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Glossary · Energy industry & energy transition

Difference costs

Differential costs EEG Surcharge market premium CfD support scheme electricity market renewable energies

Difference costs arise when a guaranteed remuneration value for electricity is higher than the revenue that this electricity earns on the market or would notionally earn. This means the financial gap between a support entitlement and the market value of the electricity generated. The term appears in connection with the feed-in tariff, the sliding market premium and contracts for difference. All three instruments secure investments without fully exposing the electricity to price risk on the market.

The basic calculation is simple. A plant generates a certain volume of electricity, usually measured in megawatt hours (MWh) or kilowatt hours (kWh). For this volume there is a reference value: in the German EEG the "anzulegender Wert" (the value to be applied), and in a contract for difference an agreed strike price. A market value or reference market price is deducted from it. This difference multiplied by the relevant volume of electricity gives the difference costs. An illustrative calculation example: the value to be applied is 6 ct/kWh (€60/MWh) and the market value is 4.5 ct/kWh. The compensation is then 1.5 ct/kWh. With annual generation of 10,000 MWh, that comes to €150,000. If the market value is above the support value, the compensation falls to zero. Whether repayments then occur depends on the respective support model.

The difference between a value per unit of energy and absolute costs is important. A large difference in euros per MWh only leads to high total costs if large volumes of electricity are also affected. Conversely, a small difference can require a lot of money if volumes are very large. Difference costs therefore always depend on three variables: the remuneration level, the market value and the volume supported.

Calculation and market value

For wind and solar power, the relevant revenue is not simply the average exchange electricity price. These plants feed in depending on the weather, time of day and season. The EEG therefore calculates a technology-specific market value. For this, the spot market price of each quarter hour is weighted by the extrapolated feed-in of the respective technology in that quarter hour. The sum is then divided by the total volume generated. If many solar plants generate electricity at the same time, prices often fall in those hours. The market value of solar power is then below the simple average price. The same applies to wind power in hours with a lot of wind.

This profile effect, also referred to as profile risk, is central to difference costs. If the market value of a technology falls, difference costs rise at the same remuneration. This does not mean that the technology has become technically more expensive. It only shows that its electricity earns less on the market in the hours in which it is fed in. Causes can be high simultaneous generation, little flexible demand, grid bottlenecks, lack of storage or the design of the electricity market.

The sliding market premium in the EEG

Under the sliding market premium, plant operators in principle sell their electricity themselves or via a direct marketer. In addition, they receive a premium. According to Annex 1 to the EEG 2023, it results from the value to be applied minus the market value. If the result is negative, the premium is set to zero. The German market premium has so far therefore worked in one direction only: high market prices reduce the subsidy down to zero, but do not trigger a repayment. Additional revenues above the value to be applied remain with the operator.

The assumption that the premium is always calculated using a monthly market value was corrected. A monthly market value applies only to plants that were commissioned before 1 January 2023 or received an award before then. For the other plants, the premium is calculated annually and retroactively on the basis of a technology-specific annual market value. This changes the incentives: an annual value smooths out seasonal fluctuations. An operator whose plant markets better than the average of its technology benefits from this. Those who perform worse bear the disadvantage themselves.

Negative prices also affect difference costs. Under Section 51 EEG 2023, for plants commissioned or awarded from 25 February 2025, the payment entitlement lapses in every quarter hour with a negative spot market price. As compensation, Section 51a EEG extends the remuneration period accordingly. For older plants, earlier hourly rules or exceptions apply depending on the year of commissioning and capacity. In hours of oversupply, new plants therefore generate no difference costs. At the same time, it is worthwhile to curtail the plant in such hours or to use storage.

Two-sided contracts for difference

In a two-sided CfD, compensation is settled in both directions. If the reference price is below the strike price, the operator receives the difference. If it is above, the operator pays the difference back. In high-price phases, difference costs can thus become negative: money flows back to the support provider. How a CfD works depends heavily on which reference price is chosen, which volumes are included and whether the plant continues to respond to short-term price signals.

The EU electricity market reform laid down in Article 19d of the Electricity Market Regulation: direct price support for investments in new plants, for example for generation from wind, solar, geothermal and hydropower without a reservoir, must in future be designed as a two-sided contract for difference or an equivalent scheme. The basis is Regulation (EU) 2024/1747. According to common accounts, the obligation applies to support contracts from 17 July 2027. The regulation names as possible forms, among others, feed-in-based contracts with one or more strike prices, minimum prices, and capacity-based or benchmark contracts. Member States may distribute revenues flowing back from such contracts to end customers.

Germany is preparing the changeover with an EEG amendment. The Federal Ministry for Economic Affairs published a government bill on this in July 2026. As of this research, the amendment has not yet been adopted. Details such as the reference period, thresholds and transitional periods may therefore still change.

Distinction from support costs, electricity price and system costs

Difference costs are often equated with support costs. This is only partly true. They describe the compensation between market revenue and support value, but not necessarily all costs of a support system. According to the Energy Financing Act (EnFG), the annual EEG financing requirement comprises the difference between the revenues and expenditures of the transmission system operators. In addition to market premiums and fixed remuneration, this includes items such as profile service costs and liquidity reserves, as well as offsetting against the balance of the EEG account. Payments to plant operators are also not the same as difference costs, because part of them is covered by market revenues.

Difference costs are also not the same as system costs. System costs additionally include grid expansion, redispatch, reserve capacity, storage, metering and control technology and other costs of security of supply. Difference costs show only a financial compensation within the support regime. On their own they say nothing about the overall economic costs that a particular generation structure causes.

Nor can difference costs be equated with the electricity price for households or businesses. In Germany they were previously financed via the EEG surcharge and were thus directly visible on the electricity bill. The surcharge was reduced to zero on 1 July 2022. Since 2023, EEG support has been financed from the federal budget. The transmission system operators publish the financing requirement every year in October for the following year. For 2026, it stood at €16.152 billion, not taking the account balance into consideration. The costs do not disappear through the change, they simply run through a different channel. This changes the distribution of burdens and the political incentives.

Why difference costs matter in the electricity system

Renewable plants require high initial investments and have hardly any fuel costs. What counts for investors is therefore how reliable future revenues are. A support value reduces price risk and can lower financing costs. Lower capital costs in turn reduce the remuneration required. A support instrument is therefore not just a payment system. It also determines which risk is borne by plant operators, the state, consumers and other market participants.

A trade-off follows from this. The more revenues are secured, the easier it is to finance investments. At the same time, price signals can become weaker if plants are remunerated regardless of the short-term value of their feed-in. Modern support models are therefore meant to limit investment risks without completely eliminating the response to negative prices, grid bottlenecks or flexibility needs. Rules such as Section 51 EEG or the EU law requirement that CfDs should preserve market-oriented behaviour serve this purpose.

Difference costs also show how the expansion of renewable energy and the development of market values are connected. As the share of weather-dependent generation grows, hours with high simultaneous feed-in become more frequent. If flexible consumers, storage, electrolysers, grid expansion or other forms of flexibility are lacking, revenues in these hours fall. Difference costs then rise even though the generation costs of new plants may continue to fall.

Typical misinterpretations

  • "High difference costs prove inefficient plants": this conclusion overlooks the link to the market price. If wholesale prices fall, difference costs rise arithmetically. At the same time, procurement costs for suppliers and consumers may fall, among other things through the merit order effect. The overall effect depends on the financing system, consumption profiles and procurement strategies.

  • "Low difference costs mean that support is free": low or negative values in high-price phases may be due to exceptionally high gas prices, scarce power plant capacity or geopolitical shocks. A support mechanism can only be meaningfully assessed across several price phases.

  • "Every difference payment is a subsidy": this is too imprecise. A difference payment can be state support. But it can also be designed as a contractual risk compensation that triggers repayments at high prices. For classification, what counts is who sets the reference value, whether access is awarded competitively through a tender, who bears the price risk and whether the mechanism works in both directions or only in one.

  • "One year says everything": a single year with high compensation payments says little about the long-term quality of a support design. What matters are the term, price assumptions, capital costs, expansion targets and the question of whether the support enables new capacity that replaces fossil fuel costs and emissions.

Institutional significance

Difference costs are also a question of responsibility. With a surcharge, electricity consumers bear the costs under rules laid down by law. With financing from the budget, the compensation competes with other state expenditure and depends on budget decisions. With two-sided contracts, additional revenues in high-price phases can be skimmed off and redistributed in a targeted way. Each form of financing changes visibility, distribution and political steering.

Even small differences in design affect behaviour. A monthly market value sets different incentives than an annual market value or an hourly reference price. Support that lapses at negative prices works differently from continuous remuneration. A CfD tied to actual feed-in works differently from a contract referring to a reference plant or capacity. Such rules help determine whether operators add storage, curtail plants, conclude supply contracts or use other flexibility options. The term difference costs therefore does not explain all costs of the electricity system. But it makes visible an important link between support, market value and financing.

Sources

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Edited by eCMS on 11.11.2026 19:01

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