The rapid growth of renewables has fundamentally changed how we manage volatility in the energy system. Flexibility has become the new currency and BESS are a crucial part of it. By balancing intermittent generation and enabling a 24/7 renewable energy supply, BESS is emerging as a cornerstone of the energy transition.
But as the market grows, so does the complexity of BESS projects. At the same time, new regulations and a tightening capital market environment are raising more and more questions. Are battery energy storage systems truly bankable today? Which revenue models are proving successful in the German market? And how do factors such as project size, contractual partners, or internal risk tolerance influence financing strategies?
In the ees Europe Conference session Commercial Models for Utility-Scale BESS – How Investor Appetite Is Shaping the Development Process in Germany , host Christopher Bryan, Director at Apricum – The Cleantech Advisory, spoke with experts from Engie, EnBW, terralayr, and Deutsche Kreditbank about the key financing dynamics driving the development of large-scale battery storage systems in Germany.
Mikko Preuß, Chief Commercial Officer (CCO), terralayr Germany:
Germany is pushing ahead faster than most countries, having added 20 gigawatts of renewables just last year. This pace creates a clear system-level need for storage to keep supply and demand in sync. At the same time, we are seeing spreads in the day-ahead market which increased by almost 300 percent over the last five years, creating real opportunities for those who understand how to manage flexible assets. Batteries offer strong returns if handled correctly.
Martin Daronnat, Head of Flexibility & Structured Origination Germany Engie: I do think the market is overheated in terms of revenue expectations. The past few years, marked by COVID-19 and the war in Ukraine, have been exceptional. These events caused extreme volatility and price increases and should not be used as the baseline for future revenue forecasts. Investors should be cautious and challenge their assumptions. They should speak to traders, request forward quotes, and use that data to get a more realistic picture of battery value over the next five to ten years.
Marcel Schepers, Product Manager Flexibility Marketing EnBW Energie Baden-Württemberg, Germany: Although we have seen a surge in grid connection requests totaling nearly 400 gigawatts, that does not mean we are in an actual capacity bubble. Much of that volume consists of duplicates because developers often apply to several Distribution System Operators (DSO) for the same project. The real issue is the significant gap between renewable generation and flexible capacity. Until that gap closes, the need for batteries and flexibility is absolutely real. High market volatility is already sending a clear signal: We need more flexible assets, and batteries are one key part of the solution.
Thomas Osburg, Sales Manager New Energies, Deutsche Kreditbank, Germany: If anything, the question is not whether we are in a bubble now, but whether we might face one in five years. With hundreds of gigawatts in the grid connection queue, I am more concerned about our actual ability to build, finance, and offtake all these projects. Although the numbers suggest explosive growth, the reality of delivery capacity will likely slow that down.
Thomas Osburg: Interestingly, the revenue model itself is not the decisive factor for whether a project gets financed – financing structures can be tailored to different strategies. But what we absolutely need from the outset is a clear revenue approach. Are you going fully merchant (high risk), using a floor model (medium risk), or pursuing a tolling structure (low risk)? That choice determines how we model the project’s risk. The best practice is to work with specialized energy advisors who provide project-specific revenue forecasts across different scenarios. Of course, we do not rely on overly optimistic projections as we also run downside cases. Even if financing has not been finalized, the revenue framework must be in place to assess bankability.
Martin Daronnat: At Engie, we’re targeting 10 gigawatts of BESS globally by 2030. Utilities such as ours have many years of experience with market risks, which shapes our investment approach. While we believe in the flexibility value of batteries, we still take a very structured approach to risk. This is one of the main tasks of our GBU Supply and Energy Management (SEM) at ENGIE. We are able to take risks because we can manage them thanks to our expertise in trading, structuring, portfolio management, and origination.
Martin Daronnat: Personally, I am convinced that revenues will decline in the coming years, especially since we have had extremely high prices for years and because we still have exceptionally high prices for additional services, which currently account for up to two-thirds of BESS revenues in Germany. However, I am not particularly concerned about the saturation of trading revenues, as we at Engie can hedge ourselves. Active risk management using various strategies is a key component of our risk management at Engie. Very few energy suppliers in Europe can secure flexibility on a large scale. Those who do not do so expose themselves to significant risks that can severely limit their growth. In Germany, we estimate that we will need several gigawatts of flexibility to maintain our renewable energy portfolio and supply our customers with green electricity around the clock by 2030. Without proper hedging, the associated market risk would quickly reach numbers which would not be viable. Hedging has been and continues to be the only way for utilities to build significant portfolios. In practice, we hedge through our renewable energy portfolio, our downstream activities, or directly through the market – sometimes through a combination of all three.
Marcel Schepers: There is no strict cutoff, but based on our experience we would say it is somewhere around 40 and 50 megawatts. Below that, projects tend to do better with merchant models or hybrid structures like floor models, because investors are more focused on upside potential. But as asset size increases, the investor profile changes: Large infrastructure funds and equity investors come in, and their priority is risk mitigation. That almost always requires some form of contracted revenue. When we closed our first toll in 2022 for a 7 MW project, it took six months of negotiation. What we need now are standardized frameworks. Without them, the merchant model remains the default for smaller projects.
Mikko Preuß: I think it is less about the size of a single asset and more about how you structure your portfolio. Most of our projects fall in the 10 to 30 MW range, but we aggregate them into larger pools. That lets us offer, say, 50 MW of capacity to off-takers with a balanced fifty-fifty mix of contracted and merchant exposure. We recently closed a deal like that, and this portfolio approach – thinking in total megawatts under management rather than individual assets – is where the market is heading.
Thomas Osburg: When it comes to tolling for smaller storage projects, it is about market access. The PPA landscape in the PV sector illustrates this well: Power purchase agreements are typically reserved for larger projects, where the legal and administrative effort makes economic sense. The same holds true for BESS. Large assets can absorb the legal costs, but when it comes to smaller ones, developers are often forced to opt for merchant models. Unless we create standardized frameworks to aggregate and contract smaller projects efficiently, many of these assets will remain excluded from structured revenue opportunities.
Martin Daronnat: First, ensure there is a clear understanding between all parties. Structured deals are complex, and even small misunderstandings in terminology can cause significant delays. Building trust is equally essential. In every deal, unexpected issues will arise—whether a missed detail, a delay, or a change of plan. When they do, trust is what keeps negotiations moving forward. Strong legal, trading, and structuring teams are also critical, as you must fully understand and accurately represent the risks involved. Finally, don’t sign a tolling deal just because it looks good on paper—sign it because it aligns with your strategy and risk profile.
Mikko Preuß: From an investor’s perspective, you should start with clarity on your own strategy. What is your risk appetite? Are you equity-constrained? Are you optimizing for long-term cash flows or internal rate of return? Without that, the market will define your outcome. Next, run a competitive process. Since there are no market standards in place yet, you need to benchmark offers properly. And finally, understand your counterparty’s value drivers. For instance, structuring the toll as a ‘virtual’, capacity-based deal rather than an asset-related structure can keep it off your balance sheet and improve deal economics. That can make a big difference.
Thomas Osburg: Do not forget the bank. We often provide up to 70 percent of project capital, and we need a say in the tolling terms. This includes understanding commercial risks, availability guarantees, penalties, and reporting rights. If the bank is brought in too late, the whole agreement might need to be reopened — and that is something nobody wants.
Marcel Schepers: You have to work out who takes which risks and who is responsible for what, such as monitoring and warranty compliance. A deal might look attractive until you realize the risk sits entirely with the asset owner. That can become a financing issue, too. So fairness and clarity in responsibilities are just as important as prices.