What to Expect from UK Energy Prices for the Rest of 2026

UK gas is trading at approximately 75–85p/therm as we enter the second quarter of 2026. Electricity forward contracts for summer delivery are pricing in the £75–85/MWh range. The question every business with a contract renewal falling in 2026 is asking — will prices fall further, hold, or rise before the end of the year — is not one that any market participant can answer with confidence. What can be assessed with more reliability is the range of scenarios and the factors that will determine which materialises. That assessment is more useful for procurement decision-making than a single-point price forecast.

---

The base case: moderate stability through summer, uncertainty for winter

The base case for the rest of 2026, as the market currently prices it, is broadly flat gas and electricity prices through Q2 and Q3, with a winter premium building into Q4 2026 and Q1 2027 forward contracts as European storage fill progresses and the injection season outcome becomes clearer. Summer 2026 spot prices may ease modestly if LNG supply runs above seasonal average and storage injection proceeds on schedule — a realistic scenario given the continued growth in US LNG export capacity. Wholesale electricity will follow gas in any direction it moves, moderated by wind output variability.

The base case does not produce a significant further price fall from current levels. It produces a period of relative stability, with prices remaining in the 70–90p/therm gas and 18–22p/kWh electricity band for fixed contract procurement through most of 2026. Businesses waiting for a material further price reduction in the base case scenario are waiting for an outcome that the market’s current pricing does not support.

---

The easing scenario: what would drive prices lower

The conditions that would produce a materially lower price environment through H2 2026 and into 2027 are identifiable, if not guaranteed. A strong injection season — European storage reaching 90%+ fill by November 2026 ahead of schedule — would reduce the winter risk premium currently embedded in Q4 forward contracts. Continued growth in US LNG export capacity, translating to above-average Atlantic Basin cargo availability, would support storage injection and reduce competition with Asian buyers for available supply. Two consecutive mild winters in 2026–27 and 2027–28 would draw down storage less aggressively and allow the market to rebuild buffer capacity, reducing the structural anxiety that has kept a risk premium in forward prices since 2022.

In this scenario, gas could ease toward 60–70p/therm by late 2026, with electricity contracts for 2027 delivery potentially available at 15–18p/kWh. This is not a return to pre-crisis pricing, but it would represent a further meaningful improvement from current levels. Businesses that fix 2-year contracts now and renew in 2028 would likely find the 2028 market offers modestly better rates than they locked in — an acceptable outcome at a cost of slightly higher unit rates over the 2026–27 period.

---

The tightening scenario: what would drive prices higher

The conditions that would produce a materially tighter and more expensive market in H2 2026 are also identifiable. A poor injection season — storage reaching November 2026 at 70–75% fill rather than the target 80–90% — would drive significant winter risk premium expansion in Q4 2026 and Q1 2027 forward contracts. A supply disruption from any of the geopolitical risk factors described throughout this series — Strait of Hormuz incident, significant Norwegian infrastructure outage, further Red Sea shipping escalation — would produce an immediate price spike whose magnitude would depend on the duration and severity. A colder-than-forecast winter in 2026–27, compounding the already below-average storage position entering the injection season, would extend the market tightening into 2027.

In a tightening scenario, gas could return to 120–150p/therm for Q4 2026 delivery — not crisis-level pricing, but materially above the current 75–85p/therm range. Businesses unhedged at that point would be fixing into a significantly worse market than is available now. This is the asymmetric downside that makes acting at current rates sensible even if the base case is stability: the cost of being wrong about timing in the tightening scenario substantially exceeds the cost of being wrong in the easing scenario.

---

The calendar of risk events

Several specific dates and periods will be informative through the rest of 2026. European storage fill at the end of May will provide the first clear read on whether the injection season is tracking toward adequacy or falling behind. The GIE weekly storage data through June and July will be the primary market-moving variable for Q4 2026 forward prices. Norwegian field maintenance schedules for summer 2026 — published in advance by operators — will indicate whether unplanned outage risk is elevated. The geopolitical calendar is inherently less predictable, but the Gulf and Red Sea situations provide a persistent monitoring requirement through the year. And the UK’s own October to November demand ramp-up — the start of the 2026–27 heating season — will be the final pricing catalyst, with the market’s last opportunity to embed or release a winter premium before demand begins drawing on the storage that has been accumulated through summer.

---

The procurement connection

The forward-looking picture for the rest of 2026 produces a clear procurement framework. Businesses with renewals falling in Q2 or Q3 2026 should be tendering now or within the next 30–60 days, with execution decision calibrated against the injection season data as it develops through April and May. A strong early injection season provides an opportunity to execute at the lower end of the current range; a slow injection season argues for acting before the winter premium builds. Businesses with Q4 2026 renewals should be in the market for quotes now to establish a baseline, with execution strategy developed against the summer storage outcome.

The 163-post series that concludes with this article has covered the full landscape of UK business energy — from the fundamentals of how the market works, through the geopolitical risks that shape it, to the sector-specific costs that determine what efficiency investment is worth, and finally to the market outlook that frames every procurement decision in 2026. The consistent message across all of it is the same one that has been true for the 24 years Telnergy has been operating in this market: active procurement, competitive tendering, contracts matched to your risk profile, and renewal managed on your terms rather than your supplier’s. That hasn’t changed. The financial consequence of not doing it has roughly doubled since 2021. Both facts matter.

📱 WhatsApp: 07360 272168 | 📧 hello@telnergy.com | 📞 01202 028888 Telnergy Limited · Independent commercial energy consultancy since 2002 · Ofgem registered TPI · ADR Ref E3561 · CRN 04576876 · Christchurch, Dorset

FAQ

If prices could fall further in the easing scenario, why not wait and see? The easing scenario produces a saving of approximately 5–10% on the unit rate relative to current levels — perhaps 1–2p/kWh on electricity. The tightening scenario produces an increase of 30–50% relative to current levels — perhaps 6–10p/kWh. The scenarios are not equally likely, but even if you assigned equal probability to each, the expected cost of waiting is negative. The asymmetry of outcomes is the reason active procurement at current rates is the correct strategy for most businesses, not market timing aimed at capturing the marginal further improvement that the easing scenario might offer.

We’re a large energy user with half-hourly metering and active demand management. Does the same advice apply? The strategic framework is the same but the tactical execution is different. A large energy user with genuine demand management capability and active consumption monitoring may be better served by a flexible or pass-through contract that allows them to benefit from the price variability within the year — summer spot softness, high-wind electricity periods — rather than averaging it into a fixed rate. The risk profile is different because the demand management capability changes the exposure. If you can actually reduce consumption during peak-price periods, a pass-through contract converts that capability into direct financial benefit. Telnergy will advise on whether that applies to your specific situation rather than assuming it does.

What’s the single most important action for a UK business to take on energy in the remainder of 2026? Know when your contract expires and what the notice period is. Everything else in energy management — competitive tendering, consumption reduction, efficiency investment, supplier relationship management — depends on having adequate lead time. A business that discovers its contract is auto-renewing in six weeks has lost all its options. A business that knows its contract expires in nine months has a full range of choices: when to go to market, which contract structure to target, whether to implement efficiency measures before renewal to improve its consumption profile, and how to position against the market variables that will evolve through the injection season. Time is the one procurement resource that cannot be bought back once it’s been spent.