Electricity regulation in the UK: overview
A Q&A guide to Electricity regulation in the UK.
The Q&A gives a high level overview of the domestic electricity market, including domestic electricity companies, electricity generation and renewable energy, transmission, distribution, supply and tax issues. It covers the regulatory structure; foreign ownership; import of electricity; authorisation and operating requirements; trading between generators and suppliers; rates and conditions of sale and proposals for reform.
To compare answers across multiple jurisdictions, visit the energy and natural resources Electricity regulation Country Q&A tool.
This Q&A is part of the global guide to energy and natural resources. For a full list of content visit www.practicallaw.com/energy-guide.
The UK has a fully liberalised and privatised electricity market. The UK was at the forefront of liberalising its electricity sector starting from the mid-1980s when the Energy Act 1983 opened the supply market to beyond the 12 area boards existing at that time. In the privatisation programmes that followed in the 1980s and 1990s England and Wales were also pioneers in creating a wholesale market where electricity generators could sell the electricity in near real time to match demand on the supply side (the "Pool" system operated in England and Wales between 1990 and 2001). The privatisation programmes were carried out along jurisdictional lines:
England and Wales. The restructuring and privatisation programme started in the early 1990s, and saw retail market opening introduced in phases in the period up to 1999.
Scotland. The vertically integrated energy boards were privatised in 1991 and nuclear interests privatised in 1996.
Northern Ireland. The electricity industry was privatised between 1992 and 1993.
Following privatisation, the landscape of the UK electricity market has changed for a variety of reasons, not least to stay in line with changes arising out of EU legislation and in particular the principles of:
Free access to the network.
Security of supply.
The EU led changes, which have been developed through a series of legislative packages affecting the gas and electricity sectors, initially followed the more advanced liberalised status of the UK market. The first of the EU energy legislation packages, Directive 96/92/EC concerning common rules for the internal market in electricity, promoted the independence of the transmission system operator, and laid down the rules relating to the organisation and functioning of, and access to, the wholesale electricity market, requirements already in existence in Great Britain (England, Wales and Scotland) at the time. The changes brought in by the second energy legislation package, Directive 2003/54/EC concerning common rules for the internal market in electricity (Electricity Directive), focused on the concepts of unbundling and third party access, defined the need for independent regulatory authorities and added measures for protecting vulnerable customers. The most current of the legislative packages, the Third Energy Package (IME3), was adopted by the:
Gas and Electricity (Internal Markets) Regulations 2011 in Great Britain.
Gas and Electricity (Internal Markets) Regulations (Northern Ireland) 2011 and 2013 in Northern Ireland.
The UK markets did not readily fit within the proposed EU models but have been considered to be sufficiently well developed and independent to meet the aims of the EU regulations. Accordingly, the IME3 includes specific measures addressing the ownership structures of the UK market (see Question 3).
The wholesale electricity markets in Great Britain are integrated following the introduction of the British Electricity Trading and Transmission Arrangements (BETTA) in 2005.
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. Given the distinct market that operates on the island of Ireland, this article focuses primarily on the position in Great Britain.
Trends in the electricity sector are directed by Government policy through the Department of Energy and Climate Change (DECC) and also arise as a response to wider geo-political and economic factors. As such they can be long-term through years of consistent policy pressures or short term shifts in the market due to external events. Because of the magnitude of changes in the sector in the recent years, some of what are described as trends also form a part of ongoing reforms (see Question 24).
The Government's priorities, as set out below, for the period 2012/13 have been influential in promoting certain policy-led trends in the market:
Promoting energy security and mitigation of climate change. The Climate Change Act 2008 was the world's first legally binding climate change legislation. It commits the UK to achieve its long-term goals of reducing greenhouse gas emissions and to ensure steps are taken towards adapting to the impact of climate change.
Pursuant to the EU Renewable Energy Directive 2009/28 on the promotion of use of energy from renewable sources, the UK committed to have 15% of its energy consumption derive from renewable sources by 2020 (Promotion of the Use of Energy from Renewable Sources Regulations 2011 (SI 2011/243)).
The UK Renewable Energy Roadmap, published in July 2011 and updated annually, sets out a comprehensive action plan:
to assist the UK in achieving its 2020 targets;
to drive innovation;
build on existing programmes such as financial support mechanisms for renewables, the Green Investment Bank and energy efficiency, nuclear, and carbon capture and storage (CCS) programmes.
No nationally binding targets have been proposed at the EU level beyond 2020. In January 2014, the European Commission published its proposals for an EU framework for climate and energy policy to 2030, which includes proposals for an EU-wide target to reduce greenhouse gas emissions by 40% from the 1990 levels and increase renewable energy consumption to 27% of total consumption levels. The UK, like other member states, is free to adopt its own trajectory for carbon emission reductions. However, during the passage of what became the Energy Act 2013, the UK Parliament debated and decided not to include a decarbonisation target for 2030.
Supporting consumers and keeping energy bills down. The current Government has come under recent public pressure in relation to rising domestic energy bills. Accounting for changes in consumption, average household dual fuel bills are estimated to have increased by around 13% in real terms between 2010 and 2012. Wholesale energy costs are estimated to have contributed at least 60% to this increase. For business consumers the affordability debate has moved centre-stage with industry concerns about being competitive against rivals in other markets.
In response, the Government has:
offered a number of exemptions to energy intensive industries from the costs of subsidising low-carbon generation and has offered a cap on the carbon tax payable through its changes to the Carbon Price Floor (CPF) (see Question 24);
introduced a series of measures aimed at promoting carbon and cost savings relating to buildings (for example, the Electricity and Gas (Energy Companies Obligation) Order 2012);
launched the Green Deal in January 2013, an initiative that allows domestic and non-domestic consumers to pay for the cost of energy-efficiency improvements in instalments over a period of time.
In addition, the Office of Gas and Electricity Markets (Ofgem) consulted in spring 2014 on opening a market investigation into the state of the energy market in Great Britain (see Question 24).
Supporting investment in the UK's energy infrastructure. About 21% of the UK's current generating capacity is due to close over the next ten years as a result of the:
scheduled decommissioning of existing nuclear power stations; and
closure of coal-fired power stations in accordance with environmental commitments and EU requirements.
There are concerns that the risks to security of supply will increase from their current levels over the coming decade (Ofgem's Electricity Capacity Assessment Report, June 2013).
To encourage new low carbon generation, the Government has been undertaking a major revision of its policies towards supporting and promoting low carbon generation with more emphasis on competitive allocation of support and restrictions on availability of support overall (called the "levy control framework"). The Electricity Market Reform (EMR) programme was legislated for through the Energy Act 2013. The supporting secondary legislation is under development. The new support contracts for low carbon generation are due to be entered into with generators in 2014 subject to state aid and regulatory approvals (see Question 7, Government policies/incentives).
In response to tightening capacity margins and increasing risks to security of supply, the Government is also legislating to run a Capacity Market in 2014 for delivery in year 2018/19 (see Question 24).
Given that the energy sector operates within a political and economic arena such that the trends in these areas have impacts on the developments in the electricity and gas markets. Other wider trends include:
Greater interconnection beyond the Great Britain market. Between 1986 and the early 2000s the main interconnection was between France and England. Since 2000, new interconnectors other than between France and Britain have been added to the system (see Question 5). Further interconnectors with Belgium, Norway and an additional one with France are planned. This adds to the considerations being made on a national level about meeting the increasing electricity demands and the need for new generation to meet capacity requirements.
Impact of the emergence of shale gas primarily in the US on coal and gas prices in Europe. The UK is among a number of countries seeking to explore its potential for shale gas developments. This has politicised the question of the energy mix in the UK adding to the uncertainty in energy policy (see Question 8). At present there is little clarity on what role shale gas will play in the UK electricity market if developments are successful.
Potential for nuclear developments. The Energy White Paper (Meeting the Energy Challenge) published in March 2007 marked a change in the UK's stance on new nuclear generation indicating that private sector investment in new nuclear power stations would be welcome.
In October 2010, eight potential sites where new nuclear generators could be located were identified. The 3.2 GW nuclear power station at Hinkley Point C is one such site and is the first grant of planning permission for nuclear generation in the UK since the start of generation by the Sizewell B nuclear station 18 years before. The encouragement of new nuclear generation has prompted a review of the energy landscape. At present, no new nuclear generation is expected to be operational before the early-to mid-2020s.
Scottish referendum. Scotland is due to hold a referendum in September 2014 on whether to be an independent country. A yes vote may impact on the current integrated electricity market and future electricity projects.
As described above, the Government has adopted as one of its priorities, the lowering of energy bills. In addition to this, the question of rising energy bills has been further politicised by statements made by the current opposition, the Labour party, who have advocated potential price freezes and the abolition of the current regulator, Ofgem. The next general election in the UK must occur no later than 7 May 2015 and energy policies and prices for consumers are anticipated to be a key political issue in the election.
The regulatory framework in Great Britain (England, Wales and Scotland) (GB) operates through system legislation, licences and industry codes with an independent regulator responsible for regulation of the sector and enforcement of any breaches.
Electricity Act 1989
The main legislative framework is set out in the Electricity Act 1989 (as amended and supplemented), which:
Establishes a licensing regime.
Sets out the statutory duties of the regulator, the Gas and Electricity Markets Authority (GEMA), which operates through the Office of Gas and Electricity Markets (Ofgem) and the Secretary of State for Energy and Climate Change (Secretary of State).
Unless an exemption applies, a licence is required for the following specified activities (Electricity Act 1989):
Participation in transmission (defined to cover both the operation and ownership activities).
Participation in the operation of an electricity interconnector.
From September 2012, providing smart metering services also requires a licence. 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)).
The Electricity Act 1989 enforces separation of activities by prohibiting an entity within the common ownership from carrying out other licensed activities. For example, the transmission licence of National Grid Electricity Transmission (NGET), which operates the GB transmission system, prohibits NGET and all affiliated and related undertakings from owning electricity supply or generation interests. Similarly, an interconnector licensee cannot hold a generation, transmission, distribution or supply licence. (There is a narrow temporary exception to transmission activities carried out by generators in cases where the generator builds the offshore transmission assets, which are then owned by a third party entity, the offshore transmission operators).
Licences are granted subject to conditions, which can be:
Standard licence conditions (broadly applicable to all licensees of a particular type).
Amended standard licence conditions.
Special licence conditions (specific to the licensee concerned).
Conditions can be modified with the licensee's consent, following a reference to the Competition and Markets Authority (CMA) or, in the case of standard conditions, through a collective modification procedure.
In addition to licences, industry codes set out the rules that govern the industry and most licence holders must adhere to the relevant industry codes (as set out in the licence via the standard licence conditions). NGET is responsible for establishing and maintaining most of the transmission system related industry codes pursuant to its transmission licence) (see below).
Other key legislation
Additional primary legislation that regulates or affects the electricity sector includes:
Utilities Act 2000. This established GEMA and the Gas and Electricity Consumer Council and provided for their functions.
Energy Act 2004. It implemented the second energy package and gave the Secretary of State power to establish new regulatory arrangements for offshore electricity transmission (to be administered by Ofgem).
Climate Change and Sustainable Energy Act 2006. It aims to boost the number of heat and electricity micro-generation installations.
Energy Act 2008. It made improved provisions for renewable energy and allowances for a feed-in tariff scheme for small scale renewable generation.
Energy Act 2010. It primarily deals with arrangements for carbon capture and storage development.
Energy Act 2011. It implements the Green Deal Framework (see Question 1 ( www.practicallaw.com/5-504-6458) ).
Energy Act 2013 (see Question 24).
There are also the following key industry codes applicable to electricity regulation:
Connection and Use of System Code (CUSC). This constitutes the contractual framework for connection to, and use of, Great Britain's high-voltage transmission system.
Balancing and Settlement Code (BSC). This contains the arrangements for the wholesale market, in particular on electricity balancing and settlement, in Great Britain.
Grid Code. This sets out the operating procedures and principles governing NGET's relationship with all users of the transmission system. This includes generating companies, suppliers or suppliers' customers, externally interconnected parties or users with systems directly connected to the transmission system.
System Operator–Transmission Owner Code (STC). This defines the high-level relationship between the Great Britain system operator and the transmission system owners.
Master Registration Agreement (MRA). It provides a governance mechanism to manage the processes established between electricity suppliers and distribution companies to enable electricity suppliers to transfer customers.
Distribution Connection and Use of System Agreement (DCUSA). It provides a single centralised document that relates to the connection to and use of the distribution networks and is a contract between generation distributors and suppliers in Great Britain.
Distribution Code. It specifies the day-to-day procedures that govern the relationship between the distribution licensee and users of its distribution system for planning and operational purposes, in normal and emergency circumstances. The Distribution Code is also designed to ensure that the distribution licensee can meet its Grid Code compliance obligations.
Department of Energy and Climate Change (DECC) and the Department of Enterprise, Trade and Investment (DETI). The Secretary of State is:
Responsible for making decisions, setting policy and implementing legislation affecting the sector.
Accountable and reports to Parliament on matters including security of supply and sustainability in the GB energy sector.
DECC is a ministerial department, supported by and working closely with other agencies and public bodies, including Ofgem.
The corresponding government ministry in Northern Ireland is the Department of Enterprise, Trade and Investment (DETI).
GEMA and Ofgem. GEMA has primary responsibility for regulation of the energy sector. It consists of a panel of individuals appointed by the Secretary of State for specified terms of not less than five years. Other than the Secretary of State's powers to remove members on the grounds of misbehaviour, determine the remuneration of members and give guidance, GEMA is independent and has no stakeholder participation.
GEMA delegates the day-to-day administration of its functions to Ofgem. Ofgem's primary duty is to protect the interests of existing and future consumers taken as a whole in relation to electricity and, wherever appropriate, achieve this by promoting effective competition (Utilities Act 2000). Also, in accordance with the Third Energy Package (IME3), it has an additional duty to promote the internal energy market and to remove restrictions to trade between EU member states. Ofgem has far reaching powers in regulating the industry. It is currently undertaking a review of the electricity market in Great Britain (see Question 24).
The UK has a long history of having an independent regulator. Prior to the establishment of GEMA from the merging of the electricity and gas regulators, the regulatory role for electricity in Great Britain was carried out by the Director General of Electricity Supply. This role was set up under the Electricity Act 1989 as part of the ministerial government department, Office of Electricity Regulation. The Director General of Electricity Supply was responsible for monitoring the activities of licensed generators, transmitters and suppliers with the aims of promoting competition, ensuring electricity demand was satisfied and protecting consumers' interests on prices, security of supply and quality of service.
The Utility Regulator for Northern Ireland, an independent non-ministerial government department, is the regulator for the Northern Ireland electricity sector. The Utility Regulator:
Promotes effective competition in the market.
Controls the supply, generation, distribution and transmission licences.
Regulates pricing for a number of companies.
CMA. In April 2014 the CMA became the UK's lead competition and consumer body. The CMA brought together the existing competition and certain consumer protection functions of the Office of Fair Trading and the responsibilities of the Competition Commission (Enterprise and Regulatory Reform Act 2013).
Health and Safety Executive (HSE). The HSE is the national independent regulator responsible for (Health and Safety at Work Act 1974):
The regulation and enforcement of workplace health and safety in Great Britain.
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 all nuclear sector regulation across the UK. ONR was formed on 1 April 2011 as an agency of the HSE and was put on a statutory footing (Energy Act 2013).
Environment Agency. The Environment Agency is responsible for:
Protecting and improving the environment.
Promoting sustainable development in England.
Since April 2013, the responsibilities in relation to environmental and other natural resources related to matters in Wales lie with 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 arise also in relation to consenting.
See box, The regulatory authorities.
Since privatisation of the generation industry in the early 1990s to form three generating companies (National Power, Powergen and Nuclear Electric), the number of generating companies in Great Britain (England, Wales and Scotland) has grown. Currently, the main companies involved in generation in Great Britain are:
Drax Power Limited.
International Power/GDF SUEZ SA.
With the increasing number of renewable generation stations, the number and types of companies involved in generation are diversifying further with new entities, such as the owners of large offshore wind farms (for example, DONG).
National Grid Electricity Transmission (NGET) is the licensed national electricity transmission system operator for Great Britain.
Ownership of the transmission assets is more mixed:
NGET owns the transmission network in England and Wales.
Scottish Hydro Electric Transmission owns northern Scottish transmission assets.
SP Transmission (Southern Scotland) owns central and Southern Scotland transmission assets.
Northern Ireland Electricity owns the transmission assets in Northern Ireland with the System Operator Northern Ireland (SONI) licensed as the transmission system operator (TSO).
There is also an emerging offshore transmission owner (OFTO) market where nine projects in Great Britain have operational OFTOs as at February 2014 and which is seeing a number of new entrants to the market.
There are six licensed distribution network operators (DNOs) in Great Britain, each responsible for one or more of the 14 distribution services area:
Electricity North West.
Scottish and Southern Energy.
SP Energy Networks.
UK Power Networks.
Western Power Distribution.
There is one DNO in Northern Ireland, Northern Ireland Electricity.
In addition, there are a number of independent distribution network operators (IDNOs) in Great Britain who own and operate smaller networks within areas covered by DNOs and mainly serve new housing and commercial developments. The six different IDNOs are:
Independent Power Networks.
The Electricity Network Company.
UK Power Networks (IDNO).
There are 34 licensed electricity suppliers in Great Britain and 14 in Northern Ireland. The main supply companies in Great Britain are:
In Northern Ireland, the main electricity suppliers are:
The provisions of the Third Energy Package (IME3) have been implemented into UK legislation (Electricity and Gas (Internal Markets) Regulations 2011 (see Question 1)). A key requirement of IME3 is for TSOs to be certified as complying with ownership unbundling, that is, the separation of transmission interests (ownership and operation of transmission systems) from generation, production and supply activities. It specifies the roles and responsibilities of transmission owners in terms of:
The UK model while not readily fitting within the proposed IME3 models has been considered to be sufficiently well developed and independent to meet the aims of the IME3. Accordingly, the IME3 includes specific measures addressing the ownership structures of the UK market (see Question 1). Article 9 of each of the Third Energy Package Directives requires TSOs to comply with one of the ownership unbundling models set out in the Directives. The default model is a type of ownership unbundling. However, TSOs that are vertically integrated can apply for certified derogation from the ownership unbundling requirement on the grounds in paragraph (9) of Article 9 (section 10E (4), Electricity Act 1989). The Scottish transmission operators (SPTL and SHETL) were granted certification on grounds of Article 9(9) subject to certain conditions and information sharing restrictions.
The unbundling requirements apply to OFTOs that fall within the meaning of transmission system under the IME3. OFTOs are accordingly required to have certification from Ofgem that they meet the requirements of the IME3. However, recognising that the obligations on OFTOs are limited compared to the responsibilities on NGET as the transmission system operator, the transmission licence conditions applying to OFTOs are separate. Further, there is a specific exception in the Energy Act 2013 relating to generators carrying out certain transmission activities during a defined commissioning period.
There are no specific restrictions in the UK. However, an additional certification process requires Office of Gas and Electricity Markets (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).
Import of electricity
The amount of trading on the interconnections has generally increased in recent years. Great Britain's (England, Wales and Scotland) imports are usually from the Netherlands via the BritNed interconnector and from France via the IFA interconnector. Great Britain generally exports from Scotland to Northern Ireland via the Moyle interconnector.
Great Britain's electricity market currently has 4 GW of interconnector capacity using the following interconnectors:
2 GW to France.
1 GW to the Netherlands.
500 MW to Northern Ireland.
500 MW to the Republic of Ireland.
65 MW to the Isle of Man.
Potential future interconnectors include England to:
Electricity generation and renewable energy
Sources of electricity generation
In 2013, electricity generation from coal accounted for 36.3% and gas accounted for 26.8% (Department of Energy and Climate Change (DECC)).
In 2013, nuclear fission accounted for 19.8% of electricity generation (DECC).
In 2013, renewable energy accounted for 14.8% of electricity generation as follows:
Offshore wind: 10.9 TWh.
Onshore wind: 16.5 TWh.
Solar PV: 1,188 GWh.
Bioenergy: 18.7 TWh.
Hydro: 4.7 TWh.
Low carbon electricity's share of generation increased from 30.7% in 2012 to 34.6% in 2013, the highest share in the last 17 years, due to both higher renewables and nuclear generation.
The Utilities Act 2000 amended the Electricity Act 1989 to allow orders to be made imposing an obligation on electricity suppliers to source a certain percentage of electricity from renewable energy sources (see Question 24).
Renewables Obligation (RO). The RO has until recently been the main financial mechanism supporting the uptake of large-scale renewable electricity generation projects in the UK. It is due to close to new generating stations after 31 March 2017. The RO places an obligation on electricity suppliers to source an increasing proportion of electricity from renewable sources. An electricity supplier can meet its obligations by:
Submitting renewables obligation certificates (ROCs) to the Office of Gas and Electricity Markets (Ofgem) for each annual obligation period.
Paying a penalty (buy-out price).
A combination of these two methods.
Electricity generators can sell ROCs to electricity suppliers (either at the same time as they sell their renewable electricity or separately or to traders and brokers who sell them on to electricity suppliers).
The payment that a renewable electricity generator receives for ROCs (which is additional to the wholesale electricity price that it receives for the electricity that it sells) subsidises the additional costs incurred by generating electricity from renewable energy sources rather than fossil fuels and nuclear. Electricity suppliers pass the additional cost of buying ROCs on to their customers. In this way, the additional cost of renewable electricity is spread over the entire electricity market.
The Electricity Market Reform (EMR) programme has introduced a transitional mechanism for the RO where ROCs are replaced by fixed priced certificates (see below and Question 24).
Contracts for Difference (CFDs). CFDs are long-term contracts between a government-owned counterparty body and low carbon generators such as renewables, nuclear and carbon capture and storage (CCS) equipped plant (Energy Act 2013). There will be a transitional period once CFDs are introduced (expected to be mid/late 2014) until 31 March 2017 during which eligible generators can choose between the RO and CFDs. In addition, the Secretary of State for Energy and Climate Change (Secretary of State) has powers under the Energy Act 2013 to enter into early form CFDs (investment contracts) to ensure that eligible projects needing to make investment decisions before CFDs are available can secure support.
Under the CFDs, generators will receive revenue from selling their electricity into the market and will also receive a top-up to a pre-agreed "strike price". If the market reference price is greater than the strike price, then the generator must pay back the difference. It is expected that the first CFD applications may be submitted in late 2014, with the first payments being made to generators in 2015.
The introduction of CFDs represents a major shift in the incentive mechanisms available to low-carbon generation. Conceptually, some of the provisions about an enhanced period of revenue support over a definite period are similar to the RO. However, the manner in which the support will be offered and the amount of additional detail means the extent to which the CFD will be an incentive for low-carbon generation is not yet clear. The new procedures fundamentally change the landscape for the industry.
The CFD regime is subject to a number of supporting regulations coming into force (see Question 24).
Feed-in tariffs (FITs). The Energy Act 2008 introduced FITs for certain renewable generators with a maximum capacity of 5 MW, to incentivise small-scale generation, including by organisations, businesses, communities and individuals who are not traditionally engaged in the electricity market.
The FITs scheme began operation on 1 April 2010. Generators with installed capacity between 50 MW and 5 MW make a one-off choice at accreditation to seek support either under the RO or under the FIT scheme. The scheme provides a fixed payment for electricity that is generated on-site called "generation tariff".
The option for a payment for any unused electricity that the generator exports to the grid is called "export tariff". The payments are made to FIT generators by suppliers and the costs are passed on to consumers.
Renewable Heat Incentive (RHI). The RHI scheme provides financial support in respect of an eligible renewable heating system depending on whether it relates to:
Non-domestic consumers. The scheme opened to non-domestic consumers in November 2011. Eligible technologies and fuels are:
solar thermal collectors;
ground and water source heat-pumps;
biomethane injection and biogas combustion (except from landfill gas).
Combined heat and power (CHP) will be eligible where the fuel or technology is listed above.
Domestic consumers. The scheme opened to home owners, private landlords, social landlords and self-builders in April 2014. Eligible technologies are:
biomass pellet-only stoves with integrated boilers;
ground and water source heat pumps;
air-source heat pumps;
certain solar-thermal panels.
The domestic RHI scheme grants financial support (at a set rate depending on technology per kwh) to the owners of eligible renewable heat systems that heat a single domestic property.
Participants receive quarterly periodic support payments accruing from the date of installation and these are available for 20 years (non-domestic) or seven years (domestic) and are index-linked. Generally, payments will be calculated by multiplying the participant's tariff level (set according to the type and size of the participant's installation) by the amount of eligible heat generated from the eligible installation in that payment quarter.
Renewable Energy Guarantees of Origin (REGOs). EU member states must ensure that a guarantee of origin is issued on request in respect of electricity generated from eligible renewable energy sources (Article 5, Directive 2001/77 EC on Electricity Production from Renewable Sources). REGOs were introduced in the UK to meet this obligation and are similar to the ROCs or Levy Exemption Certificates (LECs) in terms of being certificates that are transferred between generators and suppliers. REGOs are used by suppliers in England and Wales, Scotland and Northern Ireland to meet their licence obligation to specify in or with bills, and in promotional materials made available to final customers, the contribution of each energy source to the overall fuel mix of the supplier. They are commonly transferred with electricity but normally free of charge. From 5 December 2010, one REGO is issued for each MWh of eligible renewable output generated.
Climate Change Levy exemption for renewable source electricity. See Question 23.
Renewable energy targets
The Utilities Act 2000 amended the Electricity Act 1989 to allow orders to be made imposing an obligation on electricity suppliers to source a certain percentage of electricity from renewable energy sources.
Directive 2009/28/EC on the promotion of the use of energy from renewable sources and amending and subsequently repealing Directives 2001/77/EC and 2003/30/EC (Renewable Energy Directive 2009) sets out EU-wide targets for renewable energy and biofuels:
20% of the EU's overall energy consumption (electricity, heat and transport fuels) must come from renewable sources by 2020.
10% of each member state's transport energy consumption must come from renewable sources (such as biofuels) by 2020.
The 20% EU target for renewables is broken down into individual national targets.
The Renewable Energy Directive 2009 requires the UK to ensure that 15% of its overall energy (not just electricity) comes from renewable sources by 2020. This takes into account the fact that the UK's renewable energy share was very low (1.3%) in the baseline year of 2005.
The high upfront cost of renewable projects (other than, perhaps, biomass) has been a barrier to building significant projects. Therefore the industry has sought a clear and predictable support regime to allow it to make the necessary financial decisions, yet the signals from Government continue to be mixed. The overarching barrier affecting all technologies, across all sectors, in the UK renewable energy industry, and directly or indirectly impacting on all project development steps, is the policy risk and uncertainty in the market (UK Renewable Energy Association).
Government policy for low carbon generations (including renewables) has been in flux since the publication of the Electricity Market Reform (EMR) White Paper in July 2011. The ongoing EMR reforms and associated political statements have led to an investment hiatus over the last few years. As much as GB£330 billion of investment is reported to be at risk due to inconsistent Government signals about its commitment to a low carbon energy mix (Ernst and Young).
Increased Government emphasis on the budgetary constraints of the "Levy Control Framework" (announced as being about GB£7.6 billion) and the move away from the open-access approach of the renewables obligation (RO) scheme.
Ongoing development of the supporting legislation and introducing a large number of important changes as the EMR reforms are implemented.
The recent fast-track introduction of competitive allocation for support under contracts for difference (CFDs) has highlighted not all projects are likely to secure it, or secure it in the required time.
Since 2010, England and Wales operates the following two-tier consenting system:
A centralised and streamlined procedure for energy projects of national significance (consisting of a separate statutory procedure and sector specific government guidance, the National Policy Statements, covering issues such as need, timing and location).
The standard statutory procedure, applying to all projects falling below the national significance threshold, which is implemented through consents granted by the Department of Energy and Climate Change (DECC) as well as at local planning authority levels.
The development consent regime for nationally significant infrastructure projects (NSIP) in England and Wales was partly introduced with the aim of meeting some of the criticisms about delays in obtaining consents (Planning Act 2008).
The broad objective is that Government consent for a NSIP can be expected in most cases within 15 months of the application being accepted, although there is significant emphasis on pre-application consultation and assessment, which can take around two years in the case of major schemes.
However, the Scottish Government is responsible for the planning system of Scotland and has retained the consent system under section 36 of the Electricity Act 1989 (consent to construct and operate a generating station). Local authorities in Scotland are responsible for granting consents for generating stations under 50 MW in capacity, and projects exceeding 50 MW are determined by the Scottish Government, in consultation with local planning authorities. The lack of harmonisation and sometimes unpredictable timings for obtaining consents continues to be a factor in progressing renewable developments.
Eight sites were identified by the Government in 2010 as potentially suitable for the deployment of new nuclear power stations in the UK (England and Wales) before the end of 2025 (see Question 1, Recent trends).
Around 16 GW of new nuclear power is currently planned including the following:
EDF Energy intends to build four new EPRs (6.4 GW) at Hinkley Point in Somerset and Sizewell in Suffolk.
Hitachi has confirmed plans to build two or three new nuclear reactors each at:
Wylfa on Anglesey; and
Oldbury in South Gloucestershire.
NuGeneration plans to build up to 3.6 GW of new nuclear capacity at Moorside, near Sellafield.
Of these, the Hinkley Point C project has been a front runner in the Electricity Market Reform (EMR) scheme and has agreed an early contract for difference (CFD) (investment contract) with the Government. The contract is subject to state aid approval, which is currently under investigation by the European Commission. If prolonged, the investigation may have an impact on the planned timeline for the development of the project.
The Government commissioned a report on the implications of the Fukushima incident in Japan and the lessons to be learned for the UK nuclear industry. The report, in general, did not recommend any fundamental changes to the safety of nuclear power in the UK. However, a number of recommendations were made. These broadly cover:
Transparency of the Office for Nuclear Regulation (ONR).
Arrangements for responding to nuclear and civil emergencies.
Authorisation and operating requirements
Certain types of energy infrastructure in England and Wales fall within the category of "nationally significant infrastructure project", which require a Development Consent Order (DCO) under the Planning Act 2008. The thresholds are more than 50 MW onshore, and more than 100 MW offshore. Applications for DCO are made to and publicly examined by the Planning Inspectorate who then makes a recommendation to the Secretary of State for Energy and Climate Change (Secretary of State). On a successful application, the DCO is awarded by the Secretary of State.
In addition, consent under section 36 of the Electricity Act 1989 is needed for offshore generating stations with a generating capacity of more than 1 MW but less than or equal to 100 MW (section 36, Electricity Act 1989). Projects with a generating capacity of 50 MW and less in England and Wales are consented under the Town and Country Planning Act 1990.
In Scotland, section 36 of the Electricity Act 1989 applies to all projects above 50 MW. Projects that are less must apply for consent to the local planning authority under the Scottish Planning Act. The Scottish Executive is responsible for dealing with applications for consent for generating projects onshore. Marine Scotland, a directorate of the Scottish Executive, is responsible for dealing with applications for consent under section 36 of the Electricity Act for offshore generating stations in Scottish waters.
Depending on type of plant, further authorisations such as relating to health and safety, environmental or nuclear specific matters may also be required from the appropriate regulator.
The Government has placed two conditions on the consenting process for fossil fuelled power stations (including gas and coal-fired) to require the development to facilitate the adoption of carbon capture and storage (CCS) once it is available. These conditions are:
All commercial scale (at or over 300 MW) combustion power stations (including gas, coal, oil or biomass) must be constructed to be CO2 Capture Ready.
New coal-fired power stations must demonstrate CCS on at least 300 MW of the proposed generating capacity.
Directive 2009/31/EC on Geological Storage of Carbon Dioxide (CCS Directive), is implemented in the UK mainly through chapter 3 of the Energy Act 2008. It introduces a new regulatory framework to facilitate the offshore storage of carbon dioxide. In addition, section 36 of the UK Electricity Act 1989 (licensing of power plants), has been amended to implement the CCS Directive requirement that all new combustion power plants over 300 MW must be constructed as CO2 Capture Ready.
A generation licence is required and this stipulates compliance with the relevant industry codes. In particular, all licence holders (for example, transmission, generation, supply and distribution) must be registered within the Balancing and Settlement Code (BSC) administered by Elexon.
Certain health and safety and electricity quality measures must be in place for the construction and operation of systems that generate and supply electricity (Electricity, Safety, Quality and Continuity Regulations 2002 (as amended)).
The Health and Safety Executive (HSE) is responsible for enforcement of the safety aspects of the regulations.
Generators applying directly to connect to the transmission system need a connection agreement with National Grid Electricity Transmission (NGET) and are required to complete a connection application form, provide technical data (Data Registration Code) and pay the relevant application fee. Small generators wishing to connect to the distribution network, that do not require explicit access rights to the National Electricity Transmission System (NETS), make similar agreements with the relevant distribution network operator (DNO). Connections to the distribution system follow their own separate process which may, but does not always, involve NGET.
Generally, the process for connecting a new generator to the transmission or distribution system in Great Britain (England, Wales and Scotland) is co-ordinated by NGET, and involves a number of standardised steps and timelines:
The connection agreement requires the generator, among other things, to become a party to the Connection and Use of System Code (CUSC) Framework Agreement and comply with the CUSC and the requirements of the Grid Code. The CUSC Accession Agreement would need to be entered into by the applicant as well as entering into a bilateral connection agreement with NGET.
Interconnectors use the NETS due to the onward transmission from the interconnector to the NETS, therefore interconnector users sign a bilateral agreement (Use of System Offer) to use the system and accede to the CUSC.
If system reinforcement or other works to the system are required to be made prior to a connection being available, the generator will also be required to enter into a construction agreement. This will include the financial security that must be provided to secure against the cost of the appropriate reinforcement and connection works. Further, if any offshore construction works are needed, a separate offshore construction agreement will also be entered into.
In practice the connection process is likely to be more complex especially where there are connections involving offshore transmission owners (OFTOs), distribution systems or where offers depend on connection applications made by other applicants (interactive offers).
Authorisation and operating requirements
Consent from the Secretary of State for Energy and Climate Change (Secretary of State) is required before installing any overhead transmission lines. In England and Wales, applications for development consent for overhead lines with a nominal voltage of 132 kV or greater are classified as a nationally significant infrastructure project (NSIP) and so made under the Planning Act 2008. The consent may be subject to any conditions the Secretary of State considers appropriate. There are exemptions for overhead lines of minor scale (for example, if a 132 kV line is less than 2km, or replace an existing line and satisfies specific criteria).
If the consent for overhead lines is related to consent for generation, then both may be determined at the same time although it is also possible for generation consent to be granted separately, and ahead, of consent for transmissions (overhead lines or offshore transmission owners (OFTO)). Where there are associated works, planning permission may be needed under the provisions of the Town and Country Planning Act 1990. There are provisions under the process for NSIP's for associated works to be included in the development consent order.
Where transmission assets are to be constructed on private land, additional wayleaves (rights to install and retain cabling or piping across private land in return for annual payments to the landowner) may need to be negotiated direct with the land owner.
The primary requirement to operate the electricity transmission network is a transmission licence (Electricity Act 1989). This is held by the National Grid Electricity Transmission (NGET) in Great Britain (England, Wales and Scotland) and is subject to a number of conditions, including the requirements to establish and maintain industry codes (see Question 2).
The rates payable for connection to and use of the transmission system are set out in a suite of documents called the charging statements. The charges are broadly made up of the following:
Transmission network use of system (TNUoS) charges: to recover the revenue for the transmission system owners, that is the National Grid Electricity Transmission (NGET), the Scottish transmission owners and offshore transmission owners (OFTOs).
Balancing services use of system (BSUoS) charges: to recover the cost of balancing the transmission system and depend on the amount of balancing required.
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 UK (England and Wales).
Between July 2010 and December 2013, the Office of Gas and Electricity Markets (Ofgem) worked with stakeholders to review and eventually introduce the new price control regime "RIIO-T1" (Revenue = Incentives + Innovation + Outputs).
The new arrangements were implemented from 1 April 2013 and cover the period up to 31 March 2021. This replaced the RPI-X formula in place since privatisation and places greater emphasis on the transmission licensee's performance in accordance with the performance targets set by the transmission licensee in consultation with users and customers.
In addition, transmission licences have a statutory duty to develop and maintain an efficient, co-ordinated and economical system and to facilitate competition in the generation and supply sectors.
Authorisation and operating requirements
Consent for lines with a nominal voltage of less than 132 kV is needed unless an exemption applies, such as the nature of the works being carried out to overhead lines constituting minor installation works (section 37, Electricity Act 1989).
Where distribution assets must be constructed on private land, additional wayleaves may need to be negotiated direct with the land owner.
A distribution licence allows the licensee to distribute electricity for the purpose of enabling a supply to be given (Electricity Act 1989). Some distributors may be exempt from requirements to hold a distribution licence (see Question 2).
As with transmission charges, the connection charges for connection to the distribution system are highly regulated. Distribution network operators (DNOs) must offer access to the distribution system based on published, approved tariffs and ensure priority access for renewable generators. Each DNO must have an Office of Gas and Electricity Markets (Ofgem) approved use of system charging methodology for calculating its charges.
The applicable rates are set out in each DNO's connection charging statements and cover charges for the use of the distribution system for the supply of electricity to customers and/or the transportation of electricity across the distribution systems. Users of the distribution system enter into a connection agreement with its DNO, which includes the requirement to accede to the distribution connection and use of system agreement (DCUSA) and a connection and use of system agreement (CUSA).
Further, for new connections to the distribution system and in line with Ofgem's aims of encouraging competition in electricity connections, each DNO sets out in its connection charging methodology the scope of connection services that competitive providers are permitted to undertake (contestable works).
The RIIO-ED1 (electricity distribution price) price control sets the outputs that the DNOs must deliver and the associated revenues they are allowed to collect over the eight-year price control period. The first RIIO-ED1 period is due to start from 1 April 2015 to 31 March 2023. As with the transmission price control, the RIIO model (Revenue = Incentives + Innovation + Outputs) is intended to ensure that the necessary investment is made in the electricity networks at a fair price to the consumer.
In addition, DNO companies have a statutory duty to develop and maintain an efficient, co-ordinated and economical system and to facilitate competition in the generation and supply sectors (see Question 17).
Authorisation and operating requirements
A supply licence allows the licensee to supply electricity to premises, that is, retail electricity to customers (Electricity Act 1989). A supply licence cannot be held in conjunction with an electricity distribution licence or an electricity interconnector licence.
While there is no specific prohibition on a generator holding a supply licence, few electricity generators hold a supply licence. Even vertically integrated utilities carrying out both activities would normally have separate corporate entities carrying out the generation and the retail activities.
To satisfy the licence conditions the supplier must:
Sign up to various codes including the Balancing and Settlement Code.
Have a master registration agreement (MRA). The MRA is a contract between all licensed distributors and suppliers containing, among others, procedures for switching suppliers.
Operate the metering point administrative service for their area.
Trading between generators and suppliers
Bilateral trading between generators, suppliers, traders and customers across a series of markets operates on a rolling half-hourly basis (British Electricity Trading and Transmission Arrangements (BETTA), 1 April 2005). Under BETTA generators self-despatch.
The Balancing and Settlement Code (BSC) provides the framework within which participants comply with the balancing mechanism and settlement process to provide electricity balancing and settlement in Great Britain (England, Wales and Scotland) (see Question 12). The energy balancing aspect allows parties to make submissions to National Grid to either buy or sell electricity into/out of the market at close to real time.
The settlement aspect relates to monitoring and metering of the actual positions of generators and suppliers (and interconnectors) against their contracted positions and settling (requiring/making payments) imbalances when actual delivery or offtake does not match contractual positions.
Separately, electricity can also be traded on a number of power exchanges such as N2EX power market (the operating name in the UK for NASDAQ OMX Commodities and Nord Pool Spot energy markets) and APX.
Electricity price and conditions of sale
Rates of electricity supply are not directly regulated in Great Britain (England, Wales and Scotland) but suppliers are regulated through their licence conditions.
In August 2013, the Office of Gas and Electricity Markets (Ofgem) implemented licence modifications based on its Retail Market Review, which are intended to make it easier for domestic consumers to compare and switch suppliers (see also below, Wholesale). Ofgem has set out a phased timetable for implementation and has issued statutory directions to make the necessary modifications to energy suppliers' licences, which started to take effect from October 2013. From April 2014 suppliers must give consumers simpler tariff information and inform consumers which of their tariffs are cheapest.
A revised set of standards of conduct was introduced in August 2013 covering three broad areas:
In addition, the Secretary of State for Energy and Climate Change (Secretary of State) can amend the licence conditions of gas and electricity suppliers to ensure domestic consumers are on the cheapest tariff with the supplier that meets their preferences (Energy Act 2013).
At present, wholesale electricity prices are not regulated and depend on the market prices (which are, in general terms, overseen by Ofgem).
The status of the electricity and gas markets may change following Ofgem's intention to further develop proposals set out in its Retail Market Review to:
Improve tariff comparability.
Strengthen the Energy Supply Probe Remedies.
Prevent unfair contracting practices in the non-domestic sector.
In the light of continuing concerns about market liquidity, Ofgem also plans to take forward its proposals to address liquidity. This would make it mandatory for certain larger suppliers to sell certain products at an auction (see Question 24).
The Climate Change Levy (CCL) and the Carbon Price Floor (CPF) are part of a range of measures designed to reduce the UK's greenhouse gas emissions. The CPF came into effect on 1 April 2013 as a tax on fossil fuels used in the generation of electricity. This is to be achieved through changes to the CCL regime in the case of gas, solid fuels and liquefied petroleum gas and kerosene used in electricity generation. These changes include the setting up of new Carbon Price Support (CPS) rates of CCL.
The Government announced in its 2014 Budget that the CPS rate will be frozen at 2015 levels of GB£18.00 per tonne of carbon dioxide. In the period of 1 April 2014 to 31 March 2015 it is GB£9.55 per tonne of carbon dioxide.
The supply of "renewable source electricity" is exempt from the CCL (Climate Change Levy (General) Regulations 2001 (as amended)). The Office of Gas and Electricity Markets (Ofgem) issues Levy Exemption Certificates (LECs) for each complete megawatt hour (MWh) of "renewable source electricity" produced by accredited generators. LECs are sold by accredited generators to suppliers who then use these LECs as part of the evidence required by HM Revenue and Customs to demonstrate the amount of "renewable source electricity" supplied to non-domestic customers, which is therefore exempt from the CCL. Although LECs are sold with electricity they are often priced separately.
Electricity market reform
The Energy Act 2013 (EA 2013) received Royal Assent on 18 December 2013 and established a legislative framework for delivering secure, affordable and low carbon energy. Most of the Electricity Market Reform (EMR) programme provisions of the EA 2013 came into effect immediately and the provisions giving the Secretary of State for Energy and Climate Change (Secretary of State) powers to make orders provided for in the Act came into force two months after Royal Assent.
EMR, the cornerstone of EA 2013, was first set out in a White Paper in July 2011. Its provisions have now expanded as set out in Part 2 of the EA 2013.
The main reforms include (Part 2, EA 2013):
Contracts for Difference (CFD) (see Question 7). EA 2013 provides the legal framework for the CFD, setting out statutory obligations on suppliers and generators. The secondary legislation for the implementation of the CFD regime is not yet in force (expected to be in the summer of 2014). The CFD regime (and the early form of CFDs called investment contracts) will also require state aid clearance from the European Commission.
EA 2013 introduced new sections to the Electricity Act 1989 to provide for the Secretary of State to make an order that imposes an obligation on the Office of Gas and Electricity Markets (Ofgem), the Secretary of State or a CFD counterparty to purchase the replacement for the renewables obligation certificates (ROCs) called "certificate purchase obligations" in Great Britain (England, Wales and Scotland). Similar proposals apply for Northern Ireland.
The certificates are fixed priced certificates to be issued to accredited renewable generators in the final ten years of the renewables obligation (RO) scheme (2027 to 2037) and is expected to be index linked.
The secondary legislation detailing how such certificates should be presented for payment, details of any conditions that must be met, or any deadline, is not yet in force (Department of Energy and Climate Change (DECC) consulted on a draft order in October 2013).
RO transitional arrangements (see Question 7).
Capacity market. The Secretary of State can introduce a capacity market based on the Government's forecast of future electricity demand and an assessment of existing security of supply (Energy Act 2013). This forecast will inform the level of reliable capacity that is needed to ensure security of supply in a future period.
The capacity market will be open to electricity generators (not holding a CFD) or other demand-side response operators to compete for the provision of capacity in a pre-determined future period. The capacity providers are to be selected through capacity auctions held four years and one year ahead of the year when the capacity is needed. If selected, capacity providers enter into capacity agreements with the CFD counterparty. In return for payments, the capacity providers are expected to provide capacity (generate or come off-line) when called on or face financial penalties. At the date of writing, DECC has consulted on its implementation proposals. Details are to be set out in supporting secondary legislation.
Emissions performance standard (EPS) was implemented to limit the amount of CO2 emitted by new fossil fuel power stations as it reinforces the requirement that new coal fired power stations are constructed with carbon capture and storage (CCS). Section 7 of the Energy Act 2013 sets a statutory limit on the amount of annual CO2 emissions allowed from new fossil fuel generating stations. The limit is set at 450g/kWh until 2045. At the time of announcing the draft Energy Bill in May 2012, the Government stated that EPS does not form part of the EMR programme but together with the carbon price floor (see Question 24) is one of two mechanisms that support the EMR programme.
Details of how the EMR programme will be implemented are to be set out in secondary legislation. This is still under consultation or awaiting Parliamentary approval. The practical implications of the reforms are yet to be seen. Contracting for CFDs and entry into capacity agreements, though due to start by the end of 2014, will be for electricity not likely to be put on the system until 2018. Additionally, DECC is still determining how demand-side response can participate in the capacity market scheme and is considering other measures such as supplier of last resort mechanisms for providing back-stop power purchase agreements for generators with CFDs to ensure the power generated can be exported.
State of the market investigation
In March 2014, Ofgem proposed a market investigation by the Competition and Markets Authority (CMA) to assess the state of the electricity and gas market in Great Britain. In its assessment report, Ofgem considered the need to assess the supply side of the markets as well as consider the impact of the vertical supply chain on competition and on customers.
The market investigation comes in the context of Ofgem's Retail Market Review and also in the context of Ofgem's aims of making it easier for independent suppliers and generators to access and compete in the electricity and gas markets.
In considering the features that Ofgem would review, and in line with the Competition Commission guidelines, the framework set out to analyse the potential sources of harm in relation to a set of broad categories:
Weak customer response, lack of customer trust and confusion.
Possible tacit co-ordination, the extent of competition between the dominant suppliers, patterns of price changes, switching levels and barriers to switching.
Incumbency advantages, market concentration, switching rates and outcomes for consumers.
Barriers to entry and expansion, low levels of penetration by new entrants in the domestic market.
Vertical integration, common ownership of generation and supply, access to wholesale markets, transparency of wholesale pricing, trading models of integrated suppliers, levels of profit at different levels of the supply chain.
Rises in profitability without corresponding increases in efficiency.
Where Ofgem has reasonable grounds for suspecting that any feature or combination of features of the applicable market prevents, restricts or distorts it may (section 131, Enterprise Act 2002) make a market investigation reference to the CMA. Currently, Ofgem is considering making such a market investigation reference in relation to the state of the electricity and gas markets in Great Britain. Before making its final decision about whether to refer the issue to the CMA, Ofgem is consulting on these proposals (consultation closes on 23 May 2014). If, as expected, a competition inquiry is opened, the review is expected to take up to two years.
The regulatory authorities
Some of the key regulatory authorities relevant for entities in the electricity sector are detailed below. Other regulatory authorities such as environmental agencies for each jurisdiction and local authorities also have regulatory functions that may need to be considered. Where financial or competition related matters are involved, these are subject to separate regulations.
Department of Energy & Climate Change (DECC)
Address. 3 Whitehall Pl, London, SW1A 2AW
T +44 300 060 4000
Main responsibilities. Government department responsible for energy policy in Great Britain (England, Wales and Scotland).
Department of Enterprise, Trade and Investment in Northern Ireland (DETI)
Main responsibilities. Government department responsible for energy in Northern Ireland as well as for economic policy development, enterprise, innovation, telecoms, tourism, health and safety at work, insolvency service, consumer affairs, and labour market and economic statistics services.
Gas and Electricity Markets Authority (GEMA)
Main responsibilities. Regulates the electricity and gas markets in Great Britain (England, Wales and Scotland).
Utility Regulator (UR)
Main responsibilities. Regulates electricity, gas, water and sewerage industries in Northern Ireland.
Health and Safety Executive (HSE)
Main responsibilities. Responsible for health and safety matters such as offshore development and electrical safety.
Office for Nuclear Regulation (ONR)
Main responsibilities. Responsible for nuclear sector regulation across the UK (England and Wales).
Description. For all legislation covering England and Wales, Scotland and Northern Ireland.
Description. For more information about the Grid Code, Balancing and Settlement Code, Connection and Use of System Code, System Operator-Transmission Owner Code and development of the European Network Codes.
Description. For more information about Elexon.
Munir Hassan, Partner, Head of Clean Energy
Professional qualifications. England and Wales, Solicitor
Areas of practice
- Electricity. Head of Clean Energy at CMS in London.
- Market-leading practice in power, renewables, carbon capture and emissions trading matters.
- A power sector lawyer for 17 years and a leading commentator in this area, with regular speaking engagements, media interviews and articles in the industry press.
- Advising on independent power projects, renewables and emissions trading, regulatory and commercial arrangements, M&A transactions, sector restructurings, fuel supply arrangements and PPAs, price regulated energy networks, regional trading arrangements and wholesale/retail supply issues.
- Drafting and advising on power sector legislation, contracts, licences and codes in a number of jurisdictions.
Professional associations/memberships. Law Society of England and Wales.
Recent publications. Wind - Projects & Transactions, Globe Law & Business, consulting editor.
Dalia Majumder-Russell, Associate, Energy
Professional qualifications. England and Wales, Solicitor
Areas of practice
- Electricity. Associate in the energy, projects and construction team at CMS in London.
- Advising on a broad range of corporate and commercial matters in the electricity sectors, both in the UK and overseas.
- Advising on electricity projects and transactions including on power purchase arrangements, wholesale/retail supply issues and power sector legislation.
- Advising a number of clients on the legal, commercial and regulatory issues arising from the UK electricity market reform programme.
- Deeply involved in the development of the first commercial-scale carbon capture and storage project in the UK.
Professional associations/memberships. Law Society of England and Wales.
Power purchase agreements and subsidy arrangements, Wind: Projects and Transactions, Globe Law and Business, 30 January 2014, co-author.
Best laid plans: the policy landscape for renewables investment, Infrastructure Journal, 3 October 2013, co-author with Munir Hassan.