Power Market Summary

This chapter is a map. The book has introduced a lot of separate markets, several of which exist only in some regions, and it is useful to see all of them at once before closing the book.

What an ISO actually runs

A US ISO runs five centrally cleared products: day-ahead energy, real-time energy, ancillary services, capacity where one exists, and financial transmission rights. Two further markets matter and clear nowhere central: bilateral term trading, and power purchase agreements. Finally, weather derivatives, along with nat gas and the rest of the energy complex, clear on financial exchanges like the CME and ICE.

Cleared is doing two jobs in that sentence. When an ISO market clears, it means the auction found a price at which offers met bids, which is the economist’s sense of the word. When a trade clears on the CME or ICE, it means a clearinghouse has stepped between buyer and seller, novated the contract, taken margin from both and guaranteed performance out of a default fund it sized in advance. That is the post-trade sense.

An ISO does the first and something close to the second. It is the counterparty to every participant in its markets, it invoices and pays, and it takes collateral. What it is not is a registered clearinghouse. The CFTC’s final order of 28 March 2013 exempted RTO and ISO energy, capacity, reserve and FTR transactions from almost all of the Commodity Exchange Act, leaving the anti-fraud and anti-manipulation provisions, so these markets sit under FERC rather than under the regime that governs a futures clearinghouse.

The difference shows up when somebody fails. GreenHat Energy defaulted on the largest FTR portfolio in PJM in June 2018, and roughly $179m of losses were allocated to the remaining PJM members over the following three years, many of them utilities serving retail customers. A futures clearinghouse would have taken that loss against margin and its default fund. An ISO allocates it to whoever else was in the market.

Energy is one product cleared twice

Day-ahead and real-time are not two independent markets. They are the same product cleared twice, over different parts of the same short forward curve, and the two-settlement system is what joins them. A participant settles first on its day-ahead position at the day-ahead price, then only on the difference between that position and what it actually did, at the real-time price.

A generator that sold 100 MWh day-ahead and produced 100 MWh is completely indifferent to real time, however violent real time gets. That is why the large majority of energy clears day-ahead while real time settles only deviations, and it is why Uri in 2021 hurt whoever was short into it rather than the Texas market at large.

Real time is also not a rolling 24-hour market. The operator re-solves the dispatch every five minutes for the interval immediately ahead, against measured conditions, and a price falls out of the same solve. Europe runs on fifteen-minute periods instead, but the difference is more than the length of the interval, and the last section of this chapter sets out what it actually is. Nothing about it looks 24 hours out. A schedule laid across all 24 hours of tomorrow is the day-ahead auction, and Table 9-1 puts the two side by side: day-ahead once for 24 hours against forecast load, real-time every five minutes against measured load. A participant’s real-time position is simply its deviation from the day-ahead schedule, settled at that five-minute price, or at the fifteen-minute imbalance price in Europe. It is an optimisation rather than a trade, and nobody is trading the next five minutes with anybody.

The virtual market ties the two together

A virtual supply offer sells energy in the day-ahead market with no plant behind it and buys the position back at the real-time price. A virtual demand bid does the reverse. Neither party ever produces or consumes anything, and the effect of enough of them is to pull the two prices toward each other, which is the subject of Chapter 24. Think of the virtual market like the paper oil market, where physical delivery is avoided by netting out positions before the futures, swaps and options expire.

Ancillary services are a joint product of the energy solve

Regulation, reserves, voltage support and black start are covered in Chapter 13. In the US they are co-optimised with energy in the same solve, so they are less a separate auction sitting beside the energy market than a joint product of it: a unit held back to provide reserve is a unit not selling energy, and the optimisation prices both at once. ERCOT batteries earned most of their revenue here in 2023, and Chapter 13 explains why that could not last.

Capacity, where one exists

PJM’s delivery year runs 1 June to 31 May rather than a calendar year, which is why its auction results are quoted in pairs, 2025/26 and then 2026/27. Great Britain runs its main auction four years ahead of delivery, which is why it is called T-4.

More importantly, a capacity market is optional. ERCOT and the Australian National Electricity Market are energy-only and have no capacity auction at all, which is the argument of Chapter 16: capacity is a choice rather than a universal market type, and two systems can make opposite choices and both keep the lights on.

Congestion is a market in the difference between two places

The instrument has four names, all for the same thing. PJM, MISO and ISO-NE call it a financial transmission right; CAISO and ERCOT call it a congestion revenue right; NYISO calls it a transmission congestion contract; SPP calls it a transmission congestion right. The auctions run annually and monthly, and they are funded by exactly the congestion rent the physical market collects.

The clean way to hold the two apart is that the energy market prices electricity at a location, while the congestion market prices the difference between two locations. Chapter 24 argues that a nodal market without them would be close to unhedgeable, which is why the two were designed together.

The markets outside the ISO

Term power trades two ways. Bilateral term trading is a contract between two trading desks for blocks of hours, weeks to years out, agreed on the telephone or a broker screen and cleared nowhere. The same forward exposure also lists as a future, which does clear: EEX is the main European venue, at over 5,100 TWh of power derivatives in the first half of 2026, ICE lists hundreds of financially settled US, British and continental contracts, and Nodal Exchange holds about 56% of US power futures open interest as of mid-2026. Nodal is part of EEX Group, so one company runs the leading power derivatives exchange on each side of the Atlantic. A power purchase agreement is a contract between a generator and a buyer for the output of a plant, also cleared nowhere, and it is the longest-dated instrument in the book by a wide margin. Weather derivatives are the exception in this group, since they list on the CME and ICE as well as trading over the counter. They settle against accumulated heating or cooling degree days at a named weather station, and they hedge quantity rather than price, which is why a retailer buys them even when its energy price is already fixed.

Day to day: where the US and Europe actually differ

The US day-ahead market does not run up to midnight. It is a once-daily auction closing late morning of the day before, which is essentially what Europe does. PJM’s bid deadline is 11:00 a.m. Eastern, extended from 10:30, with results posted by about 1:30 p.m. CAISO closes at 10:00 a.m. Pacific with results by 1:00 p.m. Europe clears at 12:00 CET. So the two day-ahead auctions are near-twins: one gate, mid-to-late morning, results early afternoon, covering the next delivery day.

The difference is what happens after that.

The real difference is the middle row rather than the granularity. Europe’s fifteen minutes is two separate things, neither of them a rolling equivalent of the American five: continuous trading between participants on an order book, party to party, right up to gate closure, and then a settlement period for whatever imbalance the TSO has to cover. The US has no intraday market at all. It goes auction, then operator.

That is the ISO and TSO split from Chapter 14 showing up in the trading day. A US ISO can dispatch centrally because it runs the market, so nothing commercial needs to happen between the auction and the instruction. A European TSO runs no market, so commercial trading, on independent exchanges like EPEX SPOT and Nord Pool, has to carry the system right up to the moment the operator takes over.