Considering Grid Charges When Optimizing PV + BESS Revenues
- media7122
- Aug 10
- 5 min read
While wholesale electricity prices remain the primary driver of trading profitability, they are far from the only factor. In many countries - and even within specific regions - Distribution System Operators (DSOs) and Transmission System Operators (TSOs) apply variable grid fees. These charges often depend on time of day, voltage level, and day of the week. Ignoring them can erode project revenues, especially for utility-scale PV and battery energy storage systems (BESS). A well-designed trading algorithm must therefore account for these dynamics. In this article, I’ll focus on how grid charges impact revenue optimization, with a deeper look at three of Europe’s largest BESS markets: the UK, Germany, and Italy.
Grid Fees Vary by Region: Utility-scale PV + BESS projects face different TSO and DSO charging regimes, depending on the country. In this article I refer to the three currently most attractive European BESS markets (UK, Germany and Italy):
United Kingdom
In the UK, utility-scale BESS and PV projects connected at the distribution level (below 132kV) are subject to Distribution Use of System (DUoS) charges. These include:
Variable charges – based on imported/exported energy volumes and time-of-use bands
Fixed charges – per metering point
Capacity charges – based on the contracted connection size
These components vary by region and voltage level (Low Voltage, High Voltage, or Extra-High Voltage). Importantly, variable charges are higher during peak demand periods, particularly during weekday "red bands". However, batteries exporting during these periods may receive Generation DUoS credits, effectively turning grid charges into a revenue stream.
Projects connected at Extra-High Voltage (EHV) may have bespoke DUoS arrangements, but typically still incur capacity charges. Import behavior can be optimized to minimize variable fees.
On the transmission side, Transmission Network Use of System (TNUoS) charges can largely be avoided by correctly registering the asset as “Non-Final Demand.” Since 2023, this designation exempts batteries from most transmission charges, aside from minimal Triad-related imports, which can also be optimized operationally.
Germany
A July 2025 ruling by the Federal Court of Justice (BGH, Case EnVR 1/24) confirmed that grid operators may apply the Baukostenzuschuss (BKZ) - a construction cost contribution - to BESS, just as they do for other large grid-connected consumers. Importantly, the court clarified that the levy is lawful, but not mandatory; local grid operators retain discretion over whether to apply it.
While this decision has raised concerns among developers and investors, I would like to share my personal view: given the massive queue of grid connection applications in Germany—estimated at 400–500 GW, compared to a total market depth of around 50 GW—this measure likely acts as a regulatory screening measure. It enables grid operators to filter and prioritize projects based on their maturity, readiness, and long-term value to the grid.
Currently, utility-scale battery projects are exempt from operational grid fees until August 2029, as part of a national policy to encourage BESS deployment. This exemption significantly improves project economics today, but stakeholders should prepare for potential changes beyond that date.
Italy
Unlike the UK with detailed DUoS charging frameworks applied at multiple network levels, Italy’s system largely bundles grid usage costs into auctions, connection fees, and balancing service charges managed by Terna. Variable Fees (Dispatching Fees) are based on these real-time market results, reflecting the cost of maintaining grid balance during specific time windows, thus making the fees time-varying. Therefore, it is essential to account for Dispatching Fees when developing a bidding strategy for balancing and ancillary services.
Grid fee structures in Italy are still evolving. In some cases, grid-owned storage assets may benefit from regulated returns (such as MACSE), and grid access charges are still under policy development. This creates uncertainty but also opportunity, especially for early movers.
UK Case Study:
Modelling DUoS Charges in BESS Optimization
When optimizing distribution connected BESS revenues in the UK, DUoS charges must be carefully modelled and managed, as they can significantly impact operational costs and, consequently, overall profitability. Here is how DUoS charges are typically considered in BESS optimization:
Optimize Charging and Discharging Behaviour: Since DUoS charges apply when importing energy from the grid (i.e., charging the battery), BESS operations are optimized to minimize energy imports during high DUoS periods or high-demand periods that influence capacity charges. Strategic timing of charging (e.g., during off-peak hours) is critical to reducing DUoS costs. Batteries connected to the distribution network may also receive generation DUoS payments (credits) when exporting energy during specific time periods -known as "red bands" - when network demand is high. These DUoS export credits are both time-banded and location-specific, offering financial incentives for batteries to discharge (export) energy during peak demand or network stress periods. By scheduling discharging during these high-value export windows, BESS operators can maximize the DUoS payments received, effectively turning a portion of the DUoS costs into a revenue stream rather than a pure expense. For example, a two-hour battery performing daily cycles aligned with DUoS red bands and wholesale market price peaks can potentially generate substantial net DUoS revenues, particularly in regions with favourable tariff structures such as Southeast England.
Leverage Non-Final Demand Status to Minimize Charges: For transmission connected batteries, by qualifying for “Non-Final Demand” status for grid charging, batteries can avoid certain TNUoS charges that are typically applied to end consumers - especially volume-based tariffs. The "Non-final demand" refers to facilities that perform their functions without consuming active power from the grid for final use (such as electricity storage facilities, generation-only facilities, or combined generation and storage). However, capacity-based TNUoS charges generally cannot be fully avoided and must still be incorporated into the operational optimization strategy.
Accounting for Energy Market and Ancillary Revenue: DUoS charges should be modelled alongside projected revenues from wholesale energy arbitrage, balancing services, capacity markets, and grid-support ancillary services. The optimization algorithm must weigh these revenue opportunities against the associated grid charges to maximize net profit.
Incorporate Future Grid Fee Changes: The UK regulatory and grid landscape is evolving, with ongoing reforms that could significantly alter DUoS structures and pricing. Optimization models should therefore remain flexible and adaptable to future changes, considering dynamic DUoS charges - such as time-of-use or locational pricing - to ensure sustained profitability.
To illustrate how grid charges can be turned into a revenue lever, consider the example of a 5MW / 1.5hr High Voltage BESS system located in Southeast England:
From the published Use of System Charging Statements it can bee seen that the DUoS Cost Breakdown (2025) is:
Fixed charges: £1.67/day → ~£610/year (negligible)
Capacity charges: £74.1/MVA/day → ~£135,000/year (~£27,000/MW/year)
Variable charges:
Import during red bands: £59.95/MWh (cost)
Export during red bands: £68.24/MWh (credit)
By carefully optimizing expected revenues from wholesale energy arbitrage, balancing services, capacity markets, and grid support ancillary services alongside with those DUoS charges, the BESS can generate ~£174,000/year of added revenues (~£34,850/MW/year)!
In other words, the BESS can effectively offset its capacity charges entirely and even generate ~£7,800/MW/year in net DUoS revenues - demonstrating that grid fees are not just a cost center, but a potential value stream.
Conclusion
Grid charges can have a substantial impact on the profitability of PV + BESS projects. As shown in the UK example, strategic optimization that incorporates time-of-use tariffs, locational pricing, and regulatory exemptions can transform grid fees from a cost burden into a revenue opportunity. With evolving grid policies across major markets like the UK, Germany, and Italy, project developers must ensure their trading algorithms and financial models are flexible, granular, and grid-aware to fully unlock the value of energy storage.
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