Each panel shows weekly reservoir filling as a share of that market's peak, with 2026 in blue against the 2016–25 range. The pink line is 2022 — the last time Europe had a hydro year bad enough to make front pages.

In 2022 the drought was southern. Spain and Portugal spent that whole year pinned to the bottom of their ten-year envelope — Portugal flat around 30% through the summer — and Italy's Po valley crisis put its line on the floor of the band too. The Nordics, meanwhile, had a roughly normal year.

In 2026 the picture has flipped. Norway and Sweden drew down through the spring along the very bottom of their decade range — Sweden touched its ten-year minimum in April, and both dipped deeper than they did in 2022. The snowmelt refill has since pulled them back towards the median, but the hydrological hole peaked at more than 25 TWh across the Nordic region. At the other end of the map, Spain and Portugal are hugging the top of their ranges, and Greece has been above its interquartile band all year.

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In May I argued that plug-in solar is a red herring. That piece has found a second audience over the past few weeks, and the questions in my inbox have converged on one: should I buy a kit when the law changes?

The law changes on Thursday 27 August. The bank holiday falls on Monday the 31st. Four days — and you already know how it will look: a boxed kit in the supermarket middle aisle, wedged between the pressure washers and the padded ski jackets, at a price pitched to feel like now-or-never.

So here is the direct answer, and it is not the one the retailers want: don't. Partly because, as you'll see, there is nothing yet to buy. But mostly because the thing they'll eventually sell you is the wrong half of the story — and the right half is sitting in a regulatory waiting room.

The shelf is empty

Start with the fact that makes "rushing" impossible. A compliant plug-in kit has to appear on the ENA's public type-test register before it can be sold, and the register has a filter for exactly this product. Set the Type field to "Plug-in Solar" and here is what you get today, five weeks out:

Zero devices of zero. The shelf is built, labelled and empty.

It has been coming for months, in the loosest sense of the word. The government announced its intention to legalise plug-in solar on 16 March, in a post-Iran energy-security package. The instrument that did it, SI 2026/848, was made on 16 July and comes into force on 27 August — 122 days from announcement to signature, for a document of 1,103 words. That's nine words a day; the law is shorter than this article. It was also finished in a hurry at the very end: DESNZ published its consultation response six days ahead of schedule and made the regulations the same day, 16 July — four days before Keir Starmer handed the premiership to Andy Burnham. Whether by chance or design, plug-in solar was got over the line just as the government changed leader.

But the drafting pace isn't really the story, and it would be lazy to pretend it is. The March announcement wasn't a launch, it was a statement of intent — and it was made for a season the scheme was never going to be ready for. Nobody who heard it was ever generating this summer, because five months on there is still nothing certified to buy. You trail a product at the start of the season that sells it, then spend that whole season not shipping it. The first plug-in summer that actually exists is 2027.

Even once it's stocked, the panel is the wrong buy

Say you wait for the register to fill. What are you buying? Less than the marketing implies, and here the May argument only hardens.

It earns almost nothing, because it can't sell anything back. A plug-in kit can't be MCS-certified, and without MCS there is no Smart Export Guarantee. So every kilowatt-hour you generate and don't use in the same moment is a gift to your supplier. Anchored to my four years of measured wall-mounted yield and modelled against real half-hourly household demand, a typical home self-consumes about 64% of what a small kit makes and spills the rest. Value it at the price cap and an 800 VA kit is worth roughly £75 a year — against the £130–150 I casually put in the May piece by valuing every kilowatt-hour at retail. The no-export rule lops about a third off the top, and it bites hardest in the bright spring and autumn months, when the panel makes most and the house soaks up least:

To put that in perspective: a whole winter's generation from one of these — September to February — is worth about £24. So even once there is finally something to buy, the month you choose to buy it barely moves the needle. The thing itself is cheap; the timing of it is a rounding error.

So what should you actually pay? Work it backwards, and treat this as the discretionary purchase it is: demand a 25% return a year — a four-year payback — which is about right once you allow for the cost of the money, the kit ageing and dating, and the fair chance that you (a renter especially) move before it clears. On that hurdle the most you should hand over is roughly four times what it saves you in a year. At the £75 a typical wall kit earns, that's £300; a perfectly-sited, always-occupied home earning nearer £120 might stretch to £480. Either way, the kits on sale today — £499 and climbing — are already above the ceiling a clear-eyed buyer would set. And that is a rule that ages better than any single figure of mine: whatever a kit ends up costing, ask whether it will save you a quarter of it, every year. If not, it's too dear.

One honest exception, and it's the nice one. That sum values your time at nothing, and installing a kit isn't nothing: budget a few hours to mount it, fit the plug, notify your network operator, and nudge the angle across a few weekends to find where it likes to sit. If that sounds like a good rainy-Sunday project — and it genuinely can be — call the labour a hobby and forget it. If it sounds like a chore, add it to the bill, and the case gets thinner still.

And if what moves you is carbon rather than cash, the comparison is crueller. On today's grid — about 120 grams of CO₂ a kilowatt-hour, and falling fast — that kit's 450-odd kilowatt-hours a year displace roughly 55 kg of CO₂, shrinking a little every year as the grid itself cleans up, and shrinking again once you count the carbon it took to build the panels. Call it well under a tonne across the kit's entire life. Now take the same £300 — or £500 — and spend it instead on UK or EU carbon allowances, and cancel them: at 2026 prices near £70 a tonne, you lift four to seven tonnes straight out of the emissions cap, today. Pound for pound, tearing up carbon permits abates several times more than bolting a panel to a wall, and it does it now rather than dribbled across twenty years. Be as generous to the panel as the physics will allow — credit it with displacing marginal gas rather than the average grid mix, which roughly triples its lifetime saving to a couple of tonnes — and the permits still come out ahead, and still sooner. And sooner counts for far more than it sounds. What warms the planet is the running total of everything ever emitted, so a tonne kept out of the air this year is worth more than the same tonne kept out twenty years from now: it is cut for longer, and it holds the peak lower while the tipping points are closest. The panel delivers its carbon the slowest way imaginable — a thin trickle over two decades — exactly when the atmosphere would most value it up front. That is a deflating thing to know about a product sold on its greenness. A cancelled permit doesn't glint on the balcony, granted, and it won't teach you a thing about your own demand — but if the ledger you care about is tonnes of carbon, the wall is not where the money goes furthest.

The cap tops it out. 800 VA is a ceiling on generation, and it clips every sunny day, so a plug-in panel makes a few hundred kilowatt-hours a year no matter how much silicon you bolt to the wall. The spec lets you hang 2,000 W of panel behind that 800 VA inverter — a 2.5-to-1 ratio where a rooftop system runs 1.1 or 1.2 — but with no export payment and no battery allowed, every watt above what you're using in the moment is simply thrown away. You are permitted to buy panel capacity that is structurally unable to earn.

And Britain made it dear at the bottom. Not at the top: EcoFlow's STREAM kit is about £499 here and near enough the same on its German store, so the branded mid-market is level. The difference is the floor. In Germany the cheapest option isn't a £499 branded set — it's a €249 own-brand kit from Lidl, or a self-assembled build for less again. That long cheap tail is what made balcony solar a mass-market object there. Britain's rules abolish it by construction: complete certified kits only, so no self-assembly; whole-kit certification and a register-before-sale gate, so the discounter's €249 box can't clear the bar the way a self-declared German product does. The premium isn't that any given kit costs more here — it's that the £150 and £250 options that dominate Germany can't legally exist, so the market starts at the branded price and stays there.

So ignore the German paybacks. You'll see two-and-three-year figures quoted at British readers; they describe a different planet. Germany's smart-meter rollout has all but failed — 5.5% of homes — so roughly half the country still runs an old spinning-disc Ferraris meter, and since 2024 the law lets that disc run backward until the operator swaps it. That's free net metering at the retail rate, read once a year, often by the householder. And the same missing smart meter that hands them free export also locks them out of dynamic tariffs, so for most Germans a panel is the only way to touch cheap solar at all. A British buyer has neither problem and neither perk: a smart meter that reports every half-hour, no export payment to collect — and, crucially, the ability to just switch to a tariff like Agile and buy the grid's cheap midday solar without bolting a thing to the wall.

And there is a safety case worth taking seriously, because it came from the one expert quarter that dissented. When the government consulted, 88% of the public waved plug-in solar through — but the bodies who actually understand home wiring did not join the cheer. The ECA, Electrical Safety First, the IET, NICEIC and SELECT issued a joint warning, and NAPIT another: not against plug-in solar, but against rushing it. Their central worry is backfeed — a generator pushing power the wrong way into a ring main, past protective devices that a tired 1970s installation was never fitted to handle.

Follow that worry to its end, though, and it points away from the panel and toward the battery. A solar panel is an uncontrolled source: it pushes out whatever the sun gives and exports whatever you can't use, in the moment, whether the house is ready or not. A plug-in battery is a controlled one — it can meter itself to your own load and needn't spill a watt back to the grid, sitting as a buffer between your house and the network rather than a tap plumbed straight into it. It answers the very concern the panel raises. The people warning loudest about plug-in solar are, without quite meaning to, making the case for plug-in storage.

That's the whole case against the panel, and it's the May case with the numbers filled in. But it's only half the piece, because the interesting product isn't the panel at all.

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The border between the transmission and distribution grid was the grid supply point. These remain a crucial measuring point for Elexon (who manage the settlement of the grid), and provide a consistent snapshot to compare the changes to the shape of the demand around different archetypal areas of the country. Each Grid Supply Point serves a densely populated urban area, or a more sprawling rural one.

What the operator sees

Few things to bear in mind. The National Grid can't directly see most solar installations, or smaller wind farms. Traditionally, they just see the net demand, minus that which has been “disappeared” by the solar that hits the transmission grid; though the distribution networks increasingly have visibility further down that can be shared upward too.

The old world: everywhere looked much the same

In the old world, demand had a predictable shape. A larger evening peak, a smaller morning one. In areas with more business and industry a midday one as well. All in all however, nothing that dissimilar across the country. And they'd move roughly in line with each other as we moved through the seasons.

A revolution that started in the countryside

Most profound technological and social changes start in cities. Solar is an exception; as urban areas lack free space and rooftop availability (flats, terraced houses etc). As a result, the summer demand shape for rural area GSPs is one where for a growing share of the year, they run in reverse in the midday sun.

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I bought my heat pump in the spring of 2022, which is to say I bought it during a war. Russia had just invaded Ukraine, the price of gas was doing things the price of gas is not supposed to do, and I was not sleeping — not because of the news, but because I had a twelve-month-old who had decided that sleep was for other families. So there I was at three in the morning, awake anyway, reading about wholesale gas curves and deciding that the sensible thing to do — the hedge, the geeky thing, the right thing — was to get off gas. A few months later a shiny Mitsubishi Ecodan appeared on the side of the house.

I don't regret it. I want to say that clearly, because heat pumps have somehow become a culture war, and I refuse to file a grievance I don't have. For about nine months of the year mine is quietly excellent. It runs at a seasonal efficiency close to 4 — nearly four units of heat out for every unit of electricity in — and because I've a home battery that buys something like 99% of my power at the cheap overnight rate, my annual heating bill lands somewhere between £100 and £200. I have spent more than that on a single annual service. (That figure takes a battery, a canny tariff and more attention than any sane person gives their heating — a point I'll come back to.) It heats a slightly draughty house on flow temperatures that would embarrass a gas boiler, it drinks my own solar when the sun is out, and — far from forgetting it exists — I treat the thing as a private science project, watching its every degree of flow temperature for the sheer pleasure of the data it throws off.

And then it's July, and I'm awake at three in the morning again. Different baby-shaped problem this time — the problem is that the house is too hot, the windows are open onto still, warm Dartmoor air that isn't helping, and I am lying there acutely aware of one thing: bolted to the side of my house is a large, sophisticated, refrigerant-filled machine whose entire purpose is to move heat from one place to another, and on the one night I would give anything for it to move some heat out, it sits there doing nothing.

You have to picture where this is. My house sits in one of the highest villages in Britain, close enough to the Atlantic to take its weather full in the face — cold, wet, the kind of place where the rain tends to arrive sideways. On paper it is close to the last spot in the country you would ever think to fit air conditioning. In 2022, the idea that I'd be lying awake up here sweating — and in May, not the depths of August — would have seemed faintly absurd. And yet the data tells it plainly. By the only measure that makes sense this high — three days running above 23 °C, which for a village on the roof of Dartmoor is a genuine heatwave — my village has had eight since I fitted the heat pump: three of them this year alone, and none at all in 2024. They seem to be getting both more frequent and more fierce, up here on the high, wet roof of the south-west. That is how fast the ground has moved.

On the worst of those days — the 24th of June — I worked out at the time that, on a "feels-like" basis, it was probably the hottest day my corner of Dartmoor has ever recorded: 31.6 °C on the thermometer, but with the air so thick it felt closer to 36. That gap is the tell. What made it punishing wasn't the heat alone, it was the humidity riding along with it — which, as we'll see, is exactly why a cooling system worth the name up here has to wring the moisture out, not just take the edge off the temperature.

That's the regret. Not that I got a heat pump. That nobody — me least of all — spent a single second thinking about summer.

It's dated in a quieter way, too. Mine runs on R32; the propane units that have arrived since reach hot-water temperatures mine never comfortably will — so where older systems still lean on a resistance immersion to sterilise the tank, a newer one simply wouldn't. Two refrigerants behind, and it can't cool. I bought at the wrong moment in more ways than one.

The three things that don't work

Octopus has started trialling a gadget it's calling, with a completely straight face, the Cosy Cooler — a cooling add-on for its heat pump. Greg Jackson trailed it as one of the most-requested features they get, "for obvious reasons," and he's right, because a heat pump is a reversible machine that already contains everything you need to make cold. So of course I went looking for how to add cooling to what I've got. There are three obvious answers. I tried, or seriously costed, all three. They all fail, and they fail in instructive ways.

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On the evening of 23 June, at seven o'clock, Britain's system price hit £800 a megawatt-hour. We were short of power.

At that moment, Viking Link was exporting 1,140 megawatts to Denmark.

Also at that moment, the electricity system operator was paying £835 a megawatt-hour to stop BritNed exporting to the Netherlands. Grain's open-cycle gas turbine was being paid £496 a megawatt-hour to turn up. And in Scotland, Seagreen was being switched off.

Short of power. Exporting power. Paying to stop exporting power. Paying to turn on a peaker. Switching off a wind farm. All in the same hour.

Nobody in that paragraph did anything wrong. That is what makes it worth writing about.

Here is that whole evening in one chart. Don't decode every band yet — just notice that the wall of the evening ramp is blue, and the blue is Europe.

The instrument nobody counts

When Britain's grid operator wants to reverse a scheduled flow on an interconnector, it cannot simply instruct it. Interconnector capacity is held by traders — the firms that bought it at auction and sold the power on. So NESO goes to whoever nominated the flow and asks them to price buying it back.

It's called countertrading. And it has never once appeared in the Balancing Mechanism, because the counterparty isn't a power station being dispatched — it's a firm unwinding a position. There are, across the whole archive, precisely zero bid-offer acceptances on any interconnector unit.

It surfaces instead in a settlement file called DISBSAD, which names the firm, the link, the volume and the cost, and leaves you to work out the price yourself. It is entirely public and almost entirely unread.

Since November 2021, NESO has spent £616 million buying back scheduled British exports. Some 2.3 terawatt-hours of them, at an average of £268 a megawatt-hour, across 47 counterparties.

If you want to know whether the numbers are real: the single most expensive trade in the file is £9,724.50 a megawatt-hour, paid on Nemo Link on 20 July 2022, the day Britain hit 40°C. That's the number that made the papers. It's in there, recoverable, alongside £35 million of interconnector spend on that day alone.

That day was the energy crisis, not the norm — take it as proof the file is real, not that £9,724 is typical. The structural story is in the quieter years since.

Now let me take the obvious story away from you

You would expect this to be rising. It isn't. As a share of the exports the market actually scheduled, buy-backs have fallen — 5.3% in 2022, 1.9% so far this year.

You would expect it to be summer. It isn't. May to September accounts for about 40% of the volume, which is roughly what the calendar predicts.

What it is, overwhelmingly, is teatime. At six in the evening, 29.6% of scheduled exports get bought back. At three in the morning, 2.8%.

Widen the lens to the whole year and the whole day and a second pattern surfaces: NESO runs two opposite operations. It buys exports back in the morning and evening peaks — the move that costs the money — and it sells surplus back out overnight and at midday, which earns almost as much as it spends. Only one direction is expensive, and it is the teatime one.

And in about two-thirds of the hours where NESO buys an export back, Britain is short — the system needs more power, not less. This is not, at root, a story about surplus wind with nowhere to go. It is a story about the market scheduling exports at the exact hours Britain needs the electricity, and someone having to pay to undo it.

That is what leaving the EU's day-ahead market coupling bought us. Interconnector capacity is now auctioned separately from day ahead price auction (discovery). So flows can run against the spread. And if the grid operator wants to reverse this, especially if the reason for changing the flows is because of domestic transmission constraints, it can end up picking up a bill for it.

The rollercoaster behind teatime

The buy-backs land at teatime all year round. But the shape of day that makes teatime dangerous is a summer thing — and it is getting more violent.

Take a clear day in late June. At midday the South East is barely calling on its own generation at all: three gigawatts, sometimes less. Cheap continental solar is pouring in across the Channel, embedded panels are working behind the meter, the interconnectors are running flat out as imports. The region is coasting.

Then the sun goes down. Solar collapses, the imports swing to exports, demand climbs — and the call on generation that was three gigawatts at noon is twelve by eight o'clock.

That swing, trough to peak, has doubled with the seasons: two and a half gigawatts in midwinter, five and a half in June. On 27 June this year it hit 12.5 gigawatts in a single afternoon — steeper even than the 23rd. Run that same picture as a rolling average across three years and you can watch the midday floor drop away every summer and climb back every winter.

And the intuition is backwards. The evening peak isn't higher in summer — it's lower. A January teatime draws more power than a June one. What makes midsummer extreme is the floor falling out at midday: the trough drops from ten gigawatts in winter to three and a half in June, hollowed out by solar and imports. The ramp is steep because the floor collapsed, not because the ceiling rose.

Nor is it mostly a British demand story. Split the day into local demand and the interconnector swing, and in June about sixty per cent of the ramp is the interconnectors — European solar flowing in at noon and back out at dusk. Local demand does the smaller half, and barely moves with the season.

One honest note on that "demand": it is metered at the grid supply points, so it is already net of Britain's own embedded and rooftop solar. The domestic half of the ramp is therefore demand and our own solar fading out at dusk — not demand alone.

It is a flexibility problem wearing a capacity mask. Nobody is short of megawatts at midday. Britain is short of the machinery to climb from a three-gigawatt afternoon to a twelve-gigawatt evening — which is precisely the manoeuvre that jams the boundary and pulls in the buy-back. And it is exactly the manoeuvre a battery is built for: fill up on the midday glut, empty into the teatime wall. The single clearest thing Britain could do about any of this is build — and use — far more storage, sited where the ramp actually bites.

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I crossed the VAT threshold faster than I’d dared plan for — a good problem to have — and discovered that trying to hand HMRC more tax was the single hardest piece of admin I’ve done all year.

There is a particular kind of problem that only arrives when things are going well. You spend years worrying about whether there’s enough work — and then one quart…

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On 23 June this year it earned its place on the list. A hot, still afternoon, a grid visibly under strain, and — for once — people asking out loud whether the two were connected. That question turns out to have a more interesting answer than either side of the row assumed. So let's ask it properly: can Britain's grid actually cope with the heat?

France supplies the version that makes the front pages. Its nuclear fleet sits on rivers — the Rhône, the Garonne, the Loire — and when those rivers warm past their environmental limits, the reactors have to throttle back to avoid cooking the water downstream. Across the 2026 season, EDF's own outage register shows French reactors filing 43 environmental-restriction shutdowns on river sites, 5 on the Blayais estuary, and zero on the coast. Same operator, same regulator, same heatwave. The only variable was what the reactor uses to shed its heat.

And it isn't only the reactors. The same hot, dry summers that warm the cooling rivers drain the reservoirs behind them — back in 2022, hydropower slumped from the Alps down into Norway as the drought bit. Water is continental Europe's quiet exposure to the heat, whether it's cooling a reactor core or spinning a turbine.

So: can Britain's grid cope? The honest answer is yes — comfortably — and mostly by accident. Which is the good news. It's also, as we'll get to, the problem.

First, the reassurance: it won't melt

Britain drew three lucky cards, and they're worth understanding before we ruin the mood.

The first is that every nuclear reactor we have sits on the coast, cooled by the sea. The sea is a spectacular heat sink: it barely warms across a single hot day, and — the part everyone misses — it peaks weeks after the air does. Put 45 years of satellite sea-surface temperature next to the Central England air record and the lag is stark:

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And I thought what I suspect a lot of people think: whatever this house saves you on energy, it hands straight back to the council.

I was half right — and you don't have to take the anomaly on faith, because the neighbours make it concrete. A few streets away, a conventional 1960s bungalow of much the same size sits in band C. Down the hill, a four-bedroom gas-heated semi — a bigger house — is band C too. The three-bedroom Passivhaus, with the smallest bills of the three, is band E: two rungs above the four-bed. Fewer bedrooms, near-zero heating, more council tax. And in this part of Devon those two bands are worth about £820 a year — roughly what a Passivhaus saves on energy against a gas home. On the running costs, in other words, the tax very nearly eats the saving. My eye had done the arithmetic correctly.

But it had drawn the wrong lesson. The band isn't high because the house is big — it's small. It's high because council tax is a tax on value, and a premium eco-build is worth more per square metre than the tired stock around it. The council tax is real, and on the running costs it genuinely bites — but set against what that house costs to own, it's a rounding error. The number that makes it expensive isn't the band. It's the one I'd glanced past: the £595,000 price.

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Not because I'm clever. Because I'm the sort of person who has a grid-frequency meter in a cupboard on Dartmoor.

It's not a special meter — it's the energy monitor that came with my solar-and-battery setup, sitting on the wall next to the fuse box, quietly logging the frequency of the national grid every minute of every day. And grid frequency is the one number a person in a cupboard can hold the whole country to account with. On a synchronous AC grid, frequency is the same everywhere at once: the reading on my wall in Devon is, to a rounding error, the reading in the National Energy System Operator's control room 150-odd miles away. If NESO's official record said one thing and my meter said another, that would be a story.

So when the shadow energy secretary told Parliament that a whistleblower inside NESO had described managers keeping decisions off the books, and that the grid on 23 June had been less secure than the official version admitted, I had — unusually — the means to mark their homework. Both of them.

I went looking for a cover-up. I found something more interesting, and in the end more damning: the establishment's data was honest, the grid held — and the reason it held is the scandal nobody is shouting about.

What the meter saw

Here is 23 June on my meter, set against every other evening that month.

It's the worst-looking evening of the lot. From about ten to seven the frequency sags and stays sagged, wandering below the 49.8 Hz line that NESO treats as its operational floor, and around eight o'clock it touches what my meter reads as 49.6 — the lowest point of the entire month. If you wanted a picture to accompany the words "the grid was in trouble and they didn't tell you," this is it.

For about a day, I thought I had one.

The twist

The honest thing to do with a suspicious-looking home measurement is to check it against the professionals'. NESO's second-by-second data doesn't publish until a month after the event, but Elexon — the market's referee — carries the same official frequency at 15-second resolution, and it is available. (It's also, as it happens, exactly the source the energy analyst Kathryn Porter used for her own well-aired critique of that evening. Hold that thought.)

So I overlaid the two.

They agree. Not roughly — a correlation of 0.977, the same shape, both bottoming at the same minute around eight o'clock. My cupboard genuinely tracked the national grid. But the official curve is a little kinder than mine: the true minimum wasn't 49.6, it was 49.656 Hz — a real dip, but one that stayed clear of the 49.5 Hz statutory floor and miles from the 49.2 Hz at which the grid automatically starts shedding load. My meter reads about 0.05 Hz low, and because it reports in coarse tenths, it over-states how long frequency spent under each threshold. My eye-catching impression that it sat under 49.7 Hz for the best part of an hour? Below that line the true figure is nearer two minutes.

Which is a small humiliation with a large lesson. A £100 meter in a cupboard can tell you, remarkably well, when the grid wobbled and what shape the wobble was. It cannot tell you it breached a limit it didn't breach. The frequency is not the scandal. If anything, my amateur kit made the evening look worse than the professionals' did — the opposite of a cover-up.

So which side do you take?

You can't answer that until you're precise about what Coutinho actually alleged, because most of the coverage wasn't. She made two specific claims. First, that NESO managers told staff to work in "live documents with no version history," creating no permanent audit trail — to keep records from being preserved for Freedom of Information requests. Second, that NESO's corporate affairs team interfered in control-room decisions to protect the organisation's reputation. She's referred it to the Information Commissioner in a 7 July letter. NESO denies it; the energy minister, Michael Shanks, called it "scaremongering."

Here's the thing readers need and the shouting obscures: those are claims about NESO's internal records and motives, not its published data. So my meter — and every public dataset — can settle some of this cleanly and is simply blind to the rest.

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Three anniversaries, one tight evening. On the night Britain's grid looked its most antique — hauling half-century-old peakers off the bench to keep the lights on for the football — it was quietly doing something brand new: exporting flexibility into a sweltering continent. This is the story of that evening, read straight off the half-hourly data — what the grid did, who got paid, and why the ending is more hopeful than the start.

How continental flows differ

Conventional wisdom says the evening peak is when Britain leans hardest on its neighbours — demand up, solar gone, imports maxed. The data for the month to 24 June 2026 says the opposite. GB pulled +6.1 GW net across the interconnectors at midday and only +2.4 GW at the evening peak.

Where the swing actually lives

Split the links into four blocs and the puzzle dissolves. France (IFA · IFA2 · ElecLink) sits pinned at ~+2.8 GW in both windows. Norway's North Sea Link barely moves. Ireland stays a steady GB export. The entire midday-to-evening collapse is one bloc:

NW Europe — BritNed, Nemo, Viking — goes from +2.7 GW to −0.7 GW. A 3.4 GW reversal.

These are the Dutch, Belgian and Danish links: short, price-responsive, and wired into markets whose evening peak is steeper than ours. When their prices climb into the evening, the arbitrage flips and British electrons head east.

The heatwave tell

Why do those three links matter for a heat story? Because they are the ones that respond to continental conditions — and the month ended in a heatwave.

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Problem Statements

First, it's worth trying to summarise all the constraints around the problem.

Pushing levies into General Taxation is fanciful.

In conversations with other attendees after, I made myself a bit of an outlier for disagreeing strongly with the prevailing thought in the room, that energy levies should be put into general taxation. I have long thought this is pretty tone-deaf to the broader macroeconomic picture.

While preferences vary around the political spectrum, most voters and politicians want to spend public money on areas like the NHS, pensions or defence. Very few people want the bulk of energy costs to be subsidised. While some advocate for a more active state (e.g. public ownership) and some redistribution e.g. social tariffs, most people expect the energy industry to broadly pay its way.

Saying, "we have a problem with levies", and "we can't find a way to replace them that isn't really regressive" isn't really good enough. I get that the tax system is overall more progressive, and direct taxes on income are less inflationary. But it's incumbent on us in industry to find solutions and pay our own way in the wider economy. Plus, sensible charges are an opportunity to incentivise behaviour and reduce the overall cost of the energy system that we simply couldn't have if most of the costs were lumped into income tax or general VAT.

Standing Charges are more regressive than Council Tax

On the face of it, fixed or standing charges, especially for residential consumers have a certain economic appeal. Assuming they don't deter homes from disconnecting from the grid entirely (for gas or electricity), they don't distort the amount of energy consumed.

However, in reality I totally get why MPs (from the governing Labour party in particular) really hate standing charges:

Above Inflation But Sticky Downward

They've shot up far beyond general inflation. Even though they don't ostensibly cover wholesale energy costs, they spiked most perniciously in the aftermath of the 2022 energy crisis, at the worst possible time when the rest of the bill was also spiking due to the conflict in Ukraine. Worse still, once up they've been remarkably sticky to come back down (in contrast with tariffs per unit). TLDR, much of this is to bailout suppliers with high consumer indebtedness that hasn't recovered since 2022.

Rich vs Poor, Big vs Small

It's often said that Council Tax is pretty regressive; but at least within the same area a band H home will pay ~3 times more than a Band A property. For electricity, the occupant of a 1 bed flat in Liverpool pays the same £255/year standing charge as a castle in North Wales; a cross-subsidy nobody would advocate.

North vs South

Standing charges are set at a "regional" level, according to boundaries that were set not even when electricity was privatised in the 1990s, but how the post-war nationalised grid was grouped in the 1940s. This gives rise to very illogical arbitrary boundaries. MPs are right to feel aggrieved that standing charges in Liverpool are £255/year while more affluent Londoners pay £163/year.

Merseyside pays ~58% more than London (£258 vs £163/yr) for the same home, before using a single unit. Source: Ofgem default tariff cap, Jul–Sep 2026.

Just tax gas screws over tenants

I confess, I used to think this was the solution. We tax gas a lot for power generation, but not in homes. Now we could tax residential gas, redress some of this imbalance, improve the "spark-gap" that deters heat pump installations.

For homeowners with resources, this carrot and stick might drive heat pump retrofit over time. But for tenants (or homeowners without spare £5,000-10,000 for a heat pump), especially privately renting ones, it's naive to think most landlords are going to rush to buy heat pumps. In theory, landlords fitting heat pumps should be able to capture higher rents over time. But that assumes tenants accurately compare the running costs of homes and negotiate proactively on rents at the start and on renewal of tenancy. I'm not sure this has ever really been the case, and it's especially doubtful after the recent renters' reforms.

Taxing gas usage ignores the principal agent issue, and would if anything, disenfranchise a more vulnerable cohort of the population, and at the margin hinder their savings rate and ability to get onto the property ladder.

70% of GB air-source heat pump installations go to owner-occupiers; private renters are barely served. Source: MCS Data Dashboard.

Gas is a poor taxbase

There are more reasons gas is a poor choice for a levy (tax base), especially from domestic consumers. First, the demand is far more seasonal than electricity, cashflows stack up in the winter and the system almost goes dormant in the summer (serving hotwater and cooking but little else). Second, winter demand varies significantly, 10-20% year on year depending how cold a winter we have; setting tariffs in advance of the winter risks a cashflow/budgeting problem if the costs of the renewable system are largely fixed in advance, but the weather radically changes the levies raised. Third, gas has an uncertain long-term future, at least if we succeed in decarbonising. Tax regimes are notoriously hard to unwind once entrenched, and I can understand why a prudent, long-term-focused Treasury official would be reluctant to repeat the fuel-duty trap: building a major revenue stream on a commodity we're actively trying to phase out, then watching the receipts erode while finding it politically near-impossible to raise the rate or replace it.

GB gas demand for heat — excluding power generation — swings sharply with the seasons while its annual total falls steadily (~800 TWh to ~490 TWh). Both are awkward properties for a tax base. Source: DESNZ Energy Trends.

Volume based grid levies are backward

Our energy system was built and privatised at a time when fuel in some shape or form accounted for the majority of bills, both for gas and electricity. As recently as 2010, raising levies per kwh was a rough and ready way to share the burden according to how much consumers used. However since then, the traditional assumptions have one by one fallen away.

From coal and gas to wind and solar: the mix that per-unit levies were designed around has been turned inside out. Source: DUKES 2025, Table 5.6.

Tax Avoidance Behind the Meter

The collapse in PV costs means better resourced homeowners and businesses can bypass the grid entirely for much of the year; and it's not credible to implement the equivalent of a window tax or levy on self-generation. This mindset can be extended to broader "private-wire" agreements that bypass grid levies for entire industrial estates, or datacentres. Either way, such privileged users contribute less but rely on the grid more when it's most expensive to run i.e. in winter.

~8 GW of sub-50kW rooftop solar (domestic + commercial) now sits behind the meter — invisible to the grid records we celebrate, and largely beyond the reach of per-unit levies. Source: DESNZ Solar PV deployment.

Interest Rates have exploded

The pivotal decarbonisation decisions taken in the 2010s naively assumed interest-rates and inflation would stay low. The reality since 2022, has alongside record material inflation for steel, copper, transformers and turbines raised the cost of the electrified grid relative to earlier expectations, and relative to traditional fossil fuel options, at least outside the most extreme fuel price spikes. Even Government gilts costs are under pressure.

After a decade near zero, borrowing costs repriced sharply from 2022 — raising the cost of a capital-heavy grid. Source: Bank of England.

Not all energy volumes create an equal burden

When most electricity came from gas (or further back, coal) produced in Britain, it didn't massively matter when in the day/year it was consumed. With the decline of the North Sea and shift to renewables, the cost of energy, especially at the margin, is increasingly concentrated into periods with low wind and solar. This is especially true in winter as we electrify more heating demand. However, the levies we pay are generally smeared across broader seasons (or years), a situation increasingly untenable.

UK gas production has fallen from 108 bcm (2000) toward ~3 bcm by 2040, leaving imports — especially LNG — to fill the gap. Source: NSTA; cf. NESO Gas Security of Supply Assessment, 2025.

The Inflation Circularity and Cost of Living

Energy is a major inflation basket item, and many households on Ofgem price-cap tariffs have their bill prices set administratively. As Government's own outgoings are largely inflation-indexed (gilts, welfare, public sector payroll), radical energy levy reform has knock-on effects to other sensitive policy areas that losers will hold Government accountable for.

Energy's weight in the CPIH basket spiked in 2023 — energy-price shocks pass straight into headline inflation. Source: ONS CPIH weights.

Levies are Complex

Energy levies are, like the tax system more generally a byzantine patchwork of charges that have evolved incrementally. Governments have used them as an "off balance sheet" way of financing welfare programmes like the warm home discount. Residential customers (who can vote!) have gotten off light compared to businesses, and electricity consumers have been burdened more than gas customers. Worst of all, insiders with the best consultants can, like tax advisers/accountants, limit the levies without adding that much social value, leaving a bigger burden for the less well equipped/advised.

Better Alternatives

How do we raise the money needed to keep the energy system going, fairly and without deterring the energy transition or economic growth?

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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 h…

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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.

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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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