Every grid in America has to answer the same question: will there be enough power when demand peaks? But each state and market region answers it with a different definition, a different reliability yardstick, and a very different way of putting a price on "enough."
Start from the Ava Community Energy explainer on Resource Adequacy (RA), then widen the lens across the whole country. The goal is a single reference you can scan to see, side by side, how each region defines resource adequacy and how it prices it - from Texas, which pays nothing for capacity and lets scarcity set the price, to PJM and MISO, which run centralized auctions, to the Southeast, which never puts capacity on a market at all.
The short version
If you read nothing else, read these. Every claim below is expanded and sourced in the sections that follow.
Almost every region traces its target back to the same "1 day in 10 years" loss-of-load standard, a design basis used in the U.S. for roughly 70 years. It gets translated into a Planning Reserve Margin (PRM), often near 15%.
The CPUC sets the obligation and load-serving entities buy RA bilaterally. Its new "Slice-of-Day" rule (2024 test, 2025 live) requires proof of capacity for every hour of the worst day, not just the single peak.
PJM, ISO-NE, NYISO and MISO run centralized auctions. PJM's 2025/26 auction cleared at a record $269.92/MW-day, roughly 9x the prior year. MISO's summer season cleared at $666.50/MW-day.
ERCOT is "energy-only": no capacity payment at all. Value shows up in real-time scarcity prices capped at $5,000/MWh (cut from $9,000). Texas even wrote its own reliability standard, adding event duration and magnitude to the classic frequency test.
Across the Southeast and parts of the West, vertically integrated utilities meet a reserve margin through Integrated Resource Planning (IRP). Capacity cost is recovered in regulated rates, so there is no market "price" to observe.
The universal idea
Resource adequacy is the ability of a power system to serve demand at all times, with enough of a cushion to ride through generator outages, extreme weather, and forecast error. Ava Community Energy frames it in plain terms.
Resource Adequacy is "the ability to make energy when needed."
Ava draws a sharp line between energy (the electricity actually produced) and capacity (the standing ability to produce it on demand). RA is about capacity: proving in advance that the megawatts will be there, whether or not they are ever called.
Source: Ava Community Energy, "RA RA RA: Understanding Resource Adequacy," From the CEO's Desk, avaenergy.org. Accessed July 23, 2026.
Reliability-standard and reserve-margin figures: NERC Long-Term Reliability Assessment materials; NARUC, "The Economics of Resource Adequacy Planning"; ScottMadden Energy Industry Update. Accessed July 23, 2026.
Wherever you are, "is the grid adequate?" breaks into three practical pieces. California names them explicitly, but every region deals with all three:
System - is there enough total capacity across the footprint? | Local - is there enough inside transmission-constrained pockets (cities, load pockets)? | Flexible - can resources ramp fast enough to follow steep net-load swings as solar drops off in the evening?
California does not run a capacity auction. Instead the California Public Utilities Commission (CPUC) sets a mandatory obligation, and each Load-Serving Entity (LSE) - the big utilities plus 25 Community Choice Aggregators (CCAs) - must go buy enough RA under bilateral contracts and prove compliance. RA is administered, and priced through private deals.
Total capacity for the whole grid. Historically LSEs showed 90% of their summer-month need up front.
Reserves inside transmission-constrained urban pockets to prevent congestion-driven outages. Now handled by Central Procurement Entities (PG&E, SCE).
Fast-ramping capability to follow rapid net-load swings, the steep evening ramp as solar fades.
The old 2006 framework tested capacity against a single monthly peak. After the August 2020 heat wave triggered rotating outages, the CPUC approved a Slice-of-Day (SOD) methodology - called "a huge change to the RA paradigm" by Ava's VP of Power Resources. Under SOD, an LSE must show sufficient capacity to satisfy demand for every hour of the month's worst forecast day, not just its peak hour. CAISO used 2024 as a test year, with full implementation in 2025. This is what makes multi-hour batteries so valuable: a resource now has to prove it can cover the whole evening, not just one moment.
California figures above: Ava Community Energy, "RA RA RA: Understanding Resource Adequacy," avaenergy.org. Accessed July 23, 2026.
Because RA is bought bilaterally in a tight market, prices have climbed sharply. The CPUC noted 82 instances of LSEs paying over $100/kW-month for RA across 2023-2024, and the highest CCA transaction in summer 2023 reached $82.94/kW-month. High interest rates, inflation, and constraints on imported solar and batteries have all tightened supply. Source: CPUC 2025 RA Market Price Benchmark and CalCCA Stack Analysis (2023-2026). Accessed July 23, 2026.
The whole country, side by side
This is the heart of the brief. Read across a row to see one region's philosophy; read down the "How it is priced" column to see how differently the same idea gets valued. Color of the pill = the region's basic model.
| Region | Model | Who sets the standard | Reliability metric | How it is priced | Latest price signal |
|---|---|---|---|---|---|
| California (CAISO)CA | Administered RA | CPUC (state), with CAISO | Slice-of-Day, hourly; LOLE-based PRM | Mandatory obligation on each LSE; met by bilateral contracts, self-supply, and central procurement for local RA | up to ~$83/kW-mo highest CCA deal, Sum. 2023 |
| PJMMid-Atlantic, parts of Midwest | Capacity market | PJM / FERC | 1-in-10 LOLE → reserve margin | Reliability Pricing Model (RPM) Base Residual Auction, ~3 years forward, single clearing price | $269.92/MW-day 2025/26, record, ~9x prior |
| ISO-NENew England | Capacity market | ISO-NE / FERC | 1-in-10 LOLE → reserve margin | Forward Capacity Market (3 yrs forward), moving to a prompt, seasonal auction for June 2028 | Reform underway prompt/seasonal from 2028 |
| NYISONew York | Capacity market | NYISO + NYSRC / FERC | Installed Reserve Margin (IRM); locational | ICAP market with sloped demand curves; spot, monthly, and strip auctions; separate NYC / Long Island zones | Locational NYC & LI carry own curves |
| MISOMidwest + South | Capacity market | MISO / FERC (states via IRP too) | Seasonal, reliability-based; ELCC | Planning Resource Auction (PRA), now seasonal with a Reliability-Based Demand Curve | $666.50/MW-day 2025 summer; other seasons far lower |
| SPPCentral Plains | Reserve obligation | SPP / FERC | Seasonal PRM; ELCC + performance accreditation | No centralized auction. Each load entity must show it holds enough accredited capacity or pay a deficiency charge | 15% summer PRM new 36% winter PRM from 2026/27 |
| ERCOTMost of Texas | Energy-only | PUCT (state), ERCOT | Texas' own: 1-in-10 plus max 12-hr duration & magnitude caps | No capacity payment. Reliability value is embedded in real-time scarcity prices via the Operating Reserve Demand Curve | $5,000/MWh cap offer cap, cut from $9,000 |
| Southeast (SERC)e.g. GA, AL, the Carolinas, TN | Vertically integrated | State PUCs; utility IRPs | Utility-set reserve margin (~15% reference) | No market. Utilities build/contract to a reserve margin via Integrated Resource Planning; cost recovered in regulated rates | Rate-based no observable market price |
| West (non-CAISO)Northwest, Intermountain, Desert SW | Reserve obligation | Western Power Pool (WRAP); state PUCs | Seasonal PRM with regional diversity sharing | WRAP Forward Showing: prove PRM + 75% firm transmission 7 months ahead; deficiency charges, not an auction | Binding 2025-2028 first regional RA program in the West |
Row sources are listed in full under "Sources" below. Price figures are the most recent verified values as of July 23, 2026; capacity-auction prices move each auction cycle. Cross-market $/MW-day and $/kW-month figures use each market's native units and are not directly equivalent (auction terms, seasons, and accreditation differ).
Why the prices look so different
The single biggest reason RA prices differ across states is not weather or fuel. It is the market design choice about where reliability gets paid for. Regions sit on a spectrum.
Energy-only markets (ERCOT) keep steady costs low but lean on rare, extreme price spikes to attract investment, which makes revenue volatile and reliability harder to guarantee. Capacity markets (PJM, MISO) buy certainty up front, but that certainty now carries record price tags. Administered and IRP systems avoid a volatile market price, but shift the judgment call about "how much is enough" onto regulators and planners. Every design is a different answer to the same tension: reliability certainty versus cost.
Region by region
A closer look at what makes each region's view of resource adequacy distinctive, and where each one is heading.
Every acronym, spelled out
Traceable to the source
All items accessed July 23, 2026. Where a figure is a snapshot that changes each auction cycle (capacity prices) or a peak rather than an average (California bilateral prices), that is noted at the point of use above.