The Bipartisan American Affordability and Jobs Act - What You Need to Know

A new bipartisan Senate proposal could significantly change how energy and infrastructure projects obtain federal approvals—and how securely developers can rely on those approvals once issued. 

On September 30, Senators Shelley Moore Capito, Mike Lee, Sheldon Whitehouse, and Martin Heinrich introduced the Bipartisan American Affordability and Jobs Act of 2026. The legislation combines environmental review and permitting reforms with transmission development measures and new requirements governing the costs of serving data centers. 

For developers, utilities, and investors, the proposal’s significance extends beyond faster permitting. It would restrict federal interference with approved projects, create substantial financial remedies for certain agency conduct, change the litigation risks associated with environmental reviews, and affect the allocation of grid expansion costs. The legislation has not been enacted, and its provisions remain subject to negotiation. Nevertheless, the released text identifies several changes that warrant attention now.

A New Framework for Permitting Certainty & Project Risk

For projects that already hold federal approvals, Section 1401 could be particularly consequential. It would generally prohibit federal agencies from revoking, suspending, or altering covered authorizations in effect on or after September 16, 2026, and from interfering with construction or full-capacity operation of projects that have secured all necessary federal approvals. Exceptions would permit action based on court orders, legal violations, fraud, sponsor requests, and specified urgent harms supported by new information. Agencies would bear the burden of establishing an exception by clear and convincing evidence.

The proposed remedies would give these protections substantial financial consequences. A successful sponsor could obtain reinstatement, appropriate litigation and delay costs, and an additional award equal to 25–50% of project costs incurred as of the challenged agency action, excluding amounts recovered under the specified litigation- and delay-cost provisions. Section 1402 would create a separate remedy for qualifying applicants whose permits were improperly denied or unreasonably delayed because of an intentional pattern of disparate treatment against a covered project category. That remedy could include damages equal to 50–100% of reasonably expected construction costs. It would require specific evidentiary showings, waiting periods, and proof of the applicant’s ability to construct the project. After obtaining all necessary federal approvals, recipients would have to complete the project or repay the remedies, absent force majeure. These provisions could materially change the allocation of permitting risk, but would not make compensation automatic whenever a project stalls. 

NEPA, Water Permitting & ESA Reforms

The National Environmental Policy Act (NEPA) provisions would address both the preparation of environmental documents and the decisions that follow them. The bill would retain the one-year environmental assessment and two-year environmental impact statement framework while strengthening lead-agency coordination, linking environmental review milestones to subsequent authorization deadlines, and requiring sponsor approval for extensions. It would also establish application-completeness procedures and additional mechanisms for enforcing deadlines. For project sponsors, the practical opportunity would be a more accountable schedule across participating agencies. A missed deadline, however, would not itself constitute permit approval. 

Litigation would also operate differently. Section 1110 would generally establish a 150-day filing window for NEPA claims, subject to shorter applicable deadlines, and place review directly in federal courts of appeals. For NEPA deficiencies, the prescribed remedy would generally be remand without setting aside the authorization or enjoining project activities, with a limited correction period. Separate provisions would accelerate challenges to qualifying energy and mineral project authorizations. These changes could reduce the ability of a NEPA challenge alone to interrupt construction, while leaving projects subject to independently applicable substantive requirements. Sponsors and other stakeholders would need to track the particular authorization, publication event, and review provision rather than assume a single deadline governs every claim. 

Water permitting would see substantial changes. The bill would limit Clean Water Act Section 401 certification to defined water-quality requirements and impose stronger evidentiary requirements on denials and conditions. For projects requiring Natural Gas Act Section 7 certificates and qualifying interstate transmission projects, the certification period would be capped at nine months from receipt. For Section 404 applications submitted after enactment, EPA’s authority to prohibit or restrict disposal sites under Section 404(c) would be confined to the period between submission of a complete application and permit issuance. The draft would also expand general-permit treatment for specified discharges affecting less than two acres. That threshold would not eliminate permitting requirements. 

Under the Endangered Species Act, the statutory Section 7 consultation period would fall from 90 to 60 days, with revised extension rules. This would not establish an unconditional 60-day deadline for a final biological opinion. States could also assume specified Interior Department consultation responsibilities through approved agreements, subject to federal oversight, while applicants could elect federal consultation. The resulting choices could affect project schedules and agency coordination, particularly for projects located entirely within one state. 

Transmission Expansion & New Cost Rules for Data Centers

Transmission developers would gain a broader federal siting pathway. Section 2101 would replace the prerequisite for a Department of Energy-designated national-interest corridor with a national-interest determination and generally establish 230 kV as the minimum voltage for eligible FERC-permitted facilities, with special treatment for advanced conductors. Existing statutory triggers tied to state action or inaction would remain. Separate provisions would strengthen regional and interregional planning and require a consolidated, 20-year evaluation of generation and transmission needs. These measures could improve development prospects, although access to federal siting would still depend on satisfying the applicable statutory conditions. 

Data center developers and utilities should closely examine Section 2107’s two distinct cost regimes. One would require transmission pricing to reflect both embedded and incremental costs for qualifying computational-load customers, with lower-cost treatment for non-firm service. A separate regime would apply to data-center and high-density-computing loads of at least 20 MW, including expected phased buildout and multiple sites under common ownership or control. It would require full recovery of incremental service costs even after a customer exits, together with financial assurances or contributions before necessary infrastructure construction or upgrades. The latter regime’s cost-recovery and state-authority provisions would apply to loads interconnecting on or after enactment, while preserving previously approved service arrangements. These provisions could materially affect service agreements, collateral requirements, exit charges, and development economics.

The bill also contains targeted provisions for renewable energy rights-of-way, geothermal development, hydropower, offshore transmission, hardrock mining, and historic preservation. For example, it would establish early processing deadlines for eligible renewable energy rights-of-way applications and direct agencies to develop categorical exclusions for specified low-disturbance renewable energy and grid activities. 

Project participants can prepare by identifying which approvals, agency dependencies, and contractual milestones would be affected. Sponsors should maintain clear records of application completeness, agency requests, delay costs, and existing authorizations. Utilities and large-load customers should assess how the proposed cost-recovery requirements would interact with pending service arrangements and financial commitments. Transmission developers should evaluate potential eligibility for the revised federal pathway alongside their state proceedings.

The proposed bill is expected to be the first submitted for a vote following the November 3 midterm elections. 

If you have any questions about the issues raised in this alert, please contact the authors or the Womble Bond Dickinson attorneys with whom you normally work.