Myth-busting Peaker plant replacement & capacity markets: separating hype from reality

Natural gas peaker plants still provide roughly 10% of Europe's electricity generation capacity, yet they operate on average fewer than 500 hours per year, making them among the most carbon-intensive and least efficient assets on the grid (European Network of Transmission System Operators for Electricity, 2025). As battery storage costs have fallen 89% since 2010 and demand response programs have matured, a growing chorus of advocates claims that peakers are already obsolete. The reality is more complicated. Separating genuine disruption from premature declarations of victory is essential for founders building companies in this space and for investors sizing the actual addressable market.

Why It Matters

Europe's capacity markets, the mechanisms that pay generators to be available during peak demand, direct more than EUR 30 billion annually toward ensuring grid reliability across the EU (Agency for the Cooperation of Energy Regulators, 2025). These markets determine which technologies receive long-term revenue contracts and, by extension, which assets attract financing. For founders, the rules governing capacity markets shape product-market fit: whether a battery storage system, virtual power plant, or demand response platform can compete against incumbent gas peakers depends on how capacity is defined, procured, and compensated.

The stakes are rising. The European Commission's revised Electricity Market Design regulation, finalized in 2024, introduced emissions performance standards that exclude new fossil fuel assets from capacity mechanisms starting in 2028. Existing peakers with emissions above 550 gCO2/kWh face phase-out timelines that vary by member state. Germany has set a 2030 deadline, while Poland has negotiated an extension to 2035. These regulatory shifts are creating a window of opportunity for clean alternatives, but the window's dimensions are frequently overstated in pitch decks and market analyses.

Key Concepts

Peaker plants are generation assets designed to operate only during periods of peak electricity demand, typically summer cooling loads or winter heating spikes. In Europe, the most common peaker type is the open-cycle gas turbine (OCGT), which can ramp from cold start to full output in 10 to 30 minutes. Combined-cycle gas turbines (CCGTs) are also used but have longer start-up times and are better suited to mid-merit operation.

Capacity markets are regulatory mechanisms that compensate electricity providers not just for the energy they generate but for their availability to generate on demand. The UK Capacity Market, operational since 2014, is Europe's largest and most mature, clearing approximately 43 GW of capacity in its 2025 T-4 auction. France, Italy, Ireland, Belgium, and Poland also operate capacity mechanisms, each with distinct rules governing technology eligibility, contract duration, and performance requirements.

Peaker replacement refers to substituting gas peakers with combinations of battery energy storage systems (BESS), demand response aggregation, and in some cases distributed energy resources coordinated through virtual power plants. The replacement is not one-for-one: batteries provide 1 to 4 hours of duration versus a peaker's ability to run for 8 or more hours, requiring different system planning approaches.

Myth 1: Batteries Can Already Replace All Peaker Plants Economically

The claim that lithium-ion batteries are cheaper than gas peakers in all EU markets oversimplifies a complex economic comparison. Bloomberg New Energy Finance's 2025 analysis found that 4-hour battery storage systems are cost-competitive with new-build OCGTs in markets where annual peaker utilization is below 200 hours, which applies to roughly 40% of European peaker capacity (BNEF, 2025). For the remaining 60%, where peakers operate 300 to 800 hours annually, batteries face a duration gap: a 4-hour battery dispatched daily during multi-day heat events or extended cold spells cannot provide equivalent reliability without oversizing or pairing with other resources.

The UK's experience illustrates the nuance. National Grid ESO's 2025 Winter Outlook identified 6 GW of peaking capacity needed during sustained cold snaps lasting 3 to 5 days. Existing 2-hour and 4-hour BESS installations, totaling approximately 4.8 GW by end of 2025, could cover intra-day peaks but could not sustain output across multi-day events without daily recharging from other generation sources. The economics work for short-duration peaks; they do not yet work for the long-tail reliability events that define capacity adequacy requirements.

In Germany, the Bundesnetzagentur's 2025 capacity adequacy assessment concluded that at least 15 GW of dispatchable, duration-flexible capacity will be needed through 2035 even under aggressive renewable and storage deployment scenarios, suggesting a continued role for flexible gas capacity (ideally hydrogen-ready) alongside batteries.

Myth 2: Demand Response Can Fill the Gap That Batteries Cannot

Demand response is frequently presented as the complement that closes the duration gap between batteries and peakers. While industrial demand response has proven effective in specific applications, the aggregate available capacity in European markets remains modest relative to need. ENTSO-E's 2025 demand response inventory found that explicit demand response capacity across the EU totaled approximately 18 GW, compared to roughly 75 GW of gas peaking capacity (ENTSO-E, 2025). Moreover, much of the registered demand response capacity has not been tested under prolonged stress conditions.

France's experience during the January 2025 cold spell is revealing. RTE activated demand response programs across industrial and commercial customers, achieving 3.2 GW of load reduction during the first two days. By day four, effective demand response had declined to 1.8 GW as participating facilities reached operational limits on how long they could curtail production without incurring unacceptable commercial losses. The myth is not that demand response is ineffective but that it scales linearly and indefinitely during extended stress events. It does not.

The UK's Demand Flexibility Service, launched in 2022, demonstrated that residential demand response could contribute 1 to 2 GW during evening peaks but exhibited participation rates that varied from 40% on mild evenings to 15% during the coldest periods when consumers were least willing to reduce heating load. Reliability during the moments when capacity is most needed remains demand response's core challenge.

Myth 3: Capacity Markets Are Fossil Fuel Subsidies That Should Be Abolished

Critics often characterize capacity markets as backdoor subsidies for gas plants. This framing ignores the technology-neutral design of most European capacity mechanisms and the growing share of clean resources clearing these auctions. In the UK's 2025 T-4 capacity auction, battery storage secured 3.1 GW of contracts (approximately 7% of total cleared capacity), up from 0.5 GW in 2020. Demand-side response units cleared 2.4 GW. Interconnectors secured another 4 GW. Gas plants still dominate, but the trajectory is shifting.

Italy's capacity market reform in 2024 introduced technology-specific reliability derating factors that adjust payments based on proven availability during stress events. BESS received a derating factor of 85% for 4-hour systems, recognizing that their contribution to multi-day adequacy is lower than a gas plant's. This approach, rather than abolishing capacity markets, reforms them to reward actual reliability performance regardless of fuel source.

Abolishing capacity markets without a replacement mechanism risks underinvestment in flexible capacity. Belgium's analysis of an energy-only market scenario found that removing capacity payments would reduce investment signals for new flexibility resources by an estimated EUR 1.2 billion annually, potentially leading to capacity shortfalls during 1-in-20-year stress events (Elia Group, 2025).

Myth 4: Hydrogen-Ready Gas Turbines Are Greenwashing

Skeptics dismiss hydrogen-ready turbines as rebranding exercises for fossil fuel assets. The technical reality is more substantiated than critics acknowledge, though less advanced than manufacturers claim. Siemens Energy's SGT-800 turbine has been commercially demonstrated operating on 75% hydrogen blends at the Vattenfall plant in Hamburg, with 100% hydrogen operation validated in controlled test conditions. GE Vernova reports that its HA-class turbines have accumulated over 9 million operating hours on hydrogen blends of up to 50% across 100 installations globally (GE Vernova, 2025).

The legitimate criticism is about timing and infrastructure. Green hydrogen production in Europe reached only 0.1 GW of electrolyzer capacity by end of 2025, far below the tens of gigawatts needed to fuel a converted peaker fleet. The European Hydrogen Backbone consortium projects sufficient pipeline infrastructure for industrial hydrogen distribution by 2035, but peaker plants located away from planned hydrogen corridors may never economically access green hydrogen. Hydrogen-ready is technically real but commercially contingent on infrastructure that does not yet exist at scale.

What's Working

Short-duration peak shaving with batteries is delivering results. Zenobe Energy operates 1.2 GW of battery storage across the UK, with its portfolio achieving 97% availability during the 2025 winter stress periods and earning capacity market revenues averaging GBP 35 per kW per year. In Ireland, the DS3 system services program has integrated 700 MW of battery storage that provides sub-second frequency response and peak capacity, reducing the system's reliance on distillate oil peakers by approximately 25% since 2022 (EirGrid, 2025).

Hybrid peaker replacement projects combining batteries with solar or wind generation are proving viable in southern European markets. In Spain, Iberdrola's 200 MW Revilla-Vallejera project pairs 50 MW of battery storage with 150 MW of solar PV, contracted to provide firm capacity equivalent to a 50 MW OCGT. The project's levelized cost of firm capacity is approximately 30% below a new gas peaker, supported by Spain's favorable solar resource and low land costs.

Virtual power plants aggregating distributed resources are gaining regulatory acceptance. Next Kraftwerke, now part of Shell, operates Europe's largest VPP at over 16 GW of aggregated capacity across 14 countries, participating directly in capacity mechanisms in Germany, Belgium, and France.

What's Not Working

Long-duration storage technologies needed to fully replace peakers during multi-day events remain pre-commercial. Compressed air energy storage (CAES) and iron-air batteries from companies like Form Energy have demonstrated technical feasibility, but no commercial-scale project has delivered capacity market-qualified performance data in any European market. Form Energy's first commercial project in West Virginia (US) is expected online in 2026, but European deployment timelines extend to 2028 or later.

Permitting and grid connection timelines for battery storage are creating bottlenecks. In the UK, the average time from planning application to energization for BESS projects exceeds 3.5 years, according to Solar Media's 2025 storage pipeline analysis. In Germany, grid connection queue times of 4 to 6 years are common. These delays mean that even economically competitive storage projects cannot enter capacity markets quickly enough to replace retiring peakers.

Cross-border capacity sharing through interconnectors has underdelivered during simultaneous stress events. During the January 2025 cold snap, which affected France, Germany, and the Benelux countries simultaneously, interconnector flows provided only 60% of their contracted capacity market obligations as each country prioritized domestic supply.

Key Players

Established: Siemens Energy (hydrogen-ready gas turbines and grid-scale storage), GE Vernova (turbine technology and hybrid power plants), Vattenfall (peaker replacement pilot programs in Northern Europe), Iberdrola (hybrid solar-storage projects in Southern Europe), EDF (demand response and flexibility services in France)

Startups: Zenobe Energy (battery storage development and operation in the UK and Europe), Field Energy (large-scale BESS development in the UK), Sympower (demand response aggregation across European markets), Fever Energy (AI-driven virtual power plant platform), Habitat Energy (battery trading and optimization software)

Investors: Gore Street Energy Storage Fund (listed UK battery storage fund), Gresham House Energy Storage Fund (BESS investments across UK and Europe), Breakthrough Energy Ventures (long-duration storage technologies), EIT InnoEnergy (clean energy technology acceleration in Europe)

Action Checklist

• Map the peaker fleet in your target market by utilization hours, remaining contract length, and emissions intensity to identify replacement opportunities
• Size your product offering against the actual duration requirements of local capacity mechanisms rather than assuming 4-hour battery economics apply universally
• Track capacity market rule changes in target countries, particularly emissions performance standards and derating methodologies for storage and demand response
• Build partnerships with transmission system operators early to understand grid connection timelines and stress event performance requirements
• Develop hybrid value propositions that stack capacity payments with ancillary services, wholesale arbitrage, and balancing mechanism revenues
• Monitor long-duration storage technology readiness and plan product roadmaps for 8-hour-plus duration as costs decline
• Engage with hydrogen infrastructure planning processes to assess whether hydrogen-ready conversion represents a viable pathway in your geographic market

FAQ

Q: What share of European peaker capacity can batteries realistically replace by 2030? A: Based on current cost trajectories and capacity market rules, 4-hour BESS can economically replace approximately 30 to 40% of European peaker capacity, primarily assets that operate fewer than 200 hours per year. This represents roughly 22 to 30 GW of addressable market. Full replacement of the remaining capacity requires either long-duration storage commercialization, significant expansion of demand response, or hydrogen-fueled flexible generation, none of which will reach scale before 2030.

Q: How do capacity market derating factors affect the business case for storage? A: Derating factors determine how much capacity credit a battery receives relative to its nameplate power rating. A 100 MW battery with an 85% derating factor earns capacity payments on only 85 MW. Derating varies by market and duration: the UK applies approximately 90% for 2-hour systems and 96% for 4-hour systems, while Italy applies 85% for 4-hour systems. Founders should model revenue projections using derated, not nameplate, capacity and should anticipate that derating methodologies will evolve as system operators gain more performance data.

Q: Is the regulatory trajectory in Europe favorable or unfavorable for peaker replacement startups? A: The trajectory is strongly favorable. The EU's emissions performance standards, national coal and gas phase-out timelines, and increasing technology neutrality in capacity procurement all create space for clean alternatives. However, the pace of regulatory implementation varies widely. Germany and the UK are moving fastest, with clear peaker retirement timelines and reformed capacity mechanisms. Southern and Eastern European markets are 3 to 5 years behind, with capacity markets still heavily weighted toward incumbent thermal generation. Founders should prioritize markets where regulatory reform is already enacted, not just announced.

Q: What are the key technical risks founders should account for when developing peaker replacement projects? A: Battery degradation under high-cycling capacity market dispatch patterns is the primary concern: projects dispatched 300 or more cycles per year may see accelerated capacity fade that reduces effective duration over time. Grid connection delays are the most common project-level risk, with UK and German timelines routinely exceeding initial estimates. Performance penalties for failing to deliver contracted capacity during stress events can reach 150 to 200% of monthly capacity payments in some markets, creating significant financial exposure if systems underperform during peak demand.

Sources

• European Network of Transmission System Operators for Electricity. (2025). Statistical Factsheet 2025: European Power System Overview. Brussels: ENTSO-E.
• Agency for the Cooperation of Energy Regulators. (2025). Capacity Mechanisms in the EU: Market Monitoring Report 2025. Ljubljana: ACER.
• Bloomberg New Energy Finance. (2025). Battery Storage vs. Gas Peakers: European Market Competitiveness Analysis. London: BNEF.
• Elia Group. (2025). Adequacy and Flexibility Study for Belgium 2025-2035. Brussels: Elia.
• GE Vernova. (2025). Hydrogen Gas Turbine Technology: Commercial Deployment Status and Roadmap. Atlanta: GE Vernova.
• EirGrid. (2025). DS3 System Services: Performance and Impact Assessment 2022-2025. Dublin: EirGrid Group.
• National Grid ESO. (2025). Winter Outlook 2025/26: Electricity Capacity Assessment. Warwick: National Grid ESO.
• Bundesnetzagentur. (2025). Bericht zum Stand der Versorgungssicherheit: Capacity Adequacy Assessment. Bonn: Bundesnetzagentur.