On 19 October 2026 the Competition and Markets Authority dismissed an appeal by Gwynt y Môr Offshore Wind Farm Limited, RWE Renewables UK and RWE Renewables UK Swindon against the Gas and Electricity Markets Authority's decision of 1 May 2026 to reject Connection and Use of System Code modification CMP344. The CMA confirmed the decision on all four grounds and reserved costs.
CMP344 was raised by the RWE group on 21 May 2020. By our count, 2,342 days passed between the proposal and the CMA's order, of which 171 were the appeal. That is long even by the standards of GB charging reform.
What CMP344 was about
Offshore transmission in Great Britain is owned by offshore transmission owners (OFTOs) that buy the assets from the wind farm developer after construction. Each OFTO's revenue is fixed for the licence term once it takes over. The licence allows adjustments for Income Adjusting Events, which cover force majeure (Limb A), unexpected changes to the System Operator Transmission Owner Code (Limb B), and other events Ofgem approves above a threshold (Limb C). A typical Limb C example is a latent defect in a subsea cable that has become practically uninsurable.
When Ofgem approves an IAE, NESO pays the OFTO and first recovers the cost through the Transmission Demand Residual, paid by consumers. When the connected generator's offshore local charges are next reset, NESO raises those charges and lowers the residual. Under the existing method, the generator ends up bearing all or much of the approved cost.
CMP344 proposed that approved IAE costs should stay in the demand residual. The generators' case was that IAEs are by definition events outside anyone's reasonable control, that offshore generators cannot mitigate them, and that onshore generators are not exposed to comparable costs in the same way.
The CMA's reasoning in brief
Ground 1 alleged apparent bias. The GEMA decision-maker had represented NESO on the CMP344 workgroup in 2020 and 2021, and was the only workgroup member to vote against it in November 2020. The CMA found that a fair-minded and informed observer would not conclude there was a real possibility of predetermination, given the five-year gap and the further work done in between.
Ground 2 was the substance: whether CMP344 would better meet the charging objectives on cost reflectivity and competition. GEMA had argued that leaving costs with the generator connected to the failed asset was more cost-reflective, because those assets exist to serve that generator. The CMA agreed that GEMA was not wrong on that point, and on the related arguments that GEMA had defined IAEs too narrowly, ignored generators' inability to mitigate them, or wrongly rejected a comparison with the SHETL subsea cable reopener.
Grounds 3 and 4, on administrative efficiency and consumer benefit, also failed.
How large is the money at stake
This is where the case is more modest than six years of process suggests.
In 2026/27, generators are expected to pay 16.2% of total TNUoS charges, and consumers the rest. IAEs are by design rare, low-probability and high-impact events. The determination records that Ofgem's IAE threshold is £0.5 million or £1 million depending on the licence.
The best available measure of the effect on generators comes from the appellants' own evidence, as GEMA used it. Exposing offshore generators to IAE costs was estimated to raise CfD strike prices by about £0.06/MWh, against a strike price of £91/MWh in the AR7 auction. That is 0.066% (0.06 ÷ 91), consistent with GEMA's "less than 0.07%" description.
Our estimate of what that means for a single project: a 1 GW offshore wind farm at a 40% capacity factor produces about 3.5 TWh a year (1 GW × 8,760 hours × 0.40). At £0.06/MWh that is about £210,000 a year. Method: the capacity factor is our assumption and is in the range of recent GB offshore fleets; the £0.06/MWh is the appellants' estimate as cited by GEMA and the CMA. Actual IAE exposure arrives as a lump when an event occurs, not evenly each year.
Small in a CfD price, then, but not small to an individual owner when a cable fails, since the cost lands in one project's local charges. That concentration was the core of RWE's argument, and the CMA did not dispute it as a fact. It held that GEMA was entitled to treat cost reflectivity as pointing the other way.
The competition argument
The appellants argued that the existing method discriminates against offshore generators relative to onshore ones and to interconnectors, and that it distorts bidding in the CfD auctions and the Balancing Mechanism. GEMA's response, which the CMA accepted, was that negative-price days are rare and that the effect on CfD contract value is trivial. The CMA also rejected the challenge to GEMA's view that CMP344 could itself introduce a distortion in the CfD market.
What it means now
The decision leaves the existing allocation in place. Developers that sell assets to OFTOs keep the tail risk of approved IAEs through their local charges for the life of the OFTO licence. That risk is part of what is priced into AR7 and later bids.
The case is also a marker for how the CMA treats energy code appeals. It gave GEMA wide latitude on how to weigh the charging objectives against each other, and set a high bar for bias arguments based on a decision-maker's earlier role at NESO.