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Offshore wind is usually more expensive than utility-scale solar and overlaps the cost of a new natural-gas combined-cycle plant. Lazard’s 2025 U.S. unsubsidized comparison puts offshore wind in the middle of a wide range because marine construction, financing and site conditions vary sharply.
Those figures are levelized costs of electricity (LCOE)—modeled lifetime generation costs—not the price on a household bill or a guarantee of what a project will bid into a wholesale market. The comparison becomes meaningful only when technology, geography, financing, fuel assumptions and system requirements are kept consistent.
The 2025 cost comparison at a glance
Lazard’s 2025 Levelized Cost of Energy analysis compares new U.S. generation without subsidies. Its ranges are shown below in dollars per megawatt-hour (MWh), with the equivalent cents per kilowatt-hour (kWh) in parentheses. Dividing dollars per MWh by 10 gives cents per kWh.
| Technology | Unsubsidized LCOE (2025 Lazard) | Approximate cents per kWh | What the range represents |
|---|---|---|---|
| Offshore wind | $70–$157/MWh | 7.0–15.7¢/kWh | New U.S. offshore projects with marine construction and grid-connection costs included in the modeled project cost |
| Utility-scale solar photovoltaic (PV) | $38–$78/MWh | 3.8–7.8¢/kWh | New U.S. utility solar plants, excluding subsidies |
| Natural-gas combined cycle (CCGT) | $48–$109/MWh | 4.8–10.9¢/kWh | New U.S. combined-cycle plants using Lazard’s stated fuel and financial assumptions |
On this like-for-like benchmark, offshore wind can be cheaper than a high-cost gas project, but its full range is above the full utility-solar range. Solar has the lowest low-end and midpoint economics in the table. Gas has a broad range because fuel, turbine and construction assumptions materially affect its lifetime cost.
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How much is offshore wind per kWh?
Using the Lazard range, a new offshore-wind project costs approximately 7.0 to 15.7 cents per kWh on an unsubsidized levelized basis. That is a modeled average over the project’s cost-recovery period, not a fixed tariff that every customer pays for each kilowatt-hour.
One named U.S. project example
Lazard reports an illustrative levelized cost of about $92/MWh for Dominion’s Coastal Virginia Offshore Wind (CVOW) project. In Lazard’s February 2025 discussion, the projected CVOW LCOE was $91/MWh in 2027 dollars, with commercial operation expected in the fourth quarter of 2026. The project-specific figure should not be treated as the national offshore-wind average: its value reflects that project’s design, contracts, financing and site.
What levelized cost of electricity actually measures
The U.S. Energy Information Administration (EIA) defines LCOE as the revenue required to build and operate a generator over a specified cost-recovery period. In practice, analysts convert the project’s lifetime costs and expected electricity production into one average cost per unit of energy.
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- Up-front construction and development spending.
- Financing costs and the return required by debt and equity investors.
- Operations, maintenance and administration.
- Fuel purchases for technologies that burn fuel, such as gas.
- Expected output, including the project’s assumed capacity factor and operating life.
LCOE is useful because it puts technologies with different cost structures on a common unit basis. It is not the same as a wholesale market bid, a retail electricity rate, or the total cost of supplying dependable power to a grid. A wind or solar plant can have a low operating cost after construction while still requiring transmission, balancing, storage or backup resources that are outside a simple LCOE comparison.
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Why offshore wind costs more than most solar projects
Offshore wind is built in a difficult industrial environment. The turbine, foundation and electrical equipment must be transported and installed at sea, often miles from shore, and the work depends on weather windows and specialized equipment.
Marine construction and balance of plant
- Foundations must be designed for seabed conditions, water depth, waves and extreme weather.
- Subsea export cables carry power to land and can require complex installation and protection.
- Offshore substations collect and transform electricity before export.
- Specialized installation vessels, ports and crews are limited and expensive.
- Inspection and repair require marine access, creating higher logistics and downtime costs than an onshore facility.
These costs are incurred before a project produces its first kilowatt-hour, so the financing rate and construction schedule have an outsized effect on LCOE. Delays can add interest during construction and may force a developer to renegotiate vessel, turbine or cable contracts.
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Utility-scale PV uses a mature, highly standardized supply chain. Panels, inverters, trackers and foundations are installed on land, and the plant has no fuel bill or rotating offshore machinery. Solar still needs land, interconnection and sometimes new transmission, but its construction and maintenance generally avoid the marine premium.
Solar output is variable: production follows daylight and weather. The low LCOE therefore does not mean solar alone provides the same timing or reliability service as a dispatchable generator. Storage, transmission, flexible demand or other resources may be needed, depending on the grid.
Why gas can be cheaper—or more expensive—than offshore wind
A combined-cycle gas plant burns fuel in a gas turbine and uses the exhaust heat to make additional electricity in a steam cycle. It is dispatchable, can be sited near existing infrastructure and usually connects to the grid through established land-based equipment. Those characteristics can lower construction and integration costs compared with a remote offshore project.
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Fuel-price exposure
Gas economics include a recurring fuel expense that wind and solar do not. Lazard used a $3.45 per million British thermal units (MMBtu) gas-fuel assumption for its year-over-year comparison. If gas prices rise, a gas plant’s operating cost and LCOE rise; if prices fall, they decline. The plant’s utilization also matters because fixed costs are spread over more or fewer megawatt-hours.
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Capital-cost and supply-chain uncertainty
Lazard noted that early-stage market quotes were pushing high-case combined-cycle capital costs upward. Turbine availability, construction inflation, permitting, emissions controls and financing can move a gas project toward the top of the $48–$109/MWh range. A gas plant also remains exposed to future carbon rules or environmental requirements, which may not be fully represented in a basic LCOE number.
New plant versus an existing gas station
Comparing a new offshore wind farm with an existing gas plant is not an apples-to-apples cost test. An operating gas plant may have a low short-run or marginal cost because its construction capital is already sunk; it mainly pays for fuel, operations and maintenance. Lazard’s gas range is for building a new combined-cycle plant, just as the wind and solar figures are for new projects.
Other published benchmarks and why they differ
Different studies answer different questions, so their numbers should not be mixed without checking geography, year, currency and assumptions.
| Source and scope | Offshore wind | Solar PV | How to interpret it |
|---|---|---|---|
| Lazard, 2025, U.S. unsubsidized new build | $70–$157/MWh | Utility solar: $38–$78/MWh | A U.S. project-cost range using common financial assumptions; not a retail rate |
| IRENA publication issued in 2026 using 2025 global data | $78/MWh global weighted average | $44/MWh global weighted average | Worldwide averages weighted by projects; not a forecast for a particular U.S. site |
| IEA calculator examples | $111.78/MWh for U.S. offshore wind, 600 MW | $44.25/MWh for U.S. utility solar PV, 100 MW | Specific calculator entries with stated capacity and assumptions, not universal prices |
The global IRENA figures are not directly interchangeable with Lazard’s U.S. ranges. Labor, ports, water depth, financing, exchange rates, permitting and supply chains differ by country. The IEA values likewise describe the selected calculator cases—a 600-MW offshore project and a 100-MW solar project—rather than every project of those technologies.
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Financial assumptions can change the ranking
Lazard’s chart assumes 60% debt at an 8% interest rate and 40% equity at a 12% cost unless otherwise indicated. Those rates are assumptions about the cost of capital, not rates every developer receives.
Offshore wind and solar are capital-intensive: most of their lifetime cost is committed before generation begins. A higher discount rate therefore increases their LCOE substantially. Gas also needs substantial construction capital, but a larger share of its lifetime cost is variable fuel and operating expense. Changing the debt/equity mix, interest rate, equity return or construction schedule can narrow or widen the apparent gap between technologies.
How site conditions move the number
There is no single offshore-wind price. A project in shallow water close to a strong port and an available transmission landing can be far cheaper than one in deep water far from shore.
- Wind resource: Higher and more consistent wind increases annual generation, spreading fixed costs over more MWh.
- Water depth and seabed: These determine foundation design and installation difficulty.
- Distance to shore and grid: Longer export cables, offshore substations and onshore upgrades add capital cost and electrical losses.
- Vessel and port access: Scarcity can raise installation prices and make weather delays more expensive.
- Local financing and taxes: Interest rates, tax treatment, labor costs and permitting timelines alter project economics.
- Solar resource: A sunnier site produces more energy from the same PV equipment, while land, tracking and interconnection constraints can offset that advantage.
- Gas infrastructure: Pipeline access, fuel basis differences, cooling-water needs and transmission proximity affect a plant’s delivered cost.
Why LCOE is not the full cost of reliable electricity
A grid operator must pay for more than energy production. A fair technology decision should examine the system costs and services that LCOE leaves out or treats incompletely.
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Offshore projects may need export cables, new coastal substations and inland transmission reinforcement. Solar plants in remote areas can also trigger major interconnection upgrades. A project’s LCOE can look attractive while the connection queue contains expensive network work assigned elsewhere.
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Variability, storage and balancing
Wind output changes with weather, and solar output follows the sun. The system may need batteries, pumped storage, demand response, flexible generation or geographic diversity to match production with demand. The required amount depends on the existing grid’s mix and load shape, so it cannot be inferred from a technology LCOE alone.
Capacity adequacy and reliability
Dispatchable gas can be scheduled when needed, while the capacity contribution credited to wind and solar depends on local resource patterns and the reliability standard. A comparison that values dependable capacity may produce a different result from an energy-only LCOE ranking.
Curtailment and congestion
When renewable output exceeds what the network can absorb, operators may curtail generation. Curtailment reduces the MWh over which fixed costs are recovered. Congestion can also separate a project’s modeled production from the value of electricity at the load center.
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Environmental and policy costs
The basic ranges do not automatically include every carbon price, health effect, environmental externality or tax credit. Adding those items changes the comparison and must be disclosed explicitly rather than assumed.
A practical way to compare a proposed project
- Set the boundary: Decide whether you are comparing unsubsidized new-build LCOE, a contract price, wholesale market value or an existing plant’s marginal operating cost.
- Normalize the units: Use the same currency year and convert all values to $/MWh or cents/kWh.
- Match the geography: Use project-specific wind, solar, fuel, labor, water-depth, port and grid assumptions.
- Check financing: Record debt share, interest rate, equity return, construction duration and tax treatment.
- Stress-test fuel and utilization: For gas, model several fuel prices and capacity factors rather than relying on one gas quote.
- Add system requirements: Estimate transmission, storage, balancing, curtailment and capacity needs outside the plant gate.
- Separate energy from reliability: Report the energy cost and the cost of dependable capacity or other grid services instead of hiding them in one blended figure.
- Run sensitivities: Show how the result changes if interest rates, construction costs, wind or solar output, cable distance or gas prices move.
Bottom line for households, policymakers and developers
For a new U.S. project evaluated without subsidies, offshore wind currently sits at roughly 7.0–15.7 cents per kWh in Lazard’s 2025 benchmark. Utility-scale solar is lower at about 3.8–7.8 cents per kWh, while new gas combined cycle spans about 4.8–10.9 cents per kWh under Lazard’s assumptions.
That ranking describes modeled generation cost, not the cost of a reliable delivered grid. Offshore wind can make sense where strong marine wind, limited land, coastal demand and transmission access justify its higher construction complexity. Solar tends to win on straightforward energy cost, and gas provides dispatchability but carries fuel-price and policy risk. The right choice depends on the project site and the value of the services the grid needs—not on a single LCOE number.
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