Germany's industrial electricity price and PPAs: what the counter-investment duty means for solar parks

Almost everything written about the Industriestrompreis, Germany's industrial electricity price, takes the view of the companies applying for it. Someone who holds a stake in a solar park or is considering one has a different question: does the park lose potential buyers because the state lowers their electricity bill? Or does the rule bring new buyers, because the companies have to reinvest half of the subsidy and a power purchase agreement counts towards that?

The answer is in three documents: the directive of the Federal Ministry for Economic Affairs of 27 April 2026, the European Commission's approval of 16 April 2026 and the leaflet on counter-investments published by the Federal Office for Economic Affairs and Export Control (BAFA) on 4 August 2026. What a power purchase agreement is in general is explained in Understanding PPAs: how power purchase agreements make solar park revenues predictable; this article deals only with the new rule and its consequences for the park.

What is the industrial electricity price and who receives it?

The industrial electricity price is a federal grant for the years 2026 to 2028, not a discounted tariff. The company buys its electricity as before and applies to BAFA for a payment in the following year. Eligible are companies with consumption sites in sectors that the EU regards as exposed to a significant risk of relocation. The ministry names 91 sectors and sub-sectors with potentially up to about 9,500 companies, among them parts of chemicals, glass, paper and cement production, metal production and semiconductor manufacturing.

The amount follows a fixed formula. The starting point is the reference price: the average of all daily settlement prices at which baseload power for the billing year was traded on the power exchange during the previous year. For 2026 that is 87.44 euros per megawatt hour. The relief is half of that price, but never to below 50 euros per megawatt hour. For 2026 this gives a price difference of 37.44 euros. It applies to half of consumption; spread over total eligible consumption it comes to 18.72 euros per megawatt hour.

Below a reference price of 100 euros the floor of 50 euros limits the relief; above it the one-half rule does. If the forward price for 2027 or 2028 falls, grant and duty therefore shrink faster than the price itself. There is no legal entitlement: the payment is subject to available budget funds. If the money is not sufficient, BAFA reduces all grants by the same ratio. The European Commission approved a budget of 3.8 billion euros for the entire duration, financed from the Climate and Transformation Fund. A company that applies for indirect carbon cost compensation (Strompreiskompensation) for the same volumes receives no industrial electricity price for them.

Does the industrial electricity price make power purchase agreements redundant?

No. The grant does not replace a supply contract because it is not tied to actual purchasing. The directive counts self-consumed electricity regardless of the generation source and the type of procurement. A company that draws its power from a solar park under a long-term contract receives the same amount as one that buys on the spot market. The grant therefore does not make a favourable purchase any less valuable.

Three limits come on top. The grant covers only half of consumption; the other half carries the full price risk. It runs for three years, is paid only in the following year and can be reduced; a power purchase agreement binds for five, ten or more years. And it reaches only the listed sectors. A logistics company, a data centre or a food retailer continues to look for predictable electricity prices without a grant; the obligations that drive data centres are set out in Data centres and AI: what the new electricity demand means for solar and storage investors.

One honest objection remains: a company that receives 18.72 euros per megawatt hour from the state for three years is under less pressure to hedge in the short term. The PPA market analysis of the German Energy Agency of April 2026 describes the effect on the market as not yet foreseeable. It was written before the final directive, however. What matters for the park is therefore not the grant itself but the duty attached to it.

When does a PPA count as a counter-investment?

A power purchase agreement counts if it is new, finances a new or modernised plant in Germany that is named in the contract, and that plant receives no state aid. The directive obliges every recipient to invest at least half of the grant in new or modernised assets that lower the costs of the electricity system. Four groups of measures are admitted: renewable generation, energy efficiency, flexibility of demand and infrastructure. In the first group, alongside own plants, the directive expressly lists the costs of electricity purchased under newly concluded power purchase agreements.

Two points matter more to the park than they seem to at first. First, what counts is not the contract value but only what has actually been delivered and invoiced by the deadline. A ten-year contract gives the buyer no more credit than a four-year one. Second, the buyer is liable for the result: if it does not prove the investment at the latest three months after the deadline, BAFA reclaims the grant pro rata, with interest at five percentage points above the base rate. If the park delivers less than planned, that becomes the buyer's problem; the buyer will try to hand it back to the park by contract.

A company that applies for the flexibility bonus of ten per cent must put 80 per cent of the duty into flexibility, for instance storage or load management. Going by the example in the leaflet, roughly 30 per cent of the total investment sum then remains for all other measures. Companies taking the bonus are thus the smaller customers for a solar park.

Which solar parks qualify?

Only new or modernised parks whose electricity receives no EEG payments qualify. The leaflet is clear on this: a plant does not count if the electricity it feeds in is remunerated under the Renewable Energy Sources Act. Nor may it receive that support afterwards. Whether a plant is new depends on the commissioning date in the Marktstammdatenregister, the federal plant register; why that date decides a great deal of money elsewhere too is shown in The commissioning date of a solar park: which date fixes the tariff, the deadlines and the depreciation. Additional modules at an existing park are treated as a separate, new plant under the logic of the register.

For a park with an auction award this has a price. Today it can switch monthly between the market premium and other direct marketing (Sec. 21b (1) EEG) and sell its electricity under a contract for a time without losing its fallback. That fallback is the floor under its revenue: the volume-weighted award price in the ground-mounted auction of 1 July 2026 was 4.79 cents per kilowatt hour, just under 48 euros per megawatt hour; how the market premium is derived from it is explained in Direct marketing and the market premium: how a solar park earns its money. According to the German Energy Agency's market analysis, ten-year solar offtake contracts stood at an indicative 35 to 45 euros per megawatt hour in 2025. A park that wants to be creditable for the buyer has to give up the floor. That pays only if the contract price compensates for it.

In practice this leaves the group that already makes up the market for solar offtake contracts: new parks without an award, whether because of their size, their site or an oversubscribed auction. In 2025 that was 0.61 gigawatts according to the same analysis. For these parks nothing changes in the revenue logic; a group of buyers with an additional reason to sign is added. Parks awarded from 2027 face a changed calculation in any case under the draft EEG 2027 (EEG 2027: what the refinancing contribution means for a solar park direct investment).

How much PPA demand can result?

A lot on paper, probably only a fraction of it in reality. First the single company: with 100 gigawatt hours of eligible annual consumption and the 2026 reference price, the grant is 1.872 million euros a year. The duty is 936,000 euros. If the reference price stays the same in the two following years, that is 2.808 million euros over the term. The table shows which delivery volume covers this duty and how large a park has to be for it.

At 45 euros per megawatt hour a park of just under 14 megawatts peak is enough to cover this company's duty for all three years in time. The company would draw around 14 per cent of its annual consumption from the park. The direction is worth noting: the higher the contract price, the fewer megawatt hours the buyer needs. A buyer with a counter-investment duty is therefore less price-sensitive than one without; every euro it pays the park saves it a euro elsewhere.

Now the market as a whole. A budget of 3.8 billion euros implies at least 1.9 billion euros of mandatory investment. If all of it went into solar offtake contracts at 45 euros, that would be 42 terawatt hours. It will not happen that way, because efficiency, storage and own plants count as well. The table therefore shows shares.

Even one tenth of the duties would correspond to about 0.9 gigawatts peak of new solar capacity, roughly one and a half times what was signed in solar offtake contracts in the whole of 2025. This is a one-off requirement, spread over the signing years 2026 to 2029, not an annual one. The figure shows the order of magnitude: the lever is large enough to be felt in a market segment that has recently been weak, if the companies use it. Whether they do is not something the calculation answers.

Why are delivery years from 2029 cheaper for the buyer?

Because a megawatt hour from the park may not count twice. The buyer can either have it credited as consumption and receive the grant for it or claim its cost as a counter-investment. The leaflet rules out both together; a proportional split is allowed. A buyer that counts a megawatt hour as a counter-investment in 2027 forgoes 18.72 euros of grant at an unchanged reference price. At a contract price of 45 euros, every euro credited thus costs 42 cents.

From 2029 there is no billing year left in which consumption could count. The deadlines for the counter-investment continue to run, though: 48 months from the respective grant decision, so for the last billing year 2028 probably until 2033. Deliveries in those years count in full and cost no grant. This is our own reading of the rules, not a statement by BAFA. If it holds, buyers will prefer contracts whose delivery starts in 2029 and which run until about 2033. For a park that goes online in 2027 or 2028, that fits. For the years after that, the rule gives the buyer no further reason to purchase.

What speaks against a PPA surge?

Quite a lot. The duty can be met in many ways. For the company, an electricity contract with a third-party park is rarely the most convenient.

• Investments that were planned anyway count: a more efficient drive, an electric furnace, a storage unit on the factory site, a rooftop system of its own. A company that only has to relabel its investment budget needs no new contract.
• The flexibility bonus ties 80 per cent of the duty to flexibility. A company that takes it has little left for a park.
• The rule applies for three years, is subject to available budget funds and can be amended. A company that plans cautiously will not commit for ten years on that basis.
• Many large buyers already have solar power in their portfolio. The German Energy Agency's market analysis names this as one reason for the decline in 2025. They do not need more midday power; why the value of that power is falling is shown in Solar market value: why solar power is worth less and less on the exchange.
• Recipients are sectors with high electricity costs and a risk of relocation. These are not uniformly the counterparties with the best credit standing. Undertakings in difficulty are excluded from the grant; if the grant falls away, so does the reason for the contract.

For the park this means: the rule is an additional argument in marketing, not a business model. A calculation that works only with such a buyer is too tight.

What should a PPA with an industrial buyer contain?

More than an ordinary offtake contract, because the buyer is liable to BAFA for the result and will want to pass that risk on. Six points decide whether the contract serves the park:

• Waiver of EEG support: for what period does the park forgo the support? What applies afterwards? The waiver has a value; it belongs in the price, not in a side agreement.
• Volumes: only invoiced delivery counts. The buyer will ask for minimum volumes or replacement delivery; a solar park cannot guarantee weather, curtailment and hours with negative prices (Negative electricity prices: what they mean for solar and storage investors). What is delivered is what the park generates, with a clear rule for downtime.
• Liability: if BAFA reclaims the grant because the volume falls short, the park must not be liable without limit. A liability cap and the exclusion of consequential loss belong in the contract.
• Evidence: the buyer needs invoices, the commissioning date from the register and the declaration that no state aid has been received. What the park has to supply and who is given access should be listed exhaustively.
• Term and follow-on: if the contract ends with the evidence deadline around 2033, the park is left afterwards without a buyer and without a floor. An extension option or a price for the years after closes that gap only if it is binding.
• Security: a guarantee from a bank or the parent company, sized to the open receivables from the high-yield summer months.

What an offtake contract has to settle beyond that, from billing to the counterparty's insolvency, is covered in The direct marketing contract of a solar park: what investors should check before signing for the related case of the direct marketer.

Which questions should investors ask the provider?

If an offer document advertises an industrial buyer or eligibility under the industrial electricity price, these questions are worth asking:

• Does the park hold an auction award? If so: is it given up for the contract and what is the revenue floor afterwards?
• Is there an advance ruling from BAFA that the contract is recognised as a counter-investment? Who applied for it?
• When does delivery start and when does it end? Which price does the model assume for the years after the contract?
• Which volumes does the park owe and what happens in the event of lower yield, curtailment and negative prices?
• Up to what amount is the park liable if the buyer has to repay its grant?
• How is the buyer's credit standing documented and what security does it provide?
• How is the park financed and has it been clarified that neither the loan nor tax rules endanger eligibility?

General checkpoints for any provider are set out in How to tell a trustworthy provider of energy direct investments.

How we check it

We treat a contract with an industrial buyer like any other revenue source: we first calculate the park without it, at market value and with the floor it actually has. Only then do we add the contract, with its price, its term and the gap afterwards. A park that holds up only with the contract fails our check. So far there is no such project in our data room; when one arrives, we ask for BAFA's advance ruling and the contract text, not the summary.

We do not promise returns. How a solar park earns money overall is set out in Investing in solar parks: revenues, costs and tax leverage at a glance. Which revenue structure a specific project has is something we go through with you in a free initial consultation, ideally using an offer you already have.