Deep dive: Peaker plant replacement & capacity markets — what's working, what's not, and what's next

Natural gas peaker plants have served as the backstop for North American electricity grids for decades, firing up during the hottest afternoons and coldest evenings when demand surges beyond what baseload generation can supply. They run for as few as 50 to 200 hours per year, yet their owners collect billions in capacity payments for the promise of availability. By 2025, approximately 120 GW of gas peaker capacity operated across the United States, representing roughly 10% of total installed generation but less than 5% of annual electricity output. These plants are disproportionately old (average age exceeding 40 years), disproportionately polluting (emitting 2 to 3 times the NOx per MWh of combined cycle gas turbines), and disproportionately sited in low-income communities and communities of colour. The economic, environmental, and regulatory case for replacing them with battery storage, demand response, and hybrid clean energy resources has never been stronger. Yet the pace of actual retirement remains frustratingly slow, constrained by capacity market rules designed around dispatchable fossil generation and utility business models that profit from keeping aging assets on the books.

Why It Matters

Peaker plants occupy a critical junction between grid reliability, clean energy economics, and environmental justice. The US Environmental Protection Agency's 2024 analysis identified 89% of gas peaker plants as located within three miles of communities classified as disadvantaged under the Justice40 initiative. These facilities emit nitrogen oxides, particulate matter, and volatile organic compounds at rates that correlate with elevated asthma hospitalization rates in surrounding zip codes. A 2024 study published in Environmental Health Perspectives found that communities within one mile of peaker plants experienced asthma emergency department visits at 1.4 times the rate of comparable communities without nearby peaker facilities.

The economic picture has shifted decisively. Bloomberg New Energy Finance reported that utility-scale battery storage reached a levelized cost of USD 119 per MWh for four-hour duration systems in 2025, down from USD 388 per MWh in 2019. For the specific use case of peaking capacity (operating 50 to 200 hours annually), batteries are now 30 to 50% cheaper than running existing gas peakers on a per-MWh dispatched basis when accounting for fuel, operations and maintenance, carbon costs, and health externalities. The US Department of Energy's Liftoff Report on long-duration energy storage projects that by 2030, battery storage can economically replace 80 to 90% of existing peaker capacity in most US markets.

Regulatory momentum compounds the economic case. The EPA's updated Good Neighbor Plan and proposed Section 111(d) rules for existing power plants create new compliance costs for aging gas peakers. California's Senate Bill 1020 mandates 90% clean electricity by 2035, effectively requiring peaker replacement across the state's 14 GW of gas peaking capacity. New York's Climate Leadership and Community Protection Act (CLCPA) targets zero-emission electricity by 2040, with the New York Independent System Operator (NYISO) actively developing pathways to retire the state's 8.6 GW of in-city gas peakers. Illinois, New Jersey, and Virginia have enacted similar legislation with varying timelines but consistent direction.

Key Concepts

Capacity Markets are organized wholesale market mechanisms through which grid operators procure commitments from generators, storage operators, and demand response providers to make capacity available during periods of peak demand. PJM Interconnection, the largest US capacity market covering 13 states and 65 million customers, conducts annual Base Residual Auctions that procure capacity three years ahead of the delivery period. ISO New England and NYISO operate similar forward capacity markets. These markets were designed around dispatchable thermal generation and contain structural features (minimum run times, ramp rate requirements, seasonal availability obligations) that historically favoured gas plants over batteries and demand response.

Effective Load Carrying Capability (ELCC) measures the contribution of a resource to overall grid reliability, expressed as the percentage of its nameplate capacity that can be counted toward meeting peak demand. A gas peaker with 100 MW nameplate capacity might receive 95 to 97% ELCC because it can dispatch on demand. A four-hour battery storage system might receive 70 to 90% ELCC depending on the grid's peak demand profile and the duration of peak events. ELCC values for batteries decline as storage penetration increases because batteries saturate the short-duration peak, exposing longer-duration reliability needs. This concept is central to understanding how much storage capacity is needed to replace each MW of peaker capacity.

Demand Response aggregates reductions in electricity consumption from commercial, industrial, and residential customers during peak periods, functioning as a virtual power plant. Advanced demand response programs use automated building management systems, smart thermostats, and industrial process scheduling to reduce load within minutes of a dispatch signal. PJM's demand response capacity totalled 8.6 GW in 2025, equivalent to the output of roughly 17 large gas peaker plants. Demand response typically costs USD 30 to 80 per kW-year compared to USD 60 to 120 per kW-year for gas peaker capacity payments.

Hybrid Clean Energy Resources combine solar or wind generation with battery storage and, in some configurations, demand response into single interconnected facilities that can provide the same grid services as peaker plants. These hybrid resources offer capacity, energy, and ancillary services from a single interconnection point, avoiding the queue delays and cost overruns associated with multiple standalone projects.

Peaker Replacement KPIs: Benchmark Ranges

Metric	Below Average	Average	Above Average	Top Quartile
Battery LCOS (4-hr, peaking duty)	>$150/MWh	$120-150/MWh	$90-120/MWh	<$90/MWh
Capacity market clearing price	<$30/kW-yr	$30-60/kW-yr	$60-100/kW-yr	>$100/kW-yr
Peaker capacity factor	>15%	8-15%	3-8%	<3%
Battery round-trip efficiency	<82%	82-87%	87-92%	>92%
Demand response dispatch reliability	<85%	85-92%	92-97%	>97%
Interconnection queue time (months)	>48	36-48	24-36	<24
Community health co-benefits (NOx reduction)	<20%	20-50%	50-80%	>80%

What's Working

California's Peaker Replacement Programme

California has demonstrated the most aggressive and successful peaker replacement strategy in North America. The California Public Utilities Commission (CPUC) ordered 11.5 GW of new energy storage procurement between 2019 and 2026, explicitly targeting retirement of gas peaker plants in the Los Angeles Basin and San Francisco Bay Area. By early 2026, over 10 GW of battery storage was operational across the state, with the Moss Landing Energy Storage Facility (operated by Vistra Energy) alone providing 750 MW / 3,000 MWh of capacity. During the September 2024 heat wave, when temperatures exceeded 115 degrees Fahrenheit in inland valleys, California's battery fleet discharged 5.2 GW of power during the evening peak, equivalent to the output of approximately 10 large gas peaker plants, avoiding what would have been rolling blackouts under the pre-storage grid configuration.

The Alamitos Energy Center replacement in Long Beach provides a granular case study. Southern California Edison replaced a 1,970 MW gas plant (originally built in 1956) with a 400 MW / 1,600 MWh battery storage facility plus 100 MW of demand response contracts. The battery facility achieved commercial operation in 2024 at a total project cost of USD 637 million, less than half the estimated cost of constructing equivalent new gas peaking capacity. The surrounding community, predominantly Latino and historically overburdened by industrial pollution, has documented a 62% reduction in local NOx emissions since the gas plant's retirement.

New York's Peaker Rule

New York's Department of Environmental Conservation (DEC) adopted the Peaker Rule in 2021, establishing NOx emission limits that effectively require retirement or repowering of the state's oldest and most polluting simple cycle gas turbines. The rule applies to 3.3 GW of peaker capacity, primarily located in New York City and Long Island, with compliance deadlines in 2023 and 2025. By early 2026, 1.8 GW of covered peaker capacity had either retired or committed to retirement, replaced by a combination of battery storage, transmission upgrades, and demand response. The 316 MW Ravenswood peaker complex in Queens, operating since 1963, retired in December 2025 and will be replaced by a 400 MW battery installation developed by Plus Power, with commercial operation targeted for 2027.

NYISO's 2025 Reliability Needs Assessment confirmed that the peaker retirements have not compromised grid reliability. Reserve margins remained above 15% throughout the 2025 summer peak season, with batteries and demand response providing 4.2 GW of capacity during the August peak event. The assessment noted that battery storage dispatch reliability exceeded 98%, outperforming the 94% average forced outage-adjusted availability of the retired gas peakers.

PJM Capacity Market Reforms

PJM Interconnection, which operates the world's largest capacity market, implemented critical reforms in 2024 and 2025 that improved competitive access for clean energy resources. The introduction of Capacity Performance Seasonal Products allowed batteries and demand response to bid capacity for summer or winter seasons independently, rather than requiring year-round availability that favoured gas plants. PJM also revised its ELCC methodology to credit four-hour battery storage at 85 to 90% of nameplate for the first 5 GW of installed capacity, reflecting updated probabilistic modelling of peak demand duration.

These reforms produced immediate results. In PJM's December 2025 Base Residual Auction for the 2028/2029 delivery year, battery storage cleared 4,800 MW of capacity commitments, up from 1,200 MW in the prior auction. Demand response cleared 9,100 MW. Combined, clean peaking resources represented 22% of total cleared capacity, compared to 11% two years earlier. Capacity clearing prices fell 18%, reflecting the lower costs of battery and demand response resources competing against gas peakers.

What's Not Working

Interconnection Queue Bottlenecks

The single greatest obstacle to peaker replacement is not technology or economics but interconnection queue congestion. As of mid-2025, approximately 2,600 GW of generation and storage capacity sat in US interconnection queues, with average processing times exceeding 50 months in PJM, 42 months in MISO, and 38 months in CAISO. Battery storage projects, which could replace retiring peakers within 18 to 24 months of permitting, instead wait three to five years for grid connection studies and upgrade cost allocations. Lawrence Berkeley National Laboratory's 2025 Queued Up report found that only 14% of projects entering interconnection queues between 2018 and 2022 had achieved commercial operation, with withdrawal rates exceeding 80% in some regions.

The irony is stark: the grid operator processes that were designed to ensure reliability are now the primary barrier to deploying the resources needed to maintain reliability as aging peakers retire. FERC Order 2023, issued in July 2023 and requiring implementation by mid-2025, mandates queue reform including cluster study processes, increased financial commitment deposits, and "first-ready, first-served" principles. Early implementation results are mixed, with some regions reporting faster processing but others experiencing new bottlenecks as legacy queue backlogs persist.

Capacity Market Design Flaws

Despite reforms, capacity market rules continue to contain structural biases favouring incumbent gas generation. Minimum Offer Price Rules (MOPR), though scaled back in PJM following a 2021 order, persist in modified form in ISO-NE and NYISO. These rules prevent state-subsidized clean energy resources from offering below administratively determined price floors, artificially elevating the value of gas peaker capacity. Performance penalty structures in some markets impose asymmetric risks on storage operators: batteries face significant penalties for failing to deliver during extended multi-day events (which they cannot serve without recharging), while gas plants face proportionally lower penalties for mechanical forced outages.

Seasonal capacity constructs, while an improvement over annual requirements, still inadequately credit the complementary value of solar-plus-storage systems that can provide capacity during summer peaks when peaker demand is highest. ISO-NE's Forward Capacity Market, in particular, retains winter reliability requirements driven by natural gas supply constraints that create artificial demand for gas peaker retention even when those same plants face gas curtailment risk during winter cold snaps.

Utility Business Model Resistance

Investor-owned utilities in many jurisdictions continue to earn regulated returns on gas peaker assets that they own, creating financial incentives to delay retirement. Under traditional cost-of-service regulation, utilities earn 9 to 11% return on equity on their rate-based assets, including fully depreciated peaker plants with minimal ongoing capital investment. Replacing utility-owned peakers with third-party battery storage or demand response transfers revenue from the utility's regulated asset base to competitive market participants. This misalignment explains why utility-filed integrated resource plans frequently propose extending gas peaker operations 10 to 15 years beyond economic optimization models.

What's Next

Long-Duration Storage Closing the Remaining Gap

The 10 to 20% of peaker capacity that four-hour batteries cannot economically replace serves loads during multi-day extreme weather events. Long-duration energy storage technologies, including iron-air batteries (Form Energy), compressed air (Hydrostor), and flow batteries (ESS Inc.), are approaching commercial deployment at price points of USD 50 to 80 per kWh for eight to 100 hour durations. Form Energy's 100-hour iron-air battery, scheduled for a 15 MW / 1,500 MWh commercial deployment in Minnesota by late 2026, could provide the multi-day reliability assurance that eliminates the last reliability argument for retaining gas peakers.

Virtual Power Plants at Scale

Aggregated distributed energy resources, including residential batteries, smart thermostats, EV chargers, and controllable water heaters, are forming virtual power plants (VPPs) capable of providing peaking capacity at costs 40 to 60% below gas peakers. Tesla's Autobidder platform manages over 4 GW of aggregated distributed storage globally. Sunrun's VPP programme in California dispatched 1.2 GW of residential battery capacity during the August 2025 peak event. FERC Order 2222, requiring ISOs and RTOs to enable DER aggregation in wholesale markets, is creating the market access pathways for VPPs to compete directly against gas peakers in capacity auctions.

Environmental Justice Enforcement

The EPA's updated National Ambient Air Quality Standards for PM2.5 (finalized in March 2024 at 9 micrograms per cubic metre, down from 12) and proposed tightening of NOx standards will force compliance investments at existing peaker plants that further erode their economic viability. State-level environmental justice screening tools, including CalEnviroScreen (California) and EJScreen (federal), are increasingly integrated into permitting decisions, creating additional regulatory barriers to peaker plant life extensions. The combination of tightening air quality standards and growing community opposition is likely to accelerate involuntary retirements beyond what economic modelling alone would predict.

Action Checklist

• Assess exposure to peaker plant capacity by mapping owned or contracted gas peaker assets against retirement risk factors (age, emissions profile, community opposition)
• Evaluate battery storage alternatives using site-specific economics including capacity market revenues, energy arbitrage, and ancillary services stacking
• Engage with regional grid operators on interconnection timelines and identify fast-track pathways for peaker replacement projects
• Develop demand response capability across building and industrial portfolios to reduce peak demand contributions
• Monitor capacity market rule changes in your operating region and participate in stakeholder processes advocating for technology-neutral market design
• Quantify environmental justice co-benefits of peaker retirement for community engagement and regulatory proceedings
• Evaluate virtual power plant participation opportunities through existing distributed energy assets
• Model long-duration storage options for sites requiring multi-day reliability assurance beyond four-hour battery capabilities

FAQ

Q: Can batteries truly replace gas peaker plants without compromising grid reliability? A: For the vast majority of peaking duty (80 to 90% of existing capacity), four-hour lithium-ion batteries provide equivalent or superior reliability. California's 2024 heat wave demonstrated battery fleet discharge of 5.2 GW during evening peaks without reliability incidents. Batteries actually improve reliability in some respects: they respond to dispatch signals in milliseconds versus minutes for gas turbines, and they do not suffer the mechanical forced outages (5 to 8% annually) that plague aging gas peakers. The remaining 10 to 20% of peaker duty involving multi-day events will require long-duration storage or demand flexibility, both of which are approaching commercial readiness.

Q: What happens to capacity market prices when peaker plants retire? A: Initial modelling suggested peaker retirement could spike capacity prices, but empirical evidence shows the opposite. PJM's 2025 auction cleared at 18% lower prices than the prior year despite significant peaker retirements, because lower-cost battery storage and demand response resources displaced higher-cost gas capacity. Capacity prices reflect the marginal cost of the last resource needed to meet reliability requirements. As batteries and demand response with lower cost structures enter the market, equilibrium prices decline even as total capacity increases.

Q: How should sustainability leads prioritize peaker replacement advocacy within their organizations? A: Start with financial analysis. Calculate the full cost of continued peaker reliance including fuel costs, capacity payments, carbon pricing exposure (current and projected), maintenance escalation, and regulatory compliance costs. Compare against battery storage or demand response alternatives on a 10 to 15 year NPV basis. For organizations with Scope 2 emissions reduction targets, peaker replacement directly reduces grid carbon intensity during peak hours, which are typically the most carbon-intensive periods. Frame peaker replacement as simultaneously a cost reduction, risk mitigation, and decarbonization strategy.

Q: What is the typical timeline for a peaker replacement project from inception to operation? A: Under ideal conditions, battery storage projects can achieve commercial operation 18 to 24 months from development start. However, interconnection queue delays extend this to 36 to 60 months in most US markets. Demand response programmes can be deployed in 6 to 12 months for commercial and industrial customers with existing building management systems. The critical path item is almost always interconnection, not permitting, financing, or construction. Early engagement with grid operators and selection of sites with available grid capacity can significantly compress timelines.

Q: Are there stranded asset risks for organizations investing in new gas peaker capacity? A: Significant stranded asset risk exists. The useful economic life of a new gas peaker plant is 30 to 40 years, but regulatory and competitive dynamics suggest that gas peaking capacity in most US markets will be uneconomic within 10 to 15 years. Carbon pricing, tightening air quality standards, declining battery costs, and capacity market reforms all trend against gas peaker economics. Financial institutions including BlackRock, JPMorgan Chase, and Citigroup have flagged new gas peaker investments as elevated stranded asset risk in their climate scenario analyses. Organizations contemplating new gas peaker investment should rigorously evaluate whether storage or demand response alternatives can meet the same need at lower lifecycle cost and risk.

Sources

• BloombergNEF. (2025). Battery Storage Market Outlook: Levelized Cost Analysis and Capacity Projections. New York: Bloomberg LP.
• US Department of Energy. (2025). Pathways to Commercial Liftoff: Long Duration Energy Storage. Washington, DC: DOE.
• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection. Berkeley, CA: LBNL.
• New York Independent System Operator. (2025). Reliability Needs Assessment and Peaker Transition Study. Rensselaer, NY: NYISO.
• California Public Utilities Commission. (2025). Energy Storage Procurement Status Report and Peaker Retirement Tracking. San Francisco, CA: CPUC.
• PJM Interconnection. (2025). 2028/2029 Base Residual Auction Results and Market Reform Impact Analysis. Norristown, PA: PJM.
• Environmental Health Perspectives. (2024). Health Impacts of Peaker Plant Proximity: A Multi-City Epidemiological Analysis. Research Triangle Park, NC: NIEHS.