Power Markets: Wholesale Electricity and Capacity

Electricity is the only major commodity that must be produced at the instant it is consumed, everywhere on a network, with almost no storage between the two. That physical fact shapes every market built around it. Since the late 1990s about two-thirds of US electricity load, and almost all of Europe's, has been priced in organised wholesale markets run by independent system operators (ISOs and RTOs in the US; exchanges and transmission operators in Europe). Their core mechanism is the merit order: generators are dispatched from cheapest to dearest, and every one is paid the price of the last unit needed, the marginal price. Because the marginal unit is usually a gas plant, power prices track gas prices, which is why Europe's gas crisis of 2022 became a power crisis and why the 2026 Gulf crisis pushed European power prices up again. Because wind and solar have near-zero running costs, they push the marginal price down, sometimes below zero, and erode their own revenues. And because prices in most hours are too low to pay for plants that run only in a few, markets must solve a second problem: resource adequacy, having enough capacity for the worst hour of the year. Texas (ERCOT) relies on scarcity prices in an energy-only market; PJM and others pay generators in capacity auctions, whose prices rose from ~$28.92/MW-day (2024/25) to the cap of ~$325–333/MW-day (2026/27 to 2028/29) as data-centre load forecasts arrived (PJM, reported). Winter Storm Uri (Feb 2021) showed what happens when an energy-only market's scarcity price meets a physical failure. This section explains how the markets work, how prices are formed in each time frame, how adequacy is paid for, what ancillary services and negative prices are, how retail choice sits on top, who makes money, and how data-centre load is reshaping market design. Two companion files give a stylized merit-order, price-duration and capacity-auction worked example and a case study of Winter Storm Uri.