The United States’ renewable power capacity is forecast to expand from 414.5 GW in 2024 to approximately 1.06 TW by 2035, more than doubling over the period, despite federal policy shifts emphasizing energy security and domestic manufacturing over climate objectives, according to GlobalData analysis.
This growth trajectory relies primarily on state-level clean energy mandates, utility-integrated resource plans, and corporate power purchase agreements that create demand independent of federal initiatives, which are increasingly focused on firm generation capacity and fossil fuel infrastructure.
Solar installations are projected to increase from 231.4GW in 2024 to 737.8GW by 2035, while onshore wind capacity expands from approximately 156GW to 269GW over the same timeframe. These projections embed assumptions about sustained state policy support, continued corporate renewable procurement, and cost competitiveness that recent regulatory actions and tariff measures have placed under stress. The offshore wind sector faces particular uncertainty following the December 2025 suspension of five Atlantic coast projects and the elimination of federal leasing activity over national security concerns.
State Policy Framework and Federal Divergence
The renewable capacity forecast depends fundamentally on state renewable portfolio standards and clean electricity mandates, creating binding procurement requirements independent of federal policy direction. States including California, New York, and those in New England maintain aggressive decarbonization timelines requiring utilities to source specified percentages of electricity from zero-carbon resources by dates ranging from 2030 to 2050. These mandates generate guaranteed demand for renewable capacity regardless of federal administration priorities.
Texas, operating the nation’s largest isolated grid through ERCOT, lacks renewable mandates but hosts substantial wind and solar deployment driven by resource quality and wholesale market economics. The state’s 156GW total capacity includes significant renewable penetration that reflects cost competitiveness rather than policy requirements, demonstrating that multiple pathways exist for renewable growth beyond mandate-driven procurement.
Corporate power purchase agreements from technology companies, manufacturers, and data center operators constitute the second pillar supporting renewable expansion. These bilateral contracts provide revenue certainty, enabling project financing while meeting corporate sustainability commitments and hedging against electricity price volatility. The scale of corporate PPA activity, particularly from hyperscale data center developers, creates renewable demand that persists despite federal policy shifts.
Mohammed Ziauddin, GlobalData’s power analyst, characterizes renewable investment between 2025 and 2030 at approximately $442.2 billion, reflecting ongoing solar and wind development across regional markets. This capital deployment assumes continued access to project finance, stable input costs, and predictable regulatory frameworks that recent tariff implementations and offshore wind interventions have disrupted.
Offshore Wind Policy Disruption and Project Economics
Federal authorities ordered temporary construction halts at Empire Wind 1 off New York in April 2025 despite the project securing federal and state permits and entering the construction phase. Revolution Wind off Rhode Island and Connecticut faced a similar suspension in August 2025 before court decisions allowed work resumption. The Department of Transportation canceled $679 million in offshore wind port and logistics infrastructure funding that same month, eliminating federal support for supply chain investments required for sector scaling.
The Trump administration’s December 22, 2025, announcement suspending five offshore wind projects following federal leasing and approval halts over national security concerns places Vineyard Wind, Revolution Wind, Coastal Virginia Offshore Wind, Sunrise Wind, and Empire Wind on indefinite hold. This intervention affects projects at various development stages, from operating to under construction to permitted but not yet started, creating uncertainty extending beyond individual project economics to sector viability.
Offshore wind faces higher capital costs per megawatt than onshore wind or solar, requiring long-term revenue certainty through power purchase agreements and regulatory stability to achieve acceptable returns. The combination of construction suspensions, eliminated infrastructure funding, and leasing cessation increases developer risk premiums and potentially renders marginal projects uneconomic. Whether the offshore wind capacity embedded in GlobalData’s 2035 forecast materializes depends entirely on whether federal restrictions lift and timelines extend or whether Atlantic coast projects face permanent cancellation.
The national security framing for offshore restrictions remains analytically opaque without public disclosure of specific threats or vulnerabilities identified. Previous offshore wind opposition centered on visual impacts, marine ecosystem effects, and fishing industry conflicts rather than security considerations, raising questions about whether security justifications reflect substantive concerns or provide a legal basis for politically motivated project obstruction.
Tariff Impact on Component Costs and Project Timelines
Trade measures introduced in 2025 increased costs for solar modules, wind turbines, batteries, steel, aluminum, and copper through tariffs on imported components. These input cost increases affect project economics by raising capital requirements and reducing returns, forcing developers to renegotiate power purchase agreements, seek additional equity, or cancel projects that no longer meet return thresholds.
Solar module tariffs particularly affect project economics, given modules’ contribution to total system costs. While domestic manufacturing capacity has expanded, U.S. production cannot meet projected demand at prices competitive with imports, creating tension between protectionist industrial policy and renewable deployment objectives. The Inflation Reduction Act’s domestic content bonus credits attempt to offset tariff impacts by providing additional tax benefits for projects using American-made components, though whether these incentives fully compensate for cost increases depends on specific project configurations and tariff rates.
Wind turbine manufacturing similarly faces capacity constraints and cost pressures from steel and component tariffs. Domestic turbine production exists but relies on global supply chains for specialized components, including bearings, power electronics, and rare earth magnets used in direct-drive generators. Tariffs on these inputs increase manufacturing costs that turbine suppliers pass through to project developers, affecting overall project economics.
The cumulative effect of component cost increases has slowed project timelines, increased capital requirements, and contributed to delays and cancellations across development pipelines, according to GlobalData. Whether the $442.2 billion renewable investment projection through 2030 materializes in full depends on tariff policy evolution and whether domestic manufacturing capacity expands sufficiently to replace imports at competitive costs.
Natural Gas and Nuclear Capacity Trajectories
Natural gas capacity is projected to increase from 573.1GW in 2024 to approximately 620.9GW by 2035, reflecting continued investment in flexible generation providing grid reliability as renewable penetration increases. Combined-cycle gas plants offer dispatchable output complementing variable wind and solar generation, filling gaps when renewable production falls below demand. Simple-cycle peaking units provide rapid-response capacity during extreme demand events or supply disruptions.
The 47.8GW gas capacity addition over eleven years represents modest growth compared to renewable expansion, but addresses system needs that batteries cannot yet economically fulfill at the duration and scale required. Natural gas maintains advantages in energy density, fuel storage capability, and multi-day discharge duration that current battery technology cannot match. Whether long-duration energy storage technologies, including hydrogen, compressed air, or flow batteries, eventually displace gas peaking capacity depends on cost trajectories and performance validation occurring beyond the 2035 forecast horizon.
Nuclear capacity expanding from 97GW to 102GW reflects life extensions at existing plants plus limited new build, including small modular reactors. The 5GW increase appears conservative given announced SMR projects and potential additional life extensions, though nuclear development faces extended timelines and regulatory complexity that creates execution risk. Federal policy since 2025, emphasizing energy security and domestic fuel availability, favors nuclear, given its baseload characteristics and domestic fuel cycle, though whether this translates to accelerated deployment remains uncertain.
Ziauddin’s characterization of gas and nuclear investment, addressing capacity adequacy and long-term system needs alongside renewable growth frames these technologies as complementary rather than competitive. This portfolio approach recognizes that electricity systems require diverse generation types providing different services, with an optimal mix depending on cost, reliability, and emissions objectives that vary across jurisdictions and evolve over time.
Regional Market Differentiation and Development Patterns
Texas, California, and the Midwest markets drive solar deployment through distinct mechanisms. Texas relies on wholesale market economics within ERCOT, where solar’s zero marginal cost creates dispatch advantages and capacity value despite lacking firm capacity characteristics. California’s aggressive renewable mandates and distributed generation policies create procurement requirements exceeding market-driven deployment. Midwest development reflects improving solar economics as module costs decline and utility integrated resource plans incorporate solar to meet load growth and replace retiring coal capacity.
Onshore wind capacity additions concentrate in high-resource regions where state clean energy standards create procurement requirements. The Plains states from Texas through the Dakotas offer superior wind resources that justify transmission investments connecting remote generation to load centers. Eastern states with lower capacity factors pursue offshore wind to meet renewable targets, given limited suitable onshore sites, making offshore policy uncertainty particularly impactful for Northeast decarbonization pathways.
The geographic distribution of renewable development creates transmission planning challenges as generation concentrates in resource-rich regions distant from major load centers. Whether projected capacity additions can interconnect and deliver output to consumers depends on transmission investment keeping pace with generation deployment, an issue the United States shares with other jurisdictions experiencing rapid renewable growth.
Investment Certainty and Forecast Confidence
GlobalData’s 1.06TW renewable capacity forecast by 2035 represents a central case projection embedding assumptions about policy continuity, cost trajectories, and market conditions that recent developments have rendered more uncertain. The offshore wind suspensions, tariff implementations, and federal policy pivots away from renewable support create downside risks to capacity projections that rely on sustained investment momentum.
Conversely, corporate renewable procurement continues accelerating, driven by data center electricity demand growth that exceeds initial projections. Artificial intelligence workload expansion creates power requirements beyond what existing capacity can serve, potentially increasing renewable PPA volumes beyond historical trends. Whether AI-driven demand growth offsets policy headwinds depends on procurement timelines and whether corporate buyers maintain renewable preferences when facing supply constraints.
The $442.2 billion investment projection through 2030 requires capital markets to maintain access to renewable project finance at costs enabling acceptable returns. Rising interest rates in 2023-2024 increased financing costs across all infrastructure sectors, with renewable projects particularly sensitive given high upfront capital intensity and long payback periods. Whether financial conditions support projected investment levels depends on macroeconomic factors, including inflation, Federal Reserve policy, and investor risk appetite, that extend beyond renewable sector fundamentals.
