Direct Marketing of PV Electricity in 2026: Market Values, Market Premium, and Revenue Strategies
Excerpt
The 2025 annual market value for solar was 4.508 ct/kWh —half the average spot market price on the electricity exchange. What does this mean for PV systems of 100 kWp or more and for commercial businesses with their own photovoltaic systems? This guide to PV direct marketing explains market premiums, selecting a direct marketer, and four revenue strategies for 2026—including all monthly values, the profile factor of 0.505, and specific revenue scenarios for PV electricity.
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Subsidized direct marketing has been mandatory for PV systems over 100 kWp since 2014—contrary to many industry articles, the Solar Peak Act of February 2025 did not lower this threshold to 25 kWp. The market premium model combines electricity exchange revenues with the market premium and fully mitigates market value risk through December 31, 2026. The profile factor for solar market value has fallen to around 50% in 2025, necessitating revenue strategies beyond pure spot market sales. Note: If you are planning your own commercial system, you should first consider the self-consumption option—our analysis of the declining feed-in tariff in 2026.
Table of Contents
What Direct Marketing Means Legally in 2026
Direct marketing refers to the sale of PV electricity from EEG-compliant systems to third parties—typically a direct marketing company that sells the solar power on the EPEX Spot electricity exchange—rather than having it purchased by the grid operator in exchange for a fixed feed-in tariff. For PV systems over 100 kWp, subsidized direct marketing has been mandatory since 2014. This threshold continues to apply even after the Solarspitzengesetz.
The legal definition is set forth in Section 3(16) of the Renewable Energy Sources Act (EEG 2023). The Renewable Energy Act distinguishes between four forms of sale to which every PV system operator must assign their generation facilities—market premium, feed-in tariff, tenant electricity surcharge, or other direct marketing (Section 21b EEG). Changes 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.
Three forms of marketing are relevant for investors and companies. Subsidized direct marketing (market premium model, Section 20 of the EEG) combines electricity exchange revenues with a market premium as a safety net and is the standard for photovoltaic systems subject to tenders as well as commercial PV projects eligible for EEG feed-in tariffs. Other forms of direct marketing (Section 21a EEG) forgo any EEG subsidies but allow for the marketing of certificates of origin—the contractual basis for systems over 20 kW that have outgrown EEG subsidies and electricity supply models without EEG entitlement. The tenant electricity model ties electricity geographically to a building or neighborhood and is rarely the path taken for traditional commercial photovoltaics in practice.
Correction regarding the 25-kWp discussion
The original draft of the Solar Peak Act (October 2024) provided for a reduction of the direct marketing 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). As of April 2026, the following therefore remains in effect: mandatory subsidized direct marketing for PV systems with an installed capacity of over 100 kW. The detailed table of the current EEG feed-in tariff and the discussion regarding the possible reintroduction of the threshold can be found in our EEG Feed-in Tariff 2026 Guide.
Remote controllability pursuant to Section 10b of the Renewable Energy Sources Act (EEG)
Section 10b of the EEG requires operators of generation facilities with a capacity exceeding 25 kW to retrieve actual feed-in data in real time and to remotely reduce output. Compliance via the smart meter gateway will not be mandatory until January 1, 2028—until then, alternative transmission methods (data loggers with modems) are permitted. The additional effort required will therefore remain manageable until then.
Market values for 2025 and Q1 2026 in detail
The annual market value for solar power in 2025 was 4.508 ct/kWh—compared to 4.624 ct/kWh in 2024. Monthly values fluctuated between 1.843 ct/kWh (June 2025) and 11.511 ct/kWh (January 2025). In January 2026, the market value rose again to 11.019 ct/kWh, and in March 2026, it fell to 5.455 ct/kWh.
The solar market value is published monthly by the transmission system operators on netztransparenz.de. It is calculated by weighting the generation-weighted average of all day-ahead hourly prices on the electricity exchange by the nationwide solar power generation volume. The volatility of these prices in 2025 was historically unprecedented and directly influences the calculation of the market premium for all EEG-eligible plants.
| Month | Market Value of Solar | Day-Ahead Electricity Market | Profile factor |
|---|---|---|---|
| January 2025 | 11,511 | 12,463 | 0,924 |
| February 2025 | 11,099 | 12,847 | 0,864 |
| March 2025 | 5,027 | 9,473 | 0,531 |
| April 2025 | 3,041 | 7,794 | 0,390 |
| May 2025 (lowest value) | 1,997 | 6,734 | 0,297 |
| June 2025 | 1,843 | 6,399 | 0,288 |
| July 2025 | 5,923 | 8,780 | 0,675 |
| August 2025 | 3,832 | 7,699 | 0,498 |
| September 2025 | 4,307 | 8,351 | 0,516 |
| October 2025 | 7,150 | 8,440 | 0,847 |
| November 2025 | 9,102 | 10,188 | 0,893 |
| December 2025 | 9,373 | 9,347 | 1,003 |
| January 2026 | 11,019 | 11,009 | 1,001 |
| February 2026 | 7,717 | 9,658 | 0,799 |
| March 2026 | 5,455 | 9,929 | 0,549 |
| Source: Netztransparenz.de · DGS Sonnenenergie · Solarserver. Profile factor = market value of solar divided by the day-ahead average on the electricity exchange (also referred to as the capture rate in international discussions). | |||
Volume-weighted annual market price for solar power in 2025: 4.508 ct/kWh — the second-lowest figure since the market premium model was introduced in 2012.
Historical Comparison of the Solar Profile Factor
The profile factor (market value of solar divided by the electricity exchange baseload price) has fallen from 0.84 (2023) to 0.505 (2025) over the course of two years. By 2025, solar power was worth only half as much as the average electricity exchange price—this trend is the key context for every investment decision in 2026. The average spot market baseload price in 2025, at 8.932 cents per kWh, was significantly higher than the market value of solar; the most visible driver of this effect is negative electricity prices, which reached a historic record of 573 hours in Germany in 2025. Our separate guide on negative electricity prices for PV investors provides an in-depth look at the specific opportunities for revenue that arise from this, how the Solar Peak Act responds with the zero-remuneration rule, and the mechanics behind it.
How the market premium is calculated in practice
The market premium is the EEG bridge that absorbs market value risk. It is calculated in accordance with Annex 1 to Section 23a of the EEG as the difference between the applicable value and the energy source-specific market value. If the market value is higher than the applicable value, the premium is capped at zero—it never becomes negative. The payment is made by the grid operator.
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 articles that additionally calculate “+0.4 cents per kWh on top” are incorrect for new systems.
Example 1: Low market value (May 2025)
A 100-kWp rooftop system with a reference value of 7.50 ct/kWh will generate a market premium of 5.503 ct/kWh in May 2025, assuming a monthly market value of 1.997 ct/kWh. Effective gross revenue per kilowatt-hour: 7.50 ct; after deducting the direct marketing fee of typically 0.15 ct/kWh, the net amount is approximately 7.35 ct/kWh. The market premium protects the operator from a slump in the electricity exchange and secures their income.
Example 2: High market value (January 2025)
Using the same reference value of 7.50 ct/kWh and a solar market value of 11.511 ct/kWh, the calculated market premium would be negative. It is not paid out—the operator retains the full market price from spot sales. Effective revenue: approximately 11.30 ct/kWh net, nearly 4 ct/kWh above the fixed feed-in tariff. It is precisely during these winter months that subsidized direct marketing demonstrates its economic advantage over the fixed feed-in tariff.
Example 3: 2025 Open Space Tender
The volume-weighted winning bid prices for photovoltaic systems from the BNetzA solar ground-mounted tenders were 4.76 ct/kWh in December 2024, 4.84 ct/kWh in July 2025, and 5.00 ct/kWh in December 2025. The maximum value for the March 1, 2026, date was set by the BNetzA at 5.79 ct/kWh. The market premium bridges the gap between electricity exchange revenue and the bid price—even in a year with a solar market value of 4 ct/kWh, the plant operator’s revenue is guaranteed.
The exact rates applicable to the various plant segments can be found in the complete 2026 EEG feed-in tariff table. Here, we focus on the market mechanism—that is, how the market premium economically hedges spot market revenue.
Revenue Scenarios: Full Feed-in and Comparison of Marketing Models
For a 1-MWp ground-mounted renewable energy plant, net revenue from subsidized direct marketing is approximately €47,000–48,000 per year. The marketing model itself—market value model (monthly average) versus pay-as-produced (actual spot prices)—can further shift the net revenue by €1,000–3,000 per year, depending on the profile factor and generation hours.
Scenario A — 1 MWp ground-mounted system, market value model
With a specific yield of 1,050 kWh/kWp/year, the system produces 1.05 GWh. Applying a rate of 5.00 ct/kWh (BNetzA surcharge as of December 2025) results in gross revenue of €52,500/year. With a direct marketer fee of 0.15 ct/kWh (€1,575/year) and an estimated revenue loss due to negative price hours of 5–8% (approximately €3,000–4,000/year), a net revenue of about €47,000–48,000 per year, corresponding to 4.5–4.6 ct/kWh effective. The market premium protects this calculation from the downside: Even in a year with a solar market value of 3.5 ct/kWh, the revenue from the spot market plus the market premium would guarantee the required return.
Scenario B — 1 MWp ground-mounted system, pay-as-you-go (15-minute spot price)
The same 1-MWp plant, same location, same applicable value—but remuneration based on the actual 15-minute spot price profile since the EU reform of September 30, 2025. The plant earns its specific hourly price instead of the monthly average. With a solar profile factor of 0.505 (2025), the direct spot market average per hour of sunshine is typically 4–8% below the monthly average—the gross revenue before the market premium decreases accordingly by approximately €2,000–4,000 per year. The market premium offsets this effect, provided the annual market value remains below the applicable value. On a net basis, the model for pure PV systems without storage is usually 0.5–1.5 ct/kWh weaker than the market value model—Pay-as-Produced becomes relevant when the system can respond flexibly (e.g., with connected storage, whose optimization logic is covered in the NEGS guidelines).
| Position | A: Market Value Model (Monthly Average) | B: Pay-as-Produced (15-minute spot price) |
|---|---|---|
| Net income | 1,050 kWh/kWp | 1,050 kWh/kWp |
| Annual yield | 1,050,000 kWh | 1,050,000 kWh |
| Value to be entered | 5.00 cents per kWh | 5.00 cents per kWh |
| Gross revenue | 52.500 € | 52.500 € |
| DVD rental fee | −€1,575 (0.15 ct/kWh) | −€2,100 (0.20 ct/kWh) |
| Loss due to negative hours | €3,000 to €4,000 | €4,000 to €5,500 (profile risk) |
| Reporting burden | low | higher (15-minute data flow) |
| Net proceeds per year | approx. €47,000–€48,000 | approx. €44,500–€46,500 |
| Assumptions: BNetzA surcharge as of December 2025, data processing fee 0.15 vs. 0.20 ct/kWh, solar profile factor for 2025: 0.505. Model calculation — no guarantee of return. | ||
The bottom line: For systems that feed all their PV generation into the grid, the market-value model is the more stable and profitable option for most plant operators. Pay-as-Produced is only worthwhile if the system can actively respond to the 15-minute pricing structure via storage or a PPA tranche. For commercial operators who want to prioritize self-consumption—often a more significant economic factor than the choice of marketing model—our separate analysis on the declining feed-in tariff in 2026 provides a comprehensive comparisonof self-consumption versus feed-in tariffs.
Four Revenue Strategies to Combat Depreciation
The structural decline in the value of solar power is forcing investors and utility operators to actively optimize their revenue streams. Four strategies will dominate in 2026: revenue from storage, long-term power purchase agreements, optimization of self-consumption, and a hybrid marketing portfolio. These strategies differ in terms of complexity and their diversification effects.
Strategy 1: Storage-based revenue optimization. Co-located storage systems shift solar power from the midday trough to higher-priced hours and can significantly increase the effective market value of a PV system. Our guide to PV storage arbitrage and negative electricity prices explains exactly which revenue streams a battery storage system will tap into by 2026—day-ahead arbitrage, balancing energy, instantaneous reserve, and intraday—and how this results in an increase in IRR compared to pure PV marketing.
Strategy 2: Long-term power purchase agreements (PPAs). Power purchase agreements guarantee PV system operators a fixed purchase price for 10–20 years and decouple revenue from the market price on the exchange. They are the most important hedging strategy for institutional investors in light of the expiration of the market premium on December 31, 2026. Our overview of solar power without equity capital covers the various contract types and current price bands. Relevant for subsidized direct marketing: A PPA cannot replace the market premium—but it can replace the spot market share and pass the profile risk on to a buyer.
Strategy 3: Direct marketing of surplus electricity alongside self-consumption. For commercial operators with their own photovoltaic systems, it is not direct marketing itself but direct self-consumption that provides the dominant source of revenue. The surplus electricity is sold through direct marketing—technically, this can be retrofitted to any existing system via RLM metering and a direct marketing contract; even older solar systems can be equipped accordingly. The self-consumption rate is economically crucial; our analysis of the declining feed-in tariff in 2026 addresses its optimization and the choice between full and partial feed-in in detail. In a direct marketing setup, the system should be sized so that the residual electricity share per kilowatt-hour justifies an appropriate remuneration model—a flat-rate model for smaller residual electricity volumes, and a market-value or fixed-price hybrid for larger solar systems.
Strategy 4: Hybrid Marketing Portfolio. A typical allocation for institutional solar portfolio investments combines subsidized direct marketing via the market premium with a portion of PPAs and a variable portion of spot market sales. This diversification mitigates both market value risk and the political risk associated with the 2027 EEG reform. A typical ratio: approximately half is hedged long-term, with the remainder being variable and offering upside potential.
| Strategy | Main effect | Suitability for | Complexity |
|---|---|---|---|
| Storage Co-location | shifts revenue to peak hours | Investors with a capacity of 1 MWp or more (see NEGS guidelines) | 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 | Commercial (for personal use, see the Owner article) | low |
| Hybrid portfolio | Risk diversification | Medium- to large-scale projects | medium |
| These strategies can be combined. Model assumptions do not guarantee success. | |||
Which direct marketer is a good fit for which profile?
The German direct marketing market for renewable energy PV systems underwent significant consolidation between 2024 and 2026. The five largest providers collectively hold a marketing portfolio of over 40 GW. Quadra Energy (TotalEnergies) and EnBW lead the market, while Next Kraftwerke (Shell) is the market leader in the PV segment.
Top 5 Direct Marketers at a Glance
| Rank | Direct seller | parent company | Portfolio (MW) | Focus |
|---|---|---|---|---|
| 1 | Quadra Energy | TotalEnergies | 10.100 | Wind, +300 MW of solar capacity |
| 2 | EnBW | State of Baden-Württemberg / OEW | 9.900 | 4,700 MW of solar power |
| 3 | Next Power Plants | Shell plc | 8.020 | Market leader: 6,639 MW of solar power |
| 4 | Statkraft Markets | Statkraft AS | 6.800 | long-term purchase agreements |
| 5 | Danske Commodities | Equinor ASA | 6.400 | Pay-as-Forecasted |
| Sources: ZfK Direct Marketing Survey, February 2026; Energy & Management Industry Survey, as of January 1, 2026. Other relevant providers: BKW, MVV Trading, RWE, Energy2market, Trianel. | ||||
Compensation Models and Fees
Suppliers typically bill according to three models—the market value model (monthly average minus a fee), the day-ahead model (15-minute spot prices from the exchange, effective September 30, 2025), and the fixed-price hybrid with a minimum price range. For capacities above 1 MWp, fees typically range from 0.1–0.3 ct/kWh; for capacities below 1 MWp, flat rates of €40–80/month plus approximately €200 for setup are common. The fee amount is negotiable and depends on the portfolio of installations.
Selection criteria beyond price
What really matters: the provider’s creditworthiness (revenue is received with a time lag), the size of the balancing group (which improves forecast accuracy), and expertise in negotiating power purchase agreements—the latter becomes increasingly important as the expiration of the market premium on December 31, 2026, draws nearer.
Compensation for Losses in the Event of the Direct Marketer's Insolvency
The waves of insolvencies in 2017 (CLENS) and 2021 (Lition Energie, in.power, Otima) have shown that even established providers can default—Section 21(1), sentence 1, no. 3 of the Renewable Energy Act (EEG) provides for default compensation of 80% of the applicable value in such cases, for a maximum of six months per year.
Changes to and Phase-out of the Market Premium in 2026/2027
You can switch providers at any time within the same type of sale, effective on the first day of the month (Section 21b(4)(1) of the Renewable Energy Act). Including the notice period, the process typically takes 4–6 weeks plus a 3-month lead time. The state aid approval for the current market premium expires on December 31, 2026—those who go into operation in 2026 will secure the current system for 20 years.
The transition process in practice
In practice, the new direct marketer handles the registration with the distribution network operator—system operators need only terminate the existing contract within the required notice period (typically 3 months), issue a power of attorney, and provide the system data (MaStR number, market location ID, commissioning report, and proof of remote controllability pursuant to Section 10b of the EEG). The formal registration must be completed before the start of the month following the planned switch date (Section 21c(1) EEG).
What will change starting in 2027
The current market premium will remain in place as a core instrument, but will be restructured into a symmetric contract for difference. Our separate guide on the 2027 CfD requirement for PV investors covers the regulatory details outlined in the EEG 2027 working draft and how grandfathering provisions will apply to systems commissioned by the end of 2026. At the same time, the EU electricity market reform—Regulation (EU) 2024/1747—is already directly applicable in Germany; among other things, it brought into effect the 15-minute day-ahead settlement on the electricity exchange as of September 30, 2025.
What investors and operators need to decide now for 2026
Anyone investing in photovoltaics in 2026 should view direct marketing as one component of their revenue portfolio—not as the sole solution. Projects that rely solely on full feed-in without storage or hedging carry a growing market value risk. The choice between the market value model and pay-as-produced, as well as the creditworthiness of the direct marketer, will become key decision-making factors in 2026.
According to the Market Master Data Register, installed PV capacity in Germany reached 117.737 GW on January 26, 2026—an increase of 17.1% over the previous year. The expansion of renewable generation capacity continues to accelerate: Under a BMWE pathway with 22 GW of annual net additions through 2026 and 215 GW through 2030, a further reduction in the profile factor to 0.40–0.45 by 2030 is likely, unless storage and sector coupling counteract this trend.
Consequences for business operators with existing facilities
Before making any decision regarding direct marketing, the self-consumption option should be evaluated—our analysis of the declining feed-in tariff in 2026 provides a cost-benefit comparison between self-consumption and the feed-in tariff. Only then does the selection of the direct marketer and the compensation model for the remaining electricity become decisive: market value model for stable full-feed-in systems, pay-as-produced, or fixed-price hybrid for systems with storage or PPA connections.
Implications for investors in PV systems
Now is the perfect time to get started: Today’s market premium structure provides a safety net for 20 years, and all options for storage revenue or PPA hedging remain open. You can find a comprehensive economic analysis—including return structures, tax leverage, and specific investment scenarios for investments starting at €100,000—on our PV Investment Pillar.
Logic Energy develops PV systems through active site acquisition and secured financing prior to construction—the contracting partner is mediplan Helm e.K., a partnership with personal liability. If you are planning a direct-marketing-capable photovoltaic system for 2026 or wish to restructure an existing system, we will assess your site and model suitable revenue scenarios based on market premiums, self-consumption, and hedging. Feel free to contact our team for a no-obligation consultation.
This article is intended solely for general informational purposes and does not constitute investment, tax, or legal advice. Market values and revenue figures are based on historical or currently available data and are not a guarantee of future results. Market premium levels and EEG feed-in tariffs are subject to ongoing changes—particularly due to the upcoming EEG reform in 2027. For your specific situation, please consult a licensed financial, tax, or legal advisor. All information is provided without warranty. As of April 2026.
FAQ
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Direct marketing refers to the sale of PV electricity to third parties (typically a direct marketing company) rather than its purchase by the grid operator in exchange for a fixed remuneration. The legal basis for this is Section 3(16) of the EEG 2023; the solar power is traded on the EPEX Spot electricity exchange and financially secured through the market premium (Section 20 EEG). There are three types of direct marketing: subsidized, other, and tenant electricity.
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As of April 2026, this requirement continues to apply to subsidized photovoltaic systems with an installed capacity of over 100 kW. The reduction to 25 kWp provided for in the original draft of the Solar Peak Act was removed in the final version (Federal Law Gazette 2025 I No. 51 of February 21, 2025). For PV systems under 100 kWp, direct marketing is voluntary.
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The annual market price for solar power in 2025 was 4.508 ct/kWh (Netztransparenz.de). Monthly prices in 2025 ranged from 1.843 ct/kWh (June) to 11.511 ct/kWh (January). In March 2026, the figure reached 5.455 ct/kWh; in February 2026, 7.717 ct/kWh; and in January 2026, 11.019 ct/kWh.
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In the case of subsidized direct marketing, the grid operator pays a market premium (§ 20 EEG) in addition to the proceeds from the electricity exchange; the prohibition on dual marketing applies, meaning that certificates of origin may not be sold separately. Other forms of direct marketing (Section 21a EEG) do not receive any EEG subsidies but allow for additional HKN marketing—relevant for systems over 20 kW and electricity supply models without EEG eligibility.
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Direct sellers typically charge 0.1–0.3 ct/kWh or 1.5–4.5% of revenue for systems larger than 1 MWp. For smaller PV systems (100 kWp–1 MW), flat rates of €40–80/month plus a one-time setup fee of around €200 are common. Added to this are costs for remote control technology under Section 10b of the Renewable Energy Act (EEG) (one-time fee of €1,500–3,000).
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The state aid approval for the current market premium expires on December 31, 2026. The EEG 2027 will retain the market premium as a core instrument but will restructure it into a symmetric difference contract. Those who begin operations in 2026 will secure the current structure for 20 years.
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Within the same type of sales arrangement, this is possible at any time on the first day of the month (Section 21b(4)(1) of the Renewable Energy Act (EEG)). Industry practice: The new direct marketer must register with the grid operator 10–15 business days before the planned switch date. Required: termination of the old contract (typically with a 3-month notice period), power of attorney for the new provider, MaStR data, and proof of remote control capability.
10. Sources
Netztransparenz.de — Solar Market Value Overview (Annual and Monthly Figures for 2020–2026)
DGS — Annual Solar Market Value for 2025 and Monthly Solar Market Value for January 2026
Federal Network Agency — EEG Subsidies and Subsidy Rates for 2026 and Maximum Levels for 2026 Press Release, December 16, 2025
Laws on the Internet — Section 20 of the EEG 2023, Section 21b of the EEG 2023, Section 10b of the EEG 2023
EPEX Spot / Energy-Charts.info — Day-Ahead Spot Market Prices 2025
BSW-Solar — Feed-in Tariff Table for Q1 2026 and FAQs on the Solar Peak Act
BDEW — Electricity Price Analysis 10/2025 (Commercial Electricity Prices)
Solar Peak Act — Federal Law Gazette 2025 I No. 51, dated February 21, 2025
ZfK Direct Marketing Survey, February 2026 / Energy & Management Industry Survey, as of January 1, 2026
