If zonal pricing is the answer, what is the question?

“Electricity markets are broken” has been a familiar refrain for as long as I've been in the industry. The arguments have only grown in intensity during COVID and the energy crisis.

The one thing that everyone agrees on is that a new solution is needed, but any market reform will involve trade-offs and compromises between:

• generation and demand
• investment and operations
• price granularity and market liquidity
• the past and the future

Most of the current discussions on zonal pricing focus on the transmission system. Is this a step in the right direction, or a distraction that delays a decision on more fundamental market reform?

Recent indications suggest that Great Britain will split their national market into multiple zones, while Germany will not.

Regardless of the decisions taken this year, within the decade I suspect we will again be facing similar questions on electricity market design.

By then we will have to look deeper into the system, at distribution level congestion, at the overlap between wholesale and retail markets, and the changing needs and provision of flexibility.

These decisions are not the end of the discussion on market design. They are not even the beginning of the end. But they are, perhaps, the end of the beginning.

What is zonal pricing?

An electricity market divided into geographic zones based on bottlenecks in the transmission network is described as having zonal pricing. When congestion prevents electricity flowing freely from one zone to another, their prices will diverge. If this occurs, the price for each zone is determined by the balance of supply and demand within that zone.

• A zone where demand exceeds the capacity to supply locally or import from other zones will see prices rise, incentivising demand reduction, and investment in local generation or expanding network interconnection
• High renewable generation capacity in a zone may exceed the capacity to consume locally and export to other zones, with low prices incentivising higher demand or generation turn down, attracting investment in new demand (e.g. data centres and electrolysis) and expanding network interconnection

Why is it such a hot topic?

In the early days of electrification, it was more efficient to burn coal in power stations near demand. The development of high voltage distribution and transmission lines reduced losses from transporting power. Instead of shipping coal to be burned in cities, power stations could be built near coal mines. Our grids were built to transport power to the people from these large power stations, and heavy industry developed near the sources of power and gas.

Recent investments in generation have been dominated by wind and solar, and focused on locations that maximise their output - more wind in remote, northern regions, more solar in the south. Offshore wind, and rooftop solar on the distribution network, are both in their own way bringing power generation from new areas.

Already recognised in this Clean Energy 2016 Wire infographic, there is a growing mismatch between the capacity of the grid to move electricity from where it is now generated to where it is consumed.

How is this being addressed?

To prevent transformer overload, grid operators are having to take action to curtail generation in constrained areas. When the market construct ignores these physical constraints they have to compensate these generators. And as these curtailments leave the national market short of power, they have to pay generators downstream of the bottleneck to ramp up.

Redispatch frequently requires the curtailment of renewables in conditions ideal for generation, and ramping up dispatchable fossil fuel generators that were too expensive to clear in the national market.

Over the last 3 years this cost in Germany alone has exceeded €10 billion.

Expanding and reinforcing the network could eliminate all congestion, but is neither economically nor physically feasible. In any case, annual grid investment is expected to rise between 2 and 3 times current expenditure to €100bn per year. Even so, a JRC assessment anticipates redispatch “to increase massively”.

With bottlenecks also between national grids, the EU target to increase interconnector capacity was raised to 15% by 2030. At the start of 2025, although more than half of the EU member states were already above this level, 3 in 10 had yet to meet the previous target of 10%.

Recognising that physical bottlenecks in the grid are not reflected in market prices, debates over introducing and amending zones have been heating up.

Are decisions imminent?

A decision on introducing zonal pricing in the GB market is expected soon. The Review of Electricity Market Arrangements (REMA) ruled out nodal pricing, but ongoing uncertainty over the future pricing regime, and its effect on existing investments and upcoming CFD auction is causing concern to developers and investors. Jonathan Brearley, CEO of Ofgem, has asked for an “honest conversation” about zonal pricing. Yet the debate has remained polarized.

Initiated in 2019, entso-e’s review of Central European and Nordic bidding zones was published shortly before the Iberian blackout, which has somewhat overshadowed its impact. European member states affected by the BZR now have 6 months to come to a unanimous decision. However, with the input data collected in 2019, before both covid and the 2021-22 energy crisis, many of the assumptions on renewable generation and storage capacity are already outdated.

Is anyone happy with the recommendation?

The analysis found that splitting Germany into 5 zones would deliver the greatest economic efficiency. Likely to result in higher prices for southern Germany, the initial response has not been positive.

But the counterpoint, lower prices in northern Germany, where excess wind generation is constrained from reaching the south, would have impacts far beyond the country’s borders.

Unavailability of fossil fuel plants during a period of low renewable generation saw intraday prices spike to Eur900/mwh for the evening of 12 Dec 2024. Importing from its neighbours, the price spike was exported to the southern zones of Sweden and Norway.

Sweden’s energy minister was “furious with the Germans, ” while her Norwegian counterpart was less restrained. within weeks, Norway’s coalition government split due to disagreements on energy policy, with a single national retail price proposed by the Prime Minister.

While the BZR considered a potential reconfiguration of bidding zones in Sweden, unlike Norway, moving to a single price for consumers would require European approval.

In contrast, Italy is moving away from a single national wholesale price for consumers, the Prezzo Unico Nazionale (PUN), to match the zonal prices for generation. However, for 2025 if not longer, transitional arrangements will provide “continuity with the calculation of the single national price.”

It seems that everyone wants something different to what they have, but the process of change is slow and difficult.

What will another market reform achieve?

Since the Central Electricity Generation Board was replaced in Great Britain by the electricity pool market in 1990, there have been the New Electricity Trading Arrangements of 2001, their extension to include Scotland in the 2003 British Electricity Trading Transmission Arrangements, and Electricity Market Reform in 2012.

In this time there have been nearly 500 Balancing and Settlement Code modifications and numerous Significant Code Reviews.

Since 2009 the European Union has announced the 20-20-20 Climate and Energy Package, Energy Union Strategy, Fit for 55, Clean Energy Package, European Green Deal, RePowerEU and the latest Electricity Market Design Reform and Action Plan for Affordable Energy.

Policy stability seems to be little more than a myth, and still the one thing everyone seems to agree is the need for reforms that give better signals to generators to adapt their behaviour, to influence decisions on investments that it locates where it delivers most value for the system overall, reducing the costs of managing the system so that we spend less on network expansion.

Better price signals will incentivise consumers to adapt behaviour, encouraging flexibility and intelligent demand. Zonal pricing would put the cost of congestion, which at present is shared across all bills, into wholesale market prices in the zones where it arises.

How does zonal pricing affect wholesale prices?

Congestion between zones means that wholesale prices will vary by location. Zones with high demand will face higher prices, and those with excess renewables lower prices. For all the arguments between models looking at Great Britain, they seem aligned on where and when this will occur - Northern Scotland will have lower wholesale prices, England and Wales higher, particularly the South Coast. Initial savings from redispatch are likely to reappear as an increase in the wholesale price.

Is it fair that market changes will impact investments made over the past decade? You could make the case that some generators should get paid less - after all we've been talking about zonal pricing for 5 years and more. It’s not exactly been a secret that installing more wind and solar will increase curtailment. But we can either accept that there will be winners and losers from the change, or we can mitigate the impact.

Given that investments have been made in response to government targets and incentives, the British government has signalled that existing windfarms with CfDs, and those bidding into the next auction would be “insulated from zonal price risk” if a zonal system is adopted. This could take the form of correcting their reference price to a zonal reference price and also addressing their volume risk. With government auctions seen as driving investments in renewable generation for the foreseeable future, stability is seen as an imperative for the success of future auctions.

The equivalent commercial arrangements, Power Purchase Agreements (PPAs), are unlikely to be protected. Would this put both developers and corporates off PPAs, and slow down the build of new renewable generation outside the government backed auctions?

Would consumption change?

Zonal wholesale prices for consumers is often referred to as a postcode lottery. To some extent, this argument is misguided - regional pricing already exists due to transmission and distribution network charges. And it exists in other sectors, although for rail and air fares, Uber surge pricing and now concert tickets, it is begrudgingly accepted, if not downright unpopular. A radical change for consumers may be even less politically acceptable than for generators.

Low regional prices have been cited as an incentive for large consumers such as data centres and hydrogen electrolyzers to invest in Scotland. This is unlikely to influence residential consumers and small businesses, who won’t move to another part of the country just for lower energy prices. Zonal pricing may also have a limited impact on decisions to buy an EV or install rooftop solar, which are not taken for purely financial reasons.

Consumers do respond to prices, whether time of use network tariffs, dynamic wholesale pricing and tariffs for EVs and heat pumps. But it is unclear how much additional demand flexibility can respond to zonal prices. Renewable curtailment tends to occur when wholesale prices are low anyway. And the price spikes affecting southern zones in Sweden and Norway did not prove popular.

How will this impact networks?

Nothing changes overnight to the physical system we have. We wake up with the same generation, the same wind turbines, same demand, the same congestion and constraints, and the same curtailment when the wind in northern Germany and Great Britain exceeds both local demand and the capacity to transmit to demand in the South.

Although “building out the grid while at the same time developing plans to split the market doesn’t make sense,” zonal pricing would change the evaluation and prioritisation of currently planned network build. And with rising costs already pushing Australia to reconsider “transmission network projects previously identified as critical,” current plans for network build used in the European and GB assessments of zonal pricing are unlikely to match what would actually get built.

Practicalities of Project Development

While zonal pricing has the potential to improve investment and operational signals by better reflecting network constraints, it is by no means the only factor. Securing suitable land, navigating planning regulations, and obtaining timely grid connections can overshadow the nuanced signals from market design.

Higher wholesale prices might not be sufficient to compensate for the intense competition from housing and data centres for land in the densely populated south of England, the planning regime, which has historically presented challenges for wind turbine deployment in England, and the lengthy grid connection queue.

Many countries are grappling with substantial grid connection backlogs, with requests often far exceeding immediate capacity. While connection queue reforms are being implemented to expedite shovel-ready projects, the immediate priority for developers often remains getting projects built and connected swiftly, regardless of future market signals.

With ongoing uncertainty, developers might still build solar where it is sunny and wind where it is windy, and either accept curtailment, or anticipate that future investments in demand, storage, and network upgrades will mitigate it.

Is zonal pricing a marginal question?

The debate around zonal pricing frequently intersects with the broader discussion on marginal pricing, where electricity auctions clear at the cost of the most expensive generator required to meet demand. This mechanism led to significant price spikes when rising gas prices, exacerbated by geopolitical events, impacted even countries with high renewable penetration.

Consequently, there are persistent calls from some quarters to decouple electricity prices from gas, with proposals ranging from nationalizing gas generators to alternative market designs. While such measures might reduce price volatility, a lower overall wholesale price could lead to higher CfD payments, presenting a different set of financial implications.

One concern was that renewable generators were making excess profits when electricity prices followed gas upwards during the crisis, without a corresponding increase in their input costs. But the rush to capitalize on those prices led to a boom in solar generation across Europe.

Now we are seeing the impact of solar generation in negative prices and higher intraday spreads. Are those signals feeding through efficiently into decisions for investment in storage and networks? Sometimes the physical response lags market signals.

Is central planning the answer?

When market outcomes fail to align with anticipated results, governments and regulators often lack patience to wait before announcing interventions and reforms. If governments will not accept the results of market processes, would it be better to drop the pretense entirely?

Generous feed in tariffs have come and gone but net metering still lingers, while regulated consumer prices introduced during the crisis largely remain. Administratively set prices for UVAM in Italy and NEBEF in France have hindered demand side flexibility, while planning restrictions have hampered onshore wind from Britain to Poland.

Even Germany’s decision to shut down nuclear power after the Fukushima disaster came just 6 months after the 2010 decision to extend their lifetimes. Although the ongoing debate around zonal pricing contributes significantly to investor uncertainty about future regulatory frameworks, past decades have not been an environment of policy stability.

Although state planning may have had us building CCS coal plants, new nuclear and hydrogen filling stations, the current preferred approach is being described as “a more strategically planned system.”

That said, it sounds worryingly like Gosplan when Ofgem says “These changes will provide clarity to everyone – investors, network companies, customers – on the assets that need to be built and where they should be located.” A recent update outlines the Strategic Spatial Energy Plan as an Iterative process updated every 3 years that will “identify suitable locations and facilitate access to them in line with strategic energy plans”.

Perhaps strategic central planning would be the best way to align investments in networks and generation. But even when long term frameworks are introduced, such as the Renewable Energy Zones in Australia, incorrect assumptions can upset the best laid plans.

And although “no plan of operations reaches with any certainty beyond the first encounter with the enemy's main force,” in the electricity sector there are multiple forces including investors, developers, and consumers that will have unexpected impacts. Or even a bat colony.

The models don't matter (as much)

And so we return to the models, which can help us think about the future, but the assumptions required cannot give the certainty needed to predict it. Not the “world’s largest machine” as so often described, electricity networks are complex systems. Changing the market structure will change the assumptions modelled that justified the decision to make the change.

Afry highlights the “difficulty involved in a credible assessment of the interactions between locational pricing, CfD strike prices, grid charges and consumer welfare while also holding generation and network build fixed.”

After the introduction of locational pricing, generation and network investments will differ from the assumptions used in the model. As may the assumptions on whether existing investments in generation will be insulated, the political acceptability of a postcode lottery of prices for consumers, and how investor and consumer behaviour will be impacted. We may be heading towards the “fourth, fifth and higher degrees” of the Keynesian beauty contest.

Apart from the immediate impact on wholesale prices, perhaps the one area where the models align is that the cost of capital is the most sensitive factor influencing investment decisions.

Prolonged discussions around market reform increase investor uncertainty. But zonal pricing requires ongoing review, constantly striving for the optimal balance between granularity and liquidity, between wider physical interconnections and local pricing, between the network as is, and as it will be.

The models are just one element supporting the decisions to be taken over the next few months, and whether the number is positive or negative, the benefits of the changes quantified by each model is marginal. Other factors will determine the outcomes.

This is the end

We are looking for a market that gives signals for investment and operation, for generation and consumption, and to reflect the changing physical realities of the electricity system.

Regardless of the decisions taken this year, within the decade I suspect we will again be facing similar questions on electricity market design.

By then we will have to look deeper into the system, at distribution level congestion, at the overlap between wholesale and retail markets, and the changing needs and provision of flexibility.

Most of the current discussions on zonal pricing focus on the transmission system. Is this a step in the right direction, or a distraction that defers the decision on more fundamental market reform?

The expected decisions on zonal pricing in Great Britain and Germany are not the end of the discussion on market design.

They are not even the beginning of the end. But they are, perhaps, the end of the beginning.