Europe
Zonal pricing, day-ahead coupling and EUPHEMIA, TSOs and ENTSO-E, the 2022 crisis when the political system discovered marginal pricing in public, and the regulatory aftermath of Iberia.
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.
Every day, shortly after noon, an algorithm called EUPHEMIA clears, across 27 European countries, the largest electricity auction on earth. In 2024 it cleared around 1,840 terawatt hours. It runs in under seventeen minutes. The result is a set of prices and flows that maximises total welfare across 37 bidding zones for every quarter-hour of the following day.
Prices are identical across any two zones with spare capacity, and diverge exactly when the interconnection between them fills up. Power flows toward the expensive zone automatically, because the algorithm allocates the cross-border capacity as part of the clearing rather than requiring anyone to buy it separately first. Market coupling replaced a system in which traders bought transmission capacity and energy in separate transactions. Separation can sometimes move power in the wrong direction, which is why coupling is generally preferred.
The trade has names for the two arrangements. Buying the transmission capacity in one auction and the energy in another is an explicit auction. Allocating the capacity inside the energy clearing, which is what EUPHEMIA does, is an implicit auction. The 70% of the US with power markets is also implicit. The market portion of the United States never needed coupling: a nodal clearing already co-optimises energy and transmission in one solve, so congestion arrives inside the price rather than as something a trader has to buy first. The older arrangement survives in the roughly 30% of the United States that has no wholesale market, where transmission service is reserved separately under the open access tariff and energy is scheduled against it afterwards, which is much of what the Western imbalance market in Chapter 17 was built to improve on.
Europe still runs explicit auctions at its own edges. Great Britain left the EU internal energy market in January 2021, and its interconnectors went back to selling capacity that way, so a trader crossing the Channel now buys space on the cable in one auction and the power itself in another.
The EU-UK Trade and Cooperation Agreement of December 2020 committed both sides to build a replacement, under the name multi-region loose volume coupling. Loose, because the two systems would stay separate and exchange traded volumes rather than clearing a single price across the border, which is what full coupling does. It is still unbuilt more than five years later, and the cost of its absence is exactly the defect coupling exists to prevent: power crossing the Channel from the expensive side to the cheap one.
The EUPHEMIA algorithm is the crowning achievement of European electricity policy. What Europe has struggled with is everything around the software.
The institutional split
Chapter 14 described European transmission system operators, or TSOs, as the operators that run the wires but not the market. The EUPHEMIA algorithm belongs to the exchanges collectively. The exchanges that collect the orders are commercial businesses, EPEX SPOT and Nord Pool among them. What they collect is bids to buy and offers to sell electricity for each quarter-hour of the following day, submitted by generators, by the suppliers buying on behalf of retail customers, and by traders and large industrial users. A household never appears in it. The auction ran on hourly blocks until 1 October 2025, when it moved to 96 quarter-hours a day, matching a granularity the intraday and balancing markets had already adopted. The transmission operators that own the wires are individual national companies across Europe, coordinating through ENTSO-E, which is the operators’ association rather than a regulator. The European body closest to the US FERC is ACER, an agency coordinating the national energy regulators, which appeared in Chapter 6.
So the day-ahead auction, which covers the power day starting at midnight CET, clears once each day just after noon against a simplified representation of the grid, internal constraints inside each zone are invisible to it, and the transmission operators afterwards redispatch to make the outcome physically deliverable. Chapter 15 covered the cost of that redispatch in Germany, close to three billion euros a year. The design produces one liquid price per country that a whole economy can hedge against, and pays for it with a redispatch bill nobody trades against.
The gap between the day-ahead result and delivery is filled differently on the two continents. The United States goes day-ahead and then straight into a centrally dispatched real-time market that re-solves every five minutes. Europe fills it with continuous intraday trading on the exchanges, running right up to a cross-border gate closure thirty minutes before delivery, and closer still inside a bidding zone, after which the transmission operator balances the system. Same day ahead to realtime gap, two answers. A European transmission operator does not run a market, so commercial trading has to continue until the operator takes over.
2022, and the year a textbook term became a tax
Chapter 8 explained uniform-price clearing and inframarginal rent as matters of market design. In 2022 they became matters of politics, and that transition happened at speed.
Russian pipeline supply fell away through the year while French nuclear availability was unusually poor and hydrology (hydro relies on rain, snow, and snowmelt) was weak. Nat gas at the Dutch TTF hub reached about 339 euros per megawatt hour on 26 August 2022, roughly 99 dollars per million British thermal units against US Henry Hub at 9.48 the same day. The average European nat gas price between 2015 and 2019 was near 17.59 euros per megawatt hour. Because nat gas plants were setting the power price in most hours, the power price followed. German year-ahead power passed 995 euros per megawatt hour and the French equivalent went beyond 1,100. These were more than ten times the level European power had traded at before the crisis.
The mechanism worked exactly as Chapter 8 describes. Every wind farm, solar park, hydro station, lignite coal plant and nuclear reactor on the continent received the price set by the marginal nat gas unit, while its own costs had barely moved. Across 2022 average European electricity prices rose from roughly 80 to 272 euros per megawatt hour, with fuel costs accounting for around 85% of the increase.
The response came in two stages.
The emergency measure was Council Regulation (EU) 2022/1854, adopted on 6 October 2022, which capped the market revenues of inframarginal generators at 180 euros per megawatt hour and directed the excess to member states for return to consumers. The word inframarginal appeared in binding law. A concept that exists only because of a clearing rule became something governments collected.
The structural measure followed. The reformed electricity market design was agreed at the end of 2023, adopted in May 2024 and in force from July 2024, and its centrepiece is the two-way contract for difference. New wind, solar, geothermal, reservoir-free hydro and nuclear built with public support are to be contracted at a strike price. When the market price sits below the strike, the public counterparty pays the generator. When it sits above, the generator pays the difference back, and those receipts flow to customers. The rules apply after a three-year transition.
A two-way contract for difference leaves the merit order intact and removes the rent. The generator still offers at its marginal cost, still gets dispatched in the same order, and the price still forms the same way. Only the generator's revenue is detached from that price. Europe kept the dispatch signal and took the inframarginal upside away.
In roughly two years the same idea travelled from a term in a textbook, to an emergency confiscation, to permanent architecture for how new generation is financed on a continent.
Iberia, and the service somebody finally paid for
An expert panel found that voltage and reactive power control failed in Spain and Portugal on 28 April 2025, and that conventional plants obliged to hold voltage did not do so. Chapter 13 argued that services procured through markets are verified every settlement interval while services imposed as obligations are checked whenever somebody chooses to check them. Spain had the second kind.
Renewable facilities were required to hold their power factor inside a band measured on an hourly basis, with reactive capability limited to a fraction of active output. There were penalties for breaching the requirement and no payment at all for supplying dynamic voltage support in the seconds during which system stability is actually decided. The rule asked for an hourly average and the physics needed a second-by-second response.
The instrument that governs this, Operational Procedure 7.4, was about twenty-five years old, and a revision had been sitting with the regulator in draft form for roughly five years. It was updated on 12 June 2025, six weeks after the blackout, and fully implemented on 17 March 2026. The revision lets the system operator draw on reactive capability from generation, demand and storage, and it introduces remuneration for the more demanding real-time setpoint-following service.
Spain started paying for voltage support.
Compare this to Chapter 13's other case. FERC concluded in Order No. 904, effective January 2025, that generators should not be compensated for reactive power within the standard power factor range, reasoning that operating in that band is a condition of being connected and that a separate payment risks paying twice. Within a few months, and on the other side of the Atlantic, Spain reached the opposite conclusion about the same capability, and did so with a blackout as its evidence.
Both decisions are defensible on their own terms, and this book will not pretend one regulator was obviously right. The pair illustrates something more useful: what a power system buys and what it merely requires are not the same, and the boundary between them moves in both directions, moved by events rather than by argument.
In addition to a new market, the other consequence of the Iberian 2025 blackout was the deployment of new equipment. Spanish grid-scale battery capacity went from around 28 megawatts in April 2025 to roughly 193 megawatts a year later. The absolute numbers are small next to Texas or California. The rate of change, in a country that had almost no storage before the blackout, shows how quickly a rule change moves capital once it makes something payable.
Europe on the three axes
Set against Part Three, Europe answers the three axis questions differently from America, but with logical reasons.
Table 19-1: Europe's answers, and what each buys
| Axis | Europe | What it buys, and what it costs |
|---|---|---|
| Who dispatches | National TSOs for the wires, commercial exchanges for the market | Coordination across sovereign states, at the cost of nobody holding both the grid model and the clearing |
| How location is priced | 37 zones, mostly national borders | One deep hedgeable price per country, paid for with redispatch and no siting signal |
| How capacity is paid | Assorted national mechanisms under common EU rules | Adequacy secured nationally, subject to a 550g emissions limit that makes it climate policy too |
European market design is made in public, through legislation, and usually after something has gone wrong. The 2022 crisis produced a revenue cap and then a contract regime. The Iberian blackout produced a grid code revision that had been stalled for five years and a payment for a service that had been free. Bidding zone boundaries are being argued about in a formal regulatory process with published numbers, which Chapter 15 covered.
That process is slower than a state regulator changing an ERCOT protocol, and it produces something Texas does not have: rules that thirty countries have agreed to, in writing, which is the only way a single price can exist across a continent that fought two wars in the last century.