Alternative Energy & Power 2019

Last Updated August 07, 2019

UK

Law and Practice

Authors



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Great Britain (GB) had one of the first liberalised electricity markets. In 1989, under Prime Minister Margaret Thatcher’s government, the Electricity Act 1989 received Royal Assent, privatising the various state authorities and creating individual types of market participants – specifically generators, transmission network operators, suppliers and later distribution network operators.

The 1989 Act paved the way for the establishment of the UK energy regulatory authority, the Gas and Electricity Markets Authority (GEMA) by the Utilities Act 2000, which is supported by the Office of Gas and Electricity Markets (Ofgem). GEMA acts independently from the UK government, but is accountable to the UK Parliament.

The first, second and third energy packages of the EU – enacted in 1996, 2001 and 2009 respectively – set out to liberalise the electricity markets of EU member states, which effectively reinforced the principles of the 1989 Act. The UK electricity market is based on the principle of free competition and transparency, with Ofgem primarily acting to protect consumer interests. With the notable exception of the Low Carbon Contracts Company (see 1.8 Unique Aspects of the Power Industry), the State itself does not directly participate in the UK electricity market (see 1.3 Foreign Investment Review Process regarding 'golden shares'), although it may hold minority shareholdings in certain market participants.

It is important to note that due to historical and geographical reasons, the Northern Irish electricity grid is effectively separate from that in GB (ie, Scotland, England and Wales). As a result of devolution, electricity market regulation has to an extent been devolved from the United Kingdom to Scotland, England, Wales and Northern Ireland, whereby the regulatory regimes of the other countries are very similar to one another. Northern Ireland, however, has its own national regulatory authority, the Utility Regulator, which works in close co-operation with Ofgem. The Northern Irish electricity market, however, is coupled to the Republic of Ireland as part of the Single Electricity Market (SEM) and is regulated jointly by the Utility Regulator and the Irish Commission for Regulation of Utilities (CRU).

Due to the devolved nature of electricity policy and to the single GB national electricity transmission system (NETS), this chapter shall focus primarily on the regulatory regime in England and Wales.

Generation

As of the time of writing, there are 169 GB generation licence holders, which are all based around GB and operate a variety of generation types. The main UK-based generators include Centrica, Drax Power, EDF Energy, ENGIE, E.ON, Intergen, RWE, Scottish Power and SSE. Due to the market liberalisation, these entities are variously under UK and foreign ownership.

Transmission

As of the time of writing, there are 19 UK transmission licence holders. Under the UK electricity market trading regime, introduced through the British Electricity Trading Transmission Arrangements (BETTA), National Grid Electricity Transmission plc (NGET) was nominated as the sole operator of NETS – ie, the onshore transmission network of GB. As of 1 April 2019, NGET was split into two separate legal entities, with National Grid Electricity System Operator (NGESO) taking over the operation of NETS, whereas NGET remains owner of the onshore transmission network in England and Wales.

In Scotland, the network ownership is divided between SP Transmission Ltd (SPT) regarding southern Scotland, and Scottish Hydro Electric Transmission plc (SHE-T) regarding northern Scotland and the Scottish islands.

The remainder of transmission licence holders are primarily offshore transmission owners (OFTOs), which own and operate the transmission lines between offshore generators and NETS.

Interconnection

As of the time of writing, there are 16 UK interconnection licence holders. A number of interconnectors are currently in development, with five currently in operation:

  • IFA interconnector, jointly owned by National Grid Interconnectors Limited (NGIC) and RTE (the French transmission system operator, TSO);
  • BritNed interconnector, owned and operated by BritNed Development Limited, a joint venture between National Grid and TenneT (the Dutch TSO);
  • Moyle interconnector, owned and operated by Mutual Energy;
  • East-West interconnector, owned and operated by EirGrid (the Irish TSO); and
  • Isle of Man (also known as Manx) interconnector, owned and operated by the Manx Cable Company (MCC), a wholly-owned subsidiary of the Manx Electricity Authority (MEA).

Distribution

There are 14 GB distribution licence holders based on similar and separate geographic areas of the 12 area electricity boards formed prior to the electricity market liberalisation under the Electricity Act 1947. These are Eastern Power Networks plc, Electricity North West Limited, London Power Networks plc, Northern Powergrid (Northeast) Limited, Northern Powergrid (Yorkshire) plc, Scottish Hydro Electric Power Distribution plc, South Eastern Power Networks plc, Southern Electric Power Distribution plc, SP Distribution plc, SP Manweb plc, Western Power Distribution (East Midlands) plc, Western Power Distribution (South Wales) plc, Western Power Distribution (South West) plc and Western Power Distribution (West Midlands) plc.

In addition to the above, there are 13 independent distribution licence holders that operate smaller on-site networks, primarily used for residential and commercial developments connected to the 14 distribution networks.

Supply

In 1999, full competition was introduced into the UK electricity retail market. At the time of writing, there are 246 domestic and non-domestic licensed suppliers in the UK. However, the market is dominated by the so-called big six, some of which are additionally generation asset owners. These are British Gas, SSE, E.ON, EDF Energy, ScottishPower and npower.

In general, the UK government holds 'golden shares' in a limited number of UK companies. These are special shares conferring particular rights under a company’s articles of association. Typical golden share powers include the relevant Secretary of State (as shareholder) having the right to restrict shareholdings in the company to 15%. A number of golden shares also include powers over the disposal of material assets.

Following the entry into force of the Electricity Act 1989, golden shares were issued in energy companies to protect these from foreign takeover. However, in 2003, the ECJ held such golden shares incompatible with the EU principle of free movement of capital in its judgments on Commission v Spain (C-463/00) and Commission v United Kingdom(C-98/01).

There are currently no general laws that deal with or restrict foreign investment into the UK. As a member of the Organisation for Economic Co-operation and Development (OECD), the UK subscribes to the OECD Codes of Liberalisation and is therefore committed to imposing minimal limitations on foreign investment.

There are, however, certain limitations. Section 59 et seqof the Enterprise Act 2002 entitles the Secretary of State for Business, Energy and Industrial Strategy to intervene in the private sector on exceptional public interest purposes, such as national security, media quality and financial stability. Section 13 of the Industry Act 1975 entitles the Secretary of State to block an acquisition by a non UK-based entity of an "important manufacturing undertaking" when it appears that a change of control would be contrary to the interests of the UK or a substantial part of it; however, there is no public record of this provision ever being used to prohibit a transaction.

Golden shares are still held in only a few strategically privatised companies, such as Rolls-Royce (aerospace) and BAE Systems (aircraft and defence), while certain service activities (such as radio and land-based television broadcasting) are subject to licensing. Furthermore, the UK requires that at least one director of any company registered in the UK must be ordinarily resident in the UK.

The Enterprise Act 2002, and indirectly the Competition Act 1998, govern the process of M&A in the UK and the Competition and Markets Authority (CMA) is responsible for their administration. The CMA may investigate a merger or acquisition upon the occurrence of a "relevant merger situation". Under Section 23 of the Enterprise Act 2002, this is met when (in relation to the supply of goods):

  • two or more enterprises cease, or will cease, to be distinct as a consequence of being brought under common ownership or control;
  • either (i) the target enterprise's UK turnover exceeds GBP70 million or (ii) as a result of the merger, the combined enterprise will supply or acquire 25% or more of any goods or services in the UK or a substantial part of the UK, or an existing share of supply of 25% or more will be enlarged; and
  • the merger is in contemplation, or took place not more than four months before reference to the CMA was made (unless it took place without prior notice being given to the CMA of material facts, such facts not being made public – in such a case the four-month period starts when material facts were so given or made public).

However, the EU Merger Regulation (Council Regulation (EC) No 139/2004 on the control of concentrations between undertakings) allows the European Commission to assume exclusive jurisdiction over mergers that have a "Community dimension" (ie, exceeding certain thresholds). The primary thresholds are that (i) the combined aggregate worldwide turnover in the preceding financial year of all undertakings exceeds EUR5 billion and (ii) the combined aggregate EU-wide turnover of at least two of the undertakings exceeds EUR250 million.

Beyond the controls discussed in 1.3 Foreign Investment Review Process, there are no specific restrictions on the sale of power industry assets or businesses, or other transactions.

The ministry responsible for energy is the Department for Business, Energy and Industrial Strategy (BEIS), led by the Secretary of State for Business, Energy and Industrial Strategy, at the time of writing the Rt Hon Greg Clark.

Acting under the Secretary of State, BEIS is responsible for the development of GB energy policy and preparing bills for consideration by the Parliament. With respect to the electricity market, BEIS set out the following priorities from 2017 to 2018:

  • deliver an ambitious industrial strategy;
  • maximise investment opportunities and bolster UK interests;
  • promote competitive markets and responsible business practices;
  • ensure the UK has a reliable, low cost and clean energy system; and
  • build a flexible, innovative and collaborative department.

At the time of writing, BEIS is focused on preparing for Brexit, in particular working together with energy market regulatory of neighbouring countries to ensure continuity of interconnector operation, and ensuring national energy legislation properly functions post-Brexit, a significant amount of which derives from EU law.

Ofgem is the GB national regulatory authority, whose responsibilities can be grouped into four categories: (i) market regulation, (ii) ensuring competition, (iii) industry code governance and (iv) consumer protection. Ofgem therefore oversees the retail market to ensure that customers rights are protected and that the electricity market in general is run in an efficient and effective manner that is designed to promote innovation.

With respect to the development of transmission facilities, Ofgem and NGESO work together to ensure that NETS is fit for function, and through the use of price controls, Ofgem ensures that NETS is used in such a way as to improve efficiency, encourage companies to innovate technically and to act in accordance with the interests of consumers as well as other stakeholders.

The Office for Nuclear Regulation (ONR) is responsible for the regulation of nuclear and safety in the UK, and the Nuclear Decommissioning Authority (NDA) is responsible for the decommissioning of nuclear generating stations.

The GB legislative framework is currently aligned with the EU third energy package, which took effect as of 2011. GB does, however, in many regards go further, including creating the electricity capacity markets, as well as the cap-and-floor regime for qualifying interconnectors. The last major legislative change concerning electricity was the enactment of the Energy Act 2013, which received Royal Assent on 18 December 2013. This was a significant development in the electricity market, setting out the Electricity Market Reform (creating the contracts for difference (CfD) scheme to encourage low carbon electricity generation and the capacity market) and creating the Office for Nuclear Regulation.

On May 2018, Ofgem published a statutory consultation on modifications to the standard conditions of all electricity transmission licences. These licence modifications are intended to update and maintain the consistency of the electricity transmission licence following the legal separation of NGESO and NGET.

In November 2016 the European Commission published the draft Clean Energy for All Europeans Package, a legislative package of eight acts designed to cover the electricity market from 2021 to 2030. In June 2019 the final act of the package was passed and the new acts are:

  • Directive (EU) 2018/844 on the energy performance of buildings and Directive 2012/27/EU on energy efficiency;
  • Directive (EU) 2018/2001 on the promotion of the use of energy from renewable sources;
  • Directive (EU) 2018/2002 amending Directive 2012/27/EU on energy efficiency;
  • Regulation (EU) 2018/1999 on the Governance of the Energy Union and Climate Action, amending Regulations (EC) No 663/2009 and (EC) No 715/2009 of the European Parliament and of the Council, Directives 94/22/EC, 98/70/EC, 2009/31/EC, 2009/73/EC, 2010/31/EU, 2012/27/EU and 2013/30/EU of the European Parliament and of the Council, Council Directives 2009/119/EC and (EU) 2015/652, and repealing Regulation (EU) No 525/2013 of the European Parliament and of the Council;
  • Regulation (EU) 2019/941 on risk-preparedness in the electricity sector and repealing Directive 2005/89/EC;
  • Regulation (EU) 2019/942 establishing a European Union Agency for the Cooperation of Energy Regulators;
  • Regulation (EU) 2019/943 on the internal market for electricity; and
  • Directive (EU) 2019/944 on common rules for the internal market for electricity and amending Directive 2012/27/EU.

In the judgment of Tempus Energy Ltd and Tempus Energy Technology Ltd v European Commission (Case T-793/14) made on 15 November 2018, the ECJ annulled Commission decision C(2014) 5083 final, which had originally approved the GB CM scheme as a state aid measure compatible with EU state aid law.

The claimant successfully argued that the Commission's investigation did not equally consider demand side response (DSR) providers with respect to generators and therefore did not reveal potentially discrimination of the CM with respect to DSR providers. The Tempus judgment and annulment was, however, made based on a procedural error with respect to the Commission's investigation of the CM scheme, rather than a material issue with the scheme's state aid compatibility.

At the time of writing, the Commission is currently undertaking a full review of the CM scheme. In the interim, however, the UK government has suspended the CM for new capacity auctions until a final decision has been made by the Commission. Nevertheless, the claimant has applied for a judicial review of the UK government's decision to continue operating the CM, which, if successful, may result in the recovery of payments previously made to CM participants and the reimbursement of the charge paid by the electricity supplier.

There are currently no forthcoming significant policy changes regarding the electricity market, but the UK's withdrawal from the EU (Brexit) will have a significant impact on the UK electricity sector. The UK has enacted the European Union (Withdrawal) Act 2018, which, on the date of the UK's withdrawal, will transpose all EU law into UK law. From the perspective of the energy sector, it is understood that the UK will remain to a great extent aligned with the EU; however, subject to any international agreement between the UK and the EU27, there is no certainty as to how long such an alignment would last. Where the UK will seek to remain aligned with EU energy policy, in the case of a hard Brexit, it is possible that the UK will voluntarily implement the eight acts of the Clean Energy for All Europeans Package into UK law.

At the time of writing, the UK government has published the first Brexit statutory instruments, which include Feed-in Tariffs and Contracts for Difference (Amendment) (EU Exit) Regulations 2018. These regulations make minor amendments to the Feed-in Tariffs Order 2012 and the Electricity Supplier Obligations (Amendment and Excluded Electricity) Regulations 2015 to reflect the fact that the UK will no longer be an EU member state from the exit day; however, they do not affect the operation of the feed-in tariffs (FiTs) or CfD schemes.

Additionally, in accordance with paragraphs 137-144 of the White Paper of the Department for Exiting the EU, if the UK leaves the EU Internal Energy Market, it would explore what would be needed to ensure trade over interconnectors would continue without the automatic capacity allocation procedures that have been developed to facilitate the Internal Energy Market.

The UK has one of the oldest liberalised electricity markets in Europe, primarily originating with the Electric Lighting Act 1882, which provided for the creation of supply systems.

As noted above, the UK is generally a thought leader within the EU with respect to electricity policy, the most recent of which being the 2013 Electricity Market Reform (EMR), and EU legislation has by and large complemented, deepened and harmonised the existing regulatory regime.

An innovative approach of the UK can be demonstrated in the development of the 'cap-and-floor' regime with respect to interconnectors. In order to encourage investment and protect against electricity price fluctuations, in 2014, Ofgem decided to introduce a cap-and-floor regulatory regime to qualifying interconnector projects. This sets out a cap price and floor price for a specific interconnector, so that should the market price drop below the floor, the operator is guaranteed a certain income to increase bankability; conversely, should the market price exceed the floor, the operator can only receive the capped amount, the difference of which is used to fund the scheme.

In 2013, the EMR introduced the capacity market, detailed in the Capacity Market Regulations 2014 and the Capacity Market Rules 2014. As noted in 1.6 Recent Material Changes in Law or Regulation, however, the CM has currently been suspended until the Commission completes its full investigation and publishes its revised decision. The CM allowed NGESO as the capacity market delivery body to auction out capacity over four years (T-4) and over one year (T-1) in advance of a delivery year. Successful bidding generators entered into a capacity agreement with NGESO, and may have been called up by NGESO to deliver agreed capacity at any time during the delivery year, failing which they were faced with a financial penalty. T-4 and T-1 capacity may be bought and sold on the secondary market prior to the delivery year. Subject to the revised decision of the Commission and the UK judicial review, the CM provides another tool to NGESO to balance the electricity market.

The EMR additionally introduced the CfD programme as a support system for renewables. The CfD is a private law contract between the low carbon electricity generator and the Low Carbon Contracts Company (LCCC), which is a government-owned company. The CfD provides price security and thereby bankability by setting a specific 'strike price' for electricity. Should the market reference price fall below the strike price, the LCCC pays the difference to the generator, and if the reference price exceeds the strike price, the generator pays back the difference to the LCCC. In 2013, the CfD for renewables was approved by the Commission as being compatible with state aid rules.

The GB electricity wholesale market is a based on half-hourly delivery intervals. The start of each interval is known as gate closure, before which market participants must submit final nominations of contracted electricity quantities to NGESO. One hour after gate closure is the settlement period, and there are 48 half-hour settlement periods per day. The wholesale market can therefore be generally divided into pre-gate and post-gate closure.

Pre-gate closure, wholesale market participants can trade electricity with power purchase agreements, forwards negotiated OTC and futures (forwards traded over an exchange), all of which may be agreed from several years in advance up to approximately 48 hours pre-gate closure. Within the 48 hours prior to gate closure, electricity can be sold on the spot (including intraday) markets.

Post-gate closure, as the GB system operator, NGESO is responsible for providing 'ancillary services' until the end of the settlement period in response to imbalances of supply and demand or times of system stress. Also known by NGESO as 'balancing services', ancillary services are defined in EU Directive 2009/72/EC on concerning common rules for the internal market in electricity (Electricity Directive) as "a service necessary for the operation of a transmission or distribution system".

Imports and exports of electricity to and from other jurisdictions are permitted. Following the entry into force of the Electricity Directive, Regulation (EC) No 714/2009 on conditions for access to the network for cross-border exchanges in electricity (Electricity Access Regulation) and the subsidiary network codes (see 5.1.1 Principal Laws Governing the Construction and Operation of Transmission Facilities), and Regulation (EU) No 838/2010 on laying down guidelines relating to the inter-transmission system operator compensation mechanism and a common regulatory approach to transmission charging, imports and exports of electricity with other EU member states and European Economic Area (EEA) member countries is permitted through the use of interconnectors. Furthermore, the above legislation creates the EU internal energy market, a market across all EU member states and the EEA member countries where electricity can be traded without any technical or regulatory barriers.

The supply mix of electricity for the GB market in Q1 of 2019 was as follows:

  • coal 2.89 TWh/quarter;
  • oil 0.27;
  • gas 35.76;
  • nuclear 12.63;
  • hydro (natural flow) 1.72;
  • wind (onshore and offshore) and solar 20.52;
  • bioenergy 7.38;
  • pumped storage (net supply) -0.19;
  • other fuels 1.42; and
  • net imports (interconnectors) 6.05.

(Source: https://www.gov.uk/government/statistics/electricity-section-5-energy-trends)

Subject to 1.4 Principal Laws Governing the Sale of Power Industry Assets, there are no concentration limits in the UK.

Pursuant to the Competition Act 1998, the CMA is responsible for detecting anti-competitive behaviour and taking action to sanction such behaviour. Due to licence obligations with market participants, Ofgem has concurrent authority regarding specific anti-competitive behaviour, and the Enterprise and Regulatory Reform Act 2013 sets out certain co-operation measures between Ofgem and the CMA.

In parallel to the UK measures, both the European Commission and the CMA can enforce Articles 101 and 102 of the Treaty on the Functioning of the European Union (TFEU) on anti-competitive practices.

Under the Kyoto Protocol, the UK was required to reduce its greenhouse gas (GHG) emissions by 12.5% (below 1990 levels) in the period 2008-12, and signatories are required to cut GHG emissions by 18% by 2020 and by 20% in accordance with the EU climate and energy package.

The Climate Change Act of 2008 made the UK's voluntary national targets for the reduction of GHG emissions until 2050 legally binding. It provides a long-term framework for climate change policy in the UK, operating through a series of five-year carbon budget periods, which is designed to give businesses and individuals the certainty they need to invest in energy efficiency and low-carbon technologies. The Climate Change Act 2008 (Credit Limit) Order 2016 sets out the net amount of carbon units that may be credited to the net UK carbon account for the 2018-22 budgetary period.

As a current EU member state, the UK is part of the EU Emissions Trading System (EU ETS). It has therefore implemented Directive 2003/87/EC into the Greenhouse Gas Emissions Trading Scheme Regulations 2012 (GHG Regulations) and the Greenhouse Gas Emissions Trading Scheme (Amendment) and National Emissions Inventory Regulations 2005. Furthermore, the mechanism of the EU ETS is primarily regulated by a number of EU regulations that have direct applicability in the UK without requiring implementation into national law. The UK has additionally implemented the Carbon Price Floor as part of the EMR, which sets a floor for the emissions allowance price; ie, a minimum price companies must pay to pollute. This national measure aims to prevent low emissions allowances prices under the EU ETS from disincentivising companies from implementing decarbonisation measures. 

The UK's position on its relationship with the EU ETS post-Brexit currently remains subject to negotiation. One option is that the UK will establish a national emissions trading system that may in future be linked to the EU ETS, allowing for the cross-recognition of emissions reduction certificates.

The UK currently has eight coal power stations in operation. In 2015, former Secretary of State for Energy & Climate Change (the predecessor of the Secretary of State for Business, Energy and Industrial Strategy), the Rt Hon Amber Rudd MP announced the phase-out of all coal power plants in the UK by 2025.

Following on from this, in 2016 the UK government performed a consultation on the phase-out of coal stations. The 'Implementing the end of unabated coal by 2025: Government response to unabated coal closure consultation' was published in January 2018, formally setting out the government’s position.

The UK, Canada and over 20 other countries founded the 'Powering Past Coal Alliance' in 2017, the number of signatories to which had increased to 58 in early 2018. This sets out a commitment of governments, businesses and organisations to (i) phase out existing coal plants, (ii) prevent the construction and restrict the financing of new coal plants unless they use carbon capture and storage (CCS) technology, (iii) commit to running their operations without coal, and (iv) commit to supporting clean electricity generation through policies and investments.

The UK has implemented Directive 2009/28/EC on the promotion of the use of energy from renewable sources into a wide body of UK law. Under this implementation, a number of schemes have been developed to promote the use of alternative energy sources.

The Energy Act 2008 introduced the feed-in tariff, a fixed payment for electricity injected to the grid, to promote the development of small-scale electricity generators. The FiT is limited to specific renewable generators with a maximum capacity of 5 MW.

The Energy Act 2008 furthermore introduced the Renewable Heat Incentive (RHI), a payment system operating similarly to the FiT. This sets out a fixed payment for generators of renewable heat for domestic and non-domestic properties

The Renewables Obligation, implemented in England and Wales by the Renewables Obligation Order 2015 (as amended), imposes an obligation on electricity suppliers to procure a certain amount of renewable electricity as part of its fuel mixture each year, failing which they are subject to a financial penalty. Accredited UK-based renewable source electricity generators receive Renewables Obligation Certificates (ROCs) and suppliers may purchase these to demonstrate the fulfilment of their obligation. This allows the cost socialisation of renewable electricity financial support.

The Renewable Energy Guarantee of Origin (REGO) is a "guarantee of origin" (GoO) in the meaning of Directive 2009/28/EC. This has been implemented into the Electricity (Guarantees of Origin of Electricity Produced from Renewable Energy Sources) Regulations 2003 (as amended) and forms a key element of the fuel mix disclosure obligation under the Standard Conditions of the Electricity Supply Licence; ie, the labelling of renewable electricity supplied to end consumers. REGOs may be issued to accredited renewable source energy generators (even in parallel to ROCs), which may sell REGOs in parallel to the underlying electricity to suppliers for additional income.

The CfD scheme, introduced by the Energy Act 2013, is discussed in detail in 1.8 Unique Aspects of the Power Industry. It is not available to renewable generators that already receive support under the Renewables Obligation.

In the wider context, the EU Directive 2014/94 on the deployment of alternative fuels infrastructure (Alternative Fuels Infrastructure Directive) has been implemented into the Alternative Fuels Infrastructure Regulations 2017 and the Automated and Electric Vehicles Act 2018. This sets out specific standards for electric and hydrogen vehicle recharging/refuelling points and the framework to increase the number of recharging and refuelling points across the UK.

The position of the UK with respect to the Alternative Fuel Infrastructure Directive and alignment with related EU policy post-Brexit is unclear; however, given various commitments, the UK is likely to continue to align its policy. In 2015, the UK government reaffirmed its commitment for almost all cars and vans on UK roads to be zero emission by 2050.

https://www.gov.uk/government/news/uk-government-pledges-bold-ambition-for-electric-cars

This commitment has been reaffirmed in 2019; however, at the time of writing, pressure has been placed on the government to accelerate this to 2040 or 2030.

https://publications.parliament.uk/pa/cm201719/cmselect/cmbeis/1881/188102.htm

The Electricity Act 1989 is the principal act concerning generation assets, whereby Section 6(1)(a) places a licence obligation on any person that intends to generate electricity. The Utilities Act 2000 sets out that the Secretary of State may impose standard conditions of electricity generation licences, to which all UK generators must accede, subject to de minimis exemptions.

Section 14 of the Planning Act 2008 sets out that a "generating station" is a "nationally significant infrastructure project" (NGIP) and therefore "development consent" is required under Section 31 et seq, issued as a Development Consent Order (DCO).

EU Directive 2011/92/EU on the assessment of the effects of certain public and private projects on the environment (EIA Directive) is implemented as the Electricity Works (Environmental Impact Assessment) (England and Wales) Regulations 2017 (EIA Regulations). This requires that in making the application for a Section 36 consent, an environmental impact assessment (EIA) is required for the construction or extension of athermal generating station with a heat output of 300 MW or more (a Schedule 1 project). An EIA may be required by the local planning authority for the construction or extension of a generating station with a lower heat output (a Schedule 2 project).

The construction and operation of nuclear generating stations are primarily regulated by the Nuclear Installations Act 1965 and subsidiary regulations.

Under the Electricity (Applications for Licences, Modifications of an Area and Extensions and Restrictions of Licences) Regulations 2010, Ofgem has set out the application procedure for a generation licence.

For an electricity generation licence under the Electricity Act 1989, the applicant must submit a written application and fee to Ofgem. Following this, a notice of application must be submitted. A licence will then be granted or refused, or a request for further information may be made by Ofgem.

In parallel an application must be made to the relevant organisations in respect of the industry codes that must be complied with or become a party to the licence.

These industry codes include Elexon for the Balancing and Settlement Code (BSC), NGESO for the Connection Use of System Code (CUSC), Electralink for the Distribution Use of System Agreement (DCUSA), Gemserve for the Master Registration Agreement, NGESO for the Grid Code, the Energy Networks Association for the Distribution Code, NGESO for the System Operator – Transmission Operator Code (STC) and SECAS for the Smart Energy Code (SEC), as appropriate

Section 36 consent has five general steps: (i) pre-application stage, (ii) application stage, (iii) consideration of the application stage, (iv) determination of the application stage and (v) post-decision stage. This involves the identification of the location; establishment of contact with the Secretary of State, planning authorities and the local community; and submission of the application with an Environmental Statement (if required) to BEIS, and publishing it in the relevant media.

The planning authority may object, whereby the Secretary of State must call a public inquiry. The Secretary of State furthermore has discretionary power to call a public inquiry. Following the public inquiry, the Planning Inspector will present a report to the Ministers. If there is no public inquiry, the Ministers will decide upon the application. In the post-decision stage, the applicant must comply with granted consent and planning conditions in order to proceed.

The EIA is a five-step process.

  • Screening: the determination whether a project falls within the remit of the EIA Regulations and whether it may have a significant effect on the environment.
  • Scoping: the local planning authority determines the extent of issues to be considered in the EIA.
  • Preparing an Environmental Statement: should an EIA be required, the applicant must submit an Environmental Statement, to be prepared by experts, which includes relevant information to assess the project's environmental effects.
  • Planning application and consultation: the Environmental Statement and the application for development must be publicised and a consultation with stakeholders must be held.
  • Decision making: the Secretary of State or the local planning authority must review the application and Environmental Statement, and decide to grant or refuse the application, with the result being published.

The application for a DCO is conducted by the Planning Inspectorate in six steps.

  • Pre-application: prior to the application, the applicant must perform a consultation process with affected stakeholders.
  • Acceptance: the applicant submits the application to the Planning Inspectorate, which has 28 days to determine whether it meets the standards for examination.
  • Pre-examination: affected stakeholders may register their interest, and a preliminary meeting is held by an appointed Examining Authority. This usually takes approximately three months.
  • Examination: the Planning Inspectorate examines the application, whereby interested parties may provide more detail on their views. The Examining Authority will consider all relevant evidence to the matter, the process of which takes up to six months.
  • Decision: the Planning Inspectorate will present a report and recommendation to the Secretary of State within three months for final decision, which may take another three months.
  • Post-decision: the decision may be challenged by Judicial Review within a six-week period.

The Electricity Generation Licence: Standard Conditions set out the terms and conditions in the operation of generation facilities. This is divided into four sections: (A) interpretation, application and payments; (B) general; (C) supplementary standard conditions for Scotland; and (D) supplementary standard conditions for nuclear generators.

Section B sets out the following conditions concerning the operation of generation facilities:

  • compliance with grid code;
  • compliance with distribution codes;
  • security arrangements;
  • BSC and NETA implementation;
  • change co-ordination for BSC;
  • ancillary services;
  • change co-ordination for the Utilities Act 2000;
  • provision of information to the authority;
  • compulsory acquisition of land, etc;
  • other powers, etc;
  • regulatory accounts;
  • change of financial year;
  • financial information reporting;
  • prohibition of discrimination in selling electricity;
  • prohibition of cross-subsidies;
  • generating unit availability;
  • compliance with Connection and Use of System Code;
  • BETTA run-off arrangements scheme; and
  • transmission constraint licence condition.

(Source:www.ofgem.gov.uk/licences-industry-codes-and-standards)

There are no general eminent domain rights or similar for electricity generation facilities. However, Schedule 3 to the Electricity Act 1989 provides that the Secretary of State may authorise a licence holder to purchase compulsorily any land required for any purpose connected with the generation activities by means of a Compulsory Purchase Order. The generation licence holder may not dispose of the land or any part of it without the permission of Ofgem.

Whereas there are stringent requirements for the decommissioning of nuclear generating stations, there is no specific law concerning requirements for conventional thermal stations. Instead, this is set out more generally.

With respect to nuclear generating stations, there is a general requirement to return the site to an unrestricted and de-licensed condition, or to a state whereby the land may be used for suitable alternative uses. An EIA specifically for the decommissioning is required under the Nuclear Reactors (Environmental Impact Assessment for Decommissioning) Regulations 1999.

Nuclear decommissioning is co-ordinated by the ONR and NDA generally done in three stages.

  • Stage 1: the bulk of the radioactive material is removed from the facility.
  • Stage 2: contaminated parts of the station are dismantled and removed, or these are maintained in such a way to allow the radioactive material to decay.
  • Stage 3: the facility itself is dismantled and demolished, and the land and water are treated to meet an agreed end-state for future use.

Nuclear decommissioning is performed by NDA, acting through Site Licence Companies (SLCs), which hold the nuclear site licence, as granted by the ONR to operate the relevant nuclear sites. The SLCs are thereby tasked by NDA to decommission the sites, which do so under the continual oversight of NDA.

Requirements for thermal generating stations are broader than those for nuclear, whereby all waste and materials must be disposed without causing environmental damage, in accordance with general environmental protection legislation.

The Electricity Act 1989 is the key law that created the liberalised electricity market. This is supported with a body of primary legislation:

  • the Utilities Act 2000, which established GEMA and the predecessor of Ofgem;
  • the Climate Change and Sustainable Energy Act 2006; and
  • the Energy Acts 2004, 2008, 2010, 2011 and 2013.

The above generally allows for the implementation of energy policy over time, creating powers for the Secretary of State or another authority to enact secondary legislation, which are often very comprehensive in their scope and detail. The number of such statutory instruments is, however, too large to be summarised in a meaningful level of detail.

As an EU member state, the UK is subject to both EU directives and regulations. The most significant directive with respect to transmission system operation is Directive 2009/72/EC concerning common rules for the internal market in electricity, which has been implemented into the above national legislation.

Regulations have direct application and do not need to be implemented into UK law. The most relevant is Regulation (EC) No 714/2009 on conditions for access to the network for cross-border exchanges in electricity (Electricity Access Regulation), which established the legislative framework for the following network codes, technical rules designed to establish harmonisation of standards across the EU:

  • Commission Regulation (EU) 2015/1222, establishing a guideline on capacity allocation and congestion management (NC CACM);
  • Commission Regulation (EU) 2016/1388, establishing a network code on Demand Connection (NC DC);
  • Commission Regulation (EU) 2016/1719, establishing a guideline on forward capacity allocation (NC FCA);
  • Commission Regulation (EU) 2017/1485, establishing a guideline on electricity transmission system operation;
  • Commission Regulation (EU) 2017/2195, establishing a guideline on electricity balancing (NC BAL); and
  • Commission Regulation (EU) 2017/2196, establishing a network code on emergency and restoration (NC ER).

Section 37 of the Electricity Act 1989 sets out that consent is required for the installation and operation of overhead lines of longer than 2 km with a nominal voltage of 132 kV or higher. Section 14 of the Planning Act 2008 goes beyond this, setting out that "electric lines above ground" with a nominal voltage of 132 kV are an NGIP, and therefore a DCO is required for their construction. The Town and Country Planning Act 1990 is applicable for associated works to the construction of transmission lines.

The EIA Regulations sets out that for a Section 37 consent, an EIA is required for the construction or extension of an electric line installed above ground with a voltage of 220 kV or more and a length of over 15 km (a Schedule 1 project). An EIA may, however, be required by the local planning authority for the construction or extension of an above-ground overhead line with a voltage of over 132 kV in a sensitive area (a Schedule 2 project).

Under the Electricity (Applications for Licences, Modifications of an Area and Extensions and Restrictions of Licences) Regulations 2010, Ofgem has set out the application procedure for a transmission licence.

For an electricity transmission licence under the Electricity Act 1989, the applicant must submit a written application and fee to Ofgem. Following this, a notice of application must be submitted. A licence will then be granted or refused, or a request for further information may be made by Ofgem.

In parallel an application must be made to the relevant organisations in respect of the industry codes that must be complied with or become a party to under the licence.

These industry codes include Elexon for the Balancing and Settlement Code, NGESO for the Connection Use of System Code, Electralink for the Distribution Use of System Agreement, Gemserve for the Master Registration Agreement, NGESO for the Grid Code, the Energy Networks Association for the Distribution Code, and NGESO for the System Operator – Transmission Operator Code as appropriate.

The Section 37 consent is submitted to the Secretary of State, whereby the local planning authority is responsible for consulting with the local community and other stakeholders. The Secretary of State will decide whether to grant or refuse the application on the basis of the application itself, as well as the evidence from the consultation.

The EIA and DCO are applied for in the same manner as in 4.2 Regulatory Process for Obtaining All Approvals to Construct and Operate Generation Facilities.

The Electricity Transmission Standard Licence Conditions is divided into five sections: (A) interpretation, application and payments; (B) general; (C) system operator standard conditions; (D) transmission owner standard conditions; and (E) offshore transmission owner standard conditions.

General Conditions

The general conditions include provisions on:

  • regulatory accounts;
  • disposal of relevant assets and restrictions on charges over receivables;
  • provision of information to Ofgem;
  • prohibition of cross-subsidies;
  • restriction on activity and financial ring-fencing;
  • availability of resources;
  • undertaking from ultimate controller;
  • indebtedness;
  • credit rating;
  • security arrangements;
  • system operator – transmission owner code;
  • BETTA implementation;
  • BETTA run-off arrangements scheme;
  • regulatory instructions and guidance;
  • offshore transmission owner of last resort;
  • connect and manage implementation;
  • regional co-operation;
  • notification of changes that may affect eligibility for certification;
  • requirement for sufficiently independent directors; and
  • data assurance requirements.

System Operation Conditions

The system operation standard conditions include provisions on:

  • prohibited activities;
  • the BSC;
  • transmission licence standard conditions;
  • charges for use of system;
  • use of system-charging methodology;
  • use of system-charging requirements under the Electricity Directive;
  • connection-charging methodology;
  • connection-charging requirements under the Electricity Directive;
  • prohibition on discriminating between users;
  • requirement to offer terms;
  • functions of Ofgem;
  • CUSC;
  • production of information about the national electricity transmission system;
  • limits on the level to which transmission services are provided;
  • adjustments to use of system charges (small generators);
  • grid code;
  • compliance with distribution codes;
  • procurement and use of balancing services;
  • transmission system security standard and quality of service;
  • requirement to offer terms for connection or use of the UK transmission system during the transition period;
  • assistance for areas with high distribution costs scheme – restriction on revenue;
  • assistance for areas with high distribution costs scheme – payments from authorised suppliers;
  • assistance for areas with high distribution costs scheme – payments to a relevant distributor;
  • assistance for areas with high distribution costs scheme – annual statement;
  • energy administration and energy supply company administration – national electricity transmission system operator shortfall contribution obligations;
  • provision of information and assistance to the authority in relation to applications requiring the appointment of an offshore transmission owner;
  • requirements of a connect and manage connection; and
  • the network options assessment process and reporting requirements.

Transmission Owner Conditions

The transmission owner standard conditions include provisions on:

  • interpretation of Section D;
  • obligation to provide transmission services;
  • transmission system security standard and quality of service;
  • obligations in relation to offers for connection, etc;
  • functions of the authority;
  • prohibition on engaging in preferential or discriminatory behaviour;
  • prohibition on selling electricity;
  • Scottish settlement agreement;
  • obligations relating to the preparation of TO offers during the transition period; and
  • requirements of a connect and manage connection.

Offshore Transmission Owner Conditions

The offshore transmission owner standard conditions include provisions on:

  • interpretation of Section E;
  • regulatory accounts;
  • change of financial year;
  • disposal of relevant assets;
  • provision of information to the authority;
  • prohibition of cross-subsidies;
  • restriction on activity and financial ring-fencing;
  • availability of resources;
  • undertaking from ultimate controller;
  • indebtedness;
  • credit rating of licensee;
  • system operator – transmission owner code;
  • obligation to provide transmission services;
  • transmission system security standard and quality of service;
  • obligations in relation to offers for connection, etc;
  • functions of the authority;
  • prohibition on engaging in preferential or discriminatory behaviour;
  • prohibition on selling electricity;
  • offshore transmission owner of last resort;
  • general provisions on disclosure of information;
  • notification of changes that may affect eligibility for certification; and
  • regional co-operation.

NETS Operator Conditions

As NETS operator, NGESO is additionally subject to special conditions, which go beyond the standard conditions. These are grouped into nine chapters:

  • definitions;
  • general obligations;
  • transmission – revenue restriction;
  • system operation – revenue restriction;
  • price control financial instruments;
  • annual iteration process – adjustments to the transmission network revenue restriction;
  • annual iteration process – adjustments to the system operator revenue;
  • other revenue restriction related conditions; and
  • schedules.

The licence conditions can be found at: www.ofgem.gov.uk/licences-industry-codes-and-standards.

There is no general eminent domain rights or similar for electricity transmission facilities. However, Schedule 3 to the Electricity Act 1989 provides that the Secretary of State may authorise a licence holder to purchase compulsorily any land required for any purpose connected with the transmission activities by means of a Compulsory Purchase Order. The transmission licence holder may not dispose of the land or any part of it without the permission of Ofgem.

Under the Planning Act 2008, the construction of transmission lines requires a DCO from the Planning Inspectorate, which provides for associated land rights. The consent process requires the developer to undertake several steps to identify and consult with any stakeholders with an interest in land potentially affected by the route. Once the routing has been established, the developer enters into an agreement to grant an easement with any landowners, tenants or mortgagees, whereby the developer may make entry onto the land following the grant of a DCO.

Such easement is permanent so that, once executed, landowners, tenants or mortgagees cannot negatively affect the transmission infrastructure. Affected stakeholders would be paid compensation, including with respect to the easement, injurious affection, survey and investigation works, land acquisition and agents fees.

The Electricity Act 1989 authorised Ofgem to select a single UK NETS system operator, the role of which was recently transferred to NGESO. As noted above, in the UK there are three transmission system owners – NGET, SHE-T and SPT – as well as various OFTOs.

The provision of transmission service is primarily governed by the Electricity Transmission Standard Licence Conditions, and regulation of transmission charges is governed by CUSC, in particular (i) Part II of Section 2 regarding connection charges, and (ii) Part II of Section 3 regarding use of system charges. In the latter, Part IIB sets out transmission network use of system (TNUoS) charges and Part IIC sets out balancing services use of system charges (BSUoS).

The TNUoS charges are designed to recover maintenance and developmental costs of common infrastructure parts of the transmission system owners (NGET, SHE-T, SPT and OFTOs), whereas single user asset costs are recovered directly. TNUoS tariffs are calculated in accordance with the methodology in Part IIB of Section 3 of the CUSC and are published on an annual basis every January 1st, taking effect on April 1st of the same year.

The BSUoS charges are designed to recover costs of balancing the NETS, and BNUoS tariffs are calculated in accordance with Part IIC of Section 3 of the CUSC.

Connection charges are designed to recover the costs of installing and maintaining connection assets used to connect to the NETS. Connection tariffs are calculated in accordance with Section 2 of the CUSC.

Taking effect as of 1 April 2013, the RIIO-T1 (Revenue = Incentives + Innovation + Outputs) transmission price control regime has been in place and will remain in force until 31 March 2021. RIIO-T1 is designed to ensure effective and efficient electricity delivery for consumers, and places emphases on innovation to promote the development of a smarter electricity network. NGET is currently developing the RIIO-T2 regime which will cover 2021 to 2026, and NGET expects to submit the final proposal to Ofgem by the end of 2019.

The Electricity Access Regulation and EU network codes CACM and FCA set out that transmission systems must be operated on an open access and non-discriminatory basis. These principles are echoed in UK national law, in particular in Condition C7 of the Electricity Transmission Standard Licence Conditions (Prohibition on discriminating between users). This provision relates to the connection to and use of the system, and to the application of charges.

The Electricity Act 1989 is the key law that created the liberalised electricity market. This is supported with a body of primary legislation:

  • the Utilities Act 2000, which established GEMA and the predecessor of Ofgem;
  • the Climate Change and Sustainable Energy Act 2006; and
  • the Energy Acts 2004, 2008, 2010, 2011 and 2013.

The Planning Act 2008, Section 37 of the Electricity Act 1989, the Overhead Lines (Exemption) (England and Wales) Regulations 2009 and the EIA Regulations apply to the construction and operation of electricity distribution facilities.

Under the Electricity (Applications for Licences, Modifications of an Area and Extensions and Restrictions of Licences) Regulations 2010, Ofgem has set out the application procedure for a distribution licence.

For an electricity distribution licence under the Electricity Act 1989, the applicant must submit a written application and fee to Ofgem. Following this, a notice of application must be submitted. A licence will then be granted or refused, or a request for further information may be made by Ofgem.

In parallel an application must be made to the relevant organisations in respect of the industry codes that must be complied with or become a party to under the licence.

These include Elexon for the Balancing and Settlement Code, NGESO for the Connection Use of System Code, Electralink for the Distribution Use of System Agreement, Gemserve for the Master Registration Agreement, NGESO for the Grid Code, the Energy Networks Association for the Distribution Code, NGESO for the System Operator – Transmission Operator Code, and SECAS for the Smart Energy Code, as appropriate.

The Section 37 consent is submitted to the Secretary of State, whereby the local planning authority is responsible for consulting with the local community and other stakeholders. The Secretary of State will decide whether to grant or refuse the application on the basis of the application itself, as well as the evidence from the consultation.

The standard conditions of the Electricity Distribution Licence contains 12 chapters:

  • interpretation and application;
  • general obligations and arrangements (specifically no abuse of the licensee’s special position, licensee’s payments to the authority, provision of information to the authority, smart metering systems and provision of information to the Secretary of State, determinations by the authority);
  • public service requirements (specifically safety and security of supplies enquiry service, arrangements for access to premises, special services, smart metering – matters relating to obtaining and using consumption data, reporting on performance);
  • arrangements for the provision of services (specifically requirement to offer terms for use of system and connection, charging methodologies for use of system and connection, common distribution-charging methodology, EHV distribution-charging methodology, recovery of reinforcement costs arising in respect of relevant customers, charges for use of system and connection, standards for the provision of non-contestable connection services, connection policy and connection performance, requirement to offer terms for the connection of metering equipment, requirement to offer terms for the provision of metering point administration services, provision of and charges for metering point administration services, prohibition of discrimination under Chapters 4 and 5);
  • industry codes and agreements (specifically compliance with core industry documents, the distribution code, the smart energy code, distribution connection and use of system agreement, governance and change control arrangements for relevant charging methodologies, master registration agreement);
  • integrity and development of the network (specifically distribution system planning standard and quality of performance reporting, long-term development statement, distributed generation: connections guide and information strategy, disposal of relevant assets and restrictions on charges over receivables, theft, damage and meter interference, and application of statutory powers);
  • financial and ring-fencing arrangements (specifically restriction of activity and financial ring-fencing of the distribution business, availability of resources, undertaking from ultimate controller, accounts, independence of confidential information and appointment of compliance officer);
  • application and interpretation of Section B;
  • requirements within the distribution services area (specifically requirement to offer terms for the provision of legacy metering equipment, requirement to offer terms for the provision of data services, charges for the provision of legacy metering equipment and data services, provision of the data transfer service, treatment of payment claims for last-resort supply, and prohibition of discrimination under Chapter 9);
  • credit rating and restriction of indebtedness (specifically credit rating of the licensee, restriction of indebtedness and transfers of funds);
  • independence of the distribution business (specifically independence of the distribution business and restricted use of confidential information, appointment of compliance officer, and requirement for sufficiently independent directors); and
  • provision of regulatory information (specifically regulatory accounts, data assurance requirements, regulatory instructions and guidance, environment reporting, the innovation strategy, electricity distribution losses management obligation and distribution losses strategy, business plan commitment reporting, network asset indices methodology, and competition in connection code of practice).

There are no general eminent domain rights or similar for electricity distribution facilities. However, Schedule 3 to the Electricity Act 1989 provides that the Secretary of State may authorise a licence holder to purchase compulsorily any land required for any purpose connected with the distribution activities by means of a Compulsory Purchase Order. The distribution licence holder may not dispose of the land or any part of it without the permission of Ofgem.

Similar to the transmission system, rights to install and maintain distribution infrastructure on privately owned land include a wayleave agreement or an easement, and a transfer or lease for substation equipment.

There are no monopoly rights under law; however, due to the natural monopoly offered by the infrastructure, the entry into the market of distribution network operators (DNOs) is uncommon. Nevertheless, there are a number of infrastructure projects that are classified as either independent distribution network operators (IDNO), which relate to small-scale networks for residential or commercial projects of which 13 are currently licensed in GB, or licence-exempt private networks.

The Electricity Act 1989 and the standard conditions of the Electricity Distribution Licence, specifically Chapter 4 (Arrangements for the provision of services), comprise the regulatory regime for the provision of electricity distribution, regulation of charges and the terms of service.

The Distributed Use of System (DUoS) charges are designed to recover installation and maintenance costs of the local distribution networks operators. The 14 DNOs set the DUoS individually for their own networks and these are time-banded for different times of the day, subject to demand, whereby the prices are lower at times of lower demand and higher at times of higher demand.

Similarly to transmission, a price control regime is in place for DSOs, which is currently RIIO-ED1. This is based on the RIIO-T1 model and is in force until 31 March 2023.

Distribution terms of service are set out in the standard conditions of the Electricity Distribution Licence.

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