Energy roundup · Richard Lyon

The Week in Energy — 3 October 2026

Sat, 03 Oct 2026 00:00:00 GMT

Four official papers from the past three weeks said one thing in the headline and another in the notes underneath: a factory discount, a new grid company, a grid penalty set at nothing, a buy-British rule. An Oxford economist called the bill fixes rearranging the deckchairs. Then two bills that arrive regardless: diesel at £2 and January’s price cap.

The factory discount. On 1 October the British Industrial Competitiveness Scheme opened, promising manufacturers up to 25 per cent off their electricity from April 2027. It excuses them from three charges on the bill: two older renewable-power subsidies, and the payments that keep power stations on standby. The government’s own impact assessment says why: for a very large factory, policy charges come to about £61 a megawatt-hour, 27 per cent of the bill, against about £2 in France. Eligible firms, most of them small, will save £35 to £40 a megawatt-hour. Without a plan, it says, ‘suppliers would pass the cost of the exemption onto other consumers.’ The plan: scrap a British carbon tax on power stations from 2028, let the old subsidies rise more slowly with inflation, and have taxpayers cover the rest. The discount doesn’t make electricity cheaper to produce. It changes who pays for it.

The new grid company. On 29 September the Prime Minister announced Great British Grid, a publicly owned company to speed up grid connections. Three private companies already own Britain’s onshore high-voltage grid; the new one will compete alongside them for new lines put out to tender. The government’s own notes say ‘the role of existing network operators remains unchanged’, and its long-term budget waits for ‘a future spending review’. Four days earlier NESO, which hands out connection offers, had asked the regulator for another month, its second request. Most of the late offers were National Grid’s: up to 37, about a tenth of the total, held up by ‘complexity and engineering considerations, such as further network redesign’. Those offers wait on National Grid redesigning its own network. A fourth company bidding for future lines can’t do that for it.

The £0.00 penalty. When a grid company misses its promised date to connect a wind farm or factory, the contract can set a daily payment for the delay. Ofgem, the energy regulator, has looked: those payments are ‘predominantly set to £0.00 per day’, and it lacks ‘comprehensive data on their prevalence or the reasons for individual values’. Lower down the network, where payments do exist, customers called them ‘token payments’. Ofgem now says it will bring in a minimum above zero. Until then, it’s the customer kept waiting who carries the cost of the delay.

The buy-British rule. On 14 September ministers laid draft guidance telling Ofgem to weigh British jobs and factories when it approves grid spending. Paragraph 29 admits the risk: ‘The government recognises that this may come with a short-term cost trade-off.’ The government hasn’t put a figure on it: its explanatory memorandum says procurement guidance needs no full impact assessment, and calls the effect ‘challenging to quantify’. A government promising lower bills has admitted in writing that this rule may raise them, and hasn’t worked out by how much.

The economist’s verdict. On Friday Dieter Helm, professor of economic policy at Oxford and no climate sceptic, dismissed the government’s bill fixes in The Times: ‘A temporary VAT cut, some public money into a new Great British Grid and switching some subsidies from customers to taxpayers does not alter the costs. Nor do industrial energy subsidies. Rearranging the deckchairs will not make these high costs go away.’ He says they are ‘locked in through to the end of the 2030s’. Helm wants warming tackled and carbon priced; it’s Britain’s 2030 target and its wind-and-solar route he says are wrong. He also names a reflex he doesn’t share: ‘We don’t want to pay a carbon tax. We want energy subsidies, not energy taxes.’ This month delivered both: from 2028 the factory discount is part-paid for by scrapping a carbon tax on power stations.

The diesel bill. Diesel passed £2 a litre for the first time this week, on RAC figures; the transport minister insists there’s no shortage. In August, the government’s own figures put British diesel mid-table in Europe, ninth cheapest of fifteen. The price isn’t uniquely British. The exposure is. Britain now imports 54 per cent of its diesel, against 16 per cent in 2000, says the refiners’ trade body, after four refineries closed. America supplies nearly a third of those imports, and President Trump says he is thinking about an export ban ‘very seriously’. The war sets the price. The refineries we let close decide how exposed we are to it.

The January bill. Cornwall Insight, a leading forecaster of the price cap on household bills, expects it to rise 16 per cent in January, to £1,999 a year; September’s price rises are ‘already locked in’. On its forecast unit rates, electricity costs 3.1 times as much as gas, so a heat pump must turn each unit into about 2.8 units of heat just to match a 90 per cent efficient boiler. Its consultant Craig Lowrey comes down against easing off, but concedes ‘there are fair arguments on both sides about whether the transition should slow down given the current affordability concerns’. When a forecaster concedes that much, the question has become respectable.

The Energy Trap pattern. Each of the four papers promised speed, savings or growth. Three recorded, in their notes, a cost and who would carry it: taxpayers and subsidised generators for factories, bill-payers for British suppliers, the waiting customer for a late connection. The fourth left its bill to ‘a future spending review’. The book argues the transition’s costs are real whether or not anyone owns them, and moving them isn’t shrinking them. This month the official paperwork conceded the first half, and Dieter Helm said the second out loud.

The Week in Energy — 26 September 2026

Sat, 26 Sep 2026 00:00:00 GMT

This autumn gas bills jumped by a third while electricity rose far less. A research foundation that backs the transition explains why, and why the same mechanism stops electricity getting cheaper when gas does. Then an old subsidy shrinking, a chemical works pausing, a heat pump grant falling behind, the world’s renewables’ cost table that omits Britain, and a minister’s doubts about affordability.

The gas link. From October a typical household gas bill will be 33 per cent higher than in April, £200 a year more. Electricity is up 4 per cent, or 9 per cent without the VAT cut. The popular explanation is that wind and solar push gas off the grid. Andrew Sissons of Nesta, a research foundation that supports the transition and the source of those figures, says not: ‘Electricity spot prices have generally increased in line with gas prices.’ What supposedly holds bills down is Contracts for Difference, which guarantee a wind or solar farm a fixed price; on the rare occasions when the market price rises above it, the farm pays the difference back. But he states the other side himself: ‘If gas prices were to fall significantly, we should not expect electricity prices to follow them. Electricity is increasingly a fixed cost system.’ The hedge that softens the rise also blocks the fall, because more and more of the bill is what was spent building the system.

The old subsidy. The Renewables Obligation, the older of Britain’s two big renewable subsidies, makes every supplier hand in certificates, bought from renewable generators, for each unit it sells, and the cost goes on bills. On 25 September the government set next year’s rate, and the good news first: it falls from 0.472 certificates per megawatt-hour to 0.369, over a fifth fewer, mainly because many generators reach the end of their fixed support period next March. Then the catch. If the law is passed in time, more manufacturers will be exempted from April, and the department publishes the effect: the rate becomes 0.394, about 7 per cent more on this part of the bill for every customer not exempt, though still below this year’s. A cost taken off one group doesn’t disappear. It moves to whoever is still paying.

The Hull plants. On 22 September Ineos said it would pause production at its three chemical plants in Hull, keeping staff on while it tries to buy cheaper American gas directly or waits for prices to fall. They make chemicals for aspirin, paint and decaffeinated coffee, and are Europe’s last world-scale plants of their kind. Its chairman, Sir Jim Ratcliffe, puts the gas it pays at twelve times the American level. That figure is his: the trade press quotes the European benchmark at $26–27 per million British thermal units against $2.80–2.90 in America, a little over nine times. Either way, a plant that uses gas as a raw material can’t close that gap. The government pointed to £350 million of co-investment, to trade measures on imported chemicals, and to schemes that cut manufacturers’ electricity costs, one of them the exemption that raises the rate for everyone else. None of that touches the gas price, or the carbon tax, that Ineos blames.

The heat pump grant. The Boiler Upgrade Scheme pays most households £7,500 towards swapping a boiler for a heat pump, a device that pulls warmth from the outside air instead of burning fuel. That’s 58 per cent of the typical job. August’s figures set a record: 3,260 installations paid for. The scheme aims for 390,000 installations in the five years to March 2030. It has paid for 44,381, so it now needs about 8,000 a month, two and a half times the record, from now on. It also aims to cut the real cost of an installation by 20 to 25 per cent. So far it has fallen 11 per cent after inflation, but only 4 per cent in cash, while the typical heat pump fitted has shrunk from 10 to 8 kilowatts. The cheaper jobs are partly smaller jobs, so the day the grant can stop keeps receding.

The cost table. The OECD’s Nuclear Energy Agency and EPRI, the American power industry’s research institute, publish the standard international table of what each kind of power station costs. This month’s edition finds that new onshore wind and solar farms have stopped getting cheaper: ‘compared to past editions, no significant further cost decreases have been observed.’ They come in under $100 a megawatt-hour only ‘as long as their system costs are excluded’: the backup, storage and extra cables needed because wind and sun come and go. Twenty-one countries sent in their costs. Britain, a member of the agency, sent none. The best international check on what wind and solar cost has no British numbers in it.

The minister. In New York the Energy Secretary, Miatta Fahnbulleh, said that ‘unless we have clean power driving the system more often, we’re not going to get that impact in terms of bills.’ On the grid: ‘I’m not sure we’ve given the same attention to affordability.’ Her department’s cost figures count on building a solar farm getting about a fifth cheaper between 2023 and 2030. The table Britain stayed out of finds that fall has stalled, and that the estimate omits the system cost. Without that cut, clean power costs more than her department has pencilled in.

The Energy Trap pattern. More and more of the bill is fixed: contracts and cables paid for whatever gas does. Those costs fall when support periods end, not when prices do. The government’s sums count on solar farms getting cheaper to build; the one international check says they’ve stopped, and Britain’s numbers aren’t in it. So the lever the government keeps reaching for is who pays: VAT and some levies moved off bills onto taxpayers, and households picking up the share of manufacturers being exempted. Moving a cost isn’t cutting it.

The Week in Energy — 20 September 2026

Sun, 20 Sep 2026 00:00:00 GMT

This week the Bank of England told the government, in writing, roughly what your family’s energy bill will do this winter: up a little before Christmas, then up by about a quarter in the new year. The rest of the week’s official papers explain why help is so far away.

The Bank’s letter. When inflation rises more than one point above the 2 per cent target, the Governor of the Bank of England must write to the Chancellor explaining why. Inflation hit 3.1 per cent in August, so on 17 September Andrew Bailey wrote that letter. The important part looks ahead: based on the current market price of gas and electricity, the Bank expects the energy price cap — the limit Ofgem, the energy regulator, sets on what suppliers can charge a typical household — to rise 4 per cent this autumn and a further 24 per cent in the new year. The one bit of help this winter is that VAT comes off electricity bills in Great Britain from 1 October — the 5 per cent tax drops to zero, worth about £45 a year to a typical household. But nothing got cheaper: the tax is suspended for six months, and the roughly £850 million the Treasury will not collect is carried by the public finances instead. The charge moves from your bill to the public purse; it does not get smaller.

The grid report. Britain is spending £70 billion over six years on bigger electricity pylons and cables, to carry wind power from Scotland to the cities. You pay for this through your bill: the “network” part of a typical household bill rises from £44 a year now to £104 by 2031. This week the National Audit Office, the state’s own spending watchdog, reported that nobody ever wrote a business case for the £70 billion as a whole — because it sits on bills rather than in taxes, it never had to pass the tests government spending normally does. Ofgem says the spend will still leave a household about £30 a year better off by 2031, but only if three big cable projects are sped up. The watchdog checked: none of the three has been sped up. So the extra charge is already arriving, and the saving depends on work that is not happening.

The £35 million day. Here is why those cables matter. When it is very windy in Scotland, the wires can’t carry all the power south. So the system operator pays Scottish wind farms to switch off, and then pays gas power stations in England to switch on instead. Yes — we pay twice for the same electricity. On Tuesday 8 September this cost £35 million in one day — a record, about three times a normal day, beating a £32 million record set the Friday before. The operator said it would be wrong to draw conclusions from a single day. Agreed — draw them from the record instead. These payments have tripled since 2019. The operator itself named the three cable projects that would cut them, back in November 2024. The watchdog has just confirmed none has been sped up, and forecasts the cost reaching £6.6 to £7.8 billion a year by 2030. A record day is the going rate for work the operator asked for and has not received.

The battery queue. Companies that want to connect a big battery to the grid join a queue. The plan needs at most 29 gigawatts of batteries by 2035; the queue holds 83 gigawatts, nearly three times as much, because joining costs nothing and the planners must design the network as if every project in the queue will really be built. When a project quits, the wasted planning and building lands half on consumers — about £460 million so far, on Ofgem’s own sums, and it says the true figure is probably higher. The proposed fix is a deposit of up to £25,000 per megawatt, refunded when a project actually connects. Real projects lose nothing; paper ones finally pay. And that “full” plan is small against the need: Britain’s grid batteries hold one to two hours’ charge, so 29 gigawatts stores about 58 gigawatt-hours, where the Royal Society — from 37 years of real weather — puts the storage a wind-and-solar Britain needs at up to 175,000 gigawatt-hours, ‘far more than could conceivably be provided by conventional batteries’. Batteries move power from a windy afternoon to teatime; they do not get Britain through a calm fortnight in January, let alone a low-wind year.

The smart-appliance delay. The government’s plan for coping with expensive winter evenings is “flexibility”: electric heaters and heat pumps that can shift when they use power, away from the 6pm peak. The other word for this is “rationing”. The rule requiring new electric heating to be built this way was meant to be in force by the end of 2027. This week the government pushed it to the end of October 2028 at the earliest — and the regulations behind it still have not been written. So the tool designed to soften high prices now arrives at least ten months later, while the high prices arrive in January.

The auction. In October the government runs its yearly auction, where wind and solar farms bid for guaranteed electricity prices. A consultancy called LCP Delta reckons this round could knock £51 billion off wholesale electricity costs — but the guaranteed prices paid out to the wind farms take back £38 billion, balancing the system another £2 billion, leaving a net benefit of £11 billion. That £11 billion is a small gap between two enormous guesses, and the consultancy admits the result swings on its assumptions. Its own bottom line for an ordinary household: a £5 a year saving. Why not celebrate with a bacon roll (before bacon rolls cost more than £5, obviously)?

The carbon refund. Power stations that burn gas must pay for their carbon emissions, and that cost is passed into every electricity bill. How much? The government publishes a precise number, but only in one place: the scheme that refunds this cost to big factories that might otherwise leave Britain. The number is £32.04 per megawatt-hour — about 3.2p on every unit of electricity you use. Last year the government refunded £146.8 million of it to 115 companies: paper mills, steelworks, chemical plants. Households pay the same 3.2p on every unit. There is no scheme for you.

The pattern. The bill rise is printed in a letter and dated. The help — the cables, the smart heaters, the auction savings — is late, small, or depends on work not yet started. And the one cost the state can name to the penny is the one it gives back, to companies, not to you.

The Week in Energy — 13 September 2026

Sun, 13 Sep 2026 00:00:00 GMT

Eight documents sat on the desk this week, three of them published in it and the oldest more than a year old. They sort into two kinds. Costs that need nobody’s agreement arrive on schedule and in full. Everything requiring several institutions to act together — a connection offer, a network reinforcement, a reliability standard the auditors have twice asked the department to revisit — is late.

START WITH the Renewables Obligation. DESNZ’s monthly certificate table, updated on 10 September, records 110,024,437 ROCs issued in 2025/26 against 101,458,858 the year before, a rise of 8.4 per cent on generation up 8.0 per cent to 80,829 GWh. Only 2019/20 was larger, and the latest year is provisional until October. At the 2025/26 buy-out price of £67.06 that is roughly £7.4 billion of certificate value, and it understates what a generator receives, since a ROC is worth buy-out plus the recycle payment. Ofgem’s own figure for the obligation, on a forward basis, is £8.7 billion, quoted in an annual letter as the denominator for a 0.12 per cent administration fee. The volume is fixed by twenty-year accreditations running to 2037, and it rose because generation rose, which is what an output-based subsidy does when the plant is built and the wind blows.

On the same day the department published who pays. Its first quarterly report on the Renewables Obligation to Exchequer scheme puts expenditure from 1 April to 30 June 2026 at £520,709,288.19 in Great Britain. The measure ‘removes 75% of Renewables Obligation costs from domestic electricity bills, with these costs instead funded by the Exchequer’. Nothing about the obligation changed; only the payer did. The Budget 2025 costing runs to £6.9 billion of relief across three years, then nothing from 2029-30. Carbon Brief’s factcheck of Reform UK, published next day, is right that green levies ‘are not the drivers of recent price rises’ and right to note, in a bracket, that ‘a chunk of policy costs have recently been moved off bills into general taxation’. That bracket is why this year’s levy line looks smaller. It is a reprieve, not a reduction.

Then the value-for-money question. Ofgem found no evidence of obviously poor spending, and NESO came in £4 million under plan at £686 million; but under a pass-through model the burden is on NESO to show what the money bought, and across the majority of that spend the regulator saw limited positive evidence, in many areas ‘descriptive evidence of need without options or benchmarking’, in some ‘largely limited to the provision of organograms with team descriptions’. It could not conclude value for money had been demonstrated. NESO reported that inter-trips, pathfinders and outage optimisation saved £514 million that would otherwise have fallen on bills; Ofgem found limited evidence to support the figure. Value for money was graded below expectations. The overall grade was met expectations.

Connections is the one objective of eight that failed outright, and the one Clean Power 2030 turns on. On NESO’s own account, accepted by Ofgem, the queue fell from roughly 750 GW to 200–250 GW: the reform working on its headline measure. Underneath it, deliverables were ‘missed or delayed, some by over one year’, Gate 2 to Whole Queue went back to March 2027, and 69 per cent of survey respondents graded NESO below expectations. In Ofgem’s own voice, the connections portal ‘experienced numerous technical and usability challenges that could have been mitigated at the time’. A shorter queue is not a faster connection.

The Panel of Technical Experts, which audits NESO’s capacity forecasting for the department, found the register of future connections no longer good enough to forecast from: ‘the TEC register has not been sufficiently up to date this year for a reliable forward view’. It signed the auction off as reasonable in the circumstances, modelled on December 2025 data. Its more durable finding is what these auctions buy. The three-hour loss-of-load standard was set in regulations in 2014, but ‘since 2014, the revealed preferences of both NESO and the Secretary of State have been for a higher level of security’, and a discretionary premium was again added above the modelled result. Parliament set a standard. Twelve years of ministers have quietly bought a stricter one, and the Panel has twice asked for a formal framework governing that choice.

NESO’s balancing costs report, published June 2025, supplies the forward number and calls its projections ‘not a forecast or an accurate prediction’. On that basis costs rose 10 per cent in 2024/25 on thermal constraints, as Scottish outages meant to raise transfer capacity coincided with high wind, and are ‘expected to rise in the short term, reaching a peak of ~£8bn in 2030’ — a peak that ‘can be avoided, delivering savings of up to ~£4bn in 2030, if critical network projects are brought forward’. Both numbers come from one scenario. A £4 billion swing rests on network delivery to time, and the delivery record it depends on is the one Ofgem has just failed.

Against that, the part of the transition where a household chooses went both ways at once. DESNZ’s deployment statistics record 20,895 retrofit heat pump installations in the first half of 2026, ‘a 22% fall compared to the same period in 2025’, against a Warm Homes Plan aim of 450,000 a year by 2030. Only London and Northern Ireland grew, the latter from nine installations to 36. The count excludes new build and uncertified retrofits, so the national total is higher. The direction is what it is good for, and it is down.

Solar went the other way. There are now 23.0 GW across 2,105,000 installations, up 286,000 in twelve months, ‘the most in any 12 month period’ — uncoordinated decisions arriving faster than anything here that needs a committee. Then the department’s own caveat: ‘The bulk of Solar PV installations in the UK are domestic but they only account for 30% of the total capacity.’ At least 38 per cent is ground-mounted or standalone, and DESNZ’s own estimate puts it near 59 per cent. Two million roofs are a political fact. The capacity is mostly in fields, waiting on the queue that failed.

An obligation closed to new entrants in 2017 still earns seven billion a year in certificates, three quarters of its domestic cost moved to the Exchequer until the decade turns. A capacity auction buys above the standard Parliament set, off a register its auditors call too stale to forecast from. None of that needed anyone to agree to anything. Everything in these documents that did — the connection, the reinforcement, the standard — is still waiting.

The Week in Energy — 6 September 2026

Sun, 06 Sep 2026 00:00:00 GMT

Five British government documents crossed the radar this week, and each one concedes, in its operative text, a cost, a risk or a weakness that its own press line does not carry. Nothing was leaked and nothing was dug out; the concessions sit in plain sight on gov.uk, one click below the headline. Candour of this kind is welcome, and worth taking seriously because it is official. What follows is the small print, read.

START WITH THE gas paper. DESNZ’s interim response to its security of supply consultation, published 18 August and largely unread since, opens with the department’s own admissions: North Sea gas production has fallen 74% since its 2000 peak, Britain has been a net importer since 2004, and any intervention in the gas market ‘would be unprecedented’. The 115 respondents, many of them operators with an obvious interest in being paid to hold capacity, go further: 75% agreed imbalances ‘may become possible in low-probability, high-stress scenarios’, and a majority (56%) did not believe the market will maintain the infrastructure without further incentives. Their reasoning, which the department publishes without rebuttal, is that ‘there are simply insufficient commercial incentives for operators to hold additional capacity for peaks in demand that are low probability’. A strategic storage reserve or a floating import terminal ‘would likely be in the billions of pounds across a 25-year timeline’. Low-probability, high-stress is precisely what insurance is for, and nobody has yet been asked to pay the premium.

The Capacity Market is the scheme that pays generators to be available when the weather is not. On 2 September DESNZ opened a consultation on how firmness is verified. A plant proves itself by showing output in three half-hour periods on separate days, with what the department calls ‘a very high degree of flexibility in determining when’. Its data shows many providers regularly exceed their requirements at peak, but also that ‘some CMUs pass their tests in the middle of the night or in other low demand periods’, which ‘offers little assurance that those CMUs can deliver if required’; the test does ‘not function as a good proxy’ for a real stress event. Publishing that criticism of its own scheme is the system working. The catch is the remedy: the new winter-afternoon test will not apply to any agreement already in force, so existing multi-year contracts keep the weak test for their full term. For those plants, the assurance stays unexamined until the contracts run out.

A new levy is coming to gas bills, and the department has published the arithmetic. The Gas Shipper Obligation, due in 2027, will fund hydrogen production contracts, and DESNZ’s consultation estimates it must raise ‘approximately £150m per annum from 2028’ for the first allocation round alone: eleven projects, about 125 MW. The stated modelling assumption is that shippers and suppliers ‘will pass on costs directly to their customers’, roughly £2.60 to £4.50 a year per dual-fuel household and up to 2% on non-domestic gas prices. The second round is chasing up to 875 MW, and the document concedes costs ‘would change with the funding of further hydrogen projects’. The Renewables Obligation began the same way: small, technical, and open-ended.

Small businesses are next. The government’s response to its non-domestic smart meter consultation confirms that from 1 September 2027, new fixed-term contracts for small and medium businesses must include a term that the customer has, or agrees to have, a smart meter, with supplier communications mandatory from January 2027. The response describes those fixed-term deals as ‘significantly cheaper than alternatives’, so the practical consequence of refusing is exclusion from the cheap tariffs, with deemed and out-of-contract rates the existing backstop. The impact assessment puts the bill savings at £10m to £29m a year across the three million sites in scope, between £3 and £10 each. The stated purpose is the Clean Power 2030 mission and half-hourly settlement. The customer is buying the grid’s paperwork with their tariff.

Then the quiet one. On 3 September DESNZ announced an intention, subject to conditions, to put £400 million into the Tropical Forests Forever Facility ‘via a loan’, and explained why in its own text: funding it as a loan rather than a grant lets the money come from a ‘financial transaction’ budget line, and ‘this reprioritisation allows a switch of funding to support the cap on single bus tickets at £2’. No forest country repays; the return depends on investment income from a facility whose governance is not yet finalised. The climate-finance headline is honoured, the domestic budget is freed for cost-of-living relief, and everything now rests on a fund that does not yet fully exist. The commitment survives as an accounting entry.

Ofgem’s verdict on NESO completes the set. The overall grade was ‘met expectations’, and NESO’s blog led with ‘seven of our eight performance objectives either delivered or had made sufficient progress’. Ofgem’s assessment counts it differently: three of eight delivered in full, four with sufficient progress, one underperformed. Both are true; NESO chose the flattering sum, though its blog does own the failure lower down. The failed objective is connections reform, with ‘missed deadlines, unclear prioritisation, inaccurate offers and inconsistent quality of customer engagement’, and value for money was graded ‘below expectations’. Connections is the one objective Clean Power 2030 actually turns on, and it is the one that failed.

Finish abroad, where the same problem has been given a price. The European Commission has cleared Germany to spend between €15.6 billion and €35.2 billion, starting at roughly €1–3 billion in 2031 then running at €0.9–2.3 billion annually through 2045, paying plants that can ‘produce, store or flexibly consume electricity’ when demand outruns supply. Capacity payments predate high renewables; Britain has run them since 2014. The scale is new, though, and so is the destination: capacity on the fifteen-year contracts must operate climate-neutrally by 2045, and new gas plants bidding for them must be hydrogen-ready. This is the integration cost the levelised cost of wind leaves out, now priced at continental scale with a regulator’s signature on it.

If the week teaches anything, it is where to read. The concessions live in the consultation body, the impact assessment, the second page of the press release, published by the same departments that wrote the headlines above them. The documents are doing their job. The press lines are doing a different one.

The Week in Energy — 29 August 2026

Sat, 29 Aug 2026 00:00:00 GMT

ON THURSDAY the government published three things at once: an evaluation of a retrofit scheme, a record for solar, and the quarterly generation statistics. Nothing in them is concealed. Every caveat below is the departments' own. What changes between the press line and the evidence is the unit of account: measure fuel poverty by the property's EPC band and it falls, measure it by what the household pays and it doesn't.

START WITH the retrofit evaluation. This is not the department marking its own homework: DESNZ commissioned IFF Research, Technopolis and BRE, gave the work to a scrutiny panel including the National Housing Federation and the Social Housing Regulator, and published what came back. Wave 1 of the Social Housing Decarbonisation Fund put 31,693 measures into 16,056 English social homes for £381m, of which £159m was grant, and the evaluators metered the result against 37,245 matched control properties to find the treated homes saving an extra 1,079.9 kWh of gas a year. Worth £97, and a fifth of a tonne of CO₂.

Take the public money alone and set the landlords' £222m aside. That is £9,903 a home to take £97 a year off a gas bill. Price the carbon over thirty years and the grant buys abatement at about £2,200 a tonne, against the £273 central value in the government's own appraisal guidance — five times the top of its sensitivity band. Every omission in that sum runs the government's way, since it counts no warmth, no damp remediation and no carbon from the solar or clean-heat measures the evaluators could not track, and it holds against a scheme that was never appraised on carbon alone and did buy real capability, with installers taking accreditations and firms widening what they could fit. That capability then delivered 21% fewer homes than planned, at 32% more each, with clean heat installations cut from 1,936 to 1,344. The purchase shrank as the price rose.

And the scheme reports a triumph. Ninety-seven per cent of fuel-poor households were taken out of fuel poverty, because England measures fuel poverty by EPC band, so moving the certificate to C removes the household from the statistic whatever it pays. The evaluators say so themselves, adding that reaching EPC C 'may have not led to a reduction in energy bills'. Bills did fall — £97, on strong evidence. What should trouble you is the sample. That 97% is 284 households, and it is reported as a national outcome.

THE SOLAR record has the same shape and a harder answer. DESNZ's first regional breakdown counts nearly 172,000 installations since January, 28,000 in July, 'one installation every 2 minutes'. The unit is the installation. A balcony kit and a solar farm each count once. The capacity data was published the same day in ET 6.3, one click from the release's own notes to editors, and it shows GB solar going from 21.67 GW in December to 22.56 GW in July — 895 MW in seven months, an annualised 1,534 MW. The Clean Power 2030 plan wants 45 to 47 GW by 2030, which needs about 5,100 MW a year. In a record year, Britain is building at under a third of the rate its own plan requires.

The quarterly statistics landed alongside, reporting that renewables provided 50.8% of electricity from major power producers in April to June, up 7.6% on the year, while two lines down the same table the low-carbon share falls 0.9 points to 67.2% and the fossil share rises a point to 32.2%, because nuclear output dropped 12% over the same period. One quarter proves nothing, and the series excludes embedded generation. But the shape is the argument. Renewables passed half, and the grid got dirtier, because the firm plant retiring is being replaced by weather.

TWO subsidy lines closed the week. The Green Gas Support Scheme forecast reached £190.82m against £98.42m a year earlier, up 94%, on 33 applications each carrying a fifteen-year tariff. That is a headroom figure, not expected spend, and it triggered no cut. The geometry is what to watch: the degression threshold flattens after 2027 while the forecast nearly doubles annually, so on this trajectory the scheme meets its own trigger during 2027, which is a dated prediction anyone can check. The levy funding it is charged per meter. It falls heaviest per unit on whoever uses least.

Then the visible relief. From 1 October VAT comes off household electricity, worth about £45 a year, funded — DESNZ says so plainly — 'through the cancellation of the digital ID programme', for one financial year only. The cap still rose 4%, and that 4% already has the tax cut netted into it, so the underlying rise is larger. Ofgem's stated cause is gas.

Five documents, one habit. Where the state picked the unit, the answer came out flattering. Where it published the full arithmetic, the answer is £9,903 of public money a home to save £97 a year, and a solar build rate at under a third of what the plan needs. Both came out of the same building on the same day. Only one of them will be quoted.

The Week in Energy — 22 August 2026

Sat, 22 Aug 2026 00:00:00 GMT

The week Whitehall conceded the thing it's legislating to abolish, and tried to answer adequacy in gigawatts.

Kept on board, rarely launched, never optional.

THERE is a trick to reading an energy document — 'find the unit'. This week supplied a master class in it. A storage plan stated in gigawatts is telling you how fast it can pour, not how much is in the jug. A reactor business case stated in jobs is telling you what it employs, not what it costs. A consultation that promises a 'commercial model' is telling you there will be a bill, not what the bill will be. Seven days, six documents, and in every one the number that would settle the argument is the number that isn't there.

START WITH the frankest. On Tuesday DESNZ published its interim response to the 'Gas system in transition' consultation, and the department's own words are the finding. Gas provides 'baseload supply' and 'insurance for low probability, high stress events'; there is a 'continuing need for peak-day capacity'; the three priorities are to maintain gas infrastructure, keep it resilient, and develop 'a commercial model supporting effective operation' — a way of paying for plant and pipes that, by design, will run rarely. This is the same government legislating to 'break the link' between gas and electricity prices, conceding in a parallel document that gas is the policy the system can't be run without, and that a new payment stream will be needed to keep it there. The premium is not priced. It will be. The firming cost the ¢/kWh comparison leaves out is the machinery The Energy Trap is built around.

The premium is being paid daily, meanwhile, in the season we're told renewables dominate. NESO's own daily fuel-mix posts had gas supplying between 31% and 45% of British electricity across four consecutive mid-August days, and on one of them wind managed 4.6%. Day-ahead gas sat around 150p a therm and baseload power at £110–120 a megawatt-hour, the highest in a year, with European storage at its lowest for the date since 2011 and French reactors derated by warm rivers. David Turver put the long-run bill on this: industrial electricity 63% above the IEA median, industrial energy use down 45% since 2004, and output per head growing 0.4% a year. A 45% fall in industrial energy use is being touted as efficiency. On his reading it is deindustrialisation, and the marginal price is still set by gas in August.

Then the storage answer, which arrived three times and never once in the right unit. Carbon Brief's explainer on long-duration storage gives the plan: 2.8 GW today, 4–6 GW by 2030, 13–17 GW by 2050, a first round of sixteen cap-and-floor projects totalling 7.6 GW at durations of 8 to 32 hours. DESNZ followed with a £28m 'Ultra-LDES' challenge for storage that can discharge for over 100 hours. And on Friday the minister consented Beacon Fen, 400 MW of Lincolnshire solar with a battery of 'up to 600 MVA' — a power rating, no duration given. Adequacy is an energy question: the terawatt-hours you can dispatch through a still week in January. The Royal Society estimates we'll need around 100 TWh to survive the UK's inter-year wind variation. Sixteen gigawatts at thirty-two hours is about half a terawatt-hour. Every document states the pour rate. None states the jug.

The week's loudest argument was two spreadsheets shouting past each other. Onward's Firm Foundations claims Britain could save over £320bn by swapping net-zero policy for gas and nuclear; Carbon Brief's factcheck lists ten flaws, and some are fair — gas plant at £650 a kilowatt when current American projects are running £1,467–2,054, a network 'saving' that cuts transmission spend 86% while still plugging in 32 million EVs. But look at the rebuttal's own figure for the cost of integrating renewables: a mainstream range of £26 to £75 a megawatt-hour. A spread of three to one is not a rebuttal; it's an admission that nobody knows the number. And the quantity that decides the question — the energy deliverable through a still winter week — appears in neither report. When both sides of a cost war leave the same cell blank, the cell is the story.

The best news of the week was nuclear, and it deserves a number too. Great British Energy – Nuclear published its Full Business Case for three Rolls-Royce small modular reactors at Wylfa — about 1.5 GW of firm, dispatchable power from the mid-2030s, backed by up to £599m of National Wealth Fund finance for design. That is the right kind of capacity, the kind the fuel-mix figures above are crying out for, and it's a commitment to be glad of. But the case runs the full five Green Book chapters and contains no strike price, no pounds per megawatt-hour and no benefit-cost ratio: value for money is 'positive marginal value … with adjustments for uncertainty, risk and optimism bias', inside a £2.6bn envelope the document admits the contract will outrun. Nuclear wins the adequacy argument on the numbers. But we should be allowed to see them.

Ed Conway added the physics the 'just import it' position skips. British appliances were built for lean, dry southern-North-Sea gas, so imported LNG has to be nitrogen-blended to meet UK spec — 'the single most energy-intensive process' at the Isle of Grain — on top of the energy already spent chilling it to −162°C for the voyage. Every barrel not produced here returns as LNG at a higher energy cost and a higher lifecycle carbon count that the domestic ledger doesn't show, which is why Norway, peaking five years after us, has now produced more. Even Dale Vince, who called Rosebank 'a betrayal', backed both fields on Newsnight this week. The catch is the price controls he wants attached.

Seven days, six documents, one blank. The unit that flatters is always supplied; the unit that decides is left for someone else to find.

The Week in Energy — 15 August 2026

Sat, 15 Aug 2026 00:00:00 GMT

FOR YEARS the argument about Britain's energy policy has been an argument about a number: what it costs. This week the government gave its answer. It didn't cut the cost; it rearranged where the cost appears. In seven days it published a scheme to route industrial relief around the household bill, a discount that spreads the price of new pylons across every bill in the country, and carbon limits that forbid the adequacy fleet to do the thing it is paid to do. A minister supplied the summary. The cost, she says, is 'misinformation'.

Start with the pair that frames the week. On Wednesday DESNZ opened a consultation on the legislative plumbing for the British Industrial Competitiveness Scheme: from April 2027 some 10,000 manufacturers will be exempted from the indirect costs of the Renewables Obligation, the Feed-in Tariff and the Capacity Market — about £35–40 off each megawatt-hour, up to a quarter off their bills, worth up to £600m a year. It's worth reading the mechanism. Exchequer funding is to be 'channelled through the CfD supplier obligation' so the relief doesn't increase 'electricity bills for households and other non-exempt consumers'. The relief on offer is relief from paying for low-carbon generation; the working assumption of the policy is that British industry can't compete while carrying those levies. And the cost doesn't disappear when it leaves the bill. It moves to the Exchequer i.e. from company energy bills to household tax bills.

Days earlier, the same department priced the view from the bedroom window. Households within 500 metres of new or upgraded transmission lines will receive £250 a year for ten years — £2,500, paid through their supplier, first payments in the first half of 2027, with 43 projects named in the initial list. Compensating people who live beside new infrastructure is fair enough, although the sum in this case is a fraction of the reduction in resale value. The telling part is where the money comes from: a small addition to everyone's bill, reported at roughly 80p a year. The disamenity of the grid build-out is now priced, published and socialised — a real cost of the wires, admitted in cash, that never appears when the strike prices are compared.

From the other end of the system, the adequacy machine tied a knot in itself. DESNZ has republished its 84-page guidance on carbon limits in the Capacity Market: alongside a limit of 550 grams of CO₂ per unit generated sits a cap of 350 kilograms per installed kilowatt per year — a run-hours limit dressed as an emissions rule. The Capacity Market exists to pay firm plant to be available for the windless evening. The same contract now constrains how much that plant may run. We're paying for readiness and capping the ready.

The week's sharpest exchange was about whether any of this exists. On the Today programme at the start of the month the energy minister Miatta Fahnbulleh dismissed the claim that net-zero policy is raising bills as 'misinformation'. This week David Turver opened the accounts. Electricity subsidies — ROCs, CfDs, feed-in tariffs, Sizewell C — have risen from £0.5bn in 2010/11 to £11.8bn last year; grid integration costs from £2.8bn to £8bn; together they reached £19.8bn a year and are forecast past £40bn by 2030/31, against a gas fuel bill of about £7bn. 'Misinformation' is a word that can be checked against the government's own books. The books are not sceptic sources.

Jan Rosenow, a pro-transition lobbyist, published a comparison of heat-pump costs this week: German installations at €35,366, British at €12,095. Note what is being compared — two subsidised prices. The absolute price, and the grid cost of running the fleet on the coldest evening of the year, sit outside the frame, as they always do in his work. Its value is as a specimen of pseudo-academia — advocacy in academic clothing, the boundary drawn to keep the hard part out of the sum — not as an insight into what renewables cost.

Abroad, the week was franker. China's new five-year plan for coal has the head of the National Energy Administration calling the fuel the country's 'greatest source of confidence' in keeping the lights on; the plan commits only to coal consumption 'successfully reaching a peak', no year attached, while trimming the strategic reserve-production target from 300 million tonnes to 100. And Europe's nuclear retreat is reversing. Javier Blas reports that Spain will run to 2030 reactors that were due to close next year, and that Hungary, Slovakia, France and Britain plan to expand their fleets. The firm, dispatchable power the renewables-only timetable says it has outgrown is being readmitted — by the governments doing the building, not the critics.

And for anyone consoled by the thought that the North Sea windfall levy at least raises money, the Telegraph's arithmetic went the other way. The 78% levy is forcing fields to shut early, and early shutdown brings forward the decommissioning tax reliefs the Treasury must pay — about £13bn by 2035 on the North Sea Transition Authority's figures. 'Forcing fields to close prematurely does not simply switch off future tax receipts,' notes Brian Gilvary, chairman of Ineos Energy and no one's idea of a militant. A tax sold as taking money from a windfall now pays to close the fields, and the output returns as imported LNG.

The winter, meanwhile, is being priced now. John Kemp reports Europe's gas stores less than three-fifths full — the lowest for the time of year on record, with the refill window closing — and Bloomberg put Tuesday's day-ahead power print at £133 a megawatt-hour, the highest since June, in a summer heatwave, with gas still setting the price. Whatever the accounting says, the margin is decided upstream, months early, in molecules.

Seven days, one direction of travel: the cost of the plan is not being cut, and it's barely being disputed. It's being moved, spread and denied. The bill is not the cost.