The American offshore wind industry spent 2023 learning a brutal lesson in contract math. Developers who bid projects at $80-90/MWh discovered they needed $140/MWh to make the numbers work. The result: Ørsted wrote off $4 billion, BP walked away from contracts, and state regulators watched their clean energy timelines collapse.
Now, eighteen months into the recovery, a different industry is emerging—one with realistic pricing, localized supply chains, and a clearer understanding of what it actually costs to build in American waters.
The Wreckage and What Survived
Operating capacity on the US Atlantic Coast remains almost negligible. Block Island's 30 MW demonstration project has run since 2016. Dominion's 12 MW Virginia pilot came online in 2024. Vineyard Wind's first phases began generating late last year, with 806 MW of eventual capacity still ramping up.
The contrast with Europe is stark. The UK, Germany, Denmark, and the Netherlands collectively operate over 30 GW of offshore wind, achieving capacity factors above 45% and availability rates exceeding 95%. China added 16 GW between 2020 and 2023 alone. The US Atlantic pipeline claims 40 GW of proposed capacity stretching from Massachusetts to North Carolina—but commercial operations remain a rounding error.
What happened in 2023 was a convergence of compounding failures. Supply chain disruptions pushed project costs 30-50% above contract prices. Interest rates doubled from 3% to 6% or higher. Steel, specialized cables, and installation vessels all saw price spikes simultaneously. Developers who had bid aggressively to win contracts found themselves locked into money-losing projects.
The Offshore Wind Capacity Gap
The Offshore Wind Capacity Gap. Source: Article data. The US has less than 1 GW operating while Europe and China have built tens of gigawatts.
The termination requests followed predictably. Ørsted, BP, and Equinor each sought to exit or renegotiate state contracts. SouthCoast Wind, Park City Wind, and Skipjack faced cancellation or fundamental restructuring.
The New Economics
The 2024-2025 procurement rounds tell the story of recalibration. New contracts cleared at prices 30-50% above 2022 levels—not because costs spiraled further, but because developers finally bid what projects actually cost.
Federal support reshapes the investment case. The Inflation Reduction Act provides both investment and production tax credits, with domestic content bonuses adding 10 percentage points for projects meeting US manufacturing requirements. According to EIA's Annual Energy Outlook 2025, the agency assumes offshore wind projects will claim the ITC, with domestic content qualification expected starting in 2032 for additional bonus value.
The underlying cost trajectory offers longer-term optimism. IRENA's 2024 assessment projects global offshore wind installed costs reaching approximately $2,316/kW over the next five years—still roughly triple solar PV's $388/kW, but reflecting continued learning-curve improvements. European experience shows lifetime costs declining 60% since 2010.
Interest Rate Shock to Project Economics
Interest Rate Shock to Project Economics. Source: Article data. Financing costs doubled, compounding supply chain inflation to push projects 30-50% over budget.
For context on the generation economics: EIA's 2025 levelized cost analysis shows natural gas combined-cycle, onshore wind, and solar PV all competing in similar ranges, with capacity factor variations of 37-51% for onshore wind and 25-33% for solar PV driving regional competitiveness. Offshore wind's 45%+ capacity factors at favorable Atlantic sites help justify the higher capital intensity—but only at contract prices that reflect actual construction costs.
The Vessel Bottleneck
The Jones Act constraint receives less attention than it deserves. Federal law requires US-flagged vessels for work in American waters. Currently, only one Jones Act-compliant wind turbine installation vessel operates—Dominion's Charybdis, which entered service in 2024 after repeated delays.
The implications ripple through every project timeline. European developers routinely deploy specialized jack-up vessels with decade-long operational track records. American projects must either use the limited domestic fleet or employ workarounds involving feeder barges from foreign vessels anchored outside US waters. Both approaches add cost and schedule risk.
Manufacturing localization follows a similar extended timeline. Blade, nacelle, and tower facilities under development in Virginia, New York, and Massachusetts will eventually serve regional projects. But near-term construction still relies heavily on European supply chains. The localization transition extends through the late 2020s.
Capital Cost Reality Check
Capital Cost Reality Check. Source: IRENA 2024. Offshore wind costs roughly 6x more per kW than solar—justifiable only with superior capacity factors at prime Atlantic sites.
Grid Integration: The Overlooked Challenge
Offshore wind shares onshore renewables' interconnection queue constraints while adding complications unique to marine transmission.
Points of interconnection require substantial onshore upgrades. Projects connecting to ISO-NE and NYISO face multi-year study processes before construction can begin. Cable routing through coastal zones triggers parallel federal and state permitting tracks—BOEM for cables crossing federal waters, state agencies for state waters and onshore segments.
Grid operators also worry about concentration risk. A 1,000 MW project connecting at a single point creates contingency events larger than most existing grid components. ISO-NE currently credits offshore wind at 25-35% of nameplate capacity, reflecting expected output during loss-of-load hours. NYISO applies similar factors. A 1,000 MW offshore project thus delivers 250-350 MW of capacity value—better than onshore wind, but far below dispatchable thermal generation.
The New England Renewable Energy Connect proposal would create coordinated offshore transmission, reducing duplicative cables and improving system integration. The concept makes engineering sense. Regional political agreement remains elusive.
Grid Operators Discount Offshore Wind Capacity
Grid Operators Discount Offshore Wind Capacity. Source: ISO-NE/NYISO. A 1,000 MW offshore project delivers only 250-350 MW of firm capacity value during peak demand hours.
What Comes Next
For developers, the lesson is clear: bid what projects cost, not what states want to hear. The survivors of 2023's wreckage are companies that can execute at realistic prices rather than those who won contracts they couldn't fulfill.
For utilities and their regulators, contract design matters more than headline prices. Inflation adjustment mechanisms, force majeure provisions, and realistic milestone schedules protect both parties from market shifts.
For transmission planners, coordinated offshore grids may prove more efficient than project-by-project connections. The question is whether regional coordination mechanisms can overcome the jurisdictional fragmentation that has stymied onshore transmission development for decades.
The realistic timeline now extends to 2030 and beyond for significant Atlantic Coast capacity additions. That's later than the industry projected in 2021, but more credible than targets that assumed costs would only decline. The industry that emerges will be smaller, more cautious, and—finally—built on economics that work.
About the Author
Dr. Sayonsom Chanda
Dr. Sayonsom Chanda is an electrical engineer and senior scientist with more than a decade of experience in developing AI, ML, and other advanced computing solutions for the electric utility industry in US and India. He is also an energy policy thinker and a published author with more than 20 papers and 1 book.
