Trend analysis: Peaker plant replacement & capacity markets — where the value pools are (and who captures them)

Natural gas peaker plants have served as the reliability backbone of the US electricity grid for decades, firing up during demand spikes to prevent blackouts. But their economics are collapsing. Battery storage, demand response, and virtual power plants now outcompete peakers on cost, speed, and emissions across most grid regions. Between 2020 and 2025, more than 18 GW of peaker capacity in the United States was either retired, scheduled for retirement, or displaced by clean alternatives. The value pools that once flowed to gas turbine operators are shifting rapidly toward storage developers, aggregators, and software platforms. Understanding where this value concentrates and who captures it is essential for anyone building products, designing grid services, or allocating capital in the clean energy transition.

Why It Matters

The US peaker fleet comprises approximately 150 GW of capacity across more than 1,000 facilities, representing roughly $50 billion in installed asset value. These plants typically operate fewer than 500 hours per year but collect capacity payments, ancillary service revenues, and energy arbitrage returns that total $8 to $12 billion annually. As these revenue streams migrate to clean alternatives, the resulting value redistribution represents one of the largest structural shifts in the US electricity sector.

The financial case for replacement has become overwhelming. The levelized cost of a new 4-hour battery storage system fell to $140 to $180 per MWh of dispatched energy in 2025, compared to $180 to $250 per MWh for a new gas peaker including fuel and carbon costs. Existing peakers with fully depreciated capital still face operating costs of $100 to $160 per MWh when running, and rising maintenance expenses as aging turbines require more frequent overhauls. The Inflation Reduction Act's Investment Tax Credit provides up to 50% cost offset for standalone storage (30% base plus adders for domestic content, energy communities, and low-income siting), further accelerating the crossover.

Capacity markets administered by regional transmission organizations now increasingly clear battery storage and demand response in place of gas peakers. In PJM Interconnection's 2025/2026 Base Residual Auction, battery storage cleared 4,200 MW of capacity, up from fewer than 500 MW three years prior. NYISO's installed capacity market saw demand response and storage resources displacing 2,800 MW of aging gas peaker capacity in downstate New York alone. These auction results signal that market mechanisms, not just policy mandates, are driving the transition.

Key Value Pools

Capacity Market Revenues

Capacity payments represent the single largest value pool, totaling approximately $4.5 billion annually across PJM, NYISO, ISO-NE, and MISO. These payments compensate resources for being available during peak demand periods, regardless of whether they actually generate electricity. Battery storage systems and aggregated demand response now compete directly for these payments at clearing prices ranging from $50 to $150 per MW-day depending on the zone and delivery year. Developers who can site storage at constrained transmission nodes capture premium capacity values that exceed zonal averages by 40 to 80%.

The structure of capacity markets creates distinct advantages for clean alternatives. Gas peakers face increasing performance penalties for failing to start within required timeframes, with historical forced outage rates averaging 8 to 12% during extreme heat events when reliability matters most. Battery storage achieves equivalent forced outage rates below 2%, earning higher effective capacity ratings and avoiding performance penalties that erode peaker revenues.

Ancillary Services

Frequency regulation, spinning reserves, and voltage support constitute a $2.1 billion annual market in the US. Battery storage captures outsized value in frequency regulation because lithium-ion systems respond in milliseconds compared to 5 to 10 minutes for gas turbines. PJM's RegD signal, designed specifically for fast-responding resources, provides regulation clearing prices 2 to 3 times higher than the traditional RegA signal. Storage operators participating in frequency regulation earn $35,000 to $80,000 per MW annually, compared to $15,000 to $30,000 per MW for gas peakers providing the same service class.

Spinning reserve markets offer additional revenue stacking opportunities. Resources that can deliver sustained output for 30 to 60 minutes command reserve payments of $3 to $8 per MWh. Four-hour battery systems easily meet these requirements while maintaining capacity for energy arbitrage during non-reserve periods, creating layered revenue streams that gas peakers cannot replicate without burning fuel.

Energy Arbitrage and Peak Shaving

Wholesale electricity price volatility creates arbitrage opportunities worth $1.5 to $3 billion annually across US organized markets. Battery storage charges during low-price hours (often when wind and solar generation peaks) and discharges during high-price periods, capturing spreads that averaged $40 to $80 per MWh in ERCOT, $30 to $50 per MWh in CAISO, and $20 to $40 per MWh in PJM during 2025. These spreads increase during extreme weather events, with Texas experiencing sustained spreads exceeding $200 per MWh during winter storm events.

Behind-the-meter peak shaving generates value for commercial and industrial customers by reducing demand charges that typically represent 30 to 50% of their electricity bills. Storage systems sized to shave 15 to 30% of peak demand deliver savings of $8 to $15 per kW-month, translating to annual revenues of $50,000 to $200,000 for a typical 1 MW commercial installation.

Virtual Power Plant Aggregation

Virtual power plants (VPPs) aggregate distributed batteries, smart thermostats, EV chargers, and flexible loads into dispatchable portfolios that compete with peakers in wholesale markets. The VPP aggregation layer represents an emerging value pool estimated at $800 million in 2025 and growing at 35% annually. Aggregators who enroll 50,000 or more distributed devices can bid 200 to 500 MW of equivalent capacity into wholesale markets, earning margins of $20 to $40 per kW-year on aggregated capacity.

Who Captures the Value

Integrated Storage Developers

Companies that control the full value chain from development through operations capture the largest share of displaced peaker revenues. Firms such as Vistra Energy, which converted portions of its Moss Landing facility into 400 MW of battery storage, and NextEra Energy, which deploys utility-scale storage alongside its renewable generation fleet, earn capacity, energy, and ancillary service revenues simultaneously. Their competitive advantage lies in access to interconnection rights at existing thermal plant sites, established relationships with grid operators, and balance sheet capacity to finance multi-hundred-MW projects. Integrated developers typically capture 60 to 70% of gross project revenues after operating costs.

Software and Optimization Platforms

Revenue maximization across stacked grid services requires sophisticated optimization software that coordinates real-time bidding, state-of-charge management, and degradation-aware dispatch. Companies including Fluence (a Siemens and AES joint venture), AutoGrid (acquired by Schneider Electric), and Stem (now part of AlphaStruxure) provide platforms that increase battery revenue by 15 to 30% compared to simple time-of-use strategies. These platforms capture value through software licensing fees of $2,000 to $5,000 per MW annually, performance-based fees tied to incremental revenue, or equity positions in the assets they optimize.

Demand Response Aggregators

Aggregators such as Enel X, CPower, and Voltus enroll commercial and industrial customers in demand response programs that directly displace peaker generation during peak events. These companies earn $30 to $60 per kW-year in aggregation margins, with the highest values in constrained zones where capacity prices are elevated. Their competitive moat rests on customer acquisition costs ($50 to $150 per enrolled kW) and the operational relationships required to reliably curtail load during grid emergencies.

Transmission-Constrained Developers

The most lucrative value capture occurs at transmission bottlenecks where local peaker capacity commands premium prices. In New York City's Zone J, capacity clearing prices exceeded $12 per kW-month in 2025, compared to $3 to $5 per kW-month in unconstrained regions. Developers who secure sites and interconnection rights in these constrained areas earn returns 2 to 4 times the regional average. Rise Light & Power's Ravenswood project in Queens, converting a 2,500 MW gas plant site to a renewable and storage hub, exemplifies this strategy.

KPI Benchmarks: Peaker Replacement Economics

Metric	Below Average	Average	Above Average	Top Quartile
All-in Storage LCOS (4-hr)	>$200/MWh	$150-200/MWh	$120-150/MWh	<$120/MWh
Capacity Revenue per MW-year	<$40,000	$40-70,000	$70-100,000	>$100,000
Revenue Stack (Capacity + Energy + Ancillary)	<$80,000/MW-yr	$80-120,000	$120-160,000	>$160,000
Battery Availability Factor	<95%	95-97%	97-99%	>99%
Project IRR (Levered)	<8%	8-12%	12-16%	>16%
Interconnection Timeline	>48 months	36-48 months	24-36 months	<24 months

What to Watch

Three dynamics will reshape value capture over the next 24 months. First, FERC Order 2222 implementation across all ISOs will unlock full market participation for distributed energy resource aggregations, expanding the addressable market for VPP operators by an estimated $1.5 billion. Second, the interconnection queue backlog (currently exceeding 2,600 GW nationally) will create scarcity premiums for projects with secured grid connections, favoring developers who repurpose existing peaker plant interconnection rights. Third, the emergence of longer-duration storage technologies (iron-air batteries from Form Energy at $20 per kWh target cost, and compressed air systems from Hydrostor) will extend the displacement frontier from 4-hour peaking to 8 to 12-hour intermediate duty, threatening an additional 30 to 40 GW of gas capacity.

State-level policy actions amplify these trends. California's SB 1020 mandates 100% clean electricity by 2045, effectively requiring retirement of all gas peakers. New York's Climate Leadership and Community Protection Act targets 70% renewable electricity by 2030, with NYSERDA actively procuring storage to replace downstate peaker capacity. Illinois's Climate and Equitable Jobs Act prioritizes clean energy deployment in environmental justice communities where peaker plants disproportionately concentrate.

Action Checklist

• Map local capacity market clearing prices by zone and identify transmission-constrained areas with premium capacity values
• Evaluate existing peaker plant sites for repurposing potential, prioritizing those with viable interconnection agreements
• Model revenue stacking scenarios combining capacity, energy arbitrage, and ancillary services for target locations
• Assess interconnection queue position and timeline risks before committing development capital
• Evaluate software optimization platforms through head-to-head trials measuring incremental revenue versus simple dispatch strategies
• Monitor FERC Order 2222 implementation timelines in target ISOs for distributed resource aggregation opportunities
• Track state-level peaker retirement mandates and environmental justice policies that accelerate replacement timelines
• Engage with offtakers and utilities on tolling agreements or long-term capacity contracts that de-risk storage investments

Sources

• PJM Interconnection. (2025). 2025/2026 Base Residual Auction Results Report. Valley Forge, PA: PJM.
• New York Independent System Operator. (2025). Installed Capacity Market Report: 2024-2025 Capability Year. Rensselaer, NY: NYISO.
• BloombergNEF. (2025). US Battery Storage Market Outlook, H2 2025. New York: Bloomberg LP.
• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection. Berkeley, CA: LBNL.
• US Energy Information Administration. (2025). Electric Power Monthly: Capacity and Generation Statistics. Washington, DC: EIA.
• Federal Energy Regulatory Commission. (2025). Order 2222 Implementation Status Report. Washington, DC: FERC.
• Rocky Mountain Institute. (2025). The Economics of Clean Energy Portfolios: Replacing Gas Peakers with Clean Alternatives. Basalt, CO: RMI.