Author: Derek Michalski, Chief Editor.
Until now the Contract for Difference has been treated as settled policy furniture — the mechanism that turned offshore wind from a subsidy-hungry curiosity into Europe’s cheapest new form of power. That settled feeling ended in 2025. Auctions failed outright in Germany, Denmark and the Netherlands. The UK’s own CfD scheme came within one bad auction round of stalling its entire 2030 offshore target. And underneath the headlines, a quieter but more consequential fight has opened up over what a CfD should actually look like on the inside — which price it references, when it stops paying, and how much market risk it’s supposed to remove in the first place.
The debate is no longer academic. Under the EU’s revised Electricity Market Regulation, any member state offering state-backed price support to new renewable generation must do so through a two-way CfD, or an equivalent scheme with clawback, from 17 July 2027 — extending to 2029 for cross-border hybrid projects. In other words, Europe is about to make CfDs compulsory at exactly the moment several of its biggest markets have discovered how easy they are to get wrong. That collision is what’s really being argued about at every wind conference right now, and it’s worth separating out the distinct approaches on the table — because “redesign the CfD” means at least four different things depending on who’s talking.
Approach one: keep the mechanism, fix the price
The simplest argument is that nothing is wrong with CfDs as a concept — auctions just got mispriced against a cost base that had moved. The UK supplies the cleanest before-and-after case study anywhere in Europe. Its 2023 Allocation Round 5 capped offshore wind bids at £44/MWh (2012 prices) and attracted zero offshore projects, the first time that had happened since the scheme launched in 2014. KPMG’s Simon Virley called it “a major setback at a critical time” for the UK’s renewables ambitions. The government’s fix wasn’t structural — it simply raised the ceiling. By Allocation Round 7, results announced in January 2026, the offshore strike price cleared at roughly £90.91/MWh (2024 prices) for a record 8.4 GW, Europe’s largest single offshore procurement to date. Energy Secretary Ed Miliband framed the scheme’s purpose as “getting off the rollercoaster of fossil fuel markets” controlled by volatile gas exporters — the same policy logic as in 2014, just recalibrated to 2026 costs.
Oxford’s Smith School has argued the AR7 outcome is the first result in over a decade that “feels logical,” with offshore wind finally pricing in above onshore wind and solar rather than below it, reflecting the real cost difference between a technology built in the seabed 80 miles from shore and one bolted to a field. The lesson this approach draws is narrow but important: CfDs don’t need reinventing, they need administrators willing to move the price cap as fast as steel, financing and vessel costs move — something the scheme’s original designers didn’t build in as an automatic feature.
Approach two: replace the auction mechanism entirely
A second, more disruptive argument says the auction design itself — not just the price cap — was the problem, and some countries have concluded the honest fix is to scrap their existing model rather than patch it. Germany, Denmark and the Netherlands had all been running some version of negative bidding, where developers pay the state for the right to build rather than receiving a guaranteed price. It worked spectacularly while costs were falling — BP and TotalEnergies together pledged €12.6 billion for German seabed rights in 2023 — and then stopped working the moment costs stopped falling. Germany’s August 2025 auction for two North Sea sites drew no bids at all, an outcome German offshore wind body BWO called unprecedented. Economy Minister Katherina Reiche responded by acknowledging the sites themselves would need review, saying regulators “want to take a critical look at this”, and Berlin has since legislated to replace negative bidding with CfDs for the 2026 auction round, while trimming that round’s volume from a planned 6 GW down to 2.5–5 GW to make it more deliverable. BWO’s Stefan Thimm argued the sector needs “clear rules and fair investment conditions”, achievable through CfDs paired with power purchase agreements, plus longer 35-year operating licences and softer penalties for delayed launches.
Denmark had already reached the same conclusion after its own 2024 auction drew no bids, and is moving its next 3 GW of tenders to CfDs (its Bornholm Energy Island project, largely built for electricity exports rather than domestic supply, remains a special case still under review). The Netherlands followed suit after developers walked away from its 1 GW Nederwiek tender, and is legislating for CfDs from roughly mid-2027, bridging the gap with a €1 billion temporary subsidy programme to keep 2 GW of offshore construction moving in 2026. WindEurope has framed this as effectively the end of negative bidding as a viable European model, noting that most major markets — Belgium, France, Ireland, Italy, Lithuania, Poland, Romania, Spain and the UK — already run CfD-style auctions, leaving the negative-bidding holdouts as the outliers rather than the norm. This is a materially bigger step than approach one: it’s not recalibrating a number, it’s conceding an entire auction philosophy failed under real-world conditions.
Approach three: keep CfDs, redesign what’s inside them
The most technically dense fight is happening one level down, among the people who actually write CfD contract terms — and it’s the one least visible outside specialist policy circles, even though it will shape returns for every future project. The core disagreement is over the reference price: what market price a project’s payout is compared against. A contract that references a project’s own hourly output fully removes its price risk but also removes any incentive to site the project well or operate it flexibly, since revenue is guaranteed regardless of when the wind actually blows. A contract that references a broader market average over a month or a year preserves those incentives but reintroduces real risk for the generator. Cambridge economist David Newbery’s proposed “yardstick CfD” — a contract referencing a notional standard plant’s output rather than the actual project’s own generation — is designed explicitly to close this gap: he argues such a structure “does not over-pay for windy/sunny sites” while still allowing high leverage and low subsidy cost, because revenue certainty is preserved without dulling the signal to build in genuinely good locations.
A second, more contentious design fight is over what happens during negative prices. Since UK Allocation Round 4, CfD payments are suspended for renewable generators during sustained negative-price periods — originally justified as protecting the exchequer from paying subsidies for power nobody wants. Frontier Economics has warned this creates its own distortion: with revenue guaranteed the instant day-ahead prices touch zero, generators have an incentive to bid their output at zero rather than genuinely negative prices, shifting the same volatility problem into the intraday and balancing markets instead of resolving it. A 2026 academic study using unit-level data from Great Britain’s operating offshore fleet found the effect is real, not theoretical: CfD-backed turbines curtail output meaningfully less than pure merchant turbines during negative-price hours, distorting balancing-market outcomes precisely because the contract removes the incentive to respond to the price signal. France’s regulator CRE is running a live version of this same debate for solar, proposing to move the reference price from a technology-specific capture price to a flat baseload index and to cut compensation during negative-price windows — the same fix under discussion in the UK, arrived at independently.
Not everyone accepts that redesigning CfD internals is even worth doing at EU scale. Germany’s renewables association BEE has openly opposed Brussels’ plan to make two-way CfDs mandatory across the bloc, with president Simone Peter arguing that Germany’s own experience with a softer, one-way version under its Renewable Energies Act already showed “high implementation costs and market distortion” without the promised price benefits, and that the country should be allowed to keep its existing model rather than adopt Brussels’ preferred template. That’s a useful reminder that “redesign the CfD” doesn’t have one agreed direction — some very experienced renewables policy voices think the current EU-mandated design is itself the wrong redesign.
Approach four: reject incrementalism, redesign the market instead
The most radical position skips CfD tinkering altogether and argues the whole wholesale electricity market — the thing CfDs sit on top of — is what actually needs rebuilding. The UK tested this seriously. Its multi-year Review of Electricity Market Arrangements considered replacing Great Britain’s single national wholesale price with zonal pricing, splitting the market into regional price areas so that generation and demand signals would better reflect local grid constraints. Guy Newey, chief executive of the Energy Systems Catapult and one of the reform’s most consistent advocates, has been unambiguous about where he stands, writing that “I am strongly in favour of zonal” and describing what he sees as compelling evidence of benefit running into the tens of billions of pounds.
The government disagreed — or at least judged the transition risk too high. Its 2025 REMA conclusion retained a single national wholesale market and explicitly ruled out zonal pricing, opting instead for what it called an ambitious package of reforms to network charging and strategic siting within the existing national-pricing structure. That decision matters well beyond Britain, because it’s the clearest real-world test case of whether “fundamental redesign” should mean rebuilding the market structure beneath CfDs, or just building a better CfD on top of the market that already exists. Faced with the choice, the UK — Europe’s most CfD-experienced market — chose the latter.
So, does the model need a fundamental redesign?
The honest answer is that Europe is running all four approaches simultaneously, and that’s precisely why the debate feels unresolved at every conference this year. Prices are being recalibrated (UK). Entire auction mechanisms are being abandoned in favour of CfDs (Germany, Denmark, the Netherlands). CfD internals are being rewritten in ways that quietly matter more than any headline auction result (reference price design, negative-price clauses, the fight over mandatory EU adoption). And the most radical option — rebuilding the market itself — was seriously tested and, in the UK at least, rejected in favour of evolution over revolution.
What ties all four together is that none of them were optional. The EU’s July 2027 deadline means every member state still relying on negative bidding, fixed feed-in tariffs, or one-way market premiums has to redesign its support scheme regardless of whether it wants to — the only live question is how much further each government goes beyond the legal minimum. For an industry that spent a decade treating the CfD as finished business, 2026 has been the year that assumption quietly stopped being true.
