Every utility-scale solar-plus-storage project that reaches financial close in 2026 does so on a PPA whose pro forma assumes a specific quantity of capacity value the project will earn in each year of operation. That capacity revenue is what turns a merchant-tail solar asset into a financeable clean-firm generation asset for a hyperscaler counterparty, and it is what the tax equity investor prices against the credit stack. The number matters enough that a 5-percentage-point swing in accredited capacity moves the levered equity yield by 30 to 50 basis points on a typical 2026 solar-plus-storage deal.
That number is not a single figure that follows the project across markets. PJM, MISO, and ERCOT now use three genuinely different frameworks to translate a nameplate solar-plus-storage installation into a capacity credit, and the same physical asset would earn materially different capacity revenue depending on which of the three interconnection queues it cleared. The gap between the three is widening as ELCC saturation curves steepen, as MISO’s seasonal accreditation matures into its third planning year, and as ERCOT continues to defer the Performance Credit Mechanism it authorized in 2023. Reading the July 2026 Steel River class of announcements against the actual capacity math each project earns requires holding all three frameworks in view.
PJM: joint ELCC and the storage saturation curve
PJM adopted effective load carrying capability, or ELCC, as its capacity accreditation method for wind, solar, storage, and hybrid resources through the FERC filing that settled in 2021 and took full effect for the 2024/2025 delivery year. ELCC measures the amount of perfect capacity a resource can replace while maintaining the same reliability level on the system, expressed as a percentage of nameplate. It is calculated annually by PJM’s independent market monitor and the RTO’s Resource Adequacy group, using a chronological Monte Carlo model of the system’s loss-of-load-expectation profile.
The ELCC values PJM published for the 2028/2029 base residual auction, which cleared July 7, 2026, tell the story of storage saturation. Four-hour standalone storage ELCC came in at 62 percent, down from 64 percent in the 2027/2028 auction, and materially below the 90 to 95 percent values that four-hour storage carried in the first PJM ELCC calibration in 2022. The mechanism is straightforward: each incremental gigawatt of storage on the PJM system pushes the marginal ELCC lower, because the same four-hour discharge window now overlaps with a larger existing storage fleet during the top loss-of-load hours. The 2028/2029 calibration reflects a PJM storage installed base of roughly 11 to 12 GW nameplate, up from about 4 GW in the calibration that set the 2024/2025 values.
Solar ELCC in PJM for the 2028/2029 auction sat at 9 percent for fixed-tilt and 12 percent for single-axis tracker, roughly flat against the prior auction. The solar ELCC curve has been more stable than storage because summer peak coincidence in PJM is already largely priced into the number, and the marginal solar contribution to reliability during evening ramp hours is already low.
The hybrid accreditation piece is where the joint ELCC methodology matters. PJM does not accredit a co-located solar-plus-storage system as the arithmetic sum of the standalone solar ELCC plus the standalone storage ELCC. Instead, the joint ELCC methodology treats the combined project as a single resource with a defined interconnection service level, calculates the joint contribution to loss-of-load reduction, and expresses that as a single hybrid ELCC value. For a 1 GWac solar plus 500 MW / 2 GWh (four-hour) storage configuration at typical Mid-Atlantic siting, the joint ELCC in the 2028/2029 auction runs approximately 24 to 26 percent of the combined nameplate, which is somewhat below the sum-of-parts calculation of about 28 to 30 percent, because the shared point-of-interconnection service level constrains the two resources from delivering their full standalone capacity contributions during the same top-of-LOLE hours.
That gap between joint and sum-of-parts is a structural cost of co-location that has to be weighed against the interconnection cost savings and the tax credit stacking benefits of a co-located design. In 2026 the joint-minus-additive gap has widened modestly as storage saturation has accelerated, and PJM’s Resource Adequacy group has flagged that the gap is likely to grow further through the 2029/2030 planning cycle unless system storage growth slows.
MISO: seasonal accreditation and the four-window question
MISO moved from a single-annual capacity accreditation to seasonal accreditation, or SAC, effective with Planning Year 2023/2024. The design was the RTO’s response to the winter-peaking risk that surfaced during the February 2021 event and the summer-peak stress of 2023, and it now sets four separate accredited capacity values for each generator: one for summer, one for fall, one for winter, and one for spring. The Planning Resource Auction (PRA) clears four separate capacity products at four separate seasonal prices.
For solar and storage the seasonal split changes the accreditation question. A four-hour storage resource in MISO earns close to its full nameplate accreditation during summer and winter peaks, roughly 85 to 90 percent of nameplate across both seasons in the 2026/2027 planning year, because the loss-of-load-expectation hours in both seasons are concentrated in narrow windows the storage can span. In fall and spring the seasonal accreditation drops sharply, into the 30 to 40 percent range, because the LOLE hours are more diffuse and the marginal storage contribution during those seasons is much lower.
Solar in MISO earns most of its capacity value in summer, at roughly 50 to 55 percent of nameplate for tracker installations in the 2026/2027 planning year, dropping to 8 to 12 percent in winter and to intermediate values in spring and fall. The seasonal split matters more for solar than for storage, because the seasonal load-shape variance is where solar’s capacity value is concentrated.
MISO does not use a joint ELCC framework for hybrid systems in the same way PJM does. Instead, MISO accredits the solar and storage components separately by season, then applies a co-location adjustment tied to the shared interconnection service capacity. In 2026 the practical effect is that MISO hybrid capacity revenue is more front-loaded to summer and winter than PJM hybrid capacity revenue, and the seasonal PRA prices in those two seasons have widened materially against fall and spring since 2024. For the Steel River class of MISO South projects, the summer and winter seasonal accreditation values are the numbers the PPA structuring desk is optimizing against.
ERCOT: energy-only, ORDC, and the deferred PCM question
ERCOT has no capacity market. Solar and storage in ERCOT earn revenue through three streams: energy sales in the day-ahead and real-time markets, ancillary services (regulation up and down, responsive reserve, ECRS, non-spinning reserve), and the operating reserve demand curve (ORDC) adder that lifts real-time energy prices during scarcity conditions. Capacity accreditation, in the sense that PJM and MISO use the term, does not exist. Solar-plus-storage projects in ERCOT are financed against an expected energy and ancillary revenue stack, not against a capacity payment.
The Performance Credit Mechanism authorized by the Texas legislature in 2023 through SB 3 and Public Utility Commission of Texas Docket 55000 would introduce a capacity-adjacent revenue stream, paying resources for performance during defined tight-supply hours. The PCM has not gone live. The PUCT approved the design framework in December 2023, but implementation has been deferred repeatedly, most recently in the April 2026 open meeting where commissioners flagged the go-live target as no earlier than 2028. Until the PCM is operational, ERCOT capacity revenue for solar and storage is entirely a function of scarcity pricing outcomes in the energy market.
The practical implication for hybrid solar-plus-storage in ERCOT is that PPA structuring cannot rely on an accredited capacity value the way a PJM or MISO deal does. The pro forma has to be built against modeled scarcity pricing distributions and modeled ancillary services revenue, both of which have wider confidence intervals than a fixed capacity accreditation payment. Tax equity investors underwriting ERCOT hybrids have adjusted for this by requiring longer merchant-tail hedges and by pricing a wider capacity-revenue haircut into their base case. The high summer 2023 and 2024 scarcity events showed the upside, and the mild summer of 2025 and the volatile spring 2026 conditions showed the downside.
For hyperscaler counterparties choosing between an ERCOT hybrid PPA and a PJM or MISO hybrid PPA at similar all-in delivered cost, the ERCOT deal carries a higher revenue-variance profile that has to be modeled against the counterparty’s own load-following requirements. Google, Meta, and Amazon have all moved specific data-center anchor projects into MISO South and PJM for exactly this reason through 2025 and 2026, while ERCOT continues to attract the merchant-plus-corporate-VPPA structures that can accept the revenue variance in exchange for the interconnection speed advantage the ERCOT queue still holds against PJM and MISO.
Reading a hybrid capacity number
The through-line across the three markets is that the same physical solar-plus-storage installation earns three different capacity numbers depending on the RTO it interconnects into, and those numbers move on three different calibration cycles. PJM ELCC is recalibrated annually against a rolling three-year Monte Carlo model. MISO seasonal accreditation is recalibrated annually against a four-season LOLE model. ERCOT does not accredit capacity at all in 2026 and is not scheduled to do so before 2028.
A PPA structuring desk pricing a hybrid solar-plus-storage project in 2026 has to answer three questions before the capacity revenue line in the pro forma can be locked. First, which RTO’s queue is the project clearing into, and what is the specific ELCC or seasonal accreditation the RTO has published for the delivery year the project is expected to reach commercial operation. Second, where does the project sit on the ELCC saturation curve for that RTO, and how much further downward pressure does the RTO’s queue pipeline imply for the accreditation value over the PPA term. Third, if the project sits in ERCOT, what modeled scarcity revenue distribution is the pro forma using, and what confidence interval does that distribution imply against the fixed-price PPA the hyperscaler counterparty is willing to sign.
The three-way split in capacity accreditation methodology is now one of the defining features of US utility-scale project development. It is not a technical footnote inside the RTO stakeholder process. It is the number that anchors every hyperscaler PPA, every tax equity flip, and every hybrid interconnection cost sensitivity in the 2026 pipeline, and it is the number that moves 30 to 50 basis points on levered equity yield when it shifts by a handful of percentage points in a given RTO’s annual calibration.