"There is a US wholesale electricity market." Not really.
Most articles treat "the US wholesale electricity market" as one thing. It is not. The country runs seven separate organized markets, each with its own rules, plus a large swath of the South and West where there is no organized wholesale market at all and the utility still self-supplies through long-term contracts and its own plants.
Those seven markets do not all sell the same product, either. PJM, ISO-NE and NYISO run capacity auctions where generators get paid for being available three years in advance. ERCOT does not, and recovers fixed costs through scarcity spikes in the spot market instead. CAISO runs a 15-minute energy market alongside a day-ahead. SPP and MISO sit somewhere in between. The same plant earning the same revenue in PJM would earn it through a very different mix of payments in ERCOT.
This matters because the rule that actually pushes your bill up or down depends on which market your utility belongs to. The single most important wholesale event of the last 18 months, the PJM 2026/2027 capacity auction that cleared at $329.17/MW-day on 22 July 2025, did not move bills in ERCOT or CAISO at all. It just moved them in the 13 states and DC that PJM serves.
Read the next sections market-by-market. The mental model "one wholesale market" will give you the wrong answer every time.
What a wholesale electricity market actually is.
Three simultaneous auctions run inside every US ISO or RTO. Each one prices a different product. Your retail bill is a mix of all three, smoothed out.
Energy market
Generators bid the price at which they are willing to run for each five-minute interval. The operator stacks bids cheapest-first until demand is met. The most expensive unit needed sets the marginal price that every generator that cleared gets paid. On a mild April afternoon this might be $25/MWh; on a January cold snap it can be $1,000+/MWh in the same market.
Capacity market
A forward auction where generators sell a promise to be available three years from now, whether they run or not. PJM, ISO-NE and NYISO run capacity auctions; MISO has a seasonal version; SPP and CAISO do not, and rely on bilateral contracts. ERCOT is energy-only. The capacity auction is the layer that drives the headlines: PJM's 2026/2027 auction cleared 22 July 2025 at $329.17/MW-day, the maximum FERC allows under the new Net CONE cap.
Ancillary services
Smaller side-auctions for the technical services that keep the grid balanced: regulation reserves, spinning reserves, voltage support, black-start. Usually a few percent of total wholesale spend, but the layer where home batteries and aggregated DERs can earn money under FERC Order 2222.
The detail that surprises most readers. The marginal-price rule is what makes spot prices move 100x in minutes. When demand pushes the grid to call on the most expensive plant in the stack, every generator that already cleared gets paid that same high price. That is intentional: it gives every generator an incentive to bid honestly. It is also why a heat dome or a polar vortex can produce billions of dollars of wholesale spend in a single afternoon.
The seven organized markets, side by side.
Coverage, products and the one rule that defines each market. Source: FERC RTOs and ISOs page, May 2026.
| Market | Footprint | Capacity auction? | Defining rule |
|---|---|---|---|
| PJM | 13 states + DC (IL ComEd zone, OH, PA, NJ, MD, DC, VA, DE, WV, e-KY, NC, IN, MI) | Yes (Base Residual Auction) | 2026/2027 cleared $329.17/MW-day, hit Net CONE cap |
| MISO | 15 states from ND/MN to LA (incl. Ameren in IL) | Yes, seasonal Planning Resource Auction | Seasonal capacity, summer is the constrained season |
| ERCOT | Most of Texas (excl. El Paso, eastern panhandle and SE corner) | No, energy-only | $5,000/MWh day-ahead cap, $2,000/MWh real-time cap (RTC+B, Dec 2025) |
| CAISO | Most of California + parts of NV under Western EIM/EDAM | No (bilateral RA contracts via CPUC) | Duck-curve dispatch, 15-minute and 5-minute markets, EDAM rollout |
| NYISO | All of New York, 11 pricing zones (A to K) | Yes, monthly Installed Capacity (ICAP) auction | Downstate zones J (NYC) and K (LI) chronically clear higher |
| ISO-NE | ME, NH, VT, MA, RI, CT | Yes, Forward Capacity Market (annual) | First US ISO live with Order 2222 DER aggregation on 1 Nov 2026 |
| SPP | 14 central states (incl. KS, OK, NE, parts of TX, NM, MT) | No, bilateral resource adequacy | Markets+ expansion into West, RTO West proposal |
! The states with no organized wholesale market
A large slice of the US still has no organized wholesale auction. The Southeast (most of NC, SC, GA, AL, MS, TN, parts of FL, LA), most of the Mountain West (UT, ID, parts of MT, WY) and the Pacific Northwest (WA, OR, parts of NV) run on vertically-integrated utilities that own generation, transmission and distribution and bake the costs into regulated retail rates approved by the state PUC. There is no spot market to clear and no capacity auction to drive the headlines. The trade-off: more stable rates, but no shopping and no transparent price discovery.
How a five-minute auction ends up on a monthly bill.
The wholesale price changes every five minutes. Your residential bill does not. The translation happens in four stages, and most of them are invisible to consumers.
A Locational marginal price (LMP)
The ISO publishes a price for each substation node every five minutes. Two homes ten miles apart can sit on different LMPs when transmission is constrained. NYISO has 11 zones, PJM thousands of nodes aggregated into zonal averages.
B Utility default-service auction
In retail-choice states the regulated utility holds its own procurement auction (monthly in NY, semi-annual in PA, quarterly in OH and IL) and sells the result on at cost as "default" or "price-to-compare". Wholesale volatility is smoothed by the auction laddering.
C Capacity charge pass-through
The capacity auction price multiplied by the utility's peak load is the capacity bill it owes the ISO. In PJM that line is now $16.1 billion for the 2026/2027 delivery year (PJM, 22 July 2025), split across customers as a separate volumetric or demand charge.
D Retail supplier hedging
A retail electric provider that sells you a 12-month fixed price has to hedge its wholesale exposure with forward contracts, futures and physical purchases. When a fixed term ends, the renewal quote reflects whatever wholesale forwards have done in the meantime. That is why a renewal can step up sharply without anything visible changing on your bill in the meantime.
The takeaway: a fixed retail rate is a hedge, not insurance. It locks in the wholesale view of the future at the moment you signed. If wholesale forwards rerate (as they have done across PJM since July 2024), your next quote will reflect it.
The two market events that matter most right now.
If you only have time to absorb two recent changes, make them these. They are the rules the next 18 months of retail bills are built on.
PJM RTO-wide, $/MW-day
2026/2027 Base Residual Auction, cleared 22 July 2025. The maximum allowed under the new Net CONE cap.
Year-on-year jump
Up from $269.92/MW-day for 2025/2026. The previous year was a 9-fold leap from $28.92.
PJM capacity bill, 2026/27
Total cleared supply times clearing price. Up 9.5% from $14.7B the year before. Passed through to retail customers from June 2026.
ERCOT RTC+B goes live
Real-Time Co-Optimization plus Batteries: day-ahead cap stays at $5,000/MWh, real-time cap drops to $2,000/MWh, battery storage formally priced.
Three things the new numbers actually mean
- A PJM is supply-constrained, not policy-driven. The auction did not clear high because of climate rules. It cleared high because plant retirements, data-center load growth and a stricter new resource accreditation method pushed required capacity up while available capacity stayed flat. The signal is "build new plants here". Until they show up, the price stays at the cap.
- B The capacity charge is not the energy charge. Your bill will show a higher capacity component from June 2026, but the energy component depends on day-ahead and real-time prices that may or may not move in the same direction. Watch both lines, not just the headline.
- C ERCOT's lower real-time cap rewards batteries, not retail shoppers. The $2,000/MWh real-time cap means scarcity revenue gets spread across more hours, which favours fast-cycling batteries. Households see fewer spike days but a slightly higher base rate as the market reprices.
Why wholesale competition fell flat for households.
The wholesale-market rebuild of 1996 to 2005 did lower wholesale prices. It did not lower retail bills for most US households. Four structural reasons explain the gap.
Supply is shrinking as a share of the bill
In 1998 the supply portion was roughly 60% of a residential bill. In 2026 it is closer to 40 to 50%, depending on utility. Even a 15% wholesale discount now translates to 6 to 8% off the all-in bill, not 15%. The remaining 50 to 60% sits in regulated delivery and policy riders, neither of which the wholesale auction can compress.
Capacity and energy diverged
Wholesale energy prices fell across PJM, MISO and ERCOT through the 2010s thanks to cheap shale gas. Wholesale capacity prices kept rising, because the same cheap-gas era retired coal and nuclear faster than new plants came on. PJM's July 2024 and July 2025 auctions are the visible consequence. Capacity is a much smaller line than energy, but at $329/MW-day it is no longer rounding error.
Volatility passes through to variable retail products
The 2014 polar vortex, the February 2021 ERCOT freeze, the 2022 winter gas crunch and the 2023 heat domes each produced wholesale spot prices above $1,000/MWh. Utility default rates smooth these through laddered procurement. Variable-rate retail products do not. The repeated pattern of bill-shock incidents is what drove NY and IL to retire variable mass-market products in 2023 to 2024.
Wholesale liquidity ends at the ISO boundary
In the vertically-integrated South and West, there is no organized wholesale auction to discount against. Retail rates are whatever the state PUC approves in the utility's rate case, period. Wholesale competition cannot help a household in Atlanta, Charlotte or Salt Lake City the way it can in Houston, Cleveland or Pittsburgh.
The 1996 FERC orders did the structural work they were meant to. They did not promise lower retail bills, and they did not deliver them on their own. The bill consumers actually pay is the sum of a competitive supply layer, a regulated delivery layer and a policy layer, and the wholesale auction only governs the first.
Six things you can actually do with this information.
Identify your ISO first
Your utility's wholesale market is the rule that matters most. PJM (IL ComEd, OH, PA, NJ, MD, DC, VA), MISO (Ameren IL, much of the Midwest and South-Mississippi), ERCOT (most of TX), CAISO (most of CA). The deregulated-states map tells you which one.
Lock in before June 2026 in PJM states
If you live in IL ComEd, OH, PA, NJ, MD or DC and you are on a variable rate or month-to-month default, the July 2025 capacity auction lands on your bill in June 2026. A fixed-price quote written before that date can save real money. Refuse any contract whose renewal terms are not disclosed in writing.
Ignore variable mass-market offers
In retail-choice states, variable products pass scarcity through to your bill with no cap. NY and IL have effectively retired them for mass-market customers; other states have not. If a salesperson cannot answer "what is the maximum the price can become next month", walk away.
In ERCOT, watch the renewal cliff
A fixed-rate retail contract hedges you for the term, then resets at whatever the wholesale forwards say. RTC+B (5 Dec 2025) is repricing battery and storage value; your next quote will reflect it. Diary the renewal date the day you sign.
Track FERC Order 2222 rollout in your ISO
If you own (or plan to own) a battery, EV charger, smart thermostat or rooftop solar, the wholesale revenue you can earn through aggregation arrives on a fixed schedule: ISO-NE 1 Nov 2026, PJM 1 Feb 2028, MISO 1 Jun 2029, SPP Q2 2030. The FERC Order 2222 fact sheet is the canonical reference.
In a non-organized state, engage the rate case
If you live in NC, SC, GA, AL, FL, ID, UT, WA or OR, there is no wholesale auction to shop. Your only lever is the utility's next rate case at the state PUC. Consumer-advocate offices (NC Public Staff, GA Utility Consumer Office, OUCC in OH/IN, OCA in PA) accept public comments and frequently testify on bill impact.
Common questions about US wholesale electricity markets.
It is the auction where power plants sell electricity to the companies that resell it to you. In most of the US this auction is run by a non-profit grid operator called an RTO or ISO. Generators bid the lowest price they will accept, the operator stacks the bids cheapest-first, and the most expensive unit needed to meet demand sets the price for everyone. That price changes every five minutes. Your retail bill smooths the volatility, but it does not erase it.
Seven organized markets: NYISO (New York), ISO-NE (six New England states), PJM (13 mid-Atlantic and Midwest states + DC), MISO (15 states from the Dakotas to Louisiana), SPP (14 central states), CAISO (most of California), and ERCOT (most of Texas). Together they manage about two-thirds of US electricity. The Southeast (the Carolinas, Georgia, most of Florida, Alabama, Mississippi) and most of the Mountain West and Pacific Northwest have no organized wholesale market: their vertically-integrated utilities still self-supply and bake costs into regulated rates.
No one and everyone. The price is set by the highest-cost generator the operator actually needs to clear demand in a given five-minute interval. This is called marginal pricing. On a mild April afternoon the marginal unit might be a cheap nuclear plant clearing at $25/MWh. On a January cold snap the marginal unit might be a peaker plant clearing at $1,000+/MWh. The same auction can produce both prices on the same day.
Wholesale competition did lower wholesale prices over the 2008 to 2020 decade, thanks mostly to cheap shale gas. The catch is that wholesale costs are only one slice of your bill, alongside transmission, distribution, taxes, public-benefit charges and climate-policy riders. In most retail-choice states the shoppable supply portion now sits at roughly 40 to 50% of the total bill. The rest is regulated delivery and policy that no wholesale auction can compress. That is why retail prices kept rising even when wholesale fell. EIA Electric Power Monthly tracks the residential side; the US average for March 2026 was 18.83 ¢/kWh.
A capacity auction is a separate auction from the energy market. Generators sell a promise to be available three years from now, regardless of how much they actually run. PJM's 2026/2027 capacity auction cleared on 22 July 2025 at $329.17/MW-day for the entire footprint, up 22% from the previous year's record of $269.92/MW-day, and equal to the maximum FERC allows under the new Net Cost of New Entry cap (PJM news release, 22 July 2025). The 13 states served by PJM (IL ComEd zone, OH, PA, NJ, MD, DC, VA, DE, WV, eastern KY, NC, IN, MI) will see this cost passed through to retail bills in June 2026.
It forces ISOs and RTOs to let aggregated DERs compete in wholesale energy, capacity and ancillary-service markets. That includes rooftop solar, home batteries, smart thermostats, EV chargers and small commercial generators, when bundled by an aggregator. Implementation is staggered: ISO-NE on 1 November 2026, PJM on 1 February 2028, MISO on 1 June 2029, SPP in Q2 2030. CAISO and NYISO have older DER programs that already do most of what Order 2222 requires. Source: FERC Order No. 2222 fact sheet.
ERCOT is an energy-only market: it does not run a capacity auction. Generators recover their fixed costs almost entirely through scarcity-pricing events in the spot market. To keep that mechanism honest, ERCOT applies a system-wide offer cap, set after Winter Storm Uri at $5,000/MWh. Under the December 2025 RTC+B redesign the cap splits into a day-ahead $5,000/MWh ceiling and a real-time $2,000/MWh ceiling, with an emergency mechanism that drops the cap to $2,000 if the high cap is hit for 12 hours in 24. PJM, MISO and the rest run capacity auctions instead, so they tolerate lower spot caps. Source: ERCOT system-wide offer cap rules.
Three things. First, if you live in a PJM state, expect your supply rate to step up sharply in June 2026; the July 2025 capacity auction is the reason. Second, if you live in ERCOT, your fixed-rate retail plan absorbs scarcity for the term of your contract: when it ends, the next quote will reflect whatever the market did in the meantime. Third, if you live in a vertically-integrated state with no wholesale market, you cannot shop your way out of these mechanics. Your only lever is your utility's rate case at the state PUC.
Keep learning about US energy markets
Deregulated states map
State-by-state status of electricity and natural gas retail choice in the US.
Competition in US energy markets
PURPA, EPAct 1992, FERC Orders 888, 889 and 2000 in plain English.
How liberalization affects you
What retail choice means for residential customers, by state and ISO.
Transmission vs distribution
The two wires layers, why they are billed separately, and who is responsible.
Incumbent electricity suppliers
The legacy utilities that own the wires and provide default supply.
Who regulates US energy?
FERC, the state PUCs, the consumer advocates and where their jurisdictions meet.
Electricity prices per kWh
EIA-verified state-by-state residential prices, May 2026.
Demand response
Getting paid to use less. How aggregated demand bids into the wholesale market.
Distributed energy
Rooftop solar, batteries and EVs as wholesale resources under FERC Order 2222.
New York: 1998 to 2026
NYISO, the Reset Order and the $50M April 2026 ESCO settlement.
Illinois: ComEd, Ameren and PJM
Why the PJM 2026/2027 auction lands hardest on ComEd customers.
Texas energy hub
ERCOT, retail providers, rate plans and the RTC+B redesign.