US Power
PJM / ERCOT
The only commodity that must be made and consumed in the same instant, priced every five minutes at thousands of points on the grid.
Top Producers
US generation mix, 2024
Top Consumers
US electricity sales by sector, 2024
Main Uses
US electricity sales by sector, 2024 (EIA)
ERCOT price cap reached in Uri
$9,000/MWh
February 2021
PJM capacity price, 2026-27 auction
$329.17/MW-day (at cap)
July 2025
Gas share of US generation
roughly 40 percent
as of 2024
Data center share of US load
roughly 4 percent, projected to double or more by 2030
as of 2023
Typical hub price range
roughly $20-60/MWh outside scarcity
as of 2025
Electricity is the extreme case of a commodity. It cannot be stored at scale, so supply and demand are balanced in real time by regional grid operators, and the price is wherever that balance clears: routinely $20-60 per MWh, occasionally negative when wind and solar flood a low-demand grid, and occasionally thousands of dollars in scarcity. The two most-watched US markets are PJM, the 13-state eastern grid whose Western Hub is the most liquid power trading point in the country, and ERCOT, the isolated Texas grid that runs an energy-only design with scarcity pricing in place of capacity payments. Traders read generator economics through the spark spread, the power price minus the fuel cost of a gas plant at its heat rate, and its coal equivalent, the dark spread.
Two events define the modern era. In February 2021, Winter Storm Uri froze Texas gas wells and power plants simultaneously; ERCOT held prices at its $9,000/MWh cap for days, bankrupting retailers and co-ops and forcing a redesign that lowered the cap to $5,000. Then, after two flat decades, US electricity demand started growing again. AI data centers became the story of 2024 and 2025: PJM's capacity auction for the 2025-26 year cleared at $269.92 per megawatt-day in July 2024, roughly ten times the prior auction, and the 2026-27 auction cleared at $329.17 in July 2025, pinned at its price cap.
The generation mix beneath these prices keeps shifting: gas supplies roughly 40 percent of US electricity, coal has fallen to roughly 15 percent, and wind plus solar passed coal for the first time in 2024. Power is traded as monthly and calendar-strip futures on ICE and Nodal Exchange, split into on-peak and off-peak shapes, with basis markets at dozens of hubs and nodes layered on top.
How It Trades
| Venue | ICE and Nodal Exchange (futures and options); bilateral OTC; day-ahead and real-time auctions run by PJM, ERCOT, and the other grid operators |
| Benchmark contract | PJM Western Hub and ERCOT North Hub futures, split into on-peak (5x16) and off-peak shapes, monthly through calendar-year strips |
| Contract size | Quoted per MW of around-the-clock or peak load per delivery period; standard lots commonly equate to 400 MWh per peak month per MW |
| Price terms | USD per MWh at the named hub |
| Settlement | Cash settled against the average of the grid operator's day-ahead or real-time hub prices for the delivery period; the underlying physical markets settle locationally every hour and every five minutes |
| Typical curve | Double-peaked seasonality: summer (July-August air conditioning) and winter (January-February heating) trade at premiums to spring and autumn shoulders; Texas summer carries a scarcity premium reflecting the small probability of cap-level prices. |
| Liquidity | PJM Western Hub is the deepest US power market; ERCOT liquidity grew sharply after 2021. Liquidity drops fast beyond two or three calendar years, which is why long-dated data center and renewable deals are done as bespoke PPAs rather than exchange strips. |
Where It Trades
approximate share of global traded volume, 2025; US power is fragmented by grid operator and most volume sits in bilateral and RTO-run markets rather than a single exchange
Supply and Demand
Top producers
- Natural gas plants (roughly 40 percent of US generation, the marginal price setter in most hours)
- Nuclear (roughly 19 percent, the baseload backbone, with restarts and uprates returning in 2025)
- Wind and solar (combined above 15 percent and growing; passed coal in 2024)
- Coal (roughly 15 percent and declining, though retirements slowed as demand growth returned)
- Hydro (roughly 6 percent, concentrated in the Pacific Northwest)
Grid-scale batteries became material in 2024-2025, especially in ERCOT and California, absorbing midday solar and selling the evening ramp; they compress the daily price shape rather than the annual average.
Top consumers
- Data centers (the dominant growth story; roughly 4 percent of US load in 2023 with projections toward 10 percent or more by 2030)
- Industrial users (manufacturing reshoring, electrification of process heat)
- Residential and commercial buildings (air conditioning the key seasonal swing)
- Electric vehicles (a steady, distributed adder)
Major uses
- Computing and data center load
- Cooling and heating
- Industrial motors and processes
- Transport electrification
US load was essentially flat from 2005 to 2020. The return of demand growth from 2024 onward, concentrated in PJM and Texas, repriced capacity markets and revived gas and nuclear development.
What Moves the Price
- Weather: cooling and heating degree days dominate the front of the curve
- Natural gas prices, which set the marginal cost of generation in most hours
- Data center interconnection queues and large-load growth forecasts
- Wind, solar, and hydro output, which displace thermal generation and can push prices negative
- Plant retirements, nuclear restarts, and new-build pace versus demand growth
- Transmission congestion and outages, which split hub prices from nodal prices
- Scarcity events: heat domes, winter freezes, and the adequacy of reserve margins
- Capacity auction outcomes in PJM, which price reliability years ahead
Moments That Made the Market
2000
The California crisis of 2000-2001: market design flaws and manipulation produce rolling blackouts and utility insolvency.
2005
Organized markets mature; PJM's Western Hub becomes the benchmark for eastern US power trading.
2014
The January 2014 polar vortex spikes eastern prices and exposes winter gas-power interdependence.
2021
Winter Storm Uri in February 2021 holds ERCOT at its $9,000/MWh cap for days; the cap is later cut to $5,000.
2024
PJM's capacity auction for 2025-26 clears at $269.92/MW-day in July 2024, roughly ten times the prior year, on data center demand and retirements.
2024
Wind and solar generation together pass coal in the US mix for the first time.
2025
The 2026-27 PJM capacity auction clears at $329.17/MW-day in July 2025, at its cap; nuclear restarts and gas new-build accelerate.
What Changed Since the 2010 Handbook Era
- US electricity demand went from two flat decades to renewed growth, driven by AI data centers, reshoring, and electrification.
- Coal fell from about 45 percent of generation in 2010 to roughly 15 percent, replaced by gas, wind, and solar.
- Negative prices went from a curiosity to a routine feature of high-renewable hours in Texas and the Midwest.
- Winter Storm Uri in February 2021 made extreme-event risk a permanent part of power market design and pricing.
- Capacity, once nearly free in PJM, became the scarce product: auction prices rose roughly tenfold between 2023 and 2025.
- Grid-scale batteries emerged as a new asset class that trades the daily price shape itself.