Reform of the German electricity grid tariff system: Should producers pay grid charges?

The German regulator Bundesnetzagentur (BNetzA) published a discussion paper regarding the future of electricity grid charges in Germany in May 2025.¹ The paper asks critical questions regarding the future grid charging architecture in Germany and the consultation could yield a complete system overhaul in relation to tariff design.

Following a ruling by the European Court of Justice, which found that the existing normative regulation enacted by federal ordinances breaches the EU internal electricity market directives, the BNetzA must replace the previous regulatory framework with a new determination for grid charges from 2029 onwards.²

An overhaul of the grid charge system is also an opportunity to reflect the fundamental changes and challenges to the electrical grid arising from the net zero target and the continuing rise of renewable energy. Decentralised energy generation and the disconnect to locations of demand, the temporal pattern of renewable electricity generation, increased self-use and the rise of prosumers (i.e. energy consumers who also produce electricity, e.g. via solar panels in homes, and may export excess power to the grid) and the dramatic general increase in electricity demand might well require a different approach to grid charges compared to the existing system with all charges paid by consumers and charges mainly based on energy-usage.

The BNetzA poses five main questions within the consultation process: (1) Should producers pay grid charges as well? (2) How should tariffs be structured? (3) Should there be regionally and temporally dynamic charges? (4) Should charges be unified across local distributional grids? (5) How should storage be charged?³

This article discusses the first question on whether producers should pay grid charges. It is structured as follows: first, we set out the problem; second, we highlight the pros and cons, including the extent to which such a system change can reduce overall grid costs; third, we point out that, despite such a change, consumers would ultimately be likely to pay the costs; fourth, we discuss interdependencies with state aid, which can undermine previous conclusions; fifth, we consider grandfathering questions; and sixth, we presents our conclusion.

System cost and cost causation

The expansion of renewable energy generation is a ‘key driver of network costs’.⁴ Furthermore, the additional system costs are increasing due to the fluctuating feed-in profiles of renewable energy.⁵ These costs extend beyond the direct costs for the production of electricity at the power plant; they encompass a range of expenditures, including congestion management, balancing services, and the necessary reinforcement and expansion of grid infrastructure.

Congestion management is one of the most substantial additional system costs associated with the increased levels of renewables, given the need to manage the intermittency of renewable energy generation. Much of Germany’s renewable generation is concentrated in the wind-rich north and east, whereas its industrial demand centres lie in the south and west, creating significant grid bottlenecks. To alleviate these, network operators must implement expensive measures such as redispatch and countertrading.⁶ In 2023, Germany’s grid congestion management costs reportedly exceeded €3bn, up from approximately €1.5bn in 2018.⁷

As electricity producers in Germany currently do not pay for grid charges there is a fundamental misalignment with the actual drivers of grid costs in a system increasingly dominated by renewables. This misalignment arguably leads to inefficient grid usage and distorted investment signals; on the other hand, it provides strong financial incentives for renewables uptake, which has been a priority to decarbonise German energy production and reduce reliance on lignite, in particular, over time. In contrast, producer grid charges already exist in the German gas sector, and electricity producers already pay grid charges in other large European countries.⁸

Given this background, the BNetzA argues that feed-in charges would give an opportunity to involve electricity generators in the financing of the grid costs and would improve cost-reflectivity and incentives around investment in line with system costs. The BNetzA considers that by encouraging the party that incurs the costs to bear the costs, it can improve efficient investment and reduce overall grid costs (and accordingly the grid charges).⁹

The BNetzA considers different design variants for feed-in charges. Specifically, the BNetzA considers that electricity generators could contribute through feed-in tariffs based on: (1) the capacity booked by the generators ex ante; (2) the number of units of energy provided to the grid; (3) the maximum load fed into the grid; (4) a flat-rate base price per grid connection; or (5) a connection charge for new installations. The charges could also be regionally differentiated.¹⁰

Finally, the regulator considers whether it might be appropriate to involve existing plants in the refinancing of the grid infrastructure, as they have contributed to its costs in the past. Such ex-post changes might jeopardise prior business cases and investments, however.¹¹

Cost reflectivity and incentivising optimal behaviour

The primary objective of efficient tariff design is to ensure that prices reflect the underlying (system) costs of providing a service and thereby guiding economic decisions towards a socially optimal outcome. In the context of electricity networks, this means incentivising efficient generation, consumption, and investment patterns, with investments supported by transparent cost benefit analysis.

Following that objective, the feed-in charges proposed by BNetzA aim to improve the cost-reflective cost-allocation.¹² Such improvement can be achieved by encouraging generators to internalise the additional system costs arising from electricity production for the networks in the tariff system. The resulting producer charges could provide effective signals as to how and where installations can be undertaken cost-effectively ‘in order to avoid an unnecessarily expensive rollout of the networks’.¹³ As a result, the introduction of feed-in charges could result in reduced total grid costs and, consequently, lower overall grid charges.

In order to achieve the intended effect of lowering overall costs, producer charges must be granular, forward-looking, and proportionate. Well-designed tariffs can encourage generators to optimise operations, strategically site new facilities in areas with spare grid capacity, and adjust feed-in based on grid conditions, thereby reducing congestion and the reliance on expensive redispatch measures. However, achieving these benefits requires modelling capability that provides a robust, quantified link between a plant’s specific behaviour and the network costs it could incur from certain behaviours.

In contrast, in the absence of modelling, resorting to a broad, undifferentiated charge per megawatt-hour of electricity fed into the grid would likely lead to sub-optimal decisions, as it would not accurately reflect the actual costs imposed on the network and thus it would not incentivise optimal behaviour from a system-wide perspective.

Following the above general insight, we note that location-based and peak-injection-linked tariffs can also provide clear signals as they increase where or when the grid is more congested. This guides generators to shift output to reduce network congestion, thereby minimising costly redispatch measures and grid expansions. The principle of cost reflectivity to incentivise optimal behaviour would support regionally differentiated charges as considered by the BNetzA. At the same time, any debates on locational pricing and dynamic tariffs will tend to create winners and losers, such that robust economic analysis and careful consideration of fairness in distributional outcomes, is required.

Pass-on of additional producer costs

In competitive electricity markets, producers may attempt to pass the grid charges onto consumers through increased wholesale electricity prices, in order to cover their higher costs and maintain their return on capital.

While the extent to which there is pass-on of higher costs in retail bills is a matter for empirical analysis, and may differ across time and between jurisdictions and suppliers, it is relevant to consider that higher wholesale energy costs will put upward pressure on retail prices. In general, the extent of pass-on depends on various factors, for example:¹⁴

• If a new tariff structure contains fixed components, such costs are less likely to be passed-on than variable components within the tariff period.
• The degree of pass-on depends on the industry structure and market power, as companies with market power can optimise over price and volume and might decide to absorb some cost increases.
• Pass-on can be limited by international competition if domestic producers face competition from imports not subject to similar producer grid charges.
• Short-run pass-on will also depend on contractual obligations in fixed-price contracts or long-term power purchase agreements (PPAs).

Therefore, it is likely that producers can pass-on at least a proportion of additional costs such that—irrespective of a tariff system change—consumers will ultimately pay the grid charges.

Passing on the additional producer grid charges is not inherently problematic, given that producers compete effectively on price and wholesale electricity prices should reflect the true economic costs of operation, including the grid costs. Therefore, the pass-on does not affect the cost-incentive effect for the producers described above, since producers have an incentive to keep their costs as low as possible—even when passing-on a proportion of their costs within retail tariffs.

Nonetheless, it is essential to assess the cost pass-on in terms of both efficiency and fairness. While the BNetzA is clear about lowering direct charges to consumers if producers are included in the financing base,¹⁵ there can still be distributional effects. Some consumer groups may be affected more than others, especially with regionally differentiated charges, which could be a problem especially for low-income end-consumers.

Interdependency with state aid

Electricity from renewable energy sources is subject to state aid in Germany. As the amount of state aid can depend on the costs the producers incur, levying additional cost on producers can also affect aid and the government budget.

Currently, state aid for electricity from renewable energy sources is based on the EEG 2023 which governs aid measures until the end of 2026.¹⁶ As any change to the grid charging system will happen beyond that period, one cannot draw specific conclusions on the interaction of the grid charging system and state aid for new installations. Yet, it is reasonable to assume that renewable energy will continue to need aid after 2026, and that the design of future aid measures may share many similarities with those currently in place. In addition, aid under the EEG is typically granted for 20 years such that many aid measures are ongoing once a new grid charging system is in place.

The EEG supports renewable energy production primarily through financial aid mechanisms such as market premiums and feed-in tariffs. For larger installations (above certain capacity thresholds), support is granted via competitive tenders where projects receive a sliding market premium that covers the difference between a reference value (reflecting production costs plus reasonable returns as included in tender bids) and the electricity market price.¹⁷ Smaller or innovative installations may receive administratively set feed-in tariffs.¹⁸

The amount of aid is scaled based on a so-called funding gap analysis. The calculation method for feed-in premiums involves quantifying all relevant discounted costs (CAPEX and OPEX) and revenues of a representative reference renewable energy project over its expected economic lifetime. Revenues are based on forecasted electricity prices. The sum of discounted costs and revenues is the net present value (NPV) of the project. The funding gap is calculated as the difference between the NPV of the project and the NPV of a ‘counterfactual scenario’, i.e. what would happen without aid. In this case, the counterfactual scenario assumes no project execution without aid (i.e. do nothing), which has a NPV equal to zero. Therefore, the funding gap equals the NPV of the project’s costs minus revenues without support.¹⁹ For aid provided via tenders, the bidding parties carry out the analysis and, in principle, the funding gap equals their bid.

Having producers pay grid charges will affect the above NPV calculations. The calculations consider that operating costs and grid charges would constitute additional operating costs that increase the funding gap, all other things equal. The calculations also consider forecast electricity prices. While the wholesale power price path will depend on many factors including the level of generation that comes onboard in subsequent years, it arguably faces upward price pressure if producers pass-on additional grid charges. One stylised possible outcome would be that any increase in electricity prices would fully offset any increase in additional operating costs and the grid charges would be neutral from an aid perspective. However, the net effect on the amount of aid required is a complex question that would require careful economic analysis and there is a possible scenario in which the funding gap does increase if producers pay grid charges.

In theory, an ability to essentially recover the additional costs from the government would also change the incentives to pass-on the grid charges to consumers. From the perspective of producers, it does not matter whether the additional costs are covered by consumers or the government, and competition between them might imply that they refrain from charging higher electricity prices to customers. One would expect, therefore, that the pass-on rate vis-à-vis consumers becomes lower if indeed the government would cover the cost via increased aid, all other things equal.

If recovery from the government is possible, the cost incentivising effect of levying grid charges upon producers might suffer as well. We have outlined that pass-on as such is not detrimental to the cost incentive (and saving) effect as competition requires producers to keep costs as low as possible. But such competitive pressure could be attenuated in a state aid context, depending on the specific rules. A guardrail against undermining the cost incentive effect can be the practice of auctioning off aid. Producers must then decide if and to which extent they try to effectively pass-on their costs to the government rather than their customers. All other things equal, this limits the extent to which grid charges levied upon producers could be effectively passed-on to the government.

As not all energy producers receive state aid, the potential selective ability to offset new grid charges via state aid could also lead to competitive distortions within the electricity generation market. In an extreme case, aid recipients would not pass-on grid charges to consumers at all, while non-recipients would have no choice but to do so.

A much more detailed analysis, including a legal analysis, would be necessary to fully understand the interdependency between grid charges levied upon producers and state aid. While it is relatively straightforward to include additional grid charges in the NPV calculations, the transmission mechanism of these charges into (potentially) higher electricity prices, especially considering altered incentives for passing-on such charges, is much less obvious.

From an ‘electricity bill perspective’, having the government pay some of the grid charges is a welcome effect. But it needs to be considered that the BNetzA may effectively oblige other federal authorities (i.e. the Federal Ministry for Economic Affairs and Climate Action) to expand their existing support to renewable energy generators, and this might require a political decision. Also, having the government effectively paying some of the grid charges could be state aid in itself, which would need to be authorised by the European Commission.

Finally, the EEG (including earlier versions) includes a yearly monitoring which compares actual costs and revenues and can trigger changes to aid amounts.²⁰ The system is designed to avoid overcompensation, however, and it is unclear if the introduction of grid charges as a cost to producers would be captured in the monitoring mechanism and absorb the systematic change to grid charges.

Grandfathering

Introducing producer grid charges necessitates careful consideration of grandfathering provisions, as existing generation assets have been financed and constructed based on prior regulatory conditions. Abruptly imposing new grid charges on existing installations could significantly disrupt their financial viability, raising concerns over regulatory stability, investor confidence, and fairness. This, in turn, would tend to undermine investor confidence for future investment decisions.

A structured approach involving grandfathering or phased-in grid charges for existing plants is crucial. Such a structured approach could include the following:

• Clear transition timelines that are explicitly communicated to stakeholders, allowing sufficient time for financial and operational adjustments.
• Phased implementation—i.e. gradually increasing the charges over a defined period—can smooth economic impacts and prevent sudden cost shocks.
• Differentiating grandfathering provisions by installation date—i.e. providing longer transition periods for older plants, and shorter ones for more recent facilities—further enhances fairness.
• Incorporating capacity or utilisation thresholds, which could protect small-scale or marginally utilised installations from disproportionate financial burdens.

Moreover, clear grandfathering arrangements can mitigate potential legal challenges and political opposition, facilitating broader acceptance and smoother implementation of new tariff structures. Effective communication and transparent implementation timelines are essential to maintain investor trust, preserve market stability, and ensure the continued expansion of renewable energy installations without undue financial disruption.

Conclusion

The consultation process initiated by the BNetzA might lead to a fundamental change to the electricity grid charging system in Germany with producers being newly included in the financing base for grid costs including the additional system cost driven by the rise of renewable electricity production.

Having producers pay grid charges will encourage generators to internalise the additional system costs and could provide effective signals as to how and where installations can be operated cost-effectively. As a result, the introduction of feed-in charges could result in reduced total grid costs.

Producers will likely pass-on much of the grid costs to consumers—i.e. despite a potential system change, consumers will ultimately pay most of the grid charges. However, channelling the grid charges through producers still creates incentives for cost reduction and efficient grid use.

A careful analysis of the interplay between grid charges and state aid is necessary, however. Without full-pass-on, grid charges levied upon producers will increase aid, all other things equal. In addition to the political implications of the responsibility for ultimately bearing these charges, the possible effects in terms of dampening incentives for efficient production and of distortions to competition would need to be carefully considered. Also, introducing producer grid charges necessitates careful consideration of grandfathering provisions, as existing generation assets have been financed and constructed based on prior regulatory conditions.