Explainer: Peaker plant replacement & capacity markets — what it is, why it matters, and how to evaluate options

The UK's gas-fired peaker plants ran for an average of just 152 hours in 2025, yet they accounted for over £1.8 billion in capacity market payments, according to National Grid ESO's 2025 Electricity Capacity Report. These plants, designed to fire up during the handful of peak demand hours each year, are among the most carbon-intensive and least efficient assets on the grid: typical open-cycle gas turbines (OCGTs) operate at 30 to 38% thermal efficiency compared to 55 to 60% for combined-cycle plants, while emitting 450 to 600 grams of CO2 per kWh. As battery storage costs have fallen 89% since 2010 and demand response platforms have matured, a growing body of evidence shows that clean alternatives can now match or beat peaker plants on both cost and reliability. For sustainability professionals navigating energy procurement, corporate power purchase agreements, or net-zero strategy, understanding how capacity markets work and how peaker replacement is reshaping them is essential to making informed decisions.

Why It Matters

Peaker plants represent a structural vulnerability in the energy transition. They exist because electricity grids must balance supply and demand in real time, and demand peaks, driven by cold winter evenings, summer heatwaves, or industrial surges, require dispatchable capacity that can ramp quickly. In the UK, peak demand can exceed average demand by 15 to 20 GW, creating a need for 10 to 15 GW of flexible capacity that operates infrequently but must be available on short notice.

The UK's Capacity Market, introduced in 2014, was designed to ensure this reliability by paying generators to be available during stress events, regardless of whether they actually dispatch. In the 2024/25 T-4 auction, the market cleared at £63 per kW per year, awarding contracts worth approximately £2.1 billion to a mix of gas peakers, battery storage, demand-side response (DSR), and interconnectors (DESNZ, 2025). Gas-fired plants still captured roughly 40% of total capacity market revenues, despite providing a declining share of actual peak generation.

The problem is twofold. First, these plants lock in fossil fuel infrastructure through contracts lasting up to 15 years, creating stranded asset risk as the grid decarbonizes. Second, they impose direct costs on consumers: capacity market charges add approximately £25 to £30 per year to the average UK household electricity bill. For corporate energy buyers, capacity charges can represent 5 to 10% of total electricity costs, making them a meaningful line item in procurement budgets.

Regulatory pressure is intensifying. The UK's 2024 Clean Power Action Plan targets a fully decarbonized electricity grid by 2030, which implies that unabated gas peakers must either retrofit with carbon capture, convert to hydrogen, or be replaced by clean alternatives within the next four years. The UK Emissions Trading Scheme (UK ETS) carbon price, averaging £45 to £55 per tonne of CO2 in 2025, adds £20 to £33 per MWh to the operating cost of gas peakers, further eroding their competitiveness against zero-marginal-cost alternatives (DESNZ, 2025).

Key Concepts

Capacity market: A mechanism used by grid operators to ensure sufficient generation or demand reduction capacity is available to meet peak demand. In the UK, National Grid ESO runs annual auctions where capacity providers bid to deliver a specified amount of power (in MW) during system stress events. Successful bidders receive monthly payments for being available, separate from any revenue earned from actually generating electricity.

Peaker plant: A power generation facility designed to operate during periods of peak electricity demand. Traditional peakers are open-cycle gas turbines (OCGTs) or reciprocating gas engines that can start within 5 to 15 minutes and ramp to full output rapidly. They typically operate fewer than 500 hours per year but must be available year-round. In the UK, approximately 12 GW of gas peaker capacity is registered in the Capacity Market (Ofgem, 2025).

Battery energy storage systems (BESS): Lithium-ion battery installations that can charge during periods of low demand and discharge during peaks. Modern grid-scale BESS can respond in under one second, far faster than any gas turbine, and provide 1 to 4 hours of sustained output. The UK had 4.8 GW of operational battery storage by the end of 2025, with an additional 38 GW in the planning pipeline (Solar Media, 2025).

Demand-side response (DSR): Programs that incentivize electricity consumers to reduce or shift their consumption during peak periods. Industrial load shifting, smart EV charging, heat pump flexibility, and commercial building HVAC management can collectively provide gigawatts of peak reduction. The UK's DSR capacity in the Capacity Market grew from 1.1 GW in 2020 to 3.4 GW in 2025.

De-rating factors: The percentage of a technology's nameplate capacity that the Capacity Market credits as reliable during stress events. Gas peakers receive de-rating factors of 90 to 95%, while 1-hour batteries receive approximately 47% and 2-hour batteries approximately 72%. This means a 100 MW battery with a 2-hour duration is credited as only 72 MW of capacity, requiring more installed capacity to displace an equivalent gas peaker.

Clean power action plan: The UK government's framework for achieving a decarbonized electricity system by 2030, which includes provisions for phasing out unabated gas generation, scaling battery storage, expanding offshore wind, and reforming capacity market rules to favor low-carbon technologies.

What's Working

Battery storage is winning capacity auctions at scale. In the UK's 2024 T-1 and T-4 Capacity Market auctions, battery storage secured over 4.2 GW of new agreements, surpassing new-build gas peaker awards for the third consecutive year. The levelized cost of battery storage for peaking applications has fallen to £8 to £12 per kW per year on a de-rated basis, compared to £15 to £25 per kW per year for new-build gas peakers when carbon costs are included (Bloomberg NEF, 2025). Projects like the 300 MW / 600 MWh Thurrock Flexible Generation plant in Essex, commissioned in late 2025, demonstrate that 2-hour battery systems can provide sustained peak capacity at grid scale while also capturing revenue from frequency response, wholesale arbitrage, and balancing mechanism services.

Demand-side response is scaling beyond industrial loads. Aggregators such as Flexitricity, Limejump (now part of Shell Energy), and Octopus Energy have expanded DSR portfolios to include commercial buildings, EV charging networks, and residential heat pumps. Octopus Energy's Kraken platform manages over 1.5 GW of flexible demand across the UK, enabling households with smart tariffs to shift consumption away from peak periods in exchange for lower rates. The 2025 Capacity Market results showed DSR clearing at prices 20 to 35% below gas peaker bids, demonstrating cost competitiveness even before accounting for avoided carbon emissions.

Hybrid projects are combining renewables, storage, and gas backup. Several developers in the UK are deploying hybrid configurations that pair solar or wind with battery storage and retain a small gas engine as a last-resort backup. Harmony Energy's 196 MW / 392 MWh Pillswood battery project in East Yorkshire operates alongside co-located solar generation, capturing both renewable generation revenues and capacity market payments. This approach allows projects to compete directly with gas peakers while delivering 80 to 95% emission reductions compared to a standalone OCGT.

What's Not Working

Duration limitations constrain battery replacement of multi-hour peaks. Most UK grid-scale batteries are configured for 1 to 2 hours of duration, which is sufficient for typical demand spikes but falls short during extended cold snaps or prolonged low-wind events. The January 2025 cold spell saw elevated demand for over 14 consecutive hours, a scenario where short-duration batteries would exhaust their stored energy and require gas backup. Long-duration energy storage (LDES) technologies such as compressed air, liquid air, and flow batteries remain 2 to 3 times more expensive than lithium-ion per kWh and have limited commercial deployment in the UK, with total LDES capacity below 500 MW (UK Energy Research Centre, 2025).

Capacity market design still favors incumbent gas plants. The current auction structure awards 15-year contracts to new-build capacity but only 1-year contracts to existing assets, which creates a perverse incentive to build new gas peakers that lock in fossil fuel capacity for over a decade. Additionally, de-rating factors penalize shorter-duration storage technologies, requiring battery developers to overbuild capacity to match the market credit of a gas plant. Proposed reforms to introduce a "clean capacity" pot in the auction have been delayed, with implementation not expected before the 2026/27 delivery year.

Planning and grid connection delays bottleneck clean alternatives. The UK has a grid connection queue exceeding 700 GW, with average wait times of 10 to 14 years for new projects seeking transmission-level connections. While battery storage projects can often connect at distribution level with shorter timelines (2 to 4 years), the queue backlog means many shovel-ready peaker replacement projects cannot reach the grid in time to displace retiring gas plants before the 2030 clean power target. National Grid's 2025 Connections Reform program aims to reduce queue times to 5 years, but industry stakeholders have expressed concern about implementation pace.

Hydrogen conversion pathways remain uncertain and expensive. Some peaker plant operators propose converting existing gas turbines to run on hydrogen as a zero-carbon alternative. However, green hydrogen costs in the UK currently range from £5 to £8 per kg (equivalent to £150 to £240 per MWh on a thermal basis), making hydrogen peaking 3 to 5 times more expensive than natural gas peaking per MWh of electricity output. The UK's hydrogen production capacity in 2025 was approximately 0.5 GW, well below the 10 GW target for 2030, and no commercial-scale hydrogen peaker has yet operated in the UK (Hydrogen UK, 2025).

Key Players

Established Companies

• National Grid ESO: operates the UK Capacity Market and system balancing mechanisms that determine peak capacity requirements
• SSE Thermal: operates 4.6 GW of thermal generation in the UK including peaker plants, with plans to convert or retire unabated gas assets by 2030
• Harmony Energy: developed the UK's largest battery storage projects including the 196 MW Pillswood site in East Yorkshire
• EDF Energy: manages a diversified UK generation portfolio including nuclear, renewables, and gas peakers, with active investment in battery storage co-location

Startups

• Field Energy: UK-based battery storage developer with over 2 GW in development, focused on 2 to 4 hour duration systems for capacity market applications
• Zenobe Energy: specializes in battery storage and EV fleet electrification, operating over 800 MWh of storage capacity across the UK
• Habitat Energy: AI-driven battery optimization platform that maximizes revenue from capacity market, frequency response, and wholesale arbitrage for storage assets
• Highview Power: develops liquid air energy storage (LAES) for long-duration applications, with a 50 MW / 250 MWh demonstration plant in Manchester

Investors and Funders

• Gresham House Energy Storage Fund: listed fund with over £600 million invested in UK battery storage assets providing capacity market services
• Gore Street Energy Storage Fund: London-listed fund with 1.2 GW of operational and under-construction battery storage across the UK and internationally
• UK Infrastructure Bank: provided £200 million in financing for grid-scale storage and flexible generation projects since its establishment in 2021

Key Metrics

Metric	Current State	Target (2030)	Unit
UK gas peaker capacity in Capacity Market	~12 GW	<3 GW unabated	GW
UK battery storage operational capacity	4.8 GW	20-25 GW	GW
Capacity Market clearing price (T-4)	£63/kW/yr	£40-55/kW/yr (with clean pot)	£ per kW per year
DSR capacity in Capacity Market	3.4 GW	8-10 GW	GW
Average battery duration (grid-scale)	1.5 hours	2-4 hours	hours
Grid connection queue wait time	10-14 years	5 years (target)	years

Action Checklist

• Audit your organization's electricity procurement contracts to identify capacity charge exposure and the proportion attributable to gas peaker capacity
• Evaluate whether on-site or behind-the-meter battery storage could reduce peak demand charges and provide backup power during grid stress events
• Engage with DSR aggregators to assess the flexibility potential of your building portfolio, EV fleet, or industrial processes
• Review corporate PPA structures to ensure they include provisions for capacity market revenue sharing as clean alternatives displace gas peakers
• Monitor UK Capacity Market auction results and proposed rule changes, particularly the introduction of a clean capacity allocation
• Assess exposure to stranded asset risk if your organization holds equity in or long-term contracts with gas peaker facilities
• Include peaker replacement considerations in net-zero transition plans, aligning corporate energy strategy with the UK's 2030 clean power target
• Evaluate long-duration energy storage partnerships for sites requiring more than 2 hours of backup capacity during extended peak events

FAQ

Q: Can battery storage fully replace gas peaker plants today? A: For short-duration peaks lasting 1 to 2 hours, yes. Grid-scale lithium-ion batteries can respond faster than gas turbines (sub-second vs. 5 to 15 minutes), deliver equivalent or greater capacity, and do so at lower cost when carbon pricing is factored in. The UK's 4.8 GW of operational battery storage already provides meaningful peak capacity. However, for extended peak events lasting 4 to 14 hours, which occur during cold snaps or prolonged low-wind periods, current battery technology cannot fully substitute for dispatchable gas generation without significant overbuilding. Addressing this gap requires either longer-duration batteries (4+ hours), complementary LDES technologies, or demand-side flexibility. Most grid modeling suggests that a combination of 2 to 4 hour batteries, DSR, and a residual amount of gas or hydrogen backup will be needed through at least 2035.

Q: How does the UK Capacity Market work, and how are clean technologies changing it? A: The Capacity Market runs annual auctions where generators and demand-side providers bid to deliver specified capacity during system stress events. Winners receive monthly payments for availability, regardless of dispatch. Historically, gas peakers dominated these auctions because they offered firm, dispatchable capacity at competitive clearing prices. Since 2022, battery storage has won an increasing share of capacity agreements, driven by falling costs and the ability to stack revenue from multiple market services (capacity payments, frequency response, wholesale arbitrage, and balancing mechanism). Proposed reforms include a dedicated "clean capacity" auction pot that would ring-fence a portion of capacity procurement for zero-carbon technologies, further accelerating the displacement of gas peakers.

Q: What are the financial risks of continuing to invest in or contract with gas peaker plants? A: Gas peakers face three categories of financial risk. First, carbon cost risk: the UK ETS price is expected to rise from current levels of £45 to £55 per tonne toward £80 to £100 per tonne by 2030 under the UK's carbon budget trajectory, adding £36 to £60 per MWh to operating costs. Second, stranded asset risk: if capacity market reforms exclude unabated gas plants from long-term contracts, existing peakers may lose their primary revenue stream. Third, competitive displacement risk: as battery storage costs continue to fall (projected 20 to 30% reduction by 2028), gas peakers will be increasingly unable to compete in capacity auctions. Organizations with exposure to gas peaker assets or long-term tolling agreements should model these scenarios and consider portfolio diversification toward clean flexible capacity.

Q: What role does demand-side response play in replacing peaker plants? A: DSR is one of the most cost-effective peaker replacement strategies because it avoids the capital cost of building new generation or storage entirely. By reducing demand during peak periods rather than increasing supply, DSR lowers total system costs. In the UK, DSR capacity has grown from 1.1 GW to 3.4 GW between 2020 and 2025, with further growth expected as smart meters reach 80%+ penetration, EV charging becomes more flexible, and heat pump installations scale. For corporate energy buyers, participating in DSR programs can generate £30 to £80 per kW per year in availability payments while reducing peak demand charges. The primary limitation is that DSR availability depends on consumer behavior and operational constraints, making it less firm than dedicated generation or storage.

Sources

• National Grid ESO. (2025). Electricity Capacity Report 2025: Capacity Market Performance and Outlook. Warwick: National Grid ESO.
• Department for Energy Security and Net Zero (DESNZ). (2025). Clean Power Action Plan: Capacity Market Reform Proposals. London: UK Government.
• Ofgem. (2025). State of the Energy Market 2025: Capacity and Flexibility Assessment. London: Office of Gas and Electricity Markets.
• Bloomberg NEF. (2025). UK Battery Storage Market Outlook: Costs, Revenues and Policy Drivers. London: BNEF.
• Solar Media. (2025). UK Battery Storage Project Database: Pipeline and Operational Capacity Tracker Q4 2025. London: Solar Media.
• UK Energy Research Centre. (2025). Long Duration Energy Storage in Great Britain: Technologies, Costs and System Value. London: UKERC.
• Hydrogen UK. (2025). UK Hydrogen Sector Development Report 2025. London: Hydrogen UK.