Everything you need to know about solar investments

In our guide, you can find out everything about the process of a solar investment, tax benefits, possible risks and how you can benefit in the long term.

Guide
What is a direct solar investment?

A direct solar investment refers to the acquisition of a specific, legally and technically delimited photovoltaic system – for example a rooftop system or a delimited part of a solar park. The investor not only has a financial stake, but also physically owns the system components. Income is generated through the sale of the electricity generated by feeding it into the grid, through electricity supply contracts or own consumption. Compared to fund investments, a direct investment offers greater transparency and tax structuring options.

The options range from exchange-traded equity funds focussing on solar companies, project bonds and crowdinvesting to direct investments or the purchase of your own solar installations. Direct investments achieve the greatest control and tax effect – the investor becomes the owner of a specific technical asset with entitlement to feed-in, tax depreciation and ongoing income.

Solar energy is considered a comparatively low-risk, high-yield and sustainable investment. State subsidies and regulatory guaranteed income – for example via the EEG – create a high level of planning security. Added to this are tax incentives, social acceptance and the opportunity to help shape real values in the energy transition. In a phase of low interest rates or inflation, these are decisive advantages over traditional asset classes.

Photovoltaic systems generate electricity continuously from a predictable natural resource – sunlight. In contrast to property, where there is a risk of rent losses, or precious metals, which do not generate any ongoing income, a PV system generates monthly income. The technology is established, the maintenance costs are low and the income streams are secured for decades if the contractual situation is good.

In Germany, the feed-in of electricity from photovoltaics is regulated by the Renewable Energy Sources Act (EEG). It guarantees a statutory feed-in tariff for solar power. From a certain system size (currently 100 kWp), funding is no longer provided as a fixed feed-in tariff, but via a so-called market premium in combination with direct marketing. Each system must be registered with the Federal Network Agency and recorded in the market master data register. Tax and commercial law provisions also apply. For example, a business registration is required for direct solar investments.

Firstly, you should clarify whether you would like to take advantage of tax benefits, what amount of capital is available and what time horizon you are aiming for. You should understand how the business model of PV systems works in principle, which investment models exist and whether tax or financial benefits are relevant for you personally. The business model includes an understanding of the income, the cost structure and the legal security (e.g. through lease agreements). This is followed by the selection of a reputable partner or provider and, if necessary, the examination of individual financing options. Good preparation pays off economically for you in the end.

How does a solar asset generate income?

Revenues are generated through the sale of the electricity produced, provided it is not consumed on site. Electricity may be fed into the public grid under a statutory remuneration scheme, sold via a direct marketer on the power exchange, or supplied directly to an off-taker under a Power Purchase Agreement (PPA).

There are three principal options if electricity is not self-consumed:

  1. EEG feed-in tariff (Renewable Energy Sources Act , German: "Erneuerbare-Energien-Gesetz"): For smaller systems (up to 100 kWp), the grid operator pays a statutory remuneration per kilowatt hour fed into the grid for 20 years from commissioning. Thereafter, electricity can be marketed via direct sales on the power exchange or through long-term power purchase agreements (PPAs).
  2. Direct marketing via a service provider: From 100 kWp onwards, there is no fixed feed-in tariff; instead, electricity can be marketed directly. A specialised service provider sells the electricity on the power exchange (usually EPEX Spot). During the first 20 years after commissioning, the operator receives the market price plus a statutory market premium to compensate for the difference to the EEG remuneration.
  3. Power Purchase Agreements (PPAs): In this model, electricity is sold directly to a company or energy trader under an individually negotiated contract, typically with a fixed term and fixed price.


The optimal marketing model depends on system size, market environment, and investment structure.

For systems up to 100 kWp, a fixed statutory remuneration per kilowatt hour is guaranteed for 20 years. This payment is made directly by the grid operator. Larger systems market their electricity independently via direct marketing but receive a market premium that compensates for the difference compared to the EEG tariff (Renewable Energy Sources Act , German: "Erneuerbare-Energien-Gesetz").

After 20 years, the statutory feed-in tariff expires. However, the photovoltaic system generally continues to operate reliably. From that point onward, electricity may be sold directly on the power exchange, supplied under a PPA, or used for self-consumption. Some operators also conclude follow-up agreements with direct marketers who bundle and sell residual electricity volumes. Although revenues may become more exposed to market volatility, operation typically remains economically viable, particularly for well-located systems with low operating costs.

Under direct marketing, electricity is not remunerated at a fixed EEG tariff but sold on the power exchange, typically through a specialised service provider. The provider markets the electricity and pays the operator the achieved market price. In addition, the operator receives a statutory market premium from the grid operator to compensate for the difference to the EEG remuneration level. This model improves market integration of solar power but introduces exposure to price fluctuations, which are partially mitigated by the market premium.

The market premium compensates for the difference between the statutory EEG remuneration rate and the market price achieved on the power exchange. It is adjusted monthly and paid by the grid operator. Together with the exchange price, it aims to ensure that the operator achieves a revenue level broadly comparable to that of smaller systems receiving the fixed EEG tariff.

Power Purchase Agreements (PPAs) are individually negotiated electricity supply contracts between the system operator and an off-taker. They are based on freely negotiated prices, terms, and volumes. Unlike the EEG, PPAs do not provide a statutory remuneration entitlement. Instead, they offer greater contractual flexibility and, in some cases, higher revenue potential.

If electricity prices on the power exchange remain negative for a certain period, EEG remuneration for electricity fed into the grid is suspended for new photovoltaic systems from March 2025 onwards during that period. This applies regardless of whether the system is supported via a fixed tariff or a market premium. The threshold for suspension is no longer six hours, as under the previous EEG regime, but already 15 consecutive minutes of negative exchange prices. In such cases, only the EEG component is suspended. The market value of the electricity, meaning the price achieved on the exchange, continues to be paid. The foregone EEG remuneration is added to the end of the 20-year support period, provided the operator remains within the support scheme. Existing systems commissioned before the end of February 2025 are exempt and remain subject to the previous rules.

Electricity price development depends on numerous factors, including demand growth, the pace of renewable energy expansion, gas and CO₂ certificate prices, and regulatory developments in the electricity market. A particularly important driver is increasing electrification. The expansion of electric mobility, the replacement of fossil heating systems with heat pumps, and the electrification of industrial processes are expected to significantly increase electricity demand in Germany and across Europe. Technological progress in storage and grid infrastructure will also influence price levels and volatility over the long term.

Many market analyses therefore expect wholesale electricity prices to rise moderately on average (around 6-10 cents per kilowatt hour), albeit with strong intra-day and intra-hour fluctuations. For PV systems, the actual achieved price (the so-called capture price) may be lower, as many systems feed into the grid simultaneously, particularly during periods of high solar irradiation.

For investors and operators, this means that a well-designed marketing strategy, such as PPAs or intelligent self-consumption combined with storage, will become increasingly important to secure future revenues.

Operating costs of a photovoltaic system typically include commercial and technical operations management, maintenance, insurance, marketing costs, and, where applicable, lease payments for the site. Relative to revenues, operating costs usually account for less than 15%, making them comparatively predictable and manageable.

Conservative direct investments typically achieve annual returns of 4-6%. Through tax optimisation, leverage, and favourable marketing strategies, double-digit returns may also be achievable. The actual return on equity depends largely on the investment structure, in particular the level of equity invested and available tax structuring options.

Returns depend on acquisition price, location (solar irradiation), technology (efficiency), marketing model (EEG remuneration or PPA), operating costs, and tax structuring (use of the investment deduction allowance or special depreciation). Financing costs and capital structure also have a significant impact on overall financial performance.

How much equity is required?

The equity requirement depends largely on the investment model. For traditional direct investments, investors should expect an equity share of approximately 20-30% of total costs. With targeted use of tax advantages (e.g. the investment deduction allowance), the effective post-tax equity contribution can be significantly lower. In such cases, a project can even be initiated with less than 10% of liquid equity.

Many banks finance PV systems at 70-90% of total investment costs, and in some cases up to 100% for very solid projects. The level of financing depends, among other factors, on the investor’s creditworthiness, the financial viability of the system, the quality of contractual arrangements, and the electricity marketing strategy. Revenues under the EEG framework are generally considered highly secure, which facilitates financing.

Both traditional commercial banks and specialised institutions (e.g. environmental or cooperative banks) offer financing for PV systems. In many cases, project intermediaries or providers work with established financing partners, which simplifies the process. A well-prepared project, including a transparent financial model and standardised documentation, is essential.

After selecting a project, financing terms are coordinated with the bank. The basis typically includes a yield forecast, a financial plan, and proof of equity capital. Following a positive credit assessment, a loan commitment is issued. Disbursement usually takes place in tranches according to project progress. During the operating phase, the loan is repaid in regular instalments from ongoing electricity revenues.

In Germany, various support schemes are available, including low-interest loans from KfW (e.g. Programme 270) and regional programmes at federal state level. These can often be combined with bank financing. Applications generally must be submitted before project commencement. Some programmes include repayment grants or special terms for storage solutions or self-consumption models.

Loan maturities are typically aligned with the secured remuneration period (EEG) and the system’s economic life, with 20 years being common. Most financings are structured as annuity loans, meaning constant instalments over the term. After the loan term ends, the system is generally fully depreciated and generates revenues without interest or principal repayment obligations.

What tax advantages exist when investing in solar assets?

Photovoltaic systems are treated as commercially used assets for tax purposes. This allows investors to use several instruments to significantly reduce their tax burden, in particular the investment deduction allowance (German: "Investitionsabzugsbetrag" – IAB), special depreciation allowances, and straight-line depreciation over 20 years. In addition, VAT paid on the purchase price may be refundable. These tax mechanisms can effectively reduce the required equity capital and substantially ease the financial burden in the early years of the investment.

The investment deduction allowance (IAB) is an off-balance-sheet tax advantage available to entrepreneurs, including small business owners. It allows planned investments in movable business assets (e.g. photovoltaic systems) to be brought forward for tax purposes up to a specified maximum amount (currently € 200,000 per business). This means that, prior to acquisition, up to 50% of the planned investment costs may be deducted in order to reduce the tax burden.

Under Section 7g of the German Income Tax Act (EStG), up to 50% of the anticipated investment costs can be recognised as a business expense before the actual purchase. This allows future investments to generate immediate tax benefits in advance. The investment deduction allowance (German: "Investitionsabzugsbetrag" – IAB) reduces taxable profit and directly lowers income tax liability in the year it is formed. The actual investment must then be completed within three years. In this way, tax payments can effectively be redirected into long-term asset accumulation.

More specifically, the IAB pursuant to Section 7g EStG enables up to 50% of the planned investment costs to be deducted as a business expense before the photovoltaic system is acquired, subject to a maximum deduction of € 200,000 per business per year. The deduction reduces taxable profit in the year of formation without requiring the investment to have been completed at that time.

The actual investment must take place within three years. In the year of acquisition, the IAB is reversed and increases taxable profit, while the (reduced) acquisition costs are depreciated. The IAB therefore serves as a mechanism for timing the recognition of tax burdens. It allows high income to be smoothed deliberately and liquidity to be created for investment purposes. In practical terms, it enables taxes to be converted into long-term asset accumulation.

To use the investment deduction allowance (German: "Investitionsabzugsbetrag" – IAB), a business must already exist at the time the IAB is formed or be demonstrably in the start-up phase. This means concrete preparatory actions for the investment must have taken place, such as business registration, project negotiations, cost estimates, or advisory documentation.

The planned investment (e.g. in a PV system) must then be completed within three years of forming the IAB. If this deadline is not met, the deduction must be reversed. Typical sequence: In year 1, the IAB is formed and claimed for tax purposes. In year 2 or 3, the system is acquired. At that point, the IAB is reversed and the actual acquisition costs are depreciated.

Yes – for investments in solar assets that are not intended solely for private self-consumption, business registration is generally required. This also applies to participations in a civil law partnership (GbR) or the operation of a system on a third-party rooftop. Registration is straightforward and can usually be completed online with the relevant local trade office. An obligation to maintain double-entry bookkeeping arises only above certain size thresholds. Many investors instead use a simplified income statement method (cash basis accounting).

What are typical risks associated with solar investments?

Although solar assets are generally regarded as comparatively low-risk tangible investments, several factors may lead to reduced returns:

  • Regulatory risks: Changes to government support schemes, feed-in tariffs, energy market regulation, or tax legislation may affect the profitability of solar assets.
  • Electricity price and remuneration risks: For the first 20 years, remuneration is often secured through feed-in tariffs. Thereafter, electricity is marketed on the open market. Future electricity prices depend on numerous factors and are difficult to predict from today’s perspective.
  • Variability in electricity generation: In many cases, investment decisions are based on forecasts rather than historical operating data. Year-to-year fluctuations of up to ±20% may occur due to changing weather conditions. Soiling or shading may also reduce system performance.
  • Technological risks: Yields may be affected by insufficient component quality, installation defects, or weaknesses in the substructure (e.g. rooftop integrity). Components such as inverters or modules may fail or underperform relative to expectations.
  • Developer or intermediary dependency: Selecting weak partners may create operational and financial risks. Deficiencies in technical planning, construction, or acceptance may result in delays or lower yields.
  • Contractual risks: Unfavourable or unclear provisions in lease, purchase, or service agreements may create long-term disadvantages for the operator.
  • Operational risks: Inadequate maintenance, insufficient insurance coverage, or poor service may result in downtime, additional costs, or operational disruptions.

In most cases, risks can be effectively reduced, provided certain principles are observed during planning, selection, and operation:

  • Careful site selection: Strong irradiation values, verified rooftop or land conditions, and transparent yield forecasts (e.g. PV*Sol, PVGIS) are essential.
  • Commercial and technical due diligence: Comprehensive review of partners, assets, technology, and financial viability is necessary to ensure quality, reliability, and profitability. The use of proven components (e.g. branded inverters, insured modules) and quality control during construction reduces technical risks.
  • Reliable partners: Project developers and operators should demonstrate experience, references, and transparent structures.
  • Contracts with clear risk allocation: Long-term lease agreements secured by land register entry, clearly defined maintenance agreements, and standard market insurance coverage are best practice.
  • Regular monitoring and maintenance: Continuous system monitoring and scheduled maintenance reduce the likelihood and impact of outages.
  • Insurance protection: Comprehensive all-risk policies including business interruption coverage, operator’s liability insurance, and property damage coverage protect against technical failures or damage events.
  • Diversification: Investing in multiple assets or a portfolio reduces concentration risk related to specific technologies or regional factors.
  • Long-term planning: Robust financing models, conservative yield assumptions, and flexible exit strategies provide additional security.
How does a solar plant work?

A photovoltaic (PV) system converts sunlight directly into electricity. Solar modules consist of many solar cells that generate direct current (DC) when exposed to light. This DC electricity is converted by an inverter into grid-compatible alternating current (AC), which is either consumed on site or fed into the public electricity grid.

The amount of electricity generated depends primarily on solar irradiation, the orientation and tilt of the modules, and the technical quality of the components. Modern systems are largely automated and include digital monitoring solutions that continuously track performance and revenues.

For investors, this means the business model is based on a physically clear, well-understood process, using mature, standardised technology with comparatively low maintenance requirements.

A photovoltaic system comprises several coordinated technical components:

  • Solar modules: They convert sunlight into DC electricity and form the core component of the system. The number of modules largely determines the installed capacity (kWp).
  • Inverters: They convert the generated DC electricity into grid-compatible AC electricity. Inverter quality is critical for efficiency and yield stability.
  • Mounting system: It secures the modules on a rooftop or ground-mounted structure and must be designed to meet structural requirements and resist corrosion.
  • Cabling and protection systems: This includes DC and AC cabling, surge protection, and fuses. These components ensure safe operation in line with applicable standards.
  • Meters and grid connection: Feed-in meters measure the electricity generated and form the basis for settlement and billing.
  • Monitoring system: Modern systems include digital monitoring that tracks yields in real time and triggers alerts in the event of deviations.


Optional components may also be added, such as a battery storage system to optimise self-consumption or an energy management system to control feed-in intelligently.

Components are standardised, technologically mature, and protected by warranties. However, system design and installation quality are decisive for long-term financial performance.

The lifespan of a PV system depends on its individual components and should be assessed in a differentiated manner.

Solar modules typically have a technical lifespan of around 30 to 40 years, and in some cases longer. Output gradually declines over time (degradation). Realistic assumptions for modern modules are around 0.2–0.5% performance loss per year; high-quality modules may, according to long-term studies including those by Fraunhofer ISE, perform even better. After 20 years, many modules still achieve around 90–95% of their original rated output.

Inverters have a shorter lifespan of around 15–20 years, depending on type, quality, and thermal load. Financial models should therefore assume that at least one inverter replacement will be required over the lifetime of a PV system.

Other components such as mounting systems, cabling, and substructures are generally designed for very long service lives when installed correctly and are considered robust.

Manufacturers typically provide:

  • 25–30-year performance warranties on modules,
  • 5–15-year product warranties on inverters (often extendable), and
  • additional warranties on mounting systems.


Financial planning is often based on 20 years of EEG support, while the technical service life extends beyond that period. Under conservative assumptions, operating periods of 30 years and more are realistic, which has a clearly positive impact on overall profitability.

The performance of a PV system decreases slowly and continuously over time. This process is referred to as degradation. It is caused by natural ageing of the modules, thermal stress, UV radiation, and material fatigue.

For modern modules, realistic annual degradation is typically around 0.2–0.5% per year. This means that after 20 years, a system usually still delivers around 90–95% of its original output, and after 30 years typically around 85–90%, depending on module quality and site conditions.

Degradation is generally relatively linear and should be reflected in financial models. Manufacturers underpin this with long-term performance warranties, often guaranteeing a minimum output of 80–90% after 25 or 30 years.

For investors, this means revenues decline slightly over time, but in a predictable and moderate manner. Even after EEG support ends, the system continues to generate electricity reliably, albeit at a somewhat reduced output level.

Operating a PV system involves both technical and commercial activities. In practice, these services are often outsourced to a specialised service provider.

Technical operations typically include system monitoring, organising maintenance and repairs, and liaising with the grid operator in the event of faults. The objective is to minimise downtime and ensure consistently strong performance.

Commercial management includes settlement of electricity revenues, communication with the direct marketer, administration of insurance policies and contracts, and providing performance and revenue reporting for the investor.

Depending on the investment model, these responsibilities may be handled by:

  • the project developer,
  • an external operations manager, or
  • for larger projects, a dedicated operating company.


For investors, this means that even if they are the legal operator, the ongoing workload is generally limited, as key tasks are handled professionally.

Modern PV systems use digital monitoring solutions that capture and analyse performance in real time. This typically includes continuous measurement of energy yield, inverter status, voltage, temperature, and grid feed-in.

Data is usually transmitted via an internet connection to an online portal, enabling operators or operations managers to review performance at any time. Deviations from expected performance, for example due to technical defects or shading, are automatically detected and reported.

For larger systems, technical operations managers often provide additional remote monitoring. They regularly compare actual yield data against forecast values (planned vs actual) and initiate corrective actions if anomalies occur. This means potential issues are typically identified early, before material revenue losses arise.

PV systems are considered comparatively low-maintenance, as they typically have no moving parts, with the exception of tracking systems. However, regular inspections are advisable to ensure safe operation and stable yields over the long term.

Typical maintenance measures include:

  • Regular visual and functional inspections of modules, substructure, and cabling
  • Inspection of inverters and electrical components
  • Yield monitoring and performance checks (planned vs actual)
  • Module cleaning where required, particularly in environments with elevated soiling (e.g. agricultural areas or industrial emissions)


For ground-mounted plants with tracking systems, additional maintenance is required, as mechanical components such as motors and bearings must be inspected and serviced regularly.

For investors, maintenance costs are generally predictable and represent only a manageable share of ongoing operating costs. Professional monitoring is crucial to identify deviations early and prevent larger revenue losses.

If a technical failure occurs, for example an inverter defect, damaged modules, or a grid connection issue, this is typically detected by the monitoring system. Modern systems automatically report performance deviations to the technical operations manager or service provider.

The responsible service partner investigates the cause and organises repair or replacement of affected components. Inverter replacement over the lifecycle is common and is typically reflected in financial models.

To mitigate financial impacts, all-risk or electronics insurance policies usually cover physical damage. In addition, business interruption insurance may apply where insured damage results in lost revenues.

Under certain circumstances, temporary output reduction can occur. A distinction should be made between grid-related curtailment and market-related effects.

Grid-related curtailment (redispatch):
If the regional grid is congested, the grid operator may temporarily reduce feed-in. This primarily affects larger systems and ground-mounted plants that are system-relevant. The EEG generally provides compensation for such measures, typically around 95% of lost revenues. Smaller rooftop systems below 100 kWp are, in practice, affected far less frequently.

Negative electricity prices:
Negative power exchange prices do not automatically switch the system off. Technically, the system continues to feed in. However, for newer systems, EEG support may be suspended during such periods. This is a market effect, not a grid-related shutdown.

Overall, permanent shutdowns are rare. Short-term curtailment does occur but, particularly for smaller rooftop systems, typically has only a limited impact on annual yields.

Which contracts are required when investing in solar assets?

Investing in a photovoltaic asset typically involves several agreements covering technical, legal, and commercial aspects. These usually include:

  • Purchase agreement: Governs acquisition, handover, warranty, and payment terms for the PV asset.
  • Lease or usage agreement: If the system is installed on a third-party rooftop or land, usage is secured through a long-term agreement, often supplemented by a land register entry (easement).
  • Grid connection and feed-in agreement: Governs the technical connection to the grid and settlement of electricity volumes fed into the grid with the grid operator.
  • Operations and maintenance agreement: Regulates technical and commercial operations over the term.
  • Direct marketing agreement or PPA: For systems above 100 kWp, an agreement with a direct marketer is required. Alternatively, a bespoke power purchase agreement (PPA) may be concluded.
  • Insurance policies: Typically all-risk insurance, operator’s liability insurance, and, where applicable, business interruption insurance.


For participations held through legal entities (e.g. a civil law partnership (GbR) or a GmbH & Co. KG), an additional shareholders’ agreement is required to govern the rights and obligations of the investors.

A lease agreement governs the use of a rooftop or land area for operating a PV system. It is concluded between the site owner (e.g. building/rooftop owner or landowner) and the system operator and defines term, lease payments, and the rights and obligations of both parties.

In practice, lease agreements are often concluded for 20 years, aligned with the EEG support period. For investors, however, it is crucial that an additional unilateral extension option in favour of the operator is agreed, typically for a further 10 years or more.

This extension option ensures the system can continue operating after the EEG period ends, which is economically sensible given that module lifetimes often extend well beyond 20 years.

The lease agreement also typically regulates, among other things:

  • access rights for maintenance and repairs,
  • liability matters,
  • insurance requirements, and
  • provisions in the event of a change of ownership.


For investors, the lease agreement is therefore a core security instrument. Its term and design directly affect long-term financial performance.

At the end of the agreed lease term, the right to use the rooftop or land generally expires. Without an extension option, the PV system may not be operated further.

In practice, several scenarios are possible:

  • Lease extension: If a unilateral extension option in favour of the operator is included, the system can continue operating, often for a further 5 to 10 years or longer.
  • New agreement: If no extension was agreed, a follow-on agreement may be negotiated with the site owner.
  • System dismantling: If no agreement is reached, the system typically must be dismantled. Dismantling obligations and costs should be defined in the original agreement.
  • Transfer to the site owner: Some agreements provide that the system transfers to the site owner after expiry under agreed terms.


For investors, it is essential that lease term and extension options align with the technical lifetime of the system. As modern PV systems can often be operated for 30 years or more, contract design has a direct impact on long-term profitability.

For systems installed on third-party rooftops or land, a limited personal easement is typically registered in the land register. This secures the operator’s right to use the site long term for operating the PV system.

Land register registration is particularly important because it protects the right of use even if the property changes ownership. If the building or land is sold, the right to operate the system remains in place.

Without such land register protection, there is a risk that the right of use could be impaired in disputes or in the event of the owner’s insolvency. For investors, it is therefore critical that the lease agreement and land register protection are aligned in substance and that the term is sufficiently long.

An easement is a right of use registered in the land register. It entitles a specific person or entity to use a property in a clearly defined way, even if they are not the owner.

In the context of solar projects, this is typically a limited personal easement granting the operator the right to use the rooftop or land area for construction, operation, maintenance, and, where applicable, dismantling of the system.

The key advantage is that an easement registered in the land register remains valid even if the property is sold. The right of use is therefore secured long term and cannot be unilaterally terminated due to a change of ownership.

For investors, the easement is a central security instrument supporting the investment’s economic stability.

Responsibilities are clearly set out in the lease agreement and the operations agreement and should be reviewed carefully prior to investment.

As a general principle: The system owner is responsible for proper operation of the PV system, including technology, maintenance, and repairs to modules, inverters, and electrical components. The property owner remains responsible for the structural integrity of the rooftop or land.

For example, an inverter defect falls within the system owner’s responsibility. Structural works on the roof, such as roof renovation, are generally the building owner’s responsibility, provided the damage was not caused by the PV system.

It is important that the lease agreement includes clear provisions on: liability in the event of damage, access to the roof for maintenance, cost allocation for necessary structural measures, and coordination obligations for roof works.

For investors, clarity on these responsibilities is essential to avoid future conflicts or economic disadvantages.

If the building or land on which the PV system is installed is sold, the rights and obligations under the existing lease agreement generally transfer to the new owner, provided the agreement is validly executed and legally sound.

Securing the right of use in the land register via a limited personal easement is crucial. It ensures the right to operate the system remains in place even if ownership changes.

In addition, the lease agreement should explicitly require the seller to disclose the existing usage agreement in the property sale contract. This creates transparency and ensures the buyer is aware of, and assumes, the contractual obligations.

For investors, the key points are:

  • Land register protection is in place
  • Clear contractual provisions on legal succession
  • Long-term term and extension option


If these conditions are met, a change of ownership is generally not an economic risk for ongoing operations.

If the rooftop or landowner becomes insolvent, the lease agreement generally remains in force, and the insolvency administrator assumes the contractual rights and obligations.

However, legal security is decisive. If an easement is registered in the land register, the right to operate the PV system remains protected even in insolvency. Without land register protection, there may be a risk that the insolvency administrator reviews agreements or seeks to reassess them within the scope of legal options.

The lease agreement should therefore provide a clear term, unambiguous definition of the right of use, and appropriate provisions on succession and insolvency.

For investors, the combination of a long-term lease agreement and land register protection is the key safeguard. If these elements are properly implemented, the site owner’s insolvency risk is generally manageable in practice.

Solar assets are generally transferable. They constitute standalone economic assets and can be transferred either directly as technical assets or indirectly via an operating company.

There are two common transaction structures:

  • Asset deal: The PV system itself is transferred to a new owner.
  • Share deal: Shares in the operating company (e.g. GbR or GmbH) are sold, either partially or in full.


In practice, share deals can be more efficient, as existing agreements (lease, grid connection, direct marketing) remain within the entity.

Whether consents are required depends on contractual clauses. Typically, consent from the lessor or direct marketer is not required, but it may be contractually stipulated in some cases.

More relevant is usually the financing bank. If the loan is secured personally or relies on the original investors’ credit profile, a sale may require bank consent or refinancing.

Solar asset valuation is typically based on the discounted value of future cash flows. Key drivers include remaining EEG or PPA term, expected generation and power price development, operating costs, and the prevailing interest rate and market environment.

For investors, this means that while a solar asset is designed as a long-term investment, it is generally tradable. The secondary market for operational assets is established, particularly for stable yield profiles.

Investments in solar assets are generally inheritable and transferable. The practical process depends on the chosen structure, in particular whether the asset is held directly or via a legal entity.

Direct asset ownership (sole proprietorship or GbR participation):
In the event of inheritance, rights and obligations generally pass to the heirs. Existing agreements such as lease, direct marketing, and financing typically remain in place.

Corporate structure (e.g. GmbH or GmbH & Co. KG):
In this case, shares in the company are inherited or transferred. This can be administratively simpler, as the operating structure remains unchanged and only the shareholder position changes.

Gifts and lifetime transfers are also possible. In doing so, inheritance and gift tax allowances should be considered. Under certain conditions, business assets may benefit from favourable tax treatment.

Key points include:

  • Shareholder agreements should include inheritance provisions
  • Financing banks may need to be informed
  • Early legal and tax advice is advisable


For investors, this means solar assets are not only long-term and predictable but can also be transferred structurally, provided the legal setup is planned with foresight.

How does an investment work in practice?

A direct investment in a solar asset follows a structured process consisting of six sequential steps:

1. Project review
A specific project is reviewed in detail. This includes site analysis, technical design, yield forecast (e.g. based on irradiation data), review of the lease agreement, and a detailed financial model. The objective is to establish a robust decision basis and identify potential risks early.

2. Structuring and tax planning
Depending on the investment model, the commercial structure is set up, for example as a sole proprietorship or through participation in an operating company. Optionally, an investment deduction allowance (IAB) can be formed to utilise tax effects prior to acquisition. In parallel, and if desired, a bank financing commitment can be obtained. This phase defines the tax and financing setup.

3. Contract closing
The relevant agreements are concluded, in particular the purchase agreement for the solar asset, the lease agreement for the rooftop or land area, operations and maintenance agreements, insurance policies, and, where applicable, a direct marketing agreement or a PPA. Contract terms should be aligned and structured for the long term.

4. Financing and payment processing
Where debt financing is used, the bank loan is concluded. Disbursement and payment of the purchase price typically occur in line with construction milestones or, for an existing asset, at an agreed point in time. The financing structure is a key driver of equity returns and liquidity development.

5. Construction and commissioning
The system is built by qualified specialist contractors or acquired as an operational asset. Following technical acceptance, commissioning takes place, and the asset is registered in the Market Master Data Register. This marks the start of the revenue phase.

6. Operations, maintenance, and ongoing revenues
Following commissioning, a specialised service provider typically manages technical and commercial operations. This includes monitoring, maintenance coordination, settlement of electricity revenues, and communication with the grid operator and direct marketer. The investor receives regular performance reporting and can track the asset transparently.

Project review is carried out in several successive steps. The objective is to identify early whether an investment is economically attractive and technically and legally robust.

1. Financial viability analysis (pre-screening)
First, the project is assessed to determine whether it can deliver attractive returns. Investment costs, forecast electricity generation, operating costs, financing terms, and tax effects are modelled in a detailed cash flow analysis. If returns are insufficient under conservative assumptions, the project is typically not pursued further.

2. Technical assessment
If financial viability appears sound, a technical review follows. This assesses site conditions, rooftop or land characteristics, structural integrity, shading, orientation, system design, and the quality of key components such as modules and inverters. The basis includes yield simulations, planning documentation, and technical reports.

3. Contractual and structuring review
Purchase agreement, lease agreement, contract terms, extension options, land register protection, operations agreements, as well as liability and dismantling provisions are reviewed from a legal perspective. Marketing arrangements (EEG, direct marketing, or PPA) are also assessed. The objective is a legally sound and long-term secure structure.

4. Risk assessment
Finally, a structured assessment of key risks is performed, for example revenue volatility driven by market factors, regulatory changes, or technical failures.

Only once these points have been reviewed in a transparent and robust manner does a reliable decision basis exist. For investors, quality in this phase is decisive for long-term investment stability.

Responsibility for registrations depends on the investment structure. Legally, the responsible party is always the system operator, i.e. the person or entity operating the system and feeding electricity into the grid.

Individual systems (e.g. a rooftop system or a standalone ground-mounted plant):
The operator, often a sole proprietorship or an operating company, is responsible for proper registration. In practice, this is usually handled by the installer or project developer as part of commissioning.

Parcellated systems or participation models (e.g. subdivided sections of a solar park):
This depends on the structure. If the entire plant is operated via a single operating company, registration is performed centrally by that entity. If each investor is legally the operator of “their” system, each unit must be registered separately.

Key registrations typically include:

  • registration in the Federal Network Agency’s Market Master Data Register,
  • coordination with the relevant grid operator, and
  • where applicable, tax-related notifications to the tax office.