2 December 2016

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2 December 2016

Cornwall’s team of independent specialists have experience of liberalised energy markets and their regulation since their inception in Great Britain and elsewhere in the late 1980s. We provide consultancy, intelligence and training, and are a trusted and reliable partner whether you are a new entrant or a large, established player.

Specific areas of our expertise include:

 Wholesale and retail energy market competition and change

 Regulation and public policy within both electricity and gas markets

 Electricity and gas market design, governance and business processes; and market entry

Disclaimer

While Cornwall considers the information and opinions given in this report and all other documentation are sound, all parties must rely upon their own skill and judgement when making use of it. Cornwall will not assume any liability to anyone for any loss or damage arising out of the provision of this report howsoever caused.

The report makes use of information gathered from a variety of sources in the public domain and from confidential research that has not been subject to independent verification. No representation or warranty is given by Cornwall as to the accuracy or completeness of the information contained in this report.

Cornwall makes no warranties, whether express, implied, or statutory regarding or relating to the contents of this report and specifically disclaims all implied warranties, including, but not limited to, the implied warranties of merchantable quality and fitness for a particular purpose. Numbers may not add up due to rounding.

Contents

1 Purpose 5 2 The Markets for Electricity & Gas – The Basics 5 2.1 Importance of the Energy Sector 5 2.2 “Unbundling” 5 2.2.1 Energy Markets 5 2.2.2 Monopolies 6 2.3 Market Transformation 6 2.4 International Moves 8 2.5 Climate Change Act 2008 8 2.6 EU Emissions Trading Scheme 9 2.7 Electricity Market Reform 10 2.8 Policy Mechanisms to Support Renewable Generation 11 2.8.1 The Levy Control Framework 11 2.8.2 The Renewables Obligation 12 2.8.3 Small Scale Feed-in Tariffs 12 2.9 Policy Mechanisms to Support Energy Efficiency 13 2.9.1 Climate Change Levy and Climate Change Agreements 13 2.9.2 Carbon Reduction Commitment Energy Efficiency Scheme 13 2.9.3 Energy Company Obligation 13 2.9.4 Renewable Heat Incentive 14 2.9.5 Green Deal 15 2.9.6 Warm Homes Discount 15 2.10 Retail Market Review 16 2.11 Competition and Markets Authority Referral 16 2.12 Principles Based Regulation 17 3 Smart and Advanced Metering 18 4 European Internal Market 19 5 The Electricity Industry 19 5.1 Overview of Industry Structure 19 5.2 Generation 22 5.3 Networks 24 5.4 Trading 24 5.5 BETTA and the Balancing and Settlement Code 24 5.6 The Balancing Mechanism 25 5.7 Elexon 25 5.8 Supply 25 5.9 Significant Recent Developments 26 5.9.1 Ofgem’s Switching Significant Code Review 26

6 The Gas Industry 27 6.1 Overview of Gas Industry 29 6.2 Exploration and Production 29 6.3 Networks 30 6.4 Storage 31 6.5 Joint Office 32 6.6 The UNC 32 6.7 Xoserve 33 6.8 Supply 33 6.9 Trading and Balancing 33 6.10 The National Balancing Point 34 6.11 Imbalance (Cash-out) 34 7 Recent Significant Developments 35 7.1 Project Nexus 35 8 Legal Framework 35 8.1 Legislation 35 8.1.1 Electricity 35 8.1.2 Gas 35 8.2 Regulation 36 9 Price Trends 36 9.1 Domestic Prices 36 9.2 Industrial Prices 37 9.3 Electricity and Gas Prices in Europe 38 10 Bibliography 39 10.1 General industry statistics 39 10.2 Electricity generation companies 40 10.3 Gas and electricity suppliers 40 10.4 Transmission and Distribution Companies 41 10.5 Regulation 42 10.6 Industry Statistics 42 10.7 Consumer Prices 43 10.8 The GB Electricity Market 43 10.9 NETA / BETTA 43 10.10 The Pool 44 10.11 The GB Gas Market 44

This is a primer for new beginners entering the industry. We assume you do not know much about how the market provides electricity and gas to customers in Great Britain and your company’s role in it, but would like to learn a lot more. It explains the importance of the sector to the economy and the basics of how the market works, before outlining how policy has reshaped the sector as the government seeks to implement ambitious targets for addressing climate change while addressing the cost to do so. We then pick out the main points of how the electricity and gas markets operate. Also highlighted is key information on sector legislation, regulation and prices. If you would like further information or to discuss the contents of this primer, please contact: James Brabben via [email protected]

2.1 Importance of the Energy Sector

Gas and power supply is crucial to the economy and society. The sectors directly employ and indirectly purchase goods and services that provide livelihoods for many. The direct contribution to the UK economy in terms of Gross Value Added (GVA) was estimated to be £23bn1 in 2014. If all the indirect effects are included, the sector’s GVA rises to £83bn. 2.2 “Unbundling”

The introduction of competition brought about a disaggregated cost chain for gas and electricity. Competitive wholesale markets allow trading between gas producers, electricity generators, suppliers and financial houses for the eventual delivery to the consumer retail market. Since the late 1990s all customers have been able to choose their gas and electricity supplier.

2.2.1 Energy Markets

Wholesale markets have developed for both gas and electricity to allow participants to buy or sell energy as required. In many respects the wholesale markets are similar to other commodity markets insofar as contracts are traded (either standard or bespoke) for the delivery of an agreed amount of energy at some point in the future. Market participants face several risks that can include forecasting customer demand for energy, the risk associated with fluid wholesale and retail prices, posting credit, and the risk that there are insufficient counter-parties to trade with. Some of these risks arise because of a physical requirement to buy or sell energy; others arise because traders seek to speculate on future price movement. Whatever the motivations for wholesale trading, the respective markets provide opportunities to buy and sell electricity and gas in different quantities and over different time periods. For example, a contract for the coming day or as far forward as quarters, seasons (six months for summer starting on 1 April and six months for winter starting on 1 October) and annuals could be traded.

1 Powering the UK, Ernst & Young, November 2014

Since the end of the 1990s all customers have been able to choose their electricity and gas supplier. Retail competition began with larger businesses in the early 1990s and by the end of the decade choice of energy supplier had been introduced for all households too.

2.2.2 Monopolies

While competition has been introduced to the wholesale and retail markets, the costs associated with transporting via networks from the point of its production to its consumption remain regulated as these services are seen as natural monopolies. Ofgem (Office of the Gas and Electricity Markets), the energy market regulator, sets the amount of revenue that the network companies can recover from customers via its “price control” process. The regulator also signs off the charging methodologies that are used to derive charges for different classes of customer. Network activity is split between two functions: transmission and distribution. The former is for the large-scale movement of electricity and gas around the country—basically allowing for the entry into the networks of the energy (from power stations for electricity and gas fields or imported sources for gas) to be moved in bulk from its point of origin around the country and into the distribution networks. The distribution networks then transport energy to the customer meter for its consumption. A small number of customers are connected directly to the transmission networks (e.g. large industrial customers requiring significant volumes of gas and/ or electricity). Likewise, there are a number of producers (small scale power generation or “green gas” injection) connected to the distribution networks. The network operating companies fix the charges themselves subject to the overall price control restraint and all users are charged for their use of these networks using pricing structures that are designed to reflect the cost of providing the network assets related to their production or consumption. 2.3 Market Transformation

Opening the energy markets to competition occurred as part of a programme of restructuring and privatising previous monopoly gas and electricity providers that commenced in the 1980s. This restructuring culminated in a wave of consolidation of electricity and gas suppliers and power generators into the “Big Six” companies. These are British Gas, EDF Energy, E.ON UK, RWE Npower, Scottish Power, and SSE. Numerous other companies also have a presence in supply, power generation and gas production. The consolidation of energy suppliers in Great Britain from 14 regional electricity companies (present at the time of electricity privatisation in 1990) to the Big Six is shown in Figure 1.

Figure 1: Consolidation of GB Energy Suppliers

Source: Ofgem

British Gas remains the largest supplier and currently holds a market share of around 23% in the domestic electricity market. The other major suppliers have developed their respective shares of the market mainly through mergers and acquisitions. SSE was formed by the merger of Scottish Hydro-Electric and Southern Electric. Its subsequent purchase of the South Wales supply business in 2000 and further gains in its customer base have helped to increase its market share to around 15% and it is now the second largest supplier, along with E.ON UK. E.ON UK built its share, currently around 15% of the electricity domestic market, by first acquiring East Midlands Electricity and then TXU Energi, which comprised the former Eastern Electricity and Norweb customers. It entered the supply business by purchasing the Midlands Electricity Board and then built it further with the purchase of the Northern Electric and Yorkshire Electricity supply businesses. EDF Energy has around 12% share built through the acquisition of London Electricity, which was followed by the acquisition of the SWEB and SEEBOARD supply businesses. RWE Npower has around a 10% share and finally ScottishPower, which also owns Manweb, also accounts for about 10% of the domestic electricity customer base. In recent years the share of independent suppliers (which include companies such as the Co-operative Energy, First Utility, Ovo, Spark energy, Utilita and Ecotricity amongst others) has grown substantially from below 2% in 2012 to in excess of 10% of the market in June 2015. The domestic market for gas is still mainly served by the Big Six large vertically integrated suppliers. Centrica dominates with a market share of 36%. This share has fallen from 55% in 2005 although is still significantly higher than the next largest competitor. As of August 2015 SSE and E.ON UK each held around 12% of the market, while EDF Energy, RWE Npower and Scottish Power each had around 9%. The cumulative share of independent suppliers was 11% in June 20152. In May 2015, the number of suppliers seeking domestic customers in the energy market reached a new all- time high of 273. Figure 2: Domestic Electricity and Gas Market Shares

Electricity Market Shares Gas Market Shares

Source: Ofgem

The picture is different in the business market, although suppliers outside of the Big Six in 2015 still only accounted for around 14% of the electricity market and 44% of the gas market (by meter numbers). In terms of energy volume sold, the Big Six hold around 18% of market share in the business gas market and around 73% in the electricity market.

2 Ofgem interactive retail market indicators – Figures are updated to August 2015 3 Competition in British household energy supply markets by Cornwall Energy for Energy UK

In terms of generation the Big Six accounted for around 65% of capacity ownership in 2015, while smaller players, including Drax, Intergen, Engie, Dong Energy and Vattenfall made up another 20%. The remainder relates to other (often smaller) generators, including the rapidly growing renewables sector. The UK’s energy sector faces significant challenges over the next years in maintaining secure energy supplies; meeting ambitious government policy targets on climate change and sustainability; and ensuring the cost to the customer remains reasonable. In a DECC report on delivering investment in low carbon energy, it was estimated that investments totalling £100bn were required in the electricity system alone between 2014- 2020. The challenge of shifting the UK to a low-carbon economy is made harder at a time of volatile commodity prices and increasing import dependency. Furthermore, an increasing amount of environmental legislation targeted at the industry is putting added pressure on utility and energy companies. These factors have already had an impact on wholesale and retail prices and are expected to continue to do so during the next decade. However, the Conservative government is putting more emphasis on the affordability of environmental programmes and has already initiated changes aimed at reducing costs. 2.4 International Moves

Recent years have seen European governments implement a broadening range of policies designed to cut energy use, increase energy production from renewables and promote sustainability. These policies primarily focus on the “decarbonisation” of the generation sector. At the international level, the United Nations has initiated significant action towards environmental sustainability, with the Kyoto Protocol of 1997 the most far- reaching of its achievements to date. This agreement placed binding targets on signatory countries to reduce their greenhouse gas emissions by 2008-12. A successor agreement (the Paris Agreement) has yet to be ratified. The UK government is keen to place itself at the forefront of global activity and has introduced a raft of policies designed to limit greenhouse gas (GHG) emissions across all sectors of the economy. The hope is to reduce the UK’s current dependence on fossil fuels for electricity generation (a major contributor to greenhouse gas emissions) and replace them with low-carbon sources of generation, including renewables, nuclear, biomass and “clean coal”. The goals outlined in a key 2007 energy white paper4 are as follows:  To put ourselves on a “path” to meet required carbon emissions;

 To maintain the reliability of energy supplies;

 To promote competitive markets in the UK and beyond to raise the rate of sustainable economic growth and improve our productivity; and

 To ensure that every home is adequately and affordably heated.

In addition, there have been several important policy developments that are and will have a significant impact on the UK energy sector. The Climate Change Act 2008 is the most far reaching. 2.5 Climate Change Act 2008

The UK passed legislation in November 2008 that introduced the world’s first long-term legally binding framework to tackle greenhouse gas emissions and climate change. The Climate Change Act 20085 aims to:  Improve carbon management, helping the transition towards a low-carbon economy in the UK; and

4 Meeting the Energy Challenge: A White Paper on Energy, DECC, 2007 5 Climate Change Act 2008, DECC. November 2008

Demonstrate UK leadership internationally, signalling commitment to take the UK share of responsibility for reducing global emissions in the context of developing negotiations on a post-2012 global agreement. Key provisions include:  Adoption of a legally binding target of at least an 80% cut in greenhouse gas emissions by 2050, to be achieved through action in the UK and abroad. Also, a reduction in emissions of at least 34% by 2020. Both targets are against a 1990 baseline;

 Introduction of a carbon budgeting system that caps total UK emissions over five-year periods, with three budgets set at a time. The first three carbon budgets run from 2008-12, 2013-17 and 2018-22, and were set in May 2009. The fourth was set on 17 May 2011 for the period 2023-27, and the recommendations for the fifth carbon budget, covering 2028-34, were published in November 20156;

 The creation of an independent Committee on Climate Change to advise the government on the level of carbon budgets and on where cost-effective savings can be made; and

 Establishment of a requirement for the government to report at least every five years on the risks to the UK of climate change, and to publish a programme setting out how these will be addressed.

A number of policy programmes are in place to deliver the emissions reduction targets set out in the Act. The most relevant for energy companies and their customers are summarised below. 2.6 EU Emissions Trading Scheme

The European Union Emissions Trading Scheme (EU ETS) was the first large emissions trading scheme in the world when launched in 2005 and remains the pillar of EU climate policy. It currently covers around 11,000 energy-intensive industrial installations throughout Europe including power stations, refineries and large manufacturing plants. The scheme was expanded to the aviation industry in January 2013. These sites are collectively responsible for close to half of the EU's emissions of CO2 and 40% of its total greenhouse gas emissions. Power generators burning fossil fuels are subject to the EU ETS. Under the EU ETS, large emitters of carbon dioxide within the EU must monitor their CO2 emissions, and annually report them. Each year they are obliged to return an amount of emission allowances to their national governments that is equivalent to their CO2 emissions in that year. Under rules in place to 2012, besides receiving an initial allocation, an operator may purchase EU and international trading credits to ensure it can redeem allowances equivalent to its actual emissions. Conversely if an installation has performed well at reducing its carbon emissions, then it has the opportunity to sell its surplus credits. The EU ETS entered its third phase in 2013, which lasts until 2020. The key changes for the third phase include:  A centralised, EU-wide cap on emissions that falls annually by 1.74%, delivering an overall reduction of 21% below 2005 levels;

 Adjustment of the emissions cap up to the 30% GHG reduction target when the EU ratifies a future international climate agreement;

 At least half of allowances will be auctioned;

 All allowances required by the power sector to be obtained via an auction in the UK and across most of the EU from 2013;

6 https://www.theccc.org.uk/publication/the-fifth-carbon-budget-the-next-step-towards-a-low-carbon-economy/

 Sectors at significant risk of “carbon leakage” (e.g. companies moving to other parts of the world where no carbon schemes exist) will receive 100% free allocation;

 12% of the total allowances auctioned will be re-distributed to EU members with lower GDP;

 Access to international project credits from outside the EU will be limited to 50% of the reductions required in the EU ETS;

 Ability for small emitters and hospitals to opt-out; and

 Inclusion of aviation in the EU ETS (introduced from 2012).

Statistics released by the European Commission in May 2013 showed that the surplus of allowances within the EU ETS doubled during 2012. As a consequence, carbon prices continued steadily to decline during the early part of 2013, and dipped below €3 per tonne for the first time in January 2013, however, since then the price has risen to €8 per tonne in July 2015. In response, the European Commission is proposing “back- loading” – or postponing the auctioning––900mn of the scheme’s allowances until 2018-20, in the hope of raising the carbon price. This does not reduce the overall allowances to be auctioned during the third phase– –only the distribution of auctions over the period. As a longer-term solution to the imbalance between supply and demand, the Commission has proposed to establish a market stability reserve at the beginning of the next trading period in 20217. 2.7 Electricity Market Reform

The Electricity Market Reforms (EMR) are a set of major reforms to the electricity arrangements aimed at promoting investment in secure, low carbon electricity generation while improving affordability for consumers. The package seeks to address the rapid closure of existing capacity as older, more polluting plant go offline, as well as addressing the increased need to meet legally-binding carbon and renewable targets, as expected growth of electricity demand for use in heat and transport rises too. The reforms were implemented through the Energy Act 2013, which became law in December 2013, and through secondary legislation that became law on 1 August 2014. The EMR elements comprise:  The Carbon Price Support – Intended to provide a long- term price signal for low-carbon investors. In March 2014, the government announced 8 that the rate would be capped at a maximum of £18/t CO2 from 2016-17 until 2019-20

 Contracts-For-Difference (CfDs) – To provide long-term price stabilisation to low-carbon plants, allowing investment to come forward at a lower cost of capital and therefore at a lower cost to consumers. The first auction in December 2014 produced 25 contracts amounting to 2GW of new renewable energy

 A Capacity Market – Provides a regular retainer payment to reliable forms of capacity (both demand and supply) in return for that capacity being available when the system is

7 European Commission: Structural reform of the European carbon market http://ec.europa.eu/clima/policies/ets/reform/index_en.htm 8 Carbon price floor: reform and other technical amendments March 2014

tight. A total of 46.4GW of capacity was procured at a clearing price of £18/kW/year at the second capacity auction held on 8-10 December 2015. The auction was for delivery of capacity in 2019-20

 An Emissions Performance Standard – Places an annual limit on carbon emissions from new fossil fuel plants equivalent to 450kg/MWh at baseload. It acts as a regulatory backstop to the amount of carbon emissions new fossil fuel plants can emit

The government considers the CfDs and Capacity Market mechanisms must achieve their objectives in a way which minimises costs to consumers. Its latest analysis suggests household electricity bills will on average be £41 or 6% lower per year over the period 2014-30 under the reformed arrangements compared to meeting the government’s objectives with existing policy instruments. For businesses, bills are expected to be 7-8% lower. 2.8 Policy Mechanisms to Support Renewable Generation

2.8.1 The Levy Control Framework Levy Control Framework Projected Expenditure

Subsidies for low-carbon electricity generation are paid for through additions to consumer bills. This includes the EMR programmes outlined above, Feed-in Tariffs (FiT) and the Renewables Obligation (see section 2.8.2 below), Final Investment Decision Enabling for Renewables, and Carbon Capture and Storage (CCS) deployment. In order to limit the impact on consumer bills the government set a limit on the annual low carbon energy subsidy expenditure that could be collected from consumers, known as the Levy Control Framework (LCF). There are annual caps, and the final LCF year of 2020-21 has an expenditure limit of £7.6bn (in 2012 prices). However, the Office of Budgetary Responsibility Source: DECC projected in July 2015 that the total would in fact reach £9.1bn, an overspend of around 20%. DECC said greater technological efficiency, higher uptake of schemes and changes to wholesale prices account for why it likely to overspend against the LCF restrictions if it did not take action. In light of these financial pressures the government issued a consultation in August 20159 which proposed measures to control renewables subsidy expenditure including early closure of the Renewables Obligation to solar projects of 5MW and below and revisions to the levels of tariffs for Feed-in Tariffs. DECC has subsequently introduced a deployment cap of £100mn/yr for new FiT installations until April 2019 and reduced generation tariffs10. Importantly, in December 2015 the European Commission approved the UK’s plans to compensate energy intensive industries for the indirect costs of financing renewables through various government schemes. Compensation of up to 85% will be available to sectors with particularly high electro-intensity and trade exposure for a period of 10 years, effectively putting a larger burden on domestic consumer bills to finance renewable schemes.

9 Consultation on a review of the Feed-in Tariffs Scheme DECC, August 2015 10 Review of the Feed-in Tariffs Scheme DECC, December 2015

2.8.2 The Renewables Obligation

The Renewables Obligation (RO) is designed to encourage generation of electricity from renewable sources. It was introduced in Great Britain in April 2002 and in Northern Ireland in April 2005, replacing the Non-Fossil Fuel Obligation, which operated from 1990. The RO places an obligation on licensed electricity suppliers to source an increasing proportion of electricity from renewable sources. Suppliers meet their annual obligations by presenting Renewables Obligation Certificates (Rocs) that are awarded to eligible generators according to their production volumes. Where a supplier does not have sufficient Rocs to cover its obligation, a payment is made into a “buy-out” fund. The proceeds of the buy-out fund are paid back to suppliers in proportion to how many Rocs they have presented. Since its introduction, the RO has undergone many changes. The most significant of these were introduced in 2009 when new generation installations were awarded fractional, single or multiple Roc awards for each MWh of electricity produced, depending on the required level of support for that technology. The government sets the RO target six months before the commencement of a compliance year. This is done by reference to targets set out in legislation, and where it looks like this may be breached a “headroom” mechanism is used that ensures that the target is 10% above the estimated number of Rocs to be generated in a compliance period. This makes sure the Roc market is structurally short to maintain the value of Rocs. The RO is running simultaneously alongside the new CfD regime from 2014, and will then close to new generation on 31 March 2017. Electricity that is accredited under the RO will continue to receive its full lifetime of support (20 years), until the scheme closes in 2037. The RO for the year April 2016 to March 2017 is 0.348 Rocs/MWh in GB and 0.142 Rocs/MWh in Northern Ireland.

2.8.3 Small Scale Feed-in Tariffs

Since April 2010 customers that install eligible technologies below 5MW can receive feed-in tariff (FiT) payments from an electricity supplier. The scheme was introduced in recognition that the RO was a barrier for the deployment of smaller scale renewable generation installations. The government issues the FiT rates, which are annually adjusted for inflation, and are technology and capacity specific. Suppliers take part in a quarterly “levelisation” scheme that ensures that the cost of the scheme is spread across all electricity suppliers based on market share. Suppliers are expected to recover the cost of the scheme for the generality of their customers. Payments are also made for exports, which the government also sets. Installations below 30kW installed capacity without a half-hourly export meter have their export volumes deemed. The FiT rates and technology bands have been reviewed numerous times following concerns over the uptake (and hence cost to the customer) and as such a “degression” mechanism is now in place that automatically reduces the FiT rates for new installations once installed capacity in a quarter is breached. In August 2015, the government opened a consultation on a set of measures to control costs under the FiTs, including revised tariffs based on updated technology cost data, a more stringent digression mechanism and deployment caps. In DECC’s response to the consultation, which was published in December 2015, it decided to cut FiT tariffs for solar PV, wind and hydro by up to two thirds from January 2016; put a total deployment cap of £100mn on new FiT installation until April 2019; and prevent the inclusion of any additional technologies into the scheme. As of December 2015, around 710,000 installations were in place comprising more than 4GW of capacity – the vast majority of which is solar photovoltaic.

2.9 Policy Mechanisms to Support Energy Efficiency

2.9.1 Climate Change Levy and Climate Change Agreements

The Climate Change Levy (CCL) is chargeable on the industrial and commercial supply of taxable commodities for lighting, heating and power by consumers in: industry, commerce, agriculture, public administration, and other services. The levy does not apply to domestic consumers or charities. The CCL is added to energy bills before VAT and, although there is no legal requirement to itemise it, it often appears as a separate item on bills. From 1 April 2015 CCL was charged at £0.554/kWh for electricity and 0.193p/kWh for gas. Originally all revenue raised through the levy was recycled back to business through a 0.3% reduction in employers’ national insurance contributions, although this has since lapsed. The levy is set by HM Revenue and Customs (HMRC) and applied as a specific rate per nominal unit of energy. It is now indexed to inflation and changes annually on 1 April, with rates set for electricity, gas, LPG and coal. Until 1 August 2015 electricity from renewables was awarded a Levy Exempt Certificate (LEC) per MWh. Suppliers procured these to enable the sale of electricity to businesses that does not attract the CCL. However, the chancellor announced in the Budget statement on 8 July 2015 the government’s intention to remove the CCL exemption for renewable electricity. Therefore, all electricity, regardless of generation source, is now subject to the CCL. Climate Change Agreements (CCAs) allow eligible energy-intensive businesses to receive, until 2023, up to a 90% discount (this increased from 65% on 1April 2013) from the CCL in return for meeting energy efficiency or carbon-saving targets. Participation is voluntary, but CCAs are intended to deliver an 11% energy efficiency improvement across all industry sectors by 2020, against agreed baselines. The scheme is administered by the Environment Agency. Sector targets will be reviewed in 2016, with a view to assessing the progress made.

2.9.2 Carbon Reduction Commitment Energy Efficiency Scheme

In April 2010, the government launched the Carbon Reduction Commitment (CRC), which specifically targets carbon emissions associated with electricity and heat use in large public and private sector organisations. The scheme is designed to tackle CO2 emissions not already covered by Climate Change Agreements and the EU ETS. It is expected to reduce non-traded carbon emissions by 17mn tonnes by 2027. Inclusion in the scheme is mandatory for all organisations (public or private) that have at least one electricity meter settled on the half-hourly market, and that consumed 6GWh or more of electricity in 2008 that are not subject to CCAs or the EU ETS. Participants must monitor and report on their emissions and purchased allowances, at £16.4/tonne, to cover their carbon emissions. Under the original scheme design participant performance was published in a league table each October following the end of a compliance year. However, this element of the scheme was removed as part of the government’s move to simplify the CRC. Simplification began following complaints from industry of the administrative burden that comes with participating in the programme. HM Treasury issued a consultation11 in September 2015 seeking to scrap the CRC in order to simplify the business energy efficiency landscape by creating a single efficiency tax and report based on the CCL. Final plans going forward are to be detailed in Budget 2016.

2.9.3 Energy Company Obligation

The Energy Company Obligation (ECO) came into effect on 1 October 2012 and superseded the Carbon Emissions Reduction Target (CERT) and the Community Energy Savings Programmes (CESP).

11 Consultation: reforming the business energy efficiency tax landscape, September 2015

CERT, which was in operation between 2008 and 2012, placed an obligation on domestic energy suppliers (with 250,000 or more customers) to install energy efficiency and/ or low carbon systems in households. The obligation was divided among suppliers based on market share. CESP, which ran between 2009 and 2012, placed an obligation on the Big Six retailers but also generators with an average output of greater than10TWh/yr. The ECO requires domestic suppliers (with a customer base in excess of 250,000 accounts, where a dual fuel customer counts as two accounts) to install eligible energy saving measures to be directed at specific groups. An industry-wide target, set by government, is split between obligated parties by market share/ volumes supplied. Smaller suppliers that breach the threshold for domestic customers are given an ECO that tapers up until they reach 500,000 accounts, at which point their obligation will be fully based on market share. The ECO sub- obligations are:  Home Heating Cost Reduction Obligation (HHCRO) (accounting for 25% of total spend);

 Carbon Saving Communities (CSCO) (comprising 15%); and

 Carbon Savings Obligation (taking the remaining 60% of spend)

The CSCO has a further requirement for suppliers to deliver 15% of the CSCO (i.e. 2.25% of the overall target) to rural, low-income households in settlements with a population under 10,000. As initially designed, all suppliers were required to deliver 20.9mn t in lifetime carbon savings under the Carbon Savings Obligation, 6.8mn t under the CSCO, and a £4.2bn reduction in notional lifetime space and water heating costs under the HHCRO by March 2015 respectively. The carbon score for the scheme was designed to promote solid wall insulation, with the hope that this will transform the market for the technology in much the same way that previous programmes did for cavity wall and loft insulation. The government’s impact assessment estimated that the cost of the ECO will be £60 per year per dual fuel account. Suppliers can count carbon savings arising from a Green Deal installation at a property that also qualifies for ECO measures, such as in the instance where a Green Deal will not meet the “golden rule” and an ECO “top- up” is offered. In July 2014, the government published its response12 to an earlier consultation on proposed changes to the scheme following an announcement by the government that it would reduce the costs of the ECO. The key confirmed changes include the extension of the scheme to 2017 (known as ECO2), modifying the eligibility criteria for CSCO and allowable primary measures under CERO to ensure it is easier and cheaper to deliver, and to reduce the 2015 CERO obligation by 33 per cent. The government estimated these changes would reduce bills by around £30-35 a year. Ofgem published its final report on the ECO1 scheme in September 201513, announcing that suppliers had exceeded all ECO1 targets. Concerns, however, were raised at the relatively high technical failure rates of installations; learning on this front is to guide ECO2 from April 2015 to March 2017. Government is just commencing work to develop the successor to ECO2 which should be introduced in April 2017.

2.9.4 Renewable Heat Incentive

The non-domestic Renewable Heat Incentive (RHI) scheme is a government environmental programme that provides financial incentives to increase the uptake of renewable heat. For the non-domestic sector it

12 Government Response to the Future of the Energy Company Obligation July 2014 13 ECO1 Final Report, September 2015

provides a subsidy, payable for 20 years, to eligible non-domestic renewable heat generators and producers of biomethane for injection into the gas grid. The scheme supports renewable heat installations in business, industry and the public sector as well as district heating schemes. It has been open for applications since November 2011. The non-domestic RHI scheme currently supports the following technologies: biomass; heat pumps—ground source, water source and deep geothermal; all solar thermal collectors; and bio-methane and biogas. In February 2013, the government announced its intention to review tariffs available under the scheme, owing to disappointing uptake of certain technologies. In May 2013, DECC opened a consultation on these revised tariff levels, and confirmed that tariffs for medium commercial biomass would fall by 5% as part of the department’s degression-based approach to ensuring the scheme remains within budget. In April 2014 DECC confirmed the launch of its domestic RHI. The scheme offers homeowners payments to offset the cost of installing low-carbon systems in their properties. The technologies covered by the scheme include: air source heat pumps; ground and water-source heat pumps; biomass-only boilers and biomass pellet stoves with integrated boilers; and solar thermal panels. The guaranteed payments are made quarterly over seven years for households in England, Wales and Scotland (Northern Ireland has its own RHI scheme). In the joint Spending Review and Autumn Statement in November 2015, the chancellor announced that the budget for RHI will reach £1.15bn by 2020-21. To deliver savings, a new cap is also being implemented to ensure RHI spending does not go above its budget alongside a tariff digression mechanism, intending to deliver savings of £700mn.

2.9.5 Green Deal

The Energy Act 2011 included provision for the Green Deal, which set out to revolutionise the energy efficiency of British properties. The scheme, which was launched in March 2013, enabled private companies to offer consumers energy efficiency improvements to their homes, community spaces and businesses at no upfront cost, and to recoup payments through a charge on the energy bill—dubbed as “pay-as-you-save”. Following an assessment, property owners (if not the bill payer) were offered a package of approved installations by a Green Deal Provider that meets the “golden rule”. This stipulated that (at the time of the assessment) the cost to the customer will be equal to or less than savings made on energy bills. If the package is adopted it is repaid via the electricity bill (although most savings are likely to be seen on the gas bill, where present) with payments collected by the electricity supplier. All electricity suppliers with more than 250,000 (single) accounts are obliged to collect Green Deal repayments and remit these to the Green Deal providers. Smaller suppliers can opt-in to collect repayments, but if they choose to opt-out they are prevented from supplying those customers. The government estimated that the average length of a Green Deal will be seven years. Since the scheme’s inception DECC has made a number of changes to encourage a greater take-up. DECC’s monthly statistics on the Green Deal scheme, up to the end of November 2015, showed that a total of 614,383 Green Deal Assessments had been undertaken and there were15,231 households that had Green Deal Plans in progress at the end of September 2015. In July 2015, the government decided to end any further Green Deal funding in the light of low take up and concerns about industry standards. DECC said the government would work with the building industry and consumer groups on a new value-for-money approach.

2.9.6 Warm Homes Discount

The Warm Home Discount was launched in April 2011. The programme provides assistance to low-income and vulnerable households by providing them with an annual rebate on their electricity bill. For winter 2015 to 2016, eligible customers could get a one-off discount of £140 off their electricity bills through the scheme, usually issued between September and March. Suppliers with more than 250,000 domestic accounts were mandated to join the scheme. Government estimated that the scheme cost up to £1.1bn annually and would help around 2mn consumers. The costs of the scheme are spread across all participating suppliers.

2.10 Retail Market Review

Ofgem launched the Retail Market Review in late 2010 due to concerns that the energy market was not working effectively for consumers. The overall objective of the review was to make the retail energy market simpler, clearer and fairer for consumers. In the domestic market, in an attempt to ensure customers could make simpler tariff choices, the regulator introduced a maximum limit on the number of tariffs that suppliers can offer and simplified tariff structures so that all tariffs have a standing charge (which could be zero) and unit rate structure (no multi-tier tariffs). It also introduced restrictions on the discounts and rewards that customers could benefit from as part of their tariff. In an attempt to ensure domestic customers are provided with clearer information on their tariffs, Ofgem introduced a number of requirements on how suppliers should communicate the features of their tariffs to customers. All suppliers are now required to use a Tariff Comparison Rate to help consumers to compare the costs of energy tariffs across the market and provide Cheapest Tariff Messaging to give consumers personalised information on how much they could save by switching tariffs with their current supplier. For non-domestic customers, proposals included focus on simpler processes and fairer treatment for smaller companies, increased monitoring of suppliers’ customer transfer actions, and Third Party Intermediaries (TPI). They included  Obliging suppliers to print clearly the date a fixed term contract will end and the last day customers can give notice to end their contracts

 Binding Standards of Conduct that focus on suppliers’ dealings with micro-businesses when contracting, billing and transferring supply

 A review of the TPI Code of Practice

The Competition and Markets Authority’s investigation into the GB energy market has proposed removing the RMR’s four tariff rule, arguing that it would boost tariff innovation and competition between suppliers. 2.11 Competition and Markets Authority Referral

In November 2013 Ofgem undertook, along with the Office of Fair Trading and the Competition and Markets Authority (CMA), a state of the market assessment which considered how well competition in the energy retail market is serving the interests of households and small businesses in Great Britain. It published the results of this assessment in March 2014. Its findings indicated that there is increasing distrust of energy suppliers, uncertainty about the costs and benefits of the relationship between the supply businesses and the generation arms of the six largest suppliers, and rising profits with no clear evidence of suppliers reducing their own costs or becoming better at meeting customer expectations. It decided in June 2014 to refer the market for investigation by the CMA. The CMA initiated its investigation in respect of the supply and acquisition of energy14. It is investigating whether there are any market features that have an adverse effect on competition. Should it find that there are any such features, the CMA must take any action as it considers reasonable and practicable to “remedy, mitigate or prevent” the adverse effect on competition and any detrimental effects on customers. In July 2015, the CMA issued its provisional findings and proposed remedies. It found there was weak customer response in the markets for retail supply of gas and electricity for both domestic consumers and microbusinesses and proposed a number of “market-opening measures” and “informational remedies”.

14 CMA Energy Market Investigation

These included removing from domestic suppliers’ licences the requirements introduced by the RMR (see above) to limit the number of tariffs that suppliers could offer. The CMA has also proposed that Ofgem should provide an independent price comparison service for domestic and microbusiness customers. The CMA also suggested that it may be necessary to introduce a “safeguard tariff” that would cap the cost of contract for households and small businesses. The CMA proposed a series of measures to help microbusiness engage effectively in the market. These included that there should be a new requirement on suppliers to provide price lists for microbusinesses on their websites and make this information available to price comparison websites to provide greater transparency for these customers, and also introduce rules governing the information that third-party intermediaries are required to provide to microbusiness customers. In September, the CMA extended the investigation timetable by six months so that the revised deadline for the completion of the investigation is now 25 June 2016, with a provisional decision on remedies due in February 2016. An additional remedy was proposed in October 2015, suggesting an end to all evergreen tariffs in an effort to promote customer engagement through end of fixed term notification letters. In December 2015, the CMA identified an additional adverse effect on competition arising from the prepayment market after finding that it was less competitive and that prepayment customers tend to have a more limited tariff choice, pay more for their energy and have very low switching rates. Additional remedies specific to the prepayment market were proposed including prohibiting the charging of certain meter installation costs and a transitional safeguard price cap on prepayment tariffs. 2.12 Principles Based Regulation

Both the electricity and gas supply licences are characterised by prescriptive rules that have resulted in the standard licence conditions for electricity supply to have grown from 64 pages in 2007 to 465 pages today. Ofgem has identified that prescriptive rules bring inherent drawbacks that can lead to a number of problems including: gaps in consumer protection which could be exploited through undesirable supplier behaviour; unintentionally acting as a barrier to competition and innovation; and the detail of prescriptive rules can lead to companies following the detail of the rules rather than being compliant within the spirit of the licence. In December 2015, the regulator issued a consultation15 on its initial proposals for moving towards a regulatory framework more reliant on principles and outcomes. The starting point for a principles-based approach is the Standards of Conduct (SoC) which were introduced in 2013 following the Retail Market Review (RMR). They are intended to ensure all suppliers treat customers fairly and they apply to all areas of supplier interactions with smaller consumers. Ofgem seeks to reform the entire supply licence by restructuring it around broad principles, narrow principles and some prescriptive regulation where it is necessary, such as required by legislation or to protect vulnerable consumers. A shift towards principles-based regulation will see the onus placed on suppliers to understand and think for themselves about how to meet the needs of the customer. The regulator recognises that some suppliers, especially the smaller ones, will require guidance and support and therefore Ofgem proposes to increase its one-to-one support to suppliers on their policies, procedures and processes to help ensure they are getting it right from an early stage. To implement principles based regulation, Ofgem proposes a phased approach. Phase 1 allows industry to comment on the regulator’s suggested framework for principles and priority areas for policy development. Phase 2 will include the development of the new principles and the priority areas for removing the prescription. Finally, Phase 3 will see prescription removed in phases, and to ensure continuous consumer protection, any principles that will be used to replace prescription will be in place by the time the relevant prescription is removed. Ofgem intends to set out a clear way forward for progressing principles based regulation by the end of June 2016.

15 The Future of Retail Market Regulation Consultation, December 2015

Suppliers have licence obligations to install smart meters in their household and small business customers’ premises, though there is no legal obligation on individuals to have one. The supplier-led roll-out approach to installing smart meters for around 53mn properties by 2020 is part of the Smart Metering Implementation Programme (SMIP) created by DECC. Smart meters will be installed across the UK in two stages: the Foundation Stage and the Mass Roll-out Stage. DECC expects suppliers to be ready to begin their full-scale roll-out programme at some point after the middle of 2016 (though some suppliers have already begun their programme) and for it to be completed by the end of 2020.  It is envisioned that the SMIP will deliver the following benefits:

 Provide consumers with real-time information on their energy consumption to help them control and manage their energy use, save money and reduce emissions;

 Provide consumers with more accurate meter readings and bring an end to estimated billing;

 Support Great Britain’s transition to a low-carbon economy and help meet some of the long-term challenges faced in ensuring an affordable, secure and sustainable energy supply; and

 Enable a demand-side transformation in the energy industry by giving consumers access to information to make informed purchasing decisions and reducing the barriers to switching between energy suppliers.

The technical functionality of the smart meters is described in the Smart Metering Equipment Technical Standards (SMETS). Householders will receive an In-Home Display (IHD) that will give them real-time information on their current and historic consumption. For larger customers, suppliers are obliged by their licence to only supply through Advanced Meter Reading (AMR) equipment from April 2014 onwards. These meters are generally less sophisticated than smart meters, but are similar insofar as they are capable of recording, storing and communicating consumption information without the need for a meter reader to physically view the meter. To deal with the data arising from smart meters, a Data Communication Company (DCC) has been established that will receive consumption information and pass it on to the relevant supplier. It is envisaged this entity will be operational from mid-2016. To perform this role, the DCC will put in place the shared data and communications infrastructure necessary for smart meters to:  Operate consistently for all consumers regardless of their energy supplier;

 Provide smart metering data to network operators in support of smart grids; and

 Permit authorised third parties to provide services to consumers once they have granted permission to use their data, offering new routes for consumers to receive energy services and advice on how to reduce their energy usage.

The Smart Energy Code (SEC) is the industry rule book that all parties must follow if they wish to use the DCC’s services. It is a multi-party agreement that defines the rights and obligations of energy suppliers, network operators and other relevant parties involved in the end to end management of smart metering in Great Britain. DECC says that over the next 20 years the installation of smart meters will provide £6.7bn net benefits to the UK. The programme will cost £12.1bn and provide £18.6bn in benefits.

In March 2015, the energy and climate change select committee said in a report that the smart meter roll-out is unlikely to be accomplished by the end of the decade and that many of the issues with the smart meter programme were symptomatic of a national programme that the government has left largely to suppliers. The government, however, remains confident that supplier competition will limit the costs of the roll-out.

The Third Package of energy legislation, specifically Regulation (EC) 714/2009, set out the legal basis to create an internal gas and electricity market in the European Union and participating countries. Its purpose is to further open up the gas and electricity markets in Europe to competition and promote the liberalisation of both markets. The Third Energy Package legislated for the establishment of the Agency for the Co-operation of Energy Regulators (ACER), whose role is principally to assist and co-ordinate national regulators at EU level. The aim is that the internal market should be in place by the end of 2014. ACER is responsible for the development of Framework Guidelines that set out the principles of what the EU network codes should achieve. The European Network for Transmission System Operators for Electricity and Gas (ENTSO-E and ENTSOG respectively) are responsible for the development of the network codes that will specify how the markets across the EU will operate. Each network code passes through a process called comitology, through which the network code becomes legally binding and sits above national legislation. Network codes are currently in different stages of development and implementation. There are ten electricity and seven gas network codes which look to harmonise gas and electricity network rules for: how network capacity is allocated; balancing is achieved; operational planning and security parameters; dealing with supply emergencies; and technical connection requirements. The network codes have to be implemented in Member States ahead of specified dates for each. This is achieved through licence changes and/ or changes to the industry codes which licensees must comply with as a condition of their licences (see below for more detail on industry codes). The scope of the changes required varies with the network code; some are quite minor whereas others require more substantial changes. For example, the gas Capacity Allocation Management network code requires new auction processes to allocate cross border capacity which has required several changes to the GB arrangements.

5.1 Overview of Industry Structure

The electricity industry in Great Britain contains the following functions:  Generation – The production of electricity at power stations ranging from very small units located on user sites to the 3.9GW coal and biomass-fired station at Drax in Yorkshire, the largest station of its kind in western Europe

 Networks – The transportation of electricity from power stations through the transmission and distribution networks to customers

 Supply – Involves the purchase of wholesale electricity and its sale to end-consumers

The electricity sector in Britain emerged over a century. It developed from a series of local, typically municipal, undertakings. The sector was nationalised in 1946 when the Central Electricity Generating Board

(CEGB) was established, charged with developing universal coverage in England and Wales to regional area boards. Similar rationalisation took place in Scotland under two integrated regional companies. Electricity privatisation from 1990 was accompanied by parallel moves to create competition in both the wholesale generation function and supply activities. The first power wholesale market, the Pool, commenced operations from 1 April 1990 with the creation of three competing generator companies, when the nation’s 5,000 largest users simultaneously gained the right to negotiate a competitive electricity supply contract. This process proceeded with a pre-specified timetable for further market opening, and culminated in a fully open electricity supply market being in place by the end of that decade. Standards of operation in the market are enforced through licences and codes. Licences are official standards that all major players and the majority of smaller players in the market must abide by if they are to be permitted to carry out the relevant functions. They cover the separate functions of generation, transmission, interconnection, distribution and supply. There are a series of industry codes that describe the engineering and commercial arrangements that ensure the electricity system operates safely and effectively. Holders of licences are required to become parties to these codes. The codes include:  Balancing and Settlement Code (BSC)––determines the rules for ensuring supply and demand are matched (balanced) and apportioning costs to relevant parties for actions taken by the System Operator to maintain supply and demand balance (settlement);

 Connection and Use of System Code (CUSC)––framework for connection and use of the high voltage transmission system and certain balancing services;

 Distribution Connection and Use of System Agreement (DCUSA)––covers commercial aspects of connection and use of electricity distribution systems;

 Master Registration Agreement (MRA)––manages the change of supplier process to ensure the retail market functions (switching) and the correct meter is allocated to the correct supplier;  Grid Code––technical aspects relating to connections, operation and use of transmission network;

 Distribution Code––technical parameters relating to connection to, and use of, DNO systems; and

 Smart Energy Code (SEC)––rules for parties making use of the DCC system and levying charges for collecting and sending smart meter data.

Brief History 1946 – Industry nationalised. Central Electricity Generating Board (CEGB) generated most of electricity and also owned and operated the transmission system and interconnectors with Scotland and France (from the 1980s). The majority of the CEGB’s output was purchased by 12 area electricity boards, each of which were responsible under statute for distribution and sales within a set geographical area. 1990 – Industry restructured and privatised. In England and Wales the property, rights, liabilities and local distribution systems of the area boards were transferred to 12 Regional Electricity Companies (RECs). The RECs became the main shareholders in National Grid Group, which assumed ownership of the transmission system and inter-connectors. The CEGB’s non-nuclear generating stations were transferred to National Power and PowerGen, with nuclear stations initially remaining in state ownership. In Scotland, the two companies (Scottish Power and Scottish Hydro-Electric) provided the full range of services from generation through to supply. A wholesale "Pool" was introduced in England and Wales to allow generators and suppliers to buy and sell bulk power. Offer (later to become Ofgem) formed to regulate the industry and protect consumers. During the 1990s the supply market was gradually opened up to competition, and now all customers can choose their supplier. Retail competition was achieved in 1990 for 1MW customers, 1994 for 100kW and above customers; and 1998-99 for remaining customers. 2001 – New Electricity Trading Arrangements (NETA) reforms took effect in England and Wales when the centralised Pool was replaced by an open bilateral contracts model. 2005 – British Electricity Transmission and Trading Arrangements (BETTA) created a single wholesale market covering Great Britain by extending NETA into Scotland.

Key statistics showing how the sector has developed are in Table 1 Table 1: Electricity – Generation and Supply 1970-2014

Total Electricity Conventional Non-Thermal Electricity GWh CCGT Nuclear Generated Thermal & Other Renewables Supplied (Net)

1970 232,378 188,175 - 22,805 - 214,462

1980 269,945 215,418 - 32,291 - 250,727

1990 302,936 219,364 - - 281,678

2000 341,783 125,468 116,110 78,334 - 323,332

2010 347,846 105,142 157,818 56,442 8,208 329,231

2011 332,461 105,345 129,669 62,655 12,840 314,140

2012 328,270 139,994 84,207 63,949 17,137 308,433

2013 324,725 133,330 81,145 64,133 23,958 305,127

2014 300,823 107,945 86,775 57,903 26,763 282,981

There has been significant consolidation, particularly since the change in wholesale trading arrangements (from the Pool to the New Electricity Trading Arrangements or “NETA”) in April 2001. This supply consolidation has been paralleled by vertical integration with generation, a sector also subject to horizontal consolidation, as independent operators withdrew from the market as prices fell initially.

5.2 Generation Figure 3: Electricity Generated 1970-2014

The electricity to meet customer requirements is mainly produced from around 78GW of large-scale generating capacity connected to the transmission network. The dominant capacities installed are fired by coal, gas or nuclear energy. Three interconnectors link the British market to the Netherlands (1GW capacity), France (2GW) and two 500MW to Ireland. In 2014 Ofgem put in place a new regulated route for near term interconnector investment, known as the “cap and floor” regime, first developed for Project NEMO, a proposed interconnector between Belgium and Great Britain. It has, subject to conditions granted four further proposed interconnectors a cap and floor regime. Additionally, there is around 15GW of smaller-scale generating capacity, much of which is provided by renewable sources including wind and biomass, which is connected at the lower-voltage distribution network level. Large-scale generating capacity in Great Britain is owned by more than a dozen companies, with around two thirds of large-scale capacity in the hands of the Big Six, as Table 2 shows. There have been several developments in the generation sector since privatisation. In the 1990s there was a big move towards gas-fired power at the expense of coal following falls in wholesale gas prices and the lifting of EU constraints on burning gas in power stations. The “dash for gas” led to a temporary moratorium being placed on new gas generation developments in 1998. Figure 3 shows the impact that gas-fired power had on the UK generation portfolio between 1970 and 2013.

Table 2: Ownership of Large-Scale Power Generation Technology (GW)

Pumped Wind Party CCGT Coal Nuclear Other FF Biomass Wind All Storage (Offshore)

Centrica 3.5 0.0 1.8 0.0 0.0 0.0 0.0 0.2 5.5

E.ON UK 4.6 2.0 0.0 0.2 0.4 0.0 0.3 0.4 8.0

EDF Energy 1.3 4.0 7.1 0.1 0.0 0.0 0.4 0.1 13.0

RWE Npower 6.6 2.0 0.0 1.8 0.1 0.0 0.3 0.7 11.4 Plc

Scottish Power 2.0 2.3 0.0 0.0 0.0 0.4 1.4 0.0 6.1

SSE 1.9 2.9 0.0 0.3 0.0 0.0 1.0 0.5 6.7

Big Six 19.9 13.2 8.9 2.4 0.5 0.4 3.4 1.9 50.6

ENGIE 1.7 1.0 0.0 0.2 0.0 2.1 0.1 0.0 5.1

Drax Power Ltd 0.0 2.6 0.0 0.1 1.3 0.0 0.0 0.0 3.9

Intergen 2.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.5

MPF Operations 2.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.2 Limited

EPH 0.0 2.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0

Dong Energy 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.8 1.8

Vattenfall Wind 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5 0.6 Power

Other 2.5 0.4 0.5 1.5 0.1 0.0 2.3 0.7 10.6

Total 28.7 19.2 9.4 4.3 1.9 2.5 5.8 4.8 77.9

Big Six 69% 69% 95% 57% 27% 17% 58% 39% 65%

Source: DECCs DUKES with further calculations by Cornwall

Since 2000 efforts have been made to boost the amount of renewable energy generation in the UK. The main policy driver for this was initially the RO subsidy scheme for green generators and more recently the introduction of small scale feed-in-tariffs FiTs. In parallel tough emissions limits, have been imposed on all oil and coal generators, which mean many have had to invest in new abatement equipment or close. These initiatives have been followed by the coalition government issuing in 2011 its Electricity Market Reform proposals which are now being put into effect. See section 2.7 for more details.

Key Electricity Measures

The basic units for measuring electric power are watts, kilowatts, megawatts and gigawatts while the basic unit for measuring energy use from electricity are kilowatt hours, megawatt hours and gigawatt hours (kWh, MWh, GWh) For example: . 1kWh equates to the use of 1,000 watts of electricity for a full hour, or 100 ten watt light bulbs all lit for a full hour

. 1MWh equals 1,000 kilowatt hours – enough to supply the average power requirement for around 2,000 homes for an hour

. 1GWh is 1,000,000 kilowatt hours of electricity

. 1TWh is a thousand GWh – around 0.3% of annual GB consumption

5.3 Networks Figure 4: Electricity Distribution

The high-voltage transmission network is operated in Great Britain by National Grid, which also owns the transmission assets in England and Wales. North of the border Scottish Power and Scottish Hydro Electric own the transmission networks in southern and northern Scotland respectively. There are also a number of Offshore Transmission Operators (OFTOs) which are appointed by Ofgem after a competitive tender process to own and operate the transmission systems to offshore wind farms. Electricity is transferred from the transmission system to the lower-voltage local distribution systems that are operated by the 14 local distribution network operators (DNOs). Electricity for most commercial and industrial use and all domestic use comes through these lower-voltage networks. Figure 4 illustrates where the different regions lie. 5.4 Trading

Generators sell their electricity to suppliers by trading it in the electricity market. The rights to a unit of electricity can be bought and sold several times before the electricity is actually consumed; meaning the total amount of electricity traded can be several times the amount of total demand. Forward and Futures Markets – These are markets for buying and selling large volumes of electricity in advance–typically a trade could be for an annual amount or block, an upcoming summer or winter period or for some years ahead. Typically, these trades take the form of bilateral physical trades i.e. two parties (for example a generator and supplier) enter into a contract to deliver electricity at an agreed time in the future. These contracts are designed to manage price risk, but they can also be used by the counter-parties to speculate on future prices. The long-term nature of the contracts negates the risk of having to buy or sell in shorter timescales when prices can be more volatile. Power Exchanges – There are a number of power exchanges where traders can anonymously buy and sell power in the market place. These trades can cover different time periods from a few hours to several weeks ahead. Participants in the market place seek to meet their contractual obligations for supplying or demanding electricity by trading with other generators, suppliers and end users, so that their contracts and metered quantities match as closely as possible. 5.5 BETTA and the Balancing and Settlement Code

The British Electricity Transmission and Trading Arrangements (BETTA) set out the commercial processes by which parties use the GB transmission system (i.e. generators and suppliers). The rules are described in the Balancing and Settlement Code (BSC) and in simple terms establish an incentive for parties to trade power. At its heart is the concept that users of the transmission system must notify the GB System Operator (SO) of their intentions, ahead of time, to flow power onto the system (i.e. generators) and to take power from it (i.e. suppliers) so that the SO can take action to ensure the system in its entirety is balanced—i.e. supply meets demands on a second-by-second basis. Where parties do something different from the position they notified the SO (such as a power station unexpectedly goes offline or a supplier’s customers take more or less power than notified) they are deemed to be in imbalance and will face ex-post charges on the difference between their notified volumes and their metered positions. The SO takes action in real-time to ensure the system is balanced, via a number of means, and then following the event the cost of some of these actions are used to set the imbalance prices for those parties in imbalance. This is done on a half-hourly basis—known as a settlement period.

5.6 The Balancing Mechanism

The Balancing Mechanism is a tool operated by National Grid in its capacity as SO to ensure that supply and demand match in real time at any given point in time. An hour before the start of each half hour period “gate closure” occurs – this means that participants must notify their wholesale traded contracted positions to the SO and no further bilateral trading can take place. At this point the SO takes over the system and where necessary seeks bids and offers from generators and suppliers to vary their output and consumption (although in reality it is almost exclusively generators) in order to match supply and demand in real time. The SO is under an incentive scheme to undertake its balancing function in a cost-efficient manner. The imbalances that the SO rectifies can be either energy (that is where parties action differs from their nominated position) or system (where the transmission system is physically unable to flow power out of or in to certain location due to insufficient capacity in the wires). The costs of the SO’s balancing actions (which include it calling on Balancing Services contract holders that provide specific services outside of the Balancing Mechanism) is recovered from all users as the Balancing Services Use of System (BSUoS) charge. The costs of the actions taken in the Balancing Mechanism are used as a basis for deriving imbalance charges on those parties in energy imbalance. In conclusion to the Electricity Balancing Significant Code Review, as of November 2015, a single marginal imbalance price has been being used. This means both system buy price and system sell price parameters are retained but they are set equal to each other, with that single value being calculated using the main price methodology. 5.7 Elexon

Elexon is the Balancing and Settlement Code Company (BSCCo) and is responsible for implementing and managing the balancing and settlement arrangements for Great Britain. It does this using the Balancing Settlement Code (BSC), which outlines the rules and governance for the balancing mechanism and the associated imbalance settlement charges that arise. All licensed electricity companies who operate in the market place must adhere to this code. Elexon is a wholly owned subsidiary of National Grid, but it is independently financed and has its own independent Board of Directors. 5.8 Supply

Suppliers are responsible for selling electricity to industrial, commercial and residential customers. Their operations include the monitoring of power usage, the wholesale purchase of electricity and the billing and collection of payments due to other industry players such as National Grid, distribution network operators (DNOs) and Ofgem. There are more stringent obligations for those that wish to supply to households. This includes greater consumer protection rules and also the delivery of government’s social and environmental schemes. The six integrated operators supply the vast majority of domestic customers and also have significant positions in the business electricity market.

5.9 Significant Recent Developments

5.9.1 Ofgem’s Switching Significant Code Review16

Ofgem considers that for competition to work effectively it is vital that consumers can easily and with confidence change their energy suppliers. It believes the current arrangements are inefficient and unreliable and do not support its vision for smarter energy markets that are more efficient, dynamic and competitive. Its ambition is for consumers to be able to switch the next day (which it says could mean from the beginning to the end of the next day). Consequently, Ofgem issued a letter in November 2015 launching the Switching Significant Code Review (SCR), a development it flagged in February in its decision on how to achieve faster switching. The SCR’s initial scope (which may be subject to refinement as circumstances/ Ofgem thinking evolves) will include:  Changes to the regulatory framework to facilitate a new centralised registration service (CRS), covering all supply points connected to gas and electricity distribution networks, and decommissioning the existing meter registration services run by electricity and gas networks. This will include DCC price control and CRS charging arrangements

 Reviewing any remaining network licence obligations linked to registration, including requirements to supply data or to provide enquiry services

 Developing the requirements for a CRS that will provide registration services for the gas and electricity market and the data to support market functions, including energy settlement and network charging

 Facilitating reforms to the switching process for all domestic and non-domestic gas and electricity consumers (with the exception of transmission-connected customers) to deliver reliable next-day switching

 Harmonising the switching arrangements between the gas and electricity markets, where possible, taking into account differences in market requirements

 Defining and identifying how to execute a transition and implementation scheme for the CRS and new switching arrangements

 Implementing the new CRS arrangements with all relevant industry parties who will operate in the new environment

Under the current process, the SCR will conclude when Ofgem issues its direction to licensees to raise code changes. It will then work with industry to progress the code modifications and decide if the proposed code changes should be made. Approval of the changes will trigger the design, build and test of the new systems. The regulator’s current view is that the new arrangements should go live in 2019, noting the government’s ambition of 2018. The SCR covers three of the five stages identified for the Switching Programme:  Blueprint Phase – which designs the CRS, switching arrangements, commercial and regulatory arrangements and the delivery approach

16 Ofgem’s launch statement for the Switching Significant Code Review

 Detailed-Level Specification – where the arrangements developed in the Blueprint Phase will be set out in full, code modifications are drafted and licence changes consulted on

 Enactment Phase – where the formal industry code process begins and Ofgem will decide whether to approve the changes to industry codes and licence changes will be made

These stages will be followed by a Design Build and Test phase and, following implementation, a Monitor and Evaluate Phase (Figure 5).

Figure 5: SCR Process and Switching Programme Phases

The GB gas market developed rapidly in the period from 1967 to 1977 when the country made the switch-over from town gas (made from coal) to natural gas. In the late 1960s an Act of Parliament was introduced to prevent individual companies building or adding to the gas transmission system. A single National Transmission System (NTS) was placed in the care of the nationalised Gas Council, citing safety and economies of scale as good reasons for strong centralised control. In 1972 the Gas Act renamed the Gas Council as the British Gas Corporation (BGC). The principal function of this organisation was to buy gas on behalf of the 12 area distribution boards. The Conservative government introduced the Gas Act 1986, which led to the privatisation of BGC, and on 8 December 1986 its shares floated on the London stock market. At the same time the government created an industry regulator, the Office of Gas Supply (Ofgas), to protect customer needs – which would later become part of the Office of Gas and Electricity Markets (Ofgem).

Brief History

1940s – Gas was manufactured and supplied by a series of more than 1,000 private and municipally- owned companies. In 1949 these companies were nationalised and split into 12 autonomous area boards. They relied primarily on town gas, a product derived from coal. 1960s – Natural gas reserves discovered under North Sea, in 1966 the decision was made to convert from town gas to natural gas. 1970s. – Growth of high-pressure distribution system and opening of national control centre at Hinckley. 1973 – British Gas created and the old gas boards became regions responsible for a geographical area e.g. NEGAS. 1974 – Gas discovered in Morecambe Bay. 1976 – First North Sea gas brought ashore at Easington. 1977 – National programme to convert from town to Natural Gas completed. 1986 – British Gas plc formed upon privatisation. Ofgas (later to become Ofgem) formed to regulate the industry and protect consumers. 1990 – Large commercial and industrial users (>25,000 therms pa) became able to choose their supplier. 1992 – Competition opened up for industrial and commercial customers using between 2,500 and 25,000 therms pa. 1996-98 – Rolling programme of gas competition for domestic users across all regions. 1998 – Bacton to Zeebrugge interconnector opened connecting Britain to the European mainland for the first time. 2002 – Lattice Group (owner of Transco) merged with National Grid to become National Grid Transco. 2005 – Separation of distribution from gas transportation, and sale of regional system to four gas distribution network (GDN) operators. Following escalating tensions between the recently privatised British Gas and regulator about the competitiveness of the newly created markets, which included competition investigations, British Gas in 1997 split itself into:  Centrica, including the British Gas supply business and gas production businesses of the Morecambe gas fields in the North Sea

 BG, which took responsibility of the Transco gas transportation business and the international exploration and production business. BG went through a financial restructuring in 1999, which resulted in a new parent company (BG Group), which subsequently demerged into two new businesses BG Group and Lattice Group. Lattice contained the Transco business and went on to merge with the National Grid Company

A further major change occurred in 2005 when the gas distribution system was hived off. Four of the eight gas distribution networks (or GDNs) were sold off at that time, with National Grid Gas retaining four. Long self-sufficient in gas, the UK is growing more dependent on gas imports as production from indigenous UK Continental Shelf (UKCS) reserves declines. Since interconnection with Europe in 1998 new interconnector pipelines have been developed to facilitate increased imports of gas. Among these are the interconnector from Balgzand in the Netherlands to Bacton (the BBL interconnector), and the pipeline linking the Norwegian Ormen Lange gas field to Britain. In addition, three LNG import terminals have also opened to take delivery of gas shipment from abroad. These developments have led to an increased focus by policy- makers on the security of gas supplies.

At the end of 2014, the UK’s proven reserves of conventional gas stood at 206 billion cubic metres (bcm)17. The vast majority are located in the UK sector of the North Sea, with the largest concentration of gas production is found in the SAGE (Scottish Area Gas Evacuation) system. In recent years, the UK has become a net importer of gas with current figures reporting that around 50% of national gas demand gas is met by imports18. This figure could increase to 80% by 2020. 6.1 Overview of Gas Industry

The gas industry centres on the following functions:  Exploration and production––includes the exploration and extraction of gas from wells, primarily offshore in the North and Irish Seas. Natural gas was first discovered in the UK Continental Shelf in 1965, since then, substantial reserves have been discovered;

 Networks––the transportation of gas from beach terminals through the gas pipe network to gas consumers;

 Storage––while there is variability in demand, offshore producers prefer to produce gas at a relatively constant rate. Therefore, the gas supply system contains a variety of diurnal and seasonal storage facilities to accommodate significant fluctuations in demand;

 Shippers—unlike in electricity there is a specific function in the gas market for a shipper who is responsible for booking the use of networks to ship gas around the country; and

 Supply––involves the purchase of gas from shippers and its sale to end-consumers.

Key statistics showing how the sector has developed are in Table 3 6.2 Exploration and Production

UK gas producers operate offshore rigs in about 100 fields, almost all located in the North Sea and the Irish Sea. Shippers and, to a lesser extent, suppliers purchase gas from these offshore producers (and in much smaller quantities from onshore producers). They can take title to the gas either at the onshore coastal reception terminal (beach terminal), where the gas is referred to as beach gas or, more typically, at the national balancing point (NBP) a notional point of entry to the transportation network for trading. Gas producers deliver gas to input terminals to the national transmission system (NTS). Each terminal includes processing facilities operated by, or on behalf of, the producers and a National Grid facility for receiving gas into the NTS. In general, the producer is contractually obliged to carry out the processing needed to meet the quality specification required for entry into the NTS. Gas is put at high pressure into the NTS and, as it is transported through the system, it may be compressed further to maintain pressures at the extremities of the system. Gas from the NTS is delivered to:  Storage sites

 Large users, such as power stations

 Local distribution systems

17 UK Gas Reserves and Estimated Ultimate Recovery 2015 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/441392/UK_Gas_Reserves_and_EUR_2015.pdf 18 Digest of UK Energy Statistics https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/449418/Chapter_4_Gas.pdf

Key Gas Measures

Natural gas can be measured in a number of different ways. As a gas, it can be measured by its volume at normal temperatures and pressures, commonly expressed in cubic metres (cm). Production and distribution companies commonly measure gas in millions of cubic metres (mcm), or billions of cubic metres (bcm). Gas can also be measured as a source of energy and traditionally in the UK and the US has been measured in British thermal units (BTU) and therms. The therm is the measurement for wholesale gas trading in the UK. But, in recent years there has been an EU-wide agenda to harmonise on energy measurement and charging to customers using kilowatthours (kWh). Megawatthours (MWh) tend to be the currency for trading gas in the developing European gas traded markets. International comparisons can also be presented using gigajoules (GJ). For example: . 1 cm equates to 11.13 kWh

. 100,000 Btu equates to 1 therm

. 1 therm is equal to 29.307kWh

. 1 GJ equates to 277.78kWh

The functions carried out by National Grid’s part of each terminal include quality monitoring, metering and providing emergency shut-off facilities.

Table 3: Gas – Production and Consumption 1970 – 2014

Total GWh Production Imports Exports Consumption

1970 171,329 9,759 0 171,564

1980 405,346 116,291 0 508,684

1990 528,843 79,833 0 597,046

2000 1,260,656 26,032 146,342 1,105,537

2010 665,083 589,497 176,399 1,073,770

2011 526,711 588,475 183,689 899,743

2012 452,696 549,518 144,023 852,331

2013 424,757 535,105 109,664 843,511

2014 425,459 465,195 115,939 772,192

6.3 Networks

The network is designed to handle peak demand expected in severe winters. National Grid’s licence requires it to plan and develop its transmission pipeline system to meet the firm peak demand that is likely to be

exceeded (on one or more days) in only one year in 20. It is also required to plan the system so that it is capable of handling demand in the coldest winter that would be expected in 50 years. The NTS has over 140 offtake stations, which supply the 12 local distribution zones (LDZs) Figure 6: The Gas Distributors operated by five different distribution network (DN) companies. They also supply the main storage facilities, power stations and a few very large industrial consumers directly. A LDZ is a distribution area that is supplied by one or more NTS offtakes. Each LDZ contains a local transmission system (LTS), a network of pipelines generally operating at pressures up to half those of the NTS. These pipelines transport gas to local distribution systems. Additionally, several new entrants have become established as Independent Gas Transporters (IGTs) providing gas distribution networks in local areas but connected to DN systems—these embedded networks are typically found on business parks or new housing estates. The low-pressure local distribution systems are the most extensive parts of the transportation system. DNs manage the diurnal (day-night) profile of customer requirements in them by using local storage, including low-pressure gas holders. The new distribution ownership structure established in 2005 is shown at Figure 6.

6.4 Storage Gas Storage Capacity and Stocks in September 2014

The GB gas storage market can be broadly split into two sections:  Those facilities that were part of the British Gas portfolio and developed prior to privatisation, which are required to offer third party access

 New facilities, built since 1999, which generally have exemptions from third party access

The UK has comparatively little storage, some 4.6bcm of storage capacity, due to its historic reliance on swing (higher at peak demand) production from North Sea fields. The figure is four times this level or more in Source: CEER many European countries (see chart right) . However, as the UK swing production has declined rapidly in recent years, and imports have increased, a growing need for UK gas storage capacity has emerged, and a number of companies have tried to enter the market. The main storage facility is the 3.5bcm Rough offshore storage facility. Onshore storage ranges from salt caverns to LNG terminals. Storage is classified as: long-range––30+ days duration (with restock) e.g. Rough; medium-range––10 –30 days duration (with restock) e.g. Aldbrough, Hornsea, Humbly Grove, Hatfield Moors

and Holehouse Farm—short-range storage––<10 days duration (without restock). Avonmouth is the last short range storage site on the NTS and it will cease operation on 2016. It has been argued that the UK is in need of increased gas storage volumes to smooth out sudden demands in supply during, for example, cold spells or if daily supplies are lost due to technical difficulties or other reasons. Storage also has economic importance in that gas does not have to be bought during the main winter periods or at times of high demand when it is more expensive. But many companies have fallen foul of planning regulations with almost all either refused planning permission at the first stage, or not yet applied for it. 6.5 Joint Office

The Joint Office of Gas Transporters is the governance body for the commercial gas industry. It governs the processes that modify the commercial regime in Britain and administers the Uniform Network Code (UNC). This Code holds the standard set of terms for use of the National Grid Gas pipeline system. In addition, the Joint Office provides information on NTS auctions for gas entry and exit capacity in the long and short term. Information is also made available on Xoserve that provides transportation transactional

Figure 7: GB Gas System

services on behalf of major gas network transportation companies. 6.6 The UNC

Unlike in electricity almost all of the commercial and engineering arrangements that underpin the GB gas market are contained within the Uniform Network Code (UNC). The key principles of the UNC are to:  Provide non-discriminatory access to the network for code signatories

 System security in a liberalised market

 Cost-reflective pricing

 Robust computer systems

 Daily energy balancing

 Shippers incentivised to self-balance 6.7 Xoserve

Launched on 1 May 2005 Xoserve, formally an internal department of National Grid, acts as the interface between the UK gas distribution industry, the NTS and the gas shipper companies. Xoserve is jointly owned by all the gas distribution network companies and National Grid’s gas transmission business. It delivers transportation transactional services on behalf of the network companies to the gas shipper companies. The main services it provides are:  Recording and calculation of transportation volumes

 Transportation billing

 Energy balancing invoicing and cash collection

 Demand estimation

 Information services

 Supply point administration

 UK-link services (data transfer)

Following consultation in January 2012, Ofgem concluded that reform of the funding, governance and ownership arrangements was necessary in order to ensure they were fit for purpose to deliver value for money services in a time of industry change. It has decided to implement a co-operative model, confirming in October 2013 the changes needing to be made to current funding and governance arrangements in order to establish it. The programme is now in the development and delivery stage with a target implementation date on April 2016. 6.8 Supply

The process of deregulating supply effectively started with the privatisation of the former British Gas Board in 1986. The new British Gas plc started life with a legal monopoly serving smaller customers (with demands of less than 732 MWh/25,000 therms a year) and, in effect, a monopoly to larger users despite an erosion of the franchises to 73MWh/2,500 therms in 1992. The slow progress, in terms of entry of new suppliers, prompted various regulatory interventions, including investigations by the Monopolies and Mergers Commission and the Office of Fair Trading, that culminated in the company relinquishing market share and releasing previously contracted wholesale supplies to potential competitors. The household market opened in stages by region from 1996 to 1999. There are currently around 23mn domestic accounts and 850,000 business gas meter points in Great Britain. As in the electricity market the Big Six are dominant, but there are also a handful of large independent suppliers in the non-domestic sector, such as Total, ENGIE, Corona, and Gazprom. 6.9 Trading and Balancing

Gas can be traded on the wholesale market in the form of standard contracts that stipulate the amount to be provided and the delivery timeframe. The gas market is more liquid than that for power and it is possible for

traders to procure gas for delivery up to four or five years out. In terms of volumes the majority of gas is traded over-the-counter or as bilateral deals agreed between producers and shippers/ suppliers. The Endex exchange provides for within day and day-ahead trading. 6.10 The National Balancing Point

The National Balancing Point (NBP) is a virtual trading location for the sale and purchase and exchange of GB natural gas. It is the pricing and delivery point for traded contracts. It is the most liquid gas trading point in Europe and is a major influence on the price that domestic consumers pay for gas. Shippers out of balance at the end of the gas balancing day are automatically balanced through a “cash-out” process where the shipper is automatically made to buy or sell the required quantity of gas to balance their position at the marginal system buy or sell price for that day. As in the electricity market the primary responsibility for balancing lies with market participants, but National Grid in its role as system operator (SO) has a role as residual system balancer. National Grid can buy and sell gas to correct the residual imbalances of the market to ensure that the system remains in balance at all times. In the gas market it carries out this role over daily trading periods, not half-hourly as is the case in electricity. This balancing is usually achieved by trading on the on-the-day commodity market (OCM) and passing the cost onto gas shippers who are out of balance. When the system is short of gas it tends to force prices at the NBP up. When the system is long gas, the price is forced down. This situation can provide an advantageous trading environment to a shipper with flexible flow contracts. The OCM, which went live in 1999, was designed as the replacement for Transco’s Flexibility Mechanism for national supply/demand balancing. It was designed to provide a simple and transparent market to provide within-day liquidity. It is a trading service managed by ICE-ENDEX to which offers or requests for gas at a nominated price can be posted. The minimum amount of gas that may be traded on the OCM is 4,000 therms. ICE-ENDEX is the central counterparty to all trades; all contracts are traded anonymously, then cleared and settled on behalf of members. Three products are traded on the OCM: locational; physical; and title, all of which result in exchange of rights to gas at the NBP. Two of these products include an obligation to change physical gas flows at entry/ exit points around the hub. There is a maximum of two periods tradable at any one time: within-day and day- ahead, according to the time of day. The SO also uses “linepack” for balancing. The term describes the volume of gas in the NTS and can be manipulated in response to imbalances between demand and supply within certain safe operational limits. There are commercial benefits of minimising linepack changes day-on- day. 6.11 Imbalance (Cash-out)

The gas cash-out rules are designed to ensure that the imbalance prices to be paid by companies that go out of balance reflect the costs that the SO incurs in buying or selling energy to bring the system into balance during that balancing period. The cash-out rules place commercial incentives on market participants to achieve energy balance. By exposing market participants that do not balance their positions to the costs of gas balancing incurred by the SO, the cash-out arrangements provide commercial incentives for them to balance. The gas cash-out arrangements have evolved over time as a number of modifications to the cash-out price calculation methodologies. In simple terms, marginal system buy and sell prices are determined by reference to the weighted average prices of trades conducted on the OCM plus or minus a defined “default” amount. Where the SO has traded in the OCM as a means to ensure system balance any buy actions that are more expensive than the default price this becomes the system marginal buy price. The same applies for any SO sell actions that are priced lower than the default system marginal sell price.

7.1 Project Nexus

The ageing UK Link system, operated by Xoserve for energy settlements, supply point administration and other functions for the GB gas market is due to be replaced and Project Nexus aims to ensure that the replacement systems meet the current and anticipated requirements of market participants. Following a decision to delay implementation, the new systems and processes are due to be implemented on 1 October 2016. The requirements for the gas arrangements have been taken forward through a series of modifications to the UNC and will introduce some major changes. These include:  Individual meter point reconciliation. Currently only Larger Supply Points consuming more than 73,200kWh per year are reconciled on an individual basis. Smaller Supply Points below this threshold are reconciled on an aggregated basis through Reconciliation by Difference

 Annual Quantities, which determine the volume for non-daily metered supplies, would be calculated on a monthly rather than an annual basis

 The introduction of new settlement “products” which suppliers can choose from, although certain larger sites would remain mandatorily Daily Metered

One key theme of the changes was the need for the industry to improve its management of data with particular focus on items that can impact on the accurate reconciliation and subsequent settlement of invoices. Another is the inclusion of independent gas transporters as users of the services provided by Xoserve, meaning that shippers do not need to employ two sets of systems and procedures.

8.1 Legislation

8.1.1 Electricity

The framework for electricity legislation in England, Scotland and Wales is laid down by the Electricity Act 1989 (as amended by the Utilities Act 2000, the Energy Act 2004, the Energy Act 2008, the Energy Act 2010, the Energy Act 2011, and the Energy Act 2013). The Electricity Act 1989 (as amended) requires that companies operating in the electricity market seek licences to carry out activities. Electricity generation, transmission, interconnection, distribution and supply must be licenced separately, with conditions on which licences can be held together, e.g. an interconnection licence cannot be held in conjunction with any other electricity licence. It established an independent industry regulator, Ofgem, responsible for issuing licenses in accordance with regulations that require financial standing and technical competence to be considered.

8.1.2 Gas

The framework for gas regulation in England, Scotland and Wales is laid down principally by the Gas Act 1986 (as amended by the Competition and Services (Utilities) Act 1992, the Gas (Exempt Supplies) Act 1993, the Gas Act 1995 and the Competition Act 1998), the Utilities Act 2000, and subsequent Energy Acts). The Gas Act 1986 (as amended) requires that all companies operating in the gas market either seek licences or seek

an exemption. Under the Gas Act 1995, gas transportation, shipping and supply activities are licensed separately. As with electricity Ofgem is responsible for issuing licences. 8.2 Regulation

Prior to the enactment of the Utilities Act 2000, the Secretary of State for Trade and Industry was required, under the Gas Act 1986 and the Electricity Act 1989, to appoint a Director General of Gas Supply (DGGS) and a Director General of Electricity Supply (DGES) as the regulators of the gas and electricity industries respectively. The DGGS and the DGES had the power to establish, as non-ministerial government departments, offices to assist in carrying out their duties and functions under the separate regulatory regimes. The Utilities Act 2000 combined the duties of the DGGS and DGES and appointed a new regulatory authority, the Gas and Electricity Markets Authority (GEMA). In June 1999, the former regulatory offices, the Office of Gas Supply (Ofgas) and the Office of Electricity Regulation (Offer), were combined and renamed the Office of Gas and Electricity Markets (Ofgem). Ofgem is the official independent regulatory body for both the gas and electricity industries and its role is to protect the interests of consumers, regulate competition between providers, and monitor social and environmental issues within the industry. It focuses mainly on the following areas:  Making gas and electricity markets work effectively by promoting competition in generation and supply;

 Ensuring companies in the sector fulfil their legal and licence obligations;

 Regulating the revenues of monopoly businesses e.g. network companies; and

 Ensuring social and environmental responsibilities on energy companies are met

The industry regulator is responsible for assessing market power, preventing predatory pricing, assessing the effects of inter-company agreements on competition, approving applications for the exclusion from the Competition Act 1998 and ensuring compliance with legal requirements.

Since becoming a net importer of gas in the middle of the last decade market prices have been volatile in response to global commodity prices. In addition, geopolitical tensions and natural disasters (such as the 2011 Japanese tsunami) have highlighted the effect of high impact, low probability events. 9.1 Domestic Prices

Prices are influenced by market forces and suppliers constantly review and set their pricing policies and strategies in response to competitors and external factors. Following the introduction of competition into the domestic market in 1998 domestic electricity prices fell considerably. This reflected the decreases in costs across the industry during this period. Since 2004 unprecedented increases in wholesale gas prices reversed this trend of falling electricity prices in dramatic fashion. In late 2007 wholesale gas prices increased rapidly and prompted all six major domestic suppliers to introduce significant price increases early in 2008. This upward pressure on prices continued in July 2008 when oil prices surged upwards to reach a record $147 a barrel. Major suppliers passed on these higher costs with a further round of price increases in the third quarter of 2008. Oil prices retreated rapidly later in 2008 and this record peak was followed by prices at then four-year lows. Following some minor price decreases in late 2011 prices climbed during 2012, mainly in response to increasing wholesale, network and government programmes costs. The average dual fuel bill for a domestic

customer of the six largest suppliers declined by 7% between 2013 and 2014 from £1,286 to £1,190, according to Ofgem figures. This fall was primarily due to domestic customers using less energy: the average volume of gas supplied by the six largest suppliers fell by 18% while for electricity there was a decline of 3%. This was due to the mild weather but also increasing energy efficiency. However, as consumption fell average prices for domestic consumers continued to increase for both gas and electricity between 2013 and 2014.In 2015, the provisional average dual fuel price fell by £45 to £1,299. This follows the average industrial prices falling too. Both petrol and diesel prices were at their lowest levels for six years in December 2015. A typical dual bill reflects the cost of generation, supply costs and margin, distribution, transmission and meter provision as shown in Figure 8. The graph shows the breakdown over time for an average domestic customer

Figure 8: Breakdown of Typical Dual Fuel Bill

of a large supplier, based on the latest Consolidated Segmental Statements published by the six large suppliers.

Suppliers recover the cost of their environmental obligations through the gas and electricity bill. The scale and costs of these environmental programmes haveSource: been Ofgem increasing in recent years with the introduction of more government policies designed to support the transition towards a low-carbon energy mix. There is also a pressing need to upgrade the distribution and transmission networks in order to maintain current supply levels and to connect more renewables to the grid. Average UK domestic electricity prices including taxes for medium consumers in 2014 were the eighth highest in the IEA, third highest in the G7 and 19% above the IEA median. The UK price excluding taxes was the third highest in the EU15 and was 38.0% above the median. Over the same period average domestic gas prices including taxes were the tenth lowest in the IEA and were 9% lower than the median. Excluding taxes the UK was the ninth highest in the IEA and was 17% above the median. 9.2 Industrial Prices

The opening of the industrial market to competition and the reform of the wholesale trading arrangements had a big impact on industrial customers, who benefited from falling electricity prices as a result of introducing competition. Price reductions were achieved by all individual users but these reductions varied larger in accordance with the bargaining power users, previous pricing arrangements and length of contracts.

Figure 9: Average Gas and Electricity Prices for Different Customer Types

Source: Ofgem based on analysis of DECC data

Despite the introduction of the Climate Change Levy (CCL) in 2001 the average annual industrial price in 2003 was at its lowest level since the 1970s. However, significant wholesale price increases since 2003 reversed this trend of falling industrial electricity prices and average electricity prices rose considerably between 2004 and 2006. More recently prices fell in 2007 before rising again in 2008 and 2009 before decreasing in 2010 and then rebounding in 2011 (see Figure 9 above). 9.3 Electricity and Gas Prices in Europe

There are significant variations in the price of electricity across Europe. These result from the underlying economics of power generation (such as differences in fuel costs and capital financing), market structure,

Figure10: Residential Electricity Prices Including Taxes (December 2015)

Source: http://www.energypriceindex.com/wp- content/uploads/2016/01/HEPI_Press_Release_December_2015_new.pdf

inflation, tax and exchange rates. Figure 10 shows EU domestic electricity prices in 2015. Figures released by DECC in December 2015 showed that average industrial electricity prices including taxes in the UK between Q3 2014 and Q3 2015 fell by 6.6% for gas and increased by 0.8% for electricity.

Figure11: Residential Gas Prices Including Taxes (December 2015)

Source: http://www.energypriceindex.com/wp- content/uploads/2016/01/HEPI_Press_Release_December_2015_new.pdf

10.1 General industry statistics

World  BP’s annual review

 IEA World Energy Outlook

 IEA Oil Market Report

 Opec’s Monthly Oil Market Report

 US Energy Information Administration

 European Commission

National  DECC’s Regional Energy Statistics––annual

 DECC’s Energy Statistics

10.2 Electricity generation companies

The companies listed here are some of the major generators in the UK.  Centrica––generation assets are dominated by CCGTs

 Drax Power––operator of UK’s largest, newest and most efficient coal-fired power station

 EDF Energy––operator of the UK’s nuclear fleet

 E.ON UK––fossil-fuel dominated generator operates large coal plants and CCGTs

 Intergen–– smaller independent player, which operates CCGTs

 ENGIE–smaller independent player, which operates CCGTs and pumped storage

 RWE Npower––fossil-fuel dominated generator operates large coal plants and CCGTs

 SSE––operates large coal plants and renewables

 Scottish Power––operates large coal plants and renewables 10.3 Gas and electricity suppliers

The Big Six are British Gas; EDF Energy; E.ON UK; RWE Npower; Scottish Power; and Scottish and Southern Energy Other electricity suppliers include:  Co-operative Energy: serving households and business customers

 Countrywide Energy: A company that specialises in supplying farming and rural communities

 Ecotricity: A green supplier offering renewable electricity and green gas to the household and business sector

 EBICo: A not for profit energy supply company

 First Utility: specialises in offering smart metering solutions to customers – both business and domestic

 Good Energy: supplies 100% renewable electricity to domestic and business customers

 Gazprom marketing and trading retail: a gas and electricity supplier to major energy users

 Green Energy UK: a niche supplier of green and low carbon power to domestics and small businesses

 Haven Power: an electricity supply company established specifically to serve the energy needs of smaller business customers

 International Power GDF SUEZ: a gas and electricity supplier to major energy users

 LoCO2 Energy: a niche new entrant providing green supply offerings to businesses and households

 Opus Energy: an independent supplier of electricity to the business sector

 SmartestEnergy: an independent energy trading operation giving embedded and renewable generators access to the energy market in the UK who have entered the business supply market

 Spark Energy: an independent supplier focused on the rental residential market

 Statkraft: primarily a generator, but just entering the UK retail market

 Utilita: a multi-utility company offering customers an incentive to save energy. Specialises in serving low-income households

 Utility Warehouse: an independent supplier of electricity to the domestic sector

 A full list of licensed electricity suppliers and licensed gas suppliers can be found from Ofgem

10.4 Transmission and Distribution Companies

In England and Wales transmission is defined as being the transfer of electricity from the generating plant to a point of distribution at voltages of 275kV or above. In Scotland transmission is defined at 132kV or above. At voltages below these respective values transfer of electricity between one point and another is known as distribution. There are four onshore transmission networks in the UK:  England and Wales operated by National Grid

 South of Scotland operated by SP Transmission

 North of Scotland operated by Scottish Hydro Electric Transmission

 Northern Ireland operated by Northern Ireland Electricity

There are also currently eight Offshore Transmission Owners (OFTOs) that own the transmission systems for a series of offshore windfarms: TC Barrow OFTO; TC Gunfleet OFTO Sands; TC Robin Rigg OFTO; TC Ormonde OFTO; Thanet OFTO; Blue Transmission Walney 1; Blue Transmission Walney 2; Blue Transmission Sheringham Shoal. England and Wales and Scotland are divided into 14 distribution areas and responsibility in the respective areas rests with the Distributed Network Operator (DNO). A list summarising all the transmission and distribution network operators can be found from the Electricity Networks Association. Information on charging and regulation and other relevant issues about electricity transmission and distribution can be found here. 10.5 Regulation

 Ofgem – The Office of Gas and Electricity Markets Authority - the UK regulator for both gas and electricity.

 CER – The Commission for Energy Regulation (CER) is the economic and safety regulator for the electricity, gas and water sector.  Utility Regulator: The Utility Regulator is responsible for regulating the electricity, gas, water and sewerage industries in Northern Ireland

 ACER – The Agency for the Cooperation of Energy Regulators has a mission to assist National Regulatory Authorities in exercising, at Community level, the regulatory tasks that they perform in the Member States and, where necessary, to coordinate their action and was established in 2010. It has an important role in the development of the network codes set out under the Third Package and in fulfilling obligations under the Regulation on Energy Market Integrity and Transparency (REMIT).

 Competition and Markets Authority - Details of the energy market investigation started in 2014, submissions and provisional findings

10.6 Industry Statistics

DECC. The Department of Energy and Climate Change provides annual statistics on production and consumption of energy in the United Kingdom, covering oil, gas, coal, electricity and renewables. DECC also provides a quarterly update called Energy Trends and Prices. Useful DECC links for power are:  Monthly demand by sector and country

 Monthly generation mix

Useful DECC links for gas are:  Monthly supply/ demand balance

 Quarterly consumption by sector

 Monthly imports and exports

Other useful electricity sources include:  BM Reports

 RTE France

Other useful gas sources include:  Bacton Interconnector

 National Grid Gas Storage

 National Grid Flow Data (Mod 006)

Eurogas produces an annual statistical report. The most recent one is here. The International Energy Agency provides data on energy in the UK from 2008 as well as some information on energy policy in the UK. The European Commission publishes a quarterly report on EU gas and electricity markets which contains a section on important price developments in the UK market over the quarter. 10.7 Consumer Prices

There are a range of useful sources: Delivered prices:  DECC

 Consumer Focus

Network charges  Energy Networks Association

 National Grid

Obligations  Ofgem renewables obligation

 HMRC Climate Change Levy

10.8 The GB Electricity Market

Energy UK is the trade association for the UK energy industry representing over 80 suppliers and generators of electricity and gas for domestic and business consumers 10.9 NETA / BETTA

The New Electricity Trading Arrangements came into force on 27 March 2001 and involve both the generators and the suppliers trading in the wholesale electricity market. The arrangements favour those generators that can accurately predict the likely generation and/ or supply, and also have the ability to respond to sudden

changes (by increasing or reducing generation and increasing or reducing demand). On 1 April 2005, NETA was extended to cover Scotland as is now known as BETTA. Changing face of the electricity supply industry in the UK. This paper summarises the history of the Pool and NETA. 10.10 The Pool

The Electricity Pool operated from 1 April 1990 to 26 March 2001 and dictated the way in which electricity was distributed around England and Wales. Unlike NETA (from 27 Match 2001), the Pool involved bids from only the generators who set the price of wholesale electricity via the System Marginal Price. A description of the electricity pool and how prices were calculated can be found here. Data for prices during the final stages of the operation of the pool can be found here. A paper that describes the characteristics and historical path of pool prices can be found here. A paper by David Newbury criticising aspects of the pool including incumbent market power, cost of entry, prices, and governance can be found here 10.11 The GB Gas Market

Other useful gas sources include:  iGT UNC

 Gemserv

 Joint Office of Gas Transporters

 Institute of Gas Engineers and Managers

 Oil and Gas UK

 SBGI

 Xoserve

 AiGT

 Supply Point Administration Agreement (SPAA)