The Natural Resources Defense Council projects that a full rollback of current federal clean energy policies under a second Trump administration would eliminate 540 gigawatts of planned renewable capacity – more than the entire existing U.S. wind and solar fleet combined – effectively halving the buildout that market forces and the Inflation Reduction Act would otherwise deliver by 2035.
How the 540 GW figure was derived and what it assumes
NRDC’s modeling, led by policy analysis director Amanda Levin, compares two trajectories: a reference case that extends today’s tax credits, permitting frameworks, and EPA regulations through the early 2030s, and a “rollback” case that zeroes out IRA Section 45X manufacturing credits, phases down 45Y/48E technology-neutral credits prematurely, reinstates restrictive NEPA interpretations, and relaxes power-sector emissions rules. The 540 GW gap represents the cumulative difference in wind, solar, and battery additions through 2035. That figure exceeds the roughly 350 GW of utility-scale wind and solar currently operating nationwide, according to EIA data through late 2024. The analysis assumes no compensating state-level action beyond existing renewable portfolio standards and no new congressional legislation – a deliberate “policy vacuum” stress test rather than a most-likely forecast.
Levin’s comment that “we lose more than half of everything that we expected to be able to build” reflects the compounding effect of simultaneous credit termination and regulatory reversal. The IRA’s production and investment tax credits currently cover 30% of project capital costs with domestic-content and labor adders that can push effective subsidies above 50%. Removing those credits raises levelized cost of energy for new wind and solar by an estimated $15-25/MWh based on NREL’s 2024 ATB assumptions – enough to push many projects below utility procurement thresholds in competitive markets. Permitting delays under a restored 2020-era NEPA regime would add 12-24 months to typical interconnection queues, further eroding project economics given escalating equipment and labor costs.
Interconnection queue dynamics amplify the policy signal
The 540 GW loss becomes more consequential when layered onto today’s interconnection backlog. As of mid-2024, the seven U.S. ISO/RTO queues held roughly 2,600 GW of active generation and storage requests – 95% of them zero-carbon – but historical completion rates hover near 20%. That points to a structural bottleneck where policy certainty is the primary filter converting speculative queue positions into financed projects. If federal credits disappear, developers will withdraw marginal queue positions en masse, collapsing the “option value” that currently sustains queue depth and transmission planning assumptions. By comparison, the 2022-2023 queue withdrawal spike followed only the threat of IRA repeal during debt-ceiling negotiations; a confirmed repeal would likely trigger a larger, irreversible exodus.
This dynamic also reshapes transmission planning. FERC Order 2023 and regional long-range transmission plans (LRTPs) in MISO, PJM, and SPP all assume continued renewable growth to justify new 345 kV and 765 kV corridors. If 540 GW of expected generation vanishes, the benefit-cost ratios for those lines deteriorate, potentially stranding ratepayers with underutilized assets or forcing planners to re-scope projects mid-cycle. That points to a feedback loop: fewer renewables weakens the transmission business case, which in turn raises interconnection costs for remaining projects, accelerating further attrition.
Who this affects
- Utility resource planners: Integrated resource plans filed in 2025-2026 must now model a bifurcated policy scenario – IRA extension vs. full repeal – because the 540 GW swing alters capacity expansion timing, storage procurement targets, and gas peaker retirement schedules by 5-10 years.
- Solar and wind developers: Projects in late-stage development (post-FEED, pre-FID) face binary go/no-go decisions; those without safe-harbor provisions or signed PPAs at fixed prices will likely pause capital commitments until the 2025 tax legislative outlook clarifies.
- Battery storage integrators: Standalone storage economics depend on renewable-driven price arbitrage and capacity credit rules tied to renewable penetration; a 50% renewable buildout reduction cuts the addressable market for 4-8 hour storage by roughly 30-40 GW through 2030, based on current hybrid attachment rates.
- Transmission owners and RTOs: LRTP cost allocations approved in 2024-2025 assume renewable load growth; if that growth stalls, FERC may face complaints to reopen cost-sharing formulas, creating regulatory uncertainty for $50-80 billion in planned high-voltage investment.
- Institutional investors in clean energy funds: Fund vintage 2024-2026 deployment targets calibrated to 30-40 GW/year renewable additions must be revised downward by 40-60% under the rollback case, compressing fee income and extending fund lifecycles.
What to watch next
- House Ways and Means markup of tax extenders (Q1 2025): The specific legislative vehicle – whether a standalone clean energy bill or attachment to must-pass appropriations – will signal whether a partial IRA preservation (e.g., manufacturing credits only) is politically viable.
- FERC Order 1920 compliance filings (due mid-2025): Regional transmission plans that fail to model a low-renewable sensitivity may face rehearing requests, creating a leading indicator of how planners internalize policy risk.
- Interconnection queue withdrawal rates in PJM and MISO (monthly through 2025): A sustained monthly withdrawal rate above 5% of active queue capacity would confirm developers are pricing in credit loss ahead of legislative action.
- State-level clean energy standard amendments (CA, NY, IL, NM legislative sessions): Any state that raises its 2030/2035 targets to compensate for federal retreat would partially offset the 540 GW gap, but only for in-state or import-constrained resources.
Bottom line
The 540 GW figure is not merely a capacity statistic – it quantifies the fragility of a decarbonization trajectory that remains policy-dependent at the margin. Even if only half the projected rollback materializes, the resulting 250-300 GW shortfall would delay U.S. power-sector net-zero timelines by a decade and shift billions in private capital toward gas-fired generation or overseas markets with stable incentives. The critical variable is not the election outcome alone, but whether Congress can muster 60 Senate votes to preserve the IRA’s core tax architecture before the 2025 reconciliation window closes.
Read the full report at Utility Dive
Note: facts and figures attributed above to Utility Dive reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
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