Risks in BESS direct investments, and how they are structurally addressed

Direct investments in battery storage are entrepreneurial holdings. That means in plain terms: the capital invested is not guaranteed; like any return-oriented investment, the holding carries a corresponding risk of loss. Anyone who speaks honestly about the tax and return advantages must speak just as honestly about the risks. This article lists the four main risks of a BESS direct investment in Germany, assesses their actual probability of occurrence, and describes the structural measures by which they are addressed, not eliminated.

We use the same logic we apply in project due diligence: name the risk, estimate its magnitude, document the mitigant, disclose the residual exposure. If after reading this you don't feel a warm fuzzy feeling but a sober list with clarity about what you're taking on, the article has done its job.

What does the risk of loss mean for a direct investment?

The risk of loss means: unlike a fixed deposit or a bond, there is no deposit protection and no guarantee; in the worst case the equity invested can lose substantial value. That is the starting point of any entrepreneurial holding, much as with equities or real estate. What matters for a realistic assessment, though, is the difference between legal possibility and actual probability: behind the holding sits a real asset: a physical large-scale battery storage system with a grid connection, land and hardware that retains a realisation value even in a crisis. A severe loss is therefore a tail risk (a highly unlikely extreme event), not the base case. How such a plant is built and works is explained in How does a grid-scale battery storage system work? Design, operation and revenue logic explained.

The right expectation is thus neither 'safe like a fixed deposit' nor 'all-or-nothing bet'. It is a real-asset holding with a genuine earnings opportunity and a real but structurally addressable loss risk. The four risks below are the levers where that risk becomes concrete.

Risk 1: how large is the power-price and market risk?

The market-price risk is the largest and most relevant risk of a storage holding, especially for stand-alone projects. The reason: a storage system earns its money from the price differences on the power market (the 'spreads'), and these are not guaranteed but fluctuate with weather, demand and the power-plant fleet. How high the revenues turn out is therefore decided by the market, and that is exactly the core of the return range, which any serious assessment always states as a range rather than a single figure. How the revenues arise mechanically is set out in Battery storage returns: where the revenue comes from, and what is realistic.

A concrete, currently measurable part of this risk is the saturation of the balancing-power markets. These markets are lucrative today but small, and they fill up quickly with new storage. An example from the public data of the transmission system operators: the battery capacity prequalified for positive secondary balancing power (aFRR) rose by around 114 percent from January 2025 to January 2026 (from roughly 0.56 to 1.20 GW), while demand stayed largely constant. Average aFRR capacity prices fell accordingly by around 27 percent over the same period (from about €9,166 to €6,652 per MW per Q1). In the primary balancing market (FCR), too, the prequalified battery capacity of around 1.35 GW clearly exceeds German demand of only about 584 MW. For investors this means: early projects benefit from balancing-power revenues that are still lucrative today, while the long-term return shifts increasingly onto spot-market arbitrage.

Mitigants address this risk structurally without removing it: direct marketing across several markets in parallel (revenue stacking) smooths the revenue curve; co-located structures with a PV plant at the same grid connection diversify the revenue sources; long-term offtake agreements (PPAs) for part of the capacity create a plannable revenue base; and where available, revenue floors via insurance solutions secure a lower bound. Whether stand-alone or co-located yields the better risk structure depends on the site; both have advantages and drawbacks that must be assessed project by project.

Risk 2: what technical risks does a battery storage system have?

The main technical risks are cell degradation, fire risk, inverter failures and grid-connection outages, but overall the most manageable of the four risks, because it is insurable and can be secured contractually. The battery cells lose capacity over the operating years as planned (degradation), which is factored into the business case. The realistic technical availability of modern large-scale battery storage is around 97 to 99 percent per year; short outages of individual components are normal, a longer total failure is rare. What lies physically behind these numbers (cell chemistry, cycles, degradation curve, warranties) is covered in depth by The battery as a real asset: lifespan, degradation and warranties of a grid-scale storage system.

Mitigants here are standard and market-typical: manufacturer warranties of typically 10 to 15 years including capacity guarantees (which assure a minimum residual capacity); full-service O&M contracts that hand operation and maintenance to a service provider; property insurance with a fire and business-interruption component covering both the damage and the lost revenue; and a spare-parts inventory via the operator. The quality of precisely these contracts is one of the most important check items in due diligence; what matters in the policies themselves is set out in Insuring a solar park or battery storage asset: which policies belong to a direct investment, and who holds them.

Risk 3: how does the financing and interest-rate risk work?

The financing risk arises from the debt leverage: projects are typically financed 60 to 75 percent with bank loans, which raises the equity return but also makes the holding interest-rate-sensitive. The concrete forms are a rate-refinancing risk (when the rate-fixing period is shorter than the term and has to be extended on worse conditions), covenant risk (contractual conditions of the financing bank, such as minimum debt-service coverage ratios) and the risk of follow-on financing. In the current rate environment this risk is more noticeable again than in the low-rate phase, but it is well calculable.

Mitigants: a long rate-fixing period of 10 to 20 years matched to the storage system's revenue structure, minimising the refinancing risk; a DSCR buffer (debt service coverage ratio) in the calculation, i.e. a safety margin between ongoing revenues and debt service; and, where needed, an interest swap at the level of the holding company (KG) that fixes the interest rate for the term. A conservatively modelled financing case is recognisable by the fact that it covers debt service even in the stress scenario. How the financing is set up at investor level, from the bank-ready documentation package to the KfW 270 promotional loan, is explained in Financing a direct investment: bank loan, KfW 270 and the pitfalls.

Risk 4: what is the regulatory risk?

The regulatory risk is the danger that the legal and regulatory framework changes to the detriment of storage operation: in grid fees, in the EEG, in the direct-marketing mechanisms or in tax law (§7g EStG, Sonder-AfA). Experience over the last ten years suggests: frequent adjustments, but rarely material retroactive interventions. A concrete, current example is the grid-fee exemption for electricity storage under §118 (6) EnWG: storage systems commissioned by 4 August 2029 are exempt for 20 years from the (otherwise double) grid fees; the deadline was extended by three years in 2024 from the original 2026 cut-off. At the same time, the Federal Network Agency (BNetzA) may adjust the temporal scope of application (§118 (6) sentence 12 EnWG); market observers sum this up as: the exemption stays, but the window is closing. The mechanics of the exemption, the state of the grid fee reform and the concrete deadlines are explained in Grid fees for battery storage: the exemption until 2029 and the AgNeS reform; the market context behind them is set out in Germany's battery storage market: the numbers, the drivers, and why "now" has a date. This is exactly the kind of change risk that must be known and factored into the assessment.

Mitigants: robust contractual clauses with the direct marketers that address regulatory changes; continuous monitoring of the legislative process (BNetzA proceedings, EnWG and EEG amendments); and, as the most important structural lever, diversification across projects with different commissioning years and revenue structures, so that a single rule change never hits the entire portfolio. The tax-structuring logic behind §7g is explained in detail in IAB under §7g EStG: example calculation for battery storage.

Risk matrix: the four risks at a glance

What remains structurally unhedged?

Four residual risks in particular remain structurally unhedgeable, and honesty demands naming them rather than glossing over them: first, black-swan events (extremely unlikely but severe events that escape any calculation); second, a fundamental redesign of the power-market architecture that would change the very basis of the storage business; third, insolvency of the developer or operator, especially during the construction period before commissioning (what happens then to the plant, the contracts and the site is walked through in Provider or operator insolvency: what happens to your direct investment); and fourth, a legislative intervention with genuine retroactive effect. These risks can be reduced through diligence in project and partner selection, but not brought to zero; they remain residual. On top of that comes something no contractual clause removes: the capital lock-up. Anyone who has to sell during the term needs a buyer and the bank's consent, and time pressure costs price; what matters there is set out in Selling a direct investment early: how liquid an energy direct investment really is.

How does Copernica assess the risks in due diligence?

Copernica assesses every project against the same grid from which the four risks above are derived: site & grid connection (is the connection secured and unrestricted?), technology & operator (manufacturer warranties, O&M quality, experience), revenue sensitivity (best/mid/worst case with transparent assumptions), financing structure (rate fixing, DSCR, covenants) and insurance. From this, each project receives a risk profile that investors review in detail before committing, including the check questions you should put to any provider, which How to tell a trustworthy provider of energy direct investments summarises. How we read the revenue assessment in that process is explained in Reading a yield assessment: what P50 and P90 mean for a solar park direct investment.

Whether a specific holding fits your risk appetite and your tax situation can only be judged against real project figures. That is exactly what we do in a no-obligation first conversation: risk profile, revenue sensitivity, financing and tax effect, talked through against your situation, without sugar-coating.