity and access to lower-cost generation.
• Regional and interregional projects would use the same benefits-based cost-allocation rule, with costs roughly commensurate with benefits and no involuntary allocation to customers receiving no or trivial benefit.

Local Transmission Planning and Competition

Sections 2104–2105

• States could ask FERC to investigate local utility transmission planning practices that they believe produce less efficient or more costly projects. Remedies could include changes to planning practices, reduced returns on equity, removal of the presumption that costs were prudently incurred or financial penalties.
• Federal rights of first refusal would be prohibited for transmission facilities selected in regional or interregional plans for cost allocation.

Generator Interconnection

Sections 2106, 2110–2111

• Transmission planning and generator interconnection would be combined into one process. Regional planners would evaluate expected generation and transmission needs over a 20-year period. They would also publish planned interconnection locations with upfront zonal costs.
• Interconnection studies would use a streamlined cluster process with a single decision point and withdrawal penalties meant to discourage speculative projects.
• FERC would have to initiate a rulemaking requiring utilities to share and use AI, machine learning and automation for queue management and faster interconnection studies.
• Transmission providers would have to maintain and share accurate, current grid data needed for interconnection and other covered studies, subject to confidentiality and security requirements.

Distributed Energy Resources and Wholesale Market Access

Section 2108

• Dispatchable behind-the-meter distributed energy resources, including batteries, fuel cells and generators, could participate in wholesale electricity markets through qualifying aggregations. Distribution utilities generally could not block that participation. Compensation could be adjusted on a service-by-service basis to avoid double recovery, while still allowing separate services to be compensated independently.

Advanced Transmission Technologies

Section 2109

• Utilities would have to evaluate advanced transmission technologies on a recurring basis and deploy them when the evaluation shows benefits exceed costs. These technologies include high-performance conductors, dynamic line ratings and advanced power-flow controls.

Offshore Transmission

Section 2252

• The Department of the Interior and DOE would identify preferred routes connecting offshore generation with other offshore facilities and the onshore grid. Interior would serve as the lead agency for federal permitting and environmental review.

III. Environmental Review and Permitting Reform

The bill would revise the major federal environmental review statutes that apply to energy and infrastructure projects, with an emphasis on shortening timelines, improving coordination among agencies, narrowing when NEPA applies, clarifying and constraining the scope of environmental review, and creating more certainty for project approvals.

NEPA

Sections 1101–1133

• The bill would make structural changes to NEPA and make clear it is a procedural and informational statute under which agencies consider and disclose reasonably foreseeable environmental effects, while providing that NEPA itself does not mandate a particular substantive outcome.
• Environmental assessments would generally have a one-year deadline, and environmental impact statements a two-year deadline. Agencies reviewing the same project would have to coordinate more closely.
• The bill would narrow the universe of actions subject to NEPA. Projects whose only federal involvement is a loan or loan guarantee would not be subject to NEPA review.
• Agencies could rely more heavily on existing programmatic reviews, categorical exclusions and environmental analyses prepared by other federal agencies, states or tribes.
• NEPA challenges would have to be filed within 150 days and would generally be limited to parties that participated in the relevant comment period.
• If a court finds a deficiency and remands the authorization to the agency, the authorization would remain in effect. The project could proceed while the agency fixes the problem.

Clean Water Act

Sections 1201–1205

• State water quality certifications under Section 401 would focus more narrowly on compliance with applicable water quality requirements, with tighter standards for denials and conditions, making it more difficult for individual states to block projects.
• Section 401 certifications for interstate transmission and natural gas pipeline projects would be limited to direct point-source discharges and subject to a maximum nine-month review period.

• The maximum term for National Pollutant Discharge Elimination System permits and Section 404 general permits would increase from five to 10 years.
• Certain nationwide permits would get streamlined reissuance requirements. Challenges to specified Section 404 decisions would have to be filed within 150 days.

Endangered Species Act

Sections 1301–1308

• The standard timeline for formal Section 7 consultation would decrease from 90 to 60 days. For projects undergoing NEPA review, consultation would generally have to be completed by the time the environmental document is finished.
• Qualified states could voluntarily take on certain Section 7 consultation responsibilities for projects within their borders, subject to federal approval and oversight.
• Biological opinions would face a shorter period for legal challenges. Federal agencies would have to use qualifying state-collected scientific data in species listing and delisting decisions.

Historic Preservation

Sections 2301–2302

• Section 106 consultation would have to begin when NEPA review begins and would generally have to finish when the environmental document is completed.
• Required mitigation would be limited to prudent and feasible measures within the project’s area of potential effects.

IV. Project Certainty

The bill would limit federal agencies’ ability, across current and future administrations, to revoke permits after they are issued. It would also set new decision deadlines and a 150-day filing deadline for challenges to energy projects.

Protection of Issued Permits

Section 1401

• For projects with nonfederal sponsors or permit holders, federal agencies generally could not revoke, suspend, withdraw, amend or alter a federal authorization or permit in effect on or after Sept. 16, 2026. Agencies also generally could not otherwise interfere with the construction or full-capacity operation of a project once it has secured all necessary federal authorizations and permits.
• Exceptions would remain for a court order; a material breach or violation of law; fraud or material misrepresentation; a newly identified and urgent threat to life, property or national security; or a request from the project sponsor.
• Available remedies would include reinstatement of the permit, injunctive relief, and litigation and delay costs. A court could also award 25% to 50% of the sponsor’s total project costs not otherwise recovered, paid from the federal Judgment Fund.

Decision Deadlines and Disparate Treatment Claims

Sections 1402–1403

• Energy projects that need federal permits but not an environmental assessment or environmental impact statement would get a one-year federal decision deadline. Project sponsors could go to court to enforce it.
• Project sponsors could also seek relief for an intentional, statistically demonstrated pattern of federal agencies treating a particular type of energy project differently from its recent permitting history. The covered project types are technology-neutral and include renewables, fossil fuels, nuclear, storage, transmission and pipelines. Damages could range from 50% to 100% of the project’s expected construction cost.

Deadlines for Energy Project Challenges

Section 2201

• Challenges to federal authorizations for energy, mineral and certain wildfire protection projects would have to be filed within 150 days. If a court sends an authorization back to an agency, the agency would have up to 180 days to act.

V. Sector-Specific Energy Provisions

The bill also makes targeted changes to permitting for specific energy sectors, many of them on federal land.

Renewable Energy and Grid Projects on Federal Land

Sections 2213–2214

• Renewable energy right-of-way applications would have firm processing timelines. These include a 30-day completeness review and a 90-day deadline to begin an environmental impact statement when one is required.
• Transmission, distribution and certain energy storage projects in existing corridors, rights-of-way or previously disturbed areas would qualify for streamlined environmental review.

Oil, Gas and Pipelines

Sections 2102(b), 2211

• Certain oil and gas development on nonfederal land would no longer need a federal drilling permit where the federal government holds a minority mineral interest. Applicable state, tribal and other requirements would still apply.
• Maintenance, upgrades, looping, compression and capacity expansions within existing interstate natural gas pipeline corridors would receive streamlined NEPA treatment.

Geothermal

Sections 2221–2229

• Certain geothermal development on nonfederal land would no longer need a federal drilling permit. This would apply where the federal government holds less than half of the subsurface geothermal interest and state permitting requirements are met.

Hydropower

Sections 2231–2234

• Hydropower licensing would be streamlined in several areas. Certain license conditions would have to be reasonably related to a project’s effects, while routine maintenance, repair and replacement generally would not require additional license approval.
• Micro hydrokinetic projects of up to 5 MW would receive a streamlined licensing process.

The lawyers and professionals at McGuireWoods and McGuireWoods Consulting are monitoring this legislation. For questions or more information, reach out to one of the authors or a member of McGuireWoods’ Energy Infrastructure Practice Group.