1. Price signals have a purpose

The 4 Biomass units at Drax are a perfect natural experiment for different ways of subsidising renewables. Unit 1 already has a Contract for Difference (CfD) and gets a fixed strike price (inflation indexed) for its output. Units 2-4 earn the wholesale price plus a Renewable Obligation Certificate (ROC) for each unit they generate.

ROCs are very much out of fashion because how expensive the overall scheme has become, most significantly because until April this year, it was uprated by the flawed and overgenerous RPI measure of inflation. They've also been criticised a great deal for over-rewarding zero marginal cost renewable producers of power (wind and solar), who are not able to dispatch on demand, but are instead entirely weather dependent.

Drax is different to wind and solar because it is dispatchable. Its owners stockpile woodpellets in the yard and can wait for the wholesale price to exceed the cost of fuel; much like a traditional gas (or coal) power plant.

If you look at Units 2-4 at Drax on ROCs, it's very clear that they have dispatched more when wholesale prices have been higher — a classic upward-sloping supply curve. In contrast, the CfD unit (number 1) has a much more ambiguous relationship.

2. The 2022 crisis highlighted key deficiencies with the existing Unit 1's CfD

In 2022, energy prices, especially European gas spiked to eye-watering levels following Russia's invasion of Ukraine. Wholesale electricity prices in Britain rose too; as gas plant sets the marginal price most of the time. The revenue on offer to Units 2-4 at Drax went up, and perhaps not unsurprisingly, their generation rose to levels not seen before or since.

The CfD unit saw no benefit at all — and worse. Its subsidy is a top-up to a fixed strike price, measured against a seasonal average wholesale price; so when that seasonal price climbed above the strike, the top-up didn't just vanish, it went negative. Every unit Unit 1 generated now meant paying money back to the Government. With wood pellets also surging and Drax not yet self-sufficient in fuel, the choice was stark: far better to feed scarce, expensive pellets to Units 2-4, earning the full market price plus a ROC, than to Unit 1, now loss-making on every megawatt-hour. So Drax wound Unit 1 down.

As it turned out, there was also a substantial unplanned outage for Unit 1 in 2022, and I guess there was little urgency given its loss-making status to prioritise its repair.

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I got to visit RheEnergise's High-Density Hydro test rig, just down the hill from my home on Dartmoor — and it's one of the more elegant answers I've seen to the storage problem.

Storage is the hard part of electrification. Lithium-ion has transformed how we balance within-day swings on the grid, but for the really heavy lifting we still lean on pumped hydro — and the UK simply doesn't have enough big mountains and rivers for it. Our existing plants (Dinorwig, Ffestiniog, Cruachan) are the darlings of the grid, delivering power in ten seconds and cycling once or twice a day. We just can't build many more.

RheEnergise's trick: if you can't get more height or more water, make the water heavier. Not radioactive — just dense. They mix in the densest materials they can find to create a fluid that stores far more energy per drop. The recipe is the secret sauce, and it's already patented.

It looks a lot like the "clay slip" my potter wife works with: shaken in a medicine bottle it's startlingly heavy next to plain water, yet weirdly consistent despite being so viscous.

The Devon site is clever too — a former China Clay works, so there's an artificial hill of (relatively) soft soil to bury a reservoir in, plus an on-site power offtaker already hungry for energy. This is a device they send down inside the pipes to clean them, a bit like a bullet in a gun barrel:

The pumps and turbines are specially calibrated for the heavier-than-water fluid, and the rig is wired into the distribution grid, charging and discharging at around 500kW — which they demonstrated live during our visit.

I even got to sit in the control seat. I just had to promise not to push any buttons.

What strikes me is where this fits in the bigger picture. Like conventional pumped hydro, high-density hydro is a highish round-trip efficiency store — you get most of the energy back out — which makes it well suited to the daily rhythm of charging and discharging the grid. That's a different problem from interseasonal storage, where you're holding energy for weeks or months and the raw cost per kWh of capacity matters far more than efficiency — the natural home of hydrogen or iron-air ("iron filings") batteries. High-density hydro isn't trying to compete with those. It complements pumped storage, extending its reach to the many places that don't happen to have a mountain.

If you're curious about the cutting edge of energy storage, RheEnergise are well worth watching.

Take a trip back to 2018; we can see which elements of the energy transition have exceeded (or been exceeded) by expectations. We can do this using the FES (Future Energy Scenarios) projections, the annual scenario set National Grid ESO (now NESO) has been publishing since 2011.

The forecast error you can see from space is the overprediction of demand; something I’ve written about before. This is nowhere less evident than heat, where successive governments have baulked at gas-boiler bans, preferred the purity of small volumes of heavily subsidised pure heatpump retrofit over more flexible and scalable hybrid models. Even challenges like fixing EPC (Energy Performance Certificates) and smart metering/settlement have dragged on years and years.

These failures have broader consequences. Much of the investment we’ve made into renewable generation would have paid off better; had we seen the growth in demand that policy makers projected at the time the decisions to invest in renewables were made. Most of the capital costs of renewables are fixed; and much of the recovery is from volume based energy charges, so in the same way that a growing economy provides a tax base to support public investment, so a growing demand for electricity could have diluted the burden of the energy transition. Furthermore; demand growth in Scotland could have directly avoided much of the curtailment costs.

One small upside is the flattening of demand since 2024 — now nearly two years of broadly stable consumption — but consistent growth remains to be seen.

It’s worth being explicit about the feedback loop this creates. Most of the costs of the GB grid — the renewable subsidies, the network capex to connect them, the standing cost of the gas plants that back them up, the curtailment bill — are essentially fixed each year. They get amortised across whatever electricity the country actually uses. When demand sits ~25% below where 2018 policy expected, those fixed costs land that much heavier on every remaining MWh. And the higher the per-MWh cost gets, the harder it is for electricity to undercut gas at the boiler, the petrol pump or the factory floor — so the electrification growth that would have diluted the burden stalls further. The 2018 demand miss isn’t just a sunk cost; it’s a feedback loop that’s still tightening today.

You can see policy reaching for the sticking plaster. The Boiler Upgrade Scheme now pays £7,500 to replace a gas boiler with a heat pump (rising to £9,000 for off-gas-grid oil-heated homes) — a capital subsidy designed to bridge an operating-cost gap that wouldn’t exist if electricity weren’t loaded with policy costs in the first place. Bigger upfront grants don’t fix the loop; they just smooth its visible edges, and the smoothing itself becomes another bill borne by the same taxpayers we’re nominally trying to relieve.

To be fair, the BUS period hasn’t been pure waste. Nesta’s analysis of MCS install data shows the median air-source heat pump install fell about 11% in real terms over the four years following BUS launch in 2022 — roughly 3%/yr, driven by a mix of installer scale, supply-chain maturity and competitive entry (Octopus, British Gas, and others pushing down headline prices). The trend has stalled in the most recent year (a 0.4% real-terms uplift), which suggests the easy gains have been captured. It’s a meaningful learning curve but vastly slower than the technologies heat pumps depend on: solar PV fell ~15%/yr through the 2010s (~80% per decade), and lithium-ion battery packs have fallen by more than two-thirds since 2015 as the EV and grid-storage markets actually began to scale — ~12-13%/yr CAGR and still tracking ~10%/yr. Heat pumps are running at maybe a fifth of that rate. That’s because the cost stack is mostly labour and on-site work — installer time, plumbing modifications, hot-water cylinder, radiator upsizing — not a commoditised product where global manufacturing scale compresses unit cost. The heat pump unit itself might be getting cheaper, but it’s only ~⅓ of the all-in install bill; the rest is local, skilled labour, and that’s what bounds the scope for cost reductions.

Interest rates compound the problem from the other direction. The MCS Data Dashboard puts the average UK air-source heat pump install at ~£13,300 in 2025; after the £7,500 BUS grant, the household is left at ~£5,800 — versus a like-for-like gas boiler replacement at around £3,000. If that money is financed at a mortgage rate of 5%, even significant energy bill savings could be swallowed up by higher interest and capital payments.

Carbon policy bakes the asymmetry in even more deeply. The gas burned in a CCGT to generate electricity carries two carbon levies — the UK ETS (~£40-50/tCO2 of late) and the Carbon Price Support top-up (~£18/tCO2, frozen since 2015). Both flow through CCGT short-run marginal cost into the wholesale electricity price and onto consumer bills. The same gas burned in a domestic boiler down the road sits outside both regimes and pays no equivalent carbon price. So the carbon in a kWh of electricity (already mostly renewable) carries a price tag that the carbon in a kWh of heating gas does not — and the higher the marginal CCGT runs in the merit order, the wider the wedge. Recent policy nibbles at the edge — the Autumn 2024 Budget confirmed the CPS top-up will be abolished from April 2028, lifting ~£18/tCO2 off the power side — but the bigger ETS levy remains, and the change does nothing for the underlying asymmetry between gas-for-electricity and gas-for-heat. And if the UK relinks with the EU ETS (where carbon has been trading much higher than the UK price), the wedge against electricity widens further, exactly the wrong direction if the goal is to make electrification competitive. The structural fix would be a carbon tax on heating gas, of the kind Ireland has progressively introduced (€56/tCO2 by 2024, with a glide path to €100/tCO2 by 2030). In the UK that idea has been politically toxic every time it’s been seriously proposed.

There’s a second, subtler effect worth flagging. Because CCGTs typically set the price in GB wholesale markets, those carbon levies on power-sector gas flow directly into the wholesale clearing price — roughly £17/MWh from the ETS plus ~£7/MWh from CPS at recent levels, or about £24/MWh of carbon-driven wholesale inflation that wouldn’t be there in an unlevied counterfactual. CfDs settle against that inflated wholesale, so the headline top-up cost (the LCCC bill we see reported as “CfD support to renewables”) looks artificially small. A £45/MWh CfD strike against an ETS-inflated £65/MWh wholesale looks like the consumer is making money from the contract; against the ~£40/MWh wholesale you’d get without the carbon adders, the contract is roughly a wash. The cost hasn’t disappeared — it has just moved from the visible LCCC line to the less-visible wholesale-driven retail tariff. Both are paid by the same consumer; the optics flatter renewables policy.

Political emphasis amplifies the loop too. Clean Power 2030 — the headline target to fully decarbonise GB electricity by the end of the decade — concentrates yet more policy bandwidth, capex and consumer levies onto the sector that’s already by far the cleanest. Domestic heat (~78% still gas at the meter) and transport (majority ICE on the road) each emit more annual CO2 than power, but sit largely outside the CP30 framework. Doubling down on the cleanest sector while demand stalls makes the per-MWh maths worse, not better — and pushes the cheapest remaining abatement (heat and transport electrification, exactly the demand FES 2018 expected to materialise) further out of reach.

The deepest irony sits here. The Renewables Obligation — designed to decarbonise electricity — has, via the per-MWh premium it bakes into every consumer kilowatt-hour, quietly become a brake on the electrification needed to decarbonise heat and transport. The bill lands on households and small businesses; the receipts flow to the institutional investors (pension funds, infrastructure funds, listed utilities) who own most of the older offshore wind portfolios. A subsidy designed to accelerate the transition has, on net, slowed it. The same dynamic falls on every renewable, network upgrade and storage project we’re trying to amortise into a stalled demand base: the cost of capital has effectively doubled since the policy designs that underpin this build-out were drafted in the late 2010s, which flows through to higher CfD strike prices in recent rounds and higher TNUoS charges down the line. The vicious circle pulls in financing too: low demand keeps per-MWh costs high, which keeps electrification slow, which keeps demand low, while the cost of capital to escape any of it has roughly trebled in nominal terms.

Projections for generation technology have by and large been better than demand; though this is not that surprising given Government has more or less directly controlled the growth of the technologies through control of the CfD budget allocations and more recently limiting the growth of grid connections for new battery projects. Only PV, much of which is installed behind the meter and without either a Government CfD could be seen as a less regulated market; and the growth here has been the most impressive, though much of the returns on behind the meter solar investment actually stem from the high levies, meaning it actually exacerbates the problem of high electricity prices.

Batteries are the outright winner; and PV follows close behind. Wind, the bedrock of our system, has tracked close to the bottom of the FES 2018 range in capacity terms — broadly in line with Steady Progression, well below the Two Degrees and Community Renewables paths the policy debate at the time tended to assume.

It’s not just demand and capacity the projections got wrong — fossil costs did too. The 2021–23 gas crisis sent wholesale gas to 3–4× the FES High case, and the UK ETS launched in 2021 already running well above the EU ETS path FES had penciled in. Both fuel and carbon went far beyond the modelled range, which dramatically changed the economics of every CfD struck on the back of those projections.

How gas and wind don’t mix

A one sentence summary of 2010s electricity policy was to retire coal, replace it with wind power, retain enough gas as a backup and attempt a half-arsed gold-plated revival of nuclear power.

By providing a fixed CfD price for wind electricity and a capacity market payment for gas, the idea was that the cost of capital (finance) to duplicate our generation could be minimised. In the short-term this worked because the economy was growing (just), there was a cross-party political consensus RE decarbonisation, interest-rates were at record lows and the prospect of massive growth in demand from electrification in the future meant that the cost to consumers could be deferred. Unrealistic expectations about the speed of transmission infrastructure build out played a supporting role too.

Why gas is a growing cost for wind generation

You wouldn’t normally think of wind generation requiring lots of natural gas. But, the way the GB electricity market is structured, that’s increasingly what happens for the grid operator, NESO.

One silver lining of wind capacity added in recent years and the fall in costs that ended with the great inflation of 2022 has been the reduction in the cost of compensating curtailed wind farms. Offshore CfD strike prices fell from ~£120/MWh in AR1 to ~£37/MWh by AR4 before the 2022 inflation reversed the trend (AR7 cleared at ~£91/MWh). This has created the strange dynamic where the most recent wind farms, with cheaper CfD prices tend to be curtailed more than older vintages. You can see this trend clearly with the outward shifts of the wind bid stack in the animated chart below:

Plus the subsidy bill on top

The bid stack shows what the system pays to balance wind. But consumers pay a separate, much larger bill: the RO and CfD subsidies on every MWh delivered. Recent political debate has fixated on CfD strike prices — they’re public, banded by allocation round, and easy to cite. But CfDs still are the smaller scheme. The chart below splits the two, and RO (in purple) dominates throughout — roughly 90% of the subsidy bill in the late-2010s, falling to ~70% by 2024-25 as more of the fleet rolls onto CfDs. Offshore wind accredited before 2015 was banded at 2 ROCs/MWh (≈£145/MWh at today’s ~£73 ROC value); onshore is 0.9–1.0 ROCs (≈£65–73/MWh). Both rates lock in at accreditation and run for 20 years, RPI-indexed all the way through to the final April 2026 uplift — so the early offshore fleet earns that £145/MWh on top of wholesale into the late 2030s, regardless of where the spot price sits. CfDs work differently, topping up the difference between a fixed strike and the market reference, so they’re at least somewhat counter-cyclical (the 2022 wholesale spike triggered a £290m clawback). Across both schemes, ~£6.7bn was paid to GB wind in 2024, and as a share of baseload the total has exceeded the wholesale value of the energy itself for most of the past decade.

It's worth pausing on the indexation choice baked into the RO. The buyout price was uplifted every obligation year by RPI, not CPI — and the two are not the same animal. CPI is the conventional benchmark for inflation (it's the Bank of England target, and what CfDs are indexed to); RPI consistently runs about a percentage point a year hotter, mostly because of methodological quirks the ONS has long acknowledged but governments have been slow to fix.

From April 2010 (the heart of the offshore-wind RO accreditation window) to April 2026 (when the final RPI uplift was applied, after 16 obligation years of compounding), RPI rose 86% against CPI’s 59% — a 27 percentage point gap, with RPI compounding at 4.0%/yr versus CPI’s 3.0%/yr. That one extra percentage point a year stretched the nominal value of every ROC by ~17% more than it would have been under CPI. Applied to a 2010-era ROC worth ~£37/MWh, that’s the difference between £59/MWh and £69/MWh by April 2026 — about £10/MWh of indexation premium on top of every MWh, for 20 years from accreditation, across ~70 TWh of RO-era wind. Quiet, technocratic, and worth roughly £700m a year by the end of the indexation period.

The RPI premium is the slow leak. The bigger leak — and one the policy debate did partly notice — was the 2021-23 wholesale crisis. RO is structurally different from CfD here: when wholesale prices spiked, CfD generators paid back the upside above strike (a £290m clawback in 2022 alone), but RO generators kept all of it. The ROC is a flat per-MWh top-up paid on top of whatever wholesale price the generator captures, so a pre-2015 offshore wind farm in 2022 earned roughly £180/MWh wholesale + £145/MWh ROC ≈ £325/MWh — versus a comparable CfD generator capped near strike (~£40-130/MWh depending on allocation round). Across 2021-2024 the wholesale windfall to GB wind, against a 2017-2020 baseline, came to ~£22bn — of which ~£16bn went to RO-era assets. The Electricity Generator Levy (Nov 2022 - Mar 2028; 45% rate on revenues above a £75/MWh threshold) recovered roughly half of this — but crucially, EGL receipts flow to HM Treasury as general revenue, not back to billpayers. CfD clawback, by contrast, is netted off the supplier reference price and so does feed through to lower bills. So from a consumer perspective the levy doesn’t undo the RO windfall; it just transfers part of it from generator balance sheets to general government revenue. The other half stayed with the generators. Put plainly: the EGL is effectively a tax on energy consumers collected via generators — the consumer pays the windfall either way; the only choice is whether the generator or the Treasury banks it.

To be fair, HMT has redirected general revenue back into bill support — but selectively. The 2022-23 Energy Price Guarantee and Energy Bills Support Scheme bridged the worst of the crisis for households via direct payments and price caps; a recent reform has moved ~75% of RO costs off domestic electricity bills and onto general taxation, on the grounds that loading policy costs onto electricity makes electrification (heat pumps, EVs) artificially uncompetitive against gas; and energy-intensive industries have separate exemption schemes that remove most policy costs for them. But these are discretionary choices, not mechanical: which billpayer gets relief, how much, and for how long is set by the Treasury on a case-by-case basis — nothing like the automatic per-MWh netting CfD clawback already does for everyone. So the headline “RO is locked in to the late 2030s” understates the bill: it isn’t just the index choice that made the RO generous — it’s that the scheme has no wholesale-side correction when prices run four times the forecast.

Worth noting that we haven’t attempted to unpick the extra network costs of wind farms, which are mostly built in remote parts of the UK that previously lacked substantial transmission capacity. Ofgem’s ASTI (Accelerated Strategic Transmission Investment) framework alone fast-tracked ~£20bn of accelerated transmission projects, and NESO’s Beyond 2030 / Clean Power 2030 plans imply a network capex bill running into many tens of billions across the decade — borne by consumers through TNUoS and supplier pass-through, on top of everything in the chart above.

Why gas is no longer the biggest cost for gas plants

Commentators frequently conflate the SRMC (short run marginal cost) of gas generation with the total cost, which factors in broader startup, maintenance, capital (inc finance) costs that are amortised (spread) across the running hours. Since 2018, renewable displacement of British CCGT generation has roughly halved their generation, meaning the typical CCGT generates but 1/4 of its potential:

As a result, the non fuel costs represent a growing share of the overall CCGT cost envelope per remaining MWh generated, outside of course the short-term 2022 Ukraine spike in gas prices. Not only that, but a “perfect storm” is driving up each non-fuel element of CCGTs, including:

Start Costs CCGTs typically need to generate at 40-50% of their nameplate capacity (Stable Export Limit), and displacement by zero marginal cost renewable generators (wind and solar) in the merit order means they are forced to stop and start far more frequently. For turbines, starting is the biggest single cause of wear and tear, on top of the additional fuel needed to “warm” the turbine before each run. The average running time of a CCGT has fallen about 50% from above 30 to just above 20 hours, with 25% of starts only lasting 15 hours or so. As I’ve written about recently, they’re also being ramped more aggressively to minimise overall generation time, another penalty for wear and tear:

Capital Costs

For new build CCGTs, the great inflation of 2022 lifted the capital cost of construction and gas turbine costs, along with the better known escalation of costs for wind and solar. However, this accelerated with the onset of the AI boom in 2023-4, as demand, primarily outside Europe for gas turbines for power generation for data centers pinched the limited global supply chains for manufacture that had been on the wane for many years, and severe backlogs mean that wait times now extend several years into the future at major manufacturers. Of course, these have been complemented by higher interest rates.

Putting these together, and amortising to ever shrinking generation volumes, the non-fuel costs of gas fired power in the UK are now pushing an estimated £60/MWh, close to both the CfD price paid to cheaper renewables and the normally-dominant fuel cost.

The brake, made visible

Pull the threads together — wind cannibalising its own capture price, the rising cost of balancing it with increasingly part-time gas plants, and a subsidy bill that exceeded the wholesale value of the energy itself for most of the period — and one observation lands: each new GW of wind has delivered less to the system than the last. The cruel irony is that gas and carbon costs ran far higher than FES 2018 projected; that should have lifted baseload prices and rewarded wind handsomely. Instead the demand-side failure dominates: the electrification growth that 2018 policy assumed — heat pumps, EVs, industrial demand — simply hasn’t materialised, and the new wind capacity is scaled to a demand level that hasn’t grown. This isn’t a transient COVID effect: the COVID period is excluded from the fit below, and the trend through the non-pandemic years is unmistakable — broadly flat through the first ~22 GW, then a sharp accelerating decline past 28 GW. Diminishing returns to scale — and the root cause is the demand growth that never showed up.

Ofgem announced today’s energy price cap update: a 13% rise, taking a typical direct-debit household from £1,641 to £1,862 per year. Every newspaper led with it. Every headline used the same figure: +£221.

That figure is misleading — not because Ofgem are doing anything wrong, but because the cap they announced only lasts three months. The £221 is the annualised figure. For the three months this cap actually covers — July to September — the average household will pay about £30 extra. Not £221.

That gap matters: for understanding what the press is actually telling you, and for what to watch out for when the next cap lands at the end of August. It’s also just the first of five findings from today’s update that none of today’s coverage picked up.

Here are the other four — and what they mean for your bill, this year and next.

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If you enjoy dispatches.kilowatts.io, it would mean the world to me if you invited friends to subscribe and read with us. If you refer friends, you will receive benefits that give you special access to dispatches.kilowatts.io.

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Most big expenses depreciate, including low-carbon purchases like EVs. Solar PV is doubly so. The hardware itself degrades — the panels lose about 0.5 % of their rated output each year through cell ageing, with the inverter shaving off another ~0.2 %. On top of that there’s an economic version: as more PV gets added to the grid, every existing install faces newer, cheaper competition for the same midday hours, and the carbon and £ each kWh fetches falls accordingly — what economists call cannibalisation. A kWh of GB solar in 2025 displaces 47 % less carbon than the same kWh did in 2019, and captures 13% less of the baseload price.

PV ages like Beaujolais Nouveau — best drunk in its first year, less valuable with every vintage that follows. (I should declare an interest here: as a student I worked “les vendanges” twice there. Nouveau drops mid-November and the good bottles don’t last to Christmas — the ones that do, by definition, weren’t great fresh, so I’ve mulled them. Which is roughly what a home battery does to surplus midday PV.)

Heat pumps age like a vintage Bordeaux — laid down today, drinking better every winter, peaking only after a decade in the cellar. Unlike PV and batteries, they haven’t really got cheaper over time either; and the more generous grant they currently enjoy can’t last forever

Not entirely without risk, though: the hail-strike vintage is the cold, low-wind winter that hasn’t happened yet — the one that arrives with millions more heat pumps on the grid than today. See section 5.

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HeatpumpMonitor.org is an open-data project run by the OpenEnergyMonitor community: real UK households running heat pumps and publishing their meter readings at ten-second resolution. I pulled the full history of every public system into DuckDB — 730 heat pumps, ~20.5 million half-hourly readings, going back to early 2017.

The map shows where the fleet sits. A few quick takeaways before we dig into the findings:

• The geography is a bit skewed south and east: East England (78), South England (85), South West (52), Yorkshire (48) dominate; though London is the most under-represented region per capita — flats and shared systems are a poor fit for an owner-installed, monitoring-engaged community.

• North Scotland is over-represented per capita (0.038 systems / 1,000 dwellings) despite being the coldest part of the country — early-adopter density matters more than climate.

• The panel is self-selected: HPM users are technical, engaged and predominantly Octopus customers. This is a quality sample, not a representative one. Anything I say below is about how well-installed, well-monitored heat pumps behave — not the full UK fleet.

What follows are several things that surprised me most from working through this data, or reinforced existing priors I have.

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Right now the FiT levy adds roughly 0.77p to every kilowatt hour of domestic electricity — about £24 a year on a typical 3,100 kWh household (Ben James, electricitybills.uk, FY 2024-25). Much less than Renewable Obligations, and much more skewed toward lowish quality domestic PV.

Falling Capex Costs

PV installation costs have plummeted since 2010, in part due to the stimulus of the feed-in-tariff programme in terms of growing an industry and supply chain, but much of it due to China.

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§1 · The headline crossover

First some headline numbers from 2025:

There’s about twice as much usable solar power in a typical Spanish PV site compared to the UK. However, the wholesale cost of that energy is less than half. So the net revenue, if the solar is to be sold without subsidies or CfDs is slightly higher in the UK, at least at current exchange rates.

§2 · Why? Yield vs capture price

Turns out the North-South inversion of solar yields (sunshine) to captured prices is actually the norm among Britain’s power-trading neighbours (and Germany - to which it will soon be connected)

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Despite increasing trade frictions post Brexit, Britain’s grid is increasingly Europe’s crossroads as well as its wind hub. In each direction, different and sometimes unexpected trends are shaping the flows; Norwegian hydro to the north, a sun rising far higher than expected in the east, mostly reliable French nukes to the south and an AI boom to the West.

§1 · Twelve years of GB interconnector flows

Looking at annual aggregate flows for interconnectors totally misses their ability to flip direction depending on the time of day and year (weather). Just as a picture tells a thousand words, this animation tells a thousand pictures (or stories):

I’ll do my best to summarise the key trends for each of these.

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I recently used Ofgem data to create a net approval score for household energy, where suppliers are compared on their ability to win the trust of consumers and move off the Ofgem pricecap:

Four moments that summarise it:

• 2013, Ed Miliband campaigns on capping energy prices (Octopus doesn’t yet exist - except as a twinkle in Greg Jackson’s eye).

• 2018, after nearly “loosing” the 2017 election, Theresa May’s government legislates the cap (Octopus has under 1% of the market).

• 2022–23, the Treasury spends £46bn through suppliers to subsidise the cap through the wholesale crisis rather than reform it (Octopus takes over Bulb and gains momentum).

• 2025, the chart above. The cap preoccupied and muted Octopus’s competitors into complacency; Octopus itself rose despite it, indeed perhaps because of it.

The line between those four moments, Octopus’ rise that ran alongside, plus three plausible reforms the price cap are the back half of this piece. Spoiler, the most uncomfortable of those is the one we’ll probably end up taking.

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As I posted about recently on LinkedIn, my experience of wall-mounted panels over 4 years has yielded about 500kwh/kw/year, about 75% the typical roof-top yield, with more of a volume penalty in the peak summer months.

More recently, I ran some payback numbers for a typical property in Birmingham, more typical of the national average1. 800W of PV2 get me to annual bill savings of £130-150 a year when backcast over the last 20 years. With a notional £500 price tag, then assuming no installation cost, homes could feasibly see payback in 3-4 years.

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The demise of Giv Energy a few weeks ago was a sad moment. A British assembler, creating products tailored especially from a market and software perspective to the British market.

In the days following the administration announcement, a recurrent theme on my social media was from concerned customers and installers wondering what to do to manage the cloud and software interface.

This got me thinking, because it introduces a whole dimension of risk to the purchase of expensive retrofit items. The same logic would apply as neatly to a heat-pump or EV Charger manufacturer. Without the cloud, these devices are less user friendly. Optimisation routines break, access becomes impossible except perhaps on the home wifi network. Access reverts to an ugly web console, or an API. Either way, not everyone would share my geeky enthusiasm for controlling their heat-pump via MQTT (HomeAssistant is great at this by the way), or their Battery via MCP (again Victron is great at this!).

The risk is salient for Government. Much of the upfront cost of heat-pump and PV/batteries is being underwritten by grants and tax-breaks. It’s not in the taxpayers interest to invest in technologies that are at risk of obsolescence is a manufacturer goes to the wall, nor should a reasonable optimisation and running pattern require someone as technology literate as myself to keep control on running costs.

Which comes onto another value-perception problem, as most users are reluctant to pay ongoing subscriptions for hardware. The reality is maintaining a secure online cloud 24x7, ingesting data from devices over the cloud, maintaining and supporting user apps or websites, and running bespoke forecasting algorithms does bear a cost. But users either put a low value on these or expect them to be included in perpetuity.

What solutions are there?

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To many, nuclear is the cavalry that will save the grid, net zero and our industrial competitiveness. Stable, reliable, baseload power using a technology independent of current weather conditions, deployed at scale for 75 years.

When the final investment decision for Hinkley Point C was made, the plan was to commission in 2025. That slipped to the current hope to launch one of the two 1.6GW units in 2030, with another unit to follow one or two years later.

However, if we’re to hope that it will synchronise and immediately output 1.6GW, one should take a cautionary look at the performance of EDF’s sister project in Flamanville (Normandy), which after many years of delays commissioned in 2025.

It really hasn’t been plain-sailing. In the sixteen months since EDF formally declared commercial operation in late December 2024, Flamanville 3 has been offline for 285 of those days — an availability of around 42 per cent and an effective capacity factor of 27 per cent, about half that of our best wind farms. The design figure for an EPR nuclear reactor is closer to 90.

The damage comes from three big stoppages and a long list of small ones. The first ran for 65 days through February to April 2025. It started with a sensor reading on one of the cooling systems, gathered some turbine-bearing maintenance along the way, and ended up needing “additional work” deeper in the nuclear island — the classic while-we’re-in-here pattern. The second was longer still, running 117 days through the summer, to hand-polish — yes, hand-polish — three safety valves on the primary circuit; irregularities had been found on two and EDF pulled the third out as well, just to be sure. The third, 32 days in January and February of this year, wasn’t really a Flamanville problem at all. Storm Goretti made landfall in Normandy and EDF tripped the reactor offline as a precaution. The unit didn’t return until 9 February. Imagine a wind farm doing the same?

What’s striking is that the reactor itself has only tripped automatically once in those sixteen months. The lost output has come from auxiliary equipment, commissioning slippage, and one piece of weather. The nuclear bit is, by and large, behaving. It’s everything around it that isn’t.

Another innovation in France limiting output is the flexing of nuclear output downward in the middle of the day. To my knowledge, this has never been a requirement of the existing British nuclear fleet, and won’t be possible at Hinkley Point C. Traditionally, flexing output at nuclear plant has been known to increase wear and tear; so it’s notable at Flamanville, just a year into its commercial operation1 Watch this space for a deeper dive into nuclear flexibility.

Now for a thought experiment. Let’s imagine that, instead of commissioning last February in the UK, that the Flamanville reactor was the first reactor to be commissioned at Hinkley Point. It’s also being built by EDF and shares some (but not all) of its design. So I feel the comparison is not unrealistic.

On the one hand, Hinkley’s arrival just before the Iran war might have felt like a blessing, especially on Britain’s grid that it much more exposed to gas power. Certainly, this would be true for energy security. But in terms of cost, the situation is different.

The Strike Price for Hinkley Point C has increased substantially since the contract was signed in 2016. Even after a 3% discount was applied for economies of scale after Government gave the go ahead to Sizewell C, after years of inflation it stands at £133/MWh for the year starting in April 2026.

So, if Hinkley (Flamanville 3) had been generating for the British grid over the last year, consumers would have paid a top-up of about £248m, or £48/MWh for each unit it generated in order to make up EDF’s revenues to the level allowed by the strike price. Now I haven’t re-run a grid model to fully simulate the impact on wholesale prices, but Hinkley’s presence would reduce them, so I feel confident to say the subsidy figure is a lower bound.

Interestingly as well, because the CfD reference price for Hinkley is the baseload market reference. used for biomass plant, rather than the day ahead market reference price more widely known for wind farms, and because this has been less volatile in response to the Iran conflict (it operates with more of a lag as it more forward lookng), the top-up wouldn’t yet have been clawed back for consumers.

So would an early commissioning of Hinkley have been unambiguously bad for consumers? In fact, the CfD isn’t the complete picture for a couple of reasons. As its fashionable to now say, the Levelised Cost of Energy is not a comprehensive measure of system or consumer costs.

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In particular the continued use of net metering in the Netherlands, where behind the meter PV customers like households get to offset export credits from summer to the winter means there is little incentive to limit exports. It’s to be abolished, but not until 1st January 2027.

In case you haven’t already seen it, here’s a Sunday lunchtime snapshot (thanks Electricity Maps). TLDR → the continental grid is basically browning out from uncurtailable PV power, and users are were being payed up to €487/MWh to increase demand (at the day ahead stage). That’s like being paid 45p/kwh to use electricity. Put another way, it’s a bit like the wind curtailment payments we hear a lot about in Scotland, but instead of hapening in the balancing mechanism and being paid by the system operator, the cost is being pushed into the commercial/wholesale market.

Britain (and Ireland!) are outliers with a wholesale electricity price that’s neither close to zero or severely negative. For the uninitiated, let me explain quite clearly what the numbers mean.

1. In Ireland, the price of electricity is clearly being set by gas (CCGT) plants, with a price. Though Ireland has a lot of wind farms, like in Britain it wasn’t as windy in the Emerald Isle as it has been of late

2. In Britain, I’d argue the wholesale price is being influenced, if not explicitly set by gas, it’s just below the cost of the most efficient plants. It wasn’t that windy, and it was cloudier than recent days. The network constraints were on our ability to import power from the continent rather than south from a windy Scotland. A 50% outage on the IFA interconnector to France will have been very costly to its owners, as it could have netted a £500/MWh difference in prices, £500m an hour. In layperson speak, Britain missed an opportunity to get paid to help curtail continental solar.

So far, so good. But here’s where the situation in Britain gets a bit stranger. NESO was trying out it’s Demand Flexibility Service turn-down, for the 5th time since launching it to much attention in the media earlier this month (do checkout my post here). You can see all the auctions at my DFS site here. Here’s Sunday 26th’s attempt:

Broadly speaking, the turn-up auctions haven’t been particularly successful so far, especially compared to turn-down events on the same platform/service where NESO has been paying £150/MWh or so (15p/kwh) for evening turn down. That’s arguably expensive, even compared to elevated gas prices, but nothing crazy, and relatively consistent over time:

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