Curtailment of a solar park: when the grid operator pays and when it does not

A solar park produces when the sun shines, not when the grid needs it. So there are hours in which the grid operator turns the feed-in down because a line or a substation would otherwise be overloaded. On top of that come hours in which the direct marketer switches the plant off because the exchange price is below zero. For the operator both cases look the same in the monitoring: the curve drops. Economically they are opposites, because in one case somebody pays and in the other nobody does.

This article sorts the cases, explains what § 13a EnWG actually guarantees the operator, what the legislative change of 23 December 2025 altered in the settlement, why that can turn a credit note into an invoice at midday, and what the draft grid package would mean for new sites. It describes orders of magnitude for the market, not any specific project.

When may a solar park be curtailed?

In four cases, and the difference between them decides the money. The duty to accept curtailment applies under § 13a Abs. 1 EnWG to every generating plant from 100 kilowatts of rated output and to every plant the grid operator can remotely control at any time; the technical requirement for that is set by § 9 EEG. A solar park in a direct investment is always above that threshold. But who curtails, and for what reason, determines the legal consequence:

Market-driven curtailment has nothing to do with the grid. It is the direct marketer's answer to negative exchange prices: as soon as the spot price falls below zero, every kilowatt hour fed in costs money, and for plants commissioned since 25 February 2025 there is no market premium in those periods either, under § 51 EEG. How often that happens and what it means for the solar market value is covered by Negative electricity prices: what they mean for solar and storage investors. What counts here is only this: these hours are not eligible for compensation, and they increasingly overlap with the hours in which the grid is full as well. It is precisely that overlap which has made settlement delicate since December 2025.

How much solar power was actually curtailed in 2025?

2,704 gigawatt hours, according to the Federal Network Agency's figures on congestion management for the full year 2025. That is 94 percent more than in 2024 (1,394 gigawatt hours) and, measured against the PV generation of 73.8 terawatt hours reported by SMARD, around 3.7 percent of German solar power. Across all renewables the curtailed share was 3.5 percent; onshore wind came to 3,225 and offshore wind to 3,351 gigawatt hours. Photovoltaics is therefore not yet the largest item, but the fastest growing one.

Two rows of this table matter more for solar parks than the totals. First, the cause is shifting into the distribution grid: in 2024, 26 percent of the measures at renewable plants went back to congestion in the distribution grid, in 2025 it was 35 percent, and in the first quarter of 2026 34 percent. Ground-mounted plants nearly always hang on the distribution grid, usually on the medium-voltage side of a regional substation; the congestion therefore arises where solar parks stand. Second, the compensation total is falling even though the volume is rising: 433 million euros for all renewable plants in 2025 against 554 million the year before, and 55 million in the first quarter of 2026. Part of that is explained by lower market values, part by the new settlement rules we come to in a moment. In the first quarter of 2026 the curtailed PV volume rose by a further 23 percent against the same quarter of the previous year.

These figures are national averages. The explanatory memorandum to the grid package assumes that curtailment concentrates on a few substations; a solar park at the wrong substation can lose a multiple of the average, one at the right substation practically nothing. That is why the question about the curtailment history of the specific grid connection point belongs in every project review, not the national figure.

What does the grid operator pay under § 13a EnWG?

What the operator would have earned without the measure, no more and no less. That is how § 13a Abs. 2 Satz 2 EnWG puts it: financial compensation is appropriate if it leaves the plant operator economically neither better nor worse off than it would have been without the measure. For plants under the EEG, number 5 of the third sentence specifies this as the lost revenue plus the additional expenditure; saved expenditure has to be offset by the operator under sentence 4. For a solar park that is, in practice, the lost market premium and the lost marketing revenue for the volume of electricity it could have fed in.

This volume of electricity is called curtailed energy, and it is the real point of dispute in every settlement, because nobody can measure what a curtailed plant would have produced. The Federal Network Agency laid down procedures for it in decision BK6-20-059: either the operator supplies planned values (planning value model) or the grid operator produces a forecast (forecast model); the curtailed energy itself is determined by the peak procedure from measured weather data at the site, by the simplified peak procedure, or by the flat-rate procedure from the last fully measured output before the measure. Which procedure applies is recorded in the plant's master data and feeds straight through to the level of compensation: anyone whose midday output is extrapolated under the flat-rate procedure from the reading at 9 a.m. receives less than under the peak procedure with the actual irradiation.

Until December 2025 there was a second building block alongside this, the balancing compensation under § 13a Abs. 1a EnWG: the grid operator made the curtailed energy available to the direct marketer's balancing group, the direct marketer sold the original schedule on at the exchange as if nothing had happened, and paid the operator the contractual price. The operator noticed little of the measure financially. This system still applies to measures taken by transmission system operators. For the distribution grid, where most solar parks sit, the legislator has suspended it.

What changed on 23 December 2025?

The payment route and the price basis. Under the Act amending energy industry law of 18 December 2025 (BGBl. 2025 I Nr. 347), in force since 23 December 2025, § 14 Abs. 1 Satz 3 EnWG provides that balancing compensation for measures taken by distribution grid operators applies until 31 December 2031 only if the Federal Network Agency orders it by decision. As long as that does not happen, § 14 Abs. 1b EnWG applies: balancing compensation is deemed to have been provided, and the distribution grid operator pays the financial compensation directly to the plant operator, plus a reimbursement of expenses for the fact that the balancing group manager has to settle the measure within its own balancing group. The level of that reimbursement is set by the Federal Network Agency; the economics ministry will evaluate the arrangement by 1 July 2028.

The direct marketer has thereby dropped out of the payment flow. Previously it owed the operator the contractually agreed price for the curtailed energy, often the monthly solar market value, and recovered the money from the grid operator. Now the grid operator owes the operator the lost revenue, and the price basis used in practice is the BDEW mixed price of the transitional solution: a single price per quarter hour, formed from 72.5 percent of the intraday index ID1 and 27.5 percent of the balancing energy price reBAP and published monthly on netztransparenz.de. On top of that comes the lost market premium, where one would have accrued in the quarter hour concerned.

The difference sounds technical but is fundamental. The monthly market value is an average across all hours of a month in which solar power was fed in; it smooths the midday hours together with the morning and evening hours. The mixed price is the price of exactly the quarter hour in which curtailment took place. And a solar park is curtailed almost exclusively at midday, when feed-in is highest. In those quarter hours the price is regularly low in summer, and more and more often negative.

Why can a credit note turn into an invoice?

Because the mixed price can be below zero at midday and the settlement then applies it with the sign reversed. We evaluated the published quarter-hourly values for four months of 2026 ourselves:

In April 2026, then, almost every second midday quarter hour was negative, on average 87 euros per megawatt hour below zero; the lowest quarter-hourly value of the month was minus 2,574 euros, because the balancing energy price swings to extremes in individual quarter hours. For compensation that means: the lost revenue for a redispatch quarter hour with a negative mixed price is negative. The operator would, so the logic runs, have paid money without the measure in order to be allowed to feed in; the measure therefore saves it expenditure, and that has to be reimbursed under § 13a Abs. 2 Satz 4 EnWG. The credit note becomes an invoice.

The flaw sits in the assumption that the plant would have fed in during that quarter hour. In practice the direct marketer would have switched it off itself at a negative price, market-driven and without any claim to anything. Before December 2025 this did not show, because the direct marketer sorted both cases in its own settlement and called on the grid operator only for the quarter hours in which the plant would actually have fed in. Since settlement runs directly between grid operator and plant operator, that filter is missing unless the direct marketing contract replaces it. Some contracts now contain a difference clause under which the direct marketer covers the gap between the mixed price and the contractual price, for a fee or without one; other contracts release the direct marketer from any payment obligation as a result of the legislative change. Which version applies in a given project decides several thousand euros a year.

The spread between the second and the third row is a good 21,000 euros for an identical plant with identical curtailed energy. The only difference is which quarter hours the grid operator intervened in. And because grid congestion and negative prices have the same cause, namely too much solar power at the same time, the third row is not the exception in summer but the normal case at a loaded substation.

How the market premium and the market value interact in principle is explained by Direct marketing and the market premium: how a solar park earns its money. From 2027 the refinancing contribution is added for new awards, which moves the calculation in the other direction in high-price hours; that is covered by EEG 2027: what the refinancing contribution means for a solar park direct investment.

What would the grid package change at new sites?

It would partly abolish compensation for new plants at loaded substations. The federal government adopted the draft of an act to synchronise plant expansion with grid expansion in cabinet on 29 July 2026 and introduced it in the Bundestag as printed paper 21/7866 of 7 September 2026; the first reading is scheduled for 24 September 2026. The core for solar parks sits in three new provisions:

• § 14 Abs. 1d EnWG-E: distribution grid operators may designate substations and the line sections connecting them as capacity-limited for up to six years if the feed-in of the plants connected there was reduced by more than five percent through redispatch in the preceding calendar year. The designation is technology-specific for ground-mounted solar plants and onshore wind, is notified to the Federal Network Agency by 31 March, and is published on the grid operator's website. If the three-year average falls back below the threshold, the designation has to be lifted; the grid operator must give priority to expanding these areas.
• § 8 Abs. 4 EEG-E: in such an area there is no longer an unconditional right to grid connection. Instead the grid operator has to offer a connection contract in which the operator waives financial compensation under § 13a Abs. 2 EnWG for the duration of the designation, limited to 20 percent of the electricity generated in a year (18 percent for wind in designated wind energy areas). The waiver may be extended once by 18 months if the conditions persist and the grid operator is not responsible for the missing expansion. § 13a Abs. 6 EnWG-E clarifies that the compensation claim then exists only as provided in that contract.
• § 8 Abs. 1 Satz 4 EEG-E: for ground-mounted solar plants connected from 1 January 2027, the connection right exists only on condition that maximum active power feed-in at the grid connection point is limited to 70 percent of installed capacity. That is a planned capping of the midday peak for all new plants, regardless of the grid area.

Existing plants keep their claim to financial compensation according to the explanatory memorandum, even if their substation is later designated as capacity-limited; the waiver applies only to plants that apply for a connection there while the designation is in force. For its legality the memorandum relies on Art. 13 para. 7 of EU Electricity Market Regulation 2019/943, which requires financial compensation for non-market-based redispatch of at least the additional operating costs or the lost net revenue; whether a contractual waiver imposed by statute is compatible with that will be debated in the legislative process. The draft provides for entry into force on the day after promulgation, not on a fixed date.

For a direct investment the practical consequence is already tangible: the curtailment history of the substation becomes a site criterion. A grid area that curtailed more than five percent in 2025 or 2026 could be designated once the act enters into force, and a project whose connection request is still open at that point would only be offered the contract with the waiver. What should be checked on grid connection anyway is covered by Grid connection, easement, building rights: how to tell whether a direct investment has truly secured its site.

What does this mean for the return on a direct investment?

That curtailment needs its own line in the yield model, with an assumption that fits the site, and that the effect on equity is larger than the percentage suggests. In its early years a solar park carries debt service that ties up a large share of revenue; every euro missing at the top is missing entirely at the bottom. Using the example above, with annual revenue of 260,000 euros and debt service tying up 60 percent of it, the equity cash flow is 104,000 euros:

The table deliberately calculates without compensation, because that is the case an investor has to guard against: market-driven curtailment, redispatch at a negative mixed price without a difference clause, or a connection contract with a waiver under the grid package. A loss of 20 percent of revenue halves the cash flow on equity in this example. Three things change the picture:

• The site. The national figure of 3.7 percent says nothing about a single substation. Grid operators publish redispatch measures plant by plant; for a connection point the curtailment of neighbouring plants in previous years can be traced, and a yield assessment should show it as a separate deduction, as Reading a yield assessment: what P50 and P90 mean for a solar park direct investment describes.
• The layout. An east-west or vertical arrangement moves yield out of the midday peak into the edge hours and thereby reduces both the negative-price hours and exposure to redispatch; the figures are in South, east-west or vertical: which solar park layout pays off for investors. The 70 percent limit in the grid package anticipates this logic for all new plants.
• The battery. A battery at the same grid connection absorbs the midday peak instead of curtailing it, and sells it in the evening; it turns the curtailment hour into a charging hour. Whether that pays depends on sizing and revenue model, as Co-located vs. stand-alone: which gives the better risk structure shows; it does not remove curtailment, it shifts it into the hours in which the battery is already full.

Which questions should you put to providers and direct marketers?

Seven, and each belongs in the project documents together with its answer:

1. What curtailment does the yield model assume, as a percentage of annual yield, split into grid-driven and market-driven, and where does the assumption come from: the yield assessment, the curtailment history of the substation, or a flat-rate figure?
2. How often were the plants at the same substation curtailed by redispatch in the past two years, and is the reduction above five percent? Under the grid package this threshold decides designation as a capacity-limited grid area.
3. What does the direct marketing contract provide for financial compensation since 23 December 2025: is there a difference clause between the mixed price and the contractual price, what does it cost, and who submits the redispatch settlement to the grid operator?
4. By which procedure is the curtailed energy determined, peak, simplified peak or flat-rate procedure, and who checks the grid operator's settlements for completeness and deadlines?
5. Is the plant remotely controllable under § 9 EEG, with what technology, and has control by the grid operator been tested? A plant that cannot be controlled is taken off the grid entirely if need be.
6. Does the monitoring distinguish between a redispatch measure and a shutdown by the direct marketer, and does the investor receive this split in the reporting? Without it, compensation can neither be checked nor claimed.
7. Is there a grid connection commitment without a waiver of financial compensation, and what happens contractually if the grid operator designates the area as capacity-limited before connection: is there a right of withdrawal or an adjustment clause?

A provider who answers these questions with figures and contract pages has understood its project. One who points to the statutory compensation and leaves it at that has not read the settlement rules in force since December 2025. How else to recognise reputable providers is set out in How to tell a trustworthy provider of energy direct investments.

How we check this in our project review

For every solar park we present to investors, we set the model's curtailment assumption alongside the published redispatch data of the responsible grid operator for the area around the connection point, read the clause on financial compensation in the direct marketing contract, and rerun the worked example above with the project's own figures, once with and once without compensation. We give no return promises in doing so; we show which figure rests on which assumption and how the return moves if the assumption does not hold. That is exactly what we do in a no-obligation initial consultation, ideally on the basis of a specific offering document.