Why performance, not volume, now defines California’s saturated battery market

In the opening article of this series, we explored the foundational role of battery energy storage systems (BESS) in accelerating the energy transition. In that report we outlined how BESS enhances grid flexibility, enables renewable integration, and creates new pathways for energy system resilience. We also examined the technologies, operational challenges, and revenue models behind storage deployment in the US.

This next phase of the series turns the lens toward the markets themselves. While the fundamentals of battery storage may be universal, the economics are anything but. In the US, BESS value is determined not by a single national framework, but by the design of seven organized wholesale electricity markets. Each market has its own rules, pricing signals, policy structure, and investor outlook. These factors shape how batteries are monetized, how easily they connect to the grid, and whether their revenues are scalable, predictable, or volatile.

This article begins a set of deep dives, covering each wholesale electricity market, starting with the California Independent System Operator (CAISO). In the weeks to follow, we’ll analyze the Energy Reliability Council of Texas (ERCOT), Pennsylvania-New Jersey-Maryland Interconnection (PJM) Independent System Operator (ISO), New York ISO (NYISO), New England ISO (ISO-NE), Mid-Continent ISO (MISO), and Southwest Power Pool (SPP). This comprehensive view will highlight where storage is working, where it’s struggling, and what lies ahead.

For investors, developers, and policymakers navigating this fast-evolving sector, understanding these market-level dynamics is essential. Because in battery storage, location is everything.

Battery storage deployment in California has outpaced every forecast. In 2020, CAISO had nearly 1GW of grid-connected battery capacity. By the end of 2024, that number had grown to over 12.5GW – a more than 1,200% increase in less than five years, driven by policy mandates, market reforms, and reliability needs (see figure 1). Battery storage now accounts for nearly 12% of the system’s nameplate capacity, a penetration rate unmatched in any other US power market. As a result, CAISO has become a global reference point, watched closely by other markets seeking to understand what large-scale variability integration looks like in practice.

This expansion hasn’t just been about scale – it has been shaped by project configuration. Between 2020 and 2024, California’s grid-scale battery buildout included a relatively balanced mix of standalone and co-located systems (see figure 2). This trend highlights how standalone BESS – charging directly from the grid – have become a flexible, merchant-leaning asset class. Meanwhile, co-located systems were designed around time-shifting renewable generation and securing eligibility for the Investment Tax Credit (ITC).[1]

Looking ahead, the project pipeline tilts decisively toward standalone storage. Between 2025 and 2028, planned standalone capacity exceeds 17.8GW, compared to 7.2GW for co-located systems, an amount equivalent to nearly 40% of CAISO’s 2024 summer peak demand. This shift reflects a growing emphasis on grid-charging assets that can respond dynamically to market signals and offer capacity value independent of when energy is generated. These projects were largely planned following the Inflation Reduction Act (IRA), which expanded tax credit eligibility to standalone systems – removing a structural constraint that had previously favored BESS that are co-located with solar generation.

[1] Prior to the Inflation Reduction Act, standalone storage systems were not eligible for the federal Investment Tax Credit (ITC). To qualify, batteries had to be paired with renewable generation and primarily charged from it – driving co-located project configurations. CAISO acknowledged these constraints in market design proposals. Source: CAISO Energy Storage Enhancements, Dec 2022.

Geographic siting in CAISO reflects the commercial logic behind BESS deployment (see figure 3). Of the BESS currently operating, more than 8GW is concentrated in CAISO zone SP-15, driven by resource adequacy contracting in and around Los Angeles, San Diego, Riverside, and San Bernardino, and by BESS co-located with solar in Kern County, one of the state’s highest solar output zones. Zone ZP-26 accounts for a little over 3.1GW, clustered in Central Valley counties such as Fresno, Kings, Tulare, and Merced, where co-location with solar remains the dominant model. While zone NP-15, covering Northern California, holds the smallest share at just over 1.3GW. Systems here are sited near transmission hubs like Alameda, Contra Costa, and Solano, where interconnection access and congestion constraints shape project viability.

Looking ahead, the interconnection pipeline heavily favors SP-15. As of April 17, 2025, CAISO’s interconnection queue (the list of projects that have applied to connect to the grid) includes over 51GW of storage capacity in SP-15 – over three times the capacity in either ZP-26 or NP-15. Developers are clearly concentrating their next wave of projects in Southern California, where merchant volatility, capacity pricing, and urban reliability needs to align to support storage monetization across multiple revenue streams.

Zooming out, storage now dominates CAISO’s queue. Battery projects comprise more than 95% of all capacity in CAISO’s active queue, making it storage-centric rather than just storage-heavy (see figure 4). However, we should not interpret interconnection queues as build forecasts. According to Lawrence Berkeley National Laboratory’s 2024 “Queued Up” report, CAISO’s historical completion rate for battery projects is below 12%, with attrition driven by permitting delays, interconnection study costs, financing hurdles, and shifting market dynamics. Most queued projects will not move forward.

Still, the signal embedded in the queue is meaningful. Developers are no longer just responding to California Public Utilities Commission (CPUC) procurement targets; they’re positioning for merchant exposure, relying on RA scarcity (to meet demand during peak times), price volatility, and the grid’s growing reliance on flexible dispatchable capacity. While most queued projects may not reach commercial operation, the scale and skew of the pipeline point to a shift in developer behavior. Policy catalyzed California’s storage buildout, but market signals are now sustaining it. This shows that when flexible assets are bankable, dispatchable, and fast enough to capture volatility, storage can graduate from mandate-driven to market-driven growth.

The impact on system operations is already visible. On October 7, 2024, during a late-season heatwave, CAISO batteries discharged 8,354 megawatt (MW) into the grid at peak – supplying over 21% of system demand (see figure 5). In practical terms, BESS shaved the net load curve and displaced what would have otherwise required gas peaker dispatch. This is no longer a technology in demonstration – it is integrated, responsive, and being counted on.

CAISO remains the most advanced environment for monetizing battery storage in the US, but it's also the most competitive – and increasingly unforgiving. For investors and developers, the story in 2024 is one of sharp revenue compression across all major value streams.

According to Modo Energy,[2] the annualized market revenue for BESS dropped from USD 78,000/MW-year in 2023 to USD 51,000/MW-year in 2024. That’s a 35% decline in just one year. This figure reflects performance in CAISO’s day-ahead energy, real-time energy, and ancillary services markets, as tracked by (see figures 6 and 7). The uncontracted portion of the value stack – energy arbitrage and ancillary services – is under increasing pressure as more storage capacity enters the system.

[2] Modo Energy’s CAISO BESS benchmark includes both standalone and co-located batteries that are metered separately from generation. It excludes hybrid systems with shared interconnection and does not reflect RA contracts, which form a separate and critical revenue stream for most financed projects. Benchmark values are calculated using aggregated CAISO data and normalized to MW-year based on nameplate capacity.

Energy arbitrage is still the main source of revenue for BESS but with narrowing spreads. Real-time volatility, once the primary lever for revenue, has fallen sharply as battery participation grows. In 2023, batteries earned an average of USD 50,103/MW-year from day-ahead energy and USD 16,034/MW-year from real-time energy. In 2024, those figures declined to USD 36,396/MW-year and USD 7,743/MW-year, respectively – a 40% reduction in real-time value and a 27% decline in day-ahead.

Ancillary services have also become saturated. Market earnings from regulation and spinning reserves fell from USD 13,279/MW-year in 2023 to just USD 6,659/MW-year in 2024 (see figures 6 and 7). Regulation volumes have remained relatively flat, but battery supply has surged – pushing down clearing prices and eroding the high returns seen by early market entrants.

That leaves RA as the critical revenue anchor. Four-hour batteries are now embedded in CAISO’s RA procurement stack. Contracts in constrained local capacity areas continue to command premiums. Across both system-wide and local zones, most deals have ranged from USD 90,000/MW-year to USD 120,000/MW-year, with a small subset exceeding those levels depending on location and scarcity. These RA contracts, typically structured for five to ten years, form the revenue floor, with merchant upside layered on top.

The mechanics enabling this are well-established.[3] CAISO’s non-generator resource (NGR) model[4] supports dual market participation and real-time optimization. Recent rule updates – such as the minimum state of charge (MSoC) requirement during grid stress events – have made SoC management and dispatch discipline more important. These are not just operational factors – they affect RA compliance and market performance.

Taken together, the 2024 picture is clear: In CAISO, the market-based revenue streams are tightening, and project viability is becoming more dependent on contracting strategy and site selection. A well-sited, RA-contracted four-hour battery can still generate between USD 120,000/MW-year and USD 160,000/MW-year in total revenue,[5] but upside beyond that is rare. As the composition of the revenue stack continues to evolve, the focus for developers and lenders is shifting. The emphasis now lies in optimizing for risk-adjusted returns, not chasing volatile margins.

[3] CAISO storage participation models

[4] CAISO Non-Generator Resources (NGR) and Regulation Energy Management (REM) overview

[5] California Public Utilities Commission (CPUC) Energy Division – 2022 Resource Adequacy Report, May 2024

Even as California leads the nation in battery deployment, the scale and pace of its buildout are beginning to expose structural and operational stress points. These risks are no longer theoretical – they’re already affecting market performance, revenue durability, and development timelines.

The most immediate challenge is market saturation, particularly in energy arbitrage and ancillary services. As more batteries enter the system, daily price spreads are narrowing. Real-time volatility has declined, and dispatch profiles have become increasingly uniform. For assets built on merchant assumptions or short-duration price signals, this trend directly threatens returns. Arbitrage upside is now treated as an optionality, not as a core revenue source.

Concerns are also rising around RA performance risk. While RA contracts provide long-term cash flow, they come with strict must-offer and availability obligations. Failure to deliver capacity during system stress – often due to battery degradation, SoC management, or forecasting errors – can lead to derating and contract value loss. As the share of RA-backed batteries grows, CAISO and the CPUC are likely to tighten performance enforcement, making precision dispatch a non-negotiable requirement.

Safety and reliability have also moved to the foreground. The January 2025 fire incident at the Moss Landing Power Plant, one of California's largest BESS facilities, renewed scrutiny around thermal risk, fire suppression standards, and operational oversight. For lenders and insurers, incidents like these reshape how projects are underwritten, especially at urban or grid-critical sites.

Finally, interconnection timelines remain a gating issue. Despite the reforms approved in 2024, CAISO’s queue remains one of the largest and slowest in the country.[6] Batteries paired with solar often face longer study times and unclear upgrade costs. These delays affect commercial operation dates, tax credit timing, and near-term growth trajectories.

These aren’t existential risks – but they are defining ones. In CAISO, success no longer hinges on finding a development site or getting a contract. It’s about execution, availability, and navigating a market that’s moving from growth to maturity.

[6] Queued Up: 2024 Edition, Characteristics of Power Plants Seeking Transmission Interconnection as of the End of 2023, Lawrence Berkeley National Laboratory, April 2024

California’s battery deployment isn’t just market-driven – it’s been policy-directed from the outset. In 2021 and 2022, the CPUC issued a series of mid-term reliability procurement orders requiring 15.5GW of new clean energy capacity by 2027. Utility-scale battery storage is expected to deliver the majority of it. These mandates have supported long-term offtake contracts, especially for four-hour lithium-ion systems now standard in RA portfolios.

Longer term, California’s SB 100 targets 100% zero-carbon electricity by 2045. To reach that goal, modeling by the California Energy Commission and CPUC estimates that at least 52GW of battery storage will be needed, largely to balance rising solar and wind penetration. That ambition is already shaping developer behavior: By mid-2024, batteries accounted for approximately 45% of CAISO’s interconnection queue, with nearly half co-located with renewables.

In June 2024, CAISO approved a comprehensive interconnection reform package, replacing the first-come, first-served model with a screening process that prioritizes viable, near-term projects. The new rule favors projects with site control, commercial maturity, and demonstrable deliverability, aiming to reduce bottlenecks and better align project timelines with procurement needs. Early results are encouraging, although hybrid projects still face hurdles tied to transmission upgrade costs and queue congestion.

At the federal level, FERC Orders 841 and 2222 have enabled broader wholesale market access for both standalone and aggregated BESS. However, in California, it’s the evolving RA framework that now shapes how storage is valued, contracted, and dispatched. Ongoing discussions around derating, performance enforcement, and SoC management will increasingly influence how RA contracts are structured and financed.

Many of California’s early hybrid battery projects were designed under pre-IRA Investment Tax Credit rules, which required BESS to charge primarily from on-site renewables. While that restriction was lifted in 2023, the structural legacy remains: Solar-plus-storage hybrids continue to dominate the interconnection queue and shape operational strategies, particularly around RA compliance and tax credit optimization.

The bottom line: California’s policy architecture continues to drive BESS deployment – but it’s becoming more selective. As the market matures, long-term success depends less on headline mandates and more on project readiness, regulatory compliance, and the ability to perform reliably in a tightening grid environment.

CAISO’s battery market is entering a new phase, defined less by growth-at-all-costs and more by integration, discipline, and selectivity.

The buildout has been extraordinary, but scale alone is no longer the story. The pace of additions is exposing pressure points – compressed arbitrage margins, saturated ancillary service markets, queue congestion, and real-world reliability risks. In a grid relying on BESS for capacity and flexibility, performance now matters as much as size.

From an investment perspective, the monetization landscape is shifting. Energy market revenues are down year-on-year, and while RA contracts are essential, they now come with tighter standards. Arbitrage upside is being treated more as an optionality than as a core cash flow. Projects without a strong offtake, proven controls, or locational edge will struggle to secure financing or maintain long-term asset valuations.

Yet California’s long-term fundamentals remain intact. The CPUC’s reliability planning assumes multi-GW additions through 2030, and BESS is embedded in every utility integrated resource plan. As midday solar saturation and evening peak demand persist, four-hour storage has evolved from a marginal asset to core grid infrastructure. Continued technology improvements, particularly declining capital costs and rising energy density are likely to accelerate this trend further, strengthening storage’s role in system reliability.

Looking ahead, four dynamics will shape the next chapter:

CAISO remains the most advanced battery market in the US, offering a valuable case study for other regions pursuing storage integration, although in today’s market, volume is no longer the differentiator. In this next phase, success will hinge on locational strength, contract quality, and disciplined operations.