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 links it to the electricity exchange. It is mandatory for systems over 100 kWp. Whether this turns out to be an advantage or a risk depends on the market price of solar power—which, so far in 2026, has fluctuated between 1.317 ct/kWh in April and 11.019 ct/kWh in January.
The short answer
In direct marketing, a service provider sells solar power on the exchange (EPEX Spot). If the market value of solar power is below the EEG-mandated rate, the grid operator pays the difference as a sliding-scale market premium; if it is above that rate, the operator retains the additional revenue. For systems commissioned in 2023 or later, the annual market value applies; for older systems, the monthly market value applies. For systems with an installed capacity exceeding 100 kWp, there is no permanent feed-in tariff (Section 21(1), sentence 1, no. 1 of the EEG); anyone wishing to receive support must sell directly via the market premium (Sections 20, 21b of the EEG)—effectively a mandatory direct marketing requirement.
The most recent monthly market value for solar power , published for August 2026, is 6.359 ct/kWh. The annual market value for 2025, which serves as the benchmark for new installations, was 4.508 ct/kWh. This analysis explains the mechanics, presents the current values, 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 switch between these sales categories may only be made on the first day of a calendar month (Section 21b(1), sentence 2, EEG). The grid operator must be notified of the change before the start of the preceding calendar month (Section 21c(1), sentence 1, EEG)—for a change effective December 1, this means by October 31. To switch into or out of the outage compensation scheme, notification by the fifth-last business day of the previous month is sufficient (Section 21c(1), sentence 2, 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 more than 500 kW 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 following applies: Subsidized direct marketing is mandatory for PV systems with an installed capacity of more than 100 kW. Systems up to 100 kWp may 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 German 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 | 3.296 ct/kWh* | 9.754 ct/kWh | 0,34 |
| June 2026 | 6.190 ct/kWh | 10.952 ct/kWh | 0,57 |
| July 2026 | 5.226 ct/kWh | 10.545 ct/kWh | 0,50 |
| August 2026 (last published) | 6.359 ct/kWh | 12.689 ct/kWh | 0,50 |
| Source: netztransparenz.de (Market value overview of transmission system operators), monthly figures confirmed by pv magazine and Solarserver. * May 2026: Retrospectively corrected by the transmission system operators from 3.163 to 3.296 ct/kWh (error in the online projection of solar generation for May 1, 2026). The September figure will be published by the tenth business day of October 2026. Profile factor = solar market value divided by the day-ahead average (rounded). | |||
Annual Solar Market Value, 2023–2025
For all systems commissioned in 2023 or later, the annual market value is the key factor. It is weighted by solar generation over the entire calendar year—so months with plenty of sunshine and low prices carry more weight than winter months.
| Year | Annual Market Value of Solar | Annual Average of Spot Prices | Profile factor |
|---|---|---|---|
| 2023 | 7.200 ct/kWh | 9.518 ct/kWh | 0,76 |
| 2024 | 4.624 cents per kilowatt-hour | 7.946 ct/kWh | 0,58 |
| 2025 | 4.508 ct/kWh | 8.932 ct/kWh | 0,50 |
| Source: netztransparenz.de (annual market values pursuant to Annex 1, No. 4 of the EEG 2023); LfL Bavaria, Solar Power Market 2023–2025, as of January 26, 2026. The generation-weighted annual market value is the relevant figure. The unweighted average of the twelve monthly values published alongside it (2023: 8.003 ct/kWh) is not the legally prescribed calculation parameter. The annual market value for 2026 will be published in January 2027. | |||
The "Solar" profile factor is declining structurally
The profile factor—annual market value of solar divided by the annual spot average—has fallen from 0.76 (2023) to 0.58 (2024) and then to 0.505 in 2025. As a result, in 2025, solar power was, on an annual 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 573 hours with negative day-ahead prices (2024: 457 hours); in the first half of 2026, according to an analysis by naturstrom AG, there were approximately 291 hours (1,178 when counted in quarter-hours, SMARD)—the frequency declined compared to the same period the previous year, while the depth of the price decline increased. The mechanics of zero remuneration at 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 new installations, the grid operator pays monthly advance payments during the year, which it may base on the previous year’s annual market value. Any overpayments or underpayments are settled in the final statement the following year, as soon as the annual market value is published (Section 26(1) EEG 2023). Older plants also switch to the annual market value if they use the accrual or flat-rate option under Section 19(3b) or (3c) EEG. A separate management premium of 0.4 ct/kWh has not existed as a standalone component since the EEG 2014—it is now factored into the current applicable rate. Industry publications that additionally calculate “0.4 cents on top” for new installations are incorrect.
Calculation Example: New Investment (Annual Market Value)
A commercial rooftop system scheduled to come online in 2026 with a base value of 5.84 ct/kWh will receive the market premium based on the 2026 annual market value for solar, which will not be determined until January 2027. If we use the 2025 annual market value of 4.508 ct/kWh as a reference, this results in a market premium of 1.332 ct/kWh. Together with the exchange proceeds, the operator theoretically reaches the applicable value on an annual average basis, minus the marketing fee. Individual months do not affect this: A weak April lowers the annual market value, while a strong August raises it—calculations are based on the entire year. This example is provided for illustrative purposes.
Sample Calculation: Existing Plant Before 2023 (Monthly Market Value)
For plants commissioned before 2023, calculations are made on a monthly basis. Assuming an applicable rate of 5.84 ct/kWh, the market premium in April 2026 (monthly market value: 1.317 ct/kWh) was 4.523 ct/kWh. In August 2026, the monthly market value was higher at 6.359 ct/kWh—the premium was waived, and the operator retained the exchange proceeds, which were approximately 0.52 ct/kWh above the applicable rate. This asymmetry—hedged against declines but open to increases—applies to both groups, on an annual basis for new plants. It will end with the planned transition to two-way difference contracts under the EEG in 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. For a 10-year solar PPA in Germany, enervis’s PPA Price Tracker shows a range of 28 to 40 €/MWh for August 2026 (pv magazine, September 7, 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 portion 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, for which non-residential customers paid an average of 19.22 ct/kWh across all consumption groups in the second half of 2025, and 32.58 ct/kWh for annual consumption below 20 MWh (Destatis, excluding VAT and deductible taxes). The remaining electricity is sold through direct marketing; this can also be retrofitted in existing systems via RLM metering and a direct marketing 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, as of January 1, 2026 (ZfK, January 12, 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 bankruptcies of the CLENS Group in 2017 and of in.power GmbH in 2021 have shown that even established direct marketers can default. In such cases, Section 21(1), first sentence, No. 3 of the Renewable Energy Act (EEG) provides for default compensation: The grid operator temporarily purchases the electricity at 80 percent of the applicable value, for a maximum of three consecutive calendar months and a total of six calendar months per calendar year. If either of these maximum durations is exceeded, the entitlement for the entire calendar month drops to zero—meaning the default compensation only bridges the gap until a new direct marketer is found.
7. Transition, Phase-out of the Market Premium, and the EEG 2027
The Transition Process in Practice
To complete the switch, 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. If you are also changing the form of sale, this must be notified to the grid operator before the start of the preceding calendar month (Section 21c(1), sentence 1, of the EEG).
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 approximately 118 GWp at the end of 2025 and exceeded the 128 GWp mark in August 2026 (BSW-Solar). As capacity continues to grow, 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 for 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?
Since 2016, there has been no longer any long-term feed-in tariff for PV systems with an installed capacity exceeding 100 kWp (Section 21(1), sentence 1, no. 1 of the EEG 2023); they are subsidized solely through the market premium in direct marketing (Sections 20, 21b of the EEG)—which is, in effect, mandatory. 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 most recent published monthly market value for solar power is for August 2026: 6.359 ct/kWh (netztransparenz.de). It fluctuates significantly from month to month: in April 2026, it fell to 1.317 ct/kWh, the lowest level since April 2020. For systems commissioned in 2023 or later, the annual market value applies—in 2025, it was 4.508 ct/kWh; the value for 2026 will be released in January 2027.
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 is valid through the end of 2026 (European Commission, SA.102084). The EEG 2027, adopted by the Cabinet on July 29, 2026, is intended to convert the one-way market premium into a two-way contract for difference (CfD). As things stand, facilities commissioned by the end of 2026 will retain their grandfathering status for 20 years.
How do I switch direct sellers?
You may change your direct marketer at any time (Section 21b(4)(1) EEG). The new direct marketer will handle the registration with the grid operator; the operator will terminate the old contract within the required notice period (typically three months), issue a power of attorney, and provide the system data. Only if the form of sale changes at the same time does the notification period specified in Section 21c(1), sentence 1 of the EEG apply: before the start of the preceding calendar month.
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 provides a floor for the value to be applied—based on the annual market value for new installations—while the operator retains the exchange proceeds above that threshold. The key factor is the solar market value, which in 2026 has so far fluctuated between 1.317 and 11.019 ct/kWh per month 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 begin operations by the end of 2026 secure the one-sided market premium without a repayment obligation for 20 years. Learn more in our guides on EEG remuneration for 2026, the CfD requirement for 2027, and photovoltaic investment.
Sources and Legal Basis
- netztransparenz.de – Market Value Overview (Solar Market Value, Monthly and Annual Figures), accessed September 2026
- pv magazine Germany – “Market Price for Solar in August at 6.359 Cents per Kilowatt-hour,” September 9, 2026
- pv magazine Germany – “Market price of solar power drops to 5.226 cents per kilowatt-hour in July,” August 10, 2026
- LfL Bavaria – Solar/Photovoltaics: Electricity Market in 2025, 2024, and 2023, as of January 26, 2026
- Laws on the Internet – Annex 1 to Section 23a of the EEG 2023 (Amount of the Market Premium); also Section 26 of the EEG 2023 (Deductions and Final Settlement)
- 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); see also Sections 3(16), 10b, 21, 21a, 21b, 21c, 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) – Press Release No. 111: Electricity Prices for Non-Households, Second Half of 2025, March 31, 2026
- pv magazine Germany – enervis PPA Price Tracker for Photovoltaics (August 2026), September 7, 2026
- ZfK – Direct Marketing Survey, as of January 1, 2026 (January 12, 2026)
- BSW-Solar – “Solar Capacity Reaches Milestone – Industry Warns of Slowdown in Expansion,” August 20, 2026
Logic Energy Editorial Team. Updated: September 24, 2026.
