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White Paper by Robin Millican, Jack Andreasen Cavanaugh, Noah Kaufman + 4 more • October 27, 2026
This white paper represents the research and views of the authors. It does not necessarily represent the views of the Center on Global Energy Policy. The piece may be subject to further revision. Contributions to SIPA for the benefit of CGEP are general use gifts, which gives the Center discretion in how it allocates these funds. More information is available here. Rare cases of sponsored projects are clearly indicated.
The Bipartisan American Affordability and Jobs Act (BAAJA), introduced on September 30, 2026, represents the most comprehensive effort in years to resolve the longstanding impasse of federal permitting reform. The bill comes amid rising electricity demand, heightened concerns about household energy costs, and growing energy security challenges. Its provisions could influence oil and gas development, renewable energy projects, and electricity transmission and grid expansions. BAAJA is fundamentally a speed-and-certainty bill: it seeks to change how quickly energy infrastructure is approved and built, rather than determine what gets built.
This white paper first assesses BAAJA’s potential effects on energy costs, energy security and reliability, and emissions. It then examines the bill’s major provisions, including environmental review and litigation, transmission planning and siting, large-load cost allocation, and permitting for specific energy and mineral resources. The analysis finds that the bill would make it meaningfully faster and more predictable to build energy infrastructure of all kinds, especially interstate transmission, but that its outcomes will depend on the efficacy of its implementation, as well as on financing, supply chains, and market conditions.
Other key takeaways about the bill include:
Key issues for policymakers to consider include:
BAAJA’s central affordability proposition is that energy can become cheaper when cost-effective supply is developed and the infrastructure needed to deliver it is built faster. Shorter permitting timelines, reduced litigation risk, and more durable approvals could lower development and financing costs and bring new resources online more quickly. But permitting reform does not guarantee lower energy bills for consumers. Its effects will differ across electricity, natural gas, and petroleum products, depending on which projects get built, how much they cost, and who pays for them.
For electricity, the biggest potential affordability benefits come from increasing generation, expanding transmission, and using the existing grid more efficiently. More transmission can reduce congestion, connect customers to lower-cost generation, and allow regions to share power during periods of high demand. Some estimates suggest that, by 2035, transmission and interconnection reforms similar to those in the bill could enable approximately 100 gigawatts (GW) of additional wind, solar, and battery storage capacity and 38 GW of additional interregional transmission capacity relative to a business-as-usual scenario. In 2035, these changes would reduce grid costs by about $7 billion across the modeled regions. Under a high-natural-gas-price scenario, annual grid savings nearly double to $13 billion, illustrating the value of access to a more diverse mix of generation sources.[i]
BAAJA also requires greater use of advanced transmission technologies when their benefits exceed their costs, potentially increasing capacity without waiting years for new rights-of-way. For example, a recent study found that strategic deployment of advanced conductors could generate roughly $180 billion in savings through 2050 by reducing transmission costs and congestion and expanding access to lower-cost resources.[ii] A September 2026 CGEP white paper covers the benefits of advanced conductors, and other grid-enhancing technologies, in more detail.[iii]
BAAJA could also reduce the system-wide cost of serving rapidly growing electricity loads such as data centers by enabling faster interconnections, better use of existing grid capacity, and greater participation by customer-sited batteries and generators in wholesale markets. Projects that cannot secure timely grid connections may build dedicated generation, including natural gas plants, rather than wait for transmission and interconnection upgrades. This risks locking in a more expensive, less efficient way of meeting demand.
Dedicated plants typically cost more per unit of power. As a back-of-the-envelope illustration, one recent analysis estimates the five-year sustained cost of on-site gas generation at $101–107 per megawatt-hour (MWh), compared with an average U.S. industrial electricity price of $86 per MWh.[iv] The continued expansion of behind-the-meter projects suggests this near-term premium has not deterred many hyperscalers, for whom the value of bringing computing capacity online sooner outweighs the added power cost, on account of the so-called “bit-watt” spread. But for the roughly 40 GW of behind-the-meter gas capacity expected by 2028, the result is foregone investment in the bulk grid and, depending on asset utilization, billions of dollars per year in additional electricity costs that could have been utilized for other purposes.[v]
Beyond the direct cost of generation, some analysts also assert that large-scale reliance on dedicated gas plants increases competition for natural gas between households and industrial customers and puts upward pressure on fuel and electricity prices.[vi]
In contrast, the new legislation could allow more of this demand to be served through grid-connected or hybrid arrangements that draw on a broader portfolio of resources, while directing more investment toward shared transmission and grid infrastructure that benefits everyone. Grid-connected projects also generally benefit from the shared reserves and reliability that the bulk system provides.
Finally, BAAJA seeks to improve cost discipline and prevent customers like households from subsidizing infrastructure they do not proportionally benefit from. Section 2104 allows states to refer utilities to FERC for review of local transmission spending, with penalties potentially including reduced returns on equity. Section 2107 requires covered large loads to bear the incremental costs they cause, while Sections 2101 and 2103 require costs allocated to customers to be roughly commensurate with the benefits they receive. Together, these provisions could reduce cross-subsidization by helping ensure that existing customers do not bear costs attributable to new large loads, including the transmission and other network upgrades needed to serve them. Their effectiveness, however, will depend on implementation and how broadly their protections are applied.
The challenge will be designing cost-allocation rules that protect ratepayers without assigning an excessive portion of shared network costs to individual projects. If grid connection becomes prohibitively expensive, or large loads are required to pay for infrastructure that also benefits other customers, these provisions could encourage data centers to continue building dedicated behind-the-meter generation instead, reducing their reliance on the shared grid and limiting the broader system benefits of their participation in it.
Importantly, the timing and implementation of infrastructure investment will shape whether and how quickly cost reductions translate into lower electricity bills. New generation, transmission, and pipeline projects require substantial upfront capital, and the costs of these investments can be incorporated into utility rates before their full benefits materialize. Underscoring this point, Lawrence Berkeley National Laboratory (LBNL) recently found that, after fuel costs, distribution spending, generation capital expenditures, and transmission costs were among the main drivers of rising U.S. electricity prices.[vii] Infrastructure investment may therefore be necessary to improve affordability over the longer term while putting upward pressure on bills in the near term. The net effect will depend on whether projects are economically justified, whether their benefits ultimately outweigh financing and operating costs, and whether costs are allocated appropriately, as discussed above. Even when investments deliver net savings, customers may have to wait years for those savings to appear on their bills.
Some BAAJA provisions could also weaken cost oversight. Section 2109 directs FERC to presume that the use of advanced transmission technology is prudent and that its costs are just and reasonable. Although advanced technology can generate savings, the highest-performing conductor is not necessarily the least-cost option, and the statutory presumption could make it harder for consumer advocates to challenge expensive choices. Section 2101’s protection against allocating costs to customers who receive little or no benefit also permits recovery through voluntary customer agreements, though the bill does not clearly define what qualifies as voluntary. The bill also allows modest, though hardly negligible, costs to be passed on to ratepayers via transmission rates, including grid-data compliance costs.
Finally, overbuilding remains a risk. Section 2106 requires regional planners to jointly evaluate transmission needs and expected generation against demand forecasts over a 20-year horizon. That longer-term, integrated approach could improve coordination, but projections of data center demand remain uncertain. If utilities and regional planners build infrastructure for loads that do not materialize, customers could be left paying for underused or stranded assets. BAAJA’s interconnection queue reforms could help limit this exposure. Section 2106 requires a streamlined cluster-study process with meaningful, nonrefundable financial security and withdrawal penalties designed to deter speculative projects, while Section 2110 requires FERC to begin a rulemaking within one year directing transmission providers to use AI and automation, as appropriate, in processing generator interconnection requests. These measures could improve the quality of project information available to planners, but they cannot eliminate uncertainty about future demand. Moreover, Section 2107’s protections focus on the costs of serving covered loads; they may not fully insulate other customers from the costs of broader regional infrastructure built in anticipation of demand that never materializes.
BAAJA could reduce natural gas costs in regions where pipeline constraints prevent relatively inexpensive domestic supplies from reaching consumers. This is particularly relevant in the Northeast, where limited pipeline capacity can drive sharp winter price spikes and increase reliance on imported LNG and fuel oil to meet regional gas and electricity demand. In January 2025, for example, natural gas at the Algonquin Citygate in New England averaged $16.37 per million British thermal units (MMBtu), compared with $4.13/MMBtu at Henry Hub.[viii][ix] Stranded gas in the Marcellus, currently trading at ~$1/MMBtu at Eastern Gas South Hub, would be the most likely resource tapped for Northeast gas expansion.[x]
The bill addresses several permitting barriers to expanding capacity. Section 1202 narrows states’ authority under CWA Section 401 to block interstate gas pipelines; limits reviews to specified water-quality requirements and, for these pipelines, direct point-source discharges; and imposes a nine-month review deadline. BAAJA’s broader NEPA reforms would also exempt certain pipeline repairs, upgrades, and modifications within existing rights-of-way from federal environmental review. These changes could make it easier to expand capacity along existing routes and connect production to constrained markets.
Market factors will determine how much new pipeline capacity is built to address affordability issues in constrained regions, but there is evidence of real demand. In the Northeast, Williams has revived two long-delayed projects, the Northeast Supply Enhancement (NESE) pipeline and the Constitution Pipeline, after canceling them in 2024 and 2020, respectively, following years of disputes over state water permits.[xi] In the case of the NESE, local gas utilities have already signed long-term contracts to pay for the new capacity. Whether additional pipeline projects move forward will depend on whether utilities, generators, or other shippers are willing to finance additional capacity that may be needed primarily during a few periods of peak demand.[xii] While BAAJA reduces some regulatory hurdles, it does not resolve these commercial and cost-allocation challenges.
The bill could also reduce waste of associated natural gas in the system by allowing pipelines—often gathering lines—to be placed in federal right-of-way corridors under Section 2229. Where gathering and takeaway infrastructure is constrained, producers may have limited options for bringing gas produced alongside oil to market, leaving some to be flared in oversupplied producing regions such as the Permian Basin. The World Bank estimates that around 100 billion cubic feet (bcf) of gas was flared in the Permian in 2025[xiii]—equivalent to more than a day of average U.S. natural gas consumption. This represents a substantial waste of energy resources, while flaring releases CO₂ and can emit unburned methane when flares are unlit or combustion is incomplete.[xiv] Additional pipeline capacity can help, as the Matterhorn Express pipeline did when it came online in late 2024 and contributed to an estimated 13 percent reduction in Permian flaring the following year.[xv] Energy Transfer’s proposed Desert Southwest Expansion, a pipeline comparable in capacity to the Matterhorn pipeline, is under FERC review and would expand the existing Transwestern Pipeline to carry up to 2.3 bcf per day of Permian gas through New Mexico and Arizona.[xvi]
But greater production does not necessarily mean cheaper gas for every consumer. The location of new supply and pipeline capacity matters. The net affordability effect is therefore likely to vary by region and depend on market conditions.
To the extent that BAAJA would facilitate additional domestic oil production, its impacts on gasoline and diesel prices are likely to be negligible. U.S. gasoline and diesel prices remain closely linked to the international crude and refined-product prices. Additional domestic production could put modest downward pressure on global prices if it increases total supply, but the scale of the effect would depend on the volume and timing of new production, the level of demand, and the responses of other producers. Such production is unlikely to shield U.S. consumers materially from a major global supply disruption.
However, it can cushion the broader macroeconomic impact of global supply disruptions. When global prices rise, U.S. consumers pay higher prices, but domestic oil producers also receive higher revenues. As a net petroleum exporter, the United States now retains more offsetting oil income than when it was a net importer. As a case in point, the Dallas Fed estimates that a global oil-supply disruption of 15 percent—the magnitude of the supply shortage induced by the Iran War—would have reduced U.S. GDP growth by over 5 percent in 1980, compared to just 0.3 percent under today’s economic structure. This represents an almost twentyfold decline.[xvii]
The United States faces a changing energy security environment. Domestically, rising electricity demand, aging infrastructure, and extreme weather are increasing pressure on the power system. Globally, geopolitical tensions and export controls are exposing vulnerabilities in energy and critical mineral supply chains. BAAJA could address some of these risks, particularly by strengthening interregional transmission capacity to improve resilience during extreme weather events and helping diversify critical mineral supplies.
Interregional transmission can improve reliability during extreme weather and other disruptions. BAAJA’s transmission reforms require regional and interregional planning, strengthen federal siting authority, and establish a framework for allocating costs according to the benefits customers receive. Greater connectivity lets regions access electricity from elsewhere when local generation fails or demand surges, reducing dependence on any single region’s resources.
Winter Storm Uri in Texas in 2021 illustrates the potential value of this connectivity. Uri caused an estimated $80 billion to $130 billion in economic losses in Texas, and the state’s final mortality analysis identified 246 storm-related deaths.[xviii] In a simulation of extreme events comparable to the February 2021 storm, one study found that requiring 30 percent interregional transfer capability across the United States reduced average outages by 39 percent.[xix] The study also found that interregional transmission could reduce system costs and emissions. These are modeled benefits of a specific transmission requirement, not estimates of BAAJA’s direct effects, but they illustrate the potential value of greater interconnection to improve reliability.
Diversifying critical mineral supply chains can reduce exposure to geopolitical coercion. Electric vehicles, wind turbines, solar panels, batteries, semiconductors, and other strategic technologies depend on minerals and processed materials whose supply chains are highly concentrated. The International Energy Agency (IEA) reports that China, the leading minerals-refining country, accounted for an average of 70 percent of output across key energy minerals in 2025, including an estimated 85 percent share of rare-earth refining.[xx] Recent export restrictions demonstrate the economic and strategic vulnerabilities this concentration can create. In December 2024, China imposed a ban on exports of gallium and germanium to the United States in response to escalating tensions over U.S.-imposed restrictions on semiconductor exports. China has since suspended the ban through late 2026, but broader export-licensing requirements remain in place.[xxi] The restrictions demonstrate China’s willingness and ability to leverage its position in critical mineral supply chains for geostrategic advantage. The potential economic exposure is significant: the IEA estimates that, if fully implemented, China’s expanded rare earth export controls could put at risk $6.5 trillion in annual downstream production across the automotive, high-tech, defense, and energy sectors.[xxii]
BAAJA could help address this risk and diversify supply by reducing permitting barriers to domestic mineral development. The bill’s general permitting and judicial-review reforms cover mineral extraction and processing projects. Section 2215 also restores the ability of hardrock mining operators to establish multiple mill sites for waste rock disposal, tailings, and related activities, and makes hardrock minerals leasable on federally acquired lands.
Domestic mining is only one part of a secure supply chain, however, and faster permitting does not guarantee that mines will be developed. New projects require sufficient expected demand and prices to justify substantial upfront investment. Although demand for critical minerals has grown strongly, the outlook for individual minerals remains uncertain: changes in battery chemistries can shift demand among materials, while oversupply, price volatility, and policy uncertainty can undermine project economics. The IEA reports that investment in critical minerals fell 9 percent in 2025, while investment in battery materials declined by more than 20 percent amid weaker prices, shifting battery chemistries, and policy uncertainty.[xxiii] Mining is also only the upstream part of the supply chain; processing, refining, and component manufacturing can remain concentrated abroad.
If the United States intends to reduce its dependence on China and other sources of concentrated supply, it therefore needs a broader diversification strategy than what BAAJA alone provides. Other options to address critical minerals dependencies include sourcing from allies and partners, developing substitutes and innovative approaches, and recycling materials, all of which may offer faster, more economical paths to resilience than domestic mining expansion.
Energy policy is often framed as a “trilemma”: the challenge of balancing security, affordability, and sustainability. A healthy energy system successfully balances these priorities.
BAAJA is not climate legislation. Its main aims are security and affordability: enabling all types of energy infrastructure to be built faster and more predictably at a time when prices are rising and electricity grids and oil and gas supply chains are under strain. Its general permitting reforms apply across energy sources, and its technology-specific provisions support both emitting and non-emitting resources.
This distinction matters in the absence of a comprehensive federal climate strategy. Markets alone will not adequately address the harms caused by GHG emissions. Policies that directly reduce emissions or that incentivize producers and consumers to do so therefore remain necessary. BAAJA does not offer those policies, but it could shape their effectiveness if they are introduced in the future. Even strong climate policy cannot deliver a rapid clean-energy buildout or the steep emissions reductions it enables without the generation, transmission, and storage infrastructure required to support it. By lowering barriers to that infrastructure, BAAJA could make future emissions-reduction efforts faster and less costly.
On balance, BAAJA is likely to produce a net reduction in emissions, although the size of that reduction is highly uncertain. The bill could lower emissions by enabling additional clean energy and transmission capacity. It could also raise emissions to the extent that expanded U.S. oil and gas development increases global consumption; but, as will be discussed below, that effect is likely to be smaller, particularly for oil. The bill’s fossil fuel provisions are therefore unlikely to meaningfully impede progress toward national or global climate goals.
While this section focuses on climate change, it is worth noting that sustainability is broader than climate. BAAJA’s changes to environmental review, water-quality certification, endangered species consultation, and historic preservation could affect pollution, ecosystems, and cultures, and those effects deserve their own analysis.
BAAJA’s clearest potential climate benefits come from enabling clean energy and improving grid access. [xxiv] Its effects on individual clean technologies vary:
On grid access, transmission is particularly important: although it supports all types of generation, insufficient transmission can prevent new clean generation from displacing fossil-fuel generation, especially when resources such as wind, solar, and geothermal are located far from population centers. One analysis of the Inflation Reduction Act found that the failure to accelerate transmission expansion could erase most of the emissions reductions the law was expected to deliver.[xxv]
Faster transmission and interconnection could also help steer data centers toward the grid and away from high-emitting on-site generation, although, as discussed above, pricing rules could complicate this shift.
The emissions implications of additional oil and natural gas infrastructure require the same counterfactual analysis. Emissions from a new project are not necessarily a net addition to global emissions. In a global oil market, additional US production tends to displace output elsewhere. The net effect depends partly on the emissions intensity of the supplies involved. Additional supply can also encourage consumption by lowering prices and delay the adoption of cleaner alternatives. Easier permitting alone, however, is unlikely to increase US oil production enough to have a large effect on global consumption, particularly as growth in U.S. shale production is slowing sharply.
Natural gas presents a more complex picture because its markets are regional and it competes more directly with clean electricity. As mentioned previously, new pipelines can reduce flaring by bringing gas produced alongside oil to market. Additional gas can also lower emissions when it displaces coal, provided methane leakage is controlled, but raise them when it displaces clean electricity or encourages additional consumption. Its climate impact therefore depends on what would be produced and consumed in its absence—both domestically and abroad, to the extent infrastructure that is easier to permit in the United States facilitates any increase in exports of gas.
The bill is not, however, likely to lead to a material expansion in LNG exports. As of September 2026, DOE had authorized 49.8 Bcf/d of exports from large-scale US terminals to non-free-trade-agreement countries, more than double the roughly 20 Bcf/d now operating, and several authorized projects have yet to reach a final investment decision. [xxvi]New terminals generally need long-term buyer contracts to reach a final investment decision, so the binding constraint on further export growth is global demand for US LNG, not permitting. BAAJA does little to change that demand, so it is unlikely to translate into substantially more LNG export capacity or exports.
These market dynamics and years of experience explain why policy focused on blocking individual oil and gas projects is largely ineffective at reducing global GHG emissions. As long as demand remains strong, restricting production in one place creates opportunities elsewhere, including for producers with weaker environmental standards and governments less friendly to the United States. If other producers do not fill the gap, higher prices can encourage conservation and substitution. But governments also face strong pressure to shield consumers by subsidizing energy, releasing strategic stocks, and securing alternative supplies—blunting or nullifying the effect of restrictions. Higher prices and unreliable supplies can also undermine support for climate action.
In sum, BAAJA’s climate benefits will depend on how much it accelerates clean energy relative to fossil fuels. Oil and gas are mature industries with established development pathways, while transmission and clean energy face significant barriers to expansion. Given that reductions in U.S. supply are largely offset elsewhere, there is reason to expect that emissions reductions from faster clean energy deployment would outweigh increases from easier fossil fuel permitting.
More importantly, removing those barriers can make stronger climate policies less costly and more effective in the future. Affordable, reliable energy can also help sustain political support for such policies. As noted above, BAAJA is no substitute for an ambitious federal climate strategy, but making the infrastructure needed to reduce emissions easier to build would be an important step toward one.
The National Environmental Policy Act (NEPA), enacted in 1970, requires federal agencies to evaluate and disclose the environmental effects of “major federal actions,” such as issuing a permit, providing funding, or undertaking a federal project, before proceeding with those actions. The process also provides opportunities for public participation, including public comment. NEPA is primarily procedural: it requires federal agencies to understand and disclose the consequences of their decisions, but it does not require them to choose the least environmentally harmful option. For projects requiring an Environmental Impact Statement (EIS), the most extensive form of review, agencies must also evaluate reasonable alternatives and ways of mitigating harm. NEPA also functions as an “umbrella” process that can coordinate reviews under the ESA, CWA, and National Historic Preservation Act (NHPA). This coordination does not, however, replace the separate permitting decisions or substantive legal obligations imposed by those statutes.
NEPA’s burden on major infrastructure is concentrated in a small share of reviews and in the uncertainty surrounding them. Approximately 99 percent of NEPA reviews are resolved through categorical exclusions or less-extensive environmental assessments (EAs) rather than an EIS, although this figure encompasses a very large number of routine federal actions and says relatively little about the burden on major infrastructure projects.[xxvii] For projects with a completed EIS, the median time from Notice of Intent to final EIS was 2.2 years in 2024, compared with 3.1 years for projects completing EISs between 2017 and 2020.[xxviii] However, these figures exclude time spent on pre-review preparation, subsequent permitting under substantive environmental laws, and litigation, and therefore do not reflect the full time required to secure project approvals. They also do not capture projects developers never propose because they anticipate the cost, delay, or risk of review. A February 2026 survey of clean energy developers found that 80 percent of respondents intentionally site projects in a way that avoids triggering federal permitting reviews, given the associated uncertainty and cost.[xxix]
Two sources of uncertainty matter most. The first is scope. Historically, courts have sometimes required agencies to consider reasonably foreseeable indirect and cumulative effects, in some cases including downstream consequences and activities facilitated by a project. In its 2025 Seven County Infrastructure Coalition v. Eagle County decision, the Supreme Court narrowed that requirement. It held that NEPA reviews should focus on the effects of the project being evaluated, not on separate projects it might lead to in other locations or in the future, such as new oil wells or distant refineries linked to a new rail line. However, the Court preserved the requirement to consider indirect effects sufficiently connected to that project.[xxx] Because the decision leaves agencies to judge which effects are close enough to count, the scope of review is still likely to vary across agencies and to be tested in court.
The second source of uncertainty is litigation. NEPA challenges generally allege procedural failures, such as inadequate consideration of environmental effects or alternatives, insufficient responses to public comments, or an inadequate explanation of an agency’s decision. Under current law, the general statute of limitations for challenges under the Administrative Procedure Act can extend to six years.[xxxi] Some statutes set shorter periods, such as 150 days for federal highway and transit approvals.[xxxii] A court that finds a violation may remand the analysis to the agency and, depending on the circumstances, vacate the approval or halt the project until the deficiency is corrected. The risk is not confined to fossil fuel projects: a Stanford study of 355 major energy and transportation projects that completed federal environmental review between 2010 and 2018 found that 28 percent of those requiring an EIS faced pre-development litigation, including nearly two-thirds of solar projects, half of pipeline projects, 38 percent of wind projects, and 31 percent of transmission projects.[xxxiii] Developers and agencies prevail in most cases, but the prospect of litigation can lead agencies and project sponsors to produce more expansive and thus time-consuming analyses than might otherwise be required.[xxxiv]
BAAJA addresses both the duration of review and post-review litigation risk by:
BAAJA’s proposed reform of NEPA focuses on process and litigation. It would preserve NEPA’s fundamental role as a procedural, disclosure-oriented statute, but would narrow which projects are reviewed, constrain what reviews must consider, establish deadlines for decisions, and limit how litigation is brought and resolved.
The front-end reforms could reduce the number of reviews and make the remaining ones less labor-intensive and faster to complete. Several provisions build on changes already made through the FRA, executive action, and the Seven County decision. Codification would make these requirements more durable. Additional efficiencies could come from novel elements, including the narrowed definition of a major federal action, expanded categorical exclusions, limits on alternatives analysis, the substitution of qualifying state or Tribal reviews, and deadlines for final decisions and outstanding authorizations. Extending the period for relying on programmatic EISs from five to ten years could also reduce duplicative analysis.
The scale and timing of these benefits, however, would depend on agency capacity, implementation choices, and subsequent litigation. Some provisions, including the categorical exclusions and renewable energy review standards, require new agency rulemaking, meaning the reforms will take time to reach full effect. Others require agencies to determine whether applications are complete, coordinate reviews across multiple agencies, and issue decisions within ambitious statutory deadlines. The existence of a statutory deadline does not guarantee that an agency will meet it, and new regulations may themselves face legal challenges.
BAAJA’s reforms also do not go as far as other proposals that would redesign environmental review rather than primarily constraining the existing process. The Aspen Institute’s Building Cleaner, Faster framework, for example, would establish a “deemed to comply” pathway under which projects meeting predefined siting, design, and mitigation criteria are presumed to satisfy applicable review requirements.[xxxv] Rather than primarily shortening and limiting the scope of project-by-project NEPA review, this approach would establish environmental criteria upstream and allow qualifying projects to proceed through a more standardized process with less case-by-case analysis.
For developers and lenders, the litigation provisions in BAAJA are likely to be particularly consequential. The 150-day limitations period, stricter standing requirements, greater judicial deference to agencies on the scope and content of review, and remand without vacatur would sharply reduce the risk of an authorization being invalidated after capital has been committed. Because agencies and developers already prevail in most NEPA cases, the principal effect is likely to be a reduction in delay and uncertainty rather than a wholesale change in litigation outcomes.
BAAJA would also change where environmental litigation takes place. Covered challenges to the adequacy of NEPA review would go directly to the court of appeals for the circuit in which a project is located, bypassing district courts. This could accelerate litigation and reduce opportunities for prolonged proceedings, but it would also move fact-intensive disputes into an appellate forum, potentially making it harder for challengers to develop the evidentiary record supporting their claims.[xxxvi] Combined with the 150-day filing window and stricter standing requirements, this would substantially limit the avenues through which project opponents can challenge federal approvals.
The corresponding impact is that courts would have less leverage to compel agencies to correct deficient analyses before projects proceed. Under BAAJA, a defective NEPA review would no longer, by itself, provide a basis to halt a project while the agency corrects the deficiency. This shifts NEPA accountability away from an ex ante model, in which a court could suspend an approval until procedural defects were remedied, toward a model in which the review is corrected while construction or operation continues.
That distinction makes the continued role of substantive environmental statutes important. NEPA has never replaced the legal obligations imposed by the CWA, ESA, or other applicable laws, and BAAJA’s savings provisions are intended to preserve legal challenges under those statutes. However, the bill also amends elements of the CWA and ESA, so the full extent of available remedies must be considered alongside those separate provisions.[xxxvii] The practical result is a framework in which NEPA-based challenges would generally be less likely to halt a project, while compliance with independent statutory requirements would remain a separate constraint on project development.
BAAJA also sets deadlines and narrower standards for three reviews that can stall projects: state water quality certification (CWA Section 401), wildlife consultation (ESA Section 7), and historic preservation review (NHPA Section 106). In each case, the underlying authority remains, but timelines are shortened; for the CWA and NHPA, the scope of review is also narrowed and remedies are weakened.
Section 401 allows a state to certify, condition, or deny any federally permitted project that may result in a discharge into navigable waters and certain connected streams and wetlands.[xxxviii] A few states have used this provision as a de facto veto over pipelines, including New York in 2016 with the Constitution Pipeline.[xxxix] In that case, the developer and other critics argued that the denial reflected opposition to natural gas rather than genuine water-quality concerns.[xl] The Second Circuit upheld the denial in 2017, however, and the project was abandoned in 2020. EPA subsequently revised the implementing rules in 2020 and 2023 and proposed another revision in January 2026.[xli]
BAAJA would codify an approach similar to the 2020 rule, limiting state certification reviews to specified CWA water-quality requirements. States would generally be unable to use this process to impose conditions based on unrelated state-law requirements or indirect effects such as GHG emissions. Because state review would be limited to the water-quality requirements, the underlying criteria provided by the federal government would become more important. EPA currently issues recommended water-quality criteria as discretionary guidance that states then use to develop their standards. BAAJA (Section 1201) would require EPA to adopt these criteria through notice-and-comment rulemaking, with challenges going directly to the federal courts of appeals.
The bill would also raise the bar for state action. Denials and conditions would have to be supported by “clear and convincing evidence,” a heightened evidentiary standard. Courts now generally uphold state decisions unless they are arbitrary and capricious. The burden of proof in court would fall on the state, and any conditions would be limited to the “least burdensome” means of meeting water-quality requirements.
The bill would preserve the existing one-year limit on state review, while adding deadlines for determining whether an application is complete and requiring states to explain denials in writing. Interstate gas pipelines and transmission lines would receive a shorter, nine-month review limited to the project’s direct point-source discharges into regulated waters, rather than the broader water quality effects of the activity as a whole, which states may consider under current law. Effects such as construction runoff, erosion, and groundwater impacts would generally fall outside state review. Hydropower and other projects would remain subject to review of all discharges.
These changes would affect projects beyond energy, including some industrial wastewater facilities, because Section 401 applies broadly to federally permitted activities that discharge into regulated waters. The nine-month, direct-discharge-only review, however, would apply specifically to interstate gas pipelines and transmission lines.
The bill also extends the life of other CWA permits and reduces post-permit risk:
Section 7 of the ESA requires federal agencies to consult with the relevant wildlife agency (the U.S. Fish and Wildlife Service or NOAA Fisheries) when a proposed federal action may affect a listed species or unlawfully damage critical habitat. The action agency makes the initial effects determination, while the relevant wildlife agency conducts formal consultation and issues a biological opinion assessing whether the action is likely to jeopardize listed species or adversely modify critical habitat. If the wildlife agency finds that it is, the opinion identifies reasonable and prudent alternatives, if any, that would avoid adverse impacts.
Under BAAJA, formal consultation would be shortened from 90 to 60 days, and challengers would have 150 days after a biological opinion is published to petition the D.C. Circuit. The bill defines “best scientific and commercial data available,” requires listing decisions to use qualifying state data, and authorizes $150 million per year through FY2031 for consultation and state programs. States may assume the Fish and Wildlife Service’s consultation duties for in-state projects, but duties cannot be assigned to states in the case of multistate projects and such projects remain with the Service. Highway and transit projects in existing rights-of-way that are already categorically excluded under NEPA would be exempt from Section 7(a)(2) entirely, including its no-jeopardy duty.
Section 106 of the NHPA requires federal agencies to consider the effects of federal undertakings on historic properties—such as historically significant buildings, structures, districts, archaeological sites, and places of traditional religious or cultural importance to Tribes—that are listed in or eligible for listing in the National Register of Historic Places. It also provides an opportunity for consultation on how adverse effects may be avoided, minimized, or mitigated.
Most reviews under the NHPA end without finding adverse effects: of roughly 120,000 projects reviewed each year, about 2,000 result in such a finding.[xliii] But no statute sets a deadline for completing the evaluation, and given limited staff at state and Tribal preservation offices, reviews can run for years. BAAJA would rewrite Section 106 along the same lines as its NEPA reforms:
Taken together, the CWA, ESA, and NHPA reforms would preserve the underlying statutory authorities but generally shift leverage from states, wildlife agencies, and preservation offices to project applicants. The depth of that shift varies by statute. The bill most substantially narrows state water quality review, particularly for linear infrastructure, and rewrites historic preservation review along the same lines as its NEPA reforms. In contrast, it largely accelerates, rather than narrows, endangered species consultation.
Under the CWA, the bill’s limits on conditions are likely to matter more than its limits on denials. Outright denials are already rare: of 7,503 state decisions on Army Corps permits from November 2023 to September 2025, 0.8 percent were denials, while 67 percent were approvals with conditions.[xlv] Still, the possibility of a denial gives states leverage because it can lead applicants to accept conditions, redesign projects, or withdraw and resubmit applications. The bill would weaken both sources of state influence. Because a state could deny certification only by showing, through “clear and convincing evidence,” that no modification could bring a project into compliance, denial would become a last resort and “approval with conditions” the default. The least-burdensome standard would then limit what those conditions could require. For pipelines and transmission lines, the nine-month, discharge-only review would narrow state authority further still.
These changes matter most for pipelines, which have faced the most prominent denials, but they could also substantially benefit transmission projects over time. Because BAAJA’s proposed siting provisions and recent court decisions, including the Third Circuit’s 2025 Transource ruling, limit states’ ability to reject interstate lines on economic grounds, water quality certification could become the only remaining state tool for blocking them.[xlvi] The inclusion of interstate transmission lines in a narrower CWA review process forecloses that alternative option for blocking transmission projects. The two sets of provisions are therefore best understood together.
The Section 106 NHPA reforms follow a similar logic for historic preservation. By excluding most visual and cumulative effects, they would remove grounds that opponents have used to challenge offshore wind and transmission projects.[xlvii] These changes would matter most for clean energy and transmission.[xlviii]
The bill retains a role for Tribes and historic-preservation offices, but agencies could conclude consultation even if those parties object. Current law requires agencies to consult Tribes, but much of the process for Section 106 review is established through regulations rather than statute. In July 2026, the Advisory Council on Historic Preservation (ACHP), an independent federal agency, voted to advance a proposed rule that would overhaul those regulations, including by no longer treating natural features such as mountains and springs as eligible sites.[xlix] BAAJA would write a Tribal role into the statute, protecting it from future regulatory rollbacks. While agencies would no longer have to consult Tribes when identifying historic properties, they would still have to request information from Tribes and incorporate any response received from Tribes within 30 days. Agencies would have to consult Tribes when assessing and resolving adverse effects, and that consultation must begin no later than any associated NEPA review. The proposed Section 106 reforms would also limit stakeholder remedies in the same way as the broader NEPA provisions: by barring courts from vacating agency decisions during litigation and allowing remand only for correction.
The ESA changes are the most modest. Consultation would be faster, but the jeopardy standard, listing criteria, and judicial remedies would remain largely intact.
The principal open question is state assumption of Section 7 responsibilities. Delegation of those responsibilities to states could make consultation more responsive to local conditions, with the likely beneficiaries being single-state projects such as solar, geothermal, and mining—not interstate pipelines or transmission lines.
However, delegation risks inconsistent implementation of a federal statute across states with different levels of scientific expertise, administrative capacity, and approaches to evaluating species impacts. The bill requires participating states to certify that they have adequate resources, meet federal deadlines, and apply the same legal standards as the Secretary; it also requires annual audits during their first four years. But if applications may be denied only for lack of capability, the Department of the Interior’s ability to screen for differences in scientific approach would be constrained. Moreover, experience with the highway program on which the provision is modeled suggests that uptake may be low: relatively few states have assumed federal NEPA responsibilities, and those that have include states with substantial administrative capacity, such as California and Texas. If participation is limited, or disputes arise over the adequacy of state-led consultations, delegation may do little to reduce delays.
Across all three statutes, the bill trades the leverage of reviewing parties for speed and predictability for applicants. Whether that trade improves outcomes or merely weakens oversight will depend less on the statutory text than on implementation and the capacity of agencies, states, and preservation offices to complete narrower reviews effectively within shorter timelines.
Transmission is one of the largest bottlenecks facing the U.S. electricity system. Regional and interregional transmission projects take a decade on average to come online, while the benefits of a more interconnected grid—including improved reliability, reduced congestion, increased access to lower-cost generation, and an enhanced ability to connect new generation—often extend well beyond the customers or state where a line is physically located.[l] BAAJA addresses this problem through four linked changes: it puts transmission planning into statute, strengthens federal authority to site interstate lines, standardizes how costs are allocated, and pushes utilities to get more out of existing infrastructure.
Transmission planning is not currently required by statute. FERC requires regional planning through regulatory orders, most recently Order No. 1920, but regions retain wide latitude, and interregional planning has produced no interregional lines since Order No. 1000 first required interregional coordination in 2011.[li]
BAAJA (Sections 2103–2105) would codify regional transmission planning and cost allocation in federal law, while allowing compliance with existing FERC orders, including Order No. 1920, to satisfy the bill’s requirements. It would further require interregional processes among neighboring regions, using common assumptions and models and considering upgrades to existing lines and advanced transmission technologies. Regions would have two years to establish these processes and would update them every four years. The bill would also replace the Department of Energy’s (DOE) role in designating National Interest Electric Transmission Corridors with a requirement for DOE to conduct a congestion study every three years.
Two features stand out. First, the bill links planning to permitting: projects selected through an approved regional or interregional plan would automatically satisfy the criteria for FERC’s federal siting backstop, creating a pathway from identified need to permitted line. Second, it bans federal right-of-first-refusal provisions that favor incumbent utilities, codifying a principle FERC first adopted in Order No. 1000 and opening planned projects to competing developers.
BAAJA would also address the interaction between transmission planning and generator interconnection, which are generally conducted through separate processes today. Each planning region would be required to adopt a 20-year consolidated planning process that jointly considers forecasted generation, transmission, and load growth. Regions would publish resource- and fuel-neutral Planned Interconnection Locations (PILs), with fixed per-megawatt interconnection costs established up front for each zone. This would give generation developers greater certainty about where projects can connect and what grid upgrades will cost.
The bill would also discourage speculative queue requests. Because entering a queue has historically been inexpensive, developers often submit multiple requests expecting most to be abandoned. Of the capacity that requested interconnection between 2000 and 2020, only 13 percent had reached commercial operation by the end of 2025.[lii] When speculative projects withdraw mid-study, the upgrade costs assigned to remaining projects change, forcing restudies that delay everyone else. Building on FERC’s Order No. 2023, Section 2106 would require a cluster-study process in which interconnection requests are evaluated in groups, with “a single decision point, meaningful and nonrefundable financial security, and withdrawal penalties sufficient to deter speculative projects.” FERC would determine the specific amounts.
Under current law, states generally retain siting authority over interstate lines. FERC’s backstop siting authority under Section 216 of the Federal Power Act currently applies only within corridors designated by DOE, a process that can take a decade and requires its own environmental review. For multiple reasons, FERC has never used this authority.
BAAJA (Section 2101) would remove the DOE-designated corridor requirement and allow developers to seek a federal permit directly from FERC when specified conditions for federal intervention are met. For interstate lines capable of transmitting at least 230 kilovolts (kV)—or qualifying projects using advanced conductors—FERC would be required to issue a permit if the project is consistent with the public interest, protects or benefits consumers, improves reliability, and meets the bill’s other statutory criteria. The federal backstop could be triggered, for example, when a state lacks siting authority, denies an application under circumstances covered by the statute, or fails to act within one year.
For lines of at least 345 kV, developers could apply to FERC while the state siting process is still underway, allowing the two reviews to proceed in parallel. FERC could not, however, issue its permit until it finds that a statutory condition for federal backstop authority has been satisfied. In reviewing an application, FERC would provide at least 45 days for public comment, consider relevant state proceedings and input from affected landowners, lead the federal environmental review, and coordinate other required federal authorizations and permitting processes. Challenges to FERC’s decision would go directly to the federal courts of appeals.
BAAJA would also seek to streamline environmental permitting challenges. Upgrades within existing rights-of-way, such as reconductoring, would be exempt from federal NEPA and historic preservation review.
For lines permitted through the backstop or selected in regional and interregional plans, BAAJA would allocate costs to beneficiaries “at least roughly commensurate” with the benefits they receive. These benefits include improved reliability, reduced congestion and losses, reduced operating reserves, and added carrying capacity or access to generation, although the latter two count only where they improve reliability or lower the cost of delivered power. Reliability also serves as a threshold: every planned or backstop line must demonstrate a material reliability improvement, such as reduced loss-of-load probability or correlated outage risk. Customers receiving no or only trivial benefit could not be involuntarily charged, although utilities could recover backstop-line costs through voluntary agreements. Compliance with Order No. 1920 would satisfy the regional requirements, so these definitions would apply most directly to interregional and backstop lines. The bill does not expressly exclude state-policy benefits such as emissions reductions, but its definitions leave little room for them: a line justified chiefly by state clean energy goals would need to show reliability or cost benefits on its own terms.
A substantial share of transmission investment goes to local projects that utilities plan with limited outside review. Under Section 2104, a state could refer a utility’s local planning to FERC, which would investigate with up to three state-appointed representatives. If the utility’s process fails to select more efficient or cost-effective facilities, or interferes with regional planning, FERC could order changes, reduce the utility’s return on equity, remove the presumption that its spending was prudent, or impose fines of up to $5 million per imprudent facility, payable to the state. Fines would apply only to facilities developed or energized within the period beginning 60 days before the referral.
Section 2109 would require FERC-regulated utilities to use advanced transmission technologies, including “best-available” conductors, in new and upgraded transmission projects. Utilities would conduct recurring evaluations of dynamic line ratings, advanced power-flow controls, topology optimization, and high-performance conductors, including least-cost analysis, and would have to deploy them on a FERC-set timeline when benefits exceed costs. Utilities that fail to do so would face reduced returns on equity. FERC, with DOE, would define and annually update the best-available conductor standard. The costs of these technologies would be presumed prudent and just and reasonable.
BAAJA’s transmission provisions target three interrelated barriers to grid expansion: fragmented planning, state-by-state siting authority, and uncertainty over who pays.
The planning reforms matter chiefly for their durability and reach across regions. Codifying Order No. 1920 protects regional planning from reversal by a future commission, and the interregional mandate addresses the gap that Order No. 1000 left open. But BAAJA provides no strong mechanism within the planning process itself to compel action: regions are not obligated to select any project identified through interregional planning, and if a region fails to submit a plan, FERC’s only stated recourse is an extension of up to six months. The pressure comes instead from the backstop, as discussed below.
BAAJA’s interconnection reforms combine two elements of differing significance. Its queue-discipline provisions (cluster studies, nonrefundable deposits, and withdrawal penalties) largely build on FERC’s Order No. 2023, and their incremental benefit may be modest. Order No. 2023 cut speculative requests by more than half in PJM, CAISO, and NYISO, but has not materially accelerated processing, and interconnection still averages roughly five years nationally.[liii] Nearly three years after its issuance, FERC’s chairman noted in June 2026 that the order’s compliance process remained incomplete.[liv]
The more consequential change is to consolidated planning, which the Center for Public Enterprise describes as making interconnection subject, for the first time, to “some anticipatory planning of grid needs.”[lv] By requiring every planning region, including those outside organized markets, to publish interconnection locations with fixed upfront costs, the bill would extend nationally a Southwest Power Pool model that plans for generation in advance rather than reacting to individual requests.
BAAJA nonetheless stops short of deeper queue reforms. One recent study argues that the larger barriers to more efficient interconnection queues are conservative study assumptions, which FERC declined to standardize in Order No. 2023. It points instead to “connect and manage,” in which generators connect first and congestion is handled through curtailment. ERCOT, which uses this approach, interconnected 2.5 times more capacity than PJM in 2021–2022 despite having roughly half its peak load. However, ERCOT’s energy-only market makes this approach easier to apply than in markets that pay for capacity.[lvi] Legislation that Senator Heinrich, one of BAAJA’s lead sponsors, introduced in July 2026 would move further in this direction. The Grid Connection and Congestion Management Act would require regional transmission organizations (RTOs) and independent system operators (ISOs) to offer an energy-only interconnection service in which projects connect without upgrades for deliverability, accept curtailment to manage congestion, and receive study results within one year. It would not, however, extend to regions outside organized markets or address how curtailed generators would manage revenue risk.[lvii]
The transmission permitting and siting reforms are among the most significant in BAAJA. By removing the corridor requirement, starting the state clock at filing, and allowing concurrent federal and state review, the bill turns an authority FERC has never used into a workable backstop that could realistically prevent states from indefinitely blocking construction of a qualifying interstate line, while preserving opportunities for states and landowners to provide input.[lviii] The backstop’s effectiveness, however, depends on who uses it. Because FERC lacks the capacity to identify transmission needs nationwide, the bill relies on developers to propose lines. Combined with the ban on federal rights of first refusal, the possibility that a competing developer could secure a federal permit is meant to encourage utilities and regions to plan in good faith. That pressure works only if credible developers are willing to go over the heads of state regulators and utility partners, a step that carries reputational and commercial risk for companies that depend on those relationships. Time will tell whether BAAJA shifts that benefit-risk calculus.
Other policies could complement BAAJA’s siting provisions by improving the financial incentives for developers to build transmission. The Inflation Reduction Act’s Transmission Facility Financing program provided $2 billion in direct federal loans to build or upgrade transmission lines in national interest corridors, but Congress rescinded its unobligated funds in the One Big Beautiful Bill Act of 2025.[lix] Because BAAJA replaces corridor designations with a DOE congestion study, a revived program tied to the areas that study identifies could lower financing costs for those lines and give developers a stronger reason to advance them.[lx]
The cost-allocation framework aims to give investors confidence in cost recovery while protecting customers from the cost of lines that do not benefit them. Its emphasis on reliability and cost savings reflects a political bargain: states have resisted paying for lines built to serve other states’ clean energy policies. Rather than excluding such benefits outright, the bill narrows them through its definitions, counting access to new generation only when it lowers delivered-power costs and requiring every line to demonstrate a material reliability improvement. That threshold could disadvantage lines whose value lies chiefly in congestion relief or cost savings. Measurement presents a further challenge: resilience, optionality, and value under future system conditions are difficult to quantify and assign to particular customers. The bill partly anticipates this by defining improved reliability to include reduced loss-of-load probability and correlated outage risk. However, FERC guidance establishing standard methods for valuing extreme-weather and long-horizon benefits would help ensure that projects with real but diffuse benefits are not undervalued.
The advanced transmission technology mandate responds to a structural incentive problem: utilities earn a return on capital, so they have little reason to choose lower-cost options that expand capacity without new construction. These technologies can add capacity on existing rights-of-way far faster than new lines. The prudence presumption, however, cuts the other way. It applies to these technologies’ costs generally, not only to deployments that pass a benefit-cost test, and the highest-performing conductor is not necessarily the least-cost option. The requirement that utilities demonstrate “due care to minimize” costs offers some protection, but the presumption could make it harder for consumer advocates to challenge expensive choices.
Taken together, the transmission provisions create the authority and incentives to build more interregional transmission, but they do not guarantee it. Their effect will hinge on implementation: whether FERC and the planning regions produce credible plans, whether developers use the backstop, and whether FERC has the staff and analytical capacity to adjudicate contested benefit calculations at a scale it has not previously handled.
Section 2107 applies new cost-allocation requirements to large computational loads, including data centers, AI facilities, cloud computing, and cryptocurrency mining, in two layers. First, FERC must revise its 1994 transmission pricing policy within 270 days and then complete a rulemaking requiring utilities to charge these loads both embedded and incremental transmission costs, crediting the incremental payments against the utility’s revenue requirement to prevent double recovery. Loads accepting non-firm (interruptible) service would receive a lower rate.
Second, a new Federal Power Act Section 228 establishes a “ratepayer protection floor” for loads of 20 MW or more, counted across commonly owned sites and phased projects so that loads cannot be split to stay below the threshold: no portion of the incremental cost of serving them, including generation, storage, transmission, and distribution, may be recovered from other customers. Covered loads must post financial assurances before facilities are built and remain liable for unrecovered costs if they exit early. States may also charge covered loads above cost and credit the surplus to other customers, allocate service through announced application windows, and require loads to bring their own generation or accept limited service.
The central question that Section 2107 on ratepayer protection addresses is whether households and small businesses end up paying for the generation and grid buildout needed to exclusively serve large loads. The bill makes clear that utilities cannot build assets for a data center and pass on the associated costs to other customers. If the data center leaves the grid early, it would still need to pay those costs. These rules could address the stranded-asset risk that regulators worry about, particularly where load forecasts are uncertain.
Whether they translate into lower bills for other customers depends on several factors. First, the floor covers only costs incurred by the utility serving the load. In restructured markets such as PJM, a principal way data centers raise household bills is through higher wholesale capacity and energy prices, which the floor does not address and which would be left to states and market operators. Second, the floor applies only to loads that interconnect after enactment. Existing data centers and arrangements approved before enactment fall outside its scope, which may prompt a rush to secure approvals while the bill is pending. The new transmission pricing, by contrast, applies regardless of when a load connects, but could take up to two and a half years to finalize. Third, incremental cost is a one-time estimate made when the load comes online. Regulators must approve that estimate, but cost overruns after that point could still fall on other ratepayers.
Moreover, while these changes can go a long way toward assuaging concerns about cross-subsidization, policymakers will also need to strike a careful balance between ensuring that large loads pay their fair share of network costs and not charging them so much that they push more data centers off the grid. That said, recent experience suggests that speed to power, more than price, drives these decisions. Faster interconnection, in addition to community acceptance, may therefore matter more than cost allocation in determining where this load is served.
Finally, Section 228 raises a jurisdictional question: who decides which large loads gain access to the transmission grid, and on what terms? In most respects, the section confirms powers that states already have. State utility commissions already approve special tariffs for large customers that include collateral requirements, exit fees, interruptible service, and requirements to procure generation, and in vertically integrated states data centers are served as ordinary retail customers of the local utility. In three respects, however, the section goes further than current law:
This approach diverges from the direction of recent federal action. DOE’s October 2025 advance notice of proposed rulemaking proposed that FERC assert jurisdiction over connecting large loads to the transmission system.[lxi] FERC’s June 2026 show-cause orders to all six grid operators then pressed for rules that apply to all large loads regardless of type.[lxii] While the bill and the federal process agree on several aspects, Section 228 departs from the federal approach in two ways: it gives states a role in controlling access, and it applies only to data centers, expressly permitting them to be treated less favorably than other large customers. Enacting it could narrow FERC’s options as it develops region-wide procedures for connecting large loads to the transmission system.
The bill states that it confirms rather than creates state authority, and courts may rely on that statement to limit the “notwithstanding” clause to traditional retail matters. Until courts resolve the question, the line between state retail authority and federal open access will remain unsettled, creating legal uncertainty for data center developers and the grid operators planning to serve them. In vertically integrated states outside organized markets, where state control over retail service is already the norm, the change would be modest.
Several of BAAJA’s less prominent provisions address a problem that underlies many of its larger reforms: the data needed to plan the grid, study interconnection requests, and manage federal reviews is often incomplete, inconsistent, or inaccessible.
The first concerns data center demand. Section 2114 would require the Energy Information Administration to revise its annual utility survey (Form 861) to report electricity consumption by data centers, including facilities used for AI training and inference, cloud computing, and cryptocurrency mining, beginning with the first reporting cycle after enactment. No consistent federal data on data center electricity use currently exists, which makes it harder for utilities, regulators, and policymakers to forecast load growth and plan the investments needed to serve it.
The second concerns the data used in interconnection studies. Section 2111 would require transmission providers to obtain, maintain, and use the grid data needed for generator and load interconnection studies. It would also require owners and operators of the bulk power system to provide requested data within 15 days and in usable formats, subject to confidentiality rules governing how data is shared but not permitting it to be withheld. Noncompliance would be treated as a reliability matter subject to civil penalties, and FERC would be mandated to act on complaints within 60 days. Within one year, FERC and DOE would have to publish a reference specification identifying the data categories, formats, and validation standards needed to fully automate interconnection studies. Together with Section 2110’s direction to FERC to promote the use of AI and automation in processing interconnection requests, these provisions are intended to lay the groundwork for faster, more standardized studies.
The third concerns data on federal permitting processes. Section 1121 would direct the Council on Environmental Quality to establish common data standards for environmental reviews and, where practicable, develop a unified interagency permitting system by December 1, 2028, built around a single digital portal hosted by the General Services Administration. Project sponsors would submit all required documentation through the portal, collaborate with agencies in real time, and track the status of their reviews. The portal would also track performance metrics, including review timelines before and after BAAJA’s enactment, and give Congress direct access to performance data. Separately, Section 1132 would create a public tracker for major projects that reports quarterly on whether agencies are meeting their schedules and whether delays stem from the agency or the project sponsor. Section 1133 would authorize $20 million annually through FY2033 for a fund to improve the performance of permitting agencies.
These provisions are among the least controversial in BAAJA, but the bill’s larger reforms depend on them. Consolidated planning, published interconnection locations, and automated studies all require accurate, interoperable data, and Section 2111 is the first statutory requirement that such data be provided on a deadline, backed by reliability penalties. The data specification would also arrive within one year, before regions file their consolidated planning processes.
Developers usually commit large sums only after receiving federal permits, but permit approvals have not always held. The Biden administration revoked the cross-border permit for the Keystone XL pipeline in 2021, citing inconsistency with U.S. climate goals. In December 2025, the Trump administration suspended work on five offshore wind projects, citing national security risks, but courts have since blocked these suspensions, finding that the government had not adequately justified them.[lxiii] Under current law, a permit holder in that position can argue that the agency acted arbitrarily. But damages are generally unavailable, and no statute limits the grounds on which a federal agency may reopen a permit it has issued.
BAAJA attempts to address both problems. Under Section 1401, an agency could not revoke, suspend, or amend any federal permit in effect on or after September 16, 2026. Nor could it take “any other action to interfere with or prevent” the construction or operation “at full capacity” of a project that holds all its federal approvals. The exceptions are limited to cases such as court orders, material breaches of the permit, fraud, requests from the project sponsor, or actions needed to prevent “specific, urgent, substantial, and proximate harm” to life, property, national security, or defense based on new information obtained since the permit was issued. In these cases, the agency would carry the burden of proving that an exception applies, and if it fails, the project’s sponsor would be entitled to have the permit reinstated, a bar on further interference without approval from the same judge, attorney fees, costs associated with the delay, and an additional payment equal to 25 to 50 percent of its costs to date.
BAAJA’s Section 1402 also attempts to address the problem of administrations disfavoring a whole category of projects. An applicant for one of dozens of listed energy and mining project types could sue over a denial or a delay of more than 60 days past a deadline caused by a pattern of disparate treatment. The bill defines such a pattern in part by reference to an empirically demonstrated, substantial, and persistent increase in denials or unreasonable delays compared with the five most recent calendar years of data for the relevant project category. Official statements and executive orders can serve as supporting evidence of a pattern, which must result from an intentional federal course of action. If the applicant succeeds, remedies include economic damages and an award of 50 to 100 percent of the project’s expected construction cost, which remains conditional upon the sponsor moving forward with the project. Developers would not be allowed to collect damages and abandon the project at the same time. These awards would be paid from the federal Judgment Fund, outside the regular appropriations process—creating a potential uncapped financial liability for the federal government.
Together, Sections 1401 and 1402 aim to reduce regulatory risk and encourage investment by making federal approvals more durable. Without these changes, recent federal interference with already permitted projects could deter future investment. Lenders and investors also price into contracts the chance that an approval will be reversed or stalled after capital is committed, so greater certainty should lower financing costs and therefore allow more projects to get off the ground. The protections are deliberately technology neutral. They respond most directly to recent federal actions against wind and solar, but they would also constrain a future administration seeking to reverse fossil fuel approvals.
The central question is how far permit durability should extend. Critics warn of “forever permits,” where one administration approves projects, including in sensitive areas, that the next administration could not revisit. Proponents counter that Congress could still reverse a permit by statute, and that permits issued unlawfully could still be challenged and set aside in court.
A related concern with Section 1401 is its broad scope, which extends beyond prohibiting formal revocation or suspension to include actions that “interfere with” construction or operation at full capacity. As Michael Gerrard notes, the language could generate disputes over whether generally applicable requirements governing air pollution, methane emissions, noise, or worker safety are permissible when they affect a covered facility’s operation.[lxiv] Although Congress may intend to protect specific project approvals without immunizing facilities from otherwise applicable law, Gerrard argues the text’s breadth could invite challenges to regulatory actions that project owners claim undermine their permits.
Revisions to Section 1401 could avoid overly broad interpretation by, for example, expressly preserving authority to enforce independent statutory requirements and generally applicable environmental, public health, and safety standards, while defining more clearly which targeted actions against a particular permitted project are prohibited.
Questions have also been raised about Section 1402’s disparate-treatment provision. This provision measures disparate treatment against the five most recent calendar years of data for the relevant project category. It does not specify, however, whether that window precedes the filing of the lawsuit or the onset of the alleged pattern. Under either reading, a claim against a future administration would largely be measured against the current administration’s approval rates, including for fossil fuel projects. Gerrard argues that an administration that shifted priorities and denied more such projects could therefore face disparate treatment claims.[lxv] The historical baseline could thus entrench past permitting patterns by making substantial departures from them evidence of discrimination, even when an administration invokes different policy priorities or new circumstances.
That possibility is not necessarily an unintended consequence. Section 1402 is specifically intended to prevent administrations from using permitting decisions to systematically favor some technologies and disadvantage others. From this perspective, constraining politically motivated reversals is part of the bill’s purpose, and some short-term friction when administrations change course may be an acceptable tradeoff for greater policy stability over time.[lxvi]
The question is whether the provision can distinguish deliberate obstruction of lawful projects from legitimate policy changes, such as those responding to changed economic circumstances. As drafted, BAAJA’s Section 1402 may struggle to do so.
The greatest risk lies in how the bill treats denials versus delays. Delay claims are tied to fixed deadlines, which offer an objective benchmark. By contrast, the bill never defines what makes a denial “improper.” In project categories with few decisions or no prior denials, such as emerging technologies, even one or two denials could show a ‘substantial increase’ in the share of permits denied for that project type and support a claim. The intent requirement may offer limited protection, as an applicant could argue that a deliberate policy shift was itself an intentional course of action that created the pattern.
Several clarifications could help draw the distinction between deliberate obstruction and legitimate policy change. The most direct solution would be to remove the denial provision and keep the delay provision. Courts can already overturn unlawful denials, so the denial provision adds little protection while creating most of the risk. If Congress keeps the denial provision, it could at a minimum define “improper” to cover only denials that violate the law. To make the comparison meaningful, Congress could require a minimum number of past decisions before the numbers can support a claim, since many listed technologies have few or none. It could also specify whether the five-year period runs backward from the lawsuit or from when the alleged pattern began.
Finally, the scale of the potential damages available to project sponsors under Section 1402 warrants consideration. Damages equal to 50–100 percent of expected construction costs could impose substantial liabilities on the federal government, even when the dispute concerns a denial or delay rather than the revocation of an existing permit, because awards would be payable from the Judgment Fund rather than through the regular appropriations process. Facing that risk, agencies may approve projects they would otherwise reject, potentially including projects they consider unsafe. Congress could tie awards more closely to a developer’s actual losses while keeping enough of a penalty to deter deliberate abuse.
These provisions address a legitimate problem: developers need confidence that lawful approvals will not be withdrawn arbitrarily after substantial investments are made. The challenge is to provide that confidence without inadvertently limiting legitimate environmental, health, safety, and other regulatory obligations or making future policy changes prohibitively expensive. More precise language governing generally applicable regulation, changed circumstances, the statistical baseline, and damages could better preserve the bill’s investment-certainty objective while reducing unintended constraints on future administrations.
Beyond its crosscutting reforms, BAAJA includes targeted provisions for mining, geothermal, hydropower, and oil and gas. Most of these provisions address specific legal gaps or duplicative federal requirements rather than restructuring how these resources are developed.
Under Section 2215, BAAJA addresses two longstanding constraints on domestic critical mineral development: the lack of a leasing framework for hardrock minerals on federally acquired lands and legal uncertainty surrounding the use of federal land for mining-related activities beyond extraction.
The first constraint stems from the treatment of federal lands under U.S. mining law. The Mining Law of 1872 established a framework for hardrock mining claims on federal lands retained from the original public domain.[lxvii] However, this framework does not extend to federally acquired lands—those purchased or otherwise obtained by the federal government. Leasing on these lands is governed by the Mineral Leasing Act for Acquired Lands of 1947, which does not provide an equivalent pathway for hardrock minerals.[lxviii] BAAJA would address this gap by incorporating provisions from the proposed Mineral Extraction for Renewable Industry and Critical Applications Act (MERICA), extending the leasing framework to hardrock minerals, including base metals, precious metals, and other industrial minerals. This would allow companies to seek authorization to explore and develop mineral deposits on qualifying federally acquired lands without automatically opening them to mining.
The second constraint stems from the Ninth Circuit’s 2022 Rosemont decision, which invalidated approval of an Arizona copper mine because the company had not established the right to place waste rock on adjacent federal land where it had not discovered valuable minerals. The ruling created uncertainty for modern mines, whose footprints extend well beyond the deposit to processing facilities and waste and tailings storage. Section 2215 would allow operators to locate as many mill sites as reasonably necessary on open federal land, whether or not it contains minerals, for activities within an approved plan of operations, restoring pre-Rosemont practice. Each additional site would carry an annual $400 fee, payable to the abandoned mine fund, and the provision would not apply to lands withdrawn from mining.
The bill puts geothermal permitting on par with oil and gas, drawing on the CLEAN, STEAM, HEATS, and GEO Acts. It would require annual lease sales and give the Department of the Interior 30 days to deem a drilling permit application complete and 30 more to act on it; remove activities listed in Section 390 of the Energy Policy Act of 2005, such as drilling on a recently used well pad, from the definition of a major federal action for both geothermal and oil and gas; establish a categorical exclusion for exploratory test wells, including for enhanced and closed-loop systems; and drop the federal drilling permit on non-federal surface land when the United States owns less than half of the geothermal estate and the operator holds a state permit.
The hydropower provisions are targeted rather than comprehensive. Mandatory conditions imposed under Federal Power Act Section 4(e) by agencies managing federal reservations, such as national forests, would have to be reasonably related to the project’s effects. Drawing on the FLOWS Act, the bill would end the requirement for FERC approval of routine maintenance, nonsubstantial alterations, and temporary operating changes caused by events outside a licensee’s control, such as extreme weather. Micro hydrokinetic projects of 5 MW or less, which generate power from waves, tides, currents, or free-flowing water, would receive an expedited licensing path; conventional small hydropower would not qualify. Separately, the bill directs FERC to report on market barriers to hydropower and pumped storage.
The bill does not create a new relicensing process, even though 281 licenses covering more than 13 GW of hydropower and pumped storage expire between 2020 and 2029.[lxix] Relief for relicensing would come mainly from the changes to Section 4(e) and CWA Section 401 as well as the general NEPA and ESA deadlines.
The oil and gas–specific provisions do not directly change leasing terms or LNG export approvals; instead, they target federal permits that duplicate state regulation, drilling in previously reviewed areas, and work on existing pipelines.
The resource-specific provisions are narrower than BAAJA’s cross-cutting reforms, and their effects will depend heavily on market conditions.
For mining, restoring pre-Rosemont practice and opening acquired lands to leasing would reduce legal uncertainty before a final investment decision. And by providing a clearer legal pathway to secure the land needed for a project’s full operational footprint, Section 2215 could also make it easier for projects to attract private capital. However, as discussed above, permitting is rarely the binding constraint on mineral supply: prices, demand, and processing capacity concentrated abroad matter as much, if not more.
For geothermal, the bill addresses a meaningful bottleneck in exploration review, as more than 90 percent of U.S. geothermal resources lie under federally managed land.[lxx] One study of 133 exploration projects found an average review time of 210 days, and more than a third of categorical exclusions still took over 100 days.[lxxi] DOE finds that permitting reform alone could double geothermal capacity by 2050.[lxxii] The impact is less federal review, as routine drilling activities and test wells are exempt from NEPA and oversight of wells on non-federal land shifts to state regulators. The bill’s transmission reforms, however, may matter just as much, as the best sites are often in rural areas with limited transmission. Fervo Energy, for example, has flagged transmission constraints as a risk to delivering the full output of its flagship Utah project.[lxxiii]
For oil and gas, the provisions chiefly remove duplicative federal permits and ease work on existing infrastructure. Their effect on production is likely to be modest, but the pipeline provisions could matter more in that domain.
Section 2211 addresses wells drilled from private land that extend underground into federal minerals. Today, even a small federal interest along a well’s path can require a full federal drilling permit on top of the state permit, and federal and Indian drilling permits averaged 283 days in FY2025.[lxxiv] The impact is less federal oversight of government-owned oil and gas. Some exempted wells would still extract federal minerals, but BLM would no longer review or condition how they are drilled; the state permit would govern instead. BLM opposed an earlier version in 2023 on these grounds. [lxxv] Under the waste minimization plan required under BLM’s 2024 methane rule, operators are required to submit a plan that covers venting, flaring, and leaks with the federal permit application.[lxxvi] Under BAAJA, exempted wells would not need one, although the Department of the Interior proposed rescinding the requirement anyway in June 2026.[lxxvii]
For routine drilling reforms, Section 390 of the Energy Policy Act of 2005 already allows BLM to forego full environmental review for routine activities, such as drilling in areas with recently drilled wells—but BLM must still determine whether each project qualifies and document the relevant basis. That step has mattered: BLM relied on Section 390 for nearly 6,100 drilling permits from 2006 to 2008, and the GAO found its use often did not comply with the law or BLM guidance.[lxxviii] Section 2229 would remove these activities from NEPA entirely, eliminating the determination step. Proponents view that step as redundant for activities in previously reviewed areas, but without it, misapplication of the categories would be harder to catch or challenge. Yet the NEPA litigation reforms in BAAJA may also have an unintended effect. Because Section 390 permits require no environmental document, they may fall outside the 150-day limitations period, leaving challenges under laws such as the ESA still subject to the general six-year statute of limitations.
Of all the reforms to oil and gas, the pipeline provisions could matter most. The exemptions for work on existing pipelines could ease regional bottlenecks by facilitating incremental capacity, particularly alongside FERC’s May 2026 proposal to more than double the cost limits for pipeline projects that can proceed under its blanket certificate program without a project-specific certificate.[lxxix] Together, the two actions would allow considerably more expansion of existing pipelines to proceed without either individual FERC approval or environmental review. Section 1102’s exclusion for actions “associated with” that work, however, omits Section 2102(b)’s geographic limits and could extend beyond existing corridors. Faster development of gathering lines could help producers in basins such as the Permian bring associated gas to market. Where gathering capacity lags production, local prices can fall sharply or turn negative, encouraging flaring, as discussed above. The extent of these benefits will depend on where new infrastructure is built and whether other market constraints persist.
[i] Greenline Insights and Center for Climate and Energy Solutions, Grid and Economic Impacts of Interconnection Queue Reform and Interregional Transmission Expansion (Greenline Insights, September 2026), https://www.greenlineinsights.com/interconnection-and-transmission-reform.
[ii] Emilia Chojkiewicz et al., “Accelerating Transmission Capacity Expansion by Using Advanced Conductors in Existing Right-of-Way,” Proceedings of the National Academy of Sciences 121, no. 40 (2024): e2411207121, https://doi.org/10.1073/pnas.2411207121.
[iii] Douglas J. Arent, Lawrence Heath, and Noah Kaufman, “Unlocking Transmission Efficiency through Grid Enhancement Solutions” (Center on Global Energy Policy, September 2026), https://www.energypolicy.columbia.edu/publications/unlocking-transmission-efficiency-through-grid-enhancement-solutions-2/.
[iv] Amit Mathrani, “The Marathon: Can Behind-the-Meter Data Center Power Solutions Endure the Decade in the US?,” RaboResearch, Rabobank, June 24, 2026, https://www.rabobank.com/knowledge/d011532274-the-marathon-can-behind-the-meter-data-center-power-solutions-endure-the-decade-in-the-us.
[v] Jeremie Eliahou Ontiveros et al., “US Grid Constraints: Towards 40GW+ of Behind-the-Meter Datacenter by 2028?,” SemiAnalysis, June 25, 2026, https://newsletter.semianalysis.com/p/us-grid-constraints-towards-40gw.
[vi] Jeffrey Rissman and Eric Gimon, “Behind-the-Meter Data Center Gas Plants Will Raise US Energy Bills,” Utility Dive, June 8, 2026, https://www.utilitydive.com/news/data-centers-raise-energy-bills-not-for-reason-you-think/822205/.
[vii] Ryan Wiser et al., Retail Electricity Price Trends and Drivers: Data Update—2026 Edition (Lawrence Berkeley National Laboratory and The Brattle Group, April 2026), https://emp.lbl.gov/sites/default/files/2026-03/Retail%20Price%20Trends_2026%20edition.pdf.
[viii] U.S. Energy Information Administration (EIA), “In 2025, U.S. Natural Gas Spot Prices Increased from 2024’s Record Low,” Today in Energy, January 9, 2026, https://www.eia.gov/todayinenergy/detail.php?id=66984.
[ix] EIA, “Henry Hub Natural Gas Spot Price (Dollars per Million Btu),” daily series, released October 15, 2026, https://www.eia.gov/dnav/ng/hist/rngwhhdD.htm.
[x] Oil Price API, “Eastern Gas South (Dominion South): Appalachia’s Gas Price,” October 4, 2026, https://www.oilpriceapi.com/learn/natural-gas/eastern-gas-south.
[xi] “New York Clears Key Hurdle for Williams’ Northeast Supply Enhancement Gas Pipeline,” S&P Global Energy, November 7, 2025, https://www.spglobal.com/energy/en/news-research/latest-news/electric-power/110725-new-york-clears-key-hurdle-for-williams-northeast-supply-enhancement-gas-pipeline; “US Northeast Transco Expansion, Constitution Pipeline Revivals in the Works, Williams Says,” S&P Global, May 29, 2025, https://www.spglobal.com/energy/en/news-research/latest-news/natural-gas/052925-us-northeast-transco-expansion-constitution-pipeline-revivals-in-the-works-williams-says.
[xii] National Petroleum Council, Reliable Energy: Delivering on the Promise of Gas-Electric Coordination (National Petroleum Council, December 3, 2025), https://www.energy.gov/sites/default/files/2025-12/NPC_gas-electric_report_2025-12-3.pdf.
[xiii] World Bank, Global Flaring and Methane Reduction Partnership, Global Gas Flaring Tracker Report (World Bank, June 2026), https://thedocs.worldbank.org/en/doc/b34e0c054bb3fe3695e70154c28eef3f-0400072026/original/Global-Gas-FlaringTracker-June-23-2026.pdf.
[xiv] EIA, “U.S. Natural Gas Consumption Set a Monthly and Yearly Record in 2025,” Today in Energy, March 18, 2026, https://www.eia.gov/todayinenergy/detail.php?id=67365; Genevieve Plant et al., “Inefficient and Unlit Natural Gas Flares Both Emit Large Quantities of Methane,” Science 377, no. 6614 (2022): 1566–71, https://doi.org/10.1126/science.abq0385.
[xv] World Bank, Global Gas Flaring Tracker Report.
[xvi] Energy Transfer LP, “Energy Transfer to Upsize Transwestern Pipeline’s Desert Southwest Expansion Project,” press release, December 18, 2025, https://ir.energytransfer.com/news-releases/news-release-details/energy-transfer-upsize-transwestern-pipelines-desert-southwest.
[xvii] Lutz Kilian, Michael D. Plante, and Alexander W. Richter, “How Times Have Changed: The Impact of the 2026 Iran War on the U.S. Economy,” Working Paper 2615 (Federal Reserve Bank of Dallas, June 2026), https://www.dallasfed.org/~/media/documents/research/papers/2026/wp2615.pdf.
[xviii] Jess Donald, “Winter Storm Uri 2021: The Economic Impact of the Storm,” Fiscal Notes, Texas Comptroller of Public Accounts, October 2021, https://comptroller.texas.gov/economy/fiscal-notes/archive/2021/oct/winter-storm-impact.php; Texas Department of State Health Services, February 2021 Winter Storm-Related Deaths – Texas (Texas DSHS, December 31, 2021), https://www.dshs.texas.gov/sites/default/files/news/updates/SMOC_FebWinterStorm_MortalitySurvReport_12-30-21.pdf.
[xix] Juan Ramon L. Senga et al., “Implications of Policy-Driven Transmission Expansion for Costs, Emissions and Reliability in the USA,” Nature Energy (2025), https://doi.org/10.1038/s41560-025-01921-7.
[xx] International Energy Agency (IEA), Global Critical Minerals Outlook 2026 (IEA, July 2026), https://www.iea.org/reports/global-critical-minerals-outlook-2026.
[xxi] Aidan Powers-Riggs, Brian Hart, and Matthew P. Funaiole, “The U.S.-China Trade Truce Has Not Solved the Gallium Problem,” Center for Strategic and International Studies, May 11, 2026, https://www.csis.org/analysis/us-china-trade-truce-has-not-solved-gallium-problem.
[xxii] IEA, Global Critical Minerals Outlook 2026.
[xxiii] Ibid.
[xxiv] Zeke Hausfather (@hausfath), post on X, September 30, 2026, https://x.com/hausfath/status/2105398276681785416.
[xxv] Jesse D. Jenkins et al., Electricity Transmission Is Key to Unlock the Full Potential of the Inflation Reduction Act (REPEAT Project, Princeton ZERO Lab, September 2022), https://repeatproject.org/docs/REPEAT_IRA_Transmission_2022-09-22.pdf.
[xxvi] U.S. Department of Energy, Hydrocarbons and Geothermal Energy Office, Liquefied Natural Gas (LNG) Exports (LNG Snapshot, September 2026), https://www.energy.gov/sites/default/files/2026-09/LNG%20Snapshot%20September%2030%202026.pdf.
[xxvii] Council on Environmental Quality, Environmental Impact Statement Timelines (2010–2024) (Executive Office of the President, January 13, 2025), https://nepa.gov/sites/default/files/documents/CEQ_EIS_Timeline_Report_2025-1-13.pdf.
[xxviii] Ibid.
[xxix] Crux, “New Survey: Federal Permitting Is Obstructing Clean Energy Projects (2026),” April 8, 2026, https://www.crux.com/blog/federal-permitting-clean-energy-projects.
[xxx] Seven County Infrastructure Coalition v. Eagle County, 605 U.S. 168 (2025).
[xxxi] 28 U.S.C. § 2401(a), https://www.law.cornell.edu/uscode/text/28/2401.
[xxxii] 23 U.S.C. § 139(l)(1), https://www.law.cornell.edu/uscode/text/23/139.
[xxxiii] Michael Bennon and Devon Wilson, “NEPA Litigation over Large Energy and Transport Infrastructure Projects,” Environmental Law Reporter 53 (2023): 10836, https://fsi.stanford.edu/publication/nepa-litigation-over-large-energy-and-transport-infrastructure-projects.
[xxxiv] Arthur G. Fraas et al., Taking Green Energy Projects to Court: NEPA Review and Court Challenges to Renewable Energy, Report 25-15 (Resources for the Future, August 2025), https://www.rff.org/publications/reports/taking-green-energy-projects-to-court-nepa-review-and-court-challenges-to-renewable-energy/.
[xxxv] Aspen Institute Energy and Environment Program, Building Cleaner, Faster (Aspen Institute, June 2021), https://www.aspeninstitute.org/publications/building-cleaner-faster-report/.
[xxxvi] Michael B. Gerrard, “Senate Bipartisan Permit Reform Bill Would Upend Many Environmental Laws,” New York Law Journal, October 14, 2026, https://www.law.com/newyorklawjournal/2026/10/14/senate-bipartisan-permit-reform-bill-would-upend-many-environmental-laws/.
[xxxvii] Section 404 permits could be vacated only where an activity poses an imminent and substantial danger; NHPA claims would be limited to the same remedies as NEPA claims, while ESA remedies, including vacatur of biological opinions and injunctions, would remain unchanged.
[xxxviii] U.S. Environmental Protection Agency (EPA), “Definition of ‘Waters of the United States’ under the Clean Water Act,” last updated November 12, 2025, https://www.epa.gov/cwa-404/definition-waters-united-states-under-clean-water-act.
[xxxix] Nick Snow, “New York State’s DEC Denies Water Permit for Constitution Pipeline,” Oil & Gas Journal, April 25, 2016, https://www.ogj.com/pipelines-transportation/article/17251276/new-york-states-dec-denies-water-permit-for-constitution-pipeline.
[xl] U.S. Congress, Senate, Committee on Energy and Natural Resources, Oil and Gas Pipeline Infrastructure and the Economic, Safety, Environmental, Permitting, Construction, and Maintenance Considerations Associated with That Infrastructure, hearing, 114th Cong., 2nd sess., June 14, 2016 (Washington, DC: U.S. Government Publishing Office, 2017), https://www.govinfo.gov/content/pkg/CHRG-114shrg21990/pdf/CHRG-114shrg21990.pdf.
[xli] U.S. Environmental Protection Agency (EPA), “Clean Water Act Section 401 Certification Rule,” Federal Register 85 (July 13, 2020): 42210–87, https://www.federalregister.gov/documents/2020/07/13/2020-12081/clean-water-act-section-401-certification-rule; EPA, “Clean Water Act Section 401 Water Quality Certification Improvement Rule,” Federal Register 88 (September 27, 2023): 66558–666, https://www.federalregister.gov/documents/2023/09/27/2023-20219/clean-water-act-section-401-water-quality-certification-improvement-rule; EPA, “Updating the Water Quality Certification Regulations,” proposed rule, Federal Register 91 (January 15, 2026): 2008–42, https://www.federalregister.gov/documents/2026/01/15/2026-00754/updating-the-water-quality-certification-regulations.
[xlii] U.S. Environmental Protection Agency, “Spruce No. 1 Surface Mine,” noting that EPA issued its final determination on January 13, 2011, after the U.S. Army Corps of Engineers had previously issued a permit, https://www.epa.gov/cwa-404/spruce-no-1-surface-mine.
[xliii] Advisory Council on Historic Preservation, Section 106 Review (ACHP, July 2025), https://www.achp.gov/sites/default/files/whitepapers/2025-07/2025_Section%20106_072225v2.pdf.
[xliv] Advisory Council on Historic Preservation, Native American Traditional Cultural Landscapes and the Section 106 Review Process: Questions and Answers (Washington, DC: Advisory Council on Historic Preservation), https://www.achp.gov/sites/default/files/guidance/2018-06/NativeAmericanTCLsintheSection106ReviewProcessQandAs.pdf.
[xlv] EPA, Economic Analysis for the Proposed Updating the Water Quality Certification Regulations (EPA, January 2026), https://www.epa.gov/system/files/documents/2026-01/cwa401_proposed-rule-economic-analysis_jan2026_508c.pdf.
[xlvi] Transource Pennsylvania, LLC v. DeFrank, No. 24-1045 (3d Cir. Sept. 5, 2025), https://law.justia.com/cases/federal/appellate-courts/ca3/24-1045/24-1045-2025-09-05.html.
[xlvii] Southeast Lighthouse Foundation, “As Block Island Wind Turbines Multiply from 5 to 599, Historic Preservation Group Files Federal Appeals,” press release, November 22, 2023, https://www.culturalheritagepartners.com/wp-content/uploads/2023/11/BlockIslandPressRelease.pdf.
[xlviii] Institute for Progress, “APE Explorer: Section 106 Review Scope,” dataset compiled July 2026, https://nhpa-ape-stats.org/.
[xlix] Rafe Petersen et al., “ACHP Proposes Sweeping Overhaul of Section 106 Tribal Consultation Regulations,” Holland & Knight Alert, July 28, 2026, https://www.hklaw.com/en/insights/publications/2026/07/achp-proposes-sweeping-overhaul-of-section-106.
[l] Federal Energy Regulatory Commission (FERC), “Building for the Future through Electric Regional Transmission Planning and Cost Allocation,” Order No. 1920, 89 Fed. Reg. 49280, 49306 n.287 (June 11, 2024), https://www.federalregister.gov/documents/2024/06/11/2024-10872/building-for-the-future-through-electric-regional-transmission-planning-and-cost-allocation#footnote-287-p49306.
[li] Avi Zevin et al., “Building a New Grid without New Legislation: A Path to Revitalizing Federal Transmission Authorities,” Ecology Law Quarterly 48 (2021): 169, https://www.ecologylawquarterly.org/wp-content/uploads/archive/2021/09/48.1_Zevin_Internet.pdf.
[lii] Joseph Rand et al., Queued Up: 2026 Edition, Characteristics of Power Plants Seeking Transmission Interconnection as of the End of 2025 (Lawrence Berkeley National Laboratory, June 2026), https://eta-publications.lbl.gov/sites/default/files/2026-06/queued_up_2026_edition.pdf.
[liii] Mathrani, “The Marathon.”
[liv] Laura V. Swett, “Chairman Swett’s Remarks on the Large Load Show Cause Orders, E-7 to E-12,” FERC open meeting, June 18, 2026, https://ferc.gov/news-events/news/chairman-swetts-remarks-large-load-show-cause-orders-e-7-e-12-june-18-2026-open.
[lv] Chirag Lala, “The Bipartisan Permitting Bill Gets Transmission Right,” Center for Public Enterprise, October 1, 2026, https://publicenterprise.org/the-bipartisan-permitting-bill-gets-transmission-right-2/.
[lvi] Tyler Norris, “Beyond FERC Order 2023: Considerations on Deep Interconnection Reform” (Duke University, 2023), DukeSpace, https://hdl.handle.net/10161/31260.
[lvii] Office of Senator Martin Heinrich, “Heinrich Introduces Legislation and Grid Initiative Aimed at Delivering Cheap, Reliable Power to Working Families and Businesses,” press release, July 18, 2026, https://www.heinrich.senate.gov/newsroom/press-releases/heinrich-introduces-legislation-and-grid-initiative-aimed-at-delivering-cheap-reliable-power-to-working-families-and-businesses.
[lviii] Lala, “The Bipartisan Permitting Bill Gets Transmission Right.”
[lix] Sabin Center for Climate Change Law and Environmental Defense Fund, “IRA Section 50151 – Transmission Facility Financing,” Inflation Reduction Act Tracker, last modified August 13, 2025, https://iratracker.org/programs/ira-section-50151-transmission-facility-financing/.
[lx] Lala, “The Bipartisan Permitting Bill Gets Transmission Right.”
[lxi] FERC, “Interconnection of Large Loads to the Interstate Transmission System,” Docket No. RM26-4-000, last updated July 22, 2026, https://www.ferc.gov/rm26-4.
[lxii] FERC, “Fact Sheet: FERC Takes Action to Supercharge America’s Grid for Efficiency, Reliability, and a Bold Energy Future,” June 18, 2026, https://www.ferc.gov/news-events/news/fact-sheet-ferc-takes-action-supercharge-americas-grid-efficiency-reliability-and.
[lxiii] U.S. Department of the Interior, “The Trump Administration Protects U.S. National Security by Pausing Offshore Wind Leases,” press release, December 22, 2025, https://www.doi.gov/pressreleases/trump-administration-protects-us-national-security-pausing-offshore-wind-leases.
[lxiv] Gerrard, “Senate Bipartisan Permit Reform Bill.”
[lxv] Ibid.
[lxvi] See Jason Bordoff, host, Columbia Energy Exchange (podcast), “Daniel Palken on the Bipartisan Senate Bill to Reform Energy Permitting,” Center on Global Energy Policy, October 13, 2026, https://www.energypolicy.columbia.edu/daniel-palken-on-the-bipartisan-senate-bill-to-reform-energy-permitting/.
[lxvii] Mining Law of 1872, Act of May 10, 1872, as amended through Pub. L. No. 103-66 (U.S. Government Publishing Office), https://www.govinfo.gov/app/details/COMPS-5337.
[lxviii] Mineral Leasing Act for Acquired Lands, 30 U.S.C. §§ 351–360, https://www.law.cornell.edu/uscode/text/30/chapter-7.
[lxix] National Hydropower Association, “13 GWs of Hydropower at Risk,” fact sheet, n.d., accessed October 16, 2026, https://hydro.org/wp-content/uploads/2021/07/NHA-Hydro-Relicensing-by-2030-Fact-Sheet.pdf.
[lxx] U.S. Department of the Interior, “Federal Agencies Move to Ease Development of Geothermal Energy and Increase Power Generation,” press release, December 18, 2008, https://www.doi.gov/sites/default/files/archive/news/archive/08_News_Releases/121808a.html.
[lxxi] Tobias Russell, “NEPA Delays in Geothermal Exploration and the Categorical Exclusion Myth: Evidence from 133 Bureau of Land Management Reviews,” Pacific Legal Foundation, August 18, 2026, https://pacificlegal.org/research/nepa-barrier-to-geothermal-exploration/.
[lxxii] U.S. Department of Energy (DOE), GeoVision: Harnessing the Heat Beneath Our Feet (DOE, 2019), https://www.energy.gov/hgeo/geothermal/geovision.
[lxxiii] Diana DiGangi, “Fervo Energy Faces Transmission Constraints in the West, Analysts Say,” Utility Dive, June 5, 2026, https://www.utilitydive.com/news/fervo-energy-geothermal-transmission-constraints/822141/.
[lxxiv] Bureau of Land Management, “Table 12: Time to Complete an Application for Permit to Drill (APD), Federal and Indian,” FY2014–FY2025, https://www.blm.gov/sites/default/files/docs/2026-04/Table%2012%20Time%20to%20Complete%20an%20Application%20for%20Permit%20to%20Drill%20APD%20Federal%20and%20Indian%20FY25.pdf.
[lxxv] Senate Committee on Energy and Natural Resources, Bureau of Land Management Mineral Spacing Act, S. Rep. No. 118-53 (2023), https://www.govinfo.gov/content/pkg/CRPT-118srpt53/html/CRPT-118srpt53.htm.
[lxxvi] Bureau of Land Management, “Waste Prevention, Production Subject to Royalties, and Resource Conservation,” Federal Register 89 (April 10, 2024): 25378–432, https://www.federalregister.gov/documents/2024/04/10/2024-06827/waste-prevention-production-subject-royalties-and-resource-conservation.
[lxxvii] Valkyrie Buffa, Malinda Morain, and Theresa M. Sauer, “Interior Proposes Major Revisions to Federal Oil and Gas Leasing and Waste Prevention Rules,” Beatty & Wozniak, June 23, 2026, https://www.bwenergylaw.com/blog/2026/06/interior-proposes-major-revisions-to-federal-oil-and-gas-leasing-and-waste-prevention-rules/.
[lxxviii] U.S. Government Accountability Office, Energy Policy Act of 2005: BLM’s Use of Section 390 Categorical Exclusions for Oil and Gas Development, GAO-11-941T (GAO, September 9, 2011), https://www.gao.gov/assets/gao-11-941t-highlights.pdf.
[lxxix] FERC, “Revisions to the Blanket Certificate Program,” Docket No. RM25-12-001, item C-1, May 21, 2026, https://www.ferc.gov/media/c-1-rm25-12-001.
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