EU electricity prices for energy-intensive industries averaged more than twice US levels and nearly 50% above those in China in 2025, sustained from the prior year, while household electricity prices in many countries have risen faster than incomes and inflation since 2019. The political consequences are accumulating.
Governments across Europe spent a decade positioning the shift to clean energy as an affordability solution and are now explaining why consumers who have absorbed that transition face some of the highest retail power bills in the developed world. The explanation, however accurate, is not landing. The more important question is whether the underlying market and regulatory failures driving the divergence between cheap wholesale renewables and expensive retail electricity can be corrected before the public backlash reverses the policy commitments on which the entire transition depends.
The divergence is not universal, and that is instructive. EU household electricity prices during the first half of 2025 were down 1.5% from the first half of 2024, and excluding taxes, the decline was sharper, with prices sliding since 2023 after the post-crisis spike. Texas, the Scandinavian countries, and the Iberian Peninsula have built substantial renewable capacity without generating sustained household price crises. What distinguishes the markets where the transition is pricing people in from those where it is pricing people out is not the share of renewables but the combination of tariff design, grid cost recovery timing, the treatment of legacy levies, and the presence or absence of locational price signals.
The Levy Problem and the Gas Distortion
Non-energy charges such as network fees, taxes, and levies continue to take up a large share of final electricity bills in many markets, even as energy-related price components have fallen from crisis highs. In the UK, levies and carbon charges that fund renewable energy subsidies and grid modernisation account for roughly half a household’s bill. Those charges are applied to electricity, not to gas, which means consumers face a direct financial incentive to keep gas appliances rather than switch to electric heat pumps. The policy architecture penalises the behaviour it is nominally designed to encourage.
The solution is not novel. Historic green electricity subsidies that were levied onto power bills when electricity was predominantly coal-fired made sense when they were introduced; they are now a structural distortion that should be transferred to gas and fossil fuel consumption, shifted to general taxation, or amortised over time. Several European markets have begun this process, but the pace is slow relative to the urgency that the price competitiveness problem demands. Every year that legacy levies remain on electricity bills is another year that heat pump economics are artificially impaired relative to gas boilers.
The Grid Investment Timing Problem
The second structural driver of high bills is the mismatch between when grid investment is made and when the demand that justifies it materialises. Between 2005 and 2020, investment in the grid barely increased across most of Europe, creating a two-decade deficit that is now being addressed through a surge of planned capital expenditure. The EU grids package unveiled at the end of 2025 included €1.2 trillion for grids by 2040, of which €720 billion is for distribution grids alone. The problem is that regulated asset base mechanisms allow grid operators to begin recovering investment costs through user charges from the moment the investment is made, well before the additional demand the investment anticipates has materialised.
The consequence is a bulge in grid charges that arrives precisely when electrification needs its strongest demand signal, suppressing the volume growth that would spread fixed costs across a larger base and eventually reduce per-unit bills. The standard regulatory response, passing costs through as they occur, creates a perverse dynamic: the anticipatory investment intended to enable electrification makes electricity more expensive, which slows electrification, which means the demand on which the investment economics were premised fails to appear, which validates the concern that drove the price increase in the first place.
A mechanism that delays investment cost recovery until demand materialises could break this cycle. Germany’s Hydrogen Core Network Amortisation Fund offers a structural template: grid operators invest and run up their regulated asset base, but charges to users are held flat while the shortfall is covered by a separately capitalised account that is repaid as additional electricity demand arrives. In the electricity context, unlike hydrogen, the long-run demand trajectory is not in question. The compounding mathematics are favourable: grid assets maintained and upgraded can operate for decades, allowing the repayment period to be stretched to match the realistic timeline over which new electricity demand grows, rather than compressed into the years immediately following construction.
The Locational Pricing Gap
Analysis commissioned by Ofgem estimates that the net consumer benefits of locational pricing, whether zonal or nodal, over the period 2025 to 2040 could range from £15 billion to £51 billion compared to current arrangements, through reduced constraint management costs, lower wholesale costs, and lower congestion rents. The UK government’s REMA review, which concluded in July 2025, rejected zonal pricing under pressure from generators facing revenue uncertainty and opted instead for a reformed national pricing model with transmission charge reviews and a Strategic Spatial Energy Plan. GB redispatch costs exceeded £2 billion in 2023 as the separation between southern demand and northern wind generation widened, costs that are socialised across consumer bills regardless of where the congestion arises.
Within North America, all major independent system operators have nodal pricing in place. Ontario adopted nodal pricing on 1 May 2025. New Zealand and several other markets have had nodal pricing for more than 25 years. These are not experimental jurisdictions. The accumulated evidence from PJM, ERCOT, CAISO, MISO, and ISO-New England demonstrates that locational price signals reduce system operation costs, direct new generation and demand investment toward where it is most valuable, and produce grid architectures that require less expensive intervention to manage. The UK’s REMA outcome is a significant lost opportunity, and the search it has prompted for ways to introduce locational signals within a single national wholesale price zone faces the fundamental problem that centrally planning what a market mechanism would otherwise deliver is structurally harder and almost certainly more expensive.
Volume as the Cost Lever
The network economics of electricity are frequently mischaracterised in the policy debate. The common assumption is that adding demand raises prices because it requires more supply and more infrastructure. Over the near term, in a system with limited flexibility, that is partially true. Over the medium term, it is the opposite of true. The dominant cost driver in a deeply renewable system is fixed: transmission and distribution infrastructure, storage, system stability services, and integration costs. Those fixed costs are divided across the volume of electricity sold. A grid built to handle 200 TWh of annual throughput costs the same to operate whether it carries 150 TWh or 190 TWh; the per-unit cost falls as throughput rises.
This is the network economics argument for electrification as an affordability tool rather than an affordability problem. Doubling power demand while holding peak demand growth to 50% through flexible charging, smart heat pump scheduling, and demand response from industrial users reduces the average electricity bill by approximately 25% if half the bill is driven by fixed costs. The policy imperative is therefore to ensure that the electrification demand additions that are coming, primarily from road transport, space heating, cooling, and data centres, are structured to arrive off-peak rather than to amplify peak demand. Peak demand, not average demand, determines how much infrastructure investment is necessary and therefore how high per-unit fixed cost recovery must be.
Finland’s electrification of district heating grew approximately 70% from 1.5 TWh in 2024 to 2.6 TWh in 2025, a price-responsive load that contributed to reducing the frequency of negative price hours in the market even as renewable generation continued to grow. That is the correct direction of travel: flexible demand that absorbs renewable surplus, reduces curtailment costs, and improves asset utilisation rates simultaneously. Markets that price this behaviour correctly, through time-of-use tariffs and demand response mechanisms, capture these benefits. Markets that price electricity on flat tariffs regardless of when it is consumed waste the flexibility that the new demand categories inherently possess.
The Clean-ish Power Trade-off
The final dimension of the affordability problem is the cost difference between a grid running at 90% clean power and one targeting 100%. The last 10% of decarbonisation in any deeply renewable system requires either very expensive long-duration storage, large quantities of firm low-carbon capacity, or demand curtailment mechanisms that carry their own costs. The marginal abatement cost curve steepens sharply in this range. Pursuing 100% clean power on an accelerated timeline drives up system costs that are ultimately borne by consumers and industry, the latter of which is already operating at a competitiveness disadvantage relative to US and Chinese competitors due to structural differences in gas prices.
The average EU wholesale electricity price in 2025 was roughly twice that of the United States, which continues to face a structurally different cost profile due to domestic gas supply. The gap will not close through faster renewable deployment alone; it requires the full package of reforms, levy rebalancing, locational pricing, demand flexibility, and investment recovery timing, operating simultaneously. Any one of these reforms in isolation delivers partial improvement. The combination converts a doom loop into something closer to the virtuous circle that the underlying economics of cheap renewable generation should, with better market design, already be producing.
