Daniela Glocker
OECD
OECD Economic Surveys: United Kingdom 2026
Abstract
The United Kingdom has made substantial progress in decarbonising its economy, shifting the nature of energy security from access to fossil fuels to ensuring that an increasingly electrified, low-carbon power system can deliver affordable, reliable and resilient electricity. However, recent energy price spikes due to the conflict in the Middle East, as well as the 2021–23 global energy price shock have exposed persistent vulnerabilities linked to the United Kingdom’s continued reliance on natural gas. The government has responded with the ambition to deliver a largely clean power system by 2030, seeking to reconcile energy security, affordability and net zero objectives. Achieving this compressed timeline requires correcting price signals that slow electrification, while accelerating grid capacity expansion and strengthening short-term flexibility so that clean generation can displace gas reliably. Beyond 2030, securing durable energy security will depend on sustained investment in reliable low-carbon generation capacity, long-duration storage and climate resilient infrastructure.
The United Kingdom has made substantial progress in reducing greenhouse gas emissions, cutting them by half since 1990 (Figure 3.1, Panel A), largely through the phase out of coal and the rapid expansion of renewable electricity (Figure 3.1, Panel B). However, recent energy price spikes, driven by the conflict in the Middle East and the 2021-2023 global energy price shock, exposed persistent vulnerabilities linked to the continued reliance on natural gas, particularly for residential heating. While decarbonisation can reduce exposure to fossil fuel price volatility, it also reshapes the nature of energy security risks. As electricity becomes the backbone of the energy system, security increasingly depends not only on fuel supply but also on the capacity of the low-carbon power system to deliver affordable, reliable and resilient electricity. Key challenges include maintaining price stability, expanding grid capacity, enhancing system flexibility and strengthening resilience to climate shocks.
Note: Panel A refers to territorial (production-based) greenhouse gas emissions. In Panel C, prices include all taxes where not refundable on purchase. The G7 range refers to the range between the minimum and maximum prices between the available G7 countries per year. Panel D: Figures refer to the share of total final energy consumption. “Industry” includes non-energy use. OECD is a weighted average of all OECD member countries. G7* refers to a simple average of G7 countries without the United Kingdom.
Source: OECD (2026), Environment database; IEA World Energy Balances (database); and Department for Energy Security and Net Zero.
Despite the significant growth in renewable generation, electricity prices remain high and closely linked to international gas markets (Figure 3.1, Panel C). Two features of the current pricing system weaken the link between renewable deployment and lower consumer prices: wholesale electricity prices remain tied to gas through marginal pricing, and retail price structures place a higher burden on electricity. Natural gas still accounts for almost a third of total electricity generation, meaning that gas-fired plants frequently set the marginal wholesale price (IEA, 2024[1]). At the retail level, electricity prices remain significantly higher than gas prices, partly because policy levies and network charges are allocated more heavily on electricity. This price differential weakens incentives to electrify energy consumption, particularly for heating in residential, commercial and public sector buildings (Figure 3.1, Panel D). With about 60% of the United Kingdom’s natural gas supply consumed by households (IEA, 2024[1]), reliance on gas remains especially high in residential heating, prolonging households’ exposure to fossil fuel price shocks and adding to affordability concerns.
The government has set out a series of strategies to reconcile energy security, affordability and net-zero objectives, including the Energy Security Strategy, the 2024 Growth Mission, the 2025 Industrial Strategy, and the Clean Power Action Plan 2030 (HM Government, 2022[2]; 2024[3]; 2025[4]; 2025[5]). Accelerating the transition to a largely clean power system by 2030 can strengthen long-term energy security by reducing reliance on fossil fuels and exposure to volatile gas markets. However, achieving this objective requires not only continued renewable deployment, but also credible price signals, timely investments in grid reinforcement and system balancing and careful sequencing to maintain affordability. Without credible policy frameworks and careful sequencing, short-term cost pressures and delivery bottlenecks could slow electrification and prolong exposure to gas price volatility.
This chapter examines how the United Kingdom’s net zero transition is reshaping energy security challenges and policy priorities. It first assesses whether current pricing and carbon frameworks sufficiently support electrification and reduce exposure to fossil fuel price shocks. It then analyses current electricity supply-side constraints, focusing on electricity networks, system flexibility, and low-carbon generation capacity. Finally, it examines whether climate adaptation is sufficiently embedded in energy system planning to ensure reliability of an increasingly electrified economy under more frequent extreme weather events.
The government’s strategy to strengthen energy security focuses on delivering a largely clean power system by 2030, requiring simultaneous transformation on both demand and supply sides of the energy system. On the demand side, electrification of industry, transport and heating is essential to reduce exposure to fossil fuel price volatility and put the economy on a credible path to net zero. This will significantly increase electricity demand and load patterns. On the supply side, higher demand must be met by expanding clean generation, reinforcing transmission and distribution networks, and scaling up storage and system flexibility. Delivering this transformation will require substantial upfront investment, estimated at around GBP 26 billion (0.9% of GDP in 2025) per year until 2050 under a central scenario, with low-carbon technologies and infrastructure needing to be deployed rapidly over the coming decade (Climate Change Committee, 2025[6]).
Because the 2030 Clean Power objective substantially compresses the timeline for system transformation, demand and supply must move in parallel. Electrification lowers emissions and reduces exposure to fossil fuel imports only if clean power capacity and grid infrastructure scale at pace. Likewise, expanding renewables improves energy security and long-term affordability, but requires sufficient demand and system flexibility to absorb new capacity efficiently. Delivering largely clean power by 2030 requires aligned demand-side incentives, including aligning energy pricing across fuels and reducing supply-side constraints, notably grid capacity, flexibility and supply chains. Weaknesses on either side reinforce gas dependence and exposure to price volatility.
3.2.1. Aligning price signals to accelerate electrification and reduce gas dependence
Weak and uneven price signals slow electrification and prolong reliance on natural gas, limiting near-term gains in energy security despite increasing clean energy investment. Electricity prices remain closely linked to gas prices, despite the rapid expansion of low-marginal cost renewable generation. Wholesale electricity markets operate through marginal pricing, with gas-fired generation often determining the clearing price. As renewable penetration increases and as long‑duration storage and interconnection expand, the proportion of hours in which gas‑fired generation sets the marginal price is expected to decline. Recent government measures in response to the evolving conflict in the Middle East further aim to reduce gas price pass‑through, including through greater use of long‑term fixed contracts for low‑carbon generators. These steps support a gradual delinking of electricity prices from international gas markets (HM Government, 2026[7]), although exposure to gas price volatility remains material as long as gas remains a significant part of the generation mix.
At the retail level, policy design further shapes relative energy prices. Final prices vary significantly across fuels due to differences in tax treatment, network charges, policy levies and the extent of carbon pricing, rather than reflecting underlying system costs alone. Electricity is subject to carbon pricing under the UK Emission Trading Scheme (ETS) at production stage and faces additional policy levies at the consumption stage. By contrast, other energy carriers continue to benefit from government support measures that lower the consumption price, such as reduced VAT on households’ fuels, lower fuel duties, and consumption and production support reliefs for fossil fuels. According to the OECD’s inventory of support measures (OECD, 2025[8]), such support covered about 22% of emissions in 2023. As a result, electricity remains not only more expensive than in peer countries, but also structurally more expensive than gas for consumers (Figure 3.2), even as renewable generation expands. These asymmetries in policy treatment weaken relative investment incentives in electrification and prolong exposure to fossil fuel price volatility.
Note: End Prices. In Panel A, data for the United States Prices excluding refunds.
Source: IEA Energy Prices Database.
The government’s 2025 Industrial Strategy recognises that UK electricity prices are high by international standards and the government introduced measures to reduce them, including lowering network charges and targeted relief for energy‑intensive users from certain levies on electricity used to fund renewables and other green programmes, while keeping the balance between affordability, competitiveness and the net zero transition under review (HM Government, 2025[5]). These first steps are welcome, but reducing the prices of electricity alone does not correct the underlying distortion. Strengthening incentives for electrification also requires gradually increasing the effective cost of gas through greater alignment of emissions pricing that would narrow the electricity–gas price differential.
The price differential is particularly consequential in residential heating, which accounts for the largest share of UK gas consumption (IEA, 2024[1]). Despite expanded government schemes supporting heat pump installations, uptake remains low by international standards (Figure 3.3, Panel A). While new heat-pump installations in 2024 have been in line with the Climate Change Committee’s milestones path (Figure 3.3, Panel B), a significant acceleration is needed to reach the government’s objective of 600 000 installations annually by 2028 (Climate Change Committee, 2025[9]). While relative energy prices are a key determinant of heat pump adoption, uptake also depends on delivery side factors as discussed in the previous Economic Survey (OECD, 2024[10]), including upfront costs, installer availability and consumer experience. Ongoing government efforts to strengthen delivery alongside price incentives will therefore remain essential. The removal of 75% of the Renewables Obligation Levy from electricity bills between April 2026 until April 2029 (HM Government, 2025[11]) is also a positive step, but only narrows the price gap between gas and electricity from about 4.7 in the first quarter of 2026 to 4.3 in the second quarter. Moving forward, the government could consider to permanently remove the remaining policy levy on electricity at the consumption stage and integrating it into the broader tax base, following a transparent strategy. Consistent with findings from OECD research (OECD, 2022[12]; Hodok and Kozluk, 2024[13]) that climate policies can have significant distributional impacts, particularly on low‑income households, the government should continue to systematically assess potential impacts and embed findings in climate policy design to inform targeted assistance and strengthen public support.
Source: European Heat Pump Association; and Climate Change Committee 2025, Progress report 2025.
Transport policy illustrates how more consistent price signals can support electrification. Fuel duties result in one of the highest net effective carbon rates in the UK economy, even after persistent fuel duty freezes. Together with regulatory measures such as the Zero Emission Vehicle Mandate, this has supported growth in the uptake of electric vehicles (EV), which in 2024 has been in line with the OECD average (Figure 3.4). This has allowed policy to gradually shift from broad tax exemptions towards a more balanced mix of targeted purchase support and integration of EVs into the standard tax base through a new mileage-based tax introduced in the 2025 Budget (HM Government, 2025[11]). The government should continue to monitor progress towards ZEV Mandate targets, which requires that 80% of new car sales be zero-emission by 2030 and 100% by 2035, and phase out support as market maturity increases.
Source: IEA Global EV Outlook (database); and Climate Change Committee 2025, Progress report 2025.
Reducing incentives towards gas-based heating and power generation needs adjustments to relative carbon pricing and fossil fuel support. Phasing out environmentally harmful fossil fuel support and broadening the scope of carbon pricing to sectors where effective net carbon rates remain low (Figure 3.5), would improve consistency. For example, explicitly pricing emissions from heating fuels by broadening the scope of the UK ETS to cover heating fuels according to their carbon content would strengthen incentives to electrify, as recommended in the previous Economic Survey (OECD, 2024[10]). Gradually increasing carbon prices over time would give households and businesses time to adapt. Carbon related revenues and wider public resources within the overall budget framework could support clean energy investment and targeted assistance for lower income households to improve public acceptability of increased carbon prices (OECD, 2022[12]). Greater coherence across carbon and energy taxation, including linking of the UK and EU Emission Trading Schemes (ETS) as announced by the UK government and the EU Commission, could further enhance market liquidity, price stability, and provide clearer incentives for emissions reduction and low-carbon investment across sectors (HM Government, 2026[14]).
Carbon pricing by sector
Note: The net ECR equals the ECR minus fossil fuel subsidies that decrease pre-tax fossil fuel prices. Emissions cover all sources excluding biofuels and other GHG emissions.
Source: OECD Effective Carbon Rates (database); and OECD Share of Emissions Priced (database).
3.2.2. Securing energy supply in an increasingly electrified system
Removing grid bottlenecks to support electrification
Beyond aligning price signals, the successful electrification of the UK economy also depends on removing physical bottlenecks in electricity infrastructure. As the share of variable renewable generation and electrification of demand has increased, the electricity grid has become the key binding constraint on the United Kingdom’s clean energy transition and a central risk to energy security (Figure 3.6). The existing grid was largely designed in the 1960s and 1970s to transport power from centralised coal and nuclear plants to consumers. While it remains reliable, it is not yet configured for a system dominated by wind, solar and two-way power flows (NESO, 2025[15]). Significant new high-voltage transmission capacity is needed to connect offshore wind generation in the North Sea and onshore renewable clusters, particularly in Scotland, to industrial and population centres in England and Wales. In addition, regional and local networks need to be upgraded to accommodate distributive electrification of transport, heating, and industry, while the rapid expansion of rooftop solar and community energy schemes is making power flows more variable. Yet most distribution grids were designed for one-way power delivery and limited flexibility (NESO, 2025[16]). As a result, energy security risks are no longer primarily driven by shortages of generation, but by whether electricity can be delivered where and when it is needed, and at affordable cost.
Grid expansion is challenged by long planning and delivery timelines. Transmission projects can take 10-15 years from planning to commissioning, while renewable generation projects often progress in 3-5 years. This mismatch has contributed to a severe grid-connection backlog, which exceeded 750 GW of projects in 2025 (HM Government, 2025[4]). Thus, sufficient projects were in the waiting list to meet the requirements to reach a largely Clean Power System by 2030, but as the queue included both already built as well as speculative projects, the first-come first-served rule did not guarantee that strategically more important and already built projects were prioritised in grid connection (Figure 3.6). The establishment of the National Energy System Operator (NESO) in 2025 is a welcome step to not only address the long-standing problems of fragmented planning, but also the issue of slow grid connections. Recent reforms to the grid connection process to prioritise ready‑to‑go projects and discourage speculative connection requests, should improve investors’ and developers’ confidence and help unlock clean energy investment in areas most needed (NESO, 2025[17]; HM Government, 2026[18]). Swift and credible implementation is needed, including informing investors in the pipeline. It should also be monitored that delivery timelines evolve within priorities, while considering to further tighten connection priority to developers’ delivery progress on milestones.
Note: Panel A, capacity requirements refer to NESOs New Dispatch scenario for needed capacity by 2030. Panel B: data refers to electricity generation from solar PV, solar thermal, offshore wind, and onshore wind. G7* refers to G7 average excluding the United Kingdom.
Source: International Renewable Energy Agency (database); and NESO, Clean Power 2030.
Progress has been made in sustaining investment within a strengthened regulatory framework that supports rapid, cost-effective delivery of electricity network upgrade. The Office of Gas and Electricity Markets (Ofgem) is overseeing one of the largest modernisation and expansion programmes in the history of Great Britain’s electricity networks. With initial approvals of around GBP 24 billion for the 2026–31 period under the RIIO-T3 framework, and total investment projected to reach GBP 80-90 billion by 2031 (Ofgem, 2025[19]; 2025[20]), Ofgem attempts to balance cost discipline with the need for rapid delivery. It uses investment allowances, performance incentives and regulatory parameters for electricity transmission and distribution operators, as well as including provisions for increasing transmission investment to accelerate offshore grid connections, reinforce onshore capacity, and strengthen asset resilience in line with net-zero objectives (Ofgem, 2025[20]). At the distribution level, reforms under the forthcoming RIIOD-ED3 framework (2028-33 period) are expected to place greater emphasis on anticipatory investment, enabling operators to build ahead of demand in areas with high projected electrification. Shifting to an anticipatory approach in planning and approving transmission and connection infrastructure would be welcomed. More forward-looking allowances and clearer strategic guidance could reduce connection delays and avoid costly reactive upgrades once demand has already materialised (Ofgem, 2025[20]; 2025[21]), and is an approach that is being increasingly implemented in Europe (Box 3.1). New plans under the EU Anticipatory Investment Approach reflect a broader shift from reactive, connection driven grid expansion, towards strategic, scenario-based planning that better supports timely decarbonisation and energy security.
The rapid expansion of renewable energy and electrification requires electricity networks to be reinforced. Traditional grid planning models, which expand infrastructure only after firm connection requests are received, risk creating bottlenecks and delays. Several European countries are therefore shifting towards more anticipatory approaches to grid investment, following the formal guidance on anticipatory investment published by the European Commission.
In Austria and Denmark, long-term network development plans are aligned with national decarbonisation scenarios allowing grid operators to invest based on forward looking demand scenarios rather than confirmed projects accounting for socio-economic cost-benefit analyses.
In Belgium, parts of planned infrastructure can be included in the regulatory asset base before full utilisation, reducing the financial risk of early investment.
In Germany and Ireland, grid operators undertake case-by-case anticipatory reinforcement, particularly to accommodate renewable generation hubs or electrification clusters, supported by regulatory mechanisms that mitigate under-utilisation risk.
Source: https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=OJ%3AC_202503179
Despite these recent advances in financing and regulation, delivery risks remain. Planning and permitting procedures constitute an important bottleneck for grid expansion, due to planning issues and local capacity constraints. With the National Infrastructure Bill introduced in 2025, the government aims to streamline approval paths for national critical energy infrastructure, clarify strategic priorities and reduce procedural delays. As these reforms are critical to meet the 2030 timeline for Clean Power delivery, the government should monitor implementation and identify emerging bottlenecks early. Furthermore, it remains important that decisions at the national level maintain community consent and are in line with envisioned growth plans at the local and regional level (Chapter 4).
Supply chain and labour constraints are another significant risk to timely grid modernisation. Domestically, grid expansion competes for skilled labour, construction capacity and specialised equipment with other large infrastructure programmes including housing, transport and industrial development. At the same time, global demand for high voltage cables, transformers and substations is rising rapidly, increasing lead times and exposing projects to price volatility and import delays. These pressures risk slowing grid reinforcement, delaying renewable integration and constraining system flexibility, with indirect implications for energy security and affordability. To mitigate these risks, the government has announced to strengthen domestic supply chains, including expanding domestic cable manufacturing capacity, strengthen logistics for high-voltage equipment, and developing a skilled workforce capable of delivering major infrastructure projects. Progress on supply-chain resilience will require continuous monitoring, co-ordination across government and industry to ensure that grid expansion keeps pace with renewable generation and electrification of demand. In addition, the government should track and regularly assess trade dependencies through enhanced data collection and regularly updated tools to better understand emerging dependencies from shifting global supply chains.
Ensuring operational reliability in a high-renewables system
Even with timely grid reinforcement, system reliability under the Clean Power Plan 2030 objective will depend on the ability to balance demand and supply in real time. As renewable generation increases, managing short-term fluctuations and longer stress periods becomes a central pillar of energy security and affordability. Short peak imbalances, such as intraday fluctuations in wind and solar output, can be managed through demand-side flexibility and short-duration battery storage. By contrast, longer stress periods, such as cold winter weeks when generation might be low and demand high, require a sequence of responses, including demand reduction, short- and long-duration storage, interconnector imports and low-carbon dispatchable generation (NESO, 2025[15]). Ensuring that these flexibility options scale in line with renewable expansion is central to maintaining energy security.
Under current project timelines and system projections, nuclear capacity and large scale long-duration storage are unlikely to contribute materially before 2030 (Figure 3.7). Operational reliability over the remainder of this decade will therefore depend primarily on renewable expansion, short-duration flexibility, interconnection and the continued availability of existing gas-fired capacity for balancing. While nuclear and long-term duration storage remain important components of the longer-term system architecture (see below), they will play only a limited role in addressing near-term variability risks.
Installed and projected installed capacity, GW, by technology under different scenarios
Note: The 10-year forecast reflects NESO’s central planning outlook based on current and announced policy, existing project pipelines, realistic technology deployment rates, and expected electrification-driven demand growth, rather than the full range of long-term net-zero scenarios. In the Holistic Transition Scenario, net zero is met through a mix of electrification and hydrogen, with hydrogen mainly used around industrial clusters. Hydrogen is not used for heat except as a secondary fuel for heat networks in small quantities. Consumer engagement is very strong through adoption of energy efficiency improvements and demand shifting, with smart homes and electric vehicles providing flexibility. A high-renewable capacity pathway, with unabated gas dropping sharply. Pathway sees moderate levels of nuclear capacity and lowest levels of hydrogen dispatchable power. Supply-side flexibility is high, delivered through electricity storage and interconnectors. No unabated gas remains on the network in 2050.
Source: NESO 2025, Future Energy Scenarios.
Accelerated renewable deployment represents the central supply-side lever for reducing structural reliance on gas-fired generation before 2030. The United Kingdom has already made remarkable progress in expanding renewable electricity generation, with wind and solar together supplying over 40% of grid electricity in 2024 (Figure 3.8, IEA (2025[22])). As an early leader in offshore wind deployment, its capacity has almost quadrupled over the past decade from 3.7GW to more than 14 GW in 2024, turning the country into one of the world’s largest offshore wind markets (IEA, 2025[22]). This expansion has been supported by the Contracts for Difference (CfD) scheme, the country’s main policy instrument for incentivising renewable investment. CfDs provide long-term price certainty by guaranteeing project developers a fixed price for electricity, shielding investors from market volatility while helping to stabilise costs for consumers. The government aims to deploy up to 50GW of wind capacity by 2030 and up to 70GW of solar by 2034, more than tripling and quadrupling today’s respective capacities. In its latest auction round (AR7), 8.4GW of offshore wind capacity was secured putting the country on track to achieve its clean power mission by 2030 (HM Government, 2026[23]). This will help reduce the structural need for gas-based generation and lower exposure to international fossil fuel price volatility. However, higher renewable penetration also increases variability in supply, reinforcing the need for complementary flexibility.
Electricity generation by source and net trade, TWh
Source: IEA Electricity Statistics (database); and Electricity Information (database).
Progress has been most visible in short-duration flexibility. Grid-scale battery capacity has expanded rapidly (House of Commons, 2025[24]) and increasingly provides frequency response and intraday balancing services, reducing renewable curtailment and stabilising the system during short peak imbalances. Demand-side response mechanisms have also been developed and will play an increasingly important role as households and firms both consume and generate electricity. Home battery storage, including from electric vehicles (“Vehicle-to-grid”), combined with smart meters and smart contracts, can help households shift demand and even feed the grid in times of high demand, if barriers to flexibility on the grid are removed. Smart meters, time-of-use tariffs and digital control systems already incentivise consumers to shift demand. However, participation remains below envisioned targets (NESO, 2025[25]; HM Government, 2025[26]), reflecting weak price signals, limited rewards for rapid response, and network charging arrangements that insufficiently value flexibility. As smart meter rollout progresses, the government should consider strengthening incentives by making the time of use tariffs more reflective of grid pressures, as they have proven effective in shifting electricity demand to off-peak periods when the grid is under less strain. The development of a smart data scheme, as the government is currently exploring, should be advanced as improved access to real-time system data would further help households and businesses to participate in demand-side flexibility. Moreover, the Market-wide Half-Hourly Settlement (MHHS) programme that is being rolled out from 2025-27, means half-hourly consumption data will be the default basis for billing and settlement. This could serve as enabler for more innovative tariffs and price signals to consumers provided they consent to share data.
Interconnection provides an additional layer of resilience during prolonged stress periods. The United Kingdom is well-integrated with neighbouring European countries through a robust network of interconnections (HM Government, 2025[26]), allowing the UK to import electricity when output is low and to export surplus generation during high-output periods. The government’s target to expand interconnection capacity to at least 18 GW by 2030 will further support system flexibility. As previously recommended by the IEA (2024[1]), the government should continue to support multi-purpose interconnectors (offshore wind farms combined with interconnectors) in addition to point-to-point interconnectors. As the UK’s offshore wind capacity grows, the country could thereby strengthen its role as net exporter of clean electricity, supporting emissions reductions and energy security in the rest of Europe.
Building durable system resilience beyond 2030
Reliance on short-duration flexibility and residual gas balancing may be sufficient to deliver largely Clean Power by 2030, but maintaining energy security over the longer term will require structural reinforcement of the low-carbon system. As renewable penetration increases further in the 2030s, a system dependent on short-duration flexibility and gas-fired balancing would expose the system to rising balancing costs and continued price volatility. Strengthening structural resilience therefore will depend on expanding firm low-carbon capacity, scaling long-duration storage and reinforcing institutional frameworks that support strategic investment (Figure 3.9).
Nuclear power and long-duration storage are expected to play a more central role in the post-2030 electricity mix. As low-carbon dispatchable resources, they can reduce structural reliance on gas during prolonged periods of low renewable output and limit the need for sustained balancing through fossil-fired generation. Nuclear remains central in the UK government’s electricity strategy, but new nuclear projects face long development timelines, complex planning procedures and significant capital requirements. For example, the Hinkley Point C project, which was initially expected to begin generating power by around 2025 is now projected to come online closer to 2030. To ensure that nuclear capacity can increase by the end of the 2030s, clear signals are needed now. Plans for Sizewell C have recently advanced with a final investment decision and significant government funding committed (GBP 14.2 billion over the Spending Review Period), and in parallel, the government is supporting the development of small modular reactors (SMRs) as a longer-term option to expand nuclear capacity. At the same time, continued attention to waste management, decommissioning and accident risks underscores the importance of transparent life‑cycle cost‑benefit assessments. In this regard, the government’s commitment of GBP 13.9 billion of capital investment funding set in the Spending Review to the Nuclear Decommissioning Authority over the Spending Review period is a positive step towards addressing legacy costs and risks.
Long-duration energy storage (LDES) will become increasingly important as renewable shares rise. Technologies such as pumped hydro and emerging hydrogen-based storage can provide multi-day or seasonal balancing, but deployment remains limited (NESO, 2025[27]). High upfront capital costs, uncertain revenue streams and planning constraints continue to weigh on investment decisions. The government has taken steps to address these barriers through targeted LDES support initiatives, including a cap and floor investment support scheme, which reduces downside revenue risk while limiting excess returns, thereby improving bankability (HM Government, 2025[4]). Moreover, the government has introduced new public investment vehicles to help crowd in private capital by absorbing early-stage risks. The National Wealth Fund, established in 2024 as the successor to the UK Infrastructure Bank, is mandated to support infrastructure aligned with net zero and regional growth objectives. Great British Energy, created in early 2025, is intended to act as a strategic public investor in clean electricity and critical energy infrastructure. As these institutions are relatively new, their effectiveness should be monitored and if necessary, their mandates adjusted to ensure that they are sufficiently empowered to take risk-tolerant, early-stage positions where public capital is needed to unlock private delivery.
Note: All Panels refer to NESO’s scenario for a holistic transition, where the following is assumed: net zero is met through a mix of electrification and hydrogen, with hydrogen mainly used around industrial clusters. Hydrogen is not used for heat except as a secondary fuel for heat networks in small quantities. Consumer engagement is very strong through adoption of energy efficiency improvements and demand shifting, with smart homes and electric vehicles providing flexibility. A high-renewable capacity pathway, with unabated gas dropping sharply. Pathway sees moderate levels of nuclear capacity and lowest levels of hydrogen dispatchable power. Supply-side flexibility is high, delivered through electricity storage and interconnectors. No unabated gas remains on the network in 2050.
Source: NESO Future Energy Scenarios 2025.
Delivering on medium- and long-term climate objectives in a way that strengthens energy security increasingly depends on policy frameworks that remain effective as economic conditions, technologies and behaviours evolve, and that provide credible, predictable and well-sequenced signals while managing the trade-offs between near-term costs and long-term benefits. In the United Kingdom, the overall decarbonisation framework, including statutory carbon budgets and the net zero target, is strong and enjoys a high degree of credibility. However, weaknesses in the sequencing of measures and in the ability to adjust instruments over time risk slowing delivery, increasing short-term cost pressures, and prolonging reliance on natural gas. While 2030 targets are clear, intermediate milestones beyond 2030 and policy interactions across power, heat and buildings are not always sufficiently aligned (Climate Change Committee, 2025[9]). In the past, adjustments to policy timelines, including changes to the planned phase-out of fossil fuel boilers, have illustrated how regulatory reversals or unclear sequencing can weaken expectations, delay household and firm decisions, and reduce investor confidence (OECD, 2024[10]). In energy security terms, such uncertainty slows electrification and extends dependence on gas for heating and power generation. More adaptive regulation could help manage these risks. Adaptive regulation refers to frameworks that incorporate structured, evidence-based review mechanisms, allowing timelines and instruments to be adjusted as technologies mature, costs evolve and delivery constraints emerge, without undermining long-term direction. At present, the UK framework lacks a systematic approach to recalibrating policies in response to implementation challenges, such as grid bottlenecks or affordability pressures, even when these threaten delivery.
As the government updates its policy package in preparation for the Seventh Carbon Budget, due in June 2026, it should ensure clear regulatory sequencing and strengthen adaptability. Clearer staging of milestones would help households, firms and investors to plan for transitions towards low-carbon solutions. The government should also consider strengthening the use of adaptive regulation by embedding mechanisms that allow regulatory settings, timelines and policy instruments to be periodically reviewed and adjusted based on clear performance metrics and emerging evidence. This would help improve delivery, maintain policy credibility and help ensure that short-term affordability pressures are managed in a way that accelerates electrification, reduces exposure to gas price shocks and strengthens energy security over the longer term.
Strengthening the climate resilience of the electricity grid is essential for energy security and economic stability. Much of the UK electricity grid was designed for historical weather conditions and lower electricity loads. As climate change increases the frequency and intensity of storms, floods, and heatwaves, physical risks to the grid are rising. Adapting the grid to these changing conditions is not only an environmental priority but a prerequisite for power reliability and productivity of regions and industries increasingly dependent on continuous electricity supply.
The UK climate resilience framework, anchored in the National Adaptation Plan (NAP), identifies electricity infrastructure as a critical priority and calls for co-ordinated action among government, regulators, and network operators to embed climate risk management into all stages of planning, investment, and operation. This framework is supported by the Committee on Climate Change’s (CCC) assessments and the institutional role of the National Energy System Operator (NESO) in spatial planning. Together these provide a sound basis for integrating climate resilience into the electricity grid. Resilience considerations should be balanced against cost considerations, including potential impacts on households through higher electricity prices.
Despite this framework, preparedness in the electricity sector remains partial and uneven. Electricity infrastructure faces vulnerabilities along multiple points of the network. Transmission towers and overhead lines are exposed to high winds, lightning and ice; substations in flood-prone or coastal areas face flood and erosion risks; and rising temperatures reduce the efficiency and lifespan of both overhead conductors and underground cables; drought and extreme heat can constrain cooling capacity in generation and transmission systems. These hazards could increasingly affect reliable supply as electrification deepens, with cascading effects on critical services such as water supply, transport, and digital communications (Climate Change Committee, 2025[28]). While most transmission and distribution operators have developed adaptation plans under the Adaptation Reporting Power, implementation remains inconsistent and oversight weak (Climate Change Committee, 2025[28]). Moreover, adaptation efforts have largely focused on flood and storm resilience, with less attention to heat stress, drought impacts on cooling, and cross-sector interdependencies (Climate Change Committee, 2023[29]; 2025[28]), which are likely to become more relevant.
Recent institutional developments offer opportunities to better integrate adaptation into system planning. NESO’s Strategic Spatial Energy Plan (SSEP) sets out how electricity, hydrogen, and storage infrastructure will be planned from 2030 to 2050, embedding system resilience and co-ordination across jurisdictions (NESO, 2025[30]). While still under development, the SSEP commits to integrating climate risk factors such as flooding and heat stress into infrastructure siting and design, representing a welcomed step towards climate-resilient, co‑ordinated energy planning. Once published, clear implementation timelines should be set together with concrete investment priorities.
Effective implementation will be key to translating the SSEP into tangible improvements in climate resilience across the electricity system. NESO is required to produce strategic whole-energy system plans that inform long-term network investment and support resilience, including addressing climate risks. As highlighted by the Climate Change Committee, NESO’s planning processes should integrate climate-stress testing of grid assets and prioritise reinforcement or other mitigation measures in areas exposed to high climate risk, enabling clearer identification of vulnerabilities and adaptation needs. Given Ofgem’s central role in shaping network investment behaviour, it is welcome that the regulator is strengthening expectations around climate resilience strategies, scenario planning and reporting, and is working with network companies to develop Climate Resilience Metrics and Indicators (CRMIs) that can inform investment decisions and performance assessment under RIIO-3 (Ofgem, 2025[20]). The effectiveness of RIIO-3’s climate adaptation and resilience provisions will depend on how fully these emerging mechanisms are operationalised in practice, including through robust output-based resilience metrics, their integration into performance incentives and allowed returns, and systematic monitoring to ensure that resilience objectives translate into timely, location-specific network reinforcement. To support consistent progress on climate resilience, Ofgem should require mandatory and standardised adaptation reporting across all network operators, aligned with NESO’s spatial planning and risk assessments, to strengthen accountability, data sharing, and evidence-based regulatory oversight.
Climate resilience also requires stronger cross sector co-ordination for critical infrastructure. Reporting should explicitly stretch across sectors to identify interdependencies, as weaknesses in one network can cascade through others. Recent outages, including the North Hyde Substation early 2025, resulted in the loss of supply to 70 000 domestic and commercial customers including Heathrow Airport. Larger scale electricity disruptions could affect water pumping, transport signalling, and digital communications amongst other with serious impacts on people and businesses as seen for example during the outage in the Iberian Peninsula (2024) and in parts of Berlin, Germany, in early 2026. Following the North Hyde incident, the government announced to publish an Energy Resilience Strategy. NESO investigated the incident and recommended stronger cross-sector co-ordination with respect to critical infrastructure. Swift implementation, supported by regular system-wide stress testing, strengthened public reporting and data sharing to enable transparent monitoring of adjustments of emergency responses, will be essential.
Adaptation and decarbonisation must proceed in a co-ordinated and integrated way. The rapid build-out of electricity infrastructure required for net zero provides an opportunity to design a system resilient to future climate conditions but may also face the risk of locking in new vulnerabilities if adaptation is not embedded from the outset. The expansion of transmission lines, substations, and interconnectors under NESO’s strategic framework should therefore integrate resilience standards from the design phase, ensuring assets can withstand more extreme weather over their operational lifetime.
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