UK Energy and Infrastructure

2025 was a turbulent year for renewable energy, with supply chain constraints and high interest rates continuing to impact delivery of projects. The sector also experienced unprecedented geopolitical uncertainty, particularly in the wake of the USA federal administration’s actions to revoke permits for offshore wind projects already under construction. Given the international nature of renewable energy investments, the impacts were, and continue to be, felt globally. Despite these challenges, the UK government has remained committed to its Clean Power 2030 Action Plan (CP30) and ambitious decarbonisation targets, driving the continued acceleration of renewable energy development.

In 2025, this support helped the UK reach 16GW of offshore wind installed capacity, providing more than 17% of the UK’s electricity needs. However, with only 1.2GW of new capacity added last year, the pace of development will have to increase significantly to meet the CP30 ambition of 43-50GW of offshore wind capacity by 2030. On 14 January 2026, Contract for Difference (CfD) allocation round 7 (AR7) awarded support to 8.4GW of offshore wind capacity, an outcome that exceeded industry’s initial expectations and is intended to keep the UK on track to achieve its CP30 ambitions. AR7 originally allocated a budget for fixed-bottom offshore wind of £900 million and set an administrative strike price (ASP) of £113/MWh (2024 prices), with a separate price for projects in Scotland reflecting differences in grid network charges between the regions. However, the Secretary of State exercised his powers to double the fixed-bottom offshore wind budget for AR7 to £1.79 billion, awarding strike prices of £91.20/MWh for projects in England and Wales and £89.49/MWh in Scotland (each in 2024 prices), an increase compared to AR6. AR7 also saw two floating offshore wind (FLOW) projects receive support, with a strike price of £216.49/MWh (in 2024 prices) in a pot 4 auction, 20% lower than the ASP of £271/MWh. We expect to see a lot of activity in the offshore wind sector in 2026 and this will be a space to watch as industry digests the results. AR7 is also the first split auction, with the established (pot 1) and less established (pot 2) renewable technology auctions concluding in February (discussed below).

For FLOW, which is arguably facing similar but heightened challenges as compared to fixed-bottom offshore wind, the Crown Estate’s announcements in June and November 2025 of the awards under its 5th Celtic Sea leasing round were broadly welcomed. Three sites with potential for 4.5GW of capacity were awarded to Equinor and Gwynt Gas (two sites) and Ocean Winds (one site). In addition, public capital has been deployed to support the sector, with investment in the Pentland FLOW project (which also received support in AR7) by Great British Energy (GBE) and the National Wealth Fund (NWF). Industry will now be awaiting financial close of the Green Volt FLOW project.

AR7 implements important reforms to the CfD mechanism, including allowing repowering projects within the onshore wind category and extending the CfD term from 15 to 20 years for wind and solar projects, reducing exposure to merchant tail risk and market price volatility. Fixed-bottom offshore wind projects were also able to apply for CfD support without full planning consent, allowing projects at earlier stages of development to participate in AR7, increasing competition. In 2026, we will see further updates to the CfD terms ahead of AR8 following the outcome of an ongoing consultation, including decisions on a permanent restriction on previously surrendered capacity bidding into future ARs and introducing a new technology category for “Other Deepwater Offshore Wind” as a subset of the existing Offshore Wind category.

Aligned to the government’s growth mission, 2025 also saw the first Clean Industry Bonus (CIB) process for fixed-bottom and FLOW held ahead of AR7. The CIB provides financial rewards for projects on the condition they prioritise investment in regions of the UK that need it most or in cleaner supply chains, including traditional oil and gas communities. The government increased support to £544 million in the CIB round ahead of AR7 and anticipates that this will help leverage up to £9.3 billion in private sector investment over the next four years. In 2026, we expect to see the government response to a consultation on the CIB for AR8, including the potential expansion of the scheme to onshore wind projects.

The coming year is likely to see further deployment of funding from GBE and NWF to support CP30’s goals. Following the operationalisation and £8.3 billion capitalisation of GBE and its sister organisation GBE Nuclear in 2025, we expect GBE to drive clean energy development across the UK and seek opportunities to deploy capital as a developer, investor, and owner of clean energy projects. GBE’s strategic plan commits, by 2030, to deliver at least 15GW of clean energy generation and storage, and more than 10,000 jobs directly supported through GBE-backed and funded projects, including in areas historically dependent on oil and gas. GBE has already launched a £300 million Supply Chain Fund for Offshore Wind and Networks, aimed at building UK manufacturing capacity for key constrained components in the offshore wind and electricity network sectors such as wind turbine blades and transmission cables. Building on the Chancellor’s Statement of Strategic Priorities for the NWF in March last year, the fund will publish its strategic plan in early 2026. NWF chief executive Oliver Holbourne has indicated that it is likely to favour direct investments or co-investments (over funding via externally managed funds).

For solar, reforms to the CfD terms are expected to encourage deployment, with target commissioning windows for solar projects now extended from 3 to 12 months in AR7 to facilitate larger developments, supporting the CP30 ambition of 45-47GW of installed capacity by 2030. Up to £295 million is allocated to solar PV projects for AR7, a significant real terms increase on the maximum amount allocated to the sector in AR6. Solar projects may bid up to an ASP of £75/MWh in the AR, with results expected in late February. The government’s Solar Roadmap also includes initiatives in respect of the deployment of rooftop solar on domestic and non-domestic buildings. The sector is also expected to receive a further boost from the publication of the long-awaited Future Homes Standard and Future Buildings Standard which are expected to be published early this year. 

Planning reforms to facilitate faster consenting of renewables projects are expected to be implemented in 2026. The Planning and Infrastructure Act (PIA) received Royal Assent on 18 December 2025 and will assist by streamlining the nationally significant infrastructure project (NSIP) regime. Under related secondary legislation, from 31 December 2025, onshore wind projects (subject to a de facto ban under the Conservative government) will be reintroduced into the NSIP regime, and the capacity threshold in England and Wales at which onshore wind and ground-mounted solar projects are NSIPs will be lifted to more than 100MW – allowing smaller projects to be approved at local authority level. Beyond planning, the PIA also increases the statutory deadline for the divestment of offshore transmission assets from 18 to 27 months, a timeframe more reflective of the practical realities of testing, commissioning, and divesting these assets. Separately, the government has also committed to fast-track renewables and other planning decisions on major infrastructure by the end of this Parliament as part of its pro-growth agenda.

Finally, developers of existing renewable generation projects currently supported under the Renewables Obligation (RO) will be considering their options for when government support for a swathe of early projects comes to an end in 2027. Whilst onshore wind developers now have the option to secure CfD support for repowering for projects which meet the eligibility criteria, many will be considering what other revenue streams might be available in the market, including Corporate Power Purchase Agreements (currently the subject of a government consultation, closing on 6 March 2026).

In July 2025, the Department for Energy Security and Net Zero (DESNZ), Ofgem and the National Energy System Operator (NESO) unveiled the Clean Flexibility Roadmap building on CP30. The roadmap sets out a vision for a dynamic, consumer-focussed electricity system where flexibility is integral to cost reduction, resilience and decarbonisation. The roadmap identifies actions to unlock short duration flexibility—such as consumer-led demand response (see the Energy Markets section) and grid-scale batteries—and long duration solutions such as low carbon dispatchable power and long duration electricity storage (LDES). It also establishes a governance framework to track delivery and hold stakeholders accountable.

In relation to electricity storage, 2026 will be a significant year for the implementation of the cap and floor scheme for LDES projects. Designed to overcome investment barriers, the scheme guarantees a minimum revenue floor to provide investor confidence while capping excessive returns to safeguard consumers. The first application window for the scheme opened in April 2025, with 77 projects shortlisted to proceed to the project assessment stage in September. The shortlisted projects represent a combined discharge capacity of 28.7GW and cover a range of technology types including battery storage technologies and pumped storage hydro. Ofgem aims to publish an “Initial Decision List” of projects offered a cap and floor in Q1 2026, with the final list of successful projects to be announced in summer 2026. In spring 2026, Ofgem also aims to publish the expected timing for opening the second application window, based on advice from NESO.

In relation to low carbon dispatchable power, towards the end of 2025, Drax Power Limited signed a new low carbon dispatchable contract-for-difference (LCD CfD) with the Low Carbon Contracts Company. The LCD CfD, which runs from April 2027 to March 2031, supports the continued operation of the four biomass units at Drax’s Yorkshire power station, with flexible operation to support high and low demand periods. This innovative arrangement complements intermittent renewable generation and helps maintain security of supply. For more information on the LCD CfD, please see our post here.

The Clean Flexibility Roadmap envisages that hydrogen to power (H2P) and gas-fired power plants using carbon, capture and storage (CCS) will also be required to support system flexibility. The government intends to launch the new H2P business model, using a dispatchable power agreement-style mechanism to support the deployment of H2P (for detailed information, please see the Hydrogen section). The government’s response to a consultation on how to categorise participation of H2P in the Capacity Market is still awaited. Trials are also underway to test co-firing of hydrogen with natural gas, as a decision on hydrogen blending into the gas networks approaches, with Centrica and HiiROC doing so successfully at Centrica’s Brigg Energy Park.

Following the final investment decision for Net Zero Teesside in December 2024, support for other gas-fired power plants using CCS technology is also under consideration by government to meet system flexibility requirements (also see the CCUS section).

In relation to the CM, we expect a range of reforms to take shape in 2026. Notably, early this year the government will publish its response to a consultation ahead of the auction prequalification round commencing in July. Proposals include measures to address the interaction between the LDES cap and floor scheme and the CM, managing the transition of generating units into the CfD regime, increasing termination fees and credit-cover requirements and the introduction of a Multiple Price Capacity Market that could, if needed, support investment in new build dispatchable enduring capacity so that these units can access a higher price cap, while other participants can continue to secure agreements up to the existing £75/kW/year cap. This builds on an earlier consultation in October 2025. The government also continues to consider how better integrate low-carbon and flexible technologies into the CM.  The government’s response to its annual call for views on new generating technologies which could contribute to security of supply highlighted several forms of capacity including H2P, consumer-led flexibility and flexible compute capacity which might play a role in the CM in future. With the government’s Reformed National Pricing package expected to include changes to the CM and initiatives underway to consider engaging the demand-side in energy system balancing (see the Energy Markets section), we expect further changes to the CM in 2026.

After a busy year, the GB nuclear energy industry is looking ahead to 2026 with a renewed sense of optimism. Whilst all but one of the UK’s operational nuclear power stations are due to be retired in the early 2030s (subject to any lifetime extensions that may potentially be implemented – see below), two large-scale new nuclear plants are under construction and Secretary of State Ed Miliband has promised a new “golden age” for the sector.

New large-scale nuclear projects remain central to the UK’s future energy mix and ambition for sovereign capability in affordable, clean, homegrown power. The UK government’s final investment decision on Sizewell C in July 2025, followed by financial close in November 2025, marked a milestone for the 3.2GW plant and the first deployment of the Regulated Asset Base (RAB) model in nuclear financing. Industry observers suggest the RAB model’s success for Sizewell C could prove crucial to unlocking further private investment in new nuclear projects. Meanwhile, Great British Energy - Nuclear has been tasked with identifying suitable sites across the UK (including in Scotland) for another large-scale nuclear project, with findings due in autumn 2026. In addition, the UK government is consulting on amendments to CfD legislation to enable existing nuclear assets to qualify for CfDs, with a view to incentivising investment in reactor lifetime extensions (such as Sizewell B).

At the other end of the spectrum, modular reactors are gaining momentum. In June 2025, Rolls-Royce was announced as the selected bidder in the UK government’s small modular reactor (SMR) competition, becoming the UK government’s technology design partner for the SMR design. In November 2025, the UK government confirmed it had designated Wylfa as the first site for deployment of that SMR technology and, in December 2025, it further confirmed that work was expected to begin onsite during 2026. 2025 also saw the announcement of several private sector partnerships: X-Energy and Centrica have teamed up to develop a project for the potential deployment of up to 12 advanced modular reactors (AMRs) in Hartlepool, whilst Holtec, EDF and Tritax are collaborating on developing data centres powered by SMRs at the former Cottam coal-fired power station in Nottinghamshire. The Cottam project spotlights the potential for co-located nuclear assets to meet energy demand driven by the AI boom, with a 1GW data centre project targeted for the end of the decade. These developments underscore the significant role to be played by the private sector in the nuclear industry’s future. The UK government intends to publish imminently a framework to enable privately funded advanced nuclear projects in order to mobilise capital. 

However, challenges remain before the UK government’s vision for a “nuclear renaissance for Britain” materialises. The Nuclear Regulatory Taskforce (established by the Prime Minister in February 2025) published its review in November 2025 and confirmed that the UK remains “the most expensive place in the world to build nuclear projects”. Industry participants have warned that regulatory requirements, particularly regarding permitting and siting, represent material barriers to accelerated deployment. The Taskforce’s recommendations seek to remedy fragmentation in regulatory oversight, and to streamline environmental and permitting processes, advocating for a “radical reset” through establishing a single, unified decision-making body—a Commission on Nuclear Regulation—to act as final arbiter on all major nuclear regulatory decisions. The UK government has accepted the Taskforce’s recommendations, and is expected to produce a full implementation plan in early 2026, marking a critical juncture for whether regulatory reform can deliver the cost reductions and acceleration necessary to realise the UK’s nuclear ambitions.

We expect the future shape of the GB energy market to become clearer in 2026 as the government crystallises its thinking to electricity markets and reviews gas security of supply (as described further below). In addition, we expect the consultation on the role of Ofgem to be on the agenda in 2026, following a call for evidence in December 2024. As highlighted in the Treasury’s Regulation Action Plan Update, published in October 2025, the review is nearly complete and “recommendations for streamlining Ofgem’s duties and strengthening its mandate on growth” are imminent. Ofgem’s current remit includes regulating gas and electricity markets, heat networks, the regulated asset base model for nuclear power and carbon dioxide transport and storage networks, as well as overseeing NESO. As we have noted previously, the outcome of the review may therefore have wide-ranging consequences across the GB energy regulatory landscape.

Electricity

2025 saw significant scrutiny of the wholesale market driven by the ongoing Review of Electricity Market Arrangements (REMA) programme. In the REMA Update, published in July 2025, the government announced its decision to commit to a single national wholesale electricity market price, ruling out zonal pricing. DESNZ has, however, been clear that business-as-usual is not sustainable and indicated its intention to use a range of levers to incentivise both optimal locations for new assets and efficient system operation. For further details, please see our article here. 2026 is expected to see the publication of the Reformed National Pricing (RNP) delivery plan. Originally expected in autumn 2025, this will set out key activities for implementing RNP and an overview of the legislation required to deliver the package. The RNP deliver plan will be supported by broader market changes, including to electricity system planning, to the Balancing Mechanism, to Transmission Network Use of System charges and to the Capacity Market (see the Energy Networks and the Electricity Storage and Flexible power sections).

These market changes and interventions will need to factor in a possible future re-integration of the GB power market into the EU internal electricity market. Both the UK government and the European Commission (EC) have highlighted the benefits of reintegration, including lower consumer prices, investment in the North Sea and strengthening energy security. On 22 December 2025, they confirmed plans to begin negotiations for a European Union-United Kingdom Electricity Agreement to provide the framework for the UK’s renewed participation. It is intended that this agreement will cover wholesale and retail markets, aligning UK and EC rules for the promotion of renewables, environmental protections and State aid.

Gas

In relation to gas, 2026 is likely to see an open debate on the role of gas in the UK’s future energy mix following a consultation in November 2025 on the priorities for gas security of supply during the energy transition, and the associated challenges facing the sector. The consultation highlights that the pattern of gas supply and consumption is changing and that measures may need to be taken to ensure that security of supply is assured in rarer scenarios (e.g unprecedented failures or rare cold weather events). Whilst levers to manage this include gas storage facilities, LNG infrastructure and gas interconnectors, DESNZ highlights it would also like to explore the concept of a strategic gas storage reserve or longer-term gas contracting models. In addition, to ensure that the commercial model of gas supply works for asset owners and investors, the government is considering whether there could be a case for revenue support mechanisms for certain types of infrastructure and whether there is scope to reduce regulatory barriers to flexibility in the gas market. A response is expected in spring 2026 with further consultations to refine the detailed proposals.

Retail and supply

In relation to the retail market, following Ofgem’s publication of its Markets Regulatory Vision and Strategy in November 2025, in 2026 we expect to see continued focus on consumer energy bills and engaging consumers in the transition to net zero for example through developing skills and incentives to increase consumer engagement in electricity-system flexibility (following a consultation in 2025). Development of consumer-led flexibility will be supported by technical decisions on the sharing of customer smart data and to ensure greater visibility of distributed energy assets, as well as the migration to market-wide half-hourly settlement (currently underway and scheduled for completion in May 2027).

2026 will also see implementation of the government’s Autumn Budget and Industrial Strategy priorities to lower bills for domestic and non-domestic consumers. In particular, following the announcement of the removal of some social and environmental levies funding a range of schemes (see our briefing here), Ofgem and DESNZ will be looking to ensure the savings are fully passed on by suppliers. 2026 is also likely to see a decision (following a consultation in September 2025) on a new licence requirement on energy suppliers to offer customers at least one tariff with lower standing charges (i.e. charges designed to recover the fixed costs of the system). This is related to a wider question about how energy costs are distributed and paid for (see the Energy Markets section). Separately, following publication of its Debt Strategy, Ofgem is also consulting on a Debt Relief Scheme for customers in arrears on their energy bills for implementation this year.

Energy networks look set to continue their transition in 2026. Some analysts suggest that electricity demand is at a tipping point, predicting this is set to grow in 2026 for the first time in several years, driven by the rapid adoption of AI and the electrification of transport. Ofgem has approved an initial £28 billion investment in gas and electricity networks (with potential for this to rise to £90 billion over the five years to 2031) as part of the next price control period beginning in April 2026. £17.8 billion of this initial spending will go towards gas networks, with £10.3 billion supporting high-voltage electricity infrastructure. We are already seeing increased activity to deliver this level of new investment. Coupled with the launch of a new regulatory regime for heat networks and proposals to build the UK’s first hydrogen transport network (see the Hydrogen section), 2026 promises to be a significant year for energy network development.

The cost of increased energy network investment, as well as other costs (such as operating and policy costs), are currently collected through charges. In this context, Ofgem held a consultation in 2025 to consider whether there are more efficient ways to allocate and recover energy system costs. Following review of over 300 responses, Ofgem expects to consult on policy options in spring 2026.

2026 will also be a crucial year for network planning and the development of NESO’s centralised planning of the transmission and distribution networks with development of the first Strategic Spatial Energy Plan (SSEP) underway, following publication of the SSEP methodology in 2025. The SSEP is a long-term blueprint identifying where, and what types of, electricity and hydrogen generation and storage are needed for net zero. Originally planned for publication in the summer, final publication of the SSEP has shifted to 2027 to incorporate updated cost data into its modelling for accuracy and transparency. The SSEP will inform and complement NESO’s Centralised Strategic Network Plan (CSNP), a 25-year network blueprint for onshore and offshore transmission network requirements for electricity, hydrogen and gas, and eleven Regional Energy Strategic Plans (RESPs), comprising regional whole system energy plans across different energy types and including spatial models of future supply and demand. 2026 will see the publication of the RESPs methodology following a consultation.

Electricity networks

Increased electrification, coupled with accelerated renewable energy deployment, has exposed grid constraints as a critical bottleneck in the electricity market in Great Britain. Connection queues (for entry capacity and demand connections) now far exceed available capacity, highlighting the urgent need for substantial upgrades to the networks. Recognising that timely and efficient grid connections are essential, not only to deliver CP30 ambitions, but also to stimulate economic growth and reduce consumer costs, the government, NESO and Ofgem tackled management of the grid connection queue in 2025. Looking ahead, 2026 will see further implementation of these policies.

At the forefront is the continuation of Ofgem’s Connections Reform programme, which aims to clear speculative projects from the queue and prioritise those ready and critical to CP30 delivery. Ofgem’s approval of NESO’s “First Ready, First Needed” approach (TM04+) in April 2025 marked a decisive shift from the historic “first come, first served” model of managing grid connections. Under the new framework, Gate 2 readiness criteria were applied to determine revised queue positions and connection dates based on technology type, location, strategic alignment, and project readiness, enabling NESO to decide which projects advance in Phase 1 by 2030 and which will follow in Phase 2 by 2035. At the heart of reforms is the prioritisation of projects “where needed”, a key element of the government’s Reformed National Pricing package (see the Energy Markets section). In this regard, the development of the SSEP, CSNP and RESPs (mentioned above) will be key. Following the publication of the Connection Reform results on 8 December, the first batch of developers with connection dates in 2026/27 are now being issued with updated connection offers, with Gate 2 final customer notifications expected to be issued no later than Q3 2026. Projects failing Gate 2 criteria will receive Gate 1 offers—indicative, non-committed terms—allowing developers to terminate applications by the end of 2026. With the timeline still under review and some projects inevitably being de-prioritised, it remains to be seen whether these decisions will be challenged. Associated with this, Ofgem is currently consulting on changes to network company licence conditions and the broader regulatory framework for grid connections, to align this with the Connections Reform package.

The government, NESO and Ofgem are also looking to address the surge in demand connection applications, particularly from data centres, which has brought the total demand queue to 125GW as of June 2025. Targeted interventions are being considered to curate a viable demand queue, improve data quality and transparency, and prioritise strategically aligned demand connections. Proposed reforms include changes to grid securities, progression fees, and enabling greater participation in high-voltage asset ownership, all aimed at accelerating connection timeframes and supporting market-driven solutions. The government has also asked, Lucy Yu, the DESNZ-appointed AI Champion for Clean Energy, to carry out a review of the potential benefits and challenges of AI deployment to electricity networks, with a final report including recommendations to governments, regulators and industry, expected to be published by the summer.

Gas networks

On 30 June 2025 DESNZ published its Midstream gas system: Update to Market, setting out the government’s view on upcoming changes to the gas system in Great Britain and the measures being taken to ensure a secure, affordable and fair transition away from gas. As part of its public engagement plan, DESNZ launched a consultation in November 2025 (closing 18 February 2026) on its assessment of the priorities for security of supply. This includes consideration of the role of gas storage facilities, LNG infrastructure and gas interconnectors, and exploration of whether additional policy intervention is needed to ensure the commercial model supports the required capacity in the context of shrinking demand. In 2026, the government is expected to issue calls for evidence on network investment and affordability, and the transition of the gas system.

Heat networks

From 27 January 2026, Ofgem begins regulating heat networks in Great Britain, introducing a new authorisation regime for regulated heat network activities, strengthening consumer protections, and imposing technical standards requirements. The Heat Network Technical Assurance Scheme (HNTAS) provides the mechanism through which operators, which must register with Ofgem by 26 January 2026, evidence compliance. In parallel, the government is progressing heat network zoning, which will designate areas where heat networks offer the lowest-cost pathway to decarbonising heat. Authorities expect designations to commence in 2026 as the implementing framework takes shape.

The ambition to grow heat networks, from around 3% of heat supply today to 20% by 2050 carries an estimated investment opportunity of £60-£80 billion by mid-century. Capital grant funding—including the Green Heat Network Fund—supports this expansion. Heat pump installations have also accelerated, reaching 35,387 in the first nine months of 2025, whilst the Clean Heat Market Mechanism sets manufacturers’ Year 2 obligation at 8% of relevant boiler sales from 1 April 2026 (rising from 6%). Yet familiar constraints continue to shape delivery: the electricity-to-gas price differential blunts the household business case, grid capacity and connection timelines increasingly bite, and the supply chain—spanning manufacturing, installation, and skills—remains under pressure.

The UK CCUS sector has reached a key moment in its development with significant developments in 2025. Notably, Eni’s Liverpool Bay CO2 T&S network reached FID in April, becoming the UK’s second carbon dioxide (CO2) transport and storage (T&S) network to achieve FID (following the East Coast Cluster, developed by the Northern Endurance Partnership, in December 2024). Key emitter carbon capture and storage (CCS) projects connecting to HyNet, Padeswood cement works (Heidleberg Materials) and Protos Energy Recovery Facility (Encyclis), subsequently took FID in the autumn. £9.4 billion of additional devex funding for the sector was announced in the 2025 Spending Review, providing capital for these Track 1 projects along with devex funding for the next wave of projects in Track 2. Rounding off a busy year for the sector, the North Sea Transition Authority (NSTA) also launched its second carbon storage licensing round, offering 14 sites in English and Scottish waters to developers for exploration and appraisal, with applications due by 24 March 2026.

2026 will see the government focus on using existing capacity in these two CO2 T&S networks. We expect continued negotiations in relation to the emitter projects shortlisted for negotiation as part of the HyNet expansion exercise. The government has also indicated it will launch a further selection process in early 2026 for connections for Teesside-based projects to the East Coast Cluster. This is likely to be a high priority given bp’s decision in December to withdraw plans to develop the H2 Teesside hydrogen with CCS project (amidst competing demands for a data centre at the site). Industry bodies such as the Carbon Capture and Storage Association (CCSA) are also pressing government for progress in 2026 on negotiations with the Track 2 CO2 T&S networks: Acorn and Viking. In parallel, the market will be keen to gauge investor appetite in the proposed sale of Storegga’s stake in Acorn.

In this context, DESNZ is continuing its programme to deliver the CCUS regulatory framework. In 2026, government will consult on its view of future CCUS networks and the evolution of economic regulation for CO2 storage, following two Calls for Evidence in 2025. It will also seek stakeholder input on revisions to the framework for third party access to CCS infrastructure, and is expected to publish a long-awaited consultation on non-pipeline CO2 transportation which will be important for dispersed emitters.

The government took steps in 2025 to advance Greenhouse Gas Removals (GGR) and power with bioenergy and CCS (BECCS) to encourage private investment in large-scale GGR projects, including a £60 million Direct Air Capture and GGR Innovation Program to lower capture technology costs. In August 2025, details of the GGR business model terms for projects in the HyNet Track-1 expansion negotiation list were published. A UK GGR Standard is also under development, with interim methodologies for BECCS and direct air carbon capture and storage (DACCS) released by British Standards Institution in July 2025. The October 2025 Whitehead Review also recommended specific measures to accelerate GGR deployment, including establishment of an Office for Greenhouse Gas Removals.

In its Delivery Plan Update, published in December 2025, the CCSA highlighted the scale of development in the UK, which now has more than 100 CCUS initiatives under way with potential to capture and store roughly 77 million tonnes of CO2 annually. Despite this growth, the CCSA found that “policy uncertainty is slowing progress, stalling projects and risking investment”, noting that since 2023, 27 projects have been paused or delayed, with most experiencing average delays of around two years. As a result, industry is calling for the government to provide greater visibility of timelines for Track 2 and beyond in 2026, to increase confidence for investors in the development project pipeline.

On the international stage, the UK government used the COP30 summit to highlight its significant progress in CCUS, and leadership in emerging removal technologies. The UK and EU’s decision to link their respective Emissions Trading Schemes (ETS) is also expected to be an area of focus in 2026, as this will facilitate cross-border CO2 storage and enhance the competitiveness of UK CO2 storage projects. Industry will be hoping for further details on arrangements as part of the government’s wider negotiations with the EU (also see the Carbon Markets section).

Whilst 2025 saw steady progress in the UK’s low carbon hydrogen sector with a range of positive announcements from both the public and private sectors (outlined below), the pace of development has slowed. Projects faced delays, raising concerns about project costs, demand for low carbon hydrogen and government funding constraints. With the publication of the Hydrogen Strategy Refresh delayed from 2025, industry will be looking for government to provide fresh impetus into the market in 2026. Looking back on 2025, DESNZ made several significant hydrogen-related announcements.

In relation to the Hydrogen Allocation Rounds (HARs), under which DESNZ allocates revenue support to electrolytic hydrogen projects, DESNZ published its HAR2 shortlist in April, advancing 27 electrolytic projects to the next stage of the process. Each of the shortlisted projects will now need to pass a rigorous due diligence process (with strong emphasis placed on value for money) in order to progress further. DESNZ expects to announce the successful projects in early 2026.

The HAR2 announcement was followed in July 2025 by DESNZ’s ‘Hydrogen Update to the Market’ (the Hydrogen Update) in which DESNZ confirmed continued cross-government backing for hydrogen across key end-uses, notably in aviation where the newly introduced Sustainable Aviation Fuel Mandate (and the associated SAF revenue certainty mechanism which is designed to support SAF producers) provides opportunities for hydrogen-derived fuels (for further details on SAF, see the Alternative Fuels section). At the same time, DESNZ also confirmed the signing of ten HAR1 commercial scale green hydrogen projects. These projects, which include Hygen’s Bradford Low Carbon Hydrogen project and MorGen’s West Wales Hydrogen project, can now begin construction. DESNZ also confirmed it is currently aiming to launch HAR3 by 2026 and HAR4 from 2028.

From a regulatory perspective, green hydrogen producers also received a welcome boost when, in the November 2025 Budget, the government confirmed that it will make electricity used as part of hydrogen production via electrolysis exempt from Climate Change Levy costs, thus improving the operating cost profile of these projects. Separately, in relation to the funding of the Hydrogen Business Models, industry stakeholders are still awaiting the government’s response to the January 2025 consultation on the Gas Shipper Obligation.

Progress in relation to CCS-enabled hydrogen production was rather more limited in 2025 (for further details on CCUS, see the CCUS section). At present, no ‘blue hydrogen’ project in the UK has yet reached financial close and, in December 2025, bp decided against building a hydrogen plant in a site on Teesside, which will now be used to host a data centre instead (see the Digital & Telecoms Infrastructure section).

The government’s focus is turning to hydrogen networks and storage. The Hydrogen Update reaffirmed the ambition to develop the UK’s first regional hydrogen transport and storage network, to be operational in 2031. This was accompanied by development funding. The Spending Review in June 2025 allocated £500m for the development of hydrogen infrastructure and Ofgem announced a total of £164m of funding for Project Union in October, which seeks to repurpose existing natural gas pipelines and build new pipelines as required to create a new 1500 mile core hydrogen network for Britain, laying the groundwork for connecting regional hydrogen industrial clusters across the North of England and Scotland.

We expect activity in 2026 will be focused on the delivery of the first network, building on a consultation response on the economic regulatory framework underpinning hydrogen pipeline networks in December. This confirmed the government’s intention to establish an effective economic regulatory framework for hydrogen pipeline networks through legislation, licences, and a new hydrogen network code. We also expect further work in relation to the proposed Hydrogen Storage and Hydrogen Transport Business Models. In addition, work is underway on system planning. In October 2025, DESNZ published a policy statement setting out its view on how NESO will carry out strategic planning for hydrogen infrastructure, whilst noting that DESNZ will remain the decision maker regarding the Hydrogen Business Models. The policy statement stressed the importance of NESO taking a ‘whole system’ approach and ensuring that hydrogen infrastructure is integrated into broader energy system planning.

In relation to H2P, the government confirmed in December 2024 that it will introduce a market intervention to de-risk investment in hydrogen to power by a Hydrogen to Power Business Model based on elements of the Dispatchable Power Agreement for CCS-enabled gas-fired generation. In March 2025 DESNZ launched a consultation seeking technical evidence on innovative H2P projects which can be delivered by 2030 ahead of large-scale enabling hydrogen infrastructure. We expect to receive more details of the Hydrogen to Power Business Model during the course of 2026. Please also see the Electricity Storage and Flexible Power section.

Low-carbon fuels will play a critical role in decarbonising of aviation and surface transport as the sector progresses through 2026. Over the past year, the UK’s alternative fuels framework has shifted from policy development to implementation, yet fundamental questions around revenue certainty, cost reduction and scaling emerging fuel pathways persist.

In aviation, the UK Sustainable Aviation Fuel (SAF) Mandate came into force on 1 January 2025 and has now entered its second year of operation. The mandate operates as a tradeable certificate scheme, requiring eligible aviation fuel suppliers to ensure that SAF accounts for an increasing proportion of overall aviation fuel supply, beginning at 2% in 2025, rising to 10% by 2030, and 22% by 2040. The mandate comprises two separate obligations—the main SAF obligation and a Power-to-Liquid (PtL) obligation—with PtL obligation introduced from around 2028. Compliance with the mandate is becoming an established commercial consideration for fuel suppliers and airlines, with growing emphasis on certificate availability, pricing, and longer-term supply strategies. The industry awaits the introduction of a revenue certainty mechanism to support investment in UK SAF production. The UK’s Department for Transport has published, in the week commencing 13 January 2026, its consultation on indicative heads of terms for the SAF revenue certainty mechanism and its proposed approach to contract allocation. Without long-term price and volume certainty, developers and financiers remain cautious, particularly for capital-intensive projects. As a result, 2026 will likely prove critical in determining whether policy-driven demand can translate into a bankable domestic SAF supply chain. The eventual structure of any revenue support mechanism will attract close scrutiny, including eligibility requirements, interaction with private offtake arrangements, and the allocation of sustainability and regulatory risk. International dynamics add further complexity. For example, EU regulations and US subsidies create competitive pressure on the economic viability of UK production, whilst feedstock availability and sustainability verification present ongoing commercial and reputational challenges.

Beyond aviation, the Renewable Transport Fuel Obligation (RTFO) continues to operate as the principal support mechanism for renewable fuels used in ground transport. Updated technical guidance issued for 2026 (RTFO and SAF Mandate Technical Guidance 2026) refines fuel eligibility, sustainability reporting and lifecycle greenhouse gas accounting, reinforcing the importance of robust compliance systems for fuel suppliers.

Industry attention increasingly focuses on the need for additional government support to address the cost gap facing renewable fuels of non-biological origin and recycled carbon fuels. These fuels are widely viewed as essential to long-term decarbonisation, particularly in aviation and other hard-to-abate sectors, but remain significantly more expensive than both fossil fuels and many biofuel alternatives. Infrastructure requirements—including blending facilities, distribution networks, and storage capacity—present additional investment challenges that must be addressed alongside production economics.

The year ahead will test whether the UK’s alternative fuels framework can move from regulatory compliance to commercial viability. Success will require coordinated action across revenue support mechanisms, infrastructure development, and international alignment to create the conditions for sustained investment in domestic low-carbon fuel production.

Over the course of 2025, we observed notable progress in operationalising international carbon markets. By year end, 106 bilateral agreements between 62 countries had been adopted under Article 6.2, with 164 pilot activities recorded. The Paris Agreement Crediting Mechanism (PACM) Supervisory Body adopted foundational standards, covering baselines, additionality, leakage, suppressed demand, and non-permanence, whilst recognising landfill gas flaring and utilisation as its first methodology. Yet, concerns persist about the state of international infrastructure—particularly registries and tracking systems—with calls for accelerated implementation. Given these developments, 2026 looks set to be critical in demonstrating whether the mechanisms can deliver at scale, with the first PACM project registrations expected and bilateral Article 6.2 transactions anticipated to increase significantly.

In the UK, attention has turned to embedding integrity and transparency in voluntary carbon markets (VCMs). Building on principles published in November 2024, the government consulted in April 2025 on operationalising these through endorsing the Voluntary Carbon Market Integrity Initiative’s Claims Code of Practice and recognising the Integrity Council for the Voluntary Carbon Market’s Core Carbon Principles as minimum quality standards. The consultation explores practical measures, including official definitions for climate-related terms, claims standards with independent assurance, and cross-regulatory coordination. Parallel work addresses the tax treatment of carbon and nature credits, whilst forthcoming requirements for UK-regulated financial institutions and FTSE 100 companies to implement 1.5°C-aligned transition plans will clarify the role of voluntary credits. These initiatives are expected to crystallise into formal policy positions and, potentially, regulatory requirements during 2026, establishing the UK as a leading jurisdiction whilst ensuring compatibility with emerging international standards.

On compliance markets, the UK Emissions Trading Scheme (UK ETS) continues expanding. The maritime regime commences on 1 July 2026, covering UK domestic voyages and port emissions for vessels of 5,000 GT and above, encompassing carbon dioxide, methane, and nitrous oxide. Waste incineration and energy-from-waste facilities entered voluntary monitoring, reporting, and verification (MRV) on 1 January 2026, with full compliance obligations from 2028. On GGRs, the UK ETS Authority confirmed it will legislate for UK ETS integration by end-2028, operational by end-2029, maintaining the gross cap and requiring 200-year storage periods, with UK-based removals only qualifying initially. The Authority will publish a comprehensive assessment of the scheme’s long-term impacts during 2026.

Progress continues on the UK Carbon Border Adjustment Mechanism (UK CBAM), commencing January 2027. Following April 2025 draft legislation, the government delayed indirect emissions inclusion until 2029 at earliest. The first 12-month accounting period (January to December 2027) has returns and payments due May 2028, moving to quarterly periods thereafter. Delegated legislation will be published for consultation in early 2026.

Coordination with the EU CBAM remains crucial. Following May 2025’s UK-EU Summit and November’s EU negotiating mandate, formal talks commenced on linking the UK ETS and EU ETS, potentially preventing approximately £800 million in UK CBAM payments by 2030. Yet, significant hurdles remain. Differences in scope, carbon pricing levels, and market mechanisms must be resolved, with Switzerland’s decade-long negotiation serving as a cautionary precedent. A successful conclusion before the UK CBAM’s 2027 launch appears unlikely. UK businesses trading with the EU must therefore navigate dual compliance regimes, underscoring the importance of robust MRV systems. Collectively, these developments will determine whether 2026 marks genuine operational scaling or highlights enduring implementation challenges requiring further refinement.

In 2025, the UK government’s commitment to a “phased and responsible transition” in the North Sea remained an organising principle, but fiscal and operational pressures have intensified. In her 2025 Autumn Budget speech, the Chancellor emphasised that the UK must “build the industry of the future”, whilst retaining the Energy Profits Levy (EPL) until 2030. While Offshore Energies UK (OEUK) described this as a “bitter blow” to investment confidence, the Budget at least brought some welcome clarity on the policy direction.

The Budget coincided with publication of the government’s North Sea Future Plan, which, whilst reaffirming Labour’s manifesto commitment not to issue new oil and gas licences for new fields, introduces limited flexibility through a Transitional Energy Certificates (TECs) mechanism. TECs will permit limited production from areas tied to, or adjacent to, existing fields, provided this involves no new exploration and is necessary for a managed, prosperous, and orderly transition.

The EPL remains scheduled to conclude on 31 March 2030 but could end earlier if the EPL’s price floor—the “Energy Security Investment Mechanism” (ESIM)—is triggered. The ESIM will terminate the EPL if six-month average prices for both oil and gas fall to, or below, $74.21 per barrel and 57p per therm. The Chancellor also confirmed plans for a new Oil and Gas Price Mechanism (OGPM) to take effect when the EPL concludes. Like the EPL, the OGPM is intended to operate as a windfall tax on upstream oil and gas companies operating in the UK, but will impose an additional 35% tax rate on oil profits only where oil exceeds $90 per barrel, or on gas profits where gas exceeds 90p per therm, well above the ESIM price floor.

Office for Budget Responsibility forecasts point to a prolonged “gap” scenario through 2030, during which oil and gas prices are expected to remain above the ESIM floor, preventing early termination of the EPL, while remaining below the substantially higher price thresholds required to activate the OGPM successor tax. The result is a misalignment between the termination conditions for the existing levy, and the commencement conditions for its replacement. During this period, the EPL would continue to apply to producers at relatively moderate oil and gas prices, while the successor windfall tax remains inactive. This arguably extends windfall-style taxation beyond genuine windfall conditions, reinforcing industry concerns that the UK fiscal regime risks remaining internationally uncompetitive throughout this intervening period.

Regulatory risk has also tightened. Following the Supreme Court’s Finch ruling in June 2024, the Offshore Petroleum Regulator for Environment and Decommissioning (OPRED) issued guidance in June 2025 on environmental impact assessments for offshore projects. OPRED applies a rebuttable presumption that all hydrocarbons produced over a project’s lifetime will ultimately be combusted when assessing scope 3 emissions, while setting out the evidentiary route to rebuttal.

The EPL, together with the UK government’s policy on exploration, and recent regulatory and other legal challenges to new developments, have dampened exploration and development activity in the North Sea, a trend which we expect to continue through 2026. Conversely, these factors contributed to an increase in oil and gas M&A activity in 2025, as producers sought to replenish reserves and to generate returns from operational and financial synergies.

On emissions performance, operators’ abatement efforts contributed to a 34% drop in UK Continental Shelf (UKCS) oil and gas production emissions between 2018 and 2024, exceeding the North Sea Transition Deal’s 25% target for 2027. Yet, the NSTA’s September 2025 report warned that, without sustained focus on electrification and the elimination of routine flaring, emissions intensity could worsen, leaving UK production “less clean and less competitive compared with imports over time”. The NSTA has therefore signalled stronger impetus for electrification projects, including through primary legislation to amend its statutory objectives.

Finally, the integrated energy opportunity has expanded, with offshore wind, CCUS, and low-carbon hydrogen sharpening the case for repurposing infrastructure and supply chains. The Clean Energy Jobs Plan commits to expanding the Energy Skills Passport beyond offshore wind into sectors including nuclear and electricity networks. A new North Sea Jobs Service—launching in 2026—will also provide end-to-end transition support for oil and gas workers moving into clean energy, defence, and advanced manufacturing roles. Overall, 2025 brought consolidation rather than wholesale change, but 2026 may test the credibility of the “phased and responsible transition” framework.

The UK’s transport infrastructure has reached a pivotal moment, with 2026 poised to turn a decade of aspiration into actionable policy, provided regulatory clarity arrives quickly enough to sustain private capital confidence.

After prolonged stasis, aviation expansion has secured material political backing in line with the government’s economic growth agenda. Heathrow’s third-runway pathway—confirmed on 25 November 2025 as the basis for reviewing the Airports National Policy Statement—points toward consultation in summer 2026, and potential consent by the decade’s end. Gatwick’s Northern Runway Project, granted development consent in September 2025, faces judicial review on 20 January 2026 – although the substantive legal challenge was dismissed at first instance. Luton Airport’s expansion to 32 million passengers per annum, including new terminal capacity and taxiways, obtained consent in April 2025, its principal judicial review challenge having similarly failed. Established in June 2025 and operated by NATS (En Route) plc, the new UK Airspace Design Service will coordinate airspace redesign for the London Terminal Manoeuvring Area and its 11 airports, a prerequisite for realising capacity increases efficiently.

Increasingly, airport financing hinges on decarbonisation economics. The UK Sustainable Aviation Fuel Mandate commenced in 2025 (see Alternative Fuels section). Simultaneously, the UK ETS Authority is phasing out free allocation for the aviation sector by 2026. In combination, these instruments will intensify SAF offtake contracting and certificate value management throughout 2026, with material implications for airline balance sheets and airport investment cases alike.

Meanwhile, rail reform enters its legislative phase. The Railways Bill—introduced on 5 November 2025—will establish Great British Railways (GBR) as the single directing mind for Britain's passenger and freight network, with the body expected to become operational around 12 months after Royal Assent. The 2026 parliamentary process should clarify GBR's approach to access rights, capacity allocation, and procurement—matters of immediate consequence for signalling suppliers, digital infrastructure providers, stations developers, and freight operators navigating Britain's increasingly capacity-constrained network. Against this backdrop, the government has also announced a multi-billion pound programme to upgrade rail connectivity across Yorkshire and the North East, which it positions as part of a wider post-HS2 strategy to unlock capacity, support regeneration, and improve journey times between major northern cities.  

Road transport policy continues to reflect the government's electric vehicle ambitions, tempered by fiscal necessity. The November 2025 Budget allocated £1.3 billion in additional EV purchase support and charging infrastructure, while introducing a 3p-per-mile levy for fully electric vehicles from 2028-29—a recognition that transport taxation must evolve beyond fuel duty. In another major development, the government confirmed that it intends to proceed with the Lower Thames Crossing as a privately financed, user-funded scheme, signalling continued support for targeted new road capacity alongside its decarbonisation agenda.

The government is clear that UK ports have a significant role to play in supporting its ambitions for decarbonisation, economic growth and clean energy (offshore wind in particular). The draft revised National Policy Statement for Ports, published in June 2025, seeks to expedite NSIP consenting while strengthening environmental expectations and embedding emissions reduction into planning decisions. At the same time, maritime decarbonisation frameworks are multiplying at pace. The UK ETS Authority confirmed that domestic maritime enters the UK ETS from 1 July 2026, with consultation on extending scope to international voyages closing in late-January 2026. UK operators simultaneously face EU obligations: the EU ETS shipping phase-in reaches 70% coverage for 2026 emissions, while FuelEU Maritime has applied since 1 January 2025 to vessels calling at EU ports. Members of the International Maritime Organisation advanced mid-term decarbonisation measures in April 2025, with further decisions expected before the anticipated 2027 entry into force.

For port developers and shipowners, these overlapping regimes necessitate near-term expenditure on monitoring, reporting, and verification systems. Contractual flexibility around fuels, certificates, and allowances—where price volatility drives material value—will command increasing commercial premiums, as compliance obligations crystallise and UK-EU alignment discussions mature.

Digital infrastructure will remain a priority area for UK policymakers in 2026, as government focus shifts from recognising the sector’s strategic importance to actively shaping how it develops. Demand for data, connectivity and compute capacity continues to grow rapidly; the policy and regulatory steps taken over the past year make clear that the question for the next phase is not whether the sector will grow, but how that growth can be enabled at pace within increasingly visible system constraints.

The most significant regulatory development in the sector is the emergence of AI Growth Zones. Building on earlier announcements, the government confirmed additional Zone sites in 2025 and published a policy framework focused on accelerating delivery of AI‑driven data centre infrastructure. The approach explicitly prioritises strategically important digital infrastructure rather than reliance on a purely market‑led model. For developers and investors, AI Growth Zones will influence site selection, programme sequencing and financing structures. The framework also raises regulatory questions about transparency, competition and how prioritised projects interact with wider network planning and regional development objectives.

Less visible, yet highly determinative, are the power availability, connection costs, and delivery timelines. These factors now drive site selection and investment viability, as data centres compete for constrained grid capacity alongside broader electrification demands (see the Electricity Networks section). Developers respond through more integrated power strategies such as private wire arrangements, on-site generation, battery storage, and demand-flexibility solutions, blurring the traditional boundary between digital and energy infrastructure. These constraints reshape financing structures directly by heightening pre-FID risk, extending development horizons, and potentially sharpening focus on balance-sheet strength, phased deployment, and power-linked risk allocation. Simultaneously, environmental considerations, particularly water use, heat reuse, and emissions reporting, are evolving from secondary ESG matters into licence-to-operate imperatives, whilst shortages in specialist construction capacity and long-lead electrical equipment threaten programme certainty.  

Planning reform to accelerate digital infrastructure deployment will be another key government priority for the year ahead. In December 2025, the government launched a call for evidence on reforming planning rules to accelerate roll‑out, targeting areas where low‑impact digital infrastructure upgrades face avoidable delay and cost. This process signals a clear intention to reduce friction at local planning level, and to move more digital infrastructure into a permitted development regime. These reforms could materially shorten delivery times for network densification and upgrades, supporting nationwide connectivity objectives, and providing greater certainty for developers and operators.

The designation of data centres as part of the UK’s Critical National Infrastructure reinforces their role as foundational assets for the economy and public services, supporting continued investment in the sector. The Cyber Security and Resilience Bill, first read in Parliament on 12 November 2025, will extend baseline security standards and accelerated incident‑reporting requirements to data centre operators, increasing regulatory scrutiny of governance and operational resilience.

These developments point to continued expansion for digital infrastructure in 2026. Growth remains strongly supported, but increasingly shaped through planning reform, strategic prioritisation, and national security regulation. Success will depend on effective coordination between policymakers, regulators, and industry participants as digital infrastructure becomes ever more integral to the UK’s economic and security framework.

The coming year will be transformational for the UK water sector, heralding a range of major regulatory and institutional reforms that could reshape how water companies operate, invest, and engage with customers and the environment. The challenge for government will be to strike the right balance between regulatory rigor and consumer confidence and maintaining the sector’s attractiveness to private capital.

Fundamental regulatory changes are likely to be implemented following the Independent Water Commission’s Final Report in July 2025 (for further details see our article here). The Final Report recommended significant changes to the regulation of the water industry in England and Wales, including: (i) abolition of Ofwat and establishment of new integrated water regulators; (ii) significant re-orientation of the Price Review process towards a ‘supervisory’ approach; (iii) establishment of a new water Ombudsman in England; (iv) establishment of nine new regional water system planning authorities to oversee translation of national priorities into local plans; (v) development of new National Water Strategies and Ministerial Statements of Water Industry Priorities to provide clear, strategic direction to the sector; (vi) significant reforms to Operator Self-Monitoring to assure public health outcomes; (vii) greater alignment of public and private sector interests, including a new public benefit clause in water company licenses. The government rapidly confirmed its intention to abolish Ofwat and to introduce a single regulator for the water system in England. Full details on this and the response to other recommendations is expected imminently, followed by a public consultation on reform proposals and the transition pathway, with a new Water Reform Bill to follow. With the 2029 Price Review 2029 already coming into view, industry will be keen to achieve greater clarity on the recommendations that will be taken forward and the potential implications of these on water company businesses.

Public trust in the industry is set to remain a significant priority for industry and government. The Water (Special Measures) Act—now in effect— has strengthened regulators’ powers to ban bonuses for executives who fail to meet specific environmental and financial standards, and to bring criminal charges for persistent lawbreakers. Ofwat has also consulted on new rules to ensure senior executives meet standards of fitness and propriety to carry out their responsibilities and for involving consumers in water company decision making. Industry stakeholders will continue to monitor how these, and a raft of other new powers, are applied. In 2025, six water companies triggered the bonus ban rule under the Act for a variety of performance failures, mostly involving pollution incidents. Taken together with new minimum service standards and associated customer compensation levels, stricter enforcement and an emphasis on accountability are expected.

Final clarity on most PR24 spending plans is expected in March, when the CMA publishes its final re-determinations for the five companies that appealed Ofwat’s original determinations. The CMA has provisionally indicated that it may permit 21% - an additional £556 million in revenue – of the headline £2.7 billion the appellants collectively requested and a slightly higher average rate of return (4.29% up from 4.03%). However, it also cautioned that it would “largely reject” funding requests for new activities and projects “beyond the significant increases already allowed by Ofwat”. These headline results also belie an uneven distribution among the appellants.

Along with sector level reforms, the financial sustainability of individual water companies looks set to be tested further in 2026 with Thames Water’s long-awaiting recapitalisation plans still unresolved, its PR24 determination reference deferred indefinitely by Ofwat, and the government so far resisting temporary renationalisation under the special administration regime.