By ESS news
The opening session of BBDF day two highlighted the completion of the project, with the discussion focusing on the very real work required to get a turnkey project off the ground.
Industry experts detailed the complex negotiations that must take place between parties, with banks, optimizers, developers and an engaged industry audience all sharing their perspectives. From working with distribution system operators and navigating flexible grid connection agreements to securing credible revenue streams, attendees delved into the practicalities of completing a BESS project by 2026.
Real-world examples formed the cornerstone of the session and attendees were treated to a presentation describing two different routes to market for projects conceived in Germany.
Marcel Marquart, country manager for Germany at Clean Horizon, presented a standalone 50 MW/150 MWh project, which represented a pure trade approach. Meanwhile, Xenia Ritzkowsky, senior consultant at Enervis energy advisors, has developed a co-located model in which a 20 MW battery is added to an existing 25 MWp solar park with an existing 20 MW grid connection.
The dual focus set the stage for a debate between the higher revenue potential of standalone assets and the cost savings that BESS co-location can achieve by sharing infrastructure.
The DSO labyrinth
According to recent developer surveys, grid connection is the main obstacle to BESS adoption, closely followed by securing financing. BBDF participants heard how flexible interconnection agreements (FCAs) have evolved from simple permits to complex, site-specific documents that dictate how an asset can actually behave on the network, and that can change over the project development timeline.
Marcel Marquart illustrated the current climate using three FCA scenarios. Case A was presented as the restriction-free scenario and was considered unrealistic in 2026. Case B was presented as a more realistic scenario, introducing a ramp rate limitation of 10% of the installed power per minute and a limit on participation in support services of up to 50%. Case C was a 5% gradient and a two-hour order book freeze before delivery – somewhat unrealistic as it was too restrictive, and more of a developer’s nightmare. The presentation continued with the middle ground Case B as a reference.
One of the main pain points discussed was the instability of the rules that developers must adhere to.
Stephen Stakhiv, fund and investment manager at Flower, shared a cautionary tale from the field in Germany. Stakhiv told the audience that “a few weeks ago a DSO came back and adjusted the incremental rate to a level that made the project unfinanceable.”
This kind of pivot is exactly why early-stage involvement is basically mandatory.
Anoucheh Bellefleur, market and strategy team manager at ABO Energy, noted that these key design and technical specification decisions occur pre-ready-to-build (RTB) and require ongoing communication with lenders.
Developers are pushing for better exit strategies to protect against this. Bellefleur proposed negotiation clauses that would allow a developer to return the grid connection and reclaim its down payment (BKZ) if the DSO makes the project technically impossible. The point is to reduce the initial deposit, which can often amount to millions of euros.
The reality of virtual trading
Optimizers can have different views based on the realities of trading and Marcus Fendt, director of The Mobility House, pointed out that financial models often overestimate the physical impact of these limits. He explained that normally every transaction can be considered an option, and that patterns of actual battery charging and discharging do not reflect transactions.
The Mobility House MD also pointed out that roughly one in six to 10 trades are physical, and the rest are virtual, just like in commodity options markets – essentially no actual delivery is required. Because virtual transactions do not reach the physical network, the ramp rate does not impact the internal rate of return (IRR) as much as limiting support services would. However, it was emphasized that lenders will only buy into this if the consultancy explicitly models the assumptions of flexible connection agreements into the revenue stack from day one.
Purchasing: Turnkey EPC or DIY?
Attention then turned to engineering, purchasing and construction (EPC). Panelists discussed whether developers opt for a full EPC wrap deal, a turnkey contract where the EPC supplies all the equipment and charges a margin, or a do-it-yourself multi-contract approach.
Bankability is the main catch. Savings can be valuable, but the risks are multiplied. Tim Koenemann, Global Head of Green Infrastructure Finance at Commerzbank, said that while BESS is not the most complex thing to build in terms of large infrastructure projects, the interface risk of multiple contracts is a hurdle for debt. From a bank’s perspective, a full wrap EPC is simply simpler. If a developer chooses the individual offering route, the bank will need a very high level of trust in the sponsor to manage these interfaces.
Developers like ABO Energy echoed this, noting that moving away from a full wrap requires a strong internal capability to deal with all these different interfaces and ensure you have a foolproof strategy for aligning warranties. The audience also asked how other parties can be involved, such as owners’ engineers, to make DIY efforts less risky; and integrators, who can provide more than just the BESS by supplying all other power components. There are many other strategies that fall between complete turnkey or complete DIY.
Several panelists agreed that the multi-contract nature of DIY projects can cause problems. Koenemann said that from the bank’s perspective, multi-contracts are difficult to finance, especially for new players where ‘finger pointing’ over performance guarantees could jeopardize the project. ABO Energy’s Bellefleur explained that strong internal experience and skills in dealing with multi-contracts are crucial.
Assessing debt versus seller exposure
Risk sharing is the name of the game for BESS financing in Germany. Traditional lenders are still wary of 100% merchant exposure, a fact reflected across BBDF. Koenemann said that for Commerzbank a non-contracted strategy is not yet bankable. For non-recourse project financing, the market typically wants 50% to 60% of capacity to be leased for five to seven years through a tolling agreement.
This creates a divide in how debt is sized. Toll sections can have a Debt Service Coverage Ratio (DSCR) of 1.15, while merchant sections require a much larger buffer, often a DSCR of 2.0, to cope with the volatility.
Both Marcus Fendt and later Anoucheh Bellefleur gently challenged the conservative attitude of the banking sector and those who operate BESS.
Fendt argued that banks often only look at downward price developments, but that in some cases banks must also be aware of upward trends. He cited California, Australia and the United Kingdom as evidence that regulators are ultimately recognizing the value of storage and can offer new products that support the electric grid and generate additional revenue.
“Our regulator will recognize the value of storage in five to seven years,” Fendt predicted, suggesting that those who bridge the current gap now will reap the benefits later.
Bellefleur also noted that developers may want to retain a minority stake in a project to capture potential benefits while spreading risk.
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