ECONOMY, ENERGY AND

TOURISM COMMITTEE

15th Meeting, 2015

Wednesday 3 June 2015

The James Clerk Maxwell Room (CR4)

Meeting starts at 09.45 am

Previous Meetings Previous Meeting Papers and Official Reports Correspondence/Events Written Submissions WWF Scotland, Friends of the Earth Scotland and RSPB Scotland SSE SP Energy Networks Ofgem National Grid Background Papers

Agenda

Next Meeting is Wednesday 10 June 2015: Expected to start at 9:45am.

www.scottish.parliament.uk/economy

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ECONOMY, ENERGY AND TOURISM COMMITTEE

AGENDA

15th Meeting, 2015 (Session 4)

Wednesday 3 June 2015 The Committee will meet at 9.45 am in the James Clerk Maxwell Room (CR4). 1. Security of Supply: The Committee will take evidence from—

Dr Neal Wade, Senior Research Associate, School of Electrical and Electronic Engineering, Newcastle University; Gina Hanrahan, Climate and Energy Policy Officer, WWF Scotland; Marco Giuli, Policy Analyst, European Policy Centre; Malcolm Keay, Senior Research Fellow, Oxford Institute for Energy Studies;

and then from—

Mike Calviou, Director, Transmission Network Service, National Grid; David Gardner, Director of Transmission, Scottish and Southern Energy; Eric Leavy, Head of Transmission Network Planning, Scottish Power Energy Networks; Kersti Berge, Partner, Electricity Transmission and Head of Ofgem in Scotland, Ofgem.

2. Subordinate legislation: The Committee will take evidence on the Registers of Scotland (Voluntary Registration, Amendment of Fees, etc.) Order 2015 [draft] from—

Fergus Ewing, Minister for Business, Energy and Tourism, Colin Miller, Head of Policy, Claire Anderson, Drafting Solicitor, and Charles Keegan, Head of land register completion, Scottish Government.

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3. Subordinate legislation: Minister for Business, Energy and Tourism to move—

S4M-13318—That the Economy, Energy and Tourism Committee recommends that the Registers of Scotland (Voluntary Registration, Amendment of Fees, etc.) Order 2015 [draft] be approved.

4. Review of evidence heard (in private): The Committee will review the evidence heard earlier in the meeting.

Douglas Wands Clerk to the Economy, Energy and Tourism Committee

Room T2.60 The Scottish Parliament

Edinburgh Tel: 0131 348 5207

Email: douglas.wands@scottish.parliament.uk

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The papers for this meeting are as follows— Agenda Item 1

PRIVATE PAPER

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WWF written submission

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SSE

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SP Energy Networks

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Ofgem

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National Grid

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Agenda Item 2

PRIVATE PAPER

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JOINT SUBMISSION FROM WWF SCOTLAND, FRIENDS OF THE EARTH SCOTLAND AND RSPB SCOTLAND

Scotland’s Changing Power Sector

Summary of Key Points:

Independent research shows Scotland can securely and cost-effectively meet its 2030 power sector decarbonisation target with almost 100% renewable electricity generation, playing to its natural strengths as part of a secure GB grid. Over the course of the year, Scotland will continue to be a major net power exporter.

Security of supply is delivered at a GB level in a single integrated grid. The GB grid is secure, with numerous tools in existence, or being put in place, to ensure enough capacity is always available to meet demand. The notion of a ‘Scottish capacity margin’ is simplistic and incomplete, particularly once adequate transmission capacity is in place allowing any potential shortfalls between demand and supply during periods of low renewables output to be met.

Unabated (i.e. without CCS) gas power is incompatible with decarbonisation in Scotland by 2030 unless it is idle for much of the time. If the Scottish Government is to meet its 2030 decarbonisation target, it must rule out consenting any new thermal power that is not fitted with CCS from the outset.

The Scottish Government’s Electricity Generation Policy Statement needs to be reviewed to reflect the changing economics of renewables, the slow progress of CCS, the outcome of Project Transmit and the economic/political realities of thermal power in Scotland and across the UK.

The most cost-effective approach to securing and decarbonising the electricity system is through electricity demand reduction. Whilst the Scottish Government has only some powers in this area, it is currently afforded too little emphasis and the Scottish Government should introduce an electricity demand reduction strategy accordingly.

In addition to progress with well-sited renewables development and demand reduction, demand-side response, interconnection, decentralisation of generation, enhanced transmission and storage can all play a role in delivering security of supply and help to reduce the need to build new generating capacity. The UK Government currently fails to adequately support these wider system services, and it should make amendments to the Electricity Market regime to incentivise them and level the playing field with generation.

The UK and Scottish Governments need to work with industry to develop new revenue streams to incentivise investment in pumped storage, which has an important role to play in balancing variable renewable generation.

The capacity market as currently designed provides a windfall to aging coal plant. Cross-party support exists for phasing out coal generation, and the UK Government should therefore reform the capacity market to encourage coal phase out.

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Introduction to Scotland’s Changing Power Sector

Scotland is in the midst of a major power system transition – away from the aging, polluting, centralised and increasingly uneconomic thermal generation of the last century towards a clean, dynamic, interconnected and increasingly cost-competitive renewable-centred system. Renewables are already meeting almost half of Scotland’s demand for electricity and were the single biggest source of power in the first half of 20141.

Scotland’s energy transition is by no means unique. The role of old baseload power stations is being eroded with every new megawatt (MW) of renewable capacity built around the world. Already in Germany we are seeing periods when fossil fuel power is scarcely required. The impact of this is most clearly seen in the decision by E.On to radically restructure its business model to cut off its nuclear, and fossil fuel operations and focus on its thriving renewables business. Other countries such as Denmark and Sweden are also managing to slash emissions from their power sectors, whilst advice from the UK Committee on Climate Change indicates that the UK power sector will also need to decarbonise on par with Scotland by 2030.2

Maintaining system security during this energy transition is essential. Independent analysis by engineering consultancy DNV GL3 shows that almost entirely renewable generation is perfectly feasible and cost effective in Scotland by 2030, with efforts to manage demand and enhance flexibility, with Scotland playing to its natural strengths as part of a secure GB grid.

With abundant resources and a thriving green energy industry, it’s clear that Scotland can continue to be at the forefront of this transition with continued progress with well-sited renewable energy and sensible, evidence-based policy choices on security of supply.

The Scottish Government must take policy decisions consistent with its long-term decarbonisation target.

Q1: Is there sufficient generation to meet demand to the end of the decade? What role will new generation play in Scotland? What does the decarbonisation target mean in practice? Are there enough tools to bridge the move from fossil fuels to renewables?

The integrated GB grid provides security of supply with robust transmission links

There is more than adequate generation capacity to meet peak demand in Scotland, which is reducing over time as economic growth decouples from energy use4. The imminent closure of Longannet coal plant will reduce the availability of de-rated generation capacity located in Scotland by approximately 2 GW.5 However, Scotland is not an energy island. It is an integrated part of the GB grid and does not therefore need a standalone Scottish capacity

1 http://www.scottishrenewables.com/news/historic-milestone-new-figures-show-renewables-now/ 2 http://www.theccc.org.uk/publication/fourth-carbon-budget-review/ 3 WWF Scotland report Pathways to Power: Scotland’s route to clean, renewable, secure electricity by 2030. http://assets.wwf.org.uk/downloads/pathwaystopower.pdf. Technical Report by DNV GL available here: Implications of a Decarbonised Power Sector in Scotland by 2030. http://assets.wwf.org.uk/downloads/implications_of_a_decarbonised_power_sector_in_scotland_by_2030_dnv_gl_wwfscotland_fi_1.pdf 4 KPMG (2014): Assessing Scotland’s security of supply in the GB market: http://www.gov.scot/Topics/Business-Industry/Energy/resources/working-groups/energy-advisory-board/SecurityofSupply Scotland’s notional de-rated capacity margin is currently more than 22%. By 2020, in all scenarios studied Scotland still has substantial excess capacity by 2020, even allowing for coal phase out in that year, although the balance will change with nuclear phase out in the 2020s which will be offset by transmission reinforcement. However, the scenarios did not model the effect of Longannet’s closure in 2016, although this has been done elsewhere by National Grid, SHETL and SPT (see main text). Demand is currently approximately 5.5GW, expected to fall to 5.2 by 2020, rising slightly by 2030. 5 De-rated capacity is the installed capacity adjusted for the extent to which individual technology types can be relied on at times of peak demand.

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margin. Provided there is sufficient transmission capacity to the rest of the GB this will not pose a security of supply risk and Scotland will continue to be a net-exporter of electricity to the rest of GB.

Analysis by National Grid, SHETL and SP Transmission shows that transmission capacity to England and Wales can already support a transfer to Scotland in the winter months of approximately 2.65GW (48% of peak demand), rising to 3.9GW (70% of peak demand) once the Western HVDC bootstrap and the Beauly-Denny line are completed in 2017. De-rated generation capacity required from 2017 in Scotland is approximately 1.6GW in total, which is substantially less than existing nuclear and renewables capacity. 6 With 70% of Scotland’s peak demand backed by transmission links to the rest of GB, the need for conventional thermal power to be located in Scotland will be reduced. This need will continue to fall as transmission links increase, driven by installed renewables capacity.

There will be more than enough transmission to exceed any shortfall created by Longannet’s closure at peak demand. National Grid has also prudently procured voltage control services from Peterhead to ensure system stability until the Western HVDC link is operational. Moreover, figures from DECC and the Scottish Government show that Scotland’s electricity generation will still comfortably exceed Scottish demand across the course of a year without Longannet, so Scotland will continue to be a net exporter of electricity to the rest of Great Britain.7

Scotland’s decarbonisation target will be achieved at lowest cost through renewable generation & efforts to manage demand and enhance flexibility

Longer-term, the Scottish Government’s policy to hit its power sector decarbonisation target of 50g CO2/kWh by 2030 is set out in the Electricity Generation Policy Statement (EGPS)8. This envisages high levels of renewables, coupled with 2.5GW of gas plant progressively fitted with CCS and no new build nuclear. However, the slow pace of CCS development globally, concerns about its commercial viability and the weak business case for new thermal power in Scotland9 mean this scenario is unlikely to be borne out in reality and will need to be updated10. This means in practice that the decarbonisation target will be achieved in Scotland through renewable generation, which, coupled with efforts to manage demand, will be lower cost than scenarios with high amounts of CCS.

WWF Scotland commissioned an independent study by engineering consultancy DNV GL to test security of supply in 2030 with almost entirely renewable generation located in Scotland (save for the 340 MW CCS demonstration project at Peterhead). It showed that “with the transmission capacity to the rest of GB currently existing or planned, there is little or no need for conventional generating capacity in Scotland to maintain security of supply, even in periods of low renewables”. The scenario builds in feasible progress on reducing electricity demand (1%/year) and new pumped storage (three new 600MW schemes), both of which need additional policy support from both UK and Scottish Governments.

6 National Grid (2015): Security of Electricity Supply in Scotland 7 See WWF Scotland briefing at: http://assets.wwf.org.uk/downloads/wwf_scotland_briefing___scottish_conservative_energy_debate_25th_feb_2015_.pdf?_ga=1.232067100.2090807888.1430927136 8 http://www.gov.scot/Topics/Business-Industry/Energy/EGPSMain 9 KMPG report 10 We support the testing of CCS at Peterhead but given the slow pace of development it is critical that energy system planning does not rely on its commercialisation and risk locking in unabated thermal power.

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The report shows that the decarbonisation target can be achieved well within the current renewables pipeline, which currently stands at over 12GW of pre-operational capacity in addition to over 7GW already installed. However, this should not be seen as a cap by any means. Future renewables growth will be dictated by the economics of renewables, climate imperatives, and the wider planning and environmental constraints on individual projects.

During infrequent periods of high demand and low renewables production, power will flow to Scotland from the rest of GB, but ongoing and planned grid upgrades will be more than enough to accommodate this (potentially rising to 13GW by the mid-2020s) and the balance will be firmly in Scotland’s favour overall. On an annual basis, the study shows that, under this scenario, Scotland would remain a net power ‘exporter’.

While there are a number of system stability issues associated with the move towards high levels of renewable generation and the phase out of conventional thermal power in Scotland (such as black start and voltage control), options for mitigating any potential grid impact are being considered by National Grid in its System Operability Framework. This will ensure that system stability remains robust in the low carbon transition. In its analysis, DNV GL is confident that solutions to any challenges can be found.

There are multiple tools to ensure security of supply across the UK

In terms of overall GB-wide security, the Committee on Climate Change, National Grid and others have published long-term decarbonisation scenarios that maintain system security with high levels of renewables. While the GB capacity margin has tightened in recent winters, it is due to rise again by winter 2016/17, and a suite of balancing tools is already available to National Grid to prevent any supply disruptions and ensure that capacity is always available to meet demand. The capacity market from 2018 onwards is specifically designed to ensure adequate capacity is available to meet demand as older thermal plants are phased out. We suggest improvements to this mechanism at question 4 below.

What role for gas generation in Scotland?

Most power sector decarbonisation scenarios envisage a ‘bridging’ role for flexible gas plant to help manage the transition to renewables.11 While it is feasible that some of this generation could be based in Scotland, given the transmission regime, it is likely to be cheaper to locate it closer to major demand centres in England. DNV GL’s analysis shows that while, in principle, a 1GW gas plant could be located in Scotland, it would have to operate at a low capacity factor (<50%) to avoid breaching the decarbonisation target, which further undermines the economic case for new gas plant in Scotland.

If the Scottish Government is to achieve its decarbonisation target and fulfil its climate change commitments, it must rule out consenting any new thermal power that is not fitted with CCS from the outset.

Q.2 What impact will demand-side response have and what can be done to improve developments in this area?

Demand-side policy is the most cost-effective approach to achieving security of supply

11 See UKERC (2013) The UK Energy System in 2050: Comparing Low Carbon Resilient Scenarios.

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Far less gas generation capacity will be required across the UK to complement renewables if progress is made on demand-side response (DSR), demand reduction and storage as we transition to a dynamic, smarter system that manages and smooths peaks in demand, and is supply- rather than demand-driven. While renewable resources are variable, they can be forecast with a high degree of accuracy by comparison with thermal plant which often has unforeseen outages. This allows domestic and commercial consumers to respond to changing levels of renewables on the system.

The next UK Government needs to adjust the electricity market regime in order to provide a level playing field with new revenue streams for these important system services. For instance, there is currently no support mechanism to enable the building of new pumped storage and the capacity mechanism does not do enough to drive the development of demand reduction or response (see more in Q4 below).There is also a need to focus on energy consumers and business models for power companies in the energy transition. Important consumer tools in the delivery of DSR include smart meters, which will form the basis of dynamic demand response, alongside tariff structures that incentivise load shifting in response to changing levels of renewables on the system.

In Scotland, there is already an EU-funded pilot project underway in Findhorn which uses sophisticated weather forecasting and demand data to drive load shifting. The Origin project12, led by Heriot Watt University, is already achieving impressive results, even before the introduction of dynamic tariff structures. A number of other demand management projects in Scotland are also being supported by the Energy Challenge Fund. 13

Q3: What role will transmission projects have in securing supply and where should investment be directed? What role for the distribution network and a single European electricity market play in securing supplies?

Transmission improvements are required for Scotland to maximise its renewables resources

With increasing levels of renewables in peripheral areas and decreasing conventional power to provide system services such as voltage control, transmission projects will have a significant role to play in ensuring that Scotland can continue to maximise its renewables strengths as part of the GB grid.

National Grid have set out a range of flexible scenarios as part of their transmission network upgrade planning, including commercial and operational practices as well as new build transmission projects.14 In all these scenarios, there is a need to boost transmission capacity to accommodate new renewable generation in Scotland over the coming decades, though this will be offset to some extent by thermal power closures. In addition to major reinforcement already in construction or in design, there are a variety of projects in scoping and options are being considered for a new Eastern HVDC link, though the need for this will depend on the extent of renewables build out over the coming years.

More immediately, it’s important that the UK and Scottish Governments work with industry and regulators to find a solution that would allow grid connections to the islands to be built to help contribute to hitting the decarbonisation target. Given the renewable resources available on Scotland’s islands, this would unlock several hundred MW

12 http://origin-concept.eu/ 13 http://www.localenergyscotland.org/funding-resources/funding/local-energy-challenge-fund/phase-two-projects/ 14 2014: http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Electricity-Ten-Year-Statement/

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of onshore wind generation cheaper than offshore wind. These upgrades should be planned with a long-term view of the power which can come from the seas around and beyond our islands.

In terms of integration with European markets, Scotland is already connected to Northern Ireland through the Moyle interconnector with plans underway to develop a 1.4GW interconnector between Norway and Scotland by the early 2020s. This will further enhance security of supply given the importance of hydro pumped storage to Norway’s energy mix, which helps to balance wind variability. With 25% of Europe’s tidal and offshore wind and 10% of its wave energy potential located in Scotland, greater interconnection with Norway’s pumped storage capacity would help enable Scotland in the long-term to export its renewable energy across Europe, as part of the growth of a single European grid

The direction of travel for other European countries is increasingly towards greater interconnection, with a 15% target for interconnection set by European leaders by 2030 and ultimately towards a single European Grid and transnational energy markets, with technological and geographical diversification. This kind of integration is already well underway in the Nordic countries.

Q4: Are policies such as the capacity market adequate and what other long term signals are needed?

The UK Government must improve the Electricity Market to achieve decarbonisation cost effectively

The UK Capacity Market as currently designed under EMR is inadequate for achieving Scottish or UK decarbonisation objectives cost-effectively for three key reasons. We suggest improvements for the next UK Government to make below.

First, it is providing windfalls to existing plant rather than incentivising the building of new capacity (whether demand side response, interconnection, storage or ‘bridging’ flexible gas plant). 94% of the capacity procured under the first auction was old/refurbished capacity, despite the fact that many of these plants (e.g. existing nuclear, hydro, many coal plants outside of Scotland) are already profitable. We believe that providing lump payments to already profitable capacity is an inappropriate burden on consumer bills.

Secondly, the capacity market has provided a lifeline for coal plants in many parts of the UK, which might otherwise have closed due to the carbon price floor and the cost of compliance with the Industrial Emissions Directive. Providing consumer funded payments to coal plants is directly in conflict with affordability and decarbonisation objectives. Evidence15 from industry experts indicates that a rapid phase out of coal could be managed using system balancing tools available to National Grid, posing no risk to security of supply. Coal capacity payments should therefore be phased out now across the UK and an Emission Performance Standard introduced for existing plant.

Moreover, we do not support proposals for a carbon price support exemption for UK generators purchasing ‘restoration related coal’, and consider this to be a high-risk and counter-productive approach to funding restoration of derelict mines in Scotland.16

15 Skilling et al (2015) Assessing the balance of risks associated with coal plant phase out:: http://www.e3g.org/news/media-room/security-of-supply-is-no-excuse-uk-needs-a-coal-phase-out-policy 16 See RSPB briefing here: http://www.rspb.org.uk/Images/rpsb_parliamentary_coal_briefing_tcm9-396884.pdf

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Thirdly, the market discriminates against demand-side response and electricity demand reduction. Given that demand is well below peak for the majority of the time, building new power stations which will sit idle almost permanently is unlikely to be the most cost-effective security of supply solution compared to demand reduction and load shifting. At the moment, new demand-side response – paying electricity users willing to shift their demand away from peak times through the capacity market – is only able to access one year contracts in the capacity market, disadvantaging it compared to new generators what are able to access fifteen year contracts. In the US PJM capacity market, 9% of the capacity for delivery year 2015/16 is demand-side response compared to only 0.35% of the successful capacity in the UK’s first auction17.

If we’re to achieve decarbonisation securely and to the advantage of the consumer, the playing field should be levelled for all new capacity solutions, with reduced maximum contract lengths available of 3-5 years. Access to main auctions (as opposed to year ahead) from 2018 should be allowed for demand-side response projects that attract pilot funding in 2016 and 2017. Already profitable existing plant should not be incentivised.

Saving electricity is ‘no regrets’ policy from a security of supply and an economic perspective, helping to reduce the cost of decarbonisation for consumers by avoiding the need to build new generating capacity. However, it is currently undervalued in the GB electricity market.

DECC’s research indicates the technical potential for demand reduction of 32TWh/year GB wide.18 DNV GL analysis for WWF Scotland shows that moderate demand reduction (1% per year) would allow Scotland to securely decarbonise electricity well within the current renewables pipeline, even allowing for electrification of heat and transport. While there has been steady progress in reducing electricity demand in recent years in Scotland, it is important that the downward trend continues with economic recovery.19 However, there is increasing evidence UK wide that energy demand and economic growth are decisively decoupling20.

Therefore, other GB-wide mechanisms outside of the capacity market should be explored for electricity demand reduction, including the possibility of energy efficiency feed in tariffs, which provide a clear revenue stream for electricity demand reduction irrespective of whether there is a capacity shortfall in any given year. While the Scottish Government has only some powers in this area, demand reduction is afforded too little emphasis and the Scottish Government should also produce an electricity demand reduction strategy accordingly.

Despite its important role in storing energy generated from variable renewables and in providing balancing services to ensure system stability, pumped storage is not recognised under the current EMR regime. Consent for one scheme in Scotland is already in place, with another included in the National Planning Framework. The UK and Scottish Governments therefore need to work with industry to develop revenue streams that can unlock the potential of this and other forms of storage technologies.

17 See WWF Capacity Market Briefing: http://assets.wwf.org.uk/downloads/wwf_capacity_market_briefing_march_2015.pdf 18 DECC (2013) https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/246126/Impact_Assessment_for_Electricity_Demand_Reduction_Policy_Options_FINAL.pdf 19 See KPMG report for evidence of declining demand 20 http://www.bbc.co.uk/news/business-30518649

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SUBMISSION FROM SSE

SSE welcomes the opportunity to provide written evidence to the Committee.

SSE is a UK-listed utility and the broadest-based energy company in the UK. SSE's core purpose is to provide the energy people need in a reliable and sustainable way.

In Scotland SSE is one of the largest generators of electricity with around 3,300MW of installed capacity made up predominately of 935MW of onshore wind; 1150 MW of hydro; 300MW of pumped storage; and 1,180MW of thermal capacity at its gas fired power station at Peterhead, at which it is also developing, in partnership with Shell, a UK Government sponsored Carbon Capture and Storage (CCS) project.

SSE’s subsidiaries Scottish Hydro Electric Transmission (SHE Transmission) and Scottish Hydro Electric Power Distribution (SHEPD) own and maintain the economically-regulated electricity networks serving around 750,000 customers in the north of Scotland and the Scottish islands.

This evidence considers security of supply in Scotland, recommendations to provide stability in the policy framework for the electricity market and an outlook on the transmission network.

Executive summary

1. Scotland is part of an integrated GB wide energy market and security of supply in Scotland should be considered in the context of security of supply across GB. Security of supply across GB is the responsibility of the UK Government and is administered by the System Operator, National Grid. Whilst it is widely recognised that capacity margins have reduced in recent years, the UK Government has designed and introduced policies to maintain a secure electricity system.

2. The GB energy market is at a critical juncture as it is seeks to balance the sometimes competing challenges of delivering electricity and gas at a price that remains affordable to consumers and businesses whilst at the same time ensuring secure energy supplies and providing investors with the certainty they require to commit to the required low-carbon investments. Having undergone a period of significant change and uncertainty over the past five years whilst the Electricity Market Reform policies have been developed and implemented, it is now important for industry to enter a period of regulatory certainty and stability. SSE makes four recommendations intended to provide stability and certainty to the policy framework.

a. Ensuring security of supply through the Capacity Market

b. Setting the Levy Control Framework Budget beyond 2020/21

c. Stability in the UK carbon price

d. Equitable transmission charging arrangements

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3. As we move towards a largely decarbonised energy mix the electricity transmission system is going through a fundamental change to accommodate the growth in renewables and alleviate existing constraints on the network. Ongoing and future projects will further enhance market integration across GB and with the rest of the EU, contributing to security of supply.

A VIEW ON SECURITY OF SUPPLY

1. Security of supply across the GB electricity market is the responsibility of the UK Government and is administered by the System Operator, National Grid. These organisations, along with Ofgem, have full visibility of the market; and therefore design, implement and operate the mechanisms through which a secure electricity system is maintained. It is important to note that Scotland sits within a single GB electricity market with a single system operator and it is in this context that security of supply should be considered.

2. Ofgem has noted that capacity margins have reduced in recent years, a trend which is likely to continue until 2018. This is as a result of several factors, including weak market economics and the impacts of EU and UK regulations closing down plant.

3. In recognition of this the UK Government, together with National Grid (as the System Operator), and Ofgem has designed and implemented two mechanisms, the aim of which is to ensure that there is sufficient capacity to maintain a secure electricity system; i.e. keep the lights on. These are the Contingency Balancing Reserve (comprising the Supplementary Balancing Reserve (SBR) and the Demand Side Balancing Reserve) and the Capacity Market. In addition to these mechanisms National Grid already has the ability to manage moments when demand outstrips supply through a range of different balancing and optimisation tools.

4. In the short-term, the SBR is intended to ensure that there is sufficient generation capacity available to meet the Government’s Reliability Standard set at a Loss of Load Expectation (LOLE) of 3 hours per year.

5. In the medium to longer-term, the first Capacity Market auction held in December 2014 enabled the UK Government to procure the volume of capacity the GB system needs for 2018-19. Subsequent annual auctions will enable the UK Government to continue to procure the capacity required to meet its Reliability Standard, providing an enduring solution to keeping the lights on across GB.

6. Under both mechanisms DECC and National Grid determines how much capacity is required to ensure the Reliability Standard is met. Once this volume has been set they signal this to the market, and then procure the necessary capacity through a competitive auction/tender process.

7. SSE supports both the Capacity Market and the Contingency Balancing Reserve and believes, if they are implemented correctly, they will make a significant contribution to maintaining secure electricity supplies across GB.

Security of supply in Shetland

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8. The Shetland isles are not connected to the GB mainland but they are operated as part of the wider GB market arrangements. SSE plc’s subsidiary SHEPD currently carries out the function of System Operator on the island distribution network, although this is outside the formal role of a Distribution Network Operator. As the main generating plant that currently provides reliable capacity in Shetland is nearing the end of its operational life, SHEPD is currently working with Ofgem to deliver an open competitive process to identify the most economic and efficient future arrangements to provide a secure and reliable electricity supply to customers on the islands.

9. SHEPD is also working with Ofgem to determine the best approach in considering the timing and potential impact of the installation of a transmission cable link connecting the islands to the GB mainland, recognising that the island network would need to be capable of operating during planned or unplanned outages on a single circuit cable.

10. The historic Reliability Standard on Shetland has provided a slightly better standard of security than the 3 hours LOLE on the GB mainland. If a cable is installed connecting the islands to the GB mainland, the Reliability Standard will default to that of the rest of GB. Therefore, for the purposes of the competitive process for the new generation solution for the islands, SSE believes it is appropriate and has proposed that the GB standard of 3 hours LOLE is used.

THE ELECTRICITY MARKET

11. The GB electricity market has recently undergone the most extensive reforms since privatisation, which have fundamentally changed the policy climate to support the transition to low carbon energy and ensure security of supply, at a cost affordable to consumers. SSE makes the following recommendations in terms of the future of the electricity market.

a) Ensuring security of supply through the Capacity Market

In order to provide the necessary confidence to investors it is crucial that there is a period of relative stability in energy policy to enable the necessary investments to meet future energy needs. In particular, it is crucial that the Capacity Market is maintained as an enduring policy to ensure the UK Government can procure sufficient capacity to meet demand from 2018 onwards. Changes to this mechanism must be considered and proportionate, given the importance it has in maintaining existing plant and, in time, supporting new investments. At its core, the Capacity Market should continue to take a technology neutral approach to competitively procuring capacity at the lowest cost to the consumer.

In the preceding years before 2018/19 the SBR has been introduced to ensure sufficient capacity before the introduction of the Capacity Market. Whilst SSE strongly supports the continuation of the SBR as an interim measure, SSE does have some concerns about the inability of the SBR to procure truly additional plant and is supportive of current modifications being progressed to ensure the SBR procures genuinely additional plant.

b) Setting the Levy Control Framework Budget beyond 2020/21

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Renewable energy will play an increasing role in meeting the energy needs across Scotland and GB, and the need for policy certainty and stability applies equally to the transition to low carbon generation. However, there remains an element of uncertainty regarding future budgets to support the transition to low carbon and there are two recommendations SSE believes should be progressed to provide low carbon investors the certainty they need to take forward future investments:

A principal concern is that there is no sight of the Levy Control Framework budget beyond 2020/21. For low-carbon investors this makes it challenging to commit to any projects which are due to commission in the next decade as there is no certainty about the level of support available. SSE therefore recommends that the next UK Government should commit to providing visibility of future allocation round budgets for both the established and less established technology pots. At a minimum, the UK Government should provide a budget for two allocation rounds in advance on a rolling basis.

c) Stability in the UK carbon price

Finally, SSE believes that market-based carbon trading is the most efficient way to encourage low-carbon generation and reduce carbon emissions from the energy sector. However, at present the mechanisms to set the carbon price at the EU and UK levels have not delivered a robust and stable carbon price and action is needed.

Whilst reform of the EU Emissions Trading System is due to take place in 2019 with the introduction of the Market Stability Reserve, in the interim period SSE suggests that the next Government introduces a stable and consistent carbon price by setting the Carbon Price Floor over a five year time-frame, not subject to any change in that period. This will reduce the potential for political intervention, provide long-term certainty to the carbon price paid by consumers, businesses and generators; and help to encourage low-carbon investment.

d) Equitable transmission charging arrangements

As we move towards greater market integration across the European Union it is important that GB generators can operate on a level playing field with their European counterparts and one area that SSE believes needs to be addressed is that of transmission charging.

Whilst historically it may have made sense to incentivise generation to be located closer to areas of demand, as we continue to progress towards a market with greater deployment of renewable generation and associated network infrastructure build, the transmission system will increasingly take electricity from areas with the greatest renewable resource to the areas that need it.

Electricity generators in GB pay on average up to €2.5/MWh per annum to access the transmission system, however, the majority of European Members States do not charge their generators to access the transmission system and of those that do, charges are set at a far lower price (€0.5/MWh per annum or less) than that paid by GB generators. The variance in capacity related transmission

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charges paid by generators can be seen in Figure 1 below. In fact GB is one of only three markets in the EU that levy these charges.

Figure 1. Capacity related transmission charges across the EU (ACER 2014)1

As can be seen in Figure 1, the GB overall €2.5/MW per annum average figure masks the wide differences in the charges paid by generators in Scotland (up to £25,540 per MW per annum) and those in West Devon and Cornwall who, rather than paying to use the transmission system, actually receive £5,804 per MW per annum for using the transmission system. This creates a real market distortion for GB and will ultimately encourage developers to locate where they do not pay to use the transmission system.

Whilst the changes to transmission charging proposed through Project TransmiT (legal challenge notwithstanding), will result in more cost reflective charging for all generators, including those in Scotland, the changes proposed still fall short of equalising transmission charges across GB (and across Europe).

In line with the direction of travel within the European Union, SSE supports the harmonisation of the structure of the transmission charging regimes across all the 28 European Member States and, ultimately, the alignment of transmission charges between GB and the other Member States across the single electricity market. This will ensure the cost efficient deployment of generation assets, lowering the overall system cost for consumers over the long term by maximising the renewables resources available across Europe.

THE TRANSMISSION NETWORK

12. The lack of capacity on the electricity transmission network can mean that not all the electricity generated in Scotland can be transported to centres of demand. The significant investments therefore that are currently being made in the transmission network, including the Beauly-Denny, Caithness-Moray and Western HVDC projects, will help to alleviate this pressure. These projects will

1 Agency for the Cooperation of Energy Regulators (2014) – Opinion on the appropriate range of transmission charges paid

by electricity producers

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provide significant additional capacity to allow power to flow both north and south across the border, helping further secure Scotland and GB’s energy requirements.

13. Scottish Hydro Electric Transmission (SHE Transmission) is the licensed electricity Transmission Owner in the north of Scotland and over the next few years will be investing around £2bn, with the potential to increase this significantly in response to the needs of large scale electricity generators. Transmission network investment is directed in response to demand from electricity generators to connect to the transmission network and the need to either upgrade existing transmission network infrastructure or, in some cases, construct new transmission assets.

14. A total of 3800MW of renewable generation has been connected to SSE’s transmission and distribution networks in the north of Scotland with a further 800MW-1000MW expected to connect by 2017. Another 8GW-9GW of renewable generation is currently contracted to connect to SHE Transmission’s network over the next decade with the final connected levels dependent on progression of schemes across a range of technologies – onshore wind, Island wind, offshore wind, hydro, wave and tidal. Overall, this represents a substantial contribution to meeting Scotland’s and GB’s energy needs and Government targets.

15. In response to demand from onshore renewable generators to connect on the Scottish islands, SHE Transmission is also developing proposals to construct new transmission links to both the Western Isles and Shetland. To ensure development of these links the prospective contracted generators require certainty regarding the CfD strike price and EU state aid clearance before SHE Transmission can prepare robust ‘Needs Cases’ for submission to Ofgem.

16. Significant work has already been carried out by SHE Transmission to develop the cable solutions for connecting the Western Isles and Shetland to the GB mainland for prospective commissioning dates in 2020/21 to suit the wind farm developers. However, SHE Transmission is concerned that Ofgem’s recent proposals for Integrated Transmission Planning and Regulation (ITPR) may interfere with the planned delivery of the works for the prospective generator commissioning dates.

17. As an active participant and member of the Scottish Islands Renewables Delivery Forum, SHE Transmission is working with all relevant parties to progress both island connections and, providing policy certainty on CfDs and ITPR is resolved this summer coupled with continued developer commitment, SHE Transmission stands ready to submit ‘Needs Case’ applications to Ofgem later this year.

THE ROLE OF PUMPED STORAGE

18. Traditionally, UK pumped storage facilities have been used to bridge relatively short term variations in demand. As they were designed mainly to cope with brief imbalances in the grid, none of the existing schemes has sufficient storage volume to generate at full capacity for an extended period.

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19. However, as we move to a largely decarbonised energy mix and the quantity of variable renewable generation increases (e.g. wind, wave and tidal), it is forecast that pumped storage plants will need to move towards longer running cycles to store and release the energy generated during frontal weather events and to take energy from the grid during periods of over-supply and generation.

20. SSE’s Coire Glas project has been developed a site which allows storage to be maximised, with flexibility to pump and generate at the right times to make the best use of the available renewable generation. The scheme has been developed with an installed capacity of up to 600MW and a storage volume of up to 30GWh which would allow the station to run at full capacity for up to 50 hours.

21. However, there is currently no clear route to market for new pumped storage facilities and SSE therefore backs calls from Scottish Renewables2 to establish an intergovernmental panel to consider how the technology should be supported.

May 2015

2 http://www.scottishrenewables.com/media/uploads/140529_scottish_renewables_pumped_storage_position_paper.pdf

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SUBMISSION FROM SP ENERGY NETWORKS

Executive Summary

Security of supply is a function both of the availability and flexibility of generation plant and the capability of the transmission system to support demand from the generation plant connected to it, but is not the only aspect crucial to an effective transmission system. Other issues are also significant, including system operability, which considers whether the network is able to deliver minimum voltage and frequency standards; and Black Start capability, necessary to effect an efficient and timely Black Start restoration and minimise the social and economic impact of such an event.

In addition there is a requirement to ensure there is sufficient transmission capacity available to the System Operator (SO) to allow reasonable and economic access for the Transmission Owners (TO) to undertake maintenance, refurbishment and construction works. We have considered each of these issues as follows:

Security of supply (ensuring that there is enough generation to meet demand). Our view is that the risk of failing to meet winter peak electricity demand in Scotland remains low in the period to the end of the current decade, but it is increasing. Reliance on aging nuclear AGR generating stations contributes to the increased risk. Experience suggests the reliability of nuclear generation can be uncertain towards the end of life. Investment solutions that will deliver increases in south-north transmission capacity (England-Scotland and Central-Northern Scotland) are in construction and will improve the situation, but questions around the mix and availability of sufficient generation capacity and margins in a Great Britain (GB) context are of some concern.

In the period from 2020 to 2030, the prospective closure of the existing fleet of nuclear AGR generating stations across GB, and in particular the five AGR stations located in Scotland and the north of England, will be a major consideration and likely to present significant challenges on both a Scottish and GB wide basis.

System operation issues and voltage control (maintaining system voltages at levels that do not over-stress transmission equipment). In response to anticipated changes in the availability of large synchronous generation plant in Scotland to the end of the current decade, transmission investment solutions are being progressed that will improve the situation by the 2017 summer period.

Black start (recovering from an event which results in loss of large parts or all of the GB transmission system). Currently the operating regime and operational status of large thermal power stations is a determining factor in the speed with which any Black Start recovery can be effected. The continued de-carbonisation of the electricity system will have a fundamental impact on the location and nature of electricity generation sources, and will lead to extended recovery profiles in some areas of the UK, including Scotland. The existing

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Black Start recovery plan for central and southern Scotland will become invalid following closure of Longannet generating station.

About SP Energy Networks

SP Energy Networks own and manage the electricity transmission and distribution networks in central and southern Scotland, serving approximately 4 million people in this region. SP Energy Networks encompasses both of the licenced businesses SP Transmission plc (SPT) and SP Distribution plc (SPD).

Under the Electricity Act 1989, SPT is licensed to transmit electricity and required to fulfil the following obligations within its licence area: -

To develop and maintain an efficient, co-ordinated and economical system for the transmission of electricity; and

To facilitate competition in the supply and generation of electricity.

These statutory obligations are reflected in SPT’s transmission licence. In addition, as owner of the transmission assets within its licence area, SPT has the following obligations pursuant to its licence conditions:-

To plan and develop its transmission system in accordance with the National Electricity Transmission System Security and Quality of Supply Standard (SQSS); and

To make offers to generators wishing to connect to the transmission system in SPT’s licence area. In this regard, SPT is obliged to make its transmission system available for these purposes and to ensure that the system is fit for purpose.

In response to statutory and licence obligations placed upon it, SPT therefore provides connections for electricity generators and, where appropriate, reinforcements to increase transmission capacity both to accommodate the connection of new generation sources as well as the closure of existing generating capacity.

The three transmission licensees in GB1 work closely to ensure co-ordinated planning of the transmission system and compliance with the SQSS. In accordance with The System Operator Transmission Owner Code, in planning and developing transmission infrastructure in central and southern Scotland, SPT is obliged to employ Planning Assumptions which are provided by National Grid and in practice are aligned with the National Grid UK Future Energy Scenarios.

In this response to this call for evidence, as a Networks business, we have focused on the following question:

“A number of new transmission network projects are currently under construction or being planned. What role will these have in securing electricity supplies, and where should future investment be directed? What role might

1 The three onshore Transmission Owners are: National Grid Electricity Transmission plc, SP Transmission plc and Scottish Hydro Electric Transmission plc. NGET also acts as the GB System Operator (SO).

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the distribution network, and a single European electricity market play in securing supplies?”

RIIO-T1 Context and New Transmission Network Projects

Security of electricity supply in Scotland is function both of the availability and flexibility of ‘local’ generation plant located in Scotland and the capability of transmission infrastructure to support Scottish demand from ‘remote’ generation plant located in England and Wales. The availability and flexibility of ‘remote’ generation in England and Wales is also a highly relevant factor.

SP Energy Networks is presently delivering an investment plan in transmission infrastructure totalling £2.6 billion pounds over the 8-year RIIO-T1 price control period from April 2013 to March 2021. Along with the other GB onshore transmission licensees, this is the most significant investment in the transmission network in the last 70 years. The investment can be categorised in three broad areas:

Investing in existing assets to secure the performance of the transmission network by an extensive modernisation programme. Replacing ageing infrastructure will ensure a high level of system reliability is maintained.

Excellent progress has been made in the delivery of the plan in its first two years. The modernisation programme for overhead lines is ahead of plan, but there remain challenges to overcome. Replacing assets designed and built in the 1960s requires careful planning to ensure both that supplies are maintained during the construction works and that access to the transmission system for generators is maximised. However, it is inevitable that some generator access restrictions will be necessary while these works are ongoing. In accordance with its licence obligations, SPT develops the most economic, efficient and co-ordinated solutions, recognising the balance between capital cost and operational costs during construction, including generator constraint costs. We have identified a number of major modernisation schemes where building assets ‘off-line’ would result in an incrementally higher capital cost but achieve significantly greater savings in constraint costs. We are presently working with the other onshore transmission licensees and Ofgem to introduce a mechanism to ensure these schemes are implemented in a timely manner.

Providing connections to new sources of low carbon energy. The transmission system is being extended to provide connections to new generators, most of which are on-shore wind.

As part of our RIIO-T1 business plan submission to Ofgem, we forecasted the connection of an additional 2503MW of new renewable generation to the transmission network in the period to March 2021. We presently have contracts with NGET for 6924MW to connect during this price control period and beyond. In part, this has been influenced by the ‘Connect and Manage’ framework, which permits generators to connect to the network in advance of the completion of required wider reinforcement works. The generators’ output is then managed to ensure that the network remains operated within its capability. In some cases, this is leading to significant difficulty in securing the outages to

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complete the necessary transmission reinforcement works, in part due to the associated generator constraints.

Reinforcing the transmission network. This provides capacity to meet renewable energy targets, address local capacity issues and secure the network for the closure of existing generation capacity.

System reinforcement works have focused on the necessary increases in transmission capability to permit the bulk transfer of low carbon energy internal to Scotland and from Scotland to England and Wales. Due consideration has also been given throughout the investment planning process to the capability of the Scottish networks to import power from England and Wales. The Western HVDC link, a joint project with National Grid currently under construction, will have a bi-directional power transfer capability of up to 2250MW. The onshore reinforcements in our RIIO-T1 business plan will also provide incremental benefits for import to Scotland.

What role will these Projects have in securing electricity supplies, and where should future investment be directed? Over the last year, we have worked together with National Grid and SHE Transmission, in carrying out specific analysis with regard to these issues in Scotland, including a review of the capability of the transmission system to support power flow from England and Wales to Scotland, and from south to north across the Scottish transmission system.

Security of Supply - The existing transmission system can support a secured2 transfer in the winter months of approximately 2.65GW from England and Wales to Scotland. This represents almost 50% of the approximate 5.5GW winter maximum demand for electricity in Scotland. To serve this maximum demand at times of low wind generation output, around 2.85GW of generation output will therefore be required across Scotland. While due consideration must be given to unforeseen plant breakdown and unavailability, this requirement can presently be met from a combination of generating stations.

Completion of the Western HVDC Link is expected to enhance the capability of the transmission system from winter 2017/18 and enable transfers from England and Wales to Scotland of up to 3.9GW in the period to the end of the decade. This represents 70% of the prevailing 5.5GW maximum demand.

In the period from 2020 to 2030, the prospective closure of the existing fleet of nuclear AGR generating stations across GB, and in particular the five AGR stations located in Scotland and the north of England, will be a primary consideration. Against a background of continued change in the wider generation portfolio, this will present significant and unprecedented challenges on both a Scottish and GB wide basis. In view of the potential timeframe required to develop and implement mitigating measures, there is an increasing risk that the rapid pace and direction of change, as evidenced by recent events, may outstrip the capability of the industry to deliver the necessary infrastructure in good time.

2 Transmission capabilities have been assessed in accordance with the National Electricity Transmission System Security and Quality of Supply Standard (SQSS).

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System Operability - In addition to the above security considerations at time of winter peak demand, at times of low demand coincident with periods of low wind generation output, voltage control is becoming increasingly challenging and high voltage issues are more frequent and widespread in operational timescales. These are being driven in part by significant changes in the electrical characteristics of the demand served by the transmission system, and are exacerbated with low / reduced availability of large synchronous generation plant. SPT and SHE Transmission have identified a requirement to install an additional 720MVAr of transmission based voltage control equipment in Scotland. Design and engineering work is underway to deliver this additional equipment in advance of summer 2017. This will ensure the effective management of transmission voltages across Scotland following the reduced availability of large synchronous generation plant to the end of the decade. In the interim, we anticipate National Grid will need to manage high system voltages and may routinely need to switch out of service several lightly loaded transmission circuits, which will potentially have an adverse impact on system resilience.

Black Start - At present SPT has authority delegated to it under the Emergency Black Start Plan to manage restoration of the system within its licence area from local thermal generation. The future operating regime and operational status of large thermal power stations will be a determining factor in the speed with which any Black Start recovery can be effected. The continued de-carbonisation of the electricity system will have a fundamental impact on the location and nature of electricity generation sources, and will lead to extended recovery profiles in some areas of the UK, including Scotland. The current and long standing SPT area Black Start plan will become invalid following closure of Longannet generating station. SPT will be unable to recover the transmission system in central and southern Scotland as all the potential options require re-energisation from outside SPT licence area. Such actions must be directed by National Grid.

Discussions between the Scottish transmission companies and National Grid in its capacity as System Operator with regard to a review of Black Start procedures are being pursued to determine an acceptable recovery plan. It must be understood that the absence of sufficient suitable thermal generation plant in Scotland following closure of Longannet will significantly increase the time taken to recover supplies to customers in central and southern Scotland. Alternative strategies which are yet to be agreed, are likely to involve re-energising elements of the transmission system in Scotland from England and Wales as quickly as is practicable under the prevailing conditions, this will support any available renewable generation in Scotland to play a role in the recovery of the wider GB system. Recovery of the transmission system in central and southern Scotland will become wholly dependent on National Grid, whose organisational focus and operational priorities will be determined under the prevailing GB wide Black Start scenario and on the overall availability of generation plant within the UK mainland.

It must also be understood that under Black Start conditions, the Western HVDC Link will not be able to operate at its full capacity until sufficient local generation is connected to support operation of the HVDC Link.

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What role might the distribution network, and a single European electricity market play in securing supplies?”

Potential Role of the Distribution Network

Nearly 2 million customers (approximately 4 million people) are connected to our distribution system in the South of Scotland area, representing a maximum demand of approximately 3.8GW. We are experiencing increasing levels of embedded generation (generation connected directly to the distribution system) connecting to our network. This smaller generation is typically beyond the control of National Grid as transmission system operator (TSO) who see its impact as an overall reduction in demand. The volume of this type of generation and the limitation of communication and control mechanisms requires an alternative approach.

Innovation is an essential part of all our future plans for our transmission and distribution networks and we have been very proactive over recent years in maximising the benefits from innovation. As a Distribution Network Operator (DNO) we can provide potential solutions by developing a distribution system operator (DSO) function, which manages demand and generation on the distribution system in response to system conditions on either the transmission and distribution networks. For example, we have developed an innovation project “Accelerating Renewable Connections” (ARC) that was successful in Ofgem’s Network Innovation Competition receiving funding of £8.4m. This project allows embedded generation to connect in certain areas ahead of the transmission works being completed. Significantly this involves generators contracting with us as a DNO to allow us to manage their output in response to changing system conditions.

We are building on our ARC project by submitting a bid to the 2015 Network Innovation Competition (NIC) for an Innovation project “Project EVOLUTION”. By investing £6.8m over 4 years Project EVOLUTION will implement local system balancing through innovative commercial and technical mechanisms under a Grid Supply Point (GSP) i.e. on the distribution system. EVOLUTION will explore the wider issues around market coordination, and the effect upon national system balancing and settlements, leading to a pilot DSO model. We are engaging with National Grid in this project, because of its potential to mitigate some of the system security issues which are emerging.

Potential Role of a Single European Market

The development of a single European market has to consider fundamental issues including system stability, system operability, interconnection, capacity and congestion management. These considerations are being addressed in the suite of European network codes, which are gradually progressing towards comitology, which existing GB legislation will need to be compliant with. The various companies in the electricity industry, working with DECC and Ofgem (and supported by National Grid and ourselves and the other Transmission System Operators (TSO’s) in GB), are influencing the content of these codes and considering how we will implement them in GB. The intention of these codes is to provide the possibility of managing and mitigating local system security and operability issues by the establishment of a single market. For example, The Requirements for Generators (RfG) Code states:

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“The swift completion of a fully functioning and interconnected internal energy market is crucial to maintaining security of energy supply, increasing competitiveness and ensuring that all consumers can purchase energy at affordable prices….

And seeks to achieve…

“Harmonised rules on grid connection for power generating modules should be set out in order to provide a clear legal framework for grid connections, facilitate Union-wide trade in electricity, ensure system security, facilitate the integration of renewable electricity sources, allow more efficient use of the network and resources, and increase competition, for the benefit of consumers.”

Similar narrative introduces the other network codes and it is clear from this that a single European market is intended to improve system security issues and recognises the potential of a single market to provide solutions and is seeking to develop the conditions in terms of harmonisation and standardisation by which this may be achieved.

Conclusions

We are making a significant contribution to Scottish Energy Policy by delivering our £2.6billion Investment Plan to increase the capacity of the transmission system, connect new renewable generation and replace aging assets. Our view is that the risk of failing to meet winter peak electricity demand in Scotland remains low in the period to the end of the current decade, but it is increasing. The anticipated shift in the generation mix in Scotland represents a fundamental change. Scottish supply security will soon become totally reliant on being part of the wider generation mix across the UK.

We do not believe current investment levels in the short term in the UK for large synchronous generation are sufficient to mitigate these risks in the medium term and we are engaging with the Regulator, National Grid as the system operator, and other industry partners to jointly identify and deliver a range of measures to protect the interests of current and future consumers.

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SUBMISSION FROM OFGEM

Introduction

1. Ofgem is the Office of Gas and Electricity Markets, the independent economic regulator of Great Britain’s gas and electricity markets. We work effectively with, but independently of, government, the energy industry and other stakeholders. We do so within a legal framework determined by the UK government and the European Union.

2. Our principal objective is to protect the interests of existing and future consumers. The interests of consumers are their interests taken as a whole, including (but not limited to) value for money, and their interests in the reduction of greenhouse gases and in the security of the supply of electricity.

3. Ofgem welcomes the opportunity to submit our views to the Committee on security of supply. In our submission we provide more detail on our capacity analysis and the work Ofgem is doing under the themes the Committee have identified on demand side response, the transmission network, distribution network and integration with Europe.

Security of supply

4. Energy security in Great Britain is achieved primarily through the operation of liberalised markets. However, given the importance and complexity of energy security, a number of bodies are responsible for monitoring and ensuring security of supply. The UK Government sets overall policy on energy security. Ofgem is responsible for regulating the competitive wholesale and retail energy markets and for regulating the energy networks in Great Britain. National Grid, as the System Operator (SO) of the GB electricity system, is responsible for balancing the electricity system by ensuring that generation on the national electricity grid matches demand on a second-by-second basis. To do this, they buy and sell energy and procure a number of balancing services to ensure both the security and the quality of electricity supply across the GB Transmission System.

5. We first raised concerns over security of supply in our 2009 Project Discovery report1, highlighting the new challenges faced by our energy system by changes to the generation mix over the next 10-15 years.

6. Our report prompted the UK Government to place an obligation on us to produce an annual assessment of electricity security of supply (the Electricity Capacity Assessment). The purpose of our report is to illustrate the levels of security that could be delivered by the market alone and in turn to inform our and the government’s decisions on security of supply. We delivered our latest report to the Secretary of State in June 20142, looking at the period 2014/15 to 2018/19.

1 Project Discovery, Energy Market Scenarios, 2009 https://www.ofgem.gov.uk/ofgem-

publications/40361/discoveryscenarioscondocfinal.pdf 2 Electricity Capacity Assessment 2014, https://www.ofgem.gov.uk/publications-and-

updates/electricity-capacity-assessment-2014

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7. Our 2014 Electricity Capacity Assessment, showed that without new measures being introduced the risks to the security of our electricity supply would increase up to 2015/16 because of a fall in the level of generation capacity, before then showing an improvement in the later years of our analysis.

8. There have been a number of responses to the increased risks to security of supply. The UK Government put in place the Capacity Market as part of the wider Electricity Market Reform (EMR) programme to bring forward the capacity needed to ensure security of electricity supply. Ofgem has an enduring role in this scheme both as the regulator of National Grid, who administer the EMR policies, and, in future, as owner of the rulebook for the Capacity Market, which governs the technical aspects of the policy.

9. In addition, due to the increased uncertainty in the mid-decade period, (before the Capacity Market is in place) we have approved new tools that National Grid can use to help balance the electricity system and manage lower margins, ie the New Balancing Services (NBS). Having these new tools in place means that the risk of disconnections for consumers is lower for winter 2015/16. This is a substantial improvement for consumers, and will bring the risks lower than UK Government’s reliability standard for secure supplies.

10. Our Capacity Assessment is based on National Grid’s Future Energy Scenarios which cover four different views of the electricity market and their outlook for security of supply, affordability and sustainability. These scenarios are used as the starting point to assess the required volume to procure for the Capacity Market and the New Balancing Services.

11. Both Ofgem and National Grid look at capacity and system operability across GB as the system is operated and balanced at a GB level. At the same time, National Grid also conducts a number of localised studies such as those published recently3 on the security of electricity supply in Scotland, System Operability and Black Start Capability. This type of study allows it to assess the localised challenges a part of the network is likely to encounter and the services it needs to maintain the system within agreed Security and Quality Supply Standards.

Investment in the GB onshore transmission network

12. Ofgem regulates the monopoly companies that own and operate the transmission and distribution networks across GB. We seek to protect consumers’ interests by regulating the companies through price controls where we set the maximum amount of revenue that they can recover from users. These arrangements also seek to incentivise the companies to improve efficiency (keeping costs down for consumers), innovate technically and to act in line with the interests of consumers and other stakeholders.

13. Investment in transmission infrastructure contributes to security of supply in three main ways. It allows the connection of new generation to replace ageing or retired power stations and new sources of generation which increase the diversity of our power supply. Investment in infrastructure also strengthens the capability of the system to

3 http://www2.nationalgrid.com/UK/Services/Balancing-services/System-security/Transmission-

Constraint-Management/Transmission-Constraint-Management-Information/

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securely transport electricity from where new generation is built to where demand is located. Extending the transmission system into new areas can also increase operational flexibility.

14. We have approved funding for more than £2.9 billion investment in the Scottish transmission system which is currently under construction (as shown in table 1).

Table 1: Major transmission investment being built in Scotland in 2009/10 prices

Project name Additional capacity

Scheduled Delivery date

Cost (£m)

Beauly Denny 1,200MW 2016 £690

Western HVDC 1,200MW 2017 £1,051

Kintyre Hunterston 270MW 2016 £174

Beauly Mossford 252MW 2015 £46

Caithness Moray 800MW 2018 £959

Total 4,422MW £2,920

15. A further £2.5 billion investment in the Scottish transmission system could be needed to connect new generation under the current price control period, 2013-2021 (as shown in table 2). Large new Scottish transmission projects will be considered under the Strategic Wider Works arrangements, which allow SHE Transmission and SP Transmission to invest in additional transmission projects when more information is available about the project. This flexibility helps to manage uncertainty and ensure value for money for consumers by progressing large transmission projects at the most appropriate time.

Table 2: Future potential projects

Project name Reason for investment Estimated cost (£m)

East Coast upgrade

Increase in north south flows £215

Western Isles link New generation on Lewis £700 to £900

Shetland Isles link New generation on Shetland £600

Orkney link New generation on Orkney £200

Dumfries Galloway New generation in southwest Scotland £230

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Denny Wishaw Increase in north south flows £350

16. The charges users pay to use the transmission network are designed to reflect how much the owners of the transmission system will have to invest in the network to accommodate that customer. This applies to generators who are transmitting power over the network and to demand customers who rely on the network to provide them with power. Generators pay roughly one quarter of these charges, while consumers meet three quarters of these costs through their electricity bills.

17. In 2010 we began a review of the transmission charging arrangements under Project TransmiT. Our aim was to consider whether and in what way transmission charging should respond to the increasing amounts of renewable generation on the system. We concluded that it was in the best interests of consumers to continue with a cost reflective system but we proposed changes to better reflect the way in which different users impact on the network, for example generators who transmit power intermittently. Without a signal to enable generators to account for the costs they impose on the system decisions would not be efficient leading to higher costs for GB consumers in the long term. The importance of a locational price signal in delivering efficient outcomes is seen on the demand side as well where some large energy users already respond to price signals and contribute to a more efficient energy system. For example, some customers change their consumption at winter peak times which reduces their transmission charges. This could avoid or defer costly investments in the transmission networks.

System planning

18. In March 2015 we concluded the Integrated Transmission Planning and Regulation project (ITPR)4 which considered whether the existing arrangements for planning and delivering the onshore, offshore and cross-border electricity transmission networks were fit for purpose. Our aim was to ensure that transmission is developed in an efficient, coordinated and economic manner, with the right investments made to protect existing and future consumers.

19. An efficient transmission system should help ensure an appropriate level of security of supply whilst protecting consumers from paying for capacity that is not needed.

20. Following ITPR the System Operator will be given additional responsibilities to identify the need for investment in the transmission network, and coordinate and develop investment options. This will include a new network options assessment process, which will assess options for reinforcing or extending the GB network and the economic impact of additional interconnector capacity.

Demand-side response and system flexibility

4 Integrated Transmission Planning and Regulation project: final conclusions,

https://www.ofgem.gov.uk/publications-and-updates/integrated-transmission-planning-and-

regulation-itpr-project-final-conclusions

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21. At present, demand is driven by fairly predictable consumption patterns and by the weather. Demand-side response (DSR) – consumers changing their consumption in response to a price signal - is already used by large customers to address problems at times of system stress, such as peak times, when potential demand could run ahead of supply.

22. In the coming years, however, domestic and small non-domestic customers could play a key role in increasing the resilience of the energy system by providing demand-side response. The smart meter roll-out, the electrification of heating and cooking, the uptake of electric vehicles and of microgeneration could represent an opportunity to better manage peak demand and therefore increase the resilience of the energy system.

23. Through DSR, consumers change their energy consumption, for example by lowering their heating, in response to a signal. There is therefore an opportunity for industry to offer products to incentivise consumers to shift or reduce their consumption in order to balance demand and supply during certain periods, such as peak times. This could deliver several benefits to the system and therefore to consumers: it will reduce the amount of generation capacity needed to meet demand, it will contribute to making the most of a diverse generation mix that includes renewable generation, and it will help avoid or defer investments in the transmission and distribution networks. Industry parties and consumers will benefit from reduced energy costs.

24. To realise the benefits of DSR, it is important that industry parties have the incentives to develop innovative products, and that consumers are willing to engage when required. Ofgem’s work on system flexibility - which includes demand-side response, energy storage and distributed generation – aims at developing a strategy that clearly sets out what actions we intend to take to facilitate the use of flexibility sources in the energy system. We will publish our strategy in summer 2015.

25. Through the Smart Grid Forum we are examining the commercial and regulatory challenges to implementing a smart grid in Great Britain. Both these areas of work use learning generated by our Low Carbon Network Fund (LCN Fund).

Under the LCN Fund Second Tier, two Scottish projects have secured funding towards projects totalling over £15m expenditure. Scottish Power’s project “Accelerating Renewable Connections” is a collaboration with Community Energy Scotland, Smarter Grid Solutions and the University of Strathclyde which aims to reduce the time taken and cost to connect distributed generation. DNOs also receive funding for smaller-scale innovation projects through an innovation allowance in the price control. SSE used funding to support the development of the Orkney Energy Storage Park which has led to the installation of a battery to support the Active Network Management system and help reduce constraints on the network.

26. Alongside traditional forms of transmission-connected generation, recent years have seen the dramatic growth of smaller-scale generation connected at distribution level. Following the introduction of the Feed in Tariff (FIT) scheme 2010, Scotland now has a significant amount of distributed generation providing a potentially valuable source of energy to assist in maintaining security of supply and helping to decarbonise the energy sector.

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Table 3 shows the capacity of renewable generation connected under the FIT scheme as of December 2014. This represents 328.2MW of generation.

Technology Total installed capacity

Anaerobic digestion 2.9MW

Hydro 53.2MW

Photovoltaic 150.1MW

Wind 122 MW

Total 328.2MW

Source: Central FIT Register, December 2014

The Single European Energy Market and the role of interconnectors

27. The UK and other EU member states are committed to establishing a single European energy market to reap the benefits of trade in terms of lower prices and better security. Ofgem is playing our part to establish a common set of market rules to facilitate cross-border trade. We have also developed a regulatory regime to support greater interconnection capacity.

28. Electricity interconnectors - physical links with other countries – can increase security of supply through strengthening the transmission system and increasing potential supply sources. This is enhanced further when connecting to systems that have significantly different energy mixes which can help to balance the intermittency of GB renewable energy sources (ie wind).

29. There are currently four interconnectors between GB and Europe, providing 4GW of electricity capacity. This represents around 5% of Britain’s electricity supply. We recognised that interconnection between GB and other markets was limited and have developed a regulated regime to encourage projects to come forward called the ‘cap and floor’ regime. Through this approach, if developers’ revenues exceed the cap, then revenue above the cap is returned to consumers. If their revenues fall below the floor then consumers top up revenues to the level of the floor. Consumer gains and costs are passed on through network charges.

30. In 2014, five projects applied for cap and floor regulation in our first application window. We have issued a minded-to decision to approve four of these projects representing an additional 4.8GW of capacity, one interconnector to Norway, one to Denmark and two additional connections to France.5

31. Combined with two earlier projects, the interconnector projects currently being progressed represent a substantial increase in GB electricity interconnector capacity. These projects and those already in operation could increase GB’s interconnector capacity from 4GW to slightly under 11GW.

32. The regime is ongoing and we intend to open a second application window in 2015 for future projects that wish to be considered for the cap and floor regime.

5 In March 2015 we made a decision to grant a cap and floor in principle to the NSN project to Norway. We

also consulted on a minded-to position to grant a cap and floor regime to the FAB Link, IFA2 and Viking Link projects, but not to the Greenlink project.

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Conclusion

33. Even over the relatively short time horizon of our capacity analysis, there is significant uncertainty over the security of supply outlook across GB. In this submission we have sought to explain the action that Ofgem has taken to provide National Grid with the tools to manage these risks in the short term, while the UK Government’s Capacity Market is designed to address security of supply risks in the medium-term and beyond. We have also set out how we promote security of supply through our economic regulation of the electricity networks, and through our forward looking projects such the network innovation competitions and on DSR, the flexibility project.

34. While no electricity system anywhere in the world can give a 100 per cent guarantee we are confident that National Grid has the right tools to keep the lights on for GB consumers. However, given the tighter margins at this time there is no room for complacency. We will be happy to provide any further information to the Committee on our role and our analysis of security of supply across GB.

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SUBMISSION FROM NATIONAL GRID

Executive Summary

National Grid is committed to helping the UK move to a low carbon economy. Our role puts us at the heart of one of the greatest challenges facing our society, supporting the creation of new sustainable energy solutions for the future and developing an energy system that can underpin our economic prosperity in the 21st century. We are committed to applying our expertise to help meet this challenge.

National Grid owns the high-voltage electricity transmission system in England and Wales. Through a well-planned development and maintenance programme, our network continues to be extremely resilient. Over the next decade, we are investing around £20 billion to ensure that our electricity and gas networks continue to provide safe and reliable energy supplies to customers, as well as future-proofing against significant security and weather events.

In addition, as the National Electricity Transmission System Operator, National Grid is responsible for co-ordinating and directing power flows across the transmission system in Great Britain, which at 99.99995% is the most reliable network in Europe. We are responsible, in accordance within an agreed set of security standards, for ensuring that we balance electricity generation and demand consumption in real time whilst also maintaining a stable level of voltage control. We take our obligations to secure the electricity network very seriously, continuously monitoring, future generation, and demand via our Future Energy Scenarios and System Operability Framework, designed to provide greater clarity on the likely system impacts of our scenarios.

In the event of a sudden shock, such as an instantaneous loss of generation, we have thoroughly tested plans and procedures in place to ensure the network balancing frequency does not fall outside of the statutory limits stipulated in our licence and industry operating codes.

Shifts in the way energy is used, the need to manage ageing infrastructure and a changing energy supply mix all drive a need for investment. In particular, investment in networks to connect new sources of power and gas is a priority for ensuring security of supply as the country moves towards a low carbon economy. Part of that challenge is ensuring that new power sources, whether from nuclear, wind and other renewables are connected to the electricity transmission network in order to carry the electricity to where it is needed. Much of the new electricity generation will be in the coastal areas, or offshore, where there is currently very little existing transmission infrastructure. Therefore, a stable investment framework is essential for minimising the costs of financing these investments.

Energy efficiency should be a core part of long-term infrastructure planning, as domestic and wider energy efficient measures require effective planning. An active demand side will play an important role in meeting the challenge of delivering energy affordably and sustainably, and will reduce the need for investment in generation and networks. To encourage greater demand side participation there needs to be a clear, stably policy framework that is supported

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by delivery mechanisms that enable smart technology and initiatives to drive greater consumer awareness and participation.

Questions

1. Supply and whether there is sufficient generation to meet demand, in particular to the end of the decade. What role will new generation that is under construction, or has been consented play?

1.1. The electricity transmission network is operated on a whole GB basis and therefore any generation adequacy issues are, in the vast majority of cases, the same for Scotland as they are for the rest of GB. However, we do consider specific risks in sub-regions of the system.

Electricity demand security of the transmission network is reviewed annually and considers transmission network capability, generation and demand levels. The annual assessment is carried out in line with agreed industry standards1 and the analysis is carried out cooperatively, by the relevant transmission owners for their area of the transmission system, through the Joint Planning Committees. This is published annually through industry documents such as the Electricity Ten Year Statement.2

1.2. Scotland currently (winter 2014/15) has a 3GW positive differential between the secure transmission capability and the National Electricity Transmission System Security and Quality of Supply Standard (NETS SQSS) requirement. With the closure of Longannet and unavailability of Peterhead this could be reduced to ~1.5GW. However, on completion of the Western Link, the transmission system will have 2.5GW more capability compared to the SQSS requirement. The detail of this against the industry agreed demand security review is shown in Figure 1 below.

1.3. A number of fossil fuel plants are expected to close in the coming years, due to a combination of environmental legislation, age and profitability. Consequently, it is predicated that, ahead of the introduction of the Capacity Market in 2018/19, electricity supply margins will be tighter. There are a number of tools that can be utilised to mitigate some of the risk, such as National Grid’s Demand Side Balancing Reserve (DSBR) and Supplementary Balancing Reserve (SBR) products and DECC’s Demand Side Response (DSR) Transitional Arrangements.

1.4. However, it is vital that timely new plant is built to replace these closing plants. There are a number of mechanisms in place to support low carbon generation that will help deliver the required capacity and along with new interconnectors, new fossil fuels such as gas plant will be required to ensure security of supply into the future.

1.5. Interconnection with Europe can play an important role in delivering security of supply, as it gives GB access to generation diversity across Europe. With the introduction of Market Coupling, the flow of energy will be determined by

1 National Electricity Transmission System Security and Quality of Supply Standard

2 Electricity Ten Year Statement

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relative prices and should ensure energy goes to where it is needed most i.e. the market with the highest prices. By 2019/20, interconnectors will be able to participate in the Capacity Market which should provide greater confidence that both existing and any new interconnectors (a number of which have been granted a Cap and Floor regime by Ofgem) will deliver energy to GB.

Figure 1- Demand Security Assessment for Scotland against industry standards

The Scottish Government aims to have a “largely decarbonised electricity system by 2030”. What does this mean in practice, and are there sufficient tools in place to bridge the move from fossil fuels to renewables?

2.1. We introduced our System Operability Framework (SOF)3 in 2014 to provide a holistic view for our stakeholders of how radical changes in the energy landscape, identified in our Future Energy Scenarios (FES),4 impact future system operability. The SOF process assesses existing network performance, identifying the root causes of incidents and constraints observed on the system in recent years, and highlights potential new changes in system dynamics in future years based on system studies.

2.2. Moving to a low carbon generation mix, while achievable, does produce new challenges in particular around intermittency, system balancing, and general system operability. Some of these issues can be addressed through existing technology and tools but in addition, new technologies e.g. storage will need to play a part.

2.3. With the introduction of Electricity Market Reform (EMR) there are support mechanisms in place to help deliver both low carbon capacity and security of supply. Other tools and technologies as described above may be required to ensure system resilience.

3 http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/System-Operability-Framework/

4 http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Future-Energy-Scenarios/

Network Capability

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2.4. To further facilitate the development of the transmission networks, to meet requirements such as the move to a largely decarbonised electricity system, the introduction of new transmission system planning processes and approaches have been developed through the Integrated Transmission Planning and Regulation (ITPR) review. From roughly the end of 2015/16, a Network Options Assessment (NOA) planning process and publication will be introduced for the whole of the Great Britain transmission network. The NOA will involve greater coordination between the system operator and transmission owners, facilitating decision making on transmission reinforcements, to enable ambitions in the electricity market to be realised economically and efficiently. The NOA will be broadly similar to National Grid’s Network Development Policy, which received significant commendation from Ofgem when consulted upon and introduced in 2013. Shifts in the way energy is used, the need to manage ageing infrastructure and a changing energy supply mix all drive a need for investment, particularly as the country moves towards a low carbon economy.

2. How predictable peak demand is at present, and how is this likely to change in the coming decade. In particular, what impact will the development of demand side response have? What could be done to improve developments in this area?

3.1. Over the last decade peak demand has become more difficult to predict due to a number of factors:

Increasing drive towards energy efficiency reduced demand across all sectors.

The 2008/9 recession, also reduced demand across all sectors.

Changing consumer behaviour, including the relationship between energy prices and energy usage and increased awareness of environmental issues, such as reduction carbon footprints.

3.2. These factors led to uncertainty over the future direction of peak demand, which contributes to the difficulty in predicting peak demand.

3.3. Given the uncertainties around the economic recovery and future make-up of the economy, levels of green ambitions and future energy prices we see demand in general, and in particular peak demand, being as challenging to predict as it has been over the last decade.

3.4. Our annual Electricity Ten Year Statement aims to provide clarity and transparency on the potential development of the GB Transmission system for a range of scenarios (referenced above). Our Future Energy Scenarios also has more detail around peak demands, as well as implications for the future energy mix. This includes detailed network analysis, which enables National Grid to identify strategic gas and electricity network investment requirements for the future.

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3.5. DSR takes mainly two forms. The first shifts or reduces demand, which has the effect of reducing peak demand. The second is in the form of back up generation, such as backup generators.

3.6. Either higher underlying peak demand or high peak pricing will likely drive heavy take up of DSR. There is likely to be an increasing role for DSR into the future, which could help to reduce peak demand that would otherwise need to be met by conventional forms of generation, such as gas or coal plants, and so reduce the overall levels and costs of conventional generation required to meet peak demand. There are a number of support mechanisms in place to encourage greater participation of demand side products such as DSBR, TA (Transitional Arrangements) and CM (Capacity Mechanism).

3.7. As the System Operator, we are responsible for balancing the system in the final hour before real-time. This role is called residual balancing and occurs after the market has closed. It accounts for less than 3% of energy transactions in the market. Our transmission licence obliges us to do this in a manner which represents the best value for money for consumers. This includes a range of generation and demand side services where it is economic to do so. We continue to assess and develop new commercial services to do this role more economically in the best interests of consumers.

3.8. More than 97% of all traded actions go through suppliers, which is where there is substantial opportunity to increase demand side participation in the electricity market. Suppliers have direct relationships with customers, they have the ability to incentivise the demand community to shift demand away from peak periods, e.g. through time of use tariffs or procuring DSR services from intermediaries, or engage in more permanent demand reduction. We also see a role for smart technology and energy systems; smart grids, meters and appliances. Any reduction in peak demand would reduce the need for investment in peaking generation plant.

3.9. In order to successfully encourage greater demand side participation in the future, there needs to be a clear stable policy framework that is supported by delivery mechanisms, as well as pricing signals and communication initiatives to drive greater consumer awareness and participation. There is however a need for clear policy direction with respect to demand side products, particularly the consideration as to whether they should be subject to the same commercial framework as generation or whether more specific arrangements should be developed. Whilst the establishment of a level playing field is important, more general policy direction specific to demand side may prove beneficial in the short term to ensure the deployment of technologies in a timely manner.

3. A number of new transmission network projects are currently under construction or being planned. What role will these have in securing electricity supplies, and where should future investment be directed? What role might the distribution network, and a single European electricity market play in securing supplies?

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4.1. There are significant reinforcements planned on the electricity transmission network to facilitate Scotland’s long-term ambitions with respect to green energy and targets. Many of these investments while also contribute significantly to the security of demand within Scotland at times of low wind and during generation maintenance periods.

4.2. Some of these key reinforcements are the Western Link and Beauly-Denny which will both be complete by 2017. Pre Western HVDC Link, 2.6GW (almost half of the 5.4GW Scottish peak demand) can be supported from England and Wales and post Western Link this will be as high as 75% of peak demand. Pre Beauly-Denny and Western HVDC Link, 65% of the demand in the north of Scotland, on the Scottish Power to Scottish Hydro Electric boundary, can be secured by the transmission system. Following the completion of this work the transmission system will be able to supply wholly the demand in this area.

4.3. In the future, the transmission network owners will continue to review the network requirements in the Scottish network areas. Should any investment be required because of this work, this would be taken forward through the appropriate process within the current regulatory frameworks.

4. A number of significant changes to the electricity market have recently been finalised and are being put in place to ensure competition and cost reflective prices for consumers. Are policies such as the Capacity Mechanism under Electricity Market Reform adequate, and what other long term signals might be necessary to ensure security of supply?

5.1. The first Capacity Market auction took place in December 2014, a total of 65GW of capacity qualified to participate in the auction against a target of 48GW. The auction itself successfully procured 49.3GW of capacity for delivery in 2018/19. This was achieved at a cost of £19.40/kW, a further 2.5GW of capacity will be procured in an auction that will take place one year ahead of the delivery year allowing additional opportunity for fine tuning of the requirements for 2018/19 as well as providing an additional route to market for demand side response.

5.2. The successful outcome of the 2014 auction ensured that for the 2018/19 delivery year there will be adequate capacity available on the network to meet peak demand. The EMR policy objectives and the design of the capacity mechanism clearly set out the Government’s commitment to ensure security of supply and how this would be achieved through the Capacity Market.

5.3. Security of Supply is continually monitored and reported to Government on a regular basis, in addition to an annual report that provides a view of Electricity Capacity Adequacy and informs Government of the required volume of capacity to be procured in subsequent auctions. These reports are published and available to the market. Further regular reporting of forecast future market conditions coupled with information and analysis of current market behaviours could provide additional, useful information to the market which in turn could help to ensure security of supply.

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5. Any other matters concerning security of supply that you would like to bring to the Committee’s attention.

5.1 A review of the security of supply within Scotland has recently been conducted by National Grid Electricity Transmission, Scottish Hydro Electric Transmission (SHET) and Scottish Power Transmission (SPT). The information has been published on National Grid’s website.5

5.2 The analysis focused on three key periods of operation over the course of a year when the system could expect to be stressed by generation and demand scenarios; these were winter and summer peak and also a summer minimum condition. The areas of the network that were reviewed were north of England, England to Scotland boundary and internal boundaries in Scotland including the one between the transmission owners SHET and SPT.

5.3 The analysis was also carried out over three discrete points in the future. These three points were relative to reinforcements that are currently planned to reinforce areas of the network. These major reinforcements were Series and Shunt compensation (completion assumed Q4 2015), Western Link (completion assumed Q4 2016) and Beauly-Denny upgrade (completion assumed Q4 2015). The boundaries that were assessed are shown in Figure 2 below.

Figure 2 – Geographic boundary map of transmission system in Scotland and North England

5.4 These boundaries are assessed as part of each Transmission owners licence and are continually reviewed together as part of the Joint Planning Committee. In respect of Scottish security of supply, we intend to review the

5 http://www2.nationalgrid.com/UK/Services/Balancing-services/System-security/Transmission-Constraint-

Management/Transmission-Constraint-Management-Information/

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transmission requirements to support demand security biennially and discuss it in the relevant industry information documents.

5.5 The analysis that was undertaken took all of the generation shown in Figure 3 and took sensitivities off to stress test the system. This analysis was carried out by removing key generation plant such as Longannet and Peterhead and then taking out at least one other key power station within each sensitivity study. The generation sensitivities were taken on the key conventional plant shown in Figure 3 below. These were; Hunterston, Torness, large pump storage units in Scotland and some key units in England. The stress test involved a no-wind situation and only limited Hydro as a consistent background for all of the analysis.

5.6 Stress testing of the network occurred over different demand points throughout the year and with varied prevailing network conditions, different generation backgrounds and fault conditions on the network. In total, some 140 sensitivity backgrounds were analysed each including a varying number of key transmission faults at a time; meaning that over 1000 potential scenarios were analysed in determining the network capacity.

Figure 3 – Current generation volumes within Scotland by Plant Type

5.7 As a result of the work undertaken by the transmission owners, in advance of the key network reinforcements, a new contract to ensure Scottish demand security and ability to operate the network has been placed with Peterhead by National Grid as system operator and further investments in the network have been identified by the three transmission owners.

0

2000

4000

6000

8000

10000

12000

Scottish Generation Conventional Intermittent

Interconnector

Embedded Wind

Wind

Pump Storage

Nuclear

Hydro

Coal

CHP

CCGT

Biomass