Resource adequacy frameworks

The short version

Every grid operator faces the same physical reality: enough generation must be available to meet the next peak demand event with high probability. They use radically different mechanisms to ensure this happens. The Eastern ISOs — PJM, ISO-NE, NYISO, MISO — operate centralized capacity markets that auction off the right to be paid for being available. CAISO uses a bilateral resource adequacy (RA) program where load-serving entities contract directly with generators to meet capacity requirements set by the California Public Utilities Commission. ERCOT alone uses an energy-only design with no capacity payments, relying on scarcity pricing to provide investment signals. Each approach has different costs, different risks, and different implications for commercial procurement.

Capacity markets (PJM, ISO-NE, NYISO, MISO)

Centralized capacity markets work the same way structurally. The ISO calculates the total capacity requirement for an upcoming delivery year based on forecasted peak load plus a planning reserve margin (typically 12-18% above peak). Generators submit offers indicating the price at which they're willing to commit capacity. The ISO clears the auction at the price needed to procure the required quantity — all cleared generators receive the clearing price for every MW for the entire delivery year. The clearing price is then collected from load-serving entities proportional to their forecasted load contribution at peak, who pass costs through to retail customers.

PJM runs the Base Residual Auction (BRA) three years ahead of the delivery year. The 2026/27 BRA cleared at $329.17/MW-day across the entire footprint, hitting the FERC-imposed price cap. The 2027/28 BRA, cleared December 2025, repeated this outcome at $333.44/MW-day — the first time the entire RTO hit the cap, indicating severe capacity shortage. Drivers include rapid data center load growth, electrification, generator retirements, and slow new build progressing through the interconnection queue. ISO-NE's Forward Capacity Market runs three years ahead with reconfiguration auctions closer to delivery. NYISO uses a strip auction model with monthly spot auctions. MISO implemented a seasonal capacity construct starting in 2022 to address reliability events.

CAISO's bilateral RA

CAISO does not operate a centralized capacity market. Instead, California uses a bilateral resource adequacy program where each load-serving entity is required by the California Public Utilities Commission to contract with sufficient generation to meet RA requirements. LSEs must demonstrate compliance through annual and monthly RA showings — providing evidence that they have contracted for enough accredited capacity to cover their share of system needs.

The CAISO RA framework evolved significantly with the implementation of slice-of-day shaping starting in 2025. Rather than just meeting a peak hour requirement, LSEs must now demonstrate capacity availability across all 24 hours, with particular focus on the late afternoon/early evening ramp when solar production declines but load remains high. This change addresses the resource adequacy gap that contributed to the August 2020 rotating outages and reflects the increasing importance of energy availability over multiple hours rather than just instantaneous peak coverage.

ERCOT's energy-only design

ERCOT operates an energy-only market without capacity payments — the only major US ISO to do so. The theory: when generation is tight, wholesale energy prices should rise to scarcity levels that provide adequate revenue signals for generators to maintain availability and for investors to build new capacity. ERCOT implements this through the Operating Reserve Demand Curve (ORDC), an administrative scarcity pricing adder that increases LMPs above marginal cost when operating reserves fall below specified thresholds. The wholesale price cap was reduced from $9,000/MWh to $5,000/MWh in 2023.

Winter Storm Uri (February 2021) exposed weaknesses in the energy-only design. The Performance Credit Mechanism (PCM) was proposed as a hybrid that would add partial capacity payments without creating a full capacity market — but was shelved by the Public Utility Commission of Texas in December 2024 after years of debate. ERCOT is instead implementing the Dispatchable Reliability Reserve Service (DRRS), real-time co-optimization of energy and ancillary services, and ORDC reforms. The bet is that targeted reliability services within an energy-only framework can deliver adequate reliability without the structural cost overhead of a capacity market — though the bet is being stress-tested as ERCOT's load grows four times faster than expected.

ELCC and the accreditation problem

The conceptual challenge with capacity markets is how to credit variable resources — wind, solar, and storage — that don't behave like dispatchable thermal generators. ISOs increasingly use Effective Load Carrying Capability (ELCC) methods that measure the marginal contribution of a resource to system reliability rather than crediting nameplate capacity. A solar facility with 100 MW nameplate might receive only 20-30 MW of ELCC accreditation; a battery's ELCC depends on duration (a 100 MW / 4-hour battery might receive 80+ MW ELCC, but only if other batteries aren't already saturating the system).

ELCC accreditation has reduced capacity contributions of intermittent resources, contributing to the capacity price increases observed in 2024-2025. This is mathematically inevitable: when wind and solar with nameplate capacity displace fully-credited thermal generation, total accredited capacity declines even as installed nameplate grows. The result is higher capacity prices to procure enough accredited capacity, channeling revenue back to remaining dispatchable resources (gas plants, demand response, storage) while creating ongoing pressure to procure more storage and demand response to fill the gap. For commercial buyers, the implication is that capacity charges will likely remain elevated in capacity-market regions through the late 2020s and beyond.