Germany’s Offshore Wind Auction Failure: where ambition meets reality

A quick look back: how did we get here?

To understand how Germany’s latest offshore wind auction ended with zero bids, it’s worth tracing the policy journey that got us here.

Germany entered the offshore wind era with high hopes. In 2017, the introduction of the Offshore Wind Energy Act (WindSeeG) marked a new phase of competitive tenders and early results were promising. The 2017 and 2018 auctions awarded 3.1 GW of capacity, with some projects bidding at zero. I still remember the wave of excitement and disbelief when EnBW and Orsted won sites back in 2017. It was a bold move, a first in Germany, and people were stunned: how did they pull that off?

For a deeper dive into this aspect, I recommend the BWO interview with my colleague Udo Schneider with the title: “2017 – Null Cent, große Wirkung: Wie ein Auktionsjahr die Offshore-Wind-Finanzierung änderte”: https://bwo-offshorewind.de/15-jahre-offshore-wind-in-deutschland-2017/

That headline “subsidy-free offshore wind”  became a symbol of confidence in falling technology costs, strong investor appetite, and maturing markets.

By 2022, Germany had set ambitious targets: 30 GW of offshore wind capacity by 2030, scaling up to 40 GW by 2035 and 70 GW by 2045 as part of its broader strategy to decarbonize power generation and ensure energy security.

However, the design of the auction system changed in 2023 with the introduction of negative bidding. Under the new rules, if more than one developer submitted a zero-subsidy bid, they would enter negative bidding rounds and essentially pay the federal government for site access. Competition began to narrow, especially after that first 2023 auction, and the approach quickly drew sharp criticism from the industry. The model could work, but only if several assumptions held true: that technology and financing costs would keep falling, and that wholesale power prices would rise enough to keep projects profitable. At first, these assumptions seemed plausible. The 2023 round awarded 7 GW of capacity, with major players like BP and TotalEnergies committing over EUR 12 bn in concession payments (up to EUR 1.8 M per MW). The message seemed clear: the market was still willing to bet big.

In 2024, the momentum appeared to continue and 8 GW of capacity was awarded across two tender rounds, though the field of participants narrowed further. Bids remained high, with developers such as TotalEnergies and EnBW committing more than EUR 1 bn per project.

Then came 2025: in the first auction round, only two bidders participated. In the second round: none at all.

So why did the 2025 auction fail?

While the two auctioned sites, N‑10.1 and N‑10.2, came with their own technical challenges (deep water, uncertain grid connection timelines), the reasons behind the lack of bids go well beyond location-specific issues.

It reflects a widening gap between project risks and expected returns. Higher capital costs and capture price forecasts falling short of earlier expectations have made it increasingly difficult to model long-term project economics with confidence. Capex remains high, also because of a lack of competition on the turbine supplier side. Even though the expectation remains that parts of the supply chain will eventually stabilise, especially as fewer projects move forward globally, developers are still left with high uncertainty around electricity price risk. This is particularly relevant in a market like Germany that experiences increasingly frequent negative price hours and where long-term corporate PPAs may no longer offer the terms developers need to secure low-cost financing and a viable business case.

In this environment, the negative bidding model in Germany may have made developers think twice. While it succeeded in raising significant proceeds in previous rounds (note: 90% of the concession payment will only be paid over time after the project reaches COD), it also increased financial pressure on developers and may have discouraged broader participation. The model relies on costs continuing to fall and on developers maintaining a high tolerance for risk. These are assumptions that don’t feel sustainable.

This isn’t so much a failure of ambition or a challenge to offshore wind’s role as a cornerstone of the energy transition. Rather, it is a signal that the market conditions have changed and a reminder that policy design must evolve to keep future auctions attractive to investors and to safeguard Germany’s energy security.

CfD to the rescue?

Unfortunately, the answer is not as easy as that. Two-sided Contracts for Difference (CfD) are a powerful tool. They reduce revenue volatility, lower cost of capital, and have proven effective in other markets. The industry has long championed CfDs and we have been fans too. But in Germany, the answer isn’t as simple as adopting a CfD and all problems would be solved. In a time when renewables are once again under intense public scrutiny, it’s crucial to design a system that benefits the public without increasing the burden on taxpayers. Any remuneration model must ensure that renewable electricity is integrated into the broader power market in a cost-efficient and reliable way.

Renewable generation carries both volume risk and price risk. When large amounts of wind or solar electrons hit the grid at the same time and beyond demand, their value drops. This is especially evident during high-wind periods when every wind farm is generating at full capacity, driving down market value.

It’s understandable that the state can’t compensate at all times. Doing so would undermine market efficiency and could create severe system inefficiencies. On the flip side, leaving all the risk with developers drives up financing costs, as investors price in uncertainty, putting further pressure on project economics. Over time, this could undermine investors’ appetite and in turn, jeopardise the pace of the energy transition.

The questions are complex but unavoidable:

• How to deal with the volume risk? Should remuneration be tied to actual production, to a fixed reference output or to available capacity?
• How can incentives be designed so that offshore wind supports the grid when it’s most needed?
• How do we keep offshore wind as a needed source of energy attractive to investors?
• Will LCOEs rise over time as system challenges to reshape renumeration models?

What now? Some food for thought

Germany has committed to 30 GW of offshore wind by 2030. That’s not a distant target – that’s five years away. Can we get there without reform? Could a shift to CfDs restore investor confidence? And if so, how should they be structured to ensure both system stability and efficiency?

This isn’t just about one failed auction. It’s a moment of truth for Germany’s energy transition, industrial competitiveness, and climate goals.

The spotlight is now on Berlin: the choices made in the coming months will determine whether this setback becomes a costly pause or the beginning of a much-needed shift toward a smarter, more stable policy framework.

Any redesign will also have consequences for projects awarded in recent years, many of which remain exposed to negative price risks. The challenge will be to create a new remuneration system that supports future investment without penalising those already in development.

We at Green Giraffe Advisory will be following the policy debate closely and stand ready to contribute, as its outcome will shape not only the next auction round and the future of Germany’s energy transition, but also the business cases of our clients. Stay tuned.