‘Merchant business case proven, but tougher financing environment’: 8Energies on German BESS market

The publication of the Q&A comes just after regulator BNetzA published its draft decision document regarding long-term grid fees in the German market, a key question for energy storage project bankability, on 6 August (the questions were drafted before its publication).

We heard from another event speaker, Nina Schmüser, regulatory affairs manager in Germany for independent power producer (IPP) Grenergy, on the day of the decision document’s publication.

What are the key trends, major successes and achievements, and challenges still to be overcome in the German energy storage market?

Germany has moved from a promising niche to Europe’s most dynamic large-scale storage market. Q1 2026 saw a record build-out of roughly 2.2GWh (+38% vs. Q1 2025), the installed base stands at around 14GW, and 2026 could add 8 to 10GWh.

The merchant business case has been proven: negative price hours rose from 69 (2022) to 573 (2025), solar capture rates have fallen below 60%, and intraday spreads regularly exceed €150/MWh within an hour.

At the same time, we have to be honest about the flip side: since the beginning of 2026 we are seeing revenues come down, and the first saturation effects are clearly observable, especially in the ancillary services markets, above all in secondary reserve (aFRR).

Financing has matured with the market. At 8Energies we closed our pilot project (Wehr) at 70% LTV with senior debt on a fully merchant basis, something that would have been hard to imagine two years ago.

The key challenges: the grid connection backlog (~270GW of requests sitting with the TSOs), the grid fee regime from August 2029 shaping FID timing across the industry, and the absence of a federal storage strategy.

Is there any clarity on what grid fees/network charges will look like for BESS coming online after 4 August 2029?

Yes, and considerably more than a few months ago. The Bundesnetzagentur has now published a draft with actual numbers: storage pays a single annual capacity charge of roughly €5/kW on the contracted connection capacity (€5.14/kW), and this will be the only charge. There will be no additional volumetric charges on actual energy flows.

For our industry this is a mixed signal. On the one hand, projects that want to remain grid fee free now face a very fast sprint until the end of this year, because there will be a clear FID cutoff date at year-end, with commissioning required by 4 August 2029. On the other hand, for the long-term perspective of BESS it is a good signal: the proposed grid fee structure would move the IRR of a standard medium-voltage project by only roughly 1.5 percentage points. That is manageable for a healthy project, but it is enough to make the end-of-year FID dynamics very real across the market.

What opportunities and challenges do you see with the capacity market (CM) for energy storage?

The opportunity is obvious: a capacity market could give storage a contracted revenue floor, improving bankability and lowering the cost of capital, particularly valuable for longer-duration (4h) systems whose merchant case depends more heavily on scarcity pricing.

The risks are equally clear from abroad: Italy’s first MACSE auction cleared at ~€13,000/MWh/year against a €37,000 reserve price, 4x oversubscribed, with ~70% going to two incumbents, a warning of what happens when developers bid a capacity product into the ground.

For Germany the design questions matter more than the principle: how storage is derated by duration, whether the CM crowds out or complements merchant flexibility revenues, and whether smaller independent platforms can compete with utility balance sheets. As a fully merchant platform, we see the CM as optionality rather than a necessity; our business case does not depend on it.

What are the other key policy questions and grey areas which German industry and government still need to solve, to unlock storage’s full potential for the grid?

Flexible connection agreements (FCAs) are the point we would highlight. Storage is the ideal counterpart for a flexible connection, because curtailment can be priced and managed around. But two conditions have to be met for FCAs to work in practice. First, FCA terms must be communicated transparently and early, before later-stage development processes begin, so that developers can plan sites and business cases around them instead of discovering restrictions late in the process. Second, an FCA must still leave a good business case: the instrument only helps if projects remain bankable while at the same time enabling better utilisation of the local grid constraints. If both conditions are met, FCAs can unlock connection capacity that would otherwise sit idle.

How is the financing of BESS projects evolving?

The honest answer is that the direction of travel reversed this year. In 2025, merchant business cases became bankable, and we achieved exactly that: we financed our pilot project at 70% LTV with a senior loan on a fully merchant revenue strategy, based on conservative underwriting (we discount bankable revenue forecasts by up to 30% depending on COD), standardised technology and strict SPV-level ring-fencing.

In 2026, merchant projects are still bankable, but the overall financing environment has clearly shifted for the worse. It has become much harder for medium-voltage projects, which do not carry large CAPEX volumes, to secure sufficient senior debt financing, even when the business case itself works really well.

How is the balance between merchant and tolling/fixed revenue schemes changing? In other words, to what extent are offtake and contracted revenues key to getting project finance?

The market is visibly shifting towards tolling and floor structures as banks push for contracted revenues, but I would push back on the idea that offtake is a prerequisite for project finance. Our own pilot financing closed fully merchant at 70% LTV, and mandates like MEAG’s 231 MWh fully merchant portfolio show institutional capital is comfortable with market risk when the optimisation setup is credible.

The honest answer is that the structure follows the capital: utility-scale funds and infra investors with return targets around 7 to 9% want floors and tolls; platforms like ours targeting equity IRRs around 15% deliberately retain merchant upside and manage the risk through portfolio diversification, conservative revenue curves and front-loaded cash flows. Expect a barbell: more tolling at the large-cap end, continued merchant conviction among independent flexibility platforms.

What is the current mix of ‘full wrap’ and ‘multi-contracting’ for BESS project delivery, and is this/how is this expected to change going forward?

Full wrap EPC will still be a thing for the upcoming few years. In the long run, however, especially once grid fees come in and revenues go down, the BESS players that sustain will be the companies that bring their CAPEX down by working with lean internal EPC teams and ordering the components themselves, rather than paying for a full wrap.

What are the factors and strategies that are determining which BESS suppliers succeed in the German energy storage market?

From a developer’s perspective, two factors matter most: bankability and warranties. Bankability is a deal breaker. You want to make sure you are using tier-one components that are already built out in the German market and that the banks accept; without that, the financing conversation ends before it begins. Secondly, you want a supplier with a strong warranty structure that genuinely supports your business case over the asset’s lifetime. Everything else is secondary to those two factors.

How is the role of TSOs and DSOs in the German energy storage market evolving?

Both are evolving from passive gatekeepers into active market shapers. DSOs matter most for platforms like ours connecting at medium voltage: they control connection timelines, BKZ methodology and increasingly the terms of flexible connection agreements, and the variance between DSOs in speed, transparency and cost is enormous. Standardising that interface would do more for storage build-out than most federal policy debates. TSOs, meanwhile, are becoming counterparties as much as regulators: growing procurement of ancillary services, congestion management, and pilot projects for grid boosters where storage substitutes for redispatch.