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