Negative Electricity Prices and Solar Power: What Investors Really Need to Know in 2026
Excerpt
Negative electricity prices are no longer a rare occurrence: In 2025, Germany set a new record with 573 hours of negative electricity prices—and on some summer days, nearly all solar power generation was fed into the electricity exchange at negative prices. PV investors who understand the cause of this phenomenon, why the Solar Peak Act has changed the rules of the game, and which storage strategy unlocks the opportunity behind it have a clear advantage.
-
Negative electricity prices occur when the supply of electricity exceeds demand to such an extent that the electricity exchange pushes the price below zero—especially at midday on sunny weekends. In 2025, Germany experienced 573 hours of negative electricity prices, a record. The Solar Peak Act (effective February 25, 2025) immediately set the feed-in tariff to zero during periods of negative prices under the new regulation in Section 51 of the Renewable Energy Act (EEG)—but at the same time introduced a compensation mechanism. For plant operators and investors with a battery storage strategy, the solutions are clear: charge during hours with negative prices instead of feeding into the grid, and sell at a profit in the evening. This article provides the big picture; details on the law and arbitrage can be found in the linked cluster articles.
What are negative electricity prices?
Negative electricity prices occur when the supply of electricity exceeds demand and the price on the exchange falls below zero. Electricity producers are then willing to pay to have their energy purchased. On the electricity exchange (EPEX Spot), the day-ahead price falls below zero euros—the value of electricity in the grid is literally negative. For PV systems under the EEG, this means: feed-in tariffs do not apply during these hours.
How the mechanism works
The electricity market operates on the principle of supply and demand. When sunny weekends, holidays, and windy nights coincide, solar power plants, wind turbines, and conventional power plants all feed large amounts of electricity into the grid at the same time—while industry and commerce consume very little electricity. Electricity supply exceeds demand—resulting in a surplus in the power system.
In a well-functioning market, power plants would simply shut down. The problem is that many conventional power generators (nuclear, lignite, but also biomass and combined heat and power plants) cannot be ramped down quickly enough. They continue to produce electricity—and grid operators must find a way to offload this excess power to keep the grid stable.
The result is a negative market price. Electricity producers literally pay for consumers to take their electricity—for example, aluminum smelters, pumped-storage power plants, or foreign grids that import the surplus.
What "negative" actually means
On European electricity exchanges—primarily EPEX Spot—electricity is traded on the day-ahead market: buyers and sellers agree the day before on the volume and price for each hour of the following day. Since October 2025, trading has even taken place in quarter-hourly contracts.
Negative electricity prices are not a new phenomenon: they were first observed in Germany in 2008—at that time still a rare occurrence on days with particularly high wind and solar generation. Today, they are a regular feature of the electricity market.
A negative day-ahead price means that the spot market price is below €0/MWh
The lowest price in 2025: −€250.32/MWh on May 11, 2025 — Generators paid 25 cents per kilowatt-hour fed into the grid
For PV systems under the EEG market premium model, remuneration is not paid when prices are negative in accordance with Section 51 of the EEG —the market premium is set to zero
During these hours when electricity prices are negative, plant operators receive no revenue from feeding electricity into the grid
How often do they occur? The 2021–2025 time series
The number of hours with negative electricity prices in Germany has more than quadrupled, rising from 139 hours (2021) to 573 hours (2025). The main driver is the massive expansion of solar power: with 117 GW of installed capacity by the end of 2025, solar power generation at midday will consistently exceed the electricity market’s capacity to absorb it.
Trend in hours with negative electricity prices (EPEX Spot Day-Ahead)
The following overview shows how significantly the number of hours with negative electricity prices has increased in recent years:
2021: 139 hours
2022: 69 hours (One-time factor: energy crisis, high spot prices due to gas shortages)
2023: 301 hours
2024: 457 hours
2025: 573 hours — New record
⚠️ Data is based on EPEX Spot day-ahead prices. Sources: BHKW-Infozentrum, energiezukunft.eu / naturstrom. As of March 2026.
The year 2022 was an exception: the energy crisis drove spot prices up so sharply that even during periods of surplus, prices rarely fell below zero. Since 2023, the trend has been clearly upward—and it is structural in nature, not a random fluctuation.
Why the increase is structural: the boom in renewable energy
The expansion of renewable energy explains it all: By the end of 2025, 117 GW of photovoltaic capacity had been installed in Germany (Federal Network Agency, January 2026)—about 17 GW more than at the end of 2024. On a sunny afternoon in May, this electricity generation can temporarily feed more power into the grid than the entire German grid can handle.
Key figures on PV expansion by 2025:
Installed PV capacity in Germany by the end of 2025: 117 GW (Federal Network Agency)
PV capacity expansion by 2025: approx. 16.4–17.6 GW, depending on the source (Federal Network Agency / BSW-Solar)
Share of solar power in net electricity generation in 2025: approx. 16–17%
A historic first: In 2025, solar power will surpass lignite for the first time in terms of net electricity generation (71 TWh vs. 67 TWh)
The Forecasting Problem
There are no official forecasts for 2026 that include specific numbers of hours. Extrapolations from market analyses suggest 700–900 hours of negative electricity prices —depending on how quickly large-scale storage systems and flexible loads are integrated into the grid and how the volume of renewable energy fed into the grid develops. A reversal of this trend in the electricity system is not expected without significant expansion of storage and grid infrastructure.
📊 Trend in negative price hours, 2021–2025
Hours with negative electricity spot prices (EPEX Spot Day-Ahead) · Source: BHKW-Infozentrum / energiezukunft.eu
Why negative electricity prices hit solar power systems particularly hard
PV systems generate electricity precisely when the grid is at its fullest: at midday, in the summer, and on weekends. This systematic mismatch between electricity generation and consumption—which experts refer to as the “midday problem” or “duck curve”—means that a growing share of annual PV production occurs during periods when market prices are negative or very low. This directly impacts the revenue of system operators.
The structural midday problem: Renewable energy plants racing against the clock
Photovoltaic systems generate the most electricity when the sun is at its highest point—that is, between 10 a.m. and 3 p.m. It is precisely during this time window that electricity demand in Germany is structurally low: while offices and factories are operating, electricity consumption is predictable and limited. Furthermore, weekends and holidays significantly reduce industrial demand even further—the total renewable energy feed-in then meets with particularly low demand.
The result is known as the "Duck Curve" —the daily load profile of the residual load (the load remaining after subtracting the feed-in from all renewable energy plants) follows a duck-like pattern: the peaks (morning and evening) remain high, while the trough (midday) drops sharply. The more PV capacity is added, the lower the duck’s belly becomes—and the more frequently electricity prices slip into negative territory.
The numbers behind the lunch problem
The impact on PV investors and plant operators is measurable and tangible:
16% of Germany’s total solar power in 2025 was generated during hours when electricity prices were negative (pv magazine, January 26, 2026; data source: ENTSO-E)
Pentecost Sunday 2025 (June 8): On a single day, 89% of total daily PV generation was fed into the grid at negative prices
June 2025: 46% of total monthly PV generation occurred during hours with negative electricity prices
May 2025: 43% of monthly PV generation occurs during hours with negative electricity prices
Lowest market price for solar power in May 2025: Just 1.997 ct/kWh — a historic low on the electricity exchange
These are no longer outliers. This is the new reality of an electricity market with 117 GW of installed PV capacity.
Who is affected, and to what extent?
Not all solar power systems are affected to the same extent. The orientation and system configuration play a decisive role in determining revenue trends:
Most affected:
South-facing ground-mounted solar farms with optimal midday output
Fixed installations without a tracking system: in 2025, approximately 27% of annual production occurred during hours with negative prices
Systems with a tracking system: approximately 23%
Less affected:
East-west-facing rooftop systems (higher output in the morning and evening, lower peak output at midday)
Systems with a high proportion of self-consumption (generated electricity is used directly, with no connection to the power exchange)
Systems with integrated battery storage (decoupling of generation and sales)
For more information on revenue strategies and how co-located storage systems are turning the situation around, read our article “Battery Storage as a PV Investment Opportunity: Arbitrage, Revenue, and Strategy” →
Note to investors: Without a clear strategy to address negative prices, they can significantly reduce the return on a solar project—and thus make it more difficult to decide on new investments. That is precisely why choosing the right system configuration and marketing model is more important today than ever before.
What changes when prices turn negative? An overview of the Solar Peak Act
The Solar Peak Act has been in effect since February 25, 2025, and has fundamentally tightened Section 51 of the EEG 2023: New PV systems with a capacity of 2 kWp or more will immediately lose their EEG feed-in tariff whenever the quarter-hourly price is negative—the previous hourly rule with multiple buffer periods no longer applies. At the same time, Section 51a of the EEG establishes a compensation mechanism that defers the lost feed-in tariff.
The "hours" rule in the EEG: a brief overview
From the 6-hour rule to the quarter-hour rule
Since the introduction of the EEG (Renewable Energy Sources Act), PV systems have been subject to the so-called zero-remuneration rule in the event of negative prices—an incentive to disconnect renewable energy systems from the grid during periods of oversupply. The key question has always been: At what number of negative hours does this rule take effect?
The threshold for this hourly rule has been gradually lowered over the years:
EEG 2014: Payment was withheld only after 6 consecutive hours of negative output—the famous 6-hour rule (also known as the six-hour rule)
EEG 2021: Threshold lowered to 4 hours
EEG 2023: Initially 3 hours, planned to be 1 hour starting in 2027 — and even then, only for systems with a capacity of 400 kW or more
Small rooftop systems were effectively unaffected by this regulation. For a long time, the 6-hour rule ensured that brief price dips had no impact on feed-in tariffs—but this buffer has been completely eliminated for new installations as of February 25, 2025.
What the Solar Peak Act Changes for New PV Systems Starting February 25, 2025
The law—officially titled "Act Amending Energy Industry Law to Prevent Temporary Surpluses in Electricity Generation"—was published in the Federal Law Gazette on February 24, 2025 (BGBl. 2025 I No. 51) and entered into force the following day.
Key changes for new PV systems (commissioning on or after February 25, 2025):
Pay drops to zero immediately for every single negative quarter-hour — no more overtime buffer time
Threshold significantly lowered: now applies to systems starting at 2 kWp (previously 400 kW)
Systems under 2 kW: still exempt
Systems between 2 and 100 kW: Zero remuneration for feed-in applies only after a smart meter has been installed (transitional protection—the prerequisite is the installation of a smart meter)
Systems over 100 kW: effective immediately as of February 25, 2025; no transition period
Mandatory smart meters as a temporary solution for smaller systems
For PV systems between 2 and 100 kWp, the following applies: The new zero-remuneration rule for negative prices only takes effect once a smart meter has been installed. As long as no smart meter is in place, the transitional protection remains in effect—the system will continue to be remunerated according to the old rules. However, with the mandatory smart meter rollout (required for grid operators starting in 2025/2026, phased in based on consumption), this transition period is expected to come to an end. Anyone planning a new PV system in this capacity range today should factor in the smart meter requirement from the very beginning.
For existing systems (commissioned before February 25, 2025):
Grandfathering: The old rules remain in effect
Opt-in available: Customers who voluntarily switch to the new system will receive a 0.6-cent-per-kWh premium as compensation
The Compensation Mechanism (Section 51a of the EEG) — A Brief Overview
Without countermeasures, the Solar Peak Act would have undermined the economic viability of many systems—system operators would have suffered permanent revenue losses without receiving any compensation. For this reason, the legislature simultaneously introduced a compensation mechanism in Section 51a of the EEG:
The 20-year EEG subsidy period will be extended by the number of hours lost due to negative prices
For PV, a factor of 0.5 applies: each quarter-hour of downtime counts as only half toward the extension
The extended funding will be distributed on a monthly basis over the period following the regular end of the funding period
In practical terms, this means that a system that has not generated any revenue in 573 hours of negative electricity prices by 2025 will receive approximately 1–2 years of additional subsidies at the end of its operational life.
For a detailed analysis of how the compensation mechanism works and what it means for your specific system, see our cluster article: The Solar Peak Act and Section 51a of the EEG: What PV Investors Need to Know →
Negative Electricity Prices as an Investment Opportunity: Storage and Arbitrage
Those who operate a PV system without storage lose out on revenue when prices are negative. Energy storage systems are the key to storing excess electricity during periods of negative prices, thereby avoiding lost revenue. Those who integrate a battery storage system can take advantage of precisely this moment: charging electricity for free during the midday lull and selling it in the evening at peak prices via the intraday or day-ahead market. According to current analyses, these price decoupling solutions increase the internal rate of return of solar parks by up to 29 percent.
From Risk to Return Opportunity
The logic behind this is simple: Negative electricity prices mean that electricity is physically available on the grid, but no one wants to buy it at that moment. On the electricity exchanges, a negative price signals: "Please take this electricity, or else the grid will become unstable." A battery storage system can absorb exactly this electricity—for free or even at a discount—and release it a few hours later when demand rises and the price turns positive again.
This is called arbitrage —and the greater the price difference between the midday low and the evening high, the more attractive this strategy becomes for operators of PV systems with storage. These price spreads can be systematically exploited in both the day-ahead market and the intraday market.
The economic implications of colocation storage
A white paper published in February 2026 by 8Energies, Enspired, and Goldbeck Solar examined the economic value of co-location projects for plant operators (PV systems and battery storage at the same site, connected to the grid together):
IRR uplift for new investments: up to +29% relative (example: from 7% to ~9% internal rate of return)
IRR uplift for existing plants: up to +24% relative
Basis: 20-MW PV plant with 10 MW / 20 MWh battery storage
⚠️ IRR uplift figure from the 8Energies/Enspired/Goldbeck Solar white paper (Feb. 2026). Project-specific results may vary. As of March 2026.
Why Battery Storage Can Do More Than Just Arbitrage
A co-located storage system taps into multiple revenue streams at once—which is the real reason why it is becoming indispensable for PV system operators today:
1. Arbitrage (exploiting price spreads): Buy electricity or charge your vehicle yourself when the price is negative, and sell when it turns positive again—both in the day-ahead market and the intraday market. The day-ahead spread in Germany rose by 89% from Q1 2024 to Q1 2025 (Gridcog analysis, 2026). Every hour with a negative price is potentially cash in the bank for a storage owner.
2. Optimizing direct sales by feeding electricity into the grid specifically during peak-price hours rather than during the midday lull significantly increases the effective spot market price achieved. This boosts revenue even when prices are negative. Read more in the article on direct sales of PV electricity →
2a. Power Purchase Agreements (PPAs) as a Hedge PPAs enable plant operators to sell electricity directly to commercial consumers at fixed prices—regardless of the daily market price. Those who lock in their electricity through a long-term PPA are largely protected against negative hourly prices, because the agreed-upon fixed price applies rather than the market price. For investors, this is an important complement to the storage arbitrage strategy, particularly in light of the CfD requirement starting in 2027, which mandates market-based remuneration models for new renewable energy plants anyway.
3. Balancing power and instantaneous reserve Storage systems can provide system services to grid operators—and be compensated for doing so, regardless of current electricity generation and consumption. This incentive makes storage systems economically viable even when arbitrage spreads are seasonally lower. For more details, see the article " PV System with Battery Storage" →
4. Protect EEG payments: If negative prices are imminent, the storage system charges rather than feeding power into the grid—thereby completely avoiding the loss of payments under Section 51 of the EEG.
The storage market is growing
The figures show that other investors have already recognized this opportunity. Battery storage is evolving from a niche product into a central component of the German power system—alongside wind and solar, one of the most important energy sources of the energy transition:
Installed battery storage capacity in Germany by the end of 2025: approx. 25.5 GWh (MaStR / BSW-Solar)
Growth in large-scale storage (> 1 MW) in 2025: +60% compared to 2024
Demand by 2030 according to Fraunhofer ISE: 100–170 GWh — four to six times the current level
This trend makes it clear that the market for flexible storage solutions to complement PV systems is still in its infancy.
To learn exactly how battery storage can be integrated into PV investments and what revenue streams are realistic, read our in-depth article: Negative Electricity Prices as an Investment Opportunity: Storage, Arbitrage, and Revenue Strategy →
What does this mean for your investment decision?
Against the backdrop of the transformation of the German electricity market, negative electricity prices are not a temporary problem—they are a permanent structural feature. For investors who understand this phenomenon and choose a PV system with an integrated storage strategy, it is not a risk, but rather a distinguishing feature compared to those who ignore it.
The 2026 regulatory window
The Solar Peak Act has been in effect for over a year now—and has clearly defined the regulations for new installations. At the same time, the new federal government confirmed in its 2025 coalition agreement the EEG expansion target of 215 GW by 2030, a goal that remains in place for good reason: renewable energies are the cornerstone of German energy policy through 2040.
This means: an additional 15–18 GW of renewable energy capacity per year through 2030—and, as a result, a continued increase in the number of hours with negative electricity prices, as long as storage systems and grids cannot keep up.
At the same time, the mandatory CfD requirement for larger renewable energy plants is on the political agenda for 2027—another regulatory step that is forcing investors to plan wisely now. Read more in the article “Mandatory CfD 2027: What PV Investors Need to Know Now” →
And the declining feed-in tariff in 2026 —currently 7.78 cents per kWh—highlights why investors who rely solely on the EEG base tariff are at a structural disadvantage.
Three Guidelines for Investors
1. Plan for storage from the very beginning. By 2026, a solar power system without storage will be one that systematically forgoes revenue. Co-located storage is no longer a premium option—it is an economic necessity for systems in direct marketing and for all system operators who do not want to simply accept hours with negative prices.
2. Choose the location and orientation based on the electricity price profile. South-facing systems that feed all their electricity into the grid face the biggest challenge at midday. East-west orientations, optimization of self-consumption, and flexible load management systems significantly mitigate this risk—because the electricity generated then coincides more often with periods when prices are positive.
3. Take Advantage of Regulatory Windows 2026 is the last full year before the 2027 CfD reform. Those who invest now do so under clearly defined conditions within the EEG framework—without the uncertainty that new tender models will bring.
Who benefits from negative prices—and who doesn't?
Negative electricity prices affect different market participants in very different ways. This classification helps to fully understand the phenomenon:
Electricity consumers with dynamic rates: Households and businesses with smart meters and a dynamic electricity rate (e.g., through providers like Tibber) can purchase electricity at particularly low prices—or even at negative net prices—during hours when prices are negative. On May 11, 2025, Tibber customers in Germany received −8.6 ct/kWh for the first time—they were paid for their electricity consumption. This is particularly attractive for households with high consumption due to electric vehicles or heat pumps, which can automatically shift their consumption to off-peak hours.
Section 14a of the Energy Industry Act (EnWG) — Taxable consumers with grid fee benefits: Since 2024, Section 14a of the Energy Industry Act (EnWG) has stipulated that operators of controllable consumers (e.g., heat pumps, wall boxes, home storage systems) receive reduced grid fees if they flexibly adjust their consumption during grid congestion. In combination with negative exchange prices and dynamic tariffs, this can significantly reduce electricity costs for these applications.
Electricity customers with fixed-rate plans: Households and businesses with traditional fixed-rate contracts are largely unaffected by negative market prices—taxes, grid fees, and surcharges keep the final price stable, regardless of what happens on the electricity market. Negative prices have no visible impact on them.
Solar panel owners without storage systems: During these hours, they lose their feed-in tariff but cannot take advantage of lower electricity prices or store power for later use. They bear the risk without receiving any compensation.
How Logic Energy Guides Investors Through This Topic
Logic Energy and mediplan Helm e.K. design and build solar power plants—from site acquisition to ongoing operation, all under one roof. The investor model provides for:
Investors purchase one or more inverters and receive the revenue they generate
Term: 20–40 years; the contracting party is mediplan Helm e.K., a sole proprietorship (e.K.)
Battery storage integration is a standard part of the planning process for all relevant ground-mounted and commercial projects
No development risk: Investors will not commit until a building permit has been issued
How the model works in detail: How the Logic Energy investor model works →
This article is intended solely for general informational purposes and does not constitute investment, tax, or legal advice. Return figures are based on historical data from the Helm Group and are not a guarantee of future results. For advice tailored to your individual situation, please consult a licensed advisor. All information is provided without warranty. As of March 2026.
Anyone investing in solar power today shouldn’t view negative electricity prices as a bogeyman—but rather as a market characteristic that distinguishes well-prepared plant operators from those who are ill-prepared. Learn more about solar power investment now →
Negative electricity prices aren’t going away in the coming years—they’re becoming more common. The reasons for this lie in the structure of the German electricity system: more solar, more wind, and less predictable baseload power—this inherently leads to fluctuations in electricity prices that directly impact plant operators without storage. PV investors who understand how the electricity market handles negative prices can not only avoid revenue losses—but also turn these very fluctuations into arbitrage profits. The solutions are available: battery storage, smart marketing in the intraday market, and the EEG compensation mechanism. Logic Energy and mediplan Helm e.K. guide investors through precisely this complexity: from site selection and the integration of battery storage to long-term operational management spanning 20–40 years. With personal owner liability, active land acquisition, and a contract that accounts for the 2026 market structure from the very beginning. Contact us—we’ll show you which projects are currently available and how negative electricity prices are consistently addressed in your return planning.
FAQ
-
Facilities commissioned before February 25, 2025, are grandfathered in and remain subject to the old provisions of the EEG—specifically, the 3-hour rule for facilities with a capacity of 400 kW or more. Smaller existing plants are generally not directly affected, as the previous hourly rule only took effect after several consecutive negative hours. A voluntary switch to the new system is possible for a premium of 0.6 ct/kWh.
-
Without storage: During hours with negative electricity prices, the EEG feed-in tariff for new systems does not apply—this represents a real loss of revenue for the system operator. With storage: Instead of feeding electricity into the grid, the system can store it and sell it later when prices are positive. In addition, Section 51a of the EEG extends the subsidy period as compensation. The economic impact depends heavily on the system configuration and the marketing model.
-
In 2025, there were 573 hours with negative electricity prices—equivalent to about 6.5% of all hours in the year. During the summer peak (May/June), as much as 43–46% of monthly PV production occurred during hours with negative prices. The forecast for 2026 indicates a range of 700–900 hours with negative prices, although no official institute forecast with a specific number of hours is available.
-
As a general rule, integrating a co-located storage system is economically viable for PV systems with a capacity of 100 kWp or more. For ground-mounted solar farms with a capacity of 1 MWp or more in the direct sales market, storage is effectively a must in order to remain competitive. For smaller rooftop systems, it depends heavily on the self-consumption profile and local grid conditions.
-
The Solar Peak Act has been in effect since February 25, 2025, and makes a key amendment to Section 51 of the EEG 2023: It primarily affects new PV systems of 2 kWp or more that were commissioned after that date. For systems between 2 and 100 kW, the requirement for immediate application is the installation of a smart meter. For these systems, the feed-in tariff drops immediately to zero when quarter-hourly prices are negative. Existing systems (commissioned before February 25, 2025) are subject to grandfathering provisions and may optionally switch to the new system.
-
The Duck Curve describes the typical pattern of residual load in the power grid throughout the day: it dips at midday (the belly of the duck) because PV systems are generating the maximum amount of electricity at that time, while electricity demand is low. These midday fluctuations between oversupply and evening demand increase with every gigawatt of new PV capacity added. The more PV is installed, the deeper this dip becomes—and the more frequently prices on the electricity exchanges slip into negative territory.
-
Yes—Spain serves as both a cautionary and an instructive example: In 2024, Spain had hardly any hours with negative electricity prices on the power exchanges; by 2025, that number had already risen to 556—nearly on par with Germany. The explosive expansion of all renewable energy sources from 9 GW (2020) to 32 GW of PV (2025) has fundamentally changed the market structure. Finland, on the other hand, shows that storage and load management can reduce the number of hours with negative prices despite the expansion of renewables—so the phenomenon of negative prices can be solved if the power system and power generation are considered together.
Sources
CHP Information Center — Negative Electricity Prices: Facts and Statistics (Complete Time Series 2015–2025), as of March 11, 2026
energiezukunft.eu / naturstrom — Electricity Exchange 2025: Extreme Price Fluctuations in the Electricity Market (573 hours in 2025), January 6, 2026
pv magazine (Marian Willuhn) — Photovoltaic generation during periods of negative electricity prices: 90 percent on some days, January 26, 2026
pv magazine — Federal Network Agency: 457 hours of negative electricity prices, January 3, 2025
pv magazine — PV to Surpass Lignite for the First Time in 2025, January 2, 2026
pv magazine — Solar Peak Act Published in the Federal Law Gazette, February 24, 2025
pv magazine — Co-location: IRR uplift of up to 29%, February 23, 2026
Solarserver / 8Energies White Paper — Co-location with Battery Storage, February 23, 2026
Grant Thornton — Economic Impact of the Solar Peak Act, 2025
Federal Network Agency — Press Release: EEG Statistics (117 GW of installed PV capacity by the end of 2025), January 8, 2026
Federal Law Gazette — BGBl. 2025 I No. 51, Solar Peak Act, February 24, 2025
Fraunhofer ISE — Current Facts About Photovoltaics in Germany, as of January 2026
BSW-Solar — Battery storage capacity increased fivefold, January 12, 2026
Gridcog — Duck Curve and Price Spreads in Europe, 2026
pv magazine — First-ever negative net electricity prices for end customers (Tibber −8.6 ct/kWh, May 11, 2025), May 12, 2025
Laws on the Internet / BMWK — Section 14a of the Energy Industry Act (EnWG): Controllable low-voltage consumer equipment
