BRIEFING PAPER Number 8472, 8 January 2019

By Suzanna Hinson

Electricity Grids

Contents: 1. Background 2. Electricity Trading 3. Balancing the Grid 4. Changing grids 5. Smart Grids 6. Government policy on grids 7. Additional political views on grid issues

www.parliament.uk/commons-library | intranet.parliament.uk/commons-library | [email protected] | @commonslibrary 2 Electricity Grids

Contents

Summary 3 Glossary 4 1. Background 7 1.1 The GB Electricity Grid 7 The Transmission Network 7 The Distribution Network 8 1.2 Ofgem 9 Price Controls on the Network Owners 9 1.3 Grids in Europe 10 2. Electricity Trading 12 2.1 Structure of the Market 12 2.2 How Trading Works 12 3. Balancing the Grid 14 3.1 Balancing services 15 Inertia 16 3.2 Constraint Payments and Curtailment 16 3.3 Capacity margins and market 17 4. Changing grids 19 4.1 The changing electricity mix 19 4.2 Embedded generation 19 4.3 Future balancing 21 4.4 Renewable integration costs 22 4.5 The DNO-DSO Transition 24 5. Smart Grids 25 5.1 Smart Meters 25 5.2 Time of Use Tariffs 26 5.3 Electric Vehicles 26 5.4 Blockchain trading 27 6. Government policy on grids 29 6.1 Flexible grids 29 6.2 The Helm Review 29 Government Response – Greg Clark’s speech 31 7. Additional political views on grid issues 32 7.1 Nationalisation 32 7.2 Network costs 32

Contributing Authors: Paul Bolton

Cover page image copyright: National Grid (Image cropped)

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Summary

This briefing introduces the electricity grid in Great Britain, how it is operated and balanced, and how it may change to meet future energy needs. The grid The electricity grid is a network of wires that connect electricity generators and consumers. The GB grid is formed of two networks: the high voltage transmission network, that connects large power stations to substations with the lower voltage distribution network, that connects to consumers and also integrates smaller power generators. The GB grid is owned by a series of transmission and distribution network operators, all monopolies of specific areas, and covers England, Scotland and Wales. There are electricity interconnectors to the island of Ireland, and to mainland Europe, allowing electricity to be traded on a continental scale grid. Energy trading Electricity is traded from years in advance to an hour in advance of when it is consumed. Energy suppliers, such as the ‘Big Six’, purchase electricity from generators and sell to consumers. There are also third-party traders buying and selling electricity. Bills for consumers include the overall wholesale costs of electricity as well as the costs of using the grid (known as network costs), policy costs (such as energy subsidies), operational costs and supplier profits. Balancing the grid Electricity supply and demand must be balanced to ensure they match at all times. If there is a deficit of electricity, there may be power cuts; if there is a surplus of electricity, the frequency on the grid may rise and appliances consuming electricity can be damaged. National Grid is the transmission system operator, ensuring the transmission grid remains balanced at all times. Energy suppliers undertake extensive forecasting to purchase sufficient power to cover their predicted supply. In addition to this forecasting, there are a series of mechanisms which National Grid can utilise to ensure the grid remains balanced. As more small generators, such as renewables, connect to the distribution grid, there is an increasing role for distribution system operators to balance the distribution grid. The future of the grid Historically power was supplied by a small number of large power stations, such as coal or nuclear. Increasingly, there are a greater number of generators, including smaller scale and domestic generation, and a greater diversity of generation technology, such as renewables, that are introducing more variability in supply. The need to balance both varying demand, and now more varying supply, is an ongoing challenge for system operators. Increasingly, the grid is transforming to be more flexible, capitalising on smart appliances, and integrating new technologies such as electric vehicles and battery storage. Policy As the grid evolves and new technologies emerge, numerous consultations and reports have been conducted on the future of the grid. In November 2018, the Secretary of State Greg Clark made a speech about the future of the energy market, announcing several policy plans, some of which will impact the future operation of the GB electric grid. The Labour party support the renationalisation of grid infrastructure. Other parties have made calls for additional reforms, such as changes to network charges.

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Glossary

• Balancing: The process of ensuring supply meets demand at all times on the grid. If supply and demand do not meet, there is a risk of power cuts or a change in the frequency of the grid, which can damage appliances using electricity. • Balancing Mechanism: a tool that National Grid, the system operator, use to ensure electricity supply meets demand at all times. It involves generators and consumers changing their respective output and consumption. • Baseload power: the permanent minimum load that a power system is required to deliver. Historically supplied by fossil fuels and nuclear which are sometimes described as “continuous power” (though all generators are prone to outages). • Block chain trading: a novel form of digital technology based on a database of linked ‘blocks’ of data. The technology has many applications in different sectors and in energy could offer a new form of trading. • Capacity: the maximum electricity output of an electricity generator (in Watts). For example, the projected capacity of the Hinkley Point C nuclear power plant is approximately 3.2 Giga Watts (GW). The infrastructure of the grid also has a capacity meaning the maximum Watts any specific wire connection can transport. • Capacity Margin: the excess of installed capacity over peak demand. • Capacity Market: a Government policy created as part of the Electricity Market Reform in the Energy Act 2013. The market involves a competitive auction and successful bidders are paid to provide extra capacity to the grid if necessary. • Curtailment/Constraint: when in times of high demand, generators can be removed from the grid to help balancing or prevent electricity congestion in one area. Renewables can be paid ‘constraint payments’ when they are removed. • Demand side response: to help balance the grid at times of peak demand, consumers can reduce their consumption of electricity. This is usually large consumers who are paid for reducing consumption, but time of use tariffs mean domestic consumers may also be able to engage with demand side response. • Distribution Network: the lower voltage network that connects substations with the transmission network to consumers, and also includes smaller generators. • Distribution Network Operator (DNO): owners of the distribution network infrastructure. There are 14 DNOs each operating in specific regions. • Distribution System Operator (DSO): the role of DNOs are transforming to have a greater emphasis on operation. Small scale generation is making the supply and demand on the distribution network more complicated, requiring the DSO to act as an operator to balance the grid. This is similar to the work of National Grid System Operator on the transmission network. • Embedded generators/generation: power generators that connect directly to the distribution network rather than the transmission network. These are mainly renewables and are smaller generators than those on the transmission network. • Embedded benefits: connecting directly to the distribution network can give embedded generators advantages over transmission connected generators as they may not pay charges relating to the use of the transmission system. • Gate Closure: the time when trading of electricity stops; one hour before the ‘Settlement period’ when the electricity will be supplied.

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• Generation/generators (also referred to as supply): power plants produce electricity. This is known as generation and the power plants are sometimes referred to as generators. • Grid (also referred to as network): the infrastructure of wires that connects generators of power to consumers. See also Transmission and Distribution. • Internal Energy Market (IEM): the European Union (EU) energy market allows tariff free trading of energy across Europe. This future of the UK within the IEM will be decided as part of the Brexit negotiations. For more information, see the Library briefing on Brexit: Energy and Climate Change. • National Grid: Owner of the transmission system in England and Wales and operator of the transmission system in GB since privatisation of the energy system. Now legally separated into (owner) and National Grid System Operator (SO – operator). • Ofgem: the energy regulator. • Offshore Transmission Owner (OFTO): The transmission network for offshore wind is owned by an offshore transmission owner (OFTO). When new transmission infrastructure for a development, such as an offshore wind farm is built by the developer, an OFTO is competitively appointed by Ofgem through a tender process. • Peak load power: the maximum electricity demand. (see also Baseload power) • Renewable penetration: the proportion of power on the grid supplied by renewable generators. Expressed as a percentage. • RIIO (Revenue = Incentives+Innovation+Outputs): price controls on the owners of the grid infrastructure as they are monopolies. Managed by Ofgem and reviewed every eight years. • Settlement Period: half hourly periods of electricity supply. Electricity is traded through 48 settlement periods in each day. • Significant Code Review (SCR): Ofgem undertakes SCRs when changing the codes in the licence conditions that energy companies abide by. • Single Electricity Market (SEM)/ Integrated Single Electricity Market (I-SEM): the island of Ireland operates a Single electricity market (SEM) which allows free trading of electricity across the island. A new Integrated Single Electricity Market (I- SEM), designed closely around the rules of the IEM, was launched in 2018. • Smart Devices: machinery or appliances that can be set to operate when electricity is cheaper (and therefore demand is lower) to save consumers money and help reduce peak demand pressures. • Smart Meter: the next generation of energy meter that offers a range of advanced functions, including half-hourly metering. (See the Library briefing paper on Energy Smart Meters for more information). • System Integration Costs (of renewables): assumed extra costs of ensuring the grid remains balanced with renewable technologies. • Trading markets: Energy is traded in markets of different time frames. The Forward market is years down to two days ahead of consumption, the Day-ahead, is one day ahead of consumption, the Intraday is within a day to an hour ahead of consumption, and Balancing is from one hour ahead to the time of consumption. • Transmission Network: the high voltage network that connects large electricity generators to substations with the distribution network.

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• Transmission Network Owner: National Grid in England and Wales and SP Energy Networks and Scottish and Southern Electricity Networks in Scotland. These companies own the infrastructure of the transmission network. • Transmission System Operator (SO): National Grid in England, Scotland and Wales. National Grid manages the transmission system to ensure the grid remains balanced and supply always meets demand. • Trilemma: the three-branched energy policy: security of supply, affordable energy bills, and decarbonisation. At the end of 2018, the Government said that the trilemma was ending, as low carbon power was now also low cost power. • Vehicle to Grid (V2G): technology for electric vehicles to be used as battery storage and supply power to the grid at times of high demand to help balancing.

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1. Background

Th GB electricity grid1 (referred to in this briefing as ‘the grid’) is the medium across which power is transported from generators to consumers across England, Wales and Scotland (see Figure below).

1.1 The GB Electricity Grid Having previously been a nationalised industry under the Central Electricity Generating Board, the Electricity Act 1989 provided for the privatisation of the energy industry. Generation was transferred to three companies (PowerGen, National Power, and Nuclear Electric) and the transmission grid ownership and operation passed to National Grid. The former nationalised Area Boards on the distribution network cover the same geographical areas as the now privatised distribution network owners. Due to conflict of interest concerns, National Grid has since undergone a legal separation into National Grid plc who own the infrastructure, and National Grid SO who operate the infrastructure (see Box 1 for details). For more information, see the Library briefing paper on Public ownership of industries and services. Today, power is distributed across the grid through two networks as shown in the figure below, the transmission network and the distribution network.

Source: Provided to the Library by National Grid and reproduced with permission. The Transmission Network The transmission network is made up of the high voltage cables around GB which connect large scale generators to substations with the distribution network. Historically, power stations were often located away from large populations for practical reasons such as avoiding pollution, which led to the need for extensive transit infrastructure.

1 This briefing does not cover the gas grid.

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Transmission Network Owner The transmission network in England and Wales is owned and maintained by National Grid plc. The transmission network in Southern Scotland is owned and maintained by SP Energy Networks2, and in northern Scotland by Scottish and Southern Electricity Networks.3 These Scottish companies also own the distribution networks in their areas. The transmission network for offshore wind is owned by an offshore transmission owner (OFTO). When new transmission infrastructure for a development, such as an offshore wind farm is built by the developer, an OFTO is competitively appointed by Ofgem through a tender process.4 Transmission System Operator The transmission network is managed across all of England, Scotland, and Wales by National Grid System Operator (SO). As the system operator, National Grid SO is legally required to manage the transmission network, ensuring there is enough supply to meet the distribution networks’ demand at all times, and planning for future balancing.

Box 1: National Grid: Legal Separation National Grid has three parts to its portfolio: the transmission network owner (for both the electricity and gas grids), the GB transmission system operator (SO), and National Grid ventures (which has a commercial role in Liquefied Natural Gas (LNG), metering, US electricity grids and GB interconnectors.)5 Due to potential conflicts of interest between the owner and operation roles, National Grid has been required by Ofgem and the Government to legally separate the electricity system operator role from its commercial aspects.6 The legal separation will complete in April 2019.

The Distribution Network The distribution network is the lower voltage infrastructure transporting power from a substation on the transmission network to consumers. The distribution network also increasingly has small scale generators, known as embedded generators, connected directly to it rather than to the transmission network (see Section 4.2). Distribution Network Operators A Distribution Network Operator (DNO) is a company licensed to distribute electricity. They own and maintain cables in their operation areas. They do not sell electricity, though energy suppliers do pay them for the use of the cables. This fee, when combined with losses and the costs of using the transmission network, is the network costs element of a bill (see Box 2).

2 SP Energy Networks own the transmission infrastructure in southern Scotland as well as the distribution infrastructure in the same area and the distribution infrastructure in North Wales. 3 Scottish and Southern Electricity Networks own the transmission infrastructure in northern Scotland as well as the distribution infrastructure in the same area and the distribution infrastructure in central, southern England (see DNO map below.) 4 Ofgem, Offshore transmission factsheet, 17 March 2014 5 National Grid Group, National Grid Ventures FAQ (accessed 8 January 2019) 6 Ofgem, Ofgem confirms plans for greater separation of National Grid’s electricity system operator role, 3 August 2017

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There are 14 DNOs, which correspond to distinct geographical areas (see map below – some of these areas contain multiple DNOs owned by the same group). Although each Distribution Network is a separate geographical area, they aren’t separate electrical systems. This means electricity can flow between areas, and metering is placed at the boundaries of the areas so that these volumes can be measured. As a result of increasing demands for balancing renewable generators connected directly to the distribution network (known as embedded generation) DNOs are taking on more operational and balancing roles, transforming them to Distribution System Operators (DSO). This is known as the DNO-DSO transition and is discussed in Section 4.3.

Source: Reproduced with permission from the Energy Networks Association, Electricity Distribution Map

1.2 Ofgem The generation, transmission and supply of electricity is regulated and licensed.7 Unless authorised to do so by a licence or exemption, it is an offence to generate, transmit, distribute, or supply electricity (Section 4, Electricity Act 1989 (as amended)).8 Ofgem is the regulator for the energy market. This includes regulating the grid. As the companies that own the transmission and distribution networks are monopolies, Ofgem enforces price controls to protect customers from overcharging, although some argue these controls are not strict enough. Price Controls on the Network Owners All network owners are subject to price controls by Ofgem. This is because they are monopolies. These controls are known as RIIO-T1 for electricity transmission and RIIO-ED1 for electricity distribution. RIIO stands for Revenue = Incentives+Innovation+Outputs.9 The controls cap

7 Licences, Ofgem (accessed 8 January 2019) 8 Licences, Ofgem (accessed 8 January 2019) 9 Ofgem, RIIO – a new way to regulate energy networks, 4 October 2010

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the maximum revenue that can be collected from customers. The cap is reviewed every 8 years and is incentive based, meaning companies get penalties for exceeding the price cap and incentives for remaining under the cap. As much of the infrastructure is old, Ofgem have been allowing a managed increase in network costs to upgrade the system.10 The current price controls for network companies will end between 2021 and 2023. RIIO-2 is a new set of arrangements that will apply to limit the revenue network companies can recover from consumers (see section 7.2 for more information).

Box 2: Network cost to consumer bills Network operators charge generators and suppliers for the use of the transmission and distribution grid infrastructure. This cost is passed on to consumers as a “network” cost in their energy bills. This fee includes the cost of using the infrastructure, plus losses in physically transporting the energy though the wires. According to Ofgem, as of April 2016 a standard dual fuel bill based on typical consumption is around £1,070 a year. Of this, around £265 pays for the network costs a supplier is charged by the transmission and distribution companies.11 More information on energy bills is available in the Library Briefing Paper on Energy Bills and Proposals for Reform. There has been debate about the fairness of network charges, including for rural customers (who tend to pay more as more infrastructure is required to transport the electricity) and to address the increase of on-site renewables which are less reliant on grid infrastructure. Ofgem are consulting on changes to network costs, see Section 7.2 for details.

1.3 Grids in Europe The GB grid interacts with grids on mainland Europe through interconnectors. Interconnectors are undersea cables that link the transmission network of Great Britain with that of mainland Europe and the island of Ireland. There are two interconnectors connecting Great Britain to Europe and more planned or under construction. These are shown in the Figure below (from National Grid). There are also existing and planned interconnectors between GB and the island of Ireland.

Source: Provided to the Library by National Grid and reproduced with permission.

10 Ofgem, How the energy networks work for you (accessed 8 January 2019) 11 Ofgem, How the energy networks work for you (accessed 8 January 2019)

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Interconnectors help to increase the flexibility of all the participating energy systems and can also help to increase energy security by allowing access to a wider market of more diverse sources of power.12 Further information on interconnectors is available from the Parliamentary Office of Science and Technology (POST) in POSTnote569 on Overseas Electricity Interconnection. Although power from interconnectors can flow in both directions, the UK is a net importer of about 5% of its annual electricity demand.13 This has resulted in lower wholesale prices because power in interconnectors automatically flows to the country with higher prices meaning the UK usually imports cheaper power from Europe. The interconnector trade is harmonised because, as a member of the European Union, the UK is also a member of the Internal Energy Market (IEM) which allows market coupling mechanisms to make trading more efficient. The future of this relationship will be decided as part of the Brexit negotiations. For more information see the Library briefing paper on Brexit: Energy and Climate Change.

12 Department of Energy and Climate Change, More interconnection: improving energy security and lowering bills, December 2013 13 Department for Business, Energy and Industrial Strategy, Digest of UK Energy Statistics 2017, p.111.

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2. Electricity Trading

The supply and generation of British electricity was privatised through the Electricity Act 1989. This provided the framework for the restructuring and privatisation of the electricity supply industry in England, Wales and Scotland together with the establishment of industry regulation through the Office of Electricity Regulation (Offer). The Gas Act 1986 privatised the British Gas Corporation and established the industry regulator, the Office of Gas regulation (Ofgas).14 The energy market then entered a period of liberalisation with new suppliers emerging and competition between suppliers developing.

2.1 Structure of the Market In addition to the network companies, the energy market has three main actors: • generators who produce electricity; • suppliers who buy generators’ electricity and sell it to consumers (e.g. British Gas etc), and; • end customers or consumers (domestic or commercial). The energy market is separated into a wholesale and a retail market: • The wholesale market is the market for the sale and purchase of electricity between generators and suppliers. Suppliers buy the electricity they require to meet their expected customer’s needs. This is a competitive market, so suppliers can choose generators and wholesale prices of electricity can vary between trades. • The retail market is the market for the sale and purchase of electricity between consumers and suppliers. Consumers can choose their supplier through switching in the competitive energy market where a wide variety of tariffs at different prices are available.

Source: Reproduced with permission from Elexon, The Electricity Trading Arrangements

2.2 How Trading Works Trading electricity is managed in half-hourly segments known as “Settlement periods”. Each day has 48 half-hourly settlement periods. Power is traded to meet these periods from up to a year ahead of

14 For more details on the privatisation of British industries, see the House of Commons Library briefing paper on Privatisation

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delivery (in the ‘forward market’), to the ‘day-ahead’, to between an hour and a day ahead (in the ‘intra-day’ market). All trading ends an hour before each settlement period is due to start, known as ‘Gate Closure’. Suppliers forecast in advance what their customers’ electricity requirements will be. Suppliers then ensure they buy the expected amount from generators to manage supply and demand for their customers. Any discrepancies between power bought and delivered in settlement periods and actual demand are managed through National Grid’s balancing services (see Section 3). At the end of settlement periods, Elexon (the Balance and Settlement Code Company who ensure payments and charges for balancing and settlements are accurately distributed) calculates the imbalance prices – the difference between contracted supply and what was actually required - and ensures the costs are distributed to those in the market who have either under or over contracted power.15

15 Elexon, The Electricity Trading Arrangements, 2 November 2017

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3. Balancing the Grid

Trading arrangements mean that predicted demand is met with purchased supply but to ensure actual demand is met with adequate supply, National Grid SO employs balancing services. If supply and demand do not match, there is a risk of a loss of power to parts of the network but also a change in the network frequency (a physical property of the electrical flow). If there is oversupply, the frequency will increase and if there is not enough supply, the frequency will decrease. National Grid have an obligation to keep frequency within 1% variation of its target value of 50 Hertz.16 If frequency strays outside this range machinery and appliances that operate on the network are prone to damage as the appliances will be designed to operate at a certain frequency. It is therefore essential that National Grid manage the flow of electricity through the grid. This is shown in the figure below17 depicting a typical day with the orange line showing traded agreements, and the white line showing actual demand (both in MW).

Source: Provided to the Library by National Grid and reproduced with permission. National Grid publishes data on the frequency through the grid for each second of the day. There were no instances when the frequency was more than 1% away from 50 Hertz.18 The last reportable ‘frequency excursion’19 was in 2008-09.20

16 National Grid, Frequency response services (accessed 8 January 2019) 17 Source: House of Commons Library Correspondence with National Grid 18 Historic frequency data, National Grid 19 Where frequency is more than 1% away from 50 Hz for 60 seconds or more. 20 National Grid, National Electricity Transmission System Performance Report 2017- 2018

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3.1 Balancing services National Grid have a number of tools they can use to help with grid balancing. On long timescales, trading agreements between suppliers and generators intend to cover projected demand, ranging from years ahead to same day trading. When these arrangements do not exactly match supply and demand, National Grid SO work with generators and consumers to procure balancing services that work on a range of timescales:21 • On timescales of the same day, National Grid can use options such as the Balancing Mechanism to match supply and demand. The Balancing Mechanism involves generators and consumers offering to either increase generation/reduce demand or decrease generation/ increase demand. Information on payments for the balancing mechanism is available in Box 3. • On a timescale of minutes, National Grid can use the Short Term Operating Reserve (STOR) which requires power to be provided within 240 minutes, but with strong preference for quicker dispatch of 20 minutes. Alternatively, National Grid can use the Fast Reserve; where generators must be able to deliver power or reduce demand within 2 minutes of notification and the change should be sustainable for at least 15 minutes. • On a timescale of seconds, National Grid’s frequency response mechanisms work on a timescale of delivery within 30 seconds to maintain the target of 50Hertz.

Box 3: Balancing Payments The balancing mechanism involves a combination of Offers and Bids for generators or consumers to either increase generation or reduce demand over their contracted amount (Offer) or decrease generation or increase demand (Bid) over their contracted amount. A generator or consumer is paid by National Grid for Offers as this involves selling more energy than contracted (either by generating more or selling what they didn’t consume). Generators and consumers pay for Bids as this involves buying more electricity than contracted (either by consuming more or buying the equivalent of their reduced generation). Traditional generators are incentivised to make bids because they will make savings on the cost of fuel by reducing generation. Renewable generators that would not save on fuel but would instead lose subsidies, are paid constraint payments to be removed from the grid (see section 3.2 below). Bids and Offers are included in the Settlement Period calculations by Elexon (see Section 2.2 above) and charged to suppliers and generators where needed. Payments for balancing the grid, including National Grid’s role and the cost of its balancing tools, are known as Balancing Services Use of System Charges (BSUoSC). These are also paid by suppliers and generators who use the transmission system22 and the costs that feed into a customer bill are part of the overall Network charges (see Box 2).

For more information on the technologies that can offer flexibility services, see the Parliamentary Office of Science and Technology’s note on Flexible Electricity Systems.

21 National Grid, Balancing services (accessed 8 January 2019) 22 This does not include embedded generation. Not paying these charges and Transmission Network Use of System charges (TNUoS) charges is known as an embedded benefit (see section 4.2)

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Inertia System inertia is the energy stored in rotating machines providing power to the network (such as turbines in power plants). This built up kinetic energy means if there was an outage at the power station, the turbines do not stop immediately, but rather slow over time to a halt. This is a free balancing service, as the rate of frequency change following an outage is less steep, thereby giving National Grid SO more time to react. Renewables cannot currently provide this service, as they are connected to the grid via inverters. As such, declines in traditional generators are reducing the system inertia on the GB grid, meaning National Grid want faster acting reserves to ensure they can respond quickly after outages.

3.2 Constraint Payments and Curtailment In GB, electricity generators pay to have ‘firm’ access to the transmission system 24/7. This constant access means the generators can choose when and how much electricity to generate. Occasionally generators are disconnected (known as curtailment) when there is an oversupply and National Grid need to take balancing measures. When a generator cannot fully use the access paid for, they receive compensation in the form of a constraint payment.23 Previously, when new generation was added, National Grid would build additional grid infrastructure, to ensure the grid was reinforced enough to cope with balancing the capacity. However, to cope with the increasing proportions of renewables, the Government adopted a new policy of ‘connect and manage’ in 2010.24 This policy means the new connections are made and curtailment is used to balance the grid when there is an oversupply in an area, instead of not connecting new generators until grid reinforcement is complete.25 In GB, the choice of balancing service and which generators are curtailed is not technology specific and is instead based on cost and technical considerations. In parts of Europe, a different system, known as priority dispatch is used. The European system gives preference to renewable generators. Whilst advocates argue this creates a cleaner electricity system,26,27 there is also criticism that it can add to costs.28 This only applies to the transmission grid. Connections of embedded generators (see section 4.2) to the distribution grid are not always firm. The exact connections vary across the country due to the different conditions for connection to the 14 DNOs.

23 National Grid ESO, Transmission constraint management (accessed 8 January 2019) 24 Gov.uk, Improving grid access: Second consultation, 3 March 2010 25 Ofgem, Connections (accessed 8 January 2019) 26 P E Baker, Prof. C Mitchell and Dr B Woodman, Electricity Market Design for a Low Carbon Future, UK Energy Research Council, October 2010 27 AEBIOM, RES associations united to urge MEPs to maintain priority dispatch for existing installations, 11 July 2017 28 Agency for the Cooperation of Energy Regulators and Council of European Regulators, Regulators call for priority dispatch of existing Renewables to be removed, Press Release, 11 May 2017

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3.3 Capacity margins and market National Grid produce winter outlook reports that describe the pressure they are under to supply demand each winter and whether they have a sufficient capacity margin. A Capacity Margin means the excess of installed capacity over peak demand. In their 2018-19 Winter Outlook National Grid forecast a margin of 11.7% of underlying demand. The forecast winter margins have increased in recent years from 4.1% in 2014/15, to 5.1% in 2015/16, to 6.6% in 2016/17 and to 10.3% in 2017/18. These are not all directly comparable as the method for calculating the margin was changed in 2017. The Capacity Market has been designed to make sure the UK has sufficient power (and avoids blackouts) as the UK replaces older power stations with energy from low carbon alternatives. The Capacity Market was one of the elements of the Coalition Government’s Electricity Market Reform (EMR) programme which was introduced through the Energy Act 2013 . Its purpose is to secure capacity to cover any potential shortfall in demand during peak periods, by paying for the guarantee that a generation source (which would not normally be used, due to high costs or inefficiencies) could be called upon to supply power to the National Grid as and when required. Alternatively, a consumer can be paid to adjust their usage of power (demand-side response) to allow National Grid to manage demand as well as supply. Participation in the capacity market and prices are decided through a competitive auction, held 4 years in advance (known as T-4) and 1 year in advance (known as T-1).29 Some changes to the capacity market have been introduced that have not been welcomed by all stakeholders. For example, in July 2017, the Government consulted on changing the de-rating capacities for battery storage in the capacity market. The consultation proposed reducing the payments for batteries as they can only supply power for a short duration. In December 2017, the Government decided to reduce the payments to “correct and over-valuation of the contribution to security of supply made by short duration batteries”. Renewable UK, an industry trade body, said it may make it harder for storage to compete in the capacity market auctions, where many of the successful bids go to fossil fuel generators.30 On 15 November 2018, the General Court of the European Union annulled the European Commission’s 2014 approval of the UK’s capacity market under state aid rules. The ruling effectively rendered the capacity market illegal and suspended its operations. The case was brought by Tempus Energy, a demand side response firm, who said the scheme unfairly favoured power stations such as fossil fuel generators.

29 Engie, Understanding the Capacity Market, 2016 30 Madeleine Cuff, Batteries set to be major competitor in upcoming capacity market auctions, Business Green, 4 December 2017

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The Court’s decision was that the Commission’s original approval process was too short, and that the EU should have done further investigations into the scheme. The UK Government have called the ruling a “procedural matter” and intend to work with the EU to seek approval. The ruling is unlikely to impact generators for Winter 2018/19 as large power plants have paid for access to the grid on an annual basis until April 2019 and earn much of their revenue over winter. Further details on possible future consequences, and options for re-instating a capacity market, are available from a Carbon Brief (an environment and policy website) article on Q&A: What next for UK capacity market after surprise EU ruling? Further information on Government policy on grids is available in Section 6.

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4. Changing grids 4.1 The changing electricity mix Balancing processes are changing for National Grid due to the changing generation mix. Previously, generation was mostly provided by large, centralised power stations, which could provide continuous power. Many of these power plants were fuelled by coal. The UK is moving away from fossil fuels as part of its carbon reduction commitments and investing in renewable generation.31 The UK has said that it will end the unabated coal generation by 2025,32 and the use of coal has reduced significantly in recent years, as the graph below shows.

Source: Department for Business, Energy and Industrial Strategy, Digest of UK Energy Statistics, 2018, Table 5.6 Similarly, as the graph shows, the installed capacity of renewable energy is increasing, as the costs of these technologies have fallen in recent years and the government have encouraged their development through subsidies.33 The increase in renewable capacity helps the UK to meet renewable targets and carbon budgets. However, some types of renewable energy, such as wind and solar are intermittent based on weather conditions. As such, ensuring demand meets supply is complex for operators as both demand and supply are increasingly variable. Government policy on changing grids is covered in Section 6.

4.2 Embedded generation Embedded generation is connected directly to the distribution network, rather than the transmission network, meaning it is not managed by

31 Gov.uk, Clean Growth Strategy, 12 October 2017 32 BEIS, Implementing the end of unabated coal by 2025, January 2018 33 Damian Carrington, Spectacular drop in renewable energy costs leads to record global boost, The Guardian, 6 June 2017

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National Grid, who only manage the transmission network. Embedded generation reduces the amount of electricity that needs to be delivered by the transmission network to meet demand. As such, and in contrast to larger scale generators, embedded generators are seen by National Grid as a demand reduction rather than a supply increase. This is shown in the graph below which illustrates a typical summer day where embedded solar (yellow) and wind (green) reduce the demand (blue) requirements on the transmission system.

Source: Provided to the Library by National Grid and reproduced with permission. ElectraLink, the UK’s Energy Market Data Hub, predict that 25% of the UK’s electricity generation is supplied by renewables, and 40% of renewable generation is connected to the distribution network, making an estimate of 10% of total electricity demand at present supplied by embedded generators. Embedded generation has grown rapidly in recent years; the chart below shows the growth and variability of different types of embedded generation.

Source: Reproduced with permission from ElectraLink, Embedded generation insight

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As the graph shows, the exact proportions of embedded electricity supplied vary through the year. For example, solar generates much more power in summer than in winter and wind is also highly variable but tends to generate more in winter. There is also daily variation as solar only generates in daylight hours, meaning it does not contribute to the demand when it is dark, such as evening and early morning, especially in the winter’s shorter daylight hours. This seasonal and daily variability in embedded generation, means the demand from the transmission network also varies. National Grid reached an agreement with ElectraLink, in August 2018 to receive detailed data on embedded generation to help them plan supply to the Distribution Networks.34

Box 4: Embedded benefits As embedded generation is connected to the distribution network, suppliers using embedded generators avoid charges associated with the use of the transmission network, which larger, more traditional generators must pay. The avoidance of these charges is known as embedded benefits. Ofgem, the energy regulator, has made a number of changes to reduce the benefits, and more changes may come into force as a result of ongoing Ofgem reviews.35

4.3 Future balancing The changing electricity mix, and increase in embedded generation, in the UK is impacting grid balancing requirements. This is shown in the graphs below from National Grid’s System Operability Framework. Both the graphs are models of possible future scenarios from National Grid’s System Operability Framework report 2016, rather than specific future forecasts.

Source: Reproduced with permission, National Grid System Operability Framework 2016 The graphs show the demand from the transmission system curve in black; the dashed lines either side show the flexibility that is available to National Grid from the balancing mechanism. Underneath the demand curve is generation provided from the transmission system. This is a combination of baseload generators which provide largely constant power (such as nuclear) and flexible ‘peaking plants’ (such as gas) which

34 Dataset Will Help National Grid ‘Join the Dots’, ElectraLink 21 August 2018 35 Dan Starman, Paradise Lost: The changing face of embedded benefits, Cornwall Insight, 22 August 2018

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can ramp generation up and down to meet peaks in transmission demand. Above the black line is embedded generation (such as solar) which supresses the required supply from the transmission system. The graph on the left was a projection for Spring 2016/17 (the report was published in 2016). This scenario has a baseload including nuclear, hydro and interconnectors. Embedded generation, such as solar, acts to supress demand. Gas, and some coal, provide flexibility to meet the peaks where demand is high but embedded generation is lower. Balancing the grid in this scenario can be met with flexible gas and coal generation. The graph on the right shows a possible scenario in Summer 2025/26. In this scenario, supply from embedded generators, especially solar, has grown and supresses demand from the transmission system. No coal is required, and gas use has reduced, though it is still required for flexibility to meet peak demand when renewable generation is low, along with storage and other balancing services. Exports may also be required to prevent other baseload generators, such as nuclear, from having to be curtailed (nuclear plants cannot currently be easily turned on and off). Balancing the grid in this scenario is much more complex, and requires National Grid to draw on a wider variety of technologies, including gas, storage, and exports. Although only examples of possible future scenarios, and prone to vary both with policy changes, and seasonal variation, the graphs highlight how the operation of the grid needs to adapt to manage future changes, mainly the reduction in capacity of flexible fossil fuel plants, the rise of intermittent renewables, and the interaction of embedded generation with the balancing of the transmission network.

4.4 Renewable integration costs A grid with a greater proportion of renewables in the electricity mix is more complex to balance. Greater complexity could also make balancing more costly for National Grid, and ultimately, for consumers. The assumed extra costs of ensuring the grid remains balanced with a greater penetration of renewables are known as the system integration costs of renewable technologies (aspects of these costs are also referred to as intermittency costs, or flexibility costs). The costs include the need for flexible generation that can provide power in the case of intermittency, the costs of curtailing generators at times of high supply, higher network costs for grid connection and reinforcement, and lost system inertia.36 Cost projections of system integration costs vary from £6 to £17 per MWh.37

36 UKERC, The costs and impacts of Intermittency – 2016 update, February 2017 37 Simon Evans, In-depth: The whole system costs of renewables, Carbon Brief , 22 February 2017

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Box 5: Are there limits on the proportion of renewables the grid can manage? A 2015 report by Imperial College London suggested that there may be limits to how much of certain technologies the grid can integrate cost effectively.38 There has been widespread debate on the issue of what proportion of renewables a grid can accommodate. Varying estimates from current levels to 100% have been proposed39 that range based on factors including what technologies are defined as ‘renewable’ and the degree of intermittency. These debates are part of the wider issue of which technologies, or combination of technologies, should be used to decarbonise electricity generation. Decarbonisation could include low-carbon but less intermittent or non-renewable forms of generation, such as bioenergy, nuclear, or carbon capture and storage.

As with all possible increases in network costs, there is concern as to who pays for any additional costs of integrating energy technologies in future. More information is available in Section 7.2 on Network costs. The 2015 Imperial report suggests that in their view, achieving deep decarbonisation at a low cost relies on investment in flexibility and that advances in flexibility are beneficial to the grid even at lower levels of decarbonisation. The report argued that flexibility options are already (or are likely to soon be) available, but “may not be sufficiently incentivised by the current market arrangements.”40 It has been suggested that system integration costs of intermittent generators should be included in auctions for low carbon power contracts, known as Contracts for Difference (CfDs).41 CfDs are a price paid per MWh for electricity delivered and are the Government’s mechanism for subsidising large scale low-carbon power. More information on CfDs is available in the Library briefing paper on Control for Low Carbon levies. A similar suggestion was made in the 2017 Dieter Helm Cost of Energy review (See Section 6). In response to the review, the Government said they “will look to reforms of our CfD mechanism” […] “over the coming years”.42 However the value of subsidies has been falling lately as technology costs fall,43 and some developments have proceeded without subsides.44 It is possible that including flexibility costs with subsidies will not be a viable solution if subsidy free renewables become more widespread.

38 Imperial College London for the Committee on Climate Change Value of flexibility in a decarbonised grid and system externalities of low carbon generation technologies, October 2015 39 The Economist, Can the world thrive on 100% renewable energy?, 15 July 2017 40 Imperial College London for the Committee on Climate Change Value of flexibility in a decarbonised grid and system externalities of low carbon generation technologies, October 2015 41 Imperial College London for the Committee on Climate Change Value of flexibility in a decarbonised grid and system externalities of low carbon generation technologies, October 2015 42 Gov.uk, After the trilemma – 4 principles for the power sector, speech by Business Secretary Greg Clark on the future of the energy market, 15 November 2018 43 RenewableUK, Offshore wind prices tumble in record-breaking auction results – cheaper than nuclear and gas, 11 September 2017 44 David Pratt, UK’s second subsidy-free solar farm completed by West Sussex Council using battery storage, Solar Power Portal, 25 October 2018

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It is important to note that grids need investment for updating and modernising regardless of the mix of generating technologies. As such grid upgrade costs are not solely due to renewables.

Box 6: Broader economic issues In addition to the balancing and capacity costs of integrating more renewables, there are also broader economic issues. When renewables flood the market with power in times of low demand, they can lead to negative pricing events. This means that supply is higher than demand, which sends a market signal to generators to turn off as there is little to no value for their power. Such events, and the decrease in the wholesale price in general with more renewables deployed while demand is reducing, also disincentivise further investment, both in new renewables, and in the more traditional generators, which in the UK are part of the capacity that balances the grid when renewables are not generating. This can lead to policy issues on how to maintain security of supply and capitalise on the potential to reduce costs for consumers.45

4.5 The DNO-DSO Transition As the generation mix of GB grows more diverse, with increasing small- scale renewables connecting to the distribution network, balancing the grid and ensuring supply meets demand at all times is growing more complex. DNOs are meeting this challenge by transitioning to be Distribution System Operators (DSOs). This will see them take on a more managerial role including some of the balancing actions National Grid operates on the transmission network, being replicated on the distribution network. More information on this transition is available from the Energy Networks Association (the industry trade body) factsheet on the Open Networks Project.46

45 The Economist, A world turned upside down; Renewable Energy, 25 February 2017 46 Energy Networks Association, ENA Open Networks Project (accessed 8 January 2019)

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5. Smart Grids

In July 2017, Ofgem (the energy regulator) and the Government produced a report on Upgrading our Energy System, smart systems and flexibility plan.47 This outlined the Government’s support for a more flexible, decentralised energy system in future – further information is available in section 6. The following sections set out some of the aspects of a smart grid, including smart meters, time of use tariffs, electric vehicles and blockchain trading. Smart grids have the potential to help with grid balancing, but some argue that they can also represent a larger shift in the operation of energy networks, with consumers becoming more actively involved with producing and balancing requirements (sometimes referred to as prosumers).48

5.1 Smart Meters Smart meters are the next generation of energy meters, offering a range of advanced functions. Between now and the end of 2020 more than 50 million new energy ‘smart meters’ are being rolled out to 30 million homes and smaller non-domestic sites in Great Britain. Previously, meters had to be manually read, and customers would receive estimated bills. Smart meters can provide half hourly data, meaning customers should benefit from more accurate billing and avoiding meter reading visits. At present, under Ofgem’s smart metering Data Access and Privacy Framework (DAPF) domestic customers have to opt-in to allowing access to their half-hourly consumption data, and micro-business customers have the option to opt out. Ofgem is consulting on changing this framework, to increase access to data to make the electricity system more efficient, whilst also safeguarding consumer privacy. A decision is expected soon.49 Consumers that have installed smart meters could possibly benefit from smart appliances and time of use tariffs (see Section 5.2 below). Also, the increase in data on energy consumption can help suppliers increase the accuracy of their demand forecasts and ensure they secure enough supply.50 Smart meters should eventually also make it easier for customers to switch energy supplier, which some argue could lead to a more competitive market with lower tariffs.51

47 Ofgem & HM Government, Upgrading our energy system. Smart Systems and Flexibility Plan, July 2017 48 Adam Vaughan, Smart systems key to future of cheaper and cleaner , The Guardian, 14 April 2018 49 Ofgem, Access to half-hourly electricity data for settlement purposes, 10 July 2018 50 Due to the range of smart meters available, and different tariffs from different suppliers, not all benefits are universally available to all customers with a smart meter at present. 51 Commons Library, The Domestic Gas and Electricity (Tariff Cap) Act, 17 August 2018, Section 6 – Smart Meters

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Critics argue that the precited savings are inflated and as the cost of the rollout is rising, consumers are seeing reduced net benefits.52 More information is available in the Library Briefing Paper on Energy Smart Meters.

5.2 Time of Use Tariffs Half-hourly metering can lead to new time of use tariffs. The price of electricity varies throughout the day as demand and supply vary. Energy tariffs can capture the variation in demand and therefore the cost of energy; allowing consumers to be rewarded for using electricity at times when there is less demand.53 Time of use tariffs have existed in terms on and Economy 10 which reward customers for using energy at night or at prescribed “low peak” periods, but smart time of use tariffs, which respond to the unique daily variations in prices, were first introduced in the UK in January 2017.54 This change could be aided by smart appliances that do not need to operate at a particular time and so can choose to operate when energy is cheapest, for example washing machines running overnight (though there are some safety issues to consider.) There is potential for smart meters to catalyse the growth of new products and services such as smart appliances and home batteries which could turn on or off in response to energy tariff price information. This could mean that consumers become active in the network by providing energy or demand side response services to balance the grid.55

5.3 Electric Vehicles Numbers of electric vehicles are projected to increase significantly in the future. Bloomberg predict that electric cars will account for a third of the global auto fleet by 2040.56 The increase is expected to add to electricity demand. National Grid produced a ‘myth buster’ in response to press reports of the Government’s proposed ban of petrol and diesel cars in 2040 on 8 August 2017.57 This concluded switching to electric vehicles in line with the Government’s announcement would be likely to add 5 GW to demand, rather the 30GW referred to in some press articles. The batteries in the vehicles have the potential to be used for grid balancing as they can act as storage.58 The concept is that when supply is low and demand high, electric vehicles that are connected to the grid

52 British Infrastructure Group, Not so smart, July 2018 53 Written evidence submitted by the Department of Energy and Climate Change (DECC), SME0031, 26 April 2016 54 Andrew Ward, Households offered first time-of-use energy tariff, Financial Times, 2 January 2017 55 EY, Pipes and wires, 25 October 2017 56 Jess Shankleman, The Electric Car Revolution is Accelerating, Bloomberg Businessweek, 7 July 2017 57 National Grid, Our energy insights, Electric vehicle announcement and what the papers say, 8 August 2017 58 National Grid, Power Responsive, How smart charging can help unlock flexible capacity from EVs, 12 December 2017

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to charge can instead release power into the grid. Owners of the vehicles could then be paid for this balancing service. The car can charge when demand is lower and supply higher, such as overnight. In theory, if the car is needed to be charged for a certain time the owner would register that time which would override the use of the car as a power source. For more information see this webpage from energy supplier Ovo energy on ‘Vehicle to grid: your electric car as a power station’.

5.4 Blockchain trading Originally used to underpin digital currency bitcoin, blockchain is a distributed record of transactions, or other data, maintained by a network of computers on the internet. Information held on a blockchain exists as a shared — and continually reconciled — database.59 The blockchain database isn’t stored in any single location, meaning the records it keeps are public and easily verifiable. Rather the database is stored by millions of computers simultaneously, and its data is accessible to anyone on the internet. As there is no centralised version of this information, it is often described as un-hackable. A key potential application of blockchain technology in the energy sector is its ability to create local peer-to-peer networks for electricity in which distributed generators can sell surplus electricity to their neighbours. National Grid’s Future Energy Scenarios 2017 report (which analyses “a range of plausible and credible pathways for the future of energy, from today out to 2050”) identifies blockchain as one of a number of “emerging technologies”.60 The report states that blockchain could allow the secure execution of smart contracts in peer-to-peer networks and thus could “further unlock the potential of distributed energy resources such as solar PV and batteries.”61 A report by PricewaterhouseCoopers (PwC) on the potential application of blockchain in the energy sector similarly identifies peer-to-peer trading in microgrids as a key potential growth area for blockchain, but cautions that for its wider deployment regulatory changes would be needed: Blockchain technology strengthens the market role of individual consumers and producers. It enables prosumers, i.e. households that not only consume but also produce energy, to buy and sell energy directly, with a high degree of autonomy. The current legal and regulatory framework for consumers and prosumers in the energy sector is clearly defined and provides protection on many levels to consumers in particular. However, in the medium to long

59 Parliamentary Office of Science and Technology, Distributed Ledger Technology, 28 August 2018 60 Future Energy Scenarios 2017, National Grid, July 2017, p. 47 61 Future Energy Scenarios 2017, National Grid, July 2017, p. 47

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term, this framework will probably have to be adjusted to reflect the requirements of decentralised transaction models.62 On 27 September 2017, Electron a London-based energy tech company, announced that it had been awarded £637,000 in government funding to scale its prototype blockchain trading platform for demand-side response.63 Several energy companies are exploring the potential application of blockchain to energy trading. In April 2018, the UK’s first physical trade of energy took place using blockchain technology as part of an Ofgem trial. The trial, run by smart grid specialist Verv, is designed to test how blockchain-enabled peer-to-peer trading in a social housing community in London could help reduce energy bills and emissions.64 In November 2018, the energy company (parent company of Big Six supplier British Gas) joined the trial.65

62 Blockchain – an opportunity for energy producers and consumers?, PwC, 2016 63 Electron wins UK Government Award to advance blockchain in balancing electricity markets, Electron, 27 September 2017 64 Verv, We’ve just executed the UK’s first energy trade on the blockchain as we look to power a London social housing community with sunshine, 12 April 2018 65 James Murray, Centrica joins Verv peer-to-peer energy blockchain trial, Business Green, 16 November 2018

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6. Government policy on grids 6.1 Flexible grids In July 2017, Ofgem (the energy regulator) and the Government produced a report on Upgrading our Energy System, smart systems and flexibility plan.66 This outlined the Government’s support for a more flexible, decentralised energy system in future, with greater roles for storage and demand-side response. The report set out the ways in which Ofgem and the Government intended to support, and remove barriers to, new storage and demand-side response. A number of the proposals in the report have been implemented; Ofgem published a Progress Update in October 2018. For example, as discussed in Section 4.2 above, in August 2017, Ofgem launched a Targeted Charging Review SCR (TCR SCR). The review will look at network charges (the cost of using the wires that transport electricity around the UK). Ofgem are consulting on their minded to decision and draft impact assessment.67

6.2 The Helm Review In October 2017, Professor Dieter Helm’s Cost of Energy Review, commissioned by the Government was published.68 The review made a number of suggestions around restructuring electricity demand management, regulation and structure. On the structure of distribution systems, Professor Helm proposed: • Public ownership of system operators; • Create Regional System Operators (RSOs). While the National System Operator (NSO - a fully independent and publicly owned equivalent of National Grid under the Helm proposal) controls firm power auctions (a new concept for the competitive new capacity auctions which include intermittency costs) the RSOs are also publicly owned and are “responsible for the integrated development of the local network, and the local generation, distribution and supply, including auctioning the network improvements”; • As such the RSOs take over many DNO functions. DNOs become contractors to RSOs as part of a competitive network. As such there is no need for review periods as DNO revenue is decided at auction; • Abolish distinction between supply, generation and distribution as an RSO would do all three.

66 Ofgem & HM Government, Upgrading our energy system. Smart Systems and Flexibility Plan, July 2017 67 Ofgem, Targeted Charging Review: minded to decision and draft impact assessment, 28 November 2018 68 Dieter Helm, Cost of Energy Review, 25 October 2017

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On 7 November 2017 the Government launched a call for evidence to gain views on the Helm Review.69 A debate on the Dieter Helm review was held on 24 April 2018. Dr Whitehead, the shadow Energy Minister, agreed with Helm’s conclusion that the energy market was overcomplicated, but also criticised the lack of evidence in the report: What the Helm report says is right: we have vastly over- complicated many of the areas that we consider necessary as policy levers. […] Nevertheless, we should be clear that the report in essence represents an extended opinion piece: the opinions of Professor Dieter Helm on how the energy market and the electricity market in particular will work in future. He has been expressing those opinions—I am familiar with a number of them—forcefully for a considerable period. I strongly agree with some of his opinions and I do not agree as much with some, but they are mostly there in the report, one way or another. The question we have to ask about the recommendations that Professor Helm makes in the report is, how are they backed up with evidence? Having read the recommendations or even the executive summary, we might confidently assume that in the report we would find not only evidence to back up the recommendations, but talk of their consequences. However, we do not find that. What we find is material to back up why Dieter Helm’s opinions are right. As a satisfactory answer to the question asked, the report falls rather short of what one wishes might have been achieved. That is a problem in responding to it fully. […] There are a number of things in the report—the question of who runs the distributed energy service, how that is best run in the public interest, the simplification of the system over the period, and how the carbon price can be used in future to manage the transition to a low-carbon economy—but I am not convinced that it is much other than a good talking point as far as future energy policy is concerned.70 Responding to the debate, the Minister, Claire Perry, did not comment directly to any of the recommendations in the report, but did say the Government would make a sensible response: We have had a very vibrant debate about the report; we will not rush to respond to it. This is an opportunity when we are at a tipping point on how we generate and deliver our energy. […] We need a response that is sober and sensible, that sets out an energy policy or strategy for the future that can survive successive political cycles and can respond quickly to what I have no doubt will be enormous technological changes.71

69 Gov.uk, Cost of energy review: call for evidence, 7 November 2017 70 HC Deb, 24 April 2018, Vol 639, C324-325 71 HC Deb, 24 April 2018, Vol 639, C329

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Government Response – Greg Clark’s speech On 15 November 2018, the Secretary of State for the Department of Business, Energy and Industrial Strategy made a speech on the future of the energy market in response to the Helm review. The Secretary of State suggested that the trilemma, the need to secure low cost, low carbon, and secure power, was over, as “cheap power is now green power” and proposed transforming the power sector based on new principles. Specifically, on electricity grids, Mr Clark announced reviews on the regulation of network infrastructure. These are intended to remove regulatory barriers to smarter and distributed grids. Greg Clark also said that to enable open competition, there was a need to “accelerate reform” of DNOs to resolve their conflicts of interest as owners and operators of the infrastructure, in line with the separation of National Grid.72 Mr Clark said that the Government would set out more details through a policy paper, and a detailed White Paper would follow in 2019.

72 Gov.uk, After the trilemma – 4 principles for the power sector, speech by Business Secretary Greg Clark on the future of the energy market, 15 November 2018

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7. Additional political views on grid issues

7.1 Nationalisation The Labour party’s environmental policy includes aims to increase renewable energy generation and nationalise the grid infrastructure.73 In their September 2018 Green Transformation Document, Labour said they would: Upgrade and invest in flexible energy networks capable of supporting a transition to decentralised renewable energy, by bringing the UK’s energy transmission and distribution networks back into public ownership. This means making more use of local, micro grids and of batteries to store and balance fluctuating renewable energy, and providing the necessary investment to connect renewable energy sources to the grid. For further information, see the Library briefing paper on Public Ownership or industries and services.

7.2 Network costs Network operators charge generators and suppliers for the use of the transmission and distribution grid infrastructure. This cost is passed on to consumers as a “network” cost in their energy bills. This fee includes the cost of using the infrastructure, plus losses in physically transporting the energy though the wires. The fee varies between regions and is generally higher in more rural areas, which has led to calls for a rethink of the costs, either as an average cost per unit across the country, or a set annual fee for all customers regardless of consumption. This is an issue that has been raised by the Scottish Government: The Scottish Government believes that the existing approach to energy regulation for access and use of the UK electricity grid works against the interests of growing Scotland's renewable energy industry and impacts on delivery of Scottish, UK and European renewable energy and climate change policies and targets. Imposing high transmission access and use of system charges acts as a disincentive to investment in renewable energy generation in Scotland, which has some of the highest yields from renewable energy than anywhere else in Europe. As a result of the strong locational pricing element in the charging methodology, generators in the North of Scotland are facing the highest charges in the UK which is £20.17 per Kilowatt in the North of Scotland, compared to subsidies of £5.87 per Kilowatt received by generators in Cornwall. Locational charging means Scottish generators produce about 12% of UK generation but account for 40% of the transmission costs, or about £100 million per year more than generators in the South.

73 Labour, The Green Transformation: Labour’s Environment Policy, September 2018

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As part of our ongoing efforts to address this issue, Scottish Ministers and Scottish Government officials are in ongoing discussions with Ofgem, National Grid and Scottish generators to develop options for change that will deliver a more equitable regime. We are also engaged in active discussions on this with UK Ministers and at EU level.74 There has also been concern that as network charges are included in each unit of energy, those who consume more pay more. As some households and businesses install on-site renewables, such as solar panels, they use less electricity and therefore pay less for network charges and may disconnect from the grid altogether. This means those who take all their electricity from the grid, including those without solar panels, pay more for network charges. It has been argued that this has kept electricity prices high in some countries where wholesale costs have fallen, and may create a cycle of disconnection.75 In future, if the costs of managing the network increase (see Section 4.4 above on renewable integration costs) the division of these costs between the remaining grid connected consumers could be a cause conflict. Ofgem are consulting on changing network charging, with options including households and business paying a fixed fee, rather than a cost per unit. In addition, Ofgem have proposed a lower price control for the networks under RIIO2, due to come into force from 2021 onwards. This will reduce the baseline returns that the companies can achieve at 4%, 50% lower than under the previous controls. The change is intended to save customers £35 per year on network charges.

74 Scottish Government, Transmission Charging, (accessed 8 January 2019) 75 The Economist, A world turned upside down; renewable energy, 25 February 2017

About the Library The House of Commons Library research service provides MPs and their staff with the impartial briefing and evidence base they need to do their work in scrutinising Government, proposing legislation, and supporting constituents. As well as providing MPs with a confidential service we publish open briefing papers, which are available on the Parliament website. Every effort is made to ensure that the information contained in these publicly available research briefings is correct at the time of publication. Readers should be aware however that briefings are not necessarily updated or otherwise amended to reflect subsequent changes. If you have any comments on our briefings please email [email protected]. Authors are available to discuss the content of this briefing only with Members and their staff. If you have any general questions about the work of the House of Commons you can email [email protected]. Disclaimer This information is provided to Members of Parliament in support of their parliamentary duties. It is a general briefing only and should not be relied on as a substitute for specific advice. The House of Commons or the author(s) shall not be liable for any errors or omissions, or for any loss or damage of any kind arising from its use, and may remove, vary or amend any information at any time without prior notice. The House of Commons accepts no responsibility for any references or links to, BRIEFING PAPER or the content of, information maintained by third parties. This information is Number 8472 provided subject to the conditions of the Open Parliament Licence. 8 January 2019