From frequency control to solar cannibalisation: every mechanism that drives battery value

Executive summary

• German battery capacity passed 2 GW in mid-2025 and could exceed 3 GW by year-end, making it Europe's fastest-growing storage market.
• Day-Ahead spreads widened from €30/MWh in 2019 to €130/MWh in 2024, driven by solar cannibalisation pushing midday prices negative.
• Ancillary revenues are compressing as battery participation grows; the revenue stack is shifting toward wholesale trading.
• Flexible Connection Agreements can reduce revenues by 10-13% through import/export caps and ramp-rate limits, but enable faster grid access.
• A new inertia product from 2026 offers €8-17k/MW/year for grid-forming batteries, creating one of Germany's few locational revenue signals.

1. Why should Germany be on your radar for battery storage?

Germany is Europe's largest electricity market and fastest-growing battery system. Capacity passed 2 GW in mid-2025 and could exceed 3 GW by year-end.

It's also one of the hardest markets to model. A single price zone hides deep regional bottlenecks. Multiple balancing layers overlap. These grid constraints have turned congestion management into a daily event.

Understanding how these layers stack defines where batteries earn money, how they trade, and how quickly the business case shifts from regulated services to merchant markets.

Germany's operational BESS fleet reached 2.5 GW by end-2025, with average duration trending from 1.4h toward 2h+ for new builds.

2. How do Germany's electricity markets layer together?

A single day spans five gate closures: FCR → aFRR → Day-Ahead → Intraday → Redispatch.

• FCR and aFRR pay for frequency control: the predictable ancillary base.
• Day-Ahead and Intraday reward energy shifting: the merchant upside.
• Redispatch intervenes when grid congestion breaks price signals.

For German batteries, operating across all five determines long-term value. Ancillaries secure access. Wholesale trading defines returns. Redispatch and grid rules decide who can deliver.

3. How does the Day-Ahead market work in Germany?

Prices clear in 96 fifteen-minute blocks at 12:00 CET through a single auction. All generators, demand units, storage, and interconnector flows coordinate their schedules and set prices to match supply and demand.

​Day-Ahead sets the state-of-charge plan that operators refine through Intraday and ancillaries.

As solar and wind reshape generation, the spreads between the highest- and lowest-priced hours widened from €30/MWh in 2019 to €130/MWh in 2024. Batteries target these differences: charging at midday lows, discharging into evening peaks.

Based on Modo Energy analysis, German Day-Ahead spreads quadrupled between 2019 and 2024 as 100+ GW of solar drove midday prices negative.

4. Why is Germany's Intraday market so volatile?

After Day-Ahead closes, generators and offtakers still need to balance supply and demand in real-time. Germany's intraday is Europe's most liquid market: over one million trades clear daily across 96 delivery windows.

Continuous trading runs until five minutes before delivery. Liquidity peaks in the last half hour as participants close positions to avoid imbalance penalties.

Over half of 2025 trading days saw at least one transaction above €1,000/MWh. Operators combine physical dispatch with non-physical churn, reselling positions as prices move.

Intraday now accounts for a major share of German battery revenues, but merchant competition is rising fast.

5. What is Redispatch and how does it affect batteries?

When the grid can't move power despite commercial balance, Redispatch 2.0 gives TSOs and DSOs the authority to override schedules.

Redispatch costs in Germany hit €2.8 billion in 2024, up fifteen-fold in a decade. Every unit above 100 kW must comply.

Compensation follows pumped-hydro logic, rarely reflecting real battery behaviour. Storage remains underused despite its potential to cut congestion costs. But curtailment could disrupt battery schedules, resulting in an important downside risk for operations.

6. How do FCR and aFRR revenues work for German batteries?

Germany anchors two major European frequency markets.

FCR: ~3 GW procured daily across the continental zone, ~570 MW for Germany. Full activation within 30 seconds.

aFRR: ~2 GW capacity, €400 million TSO spend in 2024. Activation completes in five minutes.

Batteries dominate both on precision and speed. But growing participation has compressed margins. Ancillaries remain the entry point; the biggest upside now lies in wholesale optimisation.

Based on Modo Energy analysis, German battery qualification reached ~550 MW in aFRR and ~800 MW in FCR against ~570 MW procured.

7. What is Germany's new inertia market and how much can batteries earn?

Since early 2026, TSOs have been procuring inertia through a fixed-price, availability-only product. Grid-forming inverters emulate rotational inertia in milliseconds, stabilising frequency.

Economics:

• Revenue uplift: €8-17k/MW/year on top of market revenues
• CapEx increase: up to 5% for grid-forming inverter
• Energy requirement: minimal (0.035% of a 1-hour battery)

Scale: Germany needs ~30 GW of inertia-capable batteries by 2027, rising to 72 GW by 2037.

Location matters: TSOs can reject bids once regional needs are met. Biggest opportunities: northwest Germany (offshore wind DC lines) and northern Bavaria (high solar, near system-split fault lines).

8. How do Flexible Connection Agreements affect battery revenues in Germany?

FCAs trade firm grid rights for faster access. Revenues fall when dispatch is constrained.

Three restriction types:

1. Import/export caps: Based on Modo Energy modelling, a 2-hour, 75 MW battery with 2028 COD loses 13% of average revenues.
2. Ramp-rate limits: A 15-minute ramp cuts lifetime revenues by 10%+. A 5-minute ramp costs ~5%.
3. Ancillary restrictions: Without carve-outs, ramp limits cap aFRR participation (assets must reach power within 5 minutes).

Duration matters: 1-hour batteries lose 1.4pp IRR moving from 5-minute to 15-minute ramps. 4-hour batteries lose only 0.7pp.

FCAs are becoming standard in German grid negotiations. Understanding their impact on dispatch and IRR is essential for lenders.

9. Where should you build a battery in Germany?

No locational price signals exist. Every asset faces the same wholesale price. But cost and access vary sharply.

Based on Modo Energy analysis:

• BKZ fees: up to 80% lower in the north
• Land costs: up to 90% cheaper in the north and east
• Connection queue: exceeds 500 GW

Grid access is the real constraint. Developers focus on which DSOs process fastest, which regions have spare capacity, and how redispatch rules treat storage.

The latest proposals for locational, dynamic grid fees may increase locational differences from 2029, but batteries built before then are likely to be exempt.

10. Should you co-locate a battery in Germany?

Germany has a solar problem: over 100 GW of PV, but summer demand rarely exceeds 60 GW. On sunny days, the grid floods, Day-Ahead prices crash, and the solar capture rate has plummeted from 98% in 2022 to 54% in 2025.

For solar developers, merchant solar is increasingly difficult to finance, and EEG subsidy strike prices are falling.

Batteries are the fix. Co-location is the fastest route to deploy them.

• Co-locating a battery has advantages for CapEx and grid access. A green battery (which does not charge from the grid) can often bypass the connection queue, bringing immediate access.
• But the setup matters: green batteries are very restricted in their operation, lowering their IRR compared to a grey battery which can charge from the grid.
• There is a subsidy in place for newly built green batteries: Under the Innovation Tenders, the solar-storage combination enters into a one-sided CfD which pushes IRRs into investable territory.

11. What is the outlook for German battery revenues?

Ancillary revenues once anchored the German battery case. Saturation and competition are now pushing toward multi-market trading.

• FCR and aFRR returns are falling as battery participation rises. Margins will compress quickly, and entry is no longer a guarantee of strong returns. But a stronger focus on wholesale trading, with longer-duration batteries, still promises meaningful revenues.
• After 2029, new grid fees will shape project IRR. Once the exemption runs out, batteries will have to submit to a new system of grid fees that may reduce IRRs, but increase locational value and add another layer of complexity to optimisation modelling.
• A capacity mechanism may rebalance the stack. Germany plans to finalise a capacity market by 2027, with delivery in 2031, which would increase reliable revenue for batteries. But the specific market design and any de-rating factors are yet to be announced.

All revenue scenarios carry three big risks, which forecasts have to take into account:

1. Demand growth may disappoint. Many forecasts assume rising electrification and dispatchable demand, like hydrogen or data centres. If that growth lags, volatility (and spreads) could shrink.
2. Gas remains the price-setter. Merchant revenues hinge on peak prices, and those still track gas. If gas softens, batteries will feel it directly.
3. Overbuild could squash opportunities. If developers try to get their battery online before 2029 and battery deployment continues at breakneck speed, wholesale saturation could cannibalise battery revenues.