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 opened up the 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 markets are 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 (1) lowering the cost of new technologies; and (2) incentivising the construction of baseload generation. This regulatory shift, together with the 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 co-located with existing renewable projects), and the opening up of transmission (onshore and offshore) projects to private investors.


i The regulators

Gas and Electricity Markets Authority (GEMA)

GEMA is the regulator of both the gas and electricity markets in Great Britain (GB).2 The Utility Regulator for Northern Ireland, an independent non-ministerial government department, regulates the electricity and gas markets 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.

For the GB market, similar duties are performed by GEMA. 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) (Gas Act), the Electricity Act 1989 (as amended) (Electricity Act), and the Utilities Act 2000 (as amended) (Utilities Act), and it has powers in relation to granting and administering 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 often 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.

On a day-to-day basis, Ofgem exercises GEMA's powers to grant and modify the conditions of licences, to monitor the activities of gas and electricity companies, and, where necessary, takes enforcement action to ensure these companies comply with their statutory and licence obligations. Ofgem also exercises GEMA's power to impose financial penalties on licence holders for breaches of such obligations.

The regulatory framework is responsive to changes in the market through Ofgem's ability to modify the licence conditions. This is done through industry code modification panels. Appeals in respect of such modifications can be made to the CMA.

GEMA also has the power to modify the various industry codes. This power is conferred by the relevant licence condition under which a network operator (e.g., National Grid Electricity Transmission plc (NGET) or National Grid Gas plc (NGG)) is required to 'own' the code in question, and currently is not subject to any specific statutory constraints.


The CMA is the United Kingdom's lead competition and consumer body established under the Enterprise and Regulatory Reform Act 2013 (ERRA). GEMA, as energy regulator, has concurrent powers with the CMA with regard to the energy sector. The 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 (Enterprise Act) as amended by the 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 the 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 sector, Ofgem may refer a market to the CMA for a market 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: (1) the absence of locational charging for transmission losses; and (2) the mechanism for allocation of Contracts for Difference. Following the final CMA decision, Ofgem published on 3 August 2016 a strategy for the implementation of the CMA remedies and then issued its detailed implementation plan on 9 November 2016.

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 (1) British Gas Trading Limited (BGT); and (2) 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 of GB. It was established under the Health and Safety at Work Act 1974 and is responsible for the regulation and enforcement of workplace health and safety in GB 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 is responsible for the regulation of nuclear safety and security, including through nuclear site licences, across the United Kingdom. The ONR is also responsible for regulating the transport of nuclear materials and ensuring that safeguards obligations for the United Kingdom are complied with. The ONR reports to the Department for Work and Pensions, although it also works closely with the Department of Energy and Climate Change.

Environment Agency

Responsibilities in relation to environmental regulation in GB have largely been devolved to governments in each of 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. The role of the environmental agencies regarding electricity is limited to pollution-related matters, so mainly relate to conventional generation and nuclear, although additional environmental matters also arise in relation to consenting. 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.

Department for Business, Energy and Industrial Strategy (BEIS) and the Department for the Economy (DFE)

While not regulators, BEIS (in respect of GB) and DFE (in respect of Northern Ireland) are government departments responsible for setting the policies affecting the UK electricity and gas markets. The Secretary of State for Business, Energy and Industrial Strategy is responsible for making decisions, setting policy and implementing legislation affecting the sector and is accountable on matters including security of supply and sustainability in the GB energy sector. BEIS is responsible for formulating UK energy policy, which is implemented through legislation. In addition, 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.

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

ii Regulated activities

The regulatory framework in GB 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 carrying out the licensable activity without a licence (unless an exception applies).4

Licences are granted by the Secretary of State, by way of Ofgem, to the entity carrying out the particular activity. In line with European Third Energy Package rules, a licensee may not hold a transmission, distribution or interconnection licence if it already holds another 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, ACER and ENTSO are developing 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.5


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 unclear, although Ofgem is working with industry stakeholders to develop a regulatory definition for this technology (see more in Section VI, below).6


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 operate the cross-border transportation of gas. 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).

iii Ownership 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, whether foreign ownership or control poses a security of supply risk (Electricity and Gas (Internal Markets) Regulations 2011).

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').

iv Transfers 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.

III Transmission/Transportation and Distribution Services

i Vertical integration and unbundling


The GB market was privatised in the early 1990s and has been fully unbundled, thus serving as a model for many other markets. In GB 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, transmission system operators (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 Package model but was considered sufficiently well developed and independent to meet the aims of the Third Package, a derogation applies in relation to vertically integrated UK TSOs pursuant to Article 9(9) (Section 10E (4), the Electricity Act). Scottish Hydro Electric Transmission plc (SHETL) and Scottish Power Transmission Limited (SPTL), the Scottish owners, were granted certification on grounds of Article 9(9) subject to certain conditions and information-sharing restrictions.


A single regulatory framework applies across GB 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.

ii Transmission/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 GB and divided the transmission role between a GB TSO, currently NGET, on the one hand, and the existing transmission system owners on the other. Both activities – transmission operator and owner – are licensable and the transmission owners are required by law to make their respective transmission systems available to the TSO, which is responsible for the real-time balancing of supply and demand.

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 and non-discrimination.

NGET, a private company listed on the London Stock Exchange, is the holder of the transmission licence and owner of the transmission network in England and Wales, as well as being the TSO for the whole of GB. NGET 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 SHETL and SPTL. In Northern Ireland, the TSO is System Operator Northern Ireland and Northern Ireland Electricity owns the transmission assets.

There is also a market for offshore transmission owners (OFTO) with increasing 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 5 process for which ITTs were issued in April 2016 in relation to the Dudgeon, Race Bank and Rampion offshore wind farms and an EPQ was launched for Galloper and Walney Extension. The OFTO Tender Round 6 process is expected to commence in 2018, potentially for the Hornsea, East Anglia and Beatrice offshore wind farms. To date, there are 14 operational OFTOs in place (having a total investment value of approximately £3.1 billion) with a collective capacity of four.

Ofgem is currently working 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 Owners 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 (owing to 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 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' (SPV) model where the incumbent TO would run a competition for the construction, financing and operation of the project through a project specification.

Transmission and distribution are largely regulated though a series of industry codes. NGET 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 NETS, along with additional provisions on some ancillary and balancing services. The Grid Code deals in detail with matters such as connection conditions, 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 or supply licensees must be party.


Pursuant to its licence, NGET must not discriminate between any persons or class or classes of persons 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 (DNOs)

The electricity distribution system in GB is organised along geographic lines with various regional monopolies. England and Wales are divided up between 12 DNOs, while there are only two DNOs in Scotland and one DNO in Northern Ireland. As at April 2018, the DNOs active in GB are owned by the following six groups: Electricity North West Limited, Northern Powergrid, SSE, SP Energy Networks, UK Power Networks, and Western Power Distribution. 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; and use of system and connection to system charges.

Similar to the obligations of NGET under its transmission licence, 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, and 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, or 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 GB 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 GB is organised along geographic lines. There are eight GDNs in GB covering different geographic regions, which are medium and low-pressure pipeline systems. Four of the GDNs (East Midlands, West Midlands, North West England and 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 & 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).

iii Rates

For electricity, the rates payable for connection to and use of the transmission system are set out in NGET'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. Connection charges are not normally paid by generators in the United Kingdom (England and Wales).

On 13 March 2017, Ofgem launched a consultation focused on review of residual charges both at transmission (TNUoS charges) and distribution (DUoS charges) level (for more information see Section VI, below). 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., but these are not being reviewed at the moment.

Price control

Ofgem regulates the prices for regulated assets pursuant to the licence terms of the given gas or electricity licensee. The current price control model is known as RIIO (Revenue=Incentives+Innovation+Outputs). 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 places major value on stakeholder engagement in the 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 has 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 has extended this price cap to vulnerable customers who receive the Warm Home Discount (WHD). This driver behind this further change is to extend the scope of the existing prepayment meter safeguard tariff to protect circa one million consumers who receive WHD.

iv Security and technology restrictions

While there are no specific security and technology restrictions in GB, concerns around national security, cybersecurity and data processing come up in the context of electricity and gas markets. These are typically dealt with through bilateral contracts and protocols.


i Development of energy markets


GB 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.

Northern Ireland operates a separate wholesale electricity market with a pool system, the Single Electricity Market (SEM), which is integrated with the wholesale electricity market in the Republic of Ireland. A distinct market therefore operates across the island of Ireland; however, the SEM is currently undergoing significant changes to make it compliant with the European Target Model and these changes are intended to fully take effect in October 2018.


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.

ii Energy 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.

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, initially adopted in December 2011, extends the concept of the Market Abuse Directive to physical gas and power, 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 United Kingdom voted to leave the European Union, the government has given assurances that it will continue to implement EU legislation until the Article 50 procedure and the transitional period are completed, and thereafter, a proposed Great Repeal Bill will incorporate EU law into national legislation.

iii Contracts 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.

iv Market developments

There are a number of changes affecting the UK energy and gas markets. For example, in electricity transmission in GB, 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.

The introduction of the GB 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 (for which 138.6MW has been purchased for spring/summer 2017). The service is procured by National Grid and was introduced in 2016 to encourage large energy users and generators to either increase demand (i.e., take energy off the network) or reduce generation.


i Development of renewable energy

The UK has a long-established renewable energy policy. At the national level, the UK, 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 UK is the EU Renewable Energy Directive (RED).7 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. Beyond the 2020 renewable targets, EU countries agreed in 2014 on a policy framework for 2030 including targets for a 40 per cent cut in greenhouse gas emission, 27 per cent share on renewable energy consumption and at least 27 per cent reduction on energy use.8 However, pursuant to the 2014 policy framework agreement, the European Commission has put forward an amendment proposal to the RED that would, among other things, replace nationally binding 2020 renewables targets with an EU-wide target of 27 per cent renewable energy by 2030. Other amendments would seek to extend national renewable support mechanisms to projects in other member states (which the UK states may not be compatible with the principle of subsidiarity) and boost the proportion of renewable energy used for heating, cooling and transport.9 The RED amendment proposals are set to enter into force on 1 January 2021 (i.e., post the UK's exit from the EU in early 2019) and as previously stated, until the Brexit Article 50 procedure is complete, the UK will continue to implement and observe EU law as normal. After the UK's exit from the EU is effected, the entirety of EU legislation will be enshrined in national law by means of what the government calls a Great Repeal Bill. Renewables targets will, however, remain unaffected regardless of the final Brexit position as the UK's national renewables and decarbonisation targets exceed those imposed at EU-level. However, the government's focus on achieving industrial growth post-Brexit may render decarbonisation targets secondary to those of ensuring security of supply 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, the UK may still have to observe EU state aid rules to secure unrestricted access to EU markets).

Contracts for Difference

In the UK electricity sector, the main support 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) for large-scale, and Feed-in Tariffs (FiTs) for small-scale projects.

CfDs are 15-year contracts entered between a government-owned company, the Low Carbon Contracts Company, and the eligible 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 capital of the investment. The first allocation round for CfDs took place in October 2014 and contracts were awarded to 27 projects in February 2015.10 The second allocation round for CfDs for the 2021/22 and 2022/23 Delivery Years took place in April 2017 and 11 projects were successful in obtaining contracts. 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 the spring of 2019 for less established technologies (e.g., remote Scottish island wind).

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, and 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 on March 2015, and small-scale on 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 – 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.

ii Energy efficiency and conservation

Until recently, 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. The RHI was first introduced in November 2011 for non-domestic heating and subsequently expanded to include domestic heating support. Duration of support is 20 years for the former and seven years for the latter category. On 12 October 2017, the government put forward proposals to reform the RHI with a view to increasing the focus of the scheme on increased adoption of various technologies such as biomethane and heat pumps.

iii Technological developments

The electricity and gas sectors continue to attract much interest in the development of technologies. For several years, the UK government encouraged the development of industrial carbon capture and storage (CCS) and is funding a four-year co-ordinated research, development and innovation programme into CCS technologies. However, in late 2015 the government announced it was cancelling funding for a UK Carbon Capture and Storage (CCS) Commercialisation competition which would have made available £1 billion capital funding for the the design, construction and operation of the UK's first commercial-scale CCS projects.

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. 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


Although the UK market has had to cope with significant uncertainty resulting from Brexit negotiations and the government's somewhat related focus on reducing costs, the energy market has thus far demonstrated significant resilience to those developments. That is not to say that concerns and risks are behind us, as the true costs of issues such as Brexit will only truly emerge when the complete suite of exit and future trade agreements are fully settled, ratified and implemented.

The UK continues to enjoy a strong pipeline of interconnectors that benefit from the support of Ofgem and BEIS; however, it remains to be seen to what extent these will reach completion given uncertainties caused by Brexit not only in the UK but also in neighbouring countries. A recent example of negative impacts caused by enduring uncertainties relating to the UK's future relationship with Europe is the French regulator's decision to suspend approvals for new France-UK interconnectors projects (i.e., those that have not already been approved) until there is greater clarity in that respect.

The closure of the RO scheme in 2017, coupled with the sparsity of new CfD allocation rounds, has had an impact on new build renewable projects. The RO has historically been responsible for delivering much of the UK's renewable new build generation and supported 69.1TWh or 23 per cent of UK electricity generation between April 2015 and April 2016, which is in stark contrast to the 1.8 per cent of generation supported by FiTs. Although CfDs were promoted as the instrument intended to replace the RO, the market has not seen the two mechanisms as like-for-like, especially given that CfDs are currently open only to those less established technologies.12 That said, appetite for developing renewables remains strong as indicated by the oversubscription of bids for the second CfD allocation round where bids received equated to 10 times the value of the final contracts awarded.

In contrast to the decrease in new build renewables, a prominent feature of the past year has been the regulator's and the government's increasing focus on flexibility and reliability. This is reflected in the latest T-4 Capacity Market auction for which results were announced in February 2018, where the level of support dropped to its lowest ever level (£8.40/Kw) and continued the trend of existing closed cycle gas capacity taking the lion's share of the pot (followed by existing nuclear, CHP, interconnectors and coal/biomass). An encouraging feature of this latest Capacity Market auction was that storage and demand side response had a strong showing, winning a significant proportion of contracts. What has not happened, however, is the long-awaited arrival of new gas peaking plant, which is, ironically, an indictment of and results from the very low levels of support under the Capacity Market achieved through competition.

As touched on previously, Brexit has proven to be a much more complicated and extensive exercise than many would have thought only a year ago. As a result, there has been limited parliamentary and, indeed, ministerial time available for the development of new schemes such as CATOs. This has not prevented Ofgem from trying to devise methods (e.g., in relation to transmission reinforcements carried out by NGET in respect of Hinkley Point C) that emulate competition in transmission assets as closely as possible. It remains to be seen to what extent such ad-hoc competitive models will be fit for purpose and deliver sufficient savings to justify any disruption or delays they may cause to critical infrastructure projects.

The UK regulatory and legal framework for energy remains a guiding light for many developing countries wishing to inject competition into their electricity and gas markets. This is reinforced, for example, by the regulator's and government's efforts to define and integrate battery storage within the regulatory arrangements so as to maximise the efficiencies that technology can bring. However, in a move that would have surprised many if not most just a few years ago, the general election in 2017 coupled with stagnating wages (and living standards generally) prompted both the Conservative and Labour parties to include in their election manifestos price caps on rising energy costs for consumers. In the event, the Conservative government that emerged from the election decided to implement a much less ambitious price cap covering only those consumers with prepayment meters, which was later extended to also include those receiving the Warm Home Discount. Such caps were supported by the conclusions of Professor Dieter Helm's 'Cost of Energy Review' (commissioned by the government), which also proposed a much more ambitious overhaul of the UK's energy markets; however, the government has yet to decide how to take those proposals forward (if at all).

In terms of networks, the highlight of the past year has been Ofgem and the government's announcement of their plans to legally separate the system operator role performed by National Grid from its other capacity of being a transmission owner. The stated aim of this move is to help 'keep household bills down by working to ensure and enable more competition, coordination and innovation across the system'.

Challenging weather conditions, particularly in the winter, have led some to query the ability of the UK's gas infrastructure to adequately deal with demand (and therefore price) spikes. This issue has been compounded by the closure of key gas storage assets such as Centrica's Rough facility (which provided close to 70 per cent of the UK's gas storage capacity). That said, an increasingly booming and maturing global LNG market, coupled with the opening of new LNG terminals at Teesside and Port Meridian, may allay some of the concerns relating to security of supply.


In one sense, it would be sensible to expect the near-to-medium term to be a period of significant regulatory and legislative change; however, there is a real prospect that the diaries of ministers and regulators will be too crowded out by Brexit for any meaningful and considered changes to the current framework to be put forward.

As previously mentioned, the report on the cost of energy commissioned by the government and prepared by Professor Dieter Helm contained a comprehensive set of proposals aimed at radically changing many of the structures, mechanisms and frameworks that currently support the UK's energy ecosystem. As part of that review, and among many other proposals, it was suggested that the Capacity Market and CfDs are merged into a unified equivalent firm power capacity auction to give further support to renewables development, possibly in recognition of the fact that CfDs did well to reduce costs but are not sufficiently incentivising new build renewables. The government has put out to consultation many of Professor Helm's proposals and market participants are awaiting final decisions in that respect.13

More generally on renewables, it is important that a distinction is made between technologies such as onshore wind and offshore wind. The former, owing to increasingly onerous planning restrictions and activism, are not expected to grow significantly in the foreseeable future; however, there is an entirely different (success) story for offshore wind, a technology for which the UK remains a leading global player. That said, the opening up of the third CfD allocation round to remote Scottish island onshore wind may mean that that technology has a future in places where its energy benefits far outweigh the aesthetic displeasures it may cause. In addition, the cost decreases being achieved for certain technologies (e.g., onshore wind, solar) may mean that grid parity is soon reached and a subsidy-free environment becomes something that is achievable without sacrificing climate change objectives due to subsidy-related cost pressures.

Another development that promises to be of interest to many market players is the progress through parliament of the government's Domestic Gas and Electricity (Tariffs Cap) Bill, which seeks to put in place much wider price caps on electricity and gas suppliers' tariffs than the ones currently imposed by Ofgem for vulnerable consumers. We have already started to see potential divestment and consolidation of players in the supplier market as a result of this increasingly interventionist and price control-oriented approach taken by the government in the supply markets.

Finally, it remains to be seen what progress Ofgem will make in its efforts to create a wider role for DNOs by extending the scope of their role to that of Distribution System Operators, who may have an additional role in balancing and managing an increasingly dynamic embedded generation market.


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.

4 There are criminal sanctions for breaching these requirements unless covered by an exemption (Electricity (Class Exemptions from the Requirement for a Licence) Order 2001 (SI 2001/3270)).

5 For a full list of the EU-wide electricity codes and guidelines, as well as their status, see http://ec.europa.eu/energy/node/194.

6 See Ofgem's 'Smart, Flexible Energy System – a call for evidence' at https://www.ofgem.gov.uk/publications-and-updates/smart-flexible-energy-system-call-evidence; and Ofgem's 'Targeted Charging Review' at https://www.ofgem.gov.uk/publications-and-updates/targeted-charging-review-consultation, and also Ofgem's latest consultation on clarifying the regulatory framework for storage at https://www.ofgem.gov.uk/publications-and-updates/clarifying-regulatory-framework-electricity-storage-licensing.

8 For more information on the EU 2030 Energy Strategy see https://ec.europa.eu/energy/node/163.

9 For more information on RED amendment proposals see http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:52016PC0767R%2801%29.

12 For example, CfDs are open to technologies in Pot 2 (which includes offshore wind) but not Pot 1 (which includes onshore wind and solar or Pot 3 (biomass).