Germany Wind Auction Reforms: Risking Growth Targets Amid Policy Uncertainty

Germany's energy transition faces new headwinds after an August 2025 auction for two North Sea offshore wind sites received zero bids. The government had scaled back 2026 offshore wind auction targets to just 2.5–5 gigawatts from an initial 6 gigawatts following this failure, citing rising costs and supply chain constraints. This collapse highlights fundamental flaws in auction design: developers faced risks of paying for rights without revenue guarantees, creating unacceptable financial uncertainty.

Industry leaders warn these systemic issues threaten the country's 2030 offshore wind target of 30 gigawatts. Grid connection delays averaging two years compound the problem, paralyzing project timelines and increasing financing costs. The economy ministry acknowledges reforms are critical, proposing Contracts for Difference (CfDs) to stabilize returns-a model Denmark successfully uses-while pushing revised auctions for early 2026.

Without swift fixes, supply chains could unravel further. Industry groups warn another failed auction would devastate local jobs and deter investment, risking Germany's position as a clean energy leader amid EU-wide market shifts.

Onshore Growth Masks Underlying Policy Fragility

Germany's onshore wind expansion hit its highest rate since 2017, adding 2.2 GW in H1 2025 with 7.8 GW licensed for the year, though projects still lag behind EEG targets. According to clean energy data, this growth occurred alongside a decline in renewables' overall electricity share to 54% in H1 2025, down from 57% a year earlier. The dip was driven by historically weak winds cutting wind output by 17% and low precipitation slashing hydropower generation by 30%.

Despite these physical constraints, auction competition reached record levels. Developers submitted 5.7 GW of bids for only 3.443 GW of capacity in the 2025 auction. Prices fell sharply to an average of 6.57 ct/kWh, below the 7.35 ct/kWh ceiling and down from 6.83 ct/kWh in the previous round. North Rhine-Westphalia and Lower Saxony dominated awarded projects, while Brandenburg achieved its largest auction volume.

Looking forward, capacity additions are projected to reach 4.8-5.3 GW in 2025, driven by record 2024 permits (14 GW) and support contracts (11 GW). According to SP Global research, however, this growth remains vulnerable without accelerated grid reforms. Industry leaders warn that unresolved grid connection bottlenecks and delayed permits could undermine expansion momentum. Without addressing these systemic constraints, Germany's ability to meet its EU renewable goals faces significant risk.

Cost Inflation Undermines Project Economics

Offshore wind projects face a double-digit cost surge in 2024, contradicting earlier progress. Germany's offshore LCOE now ranges between €55 and €103 per megawatt-hour (MWh), reversing a previous decline that saw it fall from €73–121/MWh in 2021. Onshore wind costs also rose, climbing to €43–92/MWh for the same year. This inflation stems from higher capital expenses, notably a 6.6% weighted average cost of capital (WACC) in 2024, alongside persistent supply chain bottlenecks. These pressures threaten the affordability traditionally associated with renewable energy projects.

Despite these headwinds, some cost factors show promise for future reductions. Steel prices have dropped, and turbine costs have stabilized, offering limited relief. However, these benefits are insufficient to offset the broader inflationary trends impacting project viability.

The situation is further complicated by stark regional differences in onshore wind power purchase agreement (PPA) prices. In 2024-2025, 3-year PPA averages varied significantly across regions, from a low of €67.72/MWh in Bodensee to a high of €76.57/MWh in Hanover, with a national average of €73.13/MWh. This spread, influenced by local wind resources, grid zone imbalances, and existing installation density, highlights the lack of uniformity in market conditions. Compounding the challenge, falling wholesale electricity prices and frequent negative pricing events (301 hours in 2023) have eroded profitability. Consequently, 17% of Germany's existing onshore wind capacity is now heavily reliant on PPAs or market hedging strategies to remain financially sound. The dominance of solar in securing PPAs, accounting for just 3% of 2023 contracts, underscores the competitive pressure on onshore wind and the critical need for private-sector PPA growth to meet ambitious 2030 renewable targets.

Structural Risks and Downside Scenarios

The offshore wind thesis faces serious structural headwinds that could materially delay progress and erode returns. Germany's auction system has already failed once: a recent 2.5 GW tender received zero bids, and targets for 2026 have been slashed to 2.5–5 GW from 6 GW due to cost pressures and revenue uncertainty. This raises immediate concerns about repeated no-bid outcomes under unchanged mechanics, threatening supply chains and employment. The government's planned 2026 auctions may not resolve core flaws, as reforms like contracts for difference remain unimplemented while grid connection delays persist. These bottlenecks could push 30% of offshore projects past 2030, jeopardizing the €200 billion+ investment needed to reach the 30 GW target.

Grid infrastructure is a critical vulnerability. North Sea connection system delays of up to two years compound project execution risks, increasing financing costs and undermining viability. If these timelines aren't synchronized with turbine development, the cumulative effect could stall nearly a third of planned offshore capacity. Simultaneously, wholesale electricity market volatility invalidates economic assumptions underpinning power purchase agreements (PPAs). In 2023 alone, negative prices lasted 301 hours, eroding onshore wind profitability and forcing 17% of capacity into hedging or PPAs. Since PPAs currently cover only 3% of contracts, their scaling is essential yet uncertain amid falling prices-averaging €73.13/MWh nationally but varying by nearly €9/MWh regionally due to grid congestion and resource quality.

For investors, these risks demand caution. Auction failures signal deteriorating project economics, while grid delays act as a hidden drag on execution speed. Even if auctions proceed, the unresolved tension between long project lifetimes (now proposed at 35 years) and short-term market volatility could make PPA-based revenue models unsustainable. The industry's call for CfDs highlights a recognition that current rules disincentivize investment. Without accelerated reforms, the pathway to 2030 capacity targets-and predictable returns-remains highly fragmented.