Day 3 of 815 minutes

Day 3: Revenue & Risk — CfDs and Merchant Exposure

Contracts for Difference, merchant exposure, and how renewable revenue is structured

Imagine you are a pension fund manager considering a £500 million investment in an offshore wind farm. The turbines will spin for thirty-five years. Over that time, they will generate electricity and sell it into the wholesale market — but that market is volatile, driven by gas prices, weather, demand spikes, and geopolitical shocks. In 2022, wholesale electricity prices in Britain more than doubled; by late 2024, they had fallen by nearly half. No rational investor commits half a billion pounds to a project whose revenue can swing that wildly from year to year. The question, then, is not whether the wind will blow — it is whether someone will guarantee the price.

That guarantee is the subject of today's module. On Day 1, we mapped the scale of the UK's investment gap and the public-private architecture being assembled to close it. On Day 2, we examined the National Wealth Fund as a catalyst for de-risking private capital. Today, we turn to the revenue side of the equation: the mechanism that converts wind and sunlight into predictable cash flows — and the emerging risk that sits at the far end of those contracts, waiting to be priced.

The Daily Brief (5 mins)

A Record Auction, and a Warning Beneath It

In January 2026, the Department for Energy Security and Net Zero published the results of Allocation Round 7 (AR7) — the largest single procurement of offshore wind in British and European history. A total of 8.4 GW of offshore wind capacity was awarded under the Contracts for Difference (CfD) scheme, unlocking an estimated £22 billion in private investment. One month later, in February 2026, a further 6.2 GW of onshore wind, solar, and tidal stream capacity was awarded across the non-offshore auction (AR7a), bringing the round's total to 14.7 GW across 201 projects. The Low Carbon Contracts Company (LCCC) — the government-owned body that acts as counterparty to every CfD — has now signed more than 200 contracts from this round alone.

These are headline numbers that signal renewed confidence after the turbulence of recent years. AR5 in 2023 attracted zero offshore wind bids because administrative strike prices were set too low. AR6 in 2024 recovered with 9.6 GW across all technologies after the government raised budgets and prices. AR7 has gone further, establishing a new benchmark for CfD-backed deployment.

But beneath the record capacity lies a structural question that will define the next decade of UK clean energy finance. CfD contracts now run for 20 years — extended from 15 years for wind and solar starting in AR7. Offshore wind turbines, however, have design lifespans of 25 to 40 years. That gap — the period after the contract expires but before the asset reaches end of life — is known as the merchant tail. During this period, the generator is fully exposed to wholesale electricity prices, with no guaranteed floor. As the first generation of CfD-backed projects approaches this threshold, how the market prices that tail risk will shape the cost of capital for every clean energy project that follows.

The Deep Dive (7 mins)

1. How Contracts for Difference Work

The CfD is the UK government's primary mechanism for supporting low-carbon electricity generation, and understanding its two-way structure is essential for grasping both its power and its limitations.

A CfD is a private law contract between a renewable electricity generator and the Low Carbon Contracts Company (LCCC), a government-owned company sponsored by DESNZ. The contract guarantees the generator a fixed price for each unit of electricity produced — the strike price — for the duration of the contract term. The mechanism works symmetrically. When the wholesale market price for electricity (the reference price) falls below the strike price, the LCCC pays the generator the difference. When the reference price rises above the strike price, the generator pays the difference back to the LCCC. Those payments flow through to consumers via the electricity supply levy.

This two-way structure is what distinguishes the UK model from one-sided subsidy schemes. During the energy crisis of 2021–2022, when wholesale gas prices drove electricity prices far above CfD strike prices, generators with CfDs were paying money back to the system — effectively shielding bill-payers from the full extent of the price spike. The CfD is not a subsidy in the conventional sense; it is a price stabilisation mechanism that eliminates revenue volatility in both directions.

Contracts are awarded through competitive auctions — the Allocation Rounds — administered by the National Energy System Operator (NESO) as the delivery body. Developers submit sealed bids indicating the minimum strike price at which their project is viable. Technologies compete within designated "Pots": Pot 1 for established technologies (solar, onshore wind), Pot 3 for fixed-bottom offshore wind, and Pot 4 for floating offshore wind. Competition drives strike prices down — the lowest credible bids win — which is why the cost of offshore wind has fallen so dramatically over the scheme's lifetime: from £119.89/MWh in the first Allocation Round (2015) to £91.20/MWh in AR7 (2026), in real terms a reduction that reflects both technology maturation and the CfD's success in de-risking capital.

The LCCC's role extends well beyond signing contracts. It manages generators through construction milestones, administers payments for the life of each contract, and provides DESNZ with operational intelligence on scheme performance. As of early 2026, over 10 GW of CfD-contracted renewable capacity is operational, with more than 40 GW in the pipeline. In the twelve months to October 2025, CfD projects generated enough electricity to power approximately 13 million homes — close to half the UK's housing stock.

2. AR5, AR6, AR7: A Cautionary Tale in Three Acts

The trajectory from AR5 to AR7 illustrates both the CfD scheme's resilience and its fragility when auction parameters are miscalibrated.

AR5 (2023) was, by any measure, a failure for offshore wind. The government set the administrative strike price — the ceiling above which no bid can be submitted — at just £44/MWh (2012 prices). This figure was based on a cost-reduction trajectory that assumed pre-2022 supply chain conditions. In reality, global inflation, rising interest rates, and steel and cable cost increases had pushed offshore wind development costs sharply upward. No offshore wind developer submitted a bid. The round secured 3.7 GW of capacity, entirely from solar and onshore wind — less than a third of the previous round's total. For the supply chain, the signal was devastating: the UK's pipeline had stalled.

AR6 (September 2024) was the correction. The incoming Labour government raised the auction budget to £1.55 billion — more than seven times AR5's budget — and increased the administrative strike price for fixed-bottom offshore wind to £73/MWh (2012 prices). The round awarded 9.6 GW across 131 projects, including nearly 5 GW of offshore wind capacity. It was the most successful CfD round to date, and it restored a measure of investor confidence that AR5 had badly damaged.

AR7 (January–February 2026) went further still. For the first time, offshore wind was run on a separate auction timeline from other technologies, allowing the government to accelerate critical offshore projects. The Secretary of State was granted a new power — the ability to view anonymised sealed bids before setting the final budget — which was used in AR7 to nearly double the offshore wind budget from £900 million to approximately £1.8 billion after bids were received. The result: 8.4 GW of offshore wind at a weighted average strike price of around £91/MWh (2024 prices), with RWE alone securing 6.9 GW across five projects. The concentration of so much capacity under a single developer has raised questions — the UK's offshore wind build-out is now materially tied to one company's investment programme — but the headline volume represents a genuine step-change.

One further reform deserves attention. From AR7 onwards, CfD contract terms for wind and solar were extended from 15 to 20 years. The government's rationale was explicit: a longer contract reduces the period of unhedged merchant exposure at the end of the asset's life, which in turn lowers the cost of capital, which in turn reduces the strike price that developers need to bid. Analysis by Equinor estimated that a 20-year CfD could reduce break-even strike prices by up to 10% compared to a 15-year contract, precisely because it shrinks the merchant tail.

3. The Merchant Tail — and Why It Matters

The extension to 20-year contracts is an acknowledgement, not a solution. The merchant tail remains.

Consider a typical offshore wind farm awarded a CfD in AR7. It begins generating electricity in, say, 2030. Its 20-year CfD expires in 2050. But the asset has a design life of 35 years, taking it to 2065. For those final 15 years, the generator has no guaranteed price. It sells electricity into the wholesale market at whatever price prevails on the day — a price that, as the 2020s have demonstrated, can be shaped by gas supply disruptions, geopolitical crises, weather events, and the pace of new capacity additions. This is merchant tail risk.

For project finance, the implications are significant. Lenders size their debt based on the certainty of future cash flows. A CfD provides that certainty during the contract period, enabling high leverage ratios and low debt costs. Once the CfD expires, revenue projections become probabilistic rather than contractual. Banks either discount the merchant tail heavily in their models — requiring more equity and lower gearing — or they refuse to lend against it altogether. As Norton Rose Fulbright has noted, a merchant tail introduces uncertainty during the final years of the loan life, as lenders are asked to take market risk on spot prices they cannot forecast.

The market is developing tools to manage this risk. Corporate Power Purchase Agreements (CPPAs) — long-term bilateral contracts between a generator and a corporate buyer — can provide a degree of price certainty beyond the CfD term. But CPPA market depth in the UK has not typically extended beyond 10- to 12-year tenors, well short of the 15-year merchant tail on a 20-year CfD. Some developers are exploring revenue stacking — layering multiple CPPAs with different start and end dates alongside the CfD — to create a composite revenue profile that extends further into the asset's life. Others are simply accepting that a portion of the asset's value will remain unhedged, pricing that risk into their equity return expectations.

The systemic question is whether the merchant tail becomes a drag on capital allocation. If investors routinely discount the final decade of an offshore wind farm's life to near-zero because they cannot model the revenue, then the effective investment horizon shortens — and the capital cost per megawatt-hour rises. This matters for the transition as a whole. The CCC's investment gap analysis (Day 1) assumed that private capital would cover 65–90% of transition investment. If merchant tail risk inflates the cost of that capital, the gap widens. The NWF's catalytic role (Day 2) may need to extend to providing tail-risk guarantees or credit enhancements specifically designed to bridge the post-CfD period — an instrument that does not yet exist in its toolkit but that the logic of the architecture demands.

4. The Interaction Between CfDs and NWF-Backed Finance

The CfD scheme and the NWF occupy complementary positions in the UK's green finance architecture, but their interaction creates both synergies and tensions worth understanding.

CfDs stabilise revenue. The NWF de-risks capital structure. Together, they enable projects that neither mechanism could support alone. The NWF's January 2026 Strategic Plan identifies offshore wind, grid infrastructure, and energy storage among its ten priority sectors — all of which rely on CfD-backed revenue streams to generate returns. When the NWF provides equity co-investment or guarantees to an offshore wind project, it is underwriting the capital side of a business model whose revenue side is already secured by the CfD. The two mechanisms are designed to stack.

But the AR5 debacle revealed a vulnerability. When auction parameters are set too conservatively, the CfD pipeline stalls — and with it, the projects into which the NWF intends to deploy capital. The NWF cannot crowd in private investment for offshore wind if there are no viable projects emerging from the auction process. This dependency runs the other way too: the CfD scheme's credibility rests partly on the existence of public capital institutions willing to absorb construction and technology risk. RWE's AR7 partnership with KKR — a global investment firm acquiring a 50% equity stake in the Norfolk Vanguard projects — illustrates the kind of blended capital structure the system is designed to produce: public revenue certainty (CfD) enabling private capital at scale.

AR8 is scheduled to open in July 2026. Its success will depend not only on strike prices and budgets but on the degree to which the broader architecture — NWF guarantees, grid connection reform, planning acceleration — operates as an integrated system rather than a set of isolated policy levers.

The Designer's Corner (3 mins)

Design Challenge: Visualising Revenue Certainty and Its Limits

The CfD creates a distinctive financial profile: a flat, predictable revenue line during the contract period, followed by an uncertain, volatile line thereafter. For product designers building financial modelling tools, portfolio dashboards, or investor-facing platforms, the core challenge is: how do you visualise a revenue cliff-edge without either understating the risk or making the entire investment look unviable?

Problem 1: The cliff-edge illusion. A standard revenue projection chart that shows a clean line at the strike price for 20 years and then drops to a volatile or blank line at year 21 creates a visual shock — a cliff-edge that can overwhelm the preceding two decades of certainty. In reality, the asset does not stop generating revenue when the CfD expires; it transitions from contracted to merchant pricing. The risk is not binary (revenue / no revenue) but probabilistic (guaranteed revenue / uncertain revenue). If your chart treats the post-CfD period as a void, users will systematically over-weight the tail risk relative to the contracted period. Design implication: Use confidence intervals or fan charts for the merchant tail period rather than a single line or an empty space. Show the range of possible wholesale price outcomes — high, base, and low scenarios — alongside the flat CfD strike price, so that users can compare the certainty regime with the uncertainty regime on the same visual plane. The temporal compression problem identified in Day 1's Designer's Corner applies directly here: a 35-year asset viewed on a quarterly dashboard will look like it has a very long stable period followed by a brief period of risk, when in fact the merchant tail may span 15 years.

Problem 2: Strike price legibility across rounds. CfD strike prices have historically been quoted in 2012 prices, making cross-round comparison genuinely difficult for non-specialist users. AR7 shifted to 2024 prices, but legacy data still uses the old base year. A dashboard that displays AR4's offshore wind strike price of £37.35/MWh alongside AR7's £91.20/MWh without adjusting for the base-year change will suggest a 144% cost increase, when the actual real-terms increase is substantially smaller. Design implication: Always normalise strike prices to a common base year before displaying them in any comparative view. Offer a toggle between nominal and real-terms pricing, and default to real terms. Label the base year prominently — a small "(2012 prices)" footnote is insufficient when users are making investment decisions from the numbers.

Problem 3: Auction narrative as context. The AR5-to-AR7 trajectory is not just a data series — it is a story about policy miscalibration, market correction, and institutional learning. A chart showing three rounds of capacity figures (3.7 GW → 9.6 GW → 14.7 GW) tells a growth story. A chart that also shows the zero offshore wind bids in AR5 tells a risk story. For users assessing whether to invest in the next round, the policy context matters as much as the numbers. Design implication: Consider annotated timelines that layer policy events (budget changes, strike price adjustments, contract term extensions) onto capacity and price data. This connects to the institutional literacy problem from Day 1: users need to understand that the CfD scheme's parameters are set by DESNZ, auctions are run by NESO, contracts are managed by LCCC, and the NWF may co-invest in the same projects. A platform that shows only the numbers, without the institutional context that produced them, leaves users unable to assess whether the next round will perform like AR6 or AR5.

Key Terms

Term	Definition
CfD (Contract for Difference)	A two-way contract between a renewable electricity generator and the LCCC. It guarantees a fixed strike price: when wholesale prices fall below the strike price, the generator receives a top-up; when they rise above, the generator pays back the difference.
Strike Price	The fixed price per megawatt-hour agreed in a CfD contract, set through competitive auction. It represents the price at which the generator can viably build and operate the project. Indexed to CPI over the contract term.
Merchant Tail Risk	The financial exposure a generator faces when its CfD contract expires but the asset continues operating. During this period, revenue depends entirely on volatile wholesale electricity prices with no guaranteed floor.
Allocation Round	The competitive auction process through which CfD contracts are awarded. Developers submit sealed bids; the lowest-priced projects win until the budget is exhausted. Seven rounds have been held since 2015, with AR8 scheduled for July 2026.
LCCC (Low Carbon Contracts Company)	The government-owned company that acts as counterparty to all CfD contracts. It signs contracts with generators, manages milestone delivery, administers CfD payments, and collects repayments when wholesale prices exceed the strike price.

Sources

DESNZ — Contracts for Difference Allocation Round 7 Results (January 2026): Official results confirming 8.4 GW of offshore wind capacity awarded at a strike price of approximately £91/MWh (2024 prices). gov.uk — CfD AR7 Results
DESNZ — CfD and Capacity Market Scheme Update 2025 (December 2025): Policy summary confirming the extension of CfD contracts to 20 years for wind and solar from AR7 onwards, and the introduction of new auction design features. gov.uk — CfD Scheme Update
Energy UK — Allocation Round 7 Results Explained (February 2026): Industry analysis of AR7 outcomes, including the 14.7 GW total across all technologies and the scheme's cumulative impact on UK electricity supply. energy-uk.org.uk
DESNZ — Further Reforms to the CfD Scheme for AR7: Government Response (July 2025): The government's formal response to consultation on extending contract terms, relaxing eligibility requirements, and the rationale for 20-year versus 25-year contracts. gov.uk — CfD AR7 Reforms
Norton Rose Fulbright — Revenue Stacking: Getting the Balance Right for Fixed-Bottom Offshore Wind (2025): Legal and financial analysis of CPPA structures, merchant tail risk, and the evolving revenue models for post-CfD offshore wind assets. nortonrosefulbright.com
Lexology — UK Offshore Wind: Converting Record-Breaking Auction Success into Physical Delivery (February 2026): Analysis of AR7 outcomes, the policy changes that enabled them, and the delivery challenges — including grid connections and supply chain constraints — that lie ahead. lexology.com
Low Carbon Contracts Company (2026): The LCCC's public dashboard and operational data on CfD levy rates, contract management, and the signing of over 200 AR7 contracts. lowcarboncontracts.uk