How are offshore wind projects priced in energy markets?

How are offshore wind projects priced in energy markets?

Offshore wind doesn’t earn money on “the average power price.” It earns what the project actually captures when it produces minus the frictions of curtailment, congestion and imbalance and plus any top-ups from support schemes and certificates. In other words, price is a function of where and when the energy clears, how the project is hedged, and which policy instruments apply. This guide breaks down the revenue stack, the risks that push realised prices away from baseload, and a practical way to model it.

What actually sets the price for offshore wind?

Two lenses matter:

• Cost lens (LCOE): useful for competitiveness and auction bids but not a selling price.

• Market lens (realised or “capture” price): the volume-weighted price the project receives, shaped by timing of output, grid conditions, and hedges.

Key drivers behind realised pricing:

• Resource and technology: wind regime, wake losses, turbine rating, availability profile (seasonality and maintenance).

• Grid and connection: offshore/onshore bottlenecks, constraint compensation rules, connection charges, outage risks.

• Market structure: day-ahead vs. intraday liquidity, balancing price spreads, price zone vs. system price differentials.

• Finance and risk: WACC expectations, indexation rules, inflation assumptions, availability guarantees, and supply-chain cost volatility.

The revenue stack: markets, support and attributes

Most offshore wind projects earn from several layers:

• Wholesale market sales

  • Day-ahead (DA): core offtake; nominations based on forecast.

  • Intraday (ID): repositioning as forecasts update; reduces imbalance risk.

  • Balancing market: settlement against actual vs. nominated output; potential costs or revenues.

• Support schemes

  • Contracts for Difference (CfDs): a strike price is guaranteed against a reference (e.g., DA). If reference < strike, project receives a top-up; if > strike, it pays back. Duration, indexation and reference definition matter.

  • Feed-in Premiums (FiPs): sliding or fixed premium on top of market price; policy design sets exposure.

• Corporate PPAs

  • As-generated vs. baseload: who takes profile risk?

  • Shaped structures: floors/caps, collars, or baseload swaps to smooth cash flows.

  • Tenor and credit: counterparty quality and length affect financing.

• Attributes & services

  • Guarantees of Origin (GOs)/RECs: separate, tradable environmental value; pricing varies by country, granularity (hourly/locational), and “additionality.”

  • Ancillary services / capacity markets (where accessible): emerging but market-dependent.

Think of the stack as: Capture price × output ± CfD/FiP/PPA deltas − imbalance & curtailment + GOs/ancillaries.

Capture price, cannibalisation and basis risk

Capture price is the project’s realised, volume-weighted price—often below baseload because offshore wind tends to generate during windy hours when many other wind assets do too.

• Price cannibalisation: high simultaneous wind output lowers market prices in those hours.

• Mitigations:

  • Geographic diversification and staggered commissioning.

  • Hybridisation (co-located storage or solar) to shift supply.

  • More interconnection and grid reinforcement over time.

• Basis risk: the gap between a project’s zonal price and a system/reference price used in hedges or support schemes.

  • EPADs (Electricity Price Area Differentials) and FTRs (Financial Transmission Rights) can hedge congestion/basis, where available.

• Curtailment & constraints: export limits, grid outages or system security can force volume cuts or zero-price hours. Know the local compensation rules.

Balancing and imbalance costs

Forecast errors create exposure when actual output deviates from nominations:

• Costs arise if buying back power at high balancing prices or selling excess at a discount.

• Mitigation: Better forecasting, tighter nomination windows, active intraday trading, portfolio aggregation, and (where possible) flexible offtake that absorbs deviations.

• Pricing in: Model an expected imbalance adder (€/MWh) by season and weather regime, not a single flat value.

Policy and auction design: why terms matter as much as price

Auction mechanics and grid policy move the needle:

• CfD auction dynamics: Strike price strategy reflects capex/opex, WACC, capture discount assumptions, indexation, and penalties for delays.

• Connection & compensation: Who pays for the offshore grid? Are there curtailment payments? What’s the queue regime?

• Local content and sustainability rules: They can raise costs or timelines, which then push required strike prices higher—unless offset by favorable indexation or duration.

Hedging toolkit for offshore wind cash flows

Projects rarely stay fully merchant or fully fixed:

• CfD + merchant sleeve: Guaranteed floor but retain upside or optionality on a sleeve.

• Corporate PPAs:

  • As-generated: counterparty takes profile; often lower fixed price.

  • Baseload swap: you pay/receive the difference between as-generated profile and a flat shape.

  • Collars/caps/floors: bound the risk while keeping some upside.

• Financial hedges: forwards/futures for outright price; EPADs/FTRs for congestion; options to cap downside.

• GO strategy: decide whether to sell spot, forward, or bundle with PPAs; consider premiums for hourly/locational matching (24/7 programs).

Outlook to 2030–2040: what may move prices next?

• System mix evolution: more wind + more storage should narrow extreme lows but won’t erase capture discounts entirely; storage and flexible demand reduce cannibalisation tails.

• Grid build-out: offshore hubs, meshed grids and interconnectors cut congestion spreads and curtailment frequency over time—supporting higher capture prices relative to baseload.

• Market design: 15-minute settlement improves balancing incentives; broader ancillary access for renewables adds revenue options; 24/7 certificates can increase GO value for time-matched supply.

• Procurement trends: growth in corporate PPAs (often with shaping/floor features) and hybrid wind-to-hydrogen offtake may diversify the revenue stack.

Takeaways for buyers, developers and investors

• Don’t price on baseload: model capture explicitly—by hour and season, then subtract realistic imbalance and basis effects.

• Terms beat headlines: CfD/PPA fine print (reference price, indexation, negative-price rules, curtailment comp) often matters more than a 1–2 €/MWh difference in a notional price.

• Hedge what you can see: use EPADs/FTRs where available; size collar/floor options to your DSCR needs; decide deliberately on GO monetisation (spot vs forward vs 24/7).

• Build for flexibility: better forecasting, intraday capability, hybrid/storage options, and diversified siting materially lift net realised value over the project life.

In conclusion, offshore wind is priced by when and where it sells power and by the contracts wrapped around it. Nail the capture price, understand the frictions (imbalance, basis, curtailment), and stack the right hedges and attributes. Do that, and your “price” becomes a bankable, durable cash flow rather than a hopeful average.