Direct Sales of PV Electricity in 2026: What Are the Benefits of the Market Premium—and What About the Exchange Price?
Direct marketing of PV electricity decouples the revenue from a photovoltaic system from the fixed feed-in tariff and ties it to the electricity exchange. This is mandatory for systems larger than 100 kWp. Whether this turns out to be an advantage or a risk depends on the market price of solar power—which fluctuated in 2026 between 1.317 ct/kWh in April and 6.190 ct/kWh in June.
The short answer
In direct marketing, a service provider sells solar power on the exchange (EPEX Spot). If the market price of solar power is below the EEG reference price, the grid operator pays the difference as a sliding market premium; if it is above that price, the operator retains the additional revenue. For installed capacity of 100 kWp or more, subsidized direct marketing is mandatory (Section 21b of the EEG).
The market price for solar power stood at 6.190 ct/kWh in June 2026 and fluctuates significantly from month to month. This analysis explains the mechanics, presents the current figures, and outlines four revenue strategies. This is not investment advice.
Direct marketing of PV electricity is at the heart of any revenue planning for larger photovoltaic systems. This guide explains what direct marketing means from a legal perspective, how the market value of solar power has evolved through 2026, how the sliding-scale market premium works in practice, what the costs of marketing are, and the four strategies investors and operators can use to counter the structural decline in the value of solar power.
Direct Sales, Self-Consumption, Hedging – Calculated for Your Project
Logic Energy designs, builds, and operates turnkey PV systems. The contractual partner for direct investments is mediplan Helm e.K., a partnership with personal liability of the owners. We model your revenue scenarios based on market premiums, self-consumption, and the PPA share—free of charge for your location.
1. What does direct marketing of PV electricity mean—and when does it become mandatory?
The Renewable Energy Sources Act (EEG) distinguishes between four forms of sales, to which every PV system operator must assign their system: subsidized direct sales (market premium model), fixed feed-in tariff, tenant electricity surcharge, and other forms of direct sales. In subsidized direct marketing, solar power is sold directly on the electricity exchange, and the operator gains access to the electricity market through a service provider. A change may only be made on the first day of a calendar month, with notification to the grid operator before the start of the following month (Section 21b EEG).
Three Marketing Models for Investors and Businesses
Subsidized direct sales (Section 20 of the EEG) combine exchange proceeds with the market premium as a safety net and are the standard for larger commercial PV systems eligible for EEG subsidies that are subject to competitive bidding. Other forms of direct marketing (Section 21a EEG) do not receive any EEG subsidies but allow for the sale of certificates of origin—the path for systems over 20 kW that are no longer eligible for subsidies and for pure electricity supply models. The tenant electricity model ties the electricity geographically to a building and is rarely the route taken for traditional commercial photovoltaic systems.
From the 2014 Amendment to the Renewable Energy Sources Act (EEG) to the 100 kWp Cap
The requirement for direct marketing was introduced with the 2014 amendment to the Renewable Energy Sources Act (EEG): Initially, photovoltaic systems with a capacity of 500 kW or more were required to market their electricity directly; since 2016, the threshold has been 100 kW. Systems below this threshold may opt for direct marketing on a voluntary basis. This step was part of the transition from fixed feed-in tariffs to greater integration of renewable energy into the electricity market.
The 100-kWp limit remains in place
The original draft of the Solar Peak Act (October 2024) provided for a reduction of the direct sales requirement to 25 kWp. This reduction was removed in the final version of the law (Federal Law Gazette 2025 I No. 51 of February 21, 2025). The following continues to apply: subsidized direct marketing is mandatory for PV systems with an installed capacity exceeding 100 kW. Systems up to 100 kWp have the option to choose between a fixed feed-in tariff and voluntary direct marketing. Income from operating a photovoltaic system up to 30 kWp—including income from direct marketing—is exempt from income tax under Section 3 No. 72 of the Income Tax Act (EStG); details are covered in our guide to saving on photovoltaic taxes. The complete feed-in tariff table can be found in our guide to the 2026 EEG feed-in tariffs.
Technical Requirements: Remote Control, Measurement, and Forecasting
The technical requirements for direct marketing are a suitable metering device and the ability to be controlled remotely. Section 10b of the EEG requires operators of systems exceeding 25 kW to retrieve actual feed-in data in real time and to reduce output remotely. Billing is carried out via a recording power meter (RLM) or a smart metering system; compliance via the smart meter gateway will not be mandatory until January 1, 2028; until then, alternative transmission methods such as data loggers with modems are permitted. The direct marketer also generates weather-based generation forecasts to place the solar power on the market within the balancing group. The additional technical effort required for direct marketing thus remains manageable.
2. Solar Market Value in 2026: What Are the Current ct Values—and Why Do They Fluctuate?
The fluctuation is structural: During the sunny spring and summer months, the high volume of PV feed-in at the same time pushes the price at midday to or below zero in some cases, while the market value rises in winter when solar generation is low.
| Month | Market Value of Solar | Day-Ahead Spot Market | Profile factor |
|---|---|---|---|
| January 2026 | 11.019 ct/kWh | 11.009 ct/kWh | 1,00 |
| February 2026 | 7.717 ct/kWh | 9.658 ct/kWh | 0,80 |
| March 2026 | 5.455 ct/kWh | 9.929 ct/kWh | 0,55 |
| April 2026 | 1.317 ct/kWh | 7.852 ct/kWh | 0,17 |
| May 2026 | 3.163 ct/kWh | 9.754 ct/kWh | 0,32 |
| June 2026 (current) | 6.190 ct/kWh | 10.952 ct/kWh | 0,57 |
| Source: netztransparenz.de (market value overview), published by the transmission system operators; monthly figures confirmed by pv magazine. The July 2026 figure had not yet been published as of the date of publication (August 6, 2026). Profile factor = solar market value divided by the day-ahead average (rounded). | |||
The "Solar" profile factor is declining structurally
The profile factor—the market value of solar divided by the exchange’s baseload—has fallen within just a few years from around 0.84 (2023) to an annual average of 0.505 in 2025. As a result, in 2025, solar power was, on average, only about half as valuable as the average price on the electricity exchange. Negative electricity prices are the main driver: In 2025, there was a record of 573 hours with negative day-ahead prices (2024: 457 hours); in the first half of 2026, the figure was around 291 hours—the frequency declined compared to the same period the previous year, while the depth of the price decline increased. The mechanics of zero remuneration during periods of negative prices are covered in our guide to negative electricity prices for PV investors.
3. How the market premium is actually calculated—using current figures
For PV systems commissioned on or after January 1, 2023, the annual market value applies; for older systems, the monthly market value applies. A separate management premium of 0.4 ct/kWh has not existed as a standalone component since the 2014 EEG—it is factored into the current applicable rate. Industry publications that calculate an additional “0.4 cents on top” for new systems are incorrect.
Sample Calculation for a Low Market Value (April 2026)
A commercial rooftop system with an applicable value of 5.84 ct/kWh will generate a market premium of 4.523 ct/kWh in April 2026, assuming a monthly market value of 1.317 ct/kWh. When combined with the exchange proceeds, this results in a calculated base value of 5.84 ct/kWh, minus the marketing fee. The market premium thus protects the operator from a market crash and ensures the calculated lower limit. This example is for illustrative purposes only.
Sample Calculation for a High Market Value (June 2026)
Given the same applicable rate of 5.84 ct/kWh and a solar market price of 6.190 ct/kWh in June 2026, the calculated market premium is negative—it will not be paid out. The operator retains the full exchange revenue of approximately 6.19 ct/kWh, which is about 0.35 ct/kWh above the applicable rate. In months with a high market value, subsidized direct marketing demonstrates its advantage over the fixed feed-in tariff: there is no cap on the revenue. It is precisely this asymmetry that will end with the transition to two-sided difference contracts under the EEG 2027.
4. The Cost of Direct Marketing – Marketing Fees and Billing Models
Three Billing Models
Direct marketers typically use one of three billing models. Under the market-value model, the operator receives the monthly market value minus the marketing fee—the simplest model with minimal reporting requirements. Under the day-ahead or pay-as-produced model, the actual 15-minute spot prices achieved are passed on; since the EU reform of September 30, 2025, the exchange has used 15-minute resolution. The fixed-price hybrid model guarantees a minimum price range.
When Is Which Model Worth It?
For systems that feed all generated power directly into the grid without storage, the market-value model is usually the more profitable and stable setup because the generation-weighted monthly average smooths out the profile risk. The pay-as-produced model is only worthwhile if a system can actively respond to the 15-minute pricing structure—for example, with a battery storage system that shifts solar power from the midday trough to hours with higher prices. As long as the annual market value remains below the applicable value, the market premium largely offsets the differences between the models for the subsidized portion anyway.
5. Four Revenue Strategies to Combat Depreciation
Strategy 1: Storage-Based Marketing Optimization
A co-location storage system shifts solar power from the midday trough to hours with higher prices, thereby—controlled by an energy management system—increasing the effective market value of a PV system. In addition, it generates revenue from day-ahead arbitrage, intraday trading, and balancing energy. Our guide to PV with battery storage explains exactly which revenue streams a battery storage system unlocks and how this results in a higher return compared to selling PV power alone.
Strategy 2: Long-Term Power Purchase Agreements (PPAs)
A Power Purchase Agreement (PPA) guarantees a fixed purchase price for 10 to 20 years and decouples revenue from the market price. Solar PPA prices were most recently around 55 €/MWh (Q1 2026). For institutional investors, the PPA is the most important hedging strategy in light of the expiration of the market premium authorization at the end of 2026. A PPA does not replace the market premium, but it can replace the spot market share and pass the profile risk on to the buyer.
Strategy 3: Direct Marketing of Surplus Electricity in Addition to Self-Consumption
For businesses with their own photovoltaic systems, it is not direct sales but direct self-consumption that contributes the most to revenue—self-generated electricity replaces grid purchases at a rate of 19 to 33 ct/kWh (Destatis, second half of 2025). The remaining electricity is sold directly; this can also be retrofitted in existing systems via RLM metering and a direct sales contract. The self-consumption rate remains the key economic factor.
Strategy 4: Hybrid Marketing Portfolio
Larger solar portfolios combine subsidized direct marketing via the market premium with a portion of PPAs and a variable portion of spot market sales. This segmentation mitigates both the market value risk and the political risk associated with the 2027 EEG reform. A typical ratio is about half secured long-term, with the remainder variable and offering upside potential. This increases predictability without completely forfeiting the opportunities presented by periods of high prices.
| Strategy | Main effect | Suitability | Complexity |
|---|---|---|---|
| Storage Co-location | shifts revenue to peak hours | Investors with a capacity of 1 MWp or more | high |
| Long-Term PPAs | Price Guarantee for 10–20 Years | institutional projects | medium |
| Surplus electricity sales in addition to self-consumption | sells surplus solar power | Businesses with On-Site Consumption | low |
| Hybrid portfolio | Risk diversification | Medium- to large-scale projects | medium |
| These strategies can be combined. Model assumptions—no guarantee of success. | |||
6. Choosing a Direct Marketer: Market Overview and Selection Criteria
| Rank | Direct seller | parent company | Portfolio (MW) |
|---|---|---|---|
| 1 | Quadra Energy | TotalEnergies | 10.100 |
| 2 | EnBW | State of Baden-Württemberg / OEW | 9.900 |
| 3 | Next Power Plants | Shell plc | 8.020 |
| 4 | Statkraft Markets | Statkraft AS | 6.800 |
| 5 | Danske Commodities | Equinor ASA | 6.400 |
| Source: ZfK Direct Marketing Survey and *Energie & Management* Industry Survey, as of January 1, 2026. Other relevant providers: BKW, MVV Trading, RWE, Energy2market, Trianel. | |||
Selection criteria beyond price
What really matters: the provider’s creditworthiness, because revenue is received on a delayed basis; the size of the balancing group, because it improves the accuracy of forecasts; and expertise in brokering PPAs—the latter becomes increasingly important as the expiration of the market premium authorization at the end of 2026 draws nearer. Price alone is rarely the deciding factor.
Compensation for Losses in the Event of the Direct Marketer's Insolvency
The waves of insolvencies in 2017 and 2021 have shown that even established providers can go out of business. In such cases, Section 21(1), Sentence 1, No. 3 of the EEG provides for default compensation: The grid operator temporarily purchases the electricity at 80 percent of the applicable value, for a maximum of six months per year. Thus, the right to compensation is not lost in the event of a direct marketer’s default.
7. Transition, Phase-out of the Market Premium, and the EEG 2027
The Transition Process in Practice
To switch providers, the new direct marketer needs the MaStR number, the market location ID, the commissioning report, and proof of remote controllability in accordance with Section 10b of the EEG. The operator simply needs to terminate the old contract within the required notice period (typically three months) and issue a power of attorney. The formal registration must be submitted to the grid operator before the start of the month following the planned switch date.
What will change starting in 2027
On July 29, 2026, the Federal Cabinet approved the government’s draft of the EEG 2027. The current one-way market premium is to be converted into a two-way contract for difference (CfD): If the market price exceeds the reference value, the operator will in the future repay the difference. This implements EU Regulation 2024/1747, which mandates CfDs for new contracts effective July 17, 2027. The law has not yet entered into force; the draft is politically controversial and the details have not been finalized. As things stand today, existing installations commissioned by December 31, 2026, will continue to be subject to grandfathering provisions with a one-sided market premium for 20 years. Details are covered in our guide on the 2027 CfD requirement for PV investors.
8. What Investors and Businesses Need to Decide Now for 2026
Installed PV capacity in Germany stood at around 117 GWp at the end of 2025 and rose to approximately 118.2 GWp by the end of May 2026 (BSW-Solar). As capacity continues to expand, the profile factor is likely to continue to decline unless storage and sector coupling counteract this trend. Operators of existing systems should therefore evaluate the self-consumption option before making any decision regarding direct sales. For investors, the current market premium structure remains a safety net for 20 years, while all options regarding storage revenues and PPA hedging remain open. Our Photovoltaic Investment Pillar illustrates the complete return structure.
Revenue Scenarios for Your System – Market Premium, Self-Consumption, Hedging
Logic Energy provides full-service planning for PV systems—including active site acquisition and secured financing before construction begins—ranging from new PV installations to the restructuring of existing solar systems. The contractual partner for direct investments is mediplan Helm e.K., with personal liability of the owners. If you are planning a photovoltaic system suitable for direct marketing in 2026 or restructuring an existing system, we will evaluate your site and model suitable revenue scenarios.
9. Frequently Asked Questions About Direct Sales of PV Electricity
What is the direct sale of PV electricity?
Direct marketing refers to the sale of solar power on the exchange by a direct marketer, rather than its purchase by the grid operator in exchange for a fixed feed-in tariff. In the case of subsidized direct marketing, the operator also receives the variable market premium under the EEG. The legal basis for this is Section 20 of the EEG 2023.
At what plant size does direct marketing become mandatory?
For PV systems with an installed capacity exceeding 100 kWp, subsidized direct marketing has been mandatory since 2014 (Section 21b of the EEG 2023). The reduction to 25 kWp, which was initially discussed in the Solar Peak Act, was not implemented. Systems up to 100 kWp can freely choose between a fixed feed-in tariff and voluntary direct marketing.
What is the current market value of solar energy?
The market price for solar power stood at 6.190 ct/kWh in June 2026 (netztransparenz.de). It fluctuates significantly from month to month: in April 2026, it fell to 1.317 ct/kWh, the second-lowest value ever recorded. The annual market price for 2025 was 4.508 ct/kWh. The July 2026 figure had not yet been published at the time of writing.
What is the difference between subsidized direct marketing and other forms of direct marketing?
Subsidized direct sales (Section 20 of the EEG) combine exchange proceeds with the market premium and require eligibility for EEG feed-in tariffs. Other forms of direct marketing (Section 21a of the EEG) do not involve any EEG subsidies but allow for the sale of certificates of origin—which is common for plants over 20 kW that are no longer eligible for subsidies and for pure electricity supply models.
What are the costs associated with direct marketing?
A marketing fee is charged by the direct marketer; the amount of this fee is freely negotiable and depends on the size of the system and the portfolio. There is no officially regulated fee. Large systems pay a small fee per kilowatt-hour, while smaller systems often pay a monthly flat rate. In addition, there are technical costs associated with remote control and metering.
What will happen to the market premium starting in 2027?
The state aid approval for the current market premium expires on December 31, 2026. The EEG 2027, which was adopted by the Cabinet on July 29, 2026, is intended to convert the unilateral market premium into a bilateral contract for difference (CfD). As things stand now, facilities commissioned by the end of 2026 will retain their grandfathering status for 20 years.
How do I switch direct sellers?
A switch is possible at any time, effective on the first day of the month (Section 21b of the EEG). The new direct marketer handles the registration with the grid operator; the operator terminates the old contract in a timely manner (typically three months), issues a power of attorney, and provides the system data. Registration must take place before the start of the month following the switch date.
Conclusion
In 2026, the direct sale of PV electricity will not pose a return risk, but rather serve as a revenue stream with a safety net: The sliding market premium guarantees a minimum return, while the operator retains the full exchange revenue during periods of high prices. The key factor is the market value of solar power, which fluctuated between 1.317 and 6.190 ct/kWh in 2026 and whose profile factor is structurally declining. Those who actively address this decline in value through storage, PPAs, and self-consumption ensure profitability—and those who commission their systems by the end of 2026 secure the one-sided market premium without any repayment obligation for 20 years. Learn more in our guides on EEG remuneration for 2026, the CfD obligation for 2027, and photovoltaic investment.
Sources and Legal Basis
- netztransparenz.de – Market Value Overview (Solar Market Value, Monthly and Annual Figures), accessed August 6, 2026
- pv magazine Germany – “Market Price of Solar Rises to 6.19 Cents per Kilowatt-Hour in June,” July 9, 2026
- pv magazine Germany – “Market Price of Solar Falls to 1.317 Cents per Kilowatt-Hour in April,” May 11, 2026
- Federal Network Agency – EEG Subsidies and Subsidy Rates (Reference Values, Market Premium), accessed August 6, 2026
- Laws on the Internet – Section 20 of the EEG 2023 (Direct Marketing); also Sections 3(16), 10b, 21, 21a, 21b, and 23a of the EEG
- EUR-Lex – Regulation (EU) 2024/1747 amending the Electricity Market Regulation (CfD Requirement), June 26, 2024
- pv magazine Germany – “Cabinet Approves Drafts of the EEG 2027 and Grid Package,” July 29, 2026
- Federal Statistical Office (Destatis) – Electricity Prices for Non-Households, Second Half of 2025
- ZfK / Energy & Management – Direct Marketing Survey, as of January 1, 2026
- BSW-Solar – Installed PV Capacity in Germany, as of May 2026
Edited by Logic Energy. Last updated: August 2026.
