Wind Energy Economics: Onshore vs. Offshore Project Finance

Introduction

Wind energy is the second-largest renewable generation technology globally after solar and a major source of deal flow for energy investment bankers. The economics of onshore and offshore wind differ so dramatically that they are, for analytical purposes, entirely separate asset classes with different capital structures, risk profiles, offtake mechanisms, and buyer universes. Onshore wind is a mature, cost-competitive technology that competes directly with solar and natural gas generation. Offshore wind is a capital-intensive infrastructure play with higher costs, longer development timelines, and greater execution risk, but it delivers superior capacity factors and access to coastal load centers where land-based renewables face siting constraints.

For energy bankers, understanding the distinction matters because the advisory work differs significantly. Onshore wind transactions resemble solar deals in structure and scale: tax equity placement, PPA advisory, portfolio M&A, and development platform sales. Offshore wind transactions are megaproject financings that involve government concessions, multi-billion-dollar construction budgets, sovereign-backed offtake, and complex joint venture structures among utilities, oil majors, and infrastructure funds.

Onshore wind is one of the most cost-competitive generation technologies in the world. NREL's 2024 Cost of Wind Energy Review places the land-based wind LCOE at approximately $38/MWh on an unsubsidized basis. After the Production Tax Credit (approximately $0.028/kWh inflation-adjusted for 2025), the effective LCOE drops to approximately $10-20/MWh, making subsidized onshore wind the cheapest source of new electricity generation in most US markets.

The installed cost for a modern onshore wind project ranges from $1.2-1.7 million per MW, depending on turbine size, location, terrain complexity, and interconnection costs. Modern turbines have grown dramatically: the average nameplate capacity for new US installations now exceeds 3 MW per turbine, with rotor diameters of 140-170 meters. Larger turbines capture more wind energy per unit of installed capacity, which has been the primary driver of LCOE improvement over the past decade.

Capacity factors for onshore wind range from 30-45%, depending on wind resource quality and turbine technology. The best onshore sites (the wind corridor from West Texas through the Great Plains states of Oklahoma, Kansas, Nebraska, Iowa, and the Dakotas) consistently achieve capacity factors above 40%. Lower-quality sites in the Eastern US or mountainous terrain may achieve only 28-35%.

Capacity Factor

The ratio of a generation asset's actual energy output over a period to its maximum theoretical output if operating at full nameplate capacity continuously. A 100 MW wind farm with a 40% capacity factor produces 350,400 MWh per year (100 MW x 8,760 hours x 40%). Capacity factor is the single most important operating metric for wind economics because it directly determines revenue per MW of installed capacity. Onshore wind capacity factors of 30-45% are significantly higher than solar (22-32%) but lower than offshore wind (50-60%) and dispatchable generation sources like natural gas (which can operate at 85-95% when economically dispatched).

Onshore wind projects are financed through the same capital structure as utility-scale solar: tax equity (monetizing the PTC over a 10-year period), sponsor equity, and back-leverage debt secured by contracted PPA cash flows. The PTC (rather than the ITC) is the dominant tax incentive for onshore wind because the per-kWh production credit generates more value than a 30% investment credit for projects with high capacity factors. The partnership flip structure remains the standard tax equity mechanism. PPA prices for onshore wind averaged $25-45/MWh in recent transactions, competitive with utility-scale solar but reflecting regional variation in wind resource quality.

The Development Pipeline and Policy Risk

The US onshore wind pipeline remains substantial, with over 130 GW of proposed capacity in interconnection queues. However, the One Big Beautiful Bill Act (July 2025) introduced significant policy risk: wind projects that begin construction after July 4, 2026, lose eligibility for clean energy tax credits if placed in service after December 31, 2027. This compressed timeline has created a rush to commence construction, accelerating deal activity in the near term but clouding the post-2027 investment outlook. Developers with shovel-ready projects are commanding premium valuations as strategic and financial buyers seek to deploy capital before the policy window narrows.

Offshore wind is fundamentally different from onshore wind in scale, cost, risk, and financing structure. A single offshore wind project typically involves $3-8 billion in capital expenditure, 7-12 years of development from lease auction to commercial operation, and a complex construction process that requires specialized installation vessels, subsea cable routing, and offshore substation construction.

The installed cost for fixed-bottom offshore wind ranges from $3.5-5.0 million per MW, roughly three to four times the cost of onshore wind. The Vineyard Wind 1 project (804 MW, off the coast of Massachusetts), the first commercial-scale US offshore wind project, cost approximately $4 billion, or roughly $5.0 million per MW. Sunrise Wind (924 MW, off New York) was budgeted at approximately $1.5 billion in initial estimates, though actual costs have increased substantially through development. Dominion Energy's Coastal Virginia Offshore Wind (CVOW) project (2,587 MW) has a projected LCOE of approximately $62/MWh per the company's February 2025 update (though this figure varies with REC value assumptions), with expected commercial operation in late 2026.

The capacity factor advantage is offshore wind's most compelling economic feature. Offshore projects achieve capacity factors of 50-60%, compared to 30-45% for onshore wind, because offshore wind resources are stronger, more consistent, and less turbulent. A 1 GW offshore wind project operating at a 55% capacity factor produces roughly 4,818 GWh per year, the same output that would require approximately 1.5 GW of onshore capacity at a 37% capacity factor. This higher output partially offsets the higher installed cost when measured on an LCOE basis.

Offshore Wind Financing Structures

Offshore wind projects are financed through large-scale project finance structures that differ from the tax equity model used for onshore wind and solar. The capital sources typically include:

The following table summarizes the key differences between onshore and offshore wind economics.

In Europe, the contract for difference (CfD) mechanism is the dominant offtake structure for offshore wind. Under a CfD, the government guarantees a "strike price" per MWh; if the wholesale market price falls below the strike price, the government pays the developer the difference, and if the market price exceeds the strike price, the developer pays back the excess. CfDs provide the revenue certainty needed to finance multi-billion-dollar offshore projects and have been the primary mechanism through which the UK, Netherlands, Germany, and Denmark have built their offshore wind fleets. The UK's CfD auction system has been particularly successful, driving strike prices down from over $150/MWh in early rounds to approximately $50-70/MWh in recent allocations.