The UK has a fully liberalised and privatised electricity market, meaning that the companies responsible for the generation, transmission, distribution and sale of the UK’s electricity are all in the private sector. However, this is set to change. On 25 July 2024, the government introduced the Great British Energy Bill into Parliament – the aim of which was to establish a new, public-owned company (Great British Energy) that would work closely with the private sector to promote, invest, own and manage clean energy projects. On 15 May 2025, the Great British Energy Act received royal assent after passing through Parliament and came into force on the same day. The government has announced that Great British Energy is backed by GBP8.3 billion between now and July 2029.

Structure and System of Ownership

Currently, England, Wales and Scotland (Great Britain, Britain, or GB) have a single integrated energy market for both electricity and natural gas. On 1 October 2024, the National Energy System Operator (NESO) replaced the National Grid Electricity System Operator (National Grid ESO) as the electricity system operator for Great Britain. Unlike National Grid ESO, which was part of National Grid plc, NESO is an independent public corporation overseeing Great Britain’s electricity and gas networks. NESO’s focus is on ensuring that Great Britain’s energy system is secure, affordable and amenable to a sustainable future.

The power industry in Northern Ireland is separate to and distinct from the industry in Great Britain. This is because energy in Northern Ireland (other than nuclear energy) is a devolved power, meaning the Northern Ireland Assembly – rather than the UK Parliament – has legislative control. The electricity industry operates a single wholesale market across the whole of the island of Ireland, known as the Single Electricity Market (SEM). The operation of this single wholesale market requires the physical connection of the Northern Ireland grid to that in the Republic of Ireland. This is facilitated by the Single Electricity Market Operator (SEMO), which is a contractual joint venture between the two system operators – System Operator for Northern Ireland (SONI) in Northern Ireland and EirGrid plc in the Republic of Ireland.

Principal Laws Governing Ownership

The Electricity Act 1989 requires that the following are authorised by a licence:

• generators;
• those who participate in the transmission of electricity;
• distribution network operators;
• supply companies;
• those who co-ordinate the flow of electricity onto and over transmission systems;
• interconnector operators; and
• smart meter providers.

The last EU energy legislation package to be fully implemented by Great Britain before its exit from the EU (“Brexit”) was the Third Energy Package. This was adopted by:

• the Gas and Electricity (Internal Markets) Regulations 2011 in Great Britain; and       
• the Gas and Electricity (Internal Markets) Regulations (Northern Ireland) 2011 and 2013 in Northern Ireland.

A collection of detailed codes and agreements, known as the industry documents or industry codes, govern the rights and obligations of the companies that participate in the electricity industry. The Office of Gas and Electricity Markets (Ofgem) is involved in the modification processes for most of these industry documents and requires, under the terms of the licences granted under the Electricity Act 1989, that:

• each licensed company is a party to each agreement and complies with each code that is relevant to its licensable activities (as specified in the licence); and
• network companies (eg, National Grid or a Distribution Network Operator (DNO)) or NESO maintain and provide for the administration of key industry documents.

Generation

As of 16 May 2025, there are 631 electricity generation licences in Great Britain. Key operators include Drax Power, EDF Energy, Engie, RWE, Scottish Power and SSE.

As of 16 May 2025, there are 73 electricity generation licences in Northern Ireland.

Transmission

In Great Britain, transmission is owned and operated by NESO (who took over from National Grid Electricity Transmission plc on 1 October 2024) in England and Wales, SP Transmission plc in central and southern Scotland, and Scottish Hydro Electric Transmission plc (trading as SSEN) in northern Scotland.

As of 16 May 2025, there are 30 transmission licence holders in Great Britain.

SONI, a subsidiary of EirGrid plc, holds the transmission system operator licence for Northern Ireland. NIE Networks Limited and Moyle Interconnector Limited also hold transmission licences.

Distribution

As of 16 May 2025, there are 14 electricity distribution licensees and 22 independent electricity distribution licensees in Great Britain. The distribution licensees are:

• Eastern Power Networks plc;
• Electricity North West Ltd;
• London Power Networks plc;
• National Grid Electricity Distributions (East Midlands) plc;
• National Grid Electricity Distributions (South Wales) plc;
• National Grid Electricity Distributions (South West) plc;
• National Grid Electricity Distributions (West Midlands) plc;
• Northern Powergrid (Northeast) Ltd;
• Northern Powergrid (Yorkshire) plc;
• Scottish Hydro Electric Power Distribution plc;
• South Eastern Power Networks plc;
• Southern Electric Power Distribution plc;
• SP Distribution plc; and
• SP Manweb plc.

In Northern Ireland, NIE Networks Limited holds a distribution licence.

Sales to End-User Consumers

As of 16 May 2025, there are 65 domestic and non-domestic suppliers and 39 non-domestic suppliers in Great Britain. The main suppliers include:

• British Gas (owned by Centrica plc);
• EDF Energy (owned by French state-owned energy firm EDF);
• E.ON (owned by German energy firm E.ON SE);
• nPower (ultimately owned by E.ON UK);
• OVO (a privately owned firm that bought SSE’s domestic energy business in early 2020); and
• Scottish Power (owned by Spanish energy firm Iberdrola).

In May 2025, there are 20 holders of supply licences in Northern Ireland.

National Security and Investment Act

The National Security and Investment Act 2021 (NSIA) introduced new requirements for foreign direct investment in certain business sectors that potentially affect national security. The new regime created notification requirements for certain transactions on either a mandatory or voluntary basis. Mandatory pre-notification requirements apply in respect of entities in “key sectors”, which includes energy (and specifically includes entities that hold transmission, distribution, interconnector and/or generation licences). The requirements apply to transactions involving the acquisition of a 25% stake or more (or equivalent levels of voting rights, including certain “veto” rights) in an entity, as well as certain acquisitions that involve the acquirer moving to a higher level of interest (eg, more than 50%).

Industry Act 1975

Section 13 of the Industry Act 1975 entitles the Secretary of State to block an acquisition by a non-UK-based entity of an “important manufacturing undertaking” when it appears that a change of control would be contrary to the interests of the UK (or a substantial part of the UK).

Restrictions

As explained in 1.3 Foreign Investment Review Process, since 4 January 2022, a mandatory notification regime under the NSIA has applied to transactions that fall within the definition of a “notifiable acquisition” (as set out in Section 6 of the NSIA). Under Section 13 of the NSIA, a notifiable acquisition that is completed without the approval of the Secretary of State is void.

To qualify as a notifiable acquisition, the transaction must meet both of the following criteria, per Section 6 and Section 8 of the NSIA:

• the subject being acquired must be a qualifying entity that operates within a specific high-risk sector of the economy – the energy sector is specified as such by the Notifiable Acquisition Regulations; and
• as a result of the transaction, the acquirer gains control of the qualifying entity by:
1. acquiring voting rights that enable it to secure or prevent the passage of any class of resolution governing the affairs of the qualifying entity; or
2. increasing its shares or voting rights:
1. from 25% or less to more than 25%;
2. from 50% or less to more than 50%; or
3. from less than 75% to 75% or more.

The person gaining control or acquiring an interest in the qualifying entity must submit a notification digitally using the National Security and Investment (NSI) electronic portal and must comply with the form and content prescribed by the NSI Notices Regulation.

Where a transaction does not require a mandatory notification, parties may voluntarily notify the Secretary of State in order to obtain a call-in decision regarding the transaction.

Principal Law Governing Sales or Mergers

The Competition Act 1998 and the Enterprise Act 2002 are the major sources of competition law in the UK and govern mergers.

The Competition Act 1998 prohibits companies from:

• engaging in practices that distort, restrict or prevent competition in the market; and
• abusing a dominant position in the market.

The Enterprise Act 2002 builds upon the Competition Act 1998 and sets out the tests for when and how the government can intervene in mergers.

Following the UK’s withdrawal from the EU, any mergers that began after 1 January 2021 require clearance from the UK’s Competition and Markets Authority (CMA).

The Digital Markets, Competition and Consumers Act 2024 introduced wide-ranging amendments to the UK competition and consumer law regimes – thereby expanding the powers of the CMA and significantly altering the merger control and antitrust investigation processes.

Regulator and Approval Process

Competition and Markets Authority

The CMA was established under the Enterprise and Regulatory Reform Act 2013 and is the body in charge of competition regulation and enforcement in the UK. The CMA studies the function of competition in the UK’s energy market as a whole and can initiate targeted investigations based on its findings.

The CMA may commence a review of a merger on its own initiative or following a formal notification being made by the businesses. The CMA has a statutory deadline of 40 working days in which to complete the first phase (Phase 1) of its merger review process. If the CMA determines that the merger has a realistic prospect of substantially decreasing competition, it will begin an in-depth assessment, which is generally limited to 24 weeks (Phase 2). Parties may offer to alter aspects of the transaction in order to mitigate any competition risks that were identified.

Please see 2.4 Market Concentration Limits for details of the circumstances in which the CMA has the jurisdiction to examine a merger.

Gas and Electricity Markets Authority

The Gas and Electricity Markets Authority (GEMA), a panel of independent experts appointed by the Secretary of State, has concurrent authority with the CMA on the application and enforcement of certain competition rules in the energy sector.

Northern Ireland Authority for Utility Regulation

The Northern Ireland Authority for Utility Regulation (NIAUR) is an independent government department that promotes effective competition in the market of Northern Ireland. It enforces the prohibitions in the Competition Act 1998 and can make market investigation references to the CMA under the Enterprise Act 2002. The NIAUR and the CMA work together under the terms of a memorandum of understanding.

Ofgem regulates the electricity and downstream gas industries within Great Britain. Its powers are set out in the:

• Gas Act 1986;
• Electricity Act 1989;
• Competition Act 1998;
• Enterprise Act 2002;
• Utilities Act 2000;
• Energy Act 2004, Energy Act 2008, Energy Act 2010, Energy Act 2011, and Energy Act 2023;
• Electricity and Gas (Market Integrity and Transparency) (Enforcement etc) Regulations 2013 (SI 2013/1389); and
• Domestic Gas and Electricity (Tariff Cap) Act 2018.

Ofgem’s principal duty is to protect the interests of gas and electricity consumers. Ofgem is governed by GEMA. For details of the concurrent powers Ofgem shares with the CMA, please see 2.5 Surveillance to Detect Anti-Competitive Behaviour.

Northern Ireland has its own national regulatory authority, the NIAUR (see 1.4 Sale of Power Industry Assets), which works in close co-operation with Ofgem. Ofgem is responsible for the process of accrediting renewable energy installations and issuing Northern Ireland Renewable Obligation Certificates (NIROCs) to generators in Northern Ireland.

In Great Britain, NESO owns and maintains the high-voltage electricity transmission network in England and Wales. NESO is responsible for ensuring the stable and secure operation of the national electricity transmission system (NETS), including the adequacy of supply to satisfy the demand for electricity.

The Department for Business, Energy and Industrial Strategy (BEIS), the UK government department that previously oversaw the energy sector, was dissolved in early 2023. The Department for Energy Security and Net Zero (DESNZ) assumed the role of managing Britain’s long-term energy supply, with a special focus on meeting net zero targets.

The Financial Conduct Authority (FCA) monitors and enforces financial regulation across the commodities markets, including the energy markets. Ofgem and the FSA first put co-operation arrangements in place in 2002. Ofgem is the principal regulatory authority for UK REMIT (the retained EU law version of the Regulation on wholesale energy market integrity and transparency (Regulation 1227/2011)).

Citizens Advice is an independent watchdog that operates across the whole of the economy. Its core role in the energy sector is to secure a fair deal for energy customers. It is a registered charity.

Elexon is a non-profit-making entity responsible for managing the balancing mechanism and the imbalance price process.

The British Energy Security Strategy (published by BEIS in April 2022) stated that the UK government would appoint an Electricity Networks Commissioner to advise it on policies and regulatory changes in order to accelerate progress on network infrastructure. On 6 July 2022, Nick Winser was appointed as the UK’s first Electricity Networks Commissioner and remains in the role as of May 2025. Between July 2022 and July 2023, the Electricity Networks Commissioner engaged with stakeholders across the electricity transmission network and published an independent report setting out his recommendations to halve the total development time for transmission infrastructure.

A joint consultation between Ofgem and BEIS published in July 2021 proposed the creation of an independent system operator, known as the Future System Operator (FSO). In April 2022, Ofgem published a document setting out the decisions of the joint consultation, which explains Ofgem’s collective commitment to create an expert, impartial FSO with an important duty to facilitate net zero while also maintaining a resilient and affordable system.

In November 2022, Ofgem published its decision on the initial findings of its Electricity Transmission Network Planning Review – namely, that the FSO should deliver a new electricity transmission network planning output called a Centralised Strategic Network Plan. Part 5 of the Energy Act 2023 provided for the establishment of the FSO, which was relabelled NESO in January 2024. Please see 1.1 Law Governing the Structure and Ownership of the Power Industry for more information.

In December 2024, as a “first step to repair Great Britain’s retail energy market”, the government announced a call for evidence on the role of Ofgem. It sought views on Ofgem’s remit, standards and the tools it is equipped with.

The Great British Energy Act 2025 (see 1.1 Law Governing the Structure and Ownership of the Power Industry) has been described as landmark legislation, introducing Britain’s new publicly owned energy company, Great British Energy. The government has announced that the Energy Secretary will soon outline Great British Energy’s strategic priorities – including which technologies the government expects the company to focus on and how it should consider the public benefits from investment decisions.

Another major development was the Energy Act 2023, which has provisions concerning energy production and security and the regulation of the energy market, including on:

• the licensing of carbon dioxide transport and storage (Part 1);
• commercial arrangements for industrial carbon capture and storage and for hydrogen production (Part 2);
• new technology, including low-carbon heat schemes and hydrogen grid trials (Part 4);
• the independent system operator and planner (Part 5) (ie, the FSO, which became NESO – see 1.5 Central Planning Authorities);
• gas and electricity industry codes (Part 6);
• heat networks (Part 8);
• energy smart appliances and load control (Part 9);
• the energy performance of premises (Part 10);
• the resilience of the core fuel sector (Part 12);
• offshore energy production, including environmental protection, licensing and decommissioning (Part 13); and
• the civil nuclear sector, including the Civil Nuclear Constabulary (Part 14).

On 5 December 2022, the UK ban prohibiting the import, supply and delivery of Russian oil and oil products into the UK and associated ancillary services in respect of these activities came into effect. The principal regulations that give effect to sanctions against Russia are the Russia (Sanctions) (EU Exit) Regulations 2019 (SI 2019/855), which incorporate the amendments made by the Sanctions (EU Exit) (Miscellaneous Amendments) (No 4) Regulations 2020, Russia (Sanctions) (EU Exit) (Amendment) Regulations 2022 and Russia (Sanctions) (EU Exit) (Amendment) Regulations 2023. As of May 2025, this ban is still in force.

On 28 October 2022, the UK imposed sanctions against the Russian Federation that prohibit the import of LNG originating in or consigned from the Russian Federation – along with technical assistance, brokering services, financial services and funds relating to such import or acquisition. The ban came into force on 5 December 2022 and as of May 2025 are still in force.

In October 2021, the UK government announced its ambition to fully decarbonise the power sector by 2035.

On 7 April 2022, the government announced the British Energy Security Strategy (see 1.5 Central Planning Authorities), which resulted in the Energy Act 2023 (see 1.6 Recent Changes in Law or Regulation). The Energy Act 2023 was introduced to deliver on many of the commitments set out in the British Energy Security Strategy (as well as the government’s Ten Point Plan announced in November 2020) by:

• establishing a new FSO, now known as NESO (see 1.5 Central Planning Authorities), which will look at Great Britain’s energy system as a whole, and integrating existing networks with emerging technologies such as hydrogen;
• introducing competition in Britain’s onshore electricity networks to encourage investment and innovation; and
• supporting the growth of a 10 GW hydrogen economy and new carbon capture, utilisation and storage (CCUS) industry.

Since coming into power in July 2024, the current Labour government has reinforced its pre-election commitment to making Britain a “clean energy superpower” by 2030 as one of its key missions.

In September 2024, the government published a research briefing titled The UK’s Plans and Progress to Reach Net Zero by 2050, which provided an overview of the background context for the UK’s commitment to reach net zero, the plans in place to reach this goal, and current progress. The briefing sets out the UK’s:

• net zero targets;
• policy developments in 2023 and 2024; and
• an assessment of progress.

In October 2024, the current government announced it had made available GBP21.7 billion in funding for the first CCUS projects in the UK. CCUS is a low-carbon solution that enables the production of clean power, clean products (such as steel and cement) and clean hydrogen, which can then be used to decarbonise heating and transport.

On 12 November 2024 at COP29, the Prime Minister announced the UK’s ambitious Nationally Determined Contribution (NDC) target to reduce all greenhouse gas emissions by at least 81% by 2035, compared to 1990 levels (excluding international aviation and shipping emissions).

Locational Pricing Scheme

In April 2025, the Energy Secretary, Ed Miliband, said that he was considering plans to introduce regional pricing for power, which could lead to lower bills in parts of the country that generate more energy, as power costs would match local supply and demand. He did not set out details of the “locational pricing” scheme, which is intended to make the national energy grid more efficient and encourage investment.

In May 2025, engineering and consultancy firm AFRY completed a review of electricity market arrangements in Great Britain, in response to the electricity transmission operators programme for net zero reform and to the Review of Electricity Market Arrangements (REMA) process. AFRY found moving to locational pricing in the UK electricity market would be “high risk for little reward”. However, there are others, such as Octopus Energy’s CEO, who have called for locational pricing in order to make bills cheaper and give areas of the UK with plenty of renewable generation some of the cheapest electricity in Europe.

It has been recently reported that technology companies who are high-load consumers of electricity through their operation of data centres are advocating for the introduction of locational pricing in the UK. This is because it would likely lead to areas such as Scotland offering cheap electricity prices because of an abundance of windfarms and low population density, making them hotspots for data centres.

However, in July 2025, Ed Miliband said that the UK would not introduce locational pricing.

The UK benefits from a geographical advantage in respect of long coastline, shallow water and consistent strong winds, meaning that it is one of the world’s leaders in both offshore and onshore wind power.

Further, the UK has often led the way in terms of innovation in energy technology and related markets. Among its other contributions, the UK was:

• the first to build a coal-fired power station (the Edison Electric Light Station was built in London in 1882);
• the first to build a full-scale nuclear power station in the Western world; and
• the first major economy to put into law that it would reach net zero carbon emissions by 2050.

Great Britain currently uses national pricing. However, as mentioned in 1.7 Announcements Regarding New Policies, the Energy Secretary has recently been evaluating the benefits of a locational pricing model.

In 2005, the British Electricity Transmission and Trading Arrangements (BETTA) introduced a GB-wide electricity market, setting one price for electricity in each trading period.

The following wholesale markets operate within BETTA to allow electricity market participants to buy and sell power.

• Forwards and futures market – contracts between generators and supply companies for the delivery of electricity are entered into from between several years to 24 hours in advance. These markets allow generators and suppliers to enter into contracts for the purchase of electricity at an agreed price on an agreed date. The majority of electricity trading in Great Britain takes place in either the forwards market or the futures market.
• Short-term market (also known as the “spot market”) – this market operates two days ahead of the relevant half-hour settlement period. This means that contracts for electricity can be bought between 48 hours prior to the relevant settlement periods and the submission deadline.

In order to achieve liquidity, Great Britain’s major energy suppliers have committed to trade a proportion of their power station output in the day-ahead market (where power is sold for use the next day).

As DNOs own and operate the local distribution systems within their allocated areas, they have a monopoly. Regulation of DNOs is achieved through price controls, which limit how much DNOs can charge the supply companies. Price controls also limit how much TOs (who have a monopoly over the transmission system) can charge DNOs. The price control regime for electricity distribution from 1 April 2015 to 31 March 2023 was known as RIIO-ED1. The current price control regime (RIIO-ED2) applies from 1 April 2023 to 31 March 2028. The RIIO-ED2 price control periods are five years – rather than eight – and companies can submit proposals for allowances for specific longer-term items.

For electricity TOs, the first RIIO period (referred to as RIIO-ET1) ran from 1 April 2013 to 31 March 2021 and the second period (RIIO-ET2) began on 1 April 2021. The SO has a separate incentive regime.

For electricity suppliers, the licensing regime provides Ofgem with a means to implement consumer protection measures (including retail price controls and appointing a supplier of last resort) and industry-wide schemes such as feed-in tariffs (FITs).

The UK has a capacity market (CM), which was introduced in 2014 as part of a wider programme of reform (known as Electricity Market Reform, or EMR – itself part of the Energy Act 2013). Following the end of the UK–EU Withdrawal Agreement Transition Period (the “Transition Period”) on 31 December 2020, the CM operates under new trading arrangements with the EU under the terms of the UK–EU Trade and Cooperation Agreement (TCA).

The CM is governed by the Electricity Capacity Regulations 2014 (“the Regulations”) and the Capacity Market Rules (the “CM Rules”). The Regulations provide the overarching policy and design, including the powers the Secretary of State holds in overseeing the CM. The CM Rules provide the detail for implementing the operating framework set out in the Regulations. NESO is the EMR Delivery Body responsible for administering key elements of the CM.

Imports and exports of electricity to and from other jurisdictions are permitted in the UK. Currently, there are interconnectors linking Great Britain to France, the Netherlands, Belgium, Northern Ireland, Ireland, Norway and Denmark. The latest interconnector to start commercial operations was Greenlink in January 2025, connecting the UK with Ireland. The UK plans additional interconnectors to Germany, France and Morrocco by 2030.

Great Britain’s electricity market currently has 9.8 GW of electricity interconnector capacity:

• 4 GW to France (IFA, IFA2 and ElecLink);
• 1 GW to the Netherlands (BritNed);
• 1 GW to Belgium (Nemo Link);
• 500 MW to Northern Ireland (Moyle);
• 1 GW to Ireland (East West and Greenlink);
• 1.4 GW to Norway (NSL); and
• 1.4 GW to Denmark (Viking Link).

Under the current regulatory framework, there are two general routes for interconnector investment, as follows.

• A regulated route under the UK’s “cap and floor” regime, which allows developers to identify, propose and build interconnectors, subject to Ofgem approval. A cap and floor mechanism regulates how much money a developer can earn once in operation, providing developers with a minimum return (floor) and a limit on the potential upside (cap) for a 25-year period.
• As an alternative to the cap and floor model, developers can seek exemptions from regulatory requirements. Under this route, developers would face the full upside and downside of the investment and would usually apply for an exemption from certain regulatory requirements to better enable the business case of their investment.

All interconnection capacity is allocated to the market via market-based methods (ie, auctions) and the trading arrangements on electricity interconnectors are governed by access rules and charging methodologies contained within each interconnector’s licence.

Imports and exports typically occur when there is surplus renewable electricity. The National Grid states that, by 2030, 90% of the energy imported by interconnectors will be from zero-carbon energy sources.

In April 2025, Great Britain’s supply mix was:

• gas – 26.1%;
• wind – 22.4%;
• nuclear – 13.1%;
• biomass – 7.3%;
• solar – 10.5%;
• imports – 18.2%;
• hydro – 0.9%; and
• storage – 1.5%.

46% of electricity came from zero-carbon sources.

In Northern Ireland, for the 12-month period from January 2024 to December 2024, 43.5% of total electricity consumption was generated from renewable sources. This represented a decrease of two percentage points from the previous 12-month period.

The vast majority (81.7%) of renewable energy generated within Northern Ireland came from wind sources.

The CMA has the jurisdiction to examine a merger where two or more businesses cease to be distinct and either:

• the UK turnover of the acquired enterprise exceeds GBP100 million;
• the two businesses supply or acquire at least 25% of the same goods or services supplied in the UK and the merger increases that share of supply and at least one of the merging enterprises has a UK turnover of more than GBP10 million; or
• at least one of the merging parties has an existing share of supply of 33% in the UK or in a part of the UK, the total value of the turnover in the UK of that party exceeds GBP350 million, and the other party has a UK nexus.

The CMA and Ofgem both enforce prohibitions on abuse of a dominant position. For further details of their shared powers with regard to the gas and electricity industries, please see 2.5 Surveillance to Detect Anti-Competitive Behaviour.

The CMA shares concurrent powers with Ofgem to enforce prohibitions on anti-competitive agreements and make market investigation references within the gas and electricity industries.

The construction and operation of generation facilities is principally governed by the Electricity Act 1989. Specific authorisations required will depend on the size, nature and location of the generation facilities.

Section 6 of the Electricity Act 1989 (as amended by Section 186 of the Energy Act 2023) lays down the procedures in respect of the grant, extension or restriction of electricity licences. Unless one of two exemptions applies, an electricity generator must issue an application to Ofgem for a generation licence under Section 6(1)(a) of the Electricity Act 1989.

Once a licence is granted, licensees are required to comply with applicable industry codes. For further details, please refer to 3.3 Approvals to Construct and Operate Generation Facilities.

Onshore Generation Facilities

For the construction of onshore generation facilities over 50 MW in England and Wales, consent from the Secretary of State for Energy Security and Net Zero is required under Section 36 of the Electricity Act 1989. Such generation projects are often classified as a nationally significant infrastructure project (NSIP) under the Planning Act 2008 and therefore require a development consent order (DCO). Generation projects with a capacity of less than 50 MW are considered under the Town and Country Planning Act 1990.

It was recently reported in Scotland that Glen Earrach Energy had submitted its application for a 2 GW pumped storage hydro project near Loch Ness, under Section 36 of the Electricity Act 1989.

Onshore Wind Farms

The 2015 National Planning Policy Framework (NPPF) only permitted construction of wind turbines on land specifically designated by local councils in their development plans and with the full support of local communities. Renewable energy groups and many other stakeholders considered this to be a de facto ban on onshore wind. In September 2023, the government updated the NPPF to provide that local authorities should approve planning applications for an onshore wind farm if impacts identified by the local community are “appropriately” – rather than “fully” or “satisfactorily” – addressed. However, this amendment made little difference in practice.

On 8 July 2024, the new Labour government lifted the de facto ban on onshore wind development by removing additional restrictive tests and placing the assessment and approval of new onshore wind projects on an equal footing with all other proposed infrastructure.

Irrespective of their size, onshore wind farms are considered under the Town and County Planning Act 1990. Facilities between 1 MW and 100 MW require consent from the Marine Management Organisation. Facilities over 100 MW are considered NSIPs and are subject to the DCO regime.

Solar Farms

An updated NPPF was published in December 2024, with a new policy on renewable energy located in the Green Belt. This requires developers to demonstrate “very special circumstances” for locating “small-scale” solar farms (those generating below 100 MW from 31 December 2025) within the Green Belt.

The government’s Clean Power 2030 Action Plan (published in December 2024) includes a target for the total installed capacity of solar installations to reach 45‒57 GW by 2030, about 2.5 times the installed capacity in March 2025 (18.1 GW). It noted that there is the potential for an additional 9‒10 GW by 2030 though the deployment of rooftop solar.

The government has also recently relaunched the Solar Taskforce, a joint government industry body. The Solar Taskforce will publish a solar roadmap that will set out a “step-by-step deployment trajectory” and recommendations to government and industry for actions needed to meet the governments targets on solar energy. The Clean Power Action Plan stated the roadmap was expected in Spring 2025 but, as of May 2025, has not been released.

Nuclear Generation Facilities

All nuclear generation facilities are NSIPs and therefore require a DCO, as well as environmental permits and a nuclear site licence. The 1965 Nuclear Installations Act deals with liability and governs the construction and safe operation of nuclear plants.

All electricity generators (commercial or otherwise) must obtain a generation licence – issued by Ofgem – under Section 6(1)(a) of the Electricity Act 1989 (as amended by Section 186 of the Energy Act 2023). It is an offence to generate, distribute or supply energy without a licence unless the Secretary of State for Energy Security and Net Zero grants a class or individual exemption.

The Electricity (Applications for Licences, Modifications of an Area and Extensions and Restrictions of Licences) Regulations 2019 (SI 2019/1023) (the “Electricity Licence Application Regulations”), made by Ofgem, set out the procedure for applying for a licence and the fee payable.

Although primary responsibility for the energy sector falls on GEMA, GEMA delegates the day-to-day administration of its functions to Ofgem. Accordingly, Ofgem has the authority both to grant licences (without further reference to GEMA or any government ministry) and enforce them.

Ofgem adopts a risk-based approach to licence applications, in that all applicants must complete the information required under Tier 1 so that an initial risk assessment may be carried out. The application may then progress to Tier 2, which gives rise to additional requirements.

When considering whether to grant a licence, Ofgem will consider whether:

• the licensees can finance their activities;
• all reasonable demands for electricity and gas are met;
• the licence will contribute to the achievement of sustainable development; and
• the interests of particular consumer groups (eg, those with a disability) are met.

Ofgem must act in accordance with its duties as set out in Section 3A of the Electricity Act 1989, as well as with the Utilities Act 2000, the Competition Act 1998, the Enterprise Act 2002, the Energy Act 2004, the Energy Act 2008, the Energy Act 2010, the Energy Act 2011, the Energy Act 2013 and the Energy Act 2023.

Public participation/input is not permitted or required; rather, Ofgem undertakes the process internally.

Once Ofgem has deemed that an application has been “duly made” (ie, confirmed as complete), the relevant time period for processing the application commences. For electricity generation licences, it is 65 working days.

Applicants for a gas or electricity licence must publish notice of their application within ten working days of notification that the relevant application has been duly made.

Once a licence is granted, licensees must comply with the standard licence conditions and also become party to and/or comply with certain industry codes.

The standard licence conditions (SLCs) will depend on the type of licence that is granted. In general terms, the licence requires the provision of ancillary services to National Grid, prevents the licensee from making excessive profits from transmission constraints, and – in some cases – prohibits discrimination in selling electricity. The licence is a public document and is available on Ofgem’s electronic public register. A generation licence is the least regulated of the licensable activities.

From 1 October 2024, an electricity generation licence has the following standard conditions.

• The licensee must comply with:
1. the requirements of the Grid Code (so far as applicable);
2. every applicable Distribution Code;
3. the Fuel Security Code;
4. the programme implementation scheme designated by the Secretary of State;
5. the Balancing and Settlement Code (BSC) and New Electricity Trading Arrangements (NETA) Implementation;
6. the Connection and Use of System Code (CUSC);
7. the BETTA run-off arrangements scheme;
8. any scheme imposed by the Secretary of State in relation to the preparation and storage of regulatory accounts; and
9. any scheme made by the Secretary of State under Schedule 7 to the Utilities Act 2000.
• The licensee must make all reasonable measures to secure and implement the provisions of the Utilities Act 2000.
• The licensee must be party to:
1. the BSC Framework Agreement; and
2. the CUSC Framework Agreement.
• From time to time, upon request by the SO, the licensee must offer terms for the provision by the licensee of ancillary services from any operating generation set of the licensee.
• The licensee must, at any time and upon request of GEMA, provide a report containing the details of:
1. prices offered for the provision of ancillary services; and
2. an explanation of the factors justifying the prices offered.
• The licensee must furnish GEMA with information it reasonably requires for the purpose of performing the functions conferred on it by or under the Electricity Act 1989.
• The licensee must prepare and publish a Consolidated Segmental Statement in relation to revenues, costs and profits of its activities on its website.
• The licensee must not obtain an excessive benefit from electricity generation in relation to a Transmission Constraint Period.

There are supplementary standard conditions that apply in Scotland, under Section C of the SLCs for electricity generation.

The standard conditions may be modified by Ofgem when granting a licence (or subsequently) and, in some cases, can be modified by the Secretary of State.

There are no general eminent domain rights or similar for electricity generation facilities in the UK. The Secretary of State may, however, grant any licence holder the power to acquire land compulsorily under Schedule 3 of the Electricity Act 1989.

In England, compulsory purchase in practice falls under the Planning Act 2008 DCO procedure.

Standard Licence Condition 14(3) restricts exercise of compulsory purchase powers to generating stations of 50 MW or more.

In Wales, compulsory purchase procedures apply to onshore wind (of any capacity) and other (non-wind) onshore generating stations of between 50 and 350 MW capacity (apart from pumped storage, to which the Planning Act 2008 DCO regime applies).

There are specific requirements for decommissioning nuclear power stations. There are two distinct decommissioning processes under the Energy Act 2008:

• process for decommissioning existing nuclear power plants that were commissioned before 2008; and
• process for decommissioning new nuclear power plants that were commissioned after 2008.

Most of the UK’s existing fleet of nuclear power stations were built in the 1960s and 1970s and are nearing the end of their operational life. At present, seven power plants in the UK are being decommissioned at a cost of circa GBP23.5 billion, and most of the UK’s existing nuclear power stations will need to be decommissioned before 2030. The body responsible for decommissioning nuclear power plants is the Nuclear Decommissioning Authority (NDA). The NDA is sponsored by DESNZ.

Energy companies seeking to construct any new nuclear power stations must ensure that they have sufficient funds to cover the full costs of:

• decommissioning their existing nuclear power stations; and
• managing any radioactive waste produced by their power stations.

This is known as the Funded Decommissioning Programme (FDP). Operators of new nuclear power stations are required to have an FDP approved by the Secretary of State and in place before construction of a new nuclear power station can begin (Section 45 of the Energy Act 2008).

The Electricity Act 1989 is the principal law regulating transmission licences. As mentioned in 3.2 Obtaining Approvals to Construct and Operate Generation Facilities, Ofgem’s Electricity Licence Application Regulations set out the procedure for applying for a licence and the fee payable.

Unless an exemption applies, companies engaged in the transmission of energy must obtain a licence under the Electricity Act 1989. In the event of offshore transmission, there is a competitive tender process in place of the application procedure.

For a standard licence application, an applicant must complete the form and send the relevant fee to Ofgem. As with all licence applications (including electricity generation licence applications), Ofgem must act in accordance with its duties and objectives under the Electricity Act 1989 as well as with the laws listed in 3.2 Obtaining Approvals to Construct and Operate Generation Facilities.

Once Ofgem has deemed that an application for an electricity transmission licence has been duly made, it has six months within which to process the application.

Standard conditions have been determined under Section 137(1) of the Energy Act 2004.

In general terms, the licence ensures the provision of an efficient, co-ordinated and economical system and the facilitation of competition in supply and generation by including:

• price controls that ensure a network company does not abuse its monopoly position;
• restrictions on asset disposal; and
• measures to ensure it can finance its functions.

The licence is a public document and is available on Ofgem’s electronic public register.

The Electricity Transmission Standard Licence Conditions (as updated in October 2024) are divided into the following sections:

• A – Interpretation, Application and Payments;
• B – General;
• C – Not Used;
• D – Transmission Owner Standard Conditions; and
• E – Offshore Transmission Owner Standard Conditions.

Sections A and B apply to all licences but the conditions in Sections D and E are “switched on” depending on whether the licensee is a TO or Offshore Transmission Owner (OFTO).

Electricity transmission is a highly regulated activity, given the need to secure safe and efficient networks and to regulate the charging for a monopoly activity.

From 1 October 2024, an electricity transmission licence has 19 general Section B conditions in operation, relating to:

• the preparation and publication of regulatory accounts;
• maintaining operational control over relevant assets;
• furnishing information to GEMA as may reasonably be required;
• prohibition of cross-subsidies;
• restriction on certain activities and financial ring-fencing;
• ensuring the availability of resources;
• procuring an undertaking from the ultimate controller of the licensee;
• restriction on indebtedness;
• maintaining an Investor Grade Issuer Credit Rating at all times;
• complying with the provisions of the Fuel Security Code in respect of transmission in England and Wales and complying with the directions of the Secretary of State under Section 34 and/or 35 of the Energy Act 2004 in respect of transmission in Scotland;
• having a System Operator–Transmission Owner Code (STC) in force;
• complying with the Regulatory Instructions and Guidance (RIGs) published by GEMA;
• developing and maintaining an Electricity Network Innovation Strategy;
• complying with any Section E (OFTO of last resort) direction given by GEMA;
• doing all such things to give effect to all modifications made by the Secretary of State to the licence, the CUSC or the STC;
• notifying GEMA of any changes or circumstances that may affect the licensee’s eligibility for certification;
• having two non-executive directors who meet the criteria set out in Condition B22 of the licence;
• complying with the provisions of the Data Assurance Guidance; and
• the ability of GEMA to make “housekeeping” modifications to the licence.

Special conditions apply to National Grid Electricity Transmission plc, Scottish Hydro Electric Transmission Plc, and SP Transmission Plc.

SLCs in respect of transmission licences may be “switched on” or “switched off” by Ofgem.

Section 37 of the Electricity Act 1989 requires the consent of the Secretary of State to install an electric line above ground unless the electric line either:

• has a nominal voltage of less than 20 kV and is used for supplying a single customer; or
• is within premises either occupied or controlled by the person responsible for the installation.

In England and Wales, an overhead electric line with a nominal voltage of 132 kV or more is considered an NSIP. As such, a DCO from the Secretary of State will be required unless a specific exemption applies. Certain transmission works by statutory undertakers may be classified as “permitted developments” under the Town and Country Planning (General Permitted Development) Order 1995, meaning that planning permission is not required.

A marine licence may be required for the laying of a cable within UK territorial waters.

If any electric line passes over or under private land, the consent or agreement of the relevant landowner is also required. A wayleave or easement agreement with the landowner or occupier gives the provider rights to install, access, maintain and repair the provider’s equipment on their land.

A wayleave is an annual agreement for which a landowner and/or occupier receive an annual wayleave payment. The wayleave payment is based on the type and number of assets on the land and its land use.

An easement is an agreement that allows the provider permanent rights for the equipment in return for a one-off lump sum payment. It can only be agreed by the landowner (or long-lease holder) and the provider’s rights endure even if the land changes hands. An existing wayleave agreement can be converted to an easement.

There are no general eminent domain rights or similar for electricity transmission facilities. However, in accordance with Schedule 3 to the Electricity Act 1989 compulsory purchase powers can be used by statutory undertakers to acquire land or rights over land for the installation and retention of electric lines. Compulsory purchase is intended as a last resort to secure the assembly of all the land needed for the implementation of projects. Compulsory Purchase Orders should only be made where there is a compelling case in the public interest to do so and will require a public inquiry to be held before any decision is reached if there are any objections from owners, lessees or occupiers of the land.

The transmission system in England, Wales and Scotland as a whole is operated by NESO, which is responsible for ensuring the stable and secure operation of the national electricity transmission system.

There are four companies that own the onshore transmission system in the UK:

• National Grid Electricity Transmission plc;
• Scottish Power Transmission plc;
• Scottish Hydro Electric Transmission plc; and
• Northern Ireland Electricity Networks Ltd.

Ofgem is responsible for governing transmission licences. In turn, and as noted in 1.5 Central Planning Authorities, Ofgem is governed by GEMA. GEMA’s powers are provided for under the Gas Act 1986, Electricity Act 1989, Utilities Act 2000, Competition Act 1998, Enterprise Act 2002, and measures set out in other Energy Acts – the latest one entering into force in October 2023.

With regard to transmission charging arrangements, Transmission Network Use of System (TNUoS) charges are levied on generators and suppliers for transmitting electricity across Great Britain’s electricity grid network. TNUoS tariffs are calculated, set and billed by NESO, who recover revenue from generators and suppliers and pay it to the GB TOs.

TNUoS represents a proportion of overall transmission costs, with the remainder being met directly by consumers. As of January 2025, TNUoS charges expected to be levied on generators in 2025/2026 were forecast to be circa GBP1.13 billion and TNUoS charges on consumers were estimated to be circa GBP3.96 billion.

Recently, stakeholders have raised some concerns around TNUoS charges, including their cost-reflectivity, unpredictability and absolute values. On 1 October 2021, Ofgem issued a call for evidence in respect of TNUoS charges. On 25 February 2022, Ofgem confirmed that it will be asking the National Grid ESO (now NESO) to launch and lead task forces under the Charging Futures arrangements. In order to ensure that charges remain cost-reflective, the task forces will:

• consider the root causes of unpredictability in TNUoS charges and how they might be addressed; and
• examine the input data into the current model used to calculate the locational element of TNUoS.

The task force was set up in May 2022 and most recently met in May 2024. Further, Ofgem will itself be undertaking a significant programme of work looking at the longer-term purpose and structure of transmission charges. Specifically, it will consider the trade-offs between market signals, network planning and network charging signals necessary to foster a flexible, net zero energy system.

In September 2024, Ofgem issued an open letter to stakeholders raising concerns about the projected charge increases and their impact on investment decisions and consumer costs. Ofgem proposed a temporary cap and floor on TNUoS charges to mitigate these risks and strongly encouraged NESO to raise a code modification proposal to amend the charging methodology at the CUSC panel in October 2024.

The obligation to pay TNUoS charges and the methodology for their calculation is set out in the CUSC. The charges may be positive or negative, depending on location, and their recovery is split between electricity suppliers and generators. Charges to generators are based on their transmission entry capacity (TEC). Charges to electricity suppliers and large industrial customers are based on their electricity demand at peak times. TNUoS tariffs are calculated using a Transport and Tariff model – also known as the Direct Current Load Flow Investment Cost Related Pricing (DCLF ICRP) model – and are published annually by January 31st and take effect from April 1st each year. The TNUoS methodology is published in Section 14 of the CUSC.

The Electricity Standard Licence Conditions confirm that preferential or discriminatory behaviour as between any persons is prohibited (see Conditions D5 and E19).

DNOs are required to have a distribution licence under the Electricity Act 1989. Ofgem is responsible for issuing such licences, which are granted under Section 6(1)(c) of the Electricity Act 1989.

The holder of a distribution licence may not hold an electricity generation licence or a supply licence.

Electricity distribution is a highly regulated activity. The procedure for applying for a licence and the fee payable are set out in Ofgem’s Electricity Licence Application Regulations (see 3.2 Obtaining Approvals to Construct and Operate Generation Facilities).

Once Ofgem has deemed that an application for an electricity distribution licence has been duly made, it has six months to process the application.

The SLCs of an Electricity Distribution, which were consolidated in October 2021 and which remain applicable (with updates, including in October 2024), are split into 12 chapters:

• Chapter 1 – Interpretation and Application;
• Chapter 2 – Standard Conditions 4–7: General Obligations and Arrangements;
• Chapter 3 – Standard Conditions 8–11: Public Service Requirements;
• Chapter 4 – Standard Conditions 12–17: Arrangements for the Provision of Services;
• Chapter 5 – Standard Conditions 20–23: Industry Codes and Agreements;
• Chapter 6 – Standard Conditions 24–28: Integrity and Development of the Network;
• Chapter 7 – Standard Conditions 29–31: Financial and Ring-Fencing Arrangements;
• Chapter 8 – Standard Conditions 32–33: Application and Interpretation of Section B;
• Chapter 9 – Standard Conditions 34–39: Requirements within the Distribution Services Area;
• Chapter 10 – Standard Conditions 40–41: Credit Rating and Restriction of Indebtedness;
• Chapter 11 – Standard Conditions 42–43: Independence of the Distribution Business; and
• Chapter 12 – Standard Conditions 44–49: Provision of Regulatory Information.

The licence can relate to any area or only to a specified area. In practice, most distribution licences will cover the whole of Great Britain and – in some cases – will cover offshore distribution. The licence is a public document and is available on Ofgem’s electronic public register.

There are no general eminent domain rights or similar for electricity distribution facilities.

As DNOs own and operate the local distribution systems within their allocated areas, they have a monopoly and – in the absence of any price controls – each DNO could seek to maximise its profits by increasing its prices or reducing the availability of its service. DNOs are, therefore, regulated by Ofgem to ensure that they do not abuse their monopoly status.

The principal law governing the provision of electric distribution service and the regulation of distribution charges and terms of service is the Electricity Act 1989. Standard conditions for generation, supply and distribution licences were determined under Section 33(1) of the Utilities Act 2000.

Distribution Use of System (DUoS) charges are paid to DNOs to cover the cost of building and maintaining a local distribution network. The charges are mostly collected from suppliers under the Distribution Connection and Use of System Agreement (DCUSA) (and are recharged by those suppliers). However, they are also paid directly by any generator who is a party to the DCUSA. The methodology used to derive DUoS charges is set out in Schedules 16, 17 and 18 of the DCUSA.

Regulation of DNOs is achieved through price controls, which limit how much DNOs can charge the supply companies. The current price control regime for electricity distribution (referred to as RIIO-ED2) came into force on 1 April 2023 and will apply for a five-year period until 31 March 2028. For further details, please refer to 2.1 The Wholesale Electricity Market.