Electricity price zones: what a split of Germany would mean for solar parks and batteries

Anyone who followed the news in 2025 knows the headline: Europe's transmission system operators consider splitting Germany into five electricity price zones economically sensible, the north would get cheaper and the south more expensive. For an investor who owns or is evaluating a solar park in Schleswig-Holstein or a battery in Bavaria, this is not an abstract debate. The exchange price is one half of the revenue, the market premium the other. Both depend on the zone the plant sits in.

This article lays out the procedure with its legal references, shows the price gaps from the three relevant studies and works through what a zonal price would mean for two sites, depending on how the electricity is sold. It closes with the regional price signals that are coming anyway and with what should be in the contracts.

What is an electricity price zone, and why is Germany's disputed?

A price zone, in the law a bidding zone, is the largest area in which market participants can trade electricity without capacity having to be allocated (Article 2(65) of Regulation (EU) 2019/943, adopted into section 3 no. 93 of the German Energy Industry Act). Within the zone the exchange sets one price per quarter-hour, whether the electricity is generated in Kiel or in Munich. The grid is treated as if it could carry every kilowatt-hour anywhere. Germany and Luxembourg form one such zone; Austria was separated on 1 October 2018.

The dispute arises because the assumption does not hold. On strong-wind days, wind power from the north does not fully reach the consumption centres in the south and west. The market still clears at one national price, and the transmission operators have to intervene afterwards: curtail plants in front of the bottleneck, ramp up power stations behind it. This redispatch and its compensation are explained in Curtailment of a solar park: when the grid operator pays and when it does not. Several zones would bring the bottleneck into the price: where electricity is scarce it would be dearer, where it is abundant cheaper. Supporters expect less redispatch and better siting decisions for storage, electrolysers and new plants. Opponents point to higher prices in the south, thinner forward markets and the cost of the changeover.

Will Germany be split? What has been decided since April 2025

No, not as things stand. The decision has been taken, and it lies with the federal government, not in Brussels. The procedure behind it is set out in the EU electricity market regulation and ran in three steps.

The report by Europe's transmission operators of 28 April 2025 modelled 14 layouts, four of them for Germany with two, three, four and five zones. The five-zone layout with a separate Schleswig-Holstein zone performs best: 339 million euros more economic efficiency in the 2025 target year, the two-zone variant 264 million. Against that stand transition costs of 1.2 to 2.4 billion euros, depending on the number of zones. The report itself calls that a minimum lifetime of four to nine years before the split would have paid for itself. ACER, the agency of the European regulators, considers the benefit clearly underestimated on 18 September 2025, at 450 to 540 million euros a year, because the operators assumed too much coordination in their own congestion management. The opinion is addressed to the Council of the EU, not to the German government.

On 15 December 2025 the federal government took the decision under Article 14(7) of the regulation and kept the single zone. Its reasoning: the report identifies no structural congestion for Germany, looks only at the year 2025, the simulated gains are many times smaller than the adjustment costs, and the first domestic HVDC lines are coming anyway (Ultranet in 2026, A-Nord and SuedOstLink in 2027, SuedLink in 2028). Instead of a split it submits an action plan under Article 15: grid expansion, better congestion management and closer alignment of generation, consumption and storage with the grid. On 31 August 2026 it confirmed in the Bundestag that the reasons still apply and that it has no newer findings on regional prices.

By which routes could a split still happen?

Two. First, the federal government can change its position, for instance if a transmission operator reports that it can no longer settle trades within the zone without capacity allocation (section 11(2a) sentence 1 of the Energy Industry Act obliges it to notify the Federal Network Agency without delay). Second, the European Commission can step in, but only as a last resort: Germany would have to miss the requirement to make at least 70 percent of transmission capacity at its borders available for trading (Article 16(8)), the member states concerned would then have to fail to agree within six months, and the Commission would have to decide on a split rather than on keeping the zone within a further six months (Article 14(8) and (9), Article 15(5)). The 70 percent have applied to Germany since 31 December 2025 without transition. According to the action plan, the four transmission operators met the linear ramp-up path in every year until then.

Were a decision taken, there would be time. The separation of Austria went back to an ACER decision of November 2016 and took effect on 1 October 2018, around two years later. A Commission decision has to set the date and transitional measures (Article 14(10)), the Federal Network Agency would have to implement it through determinations (section 20(3) sentence 2 no. 6 of the Energy Industry Act), and from a market perspective everything speaks for a turn of the year, so that forward contracts do not lose their delivery area mid-year. The next regular review of Europe's zones follows a three-year cycle. A split zone before the end of the decade is therefore hardly realistic, and nobody has decided on one.

How large would the price gap between north and south be?

Small on an annual average, large in individual hours. Three studies have simulated this for Germany, with different target years and layouts; all three are model results, not forecasts.

• ENTSO-E (target year 2025, two to five zones): in the northern zones and in Denmark the average price falls by around 4 euros per megawatt-hour, in the south as well as in the Czech Republic, Austria and Luxembourg it rises by up to 3 euros. Price volatility in the northern zone increases markedly, because wind sets the price there.
• Ariadne analysis by the Hertie School and Fraunhofer IEE (target year 2030, two to four zones): up to 11 euros per megawatt-hour between zones, the south-west 13 percent dearer and the north 11 percent cheaper than the single zone. For photovoltaics the market value in the four-zone layout is up to 25 euros per megawatt-hour lower in the north-east than in the south-west.
• Ariadne case study by Fraunhofer IEE and ISI (data year 2024, three, nine and 22 zones): with small zones, prices in the north are 20 to 30 percent below the single-zone price, in the south mostly less than 10 percent above it. The volume of renewable electricity that the market itself curtails rises from 0.4 to as much as 4.9 terawatt-hours.

Two things stand out. The price falls more in the north than it rises in the south, because the south keeps importing from the north and the scarce border capacity only binds in a few hours. And the difference is smaller for solar than for wind: photovoltaics generates where electricity is consumed, and at times when both zones are similarly full. For onshore wind the Ariadne analysis gives the south a 19 euro per megawatt-hour lead; for photovoltaics it only gets really expensive in a four-zone layout with a separate north-eastern zone.

What changes for a solar park with a market premium?

That hinges on a single calculation rule that nobody has laid down yet. A solar park's market premium is the applicable value minus the solar market value, the generation-weighted exchange revenue of all German solar plants (Annex 1 no. 3.1.2 of the Renewable Energy Sources Act, for plants from 2023 as an annual market value under no. 4). How that market value comes about is explained in Solar market value: why solar power is worth less and less on the exchange. With two zones there would be two options: one market value per zone, or still one nationwide value across all zones. The 2024 Ariadne analysis describes both; the law does not yet know the question.

With a zonal market value the premium offsets the lower northern price: if exchange revenue in the north falls by 11 euros, the premium rises by 11 euros and revenue per kilowatt-hour stays at the applicable value. With a nationwide market value the premium stays the same and the northern park carries the discount alone. The Ariadne authors recommend the zonal value for existing plants, so that the changed market design does not retroactively interfere with running business cases, and the nationwide value for new plants, so that the siting signal is preserved. What the legislator would do is open.

We ran the numbers for two sites: Kiel as the northern zone, Munich as the southern zone, each 1 megawatt-peak facing south with the PVGIS weather year 2023 and the 2025 hourly prices, applicable value 4.79 cents, no feed-in in hours with a negative price (section 51(1) of the Renewable Energy Sources Act). The price gaps from the studies sit as a fixed discount or mark-up on every hour. Base revenue 2025 per megawatt-peak: 48,900 euros in Kiel, 62,100 euros in Munich; the difference in yield and capture price by site is explained in Is a solar park in northern Germany worth it? Location, yield and the price per kilowatt-hour.

The left column is the case in which the premium does its job. That a small minus remains in the north is down to the negative hours: with a price 11 euros lower, a further 330 generating hours slip below zero in our calculation, hours in which the park receives nothing under section 51. In a real northern zone with more wind this effect would tend to be larger than in our flat shift. The middle column shows what a nationwide reference value would cost: 2,800 to 7,100 euros per megawatt-peak and year in the two more realistic scenarios, almost as much as a park without any premium would lose.

In the south the mirror image applies, with one peculiarity: the market premium is a one-way street. It cannot turn negative (Annex 1 no. 3.1.2 sentence 2). In 2025 the annual solar market value was 4.508 cents, so with an applicable value of 4.79 cents the premium was just under 0.3 cents. If the southern price rises by 3 euros per megawatt-hour, the premium drops to zero and only 0.7 percent of the price advantage remains. Only once the zonal market value clearly exceeds the applicable value does the advantage reach the park in full; at +11 euros it is 14 percent. For an older park with an applicable value of 5.9 cents it looks different: in the north a two-zone split with a zonal value costs 3.6 percent, in the south it brings 2.7 percent, because the higher premium absorbs almost everything. The higher the applicable value, the less the park cares about the zone, as long as the reference value is calculated per zone.

What changes for PPA and post-EEG revenue?

Here there is no buffer. Anyone selling electricity through a power purchase agreement, or directly on the market after the EEG tariff has expired, receives the price of their zone: in Kiel 5 to 14 percent less, in Munich 5 to 18 percent more (right-hand column of the tables). Three further points do not appear in any table.

• Delivery area in the contract: today a PPA names the Germany-Luxembourg bidding zone as the delivery point and price reference. If after a split the park sits in a different zone from the offtaker, the contract needs a rule on who bears the price difference and the cost of border capacity. If it is missing, interpretation decides. The clauses that come into question are set out in Understanding PPAs: how power purchase agreements make solar park revenues predictable.
• Forward market: hedges run through forward contracts for the German zone. After a split, the contracts of the smaller zones would be more thinly traded and hedging more expensive. This is the central argument of the opponents, and of the action plan.
• Remaining term: a park whose EEG tariff ends in 2040 would still have ten years of premium as a buffer in a split scenario at the end of the decade. A park from 2012 would stand without a premium from 2032 in whichever zone it is in.

Does a battery gain or lose?

In the north it gains, in the south it loses slightly, at least in arbitrage. A battery earns on the gap between cheap and expensive hours of the same day; the mechanics and current spreads are in Direct marketing explained: day-ahead, intraday and balancing power. In a northern zone, where wind pushes the price towards zero more often and volatility increases, there are more such gaps. The 2024 Ariadne case study quantifies this through full cycles: a battery in Lower Saxony runs 1.39 cycles a day in the single zone, 1.96 in a nine- or 22-zone world. In Baden-Württemberg the figure falls to 1.29 to 1.36, because the north's wind surpluses no longer show up in the price there.

As a rough estimate: the average daily spread in 2025 was 125 euros per megawatt-hour by our calculation from the SMARD hourly prices. If it stayed the same per cycle, the arbitrage revenue of a northern battery would be at index 141 against 100 in the single zone, that of a southern battery at 93. This is a coarse frame, not a result: none of the studies says whether the spread per cycle would stay the same in the zone. Balancing power and the capacity market are procured nationwide today; how they would be cut in a split, none of the studies says. Anyone planning a battery, unlike a solar park, can choose the site, and this steering effect is precisely the declared aim of the supporters.

Which regional price signals are coming even without a split?

Several, and they hit generators and storage earlier than any zone split. In its answer of 31 August 2026 the federal government says explicitly that regional signals are to come through the Federal Network Agency's grid fee reform, not through the exchange price. The action plan lists:

• Feed-in fees and dynamic grid fees: generators above 30 kilowatts are to pay a fee per kilowatt of feed-in capacity from 2029, later with time- and region-dependent components. The level and grandfathering are explained in Grid fees for generators from 2029: what Germany's planned feed-in charge costs a solar park and who is grandfathered.
• Storage fees: the Federal Network Agency is reviewing whether the exemption of storage from grid fees stays or is replaced by rules that reward grid-friendly behaviour and price grid-stressing behaviour.
• Flexible connection agreements under section 17(2b) of the Energy Industry Act, which let the grid operator intervene in a large battery's schedule, and the 70 percent rule for new solar parks from the grid package; both are covered in Overbuilding the grid connection: what more module capacity than connection capacity means for yield and investors.
• Capacity-limited grid areas and the planned redispatch reservation: anyone connecting in a congested area is to forgo compensation for grid-related curtailment for up to ten years. The details are in Curtailment of a solar park: when the grid operator pays and when it does not.
• The reference yield model for onshore wind is being reviewed for uneconomic low-wind sites; for photovoltaics there is no regional scale.

For project due diligence this means: the question "which zone is the park in?" is the less likely version of the question "what does the grid connection at this location cost over twenty years?". The second question already has answers today.

Should I buy in the south instead?

Not because of the zone. A solar park is bought on the price per kilowatt-hour of annual yield, and that price already reflects irradiation, lease and grid connection at the site. A zone split that nobody has decided, that would come years after a decision at the earliest, and whose effect on a park with a market premium depends on a calculation rule not yet written, justifies no premium for Bavaria and no discount for Schleswig-Holstein. It justifies three things in the contract and in the calculation:

• In the direct marketing contract, word the revenue formula so that it references the exchange price at the delivery point and the official market value, not a fixed index for "Germany". That way the contract follows a reorganisation automatically.
• In a PPA, agree the delivery point, the price reference and an adjustment clause for a change of bidding zone, including the allocation of capacity costs between zones.
• In your own return calculation, carry the revenue without premium as a sensitivity: what remains if the park sits in a northern zone without premium in 2040, and what if it sits in a southern one? Working through the tables above shows that the range is smaller for solar than for wind, but not zero.

Which questions should you put to the provider?

• Which market value and which exchange price does the revenue formula in the direct marketing contract refer to, and what happens if the bidding zone changes?
• Does the revenue report assume a nationwide price path after the EEG tariff ends, or a regional discount for the site?
• Is the park or battery in a grid area that the operator could designate as capacity-limited, and how much redispatch was there over the last two years?
• What is the agreed feed-in capacity at the grid connection, and is it limited statically or dynamically?
• For the battery: which assumption on cycles and spread sits in the revenue forecast, and how does the result change with 20 percent less spread?

A provider who answers these questions with references rather than "that does not affect us" has the topic on the radar. What else makes a reputable provider is set out in How to tell a trustworthy provider of energy direct investments.

How we account for the bidding zone in our project check

We recalculate every prospectus with our own model, and there the zone runs as a sensitivity, not as a base assumption: how much revenue is missing after the premium ends if the site were in a cheaper zone? We read the direct marketing contract for its revenue formula and the revenue report for its price path after the EEG period. For a battery we check whether the cycle assumption fits the site. Whatever changes in the procedure, we update in this article; the government's answer to the October 2026 parliamentary question is still outstanding.

We make no promises on returns. We show which figure rests on which assumption. What makes a solar park as a direct investment overall is set out in Investing in solar parks: revenues, costs and tax leverage at a glance. That is exactly what we check with you in a no-obligation initial consultation, ideally on the basis of a specific prospectus.