UK: Securing Industrial Energy Competitiveness — From Price Relief to Structural Resilience

Executive Summary

British industry faces a structural cost disadvantage in electricity. In the second half of 2025, large industrial consumers in the 20–70 GWh/year band paid 16.88 p/kWh before taxes and levies and 23.37 p/kWh including them. The pre-tax price was 42% above Germany, 71% above the Netherlands and 148% above France. Including taxes and levies, the gaps widened to 68%, 130% and 214%.

A separate IEA benchmark for very large industrial consumers (>150 GWh/year) places selected 2024 regional examples in China, India and the United States at approximately US$70, US$62 and US$45/MWh respectively. These figures are indicative context rather than like-for-like comparisons: the consumption groups, periods and geographical bases differ.

The economic transmission is cumulative: higher electricity costs raise unit production costs; higher costs compress margins or force higher selling prices; producers lose price competitiveness, orders and market share; persistent losses then reduce investment, capacity utilisation, skills and supplier ecosystems.

The risk is amplified by the combination of competitive energy and increasingly affordable automation. Producers that combine dependable lower-cost electricity with robotics and AI-enabled process control can reduce unit costs and expand their competitive advantage.

Germany is a useful European comparator, but not a sufficient strategic target. Matching German prices would not by itself secure the future competitiveness of British industry. The objective should be to build a coherent system that connects industrial demand, long-term electricity procurement, dependable generation, networks, flexibility, infrastructure investment and lifecycle cost management.

This publication presents the central findings and policy architecture of an independent proposal prepared for discussion with the UK Department for Energy Security and Net Zero (DESNZ), industry associations and energy-market participants.

1. The Problem: Energy Costs and Industrial Competitiveness

For energy-intensive industries, electricity is not simply an operating expense. It is a determinant of unit cost and the ability to compete in domestic and international markets. Exposed sectors include metals, chemicals, fertilisers, cement, glass, paper and selected branches of engineering.

The transmission mechanism is straightforward:

Higher energy costs → higher production costs → lower margins or higher selling prices → loss of orders and market share → reduced investment and capacity utilisation → loss of skills, suppliers and industrial capability.

Once specialist teams and supplier ecosystems disappear, restoring them can cost considerably more than preserving them. Industrial capabilities are not always rebuilt simply by restoring the original price conditions. They depend on accumulated experience, skilled labour, specialised equipment, long-term commercial relationships and the ability to maintain serial production.

The available UK data illustrate the scale of the problem. The Office for National Statistics reported that output across four energy-intensive manufacturing groups fell by 33.6% between the first quarter of 2021 and the fourth quarter of 2024, reaching the lowest point in the available series beginning in 1990.

Energy costs are not the sole explanation for this contraction. They are, however, a material constraint on the ability of exposed industries to remain competitive.

Germany provides a further warning. Between February 2022 and March 2026, production in German energy-intensive branches fell by 15.2%, while employment declined by 6.3%, or approximately 53,200 people. These figures do not establish that energy prices alone caused the decline. They do show that the problem is not confined to the United Kingdom.

2. The UK's Position Relative to Competitors

The European comparison below covers large industrial consumers in the 20–70 GWh/year band in the second half of 2025. The separate global benchmark covers selected regional estimates for very large energy-intensive consumers, generally above 150 GWh/year, in 2024.

Country / Region	Electricity price	Basis	UK difference
United Kingdom	US$226.2/MWh pre-tax; US$313.2/MWh including taxes	20–70 GWh/year, H2 2025	Reference
Germany	US$159.1/MWh pre-tax; US$186.1/MWh including taxes	20–70 GWh/year, H2 2025	+42% pre-tax; +68% including taxes
Netherlands	US$132.4/MWh pre-tax; US$136.1/MWh including taxes	20–70 GWh/year, H2 2025	+71%; +130%
France	US$91.3/MWh pre-tax; US$99.6/MWh including taxes	20–70 GWh/year, H2 2025	+148%; +214%
United States (Texas)	US$45/MWh	IEA regional benchmark, 2024	Indicative comparison only
China (Inner Mongolia)	US$70/MWh	IEA regional benchmark, 2024	Indicative comparison only
India (Andhra Pradesh)	US$62/MWh	IEA regional benchmark, 2024	Indicative comparison only

The global comparison should not be interpreted as a claim that the average British factory pays the same price as a factory in Texas, Inner Mongolia or Andhra Pradesh. The consumption cohorts, periods and methodologies differ. Its purpose is to illustrate the scale of the international cost challenge.

The strategic objective should therefore be more ambitious than simply matching Germany. Britain needs an energy framework capable of supporting competitive industrial production over the long term.

3. Why the Price Gap Exists

The difference in industrial electricity prices is not explained by a single factor. It reflects the interaction of energy supply, market structure, infrastructure, policy costs and contract conditions.

3.1 Gas Exposure and Wholesale Price Formation

Under marginal electricity pricing, gas-fired generation can set the wholesale price when it is required to meet demand. Gas prices can therefore influence electricity prices even when a significant share of annual generation comes from nuclear power or renewables.

3.2 Firm Capacity and System Adequacy

Industrial users need electricity when production schedules require it. Wind and solar contribute annual energy but are variable and not fully dispatchable. Their firm-capacity contribution is distinct from nameplate capacity and annual capacity factor.

Nuclear generation can provide dependable low-carbon electricity. However, planned maintenance, unplanned outages and construction delays require adequate reserves and a diversified supply system.

3.3 Networks, Balancing and Curtailment

Generation capacity alone does not guarantee that electricity can be delivered to an industrial site at the required time and price. Transmission constraints, balancing requirements, storage and curtailment all affect the final cost.

NESO spent £1.34 billion on direct thermal constraint actions in 2024/25. The government's Reformed National Pricing Delivery Plan states that, without further mitigating action, constraint costs could peak at around £7 billion in 2030/31. This is a scenario-dependent estimate, not an inevitable outcome.

3.4 Policy Costs and Levies

Analysis by the Institute for Fiscal Studies indicates that, between 2017 and 2025, energy and supply costs for industrial consumers without an energy-intensive industry discount increased by 3.1 p/kWh, network costs fell by 2.2 p/kWh, and taxes, fees and levies increased by 4.5 p/kWh.

The resulting net increase across these components was 5.4 p/kWh. The levy increase therefore represented approximately 83% of that net increase. This is a contribution-to-net-change ratio, not the percentage growth rate of levies themselves.

3.5 Contract Structure

Long-term power purchase agreements and hedging can reduce exposure to spot-market volatility. They cannot eliminate generation, network, balancing or counterparty costs. Their effectiveness depends on contract duration, price formula, delivery profile, indexation, collateral and the allocation of risks between participants.

3.6 Renewables: Efficiency and System Value

Module efficiency, capacity factor, annual energy yield and firm-capacity contribution are different measures. Improvements in photovoltaic module efficiency are significant, but they do not remove intermittency, seasonal variation, storage, transmission or land-use requirements.

Project appraisal should therefore account for connection, transmission, curtailment, balancing, storage, firm-capacity contribution, land use, lifecycle operation and maintenance, and decommissioning.

Rooftops, car parks, brownfield sites, industrial land, offshore generation and co-location can reduce some land-use conflicts. Their suitability and economic value remain site-specific.

4. Renewable Infrastructure: Full Lifecycle Cost

Energy infrastructure should be assessed over its entire lifecycle, not only by its initial construction cost or generation cost.

A complete assessment should disclose:

• asset life by component;
• planned and unplanned maintenance;
• major component replacement;
• repowering or life extension;
• decommissioning and transport;
• recycling, disposal and site restoration;
• financial security available to meet end-of-life obligations.

Indicative component lifetimes vary. Solar PV modules may operate for approximately 25–35 years, while string inverters may require replacement after 10–15 years. Lithium-ion batteries commonly have an indicative service life of 10–15 years, depending on operating conditions and degradation. Onshore and offshore wind assets also have different maintenance, access and replacement profiles.

Operation and maintenance costs can be substantial over the lifetime of an installation. IRENA's global weighted-average utility-scale PV benchmark is approximately US$13.1/kW/year. For a 1 GW installation, that corresponds to approximately US$13.1 million annually, or US$328 million over 25 years without discounting and assuming constant costs. This is not a UK project quote and does not include every replacement, financing or grid cost.

Offshore wind has a different cost structure. DESNZ/Arup's 2025 assessment gives median offshore wind operation and maintenance costs of approximately £46,500/MW/year in 2023 prices. For 1 GW, this is approximately £46.5 million annually, or £1.16 billion over 25 years without discounting.

Decommissioning also requires explicit treatment. A DESNZ peer review recommends offshore wind planning scenarios of approximately £110,000, £255,000 and £507,000 per MW. For a 1 GW installation, these imply £110 million, £255 million and £507 million respectively. Actual costs depend on foundations, cables, vessels, seabed obligations and material recovery.

A legal duty to decommission does not guarantee that the necessary funds will remain available decades later if a developer becomes insolvent. Project approvals should therefore require independently reviewed financial assurance: ring-fenced reserves, bonds, insurance or enforceable guarantees, recalculated periodically and protected against insolvency.

Four cost categories should be reported separately:

1. Generation LCOE.
2. Adjusted LCOE, including major replacements and lifecycle operation and maintenance.
3. Full project lifecycle cost, including decommissioning, recycling and restoration.
4. System cost, including balancing, storage, curtailment and transmission.

The same lifecycle discipline should be applied to nuclear power and other firm resources. The purpose is not to privilege one technology, but to compare alternatives on a consistent basis.

5. Existing Government Measures and Their Limits

The United Kingdom already has several relevant policy instruments, including the British Industrial Competitiveness Scheme (BICS), the British Industry Supercharger, Contracts for Difference, Sizewell C, the Small Modular Reactor programme and Great British Energy.

These are relevant building blocks. The remaining question is whether they operate as one coherent mechanism connecting industrial demand, long-term procurement, firm generation, network investment, flexibility and the public balance sheet.

Contracts for Difference stabilise generator revenues, but do not alone guarantee a competitive delivered price for a particular industrial site. Similarly, Great British Energy's current remit is primarily domestic; overseas investment should not be assumed without explicit legal authority and mandate.

The challenge is therefore one of system integration: individual measures need to work together to produce a measurable improvement in the cost, reliability and predictability of electricity delivered to industry.

6. A Proposed UK Industrial Energy Competitiveness Framework

The proposed framework consists of five mutually reinforcing measures. Each addresses a different structural constraint.

6.1 Long-Term Industrial Power Contracts

Enable 10–20-year electricity contracts for strategic industrial sites. Contracts should specify price formula, delivery profile, indexation, balancing, volume flexibility, curtailment, collateral, counterparty obligations and termination rights.

Supply may combine nuclear generation, renewables and imports. Any public support should be transparent, targeted and justified against a published counterfactual.

6.2 Firm Low-Carbon Supply and Resilience

Support safe and economically justified nuclear life-extension, disciplined delivery of Sizewell C and evidence-led assessment of SMRs. Maintain domestic engineering and maintenance capability.

Complement firm generation with reserves, storage, interconnection and demand flexibility. The objective is not reliance on a single generation technology, but dependable supply under a range of operating conditions.

6.3 Renewables Assessed on Full System Value

Continue renewable investment where projects demonstrate value after accounting for connection, transmission, curtailment, balancing, storage, firm-capacity contribution, land use, lifecycle operation and maintenance, and decommissioning.

Direct physical footprint and the wider project envelope should be disclosed separately. This makes it possible to assess land-use trade-offs without overstating or understating them.

6.4 International Energy and Infrastructure Portfolio

Assess opportunities in overseas upstream gas, LNG, storage, pipelines, generation, transmission and interconnectors, as well as critical equipment and services.

Equity ownership or dividends do not guarantee cheaper physical supply. Physical security requires enforceable offtake, transport, terminal, storage and interconnector rights.

Only distributable net cash returns — after operating costs, debt service, reinvestment, taxes, reserves and contractual obligations — should be considered for transfer to a stabilisation fund. The legal owner, investment manager, mandate, risk limits, audit, oversight and withdrawal rules must be defined before launch.

6.5 Industrial Energy Stabilisation Fund and Industrial Zones

A stabilisation fund could protect viable industrial capacity during exceptional price shocks and support infrastructure that improves the economics of long-term supply.

Permitted uses should be limited to:

• support for qualifying long-term industrial electricity contracts;
• temporary, rules-based relief during extreme price events;
• co-investment in site infrastructure such as direct connections, storage and demand response.

The fund should be ring-fenced, independently audited and subject to published fiscal-risk disclosure. Eligibility criteria, caps, sunset clauses, liquidity reserves and clawbacks are essential.

Industrial energy zones could align infrastructure investment with concentrated industrial demand. Candidate clusters include South Wales, Teesside and the North East, the Humber and the North West. These are candidates for assessment, not predetermined winners.

Selection should consider industrial load, network constraints, connection queues, logistics, proximity to generation and storage, land availability, skills and credible investment plans.

7. Economic Rationale: Competitive Energy and Automation

The cost of industrial robots, automation and AI-enabled process control is falling. Producers combining these technologies with affordable, dependable electricity can reduce unit costs, automate more process stages and improve throughput, quality and energy productivity.

These advantages can reinforce one another. Cheaper automation lowers production costs, while competitive energy makes electrified heat, material handling and other energy-intensive processes more viable.

Lower unit costs allow foreign producers to reduce prices, expand market share and displace British products in domestic and export markets. If the divergence persists, British manufacturers may lose orders, investment, scale, skilled labour and supplier networks.

This is not a deterministic forecast that all British industry will disappear. The risk depends on the persistence of the energy-cost gap, automation adoption, trade exposure, productivity and policy response. It is nevertheless a strategic industrial risk, not a distant technology trend.

8. Implementation, Governance and Evaluation

A 24–36-month regional pilot should test the framework before it is scaled. The pilot should focus on data, contract design, governance, stress testing and limited site-level measures. It should not promise completion of major generation or transmission projects within that period.

The pilot should:

1. Select a region using industrial load, network constraints, connection queues, land availability and committed participants.
2. Establish a confidential baseline covering hourly consumption, delivered prices, contracts, outages, flexibility and planned investment.
3. Design and test a small portfolio of long-term contracts with different supply and indexation structures.
4. Implement one or two measurable site-level measures, such as a direct connection, storage or demand response.
5. Complete legal, financial and physical-security due diligence for candidate overseas assets before material capital commitment.
6. Introduce lifecycle cost disclosure and financial-assurance requirements for supported assets.
7. Evaluate results independently against a published counterfactual, including fiscal and distributional effects.

Governance should preserve the distinct mandates of the participating institutions. DESNZ and HM Treasury should establish policy and fiscal boundaries; NESO should provide technical system analysis; Ofgem should retain its independent regulatory responsibilities; investment vehicles should act under defined mandates; and industrial enterprises should provide demand evidence and participate in procurement.

The programme should be judged by outcomes rather than public money disbursed. Relevant measures include:

• delivered industrial electricity prices, disaggregated by energy, network, balancing, tax and levy components;
• price volatility and hedge effectiveness over rolling 12-, 36- and 60-month periods;
• price gaps against comparable European peers using the same consumption band and tax basis;
• firm capacity, gas-price sensitivity, reliability, outages and curtailment;
• connection cost and time, network constraint costs and storage utilisation;
• industrial output, capacity utilisation, investment, employment and supplier retention;
• fiscal cost per unit of industrial output preserved or private investment mobilised;
• lifecycle operation and maintenance, component replacement, decommissioning provision and financial-assurance coverage.

Stress testing should be mandatory before the overseas portfolio is scaled, before the Stabilisation Fund assumes material obligations and before long-term contracts are offered at scale. Scenarios should include gas-price shocks, prolonged low renewable output, major asset outages, infrastructure delays, overseas disruption, financial stress and compound crises.

Scaling should follow only after independent evaluation shows that the framework reduces the full cost and risk of industrial energy rather than merely redistributing them.

Conclusion

High industrial electricity costs are a long-term threat to the productive base of the United Kingdom. Higher energy costs raise unit production costs; higher costs weaken price competitiveness; persistent loss of competitiveness can displace British output from domestic and international markets.

A coherent framework should connect industrial procurement, firm supply, renewables, networks, land-use planning, lifecycle liabilities, international energy exposure and public investment risk.

This is not a case for abandoning renewables or relying on nuclear power alone. Every option should be assessed by its contribution to reliable, affordable electricity at the industrial site, including system, spatial, lifecycle and fiscal costs.

The international portfolio proposal is conditional: ownership alone does not guarantee physical supply, and returns may not arrive when industry needs support. Contractual rights, legal authority, portfolio limits and rigorous stress tests are prerequisites.

The practical first step is a regional pilot under coordinated oversight by DESNZ, HM Treasury, relevant investment institutions, NESO and Ofgem, with active industrial participation. Scaling should follow only after independent evaluation demonstrates that the framework improves industrial competitiveness without transferring unpriced risks to taxpayers or other consumers.

About the Author

Dmitry Kazakov is an Independent Software & Systems Engineer with more than 15 years of experience in the design, development and integration of technical systems. He has worked in IT development since 2006, professionally since 2010, and has maintained an independent engineering practice since 2015.

His work includes systems architecture, industrial software, data analytics, knowledge-management systems and security engineering. Alongside his engineering practice, he has accumulated experience in public and political processes since 2017.

This proposal applies a systems-engineering approach to industrial energy policy. The author does not present himself as an energy-market economist or a specialist in nuclear or renewable generation. Findings based on public data require validation by relevant technical, economic and institutional experts. The author has no commercial interest in a particular generation technology, supplier or industrial sector.

This is an independent analytical proposal prepared for discussion with DESNZ, industry associations and energy-market participants. It is not commissioned government advice.

Prepared with analytical assistance from ChatGPT and Grok.

Principal Sources and Methodology

• DESNZ, Quarterly Energy Prices, international industrial electricity price comparisons, 2025 Q2/H2 tables. Source.
• Bank of England, exchange-rate database, 2025 annual average GBP/USD. Source.
• IEA, Estimated final electricity price for large industrial customers in energy-intensive industries, 2019–2024. Source.
• ONS, The impact of higher energy costs on UK businesses: 2021 to 2024, 19 May 2025. Source.
• Institute for Fiscal Studies, Electricity prices, 22 September 2026. Source.
• DESNZ, Reformed National Pricing: Delivery Plan, 21 April 2026. Source.
• DESNZ, National Policy Statement for Renewable Energy Infrastructure (EN-3), 2025. Source.
• European Commission Joint Research Centre, PV status and development trends, 2025. Source.

European comparison: 20–70 GWh/year industrial consumers, H2 2025. Values converted from p/kWh using the 2025 annual-average GBP/USD rate of approximately 1.34. Conversion is for unit comparison, not local purchasing-power equivalence.

Global benchmark: selected IEA regional estimates for large energy-intensive consumers, generally above 150 GWh/year, 2024. Percentages against the UK are arithmetic context because cohort, period and regional basis differ.

Lifecycle estimates are indicative and depend on design, geography, maintenance regime and scope. Stress scenarios are illustrative tests, not probability-weighted forecasts.

A whole proposal available by link.

Related publications:

Germany: Escape Deindustrialisation Trap and a Critical Reassessment
China: Bridging the Gap Between Production Capabilities and Market Consumption
USA: How to Protect a Critical Production Chain if the Market Itself Produces Its Vulnerability