ROC support is ending for many renewable generators, and the route-to-market choice you make next matters.
Three numbers set the scene for this transition:
Put those together and the timeline stops looking distant. That's the thread running through Episode 1 of Life After ROCs, our new webinar series on what comes next once ROC support ends. Greg Rahilly and Sarah King were joined by Ken Corless, Senior Financial & Commercial Manager at UK Renewables Energy Group, for a first-hand view from inside a portfolio actively planning for it.
ROCs are the currency of the Renewables Obligation scheme, which ran from 2002 to 2017 and underwrote much of the UK's large-scale renewables build-out — at its peak, the largest third-party cost on UK energy bills, at around 20% of the average consumer's bill in 2025. Technology-specific banding introduced in 2009 means that support rolls off in waves, starting with the first assets in 2027 and running through to the scheme's final expiry in 2037.
Renewable Exchange's data team, drawing on Ofgem's ROC register, puts the scale of it plainly: over 10GW of capacity rolls off the RO scheme by the end of the decade, across every major technology type. A large, concentrated wave of generators facing the same route-to-market decision.
UK Renewables Energy Group's wind portfolio — acquired in 2024, sites ranging from 0.5 MW single turbines to 25MW+ arrays, most around 10–15 years old — currently draws roughly half its revenue from ROCs and ROC recycle. Because ROC income rises with CPI, it's the most predictable line on the books today — which is exactly why planning for its replacement is already live at management level, well ahead of any single site's roll-off date.
Sarah set out the route-to-market menu this series will unpack episode by episode:
“If we were to repower, the grid connection queue is 6-plus years... we need to start the process now on repowering, because if we wait a few years, we'll be running a loss on this site before [the new revenue] even kicks in." — Ken Corless
A ROC roll-off date seven or eight years out looks like breathing room, until a 6+ year grid connection queue and a planning process are counted backwards from it. The decisions that determine what a site looks like in 2033 need to start now.
Ken also made the case for weighing more than the model. Decommissioning doesn't just retire turbines — it unwinds relationships built over a decade or more of operation:
"We bought the hard assets — the turbines, the lease agreements. But there's all the soft assets too: the relationships with O&Ms, with landowners, the community benefit funds." — Ken Corless
Those community benefit funds, local discount schemes and landowner relationships, built up around a site over its operating life that doesn't reappear if the asset goes dark.
More good questions came in than we could get through live. Here they are with the answers in full.
What's being done to work with the government to mitigate lost generation?
DESNZ ran a consultation through autumn 2025 into how RO pricing gets handled as we head toward the cliff edge, and it wasn't a token exercise. 247 responses came in, with a big chunk from institutional investors and trade bodies, and government published its response in late January. Separately, the reopening of CfD to onshore wind and solar in AR7a earlier this year is a big piece of the puzzle for anyone looking at repowering. It means there's now an actual subsidy route on the other side of ROCs, not just merchant risk. It's not solved, planning and grid connection timelines are still the binding constraint for a lot of sites, but the direction of travel is that government is engaging, not ignoring it. — Greg Rahilly
What conditions would make an asset owner consider co-locating with storage when repowering?
The key considerations would be:
- Grid constraints: If the site has valuable grid capacity but experiences curtailment or export limitations, storage can improve utilisation of that connection and defer costly network reinforcement.
- Capture price deterioration: As renewable penetration increases, particularly for wind and solar, capture prices can come under pressure. Storage can shift output into higher-value periods and improve realised revenues. This is increasingly relevant as negative pricing events become more common. This will then play a part in how we would contract from a route to market perspective
- Site fundamentals: Existing land rights, planning conditions, grid infrastructure and operational expertise can significantly reduce development risk and cost relative to a greenfield battery project. — Ken Corless
What about Peer-to-Peer sales — doesn't that offer an uplift on a standard PPA?
It can — generators can see an £8–£25/MWh+ uplift. It's an additional revenue layer rather than a standalone route, and it comes with real constraints: no guaranteed upside (dependent on how well generation matches demand), a hard 5MW/h supply limit (2.5MW to domestic) beyond which it's a criminal offence, compliance risk from aggregation errors, exposure to policy change on LES benefits, and some reputational sensitivity around perceived levy avoidance. Our platform has a number of offtakers offering P2P/LES — get in touch to explore it, or see our licence-exempt supply FAQs. — Sarah King
Without debt covenants, why not just trade day-ahead on N2EX and capture favourable prices?
Day ahead is a play that can be made and has the opportunity for high gains as prices spike, however the revenue volatility gives difficulties for forecasting, budget certainty, dividend planning. The site would also be subject to negative pricing exposure, which we expect will increase as more renewables come on line. I think the way that it would be useful is as part of a wider portfolio strategy, having some of the portfolio on N2EX allows you to access the high prices as they come in, however then also having some sites on longer term fixed PPAs give the company some stability. It is not a binary decision, a sensible strategy will be to retain some merchant exposure but locking in enough of the portfolio to give some certainty. — Ken Corless
Would asset owners consider entering the Balancing Mechanism as a revenue stream?
The BM rewards the ability to turn output up or down on National Grid ESO's instruction, and weather driven generation just isn't built for that. You can curtail down, but you can't dial up wind that isn't blowing. AD has a bit more flexibility if there's gas storage or flexible offtake built in, but it's still a narrow window. Where we are seeing asset owners get exposure to it is through aggregators, and usually paired with batteries or flexible load rather than the generation asset on its own. The storage does the balancing, the generator just keeps generating. So I'd frame it less as "should generators enter the BM" and more as "does it make sense to add flexible capacity alongside the asset". — Greg Rahilly
Count the grid queue and planning time backwards from your roll-off date, and "years away" can quickly become "now." Talk to the Renewable Exchange team about your options, and what the market data says about timing the move.
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