How Capacity Is Paid For
Energy-only against capacity markets against Europe’s remuneration mechanisms. Nobody has a clean answer, and the ones who claim to have moved the cost somewhere less visible.
Words the industry uses are marked like this at the sentence that defines them, so you can tell a term you will hear on a desk from a phrase this book happens to be using.
A peaking plant earns nothing for most of its life and has to recover its costs from a few hours a year. Offer caps, operator intervention and ordinary caution all conspire to make those hours pay less than the theory requires. The world has produced three ways to pay for capacity, and the map of who chose which is the third market design axis.
Answer one: pay for energy and nothing else
An energy-only market pays generators for megawatt-hours and for reserves, and pays nothing at all for existing. If the system is short, prices rise, and the prospect of those prices is what persuades somebody to build. The scarcity machinery in Chapter 12, including the operating reserve demand curve, exists to make sure the price rises far enough and early enough for the arithmetic to work.
Texas and the Australian National Electricity Market both run this way. Nobody has to forecast how much capacity the system will need in four years, because the price does that job continuously. Nobody has to decide what counts as a megawatt of reliability. Investors take the risk, and if they misjudge it, they lose their own money rather than a consumer's.
The design depends on prices being allowed to reach levels that justify building standby generators which will only rarely be called on, and on customers and politicians tolerating those prices when they arrive. Uri in Texas in February 2021 tested both conditions inside a single week, and the subsequent lowering of the offer cap from 9,000 dollars to 5,000 is the clearest available evidence of where the tolerance ran out.
Answer two: buy the capacity separately
A capacity market pays generators to be available, in a market held apart from energy. PJM runs the largest example, the Reliability Pricing Model, and every capacity market resembles it closely enough that its shape is the one to learn.
The operator forecasts peak demand several years ahead, adds a reserve margin, and constructs a downward-sloping demand curve for capacity. It then runs a forward auction, typically about three years before the delivery year, in which resources offer to commit. PJM calls that auction the Base Residual Auction, which is the name attached to the numbers below. Residual, because it buys only what is left after utilities have self-supplied or contracted bilaterally; base, because three incremental auctions follow it closer to delivery. A delivery year runs from 1 June to 31 May, which is why the years below come in pairs. Clearing resources, which means every resource that commits and not only the rarely used backup generators, receive a payment per megawatt per day for the whole delivery year, and in return carry an obligation: they must be available when called, and they pay penalties when they are not. The delivery-year obligation, rather than the payment, is what distinguishes this from a subsidy.
Two properties follow from the design and cause most of the argument. The quantity bought when the capacity is ultimately needed is chosen by the operator rather than discovered by an independent market, and the definition of a megawatt of capacity is written by the operator too. The definition is specified in advance, in the tariff, rather than settled on the day. What makes it contentious is that the operator keeps rewriting it between auctions, and the definition decides how much each technology is credited with and so how much it is paid, which is the accreditation argument later in this chapter.
What the price did
PJM's recent auctions show what a capacity market produces when supply tightens against an administratively set demand curve.
Table 16-1: PJM base residual auction clearing prices
| Delivery year | Clearing price | Note |
|---|---|---|
| 2024 / 2025 | under $30 per MW-day | Ample supply |
| 2025 / 2026 | $269.92 per MW-day | Roughly a tenfold jump |
| 2026 / 2027 | $329.17 per MW-day | At the price cap. 134,311 MW cleared, about $16.4bn |
The 2026/2027 auction, announced in July 2025, cleared at the cap and cost around 16.4 billion dollars for a single delivery year, with estimated retail bill effects of roughly 1.5 to 5% depending on the state. Data centre load growth, thermal retirements and an interconnection queue too slow to replace them all pushed the same way at once.
Great Britain, running the same species of mechanism, moved the other way. Its T-4 auction, meaning the one held four years ahead of the delivery year, for delivery in 2028/29 cleared at 60 pounds per kilowatt year, which is about 222 dollars per MW-day. The following auction, for 2029/30, cleared at 27.10 pounds, about 100 dollars per MW-day, a fall of about 55%, because more capacity prequalified than the target required. Across its history the British auction has cleared anywhere between 6.44 and 65 pounds, roughly 24 to 240 dollars per MW-day. The dollar figures convert at about 1.35 to the pound and are given so the British numbers can be read against PJM’s, which are quoted per MW-day already.
Different currencies and different units, so these are two charts rather than two lines. PJM in dollars per megawatt-day for the delivery year shown; Great Britain in pounds per kilowatt-year from the T-4 auction. The GB figure for 2027/28 is approximate.
Both outcomes are the mechanism working. A capacity market does not remove volatility from generator revenue. It moves the volatility out of the energy price and into an annual auction, where the clearing price depends on the distance between a quantity the regulator chose and the supply that turned up. That distance can be small, and the price collapses. It can be negative, and the price hits the cap.
Answer three: buy some of it, for some people
Europe mostly sits between the two, under the label capacity remuneration mechanism, which covers arrangements of quite different ambition. A strategic reserve holds a small number of plants outside the market entirely, to be called only in emergency, which keeps them from depressing the ordinary price. A market-wide mechanism, as in Britain, France and Poland, pays every qualifying resource.
These sit inside a framework the electricity market of 2010 would not recognise. Regulation (EU) 2019/943 sets an emissions limit of 550 grammes of fossil carbon dioxide per kilowatt-hour for participation. New plants above that line cannot take capacity payments at all, and existing plants above it, together with an annual average above 350 kilogrammes per kilowatt installed, were excluded from 1 July 2025.
A capacity mechanism therefore does more than buy reliability in Europe. It selects which technologies are permitted to be reliable, which makes it an instrument of climate policy operating through a reliability product. That dual purpose is a large part of why these mechanisms are controversial.
The question that has become the hard one
Buying capacity requires deciding how many megawatts a resource is worth, and that has stopped being obvious.
A gas turbine rated at 300 megawatts contributes close to 300 megawatts of reliability, discounted by how often it breaks. A 300 megawatt solar farm contributes nothing at all on a January evening. A four-hour battery contributes fully to a four-hour shortfall and very little to a thirty-hour one. Nameplate capacity, the maximum output printed on the machine, stopped being a useful measure of what a resource does for reliability.
The industry's answer is effective load carrying capability: the amount of additional demand a system can serve, at unchanged reliability, once a resource is added. It is computed from probabilistic simulation rather than engineering ratings, and the resulting numbers vary enormously. Onshore wind is commonly credited at something like 15 to 21%, four-hour batteries at 83 to 100%, and solar anywhere from single digits to over 80% depending on the region and on when that region actually has its shortfalls.
PJM applies this to renewables, storage and hydro and has been extending it across all capacity resources. MISO is moving its accreditation to a direct loss-of-load approach later this decade. The methods keep changing because the answers keep changing.
The property that makes accreditation genuinely difficult is that these values depend on each other. Adding storage raises the capacity value of solar, because the battery can move midday output into the evening when the shortfall occurs, and adding solar raises the value of storage for the same reason. A resource's contribution also falls as more of its own kind is built, since the tenth solar farm defends the same midday hours the first nine already covered. Accreditation is a moving judgement about a portfolio, recomputed as the portfolio changes, and every revision moves real money between real companies.
Where the decision sits
A capacity market contains two administrative decisions: how much to buy, and what counts. Both are made by a regulator, years ahead, and the auction discovers only the price at which the chosen quantity of the defined product can be met. An energy-only market contains an administrative decision too, in the value of lost load and the shape of the reserve demand curve, made once and embedded in a formula that then runs continuously.
So both designs place a judgement about the worth of reliability in the hands of an authority. They differ in where that judgement sits, how often it is revisited, and how visible it is when it turns out to be wrong. An energy-only market makes it wrong quietly for years and then expensively in a single week. A capacity market makes it wrong in public, once a year, with a number attached and a bill impact somebody can put in a press release.
That completes the three axes. Who dispatches, how location is priced, and how capacity is paid for. Every system in Part Four is a combination of those three choices, and the combinations are not random: they follow from what each place was trying to protect when it wrote the rules.