Demand Side Flexibility Annual Report 2019 - Power Responsivepowerresponsive.com/wp-content/uploads/2020/04/Power... · 2020-04-09 · 03 We are pleased to publish the 2019 Power

Demand Side Flexibility Annual Report 2019

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Contents

Foreword 03

1. Introduction and Headline Findings 04

2. Power Responsive Programme 09

3. Demand Side Flexibility – Provider Insights and Industry Developments 123.1. Demand Side Provider Insights 123.2. Policy, Regulatory and Market Developments 12

4. Metrics Illustrating Participation in Demand Side Flexibility 194.1. Short Term Operating Reserve (STOR) 194.2. Fast Reserve 284.3. Firm Frequency Response (FFR) 354.4. Frequency Response Auction Trial 404.5. Capacity Market 454.6. Triad Avoidance 46

5. Future Developments for Demand Side Flexibility Opportunities 48

6. Annex A: Power Responsive Steering Group Members 2019 52

7. Annex B: Glossary 53

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We are pleased to publish the 2019 Power Responsive Annual Report, which reflects on policy, regulatory and market developments over the past 12 months, as well as trends in demand side flexibility participation. This report is designed to help stakeholders navigate industry change and complexity and support the continued development of demand side participation in flexibility markets.

For more information on Power Responsive, visit www.powerresponsive.com.

The 2019 Power Responsive Annual Report has been written on behalf of the Power Responsive Steering Group by National Grid Electricity System Operator and the environmental charity Sustainability First.

Demand side response (DSR) by flexible load shifting (e.g. heating/cooling systems, business operations and appliances).

DSR by onsite generation.

DSR by onsite energy storage.

Distributed generation – for export.

Distributed energy storage – for export.

The Power Responsive programme uses the term demand side flexibility (DSF) to encompass five categories of flexible response:

It has been a year since National Grid Electricity System Operator (ESO) became a legally separate business within the National Grid Group. That year has also seen an increased focus on climate change across the globe, which has accelerated the drive towards a low-carbon future.

The energy industry has a critical role to play in delivering net-zero emissions by 2050, and together we’ve been making significant progress, particularly in the area of providing flexible and greener energy that delivers cost benefits to the consumer.

As the ESO, our mission is to enable the transformation to a sustainable energy system and ensure the delivery of reliable, affordable energy for all. Success in 2025 looks like:

• An electricity system that can operate carbon free;

• A whole system strategy that supports net zero by 2050;

• Competition everywhere; and• The ESO as a trusted partner.

Our RIIO-2 Business Plan sets out how we are going to achieve these ambitions – what we are going to do, what investments we need to make and how our performance will be measured. We’ve also been putting in place learnings following the 9th August power cut, so that we can continue to provide a reliable electricity system as the UK switches to more renewable sources of generation. Through Power Responsive we are focusing on demand side flexibility (DSF), which provides us with a way of balancing the network and allowing energy users to reduce their carbon footprint by changing their energy consumption.

Our work in this area is a collaborative effort, and I’d like to thank everyone who has engaged with and contributed to the Power Responsive programme this year. I look forward to continuing this engagement as we continue to work towards delivering a cleaner, greener and affordable energy future for the UK.

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Foreword

Message from Kayte O’NeillHead of Markets, National Grid Electricity System Operator

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Introduction and Headline Findings

Within this section, we introduce the Power Responsive Annual Report and its purpose, as well as provide a snapshot of the key headlines.

As we transition into a low-carbon world, demand side flexibility has an increasingly important role. Electricity system requirements are evolving, at both a transmission and distribution level, and we need additional sources of flexibility to meet these needs – from an increasingly diverse range of technologies.

This is the fourth Annual Report of the Power Responsive programme, aimed specifically as a tool to support demand side providers and investors, whilst also providing a reference for industry stakeholders interested in the flexibility landscape.

Demand side markets are still maturing, yet also developing quickly in response to changing system needs. This report therefore reflects flexibility progress in 2019 and highlights upcoming activity into 2020/21. The content covers:• An overview of Power Responsive and the programme’s future strategy for

supporting the development and participation of demand side markets.

• Highlights of recent policy, regulatory and industry-led initiatives supporting or impacting DSF.

• Demand side metrics across National Grid ESO Ancillary Services, the Capacity Market and Triad activity in 2019 assessing how these markets have developed over a three-year period.

• Future outlook for demand side markets and flexibility opportunities.

Headlines from the 2019 Report

Change continues to cause uncertainty Uncertainty was a theme reported in 2018 and has continued as demand side providers face challenging times, with many changes to markets, charges and regulations affecting their revenue streams. The main reasons for this uncertainty are changes to the network charges providers will pay in the future as a result of Ofgem’s Targeted Charging Review (TCR), the suspension and then reinstatement of the Capacity Market, and ongoing developments to the Ancillary Services products and markets to make them fit to meet the future challenges of managing the system.

Markets continue to deliver opportunities for DSF providersDSF providers’ share of reserve markets continues to increase, despite lower volumes of utilisation in Short Term Operating Reserve (STOR) following an internal review in August 2018. This increase was helped in

2019 by greater volumes of Fast Reserve being procured by the ESO and the lowering of the minimum unit size from 50MW to 25MW. Prices have remained broadly stable, indicating mature and competitive marketplaces. The Firm Frequency Response (FFR) market continues to be a healthy opportunity for demand side providers to operate in, with comparable static capacity awarded in 2019 and double the dynamic capacity awarded to DSF providers compared to 2018. A natural price point has also emerged in Dynamic FFR. The introduction of the weekly Frequency Response auction in November 2019 is likely to provide further opportunities in 2020.

Mixed success for DSF in the Capacity MarketWhilst DSF market share and cleared price remained broadly the same for the T-4 and T-3 auctions, participation and success continue to decline in the T-1 auction, with less than 100MW being successful in 2019. This is likely due to the T-1 price collapsing and the uncertainty over the suspension.

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Detailed Summary of the 2019 Report

Regulatory and Policy Developments

Key Message: Change continues to cause uncertainty Uncertainty was a theme reported in 2018 and has continued as demand side providers face challenging times to unpick the flexibility landscape and its evolving developments.

– The Clean Energy Package came into force in July 2019 with many of its provisions applying from 1st January 2020. As a result, National Grid ESO are required to make some changes in their approach to procuring reserve services. The STOR and Fast Reserve markets have been suspended as a result.

– The Targeted Charging Review decision was announced by Ofgem in November 2019. The decision changes the way in which some of the costs of the electricity networks are recovered, so that the ‘residual charges’ are recovered more fairly today and in the future. Therefore, demand users who have previously paid minimal Transmission Network Use of System (TNUoS) as result of Triad Avoidance will now pay a fixed, unavoidable charge.

– ESO market developments – in order to meet growing renewable generation, the ESO are reforming existing reserve and response markets, and exploring wider opportunities to manage new challenges such as voltage, inertia and constraint management. Whilst clear about our intent, this still causes uncertainty for providers and their business models.

– Greater opportunities lie ahead for demand side providers as Distribution Network Operators (DNOs) become more active in managing their networks. Ofgem have shown a desire for greater progression in this space and called for DNOs to move quickly in the build-up to the new RIIO-ED2 price control.

– Capacity Market – whilst its reinstatement is positive for the demand side provider, its suspension still created uncertainty throughout much of 2019.

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Market Metrics

STOR

Key Message: Realigning STOR to the Balancing Principles Statement in 2019 has had a significant effect on the service utilisation, procurement and utilisation pricing. Whilst aligning to the Balancing Principles Statement should provide greater transparency, it has also reduced the size of the service and reduced average prices.

Detail:Total utilisation has significantly decreased in 2019 as a result of National Grid ESO’s August 2018 review to ensure the use of STOR aligns with the Balancing Principles Statement. From September 2018 onwards, STOR usage reduced in line with this guidance.

This has also affected the available capacity that has been procured throughout 2019, having decreased from 2018 procured capacity. However, DSF market share compared to traditional providers has remained favourable, which indicates that the August 2018 review has affected the whole STOR market rather than DSF in particular.

Substantially more DSF volume continues to be utilised, likely to be reflective of the lower utilisation prices award to DSF providers, and therefore instructed in price merit order by National Grid ESO’s control room. Accepted availability prices have remained broadly the same across 2019, indicating that the market has reached a natural price point for availability of around £2/MW/h.

Fast Reserve

Key Message: Demand side flexibility providers began to take a substantial share of the Fast Reserve market, in part due to the entry-level reduction from 50MW to 25MW in March 2019. In general, the service remained relatively static, with comparable utilised volumes to 2018, and availability prices finding a consistent price.

Detail:Following a consultation on proposed changes to the Standard Contract Terms for Fast Reserve, a decision was made to reduce the entry level from 50MW to 25MW from 25th March 2019. To date only five tenders of less than 50MW have been accepted; however, this is an appreciable share considering that the capacity being procured through Fast Reserve is around 300MW at any one time. In general, availability prices have remained broadly stable, whilst utilisation prices for DSF have continued to decrease over 2019.

The increase in requirement being sought through the December 2019 tender resulted in a noticeable increase in success for DSF providers, with 75% of tenders being accepted in 2019 compared to just 30% in 2018, for a total capacity of 544MW. This tender also showed a wider and higher range of accepted availability prices for DSF, combined with lower utilisation prices, indicating that providers are seeking more certainty over Fast Reserve revenues.

The changing flexibility landscape continues to provide opportunities for DSF providers despite the uncertainty.

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Firm Frequency Response (FFR)

Key Message: FFR continues to be a healthy market for demand side providers to operate in with comparable static capacity awarded in 2019, and double the dynamic capacity awarded to DSF providers compared to 2018. A natural price point has also emerged in Dynamic FFR.

Detail:The requirement in the FFR market is starting to be moved to the Frequency Response Auction Trial, so we expect to see a gradual reduction in the volumes being achieved in FFR. However, in 2019 the trend of DSF replacing traditional units in providing Dynamic FFR continues, with double the capacity of DSF being successful in 2019 compared to 2018. This was helped to some extent by the decision to move some response requirement from the mandatory market to the FFR market in the latter half of the year.

This came at the expense of the static service, none of which was procured in the last three months of the year, although there had been no requirement for overnight Static FFR since April 2019.

Prices for Dynamic FFR remained similar to the previous year’s average of £4.76/MW/h for the majority of 2019.

Towards the end of the year, the larger volume being sought meant that units with higher prices were being accepted, which increased the average accepted price through 2019 to £11.50/MW/h. This price increase, combined with the move of some requirement out of the mandatory market, meant that some traditional providers returned to FFR and were consistently successful for the first time since mid-2018. DSF providers were still more successful, however, achieving three times the capacity of traditional units in the dynamic service.

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Market Opportunities and Developments

Demand side flexibility is continuing to evolve at pace, helping the ESO to maximise the use of renewable sources of electricity generation, and reducing and removing constraint payments from network management tools. In the following section, we have set out some of the significant developments taking place across the flexibility markets and where there may be potential future opportunities.

• Local flexibility – DNOs are continuing to explore contracting demand side flexibility services at a local level. Coordination across markets is being explored through numerous projects and programmes, most notably the Energy Networks Association’s (ENA’s) Open Networks Project. Market platforms are being trialled to explore different approaches to coordinated transmission and distribution flexibility procurement, with BEIS in particular launching their Flexibility Platform Completion in 2019.

• National Grid ESO Reserve and Response – in December 2019, National Grid ESO published their Response and Reserve roadmap to inform stakeholders of plans to reform the Frequency Response and Reserve services, providing a clear view of future developments, and support market providers to respond and adapt to market change.

• Understanding opportunities for evolving system requirements – setting out the 2025 net-zero ambition for a system that can operate carbon free sets out a clear direction for where National Grid ESO will explore wider opportunities to manage new challenges such as voltage, inertia and constraint management.

• Wider Access and the Balancing Mechanism – National Grid ESO opened up access to the Balancing Mechanism for non-BSC (Balancing and Settlements Code) parties in December 2019 through the Virtual Lead Party (VLP) route. Increasing access to the Balancing Mechanism is a step in the move to a low-carbon future. To date, only one provider completed the VLP process, whilst a number of non-BSC party assets have participated via the supplier route.

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Power Responsive Programme2.0This section provides an insight into the objectives of the Power Responsive programme, the activities and achievements during 2019 and what the priorities are for 2020.

About the programmePower Responsive is a stakeholder-led programme, facilitated by National Grid ESO, to stimulate increased participation in different forms of flexible technology such as demand side response (DSR), small-scale generation and storage. Together we class these solutions as demand side flexibility (DSF).

The programme brings industry and energy users together, to work in a coordinated and collaborative way. A key priority is to grow participation in DSF, making it easier for industrial and commercial businesses to get involved and realise financial and carbon-cutting benefits.

Power Responsive is overseen by a high-level steering group, which meets quarterly with representatives of relevant DSF stakeholder groups. The steering group sets the strategic direction, objectives and priorities of the programme. We also host Power Responsive Flexibility Forums to encourage industry collaboration across all DSF technologies, raise awareness of relevant industry developments and provide the opportunity for delegates to speak with subject-matter experts. A metrics sub-group met over the autumn to inform DSF metrics for this report.

Success to dateSince the creation of Power Responsive in 2015, there has been an increasing awareness and focus on demand side flexibility (DSF). At inception, Power Responsive was unique in its approach: collaborative, looking across the DSF landscape, steering a concerted programme to deliver greater awareness and develop markets. Power Responsive has played

a significant role in transitioning demand side flexibility and provision of balancing services to become a mainstream proposition:

• Between 30% and 50% of balancing services tenders in 2018/19 were received from demand side providers.

• We have moved from engaging 20 to 30 participants in our original DSR provider group to regularly hosting over 200 attendees at our flexibility forums and summer events.

Looking aheadIn recent years, new forums and programmes have appeared which have focused wholly or partially on demand side providers1. DNOs are now starting to procure demand side flexibility directly to manage issues on their own networks, and there are now local energy market platforms being developed to trade or sell flexibility across distribution and transmission.

In this landscape, it is challenging for DSF providers to fully engage with all developments, and it is also challenging for policy-makers to ensure that they are listening to and taking on board the views of the demand side flexibility community. To date, few, if any, other forums bring customers and industry parties together with policy-makers and regulators on a regular basis to discuss issues that cut across multiple areas of DSF. Power Responsive has developed its strategy for 2020 and beyond to have a clear focus, retaining a defined identity, and continues to add value for providers.

¹. Such as BEIS and Ofgem’s Smart Systems Forum; the Wider Access to the Balancing

Mechanism project; the Association for Decentralised Energy’s ‘Flex Assure’ code

of conduct for aggregators; the Energy Networks Association’s Open Networks

Project; the Charging Futures Forum; the Charging Delivery Body (CDB); and the

Settlement Design Advisory Board.

A key priority is to grow participation in DSF, making it easier for industrial and commercial businesses to get involved and realise financial and carbon-cutting benefits.

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Power Responsive Strategic Goals

Our strategic goals for 2020/21are to:

• Inform the development of inclusive markets for flexibility, which through competition can deliver economic efficiency, carbon reduction and innovation.

• Promote fair and equitable flexibility market participation, focusing primarily on markets facilitated by the ESO.

• Allow customers and DSF provider perspectives to be heard by policy-makers and market actors, and to feed these perspectives into the development of flexibility markets, policy and regulation.

• Identify and champion the removal of barriers to flexibility entry and participation.

• Support the progression of BEIS and Ofgem’s Smart Systems and Flexibility Plan.

• Support the delivery of the ESO’s ambitions to deliver a sustainable whole energy future, and achieve zero-carbon operability by 2025.

National Grid ESO Commitments

Power Responsive’s strategic goals support National Grid ESO ambitions through its RIIO-2 Business Plan and Forward Plans 2019-21.

RIIO-2 Business PlanThe ESO Business Plan sets out the ambitions of the ESO across the first five-year price control period as a legally separate entity. It is designed to meet the future needs of the energy market, and its development has allowed the ESO to engage extensively with stakeholders to define and develop its role during a time of significant change. The outputs in the RIIO-2 period have been grouped into four themes:

• Reliable, secure system operation to deliver electricity when consumers need it

• Transforming participation in smart and sustainable markets• Unlocking consumer value through competition• Driving towards a sustainable whole energy future

Power Responsive forms part of the second theme: Transforming Participation in Smart and Sustainable Markets. Through the RIIO-2 period we will continue to evolve the work of Power Responsive by introducing more regular and specific metrics and publications.

Forward Plans 2020-21National Grid ESO Forward Plans are published annually for the financial year and include a set of criteria to measure its performance against, which covers:

• Control Centre operations • Market development and transactions• System insight, planning and network development

The work of Power Responsive sits firmly under ‘Market development and transactions’, covering balancing and ancillary service market design, and service procurement and settlement.

There are three specific deliverables for Power Responsive that the ESO has committed to achieving through the Forward Plan:

• Developing a programme to increase and focus feedback and interaction with the demand side community on our balancing services developments;

• Promoting industry developments for demand side flexibility and facilitating feedback to shape ESO deliverables through a range of engagement activities; and

• Building on our 2019-20 deliverable of stakeholder engagement and innovation projects, moving closer to introducing a whole system flexibility programme.

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Impact of COVID-19Since preparing this plan, we have all been faced with huge changes in our home and business lives as a result of COVID-19. It is clear that disruption will continue during the months ahead and, as we aren’t quite clear on the impact on our business and the energy industry just yet, we haven’t currently changed the contents of this plan. However, we will be constantly reviewing our plans taking into account changing priorities for the ESO and our stakeholders as we work to continue operating a secure and reliable electricity system.

Approach to deliveryThe Power Responsive programme is facilitated by the ESO and delivered through a coordinated and collaborative approach with end-customers and industry participants. It aims to:

• Increase awareness and engagement of all flexibility markets at both transmission and distribution level;

• Build confidence in the markets and new revenue streams;

• Identify areas needing change to lower barriers to participation; and

• Take forward actions to support the transition towards whole system outcomes.

Steering GroupWe will continue to coordinate delivery of the programme through the quarterly Steering Group meetings, chaired by the ESO. The purpose of the Steering Group is to be a high-level cross-industry forum, tasked with identifying opportunities, gaps, blockers and disconnects, offering feedback, advice and critical challenge to those setting the frameworks, rules and/or procuring DSF. The Steering Group is comprised of senior representatives from a number of industry sectors (see Annex A). Steering Group nominees for each sector are identified via a relevant trade body, where applicable, with input from the Power Responsive team.

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Demand Side Flexibility – Provider Insights and Industry Developments3.0This section highlights provider insights from The Energyst’s DSR Survey 2019 and industry developments across policy, regulation, network operators and wider industry actors.

3.1. Demand Side Provider Insights

Headlines from The Energyst DSR Survey 2019In September 2019, The Energyst launched their fifth Demand Side Response Report: Shifting Value, offering a perspective from end-users and service providers. Of 108 responses, 68 customer responses were used for the survey (removing responses from aggregators, energy companies and consultants). Findings from the survey include:

• The majority of providers remain broadly satisfied that DSR is worth their while. But, revenue and confidence have been eroded by changes to products, new regulations and suspension of the Capacity Market (now restored).

• Most respondents don’t participate in DSR (72%). Of the 28% that do participate in DSR, 65% are large companies, 84% spend more than £1m per annum on electricity and only 11% have a maximum demand of less than 1MW.

• Most DSR is contracted through an aggregator (60%), with some through a supplier (22%), a DNO (28%) or direct with National Grid (11%).

• 61% of DSR providers say they could provide significantly more flexibility. These include companies in the water, retail, transport and education sectors. The barriers to providing more DSR include revenue uncertainty, insufficient rewards, regulatory uncertainty and operational concerns.

3.2. Policy, Regulatory and Market Developments

Developments within the energy industry and flexibility markets are happening at pace. Here we highlight some of the developments that are taking place across policy, regulation and markets with relevance to DSF.

European network codesThe Third Energy Package of European legislation created a requirement for European network codes (ENCs), covering grid connections, markets and system operation. The codes are designed to provide a sustainable, secure and competitive electricity market across Europe and facilitate the development of a harmonised European internal energy market.

The Clean Energy Package is the next tranche of European energy legislation, and it builds upon the content of the Third Energy Package and the associated network codes. It came into force over the course of 2018 and 2019 with the aim of decarbonising energy and facilitating better consumer outcomes with many of its provisions applying from 1st January 2020.

61% of DSR providers say theycould provide significantly more flexibility.

What does this mean for DSF?One such provision of note to demand side providers requires National Grid ESO to procure Reserve at no more than one day ahead, for a contract length of no more than one day. At the time of publication STOR and Fast Reserve tenders have been suspended whilst National Grid ESO ensure its procurement aligns with the new requirement.

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The European Commission has also identified demand-side flexibility as an area where a network code could be required to facilitate cost-effective large-scale integration of renewable energy sources. The consultation period closes in April 2020.

GovernmentA huge number of reports and consultations were published in 2019 and early 2020, with implications for demand side flexibility. BEIS and Ofgem are systematically working to implement actions from the 2017 Smart Systems and Flexibility Plan and 2018 Progress Update. An Energy White Paper is expected in spring 2020. The Smart Systems Forum continues to meet with a likely focus in 2020 on removing barriers for storage, consumers and buildings, improving markets for DSF and implementing the recommendation of the Energy Data Taskforce Report for presumed open data, as also outlined in a Smart Data Strategy.

The government has adopted a statutory target of net-zero greenhouse gas emissions by 2050. This follows advice from the Committee on Climate Change in their Net Zero report. BEIS plans to produce a document on Pathways to 2050 – which will consider barriers in the market for flexibility – measuring and monitoring progress. The Environment Bill is passing through the Commons with a focus on climate change and air pollution. COP 26 will be hosted in Glasgow in November 2020, which will increase the focus on the UK’s leadership on climate change. The government is also working to maintain continuity and trading arrangements with the EU including via the interconnectors, in the context of Brexit.

• Capacity Market Suspension of the Capacity Market has been lifted, following an investigation by the European Commission and European Court of Justice ruling to ensure compliance with State Aid rules.

• Contracts for Difference (CfD) There is an open consultation on CfD Allocation Round 4 with proposed amendments to the scheme to facilitate floating offshore wind projects – which will be classified as a separate technology with a distinct administrative strike price – and exclusion of new coal-to-biomass conversations. BEIS is also consulting on extending the negative pricing rule to ensure offshore wind does not receive CfD payments if prices are negative in the day-ahead markets. This could have significant implications in terms of signals to the wholesale market.

What does this mean for DSF?There is a great deal of focus on removing barriers to flexibility, and it is expected that there will be further commitments to this in the Energy White Paper once published. The heightened focus on climate change and net zero could strengthen the requirement for demand side provision of flexibility and should provide confidence to investors and demand side providers, depending on the policy goals that are addressed.

The reinstatement of the Capacity Market should be further positivity for the demand side provider as deferred Capacity Market payments can now be made, and future Capacity Market volumes can be tendered for.

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/633442/upgrading-our-energy-system-july-2017.pdf

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/633442/upgrading-our-energy-system-july-2017.pdf

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/756051/ssfp-progress-update.pdf

https://www.ofgem.gov.uk/publications-and-updates/smart-systems-forum

https://es.catapult.org.uk/reports/energy-data-taskforce-report/

https://www.gov.uk/government/consultations/smart-data-putting-consumers-in-control-of-their-data-and-enabling-innovation

https://www.gov.uk/government/news/uk-becomes-first-major-economy-to-pass-net-zero-emissions-law

https://www.gov.uk/government/news/uk-becomes-first-major-economy-to-pass-net-zero-emissions-law

https://www.theccc.org.uk/wp-content/uploads/2019/05/Net-Zero-The-UKs-contribution-to-stopping-global-warming.pdf

https://services.parliament.uk/bills/2019-21/environment.html

https://www.gov.uk/government/collections/contracts-for-difference-cfd-allocation-round-4

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/869778/cfd-ar4-proposed-amendments-consultation.pdf

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/869778/cfd-ar4-proposed-amendments-consultation.pdf

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OfgemOfgem has produced a Decarbonisation Programme Action Plan in response to the challenge of net-zero emissions, underpinned by a focus on flexibility. This follows on from Ofgem’s Strategic Narrative: 2019-2023 and Medium Term Objectives and Priorities to deliver major changes to the energy system including large-scale extension of flexibility markets enabled by appropriate technologies.

The Targeted Charging Review (TCR) concluded that residual charges are levied on a fixed basis. The proposed removal of embedded benefits is likely to have implications for some large customers and DSF providers. The RIIO-2 Business Plans Draft Guidance was released with an Open Letter Consultation on approach to setting the next electricity distribution price control (RIIO-ED2). Ofgem published a consultation on the regulatory treatment of CLASS as a balancing service in RIIO-ED2 network price control, with a minded-to position that DNOs provide network voltage control and network management services.

Ofgem is working toward a more standardised set of arrangements for demand side flexibility, and also produced an insight paper on Flexibility Platforms in electricity markets. Retail market reforms include consideration of how smaller customers can engage with smart systems – including smart meter rollout and market-wide half-hourly settlement reform.

What does this mean for DSF?Outlining major changes that include a large-scale extension of flexibility markets should be viewed positively by demand side stakeholders.However, the minded-to position to allow DNOs to provide network management services could be viewed negatively, as this is likely to compete with demand side customer opportunities. The effect of the TCR decision on how TNUoS charges are calculated will differ per demand user dependent on the ‘band’ each customer is put into. The ‘band’ is related to the voltage level that they are connected to, and their individual consumption. Therefore, demand users who have previously paid minimal TNUoS as result of Triad Avoidance will now pay a fixed, unavoidable charge.

https://www.ofgem.gov.uk/system/files/docs/2020/02/ofg1190_decarbonisation_action_plan_revised.pdf

https://www.ofgem.gov.uk/system/files/docs/2019/07/our-strategic-narrative-2019-23.pdf

https://www.ofgem.gov.uk/publications-and-updates/ofgem-sets-out-medium-term-objectives-and-priorities

https://www.ofgem.gov.uk/publications-and-updates/targeted-charging-review-decision-and-impact-assessment

https://www.ofgem.gov.uk/system/files/docs/2019/06/riio-2_business_plans_guidance_june_2019_-_published.pdf

https://www.ofgem.gov.uk/system/files/docs/2019/06/riio-2_business_plans_guidance_june_2019_-_published.pdf

https://www.ofgem.gov.uk/system/files/docs/2019/08/open_letter_consultation_on_the_riio-ed2_price_control.pdf

https://www.ofgem.gov.uk/system/files/docs/2019/08/open_letter_consultation_on_the_riio-ed2_price_control.pdf

https://www.ofgem.gov.uk/system/files/docs/2020/02/regulatory_treatment_of_class_as_a_balancing_service_in_riio-ed2_network_price_control_1.pdf

https://www.ofgem.gov.uk/system/files/docs/2020/02/regulatory_treatment_of_class_as_a_balancing_service_in_riio-ed2_network_price_control_1.pdf

https://www.ofgem.gov.uk/system/files/docs/2019/09/ofgem_fi_flexibility_platforms_in_electricity_markets.pdf

https://www.ofgem.gov.uk/system/files/docs/2019/09/ofgem_fi_flexibility_platforms_in_electricity_markets.pdf

https://www.ofgem.gov.uk/publications-and-updates/market-wide-settlement-reform-outline-business-case

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National Infrastructure CommissionThe National Infrastructure Commission’s (NIC)’s Annual Monitoring Report 2020 stresses the need to increase flexibility in the UK’s electricity networks. It includes recommendations to maintain access to future interconnector projects in negotiations with the EU, amend legislation to support the delivery of storage capacity and set out a clear level of ambition for overall system flexibility, including a transparent framework to monitor it.

Electricity System OperatorThe National Grid ESO RIIO-2 business plan focuses on how to ensure resilience and reliability of the electricity system. The ESO Forward Plan for 2020-2021 sets out a mission to 2025 for an electricity system that can operate carbon free; a whole system strategy that supports net zero by 2050 and competition everywhere; and the ESO as a trusted partner. In Ofgem’s response to the ESO’s consultation, it welcomed the ESO’s positive engagement to date with stakeholders, whilst requesting further detail on deliverables and prioritisation. A final version of the plan and stakeholder responses is due before 1st April 2020.

The ESO’s Operability Strategy Report explored future challenges in maintaining an operable electricity system nationally and regionally – considered in the Regional Trends and Insights Report. The ESO is working toward a single platform for flexibility products – starting with an auction trial. The ESO is also developing new balancing products – for voltage, constraint and inertia, discussed in the next section.

Steps have been taken to widen access to the Balancing Mechanism to non-Balancing Mechanism Units (BMUs) through two routes: the ‘Supplier’ route, and the creation of Virtual Lead Parties (VLPs). To date, 58 live units from eight providers have entered the BM through the SVA (supplier volume allocation) route and several providers are pre-qualifying for the VLP route, although none of these are live as of March 2020. The VLP route is being delivered through GB’s participation in Project TERRE (Trans-European Replacement Reserves Exchange).

What does this mean for DSF?Setting out the 2025 net-zero ambition for a system that can operate carbon free sets out a clear direction for where National Grid ESO will explore wider opportunities to manage new challenges such as voltage, inertia and constraint management.

The creation of the VLP route to the Balancing Mechanism is offering smaller providers access to a market which was traditionally the domain of large power stations.

https://www.nic.org.uk/publications/annual-monitoring-report-2020/

https://www.nic.org.uk/publications/annual-monitoring-report-2020/

https://www.nationalgrideso.com/document/158051/download



https://www.ofgem.gov.uk/publications-and-updates/ofgem-response-esos-consultation-draft-forward-plan-2020-21


https://www.nationalgrideso.com/sites/eso/files/documents/SOF%20Report-%20Regional%20Trends%20and%20Insights.pdf

16

Energy Networks Association (ENA) Open Networks ProjectBEIS and Ofgem produced an Open letter to the ENA Open Networks Project setting out priorities including transparency in evaluating flexibility tenders, clear information on current and future system needs, open data (in line with recommendations of the Energy Data Task force) and improved availability of network information. The Energy Networks Association is consulting on a draft 2020 workplan for the Open Networks Project; priorities include advancing local markets for flexibility to ensure standard approaches across DNOs for the procurement and contracting of flexibility services, and alignment with ESO markets where possible; building on the work of the Energy Data Taskforce to enhance transparency, data visibility and better access to non-confidential data across transmission and distribution networks; and growing the reach of the project with a series of new Community Energy Forums.

There is a consultation on a code modification proposal to the Distribution Connection and Use of Service Agreement (DCUSA), which will require DNOs to create a national, public register of all sites that use their networks and influence the operation of the GB power market. This register would contain details of each connected site and would be kept up to date by the DNOs. These connected sites include generators, demand sites (that have a contract to provide flexibility) and storage sites. This is an important step to providing a formal/legal mandate for DNOs to collect, maintain and share this information, improving visibility of infrastructure and assets connected to the distribution network.

What does this mean for DSF?Greater opportunities ahead exist for demand side providers as DNOs become more active in managing their networks. Ofgem have shown a desire for greater progression in this space and called for DNOs to move quickly in the build-up to the new RIIO-ED2 price control.

https://www.energynetworks.org/assets/files/ON-PRJ-2020%20Work%20Plan%20Consultation%20Paper-PUBLISHED.pdf

https://networks.online/power/taskforce-sets-out-recommendations-to-modernise-energy-system/

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Smart Export Guarantee Since the scheme came into force in January 2020, large suppliers are offering smart export tariffs on generation from solar PV, wind, micro combined heat and power, hydro and anaerobic digestion. These are all fixed tariffs for those exporting, although dynanic tariffs are likely to be developed in future, reflecting the benefits of flexibility to the system.

Quality, standards and unlocking potentialThe British Standards Institution (BSI) is developing technical standards for smart appliances and EV charge points, and a framework for demand side response. The Association for Decentralised Energy (ADE) plans to extend the Flex Assure Code – a code of conduct scheme, which sets common standards for demand side aggregators – to small customers. The Energy UK, ADE and BEAMA report on Delivering on the Potential of Flexibility urges government to accelerate progress in unlocking flexibility across the energy system to achieve net zero.

Open dataThe Office for National Statistics (ONS) is developing a data catalogue considering who data users might be and their needs. The ENA has developed an early prototype of a digital systems map – for sharing energy systems data in a coherent way. BEIS and the Energy Systems Catapult have commissioned their energy data best practice guidance. In collaboration with BEIS and Ofgem, Innovate UK launched the modernising energy data access competition. It aims to solve the problem of exchanging digital energy information between energy organisations and with other industry stakeholders. The winners will be announced in April.

What does this mean for DSF?A set of standards for smart appliances and EVs will help unlock greater volumes of flexibility, particularly from small-scale providers, although the work is at a very early stage.

What does this mean for DSF?Demand side providers who are capable of (or looking to) generate and export can ensure a fixed price for the electricity they export. This should help to provide some confidence and certainty to new and existing projects.

What does this mean for DSF?Access to and the exchange of data across the industry is thought to have significant advantages to network planning. In turn, this is likely to help signal flexibility requirements and facilitate efficient procurement, defer network infrastructure investment and drive lower bills to the end-consumer.

https://www.bsigroup.com/globalassets/localfiles/en-gb/smart-appliances-for-flexible-energy/the-energy-smart-appliances-programme.pdf

https://www.bsigroup.com/globalassets/localfiles/en-gb/smart-appliances-for-flexible-energy/the-energy-smart-appliances-programme.pdf

https://www.flexassure.org/

https://www.flexassure.org/

https://www.energy-uk.org.uk/files/docs/Research%20and%20reports/DeliveringthepotentialofFlexibility.pdf

https://es.catapult.org.uk/guides/energy-data-best-practice-guidance/

https://apply-for-innovation-funding.service.gov.uk/competition/491/overview

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Innovation and low-carbon technologiesThe government has committed up to £70 million to smart energy system innovation, with around £265 million investment expected in smart systems research, development and demonstration across government, Innovate UK and Research Councils. This includes the government’s FleX competition to support the development and demonstration of innovative solutions to value and trade flexibility, including the Piclo Exchange – an open flexibility market with primary and secondary trading at local and national levels; and Electron’s Project TraDER – to develop, integrate and scale a flexibility exchange that optimises renewable energy integration into the UK’s changing energy markets.

Electricity storagePositive steps have also been taken to clarify the treatment of storage as generation in legislation and for licensing, and confirm that DNOs cannot operate storage without Ofgem’s consent. Guidance has also been given on the co-location of storage with renewable technologies and enabling deployment of storage through the planning regime, network charging and connections. BEIS has proposed removing electricity storage (except pumped hydro) from the Nationally Significant Infrastructure Projects (NSIPs) regime as the process was considered too burdensome for storage developers.

Electric vehiclesThe Office for Low Emission Vehicles (OLEV) ran a call for evidence on Electric Vehicle Smart Charging as part of a major policy-push on standards/interoperability for electric vehicle charging. The government also ran a consultation on electric vehicle charge points in residential and non-residential buildings.

What does this mean for DSF?Innovation projects are exploring how networks can unlock greater flexibility and simplify the proposition for the demand side user. A challenge for the industry will be transitioning trials into business-as-usual activities.

What does this mean for DSF?Confirmation to restrict network operators from operating storage should benefit demand side developers who manage or develop storage projects. Guidance on co-locating storage with existing generation should assist distributed generators in operating under the Renewables Obligation (RO) or Feed-in Tariff (FiT) schemes.

https://www.gov.uk/government/publications/flexibility-exchange-demonstration-projects-flex-competition

https://www.ofgem.gov.uk/publications-and-updates/enabling-competitive-deployment-storage-flexible-energy-system-statutory-consultation-changes-electricity-distribution-licence

https://www.ofgem.gov.uk/publications-and-updates/clarifying-regulatory-framework-electricity-storage-licensing

https://www.ofgem.gov.uk/publications-and-updates/clarifying-regulatory-framework-electricity-storage-licensing

https://www.ofgem.gov.uk/publications-and-updates/guidance-generators-co-location-electricity-storage-facilities-renewable-generation-supported-under-renewables-obligation-or-feed-tariff-schemes-version-2

https://www.legislation.gov.uk/uksi/2018/254/made

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/817107/electric-vehicle-smart-charging.pdf

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Metrics Illustrating Participation in Demand Side Flexibility 4.0This section provides an overview of demand side flexibility participation in different markets.

This report uses the same metrics for DSF participation as the Power Responsive Annual Report 2018, to ensure comparability, and where possible we have included data for a three-year period, 2017 to 2020.

We refer to Balancing and Settlement Code Parties as ‘traditional providers’ and non-Balancing and Settlements Code Parties as ‘DSF providers’. The report focuses on Ancillary Services and discusses the Capacity Market and Triad management.

4.1. Short Term Operating Reserve (STOR)

Market Summary

UtilisationTotal utilisation has significantly decreased in 2019 as a result of National Grid ESO’s August 2018 review to ensure the use of STOR aligns with the Balancing Principles Statement. From September 2018 onwards, STOR usage reduced in line with this guidance. This has also affected the available capacity that has been procured throughout 2019. Substantially more DSF volume continues to be utilised, likely to be reflective of the lower utilisation prices award to DSF providers, and therefore instructed in price merit order by National Grid ESO’s control room.

CapacityFor DSF, the levels of tendered and accepted capacity and the number of individual units have all fallen since 2018 but are still higher than the figures for 2017. DSF market share compared to traditional providers has remained favourable, however, which indicates that the August 2018 review has affected the whole STOR market rather than DSF in particular.

PriceAccepted availability prices have remained broadly the same across 2019, indicating that the market has reached a natural price point for availability of around £2/MW/h. There remain some DSF providers offering availability for free to retain their flexibility to access other markets; we expect this to change through 2020 as a result of the changes to the STOR market to comply with the Electricity Balancing Guideline (EBGL).

Accepted utilisation prices continue to span a wide range; however, DSF prices decrease on average across 2019. This was due to less utilised volume and therefore ESO instructing lower prices in the merit order. Average DSF prices are lower than traditional providers; this does not appear to be changing over time.

Medium Combustion Plant Directive (MCPD): The directive came into force in January 2019 restricting the use of unabated back-up diesel generation for Balancing/Ancillary Services. However, we have seen only a small decrease in the proportion of diesel generators being tendered in, which indicates that providers had already started to move away from this technology type before the MCPD came into effect.

Service Description

Short Term Operating Reserve (STOR) is a service that provides additional active power from either generation or demand reduction. National Grid ESO has traditionally procured STOR via three competitive rounds per year.

STOR Procurement Process up to and Including December 2019Tenders are assessed and accepted or rejected upon economic merit; technology type is not considered during the assessment process. If accepted, tenders become binding to both parties. Tenders have been for one or more STOR season, up to a total contracted period of two years.

The STOR year runs from April to April with each year divided into six seasons, each of differing length, as driven by operational requirements. Typically, three tender rounds are run each year covering a number of seasons.

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STOR Service RequirementsIn order to participate in STOR, providers must be able to meet the following technical requirements:

Minimum threshold A STOR provider must be able to offer a minimum of 3MW of generation or steady demand reduction. This can be aggregated from more than one site.

Response time Providers should be able to respond to an instruction within a maximum of 20 minutes.

Ability to sustain A STOR provider must be able to sustain the response for a minimum of two hours and have a recovery period of not more than 1200 minutes.

STOR Metrics

How is STOR being provided and utilised?

Chart 1: STOR – Total MWh utilised by month for STOR (traditional and DSF) from January 2017 to December 2019.

Having seen total STOR utilisation (MWh) increase in 2018, total utilisation has significantly decreased in 2019 as a result of National Grid ESO’s August 2018 review to ensure the use of STOR aligns with the Balancing Principles Statement. From September 2018 onwards, STOR usage reduced in line with this guidance. For the 2019 calendar year, the mean STOR usage was 18,086 MWh/month.

Substantially more DSF volume than traditional continues to be utilised, likely to be reflective of the lower utilisation prices award to DSF providers, and therefore instructed in price merit order by National Grid ESO’s control room.

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Chart 2: STOR – Accepted capacity (MW) of STOR by Technology Type – December 2019.

From a snapshot of December 2019 (chart 2), a range of fuel types have been accepted to deliver STOR – including battery, pump storage, gas, diesel, CHP (combined heat & power), hydro, load reduction and OCGT (open-cycle gas turbine).

The majority of accepted capacity is provided by OCGT – 51% (2339 MW). Pump storage (6.5%), gas (15%), and diesel (13%) also contribute significant amounts. However, aggregated portfolios of multiple fuel types (14%) also offer reserve services through

STOR and are made up of CHP, load reduction, hydro and additional diesel.

In our 2018 report, we suggested that 2019 may see greater diversification of technologies in the STOR market due to the MCPD, in particular for diesel generators (616 MW in December 2018). There has been a small reduction in the accepted capacity from diesel generators, indicating that the MCPD has not impacted providers’ ability to provide balancing services as much as anticipated.

Pump Storage, 300 MW

Multiple - Diesel, CHP, Load Reduction, 22 MW

Gas, 710 MW

Battery, 4MWOCGT, 2339 MW

Diesel, 598 MW

Multiple - Diesel, CHP,Load Reduction, Hydro, 326 MW

Multiple - Diesel,Load Reduction, 302 MW

22

Accepted capacity in the STOR market has followed the same trend shown in 2018, with DSF units achieving greater capacity in each of the three 2019 tenders when compared to accepted capacity from traditional providers, and in only one tender round (TR 38) since February 2017 have traditional

units won comparative capacity to DSF providers. Lower availability and utilisation prices submitted by DSF parties (as seen in charts 4 and 6) typically makes them more cost-effective to procure, which translates to more accepted tenders.

Whilst DSF has maintained a greater proportion of accepted capacity compared to traditional providers, across the whole year there has been an overall decrease in both the tendered and accepted DSF capacity from 2018. This reflects a reduced requirement for the service and aligns with the observed reduction

in utilisation of the STOR service throughout 2019 as a result of the review into STOR utilisation in 2018, which was discussed earlier. However, both tendered and accepted figures are still above 2017 levels. This trend is also reflected in the number of unique DSF units tendered and accepted, as shown in Table 2 on the next page.

Chart 3: STOR – Accepted and rejected maximum tendered unique capacity from traditional and DSF providers showing capacity (MW), from October 2016 to December 2019.

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2017 2018 2019

Tendered Capacity (MW) 3163 3038 2726

Traditional Accepted Capacity (MW) 1939 1309 1918

% of Accepted 52.5% 37.2% 48.1%

Tendered Capacity (MW) 2417 3314 2606

DSF Accepted Capacity (MW) 1757 2691 2066

% of Accepted 47.5% 67.3% 51.9%

Table 1: STOR – Sum of maximum accepted capacity by unique units – 2017-2019.

23

Table 3: STOR – Average size (MW) of unique accepted units – 2017-2019.

2017 2018 2019

Traditional – Average Accepted Unit Size (MW)

69.25 93.5 80.9

DSF – Average Accepted Unit Size (MW)

7.91 10.15 9.06

No. Awarded Traditional Contracts

207 75 152

No. Awarded DSF Contracts 1224 1478 1353

Unit Size

Contracts

The average unit size to have been awarded contracts has fluctuated slightly over the three years of focus. For both traditional and DSF providers, average unit size increases into 2018 (by 35% for traditional providers and by a comparative 28% for DSF units). Whilst still remaining higher than in 2017, accepted average unit size reduces across 2019 for both traditional and DSF providers. There

appears to be some natural variation of accepted unit size; however, no clear trends are apparent.

The number of awarded contracts to DSF providers remained relatively consistent across 2018 and into 2019 and are significantly greater in number than those awarded to traditional providers.

2017 2018 2019

Tendered Units 53 41 32

Traditional Accepted Units 28 14 20

% of Accepted 11.2% 5% 8%


DSF Accepted Units 222 265 228

% of Accepted 88.8% 95% 92%

Table 2: STOR – Accepted unique units participating in STOR year – 2017-2019.

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Chart 4: STOR – Accepted availability prices (£/MW/h) from traditional and DSF providers – January 2017 to December 2019. Size of the data point signifies unit volume.

STOR Accepted Prices

This section focuses on the accepted prices that have won STOR contracts between January 2017 and December 2019. Price trends for both availability and utilisation prices over this period are assessed, drawing comparisons between traditional and DSF providers, and tendered unit volumes.

• Availability Fee – STOR providers receive a fee based on their £/MW/h tender submission for making themselves available during agreed time windows to be utilised/called upon when receiving an instruction from National Grid ESO.

• Utilisation Fee – Providers are paid a £/MWh fee for responding to a dispatch notice from National Grid ESO at times of system stress.

Chart 4 shows the trend and direction of travel for STOR availability prices from January 2017 to December 2019. Supported by the average annual prices reported in table 4, availability prices show a decrease over the time period Jan 2017 to September 2018, but since then the prices have remained more stable.

The range of accepted prices has narrowed over the three focus years, but since 2018 it has remained broadly the same, indicating that a natural availability price point has emerged. Through 2017, DSF providers have typically been awarded contracts at significantly lower £/MW/h price points than traditional providers; however, this difference has nearly

disappeared by 2019 (excluding £0/MW/h contracts).

DSF providers remain much more willing to accept a £0/MW/h availability fee and earn their revenue through utilisation payments than traditional providers. The vast majority of these £0/MW/h contracts are from providers tendering into the Flexible STOR service, meaning they have the option in real time to withdraw from STOR and take part in other markets. Offering £0/MW/h makes acceptance highly likely and therefore increases the optionality they have – both in STOR or other markets.

Realigning STOR to the Balancing Principles Statement in 2019 has had a significant effect on the service utilisation, procurement and utilisation pricing.

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Chart 5: STOR – Accepted availability prices (£/MW/h) from Committed and Flexible STOR service providers – January 2017 to December 2019. Size of the data point signifies unit volume.

Chart 6: STOR – Accepted utilisation prices (£/MWh) from traditional and DSF providers – January 2017 to December 2019. Size of the data point signifies unit volume.

As per STOR availability prices (shown in chart 4), there is a trend towards lower utilisation prices being awarded to DSF providers (see table 4). Beyond this, there are no clear trends in utilisation prices over time, with a wide range of accepted prices for both traditional and DSF providers. Utilisation prices achieved by traditional providers have increased into 2019 (by £44.91 MWh on average – table 4); however, this appears to be driven by procurement in a single

tender round (TR38 – June 2019) where there were some higher prices accepted on traditional units. With less thermal generation running due to increased renewables, traditional generators are potentially looking to recover the same amount of revenue over less generation through balancing services.

The lowest accepted tender price per tender round continues to fall. In October 2019 (TR 39), a utilisation price of £4.97 MWh was achieved for

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Chart 7: STOR – Accepted utilisation prices (£/MWh) from Committed and Flexible STOR service providers - January 2017 to December 2019. Size of the data point signifies unit volume.

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STOR Utilisation

Chart 8: STOR – Total MWh utilisation by unit size between January 2017 and December 2019.

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delivery in season 13 – substantially the lowest price achieved in any STOR tender during the reported period.

In a similar way to accepted availability prices, accepted utilisation prices

for Flexible STOR are also low. As discussed, this likely to be due to DSF providers locking in a base level of revenue to remove uncertainty.

Table 4: STOR – Average annual availability (£/MW/h) and utilisation (£/MWh) prices by traditional and DSF providers – 2017-2019.

2017 2018 2019

Traditional 4.20 (2.95) 2.54 (1.25) 1.76 (0.53)

DSF 1.80 (2.75) 0.96 (1.43) 0.35 (0.66)

Traditional 163.25 (2.47) 170.05 (24.58) 214.96 (34.10)

DSF 75.17 (35.68) 71.22 (45.13) 53.12 (55.90)

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Chart 9: STOR – Total MWh utilisation by price range between January 2017 and December 2019.

As previously highlighted in chart 1, DSF volumes were utilised significantly more than traditional. This is supported in chart 8, highlighting that smaller units have typically been called upon, in particular in the 1–20MW unit range. There is noticeably little utilisation of units between 50 and 291MW, due to little (and sometimes no) availability of units of this size.

The majority of instructions in 2019 have been made at the lower £/MWh price, between £10 and 50 MW/h. This is a reflection a) the reduction in utilised volume (chart 1), and b) lower accepted utilisation prices that have been contracted (chart 6). Therefore, the ESO have been able to utilise cheaper volumes in the price stack to meet system needs.

Upcoming changes: • PAS (Platform for Ancillary Services) has now gone live in the

National Grid ESO control room. Providers are being migrated over to the new platform.

• As of 1st January 2020, under the Clean Energy Package, National Grid ESO must procure Reserve services (including STOR) at no more than one day ahead, for a contract length of no more than one day.

• As of 31st January 2020, providers can submit utilisation prices in real time, meaning the price they can be dispatched at can differ from their tendered price.

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4.2 Fast Reserve

Market Summary

Following a consultation on proposed changes to the Standard Contract Terms for Fast Reserve, a decision was made to reduce the entry level from 50MW to 25MW from 25th March 2019. This is a positive step forward in making the service more accessible to smaller-scale providers. To date, only five tenders of less than 50MW have been accepted; however, this is an appreciable share considering that the capacity being procured through Fast Reserve is around 300MW at any one time. DSF and gas capacity has been significantly more successful than hydro in 2019, with diesel capacity disappearing altogether. There has only been one new DSF unit entering the market in 2019; however, the DSF units that have been participating have been more successful in securing capacity in tenders throughout the year.

In general, availability prices have remained broadly stable, whilst utilisation prices for DSF have continued to decrease over 2019. The increase in requirement being sought through the December 2019 tender resulted in a noticeable increase in success for DSF providers, with 75% of tenders being accepted in 2019 compared to just 30% in 2018, for a total capacity of 544MW. The December tender also showed a wider and higher range of accepted availability prices for DSF, combined with lower utilisation prices, indicating that providers are seeking more certainty over Fast Reserve revenues.

Service Description

Fast Reserve provides rapid and reliable delivery of active power through increasing output from generation or reducing consumption from demand sources.

In order to participate in Fast Reserve, providers must be able to meet the following technical requirements:

Fast Reserve Metrics:

How is Fast Reserve being provided and utilised?

Chart 10: Fast Reserve – Utilised volume for both traditional and DSF – January 2017 to December 2019.

Minimum threshold Active power delivery must start within two minutes of the dispatch instruction.

Response time The delivery rate must be in excess of 25MW/minute.

Ability to sustain The reserve energy should be sustainable for a minimum of 15 minutes and must be able to deliver a minimum of 25MW.

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Table 5: Fast Reserve –Cumulative utilisation (MWh) for traditional and DSF providers – 2017-2019.

Fuel Type Provision

Chart 11: Fast Reserve – Capacity of accepted fuel types providing Fast Reserve from January 2017 to December 2019.

Having increased from 2017 to 2018, the total annual Fast Reserve volume used remained comparable across 2018 and 2019.

Typically, a greater number of MWh have been utilised in the winter periods, in particular January 2018 and 2019, and likely to be a reflection of higher demand. However, the rather predictable pattern (high winter and low summer utilisation) in 2017 becomes increasing disrupted in 2018 and 2019, particularly due to June and

July summer peaks of 2019. Again, this could be attributable to shifting summer demands and a greater prevalence of air- conditioning within buildings causing unanticipated demand changes with short lead times.

Due to the small number of providers participating in the Fast Reserve service, we are unable to break down utilisation data further, as this may potentially reveal commercially sensitive provider information.

Across 2017, 2018 and 2019, gas and hydro technologies have provided the backbone of Fast Reserve capacity, at least 80% each year. A more diverse mix is seen from 2017 onwards, reflecting the transition from traditional providers to DSF providers. In 2019, approximately 10% of capacity is provided by demand response, which is provided through Electricity

North West’s (ENW) CLASS project. We also see a large rise in capacity from DSF gas capacity, likely to be due to a combination of the decrease in the minimum accepted service volume from 50MW to 25MW and the increase in capacity sought during the December 2019 tender round of up to 600MW.

2017 2018 2019

Total Utilisation (MWh) 181277.44 234458.01 234367.91

% Change - 29.34 -0.04

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Fast Reserve Tendered Volumes

12: Fast Reserve – Accepted and rejected tendered capacity (MW) from traditional and DSF unique units – January 2017 to December 2019.

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Accepted capacity from DSF providers increased significantly in 2019 (340%) following a dip in 2018. Of particular note is the 494MW of capacity accepted in the December 2019 tender – significantly higher than any

other tender round during the 2017 to 2019 focus period. Compared to 2017 and 2018, DSF tenders were regularly more successful in 2019, with traditional capacity only outperforming DSF in two tenders.

Table 6: Fast Reserve – Summary of Traditional and DSF capacities (tendered and accepted) – 2017-2019.

Table 7: Fast Reserve – Accepted unique units participating in Fast Reserve – 2017-2019.

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Traditional Providers Accepted Units 280 370 180

% of Accepted 61% 70% 25%


DSF Providers Accepted Units 180 160 544


2017 2018 2019


Traditional Providers Accepted Units 3 4 2



DSF Providers Accepted Units 3 3 8


31

Therefore 2019 appears to represent a step change in the transition of the Fast Reserve market from being dominated by traditional flexibility providers. This is evident in the dataset presented in tables 6 and 7 where significantly more capacity was accepted from DSF providers in 2019, despite DSF tendering in roughly the same capacity as in 2018.

Only one additional unit tendered in 2019, compared to 11 additional units in 2018. Whilst the number of tendered DSF units remained relatively constant, the number of accepted DSF units more than doubled from three to eight from 2018 to 2019.

Despite the reduction in the minimumMW threshold from 50MW to 25MW to participate in the Fast Reserve market, the average unit size of DSF providers increased by 27% from 2018 to 2019. This followed a 10% decrease in average unit size from 2017 to 2018. This is due to a large increase in the number of ~60MW units being accepted in the December 2019 tender (see chart 13). There have been

five accepted tenders for contracts below 50MW, all from the same unit, and range from 30 to 45MW in size. The overall number of Fast Reserve contracts awarded grew significantly (almost treble) in 2019 – 88% of which were awarded to DSF providers, which is likely to be a reflection of the lower prices tendered by DSF providers discussed in the next section.

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Traditional – Average Accepted Unit Size (MW)

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Table 8: Fast Reserve – Average size (MW) of accepted Fast Reserve units – 2017-2019.

32

33

Fast Reserve Accepted Prices

Chart 13: Fast Reserve – Accepted availability prices (£/MW/h) from traditional and DSF providers – January 2017 to December 2019. Data point size signifies unit capacity.

Accepted availability fees for DSF providers demonstrate a downward trend across the previous three years, perhaps symptomatic of the increased market liquidity seen particularly in 2019. This is largely as a result of the average DSF availability price decreasing from £5.88 MW/h in 2017 to £2.23 MW/h in 2019.

The exception to this is the wide range of accepted availability prices seen in the December tender round. The increased price spread seen for this month is likely to be a result of the increased requirement (600MW) over EFA blocks 3, 4, 5 and 6 from 1st January 2020 to 31st March 2020,

with the December 2019 month-ahead only tender the first opportunity for providers to bid for this additional capacity.

There are not enough data points in 2019 to draw reliable conclusions for traditional units; however, the three accepted prices are broadly in line with previously accepted tenders.

Of particular note is the lowest accepted £/MW/h prices (£0.87 MW/h) awarded in November and December 2019 – substantially lower than the equivalent prices of £5.55 MW/h in 2017 and £3 MW/h in 2018, all awarded to DSF providers.

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Chart 14: Fast Reserve – Accepted utilisation prices (£/MWh) from traditional and DSF providers – January 2017 to December 2019.Data point size signifies unit volume.

Table 9: Fast Reserve – Average annual availability (£/MW/h) and utilisation (£/MWh) prices by traditional and DSF providers – 2017- 2019.

Accepted utilisation prices from DSF providers are showing a more noticeable downward trend than availability prices and have decreased by approximately 10% year on year. The average 2019 price is £87.00 MWh compared with £95.25 MWh in 2018 for DSF parties. When taken with the higher accepted availability prices in 2019, it appears that DSF providers are seeking revenue through availability rather than utilisation. This

may be due to provider concerns that the reduction in utilisation of STOR because of the August 2018 review will also affect Fast Reserve utilisation.

As per availability, there are not enough data points in 2019 to draw reliable conclusions for traditional units; however, the three accepted prices are broadly in line with previously accepted tenders.

Fast Reserve snapshot

Upcoming changes: As of 1st January 2020, under the Clean Energy Package, National Grid ESO must procure reserve services (including Fast Reserve) at no more than one day ahead, for a contract length of no more than one day.

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35

4.3 Firm Frequency Response (FFR)

Market Summary

The requirement in the FFR market is starting to be moved to the Frequency Response Auction Trial (see next section), so we expect to see a gradual reduction in the volumes being achieved in FFR. However, in 2019 the trend of DSF replacing traditional units in providing Dynamic FFR continues, with double the capacity of DSF being successful in 2019 compared to 2018. This was helped to some extent by the decision to move some response requirement from the mandatory market to the FFR market in the latter half of the year, increasing capacity procured from 1400MW to 1719MW. This came at the expense of the static service, none of which was procured in the last three months of the year, although there had been no requirement for overnight Static FFR since April 2019. Furthermore, the average DSF unit size increased from 11.8MW to 22.16MW in 2019, and availability prices submitted by DSF remained competitive compared to traditional units.

Prices for Dynamic FFR remained similar to the previous year’s average of £4.76/MW/h for the majority of 2019. Towards the end of the year, however, the larger volume being sought meant that units with higher prices were being accepted, which increased the average accepted price through 2019 to £11.50/MW/h. This price increase, combined with the move of some requirement out of the mandatory market, meant that some traditional providers returned to FFR and were consistently successful for the first time since mid-2018. DSF were still more successful, however, achieving three times the capacity of traditional units in the dynamic service.

Service Description

National Grid ESO has a statutory obligation to maintain the frequency of the National Electricity Transmission System within ±1% of 50Hz (49.5 to 50.5Hz). However, the National Grid ESO control room normally controls frequency within tighter operational limits of 49.8 to 50.2Hz.

System frequency is continuously changing: it is determined and controlled by the balance between demand and generation. If demand is greater than generation, frequency falls. If generation is greater than demand, frequency rises. National Grid ESO must therefore ensure that sufficient generation and/or demand is held in readiness to respond to frequency variations.

Response represents the ability to modify generation or demand to compensate for changes in system frequency within 2–30 seconds, depending on service type. The service is split into two physical products which are procured through the FFR market: Static (non-dynamic) and Dynamic Frequency Response.

• Static Frequency Response is triggered at a defined frequency deviation that is specified in the provider’s Framework Agreement, which must be in place before tendering. No response is required within the operating range.

• Dynamic Frequency Response is continuously provided and is used to manage second-by-second frequency variations. The service is automatically delivered for all frequency variations outside of the 50Hz ±0.015Hz range – which is referred to as the ‘dead-band’.

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The service is procured through monthly tenders and, in order to participate, providers must be able to meet the following technical requirements:

Firm Frequency Response Metrics

Firm Frequency Response Tendered Capacities

Chart 15: Static FFR – Accepted and rejected tendered capacity (MW) from traditional and DSF providers by unique units – January 2017 to December 2019.

Minimum size Minimum response is 1MW. This can be from a single unit or aggregated from several smaller units.

Frequency sensitive Providers must have the capability to operate (when mode instructed) in a frequency sensitive mode for Dynamic

Frequency Response, or change their MW level via automatic relay for Static Frequency Response.

FFR Tenders Monthly tender process. Once service providers pass a pre-qualification assessment and sign onto a framework agreement, they can then tender in for one or more months ahead.

Dispatch There must be a single point of dispatch or a method in which the total output of the combined loads can be monitored to demonstrate to National Grid ESO that the service is available.

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In the 2018 Power Responsive Annual Report we highlighted the move towards greater DSF capacity accepted in the FFR market, potentially due to increased participation, market liquidity and evolving business models. Similarly, the decrease in activity from traditional parties in 2018 could be a result of a greater focus on intraday mandatory markets.

This trend continued into 2019 with significantly increased dynamic capacity (double) awarded to non-traditional providers. In comparison, dynamic capacity awarded to traditional providers has decreased by 25% – supporting the notion that short-duration mandatory contracts through the Balancing Mechanism are more attractive to traditional providers at present.

There is a noticeable exiting of the market from traditional sources from May 2018, coinciding with the separating of the FFR market into monthly month-ahead procurement and quarterly long-term tenders.

Significant peaks of rejected capacity can be seen in June, September, and December 2018.. These tender roundswere the first of the quarterly long-term tenders and had the potential for providers to win long-term contracts,potentially an attractive proposition for investors and new build flexibility projects.

Noticeably, no Static FFR contracts were awarded in October, November or December 2019, as a result of an increase in the procurement of Dynamic FFR. This increased dynamic requirement was taken from the mandatory market, where it had been provided by BM parties, to the FFR market in order to increase transparency and allow a broader range of parties to compete. However, as the total requirement being met through the FFR market was unchanged, this resulted in the reduction of required Static FFR. The volume that was secured via long-term tenders was sufficient to satisfy static requirement from October 2019 until February 2020.

Chart 16: Dynamic FFR – Accepted and rejected tendered capacity (MW) from traditional and DSF providers by unique units – January 2017 to December 2019.

Table 10: FFR – Accepted MW capacity awarded – 2017-2019.

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In 2019, DSF providers were awarded double the dynamic capacity they received in 2018.

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Accepted DSF Capacity (MW) 315 475 374

Accepted Traditional Capacity (MW) 759 453 340

Accepted DSF Capacity (MW) 136 472 975

Total 1210 1400 1719

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The average size of DSF units has doubled over the past year. The average unit size of traditional units in the Dynamic FFR market, however, has significantly decreased. The Static FFR service in contrast has remained relatively consistent over the three-year period, in terms of units tendering, accepted and average MW size.

Table 11: FFR – Count of tendered and accepted units – 2017-2019.

Table 12: FFR – Average size of accepted units – 2017-2019.

2017 2018 2019

Traditional - Average Accepted Unit Size (MW)

– – –

DSF – Average Accepted Unit Size (MW)

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39

Only DSF providers have participated in the Static FFR market between 2017 and 2019 as the design of the service is more suited to DSF assets, and higher prices can be achieved through the Dynamic FFR service.

Over the three-year period, the accepted tender prices generally reduce up to March 2019. There is a step change from March 2019 to the year end, with a grouping of increased accepted Static prices for a five-month period from April 2019. Therefore 2019

sees a higher average £/MW/h figure (£2.87 MW/h) than in 2018 (£1.98 MW/h). The reason for this upturn in average price is that from April 2019 to September 2019 there was no requirement for Static overnight response via the monthly tender, only daytime response. The price for overnight response tends to be lower compared to the price for daytime response, and this has therefore impacted the average price for these months.

Firm Frequency Response Prices

Chart 17: FFR – Accepted availability prices (£/MW/h) for Static FFR – January 2017 to December 2019. Data point size signifies unit volume.

Chart 18: FFR – Accepted availability prices (£/MW/h) for Dynamic FFR from traditional and non-traditional providers – January 2017 to December 2019. Data point size signifies unit volume

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Upcoming changes: We anticipate that the Frequency Response Auction Trial (detailed in the next section) will gradually begin to replace volume from the FFR and mandatory markets. In addition, the rollout of the new, fast-acting Dynamic Containment product will also create downward pressure on available volumes in FFR.

Table 13: FFR – Average FFR prices (£/MW/h) for traditional and non-traditional units - 2017 to 2019.

Accepted DSF prices for the Dynanic service looked to be finding a natural price point from mid-2018 to October 2019 with average accepted price of £4.76 MW/h across this time period. October, November and December tenders show a significant movement in the market, with the average price jumping to £11.50 MW/h. Since October 2019 when

total frequency requirement was reviewed, National Grid ESO started procuring more Dynanic response compared to preceding months. This has impacted the average price as bids were accepted based on the benefits they could offer – highest to lowest. The price paid was below the cost of alternative actions that could have been taken in the mandatory market.

4.4 Frequency Response Weekly Auction Trial

Market Summary

The auction trial is in a very early stage, with only five auctions held in 2019. It is therefore unrealistic to expect any trends to appear so far. However, we can say that participation in the Dynamic Low and High (DLH) product is growing week on week, and also that the price being achieved is within the range of the prices achieved in the Dynamic FFR tenders, which is the equivalent service.

For Low Frequency Static (LFS), the accepted capacity is very stable, which is expected as there are only a small number of providers participating and hence the levels of competition are low. This is likely to be a result of the lower accepted prices for LFS compared to DLH, which creates an incentive for assets to participate in DLH if they are technically able to do so.

Service Summary

The auction trial is an innovation project which is procuring LFS and DLH frequency products through the EPEX SPOT Auction Platform on a weekly basis. The DLH product is equivalent to the dynanic product in FFR or the mandatory market, whilst the LFS product is most similar to the now defunct Frequency Control by Demand Management (FCDM) fast static product.

Phase 2 of the Frequency Response Auction Trial launched at the end of November 2019 for procurement of up to 100MW of both Static and Dynamic Frequency Response services. The auction trial is a two-year project to test closer-to-real-time procurement of Ancillary Services in a weekly, pay-as-clear auction. It is expected that the trial will facilitate DSF providers to offer frequency response services and therefore increase the liquidity of the response market. Over the duration of the trial, the volume and number of products procured will be increased.

2017 2018 2019

Static DSF 3.22 1.98 2.87

£/MW/h Traditional 12.42 6.66 10.57

DSF 13.57 6.04 6.39Dynamic

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Whilst the duration of the weekly FFR auction trial is a two-year project, for the purposes of this report, we only focus on the first five weeks of phase 2, 28th November to 31st December 2019, to align with the reporting period throughout the rest of this report.

Product Description

LFS This is a static service that is triggered at 49.6Hz. (Low Frequency Static) Minimum requirement is 1MW and must be

able to deliver full output in one second. For full requirements please refer to the testing guidance specifications listed on the ESO website.

DLH This is a dynanic service that delivers equal (Dynamic Low and High) volumes of Primary, Secondary and High

frequency response. For full requirements please refer to the testing guidance specifications listed on the ESO website.

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Frequency Response Auction Trial Metrics

Frequency Response Tendered Capacities

Chart 19: Frequency Response Auction Trial – Average weekly accepted unit capacities for DLH and LFS services by EFA blocks.

Table 14: Frequency Response Auction Trial – Daily EFA blocks and their corresponding time of day.

Table 15: Frequency Response Auction Trial – Maximum tendered and accepted MW capacity across 2019.

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1 23:00 – 03:00

2 03:00 – 07:00

3 07:00 – 11:00

4 11:00 – 15:00

5 15:00 – 19:00

6 19:00 – 23:00

Chart 19 shows that larger units are more successful over EFA blocks 1 to 4 (23:00 to 15:00), indicating that there is a larger requirement during periods of lower system demand. A lower requirement in EFA blocks 5 and 6 means it is more difficult for larger

units to fit within the buy order.

The capacity of assets providing LFS remains relatively consistent across the week and EFA blocks, indicating a more stable requirement.

Wk1 Wk2 Wk3 Wk4 Wk5

Tendered Capacity (MW)

187 137 140 232 287


187 137 140 227 267


42 48 43 34 49

Accepted Capacity (MW)

42 48 43 34 48

DLH

LFS

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Whilst the trial has only been operating for five weeks, table 15 shows that tendered and accepted capacity in the DLH service has been increasing week on week since week 2. For LFS the accepted capacity is very stable, which is expected as there are only a small number of providers participating and hence the levels of competition are low. This is likely as a

result of the lower accepted prices for LFS compared to DLH. This is also not just a reflection of the greater number of units tendering into the DLH service (see table 16), but also of larger units tendering in through the DLH service compared to the LFS service – 9.5MW per unit on average for DLH, compared to 7.5MW on average for LFS (see table 17).

The auction trial is at a very early stage, with only five events held in 2019, and therefore it is difficult to make any firm statements. However, we can see that average DLH prices per EFA block fluctuated between £4.98 and £9.83 MW/h in the first five weeks of the auction trial. This

appears to reflect different values per EFA blocks and therefore the ability of providers to offer the service at different times of the day. Prices across the five weeks for each EFA block appear consistent, which should help signal the value of each EFA block.

Table 16: Frequency Response Auction Trial – Count of tendered and accepted units across 2019

Table 17: Frequency Response Auction Trial – Average size of accepted units in 2019.

Auction Prices

Chart 20: Frequency Response Auction Trial – Average accepted availability prices for the DLH service (£/MW/h) – November to December 2019.

DLH Average Accepted Unit Size (MW) 9.5

LFS BM - Average Accepted Unit Size (MW) 7.5

4

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Ava

ilab

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/MW

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Week 1 Week 2 Week 3 Week 4 Week 5

EFA Block 1 EFA Block 2 EFA Block 3 EFA Block 4 EFA Block 5 EFA Block 6

Wk1 Wk2 Wk3 Wk4 Wk5


187 137 140 232 287

No of Units Tendered

23 12 13 27 31

No of Units Accepted

22 12 13 25 30

Accepted Capacity (MW)

42 48 43 34 48

DLH

LFS

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Table 18: Frequency Response Auction Trial – Price ranges per EFA block – November to December 2019.

Lowest Cleared£/MW/h

Highest Cleared£/MW/h

Lowest Cleared£/MW/h

Highest Cleared£/MW/h

EFA Block 1 4.98 7.73 5.04 5.20

EFA Block 2 4.98 7.47 5.04 5.20

EFA Block 3 5.41 12.72 3.29 3.37

EFA Block 4 5.41 11.70 3.29 3.37

EFA Block 5 0.00 9.50 3.29 3.37

EFA Block 6 5.56 11.22 3.29 3.37

DHL LFS

Prices in the LFS market show significantly greater stability across all EFA blocks than seen in the DLH service, and should therefore, in time, provide greater investor confidence.

Cleared prices in the LFS service also show a narrower range per EFA block (between £0.08 and £0.16 MW/h) compared to DLH (between £2.49 and £9.50 MW/h).

The £0.00 MW/h cleared price in EFA Block 5 of the DLH service was caused as a result of an unusual set of circumstances, and we do not anticipate that it will be repeated as more providers enter the market. The particular bid that cleared at £0.00

MW/h formed part of a linked set of bids, where all tendered volume must be accepted or rejected together. The combination of prices which cleared across all EFA blocks, along with the algorithm’s assessment of surplus value, meant that the cleared price in that block was zero. More information on this can be found on the Frequency Response website².

EFA blocks 1 and 2 see typically lower prices in DLH compared to EFA blocks 3, 4, 5 and 6, which is the reverse of the prices for LFS. This may indicate a difficulty for providers to offer the LFS service overnight between 23:00 and 07:00.

Future developmentsThe stated ambition is to move to day-ahead auctions; however there is no firm timetable for this at present. It is hoped that moving towards closer to real-time auctions will provide investors with clearer pricing singles than the current pay-as-bid FFR tendering process. In the next Power Responsive Annual Report we will anticipate finding consistent weekly auction trial pricing week on week, with appropriate market movement dependent on liquidity.

². shttps://www.nationalgrideso.com/industry-information/balancing-services/

frequency-response-services

LFS prices are significantly lower and more stable across all EFA blocks than DHL prices.

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0

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2016Transitional Arrangements &

Early Auction

Awarded Exited

2017T-1 Auction

Awarded Exited

2018T-1 Auction

Awarded Exited

2019T-1 Auction

Unproven DSR (MW) Proven DSR (MW) Early auction Clearing Price £/kW/year T-1 Clearing Price £/kW/year

4.5 Capacity Market

Market Summary

DSF continues to be successful in the T-4 auctions, with the overwhelming majority of contracts awarded to unproven tenders. Prices in the T-4 auction show no clear trend. By contrast, DSF capacity secured in the T-1 auction continues to drop, with 2019 tenders awarding less than 100MW to DSF despite over 500MW tendering. Prices in this market have collapsed to less than £1/kW/year.

Service Description

As the Delivery Body for Electricity Market Reform, National Grid ESO runs the main T-4 annual auction, buying capacity for four years ahead of delivery. The annual T-1 auction

runs one year ahead of delivery as a top-up to secure volume. The first auction, described as the ‘Early Auction’ (EA), was held on 31st January 2017, for delivery in winter 2017/18. The DSR Transitional Arrangements (TA) auction offered targeted support to DSR to encourage enterprise and increase levels of participation in the intervening years 2016 to 2018.

The market was suspended in 2018 by the European Court of Justice whilst the Commission conducted their formal investigation into aspects of compliance with State Aid rules. The European Commission advised on 24th October 2019 that, following its formal investigation, the GB Capacity Market scheme is compatible with EU State Aid rules and was subsequently reinstated.

Service Metrics

Chart 21: Capacity Market – T-4 accepted and exited provenand non-proven DSR capacity by tender year.

Chart 22: Capacity Market – T-1 accepted and exited provenand non-proven DSR capacity by tender year.

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Awarded Exited

2016T-4 Auction

Awarded Exited

2017T-4 Auction

Awarded Exited

2018T-4 Auction

Awarded Exited

2019T-3 and T-4 Auction

Unproven DSR (MW) Proven DSR (MW) T-4 Clearing Price (£/kW/year) T-3 Clearing Price (£/kW/year)

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Future developmentsThe UK government has committed to implementing a number of improvements to the design of the Capacity Market to reflect recent market and regulatory developments. This includes proposals to allow all types of capacities above a defined capital expenditure threshold, including DSR, to access multi-year agreements.

4.6 Triad Avoidance

Triad events are the three half hours of highest demand on the GB electricity transmission system between November and February each year, separated by at least ten days. Triads are a mechanism to help manage peak demand on the network and to determine Transmission Network Use of System (TNUoS) charges for end customers with half-hour (HH) metering. This tends to be for industrial and commercial customers. If they don’t consume electricity in the three Triad periods, they don’t pay HH TNUoS charges for the entire financial year, so there is a significant incentive on HH metered customers to avoid these periods and the subsequent costs.

The Triad avoidance (TA) season runs from 1st November to the end of February, and historically, it helps avoid the need for expensive infrastructure investment that all customers would otherwise need to pay for.

There is little data held on self-dispatch activity, as no formal instructions are sent to dispatch providers to initiate a change in energy usage or production. Triad avoidance has become a well-understood signal to end-customers, with many energy users choosing to participate in DSF activities initially with this opportunity, before venturing into contracted services with more complex requirements and explicit instructions.

A significantly greater proportion of unproven DSR capacity than proven continues to be accepted in each year across both the T-4 and T-1 auctions. Unproven DSR represents capacity that has not yet been built yet offers investors the opportunity to win Capacity Market contracts and therefore provides greater investment certainty.

The T-1 auctions see lower capacity awarded to DSR year on year despite large amounts participating, and a significantly higher capacity exiting the auctions without a contract. This could be a reflection of increased price competition; the last two T-1 auctions have cleared as low

as £0.77 kW/year and £1.00 kW/year respectively, and a reduction in capacity sought year on year as the T-1 auction seeks to top up on previously run T-4 awarded contracts.

By contrast, the T-4 auction continues to see high levels of capacity being accepted from DSF compared to tendered capacity. The T-4 auction is likely to be more attractive to new build DSR as this provides them with a longer lead time in which to implement their developments. There is also a larger capacity to tender for in the T-4 auction; therefore greater amounts of DSR should be expected to win contracts compared to the T-1 auction.

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Future developmentsIn November 2019, Ofgem published their decision on the Targeted Charging Review (TCR). Through the TCR, the residual element of Transmission Network Use of System (TNUoS) will only be paid by demand, and will be on a banded basis, where everyone in the same band will receive the same charge, rather than on a Triad basis. This is due to come into effect in April 2021.

Triads will remain in the locational element of the TNUoS charge for demand; however, this is a very small proportion of the charge.

The maximum Triad avoidance is seen to be increasing in recent years (as seen in table 19). This is believed to be linked to the growing capacity of battery-distributed generation. Last winter, for the first time, we saw frequency deviations in the settlement period before expected Triad avoidance activity. National Grid ESO believe this is as a result of batteries switching from charging to discharging.

Some suppliers and consultancies provide a Triad forecasting service to notify their customers when they believe a Triad is likely to occur.

Table 19 shows how many instances of Triad avoidance activity that exceeded 500MW were observed during the Triad avoidance season, alongside the maximum Triad avoidance for that same time period.

Service Metrics

Table 19: Triad Avoidance - activity across 2009/10 to 2018/19. Number of occurrences, i.e. the days on which Triad warnings were issued, and the maximum observed Triad avoidance for the winter, i.e. observed demand reduction (GW).

TA season No of occurrences Max TA (GW)

2009/10 15 1

2010/11 14 1.2

2011/12 17 1

2012/13 14 1.2

2013/14 22 1.8

2014/15 24 1.2

2015/16 36 2

2016/17 48 2

2017/18 33 2

2018/19 30 2.4

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Future Developments for Demand Side Flexibility Opportunities 5.0Demand side flexibility is continuing to evolve at pace, helping the ESO to maximise the use of renewable sources of electricity generation, and reducing and removing constraint payments from network management tools. In the following section, we have set out some of the significant developments taking place across flexibility markets and where there are potential future opportunities.

Ancillary Services

One of National Grid ESO’s ambitions is to create markets where balancing service providers can compete on a level playing field to provide flexibility that meets the changing needs of the electricity system.

Response and Reserve In December 2019, National Grid ESO published its Response and Reserve Roadmap. The purpose of this document is to inform demand side stakeholders of our plans to reform the Frequency Response and Reserve services, set out a clear view of the future, and make sure that market providers are supported and able to adapt and respond to market changes.

• Frequency Response Weekly Auction Trial – In spring 2019, phase 1 of the auction trial was launched to procure Low Frequency Static response. Following on from this, on 29th November 2019, phase 2 of the auction trial was launched to procure dynanic frequency response products. These different types of frequency products are key to helping National Grid ESO manage the electricity system in a world where the energy mix is becoming more diverse and the way consumers use electricity is evolving. The auction trial is a two-year project to test closer-to-real-time procurement of Ancillary Services in a weekly, pay-as-clear auction. It is expected that the trial will facilitate intermittent generation to offer frequency response services, increasing the number of participants able to compete in the market. Over the duration of the trial, the available volumes and number of products procured will be increased.

• New Suite of Frequency Response Services – As we move to a world where the energy mix is evolving

and we are seeing more renewable generation on the system, the ESO require products that are quicker at responding to frequency changes. Therefore, a new suite of three dynamic frequency response services, which will eventually replace existing response services is under development:

– Dynamic Containment will be designed to operate when the frequency moves outside the operational limits. The product will have a very fast response time and will help to secure both generation and demand losses. Procurement of this product will start before summer 2020.

– Dynamic Moderation will be designed to operate within operational limits to manage sudden imbalances in supply and demand. Providers will need to occasionally deliver rapid proportional response.

– Dynamic Regulation will be designed to correct continuous but small deviations in frequency. Providers will not need to respond as rapidly as for the other services (containment and moderation), but they must have a duration of service that supports continuous operation.

• Reserve Reforms – Reserve is an important service as it helps to correct imbalances between generation and demand, that can be caused by forecasting errors, or by an unexpected loss of generation or demand. This service is procured from market participants ahead of real time through tenders. The ESO are focusing on the standardisation of the existing reserve services to improve competition and transparency in the markets. It is expected for the Wider Access to the Balancing Mechanism project and European-wide Project TERRE to significantly change requirements for reserve services,

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and the ESO are therefore waiting to understand the impact of these projects before consulting with stakeholders on further changes to the reserve products.

• Clean Energy Package – National Grid ESO have taken the decision to suspend the next procurement of reserve service (STOR and Fast Reserve) there is have a clear legal framework agreed with Ofgem. Historically, the ESO have procured reserve services through tender rounds contracting for up to two years ahead. Within the Clean Energy Package, Article 6(9) National Grid ESO are to procure balancing capacity (reserve) at no more than one day ahead, for a contract length of no more than one day. The initial legal view was that these changes would not occur until June 2020; however, there has been discussion with Ofgem over whether the changes were required from 1st January 2020. Until this situation is resolved, the ESO has decided to suspend STOR and Fast Reserve tenders. The decision has not been taken lightly, but after consideration of the potential risks or consequences of non-compliance, National Grid ESO believe the suspension will allow time to review the current arrangements.

Pathfinder ProjectsTo achieve its zero carbon by 2025 ambition, the ESO need to be able to safely operate and manage the transmission network, with increasing amounts of renewables such as wind and solar. The ESO recently launched

a series of different pathfinders to help find the most cost-effective solutions to meet the challenges faced in operating the electricity system. It is believed that greater consumer benefit can be achieved by looking towards DSF assets and markets for solutions. There will be a number of tender opportunities throughout 2020.

• Stability Pathfinder – looking for new stability products that can be offered from both existing and new assets. This is looking to replace the technical characteristics received from synchronous generation, and it is one of the first steps towards meeting ESO 2025 Zero Carbon ambitions.

• Voltage Pathfinder – more services are required to manage reactive power due to less synchronous generation on the system. Existing mandatory reactive power markets and services are large generation and not accessible to Distributed Energy Resources (DERs). Work is being carried out to expand reactive power services and markets to embedded assets in the distribution network.

• Constraint Pathfinder – the learnings from the Voltage and Stability Pathfinders will feed into the Constraint Management Pathfinder looking at creating markets for constraint management.

Project TERREProject TERRE will provide a new opportunity for flexibility providers to participate and trade reserve services

Developing existing markets and creating new opportunities that meet changing system needs will help to facilitate a low carbon energy future.

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with European markets. The go-live date was proposed as December 2019; however, the project has been delayed due to challenges on RTE’s network. As a result, National Grid ESO have been granted a derogation until June 2020.

Distributed RestartDistributed ReStart is a three-year project that is testing how distributed generation can be used in the event of a Black Start scenario. National Grid ESO is investigating alternative routes to system restoration and how different assets can be brought together to form a controllable, stable and scalable platform for recovery. This work will drive more consumer benefit as we develop competitive markets where previously none existed. It is also likely to enable low-carbon generation sources and DER to compete.

Targeted Charging Review

Ofgem published its decision on the Targeted Charging Review on 19th November 2019, having looked at how electricity network residual charges should be set in the future, for both transmission and distribution. In the review, Ofgem concluded that:

• Demand residual charges – despite significant industry feedback, Ofgem has elected to charge demand sites in a ‘banded’ approach, where consumers are categorised based on their consumption/capacity and all consumers in that category pay the same charge. Once assigned to a category, a site cannot move from it for the duration of the TO’s price control. National Grid ESO are also required to create a new non-half hourly (NHH) methodology to introduce NHH residual charges. The transmission element of the residual charge is due to be introduced from 21st April 2021.

• Removal of Transmission Generation Residual (TGR) – the generation residual charge currently used to ensure compliance with the €0-2.50/MWh regulatory range is being removed. The TGR residual is due to be implanted from 21st April 2021.

• Balancing Service Use of System (BSUoS) taskforce – Ofgem has requested that the ESO leads a second BSUoS taskforce to identify how demand should pay BSUoS in the future. As expected, the decision means that generators will not pay BSUoS charges. The taskforce is due to conclude in June 2020.

• Embedded benefits – As it is only demand that will pay BSUoS in future, and Ofgem’s position is that all cost-recovery charges should be unavoidable, the current BSUoS embedded benefit will be removed. The potential for this has been signalled to the industry for over 12 months; however, it will still be of concern to embedded generators as it is currently a sizable revenue stream. The current embedded benefit is due to be removed from 21st April 2021.

Distribution Network Operator (DNO) procurement

Through coordination of the ENA Open Networks Project, DNOs have now gone to market for flexibility services. The Open Networks Project has defined a set of four active power DSO services that are being used in DNO procurements and should assist with a level of coordination and market transparency. For 2020, the Open Networks Project is planning to further develop standardisation for the next level of detail for these services, as well as delivering standard contracts to ensure the proposition remains simple and accessible to customers. DNOs are continuing to trial new services and approaches to procurement in coordination with the ESO, including trials such as Power Potential, Cornwall LEM and the BEIS Flexibility Exchange Demonstration Competition.

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Technological innovations and trials

National Grid ESO are leading or collaborating with other industry parties on a series of projects:

• Cornwall Local Energy Market (with Centrica and WPD) – to demonstrate a local market for coordinated procurement of flexibility between multiple flexibility markets. The trial concludes in March 2020, from which point learnings will be shared regarding whole system benefits and conflict management.

• Power Potential (with UK Power Networks) – to demonstrate whether distributed energy resources can provide key services to the transmission network, such as dynanic voltage control.

• RecorDER – A Network Innovation Allowance (NIA) funded project (with Electron, UK Power Networks, and ScottishPower Energy Networks) that seeks to provide a proof of concept blockchain flexibility asset register. The ambition is to provide a single view of network connected assets of 1MW and above. We hope that by providing networks and the wider

industry with greater visibility of network connected assets, that efficiencies, cost-savings and better network management can be achieved.

• Enhancing Energy Flexibility from Wastewater Catchments through a Whole System Approach – We have been working with United Utilities through this NIA project. The project has been exploring how coordination of a single wastewater catchment area could unlock more flexibility than considering these assets on their own. The project is at an advanced modelling stage and is due to publish results in Q1 2020/21.

• Residential Response – We have been working with a number of companies through the Residential Response NIA Project. This project is looking at the various barriers to providing frequency response from domestic assets, such as metering, prequalification and portfolio management. The project team recently presented the work and initial findings at the ENA Innovation Forum in February 2020; the project is due to conclude in Q1 2020/21.

Thank youWith thanks to Sustainability First for their continued contribution to the publication of this report, and to the Power Responsive programme.

Disclaimer: This report should not be taken as investment advice in demand side markets on the part of National Grid Electricity System Operator or Sustainability First.

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Annex A – Power Responsive Steering Group members 2019

Sector Representative

PolicyDepartment for Business, Energy & Industrial Strategy

Regulation Ofgem

System Operator National Grid ESO

Distribution Network Operator

Northern Powergrid

Western Power Distribution

Suppliers Centrica

Renewables Renewable Energy Systems

AggregatorsKiWi Power

Flexitricity

Market Consultant EnergyBridge

Market Commentator Cornwall

Market Trading ELEXON

Technology Provider BEAMA

End Users

United Utilities

Crown Commercial Service

MEUC

StorageDNV GL

Fluence

SecretariatSustainability First

National Grid ESO

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Annex B – Glossary

Aggregator Aggregates loads and participates in contracted markets or responds to price signals on behalf of customers.

Capacity Market (CM) Designed to provide incentives for investment in the overall level of reliable capacity (supply and demand side) and secure supply of electricity.

Charging Futures Forum (CFF)

A stakeholder forum to consider electricity network charging reviews led by Ofgem and industry.

Demand Side Flexibility (DSF)

Electricity demand is changed (increased, reduced or shifted) at a particular moment in time in response to an external signal (such as a change in price, or a message). DSF providers include industrial and commercial energy users and owners of small-scale generation and electricity storage, such as batteries.

Demand Side Providers

Demand side providers offer demand side flexibility services to markets and market actors, including aggregators, suppliers, customers and third-party intermediaries.

Demand Turn Up (DTU)

Increasing demand at times of high generation (e.g. from wind and solar) in response to a signal from the electricity system operator. Demand increase should be achieved through shifting demand, not the wasting of energy.

Distribution Network Operator (DNO)

Companies that build, maintain and operate distribution networks that transport electricity from high-voltage transmission networks to customers.

Distribution System Operator (DSO)

An emerging role for DNOs which involves more active management of supply, demand and constraints at a local level.

Electricity System Operator (ESO)

ESO balances electricity supply and demand in real time, acting as a legally separate company within the National Grid Group from April 2019.

Embedded Benefits Benefits available to small-scale ‘embedded’ generation under industry arrangements.

Embedded Generation

Embedded generation is the production of electricity from generators that are directly connected to a distribution network.

Fast Reserve A monthly tendered service designed to procure large blocks of reserve energy of 50 MW to respond within 2 minutes.

Firm Frequency Response

Procured via a monthly tender round. Participants can tender for contracts beginning the month ahead up to 2 years ahead. Dynamic FFR is a continuously provided service used to manage the normal second-by-second changes on the system. Static FFR is a discrete service triggered at a defined frequency deviation.

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Frequency Response System frequency is a continuously changing variable that is determined and controlled by the second-by-second balance between system demand and total generation. The ESO must maintain a frequency of +/-1% of 50Hz at all times, so procures frequency services in readiness to manage fluctuations in electricity demand or generation from forecast volumes or to withstand faults to the network or connected generation.

Half-Hourly Settlement

The electricity settlement process places incentives on suppliers to buy energy to meet their customers’ demand in each half hour of the day. With advanced meters, customers are increasingly able to have their electricity consumption settled on a half-hourly basis.

Industrial and Commercial (I&C) Customers

This refers to large business customers of electricity, including those manufacturing goods, those serving customers and public sector organisations.

Medium Combustion Plant Directive (MCPD)

EU legislation restricting emissions of certain pollutants from combustion plants with a rated thermal input equal to or greater than 1 megawatt and less than 50 megawatts. This impacts diesel plant – resulting in limited running hours for commercial gain.

Reserve Services In order to deal with unforeseen changes in demand or lack of generation, the ESO requires access to additional sources of power in the form of generation or demand reduction. The response time and duration are typically longer for reserve services than frequency.

Short Term Operating Reserve (STOR)

An important source of reserve energy for the ESO, which is procured via three tenders throughout each year and requires a response time of less than 20 minutes.

Significant Code Review (SCR)

A process which enables Ofgem, as energy regulator, to initiate wide-ranging and holistic changes and to implement reform to a code-based issue.

Targeted Charging Review (TCR)

An Ofgem review to consider reform of residual charging for transmission and distribution, for both generation and demand, to ensure that it meets the interests of consumers, both now and in the future.

Third Party Intermediaries (TPI)

Organisations or individuals that give energy-related advice aimed at helping customers to buy energy and/or manage their energy needs.

Transmission Network Owner (TNO)

Companies that build, maintain and operate transmission networks, transporting electricity at a high voltage across the country.

Triad Avoidance Reducing consumption at periods where peak winter national demand is forecast, in order to proportionally reduce TNUoS (Transmission Network Use of System) changes.

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