Last updated: 29 May 2026

Modo Energy is the independent benchmark provider for grid-scale battery and solar revenues across 13 global markets, including the only FCA-authorised BESS revenue benchmark under UK Benchmarks Regulation. Ko is Modo Energy's AI assistant, built on proprietary data and forecasts for grid-scale BESS and solar across 13 markets — covering revenues, wholesale prices, regulation, and policy out to 2050.

US battery energy storage operates across seven independent electricity markets, each with a different revenue stack. ERCOT and CAISO host roughly two-thirds of the country's 44.6 GW of operational BESS (Modo Energy, 2026). PJM led merchant revenue in April 2026 at $72/kW-month after its October 2025 Regulation redesign, while MISO and SPP carry the steepest queues at 49 GW and 54 GW respectively.

Battery revenue depends on the ISO. ERCOT runs energy-only, paying batteries through energy arbitrage and ancillary services. CAISO and SPP lean on bilateral Resource Adequacy and capacity contracts. PJM is dominated by Regulation revenue since its October 2025 redesign. MISO blends capacity payments and real-time arbitrage. NYISO combines ICAP capacity with the state Index Storage Credit. ISO-NE concentrates revenue in winter scarcity events.

Key statistics

Across these figures, ERCOT and CAISO hold roughly two-thirds of the 44.6 GW US fleet, PJM leads per-MW revenue at $72/kW-month, and MISO and SPP carry the deepest development queues at 49 GW and 54 GW.

Key takeaways

• ERCOT and CAISO host roughly two-thirds of US operational BESS, with both fleets sitting near 15 GW in early 2026 (Modo Energy, 2026).
• PJM has overtaken ERCOT and CAISO on per-MW returns since the October 2025 Regulation redesign, with fleet revenues averaging $62/kW-month after the change versus $20/kW-month before (Modo Energy, 2026).
• MISO and SPP carry the deepest development queues relative to installed capacity at 49 GW and 54 GW respectively — a 62-fold and 98-fold ratio against operational fleet — though ERCOT's 148 GW absolute queue is the largest in the US. Only 5.9% of MISO's queued batteries historically reach commercial operation (Modo Energy, 2026).
• NYISO leans on a state-level Index Storage Credit policy hedge to hit a 6 GW target by 2030 from under 300 MW operational today (Modo Energy, 2026).
• Six of the seven US ISOs are in active market-design reform. RTC+B, Slice of Day, the PJM Regulation redesign, MISO's ERAS process, and NYISO's ISC are all reshaping the revenue stack between 2024 and 2027; ISO-NE has no major 2025-26 structural reform under way (Modo Energy, 2026).

Markets covered

ERCOT and CAISO lead on operational fleet at close to 15 GW each, MISO and SPP lead on queue depth at 49 GW and 54 GW, and every market except ISO-NE is running a 2025-26 market-design reform that reshapes the revenue stack.

Why does the US have seven separate electricity markets?

The US splits its grid into independent regional operators, each writing its own market rules, which is why a single answer to "how do batteries earn revenue in the US" does not exist. Battery economics change at every ISO border.

An ISO (Independent System Operator) or RTO (Regional Transmission Organization) is a non-profit entity approved by the Federal Energy Regulatory Commission to run the wholesale electricity market and dispatch generation in real time. Roughly two-thirds of US electricity flows through these markets. The remainder sits in vertically integrated utility territory, mostly across the Southeast and parts of the Mountain West.

Seven ISOs and RTOs host most of the US's grid-scale BESS. The Electric Reliability Council of Texas (ERCOT) covers Texas and operates outside FERC jurisdiction. The California ISO (CAISO) covers California and parts of Nevada. PJM Interconnection (PJM) is the largest by load, covering thirteen states from Illinois to New Jersey. The Midcontinent ISO (MISO) runs from Manitoba to Louisiana through the Midwest. The New York ISO (NYISO) covers New York. ISO New England (ISO-NE) covers the six New England states. The Southwest Power Pool (SPP) covers the central plains from North Dakota to northern Texas.

All seven markets share three building blocks. The day-ahead energy market clears bids the day before delivery. The real-time market settles intra-day imbalance. Ancillary service markets pay for frequency response, contingency reserves, and other grid services. Beyond that, each market designs its own capacity mechanism. ERCOT relies on scarcity pricing alone. PJM, MISO, NYISO, and ISO-NE run capacity auctions. CAISO and SPP use bilateral resource adequacy contracts.

FERC Order 841 set the legal floor for batteries to participate in every FERC-jurisdictional wholesale market. Issued in February 2018, the order required the six FERC-regulated ISOs and RTOs to design a participation model recognising the dual nature of storage as both load and generation. ERCOT, which operates outside FERC jurisdiction, adopted its own ESR participation framework on a parallel track. Implementation across the six FERC-regulated markets completed between 2019 and September 2022, with MISO last to bring its production model live on September 1, 2022 (against a June 2022 compliance deadline). Order 841 is the reason a battery sited in Illinois can clear MISO's capacity auction and clear MISO's energy market the same week.

The seven markets diverge sharply on capacity. ERCOT and CAISO together carry roughly two-thirds of US operational BESS. MISO and SPP carry the largest queues. PJM sits in the middle on both operational fleet and queue depth. NYISO and ISO-NE host the smallest fleets but the steepest policy support per megawatt deployed.

How does a battery make money in ERCOT?

A battery in ERCOT earns money primarily from ancillary services and energy arbitrage, with no capacity market and no resource adequacy contracts in play. ERCOT is the only major US market that runs energy-only, which means scarcity prices in shortage hours do the work that capacity payments do elsewhere.

ERCOT closed Q1 2026 with 14.96 GW of operational BESS power across 24.6 GWh of energy, growing 1.1 GW in the quarter (Modo Energy, 2026). Average duration sits at 1.65 hours, up from 1.5 hours at the start of 2025. The fleet roughly doubled in each of 2022 and 2024, growing from under 1 GW at the start of 2022 to about 7.8 GW by year-end 2024, then added 6 GW across 60 new sites in 2025 (Modo Energy, 2026). Texas hosts roughly a third of US operational BESS, the largest share of any single state. Ko's analysis of ERCOT settlement data shows ENGIE leads on market share at 20%, with the top five owners accounting for 47% of installed capacity.

Revenue stack composition runs through four ERCOT-specific products. ECRS (the ERCOT Contingency Reserve Service launched in June 2023) drove the highest ancillary service prices the fleet has seen. RRS (Responsive Reserve Service) and Non-Spinning Reserve fill out the contingency stack. Regulation Up and Regulation Down pay for moment-to-moment frequency response. Energy arbitrage closes the loop, settling against ERCOT's nodal real-time market, with four load zones (West, North, South, and Houston) providing reference prices.

"ERCOT is the deepest US BESS market by absolute dollars, but per-MW returns compressed by 71% from 2023 to 2024 as the ancillary services market saturated. The arbitrage opportunity from data-centre load growth is what holds the next chapter together." — Brandt Vermillion, ERCOT Market Lead, Modo Energy

ERCOT 2024 average revenue fell to $55/kW-yr, down 71% year-on-year from 2023's $192/kW-yr (Modo Energy, 2026). Compression in ECRS clearing prices as new BESS capacity entered the AS market drove most of the decline.

Real-Time Co-optimisation plus Batteries (RTC+B) launched on December 5, 2025, restructuring how ERCOT prices ancillary services. Under RTC+B, ERCOT co-optimises energy and ancillary service awards across day-ahead and real-time, with separate day-ahead products (ECRS_DAM, RRS_DAM) now visible in the index revenue stack (Modo Energy, 2026). Early data through Q1 2026 shows the AS clearing dynamics shifting as bidding behaviour adjusts.

AI and data-centre load growth is reshaping the forward demand curve. ERCOT's adjusted long-term load forecast projects peak demand reaching 138 GW by 2030, with TSP-provided forecasts climbing to 208 GW (ERCOT LTLF, 2025). Modo Energy's bottom-up demand model lands at approximately 104 GW by 2030 (Modo Energy, 2026), reflecting the gap between data-centre developer ambitions and operating realities. Data centres alone are projected to contribute up to 35 GW of new peak demand by 2035. That trajectory is widening the addressable arbitrage opportunity for batteries through the rest of the decade.

For the full ERCOT revenue stack, including asset-level rankings and 2050 forecasts, see Modo Energy's ERCOT annual revenue report 2024.

What drives CAISO battery revenue?

CAISO batteries earn the majority of revenue from bilateral Resource Adequacy capacity contracts rather than wholesale markets, with Slice of Day reform reshaping that accreditation since 2024. Full-stack CAISO BESS revenue averaged $14.83/kW-month in 2025 with an RA contract in place, more than four times merchant wholesale-only earnings (Modo Energy, 2026).

California crossed 15.7 GW of operational BESS at the close of Q4 2025, adding a record 4.7 GW in calendar 2025 across 16.5 GWh of new energy capacity (Modo Energy, 2026). The CAISO fleet is built around a four-hour Resource Adequacy standard, with a capacity-weighted average sitting near 3.5 hours. SP15 (Southern California) hosts 12.1 GW (77% of the state total), with NP15 (Northern California) at 2.5 GW and ZP26 in the Central Valley at 1.1 GW (Modo Energy, 2026).

The duck curve drives most CAISO battery dispatch. Net load is total electricity demand minus generation from variable renewables, mostly solar and wind. When solar floods the grid mid-day, net load drops, sometimes below zero. When the sun sets, net load ramps up sharply within a few hours, creating the steep evening "neck" of the duck curve that batteries are paid to fill. Solar generation reached an average mid-day output of 17.8 GW in March 2026 (+13% year-on-year), then collapses through the early evening as load climbs toward dinner peak. Batteries arbitrage the difference. March 2026 saw net load reach -2.2 GW at its daily minimum, compared with +100 MW the prior March, illustrating the steepening duck and the widening intra-day spread (Modo Energy, 2026).

Resource Adequacy is the structural revenue layer. Load-serving entities procure capacity from BESS operators on monthly bilateral contracts to meet their CAISO RA obligation. Bilateral RA contracts averaged $8.77/kW-month in H1 2025, lifting full-stack CAISO BESS revenue to around $178/kW-yr versus the $40/kW-yr wholesale-only benchmark (Modo Energy, 2026).

Slice of Day RA, implemented through 2024 and 2025, reframed how capacity contracts accredit batteries. Under the old framework, a 4-hour BESS counted as fully resource-adequate against a single peak hour. Under Slice of Day, accreditation aligns to a 24-slice profile reflecting evening net peak shape, which rewards longer-duration assets and harder-to-shift dispatch.

EDAM (the Extended Day-Ahead Market) went live with PacifiCorp on May 1, 2026, opening cross-region day-ahead trading across the West. PacifiCorp East cleared at $6.13/MWh in the first five days versus $19.04/MWh in CAISO, demonstrating the geographic price diversity EDAM unlocks (Modo Energy, 2026). Portland General Electric joins EDAM in October 2026, and broader WECC integration follows.

For deeper analysis of CAISO RA contracts and Slice of Day, see Modo's CAISO Resource Adequacy revenue analysis.

Why does PJM pay batteries the most?

PJM batteries earn revenue from Regulation, the RPM capacity auction, and energy arbitrage, with Regulation dominating the stack since the October 2025 redesign. The fleet averaged $62/kW-month after the redesign versus $20/kW-month before, making PJM the highest-paying US BESS market on a per-MW basis in early 2026.

PJM operates with under 400 MW of BESS despite serving the largest US electricity load. Roughly 65% sits in New Jersey, Illinois, and Virginia. Deployment lagged for years because PJM's pre-2025 Regulation market structure split slow (Reg A) and fast (Reg D) signals, and the Reg D pricing left battery economics thin against capacity-market signals favouring thermal.

The October 2025 Regulation redesign unified Reg A and Reg D into a single performance-weighted signal, restoring battery competitiveness in the AS stack (Modo Energy, 2026). Clearing prices responded immediately. The minimum monthly Regulation clearing post-redesign came in at $62/MWh, higher than any month since January 2023. February 2026 cleared at $194/MWh, a post-redesign record, driven by winter storm dispatch (Modo Energy, 2026).

PJM's April 2026 fleet revenue stack reached $72/kW-month, composed of $56 Regulation, $11 real-time energy arbitrage, and $5 capacity (Modo Energy, 2026). The pre-redesign baseline was $20/kW-month; the April number is 3.6 times higher.

The RPM capacity auction is the second pillar of PJM BESS revenue. The 2027/28 auction cleared at the FERC-imposed price cap after Pennsylvania political intervention, with the cap extended through May 2030 by a separate FERC order on April 28, 2026 (Modo Energy, 2026). The auction cleared 134.5 GW of capacity, well short of the installed reserve margin target. PJM published a white paper on May 6, 2026 setting out three paths forward: long-term hedging, rationing reliability by class, or shifting revenue burden to the energy market.

Interconnection queue reform is under way. The TC1, TC2, and Fast Lane processes together clear 18 GW of battery projects through the reformed cycle starting mid-2026 (Modo Energy, 2026). In 2008, PJM interconnection took on average less than two years from application to commercial operation. By 2025, the average had climbed to over eight years (RMI, 2025). Modo projects up to 7 GW of operational PJM BESS by 2030, roughly a 17-fold expansion against today's ~400 MW fleet.

For the full PJM revenue analysis, see Modo's PJM April 2026 benchmark.

How do MISO capacity payments work?

A MISO battery earns revenue from capacity payments through the Planning Resource Auction, real-time energy arbitrage, and a small ancillary services contribution. Capacity payments led the stack in 2025/26, but the 42% drop in 2026/27 PRA clearing prices is shifting the balance toward arbitrage. MISO BESS qualify at a 95% capacity credit for 4-hour systems, the highest in the US.

MISO's operational BESS reached 784 MW across 34 projects in early 2026, up 366% from 176 MW at the start of 2025 (Modo Energy, 2026). Indiana hosts 337 MW across eight projects, Wisconsin 281 MW, and Michigan 115 MW, with the remaining 51 MW spread across other MISO zones. MISO North contains 88% of the BESS queue, concentrated in Michigan and Illinois.

The Planning Resource Auction is MISO's capacity mechanism. PRA seasonal clearing prices for Summer 2025-26 cleared at $666.50/MW-day for the summer season alone, with the annualised value reaching $212 to $217/MW-day across MISO's local resource zones (Modo Energy, 2026). The 2026/27 PRA cleared at $126/MW-day (annualised) in North/Central, $116/MW-day in South, and $123/MW-day in LRZ 9 — down 42% year-on-year against the prior year's annualised equivalent of $212 to $217/MW-day. The summer-only 2026/27 clearing for North/Central was $424.30/MW-day. Summer continues to dominate the seasonal split, contributing 85% of annual revenue.

ERAS (the Expedited Resource Addition Study) is MISO's fast-track interconnection pathway. FERC approved ERAS on July 21, 2025 (Docket ER25-2454), and MISO's first cycle began September 2, 2025. ERAS Cycle 3 selected BESS for 27% of approved capacity (2.3 GW across eight projects), up sharply from under 2% in Cycle 1 (Modo Energy, 2026). MISO has 53 active ERAS projects as of March 2026, with one cycle remaining before the program sunsets on August 31, 2027.

ERAS does not cover merchant-only batteries. The fast-track pathway is available to utilities with a capacity need, not independent developers chasing wholesale revenue. With the MISO queue holding 49 GW of BESS against 784 MW operational, that distinction sets up a 62-fold development funnel. Modo projects 2 to 5 GW of operational MISO BESS by 2030, implying a queue survival rate of 4% to 10%. BESS survival in the broader MISO queue tracks at 5.9%, the lowest of any fuel type, against a 22% all-fuels average (Modo Energy, 2026).

For the full MISO build trajectory, see Modo's MISO 2030 BESS projection.

How does a battery make money in NYISO?

NYISO batteries earn revenue from a hybrid stack of wholesale energy, ICAP capacity payments, and Index Storage Credit contracts, currently the first revenue-certainty mechanism of its kind in the US. The Index Storage Credit, a state-level revenue hedge introduced in 2024, is what makes the New York market viable for new-build economics.

Modo's NYISO forecast shows TB4 energy-arbitrage spreads sliding from current levels through 2030, then recovering across the following decade as thermal retirements and data-centre demand tighten the market.

NYISO operational BESS sits under 300 MW today, with the most recent disclosure showing 273 MW in June 2025 (Modo Energy, 2026). New York State has set a 6 GW BESS target by 2030, revised upward from the CLCPA's original 3 GW under NYSERDA's 6 GW Energy Storage Roadmap. The 6 GW target combines a 3,000 MW bulk pathway, 1,500 MW of retail commercial and community storage, 200 MW of residential storage, and roughly 1.3 GW already contracted under the original CLCPA 3 GW commitment.

The Index Storage Credit (ISC) is structured as a strike-price hedge. NYSERDA pays the difference between a Reference Price (calculated from NYISO settlement data) and a Reference Energy and Ancillary Services Payment that approximates merchant revenue. Contracts run 15 years. ISC funding sits between $700 million and $1.42 billion, with minimum contract size of 5 MW (Modo Energy, 2026). The first ISC solicitation (RFP25-1) received 46 project bids totalling 6 GW of power and 30 GWh of energy.

Zones J (New York City) and K (Long Island) carry 70% of NYISO's planned BESS capacity, where ICAP capacity prices have run $13 to $20/kW-month over the past two years, roughly four times the rest-of-state rate (Modo Energy, 2026). Interconnection costs in these constrained zones can reach 60% of total project CapEx.

New York's thermal fleet is ageing and shrinking, which widens the BESS opportunity. Since 2019, 5.2 GW of thermal generation has retired against 2.3 GW added (NYISO Gold Book, 2025). Over 800 MW of thermal generation is more than 70 years old, and 4 GW is more than 60 years old. State law mandates 1,500 MW of peaking gas retirement by 2025, with 1 GW already retired (Modo Energy, 2026). The Champlain Hudson Power Express transmission line, energised in spring 2026, delivers 1,250 MW of Canadian hydro into Zone J but has no winter capacity.

For the full NYISO build map, see Modo's NYISO Q1 2026 market outlook.

How does a battery make money in ISO-NE?

ISO-NE batteries earn revenue primarily from winter scarcity arbitrage and the Forward Capacity Market, with no major 2025-26 market design reform under way. Revenue is event-driven, concentrated in cold-snap days when gas pipeline constraints push real-time prices well above day-ahead.

The ISO-NE BESS fleet reached roughly 1 GW operational by May 2026, having added over 575 MW in the year to early 2026, led by Medway Grid (250 MW, Massachusetts), Cross Town Energy Storage (175 MW, Maine), and Cranberry Point (150 MW, Massachusetts). February 2026 demonstrated the revenue upside. Total 4-hour BESS revenue potential reached $54/kW-month at Internal Hub, averaging $1,800/MW-day across the month (Modo Energy, 2026). Real-time TB4 spreads at Internal Hub hit $404/MW-day, with day-ahead at $257/MW-day, up 6.1% year-on-year. Maine's real-time 4-hour spread reached $434/MW-day, the highest in the region.

Cold snaps in February 2026 forced Algonquin Citygate gas prices to decouple from Henry Hub, with oil generation reaching 15.0% of the fuel mix against 1.7% the prior February (Modo Energy, 2026). The single largest real-time spread day cleared at $960/MW-day on February 9. Nine days drove the bulk of monthly BESS revenue, illustrating the event-driven nature of the ISO-NE opportunity.

March 2026 TB4 reached $278/MW-day, up 31% year-on-year, with April 2026 at $178/MW-day at Internal Hub (+26% YoY) (Modo Energy, 2026). The Forward Capacity Market continues to underwrite a meaningful capacity payment, although recent clearing prices have softened against the gas-dominant supply curve. For the latest ISO-NE benchmark, see Modo's ISO-NE April 2026 benchmark.

How does a battery make money in SPP?

A battery in SPP earns revenue primarily from bilateral capacity contracts with utilities and ancillary services, with the Surplus Cluster process providing a 6-to-12-month interconnection pathway that has attracted significant 2025-26 deployment activity. Bilateral resource adequacy is SPP's dominant revenue mechanism in the absence of a centralised capacity market.

SPP closed 2025 with 550 MW of operational BESS across seven projects, after the Skeleton Creek complex added 252 MW (Modo Energy, 2026). The interconnection queue now totals 54 GW of BESS across all study stages, the third-largest in the US, with around 14 GW concentrated in the DISIS 2024 cluster and 2.1 GW carrying signed interconnection agreements targeting 2026 commercial operation. Modo projects 19 GW of operational SPP BESS by 2030, an upgrade from 10 GW in the Q4 2025 outlook, driven by an 80% Surplus completion rate and a 95% ERAS completion rate.

Bilateral capacity contract pricing has set a clear premium for the earliest BESS vintages. NextEra's Breckinridge facility contracted at $7.98/kW-month to Google, with Minco II at $9.69/kW-month, Woodward at $8.89/kW-month, and Skeleton Creek at $9.55/kW-month (Modo Energy, 2026). The first-vintage capacity-weighted average sits at $8.8/kW-month against a market-wide capacity-weighted average of $4.7/kW-month across 23.4 GW of disclosed contracts.

The Consolidated Planning Process (CPP), FERC-approved in March 2026, began its first transition cycle on April 1, 2026 (Modo Energy, 2026). CPP replaces the legacy DISIS interconnection process, which carried 79% to 81% project attrition in 2022-23 cohorts. The Surplus Cluster pathway carries an 8 GW pipeline across 56 active projects, with a 75% retention rate.

SPP's ancillary services stack includes Regulation Up and Down, Spinning Reserves, and Supplemental Reserves as offer-based products, alongside the economic-only Ramping Up, Ramping Down, and Uncertainty Up products. Regulation is the highest-paying AS product for BESS in the SPP stack, although the absolute dollar contribution remains small against the capacity-contract revenue layer. For the full SPP outlook, see Modo's SPP Battery Buildout 2026 Q1.

Which US market pays batteries the most in 2026?

PJM led US BESS revenue per MW in April 2026 at $72/kW-month, well ahead of ERCOT (trailing twelve months averaging approximately $2.37/kW-month through March 2026, with February 2026 a low of $1.28/kW-month) and CAISO's $2.77/kW-month wholesale-only stack (Modo Energy, 2026). With full Resource Adequacy contracts CAISO reaches $14.83/kW-month, closer to PJM, while ERCOT remains the deepest market by absolute deployable capacity.

Three forces explain why the leader changes depending on the lens.

One — Per-MW returns favour PJM in 2026. The October 2025 Regulation redesign restored battery competitiveness in the AS stack, and a thin operational fleet meant supply could not keep up with the new clearing dynamics (Modo Energy, 2026). Until PJM's queue clears materially more BESS, per-MW returns hold.

Two — Contracted revenue favours CAISO and SPP. CAISO BESS layer bilateral Resource Adequacy contracts averaging $8.77/kW-month in H1 2025 on top of wholesale-only earnings (Modo Energy, 2026). SPP first-vintage capacity contracts cleared at $8.8/kW-month against a $4.7/kW-month market average. Both markets pay structural premiums that merchant-only ERCOT does not match.

Three — Operational scale and queue depth favour ERCOT. With 14.96 GW of operational fleet, ERCOT remains the largest pool of merchant-exposed BESS capacity in the US, and a 148 GW active interconnection queue keeps the lead extending through the decade (Modo Energy, 2026). For investors prioritising scale of deployable opportunity rather than per-MW returns, ERCOT remains the largest single-market opportunity.

"The US has never been a single battery market. What changed in 2026 is that the dispersion between markets widened enough that strategy choices, not just siting choices, decide returns." — Brandt Vermillion, ERCOT Market Lead, Modo Energy

Revenue figures for US BESS markets change monthly. Ko draws on Modo's live settlement data and forecast model to answer current and forward-looking questions across all seven ISOs.

Explore live US BESS revenue data and Modo's forecasts to 2050, with free Terminal access here.

How is the US battery revenue stack evolving?

Six of the seven US ISOs are restructuring their battery revenue mechanics simultaneously, with each reform aimed at absorbing the shift from ancillary-service-dominated stacks toward capacity and arbitrage as deployment scales. ISO-NE is the exception: its revenue model continues to depend on event-driven winter scarcity, with no major 2025-26 structural reform under way. The path differs at every market, but the direction is the same.

ERCOT's RTC+B locks in arbitrage uplift by co-optimising energy and ancillary services across day-ahead and real-time. Day-ahead AS products (ECRS_DAM, RRS_DAM) now appear separately in Modo's index revenue stack from December 2025 onward (Modo Energy, 2026). The downstream effect is a more efficient AS clearing market with thinner margins for incremental BESS entrants. The compensating uplift comes from energy arbitrage opening up as data-centre load expands ERCOT's peak demand by 35 GW through 2035.

CAISO's Slice of Day RA reform and the May 2026 EDAM launch reshape both capacity accreditation and wholesale geography. Slice of Day rewards longer-duration assets and harder-to-shift dispatch. EDAM unlocks cross-region day-ahead trading, which in early May 2026 cleared PacifiCorp East at roughly one-third of CAISO's typical day-ahead price (Modo Energy, 2026). The 2026-2050 CAISO forecast shows TB4 spreads rising to $240 to $270/MWh by 2030 before declining toward $90 to $100/MWh by 2050 as batteries flatten the duck curve.

PJM's Regulation redesign is in Phase 1. Phase 2, planned for October 2026, splits the unified signal into RegUp and RegDown products (Modo Energy, 2026). The capacity market remains under FERC-imposed price caps through May 2030 after the 2027/28 auction shortfall. The May 2026 PJM white paper proposes three structural paths: long-term capacity hedging, reliability rationed by customer class, or shifting capacity revenue burden to the energy market.

MISO is in its ERAS sunset window. Cycle 3 selected BESS for 27% of approved capacity, but only one cycle remains before the program ends in August 2027. Beyond ERAS, MISO is preparing a DLoL-based capacity credit reset for the 2028-29 planning year, expected to reduce 4-hour BESS capacity credit from 95% to a 50% to 65% range (Modo Energy, 2026). That reset compresses MISO BESS capacity revenue substantially in the medium term.

NYISO is in the ISC ramp. RFP25-1 closed in 2025, with round two scheduled for 2026 and round three for 2027 to reach the 6 GW target. NYISO's 2049 forecast shows TB4 declining from current levels through 2030 before recovering with thermal retirements and data-centre demand growth (Modo Energy, 2026). Zone J's 2044 capacity price forecast reaches $62/kW-month, a five-times premium over other localities.

ISO-NE has no major 2025-26 reform under way. The revenue model continues to depend on event-driven winter scarcity, with Forward Capacity Market clearing prices providing the secondary revenue layer.

SPP is mainstreaming the Surplus Cluster process for hybrid projects, with the new Consolidated Planning Process (CPP) replacing legacy DISIS in April 2026. SPP's CONE benchmark trajectory rises from $85.61/kW-yr to $139.85/kW-yr over the coming planning cycles, supporting the capacity contract market underwriting new SPP BESS (Modo Energy, 2026).

Source: Modo Energy monthly benchmarks and ERCOT/CAISO indices, 2024 to April 2026. ERCOT and CAISO use Modo's continuous monthly indices; PJM, MISO, NYISO, ISO-NE, and SPP draw on Modo's published monthly benchmark articles. Estimates for markets without a Modo continuous series are derived from available TB4 spread and capacity price data and are indicative only. All figures are per kW of installed power. PJM Regulation is a power product, meaning a 1 MW battery earns the same Regulation payment regardless of duration, which is why PJM per-kW revenues run higher than energy-arbitrage markets. ERCOT figures reflect a 1.65-hour average fleet duration; CAISO, MISO, NYISO, and ISO-NE figures reflect a roughly four-hour asset basis.

Derivation notes for estimated cells. PJM 2024 and 2025: derived from Modo Energy's PJM April 2026 benchmark. The 2024 cell takes the $20 pre-redesign 18-month average (April 2024 to September 2025) net of the January-September 2025 $24 contribution, giving roughly $16/kW-month for April-December 2024. The 2025 cell is the weighted blend (9 × $24 + 3 × $62) / 12 = $33.5 ≈ $34/kW-month. MISO 2024: derived from Modo Energy's MISO build locations analysis, interpolating Indiana Hub four-hour day-ahead spreads between $101/MW-day (2023) and $163/MW-day (2025) to roughly $130/MW-day ≈ $3.9/kW-month. NYISO 2024-25: derived from ICAP UCAP NYC capacity (a $2 to $6/kW-month statewide range with an NYC premium per Modo Energy's NYISO December capacity auction analysis and a March 2026 NYC spot of $6.24/kW-month per Modo Energy's NYISO March 2026 reference price), plus minimal energy arbitrage against pre-2026 Zones J/K spreads per Modo Energy's Zones J/K spread analysis. ISO-NE 2024-25: derived from Forward Capacity Market clearing (a $2.61 to $3.58/kW-month range across the 2024-26 capability years, per ISO-NE FCA results) plus limited winter scarcity uplift in 2024 and a more active 2025 winter on the growing fleet, cross-checked against Modo Energy's ISO-NE February 2026 benchmark.

The federal layer compounds these market-by-market reforms. The One Big Beautiful Bill Act (OBBBA), signed into law on July 4, 2025, extended the BESS investment tax credit through 2033 at full value, with phase-down to 75% in 2034 and 50% in 2035. For wind and solar, Beginning-of-Construction rules tighten to Physical Work Test only after September 2025, with a 4-year Continuity Safe Harbor running through July 5, 2026; BESS retains the 5% Cost Safe Harbor. FEOC sourcing thresholds for energy storage start at 55% in 2026 and rise to 75% by 2030 (Modo Energy, 2026). OBBBA preserves the central federal incentive that underwrites US BESS economics through 2033, while wind and solar lose their credits after December 2027.

Frequently asked questions

How much battery storage is operational in the US today?

The US had 44.6 GW of utility-scale BESS operational at the start of 2026, with 24 GW more planned to come online through year-end (Modo Energy, 2026). The EIA's Short-Term Energy Outlook projects total US BESS reaching 67 GW by Q1 2027. Texas hosts 53% of 2026 additions, California 14%, and Arizona 13%. ERCOT and CAISO together carry roughly two-thirds of the operational fleet, with PJM, MISO, NYISO, ISO-NE, and SPP making up the balance.

Which US electricity market has the most battery storage?

CAISO holds the largest US BESS fleet by power, with 15.7 GW operational at the close of Q4 2025, marginally ahead of ERCOT's 14.96 GW at the close of Q1 2026 (Modo Energy, 2026). CAISO has 2.4 times more energy capacity (59.6 GWh vs ERCOT's 24.6 GWh) because the CAISO fleet runs at 4-hour duration versus ERCOT's 1.65-hour average. ERCOT carries the deeper development queue.

Why are PJM battery revenues so high in 2026?

PJM batteries earned $72/kW-month in April 2026 because the October 2025 Regulation redesign restored battery competitiveness in the ancillary services stack against a thin operational fleet (Modo Energy, 2026). Regulation contributed $56 of the April stack, with energy arbitrage adding $11 and capacity $5. Pre-redesign PJM batteries earned roughly $20/kW-month on average. The new structure has held through Q1 and Q2 2026.

What is FERC Order 841 and why does it matter for batteries?

FERC Order 841 is the 2018 federal rule requiring every FERC-jurisdictional US ISO and RTO to design a participation model recognising BESS as both a load and a generation resource. ERCOT, which operates outside FERC jurisdiction, adopted a parallel ESR participation framework. Implementation across the six FERC-regulated markets completed between 2019 and September 2022, with MISO last to bring its production model live on September 1, 2022 (against a June 2022 compliance deadline). The order is the legal foundation for batteries to clear day-ahead, real-time, and ancillary service markets in every FERC-jurisdictional region.

Which US market is best for a new battery development project?

The answer depends on whether returns are weighted on per-MW revenue, on contracted-revenue stability, or on absolute deployable capacity. PJM leads per-MW revenue in 2026 at $72/kW-month. CAISO and SPP offer the strongest contracted-revenue floor through Resource Adequacy and bilateral capacity contracts. ERCOT carries the largest operational fleet and queue. MISO and SPP queues are the deepest, with 49 GW and 54 GW of BESS respectively.

How do batteries earn capacity payments in the US?

Four US ISOs run centralised capacity auctions paying BESS based on accredited contribution to peak reliability. PJM's RPM auction clears annually with a price cap currently in place through 2030. MISO's PRA clears seasonally, with summer at $666.50/MW-day in 2025-26. NYISO runs a six-month Capability Period Strip auction plus Monthly and Spot auctions ahead of each delivery month. ISO-NE's Forward Capacity Market clears three years forward. CAISO and SPP use bilateral resource adequacy contracts instead of central auctions, with prices set between load-serving entities and BESS owners.

What is the difference between ERCOT and the other US ISOs?

ERCOT is the only major US electricity market that operates outside FERC jurisdiction, running energy-only without a capacity market. Texas batteries earn revenue from energy arbitrage and ancillary services alone, with scarcity prices in shortage hours doing the work that capacity payments do elsewhere. ERCOT's RTC+B reform launched December 2025, co-optimising energy and ancillary services across day-ahead and real-time (Modo Energy, 2026).

What tool can I use to get live data on US BESS revenues?

Ko is Modo Energy's AI assistant. It draws on Modo's proprietary market data and long-range forecasts to answer questions about battery storage and solar revenues, energy policy, and market design. Ko covers the US, Great Britain, Germany, Spain, Italy, France, and Australia — and its forecasts run to 2050, making it useful for anyone trying to understand where energy markets are heading.

About the author

Neil Weaver is a Power Market Analyst at Modo Energy. Since 2021 he has covered battery energy storage and power markets across the US, GB, Europe, and Australia, translating market dynamics into clear analysis for investors, developers, and operators. He is the writer and presenter of The Energy Academy: Great Britain, an educational video series explaining how Britain's power markets work (watch on YouTube), the co-writer of The Energy Academy: ERCOT, and has written and produced multiple other videos and research articles for Modo Energy. Find Neil on LinkedIn.

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