Wind Stocks

Onshore wind is the lowest-cost dispatchable source of new electricity in many markets, while offshore wind underpins national net-zero plans across Europe and parts of the US and Asia. Demand is reinforced by CfD/AR rounds in the UK, multi-GW state procurements in the US Northeast, the EU REPowerEU package, and accelerating offshore targets in China. Corporate PPAs and load growth from electrification and data centres are adding incremental demand on top of policy-led volumes.

Turbine OEMs (Vestas, Siemens Gamesa, GE Vernova, Nordex, Goldwind, Ming Yang) manufacture and service wind turbines. Their economics are driven by order intake, turbine pricing, supply-chain costs, and warranty performance, with services providing recurring high-margin revenue. Developers and IPPs (Ørsted, EDPR, Iberdrola, NextEra, RWE) own and operate wind farms, earning returns from PPAs, CfDs, and merchant power. The two ends of the chain do not always move together — turbine pricing power can rise even as developer IRRs come under pressure.

Offshore wind faced a sharp cost reset from 2022 onwards driven by interest rates, steel and cable inflation, vessel availability, and grid-connection delays. Several large projects were cancelled or repriced, notably in the US Northeast and Taiwan. The UK AR5 round received zero offshore bids before strike prices were lifted in AR6/AR7. Onshore wind has been less exposed because of shorter project cycles, more diversified supply chains, and lower per-MW capex, though it has its own challenges including permitting and turbine quality issues at certain OEMs.

Key risks include turbine quality and warranty costs (a recurring source of pressure across multiple OEMs), interest-rate sensitivity for developers and infrastructure funds, policy risk (PTC/ITC repeal exposure, US offshore permitting delays), supply-chain bottlenecks (vessels, monopiles, HVDC cables), and execution risk on offshore projects where any delay can cascade through CfD/PPA terms. Chinese OEMs face limited Western market access; Western OEMs face Chinese price competition in non-Western markets.

Wind is highly rate-sensitive on the project side. Developers and IPPs rely on long-dated debt financing, so higher rates raise the cost of capital and compress project IRRs — particularly for offshore projects where long lead times and high capex amplify duration risk. Wind infrastructure funds (Greencoat UK Wind, TRIG, Greencoat Renewables) trade on dividend yields and have historically de-rated when long-end government bond yields rise. Turbine OEMs are less directly rate-exposed but suffer indirectly when developer demand softens.

Wind turbines installed on land. Onshore wind is the larger of the two wind segments by installed capacity globally and benefits from shorter project timelines, lower capex per MW, and broader geographic deployment than offshore. Modern onshore turbines have hub heights of 100–160m and rotor diameters of 130–170m, with unit ratings typically 4–7 MW.

Wind turbines installed at sea, either fixed-bottom (in shallower waters using monopile or jacket foundations) or floating (deeper water using semi-submersible or spar platforms). Offshore wind delivers higher and more consistent capacity factors than onshore (40–55%+) but requires significantly more capex, specialised installation vessels, and HVDC export cables for distant projects.

The ratio of actual electricity generated to maximum theoretical generation if a turbine ran at full output continuously. Modern onshore wind capacity factors are typically 30–45%; offshore wind 40–55%+. Capacity factor drives project economics and is a function of resource quality, turbine technology, and downtime.

A government revenue-stabilisation mechanism widely used in UK and European offshore wind. The developer is paid a fixed strike price per MWh; if the wholesale market price is lower the government pays the difference, and if higher the developer pays it back. CfDs underpin the bankability of large offshore wind projects and are awarded through competitive auctions (UK AR rounds).

The Production Tax Credit (PTC) and Investment Tax Credit (ITC) are the two principal US federal tax credits for renewable energy. The PTC pays a per-MWh credit over the first 10 years of operation; the ITC is a one-time percentage of capex. Wind projects historically used the PTC; many now choose between the two under the post-Inflation Reduction Act framework. Tax credits are commonly monetised via tax-equity or transferability.

A long-term contract (typically 10–25 years) between a solar project owner and an offtaker (utility, corporate, or government), fixing the price and volume of electricity to be delivered. PPAs provide the contracted revenue stream that enables non-recourse project financing. Solar PPA prices have moved up from $40–60/MWh at the start of the cycle to $50–70/MWh today across major US markets, still well below other generation technologies. Variants include physical PPAs (electricity is physically delivered), virtual PPAs (financial swap with no physical delivery), and tolling agreements (offtaker pays a capacity fee and controls dispatch).

The sale by a developer of a partial stake (typically 25–50%) in an operational or under-construction wind farm to a financial investor (pension fund, infrastructure fund, sovereign wealth). Farm-downs recycle capital, validate project value, and reduce balance-sheet risk. They are a core lever for capital-light growth among offshore wind developers like Ørsted and EDPR.

High-Voltage Direct Current transmission. The dominant technology for connecting large or distant offshore wind farms to onshore grids, replacing earlier HVAC connections at distances above ~80–100 km. HVDC export cables and converter stations are supplied by Prysmian, NKT, Nexans, Hitachi Energy, Siemens Energy, and GE Vernova among others — the supply chain is a structural bottleneck for offshore wind build-out.

The dominant fixed-bottom foundation type for offshore wind in shallow-to-intermediate water depths. A single large-diameter steel tube (typically 8–12m diameter, weighing 2,000–3,000+ tonnes) is driven or vibrated into the seabed. Major suppliers include Sif Holding, Steelwind Nordenham, EEW Group, and Haizea Wind. Foundation diameters have grown rapidly with turbine size — XXL monopiles are now standard for new projects.

A specialised offshore installation vessel that lowers legs to the seabed and elevates the hull above the waves to provide a stable platform for installing offshore wind turbines and foundations. Modern next-generation jack-ups (e.g. Cadeler's A-class, Eneti's NG-series) are sized for 15+ MW turbines. The fleet is structurally tight relative to the global offshore wind pipeline.

A wind turbine architecture that omits the gearbox by using a permanent-magnet generator coupled directly to the rotor at low speed. Direct-drive eliminates a key historical failure mode but requires more rare-earth magnets and is heavier per MW. Goldwind has built its market position on direct-drive; Siemens Gamesa (offshore) and Enercon are also long-standing direct-drive proponents.

For wind turbine OEMs, the firm and unconditional contracted equipment backlog plus signed service contracts. Order intake (new orders signed in a period) is the leading indicator of revenue 12–24 months ahead. Pricing per MW within the order book is a key driver of forward gross margin and is closely tracked by analysts following Vestas, Nordex, Siemens Energy, GE Vernova, and the Chinese OEMs.

The average cost per unit of electricity (typically expressed in $/MWh) generated over a power plant's lifetime, accounting for capital costs, operating costs, fuel, financing costs, and capacity utilisation. LCOE is the standard tool for comparing the economics of different generation technologies. Unsubsidised utility-scale solar LCOEs sit at $50–70/MWh in the US and below $30/MWh in the highest-irradiance regions, against $80–100/MWh for new-build combined-cycle gas turbines, making solar the cheapest source of new electricity in most major markets.