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Reports Summer heat, winter prices: GB electricity market summary Q3 2026

Summer heat, winter prices: GB electricity market summary Q3 2026

Rising gas prices pushed GB day-ahead power up 69% in Q3 2026.

This report from Montel’s power market analysts reviews how the GB electricity market performed between July and September 2026. Record-breaking temperatures, rising gas prices and highly variable renewable output all shaped prices over the quarter. The report explains why wholesale prices reached their highest levels in September, how the Q4 baseload contract rose around 50% during the quarter, and what that repricing says about expectations for winter.

Q3 2026 at a glance

  • Day-ahead power: EPEX prices averaged £122.61/MWh, up 69% on Q3 2025

  • Q4 baseload contract: rose from around £98/MWh to £147/MWh, after peaking at £164.95/MWh on 14 September

  • Renewable generation: 34.3 TWh, 54% of total supply and 8% higher than Q3 2025

  • Wind curtailment: around 2.9 TWh, approximately 14% of potential wind generation

  • Negative prices: 17 hours, down from 49 in Q2

  • Net imports: 6.7 TWh, 15% lower than Q3 2025

Inside the report

  • Executive summary. The main forces behind GB prices in Q3, from repeated heatwaves to the rise in NBP gas prices

  • Q3 review. How gas prices, wholesale power prices, CCGT generation and interconnector restrictions developed through the quarter

  • Key takeaways. Generation by fuel type, nuclear life extensions at Sizewell B, Heysham 1 and Hartlepool, and the scale of wind curtailment

  • Temperature and negative pricing. How five heatwaves by mid-August strained the system, and why negative prices became less frequent

  • Q4 outlook. How the forward contract for Q4 baseload power was repriced during the quarter

  • Supporting tables. Quarterly generation and price data, with year-on-year Q3 comparisons back to 2018

Key takeaways

  • Rising gas prices were the main driver of GB power prices in Q3 2026, as renewed hostilities between the US and Iran disrupted LNG shipping through the Strait of Hormuz.

  • NBP gas prices reached their highest level since December 2022.

  • EPEX day-ahead power prices averaged £122.61/MWh, 69% higher than a year earlier.

  • Renewables supplied 54% of GB electricity, but stronger wind in September put more pressure on the grid, with around 2.9 TWh of potential wind generation curtailed across the quarter.

  • Repeated heatwaves tightened the system around the evening peak as solar output fell.

  • Negative prices became less frequent, falling from 49 hours in Q2 to 17.

  • The Q4 baseload contract ended September around 50% above its level at the start of July.

What you’ll learn

  • Why NBP gas prices reached their highest level since December 2022, and how that fed through to power prices

  • How heat and falling solar output tightened the system around the evening peak

  • Why CCGT output swung from around 4.0 GW at midday to more than 17 GW at its quarterly peak

  • How NESO’s day-ahead capacity limits restricted exports across Nemo Link, Viking Link, ElecLink and North Sea Link

  • Why September accounted for almost two-thirds of the quarter’s wind curtailment

  • What the rise in the Q4 baseload contract says about power price expectations for winter

Who this is for

  • Traders and analysts tracking the drivers behind GB power and gas prices

  • Portfolio and risk managers preparing for winter price risk

  • Power producers and wind farm operators assessing curtailment, constraints and capture prices

  • Procurement and corporate energy teams planning purchases and budgets

FAQ

  • EPEX day-ahead prices averaged £122.61/MWh, up 69% on Q3 2025. Prices broadly tracked rising NBP gas prices and peaked in September.
  • Renewed hostilities between the US and Iran disrupted LNG shipping through the Strait of Hormuz, while low European gas storage and planned Norwegian maintenance added pressure. NBP day-ahead prices briefly exceeded £70/MWh in mid-September.
  • Around 2.9 TWh of potential wind generation was turned down through the Balancing Mechanism, approximately 14% of total potential wind output. Around 1.8 TWh of that was in September.
  • Higher gas prices lifted the underlying price level, so periods of strong renewable output pushed prices below zero less often. The GB day-ahead auction recorded 17 negative-price hours, down from 49 in Q2.
  • The Q4 baseload contract ended September at £147/MWh, around 50% above its level at the start of July, reflecting higher expected gas costs, low storage and uncertainty over LNG supply.