How Location Is Priced
Nodal, zonal, regional. PJM clears roughly 11,000 nodes while all of Europe clears roughly 40 bidding zones, and the German bidding-zone split fight is the live argument.
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.
PJM, on the US East Coast, computes a price at roughly 11,000 nodal points on its network, every five minutes. The whole of continental Europe computes prices across around just 40 zones. US market prices are nodal. Europe is zonal. PJM, the largest ISO in the US, serves around 65 million people, and the European system serves around 450 million.
The US power market is nodal in the 70% of the US with a wholesale power market. The other 30% are vertically integrated utility systems without markets and that set their own prices via regulated tariff rates.
Confusingly US power market prices are nodal on the supply (generator) side, but zonal on the load (demand) side. Generators settle at their own node; load usually settles at a zonal average, which Chapter 10 established. So a great deal of American demand faces a zonal price inside a nodal market. This is the big way that the US differs from Europe. Europe is zonal from top to bottom.
That comparison is the most significant single difference between the two largest electricity markets on earth, and everything in this chapter follows from it. Chapter 10 established why a price varies by location: the wires are finite, constraints bind, and the cost of serving one more megawatt-hour genuinely differs from one substation (each containing one or more nodes) to the next. This chapter describes whether the market sees that individual nodal price or not.
The market that sees the network, and the one that does not
A nodal market solves the dispatch against a model of the actual grid, with every relevant line limit in it, and publishes the resulting price at every point. Generators settle against the nodal point where they inject power. The price at a location carries the full information about what it costs to serve that location.
A zonal market draws a boundary, commonly a national border, and clears as though everything inside were a massive copper plate without line capacity constraints. Any generator inside the zone can serve any load inside the zone, at one price, and the market never considers the lines between them. Only the links between zones (interconnectors) are modelled as constraints.
Inside a small, well-meshed country with no serious internal bottlenecks, those two designs produce almost the same answer. Germany is the extreme case of a zone with exactly the internal congestion that nodal pricing exists to expose. Its wind is in the north and on the coast, its heavy industry and its largest cities are in the south and west, and the transmission between them has been inadequate for over a decade. Germany is nonetheless a single bidding zone, so those internal limits are invisible to the price while the network still has them. The next section is what that costs.
What happens when the market ignores a wire
The German zonal market clearing produces a schedule. Sometimes that schedule cannot be delivered, because moving the scheduled quantity of northern wind to southern demand would overload lines the market was never shown. Physics does not accept the schedule.
So the transmission operator intervenes after the market has cleared. It instructs generation in the north to reduce output and generation in the south to increase it, compensating both: paying the southern plant to run when the market did not select it, and paying the northern plant for output it was scheduled to produce and is no longer allowed to. That process is redispatch, and the cost is recovered through network charges rather than appearing in any publicly set market price.
Germany spent roughly 3.2 billion euros on redispatch in 2023 and close to 2.9 billion in 2024. In 2023 grid bottlenecks meant around 19 terawatt hours of electricity could not be delivered where it was wanted, and in 2024 about 3.5% of German renewable generation could not reach consumers. Transmission operators expect the volumes to rise again as more wind connects ahead of the lines being built to move it.
A German wholesale price is therefore an incomplete account of German electricity. It reports the cost of a dispatch that was not physically possible, and the cost of making it possible arrives separate from the market on a privately set network bill. The constraint is real either way. The design choice determines whether it appears in the price or in a charge.
Three designs
Table 15-1: How the three designs treat the network
| Nodal | Zonal | Regional | |
|---|---|---|---|
| Where | US ISOs, New Zealand, Singapore | Continental Europe | Australia |
| Prices published | Thousands | Roughly 40 across the continent | Five |
| Internal constraints | In the market | Outside it, handled by redispatch after clearing, day-ahead and intraday | Outside it, plus an annual loss adjustment |
| Congestion cost appears as | Price differences between nodes | Network charges | Network charges and loss factors |
| Siting signal | Direct and continuous | Almost none inside a zone | Weak, and revised once a year |
Australia sits between the two. The National Electricity Market has five regions, one per state, and every power generating asset in a region receives the same spot price. Losses are then handled through marginal loss factors, recalculated annually, which scale a generator's revenue according to how far it sits from the regional reference point. The scheme gives a locational signal of a sort, though delivered as an annual number rather than a price. Loss factors have moved sharply from year to year in weak parts of the network where large amounts of remote renewable generation connected quickly, which produces exactly the revenue uncertainty a long-term contract exists to remove. New Zealand, next door, runs a nodal market.
The German argument, and a number that complicates it
Whether Germany should be split into several bidding zones has been argued for more than a decade, and it is the live version of this chapter's question. The European regulator ACER set out the alternative configurations to be studied, and transmission operators published their assessment in April 2025.
The modelling favours splitting. A configuration dividing Germany and Luxembourg into five zones scored highest, at an estimated benefit of around 339 million euros for the 2025 target year, with the various split options ranging from roughly 251 million upward. ACER considered the operators' study conservative, putting the gain from splitting Germany combined with a Dutch power market reconfiguration at 450 to 540 million euros a year, around 70% above the operators' figure.
Set those numbers against redispatch spending of nearly three billion euros a year and the relationship between the two numbers is the point. Splitting the zone does not recover the redispatch bill. Much of the redispatch spending is a transfer to generators rather than waste, and the physical shortage of wires between north and south survives any decision about pricing. What a split changes is the quality of the signals: where new generation chooses to connect, where industrial load chooses to sit, which projects look attractive, and how much of the cost is visible to the people making those decisions. The gain is measured in better decisions over time rather than in an immediate saving.
The resistance is equally real. A single German price is a political object as much as an economic one, and splitting it would raise prices in the industrial south while lowering them in the windy north, creating identifiable losers in the regions with the most electoral weight. A single zone also supports a deep forward market, since traders can hedge German power as one product. Five zones would fragment that liquidity into five thinner books, and a forward curve that nobody trades is of limited use to anyone trying to finance a plant.
The one system that changed its mind
Texas provides the closest thing to a controlled experiment, because ERCOT ran a zonal market and then replaced it with a nodal one.
The nodal market went live on 1 December 2010, four years later than originally intended and after roughly 500 million dollars of systems investment, along with about fifty additional staff to run the more complex market. Studies of the period after the switch found the daily operating cost of thermal generation fell by around 3.9%, a saving that recovered the investment within a few years.
The transition is cited by both sides of the argument, which suits it. Half a billion dollars and a four-year delay is a genuine barrier, and the efficiency gain arrived and persisted. The relevant difference for Europe is that ERCOT rebuilt one market inside one state under one regulator. Redrawing bidding zones in Europe means renegotiating boundaries between sovereign states whose citizens pay the resulting prices.
What the choice actually settles
Reading this as a contest about accuracy would miss most of it. Nodal pricing is more accurate, and nobody serious disputes that. The argument continues because accuracy is only one of the things a market is being asked to deliver.
A nodal market puts the cost of congestion in the price, where the people whose decisions create and relieve congestion can see it, and hands them a continuous signal about where to build. It also produces thousands of illiquid prices, exposes individual generators to a node nobody can hedge without the instruments in Chapter 24, and creates locations where a single plant behind a constraint holds obvious market power.
A zonal market produces one liquid, tradeable price that a whole country can hedge against, at the cost of making the network invisible to everyone making decisions about it, and moving several billion euros a year into a charge that no market participant responds to.
Which is why this is one of the three axes (who dispatches, how location is priced, and how capacity is paid for) of market structure rather than a solved question. The choice in this chapter about location pricing determines where congestion cost surfaces, who sees it, and whether anyone can act on it. Chapter 19 takes up what Europe has done with that choice, and Chapter 24 covers the instruments a nodal market has to invent so that participants can live with the prices it produces.