Should You Buy an Existing Photovoltaic Plant or Build a New One? The 2026 Investor Comparison
Should you buy an existing plant or build a new one? It’s no longer possible to have both a high feed-in tariff and a long remaining term at the same time. The 2026 Investor Comparison, featuring a present value table, key considerations, and the current EEG rates.
The short answer
Anyone looking to buy an existing photovoltaic system in 2026 will be seeking a combination of a high historical feed-in tariff and a long remaining term. That combination no longer exists. A feed-in tariff of 35 cents indicates a system built in 2009 or 2010, meaning three to four years of remaining subsidies. A remaining term of eight years indicates a system built in 2014, which translates to a feed-in tariff of around 11 cents. The market does not provide current price statistics for this—prospective buyers will have to do the math themselves.
Should I buy an existing photovoltaic system or build a new one? The answer depends on two figures that are known precisely for each individual system: the feed-in tariff and the remaining subsidy period. Market averages and rules of thumb can be misleading. This article is intended for investors with at least 100,000 euros in equity and for businesses considering a system as a capital investment. A note on our own behalf: Logic Energy designs and builds new systems. The calculation methods and checkpoints in this article are disclosed so that you can verify the results yourself.
Who Buys an Existing Photovoltaic System — and Why
Buyers include institutional investors, family offices, and high-net-worth individuals. They want immediate cash flow, predictable returns, and no construction risk. The trade-off is a short remaining term, a portfolio with twelve to sixteen years of operation remaining, and a warranty against the builder that has long since expired.
First, three terms to define. An existing solar power plant is one that is already in operation; it is not newly constructed but is acquired from the previous operator. The secondary market is the market where such plants are traded. The remaining EEG term is the duration left on the legally guaranteed feed-in tariff; it does not restart when ownership changes.
The German portfolio now comprises approximately 127 gigawatts across more than six million units. The portion of this portfolio that is suitable as an investment opportunity stems primarily from the boom years of 2010 through 2014—plants that will have been connected to the grid for 12 to 16 years by August 2026. Trading takes place through specialized platforms, boutique M&A advisors, and special-purpose funds that consolidate vintage portfolios.
A note on how to classify these platforms: For some of them, the marketplace operator, project developer, proprietary trader, and payment processor are all part of the same corporate group. Anyone who buys through these platforms should be aware of whose interests the rating reflects.
A Market Without Price Tags
There are no publicly available, up-to-date price statistics for the German PV secondary market. The most recent survey was conducted in 2020; it is no longer accessible, and its author had already announced at the time that the data would be phased out. Anyone entering this market is buying without price transparency.
This gap can be identified in three areas. The Federal Network Agency tracks system commissioning and decommissioning, but not changes in ownership. The price monitor of the German Solar Industry Association covers only new systems up to 100 kilowatt-peak. And the overview of all German photovoltaic price indices in the trade magazine *pv magazine* includes a module price index, a PPA tracker, and the market value of solar—but no index for system transactions.
The frequently cited figure of 2,099 euros per kilowatt-peak comes from a survey conducted by the platform itself covering 482 transactions between January 2014 and July 2020. Three points are important to note when using this figure. First, it is an arithmetic mean for the years 2014 through 2019, not a snapshot. Second, the same survey showed a figure of just 1,569 euros for 2019 alone —25 percent below the six-year average. Third, the author explicitly predicted a turning point at which existing plants would, for the first time, fetch lower prices than new turnkey plants.
For an investor, this means that the market average is of no use as a guide. What matters is the present value of the specific investment.
The Spread: Compensation Rate vs. Remaining Term
For an existing plant, the purchase price is almost entirely the present value of the remaining EEG payments. Today, high historical feed-in tariffs and long remaining contract terms are mutually exclusive—which is precisely why the prices seen from 2014 to 2019 are no longer attainable. The following table provides a benchmark that allows you to evaluate any offer in just a few minutes.
The EEG pays the feed-in tariff for 20 years starting from the date of commissioning. For systems whose applicable value is determined by law—that is, the entire installed base from 2010 through 2014—the period is extended until December 31 of the twentieth year. For plants with a value determined through a competitive bidding process, the period runs to the day. As of the cutoff date of August 2026, plants commissioned up to and including 2005 will no longer receive payments; a plant commissioned in 2009 will continue to receive payments until the end of 2029.
What the remaining funding is worth
The following table shows the present value of the remaining EEG payments in euros per kilowatt-peak. Assumptions: Roof-mounted system with 900 kilowatt-hours per kilowatt-peak per year, operating costs of 21.5 euros per kilowatt-peak per year, and a nominal discount rate of 5.3 percent.
| Rate of compensation | 4 years remaining | 6 years remaining | 8 years remaining |
|---|---|---|---|
| 35.5 ct/kWh | 1.049 € | 1.498 € | 1.902 € |
| 30 cents/kWh | 875 € | 1.249 € | 1.587 € |
| 25 cents per kWh | 717 € | 1.023 € | 1.300 € |
| 20 cents/kWh | 558 € | 797 € | 1.012 € |
| 15 cents/kWh | 400 € | 571 € | 725 € |
| Own calculation. Discount rate and operating costs based on Fraunhofer ISE, Levelized Cost of Electricity for Renewable Energies, July 2024. Values are rounded and do not take degradation into account. | |||
The table is read diagonally, not column by column. A rate of 35 cents indicates commissioning around 2009 or 2010—that is, the column with a remaining term of four years. A remaining term of eight years indicates commissioning in 2014 and thus a rate of about 11 cents. The high values in the upper right corner can be calculated, but are not found on the market.
For ground-mounted systems, operating costs are lower at 13.3 euros per kilowatt-peak per year, and the present values are correspondingly slightly higher.
This was precisely the situation between 2014 and 2019: Systems installed during the years of high feed-in tariffs still had 14 to 18 years remaining on their terms at that time. As a result, 2,099 euros per kilowatt-peak was achievable. This overlap has come to an end—permanently, not cyclically.
Two figures from mandatory disclosures by a publicly traded operator illustrate the extent of the gap between old and new feed-in tariffs: an existing facility with a rate of 354.9 euros per megawatt-hour, compared to a solar farm set to begin operations in 2026 with a rate of 87 euros. The high rate for the existing plant indicates an early commissioning year—and thus a correspondingly short remaining term.
What Remains After Funding
Not much. The annual market value of solar power in 2025 was 4.508 cents per kilowatt-hour. From this, the deduction for systems no longer eligible for subsidies—which stood at 0.715 cents in 2025—is subtracted, leaving a net amount of 3.79 cents, before operating costs of just over two cents. For 2026, the deduction was lowered to 0.228 cents. The reason for this low level is the cannibalization effect: the solar capture rate fell from 58.2 percent in 2024 to 50.5 percent in 2025.
In terms of valuation, this means that—based on the actual value in 2025—the capitalized income value, discounted over the ten years following the end of the feed-in tariff, is worth only 65 to 80 euros per kilowatt-peak. For a plant with a high historical feed-in tariff rate, this represents just a few percent of the purchase price. Anyone valuing an existing plant using the argument that “it will keep running afterward” should be aware of this order of magnitude.
Revenue after the subsidy period ends depends entirely on the market price of electricity. In direct marketing, this means: revenue based on market value, minus marketing costs. The system still retains its value as a tangible asset—but one whose profitability declines significantly once the subsidy ends. The guide on systems after the end of EEG subsidies provides a more detailed look at what the market looks like after the subsidy period ends.
What a new investment will actually yield in 2026
Three separate regimes apply to new installations—a feed-in tariff up to 100 kilowatts, a sliding market premium up to 1,000 kilowatts, and a bidding process for capacities above that. There is no flat, fixed rate for installations under one megawatt. Anyone comparing offers needs to know which segment their installation falls into.
The feed-in tariff applies to capacities up to 100 kilowatts. For capacities above that and up to 1,000 kilowatts, the sliding market premium applies in direct marketing, with the amount determined by the applicable value. For capacities above 1,000 kilowatts, the amount is determined through a competitive bidding process. You can find all rates by capacity class in the overview of EEG remuneration for 2026.
| System type | Power up to | Partial injection | Full feed-in |
|---|---|---|---|
| Buildings and Noise Barriers | 10 kW | 8.10 ct/kWh | 12.62 ct/kWh |
| Buildings and Noise Barriers | 40 kW | 7.06 ct/kWh | 10.64 ct/kWh |
| Buildings and Noise Barriers | 100 kW | 5.84 ct/kWh | 10.64 ct/kWh |
| Buildings and Noise Barriers | 400 kW | 5.84 ct/kWh | 8.85 ct/kWh |
| Buildings and Noise Barriers | 1,000 kW | 5.84 ct/kWh | 7.63 ct/kWh |
| Other facilities, particularly open spaces | 1,000 kW | 6.59 ct/kWh | 6.59 ct/kWh |
| Federal Network Agency: Rates to be applied pursuant to Section 20 of the Renewable Energy Act (EEG) for systems commissioned between August 1, 2026, and January 31, 2027. Scheduled to be one percent lower than the previous period; next reduction phase effective February 1, 2027. | |||
A note on how to read the table: The table shows the base rates. Those who opt for the feed-in tariff in the up to 100-kilowatt segment will receive slightly lower rates derived from these—currently 7.70 cents for partial feed-in and 12.22 cents for full feed-in for rooftop systems up to 10 kilowatts.
For amounts above one megawatt, the bidding process determines the outcome. The bidding deadline on March 1, 2026, resulted in a total of 268 awards covering 2,299,280 kilowatts, with a total bid volume of 4,622,487 kilowatts and a coverage rate of 201 percent; the volume-weighted price was 4.94 cents, with a range of 3.99 to 5.10 cents.
The follow-up auction on July 1, 2026, shows a significantly lower coverage rate: 401 bids totaling 3,169,977 kilowatts for a tender volume of 2,134,567 kilowatts, which corresponds to 148.5 percent. A total of 261 bids totaling 2,134,657 kilowatts were awarded at a volume-weighted price of 4.79 cents, ranging from 4.38 to 4.97 cents, with a maximum permissible price of 5.90 cents. Competitive pressure has thus eased, yet the price level has continued to fall. For rooftop tenders, the Federal Network Agency lowered the maximum price for 2026 to 10.00 cents.
Why the 2026 timeframe matters — and what's important to keep in mind
The European Commission’s approval of the EEG under state aid law (Decision of December 21, 2022, State Aid Case SA.102084) is valid only until December 31, 2026. This is the actual reason for the transition—not, as is often simplistically stated, the European requirement for bilateral differential contracts.
Commissioning is not always the decisive factor here. For facilities subject to a bidding process —that is, ground-mounted photovoltaic systems exceeding one megawatt—eligibility for subsidies begins when the contract is awarded. Only for projects exempt from the tendering process is eligibility tied to commissioning. For a project in the first solar segment, it is therefore essential that a valid award be granted by the end of 2026—not that the plant be connected to the grid by New Year’s Eve. Anyone who overlooks this distinction will base their planning on the wrong deadline.
To put the European regulation into context: Article 19d of Regulation (EU) 2019/943, as amended by Regulation (EU) 2024/1747, requires that direct price support schemes for investments in new facilities take the form of bilateral difference contracts. This requirement applies to contracts concluded on or after July 17, 2027, and covers wind, solar, geothermal, hydropower without storage, and nuclear energy. Member States may exempt small-scale installations and demonstration projects.
The government’s draft bill on the EEG reform, approved by the Cabinet on July 29, 2026, provides for the elimination of the fixed feed-in tariff for new installations, a requirement for direct marketing, and a feed-in cap. According to a statement from the Federal Ministry for Economic Affairs, the new regulations apply “exclusively to new plants that participate in tenders starting in 2027 or are commissioned without tenders”; existing plants will retain their guaranteed subsidies for the entire duration of their operational life. The draft has not yet been adopted —as of this writing, neither a Bundesrat nor a Bundestag document is available, and no date has been set for a first reading.
Buying a Solar Farm: Existing or New Construction?
Anyone looking to buy a solar farm will find, on the secondary market, mainly facilities with a short remaining term, whereas a new construction ensures a revenue stream for twenty years. The key difference, however, often lies elsewhere: in the grid connection, the lease agreement, and whether repowering is even permitted.
Anyone looking to buy a solar farm faces the same calculation as with a rooftop system—only with different parameters. For an existing farm built in 2012, the guaranteed base revenue continues for six more years; after that, direct sales at the annual market value begin. For a new construction, the period is twenty years. Ground-mounted systems of this size are almost always larger than one megawatt and thus fall into the tender segment.
On the secondary market, solar farms are primarily sold as entire facilities; they are less commonly sold as shares. When the entire facility is purchased, ownership of the assets is transferred; when shares are purchased, only an ownership interest in the operating company is acquired. This has a significant impact on tax treatment.
Second, the property. The remaining term of the lease agreement determines whether continued operation is even possible after the subsidy period ends—often in conjunction with decommissioning obligations and guarantees that the buyer assumes. The following must be reviewed: the written form of the agreement, a contractual right of succession, security interests recorded in the land registry, and insolvency protection. A contractual prohibition on termination is binding for a maximum of 30 years from the date of transfer, pursuant to Section 544 of the German Civil Code (BGB).
Third, the grid connection. It is already in place at an existing wind farm and can represent the actual value in repowering scenarios. Just how scarce this resource has become in the German grid is illustrated by a case from the service area of a distribution system operator in southern Germany: Seven projects with a combined capacity of 126 megawatts share a single 80-megawatt connection.
Roof-mounted systems follow their own logic. In these cases, the available roof area determines the system’s potential output, and the condition of the roof deck determines the remaining useful life of the entire system. A company that takes over an existing system on its own business building is effectively purchasing two risks: that of the system itself and that of the roof beneath it.
There is a special provision regarding repowering that significantly affects the value of an existing facility: For ground-mounted systems, modules may be replaced to improve efficiency—without forfeiting the right to feed-in tariffs—following a relaxation of the rules in the fall of 2022. For rooftop systems, the original feed-in tariff is retained only if the replacement is necessitated by a technical defect, damage, or theft—and only up to the originally installed capacity.
What Technical Due Diligence Must Identify
Systems installed between 2010 and 2014 carry risks that are not apparent from an analysis of yield data. The greatest of these is insulation failure caused by damaged backsheets—it does not produce a signal in the yield data until the inverter fails and is invisible from the outside.
Backing films: a safety issue, not a yield issue
Around 2010, backsheets made from PVDF and polyamide entered the market—the very materials that are drawing attention today. A study by Fraunhofer ISE of 279 modules from 26 power plants provides reliable figures:
- 46 of the 279 modules failed the wet insulation test.
- In more than 80 percent of the modules with certain film structures, the inner layers were severely damaged— invisible from the outside. A visual inspection would not detect this.
- Six out of 26 power plants reported that inverters had been shut down due to insulation faults.
- In 11 out of 26 projects, different backsheets were used under the same product name. Researching data sheets is no substitute for actual measurement.
At a German solar plant built in 2012, the insulation resistance in some of the inverters dropped suddenly and sharply after six years—not a gradual process, but a sudden drop. The international technical recommendation is clear: Modules that fail the insulation or wet leakage current test must be replaced. For systems built between 2010 and 2014, this effectively means a partial repowering due to the lack of available replacement models.
Potential-Induced Degradation
In international fault assessment, PID ranks first in terms of impact on performance. The strongest evidence of the risk associated with the year of manufacture, however, is not a measured value but a gap in the standard: The technical specification for PID testing was not published until 2015. Modules manufactured between 2010 and 2013 were never tested for PID at the time of their certification; the general module standard does not include such a test.
The field data supports this: The first documented cases date back to 2008, and starting with vehicles manufactured in 2016, they no longer appear in the international database. The 2010–2014 model years fall within this timeframe. Regarding reversibility: PID can be partially reversed by heat or by reversing the voltage—but residual damage remains.
What the "Top Five" Lists Usually Overlook
Three risks are rarely mentioned in standard lists but are relevant to this cohort:
In terms of performance impact, bypass diodes and junction boxes rank just behind PID. Here, too, there is a gap in the standards: At the time these modules were certified, no diode test existed. A diode in open-circuit conditions remains invisible in the absence of shading.
According to an analysis by an industrial insurer, connectors and direct current cabling are the most common causes of fires in photovoltaic systems. In 2014, the relevant standard was still only in draft form; mixing and matching visually identical brands was common practice on construction sites.
Transformers and medium-voltage substations are the most underestimated components in ground-mounted and large-scale rooftop solar installations. In a 20-year reliability analysis, the loss of output attributable to the transformer was nearly on par with that of the inverter.
Degradation, Inverters, and Test Methods
The figures circulating—15 to 25 percent loss of performance after 20 years—are not an expected value, but rather a worst-case scenario. A more realistic figure is 8 to 12 percent. When it comes to inverters, the problem isn’t the device itself, but rather the approval of the replacement unit—and no single testing method can detect all relevant damage.
The most frequently cited international dataset reports a median of 0.5 percent per year —approximately 9.5 percent over 20 years. The Fraunhofer ISE, however, measures a rate of just 0.15 percent per year across 44 quality-assured German rooftop systems and describes the 0.5 percent assumption as “very conservative.” A realistic figure is 8 to 12 percent after 20 years —which includes one to two percent in one-time light-induced loss at the start of operation. Higher values occur when a failure mechanism is added.
The real takeaway is the variation. A long-term study of a facility that began operations in 1982 shows that, after 35 years, about 60 percent of the modules still operate at over 80 percent of their initial output—but the population is divided into two groups, and the driving factor is the encapsulation material . The rate of aging is not a property of the technology itself, but rather of the specific bill of materials.
In financial models, the industry assumes that inverters will be replaced shortly after their tenth year of operation; there is no measured average lifespan cited in the technical literature. The more important practical point is that, under feed-in tariff regulations, the replacement poses no problem because inverters are not considered plant components within the meaning of the EEG. Under grid connection regulations, however, it may trigger a certification requirement —the complete replacement of an inverter in a medium-voltage system is considered a material modification. According to an industry survey, a plant certificate costs between 5,000 and 15,000 euros and takes six to twelve months to obtain. Since many manufacturers of inverters built between 2010 and 2012 no longer exist, replacement is technically possible but carries a risk in terms of timing.
No single testing method is sufficient on its own. Electroluminescence makes microcracks visible but does not provide any information about performance. Thermography detects hot spots but does not identify insulation faults. An array-level characteristic curve measurement provides only an average value. Backsheet damage is detected exclusively through insulation testing.
Two points to note regarding the purchase agreement: A complete inspection of large systems is not feasible, and sampling procedures are not harmonized internationally—the scope of the inspection should be specified in the contract, not in the expert report. Furthermore, the conversion to standard test conditions in commercial measuring instruments often does not comply with the relevant standard.
Legal Considerations When Purchasing an Investment
Three legal factors have a greater impact on the risk involved in purchasing an existing asset than its technical condition: the reporting history in the market master data registry, the statute of limitations on the warranty, and whether shares or assets are being purchased. All three can be clarified before price negotiations begin—and all three can significantly affect the value of the asset.
The reporting history is the most critical issue. In its ruling of July 5, 2017 (Case No. VIII ZR 147/16), the Federal Court of Justice held that the grid operator may reclaim the feed-in tariff that was paid if the report to the Federal Network Agency was not submitted—and that the operator has no duty to provide information. A buyer assumes this risk for past remuneration periods. The change of operator itself must also be reported.
The warranty against the installer has generally expired. Depending on how the system is classified, the warranty period is either five or two years; for a system that has been in operation for twelve to sixteen years, both periods have expired. An exception applies in cases of fraudulent concealment of a defect. Otherwise, the only recourse is manufacturer warranties—whose value depends on the manufacturer’s solvency, and the list of module and inverter manufacturers from that era that have gone out of business is long.
Whether it is an asset deal or a share deal determines the overall tax treatment. See the next section for more on this.
Tax Leverage: The Difference Isn't in the Novelty
The widespread assumption that the investment tax credit and declining-balance depreciation apply only to new assets is incorrect—neither provision requires that movable assets be new. What actually limits the tax benefits when purchasing existing assets are the transaction structure, the shortened remaining useful life, and the allocation of the purchase price.
The tax package consists of four components: an investment deduction—IAB for short—of 50 percent under Section 7g(1) of the Income Tax Act (EStG), a special depreciation allowance of 40 percent under Section 7g(5) of the EStG, declining-balance depreciation under Section 7(2) of the EStG, and straight-line depreciation over the useful life. For a photovoltaic investment, the IAB is the component with the greatest leverage because it takes effect even before the purchase. Declining-balance depreciation applies to movable assets acquired after June 30, 2025, and before January 1, 2028; it is capped at three times the straight-line rate and at 30 percent.
The investment deduction applies to depreciable movable fixed assets. The statutory text does not require that they be new—the “new” requirement of the previous regulation was eliminated with the 2008 amendment. Declining-balance depreciation is based solely on the date of acquisition.
One requirement must be met: The system must be a movable fixed asset. Rooftop systems meet this requirement as operational equipment. In the case of roof-integrated systems, the opposite is often claimed—but this applies only to valuation law. For income tax purposes, the tax authorities treat them—pursuant to a decision by the heads of the federal and state income tax divisions—the same as rooftop systems: as independent movable assets, depreciable over 20 years. Only the roof structure is treated as part of the building. Investment tax credits, special depreciation, and declining-balance depreciation are therefore also possible in this context.
In addition, the asset must be used for business purposes at least 90 percent of the time in the year of acquisition and the following year.
What Really Limits Leverage When Buying Stocks
| factor | Effect |
|---|---|
| Share Deal Instead of Asset Deal | When purchasing the operating company, no acquisition costs are incurred at the asset level. The tax base is completely depleted, and the depreciation base remains that of the seller. |
| Shortened Remaining Useful Life | Declining-balance depreciation is three times the straight-line rate, capped at 30 percent. If the remaining useful life is short, the cap takes effect, and the advantage over straight-line depreciation diminishes. |
| Allocation of the Purchase Price | The purchase price must be allocated among the plant, the utility connection, permits, and land rights. Only the portion attributable to the movable asset is subject to the leverage effect. |
The 77.5 Percent Got It Right
When setting up a new investment, the components can be combined to achieve a tax deduction of up to 77.5 percent. Two key points should be noted:
This is a two-year rate, not a first-year effect. The investment deduction applies in the year prior to the acquisition; in the year of acquisition itself, the rate is 27.5 percent. And this rate applies only to acquisitions made in January, because declining-balance depreciation is calculated on a monthly basis, whereas special depreciation is not. If the asset is put into service in October, the two-year rate drops to approximately 71.9 percent.
In the model calculation, for a system costing 100,000 euros and a marginal tax rate of 42 percent, this results in a reduction in profit of 77,500 euros and a tax savings of 32,550 euros over two years. The benefit is a liquidity and interest effect, not a permanent savings. The complete calculation can be found in the guide to the tax stack for photovoltaic systems.
Two pitfalls that are often overlooked. First, for small building systems, the tax exemption under Section 3, No. 72 of the Income Tax Act (EStG) applies—in which case the deduction for business expenses does not apply. For systems acquired or put into operation after December 31, 2024, a limit of 30 kilowatt-peak per residential or commercial unit applies, with a maximum total of 100 kilowatt-peak per taxpayer. This is irrelevant for a typical investor’s system: The exemption applies only to systems on, attached to, or inside buildings—ground-mounted systems are never covered, regardless of their size, and the exemption does not apply to systems exceeding 100 kilowatt-peak anyway. Second, an investment tax credit that is not followed by an investment is retroactively reversed in the year of the deduction—with interest on back payments accruing over several years.
The model calculation assumes commercial use, deduction in the correct fiscal year, and compliance with the usage and profit limits set forth in Section 7g of the German Income Tax Act (EStG). Your tax advisor can determine whether these provisions apply in your case and to what extent—the effect depends on the transaction structure and your individual tax rate.
Italy: FER X Instead of the Existing Rate
Italy transitioned its subsidy system to FER X Definitivo in June 2026. There are two key dates for investors: The portal for prequalification opens on August 25, 2026, and applications for the first competitive bidding round must be submitted by September 30, 2026. For projects larger than one megawatt, the application window closes earlier than many had assumed.
The total quota is 37.15 gigawatts. It is divided into 10 gigawatts of direct access for plants up to one megawatt—open to all technologies—and 27.15 gigawatts for competitive bidding above that threshold. Of the competitive allocation, 10 gigawatts are earmarked for photovoltaics.
The most important date is not listed on the overview page. The program is nominally set to run through the end of 2030. However, for plants with a capacity exceeding one megawatt, the EU state aid decision limits the grant period to the first two years following the entry into force of the decree of June 18, 2026—meaning the window closes in mid-2028. The procedural calendar confirms this: Regular tenders will be held quarterly from December 2026 through June 2028.
The two procedures under the transitional regulation serve as a benchmark for pricing: In the first, approximately 7 , 700 megawatts of photovoltaic capacity were awarded at a weighted winning bid price of 56.825 euros per megawatt-hour; in the second—which was put out to bid under European supply chain criteria—over 1,100 megawatts were awarded at 66.378 euros.
On the market side, the situation has changed significantly. The Italian uniform price in July 2026 was 157.04 euros per megawatt-hour, compared with 113.13 euros in the same month of the previous year. On an annual average for 2025, northern Italy was 26.5 euros per megawatt-hour more expensive than Germany; northern Italy was cheaper or the same price as Germany in only 13.3 percent of the hours.
Existing plants in Italy face an additional risk. In 2014, the country retroactively reduced the Conto Energia rates for larger plants; the Constitutional Court upheld this decision in 2017. A second intervention followed in February 2026, which has been in effect since April 2026 as Law No. 49/2026. It offers affected operators a choice between a temporary tariff reduction and early termination in exchange for compensation. This affects plants from the first four Conto Energia rounds with a capacity of more than 20 kilowatts and a contract expiration date starting in 2029.
Anyone reviewing an existing Italian power plant should therefore clarify one thing above all else: Has the previous operator signed an agreement on tariff adjustments? The cash flow profile and the end of the contract term depend on this. The deadlines and settlement terms for this process are complex in detail and should be reviewed by the grid operator GSE or a lawyer on a case-by-case basis.
When an Existing Facility Is Still the Right Choice
There are three scenarios that justify the purchase of an existing asset: the operational expansion of an existing portfolio; a negotiated price below the present value of the remaining term; and a repowering project, where the location, permits, and grid connection constitute the actual value. Outside of these three cases, building a new facility is structurally superior.
Anyone who manages a portfolio of solar farms and acquires a facility for less than the present value of the remaining payments is making a sound investment—the table above provides the benchmark. The same applies to anyone who finds a property with a long-term, secure lease agreement, a clean reporting history, and reliable maintenance documentation. For companies that already operate a plant, an additional purchase also lowers the investment costs per kilowatt-peak because operational management and direct marketing are spread across a larger capacity.
Repowering has become increasingly important. A German portfolio owner has secured up to 1.6 billion euros to renew its portfolio and plans to increase capacity from 457 to approximately 1,100 megawatts. The value lies not in the modules themselves, but in the location, permits, and grid connection.
Another option is retrofitting with a battery storage system. A storage system connected to the AC side can be installed even in older systems without modifying the DC components. The key factor is whether the remaining service life is long enough to cover the payback period—see the guide on co-located PV storage for more details.
For the typical target group—investors with 100,000 to 500,000 euros in equity and a desire for a predictable 20-year investment—an existing PV system, on the other hand, is rarely the right choice. Those seeking a photovoltaic investment as a tangible asset with a predictable return will find a better starting point with a new installation: a longer term, full tax benefits, and no legacy issues with the documentation.
Let's work through your scenario
Whether it’s an existing system or a new installation: The decision depends on your specific figures. Logic Energy designs, builds, and operates photovoltaic systems for investors with at least 100,000 euros in equity. The contractual partner for direct investments is mediplan Helm e.K., with personal liability on the part of the owner.
Three Steps to Making a Decision
Request the EEG statement instead of a market average, calculate the present value yourself, and review the reporting history and insulation resistance before negotiating the price. Anyone who instead wants a new system built under the current regulations must receive a grant or have the system commissioned by the end of 2026—depending on the system’s size.
First: the specific figures for the system. The feed-in tariff and remaining term are listed exactly as they appear on the EEG statement. Using the present value table in this article, you can calculate a price cap in just a few minutes. Factor in a price of less than 100 euros per kilowatt-peak for the period after the subsidy ends.
Second: the two tests that cost nothing but reveal a lot. An extract from the market master data registry shows the reporting history. An insulation test identifies damage that the performance data does not reveal. Both should be available before price negotiations, not after.
Third: the comparison with new construction. Don’t compare rated capacities; instead, compare remaining terms, the value to be applied in the respective segment, and the effectiveness of the tax stack in your specific transaction structure. Anyone who wants to secure the terms under the current regime must know the correct reference point: for open-field projects exceeding one megawatt, it is the award in 2026; for projects not subject to a bidding process, it is commissioning by December 31, 2026. State aid approval expires at the end of that year.
Frequently Asked Questions
Is it worth buying an existing solar power system in 2026?
Only in three scenarios: as a portfolio addition, when the price is below the present value of the remaining term, or as a repowering project. The reason is structural: high legacy feed-in tariffs and long remaining terms no longer coexist. Anyone who finds a rate of 35 cents per kilowatt-hour will get a plant with three to four years of remaining subsidies.
What is the value of an existing facility?
Almost the entire present value of the remaining EEG payments. At 900 kilowatt-hours per kilowatt-peak, 21.5 euros in operating costs, and a 5.3 percent discount rate, this amounts to approximately 1,023 euros per kilowatt-peak, assuming a feed-in tariff of 25 cents and a remaining term of six years. The period after the end of the subsidy contributes only 65 to 80 euros.
Are there current market prices for existing PV systems?
No. There are no publicly available, up-to-date price statistics for the German secondary PV market. The Federal Network Agency does not track changes in ownership, and the most recent survey available was from 2020 and is no longer accessible. Buyers must calculate the present value themselves.
How long does the EEG feed-in tariff apply to an existing plant?
Twenty years from the date of commissioning; for systems with a legally mandated feed-in tariff, until December 31 of the twentieth year. The period does not restart upon a change of ownership. As of August 2026, systems commissioned through 2005 will no longer receive feed-in tariffs—a system commissioned in 2009 will continue to receive feed-in tariffs until the end of 2029.
What rate of compensation will a new facility receive in 2026?
That depends on the segment. The feed-in tariff applies up to 100 kilowatts. The sliding market premium applies up to 1,000 kilowatts: 7.63 cents for building-mounted systems in the top band when feeding all electricity into the grid, and 6.59 cents for ground-mounted systems. For capacities above one megawatt, the tender determines the rate; the July 1, 2026, tender resulted in an average of 4.79 cents.
What are the technical risks associated with an old photovoltaic system?
The most significant issue is insulation failure caused by damaged backsheets: It is invisible from the outside and does not trigger a warning in the yield data until the inverter fails. Other factors include potential-induced degradation, bypass diodes, connectors, and the transformer. Only an insulation test can detect the first type of damage.
Does the investment tax credit also apply to used equipment?
Yes. Neither Section 7g of the Income Tax Act (EStG) nor the declining-balance depreciation method under Section 7(2) of the EStG requires a new asset. What limits the tax leverage in a portfolio acquisition is the transaction structure: In a share deal, no acquisition costs arise at the asset level, and the depreciation reserve is depleted.
What will change for new installations starting in 2027?
The EEG’s approval under state aid law is valid until December 31, 2026. The cabinet draft dated July 29, 2026, provides for the elimination of the fixed feed-in tariff for new plants and mandates direct marketing. It applies to plants that participate in tenders starting in 2027 or that go into operation without a tender. Existing plants will retain their subsidies. The draft has not yet been adopted.
References
- Federal Network Agency — EEG Subsidies and Subsidy Rates, Values to Be Applied Starting August 1, 2026
- Federal Network Agency — Results of the Solar Open-Space Tender, Bid Deadline: March 1, 2026
- Federal Network Agency — Results of the Solar Open-Space Auction, Bidding Deadline: July 1, 2026
- Federal Network Agency — Renewable Energy Statistics from the Market Master Data Registry
- Fraunhofer ISE — Levelized Cost of Electricity for Renewable Energy Sources, July 2024
- Grid Transparency — Market Value Overview, Annual Solar Market Value 2025
- Grid Transparency — Deduction for Facilities That Have Ceased to Receive Subsidies in 2026
- Market Price Study on the PV Secondary Market, as reported in pv magazine, December 2020
- Fraunhofer ISE — Study of 279 modules to examine backsheets, EPJ Photovoltaics 2021
- IEA PVPS Task 13 — Degradation and Failure Modes
- IEA PVPS Task 13 — Photovoltaic Project Decisions, 2026
- Fraunhofer ISE — Recent Facts About Photovoltaics in Germany
- EEG|KWKG Clearing House — Legal Issue Regarding Inverter Replacement
- § 7g of the Income Tax Act (EStG) — Investment Tax Credit and Special Depreciation
- § 7 EStG — Depreciation Deduction
- § 3 No. 72 of the Income Tax Act (EStG) — Tax Exemption for Small Photovoltaic Systems
- Bavarian State Tax Office — Income Tax Treatment of Roof-Integrated Systems
- § 544 BGB — Contract with a Term of More Than 30 Years
- European Commission — State Aid Decision on the EEG, Case SA.102084
- Regulation (EU) 2024/1747 — Reform of the Electricity Market Design, Article 19d
- Federal Government — Cabinet Decision on the Amendment to the Renewable Energy Sources Act (EEG) of July 29, 2026
- Federal Ministry for Economic Affairs — Press Release on the EEG Amendment and the Grid Connection Package
- GSE — FER X Definitive: How It Works and Quotas
- GSE — FER X Definitive Version: Operational Rules Approved
- GSE — Phase-out of the Conto Energia Program
- GME — 2025 Annual Report, PUN, and Price Spreads
- pv magazine — Repowering and Revamping of Existing Plants
- pv magazine — Grid Connection Shortage in the Distribution Network
- pv magazine — Study on the Causes of Fires in Photovoltaic Systems
- Federal Court of Justice (BGH), Judgment of July 5, 2017 — VIII ZR 147/16, Reclaiming Feed-in Tariff Payments in the Absence of a Report
- Letter from the Federal Ministry of Finance (BMF) dated June 15, 2022, regarding Section 7g of the Income Tax Act (EStG), BStBl I 2022, 945, Margin Note 6 — Investment Deductions for New or Used Assets
Important Note: This article is intended solely for general informational purposes and does not constitute investment, tax, or legal advice. All information is provided without warranty and is current as of August 18, 2026. The present value table is a model calculation based on disclosed assumptions and does not replace an assessment of individual circumstances.
The feed-in rates apply to projects commissioned from August 1, 2026, through January 31, 2027; the next rate reduction phase takes effect on February 1, 2027. The premiums from the July 1, 2026, bidding round were announced on August 18, 2026, and are deemed to have been announced on August 25, 2026. The government draft of the Renewable Energy Act (EEG) dated July 29, 2026, has not yet been adopted and may be amended during the parliamentary process.
Tax-related statements are based on the legal situation as of August 18, 2026; it is essential to consult a licensed tax advisor regarding your individual situation. Information regarding Italian subsidy laws must be verified with the GSE or through legal counsel for your specific case. The contracting party for direct PV investments is mediplan Helm e.K., with personal liability of the owner pursuant to Sections 1, 17, and 19 of the German Commercial Code (HGB).
