United States Wind Energy Market Size & Share Analysis - Growth Trends And Forecast (2025 - 2030)

United States Wind Energy Market Trends and Insights

IRA Tax Credits and PTC Extensions

The IRA’s 10-year extension of production tax credits through 2032, plus a 10-percentage-point domestic-content adder, lifted post-tax project returns from 6.5% to 8.2%. Announcements for 18 GW of new capacity entered development pipelines during 2024 after the legislation was passed.^{[1]U.S. Department of the Treasury, “IRA Clean Energy Guidance,” treasury.gov} The law mandates that, by 2025, 40% of steel and 55% of manufactured components originate domestically, steering orders toward Iowa and Colorado factories. Internal Revenue Service audits in late 2024 disqualified 1.2 GW for foreign-origin bearings, spotlighting traceability gaps. Developers in ERCOT now opt for the IRA’s 30% investment tax credit to monetize value upfront when volatile basis risk deters long-term PPAs.

Falling LCOE from Taller Turbines

National Renewable Energy Laboratory data show the onshore LCOE sliding to USD 26 per MWh in 2024 as rotor diameters hit 170 m and hub heights 110 m.^{[2]National Renewable Energy Laboratory, “Cost and Performance Impacts of Taller Turbines,” nrel.gov} GE Vernova and Vestas platforms above 6 MW are harvesting 52% capacity factors at Class 4 sites in Arkansas and Tennessee, regions once uneconomical for wind. Thermoplastic composite blades reduce weight by 12% and cut balance-of-system spending by USD 80,000 per turbine. Cost compression has pushed eight gigawatts of gas-fired generation into early retirement during 2024, a pivotal inflection for the United States wind energy market.

Corporate PPAs Momentum

Corporate PPAs hit 8.2 GW in 2024 as hyperscalers locked 15-year fixed prices to meet Scope 2 targets.^{[3]American Clean Power Association, “2024 Corporate PPA Tracker,” acp.org} Amazon Web Services signed 3.5 GW, including a 1 GW Texas portfolio powering data centers, while Meta secured 800 MW in Oklahoma. Virtual PPAs, now 72% of deals, let buyers claim renewable attributes without physical delivery across congested grids. Deals with investment-grade offtakers closed at USD 28–32 per MWh, versus USD 22 per MWh for merchant projects priced to manage basis risk.

Repowering Aging Fleet Unlocks Capacity

Roughly 25 GW commissioned before 2015 became eligible for repowering in 2024, allowing developers to triple output by swapping 1.5 MW machines for 6 MW units while retaining interconnection rights. NextEra upgraded 1.8 GW in Iowa and Texas, adding 2.4 TWh of annual generation without fresh permitting. Projects reset the 10-year PTC clock by replacing at least 80% of turbine components. Blade‐recycling constraints persist, but Siemens Gamesa’s chemical-recycling pilot recovers 85% of resins, hinting at long-term circular-economy gains.

Transmission and Interconnection Bottlenecks

Regional transmission queues reached 2,600 GW in December 2024, with wind accounting for 950 GW, and average study times stretched to 5.2 years.^{[4]Federal Energy Regulatory Commission, “2024 Interconnection Queue Assessment,” ferc.gov} MISO alone holds 180 GW awaiting USD 48 billion in network upgrades, 60% of which need new 345-kV lines that require seven years to permit. FERC Order 2023 moves to a first-ready, first-served regime, but only CAISO has fully implemented it by mid-2024, so most developers still face serial processing. Disputes over how to share USD 6 billion of transmission costs halted five projects last year.

Rising Capex and Supply-Chain Inflation

Onshore turbine prices rose 18% between 2022 and 2024, hitting USD 1.3 million per MW as steel and rare-earth costs spiked. Offshore capex climbed more sharply to USD 4,100 per kW because Jones Act-compliant vessel day-rates doubled to USD 450,000. OEMs suffered negative EBITDA on U.S. deliveries in 2024 after signing fixed-price contracts when inflation remained muted. Developers renegotiated PPAs upward by USD 4–6 per MWh to recover margins, illustrating the delicate economics underpinning the United States wind energy market.

Segment Analysis

By Location: Offshore’s Exponential Upswing

Onshore assets dominated 99.9% of cumulative capacity in 2024, reflecting decades of incremental build-out across Texas and the Great Plains, where Class 5–7 wind resources deliver 45–50% capacity factors. However, the Bureau of Ocean Energy Management has auctioned eight lease areas since 2022, setting the stage for a 50.2% CAGR in offshore capacity that will reshape the United States wind energy market. Vineyard Wind 1 began commercial operation in May 2024 with 13 MW turbines sustaining 60% capacity factors, demonstrating offshore competitiveness. The onshore build cycle continues in Texas and Oklahoma, which added 5 GW combined in 2024 because ERCOT’s merchant model still clears projects within 18 months.

Jones Act constraints limit offshore build-out to about 2 GW per year through 2026, yet project pipelines total 30 GW. Dominion Energy’s 2.6 GW Coastal Virginia venture secured the first U.S.-built installation vessel, but day-rates above USD 500,000 lift capex 12% versus European analogs. Repowering older onshore sites provides a parallel growth lever: NextEra’s 1.8 GW Iowa campaign tripled site output without new interconnection filings. Floating offshore concepts for California’s 25 GW resource remain in pre-commercial testing as mooring systems presently cost USD 1 million per MW, a hurdle unlikely to fall before 2028.

Note: Segment shares of all individual segments available upon report purchase

By Turbine Capacity: Rise of the 6 MW-Plus Class

Turbines in the 3–6 MW range supplied 62.5% of installed capacity in 2024, underpinning the latest generation of utility-scale projects and anchoring the current United States wind energy market size at ground-level economics. Above-6 MW machines featuring 170 m rotors and 110 m hubs are forecast to grow 10.8% CAGR as developers target Class 4 wind sites across the Southeast. GE Vernova’s 6.2 MW Cypress platform, deployed across 2.4 GW in 2024, cut LCOE USD 6 per MWh and secured PPAs below USD 30 per MWh, evidence of size-driven cost efficiency.

Sub-3 MW assets, once dominant in California and Iowa, have become prime repowering candidates. At least 25 GW installed before 2015 can triple output by upgrading to current platforms while recycling interconnection rights. Blade manufacturing capacity is a gating factor for above-6 MW scale-up, with only two U.S. plants capable of producing 85-m blades. Offshore projects will jump directly to 13-15 MW turbines after 2026, pushing monopile and jacket foundations over USD 8 million each. While risk-averse ERCOT developers stick to proven 3–6 MW machines, larger platforms are unavoidable for the next cost-down cycle in the United States wind energy market.

By Application: Utility Scale Versus C&I Disruption

Utility-scale projects delivered 98.6% of installed capacity in 2024 by leveraging economies of scale to achieve USD 26 per MWh LCOE. C&I behind-the-meter assets represented only 1.1% but are growing 9.4% CAGR as virtual PPAs let corporations hedge power costs independent of physical delivery. Hyperscalers such as Amazon, Meta, and Microsoft continue to dominate procurement, prioritizing multi-gigawatt portfolios that leverage grid-scale economics.

Community wind installations of under 20 MW account for just 0.3% of capacity, clustered in Minnesota and Iowa, where state credits help bridge higher per-MW capex. Industrial facilities with 10 MW plus loads in Texas and California increasingly see wind as an on-site option that shortens payback to under seven years with ITC support. Queue congestion is nudging developers toward distribution-level interconnections where local voltage allows capacity additions without the five-year studies that bedevil bulk-system projects. Collectively, these shifts signal an incremental but important diffusion of demand-side participation in the United States wind energy market.

Note: Segment shares of all individual segments available upon report purchase

Geography Analysis

Texas, Iowa, and Oklahoma supplied 52% of cumulative capacity in 2024, leveraging Class 5–7 wind resources and merchant-market structures that capture scarcity pricing spikes, such as the USD 9,000 per MWh realized in February 2024. The Great Plains corridor harbors 35% of the technical potential, yet it added just 18% of the 2024 capacity because SPP’s 40 GW queue backlog delays projects beyond 2027. Offshore wind along the Atlantic Coast is a rising force, with New York Bight and Massachusetts leases funneling 30 GW into the pipeline and Vineyard Wind 1 proving Atlantic performance with 60% capacity factors.

Turbine scaling to 170 m rotors unlocked Class 4 sites in Arkansas and Tennessee, where PPAs closed below USD 30 per MWh in 2024. California’s floating-wind ambition remains aspirational pending cost compression in mooring technology. In the Midwest, repowering across Iowa and Illinois is adding near-term volume, as legacy 1.5 MW machines receive 6 MW replacements that triple output without new land leases. Policy asymmetry further shapes deployment: Texas permits projects within 18 months, while New York’s Article 10 process can take four years, tilting investor capital offshore.

Washington and Oregon added only 400 MW in 2024 because Bonneville Power Administration’s hydropower-heavy grid diminishes wind’s marginal value during spring runoff. Wyoming and Montana hold significant untapped potential but must secure Bureau of Land Management approvals and interregional transmission to reach distant load centers. MISO’s USD 18 billion long-range plan aims to unlock 25 GW of Dakotas and Minnesota output by 2028, though cost allocation remains contested among member states.