Assessing Scotland s security of supply in the GB Electricity market OCTOBER 2014

Assessing Scotland s security of supply in the GB Electricity market OCTOBER 2014

Contents 1 Key messages 1 2 Introduction 4 2.1 Aims of this study 4 2.2 Scottish Government policy objectives 4 2.3 Context 4 2.4 Approach and structure of the document 5 2.5 Report structure 7 3 Drivers of security of supply 9 3.1 Electricity supply and demand in Scotland 9 3.2 The transmission network and interconnection in Scotland 12 3.3 Policy and market drivers 13 4 Defining security of supply 20 4.1 Security of supply frameworks 20 4.2 A taxonomy of security of supply problems 22 4.3 An example from overseas - Australia s National Electricity Market (NEM) 23 5 Scottish capacity margin scenarios 25 5.1 De-rated capacity margins 25 5.2 Baseline Scotland s current capacity 25 5.3 Scenarios - defined 27 5.4 Scenarios results 33 5.5 Sensitivities 35 Appendix 1 Important notice 40 Appendix 2 CfD Strike Prices 41 Appendix 3 Policy & Market Drivers further background 42

Appendix 4 New thermal policy drivers (by fuel) 51 Appendix 5 Scotland s Future Transmission Network 54 Appendix 6 References 56

1 Key messages 1.1. This report has been prepared by KPMG for the Scottish Energy Advisory Board (SEAB) on behalf of the Scottish Government. It considers the security of electricity supplies in Scotland between the present day and 2030 1, and the policy and market influences that are likely to shape the level and form of generation capacity present in Scotland over this period. The following key messages can be derived from the study: There are relatively weak incentives to build new thermal capacity in Scotland, or to continue to operate some existing thermal plant in the medium term. This reflects the competitive disadvantage of Scottish generation resulting from higher transmission charges, and in some cases plant efficiency. Project TransmiT has the potential to mitigate these cost disadvantages marginally. The security of energy supply in the Scottish market in the short term (now to 2020) seems largely secure, when considered in the context of the de-rated capacity margin however this security is largely dependent on the presence and operation of Scotland s three largest thermal plants (Hunterston, Torness and Longannet). This becomes more evident in the period beyond 2020 where our analysis shows a significant deterioration in Scotland s capacity margin. Interconnection within the Scottish market is currently limited although the completion of future projects could be key to improving the security of supply situation in Scotland subject to clarity on what the relevant measures and key determinants of capacity adequacy should be specifically for the Scottish market. Scottish settings to complement GB-wide mechanisms such as the Capacity Mechanism would appear to be an important potential focus for policy discussions, and have some precedent from other electricity markets internationally. For example, the policy question of whether a reliability standard should be set at GB-wide level, or a Scottish level. This has large implications in view of instances of capacity adequacy in other markets such as the Australian electricity market. There continues to be strong incentives to build onshore wind in Scotland, subject to the competitive CfD allocation process for "mature" technologies. Consequently, Scottish onshore wind is making a cost-effective contribution to the attainment of GB and Scottish targets for renewables. The prospects for offshore wind are more mixed. The overall budgets for low carbon generation support are set for the period to 2020/21. The value of flexible generation, such as pumped storage, is unlikely to be signalled in full through the market price for wholesale electricity. This is because the imbalance price will continue to be calculated after the costs of system balancing actions have been removed. If the value of such capacity is not signalled through the market or the capacity mechanisms, then the remaining route for signalling investment for flexible plant is through the provision of services to the system operator. The trend increase in the volatility of net demand in Scotland would appear to imply a growing importance for this route. 1 As part of our scope of work we have not been asked to comment on the likelihood of different scenarios, nor on the merits of different existing or potential energy policies. The relative merits of these approaches are not assessed in this document and the extent to which these approaches are considered, combined or adopted remains for policy makers. 1

As the volume of thermal capacity in Scotland reduces over time, the question of whether capacity margins are adequate is increasingly contingent on how the contribution of intermittent generation is measured. 1.2. These points arise from quantitative analysis of de-rated capacity margins under a range of scenarios. The scenarios are build on a common background for thermal plant, and a range of scenarios for new renewables, derived from existing UK government policy settings and modelling. This is illustrated in Figures 1 and 2 below. Figure 1: Trends in Scottish generating capacity 2014 to 2030, major capacity events 14.0 13.0 12.0 11.0 Beatrice Longannet Hunterston& Torness Torness Extension GW 10.0 9.0 8.0 7.0 6.0 2014 2016 2018 2020 2022 2024 2026 2028 2030 Built Under Construction/Commissioning Beatrice (664 MW) Torness Life Extension Source: DECC, KPMG analysis Figure 2: Trends in Scottish generating capacity 2014 to 2030, DECC scenarios 22.0 20.0 18.0 16.0 GW 14.0 12.0 10.0 8.0 6.0 2014 2016 2018 2020 2022 2024 2026 2028 2030 Built Under Construction/Commissioning Beatrice (664 MW) New Renewables (Low) New Renewables (High) New Thermal Source: DECC, KPMG analysis 1.3. We examine the evolution of capacity margins in this context, and using two key sensitivities: First, by considering a slower deployment of new renewables in Scotland that assumed in the ranges and analysis published by the UK government; Second, by assuming a lower de-rating factor to characterise the contribution of onshore and offshore wind to Scottish peak demand. 2

1.4. The findings of this analysis using National Grid s Slow Progression scenario are presented in Table 1 below. The results for National Grid s Gone Green scenario are also provided in the report. Table 1: De-rated capacity margins in Scotland in 2014, 2020 and 2030 Plant type Installed Capacity De-rated Capacity Scenario A 50% slower onshore rollout 10% de-rating factor applied to 50% wind (MW) 2014 2014 2020 2030 2020 2030 2020 2030 Wind 3,709 760 1,753 2,185 1,319 1,603 644 782 Hydro 1,071 899 973 979 973 979 973 979 Other renewables 441 218 313 307 313 307 313 307 Nuclear 2,150 1,742 1,742 0 1,742 0 1,742 0 Coal 2,260 1,989 0 0 0 0 0 0 Gas 420 372 372 372 372 372 372 372 Other nonrenewables 839 792 792 792 792 792 792 792 Total 10,890 6,772 5,945 4,635 5,511 4,053 4,836 3,231 Slow Progression Peak Demand Slow Progression De-rated Capacity Margin 5,560 5,230 5,140 5,230 5,140 5,230 5,140 22% 14% -10% 5% -21% -8% -37% 3

2 Introduction 2.1 Aims of this study 2.1. This report into the security of electricity supply in Scotland under a range of scenarios has been prepared to inform the Scottish Energy Advisory Board (SEAB). SEAB is a collaborative forum involving Ministers, senior industry and academic representatives that convenes for strategic discussion on the current and future energy challenges and opportunities for Scotland. 2.2. The report covers: A medium term assessment of Scotland s security of supply position in its own right in the context of the current UK policy and regulatory environment; An insight into the extent to which the regulatory, legal and technical arrangements provide sufficient social, commercial and economic incentives for Scottish generation assets to continue to contribute towards an adequate GB capacity margin; A high level indication of the potential system costs/risks borne by both domestic and commercial consumers (in Scotland and/or across GB) in the event of insufficient security and stability of supply. 2.2 Scottish Government policy objectives 2.3. In the Energy Generation Policy Statement 2013 the Scottish Government has outlined its policy priorities for the electricity sector as; A secure source of electricity supply; At an affordable cost to customers; Which can largely be decarbonised by 2030; and Which achieves the greatest possible economic benefit and competitive advantage for Scotland including opportunities for community ownership and community benefits. 2.3 Context 2.3. Scotland is undergoing a transformation in its generation mix. In 2009, there was 4.9 GW of coal or gas-fired generation capacity in Scotland participating in the GB wholesale market. In 2014, this figure has fallen to 2.7 GW. Over the same period, the volume of wind-powered generation capacity has increased by broadly the same amount. Policy settings and market signals suggest that this transition away from thermal generation towards renewables may well continue 2. 2.4. However, there are many uncertainties that could affect the evolution of the generation mix in Scotland. Two key uncertainties are: 2.5. First, the policy environment for non-renewable forms of generation is also in a period of change. There remain important implementation decisions regarding Electricity Market Reform to be put into place. 2 A high level review of National Grid s TEC Register demonstrates that the majority of proposed or planned new generation for Scotland over the period to 2030 are renewables and in particular wind sets. 4

Tight capacity margins at a GB level in the period 2014 to 2018 have resulted in additional policies being put into place outside of existing market arrangement, for example on 10 June 2014 National Grid announced its intention to procure up to 1.8 GW of reserve capacity outside of the market by National Grid in winter 2015/16 3 ; There is also some uncertainty regarding the continuing review, and potential reform, by Ofgem of transmission charging which will impact the location of new plant or the profitability of plant that must be built in specific locations. 2.6. Second, financial support mechanisms for renewable generation are being reformed, which impacts the willingness to invest in these technologies. The Renewables Obligation (RO) is being closed and Contracts for Difference (CfDs) are being introduced as part of the package of market changes that comprise Energy Market Reform (EMR); There remains uncertainty as to how decisions will be made regarding the allocation of Levy Control Framework (LCF) funding, for example allocations between technologies (including nuclear new build), and over the volume of new capacity that this budget will support in practice; and The budget for the LCF beyond 2020/21 is yet to be set, so longer term proposed projects cannot be certain as to the level of funding available. 2.7. Uncertainty in the funding support mechanism, among other issues, has been reflected in the commercial positions being taken by market participants. There has been, and there is likely to continue to be, a steady stream of public announcements relating to potential generation projects. To illustrate: in late 2013 Scottish Power announced its decision not to proceed with the planned 5.4 billion Argyll Array offshore 1.8 GW wind farm, this was followed in early 2014 by SSE announcing a major reduction in its generation investment programme 4. 2.4 Approach and structure of the document 2.8. We identify four main sources of potential issues with security of supply in the electricity sector: Overall capacity inadequacy; Adequate capacity in aggregate but insufficiently flexible; Adequate capacity in aggregate but with regional disparities; and Adequate capacity in aggregate but reliance on interconnection and the importing of power at peak times from other regions or jurisdictions. 2.9. To evaluate the impact of security of supply this report presents an analysis of de-rated capacity margins, this approach is consistent with Ofgem s approach to assessing capacity margins. The capacity margin is a measure of security of supply, gross capacity margins measure total capacity relative to peak demand. The de-rated capacity margin is adjusted for the extent to which different forms of capacity can be relied upon to be available at times of peak demand. The adjustment is made by applying a de-rating factor to each type of capacity. De-rated capacity margins are usually presented as a percentage and are calculated as: % 100 3 http://www2.nationalgrid.com/media/uk-press-releases/2014/national-grid-to-contract-for-new-balancing-services/ 4 http://sse.com/newsandviews/allarticles/2014/03/review-of-offshore-wind-farm-development/ 5

2.10. We use de-rating factors prepared by Ofgem for their 2013 Capacity Assessment 5 and apply them to plant capacity projections based on National Grid s TEC register 6. We are using data on TEC as a indicator of the volume of capacity which is participating in the market. TEC is the maximum level that an individual generator is permitted to notify as its physical position in any given half-hourly settlement period. 2.11. Calculation of the de-rated capacity margin requires developing an assessment of what plant will be built and operating over the medium term in Scotland. Our approach to assessing operating plant capacities is based on developing scenarios and sensitivities around: A base line of thermal plant operating in Scotland at present based on the NG TEC register (with the exception of using the data for EDF s nuclear plant capacities from the EDF website); Consideration of potential plant build scenario in line with DECC s scenarios National Grid s longer term scenarios for the period 2020 to 2030. 2.12. Informed by discussions with relevant stakeholders, we consider a baseline for thermal generation capacity in Scotland, assuming: The nuclear stations at Hunterston and Torness operate until their estimated decommissioning date of 2023 (however while also noting the commercial imperative to seek a life extension, where possible); Peterhead maintains Transmission Entry Capacity (TEC) of 400 MW for the duration of the period; and, Longannet power station ceases operation in 2019. 2.13. This constitutes a material reduction in Scottish thermal plant capacity over the medium term, and is illustrated in Figure 3 below. Figure 3: Trends in Scottish generating capacity 2014 to 2030, major capacity events 14.0 13.0 12.0 11.0 Beatrice Longannet Hunterston& Torness Torness Extension GW 10.0 9.0 8.0 7.0 6.0 2014 2016 2018 2020 2022 2024 2026 2028 2030 Built Under Construction/Commissioning Beatrice (664 MW) Torness Life Extension Source: DECC, KPMG analysis 2.14. Against this baseline we assess a range of scenarios for new-build renewable generation capacity. Our starting point is the forecasts published by DECC in its EMR Final Delivery 5 Ofgem: Electricity Capacity Assessment, 2013 6 Transmission Entry Capacity (TEC) related to transmission-connected generation, hence will not be a complete measure of generation capacity. 6

Plan. These ranges are presented by DECC as being consistent with the LCF budget, and with the published strike prices for CfDs in the first EMR delivery period (which runs to 2018/19). Figure 4: Trends in Scottish generating capacity 2014 to 2030, DECC scenarios 22.0 20.0 18.0 16.0 GW 14.0 12.0 10.0 8.0 6.0 2014 2016 2018 2020 2022 2024 2026 2028 2030 Built Under Construction/Commissioning Beatrice (664 MW) New Renewables (Low) New Renewables (High) New Thermal Source: DECC, KPMG analysis 2.15. As Figure 4 demonstrates, the new capacity that could be planned for Scotland is predominantly renewable energy. There is a wide range in the amount of generating capacity that could be added to the system in different scenarios between now and 2030. For the reasons given above, there is considerable uncertainty as to how much of this proposed additional renewable capacity will actually be commissioned. To address this uncertainty we undertook some sensitivity analysis for our security of supply assessment. 2.4.1 Sensitivities 2.16. We present two key sensitivities to the baseline: First, we consider a lower, slower deployment of wind, than shown in Figure 4. For example, reflecting the constraint of the LCF budget binding more quickly than anticipated, or a shift in policy. Second, we apply a lower de-rating factor for wind of 10% as opposed to 21%. A higher proportion of wind-powered capacity means that this parameter has a more material impact, and a factor of 10% has some precedent internationally. 2.17. We also consider volatility on the system. An additional security of supply challenge in Scotland relates to the ability of the power system to handle the output of large-scale intermittent generation. The retirement of thermal plant in Scotland would appear to make this challenge more acute, and also emphasises the importance of flexible plant (including pumped storage) in the capacity mix in Scotland. 2.5 Report structure 2.18. The report is organised in three further sections: Chapter 3 sets the scene for the report, by presenting some key factors about supply and demand in Scotland, the transmission system, and the prevailing policy context; 7

Chapter 4 describes different frameworks for security of supply, and different types of security of supply issues that can be experienced by electricity supply systems; Chapter 5 sets out the current de-rated capacity margin in Scotland, and rolls this forward based on new capacity under construction, planned closures, and a range of scenarios for new developments. It also illustrates how sensitive de-rated margins are to individual plant decisions, and to alternative supply and demand scenarios. 8

3 Drivers of security of supply 3.1. This section describes: The supply/demand balance and plant mix in Scotland currently, and in the recent past; Scotland s transmission network; and The high level policy environment and current wholesale market arrangements. 3.1 Electricity supply and demand in Scotland 3.2. This section provides a short overview of the supply and demand balance in Scotland currently, and in the recent past. It describes the form, scale and mix of power generation in Scotland and trends in electricity supply and demand in Scotland. 3.1.1 Generation capacity 3.3. There is approximately 11 GW of transmission-connected capacity in Scotland currently participating in the GB electricity wholesale market 7, plant locations are shown in the map below. Figure 5: Generation plant locations: Scotland 8 7 Based on volumes of built Transmission Entry Capacity (TEC) as at 24 th March 2014 National Grid: TEC Register, 2014 8 Source: http://www2.nationalgrid.com/uk/industry-information/future-of-energy/electricity-ten-year-statement/currentstatement/ 9

3.4. While the total installed capacity in 2014 is similar to 2009 the mix of generation has changed substantially over this period. The amount of coal or gas fired generation has reduced from 4.9GW to 2.7GW, and the amount of wind-power generation has increased from 2.1GW to 3.7GW. Installed nuclear capacity is unchanged throughout the period. Table 2: Participating, installed capacity in Scotland (2009, 2014) Plant type Capacity (MW) Number of plant Capacity (MW) Number of plant 2009 2014 Wind 2,096 46 3,709 66 Nuclear 2,150 2 2,150 2 Coal 3,406 2 2,260 1 Hydro 1,070 37 1,072 35 Pumped Storage 740 2 740 2 Gas 1,534 2 420 2 Microgeneration n/a n/a 239 [40,000+]* CHP 255 4 132 3 Oil n/a n/a 99 4 Biomass 45 1 63 4 Wave 0 0 7 1 Total 11,296 96 10,890 120 *The figure for microgeneration is derived from the total for the UK population, this takes account of domestic as well as non-domestic installations. Source: National Grid: TEC Register, 2009 & 2014 3.5. The reduction in available installed capacity reflects both plant closures and decisions to withdraw capacity from the market. The largest single case of this is 0.8GW of gas-fired generation withdrawn at Peterhead 9. The closure in 2013 of Cockenzie power station accounts for 1.2 GW of coal-fired capacity which left the market between 2009 and 2014. 3.1.2 Output and capacity factors 3.6. Output from installed capacity in Scotland has been relatively stable on aggregate at around 50,000 GWh a year. However, the composition of that output has changed significantly reflecting the growing contribution from wind-powered capacity. The contribution from nuclear generation has remained relatively stable throughout the period at around 17,000 GWh (or around 30-35% of Scotland s total output), as illustrated below. 9 Although National Grid has recently contracted for 400MW of capacity to remain available at Peterhead for system operation purposes. 10

Figure 6: Electricity production by fuel type: Scotland 2000 to 2012 60000 50000 40000 GWh 30000 20000 10000 0 2000 2002 2004 2006 2008 2010 2012 Biomass Coal Gas Hydro Hydro pumped storage Nuclear Oil Other Wind Source: DECC: Scottish energy statistics 3.1.3 Demand 3.7. According to Ofgem s 2012 electricity capacity assessment, peak demand in Scotland for 2012 was 5,478 MW. Electricity consumption in Scotland has been falling over the last decade as show below. Figure 7: Scottish electricity consumption, GWh (2005-2012) GWh 45000 40000 35000 30000 25000 20000 15000 10000 5000 0 2005 2006 2007 2008 2009 2010 2011 2012 Source: DECC 3.8. The reduction in electricity consumption in Scotland over the past few years is in the context of a general increase in both the Scottish population (representing a 3% increase) and the number of households in Scotland (representing a 5% increase). 11

3.2 The transmission network and interconnection in Scotland 3.2.1 The transmission network in Scotland 3.9. The Scottish electricity transmission network is split into two parts with two separate transmission system owners each responsible for maintaining and developing the Scottish electricity network. Scottish Hydro Electric Transmission Limited (SHETL) owns the network in the North of Scotland; with Scottish Power Transmission (SPTL) taking responsibility for the network in southern and central Scotland. Figure 8: Scottish transmission networks Source: SP Energy Networks, National Grid 10 3.10. National Grid s commentary regarding the Scottish Transmission network from their 2013 Ten Year Statement highlights the primary network challenge as being significant growth of renewable generation in remote areas, with a relatively low capacity and sparse network infrastructure. National Grid also highlight a number of regional drivers for transmission reinforcement, given forecast generation and demand. Specifically, it cites limitations in: Power transfer from remote locations to the main transmission system; Exporting power from Argyll and the Kintyre peninsula; Power transfer from north to south of Scotland; and Power transfer through Scotland into England. 10 Source: http://www2.nationalgrid.com/uk/industry-information/future-of-energy/electricity-ten-year-statement/currentstatement/ 12

3.11. National Grid observe that significant transmission reinforcement has been, and is being, undertaken (e.g. the Beauly to Denny reinforcement, due to be completed in 2015) to increase boundary capability and upgrade parts of the network where required. In this context, National Grid also note that further network constraint limits are being reached earlier than would otherwise be the case, as result of Connect & Manage arrangements. 3.2.2 Interconnection 3.12. Scotland currently has one interconnector, which connects the Scottish Transmission Network (via SPTL) with the transmission network in Northern Ireland with 250MW transfer capability. 11 The Scottish transmission network is connected to the rest of the GB transmission network via a 400KV double circuit transmission link from Elvanfoot/Gretna to Harker and another 400KV double circuit transmission link from Eccles to Stella West. 3.13. Scotland has a number of projects in the pipeline which aim to significantly increase Scottish interconnection capability, which will provide additional benefits in terms of Scotland s security of supply as well as the ability to export surplus electricity to interconnected markets: The Western HVDC Link subsea cable expected to have a capacity 2000MW with flows in both directions. The project is expected to commission in 2016; The Eastern HVDC link (capacity to be confirmed), potentially being considered for after 2020; The NorthConnect project which will, if progressed, link Scotland s transmission systems (via Peterhead) with Norway s electricity network at Samnanger. This proposed HVDC link will provide an anticipated 1,400MW of transfer capability, however the project is not due to be completed until at least 2021. 3.14. As well as confirmed and consented interconnection projects, there is a number of longer term projects which could have an impact on the Scottish electricity market. Current interconnector grid projects which could impact Scotland s security of supply status include the ISLES, the North Sea Offshore Grid, the European Supergrid and the Europagrid projects. Detailed analysis of these projects is not included within the scope of this report. 3.3 Policy and market drivers 3.15. The policy and market background for this study is fluid and uncertain. This uncertainty has, for example, influenced a number of recent announcements by market participants in respect of future investment plans. 12 In this context it is important to consider the potential drivers that might influence decision making by current or prospective holders of capacity. In this section we draw out the main drivers by non-renewable plant type in Scotland. Further information, across a wider range of potential drivers is provided in Appendix 3, and by plant type in Appendix 4. 11 Capacity across the interconnector is currently limited to 250MW due to a cable fault. It is anticipated that this interconnector will return to operating at its full capacity towards the end of 2017. 12 26th March 2014: SSE plc has decided to narrow significantly the focus of its near term development plans for its offshore wind development portfolio. During the remainder of 2014 SSE will focus its efforts and resources on progressing the Beatrice project: 13th December 2013: Scottish Power abandoned a 5.4bn plan to build the world's largest offshore wind farm, after four years of planning, because it is "not financially viable". At this time as well there is considerable press coverage of energy groups cancelling projects elsewhere in the UK citing that subsidies available for new wind projects are not high enough 13

3.3.1 Capacity mechanism (CM) 3.16. Legislation 13 introducing a capacity mechanism has been passed by UK Parliament. This is in conjunction with the Capacity Market Rules that provides the operating framework of the policy 14. Under current plans, the first capacity auction, also known as a T-4 four year ahead auction, will be held in December 2014 15 to deliver additional capacity for winter 2018. 16 3.17. The current design for the Capacity Market, as described in the Capacity Market Rules and Guidelines has the following key features: the Auction Parameters (which include the target capacity to be procured, demand curve, and price caps) are determined by the Secretary of State based on capacity assessments by the Delivery Body (National Grid); The UK Secretary of State has determined the reliability standard to be a Loss of Load Expectation (LOLE) of 3 hours per year and estimated that the cost of new entry (CONE) would be 47 per kw-year. 17 The Delivery Body will facilitate the Capacity Mechanism and auctions. The Delivery Body will advise the Secretary State each year on capacity requirements, the demand curve for additional capacity, and the types of capacity that are forecast to be contributing to meeting peak demand (e.g. interconnectors, indigenous generation, demand side response); the Delivery Body will issue guidelines that, among other things, set values for how different generation technologies should be de-rated for the purposes of participating in auctions; the auction will be a descending clock auction where all pre-qualified applicants start in the auction at the price cap and exit as the price decreases. All parties that remain at the clearing capacity will be awarded capacity agreements at the clearing price, subject to penalties for non-delivery and the overall price cap; Applicants are categorised into either prospective generators or existing generators. Prospective generators are price-makers who can set the price but existing generators are price-takers that have to participate in the auction by default and cannot exit the auction above a certain threshold ( 25/kW/yr for the T-4 auction). Prospective generators are also eligible for longer periods of capacity payments relative to payments made to generators currently operating in the market. This system is designed with the intention of achieving the lowest price required to provide the desired amount of additional capacity whilst encouraging new generation. Implications for different plant/plant types The CM is only relevant to plant that does not have a CfD; It makes the revenue stream of plant funded through the mechanism less reliant on the volume of electricity they produce hence reduces the likelihood of plant closing as a consequence of low running hours; 13 UK Government: The Energy Act, 2013 14 https://www.gov.uk/government/publications/capacity-market-rules 15 http://www2.nationalgrid.com/uk/our%20company/electricity/market%20reform/announcements/capacity%20mechanism %20Auction%20Guidelines/ 16 In addition to the capacity mechanism, National Grid are implementing two transitional arrangements, known as the Demand Side Balancing Reserve and Supplemental Balancing Reserve that in effect, enable limited contracting for capacity during the periods leading up to 2018. 17 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/335760/capacity_market_policy_presentation. pdf 14

It will be a significant consideration for the development of any new thermal plant in Scotland (e.g. a new CCGT); One question is whether, and how, National Grid may have regard to the location of capacity. Arrangements which place some weight on location might be expected to increase the likelihood of generators in Scotland being successful in CM tender rounds, and result in a higher clearing price compared to arrangements which were indifferent to location. 3.3.2 Large Combustion Plant directive (LCPD) / Industrial Emissions Directive (IED) 3.18. The EU s Large Combustion Plant Directive (LCPD) entered into force in 2001. The LCPD effectively places a limit on the emissions produced by large combustion plants (LCPs). Under the directive, plants that do not meet the specified emission standards must either retrofit appropriate pollution abatement equipment or close down. Plants that opt out of this can operate for a maximum of 20,000 hours after January 2008 and must shut down by the end of 2015, regardless of whether its allocated hours have been used up. 3.19. The Industrial Emissions Directive (IED )18 supersedes the LCPD. It came into force in the EU in January 2011 and was transposed into UK national legislation in 2013. The LCPD s requirements are still valid under the IED. Large combustion plants already in operation before 6 th January 2013 will need to meet IED requirements by 1 st January 2016. Emission limits will be further constrained by the IED, which will require large combustion plants to install further abatement technologies. The directive highlights the concept of using Best Available Technology (BAT) in controlling emissions and, in fact, emission limit values (ELVs) must be based on BAT. Thus, the IED contains certain elements of flexibility by allowing the licensing authorities to set less strict emission limit values in specific cases. Such cases include when the achievements of emission levels implied by BAT would lead to disproportionately higher costs compared to the environmental benefits (due to geographical location, local environmental conditions or the technical characteristics of the installation). Implications for different plant/plant types The most direct implication of the LCPD / IED in Scotland, is as a significant contributing factor to the closure of coal-fired plant at Cockenzie; The impact to Scotland s plants currently in operation is not fully known, as the deadline for opting in to the IED arrangements is January 2016, however due to Longannet and Peterhead s current emissions profiles, it is likely that these plant will be impacted. 3.3.3 Emissions Performance Standard (EPS) 3.20. Emissions Performance Standard sets an annual limit on carbon emissions from new fossil fuel plant. The EPS is applicable to new fossil fuel power stations with capacities of 50MW or over. It is not applied retrospectively, although it would be applied to existing plant that undergoes significant upgrades or life extensions. There is scope for exceptions to be granted in order to maintain energy security. 3.21. The stated purpose of the EPS is to prevent the building of new coal-fired power stations unless they are equipped with sufficient carbon capture and storage (CCS). The standard is calibrated to permit the building of new gas-fired power stations. The standard is set at 450g/KWh. Implications for different plant/plant types The EPS constrains options for new thermal plant in Scotland to exclude power stations without CCS. Any options to significantly upgrade or extend the life of Longannet power station would also need to comply with the requirements of the IED, unless an extension were to be granted. 18 Department for Environment, Food & Rural Affairs: Industrial Emissions Directive 15

3.3.4 Carbon pricing: EU ETS and Carbon Price Floor (CPF) 3.22. The ETS is an EU wide scheme, which aims to reduce greenhouse gas emissions through a system of tradable carbon allowances for companies in specific industries in 31 countries. 19 It works on a cap and trade principle: the amounts of greenhouse gases that are permitted from covered industries are capped, and allowances can be traded between parties to ensure effective allocations. Since 2013 there has been a single EU-wide cap put in place. Caps are reduced over time to bring down total emissions. By 2020 the total emissions by covered sectors will have decreased by 21% relative to the baseline. 20 3.23. Allowances are distributed either by free allocation or auctioning. During the first and second trading periods under the scheme, member states had to draw up National Allocation Plans (NAPs) outlining total ETS emissions and emissions per plant or industrial unit. From 2013, NAPs are no longer required and power generators must buy all their allowances: none will be permitted through free allocations. Forty percent of allocations were auctioned in 2013. 21 Prices of allowances are determined by supply and demand. In 2012, 7.9 billion tonnes worth of allowances were traded at an average price of just over 7 per tonne. 22 3.24. The UK also has a carbon price floor (CPF). The target price for carbon in 2013 was around 15.70 23 per tonne of CO2 emitted. As forecast market prices were below target price, the carbon price support - the top up tax which electricity generators must pay on fossil fuels - was set at the equivalent of 4.94 per tonne of carbon dioxide 24 emissions. This will rise to 18.08 in 2015-16 25 but will thereafter be capped until 2020, as announced by the Chancellor in the 2014 budget. 26 Implications for different plant/plant types The EU ETS and CPF increase the short-run marginal cost of non-renewable generation plant. It therefore contributes to reducing the number of hours that such plant runs. It also contributes to higher wholesale prices when such plant does run. 3.3.5 Connection: Connect and Manage 3.25. All applications to connect to the transmission system are managed by National Grid, irrespective of location. The process concludes with the connecting party being allocated Transmission Entry Capacity (TEC), which affords the right to generate up to a specified limit at any time. 3.26. Substantial changes were made to these rules in 2010 to accelerate connection dates. Connect and Manage was introduced in 2011 27, replacing the prevailing Invest then Connect approach. Connecting parties are allocated TEC before the physical network is fully capable of accommodating the additional capacity. National Grid then manages the resulting constraints, while the reinforcement works are catching up. The associated costs are socialised through BSUoS. 3.27. The latest Connect and Manage report covering the period to September 2013 highlights that the approach in Scotland has affected 126 large projects (all renewables, 15.6GW capacity in total), with an average reduction in offered connection data of 5.8 years, and 15 of which 19 28 EU member states, as well as Norway, Iceland and Lichtenstein which opted into the system in 2009. 20 European Commission: EU ETS factsheet 21 European Commission: The EU Emissions trading system, 2013 22 Ibid. 23 HM Revenue and Customs: Carbon Price floor consultation: the government response, 2011 24 HM Revenue and Customs: Carbon Price Floor: Rates from 2015-2016, exemption for Northern Ireland and technical changes 25 Ibid. 26 HM Revenue and Customs: Carbon Price Floor 27 Ofgem: Monitoring the Connect and Manage electricity grid access regime, 2013 16

(comprising 743MW) have already connected. 28 National Grid estimate that connection dates will be the same under both approaches by 2023, given planned network reinforcement. Implications for different plant/plant types Connect and manage has the effect of accelerating the connection of new, renewable generation. A large proportion of this is in Scotland. Hence, C&M has the effect of accelerating the change in the plant mix in Scotland and the consequent change to operating hours for thermal plant. C&M is also a driver for the volume and form of actions taken by the system operator The addition of new capacity in Scotland also impacts on the relative level of transmission charges in Scotland. More generation in Scottish zones tends to increase transmission charges relative to other zones although Project TransmiT would tend to negate this impact somewhat. 3.3.6 Transmission access and charging 3.28. Access to the transmission system (and hence access to the GB price for wholesale electricity) is provided on a firm basis, contingent on the allocation of Transmission Entry Capacity (TEC). TEC is provided pursuant to a connection agreement, and cannot be altered unilaterally by the System Operator. 3.29. Transmission access comes with associated charges. There are two forms of charge relating to use of the transmission system: Transmission Network Use of System (TNUoS); and, Balancing Services Use of System (BSUoS). There are also charges for losses (which are given effect by adjusting the amount of electricity deemed to have been sold in any given half hour, by a non-locational loss factor ). 3.30. TNUoS charges are levied on the basis of generating capacity, and vary by zone. There are 27 generation charging zones, of which 12 are located in Scotland. There are 14 demand charging zones, of which two are located in Scotland. Charges to generators are on a /kw basis. Differentials in charges are designed to reflect the long-run marginal cost of providing additional transmission capacity at different locations. 3.31. The basis for setting TNUoS has been subject to an Ofgem review ( Project TransmiT ) September 2010. Ofgem s decision on Project TransmiT is likely to result in charges to intermittent generators (e.g. wind turbines), varying less by location than is currently the case. This derives from a change in methodology to reflect the less significant impact that forms of intermittent generators have on transmission investment compared to other forms of capacity. 29 3.32. BSUoS charges are levied on the basis of generated output, and do not vary by location. They are designed to recover the day-to-day costs of balancing the transmission system. Charges are calculated daily based on out-turn balancing costs. National Grid also publishes a monthly forecast of BSUoS charges. Implications for different plant/plant types TNUoS is the only component of the GB wholesale market design that results in cost or prices that vary by location energy, balancing charges and losses are all non-locational. The current charging methodology increases the cost of locating generation in Scotland, compared to other areas of GB; this therefore makes generation in Scotland less competitive in GB-wide competitive processes, such as the CM and (in the longer term) CfDs. 28 Ibid. 29 This is proposed to be given effect by separately identifying the locational charge relating to peak system security, and exempting intermittent generators from it. 17

The impacts are mitigated to a degree by Project TransmiT s proposed methodology change, both directly and indirectly, however, this has not been finalised. 3.3.7 System Operation: Ancillary services and Short-Term Operating Reserve (STOR) 3.33. The responsibility for balancing the GB transmission system in real time resides with National Grid, in its role as GBSO. This task relies on a combination of market mechanisms and regulatory obligations. 3.34. Users of the transmission system are subject to a range of obligations to support the secure operation of the network. These obligations are contained within connection agreements and industry codes, notably the Grid Code 30. National Grid routinely procures a range of balancing services, through a variety of contractual routes. The range of services includes: o fast reserve; o short-term operating reserve; o frequency response; o black start; and o constraint management. 3.35. Tight capacity margins at a GB level in the period 2014 to 2018 have resulted in additional balancing services being procured by National Grid outside of existing market arrangements. On 10 June 2014 National Grid announced its intention to procure up to 1.8 GW of reserve capacity outside of the market by winter 2015/16 31 3.36. The costs incurred by National Grid in balancing the transmission system are recovered from users of the transmission system through Balancing Services Use of System (BSUoS) charges. These are levied on generators and demand customers, on the basis of production or consumption volumes. The charges are calculated daily, based on actual costs, and do not vary by location. 3.37. The amount National Grid is permitted to recover is, however, subject to a set of financial incentives. These, in effect, set a target cost, with a profit/loss sharing arrangement for any differences between actual and target costs. There is a cap on profits and a floor on losses. Implications for different plant/plant types 3.38. The provision of services to the System Operator (either within the market, or on a bilateral basis) is an alternative revenue stream for generators in Scotland. 3.39. The size of this revenue stream is contingent on the services required by the SO which in turn reflects how market participants choose to operate. 3.40. There are a number of factors where stylised assumptions made for the purpose of enabling the market to operate are increasing the potential role of the SO, these include, but are not limited to: The current Connect and Manage arrangements; Assumptions that all patterns of production consistent with allocated TEC can be safely and securely accommodated within the system and where the costs of system balancing are not reflected in the imbalance price. Potentially, under the CM, the assumption that capacity can be considered in non-locational terms (in the context of a transmission network that includes HVDC transmission circuits). 30 National Grid: The Grid Code 31 http://www2.nationalgrid.com/media/uk-press-releases/2014/national-grid-to-contract-for-new-balancing-services/ 18

3.3.8 EU Internal Energy Market Overview The Internal Energy Market 32,33 is an ambitious EU objective aimed to harmonise European markets through regulatory instruments approved by the European Commission. This involves a variety of policy initiatives to develop a competitive and interconnected internal market while establishing frameworks for public procurement and taxation. Examples of specific initiatives include the Agency for the Cooperation of Energy Regulators (ACER), joint electricity trading, Priority Interconnection Plan and transparency in prices, among others. There are also various Framework Guidelines and Network Codes which will effectively replace aspects of GB regulation from 2014 onwards. The liberalisation of electricity markets and their increased integration in one internal electricity market create challenges for ensuring generation adequacy. As the Commission indicated in its Communication Making the internal energy market work, with the development of a competitive internal electricity market with multiple producers and unbundled network operators, no single entity can on its own ensure the reliability of the electricity system any longer. The role of public authorities in monitoring and ensuring security of supply, including generation adequacy, has consequently become more important. 34 Implications for different plant/plant types In theory the EU internal energy market is proposed to deliver a number of benefits such as increased integration of cross-border interconnections, the coupling of cross-border exchanges, as well as price liberalisation resulting in improved security of supply and a smoothing of price differentials across the continent and consequentially a reduction in prices. However in practice the price of energy is dependent upon a range of supply and demand conditions and in the short term these factors are indicative of domestic conditions. Within a wider and longer term context additional price determining factors include the geopolitical situation, import diversification, network costs, environmental protection costs, severe weather conditions, and levels of excise and taxation. Because the Internal Energy Market is comprised of a series of policies, it is difficult to determine the direct implications on Scottish plants. However, the primary impact of EC legislation would be that Scotland, if part of the EU, would be subjected to regulation and legislation outside of its control. Furthermore, new network codes would determine interconnection between EU member states such as with Ireland via the Moyle interconnector. 32 http://europa.eu/legislation_summaries/energy/internal_energy_market/index_en.htm 33 http://ec.europa.eu/energy/gas_electricity/internal_market_en.htm 34 http://ec.europa.eu/energy/gas_electricity/doc/com_2013_public_intervention_swd01_en.pdf 19

4 Defining security of supply 4.1. This chapter sets out the different ways in which security of supply can be defined. We then draw out the different forms of security of supply issues that could potentially materialise. We illustrate with a comparison to the Australian market, as a relevant comparator of a national liberalised market with regional interests. 4.1 Security of supply frameworks 4.1.1 The role of standards 4.2. A reliability standard might be explicitly stated, as a designated target; or might be implicit in how the market is designed to operate, e.g. the level at which the market price is permitted to clear. Reliability standards can be expressed in a number of ways for example as a capacity margin (of generation over demand, at peak times), a loss of load probability, or an expected volume of un-served energy. 4.3. The attainment of the desired reliability standard will be influenced by the capabilities of the transmission network, as well as the availability and presence of sufficient generating plant. The planning standard for transmission is often specified in regulation, and relates to the ability of the transmission system to cope (i.e. to continue to transfer power in a manner which maintains the balance of supply and demand across a secure network) under various conditions. 4.1.2 Market architecture 4.4. The objective of maintaining a desired level of security of supply will be reflected in the market design, market institutions and forms of regulation. Three important component parts are: Wholesale market design: encompassing how prices for power (and available capacity) are set, and how access to those prices is determined; System operation: encompassing how services which are ancillary or complementary to the market, but required for the safe operation of the power system, are procured and priced; and Transmission investment planning: encompassing how decisions to reinforce or extend the transmission system are made, and funded. 4.5. Security of supply is not the only policy objective for energy markets. The carbon-intensity of the outcomes is an increasingly important parallel consideration, as is cost. The design and implementation of policy measures to promote low carbon energy, and how effectively they integrate with the existing market arrangements and institutions, constitutes a significant challenge in many energy markets. 4.1.3 Application in GB 4.1.3.1 Wholesale market design 4.6. Electricity wholesale market designs in GB have evolved substantially over the past fifteen years. Over this relatively short period (as compared, for example, to the operational life of a power station) market participants have experienced the following: 20

A gross pool for energy 35 with a form of capacity payment, and an administered price in Scotland pegged to the pool price in England & Wales (until 2001); A net, energy only market 36 in England & Wales, and an administered price in Scotland linked to a basket of prices in England & Wales (between 2001 and 2005); and A net, energy only market in GB (from 2005 to date). 4.7. The UK Government s Electricity Market Reform (EMR) is introducing further changes to this market design. This will lead to the introduction of a capacity mechanism. Under current plans, the first capacity auction will be held in 2014 for capacity to be available in 2018. There are also some transitional arrangements that, in effect, enable limited contracting for capacity to be delivered before 2018. 4.8. A formal reliability standard for the GB power system has only recently been articulated explicitly in the context of the implementation of the capacity mechanism. It is set at a Loss of Load Expectation (LOLE) of 3 hours/year. This translates to a system security level of 99.97%. National Grid, as the EMR Delivery Body, has a key role in advising the UK Secretary of State on the translation of the reliability standard into a demand curve for the capacity mechanism. 4.9. The standard is derived from an estimate of the Cost of New Entry (CONE) and an estimate of the Value of Lost Load (VoLL). DECC estimate CONE as being 45,000/MW-year, representing the new build cost of peaking generation (assumed to be an open cycle gas turbine). Ofgem estimate the value to the average customer of preventing disconnections at times of system peak as being 17,000 per MWh. Hence, a new peaking plant operating for three hours per annum would recover its costs. In this stylised analysis it would not be profitable for the market to invest in capacity that delivers more reliability than this. The UK Government has committed to review this standard every five years 37. 4.1.3.2 System operation 4.10. The responsibility for balancing the GB transmission system in real time resides with National Grid, in its role as GBSO. This task relies on a combination of market mechanisms and regulatory obligations. National Grid routinely procures a range of balancing services, through a variety of contractual routes. The range of services includes, but is not limited to 38 : fast reserve: provides the rapid and reliable delivery of active power through an increased output from generation or a reduction in consumption; short-term operating reserve: provides reserve power in the form of either generation or demand reduction to be able to deal with actual demand being greater than forecast demand and/or plant unavailability; frequency response: can be used (within limits) to determine and control the balance between system demand and total generation, when demand is greater than generation, the frequency falls while if generation is greater than demand, the frequency rises; maximum generation: this allows National Grid access to capacity which is outside of the Generator's normal operating range in emergency circumstances; and constraint management: in the event that the system is unable to flow electricity in the way required, National Grid will take actions in the market to increase and decrease the amount of electricity at different locations on the network. 35 A gross pool is a market in which all spot energy must be traded via a market that is priced and settled centrally. Hedging contracts are generally expressed as contracts-for-difference relative to the pool price. 36 A net market is one in which only imbalances (between contracted and actual volumes) are priced and settled in the centralised market. 37 DECC: EMR Final Delivery Plan, Dec 2013 38 National Grid: Balancing Services, 2014 21