Electricity market design across the Atlantic: Nodal or zonal pricing?

US electricity markets rely largely on nodal pricing, while Europe operates mostly with zonal pricing. What does each system get right and what not? From a European perspective, is nodal pricing something to aspire to, or would it be too difficult to implement politically?

Across the Atlantic, the United States and Europe often pursue different approaches to energy and climate policy. Yet many of today’s policies have been shaped by decades of exchange, adaptation, and mutual learning.

In this final instalment, experts from MIT CEEPR and the Florence School of Regulation compare the European and North American approaches to electricity market design, discussing the strengths and limitations of zonal and nodal pricing and whether Europe’s current model is fit for the challenges of the energy transition.

From the US: Paul L. Joskow, Elizabeth & James Killian Professor of Economics, Emeritus, MIT Department of Economics

The presumption in the question is not quite correct. In the U.S., all of the RTO/ISOs rely on organized nodal pricing in day-ahead and real time hourly “spot” or “economic dispatch” markets for energy. Hourly day-ahead and real-time spot markets for ancillary services are also co-optimized with the energy markets. These nodal pricing “spot” markets work well. All RTO/ISOs have external (and most internal) market monitors to mitigate potential market power and market manipulation.

With a couple of exceptions, the RTO/ISOs do not rely on these short-term markets to identify and support investments in new generation to meet resource adequacy (RA) criteria. CAISO, SPP, MISO, NYISO impose resource adequacy requirements on load-serving entities, primarily distribution companies. Only PJM and ISO-NE rely in capacity markets to signal the need for new generation without imposing any RA obligations. In the other ISOs, capacity markets are primarily a vehicle for trading capacity in the short term to allow LSEs to meet their RA obligations economically. In all U.S. markets, investments in and financing of new generation is increasing supported by long-term PPAs with “corporate” buyers or LSEs or where regulated  distribution companies can own generation, supported by cost-of-service regulation.

The rejection of nodal pricing in the EU is in part political and in part reflects rent seeking by interest groups. In some countries (e.g. Germany), there is concern that nodal pricing will undermine commitments to have only one wholesale price, hiding the North/South congestion. Energy traders also like the current system in the EU because it provides opportunities for them to make money on trading and to facilitate market manipulation. In the U.S., ENRON supported a PX/SO model for this reason. The PX/SO system facilitates market power and market manipulation as well. Moreover, unlike the U.S. where RTO/ISOs are non-profit entities and own no electricity supply assets, in the EU, the system operators also typically own the transmission network and can profit from congestion in a non-transparent way. For this and other reasons, Great Britain has now separated the system operator from the owner of its backbone transmission network.

From Europe: Tim Schittekatte, Part-time Professor at the Florence School of Regulation

EU vs North America: it’s more than market design, the institutional setup matters too

The high-level principles of electricity market design in the EU and North America are similar: marginal pricing, unbundling and a sequence of markets running from years ahead to real time. The implementation differs a lot, though. Perhaps the starkest difference is the spatial granularity of wholesale prices, meaning how much prices can vary from one location in the network to another.

The EU (plus Norway) uses a zonal model, while each North American independent system operator (ISO) uses nodal pricing. The institutional setups also differ, and that is no coincidence. Each one closely relates to its pricing model.

In the EU, transmission system operators (TSOs) build, own and operate the grid, and power exchanges run the wholesale market. A single central algorithm (Euphemia, for day-ahead) “couples” the market across all bidding zones. In most countries, power exchanges compete for clients and forward their bids and offers to that algorithm. The TSOs supply the other key input: the available transmission capacity between bidding zones, or the parameters needed to calculate it. The algorithm is truly pan-European, setting prices from Portugal to Finland. That makes the EU the largest coupled power market in the world, covering roughly three to four times the consumption of PJM, the largest US ISO. The catch, discussed below, is that bidding zones can be very large, and each zone has only one price per market time unit (15 minutes).

In North America, ISOs operate both the grid and the market, while transmission owners (TOs) build and own the network. Wholesale power exchanges do not exist (anymore). Because one entity runs both the grid and the market, nodal pricing becomes practical: every transmission element is considered when the market clears. Ignoring losses, prices differ between two nodes when the lines connecting them are congested. The Western Energy Imbalance Market (WEIM) is an exception: a real-time nodal market in the western US with no ISO covering its whole footprint. CAISO operates the market, but the participating Balancing Authorities (BAs) remain responsible for balancing their own areas. Recently also a day-ahead extension has been introduced. US nodal markets are not coupled with each other in the EU sense. Trade across these “seams” relies on bilateral trading arrangements, which is not unlike the current situation between the EU and Great Britain.

In short, and setting the WEIM aside, the EU is better at organising trade between system operators, while North American ISOs are better at organising trade within their control areas.

The EU bidding zone deadlock: it’s politics

The zonal model has served the EU well. Its relative simplicity probably made it possible to couple all Member States over the past 20 years and to harmonise the key design elements: first day-ahead, then intraday, and now balancing. The current bidding zones were drawn when national grids were strong, a legacy of vertically integrated utilities, and cross-border capacity was limited. In that setting, zonal pricing works well. Most bottlenecks sit on the borders between zones and are reflected in prices, so TSOs rarely need to intervene to keep the market schedule within the limits of the internal network.

That setting no longer exists. Transmission has been built far more slowly than new generation, especially intermittent renewables. As a result, the corrective actions TSOs take to make market schedules physically feasible have grown sharply. Redispatch costs in Germany alone have reached several billion euros a year.

High redispatch costs are a symptom of an outdated zone configuration, and they land on consumer bills. While redispatch costs are transfers between generators and consumers, an outdated zonal configuration also create significant economic inefficiencies: poor price signals lead to suboptimal dispatch and poor siting decisions, and eventually to the wrong transmission being built. The classic example of an underutilised asset in such market design has long been cross-zonal transmission capacity. A newer one is batteries: with good price signals they can substitute for transmission, but in a large zone with heavy internal congestion they often make congestion worse. This is necessarily not a matter of bad faith. It is the result of bad price signals. As TSOs increasingly must intervene close to real time, security of supply comes under pressure too.

The fix is straightforward: split zones that have significant internal congestion. EU law requires periodic bidding zone reviews to test whether the current configuration is still fit for purpose. The methodology and data of the recently completed second review can be debated, but its conclusion was clear: splitting the large, heavily congested zone in central Europe makes sense. Politicians nevertheless decided to keep the status quo.

The main obstacle is distributional. A split would make the system cheaper to run overall, but wholesale prices would fall in some areas and rise in others. Consumers as a whole would benefit, while some influential large consumers and producers would lose out, at least in the short run. Arguments about liquidity and market power are also raised; see the paper in the footnote for a rebuttal.[1]

How to move forward: three scenarios

I see three broad paths: do nothing, split the bidding zones, or move to nodal pricing.

1. Do nothing. The status quo is not stable. If prices cannot coordinate the market with the physics of the grid, something else will have to, and that something is central control by the system operator. This is not only a matter of costs but also of system security. We can already see the patches as a response to rising redispatch volumes: TSOs restricting how batteries and other flexible assets operate, grid connections tied to curtailment conditions, and a growing collection of local flexibility and congestion management schemes. Each patch is defensible on its own, but together they amount to a slow drift from a market-based system toward an increasingly costly administrative dispatch. Some commentators would argue that redispatch volumes will fade away if we build more network assets. Considering the estimates of network costs and delays I do not find this a credible scenario, unless we would abandon the energy transition.
2. Split bidding zones. This is the most realistic step change, since it fits the existing institutional framework: Euphemia, the TSOs and the power exchanges all remain in place. Two things might help to make it politically viable and durable. First, well-designed transitional arrangements (grandfathering) for those who lose out, such as temporary compensation funded from congestion income or long-term transmission rights that hedge the new price differences. Such arrangements should be time-limited and should not blunt the new price signals at the margin. Second, a clear, rules-based procedure for adjusting zones over time. Today every reconfiguration is a one-off political battle. Instead, zones should be reviewed at a predictable frequency against transparent congestion criteria, so that market participants can anticipate changes and the configuration keeps pace with the grid.
3. Nodal pricing. This is the ‘first best’ answer: every significant constraint is priced, and dispatch, siting and flexibility all get the right signals. North America shows that the transition can be done. Ontario recently moved from a single uniform price to nodal pricing, and Alberta is preparing to do so next year. For the EU, though, the hurdles are far higher. Nodal pricing works best when market and grid operation are closely integrated, whereas the EU has deliberately separated TSOs from power exchanges and has dozens of mostly national TSOs rather than one pan-European ISO. Entirely integrating system operation across borders does not seem realistic in the short to medium term, but perhaps the WEIM can be an inspiration for the EU where a nodal market exists but important system operation functions have remained local.

The real question is not whether Europe can design a better market, since the technical answers are largely known. It is whether Europe can build the political deal, with the right compensation and the right procedures, that allows it to adopt one.

Looking back to Florence

The inaugural FSR-MIT CEEPR Annual Conference on Energy and Climate Policy took place in Florence on 7-8 October 2026, bringing together researchers, policymakers and experts from both sides of the Atlantic. Building on the longstanding collaboration between the Florence School of Regulation and MIT CEEPR, the conference provided an opportunity to exchange perspectives on some of the most pressing energy and climate policy challenges facing Europe and the United States.

Stay tuned for further insights and outputs from the conference, as we continue the conversation beyond Florence.

[1] Eicke, A. and Schittekatte, T., 2022. Fighting the wrong battle? A critical assessment of arguments against nodal electricity prices in the European debate. Energy Policy, 170, p.113220. (link)