Scottish and Southern Energy Power Distribution RIIO-ED1 Smart

Scottish and Southern Energy Power Distribution

RIIO-ED1 Smart Metering

Business Plan

Scottish and Southern Electric Power Distribution RIIO-ED1 Smart Metering Business Plan

Issue 1 of 35

References Paper Reference Code RIIO-ED1_SSEPD_BP_July13_smart_meter_strategy File Reference: \\RIIO-ED1 3.Business Plan\Final Documents\Finalised

Documents\Summary Papers Output Paper Reference: Smart Metering Business Plan Issue Number Issue 1 Issue Date 01/07/2013 Copy No Issue Status Date Approval Signature Proposed 10/06/2013 Dave Brogden Approved 17/06/2013 Beverly Grubb


Issue 1 of 35

Abbreviation List

Abbreviation Definition BMPN Business Process Modelling Notation DCC Data Communication Company DCUSA DECC

Distribution Connection and Use of System Agreement Department of Environment and Climate Change

DNO Distribution Network Operator DPCR5 Distribution Price Control Review 5 ENA Energy Networks Association EV Electric Vehicle FBPQ Forecast Business Plan Questionnaire GB Great Britain GIS Graphical Information System HR Human Resources HV High Voltage IT Information Technology LCT Low Carbon Technology LV Low Voltage OFGEM Office for Gas and Electricity Markets RIIO-ED1 Revenue = Incentives + Innovation + Outputs, Electricity Distribution 1 SCADA Supervisory Control and Data Acquisition SEPD Southern Electric Power Distribution SHEPD Scottish Hydro Electric Power Distribution SLA Service Level Agreement SMIP Smart Metering Implementation Program UML Unified Modelling Language


Issue 1 of 35

Table of Contents 1 Overview ............................................................................................................................ 62 Fundamental Drivers for Expenditure ............................................................................ 8

2.1 Current rules applied for DPCR5 ............................................................................... 82.2 Proposed changes for RIIO-ED1 ............................................................................... 9

3 SSEPD Strategy for RIIO-ED1 ....................................................................................... 183.1 Innovation ................................................................................................................ 183.2 Cost Efficiency ......................................................................................................... 193.3 Stakeholder Feedback ............................................................................................. 19

4 Forecast Expenditure in RIIO-ED1 ................................................................................ 214.1 Volumes ................................................................................................................... 214.2 Unit Rates ................................................................................................................ 23

Unit Costs Relating to Smart Roll-Out ................................................................................. 234.3 Total Direct Costs .................................................................................................... 244.4 Cost Recovery ......................................................................................................... 26

Incentive Mechanism for Smart Roll-Out ............................................................................ 264.5 Information Sources ................................................................................................. 274.6 RIIO-ED1 Performance ............................................................................................ 27

Appendix A. Smart Metering Outputs Paper ................................................................. 28


Issue 1 of 35

PAGE INTENTIONALLY LEFT BLANK


Issue 1 of 35

1 Overview

1.1.1 This section of our business plan provides an overview of the Government’s smart metering programme, its vision and the impact on SSEPD. We also set out details of the main areas of activity for SSEPD over the next price control period, our strategy, objectives and commitments, along with associated costs, cost recovery mechanisms and benefits in order to meet wider expectations.

1.1.2 Over the next 7 years we plan to work with the industry and suppliers to support them in the roll-out of smart meters to every domestic and small business customer in GB. This will involve responding to suppliers’ requests to carry out work at some of our supply points to allow a smart meter to be installed and to ensure our network remains safe and reliable. We will also be implementing significant system development to allow us to access customer data that will be available to us from the smart metering system. This data will allow us to better understand how customers use electricity so we can be more efficient and improve our services.

1.1.3 The changes brought about by the smart metering programme and wider policy objectives will require significant changes to be made to our business processes and practices. We will also need additional staff to meet our obligations and to implement changes.

1.1.4 The overall cost to our business is forecast to be £203.5m; £6.9m will be incurred in this price control period and £196.6m will be incurred in RIIO-ED1. High level information is provided in Table 1. The corresponding benefits are believed to be wide ranging, including wider policy objectives e.g. related to delivering smarter grids and the Government’s Low Carbon Plan as well as direct network benefits. Work is still ongoing with other DNOs and the ENA to identify and quantify all network benefits. This work also looks at the phasing of benefits between the current price control period, RIIO-ED1 and future price control periods. Our initial view is that benefits to SSEPD over RIIO-ED1 are low and in the order of £5m. More information can be found in our Smart Metering Benefit paper in Appendix A. Once benefits have been confirmed we will share this information with Ofgem and our stakeholders. This work will also identify where benefit accrues directly to DNO and the instances where a benefit is provided to the general mass of customers e.g. more informed reinforcement decisions leading to lower levels of capital expenditure. At present we believe most of the benefits will not start to materialise until RIIO-ED2 when a significant proportion of smart meters will have been installed and the penetration levels of new low carbon technologies has started to increase. They are also likely to accrue over a number of years and future price control periods


Issue 1 of 35

Table 1 – Smart Metering Costs

Item Description SHEPD (£m) SEPD (£m)

DPCR5 RIIO-ED1 DPCR5 RIIO-ED1

On site physical - direct costs £0.7 £15.6 £4.1 £66.3 Indirect costs, IT and data services - volume driver £0.1 £2.4 £0.5 £9.4

Indirect costs, IT and data services - pass through £0.3 £16.3 £1.2 £65.4

Indirect costs, IT & data services - not subject to pass through £0 0.4 0 1.5

Recruitment, training and HR costs £0 £3.9 £0 £15.4

Total £1.1 £38.6 £5.8 158.0


Issue 1 of 35

2 Fundamental Drivers for Expenditure

2.1 Current rules applied for DPCR5

2.1.1 Smart meters are intelligent meters that tell customers how much energy they are using at any point in time and the cost of the energy they are using. Information is displayed on a device in the home or customer’s property so it is easy to access and read. The meters can also communicate with energy suppliers and other parties who are authorised to access it, including Distribution Network Operators like SEPD and SHEPD. We can then use this information to help us manage the energy supply and the networks.

2.1.2 The Government’s vision is for every home and small business in Great Britain to have a smart metering system installed by the end of December 2020. This means the industry will need to replace around 54million meters and visit over 29 million properties. We have 3.7 million meters in our network areas in the north of Scotland and south of England that will need to be replaced (SEPD - 2,940,000, SHEPD - 743,000).

2.1.3 The potential benefits associated with smart metering systems are wide ranging. They are expected to:

• Help customers understand and control their energy use to save energy and

reduce bills; • Remove the need for estimated bills so customers’ bills will be more accurate

and reflect actual energy used; • Reduce the need for meter reading and the cost associated with this; • Help ensure information needed to allow customers to switch supplier is

available to make the process quicker and smoother; • Provide network operators with information about how customers use energy

so we can improve our services and improve efficiency.

2.1.4 All these benefits should help with the transition to a low carbon economy and help GB meet the future challenges of ensuring an affordable, secure and sustainable energy supply. The total cost of the national programme is forecast to be £12.1bn (January 2013) but net benefits across GB are expected to be in the order of £6.7bn.

2.1.5 We are still at an early stage in the programme, known as the “Foundation Stage” where a lot of the detailed design work and development of technical, commercial and regulatory frameworks are still taking place. However suppliers have kicked off trials or early roll-out so they can learn lessons before the next phase, “Mass Rollout”, starts in 2015. The programme is expected to be complete by December 2020.


Issue 1 of 35

2.1.6 The Government established a Smart Metering Implementation Programme (SMIP) to help deliver its vision. It produced a prospectus in March 2011 setting out policy decisions to help it deliver the programme. The Government is also responsible for overseeing the development of the commercial and regulatory framework. Its obligations are underpinned by powers established under the Energy Act 2008.

2.1.7 A policy decision was taken by the Government early in the programme, making suppliers responsible for delivering smart metering systems to consumers. This is enforced through an obligation in their supply licence. While we are not responsible for installing the systems, our help will be needed to support the development of the programme and the supplier led rollout programme. We also have a duty to use data provided by smart metering system to improve our activities and ensure full benefits are realised and passed on to customers. Our responsibilities are also enforced through obligations set out in our licence.

2.2 Proposed changes for RIIO-ED1

Information about our specific role and obligations and the expected impact on our business is set out in the sections below under:

• Developing and Managing the Network; • Facilitating Roll-out; and • Business Processes, Information Systems and Interfaces.

Developing and Managing the Network Challenges

2.2.1 Electricity Distribution Network Operators (DNOs) like SEPD and SHEPD face a number of challenges over the next decade and beyond:

• We are seeing significant change in the way customers use electricity as

energy efficiency awareness increases and in response to rising energy costs;

• We are seeing changes in the way customers use electricity in response to changing weather patterns and are having to develop plans to adapt to cope with more frequent and extreme weather conditions;

• We are experiencing increased demand to connect renewable generation, usually in areas where capacity is constrained. Connection can also result in changes in energy flows and the way we operate the network;

• We are experiencing increased demand to connect low carbon technologies such as heat pumps and electric vehicles which increase demand on our network and other technologies such as solar panels which can increase supply. Although micro generation such as solar panels can offset the total electricity used by a household a new connection is needed to export electricity onto the network. The electricity generated is quite often at different times to when the electricity is needed, changing the demand profile of the customer.


Issue 1 of 35

2.2.2 This means we need to find new, more innovative and smarter ways of planning, developing and managing our network, particularly at low voltage, where most of the smart metering benefits are likely to be achieved. More information on our approach to innovation and the role of smart metering can be found in our innovation strategy and section 3.2 below.

Our objectives

2.2.3 The framework established by the Government allows us to access data from smart meters. We plan to develop our own processes, systems and tools to use smart metering data. This will help us to develop Smart Grids which will ensure we plan, develop and operate our network in the most economic and efficient way possible. This will ensure that we provide a safe and reliable supply of electricity for current and future customers and meet the challenges of the future while minimising cost. We also plan to use smart metering data to help deliver outstanding customers service.

Our commitment

2.2.4 We will:

• Work with DECC and other industry participants to develop systems, process and interfaces that will allow us to access the data we need in a timely and efficient way to minimise costs associated with network investment, improve network reliability and improve customer service;.

• Develop processes and procedures to protect the privacy and security of customers’ data;

• Comply with industry governance arrangements around data access and security; and

• Complete entry processes and user acceptance tests.

Facilitating Roll-out Challenges

2.2.5 A key element of our activities will be supporting suppliers during rollout of smart metering systems. We carried out surveys on our network from the end of 2010 to early 2011 which suggest that across both our networks 6% to 7% of smart metering installations will need some work to be carried out by us on our equipment before a smart meter can be installed. More information on our surveys can be found in the Managing Work on our Network section below.

2.2.6 The work we will need to carry out will be varied in terms of urgency, cost and skills required. It will mean a significant increase in workload and costs for our business over the next 7 years. Dedicated resources will be needed to ensure we are able to respond in timescales that will minimise disruption for our customers. However we will also need to plan our work and respond efficiently to maintain safety and keep costs down.


Issue 1 of 35

Our objectives

2.2.7 We have taken part in DECC work groups to share the results of our survey with DECC, Ofgem, other DNOs and suppliers. We will continue to work with them to develop a clear framework that will allow us to plan and manage our workload efficiently. We will also ensure all jobs requiring network input are identified, categorised and reported correctly to ensure we can respond efficiently to keep costs down and ensure our network remains safe and reliable.

Our commitment

2.2.8 We will:

• Work with suppliers to better understand their rollout plans as they emerge and ensure sufficient detail is provided to allow us to plan and manage our work efficiently e.g. by month and location, ensuring the right type and level of resource is available in the right place and at the right time;

• Explore opportunities to dovetail work programmes with Suppliers and their agents to improve efficiency;

• Work with Suppliers and their agents to develop a service level agreement and training material that will allow them to accurately identify and report network issues, avoid misreporting or aborted calls and minimising the number of site visits. They will also set clear standards for carrying out work;

• Work with Suppliers to allow them to deal with issues directly where appropriate, to avoid additional callout and resource costs for SSEPD.

2.2.9 Details of benefits, costs and proposed cost recovery mechanisms are set out in Sections 2.2.31, 4.3 and 4.4 below.

Managing Work on Our Network Understanding the Challenge

2.2.10 To help us understand the potential impact on our network when Suppliers install smart metering systems, we carried out a survey of a cross section of 4,099 supply points on the SEPD network (3,786 domestic and 313 commercial) and 2,565 supply points on the SHEPD network (2,429 domestic and 136 commercial) between December 2010 and May 2011 to get a better understanding of any work that may need to be done to allow a smart meter to be installed and to ensure our network remains safe and reliable. The survey was carried out by experienced meter operators to ensure the results are reliable and representative of the entire population. This suggests 6% of smart metering installations on the SHEPD network and 7% on the SEPD network will require some input from us. 3.5% of all installations on SHEPD network and 4% on the SEPD network will require work to be carried out by us on our network either immediately to maintain safety or in the short term to allow the smart metering system to be installed. The majority of the remaining jobs can be carried out at a later date as part of ‘business as usual’ where there is no immediate safety or reliability concern and there is no impact on the smart metering programme.


Issue 1 of 35

2.2.11 We have shared these results with DECC, Ofgem, suppliers and other DNOs. We believe they provide a good indication of future workload and have been used as the basis for developing a robust framework for managing network activities.

Developing a Plan

2.2.12 Along with other DNOs we have engaged with DECC and Suppliers to better understand their rollout plans so we can plan our activities. While roll-out volumes have been low in the Foundation Stage, this is because suppliers are still developing and trialling their systems and processes. They have also tended to target straightforward installations and there has been very little impact on DNOs up to now but we are starting to see some issues emerging. Our plans show volumes are likely to increase significantly from 2015, when central data communication services are due to go live. Suppliers’ plans currently available to us also show workload is likely to peak towards the end of the programme. Based on these plans and recent discussions with suppliers, we believe the most significant period of work for us is likely to be in 2019. However the end date for the programme has been extended recently and is now scheduled to be complete by December 2020. We are working with DECC and suppliers to understand the impact this may have on their plans. As such our view may change. In addition we will continue to work with them to obtain more granular information on supplier plans e.g. by location and by month. This is essential to ensure we have the right level of resource in the right place at the right time to respond to suppliers’ and customers’ needs while minimising cost and maintaining customer service.

Work Requirements

2.2.13 Through our survey we have been able to break down work we will be required to carry out to help us understand the number of staff required, the skills required, workload and cost. Workload can be split as follows:

Category A – Emergency

2.2.14 Work in this category will generally have safety implications and our prompt presence on site will be required. Examples of jobs falling into this category include cut-outs operating hot or physical damage to our equipment which requires immediate action. When we receive notification of jobs falling into this category we will respond to and manage them as we do now; we aim to attend site within 3 hours (4 hours outwith normal working hours). Our first priority will always be to make safe. In instances where further work is required to enable a smart meter to be installed, these jobs will be prioritised in accordance with category B jobs (detailed below).


Issue 1 of 35

Category B – Remedial work required before a smart meter can be installed

2.2.15 There are a number of examples which fall into this category including specific issues associated with cut-outs which prevent the operation of our equipment but pose no immediate risk to the meter operative or our customers. Examples include; operative unable to remove cut-out fuse and issues relating to equipment design. When a job in this category is reported we will take action to remedy the situation and allow the smart meter can be installed. Work will be scheduled in line with the standards that are currently being developed with Suppliers e.g. through DCUSA Change Proposal DCP1531

.

Category C – Asset condition reports

2.2.16 These jobs have no immediate impact on smart meter rollout and no immediate safety concern but we will want to be made aware of issues relating to the condition of our assets. Examples include issues which may impact on the ability to adequately seal cut-outs or equipment with a rating of less than 60A. Where it is determined that remedial action is required work will be scheduled according to our current standards and priorities i.e. as business as usual. As a result we expect there will be minimal impact on resource requirements or cost under the smart metering programme.

2.2.17 Our immediate focus will be on Category A and B jobs which will impact on 3.5% of all installations on the SHEPD network and 4% on the SEPD network.

Business Processes, Information Systems and Interfaces The Challenge

2.2.18 To access the data that will be available from smart metering systems and needed to deliver the network benefits set out above, we will need to develop business processes, information systems and interfaces to:

Access central systems where smart metering data will be collected and managed;

• Transfer and store data; • Manage data to maintain confidentiality and security; • Process and manipulate data to get it into a format that can be used to help

manage and operate our network and deliver the benefits set out above, particularly in relation to innovation, demand forecasting, network planning, network investment and operation;

• Comply with industry rules, governance arrangements and testing requirements;

• Deliver customer service benefits that will help us meet our RIIO-ED1 objective of delivering exceptional customer satisfaction; and

• Help us identify vulnerable customers so that we can provide additional support;

• Build a platform that enables continual development and innovation. It must support future needs of smart grid capability and development in ED1 and beyond.

1 http://www.dcusa.co.uk/Public/CP.aspx?id=174


Issue 1 of 35

Our Approach

2.2.19 To meet our objectives the first phase of our programme will focus on mandatory activities associated with:

• Supporting Suppliers during smart meter roll-out; • Interfacing with central systems to access smart metering data; and • Integration of internal systems such as SCADA, Outage Management,

Geographic Information Systems (GIS) and planning management systems and integration with external systems such as the Data Communication Company (DCC) and any new registration systems.

2.2.20 The next phase will focus on replacing internal systems where we find they can’t be adapted, they can’t be integrated or they are not robust enough to meet data protection, security and integration requirements.

2.2.21 We have identified a need to develop and improve the integration of systems across three key areas in order to meet the requirements of the smart metering programme, improve customer service and deliver our innovation strategy and wider network benefits. These are summarised as:

• Customer Data; • Network Models; and • Asset Management.

They are shown in Figure 1 below:

Figure 1: Business Integration Objectives

Customer Network Connectivity

Asset Management

Network Data Management Systems


Issue 1 of 35

2.2.22 Using experience gained from our innovative projects under the Low Carbon Network Fund projects, we have adopted a structured approach to business process and system development, based on architecture frameworks which help us understand our end to end business activities and relate them to future business needs. Business needs will be focused on supporting changes that will help improve our customer service including outage management and demand management. We have used architecture frameworks to determine the scope of work, delivery requirements and the roadmap.

2.2.23 Outputs are defined in standard models such as UML (Unified Modelling Language) and BPMN (Business Process Modelling Notation) that are common across all industries and can be shared with others to learn lessons established elsewhere and to identify and implement best practice.

2.2.24 Our development plans identify critical changes to meet the initial rollout requirements and strategic changes which support wider rollout and help deliver the SMIP full programme benefits. However, we recognise the smart metering programme is evolving and our approach will remain flexible to respond to changes as they emerge. Our approach also recognises network critical areas such as responding to requests to carry out work on our network, changes to central systems and management of smart metering data require resilient and scalable systems that can meet strict recovery objectives.

2.2.25 We have also ensured compliance with the national SMIP architecture which shows the key elements of software, hardware and interfaces (as shown below in Figure 2) and system specification and governance arrangements.

Figure 2: National Smart Meter Architecture


Issue 1 of 35

Timescales

2.2.26 We have started work in DPCR5 to define the framework. This will be developed as further clarity is provided through the SMIP. Discussions are ongoing with DECC. At this stage changes to business processes and systems are not expected to be developed or implemented until the initial years of RIIO-ED1. Further details are included in our RIIO-ED1 Smart Metering Information Systems Strategy document.

Network Connectivity Model

2.2.27 A key part of our programme is the development of accurate network models, at all electricity voltage levels. To deliver the network benefits associated with smart metering data e.g. power outage management, improved demand forecasting, network planning, network investment and network operation we will need to have accurate and detailed models that reflect our network. Our existing network connectivity models are accurate to 11kV/distribution substation level but existing Low Voltage (LV) geospatial and schematic diagrams are simple line diagrams that represent the network and show how it is connected. Information associated with individual supply points and how they are connected to the network is limited which makes it difficult to link data on a street by street or house by house basis. Additionally the systems we use are not capable of managing information associated with actual power flows. To make full use of smart metering data and deliver benefits we will need models that are capable of managing actual power flows to specific points or locations, on our network.

2.2.28 We plan to develop these models using existing network models supplemented with additional data from other sources such as GIS, outage management and asset registers. We will validate the quality of the data from these sources before it is used. We also plan to develop more detailed customer databases which we will align with our network model to provide more detailed, meaningful and integrated information about our network and customers.

Registration Systems

2.2.29 During RIIO-ED1 we expect changes to be implemented through the SMIP which will transfer information contained in our existing customer registration systems to the new central Data Communication Company (DCC). This will involve significant industry change initially. It is also likely to require additional data items to be captured under the SMIP e.g. Unique Premises Reference Number. We will work with DECC, DCC and other industry participants to ensure any transfer is managed efficiently.

Data Protection

2.2.30 Data protection will be a key priority throughout. Customer consumption data has been deemed personal data and although we will have access through the regulatory framework we will need to ensure compliance with the Data Protection Act and industry governance arrangements being introduced through the SMIP.


Issue 1 of 35

Benefits

2.2.31 As our role in relation to smart meter rollout is to support suppliers, the benefits are difficult to quantify in financial terms. However it is clear the work we will carry out and our proposed approach will help:

• Improve network asset health and safety as issues will be detected and

reported by suppliers during meter installation allowing us to take action which might otherwise not be picked up for some time as “business as usual”;

• Ensure there is a clear reporting process and standard of service to avoid delay and minimise disruption for customers;

• Minimise costs overall for SSEPD, suppliers and ultimately customers; • Ensure appropriate incentives exist to work together and act efficiently to

ensure the smart metering programme is a success; and • Ensure the customer journey is as streamlined as possible to help deliver

exceptional customer satisfaction during smart meter roll-out and avoid customer complaints.


Issue 1 of 35

3 SSEPD Strategy for RIIO-ED1

3.1 Innovation

3.1.1 Data from smart meters will enhance our understanding of how our LV networks operate. This will become more important as loading on our networks change, brought about by customers adopting new LCT’s such as EV’s, Heat Pumps and micro generation.

3.1.2 Use of data will enable us to understand where network constraints exist or are developing. This in turn will enable us to make informed decisions relating to network operation, development and investment.

3.1.3 We expect that we will not gain access to smart metering data until the DCC commences its communications provision towards the end of 2015 and it won’t be until late 2018 when the 70% penetration level of meters is reached.

3.1.4 It is also important to realise that there will be a charge levied for data from smart meters and we aim to demonstrate that its use will deliver a net benefit to our business. It therefore follows that prior to the deployment of systems that use data from smart meters we will scrutinise the overall development and operating costs. Data from smart meters potentially has a number of uses associated with the operation of our distribution networks, these include:

• Assess Network Performance • Actively Manage Networks (including Demand Response) • Manage Planned/ Unplanned Outages • Manage Safety Issues

3.1.5 Development of technical solutions will continue to progress within the network operator/ vendor community, however it must be realised that whilst technical solutions may develop progress will also need to be made in other aspects of industry governance, namely supportive commercial and regulatory arrangements .

3.1.6 Within SSEPD we have identified a number of key areas associated with the operation of smart meters by suppliers and our use of data that require significant development. We believe that Innovation in these areas is vital if maximum benefit is to be extracted from us having access to data from the GB smart metering system and all risks associated with their operation are to be managed. The areas identified are:

• Network planning information – Development of new tools to assist planning

engineers manage all aspects of LV network planning including the connection of low carbon technologies and microgeneration.

• Power outage management – Determine how power outage messages can be optimised to deliver maximum benefit to customers with a specific emphasis on providing support for vulnerable customers.

• Responsive demand – Investigate how supplier actions associated with the control of existing space and water heating load can be managed to avoid overloading SSEPD networks in areas where network constraint exists.


Issue 1 of 35

• Power quality management – Understand how granular data, including voltage data from smart meters can be used to identify where network problems exist or where they are likely to develop and help identify the likely cause.

• Management of Network Losses – Having access to granular consumption data will enable SSEPD to better understand the scale of losses associated with its LV networks. It will develop means to identify where networks are operating with losses that are higher than would normally be expected and ascertain the potential reason. We would then be able to target any required remedial action.

3.1.7 This work is in addition to our £30 million Thames Valley Vision Low Carbon Networks Fund project which aims to:

• Understand consumption behaviour to determine potential network issues • Anticipate future changes to identify new network management requirements

3.1.8 Support the necessary changes to network management through new technology and commercial solutions.

3.1.9 We recognise that there will be an increasing need to use data from smart meters to understand changes in network loading at specific geographic locations, i.e. where a number of customers have deployed LCT’s on the same section of LV network. As detailed above the timescale associated with the deployment of many of these technologies will be based upon need which in turn will be driven by low carbon transition. We expect, with the exception of power outage management, that there will be no requirement to have systems and processes fully operational before all smart meters have been installed, i.e. before 2020. However we will maintain a flexible approach as circumstances may arise where use of data from smart meters could be used to identify and militate against developing network issues.

3.2 Cost Efficiency

3.2.1 We are developing cost schedules that will be published and allow suppliers to choose different callout options and response times. If suppliers want us to respond outwith normal hours and we incur additional costs, these costs will be reflected in our charges to ensure suppliers have the right incentives to select the most efficient service for everyone, particularly customers, and to ensure a balance is struck between efficiency and cost.

3.3 Stakeholder Feedback

3.3.1 We have worked with DECC, suppliers, electricity distribution network operators and other industry participants, directly and through the ENA, to help develop and define the rollout process, the role of participants and the commercial and regulatory framework. We have shared information obtained from our survey work with them and Ofgem to help raise awareness of the potential scale of the problem and to ensure a robust framework is developed to ensure a seamless service is delivered to customers and to minimise cost and avoid inefficiency. We are also working with Suppliers directly and through established industry work groups to develop Service Level Agreements (SLA’s) between Suppliers, their agents and Network Operators to ensure there are clear recording and reporting processes; clear and robust standards for responding to and resolving network issues; appropriate charging methodologies and incentive mechanisms to target costs, drive efficient behaviour and avoid cross subsidy.


Issue 1 of 35

3.3.2 We have engaged with stakeholders using a number of different methods, depending on the audience and complexity of the issues to be discussed. We have had bilateral meetings with suppliers, bilateral meetings with DECC and Ofgem, delivered presentations and papers to industry work groups e.g. DECC Smart Metering Programme and ENA working groups. The feedback we have received has helped shape these proposals, particularly in relation to SLAs and charging arrangements.


Issue 1 of 35

4 Forecast Expenditure in RIIO-ED1

4.1 Volumes

4.1.1 It is important to understand the type of issues likely to be identified by suppliers during smart meter roll-out already exist today, but would only be picked up during routine visits e.g. to obtain a meter read, carry out work at the customer’s property or to replace a meter. As a result annual volumes are currently very low. As the SMIP will mean that every domestic and small business customer will be visited by the end of 2020 to have a new smart meter installed, the workload that would normally occur over a period of up to 20 years (approximate meter recertification period) will now be concentrated into a much shorter period, meaning annual volumes will increase significantly. Figures 3 and 4 below show the forecast profile of work by category across both our networks in each year of the programme. Profiles are based on information provided by DECC and suppliers, revised to take account of the recent extension to the end date and knowledge we have of suppliers’ attitudes towards installation during the Foundation Stage.

Figure 3 – SHEPD Expected Volume of Network Related Jobs

0

1000

2000

3000

4000

5000

6000

7000

8000

2012 2013 2014 2015 2016 2017 2018 2019 2020

Num

ber o

f Net

wor

k Is

sue

Year

Category ACategory BCategory C


Issue 1 of 35

Figure 4 – SEPD Expected Volume of Network Related Jobs

Developing a Service Level Agreement

4.1.2 We are working with suppliers and other DNOs to develop Service Level Agreements that will set clear standards for reporting jobs that require some network involvement and details the expected response from ourselves. This will help ensure all the information we need to carry out our work is available to us and will help avoid inaccurate reporting of issues and aborted callouts. They will also give suppliers and customers a clear indication of how they can expect us to respond, setting out our commitment to them and our customers, so they can manage their activities.

4.1.3 In some cases we may need to attend site and carry out a survey before we can start work. Where we need to do this we will try to ensure we minimise the number of visits. We are also committed to planning and managing all our work at mutually acceptable times; taking into account the needs of suppliers and our customers.

4.1.4 We are developing cost schedules that will be published and allow suppliers to choose different callout options and response times. If suppliers want us to respond outwith normal hours and we incur additional costs, these costs will be reflected in our charges to ensure suppliers have the right incentives to select the most efficient service for everyone, particularly customers, and to ensure a balance is struck between efficiency and cost.

0

5000

10000

15000

20000

25000

30000

35000

2012 2013 2014 2015 2016 2017 2018 2019 2020

Num

ber o

f Net

wor

k Is

sues

Year

Category ACategory BCategory C


Issue 1 of 35

4.1.5 We will also monitor activities to identify situations where there is persistent misreporting, inappropriate callouts or aborted calls. Where there appears to be a problem we will work with our staff, suppliers and their agents to ensure processes and procedures for identifying and reporting network issues are clear and appropriate. Where we identify additional training or changes to processes are required they will be implemented promptly. If we find a party persistently misreports network issues causing unnecessary costs to be incurred we will look to pass on these costs to the relevant party to ensure appropriate incentives exist to act responsibly and efficiently and in the best interest of customers. Similarly we plan to develop a cost schedule and recharge installers where we are required to attend a site and carry out remedial work as a result of poor workmanship or issues caused during a smart meter installation.

4.1.6 We will also work with suppliers to regularly review the services we provide and our charges to ensure charges are cost reflective and services are aligned with suppliers’ and customers’ needs.

4.2 Unit Rates

Unit Costs Relating to Smart Roll-Out

4.2.1 We support Ofgem’s proposal to then set a volume driver which would be settled on an annual basis to recover any incremental cost. Details of proposed unit costs for the volume driver are set out in Table 2 below. They are based on information collected from surveys and current unit cost rates as further detailed in our Smart Metering Justification Paper and the associated CV109 spreadsheets. As such we believe they provide a sound basis for setting future allowances.

Table 2: Unit Costs

Item Description SHEPD SEPD


Cut out change £745.80 £745.80 £741.33 £775.64

Service Inspection £22.22 £22.22 £17.33 £17.33

Service Alteration £1,223.58 £1,223.58 £1,224.03 £1,580.75

Abortive calls £68.89 £68.89 £66.45 £66.45

Miscellaneous repairs/ safety reports £232.11 £232.11 £227.57 £242.44


Issue 1 of 35

4.3 Total Direct Costs

Costs associated with Managing Work on the Network

4.3.1 Overall costs associated with responding to supplier related call outs and undertaking work on our network to facilitate smart meter installation have been assessed. We have identified that costs will be incurred in three principle areas, namely:

• The direct cost of undertaking work within customers properties; • Indirect costs associated with work scheduling and additional call centre

costs; • Up front recruitment, training and HR cost.

4.3.2 We estimate the total cost associated with managing work on our network to facilitate supplier rollout will be £115.4m. The level of cost likely to be incurred in this price control period is £5.3m and over RIIO-ED1 the cost will be £110.1m.Our assessment of overall costs related to supplier call outs are summarised in Table 3 below.

Table 3 - Overall network costs associated with supplier call outs



Direct Costs £0.64 £15.58 £4.06 £66.32

Indirect costs £0.1 £1.8 £0.5 £7.1

Recruitment, training and HR costs £0.0 £3.86 £0. £15.44

Total £0.74 £21.24 £4.56 £88.86

4.3.3 The direct costs associated with responding to supplier callouts and carrying out work on our network have been calculated using details available from our survey, supplier rollout volumes and calculated unit costs. We expect total direct costs to be £86.6m. The level of cost likely to be incurred in this price control period is £4.7m and over RIIO-ED1 costs will be £81.9m.

4.3.4 Details of total direct costs are summarised in Table 4 below. More information regarding direct and indirect costs can be found in section 4 of the Smart Metering Justification Paper and the associated CV109 spreadsheets.

4.3.5 We have identified that £19.3m relates to HR, recruitment and training costs. These costs will be incurred over a 3 years period from 2015/16 through to 2017/18. More detailed information can be found in the Closely Associated Indirects section of the Indirect Supporting Paper under the HR and Operational Training section.


Issue 1 of 35

Table 3 - Network Costs



Cut out change £0.49 £10.59 £2.66 £42.82 Service Inspection £0 £0.56 £0.12 £1.87 Service Alteration £0.0 £0.2 £0.05 £1.09 Abortive call £0 £0.11 £0 £0.46 Miscellaneous repairs/ safety reports

£0.15 £4.12 £1.23 £20.08

Total £0.64 £15.58 £4.06 £66.32

Costs associated with Business Processes, Information Systems and Interfaces

4.3.6 Our forecast costs associated with developing and implementing all elements of our smart metering IT programme are £77.9m as set out in Table 5 below. They are split into the following categories:

• Interfacing with central systems e.g. the Data Communication Company

which will collect and process smart metering data from customers; • Internal data cleansing, improvement and system integration; • Network data management, which includes our network connectivity model

and data protection; and • IT Support and Maintenance;

4.3.7 Costs are based on other corporate integration and system replacement projects implemented across SSE. They include system design, development, and hardware and software costs. They make use of standard industry models and practices for similar system development and implementation projects and are based on detailed consultation with the business to determine effort and define processes and requirements.

Table 5: IT and Process Development Costs

Cost Summary RIIO-ED1 Smart Meter Data Management Systems (£m)

DCC Interface Data Improvement & Integration

Network Data Management

Support and Maintenance

SHEPD £2.4 £3.1 £10.0 £0.1

SEPD £9.6 £12.3 £40.0 £0.4

Total £12.0 £15.4 £50.0 £0.5 .


Issue 1 of 35

Costs Associated with DNO Use of Smart Metering Data

4.3.8 Based on indicative charges provided by DECC earlier this year, we believe the fixed costs associated with accessing smart metering data from the DCC will be in the order of £0.15m annum for SHEPD and £0.6m for SEPD. As these charges relate to fixed costs associated with DCC services and SHEPD and SEPD will be required under licence to be signatory to the Smart Energy Code and pay associated charges, these costs should be subject to a ‘pass through’ mechanism until the network benefits associated with smart metering data can be realised, particularly given current uncertainty regarding supplier rollout profiles and the likelihood that network benefits associated with such data are unlikely to materialise to any significant extent until RIIO-ED2. For the same reason we believe efficiently incurred variable costs associated with DCC charges and DCC licence fees should also be subject to pass through arrangements to allow DNOs to access data to facilitate development work required to realise full network benefits at a later date, at least until a significant penetration and flow of smart metering data is achieved.

Internal IT Costs

4.3.9 A summary of our internal smart metering IT costs are set out in section 5.7 above and in our supporting our RIIO-ED1 Smart Metering Information Systems Strategy document. These costs are embedded in our IT business plan proposals as part of our wider IT strategy.

4.4 Cost Recovery

Upfront Costs

4.4.1 As set out in our response to Ofgem’s Strategy Decision document for RIIO-ED1, submitted in April 2013, we support Ofgem’s decision to set an ex-ante allowance to cover costs associated with supplier call outs and believe the proposal to base this on a 2% call out rate is an accurate reflection of the initial level of workload we now believe will be required, particularly taking into account cost likely to be incurred in this area in the current price control period DPCR5 (£5.3m)

Incentive Mechanism for Smart Roll-Out

4.4.2 We do not agree with Ofgem’s proposal to introduce a tapering mechanism to provide an incentive to minimise the amount of work required by DNOs to support suppliers during smart metering roll-out. We do not believe there is any sound justification for such a mechanism, particularly as this part of the programme is supplier led and to a significant extent outwith our control. As demonstrated earlier in this document, workload in any year and between years is also likely to be extremely variable and at present difficult to predict. This is widely recognised within the DECC programme and SSEPD is working with Suppliers and DECC to try and resolve this. Workload will be focused on delivering a Government policy objective.


Issue 1 of 35

4.4.3 We are further concerned that the parameters proposed are arbitrary and are not based on observed data. All incentive mechanisms should be based on experience to ensure they are achievable and do not introduce unnecessary or disproportionate risk.

4.4.4 Given a significant proportion of activity is also likely to have implications for safety and reliability of the network we believe an incentive mechanisms in this area would be inappropriate. .

4.4.5 We believe the work we are carrying out with Suppliers to establish Service Level Agreements and standards is a more appropriate way of addressing Ofgem’s concerns.

4.5 Information Sources

4.5.1 Please Cost and Volumes Tables Commentary.

4.6 RIIO-ED1 Performance

4.6.1 We will measure our performance in relation to our objectives through our customer satisfaction survey results and through our work activity reports to ensure we meet all our targets in relation to our service level agreements with suppliers and their agents. We also plan to monitor our performance on a per unit cost basis. More information on standards of performance will be provided as service level agreements develop.


Issue 1 of 35

Appendix A. Smart Metering Outputs Paper


Issue 1 of 35

Analysis of Network Benefits from Smart Meter Message Flows Application of ENA Evaluation to Scottish and Southern Energy Power Distribution 1 - Introduction In March 2012 the ENA Smart Metering Steering Group (SMSG) published a document entitled the Analysis of Network Benefits from Smart Meter Message Flows to help inform debate under the DECC Smart Metering Implementation Programme. This was reviewed in March 2013 taking into account changes that had occurred in the national smart meter programme where they have an impact on the ability to deliver the benefits identified, e.g. changes in the national smart metering system security architecture (which prevent DNO’s from having direct access to load control) and changes to the specification for electricity smart meters. The 2013 report details the party responsible for delivering the benefits, the scale of benefit available and when benefits will likely be delivered. Importantly it also draws a distinction between benefits that will accrue directly to consumers and those which will enable DNOs to reduce their cost bases. In this appendix we have taken the ENA’s March 2013 report and overall GB figures and given an indicative view of SSEPD’s (SEPD and SHEPD) share of the benefits identified at that time. We have assumed that each customer will have an equal share of the benefits identified and have based our calculations upon the ratio of customers in each licence area when compared to the overall number of customers in GB2

.

However, since the ENA completed its review in March 2013 the overall smart metering programme has “slipped” by one year. The impact of this change is currently being considered and has not yet been factored in to the analysis set out in this paper. This change will reduce the overall benefit available to SSEPD from having access to and being able to use smart meter message flows during the RIIO-ED1 period. The ENA has also commissioned work to re-assess the overall value of benefits available to GB that can be derived by DNO’s having an ability to access smart meter message flows. The outputs of this work will not be available until July 2013. Once this information is available we will review the SEPD and SHEPD benefits to update this paper. We will share this information with Ofgem, DECC and other stakeholders as soon as it is available. This report has been included in the Business Plan at this point in time to give a very high level indicative view only and should not be relied upon for decision making purposes. 2- High Level Benefits Tables The tables set out below provide information regarding our initial view of benefits which can be delivered by individual industry parties (DNO’s/ suppliers). Note all values shown are in £m.

2 2 Evaluation based upon customer allocation ratios: SHEPD 2.93% of GB electricity customers (PC 1 – 4) only SEPD 10.29% of GB electricity customers (PC 1 – 4) only


Issue 1 of 35

Table 1 - Benefits deliverable by Scottish and Southern Energy Power Distribution independently of other parties (based on SMETS2 functionality).

Category Nature of Benefit

Basis of Derivation

SSEPD ED1

Period Benefit

(£k)

SSEPD ED2

Period Benefit

(£k)

Notes

Proactive Planning of HV & LV networks

Better informed load-related investment decisions

DPCR5 baseline for HV & LV general reinforcement

2.33 1.75

From 2019-2025 only - then superseded by Responsive Demand and ANM benefits

Voltage monitoring and sag/swell alarms

Avoided voltage complaints and admin costs

Avoided costs of site visits to install and recover voltage recorders and track sources of PQ problems

0.36 0.73

Assuming gradual increasing benefit from 2015 to 2020 due to increasing smart meter volumes and from 2025 due to faster LCT ramp rate


Reduced investment to serve new connections

DPCR5 baseline for demand connections

1.82 1.37


Power Outage Management*

Reduce duration of LV interruptions

Assumed 10 min reduction (from 192 to 182 min) in avg. time to restore supplies for an LV fault - valued at 17p per min (WTP)

3.70 4.79

Increasing from 2015 to 2019 (when rollout complete) Benefit is based purely on consumer valuation (WTP) and assumes no DNO incentive benefit or opex saving

Power Outage Management

Reduced Guaranteed Standard failure and payments

Elimination of GS2 failures (11,237 in 2009/10) approx. £0.5m p.a.

0.26 0.53

From 2019 assuming energisation status polling capability Note: proposed ED1 reduction from 18h to 12h not taken into account

Active Network Management*

Optimising LV network voltage and power flows (or power sharing) informed by smart meter data

IC Report assessment of HV & LV reinforcement required due to LCT (potentially avoided through ANM)

0 15.67

Based on LCT exponential growth trend and minimum cost of counterfactual in the IC report (assuming 10% increase in capacity headroom) Assumes hh ‘real time’ data flows from smart meters

TOTAL 8.37 24.84


Issue 1 of 35

* Power Outage benefit is based on value to consumer (WTP) and confers no direct benefit to DNO - other than a small IIS benefit and a potentially improved BMCS score (improved consumer experience from DNO being aware of loss of supply and able to act proactively) *It is SSEPD’s view that there will be no benefit from ANM delivered by using data from smart meters during RIIO-ED1. We also expect the scale of benefit for ED2 may be optimistic. This is to be reviewed and where appropriate refined in future ENA work.

Table 2 - DSR benefits dependent upon Supplier-led ToU tariffs and load control / smart appliances


Basis of Derivation

SSEPD ED1

Period Benefit

(£k)

SSEPD ED2

Period Benefit

(£k)

Notes

Responsive Demand - TOU tariffs*

Reduced need for network capacity to meet peak demand

Avoided cost of reinforcement due to improved load factor releasing capacity headroom

3.45 23.49

Based on LCT exponential growth trend and minimum cost of counterfactual in the IC report (assuming 15% contribution towards ideal LF)

Responsive Demand - Load Control

Remote control or smart appliance managed responsive demand


4.60 31.32


Management of Network Losses*

Mitigated increase in HV/LV transformer and LV I2

Current level of technical losses and predicted 19% increase in energy throughput at 2030 with potentially deteriorating LF

R network losses due to improved load factor

13.33 90.65

Based on DECC 4th

TOTAL

carbon budget scenario 3 for heat pumps and EVs (19% increase in distributed electrical energy to 416TWh at 2030) – assuming losses valued at £60 per MWh (DPCR5)

21.38 145.46

* In SHEPD we have the requirement to control space and water heating load (“off peak”) to ensure existing network constraint is managed.

* Losses benefit is based on the £60 per MWh DPCR5 valuation: this confers no direct ED1 benefit to DNO in the absence of a target-based losses incentive - other than in terms of licence compliance and freeing-up network capacity and potential to compete for discretionary reward.


Issue 1 of 35

3 - DNO Cost Base-Impacting Benefits - Realisation and Deliverability It is apparent from Tables 1 and 2 that, in monetary terms, the bulk of the benefits are those related to Demand Side Response which are dependent on actions of Suppliers (and consumers) for their realisation, particularly over the ED2 period. It is also apparent that, in monetary terms, only a small proportion of the benefits will impact a DNOs’ cost base (i.e. operational costs, network investment requirements, and incentive rewards/penalties).

It is important to draw a distinction between benefits that will accrue directly to consumers and those which will enable DNOs to reduce their cost base (and which therefore will accrue to consumers in terms of ED1 and ED2 baseline allowances).

Tables 3 and 4 only list the benefits from the above tables which will directly impact a DNOs’ cost base. The first table lists those cost base-impacting benefits which DNOs are able to deliver independently of other parties; the second table lists those cost base-impacting benefits on which DNOs are dependent upon Suppliers and consumers for their delivery.


Issue 1 of 35

Table 3 - DNO cost base-impacting benefits deliverable by Scottish and Southern Energy Power Distribution independently of other parties


Basis of Derivation

SSEPD ED1

Period Benefit

(£k)

SSEPD ED2

Period Benefit

(£k)

Notes


Better informed load-related investment decisions

DPCR5 baseline for HV & LV general reinforcement

2.33 1.75


Voltage monitoring and sag/swell alarms

Avoided voltage complaints and admin costs

Avoided costs of site visits to install and recover voltage recorders and track sources of PQ problems

0.36 0.73

Assuming gradual increasing benefit from 2015 to 2020 due to increasing smart meter volumes and from 2025 due to faster LCT ramp rate


Reduced investment to serve new connections

DPCR5 baseline for demand connections 1.82 1.38


Power Outage Management

Reduced Guaranteed Standard failure payments

Elimination of GS2 failures (11,237 in 2009/10) approx. £0.5m p.a.

0.26 0.53

From 2019 assuming energisation status polling capability Note: proposed ED1 reduction from 18h to 12h not taken into account

Active Network Management

Optimising LV network voltage and power flows (or power sharing) informed by smart meter data

IC Report assessment of HV & LV reinforcement required due to LCT (potentially avoided through ANM)

0 15.66

Based on LCT exponential growth trend and minimum cost of counterfactual in the IC report (assuming 10% increase in capacity headroom) Assumes hh ‘real time’ data flows from smart meters

TOTAL 4.77 20.05


Issue 1 of 35

Table 4 - DNO cost base-impacting benefits dependent upon Supplier-led Demand Side Response*


Basis of Derivation

SSEPD ED1

Period Benefit

(£k)

SSEPD ED2

Period Benefit

(£k)

Notes

Responsive Demand - TOU tariffs

Reduced need for network capacity to meet peak demand


3.45 23.49


Responsive Demand - Load Control

Remote control or smart appliance managed responsive demand


4.60 31.32


TOTAL 8.05 54.81

*The above benefits assume that volumes of low carbon ‘demand’ technologies such as electric vehicles and heat pumps will grow broadly in line with DECC’s 4th

Carbon Budget scenarios (1, 2 or 3) and represent the anticipated level of conventional network reinforcement that would be necessary in the absence of effective Demand Side Response.

4 - Overall ED1 Summary for Scottish and Southern Energy Power Distribution The SSEPD share of benefit calculated from the original ENA paper published in March 2012, that could be ‘harvested’ by our actions have a present value of £171m (13.32% of the £1.29bn which was identified as accruing to GB as a whole). This valuation was based on a DCF study taken over the period 2015 to 2030 and applying an annual discount rate of 3.5% real. The study period was selected as being broadly representative of the (i) earliest time at which benefits might become available (which was assumed to correspond coincidentally with the beginning of both mass rollout and RIIO ED1); and (ii) a realistic assumption as to the life-expectancy of the initial generation of SMETS-compliant smart meters and the DCC system.

Looking only at the RIIO-ED1 period, and still maintaining the original studies’ assumptions, the total benefits calculated were £35.2m. This includes all benefits, including those are no longer achievable due to functional omissions in SMETS2, and those which would not in any case have affected the cost-base of DNOs.

Of this £35.2m RIIO-ED1 period benefit, this interim review has identified that we should discount some benefits because certain aspects of functionality, assumed to be provided as at March 2012, will in fact not be provided due to functional omissions in SMETS2. These benefits are associated with the costs of communicating with customers for operational management (e.g. notification of planned outages) and of dealing with the customer side consequences of neutral fault incidents. These benefits can no longer be harvested because the DNOs’ ability to communicate with the customer and the meter’s functionality to protect against neutral faults will not be provided. The total un-realisable benefit arising from this issue is £3.2m over the RIIO-ED1 period resulting in a reduced RIIO-ED1 period benefit of £32m.


Issue 1 of 35

Of this £32m RIIO-ED1 period benefit, £13.32m represented an estimate of the saving in losses (valued at £60 per MWh) that would result from improved network load factor. This was anticipated to flow from the ability to send commercial signals (i.e. time of use tariffs) to consumers (who it was assumed would therefore lower consumption at times of peak network demand or shift demand to lower price periods). This saving would not in any case appear as a reduced cost line in DNOs’ current cost base or indeed in DNOs’ business plans going forward. Instead it would also accrue directly to consumers, if realised. This leaves £18.7m ED1 period benefit that could potentially be realised by DNOs. Of this, £8m represented avoided network reinforcement as a result of headroom created by improved load factor. This was anticipated to flow from the ability to send commercial signals (i.e. time of use tariffs) to consumers (who it was assumed would therefore lower consumption at times of peak network demand or shift demand to lower price periods) and hence improve network load factor. However, the functionality to send these signals is only to be made available to Suppliers and so it cannot necessarily be assumed at this stage that these benefits would be harvestable by DNOs.

Of the remaining £10.7m benefit, £3.7m represented the value to consumers of reduced duration supply interruptions resulting from faults on LV networks and HV fuse-controlled spurs; local distribution transformer HV circuit breaker operations; and HV overhead-line open-circuit faults (i.e. faults which our SCADA systems would not generally detect and which therefore would normally be identified only through consumer calls). The valuation was derived from an assumed reduction in restoration time for such faults and a ‘willingness to pay’ value of 17p per minute of lost supply. Whilst harvestable by us, this £3.7m benefit would not of course appear as a reduction in our cost base (as the supply restoration “clock starts earlier”). Subtracting this £3.7m from the £10.7m results in total realisable SSEPD cost-base benefit over RIIO-ED1 of £7m. As with all figures in this study, these benefits maintain the assumptions that underpinned the March 2012 paper. This includes assumptions regarding the degree of low carbon technology uptake and any increases in network cost base associated with this. 5 - Conclusions The work undertaken by the ENA (SMSG) provided a valuable indicative assessment for Ofgem and DECC of overall benefits that may be available to DNO’s during the RIIO-ED1 period and beyond. However the changes imposed under the DECC programme and a DNO’s ability to use certain elements of smart metering functionality under the programme have resulted in a significant reduction in overall benefit that we believe can be realised during the RIIO-ED1 period and beyond. Additionally the most recent analysis has determined where network related benefits accrue; whether directly to DNO’s or directly to customers. If we allow for the recent delay to the overall smart metering programme it is likely that the overall benefit to SSEPD of using smart meter message flows during RIIO-ED1 will be around £5m. We remain concerned that the overall benefits available to DNO’s associated with using data from smart meters is often overstated. We are working with DECC and all of our stakeholders to develop more accurate and robust information taking into account further detail emerging from the DECC programme, particularly in relation to technical specifications, governance arrangements and timelines. This information will be shared with Ofgem and DECC as soon as it is available.

Scottish and Southern Energy Power Distribution RIIO-ED1 Smart

Documents

Transcript of Scottish and Southern Energy Power Distribution RIIO-ED1 Smart