Germany's Energy Policy 2026–2031: Costly Relief, Unresolved Structural Costs

Starting Point and Findings

Germany is among the most expensive locations worldwide in terms of energy costs for industry, which has become the central location question of economic policy since the energy crisis of 2022. According to Eurostat, the average electricity price for companies in Germany in the first half of 2025 was around 16.3 ct/kWh compared with about 15 ct/kWh in the EU average, with large consumers exceeding 150 million kWh in annual consumption paying about 12 ct/kWh. The wholesale exchange price rose from around 3.5 ct/kWh before the crisis to 8.9 ct/kWh in 2025 and to about 9.9 ct/kWh in the first months of 2026, driven by tensions in the Middle East. Around 30 to 35 percent of the electricity price now goes to grid fees, making them the second-largest cost block after taxes and levies. In 2026, the federal government is responding with a broad relief package intended to relieve households and companies by a total of around 10 billion euros. The sober finding is: the measures noticeably dampen the burden, but according to the assessment of the Research Center for Energy Economics a trend reversal is not in sight, because the structural cost drivers persist. The location disadvantage is thus mitigated but not eliminated.

How it came about: from levy financing to budget subsidy

The core of today's system arose from several overlapping decisions. With the abolition of the EEG levy in 2022/2023, the funding of renewable energies shifted from the electricity price to the federal budget; the EEG financing requirement for 2026 amounts to around 14.6 billion euros and, if levied, would arithmetically correspond to about 4.6 ct/kWh. Following the ruling of the Federal Constitutional Court on the Climate and Transformation Fund in November 2023, the previously granted grid fee subsidy was eliminated, whereupon transmission grid fees jumped from 3.12 in 2024 to noticeably higher values and to 6.65 ct/kWh in 2025. The phase-out of nuclear power (2023) and the decided coal phase-out by 2038 at the latest simultaneously reduce controllable generation capacity. In parallel, the massive grid expansion for wind and solar power – line projects such as SuedLink, SuedOstLink, and Ultranet with costs in the double-digit billions – drove grid costs permanently upward. The combination of a gas-price-driven merit order, disappearing baseload power plants, and rising grid costs produced the cost situation to which policymakers are responding with new subsidies in 2025/2026. According to the Federal Network Agency, grid fees had more than doubled within 14 years, from 5.81 ct/kWh (2010) to 11.62 ct/kWh (2024).

Drivers and mechanisms of cost formation

The most important mechanism is the merit order: the exchange price is determined by the most expensive power plant still required, which in the German market area is frequently a gas-fired plant, so that the gas price dominates the electricity price. The average gas price rose from 1.7 ct/kWh (2016–2020) to 3.7 ct/kWh (2025) and to about 4.3 ct/kWh at the start of 2026, which feeds directly into industry's electricity procurement costs. The second driver is grid costs: the expansion of renewables takes place primarily in sparsely populated northern and eastern regions, so that disproportionate expansion costs there fell on few grid users. Since 2024, these additional costs have been distributed via a nationwide surcharge for special grid use, which stands at 1.56 ct/kWh in 2026 and comprises an allocation volume of 2.725 billion euros. A structural inefficiency factor is fragmentation: around 880 distribution grid operators, of which about 70 percent each supply fewer than 30,000 customers, drive up administrative and digitalisation costs. In addition, there are growing system costs for congestion management; the redispatch and reserve costs of the transmission system operators already amounted to around 3.06 billion euros in 2025. Rising volatility and more frequent negative prices signal an increasingly inflexible system whose balancing costs are ultimately borne by all consumers.

Ongoing and planned measures

The industrial electricity price has been in force since 1 January 2026, approved by the EU Commission on 16 April 2026 under the CISAF state aid framework and endowed with 3.8 billion euros for the settlement years 2026 to 2028. It lowers the price for around 2,000 energy-intensive companies from about 91 KUEBLL sectors to 5 ct/kWh for up to half of their consumption; for 2026 a reference price of 87.44 EUR/MWh and a differential price of 37.44 EUR/MWh apply, coupled to decarbonisation investments of at least 50 percent of the subsidy. On grid charges, a KTF subsidy of 6.5 billion euros dampens the 2026 transmission grid charge to around 2.86 ct/kWh, thereby reducing household charges by an average of 12.9 to 17.6 percent and a model household by about 75 euros per year. The electricity tax remains permanently at the EU minimum rate for around 600,000 companies in the manufacturing sector as well as agriculture and forestry, which burdens the federal budget by about 3 billion euros annually. Under the power plant strategy (StromVKG), twelve gigawatts of controllable capacity will be tendered in 2026, of which 10 GW with a long-term criterion, effectively gas-fired plants that must come online by 2031 at the latest and be H2-ready. An internal EU paper names a total volume of up to 41 GW by 2029; financing is to take place later via a still undetermined electricity price levy. In addition, from 2027 an EEG reform with contracts for difference and the elimination of guaranteed feed-in tariffs, as well as the grid charge reform AgNes, which from 2029 will for the first time also involve generators in grid financing, are on the agenda.

Economic impact: costs, benefits, fiscal effects

The benefit of the packages lies in a short-term, well-targeted relief for electricity- and trade-intensive operations and thus in securing value creation and jobs with a high relocation risk. The fiscal price is considerable: the BMWE share of the KTF amounts to 29.5 billion euros in 2026, plus the EEG financing requirement of 14.6 billion euros and the permanent electricity tax reduction of around 3 billion euros annually. The IW criticises that very high subsidies are being paid to keep electricity prices in check, but that in the long term this is a very expensive solution that does not address the root cause. The expert commission on energy transition monitoring accordingly demands that measures which reduce system costs and increase efficiency should take precedence over relief from public funds. The built-in funding cliff is problematic: the industrial electricity price is scheduled to expire at the end of 2028, without a structural decline in the market price being secured by then. Moreover, budget financing merely shifts the burden from the electricity bill to the federal budget, where it collides with the debt brake and competing expenditures. The actual efficiency question – cheap grid expansion, market-oriented capacity provision and fewer congestion costs – remains largely open.

International classification and competition

In an international comparison, Germany remains a high-cost location: in 2024, the average industrial electricity price stood at around 14 ct/kWh according to FfE/vbw, compared with 12 ct/kWh in the EU-27 average. Countries such as France, Spain and Norway offer considerably more favourable conditions; France recently stood at about 8 to 9 ct/kWh, while industrial customers in the USA and China pay only around half the German level. China's market decouples the electricity price from the fuel price through state intervention, while the USA benefits from its own fracking gas and low generation costs. Not all comparison countries are better off: in 2024, the United Kingdom recorded higher prices at around 27 ct/kWh and Ireland at 19 ct/kWh for the energy-intensive industry, owing to its island location and high gas share. The German target price, subsidised to 5 ct/kWh, would in the short term bring supported businesses to or below the level of France and the USA, but it applies only to half of consumption and is limited until 2028. For the broad economy not eligible for support – from SMEs through retail to logistics – the burden remains above average. The competitive pressure is real: according to IHK surveys, around one third to four out of ten businesses are considering relocation, and the basic materials industry reported double-digit declines in demand.

Distributional and second-round effects

The relief measures are unevenly distributed: the industrial electricity price specifically benefits around 2,000 energy-intensive companies, while private households and the broad SME sector benefit above all from the grid fee subsidy and the abolished gas storage levy. Regionally, the nationwide distribution of grid costs has a strong redistributive effect: in renewables-rich states such as Mecklenburg-Vorpommern, grid fees fell to around 7.2 ct/kWh in 2026, while Hamburg holds the highest value at around 11.8 ct/kWh. High-consumption regions with a low share of renewables thereby take on a larger part of the expansion costs. A key second-round effect is the planned capacity levy of the power plant strategy: a state-organised capacity market tends to lead to higher electricity prices via this levy and could partly eat up the relief effect again. The strong focus on gas power plants also carries the risk of raising electricity and gas prices for the entire industry, while critics fear fossil overcapacity. Shifting the support costs into the federal budget makes them invisible to electricity customers, but shifts the burden onto taxpayers and future budgets. The AgNes reform has a positive effect, provided it distributes costs more fairly and according to causation through efficiency requirements and the participation of generators.

Energy price relief measures and their fiscal costs in 2026

Scenarios

Options for action

1. Reduce system costs before public moneyInstead of permanent price subsidies, efficiency measures should be prioritised, as demanded by the Expert Commission on Energy Transition Monitoring. A more cost-efficient grid and renewables expansion dampens the price at the root and relieves the federal budget, which in 2026 is burdened by 29.5 billion euros through the BMWE's KTF share alone.
2. Use the AgNes grid fee reform consistentlyThe tightened efficiency requirements from the NEST process and the participation of generators from 2029 should be implemented swiftly. A consolidation of the more than 880 distribution grid operators and binding cost-efficiency requirements can permanently dampen the second-largest price block of around 30 to 35 percent.
3. Ensure capacity in a technology-open and market-oriented wayThe power plant strategy's focus on gas-fired power plants tends to increase prices via the merit order and a future levy. A technology-open tender including storage and flexible loads, as well as a reviewed hedging obligation, could ensure security of supply more cost-efficiently and without fossil overcapacity of up to 41 GW.
4. Keep the time limit and follow-up perspective credibleThe industrial electricity price expires at the end of 2028; without a structurally lower market price, a cost cliff looms. Policymakers should define a binding efficiency and expansion path so that the relief actually acts as a bridge and not as a permanent subsidy, and fiscal sustainability is preserved.

Key risks

• Permanent fiscal burdenEEG requirement (14.6 billion euros), grid subsidy (6.5 billion euros) and electricity tax reduction (~3 billion euros/year) tie up double-digit billion amounts and collide with the debt brake and budget consolidation.
• Gas price and merit-order dependencySince gas-fired power plants frequently set the price, geopolitical shocks pass through directly; the day-ahead price already rose to around 9.9 ct/kWh at the beginning of 2026.
• State aid law uncertaintyThe industrial electricity price and the power plant strategy depend on EU approvals; five complaints and open compliance questions can delay or alter projects.
• Fossil overcapacity and capacity levyUp to 41 GW of planned capacity and the still undetermined levy could increase electricity prices and cement costs for decades.
• DeindustrialisationAccording to IHK surveys, around one third to four out of ten companies are considering relocation; the basic materials industry already reports double-digit demand declines.
• Subsidy cliff 2028The expiry of the industrial electricity price at the end of 2028 without structurally reduced market prices can trigger abrupt cost increases and relocation.

Outlook

Over the next five years, Germany's energy economic policy remains a balancing act between short-term relief and fiscal sustainability. The packages launched in 2026 give industry breathing room, but they are expensive, time-limited and only insufficiently address the structural cost drivers – gas price dependency, grid expansion costs and system inefficiency. It will be decisive whether it is possible, via AgNes, a more efficient grid expansion and market-oriented capacity provision, to permanently reduce system costs instead of subsidising symptoms. If this succeeds by the time the industrial electricity price expires in 2028, competitiveness can improve structurally; if it does not, an accelerated relocation of energy-intensive value creation looms after the subsidy cliff. The net effect on the location over five years is therefore likely to be slightly negative, because high fiscal burdens and persisting price disadvantages overlay the short-term relief. The decisive factors are the gas market, the pace of approvals from Brussels and the consistency on cost efficiency.