What changed?

Almost all of the increase comes from gas. Ofgem says gas bills are rising by around 8%, while electricity costs are broadly flat. Wholesale prices have gone up 11% over the past three months, and Ofgem ties that to continuing conflict in the Middle East and the volatility it has caused in global gas markets. Neil Kenward, Ofgem’s Director General for Markets, said high international gas prices are continuing to drive energy costs.

Electricity looks calmer largely because of a policy decision. The government has removed VAT from domestic electricity bills, which Ofgem says saves customers about £45. Without that, the picture would be less comfortable. It also shows how much the final bill depends on choices made in Westminster as well as on what happens in the gas market.

One quirk is worth knowing. Ofgem updated its assumptions about typical consumption in July, and now assumes the average home uses 17% less gas and 7% less electricity than before. That makes the headline figure look lower than it would have under the old assumptions, so comparisons with earlier quarters need care.

What the forecasts say about January?

The October rise is the smaller part of the story. Analysts quoted this week expect the cap to climb by a further 12% to 14% from January 2027. Suppliers’ own forecasts put the typical annual bill at £1,932 for EDF, £1,941 for E.ON Next and £1,970 for British Gas. Those are predictions, not announced figures. Ofgem will publish the actual January cap in November, and it will depend on how wholesale gas behaves between now and then.

About 35% of households, around 11 million, are on fixed tariffs and are unaffected for now. Ofgem’s advice is that fixed deals are available more than £100 below the cap level, which is a reminder that the cap is a default price, not a bargain.

Why this matters for businesses?

The price cap covers households, not companies. Business energy contracts are priced separately, and none of Ofgem’s announcement deals with non-domestic customers. But the cause of the rise, wholesale gas, is the same cost that feeds into business contracts. When wholesale prices move, suppliers reprice what they offer to commercial customers too, and the lag between the two is shorter than many finance teams assume.

That makes the next few weeks a decision point for anyone whose fixed contract ends before spring. If a renewal falls between now and the end of the winter, the sensible question is whether to lock in before the market moves again or wait on the hope that prices ease. Nobody can answer that with certainty, and the January forecasts suggest the risk is weighted toward higher prices, though forecasts have been wrong before. What you can do is find out your renewal dates, look at what your contract says about notice periods and deemed rates, and get quotes early enough that you are not forced to accept whatever your supplier rolls you onto.

Businesses with flexible or pass-through contracts have more exposure to wholesale swings, and those on fixed terms have less, until the fixed term ends. Either way, it is worth knowing which of the two you are.

Usage is the other lever. Ofgem’s own revised assumptions show that household consumption has fallen noticeably, which is partly the effect of efficiency measures and behaviour. For a business, a metering and usage review costs little compared with a double-digit rise in the unit rate, and cutting consumption lowers the bill whatever the market does.

What is pushing prices up

Ofgem puts the rise down to wholesale gas, which climbed 11% over the three months before the announcement on 26 August and added 8% to gas bills. The regulator points to tension in the Middle East. Government action on VAT and levies took some of the sting out: without the removal of VAT on domestic electricity, Ofgem says the cap would have been about £45 higher. Electricity bills stay broadly flat as a result.

Households on the cap have that cushion. Businesses do not. Non-domestic customers on flexible or renewing contracts take wholesale movements more or less directly, and the picture from the wholesale market is not comforting. According to the NRLA’s September update, gas ended August at around 167p/therm and power at £130/MWh, after touching £146/MWh earlier in the month. Forward prices for the rest of 2026 and winter 2026/27 were up about 15% for gas (to roughly 170p/therm) and 10% for power (to nearly £140/MWh). The same update warns of another double-digit gas increase if the winter turns out cold.

The supply backdrop explains the nervousness. Utility Helpline’s 23 September analysis says roughly 18% of global LNG supply has been removed by conflict and disruption. Traffic through the Strait of Hormuz has fallen from around 125 large commercial vessels a day to about 12, and European imports of Qatari LNG are down around 61% so far this year. European gas storage stands at 69%, twelve percentage points below the same point last year. Getting from 70% to 73% would take another 5.1 billion cubic metres, roughly 53 LNG cargoes. Britain leans more heavily on US LNG as other sources tighten, and gas still generates 24.5% of our electricity, so gas price swings feed into power prices too.

One oddity worth noting for anyone signing a contract now: the curve is steeply inverted. Winter 2026 gas trades around 184p/therm, while summer 2028 is nearer 107p/therm. Longer-term deals currently look cheaper than short-term ones, which is unusual and worth pricing.

The cost of the cost!

The strain shows up in business surveys. A poll of 526 UK businesses by EDF Small Business, Enterprise Nation and Square, published on 11 September, found that 69% had delayed or cancelled growth plans in the past year and half had cut investment. Respondents said rising energy bills had trimmed profit margins by about 18% on average. Among high street businesses, 77% had put growth on hold.

Large users are just as worried. An npower Business Solutions survey of more than 400 large energy users, reported on 18 September, found 93% concerned about the financial impact of the clean energy transition and 86% wanting more government financial support. Energy has been the top business risk for five years running, and 78% of respondents expect costs to go up over the next 12 months. The same research puts UK medium, large and very large firms paying 90%, 130% and 110% more for electricity than the EU14 median. It also projects peak business energy costs of £523/MWh in January 2028, during the Capacity Market charging period.

The Clean Power 2030 argument

The headline finding from the npower survey was that one in ten large users would now back pushing the government’s Clean Power 2030 target back to 2035. One in ten is a minority, and it is worth saying so plainly. The survey also found businesses still support the renewable goals themselves. The frustration is with costs they cannot control, which Anthony Ainsworth, nBS’s chief operating officer, said were hurting confidence and competitiveness.

The politics are already noisy. Attacks on the cost of the clean power plan have been circulating widely this month, and some of that material comes from campaigning outlets with a clear position. Readers should treat headline cost claims with care and look for the underlying analysis. The more grounded point is the one the surveys make: firms are being asked to plan for a transition while paying far more for electricity than European competitors.

There is an awkward logic here too. The latest DESNZ figures for May to July show renewables supplying 48.5% of generation, but the low-carbon share fell 5.4 percentage points year on year to 63.2%, mostly because nuclear output dropped 27% and gas generation rose 18%. A grid that leans on gas is a grid that inherits gas price risk.

What to do about it?

For most businesses the practical answer is dull but effective. Check when your contract ends and what the renewal terms are, because April is a peak renewal month and this winter’s pricing may be poor for anyone forced to buy at short notice. Ask suppliers for both short and long-term quotes given the inverted curve. Look at flexible or blended purchasing rather than a single fixed price at a bad moment.

Efficiency deserves more attention than it gets. In the EDF survey, 75% of small businesses did not know what efficiency grants or reliefs were available, and 69% were unaware that cutting energy costs by 20% has roughly the same profit effect as 5% sales growth. On-site solar, better metering and load management all reduce exposure to wholesale swings, and the case gets easier every time the gas price jumps.

The Budget is the next date to watch. In the EDF survey, 37% of businesses were asking for a VAT reduction ahead of it, and the domestic VAT change shows the Treasury is willing to use tax to blunt energy costs. Whether any of that reaches non-domestic customers is the open question. Until it does, the sensible assumption is that the Gulf, not Westminster, will set the direction of your winter bill.

Seven months of a conflict that reset energy markets

It’s worth remembering how we got here, because the last two days only make sense against that backdrop. The US-Iran conflict, which the Pentagon refers to internally as Operation Epic Fury, is now well past its 200th day, having escalated from the late-February breakdown of earlier negotiations. The Strait of Hormuz, through which roughly a fifth of the world’s oil and a similar share of global LNG passes, has been intermittently closed or heavily restricted since late March, an event that reset the baseline for what “normal” oil and gas prices look like this year.

The most recent flashpoint came on 11 September, when Iraq-based drone strikes hit three pumping stations on Saudi Arabia’s East-West Pipeline, the 1980s-built route that lets Saudi Arabia and the UAE move crude to the Red Sea port of Yanbu without going anywhere near Hormuz. Satellite imagery published in the days afterward showed extensive damage. Riyadh shut the pipeline entirely on 13 September, removing one of the few working bypass routes at a moment when the strait itself was already seeing only a handful of tanker transits a day. Brent broke back above $100 within hours and peaked near $107 the following week, with Gulf supply disruptions estimated at more than 10 million barrels a day at their worst point.

What actually changed this week?

Two things happened in the past 48 hours that moved the price, and it’s worth being precise about what they were and weren’t. First, Saudi Arabia restarted the East-West Pipeline on Tuesday, though at reduced capacity; Aramco is targeting full flows, but analysts think complete restoration will take several more weeks. Second, and more significant for sentiment, a senior Iranian official told Japan’s Kyodo News that Tehran would reopen the Strait of Hormuz within seven days if Washington ends its naval blockade of Iranian ports and halts strikes in the strait. That offer came with seven conditions in total, including the release of frozen Iranian assets, transmitted to Washington via Qatari intermediaries on 19 September.

Trump told reporters that US and Iranian officials had spent three hours in talks, and Treasury Secretary Scott Bessent has simultaneously floated new sanctions on Iranian airlines and financial institutions, a reminder that pressure and diplomacy are running on parallel tracks rather than one replacing the other. Iran’s Revolutionary Guard has said plainly that “the war is not over,” and has kept open the option of further strikes if talks stall. None of the underlying military positions have actually been withdrawn. What’s changed is that both sides are now talking, in public, at the same summit, which markets are reading as the best chance of de-escalation in months.

The case for caution!

Energy traders who have lived through this conflict since February have seen this pattern before: an announcement of progress, a rally in risk assets, oil sheds a few dollars, and then talks stall or a new incident sends prices right back up. One widely read market note this week put the odds of another such reversal over the next two to three weeks at roughly six in ten, with a plausible floor for WTI around $82-85 if the current mood holds and a rapid return above $100 if it doesn’t. Nothing about Tuesday’s news changes the fact that Hormuz traffic remains far below normal, that Saudi Arabia’s bypass pipeline is running at a fraction of capacity, or that Iran’s hardline factions have shown they can act independently of what Tehran’s diplomats say in New York.

Why this matters for UK buyers specifically

Britain has felt this conflict more acutely than most of Europe. Roughly a fifth of the world’s LNG passes through Hormuz, and Qatar’s Ras Laffan terminal, the largest LNG export facility on the planet, has no alternative sea route. Because the UK relies on LNG imports and prices off the same international gas benchmarks as everyone else, the shock transmitted directly into UK wholesale gas, which peaked around 75% above pre-conflict levels earlier this year and was still roughly a third higher by late spring. The domestic price cap for July to September, set using market prices from February through May, captured that spike in full, and household bills rose in step. Business energy buyers, who aren’t shielded by a price cap at all, felt the swings even faster.

That history is the reason this week’s rally in sentiment deserves a measured response rather than relief. A real, durable reopening of Hormuz and a fully repaired Saudi pipeline would be genuinely good news for anyone buying gas or power in the UK. A few days of positive headlines during a UN summit isn’t the same thing, and businesses currently weighing whether to lock in winter energy contracts should treat this week’s dip as a chance to review exposure, not as a signal that the risk has passed. The conflict’s own history over the past seven months is the best evidence available that this kind of optimism has been premature before.

The short version: Europe is heading into winter with less gas in storage than it has had at this point in the year for at least a decade, at the same time as the Middle East conflict has knocked a meaningful chunk of global LNG capacity offline for years, not months. Put those two things together and you get a market that is pricing risk into every contract currently on offer for delivery this winter and next.

Empty tanks, tight cargoes

EU storage sites were only around 57% full in early August, the lowest reading for that point in the calendar since 2011. Wood Mackenzie has since warned that Europe is at real risk of missing even its relaxed 75% storage target for November, let alone the usual 80% goal for December. That matters because storage is what Europe leans on when cold snaps push demand up faster than pipelines and LNG terminals can deliver it. A thin buffer means more days where the market has to scramble for spot cargoes at whatever price sellers demand, and those spikes tend to ripple straight through to business tariffs.

The supply side isn’t helping. Damage to Qatar’s LNG export facilities during this year’s Middle East fighting, along with disruption to tanker traffic through the Strait of Hormuz, has done more than cause a temporary wobble. The IEA now reckons the conflict will delay the wave of new global LNG supply that was supposed to ease the market by around two years, and puts the cumulative hit to LNG availability between 2026 and 2030 at roughly 120 billion cubic metres, something like 15% of the LNG the world was expecting over that period. A ceasefire in the spring brought prices down from their most extreme peaks, but the underlying damage to Qatari output, expected to take years to repair, hasn’t gone away, and neither has the market’s nervousness about further escalation.

Closer to home, a cluster of planned nuclear outages has added to the tightness at exactly the wrong moment. Heysham 2, Torness and Hartlepool all went into scheduled maintenance windows in the first half of September, taking hundreds of megawatts of low-carbon baseload off the system just as the wider market was jumping on Middle East headlines.

What this means for the UK

On the domestic side, Ofgem has already confirmed the numbers: the household price cap rose 13% for the July-to-September quarter, driven by the earlier spike in wholesale gas, before easing to a smaller 4% rise for October to December. The VAT relief on electricity that kicks in this quarter takes a little of the sting out for capped customers.

Businesses sit outside the price cap entirely, which is exactly why this week’s market moves matter more than they might first appear to. Wholesale forward prices for the 2026/27 winter period have already climbed above 170p a therm, and industry reporting suggests business energy costs are up around a quarter since February for firms buying through this period. There’s a genuine bright spot: the National Energy System Operator expects a healthy 5.5 gigawatt electricity margin this winter, an 8.8% buffer over peak demand. So this isn’t shaping up as a blackout risk. It’s a cost risk, and the pinch is most likely to land on the tight days NESO flags for mid-to-late January.

The practical advice circulating among energy consultants right now is fairly consistent, and it lines up with what the market data is showing: because forward prices are broadly flat out into 2027 and 2028, there’s no obvious dip on the horizon to wait for. A 12-to-24-month fix locked in now avoids absorbing the full winter premium that’s currently baked into short-term contracts, and for businesses weighing up term length, a 24- or 36-month fix often comes out as the cheapest blended rate precisely because it isn’t as exposed to this winter’s spike.

There’s a wider point here too, about resilience. Nuclear employment in the UK has just passed 100,000 jobs for the first time, up 67% in five years, part of a broader push toward generation that doesn’t depend on a tanker making it safely through the Strait of Hormuz. That won’t change anyone’s bill this winter. But it’s the backdrop against which this volatility is playing out: a system still leaning heavily on a global gas market that keeps proving how exposed it is to events thousands of miles from the UK coastline.

For now, the message for anyone managing a business energy budget is a simple one. The wholesale market has already told you what it thinks winter is going to cost. The only real decision left is how much of that risk you’re willing to carry unhedged.

Read the full NAO report at: www.nao.org.uk/reports/upgrading-the-electricity-transmission-network/

A price cap set thousands of miles from home

Wholesale gas prices in late August hit their highest level since January 2023, and the reason traces back to 28 February this year, when the United States and Israel launched military strikes against Iran. What began as an air campaign has since drawn in the Strait of Hormuz, the narrow channel through which roughly a fifth of the world’s seaborne oil and a similar share of its LNG normally passes. Iran’s Revolutionary Guard has warned vessels away, boarded ships, and laid mines. Traffic through the strait has collapsed from more than a hundred vessels a day before the war to around five now, according to shipping data reported by Al Jazeera. QatarEnergy declared force majeure on its LNG exports in early March after strikes hit its Ras Laffan facility, pulling a significant slice of global gas supply off the market overnight. Gulf crude exports are down by close to half compared with last year.

Britain does not import much gas directly from the Gulf. It does not need to. Gas is priced on a global market, and when a chokepoint responsible for a fifth of world LNG flows effectively closes, prices rise everywhere that buys gas, including the UK, regardless of where the molecules in a British boiler actually came from. That is the mechanism behind this rise, and it is the same mechanism behind the 13% increase to £1,663 that took effect in July. This is now the second consecutive quarterly rise driven substantially by the same conflict, and Ofgem’s own guidance offers little comfort: with no resolution in the Gulf in sight, the regulator and most market analysts expect prices to hold at this level or climb further into 2027.

The bill behind the bill

There is a second, less visible cost building alongside the headline figure. Energy suppliers are currently sitting on roughly £5.5 billion of customer debt, a legacy of previous price shocks that has not been paid down, and Ofgem’s price cap already bakes in an allowance of around £50 per typical household simply to cover the cost of that debt across the industry. In other words, part of every bill now is not paying for gas or electricity at all. It is paying for gas and electricity that was used, and not yet paid for, in earlier and even worse years. That is a structural drag that will persist even if wholesale prices eventually ease, and it is worth understanding as distinct from the Hormuz-driven spike, because the two won’t unwind on the same timeline.

Why this hits businesses harder, and differently

For households, the price cap at least puts a ceiling on how quickly suppliers can pass costs through, and spreads the pain over a fixed quarterly cycle. Businesses have no such protection. Non-domestic customers sit entirely outside the price cap regime, which means wholesale volatility of the kind driven by the Strait of Hormuz crisis reaches commercial energy bills faster and with fewer guardrails than it reaches domestic ones.

It also compounds with a separate, longer-running trend. Non-commodity costs, the network charges, balancing costs and policy levies layered on top of the wholesale price, now make up somewhere between 60 and 64% of a typical UK business electricity bill. Transmission network charges alone rose from around £16 to £31 per megawatt-hour from April this year, an increase of more than 60% on that single line item. So a business renewing a contract this autumn is facing two things at once: a wholesale gas market inflated by a conflict on the other side of the world, and a domestic network cost base that has been climbing independently of it. Neither is likely to reverse quickly, and together they explain why many finance directors are seeing electricity costs rise even in businesses where consumption has stayed flat or fallen.

What this means for the months ahead

None of the underlying drivers look close to resolving. The Strait of Hormuz situation is a function of an active conflict, not a temporary market dislocation, and European gas storage is currently running below historical norms for early September, which removes some of the cushion that might otherwise have absorbed a shock like this one. For businesses with contracts up for renewal in the next two quarters, the practical takeaway is simple even if the cause isn’t: treat current pricing as the likely baseline for the next several months, not a spike to wait out, and lock in visibility on fixed costs sooner rather than later. Anyone reviewing demand profiles, capacity agreements or contract timing over the coming weeks should factor in both the wholesale picture and the non-commodity trend, since it’s the two together, not either one on its own, driving what’s showing up on bills this autumn.

It’s worth sitting with the wider lesson here. A shipping lane most of us will never see has, within months, worked its way into the annual accounts of businesses across the country. UK energy security has always depended partly on global stability. This autumn is a reminder of how directly, and how quickly, that dependency shows up on the bottom line.

The swing tells you most of what you need to know about where this market’s attention is right now. It isn’t really about UK fundamentals. Storage is filling, Norwegian flows are steady enough, and LNG cargoes keep landing on schedule at Gate, Eemshaven and the rest. What’s moving prices is the Strait of Hormuz, and specifically whether Washington and Tehran can turn five months of intermittent conflict into something that actually reopens the waterway.

Power tracked gas higher across the week. UK day-ahead baseload climbed from £111.28/MWh to £133.24/MWh. Brent had the sharpest run of the lot, up almost $9.50 a barrel as shipping through Hormuz thinned out again.

Storage still lagging, but the trend is right

EU gas storage moved from around 58% full on 4 August to just under 59% by 9 August, according to GIE data cited in the broker notes. That’s roughly 12 percentage points below where the bloc sat this time last year. Germany and the Netherlands remain particularly underfilled, sitting below 50% and 40%. Injection rates have been running around 18% behind last year’s pace.

UK storage tells a similar story. Rough remains offline at zero, Humbly Grove is still empty, and the more meaningful UK gas sites (Aldbrough, Holehouse Farm, Hornsea and Stublach) sit in the high 30s to high 60s percent range. South Hook’s LNG storage has been one of the standout movers, climbing from 41% on 6 August to a peak of 79% on 7 August before settling back into the 70s.

The read from TotalEnergies’ desk this week is that Europe may struggle to get much beyond 70-75% storage before winter without a sustained pickup in LNG imports. That’s well short of the bloc’s 90% flexible target for 1 October to 1 December.

Hormuz: hopes raised, then dashed

The week’s real story played out in the Gulf. Monday through Wednesday brought genuine optimism. Iran signalled it was nearing a final agreement with Oman on new shipping lanes through the Strait, and traders started pricing in a partial reopening. That optimism didn’t last. By Tuesday this week, both the US and Yemen’s Houthis had reported separate attacks on shipping, and President Trump responded to Iran’s conditions for a peace deal by demanding compensation for those killed in the conflict. The standoff hardened rather than eased.

Vessel movements through the Strait have been the clearest barometer. They fell to just six on Monday, against a 10-day average of around 11, and TTF front-month gas spiked almost 10% in a single session on 11 August. Congressional Research Service data this week confirmed what the daily flows have been showing all along: periodic Iranian attacks and retaliatory US strikes have disrupted Strait traffic for most of the past five months. The current calm looks more like both sides running out of steam than any real resolution. Roughly a fifth of global LNG supply normally transits Hormuz, so every flare-up shows up almost immediately in European forward curves.

Supply side: Norway steady, LNG arrivals holding up

Norwegian Continental Shelf exit nominations bounced around a fairly narrow band this week, from the low 310s up to 325.5 mcm/day this morning, with planned maintenance at Vesterled and the Ormen Lange field trimming capacity at the margins. Gassco extended the partial Ormen Lange outage through to 1 February 2027. It barely moved the daily numbers, but it quietly takes some winter flexibility off the table.

LNG arrivals into North West Europe have stayed busy: a steady flow of US cargoes into Gate, Eemshaven and Fos, plus occasional deliveries from Norway, Algeria and, notably, Russia (a 103,000 cmc cargo booked into Gate for 15 August). UK LNG sendout has held close to 8 mcm/day for most of the week.

Weather has added to demand too. The UK has moved through a run of heatwave conditions, with forecasts peaking in the low-to-mid 20s°C around 12-13 August. Gas-for-power demand has climbed as a result, even with wind output generally sitting below seasonal norms.

What to watch

• Iran-Oman talks: any concrete progress on Strait shipping lane rules would likely pull risk premium back out of Winter-26 gas and power contracts quickly. Equally, a fresh escalation could push NBP through 150p.

• French and Belgian nuclear availability: heat-related outages have been building, with French nuclear reductions expected to peak around 10.7 GW this week, partly driven by a jellyfish influx affecting cooling intake at coastal stations.

• EU storage trajectory into September: watch whether injection rates start closing the gap on last year’s pace, or whether the 70-75% ceiling becomes the market’s working assumption for winter entry.

• UK temperatures: EC46 forecasts have been revising toward a cooler second half of next week, which should ease gas-for-power demand from current heatwave-driven highs.

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Why the North Sea is back on the table

The case being pushed by industry is straightforward. UK upstream oil and gas investment fell to roughly £4.4 billion in 2025 and was on track to fall further, to around £2.5 billion this year, as operators pulled back in the face of licensing uncertainty and the windfall tax regime introduced in 2022. Offshore Energies UK, the industry’s main trade body, has argued there is an “overwhelming” case for developing Jackdaw and Rosebank, framing continued domestic production as a matter of energy security and industrial jobs rather than a retreat from climate commitments. The Chemical Industries Association has made a similar argument, describing backing for North Sea projects as a way to protect manufacturing competitiveness and cut reliance on imported gas, rather than a move against renewables.

Burnham’s team appears to be trying to hold both positions at once: approve new domestic production while insisting the UK’s 2050 net zero target and broader clean power ambitions remain intact. Whether that balance holds under scrutiny from his own backbenches and from climate groups is an open question, but for businesses buying energy, the more immediate point is what new domestic supply could do to price volatility. Britain currently imports a significant share of its gas, which leaves wholesale prices exposed to global shocks. That was on full display in July, when Middle East tensions and low wind output pushed day-ahead power prices up by more than 140% in a matter of weeks. More domestic production would not insulate the UK from global gas pricing entirely, since North Sea gas is sold into the same wholesale market, but industry argues it would reduce the exposure to shipping, geopolitics and currency swings that comes with imported LNG.

The windfall tax complicates the investment picture

The North Sea reset is landing at an awkward moment for renewable generators. From 1 July, the Electricity Generator Levy (a windfall tax on low-carbon power generation introduced in 2023) rose from 45% to 55%, and the government has extended it beyond its original 2028 end date. RenewableUK’s chief executive has warned that the uncertainty around the change itself, not just the higher rate, is what unsettles investors, and that clarity is needed quickly to stop it pushing up the cost of financing new projects. Independent analyst Kathryn Porter has flagged a further wrinkle: the levy also applies to the UK’s ageing nuclear fleet, which could hasten retirements at exactly the point the grid needs firm, low-carbon capacity to back up intermittent wind and solar.

For businesses on flexible or renewables-linked contracts, this matters because generator economics feed through to long-term power purchase agreement pricing and, eventually, to what suppliers charge. A tax regime that discourages new renewable build even as electricity demand climbs (up 1.2% last year, with much sharper growth expected from electric heating, transport and data centres) tightens the supply-demand balance that keeps a lid on prices. New projects where the investment decision was taken before November 2023 are exempt from the levy, which protects some of the pipeline already underway, but it does little for the next wave of projects still being financed.

What this means for the rest of the year

None of this changes the numbers Ofgem is working through right now. The regulator must confirm the Q4 2026 price cap, covering October to December, by 26 August, with independent forecasters at Cornwall Insight currently pencilling in a level somewhat below the current quarter’s cap, assuming wholesale prices ease from July’s spike. Businesses on fixed contracts renewing this autumn should treat that forecast as a starting point rather than a guarantee, given how quickly wholesale prices have moved this year on weather and geopolitical news alone.

The broader signal from this month is that UK energy policy is trying to pull in two directions simultaneously: more domestic fossil fuel production to shore up supply security, and a tougher tax regime on renewables that industry says risks the opposite. Businesses that buy energy in volume have reasonable grounds to expect continued volatility through the rest of 2026, driven less by any single policy decision than by the tension between them. The practical takeaway is the same one that’s applied all year: build in a wider margin for price risk than usual when reviewing contracts, and don’t assume this summer’s calm in any one market signals a return to stable pricing for winter.

Cooling water is running out

Hungary came close to a forced shutdown at its only nuclear plant this week as Danube water levels dropped. Romania went further: engineers set off a controlled explosion in the river to redirect cooling water to its one operating nuclear plant, after low levels had already forced two reactors offline. The Rhine and the Danube, the two rivers most of the continent’s fleet depends on for cooling, are both under strain, and at least one water-cooled plant is running at just 10% of capacity.

The mechanics are simple enough. Reactors need large volumes of river water to shed heat. When rivers run low, or warm up too much, plants either throttle back or risk breaching discharge temperature limits. The European Commission puts a rough number on it: every 1°C rise in cooling water temperature can cut nuclear output by about 0.2%. That sounds small until it’s stacked across a fleet that’s already running hot and short of water at the same time.

Why this matters for procurement

None of this shows up on a UK balance sheet directly, but it doesn’t stay contained to one grid either. Lost continental nuclear output tightens the wider European supply and demand balance right at peak summer demand, and that tends to show up in interconnector flows and day-ahead power pricing. Anyone pricing risk for clients this month should be watching continental river levels and nuclear availability data alongside the usual weather and demand forecasts.

Meanwhile, the UK’s connection queue is getting a shake-up

Two separate stories from the past few days point at the same underlying problem: getting new capacity connected to the grid fast enough. NESO’s new Progression Commitment Fee is meant to stop developers sitting on capacity in the queue without pushing projects toward construction. Projects that reach Gate 2 without a planning application on file face a rising security requirement of £2,500 per MW every six months, up to a cap of £10,000 per MW, so a 500MW project could go from a £1.25 million commitment to £5 million if it stalls long enough. The fee only kicks in once total terminated capacity in the queue hits 6.5GW. NESO’s first reading came in at 0MW, so nobody’s paying it yet, but the mechanism is live now and worth tracking as a leading indicator of how bad queue congestion is getting.

On the demand side, new research from Resource Recovery UK points at a different fix. Co-locating data centres with energy-from-waste facilities via private wire connections could cut the wait for a grid connection from around a decade to roughly two years, with sites planned in Greater London, Oxfordshire and Fife. It’s a narrow solution that only works where an EfW plant happens to be nearby, but it’s a sign that developers are routing around the queue rather than waiting for it to clear.

The takeaway

Two different continents, two different problems, one shared theme. Physical constraints, whether that’s a shrinking river or a backed-up connections queue, are increasingly what decides where power gets built and how reliably it flows. Both are worth keeping on the radar heading into autumn.

^{The Energy Ledger is an independent read on UK energy markets, policy and the people who run them. If this was useful, the best thing you can do is share it with one other person in the industry who’d find it useful too.}

If you’ve been half-watching the headlines rather than the desk chatter, here’s the catch-up — and, more importantly, what it means for anyone sitting on UK gas or power exposure heading into winter.

What actually happened

Weekend escalation between the US and Iran pushed into a ninth consecutive day of tit-for-tat strikes. Iran’s IRGC reported two oil tankers struck and disabled in the Strait of Hormuz, alongside claims that a southern smuggling route through the waterway had also come under attack. US Centcom confirmed strikes against Iranian military installations, coastal surveillance assets and communications infrastructure, in what it framed as retaliation following reports of US personnel killed in Jordan.

This isn’t the first flare-up this year — the Strait saw a much larger disruption back in the spring, when transit through the waterway effectively seized up for a period before a fragile normalisation took hold. What’s notable now is that the “de-escalation trade,” as one market strategist put it recently, is looking fragile again rather than settled. Reports late last week suggested Pakistan and Qatar were once more acting as intermediaries on a possible short-term ceasefire, and prices did retrace intraday on those headlines — before contradictory statements from both sides pushed the market straight back up by the close.

Brent has now put in its strongest monthly run since March, briefly testing $90/bbl and settling in the high $80s. That’s roughly a 23% gain for the month at time of writing.

Where UK gas and power landed

The knock-on into UK markets has been sharp and fairly mechanical:

• NBP day-ahead pushed into the high 130s/low 140s p/th across the reporting window, with some desks flagging day-on-day moves in the high single digits.

• UK baseload day-ahead power swung hard — one desk logged a fall of over 25 on the previous settlement before jumping back close to 29 on the current offer, which tells you more about liquidity than direction. The forward curve was more consistent: Q4-26 baseload sits around 120–125 £/MWh, Winter-26 around 118–122 £/MWh, both up several pounds week-on-week.

• TTF followed NBP up, gaining comfortably over 1.5% across spot and front-month in the same window, and Asian JKM continues to sit at a material premium to European hubs — a reminder of where the marginal LNG cargo is actually going.

• Carbon was the odd one out: EUA drifted slightly lower even as everything else in the complex rallied, while UK ETS ticked up modestly. That divergence is worth sitting with for a moment, because it isn’t really about gas at all — it’s about Brussels.

The other story: Brussels quietly rewrites the ETS rulebook

While the desks were consumed with the Middle East, the European Commission tabled its long-awaited reform of the EU Emissions Trading System on 17 July — the framework that will govern Phase 5 of the scheme from 2031 through 2040.

The headline change is a slower reduction in the annual emissions cap: the linear reduction factor drops from the current 4.3% to 3.7% for 2031–2035 and then to 1.7% from 2036, pushing the point at which allowances are fully exhausted out from 2039 to somewhere between 2046 and 2048. Free allocation for energy-intensive industry — currently averaging 85% of covered emissions — is set to run at roughly 78% for 2026–2030, with new conditions attached from 2031: 80% of free allowances tied to published decarbonisation investment plans, the remaining 20% only released once emissions cuts are actually verified. There’s also room for a limited use of international carbon credits from 2036, capped well below what industry groups had lobbied for, and a fast-tracked revision to the “fallback benchmarks” used to calculate free allocation — worth an estimated €6bn to industry on its own.

Read together with this week’s price action, the signal is: less regulatory pressure pushing carbon higher over the next decade than the market had been assuming, at exactly the moment geopolitical risk is doing the opposite job on gas and power. That’s a genuinely interesting divergence for anyone running a combined hedging book, and one I’d expect to see picked apart in more detail as the co-decision process between Parliament and Council gets under way over the next year.

Storage: the number that should worry you more than Brent

Buried under the geopolitics is a fundamentals story that hasn’t gone away. European gas storage is sitting in the low-to-mid 50s percent full, somewhere between 10 and 16 percentage points below both last year’s level and the five-year average, depending on whose numbers you’re reading. Injection rates continue to lag seasonal norms. One desk’s own modelling, based on historical five-year average injection pace from current levels, projects storage reaching only around 71–72% full by 1 October — a number that, in a normal year, wouldn’t raise many eyebrows, but against this year’s starting point and this year’s geopolitical backdrop, gives the market very little cushion heading into winter.

LNG isn’t picking up the slack the way it has in previous tight years. Flows into Northwest Europe have been running at 12-month lows, roughly a quarter below the 30-day average, with Pakistan and other Asian buyers bidding aggressively for spot cargoes and pulling flexible LNG away from Europe. Add China’s structurally uncertain long-term appetite — analysts reportedly see a possible 32 million tonne swing in Chinese LNG demand by 2035 depending on how fast gas-fired generation shifts from baseload to backup duty — and you have a market where the marginal cargo is genuinely contested, not just expensive.

The bit that matters for procurement decisions

None of this is a call to panic-buy forward positions on a Tuesday morning headline. But three things are worth holding in mind if you’re advising on, or making, UK gas and power purchasing decisions right now:

1. The risk premium in the curve is doing real work, not just noise. Winter-26 and Q4-26 forward prices have moved several pounds in a matter of days on geopolitical headlines alone, before any change in underlying UK fundamentals. That’s a market pricing tail risk, not a market repricing supply and demand.

2. Storage math leaves little room for a cold snap or a supply shock. A market entering winter already 10+ points behind on storage doesn’t have the same buffer it had in recent milder years — and the LNG market it would normally lean on is tighter than usual.

3. Carbon costs are becoming a slower-moving, more predictable input than gas. With the ETS reform pointing towards a gentler compliance trajectory through the early 2030s, the carbon line of a forward cost stack may be the one part of the curve you can actually plan around with some confidence — even as gas and power stay reactive to headlines out of the Gulf.

Worth watching this week

• Whether the Pakistan/Qatar-brokered ceasefire talk resurfaces with anything more concrete than headlines.

• EU storage injection data over the coming fortnight — the 71% projection by October is a base case, not a guarantee.

• Early reaction from EU member states and Parliament to the ETS proposal; expect industry groups to push for even more flexibility, and NGOs to push back hard on the extended timeline.

• French nuclear availability — Golfech-2 and Chooz-2 restrictions tied to river cooling-water temperatures have already been a bigger driver of continental power pricing than most people are giving them credit for.

That’s the ledger for this week. As ever, treat every number above as indicative and time-stamped — by the time you’re reading this, at least one of them will have moved.

— Asher Kilbride

The Energy Ledger is an independent read on UK energy markets, policy and the people who run them. If this was useful, the best thing you can do is share it with one other person in the industry who'd find it useful too.

Power outpaced gas over the run, which tells you something about the fundamentals layered underneath the headline risk premium — more on that below.

The driver: Hormuz, tankers, and a tariff that came and went

The thread running through every single one of this week’s morning notes was the Strait of Hormuz. It started with US strikes on Iranian targets over the weekend of 11–12 July, which were met with Iranian attacks on Bahrain, Kuwait and Jordan. By Monday, markets were parsing genuinely mixed signals: Tehran declared the Strait closed, yet vessel-tracking showed at least one laden Qatari LNG carrier transiting with its AIS switched off — evidence that some physical flows were continuing even as the rhetoric hardened.

Tuesday brought a sharper escalation. Reports emerged of Iranian attacks on two UAE-flagged tankers, with casualties among the crew, followed by continued US strikes along the Iranian coastline. President Trump responded by floating a US-enforced blockade on Iranian ports and a proposed 20% transit fee on cargo moving through the Strait — a policy idea that, regardless of its practical implementation, immediately built a fresh risk premium into the front of the TTF curve. The logic was straightforward: a transit fee raises the delivered cost of Gulf LNG and oil, and it raises questions about future cargo availability, so the market moves first and asks about enforcement mechanisms later.

By Wednesday, the fee proposal was withdrawn just as quickly as it arrived, with Trump citing a preference for alternative trade arrangements with Gulf states. Prices eased on the news — briefly. But the underlying tension didn’t go anywhere, and by Thursday attention had broadened to include Red Sea shipping risk, with markets watching for any escalation in Houthi activity that could add a second chokepoint to the geopolitical calculus.

The net effect across four sessions: a market that repeatedly tried to fade the risk premium and repeatedly found a reason not to.

Underneath the headlines: fundamentals were leaning the same way

It would be too easy to say this was a purely geopolitical rally. The fundamentals gave the risk premium somewhere to land.

Storage is running behind schedule. EU gas storage sat at roughly 52% full through the week — about 10.5 percentage points below where it stood at this point last year. Net injection rates were consistently coming in below the pace required to reach the EU’s 90% target by 1 November, and day-on-day injection figures were themselves softening rather than accelerating. That’s a slow-burn structural support for the winter curve, independent of anything happening in the Gulf.

Weather turned unhelpful for renewables just as demand ticked up. UK wind generation was forecast to fall by around 36% to just 3.1 GW by mid-week, even as temperatures ran above seasonal norms across Northwest Europe. That combination — weaker wind, hotter weather — pushed gas-for-power demand higher and did real work in lifting the prompt, quite apart from the headline risk story.

Nuclear had a rough few days. Two unplanned outages hit Heysham 2-7 in quick succession through 15–16 July, on top of an unplanned reduction at Hartlepool-2, adding unexpected thinness to UK generation capacity right as demand firmed. Planned outages at Heysham 1 and Sizewell B were already baked into the curve, but the unplanned losses were a genuine surprise the market had to absorb in real time.

LNG kept arriving, but the mix is worth watching. North West Europe took steady cargoes from the US, Trinidad, Peru and Algeria through the week, alongside a scattering of Russian-origin volumes into Zeebrugge and Gate — a reminder that European LNG sourcing remains a genuinely global, and geopolitically sensitive, supply chain.

Power outperformed gas — why that matters

UK day-ahead power rose faster than gas over the four sessions, which usually signals something beyond a simple gas-pass-through. Nuclear unplanned outages and softer wind both point to a power-specific tightening layered on top of the gas-driven risk premium. Worth watching whether that gap persists once Heysham 2-7 returns to full capacity, expected around 20 July.

Carbon and currency: quieter, but not idle

EUA Dec-25 carbon added a modest 2.5% over the week, tracking broader energy sentiment without the same volatility as gas or power — a reminder that carbon remains sensitive to macro energy direction but rarely leads it. UK ETS carbon moved rather more sharply, up close to 7% over the same period, a gap between the UK and EU carbon markets worth keeping an eye on for anyone running cross-scheme hedges.

Sterling, meanwhile, weakened modestly against the dollar through the week — a dynamic that matters for anyone pricing dollar-denominated LNG or Brent-linked contracts into GBP exposure, since currency moves were compounding rather than offsetting the commodity price rise.

What to watch next

● Hormuz transit conditions. The transit fee proposal may be dead for now, but the underlying tension between Washington, Tehran and Gulf shipping isn’t resolved. Any further escalation — or genuine de-escalation — will move the front of the curve fast.

● UK storage refill pace. With injections running below the trajectory needed for a 1 November target, this is a slower-moving but arguably more durable story than the geopolitical headlines.

● Nuclear return-to-service dates. Heysham 2-7’s restoration timeline is worth tracking closely given its role in this week’s power outperformance.

● Red Sea shipping risk. A second chokepoint story would add a further layer of complexity to an already jumpy market.

None of this is trading advice — just an honest account of what moved the UK energy complex this week, and why. As ever, more to come.

— Asher Kilbride

The Energy Ledger tracks UK energy markets, policy and the people shaping the sector, for those who work in and around it. If this was useful, consider sharing it with a colleague.

That’s what The Energy Ledger is for.

Each week, I read through the industry noise and tell you what actually matters and why. Not headlines repackaged. Not cheerleading for renewables or nostalgia for fossil fuels. Just clear-eyed synthesis from someone whose job is to have already done the reading. The first full issue lands this week.

The Energy Ledger is free to read for now. If it’s useful to you, the best thing you can do is reply and tell me what you want covered — the direction of this newsletter over the next few months will be shaped in large part by that feedback.

Welcome aboard.

Asher