NERC released its 2026 Summer Reliability Assessment with what reads on the surface as a positive headline. Summer resource capacity rose by more than 58 gigawatts compared to last year, more than three times the prior-year addition. The list of subregions at elevated risk under above-normal or extreme conditions shrank to three: NPCC New England, MRO SaskPower, and WECC Northwest. ERCOT, CAISO, MISO, and PJM are not on that list this summer. A year ago, several of them were.
The line worth pulling out is not the 58 gigawatt number on its own. It is the composition of the additions, and the geography of where they did and did not go. The elevated-risk regions in the 2026 assessment are, almost without exception, the regions that have not built grid-scale battery storage at the gigawatt-plus level. The regions that have aged off the list are the ones that did.
What ERCOT actually looks like going into summer 2026
ERCOT entered 2026 with 15.7 gigawatts of installed and operating battery energy storage, by ERCOT’s own February 2026 reporting. By May 2026, the operating fleet sat at roughly 16.1 gigawatts across 232 utility-scale projects. The grid added more than 6 gigawatts of storage in the prior twelve months. ERCOT’s 2026 planning scenario models 15 to 18 gigawatts of installed storage, of which roughly 97 percent is one-hour and two-hour duration. BESS output has at points carried 10 percent of total ERCOT load.
That is the largest grid-scale battery fleet in North America by a meaningful margin. It is also the largest one to have been built without a single capacity market mandating it. ERCOT remains energy-only. The storage build was driven by ancillary service revenue (regulation, responsive reserve, ERCOT Contingency Reserve Service), arbitrage on day-ahead and real-time price spreads, and the structural shape of Texas net load with solar-driven daytime troughs and steep evening ramps.
The reliability effect is now visible in the assessment. ERCOT’s summer load forecast continues to climb, with hyperscale data center growth in West Texas and across the Permian, but the operating reserve margin under normal conditions remains adequate in the NERC framing. The far-west zone is flagged for load disruption risk when wind and solar are low and transmission constraints limit imports. That is a transmission and locational issue, not a system-level resource adequacy gap.
What the three elevated-risk regions have in common
NPCC New England. ISO-NE went into summer 2026 with reduced firm import commitments. Hydro-Quebec deliveries through the existing interties remain subject to economic curtailment. The replacement of retired oil and coal capacity has come primarily from gas and offshore wind, with offshore wind interconnection still slow. ISO-NE’s battery storage fleet stands at roughly 1.0 to 1.2 gigawatts as of mid-2026, an order of magnitude below ERCOT. Capacity market structure (Forward Capacity Auction) clears reliability contracts at prices that historically have not supported BESS at scale. The pipeline of storage projects in ISO-NE interconnection queue is large, but the build cycle has not caught up to retirements.
MRO SaskPower. Saskatchewan’s grid is small (peak demand in the 4 GW range), provincially run, and historically resource-rich on coal and gas. A higher demand forecast and the retirement schedule on legacy coal units have squeezed reserves. SaskPower’s storage portfolio is essentially zero at utility scale, with the first announced grid-scale BESS still in development. The province operates two AC interties to neighboring grids (AESO in Alberta, MISO via Manitoba Hydro), with limited capacity. The reserve margin compresses under stress without an internal flexibility resource that can ride through evening ramps.
WECC Northwest. The Pacific Northwest reliability story this summer is hydro. Below-normal snowpack across the Columbia basin has reduced expected generation from the federal hydro system that historically anchored summer reliability in the region. BPA, PacifiCorp, PGE, and Puget Sound Energy have material storage development underway, but installed BESS in the Pacific Northwest remained under 1 gigawatt entering 2026. The region has been a net exporter into California for decades. Drought-constrained hydro flips that flow and exposes both ends of the trade to thinner reserves.
The pattern across the three is consistent. None of them has reached the gigawatt-class storage scale that ERCOT, CAISO, and the desert Southwest have built. Two of the three (New England and Saskatchewan) have a capacity market or vertically-integrated structure that has not yet sized storage procurement to the level the assessment now implies is needed. The third (Pacific Northwest) has been a hydro region for so long that the flexibility role storage plays elsewhere has been a federal dam fleet, and the dam fleet is having a bad water year.
What storage solves for, and what it does not
Storage at the gigawatt scale solves the specific failure mode that produced most of the bad summer hours of the last decade. The pattern is well documented: load peaks late afternoon to mid-evening, solar output rolls off into sunset, gas peakers and demand response have to cover the ramp, the reserve margin compresses, and prices spike or load gets shed. Four-hour batteries (and increasingly six- and eight-hour systems) cover the ramp window with very high availability. They do not require fuel logistics. They start in seconds. They reduce the marginal cost of the peak hour.
What storage does not solve, and what the assessment continues to flag, is the multi-day extreme event. A four-hour BESS provides four hours of full output. A seven-day heat dome with wind drought and impaired hydro is not what 1- and 2-hour BESS (97 percent of the ERCOT fleet) was sized for. Longer-duration storage (6, 8, 10 hour) is growing but remains a minority of the operating fleet everywhere. Capacity accreditation rules for storage in ERCOT, CAISO, MISO, and SPP are still being calibrated against extreme-event performance, and the assessment is implicitly warning that the calibration has not yet been tested by the next 2021-class event.
Storage also does not solve transmission. The far-west ERCOT note in the assessment is a reminder that resource adequacy at the system level is not the same as deliverability at the zonal level. CAISO’s queue includes large storage projects sited where transmission upgrades are still years out. The Pacific Northwest hydro issue is structurally a fuel issue, but the inability to import from California at peak is a transmission issue too.
Where the build needs to happen for the 2027 SRA to look different
Three takeaways for what the 2027 Summer Reliability Assessment is most likely to flag, based on what is currently in development versus what would have to be in development now to change the next assessment.
ISO-NE has to procure storage at the gigawatt scale through its capacity market or through state procurement. Massachusetts and Connecticut both have storage targets, but the FCA-cleared MW that count for reliability remain modest. A 1 GW addition across the next two FCA cycles, combined with the Avangrid and Vineyard Wind interconnections coming online, would meaningfully change the New England line in next year’s assessment. Without it, the region stays on the list.
SaskPower has to either build internal storage or expand the AESO intertie. Provincial procurement timelines and the political economy of crown-corporation utility planning make the first option slower than the engineering would suggest. Expanding the Alberta intertie is on the table but politically constrained. The most likely outcome is incremental, which means SaskPower stays elevated in 2027.
The Pacific Northwest hydro shortfall is a weather-cycle problem with multi-year structural overlays. Snowpack will recover in some years and not in others. BPA’s draft 2026 IRP signals a meaningfully expanded storage role and BPA-region utilities have specific projects in development, but the operating fleet is still building toward the gigawatt threshold. Drought conditions are also a multi-year story for the Lower Snake reservoir system and for Columbia basin agriculture, and water management cannot prioritize summer peak generation against irrigation and fish passage indefinitely. The region’s reliability path runs through both storage and demand-side flexibility, not just generation.
Positioning implications
- Storage developers with active queue position in ERCOT, CAISO, and the desert Southwest continue to operate in markets where the marginal value of additional MW is competing with a large existing fleet. Returns increasingly depend on duration (4 hours and longer) and on specific locational value. The easy spreads have compressed.
- Storage developers with queue position in ISO-NE and BPA are positioned at the front of what is likely to be a multi-year procurement cycle. The reliability case is now backed by NERC framing, which strengthens the regulatory and political path for state-led procurements and for capacity market reform.
- SaskPower and provincial Canadian crown utilities are an underserved storage opportunity at modest scale. The buyer is the province. The volume per project is small. The competitive field is thin.
- Gas peaker developers retain a position in regions where storage scaling is slow and where capacity accreditation rules continue to favor dispatchable thermal. The window is shrinking but not closed. New England gas-fired retirement timelines are slipping for exactly the reason the assessment flags.
- Transmission developers are positioned across all five regions named, including ERCOT’s far-west zone. Storage substitutes for transmission only over short timeframes and short distances. The build cycle for storage is one to three years, for transmission five to fifteen.
The 2026 assessment is the first one where it is possible to draw a clean line through the elevated-risk list and say: this is what happens when storage build does and does not keep up. The 2027 assessment will be the first one where that frame either holds or starts to break down, depending on whether storage solves for the multi-day event the way it has solved for the daily ramp.
Sources
- NERC, 2026 Summer Reliability Assessment, May 2026, nerc.com/our-work/assessments.
- ERCOT, Understanding Battery Energy Storage Systems: Current and Future, February 2026 stakeholder briefing.
- ERCOT, Capacity, Demand and Reserves (CDR) Report, December 2025.
- Modo Energy, ERCOT Annual Buildout Report: Battery capacity reaches 14 GW entering 2026, 2026 research note.
- ISO New England, Forward Capacity Auction results and reliability outlook, 2025 and 2026 filings.
- Bonneville Power Administration, 2026 Integrated Resource Plan, draft chapters.
- SaskPower, Resource adequacy and supply plan filings, 2025 and 2026.