Is a solar park in northern Germany worth it? Location, yield and the price per kilowatt-hour

Anyone who lays two offer documents side by side, one from Schleswig-Holstein and one from Lower Bavaria, quickly meets the reflex: the sun shines longer in the south, so the southern project must be the better one. The first half of that sentence is true. The second does not follow, because a solar park is not bought by hours of sunshine but at a price per kilowatt of installed capacity, and that price may or may not reflect the location.

So we calculated instead of guessing: the same solar park at six locations from Kiel to Freiburg, with public irradiation data, with the exchange prices of two very different years and with the award statistics of the Bundesnetzagentur. Out comes a clear yield gap, a market effect many do not expect, and a rule of thumb that reduces the comparison between regions to a single number.

How large is the yield gap between northern and southern Germany really?

Around 13 percent between the coast and the Alpine foothills, for an identical system. Using the European Commission's PVGIS tool we calculated the same standard system for six locations: free-standing, facing south, tilted at 20 degrees as many ground-mounted systems are, 14 percent system losses, long-term mean of the satellite data 2005 to 2023. The only difference between the rows of the table is the place; the abbreviations give the federal state.

Two things stand out. First, the north-east is closer to the south than the map suggests: Berlin and Brandenburg are only 7 percent behind Munich, because the air there is drier and the sky clearer more often than on the coast. Second, the gap between Kiel and Hanover is smaller than the one between Hanover and Berlin; the coast is not the end of the scale, merely its dampest point. At the optimal tilt of 38 to 40 degrees every location would come out around 4 percent higher without changing the relations; why ground-mounted systems are nevertheless built flatter is explained in South, east-west or vertical: which solar park layout pays off for investors.

The measured values of the German Meteorological Service (DWD) serve as a cross-check. In the radiation year 2025 the national mean was 1,187 kilowatt-hours per square metre, 9.4 percent above the 1991 to 2020 reference period and the fourth-highest value since 1991. The DWD reported the lowest sums for the north, especially Schleswig-Holstein, and the highest, above 1,300 kilowatt-hours per square metre, for the Lake Constance region, the Breisgau and Lower Bavaria. The gradient of the satellite climatology thus shows up in the measurements.

The same DWD figures also put the gap into proportion: between an average and a very sunny year lie around 9 percent nationwide, between the coast and the Alpine foothills 13. Location therefore weighs about as much as the question of whether you get a good or an average weather year. For an individual project the decisive document is not the map but the yield report with its uncertainty bands; how P50 and P90 are read is explained in Reading a yield assessment: what P50 and P90 mean for a solar park direct investment.

One difference from the same calculation becomes important later: the distribution over the year. In Kiel, Schwerin and Hanover only 24 to 27 percent of annual output falls in the winter half-year from October to March, in Munich and Freiburg 32 to 33 percent. The south has not only more sun but sun spread more evenly. What PVGIS does not model applies to all locations alike: row shading, snow cover (more frequent in the south) and fog in river valleys and the Alpine foothills belong in the yield report, not in a climate map.

Why does the price per kilowatt-hour matter for a solar park, and not the price per kilowatt?

Because you sell kilowatt-hours, not kilowatts. The applicable value (anzulegender Wert) from the tender is a nationwide figure; in the round of 1 July 2026 the weighted award value was 4.79 cents per kilowatt-hour, for Kiel as for Munich. A kilowatt in Kiel produces 13 percent fewer kilowatt-hours than one in Munich and sells each of them at the same rate. Anyone comparing offers by price per kilowatt therefore compares systems that deliver different amounts against the same yardstick. How the market premium secures the rate is explained in Direct marketing and the market premium: how a solar park earns its money.

The clean yardstick is the purchase price divided by the expected annual yield, in euros per kilowatt-hour and year. From the table above it follows directly how far the price per kilowatt may differ between two locations for both to be equally expensive per kilowatt-hour:

This index is deliberately a relation and not a price. What a kilowatt costs depends on year of construction, size, grid connection and the contract package; what it is worth depends on the yield at the location. The gap between the two is the point you negotiate. A provider who asks the same price per kilowatt in the north as in the south is asking 15 percent more per kilowatt-hour. A provider who prices in the gap offers the same arithmetic in the north as in the south, only with a smaller number on the purchase contract and a smaller yield in the report.

One quantity is independent of location: the tax effect. The investment deduction (Investitionsabzugsbetrag) and special depreciation attach to the acquisition cost, not to the kilowatt-hours. Per euro invested the tax effect in Kiel is therefore the same as in Munich. That makes it all the more important that the euro also buys yield at the location; a favourable tax effect does not offset an excessive price per kilowatt-hour, it only stretches the time until it shows. How the two levers interact is explained in Deducting photovoltaics from tax: when depreciation and the §7g deduction still work.

Does solar power in the north get a different price on the market?

Yes, a slightly lower one, and for a reason that is not obvious at first: the distribution over the year. Germany and Luxembourg form one bidding zone, so the exchange price of a given hour is the same in Kiel and Munich. What differs is only how much the system delivers in that hour. We multiplied the PVGIS hourly profile of the weather year 2023 for each location by the day-ahead prices from SMARD, once for 2023 (300 negative-price hours) and once for 2025 (573 negative-price hours), and from that calculated revenue per kilowatt in the market premium model: exchange price plus premium in hours with a price at or above zero, nothing in negative hours, as section 51 EEG provides for new systems.

In 2023 the market was still even-handed: all six locations earned between 72 and 75 euros per megawatt-hour on the spot market (Kiel 73.5, Munich 72.9), and revenue per kilowatt followed yield almost exactly. Not so in 2025. Negative hours cluster on sunny summer and weekend middays, and that is exactly where northern output is more concentrated: in Kiel 26.6 percent of kilowatt-hours fell in hours with a negative price, in Munich 22.1 percent. The south produces a larger share of its electricity in the winter half-year, when prices are high and the premium is effective. The capture price in Kiel was therefore 11 percent below Munich, and revenue per kilowatt 23 percent below instead of the 13 percent that yield alone would suggest.

That is the honest number that belongs in a price comparison: the yield gap is not evened out by the market but stretched to 17 to 23 percent in years with many negative hours. It does not mean a solar park in the north does not pay. It means the price per kilowatt there has to be correspondingly lower, and that the revenue assumption in the offer should know the location's market profile, not only its hours of sunshine. Curtailing in negative hours or adding storage changes the arithmetic at both locations; the mechanics are explained in Negative electricity prices: what they mean for solar and storage investors and Solar market value: why solar power is worth less and less on the exchange.

Two caveats belong here. The weather profile comes from one year and was laid over two price years; a different weather year shifts the numbers but not the direction, because the summer concentration of the north is a property of the climate. And 2025, with 573 negative hours, was an outlier on the high side; whether that continues depends on storage build-out, curtailment and the rules of the EEG 2027, not on location.

Which location factors are not a compass direction?

Land rent, weather risk, grid and eligible land, and none of these four runs along the north-south axis. Anyone who assumes the north is cheap because the land is wider is wrong for the coastal states; anyone who assumes the south is safe because the sun shines overlooks the hail.

Land: according to the Federal Statistical Office's 2023 farm structure survey, agricultural rent per hectare averaged 357 euros nationwide, 560 euros in North Rhine-Westphalia, 548 in Lower Saxony, 479 in Schleswig-Holstein and 415 in Bavaria. The two large coastal states are thus more expensive than Bavaria, not cheaper. Purchase values show the real dividing line between west and east: Bavaria reports an average of 77,721 euros per hectare for 2024, Mecklenburg-Vorpommern 22,756 euros. Solar rent is a market of its own with much higher rates, but the agricultural alternative sets the floor, and that floor is different in Lower Saxony than in Brandenburg. A simple calculation shows how rent works per kilowatt-hour: at 1.2 hectares per megawatt and 3,000 euros per hectare the land costs 0.38 cents per kilowatt-hour in Kiel and 0.33 cents in Munich; the models and pitfalls are in The land lease of a solar park from the investor's side: why it is a Mietvertrag, what the rent costs per kilowatt and how you step into the contract.

Weather risk: the insurers' statistics on storm and hail damage to residential buildings are not a PV data set, but a usable indicator of a region's weather load. In the ten-year mean 2013 to 2022 Schleswig-Holstein and Hamburg reported 6.1 claims per 100 policies per year, Lower Saxony and Bremen 5.9, Bavaria 2.9 and Baden-Württemberg 2.7. The north thus has storm damage twice as often. The reverse holds for the loss per claim: Baden-Württemberg 2,310 euros, Bavaria 2,148 euros, Schleswig-Holstein and Hamburg 1,097 euros, with hail years such as 2013 in Baden-Württemberg (5,899 euros) and 2019 in Bavaria (4,345 euros). Frequent and small in the north, rare and large in the south; for a solar park that means wind bracing of the mounting structure here, hail class of the modules and serial-loss clauses there. The insurance side is covered in Insuring a solar park or battery storage asset: which policies belong to a direct investment, and who holds them.

Grid: the north is wind country, and where wind power fills the grid, solar systems are curtailed too or wait longer for connection capacity. That is not an argument against a location, but a question to check: how often has the grid operator intervened in the area in recent years, and is the grid connection firmly committed? How compensation for curtailment works is explained in Curtailment of a solar park: when the grid operator pays and when it does not, what the documents should contain on the grid connection in Grid connection, easement, building rights: how to tell whether a direct investment has truly secured its site.

Eligible land: which land can carry an EEG payment is regulated nationwide, but the disadvantaged areas that have formed the largest category since 2024 are concentrated in Bavaria, and the states may block that category by ordinance. Whether a northern project sits in the strip along a motorway or railway or on a conversion site is therefore a separate check; the categories and their reference dates are explained in Eligible land: where can a solar park be built in Germany?.

Where are solar parks actually built?

Above all in Bavaria, but with a falling share. The Bundesnetzagentur publishes the bid and award volumes of the ground-mounted tenders by federal state. For the eleven bid dates since the EEG 2023 (1 March 2023 to 1 July 2026) we added up the awards:

The five northern states together account for 5,216 megawatts or 22 percent of awards, the east for 20 and the south for 42 percent. More interesting than the stock is the movement: Bavaria's share fell from 41.8 percent in 2023 via 37.2 and 30.3 percent to 25.3 percent in the two rounds of 2026, while the north's share rose over the same period from 18.5 to 26.5 percent. In this year's bid dates the north has for the first time been awarded more capacity than Bavaria.

The award rate also shows that northern bids do not systematically lose out in the competition: Lower Saxony at 57 percent is above Bavaria at 53, Schleswig-Holstein and Mecklenburg-Vorpommern at 46 and 47 percent just below. Whoever submits a bid in Kiel with 13 percent less yield has evidently calculated the price accordingly, otherwise it would not win an award. The market has long been calculating per kilowatt-hour; the investor should do the same.

How do you compare two offers from different regions?

In six steps, only the first of which has anything to do with the federal state:

1. Check the yield figure for plausibility: compare the offer's P50 value in kilowatt-hours per kilowatt with a free PVGIS calculation for the coordinates and the design. If the offer is more than 5 percent above it, ask for the reason (tracking, bifacial modules, on-site measurement) and for the name of the assessor.
2. Form the price per kilowatt-hour: purchase price divided by the P50 annual yield. This figure, not the price per kilowatt, is comparable between regions.
3. Check the revenue assumption: which applicable value, which market value and which share of negative hours does the offer use? A northern project with the same revenue per kilowatt-hour as a southern one has ignored the summer concentration.
4. Calculate rent per kilowatt-hour: annual rent divided by the P50 yield. That turns euros per hectare into a figure that makes locations comparable.
5. Ask for the insurance premium and deductible for storm and hail at the location, not as a flat rate.
6. Check the grid connection and the curtailment history of the grid area, in wind regions first.

Add three questions every provider should be able to answer: where does the yield figure come from and with what uncertainty? Why is the price per kilowatt where it is, measured against the location's yield? And which locations has the provider developed or brokered in recent years, with what measured yields? Anyone who answers the second question with the sun rather than the price has not read this article. Further checkpoints for ground-mounted systems are collected in Investing in solar parks: revenues, costs and tax leverage at a glance, warning signs about providers in How to tell a trustworthy provider of energy direct investments.

How we check the location in our project review

We first recalculate every project with a free irradiation database for its coordinates and lay the result next to the provider's yield report. Then we form the price per kilowatt-hour and the revenue assumption per location with our own market data, check rent, insurance and grid separately and compare the project with others we have seen, regardless of federal state. We would rather recommend a northern project with the right price than a southern one with the wrong price. We make no return promises. If you would like a specific offer reviewed, you can bring it to a no-obligation initial consultation.