The United Kingdom has one of the most mature and dynamic electricity and gas markets. The country was a pioneer in the drive towards liberalisation, starting with the Energy Act 1983 that facilitated private competition within the generation and supply markets. The liberalisation was later bolstered by an ambitious privatisation programme in the late 1980s and 1990s, which led to the creation of wholesale markets where generators could sell electricity in real time. At present, the market is fully liberalised and privatised.

The United Kingdom has since pushed an energy agenda focused on decarbonisation, demonstrated by the country’s national 2020 renewable energy targets, which exceed those required under the European Renewable Energy Directive. This has resulted in strong growth for renewable generation over the past decade with subsidies providing attractive returns and investment opportunities. In the wake of the 2008 financial crisis, government policy has given increased attention to lowering the cost to consumers. In addition, concerns about the intermittent nature of renewable generators and their growing share of the generation profile of the United Kingdom have shifted policy focus towards ensuring security of supply. The result has been a reconfiguration of subsidy support mechanisms, with the twin aims of lowering the cost of new technologies, and incentivising the construction of baseload generation. This regulatory shift, together with the protracted uncertainty resulting from Brexit, has led to a slowdown in growth for new renewable projects and a converse increase in activity in the secondary market for operational renewable assets. However, there is sustained optimism in the energy sector, particularly in relation to emerging technologies such as battery storage (especially when such storage is co-located with existing renewable projects), carbon capture and storage, electric vehicles, smart metering/‘internet of things’ (IoT), and the opening up of transmission (onshore and offshore) projects to private investors.


iThe regulators

Gas and Electricity Markets Authority

The Gas and Electricity Markets Authority (GEMA) is the regulator of the gas and electricity markets in Great Britain.2 GEMA consists of a panel of individuals appointed by the Secretary of State for a specified term of not less than five years, but it is independent of government and has no stakeholder participation. GEMA’s duties are set out in the Gas Act 1986 (as amended) (the Gas Act), the Electricity Act 1989 (as amended) (the Electricity Act), and the Utilities Act 2000 (as amended) (the Utilities Act), and it has powers in relation to granting and administering electricity and gas licences, as well as concurrent authority with the Competition and Markets Authority (CMA) on the application and enforcement of certain competition rules. GEMA operates through its office, the Office of Gas and Electricity Markets (Ofgem), to which it delegates the day-to-day administration of its functions. Ofgem is therefore more commonly referred to as the regulator in common parlance.

GEMA’s objectives are enshrined in the relevant sections of the Gas Act and the Electricity Act. While these are varied and at times inconsistent, GEMA’s principal objective is to protect the interests of existing and future consumers in relation to electricity and gas and, wherever appropriate, to achieve this by promoting effective competition. An increasingly important feature in the regulated markets (particularly price-controlled networks and, more recently, supply markets) is GEMA’s duty to have regard to the need to secure that licence holders are able to finance their activities, which are the subject of obligations imposed under the Electricity Act (and, in practice, this is interpreted widely to cover the majority of GEMA’s functions). Although impractical to list here, the Electricity Act and the Gas Act contain additional matters to which GEMA must have regard when exercising its functions, for example, the need to ensure that all reasonable demands for electricity are met (i.e., ensure security of supply), the interests of consumers in the reduction of emissions of targeted greenhouse gases, the need to contribute to the achievement of sustainable development, etc.

On a day-to-day basis, Ofgem exercises GEMA’s powers to grant and modify licence conditions, monitor the activities of gas and electricity companies, and, where necessary, take enforcement action to ensure these companies comply with their statutory and licence obligations; however, Ofgem must follow its own guidelines and policies when taking such enforcement action, meaning its discretion is limited. As such, Ofgem’s enforcement guidelines provide that it will have regard to the principles of transparency, accountability, proportionality, consistency and will target regulatory activity only at cases in which action is needed, and to other principles that it considers represent best regulatory practice. Ofgem also exercises GEMA’s power to impose financial penalties on licence holders for breaches of such obligations, and there is the ability to benefit from discounts where there is an early settlement of the breach.

The regulatory framework is responsive to changes in the market through Ofgem’s ability to modify licence conditions. Appeals in respect of such modifications can be made to the CMA.

GEMA also has the power to modify the various industry codes that contain the detailed operational and technical rules governing the industry. This power is conferred by the relevant licence condition under which a network operator (e.g., National Grid Electricity System Operator Limited (NGESO) or National Grid Gas plc (NGG)) is required to ‘own’ the code in question, and currently is not subject to any specific statutory constraints. Lastly, the Secretary of State has powers under the Electricity Act and the Gas Act to make secondary legislation to respond to more structural changes in the market.

Northern Ireland Authority for Utility Regulation

The Northern Ireland Authority for Utility Regulation, an independent non-ministerial government department, regulates the electricity, gas, water and sewerage industries in Northern Ireland. Its duties are to protect the short- and long-term interests of electricity, gas, water and sewerage consumers with regard to price and quality of service; promote a robust and efficient water and sewerage industry; deliver, where appropriate, high-quality services; promote competition, again where appropriate, in the generation, transmission and supply of electricity; and to promote the development and maintenance of an economic and coordinated natural gas industry.


The CMA is the United Kingdom’s (i.e., Great Britain and Northern Ireland’s) lead competition and consumer body established under the Enterprise and Regulatory Reform Act 2013 (ERRA). GEMA, as the energy regulator, has concurrent powers with the CMA with regard to the energy sector. ERRA requires sectorial regulators, including GEMA, to consider applying competition law before using their sector-specific powers. The provisions of the Competition Act 1998 and the Enterprise Act 2002 (the Enterprise Act) as amended by ERRA dealing with anticompetitive practices play a particularly important role and are jointly applied and enforced by GEMA and the CMA.

To improve the effectiveness of these concurrent powers, the CMA is required under ERRA to publish an annual report, in consultation with the sector regulators, on how the cooperation under the joint competition powers has worked.

Under the Enterprise Act, the CMA may investigate the functioning of competition within a market in the United Kingdom as a whole (as opposed to targeting specific actions of companies) and open an investigation where it has reasonable grounds for suspecting that any feature, or combination of features, of this market restricts or distorts competition in the supply or acquisition of any goods or services. In the case of the gas and electricity sectors, Ofgem may refer any of those markets to the CMA for a market-wide investigation or the CMA may direct Ofgem to transfer the case to it. The CMA conducted an extensive energy market investigation and on 24 June 2016 published its final findings and remedies.3 Although it found the wholesale electricity market was generally ‘working well’, it identified two aspects of the regulatory regime that adversely affected competition, namely: the absence of locational charging for transmission losses; and the mechanism for allocation of Contracts for Difference. Following the final CMA decision and issuing by the CMA of the Energy Market Investigation (Electricity Transmission Losses) Order 2016, NGESO raised a code modification to the Balancing and Settlement Code that sought to allocate transmission losses on a geographical basis.

The CMA also has powers to hear appeals in relation to price controls set by Ofgem for network companies (price controls are explained further below in Section III). Two such appeals were brought in 2015 by British Gas Trading Limited (BGT), and Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc (together ‘NPg’) in respect of the RIIO-ED1 price controls set by Ofgem. The result was the dismissal of two out of the three grounds of appeal for NPg and four out of five grounds of appeal for BGT.

Health and Safety Executive (HSE)

The HSE is the national independent regulator with regard to health and safety in Great Britain, which was established under the Health and Safety at Work Act 1974. It is responsible for the regulation and enforcement of workplace health and safety in Great Britain and for producing guidance and carrying out research in relation to occupational risks.

In Northern Ireland the role is performed by the Health and Safety Executive for Northern Ireland.

Office for Nuclear Regulation (ONR)

The ONR was established as a statutory public corporation on 1 April 2014 under the Energy Act 2013. It is responsible for the regulation of nuclear safety and security, including through granting nuclear site licences, across the United Kingdom. The ONR is also responsible for regulating the transport of nuclear materials and ensuring that safeguarding obligations for the UK are complied with. The ONR reports to the Department for Work and Pensions, although it also works closely with the Department for Business, Energy and Industrial Strategy (BEIS).

Environment Agency

Responsibilities in relation to environmental regulation in Great Britain have largely been devolved to governments in England, Wales and Scotland. For example, in England, the Environment Agency is a non-departmental public body sponsored by the Department for Environment, Food and Rural Affairs. It is responsible for protecting and improving the environment and promoting sustainable development in England.

In Wales, since April 2013, environmental and other natural resources-related matters have been the responsibility of Natural Resources Wales. With regard to electricity, the role of the environmental agencies is limited to pollution-related matters, and therefore mainly relate to conventional and nuclear generation, although additional environmental matters also arise in relation to consenting. In addition, the Environment Agency in England is also responsible for limiting and preparing for the impacts of climate change.

In Northern Ireland, the Northern Ireland Environment Agency is the body responsible for the protection conservation and promotion of the national environment.

The Department for Business, Energy and Industrial Strategy and the Department for the Economy

While not regulators, the Department for Business, Energy and Industrial Strategy (BEIS) (for Great Britain) and the Department for the Economy (DFE) (for Northern Ireland) are government departments responsible for setting the policies affecting the UK electricity and gas markets. The Secretary of State for BEIS is responsible for making decisions, setting policy and implementing legislation affecting the energy sector and is accountable on matters including security of supply and sustainability in Great Britain’s energy sector. There are some regulatory powers that are reserved to the Secretary of State directly. For example, the Secretary of State is authorised to make orders under the Electricity Act granting exemptions from the requirement to hold a licence, where certain criteria are met.4 Further, BEIS is responsible for formulating UK energy policy, which is implemented through legislation.

The corresponding government ministry in Northern Ireland is the DFE, which assumed most of the roles and responsibilities of the former Department of Enterprise, Trade and Investment.

iiRegulated activities

The regulatory framework in Great Britain operates through a system of legislation, licences and industry codes with an independent regulator responsible for the regulation of the sector and for enforcing any breaches of the rules. In the case of both electricity and gas, there is a prohibition on (and an associated offence for) carrying out the licensable activity without a licence (unless an exemption applies).5

Licences are granted by Ofgem to the entity carrying out the particular activity. In line with European Third Energy Package (IME3) unbundling and certification rules, a licensee may not hold a transmission, distribution or interconnection licence if it already holds a generation or supply licence.

The regulatory regime for gas has recently undergone reform through the development of the European Union-wide Network Codes. Regulation (EC) No. 715/2009 provided for the establishment of Network Codes to help facilitate cross-border network access and market integration. Changes to the electricity sector are also under way pursuant to Regulation (EC) No. 714/2009 regarding harmonising the technical, operational and market rules governing the electricity grids; however, the European Commission has proposed in its latest fourth ‘winter package’ to recast this Regulation. Under this latter EU legislation, the European Commission, ACER, ENTSO have developed European Union-wide codes and guidelines for matters such as system operation (adopted), balancing activities (adopted), demand connection (adopted), grid connection for generators (adopted), capacity allocation and congestion management (adopted), and forward capacity allocation (adopted), among others.6


Unless an exemption applies, a licence is required for the following specified activities under the Electricity Act:

  1. generation;
  2. participation in transmission (defined to cover both the operation and ownership activities);
  3. distribution;
  4. supply; and
  5. participation in the operation of an electricity interconnector.

From September 2012, providing smart metering services also requires a licence. The position regarding electricity storage is currently in development, and Ofgem is working with industry stakeholders to develop a regulatory definition for this technology (see more in Section VI).7


As with electricity, the Gas Act makes it an offence for an entity without a licence to carry out any gas transportation, interconnection, gas shipping, supply or smart metering (unless an exemption applies). For example, a licence to transport provides the right to convey gas through pipeline systems, while an interconnector licence gives the licensee the right to participate in the operation of a gas interconnector. The activity of gas shipping consists of buying gas from producers or importers and arranging for its transport (with gas transporters) via a pipeline system to a gas supply point, to then sell it on to gas suppliers.

Gas storage is subject to regulation but is not separately licensed.

A licence on its own does not give an entity the right to carry out other activities such as develop a project. Separate rights need to be secured in relation to land rights, planning requirements, decommissioning, etc., and the licensee would need to comply with other relevant legislation. In practice, this means obtaining authorisations from other regulatory bodies noted above (e.g., the HSE).

iiiOwnership and market access restrictions

There are no energy-specific restrictions on foreign investment or ownership of energy companies or assets in the United Kingdom. However, an additional certification process requires Ofgem to assess, in consultation with the European Commission and the Secretary of State for BEIS, whether foreign ownership or control (meaning a licensee or a person who controls that licensee from a country that is not an EEA state) of transmission and interconnection infrastructure poses a security of supply risk in the United Kingdom or any other EEA state. In the event of a no-deal Brexit (or following the end of any transition period as provided for under the draft withdrawal agreement), the additional Ofgem certification requirements for transmission and interconnectors will apply to persons who are not from the United Kingdom.

In addition, the Secretary of State for BEIS has powers to take action in respect of transactions (including within the energy sector) on specific public interest grounds and where the relevant EU merger control thresholds have not been triggered.

In a similar vein, the unexpected decision to delay sign-off on final approvals for Hinkley Point C announced by the Conservative government in 2016 demonstrates that the executive branch has indirect levers for ensuring control over ownership of national critical infrastructure. In this instance, the government pointed to concerns over spiralling costs and security of supply to delay the signing of the final contracts, particularly the Contract for Difference awarded to Hinkley Point C securing the price of its output at £92.50/MWh (double the wholesale price at the time). In the event, the government approved the project; however, it proposed new legal safeguards mainly through a mechanism that will allow it to prevent any transfer of ownership in UK critical infrastructure without its consent or knowledge, including that of EDF in Hinkley Point C (in this case through its holding of a ‘golden share’).

ivTransfers of control and assignments

There are no specific restrictions on control in a licence but assignments require prior written consent of the licensing entity. This is likely to require the incoming party to satisfy the Secretary of State that it is able to meet the licence obligations, and follows a similar vetting process as that for a new applicant. In practice, transfers are usually effected by transfer of the company that holds the relevant licences. The transmission, distribution and interconnection licences include obligations to ring-fence the regulated asset, which provides an additional level of control to Ofgem.

IIITransmission/Transportation and Distribution Services

iVertical integration and unbundling


The Great British electricity transmission market was privatised in the early 1990s and has been fully unbundled, thus serving as a model for many other markets and jurisdictions (including for the EU’s Third Energy Package unbundling regime). In Great Britain, the legal separation of electricity supply and distribution activities was introduced by the Utilities Act as part of further restructuring of the market. As a result, distribution and supply are treated as separate licensed activities and licences may in principle not be held by the same person.

Under the provisions of the Third Energy Package TSOs must be certified as complying with ownership unbundling. This means that transmission interests (ownership and operation of transmission systems) must be separate from generation, and supply activities. As the UK position did not readily fit within the Third Energy Package model but was considered sufficiently well developed and independent to meet the aims of the Third Energy Package, a derogation applies in relation to vertically integrated UK TSOs pursuant to Article 9(9) (Section 10E (4), Electricity Act 1989). Scottish Hydro Electric Transmission plc (SHETL) and SP Transmission plc (SPTL), the Scottish transmission system owners, were granted certification on grounds of Article 9(9) subject to certain conditions and information-sharing restrictions.


A single regulatory framework applies across Great Britain in respect of the gas sector. Under the Gas Act there is no distinction between gas transmission and distribution activities: both activities are dealt with by the provisions relating to gas transportation.

iiTransmission/transportation and distribution access


Transmission and distribution

In 2005, the British Electricity Trading and Transmission Arrangement (BETTA) introduced a single transmission system for the whole of Great Britain and divided the transmission role between a Great British transmission system operator (TSO), currently NGESO, on the one hand, and the existing transmission system owners on the other. Both activities – transmission system operator and owner – are licensable and the transmission owners are required by law to make their respective transmission systems available to the TSO (i.e., NGESO), which is responsible for the real-time balancing of supply and demand and dispatch of generation.

The Electricity Act imposes a duty on transmission licence holders to develop and maintain an efficient, coordinated and economical system of electricity transmission; and to facilitate competition in the supply and generation of electricity. This primary obligation is supplemented by detailed provisions in the respective transmission licences dealing with issues such as compliance with industry codes, charging methodology, non-discrimination and competition issues (e.g., prohibition on cross-subsidies and separation of businesses).

NGESO, a private limited company within the National Grid Group, is the holder of a transmission licence in its capacity as transmission system operator for the whole of Great Britain; it does not own any transmission infrastructure. National Grid Electricity Transmission plc (NGET), a public limited company that is similarly part of the National Grid group, also holds a transmission licence in its capacity as owner of the transmission network in England and Wales; until 1 April 2019 NGET (in lieu of NGESO) performed the system operator function for the whole of Great Britain; however, from that date NGESO took over the role of system operator (only). NGESO is also the designated system operator for electricity interconnectors, where it performs system operator to system operator functions.

The respective transmission networks in northern Scotland and southern Scotland are owned by Scottish Hydro Electric Transmission plc and Scottish Power Transmission Limited. In Northern Ireland, the TSO is SONI Limited and Northern Ireland Electricity Networks Limited owns the transmission and distribution assets.

There is also a market for offshore transmission owners (OFTO) with increasing private investor participation. Ofgem has granted a number of licences for electricity transmission connections to offshore wind farms following competitive tenders. The regulator is currently running the OFTO Tender Round 6 process in relation to the Beatrice, Hornsea Project One (expected to be the world’s largest offshore wind farm, once complete) and East Anglia ONE offshore wind farms. To date, there are 14 operational OFTOs in place (having a total investment value of around £3.3 billion) for offshore windfarms with a total capacity of more than 5GW. OFTO Tender Round 6 is expected to attract a further £2 billion in relation to the new transmission assets for the three windfarms.

Ofgem is continuing to work with the government on developing competitive tenders for the design, procurement, construction and operation of new, separable, and high-value onshore transmission assets (designated as Competitively Appointed Transmission System Operators or CATOs). The first tender was projected to run in the early part of 2019; however, Brexit has delayed the development of the legislative framework (as a result of limited parliamentary time) and there is no clear indication as to when this may be completed. However, Ofgem has been considering whether the current legislative framework allows for the development of alternative models for the competitive delivery of new, separable, and high-value onshore transmission assets. Consequently, and as part of the necessary transmission reinforcement and connection works that NGET is required to carry out, for example, in respect of the Hinkley Point C nuclear project, Ofgem has consulted on two potential models to enable competition: (1) a ‘competition proxy’ model where Ofgem would set the transmission owner’s (TO) allowed revenue for a project in line with the outcome it considers would have resulted from an efficient competition for construction, financing and operation of the project, and (2) a special purpose vehicle model where the incumbent TO would run a competition for the construction, financing and operation of the project through a project-specific company. To date, Ofgem has confirmed its preference to use the competition proxy model for the development of the Orkney and Shetland transmission link projects.

Each of the activities of transmission and distribution is to a large extent regulated though a series of industry codes. NGESO has the licence obligation to maintain and administer various industry codes dealing with the operation and use of the transmission system, including the Connection and Use of System Code (CUSC), the Grid Code and, in conjunction with ELEXON, the Balancing and Settlement Code (BSC).

The CUSC sets out the main rights and obligations in relation to the connection to, and use of, the national electricity transmission system, along with additional provisions on some ancillary and balancing services. The Grid Code sets out the detailed rules and requirements for matters such as connection conditions, dispatch, scheduling, operational liaison and safety coordination, and all material technical aspects relating to connections to, and the operation and use of, the transmission system. The governance of balancing and settlement arrangements is set out in the BSC, to which all generation and supply licensees must be party.


Pursuant to its licence, NGESO must not discriminate between any persons or class or classes of person in the provision of use of the system or in the carrying out of works for the purpose of connection to the transmission system.

Distribution network operators

The electricity distribution system in Great Britain is organised along geographic lines with various regional monopolies. England and Wales are divided up between 12 distribution network operators (DNOs), while there are only two DNOs in Scotland and one DNO in Northern Ireland. As at April 2019, the monopoly distribution networks in Great Britain are operated by the following six companies: Electricity North West Limited, Northern Powergrid, SSE, SP Energy Networks, UK Power Networks, and Western Power Distribution. Ofgem also grants licences to Independent Distribution Network Operators (IDNOs), which are not geographically restricted. IDNOs compete with the monopoly DNOs by providing distribution services to large industrial and commercial customers such as the provision of connections and the design, construction and operation of small to medium-sized private distribution networks. The introduction of IDNOs and their ability to operate anywhere in Great Britain was intended to facilitate and bolster competition in the distribution sector, which has been (and to a large extent continues to be) dominated by the incumbent monopoly DNOs (which now, in law but not in practice, are no longer monopolies).

The DNO in Northern Ireland is Northern Ireland Electricity. Each DNO holds an electricity distribution licence and owns and operates the local electricity distribution system.

Pursuant to the Electricity Act, DNOs must develop and maintain an efficient, coordinated and economical system of electricity distribution and facilitate competition in the supply and generation of electricity. As with transmission, the electricity distribution licence conditions subject the DNOs to obligations such as non-discrimination in the provision of use of system and connection to system; safety and security; prohibition on cross-subsidies; business separation; and use of system and connection to system charges.

Similar to the obligations of NGESO under its transmission licence for its role as transmission system operator, under the terms of their distribution licence conditions, DNOs are each required to maintain and comply with the Distribution Code dealing with technical aspects relating to connections to and the operation and use of the licensee’s distribution system. In addition, one of the objectives of the licences and the codes is to facilitate competition in the generation and supply of electricity.


Under the Electricity Act, DNOs have an obligation to make a connection between their distribution system and any premises when requested to do so by the owner of the premises or an authorised electricity supplier. Pursuant to the licences, DNOs must not discriminate between any persons or class or classes of persons in the carrying out of works for the purpose of connection to the licensee’s distribution system. In addition, DNOs must not discriminate in the provision of use of the system, and must on application made by any person offer to enter into an agreement for use of the distribution system.



The Great British gas transmission network, the National Transmission System (NTS) – a high-pressure pipeline system that transports gas from entry terminals to various gas distribution networks (GDNs) and large industrial customers – is owned and operated by NGG. However, in May 2005, the Uniform Network Code (UNC) enabled companies other than NGG to own gas networks.

The UNC, which is maintained by the Joint Office of Gas Transporters, is the contractual framework that forms the basis of arrangements between the owners and operators of the gas transportation systems in GB and the users of those systems. Similar to the CUSC, the UNC is given effect by a shipper framework agreement, in the form of a contract between a gas transporter and an individual shipper user, by virtue of which they agree to be bound by the provisions of the UNC. In addition to entering into a shipper framework agreement, to become a shipper user under the UNC an applicant must satisfy certain admission requirements including the need to hold a gas shipper licence under the Gas Act.

Within their authorised area, gas transporters must develop and maintain an efficient and economical pipeline system for the conveyance of gas and, in so far as it is economical to do so, are under a duty to provide connection to that system and to convey gas. Additionally, the Gas Act imposes a general duty to facilitate competition in the supply of gas, and to avoid any undue preference or undue discrimination when connecting premises, or a pipeline system operated by an authorised transporter, to any pipeline system operated by the transporter, or in the terms on which the transporter undertakes the conveyance of gas by means of such a system.

The Gas Act is supplemented by detailed provisions on charging for connection and transportation services, standards of performance and system development obligations in the individual licences held by gas transporters.


Similarly to the electricity distribution system, gas distribution in Great Britain is organised along geographic lines. There are eight GDNs in Great Britain covering different geographic regions, which are medium- and low-pressure pipeline systems. Four of the GDNs (east Midlands, west Midlands, north-west England and the east of England (including north London)) are owned by Cadent (formerly part of NGG), while the remaining four GDNs are owned and operated by Northern Gas Networks Limited (north-east England (including Yorkshire and Northern Cumbria)), Wales and West Utilities Limited (Wales and south-west England) and SGN (Scotland and southern England (including south London)). On 8 December 2016, NGG announced it had agreed to sell a 61 per cent equity interest in its gas distribution business to a consortium made up of Macquarie Infrastructure and Real Assets, Allianz Capital Partners, Hermes Investment Management, CIC Capital Corporation, Qatar Investment Authority, Dalmore Capital and Amber Infrastructure Limited/International Public Partnerships. Similarly, on 17 October 2016, SSE announced it agreed to sell a 16.7 per cent equity stake in Scotia Gas Networks Limited (SGN) to wholly owned subsidiaries of the Abu Dhabi Investment Authority (ADIA), for a headline consideration of £621 million.

There are also a number of smaller gas transportation networks connected to the GDNs and owned and operated by six independent gas transporters (IGTs). The IGTs compete with each other and the GDN owners to provide gas transportation services. Unless an exemption applies, each IGT and GDN owner is required to hold a gas transporter licence.


Under the Gas Act, gas transporters must, following any reasonable requests for connection, grant access to their pipeline system, in so far as it is economical to do so, convey gas by means of that system to any premises and comply with any reasonable request to connect to a pipeline system operated by another authorised transporter.

Access to the gas network is provided on an entry-exit basis instead of on a point-to-point basis. As access rights comprise entry and exit capacity at entry and exit points, shippers are required to book entry capacity and exit capacity to flow and take gas (there are relatively few entry points – principally gas terminals at which gas is landed from offshore fields).

iiiCharges and tariffs

For electricity, the rates payable for connection to and use of the transmission system are set out in NGESO’s charging statements. The charges are broadly made up of the following:

  1. transmission network use of system charges: to recover the revenue for the transmission system owners, that is NGET, the Scottish transmission owners, OFTOs, and in future CATOs;
  2. balancing services use of system charges: to recover the cost of balancing the transmission system, and which depend on the amount of balancing required; and
  3. connection charges: to recover the cost of installing and maintaining connection assets used by the party connecting to the transmission system. It takes into account the asset value, asset age and maintenance costs.

These are calculated in accordance with the relevant rules set out in the CUSC.

Ofgem is currently consulting on significant changes regarding the residual element of use of system charges both at transmission (TNUoS charges) and distribution (DUoS charges) level, as well as reform of embedded benefits for distribution-level generation (for more information see Section VI). Residual charges are intended to top up and make up for any deficit in the revenues allowed to be recovered by network companies after forward-looking charges have been levied. In contrast, forward-looking network charges are intended to send signals to market for matters such as where to place generation, fuse size, etc., and these are also being reviewed by Ofgem at the moment.

Price control

Ofgem regulates the prices for regulated assets (e.g., transmission and distribution networks) pursuant to the licence terms of the given gas or electricity licensee. The current price control model is known as ‘revenue = incentives + innovation + outputs’ (RIIO). These RIIO price controls set out the revenue that the network companies are allowed to recover and what they are expected to deliver, as well as specifying details of the regulatory framework over the eight years from 2013 to 2021 for transmission and gas distribution, and from 2015 to 2023 for electricity distribution.

The RIIO price controls are established against framework objectives set by Ofgem, against which the network companies present a business plan detailing how they intend to meet the objectives. The business plans are evaluated and approved by Ofgem. The process is significant in terms of its scope and the time and effort it requires on the part of many stakeholders. Consequently, it places major value on stakeholder engagement in decision-making, efficient investment in services, innovation in networks and reduction of carbon outputs.

Additionally, in its final report on the energy market investigation the CMA proposed a transitional price cap for customers on prepayment meters from 2017–2020 and this has been implemented by Ofgem. In addition, since February 2018, Ofgem extended this price cap to vulnerable customers who receive the Warm Home Discount (WHD). However, on 1 January 2019 the Domestic Gas and Electricity (Tariff Cap) Act 2018 came into force, which aims to protect all domestic customers on default tariffs (known as standard variable tariffs or SVTs), including those on the WHD. However, even this primary legislation is intended to be a temporary measure until 2023, by which point Ofgem intends to have reformed the supply market so that it is more competitive.

ivSecurity and technology restrictions

While there are no specific security and technology restrictions in Great Britain, concerns around national security, cybersecurity and data processing have become increasingly common in the context of electricity and gas markets. These are typically dealt with through bilateral contracts and protocols.


iDevelopment of energy markets


Great Britain was among the pioneers of electricity-sector liberalisation from the mid-1980s, when the Energy Act 1983 created the requirement for the state-owned area boards to offer private generators access to their networks and to purchase the power they generated. Since 1991, the electricity market was privatised and the parties are now free to trade on the basis of bilateral contracts (generally known as Power Purchase Agreements or PPAs).

Until 1 October 2018, Northern Ireland operated a separate wholesale electricity market with a pool system, the single electricity market (known as the SEM), which is integrated with the wholesale electricity market in the Republic of Ireland. However, on 1 October 2018 the SEM was reformed (through a project known as I-SEM) and transitioned to a bilateral contract market approach in order to comply with the IME3 EU Target Model and therefore facilitate market coupling.

At the time of writing, the UK as a whole has taken significant steps to implement the market coupling measures provided for in EU legislation, particularly those set out in Regulation 714/2009 and the network codes flowing out of that. By way of example, the UK has achieved the price coupling of its market within the EU-wide single day-ahead coupling project and continues to take steps in relation to the single intraday coupling project (known as XBID). However, without special arrangements being agreed between the UK and the EU, post-Brexit it is expected that the UK will have to revert to explicit auctions for selling cross-border capacity in the day-ahead time frame and will cease efforts to achieve price coupling for the intraday time frame.


Gas trades, subject to licensing requirements, can be traded by gas shippers within the NTS and at exit points on the gas system. This is usually done on the basis of standard-term contracts and in line with the requirements of the UNC.

The regulatory regime for gas has recently undergone reform through the development of the European Union-wide Network Codes. Regulation (EC) No. 715/2009 provided for the establishment of Network Codes to help facilitate cross-border network access and market integration. These Network Codes were thought necessary because of the increased interconnection and trade between EU countries and the need to manage gas flows. These Codes further inform the trading of gas.

iiEnergy market rules and regulation

Energy market rules are largely set out in industry codes such as the Grid Code, the CUSC and the BSC. Compliance with these is governed through licence conditions, which require the relevant licensees to accede to and comply with those industry codes.

The BSC is particularly relevant for market trading. It seeks to ensure that total electricity generation and demand are balanced in real time, through a balancing mechanism operated by National Grid. It also quantifies imbalances between the amounts of electricity traded and the actual electricity generated or consumed, and regulates how these are paid for through a post-event imbalance settlement process operated by ELEXON. The BSC contains the rules and governance arrangements for the balancing mechanism and imbalance settlement processes. These arrangements, and the scope of the BSC, were subsequently extended to Scotland in April 2005 under the BETTA. Most electricity trading is done on the basis of industry standard contracts (grid trade master agreements (GTMAs) or an international swaps and derivatives association master agreement with a GTMA index) or by way of bespoke power purchase agreements between generators and suppliers.

Electricity trading is also subject to market transparency regulation and requires disclosure of price-sensitive information to the market. The Regulation on Wholesale Energy Market Integrity and Transparency (Regulation (EU) No. 1227/2011), initially adopted in December 2011, extends the concept of the Market Abuse Directive to physical gas and electricity, and requires market participants to disclose physical inside information, and to avoid attempted and actual market manipulation and abuse. More recently, the Markets in Financial Instruments Directive II has significantly narrowed the exemptions currently available to commodity derivatives trading firms to ensure that ‘participants on commodity derivatives markets [are] subject to appropriate regulation and supervision’. It is worth noting that although the UK voted to leave the EU, the government has given assurances that it will continue to apply similar transparency rules at national level.

iiiContracts for sale of energy

Generators, electricity suppliers, electricity traders and large customers can enter into commercially negotiated contracts to buy and sell electricity. The volumes (not commercial details) of the resulting trades are notified to the system and market operators, and any failure to achieve these notifications (called imbalances) are priced and settled. Trading takes place on a half-hourly basis with gate closure – set one hour ahead of real time – and participants notifying the system operator of their intended final physical position. After this point, no further contract notification can be made and settlement is based on positions at gate closure.

ivMarket developments

There are a number of changes affecting the UK energy and gas markets. For example, in electricity transmission in Great Britain, there are plans to introduce competitive auctions or models to build new onshore transmission lines. Ofgem is also continuing to run auctions for competition in offshore transmission.

There has also been a rise in the number of new entrants to the electricity supply markets. This is in line with government aims to decrease the dominance of the ‘big six’ vertically integrated utilities in the domestic supply market. However, this increase has been followed by an increasing number of resounding failures among smaller independent suppliers, whose business models proved too optimistic particularly in light of their failure to hedge against commodity price fluctuations.

The introduction of Great Britain’s capacity market in 2013 has also given rise to more attention being paid to demand-side response and how it is able to provide security of supply during times of system stress. In this respect, National Grid has launched a new demand-side response product, namely the ‘demand turn up’ ancillary service. However, this was discontinued in 2019 owing to feedback that the offline dispatch process, long notice period for delivery and small volume procured are significant barriers to increased utilisation of the service in its current form (therefore leading to ‘disappointing’ revenues for service providers). NGESO is currently reviewing alternative services for DSR.


iDevelopment of renewable energy

The United Kingdom has a long-established renewable energy policy. At the national level, the United Kingdom, via the Climate Change Act 2008, has committed to a reduction of greenhouse gas emissions by 34 per cent by 2020 and 80 per cent by 2050 in comparison with 1990 levels.

The current main driver for renewable energy policy in the United Kingdom is the EU Renewable Energy Directive (RED).8 The RED aims to reduce the EU’s dependency on fossil fuels and to foster low-carbon and sustainable energy generation. EU Member States agreed under the RED to jointly achieve a target of 20 per cent of energy consumption from renewable sources by 2020. However, on 24 December 2018, the revised Renewable Energy Directive (Directive (EU) 2018/2001) came into force, which now sets a binding EU-wide target of at least 32 per cent by 2030. After the UK’s exit from the EU is effected, the entirety of EU legislation will be enshrined in national law (which will be known as ‘retained law’) by means of the operation of the European Union (Withdrawal) Act 2018 (subject to certain modifications that will be effected through secondary legislation and licence modifications). The transposition deadline for the revised RED is 30 June 2021 (at which point the RED will be repealed) and, therefore, the adoption of the new measures by the UK will depend on whether it has adopted the necessary laws and regulations to transpose the revised directive. Should that happen, the position on renewable energy consumption targets will remain unaffected regardless of the final Brexit position as the UK’s national renewables and decarbonisation targets exceed those imposed at EU level. However, there is concern that the government’s renewed focus on achieving industrial growth post-Brexit may render decarbonisation targets secondary to ensuring security of supply and low prices for large industrials. Not least, exit from the EU could potentially allow the UK to pursue an even more ambitious energy policy given that EU rules on state aid would cease to apply (however, such a departure from the EU’s state aid rules is unlikely given that the UK will have to observe such rules in order to secure maximum access to EU markets).

Contracts for difference

In Great Britain’s electricity sector, the primary support instrument for renewables is through contracts for difference (CfDs), which were introduced in 2013 by the Energy Act 2013 as part of the United Kingdom’s Electricity Market Reform (EMR) programme. Prior to its introduction, the main support measures available for low-carbon generation were in the form of the renewables obligation (RO), and feed-in tariffs (FiTs) for small-scale projects.

CfDs are 15-year contracts entered into between a government-owned company, the Low Carbon Contracts Company, and the successful low-carbon generators. The CfD mechanism works by setting a fixed price (strike price) thus reducing the generator’s exposure to electricity prices volatility and consequently the cost of debt and equity capital required for the investment. The first allocation round for CfDs took place in October 2014 and contracts were awarded to 27 projects in February 2015.9 The second allocation round for CfDs for the 2021/22 and 2022/23 delivery years took place in April 2017 and 10 projects were successful in obtaining contracts (three of these were subsequently terminated). The government estimated that the capacity delivered under the second allocation round cost up to £528 million per year less than it would have in the absence of competition. The third allocation round is currently planned to be held in May 2019 for less-established technologies (e.g., remote Scottish island wind).10

Renewables obligation

Support for renewable generation via the RO scheme was introduced in England and Wales in 2002 and administered by Ofgem. The RO scheme imposes an obligation on electricity suppliers to source a fraction of their electricity from renewable generation. Compliance with this obligation is shown by obtaining RO certificates issued to generators accredited on the scheme (with the number of certificates issued varying depending on the technology and the value of each certificate being broadly maintained through terms, such as a buyout price, set from time to time by the electricity regulator).

The RO has been closed to all new generation from the end of March 2017, but the process of closure has been implemented gradually through a series of legislative amendments, which imposed a cap on biomass, closed support to solar PV (large-scale in March 2015, and small-scale in March 2016) and closed support for onshore wind in May 2016. Early closures are subject to provisions of specific grace periods.


The FiTs scheme was introduced to promote the deployment and use of small-scale (5MW and below) renewable and low-carbon generation. The FiTs scheme began operation on 1 April 2010 and is administered by Ofgem, which accredits generators, maintains the Central FiT Register of the accredited installations and monitors the reaching of deployment caps as well as compliance with the scheme.

Payments under the scheme are administered and performed by FiT licensees – meaning suppliers that join the FiT scheme either compulsorily (those supplying more than 250,000 domestic users) or voluntarily – which then pass on costs to consumers. A fixed payment is made under the FiT scheme for electricity that is generated on-site, the ‘generation tariff’, and another payment for any unused electricity that the generator exports to the grid, the ‘export tariff’.

Major changes to the FiT scheme were introduced at the end of 2015, including a reduction of tariffs, the introduction of quarterly deployment caps coupled with a default degression mechanism and an overall FiT budget limit.

On 19 July 2018, BEIS announced that the FiT scheme will be closed as of 1 April 2019 (subject to certain grace periods that will allow accreditation following that date).

iiEnergy efficiency and conservation

The CRC Energy Efficiency Scheme was a mandatory carbon emissions reduction scheme that applied to large non-energy-intensive organisations. This was scrapped in March 2016 with effect from the end of the 2018/2019 compliance year.

The climate change levy (CCL) is a tax on energy delivered to non-domestic consumers that aims to incentivise increased energy efficiency. The government has introduced a 100 per cent exemption from CCL for energy used in certain energy-intensive (metallurgical and mineralogical) industrial processes. Further, climate change agreements are voluntary agreements that allow eligible energy-intensive sectors to receive up to 90 per cent reduction in the CCL if they agree to meet certain energy efficiency targets.

Separately, the government has introduced the Renewable Heat Incentive (RHI) scheme aimed at promoting energy efficiency through encouraging renewable heat. The RHI is aimed towards levelling the cost of renewable heat with that of heating from fossil fuels by providing successful participants with periodic payments calculated in terms of £/kWh of eligible renewable heat or biomethane produced. The RHI was first introduced in November 2011 for non-domestic heating and subsequently expanded to include domestic heating support. Non-domestic RHI is governed by the Renewable Heat Incentive Scheme Regulations 2018, which came into force on 22 May 2018 revoking and replacing the Renewable Heat Incentive Scheme Regulations 2011 that previously governed the non-domestic RHI in Great Britain. Domestic RHI is underpinned by the Domestic Renewable Heat Incentive Scheme Regulations 2014 (as amended). Duration of support is 20 years for non-domestic and seven years for the domestic category.

iiiTechnological developments

The electricity and gas sectors continue to attract much interest in the development of new technologies. For several years, the UK government encouraged the development of industrial carbon capture and storage (CCS) and is funding a four-year coordinated research, development and innovation programme into CCS technologies. However, in late 2015 the government announced it was cancelling funding for a UK CCS commercialisation competition that would have made available £1 billion capital funding for the design, construction and operation of the UK’s first commercial-scale CCS projects. That said, on 28 November 2018, Energy and Clean Growth BEIS Minister Claire Perry announced a £20 million dedicated fund that will facilitate the development of carbon capture infrastructure at various sites, in addition to an existing funding of £100 million.

The UK government has also set up a Low Carbon Innovation Co-ordination Group to support innovation in energy technologies to meet the climate change goal of an 80 per cent reduction in greenhouse gas emissions by 2050. The group aims to maximise the impact of UK public sector support for low-carbon technologies.

The UK is emerging as a market leader and pioneer in the battery storage industry and there are ongoing efforts to create an appropriate legal and regulatory framework for this emerging technology. According to an all-party parliamentary group on energy storage, the deployment of 12GW of battery storage by the end of 2021 is achievable and would encourage post-Brexit growth.11


Similar to events in 2017, many developments in the UK’s energy legislation and regulation over the past year have been reactive rather than proactive. This has been in large part due to the time- and resource-intensive process surrounding the UK’s departure from the European Union (Brexit), which has severely constrained the resources available to government, Parliament and the regulator to consider and implement forward-looking structural reforms.

Judging from the amount of media coverage, industry commentary and immediate impact for the consumer, the area that has witnessed the greatest degree of change has been the electricity and gas supply market. Arguably the headline event of 2018 was the imposition of the general electricity and gas price cap (i.e., price controls) for consumers on the default plan (the standard variable tariff or SVT). This represented a major change of philosophy for Great Britain’s policy in the supply market, given previous governments’ reluctance to intervene directly, and their converse preference to increase competition in that market as a remedy to increasing prices. However, the legislation that introduced the default price cap is also intended to be a temporary measure, lasting until further retail market reforms are completed.

That said, the imposition of the default price cap was merely one of many other measures announced or implemented in the supply sector, which notably has been hit by a spate of smaller supplier insolvencies due to failure to hedge (in a relatively volatile commodity market) and overly-ambitious business plans that failed to convert low entry-prices into volume-generated profits. For example, over the past year Ofgem has introduced licence restrictions on back-billing customers (i.e. bills may only be issued for consumption over the past 12 months), announced a wholesale review of supply licence conditions, together with BEIS kicked off a project to facilitate access to consumer data, continued the smart meter rollout and the transition to half-hourly settlement, etc. Cumulatively, the effect of all these measures and events has been to separate the wheat from the chaff, as the most sophisticated and well-run new and incumbent suppliers have been able to leverage the gaps in the market resulting from the significant number of insolvencies affecting the retail sector.

In respect of electricity networks, the signal event of 2018 was the creation of a new separate entity, NGESO, within the National Grid group to perform the role of Great Britain’s transmission system. This role was previously performed by National Grid Electricity Transmission plc (NGET), which was also (and continues to be) the owner of the England and Wales electricity transmission system; however, given the increasing scope and importance of the system operator’s functions over time, it was agreed by Ofgem and NGET that the creation of a legally separate entity would enhance its independence, and enable a more secure, competitive and flexible system. NGESO officially took over the role of electricity system operator on 1 April 2019, at which point NGET continued solely in its capacity as the transmission system owner for England and Wales.

The past year has also seen increased levels of activity for networks in relation to the next price control period. On 7 March 2018, Ofgem began its consultation for RIIO-2 gas distribution (GD2) and gas and electricity transmission (GT2/ET2). Since that initial step, Ofgem has published its framework decision in respect of RIIO-2 and detailed consultations on sector-specific methodologies for GD2, GT2, and ET2. Perhaps the most notable features of Ofgem’s proposals are the sharp reduction in the allowed cost of equity and innovative regulatory approaches. Ofgem is also proposing to continue using a cost of debt index to calculate the allowed cost of debt for network companies throughout the price control period. Given initial reactions to its proposals and the appeals brought by British Gas and Northern Powergrid as part of RIIO-ED1, it would be prudent to assume that there will be appeals in respect of RIIO-2, in some form. Although the current political climate (which has also resulted in relatively depressed economic growth) requires Ofgem to be seen as fighting the consumer’s corner, it is equally true that the move to a more flexible and dynamic electricity system demands significant and extensive investment in infrastructure that requires commensurate returns on debt and equity so that network companies can finance their activities.

A major feature of the past year, which few expected, was the annulment by the General Court of the European Union of the European Commission’s state-aid approval for the capacity market in Great Britain following its judgment in the Tempus Energy case (note that the Irish SEM capacity market was unaffected, as it was the subject of a separate state-aid clearance, although that too was challenged and the case is ongoing). The effect of this decision was to suspend all capacity market payments and the collection of capacity market supplier charges (used to fund those payments). Holders of capacity agreements, whose financial models relied on that income, are now faced with a prolonged period of uncertainty while the European Commission carries out a formal investigation and finalises that exercise. Unless and until the state aid issue is positively resolved, this will require careful engagement between capacity agreement holders and financiers to ensure that any shortfall in capacity market income does not trigger a chain reaction that may have adverse unintended consequences for the entire energy sector in Great Britain. The suspension of the collection of capacity market supplier charges has also caused issues for electricity suppliers in terms of whether or not charges should still be levied on customers and what provision should be made for a potentially large back-payment once the state aid clearance is reapproved by the European Commission.

The UK renewables sector has continued to see a large amount of secondary market activity. That said, due to a number of significant offshore wind projects coming online (e.g., Rampion) or adding additional capacity, 2018 was yet another record year for renewables generation (with a commensurate record low for fossil-fuel generation). This has resulted in a 43 per cent reduction in carbon emissions since 1990, which has been assisted in part by record low levels of electricity consumption.

Brexit has also left its mark on the UK’s energy regulation, as government and Ofgem have had to put in place various electricity and gas statutory instruments and licence modifications to deal with the possibility of a no-deal Brexit. However, there have been other, less visible, effects of the UK’s departure from the EU that have impacted confidence levels, causing some investors to postpone final investment decisions in renewables and other energy infrastructure until the UK’s future relationship with Europe is set on a more certain footing.


There have been few times in recent history when it has been as difficult as it is now to anticipate the direction of travel for UK energy regulation and markets. This is in large part due to the unexpected length and complexity of the Brexit process, which, depending on its outcome, may require the UK to promptly put in place alternative mechanisms to replace those supported under EU law or by virtue of the UK’s EU membership. At the time of writing, the UK had already extended its departure date from the EU once, and was in the process of seeking a further extension. Clearly, UK energy policy and legislation will require an inflexion point once clarity is achieved in respect of the UK’s enduring relationship with the EU so as to reboot the growth engine and future-proof this fast-evolving sector.

That said, there are some future developments that, all other things remaining the same, may be currently ascertained. For example, the highly anticipated CfD allocation round 3 is due to occur in May 2019, and will only be open to less-established technologies, including for the first time remote island onshore wind (mainly aimed at the remote Scottish islands, e.g., Shetland). To the extent any Scottish island onshore wind projects are successful, this will also require transmission links to be built connecting those generators to the transmissions system on mainland Great Britain. For example, Ofgem has confirmed that Shetland generators obtaining a CfD is a condition precedent for its final approval of SHE-T’s final needs case for the planned 600MW HVDC link that will connect Shetland generators to mainland Great Britain.

The industry is expecting BEIS and Ofgem to provide legal and regulatory clarity regarding battery storage. Ofgem and BEIS have previously stated that they intend to achieve this by amending the Electricity Act 1989 and other relevant legislation to explicitly define electricity storage as a distinct subset of generation, and by the creation of a separate licence for storage. Evidently, a lot of parliamentary time has to date been taken up by Brexit considerations and it is unclear whether BEIS will be able to progress this workstream in 2019.

Market participants are also anticipating the conclusion of Ofgem’s Supplier Licensing Review process, which may be a first step towards reinstating full competition within the supply market by removing at least some of the retail price controls (e.g., the default tariff price cap). In a similar vein, Ofgem is also expected to make a decision on its consultation on TCR SCR proposals relating to reform of embedded benefits (and charges), as well reform of the residual elements of transmission network use of system charges.

Finally, generators and other capacity providers are keenly awaiting the outcome of the European Commission’s in-depth investigation into Great Britain’s capacity market, which was officially opened on 21 February 2019.


1 Munir Hassan is a partner and Filip Radu is an associate at CMS Cameron McKenna Nabarro Olswang LLP.

2 This chapter focuses on Great Britain and only gives a brief overview of electricity and gas regulation in Northern Ireland.

5 There are criminal sanctions for breaching these requirements unless an exemption applies (see for example the Electricity (Class Exemptions from the Requirement for a Licence) Order 2001 (SI 2001/3270)).

6 For a full list of the EU-wide electricity codes and guidelines, as well as their status, see

7 See Ofgem’s ‘Smart, Flexible Energy System - a call for evidence’ at; and Ofgem’s ‘Targeted Charging Review’ at, and also Ofgem’s latest consultation on clarifying the regulatory framework for storage at