HV FEEDERS LOAD RELATED · 2021. 7. 2. · brief of our RIIO-ED2 planning forecast is provided in Section 5. Section 6 describes our strategy that we have developed to manage of HV

RIIO ED2 Engineering Justification Paper (EJP)

HV FEEDERS – LOAD RELATED

Investment Reference No: 69/SHEPD/LRE/Feeders

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Contents

Definitions and Abbreviations .............................................................................................................................. 3

1 Executive Summary ...................................................................................................................................... 4

2 Investment Summary Table ......................................................................................................................... 5

3 Introduction ................................................................................................................................................. 6

4 Background Information .............................................................................................................................. 7

4.1 HV Network Configuration and Utilisation .......................................................................................... 7

4.2 Licence Obligations and Industry Standards ........................................................................................ 7

4.3 Investment Drivers ............................................................................................................................... 8

4.3.1 Cables and overhead line capability ............................................................................................. 8

4.4 HV feeder faults from thermal overload .............................................................................................. 9

5 RIIO-ED2 Load Forecast .............................................................................................................................. 10

6 Optioneering .............................................................................................................................................. 12

6.1 Secondary Reinforcement .................................................................................................................. 12

6.1.1 Summary of Options .................................................................................................................. 12

6.1.2 CBA Analysis Summary ............................................................................................................... 13

6.1.3 Stage 1: Flexibility solution to defer investment ....................................................................... 14

6.1.4 Stage 2: Asset reinforcement ..................................................................................................... 15

6.2 Fault Level Reinforcement ................................................................................................................. 15

7 Analysis and Cost........................................................................................................................................ 16

7.1 SEPD Costs and Volumes .................................................................................................................... 16

7.2 SHEPD Costs and Volumes ................................................................................................................. 18

8 Deliverability and Risk ................................................................................................................................ 20

9 Conclusion .................................................................................................................................................. 21

Appendix 1: Technical Specifications and Data.................................................................................................. 22

Underground Cables ...................................................................................................................................... 22

Appendix 2: Underground Cables Reinforcement Cost Breakdown .................................................................. 23

Appendix 3: Whole Systems consideration ....................................................................................................... 24

Appendix 4: Relevant Policy, Standards, and Operational Restrictions ............................................................. 26

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Definitions and Abbreviations

Acronym Definition

CAPEX Capital expenditure

CBA Cost Benefit Analysis

CI Customers Interrupted

CML Customers Minutes Lost

CT Consumer Transformation

DFES Distribution Future Energy Scenarios

DNO Distribution Network Operator

DSO Distribution System Operator

EJP Engineering Justification Paper

EREC Engineering Recommendation

ENA Energy Networks Association

EV Electric Vehicle

GIS Geographic Information System

HP Heat Pump

HV High Voltage

IDP Investment Decision Pack

km kilometres

kVA kilo volt-ampere

LCT Low Carbon Technology

LRE Load Related Expenditure

LV Low Voltage

MVA Mega volt-ampere

SEPD Southern Electric Power Distribution

SHEPD Scottish Hydro Electric Power Distribution

SSEN Scottish and Southern Electricity Network

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1 Executive Summary

This paper identifies the need to carry out works on the SSEN HV circuits asset class category to accommodate the forecast load growth. This includes 6.6kV and 11kV underground cables and overhead lines which will be overloaded under our stakeholder-supported DFES. The primary drivers of the proposed expenditure are capacity-related (demand or generation) or fault level-related.

SSEN’s stakeholders have informed the network planning studies during RIIO-ED2 to adopt the DFES 2020 Consumer Transformation scenario as the baseline scenario where the impact EVs and HPs forecasts have been assessed. It has been found that approximately 6% of SSEN HV circuits are expected to have sections of the feeder overloaded by end of RIIO-ED2 due, principally, to LCT uptake. Following optioneering and detailed analysis, as set out in this paper, the proposed scope of work can be summarised as follows.

For secondary capacity-related reinforcement:

▪ Re-conductor approximately 95 km of underground cable ▪ Re-conductor approximately 71 km of overhead line ▪ Procure approximately 13 MVA of flexibility services

For fault level reinforcement:

▪ Re-conductor approximately 75 km underground cable ▪ Re-conductor approximately 177 km of overhead lines

The cost to deliver the proposed solutions is £41.5 million and the work is planned to be completed during the ED2 period (2024-2028).

This proposed HV circuit expenditure programme delivers the following customer outputs and benefits:

▪ The uplift in network capacity needed to meet the ongoing capacity needs of our customers. ▪ Fault level compliance to ensure the safety of our operational staff and the public ▪ Facilitates the efficient, economic, and co-ordinated development of our distribution network to

support and facilitate the delivery of net zero.

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2 Investment Summary Table

Table 1 provides a high-level summary of the key information relevant to this Engineering Justification Paper (EJP) and the management of SSEN’s HV Feeders.

Name of Programme HV feeders

Primary Investment Driver

Load-related (thermal capacity and fault level compliance)

Investment reference/mechanism or category

69/SHEPD/LRE/Feeders

Output reference/type

6.6/11kV UG cable

6.6/11kV overhead line (BLX or similar Conductor)

6.6/11kV OHL (conventional conductor)

Cost CV2: £18.8m

CV3: £22.7m

Delivery year RIIO ED2 (2024-2028)

Reporting Table CV2: Secondary Reinforcement

CV3: Fault Level Reinforcement

Outputs included in RIIO ED1 Business Plan

No

Spend apportionment

CV2 Seondary Reinforcement

Spend (£m)

ED1 ED2 ED3+

SEPD - 11.6 -

SHEPD - 7.2 -

CV3 Fault Level Reinforcement

Spend (£m)

ED1 ED2 ED3+

SEPD - 22.7 -

SHEPD - - -

Total - 41.5 -

Table 1 Investment Summary

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3 Introduction

Our Load Annex sets out our methodology for assessing load-related expenditure (LRE) and describes how we use the Distribution Future Energy Scenarios (DFES) 2020 as the basis for our proposals. We have established a baseline view of demand which provides a credible forward projection of load-related expenditure for the ED2 period and reflects strongly evidenced support from our stakeholders. Our ex-ante baseline funding request is based on the minimum investment required under all credible scenarios. Our plan will create smart, flexible, local energy networks that accelerate progress towards net zero – with an increased focus on collaboration and whole-systems approaches.

This Engineering Justification Paper (EJP) describes our proposed load-related investment plan for HV circuits portfolio, which is the expenditure SSEN requires to ensure our networks can facilitate the change in demand and generation at the distribution level. LRE improves network resilience, enables the connection of new load and minimises the frequency and duration of outages our customers might have to experience.

It is essential not to exceed the thermal and fault level rating of HV underground (UG) cables and overhead lines (OHL). Failure to do so is likely to lead to the unplanned failure of assets in operation – with the associated customer supply interruptions and potential safety hazard. With anticipated LCT uptake during RIIO-ED2, it is expected that there will be substantial growth in demand, which will require adequate availability of capacity on the HV feeders. Our HV network characteristics and background information are provided in section 4. A brief of our RIIO-ED2 planning forecast is provided in Section 5.

Section 6 describes our strategy that we have developed to manage of HV circuit portfolio and associated expenditure. Key features of this strategy are set out in this EJP and provide the basis and justification for our decision-making. The LRE strategy for the HV and LV networks is described in more detail in the ED2 Load Annex1.

Section 7 presents the volumes needed and associated costs during RIIO-ED2. The deliverability plan and potential risks are explained in Section 8. Finally, our proposed investment plan conclusion is drawn in Section 9.

1 ED2 Business Plan Load Annex, Section 5.

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4 Background Information

This section provides background information and description of the HV feeder asset class under consideration, the relevant SSEN and industry policies, and the approach used to identify those assets that will require investment during RIIO ED2.

The 11kV2 distribution system comprises overhead lines, underground cable and secondary distribution substations. Error! Reference source not found. shows the quantity of HV feeders and circuits within the SSEN licence areas. Rural feeders consist of predominantly overhead lines and some underground cables, while urban feeders consist of underground cables only.

SEPD SHEPD

Number of HV circuits 3,384 1,687

6.6kV/11kV underground cables (km) 17,105 5,590

6.6kV/11kV overhead Lines (km) 13,140 21,762

Table 2 SSEN HV Feeder Counts

4.1 HV Network Configuration and Utilisation

The utilisation level of a given circuit is defined as the load (e.g. MVA, kVA) supplied by the circuit divided by the circuit capacity (e.g. MVA, kVA), usually expressed as a percentage. The utilisation percentage indicates the extent to which the circuit can accommodate additional load in the event of a sudden and unexpected fault and is therefore an important aspect of determining security of supply compliance.

Our HV distribution networks are normally configured to achieve maximum utilisation whilst maintaining security of supply standards, at a minimum cost. The 6.6kV/11kV urban network is usually configured as a ‘loop-tee-loop’ arrangement in an open ring formation. The 6.6kV/11 kV rural network is normally configured as an open ring with pole-mounted 11 kV/LV transformers directly connected. However, under abnormal operating conditions, such as faults or planned outages, the network is designed in a way that load can be supplied from alternative substations by operating switches to move the ‘normal open point’. Where group demand is below 1 MVA, the network configuration may be radial feed with no back-feed facility.

4.2 Licence Obligations and Industry Standards

The following standards are the guiding principles which underpin the policy for planning and designing the distribution network in SEPD and SHEPD:

▪ Licence conditions ▪ Distribution Code ▪ Electricity Safety, Quality and Continuity Regulations ▪ Environmental standards ▪ Company internal standards

2 HV includes our network assets operating at 6.6kV as well as those at 11kV.

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We have a mandatory obligation to comply with the Electricity Act 1989.and Standard Licence Condition (SLC) 5, which requires us to develop and maintain an efficient, co-ordinated and economical system of electricity distribution, and to ensure it is designed to a security standard not less than that provided by EREC P2/73.

According to ENA EREC P2/7 a ‘circuit’ is the part of an electricity supply system between two or more circuit breakers, switches and/or fuses inclusive. It may include ‘transformers, reactors, cables and overhead lines’. Furthermore, a circuit should not be ‘loaded to a point where it would suffer unacceptable loss of life’4. Security Standard EREC P2/7 goes on to state that

“Circuit Capacity is the appropriate continuous rating or cyclic rating or, where it can be satisfactorily determined, the appropriate emergency rating, taking into account the relevant environmental conditions and the expected demand profile, should be used for all circuit equipment and associated protection systems”.

We fulfil this standard through strategic system planning, taking into consideration the health indices and load requirements of the network. Targeted investment for the reinforcement and replacement of our distribution system is designed to ensure compliance with our mandatory licence obligations and industry standards.

4.3 Investment Drivers

The principal investment driver for HV circuits in ED2 relates to load growth, where the anticipated uptake in LCTs will increase customer demand (as well as significantly alter the cyclic profiles) and this additional load result in circuits approaching, or exceeding, thermal capacity limits. In addition, where there is an anticipation of the system fault level exceeding the safe fault rating of network equipment, such as switches, then reinforcement of the network for fault level may be needed.

According to our least scenario analysis5, in all DFES scenarios it is expected that there will be in excess of 4.3 million EVs connected by the 2040s in SEPD and over 800,000 in SHEPD within the same time period. The UK Government’s commitment to stop the sale of petrol and diesel engine vehicles by 2030 is a huge contributory factor. The switch of domestic and non-domestic heating to electric heat pumps is less certain, however there is still expected to be substantial uptake across both licence areas (c. 1.7 million properties in SEPD and c. 700,000 properties in SHEPD) in some of the DFES scenarios. In addition, some 600,000 new houses are expected to be built in SEPD and around 112,000 in SHEPD across all scenarios by 2050.

It is not certain how LCT uptake will take shape throughout ED2 however, it is expected that we will start to see the changes in demand patterns from customer LCT uptake, and some areas of network will approach, reach or even exceed thermal capacity limits during the ED2 price control period.

Overloaded circuits and inadequate asset ratings can lead to supply interruptions for customers. This can also result in failure to comply with licence obligation associated with planning security standards. If not managed effectively it may also introduce safety and/or environmental consequences for network customers and SSEN employees.

4.3.1 Cables and overhead line capability

To ensure that HV feeders have adequate capacity to meet the growing system demand, and also comply with the necessary industry standards during RIIO-ED2 period, HV conductors need to be capable of withstanding

3 ENA Engineering Recommendation P2, Issue 7, 2019, Security of Supply 4 It should be noted that EREC P2/7 is not applicable to individual end customers and so specific solutions can be designed as per customer requirements. 5 Based on DFES 2020 Southern England licence area Results and Methodology Report, December 2020 https://www.ssen.co.uk/WorkArea/DownloadAsset.aspx?id=20282 and DFES 2020 North of Scotland licence area Results and Methodology Report, December 2020 https://www.ssen.co.uk/WorkArea/DownloadAsset.aspx?id=20283 .

https://www.ssen.co.uk/WorkArea/DownloadAsset.aspx?id=20282

https://www.ssen.co.uk/WorkArea/DownloadAsset.aspx?id=20283

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the maximum foreseeable current under the specified conditions and loading pattern. This maximum loading must not cause the conductor temperature to exceed its maximum permitted value. An intervention is triggered where a shortfall is identified in the conductor current-carrying capacity. For example, where the load is expected to exceed the rating of the cable, or overhead line, conductor load rating. Whilst such intervention can often end up involving conventional network reinforcement, this is only after full consideration of alternative solutions, such as the use of flexibility services or demand-side response.

In the event of a short circuit occurring on the network, such as a phase-to-phase fault on a cable, or a phase-to-earth faults on an overhead line, the limiting factor is usually the maximum permitted temperature of the phase conductor or conductor insulation. Whereas for earth faults on lead sheathed cables, it may be the maximum temperature rise of the lead sheath itself which determines the circuit rating. In all cases, the network cables and overhead lines must be capable of operating safely during fault conditions until such time as the circuit protection devices operate to disconnect faulty parts of the system.

4.4 HV feeder faults from thermal overload

The thermal rating of cables and overhead lines is usually based on the maximum conductor temperature which can be sustained safely without causing damage or detriment. Overloading causes conductor temperature to rise. Although extended overloading will often lead to cable and overhead line failure, conductors and insulation can usually withstand much higher temperatures, and therefore higher loading, for short period of time. Failure of underground cables is costly and time-consuming, with repair or replacement often leading to extended customer outage times. In some cases, excess loading of overhead lines can cause lines to sag lower than permitted – breaching ground and building safety clearance distances.

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5 RIIO-ED2 Load Forecast

In order to understand the future pathways for LCT demand on our HV and LV network, SSEN has carried out extensive scenario studies – the Distribution Future Energy Scenarios (DFES). The basis for this work is National Grid’s Future Energy Scenarios (FES) 2020. This framework comprises four potential pathways for the future of energy based on how much energy may be needed and from where it might come. The variables for the four scenarios are driven by government policy, economics and consumer attitudes related to the speed of decarbonisation and the level of decentralisation of the energy industry. We have worked closely with our partner Regen to develop the forecasts between 2020 and 2050 through enhanced engagement with the local authorities, local enterprise partnerships, devolved governments, community energy groups and other stakeholders.

A high granularity projection has been produced for LCT uptake in both the North and South SSEN licence areas; this has been done down to the level of secondary distribution transformers and to individual LV feeders. This level of granularity corresponds to post code or street level. A bottom-up assessment of local resources, constraints and market conditions has been carried out to develop the four scenario forecasts for each technology. Locational data and GIS analysis have been used to understand the potential for technologies to develop through geographical distribution, local attributes, and constraints. The key LCT expected to increase the electricity demand on HV network are electric vehicle chargers and electricity-fuelled heating technologies (air source and ground source heat pumps, hybrid heating and direct electric heaters).

Based on the enhanced stakeholder engagement feedback, we have chosen Consumer Transformation as a credible baseline scenario on which to base our maximum demand projection for ED2. In order to protect our customers against the costs of forecasting uncertainties, our ex-ante baseline funding only includes load related investment required in the first two years in the RIIO-ED2 period unless it is also required by other net zero scenarios. Full details on our DFES methodology, stakeholder input and regulatory treatments of load related investment can be found in the Load Annex to the ED2 Business Plan6.

Detailed DFES datasets have allowed us to model the potential impact of demand and technology changes on the HV network and to understand the scale and range of network reinforcement that might be needed during RIIO-ED2.

With approximately 57,290km of HV circuits across our two licence areas, it is unviable to model and technically assess our entire HV network. Therefore, we took the approach to identify areas or ‘hotspots’7 of concern that see potential overloading issues in the ED2 period. Using the forecast load of the HV feeders, we checked this against the thermal rating of the first section of the mains circuit.

To identify the existing peak demand/baseline load, we have used the half-hourly measurement data available at the majority of our HV circuit breakers. A key assumption has been to use the winter cyclic ratings on the basis that the majority of SSEN HV feeder load peaks during the winter period.

With the baseline load calculated as described, we have added the Consumer Transformation scenario forecast demand drawn from the DFES work. Through comparison of forecast loading to circuit rating, we identified an initial hotspot list of 300 HV circuits with potential risk of thermal overload in the ED2 period. We have modelled these on power flow analysis software (PSS Sincal) to assess thermal, voltage and fault level. These assessments have been carried out for normal operating conditions, highlighting the system constraints and limitations by year. The load on each distribution transformer has been diversified to meet the associated HV

6 Load is covered in ED2 Business Plan Chapter 11 and Annex A12. 7 The methodology to identify hotspots is available in RIIO-ED2 Business Plan, Load Annex (A12), Section 5

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feeder maximum demand. We have identified approximately 345km of HV circuits that require intervention in ED2 as a result of thermal capacity constraint.

To identify areas of the network where the fault level exceeds the conductor fault level rating a fault level assessment has been undertaken based on the worst fault-level case (maximum demand/maximum generation) in the event of three phase fault occurrence. Any fault levels which have been identified to be in excess of the conductor fault level rating has been considered for intervention. We identified 93 HV circuits that require such intervention due to fault level constraints.

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6 Optioneering

This section sets out the investment options that are being proposed to manage HV feeder asset class in ED2. Section 6.1 describes our holistic approach taken to address thermal constraints and Section 6.2 describes our approach to mitigate fault level non-compliance. Our reinforcement approaches ensure investment options are chosen which are both least regrets and represent best value-for-money for network customers.

We have additionally considered the potential for using Whole Systems solutions (involving collaboration with third parties) to deliver this investment programme. We set out our Whole System assessment process in Appendix 3 of this EJP. This follows our standard approach for embedding Whole Systems consideration into our load and non-load investment decisions (in line with Ofgem’s ED2 business plan guidance), as described in our Enabling Whole System Solutions business plan annex8.

Our assessment enables us to take a proportionate consideration of Whole System options, based on the feasibility of such options existing and materiality of the costs involved.

In this case, our Whole Systems assessment finds that this programme is not expected to have any immediate wider Whole Systems interactions and we have not identified any Whole Systems solutions or opportunities at this moment in time. Our Whole Systems process will ensure that this situation is kept under continual review.

6.1 Secondary Reinforcement

Conventional (constructed) network solutions and flexibility services are alternative potential solutions to alleviate network thermal overloads.

Network Solutions increase network capacity but do not specifically aim to reduce peak demand. An example includes upgrading with larger cross-sectional area conductors.

Flexible Solutions aim to reduce peak demand, either by shifting energy consumption out of peak demand periods or by reducing energy consumption overall. Encouraging local generation of power to offset demand – particularly at times of peak – can also be an effective means of matching supply and demand and avoiding or postponing conventional circuit reinforcement. Demand side response, energy storage systems, time of use tariffs, hybrid heat pumps and smart electric vehicle charging schemes are all sources of flexibility service.

6.1.1 Summary of Options

Error! Reference source not found. below provides a high-level summary of the investment options under consideration along with the advantages and disadvantages associated with each.

Option Description Advantages Disadvantages

1. Do Minimum

Load Shift. utilise network back-feed capability when required to provide additional capacity

- Short-term expenditure reduction

- No civil cost required

- Limited spare capacity for additional load

- Increased network losses

- Risk of EREC P2/7 non-compliance

- Accelerate deterioration of

8 Our approach to Whole Systems is presented in more detail in Chapter 14 and Annex A18.

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assets health and lifespan

2. Conductor Upgrade

Replace existing conductor with higher rated conductor

- Increased Network Capacity

- Meet licence obligations and industry standard compliance

- Readiness to accommodate EVs and HPs uptake.

- Improvement in asset lifetime

- High expenditure - Potential disruption

to network stakeholders

- Civil costs required. - Additional carbon

footprint

3. Feeder Split Additional feeder to reduce load

- Improved network capacity

- Reduced disruption to network customers and stakeholders

- Improvement in asset lifetime

- Additional expenditure

- Potential disruption to network stakeholders

- Civil costs required - Additional carbon

footprint

4. Flexibility Procurement

The procurement of flexibility services from network customers to defer/avoid feeder uprating

- Defer expenditure required to upgrade circuit

- Increased efficiency

- Supports development of third-party flexibility markets and the transition to DSO

- Reduces the risk associated with increased maintenance

- The flexibility market on HV Level is still uncertain.

- The price point for flexibility services is often uncompetitive when compared to conventional solutions

- Limited market liquidity in various regions of the SSEN network.

Table 3 Summary of CV2 Secondary Reinforcement Investment Options

6.1.2 CBA Analysis Summary

A detailed exercise has been undertaken to support the investment strategy that is described within this EJP. A Cost Benefit Analysis has been undertaken to determine how we should invest in the HV feeder portfolio in ED2. Three CBA options have been considered: feeder split; Upgrading conductors and flexibility procurement. The preferred option has been found to be upgrading conductors, due to lower capital cost of underground cables and overhead lines in comparison to other options.

However, the option to reinforce all identified overloaded assets has been found to be implausible solution at this stage, as it will not align with our Business plan ambition and DSO objectives. To manage the whole

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portfolio, recognising that a single CBA is not sufficient to reflect the investment needs of the assets, we have taken an investment strategy approach based on lessons learned from innovation projects executed during RIIO ED1. Our proposed investment approach is described below (sub-sections 6.1.3 and 6.1.4).

For HV feeders loaded at 100% or above, the following approach have been proposed to reflect the best value-for-money to customers and the most efficient way to ensure the HV network is equipped to support the expected demand growth in ED2 and beyond. The proposed investment strategy has the following stages:

6.1.3 Stage 1: Flexibility solution to defer investment

A key solution that will be implemented during the ED2 period is the procurement of flexibility services and this is reflected in our Flexibility First approach. This approach will be a key enabler of SSEN’s aspiration to have distribution system operation capabilities. These flexibility services will be procured to defer or avoid the need to carry out costly network reinforcement and investment in network assets. The flexibility services to be procured in ED2 is expected to include smart charging of EVs, local generation and demand side response services and customer time of use tariffs. Further details of our approach to flexibility can be found in the flexibility Appendix to our DSO Annex9.

It is likely that Flexibility Services will mature significantly within the price control period and as such be applicable for a greater percentage of schemes, however at this stage we are taking a moderate view of roll-out capabilities. Whereas 10% of the HV feeders noted as being loaded to 100% or more in ED2 will be suitable for flexibility service procurement. Of that 10%, flexibility services will manage load growth and peak demands such that investment can be deferred to ED3 on half of these circuits (i.e., 5% of the total number of overloaded HV feeders) in ED2. The other half of these 10% of circuits are forecasted to require investment after two years10 because demand growth has exceeded the amount of flexibility capacity that can be procured in the area; and/or ongoing flexibility service costs no longer offer better value to customers than investment.

Deploying flexibility has significant potential to reduce investment needs, unlocking savings for consumers. The scale of these savings has been estimated below in Table 4 based on the avoided cost of asset replacement during ED2 from the use of flexibility schemes we have put into our baseline proposals, as well as the time value of benefit obtained from deferring for two years.

Deferred out of ED3 Time value of money of

other deferrals Total

SEPD benefit (£m) 0.38 0.03 0.41

SHEPD benefit (£m) 0.83 0.06 0.89

SSEN benefit (£m) 1.21 0.08 1.29

Table 4 Benefit Estimation of Flexibility Deployment

Furthermore, flexibility procurement has the following potential for load and non-load related purposes:

▪ Reduces the rate of asset degradation by reducing peak network loading (thermal strain) on high-risk assets.

9 RIIO-ED2 Business Plan, DSO Annex A21 10 Two years is the typical lead-time for assessment and development stages within SSEN investment framework. Also, it provides enough opportunity to assess the demand profile of the asset under study.

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▪ Allows DNOs to secure the network prior to planned outage events, in some cases avoiding the need for mobile diesel generation support.

It is possible that HV flexibility services can be procured on a larger scale during ED2 however, since the market is still uncertain, SSEN is taking a moderate view of roll-out capabilities at this stage.

To ensure that no opportunities are missed, and in line with our Flexibility First approach, we will perform a CBA for all schemes and for HV Feeders which are identified as having potential for flexible solutions, we will carry out Flexibility market tests to establish the cost, location and technical capabilities of the available flexibility before making a final decision on the optimum option to progress.

If the market test is successful, a Flexibility Solution will be employed offering value to SSEN and our customers in terms of investment deferral and optionality. Should the market test fail or only partially succeed in identifying the required Flexibility, SSEN will utilise the CEM Framework or alternative CBA mechanism to assess the optimal, secondary solution for this location, be that a further market test for full Flexibility, accelerating the Conventional solution or a Hybrid Scheme.

Should flexibility only offer time-limited benefits, after two years assets will be reinforced. we have made the decision to reinforce all constrained conductors with the maximum size cable or OHL conductor that does not incur significant additional expense. For instance, OHL routes may be strung with a thicker diameter conductor, but at a particular threshold of conductor size work would be required on the towers, significantly changing the economics of the approach. The proposed reinforcement offers better network capacity, reliability, and value for money for customers. All asset reinforcement aligns with SSEN’s Losses Strategy. The HV cables for network extensions/reinforcement are selected to ensure that there is no derating of the existing overall circuit and are to be of an approved design.

6.1.4 Stage 2: Asset reinforcement

The solution is to reinforce the constrained sections of HV feeders with a higher rated conductor that will increase network capacity, enhance network reliability, and facilitate the transition to electrification of transport and heat. It will also support our Losses Strategy11, where the network shall be designed to minimise system losses.

Based on the proposed HV feeders investment strategy, it is assumed 90% of the 100%+ loaded HV feeders will require reinforcement in ED2 to mitigate overloading and provide spare capacity for LCT uptake.

As noted above, we have made the decision to reinforce all HV feeders constrained sections with the maximum size cable or overhead conductor to provide better network capacity, reliability, and value for money for customers in the long-run. The marginal cost of installing larger conductor or cable is less than the marginal benefit associated with losses reduction and with the potential future costs of further upgrade – particularly for underground cables where the cost and inconvenience of excavation and installation can be significant. This supports our ‘once touch to net zero) approach.

6.2 Fault Level Reinforcement

To address HV circuits fault level non-compliance, it is proposed to reinforce affected HV feeders’ sections with higher fault level rated conductors. SSEN’s planning standard requires that the two seconds (2s) short circuit ratings shall be used. For fault level reinforcement of cables, the actual size of cable should be rated to the 2s fault level + 20 % to allow for future increase in fault levels. This also applies to conductors used for earthing

11 SSEN Distribution’s RIIO-ED1 Losses Strategy, March 2021

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installations. This will ensure that the assets are operating within the permissible fault level ratings (fault level compliant) and safe for our operational staff and the public.

7 Analysis and Cost

Our draft RIIO ED2 Business Plan costs are derived from our outturn RIIO ED1 expenditure. We have modified costs per activity, capturing and reporting those adjustments in our cost-book. By tying our costs back to reported, outturn, real life data this approach provides multiple data points on which both the Regulator and we can benchmark cost efficiency. It provides a high level of cost confidence in our Business Plan cost forecast for RIIO ED2.

Unlike asset replacement, load projects will include more unique and site-specific costs. For example; civils, waterway, road or rail crossings; and local planning considerations. Many years ahead of delivery, projects are not fully designed. We have therefore reflected the cost impact of this future scope refinement within the adjusted unit costs we have applied. Further detail on our unit cost approach, cost efficiency and cost confidence for RIIO-ED2 can be found within our Cost & Efficiency Annex.

We expect that as our Business Plan continues to develop, project scopes and costs will be refined, especially with valuable stakeholder feedback on our draft proposals. In our final Business Plan submission in December our cost forecasts will contain that refinement and the changes captured within our supporting Plan documentation. Development of our Commercial Strategy and updated project scope for the initial year of RIIO ED2 is expected to drive much of this refinement.

This section of the report provides an overview of the volumes and costs associated with the proposed HV feeder investment approach in ED2.

7.1 SEPD Costs and Volumes

Table 5 provides details costs and volumes for HV feeder investment in the SEPD licence area of SSEN for ED2. It should be noted that in Table 5 and Table 6 the costs of secondary reinforcement include those where flexibility has been used to defer investment by two years.

Asset Reinforcement Unit 2024 2025 2026 2027 2028 Total

6.6/11kV Overhead Lines km 5.3 8 22.4 12.7 2.8 51.2

6.6/11kV Underground Cables km 4.1 6.8 15.2 11.4 3.7 41.2

Table 5 SEPD HV Feeders Secondary Reinforcement Volumes


6.6/11kV Overhead Lines £m 0.24 0.36 1.01 0.57 0.12 2.29

6.6/11kV Underground Cables £m 0.81 1.34 2.99 2.24 0.74 8.11

Table 6 SEPD HV feeders Secondary Reinforcement Costs

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For HV/LV flexibility service procurement, SSEN has taken guidance from recent HV/LV flexibility tenders run by other UK DNOs and the assumed cost of this is £47.58/kW/year12. Based on the number of feeders and the required flexibility capacity, the costs and volumes of HV flexibility for SEPD in ED2 is presented in Table 7 and Table 8Table 8.

Flexibility 2024 2025 2026 2027 2028 Total

Number of feeders (unit) 2 2 3 2 2 11

Length of feeders sections (km)

0.70 0.70 1.05 0.70 0.70 3.86

Table 7 SEPD HV Feeder Flexibility Volumes


Capacity required (MVA) 2 2 3 2 3 13

Cost of procuring capacity (£m)

0.18 0.20 0.32 0.24 0.26 1.19

Table 8 SEPD HV Feeder Flexibility Costs

Table 9 and Table 10 present the volumes and costs for HV feeders fault level reinforcement for SEPD in ED2.

Asset Type Unit 2024 2025 2026 2027 2028 Total

Number of Circuits # 19 21 16 17 20 93

6.6/11kV Overhead Lines km 32 33 31 39 42 177

6.6/11kV Underground Cables km 16 18 20 12 9 75

Table 9 SEPD HV Feeder Fault Level Reinforcement Volumes

12 Assumed flexibility cost at HV and LV is different from than for EHV.

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Table 10 SEPD HV Feeder Fault Level Reinforcement Costs

7.2 SHEPD Costs and Volumes

Table 11 and Table 12 provides costs and volumes for HV feeder investment in the SHEPD licence area of SSEN for ED2. It should be noted that in Table 11 and Table 12 the costs of asset reinforcement include those where flexibility has been used to defer investment by two years.


6.6/11kV Overhead Lines km 25.7 0.4 4.2 4.9 8.3 43.6

6.6/11kV Underground Cables km 15 8.2 2.1 2.1 2.3 29.8

Table 11 SHEPD HV Feeder Asset Reinforcement Costs




Table 12 SHEPD HV Feeder Asset Reinforcement Costs

For HV/LV flexibility service procurement, SSEN has taken guidance from recent HV/LV flexibility tenders run by other UK DNOs and the assumed cost of this is £47.58/kW/year. Based on the number of feeders and the required flexibility capacity, the costs and volumes of HV flexibility for SHEPD in ED2 is presented in Table 13 and Table 14.

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Number of feeders (unit)

1 2 2 2 1 8

Length of feeders sections (km)

6.12 4.46 0.03 0.43 0.06 11.1

Table 13 SHEPD HV Feeder Flexibility Volumes


Capacity required (MVA) 0.02 0.05 0.11 0.11 0.06 0.35

Cost of procuring capacity (£m)

0.00 0.00 0.01 0.01 0.01 0.03

Table 14 SHEPD HV Feeder Flexibility Costs

The network in the North (SHEPD) and the South (SEPD) are different, which necessitates different approaches to reinforcement. The nature of the network in the South is such that there is a high degree of interconnection, whereas in the North there are long radial circuits and a high number of subsea cables feeding the islands that surround the North of Scotland.

For HV circuits reinforcement, standard design parameters are assumed at this stage and therefore unit cost i.e. cost per km is only used for comparison purposes. Each cable overlay/OHL re-conductor scheme brings its own challenges and must be designed as an individual project. The cost to reinforce a cable/OHL is split in to two parts which are cost to design replacement work (approximately 10%) and cost to undertake physical work (approximately 90%). For more details on physical work breakdown, please refer to Appendix 2: Underground Cables Reinforcement Cost Breakdown

8 Deliverability and Risk

Our deliverability strategy detailed in Chapter 16 of the Business Plan describes our approach to evidencing the deliverability of our overall plan as a package, and its individual components. Testing of our EJPs has prioritised assessment of efficiency and capacity, and this has ensured that we can demonstrate a credible plan to move from SSEN’s ED1 performance to our target ED2 efficiency. We have also demonstrated that SSEN’s in house and contractor options can, or will through investment or managed change, provide the capacity and skills at the right time, in the right locations. This assessment has been part of the regular assessment of our EJPs, CBAs and BPDTs, and we will further refine our bottom up efficiencies and work plan phasing for our final submission in December through the ongoing development of our ED2 Commercial & Deliverability Strategy and engagement with our supply chain.

Our deliverability testing has identified a major strategic opportunity which is relevant to all EJPs.

▪ In ED2 SSEN will change the way Capital Expenditure is delivered, maximising synergies within the network to minimise disruptions for our customers. This is particularly relevant for a Price Control period where volumes of work are increasing across all work types.

▪ The principle is to develop and deliver Programmes of work, manage risk and complexity at Programme level and to develop strategic relationships with our Suppliers and Partners to enable efficiency realisation.

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▪ The Commercial strategy will explore the creation of Work Banks (WB) and identify key constraints. The Load work will be the primary diver for a WB, supplemented by Non-Load work at a given Primary Substation. This approach will capitalise on synergies between the Load and Non-Load work, whereby the associated downstream work from a Primary Substation will maximise outage utilisation, enabling the programme to touch the network in a controlled manner with the objective of touching the network once. Where there is no Primary Load scheme to support the Non-Load work, these will be considered and packaged separately, either insourced or outsourced dependant on volume, size, and complexity.

▪ Transparency with the Supplier in terms of constraints, challenges, outage planning and engineering standards will capitalise on efficiencies, supported by a robust contracting strategy.

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9 Conclusion

The purpose of this Engineering Justification Paper (EJP) is to set out the overarching investment strategy that SSEN intends to take during RIIO ED2 for the load related investment of HV feeders including underground cables and overhead lines.

To address thermal capacity constraints due to LCT uptake during RIIO-ED2 price control period, conventional and flexible solutions are considered as potential interventions that will depend upon the attributes of each HV circuit project requiring investment (rate of load growth, flexible market availability, etc.). During RIIO ED2 a detailed Cost Benefit Analysis (CBA) will be used on a case by case basis to identify which option represents best value for money for network customers and can be considered least regret.

As described within Section 6, a holistic approach has been taken to establish the HV feeder secondary reinforcement investment strategy. This included a hot spot analysis of SSEN’s existing HV and LV networks, future network trend analysis and careful consideration of the financial, safety, and environmental implications of each investment option. The proposed investment strategy to manage HV feeders secondary reinforcement during RIIO-ED2 is as follows:

▪ Stage 1: Flexible solution to 10% of identified overloaded HV feeders for two years, where 5% of these feeders will have investment deferred to ED3 and conductor upgrade to 5% of identifed overloaded HV feeders

▪ Stage 2: Conductor upgrade will be carried out on 90% of identified overloaded feeders

The stages listed above have been assessed against RIIO ED2 strategies as follows: meeting licence obligations, steady performance, and leading reliability.

The total cost of £18.8 million to deliver the proposed HV feeders secondary reinforcement needed during RIIO ED2. The delivery of the proposed investment strategy will be a key in enabling the achievement of our strategic ambition to facilitate the connection of 1.3m EVs and 800,000 heat-pumps by the end of ED2. As well as releasing capacity and enabling the connection of LCT, our investments will also provide further benefits to consumers. These include a positive impact on long-term network reliability associated with the number and duration of supply interruptions.

Our ex-ante baseline allowance proposal for fault level reinforcement work will enable 93 fault level constraints to be resolved in the ED2 period for a total cost of £22.7million. Consumers will benefit from these interventions on the network, which result in no assets operating with fault level operational restrictions and no safety hazards for operational staff and the public.

The delivery of both these schemes will be measured throughout RIIO-ED2 by the volumes delivered, and the reduction of CI/CML’s.

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Appendix 1: Technical Specifications and Data

Definitions

Rural Feeder Customers (no more than 2,000 customers on main line) interconnected by mainly overhead line and some underground cable.

Urban Feeder Customers (no more than 2,000) interconnected via underground cable only

Underground Cables

Underground cable conductors have robust insulation to withstand high voltage, protect cable from mechanical damage and to ensure safety of operational staff. SSEN existing HV network comprises different technologies of underground cables as follows:

• Aluminium or copper paper insulated, lead covered, steel tape/steel wire armoured construction (PILCSWA/PILCSTS/PILCSTA)

• Aluminium paper insulated, concentric aluminium sheath (PICAS)

• Cross-linked polyethylene (XLPE)

The physical environment (i.e ground condition; direct/duct laid; spacing and depth) where the cable is buried has a significant impact on the cable electrical performance. Therefore, the effect of derating factors arising from grouping or ducting are always considered at design stage or assessment of existing cable rating. Underground cables have an advantage over overhead lines in reducing visual impacts and threat to sensitive habitats. The capital cost depends on cable type; length; ground conditions; method of installation; and cable rating.

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Appendix 2: Underground Cables Reinforcement Cost Breakdown

The cost to replace a cable is split in to two parts:

- Cost to design replacement work (approximately 10%) - Cost to undertake physical work. (approximately 90%)

It is worth stating and noting that each cable overlay scheme brings its own challenges and has to be designed as an individual project and therefore unit cost i.e. cost per km is only used for comparison purposes. In designing a replacement scheme the following steps are undertaken;

1. Cable overlay route selection 2. Other utilities plant and equipment survey 3. Local Authority engagement for work consents, notifications etc. 4. Identification of enroute engineering difficulties such as crossing of roads, canal, culverts etc. 5. Liaison with other utilities for Telecom, Gas, Water, Cable TV, plant coordination 6. Traffic management 7. Engagement with customers for excavations in private property 8. Continuity of supplies during construction work 9. Location of joints 10. Possibility of replacing service cables due to access issues 11. Customer liaison 12. Customer specific reinstatement requirement 13. Services to blocks of flats

The above elements account for about 10% of the cost

The physical cost of undertaking cable overlay work includes the following:

1. Work mobilisation which includes site set up and CDM compliance cost 2. Material cost of replacement cable 3. Diversion cost for other utilities apparatus when other plant is in close proximity. 4. Excavation, backfill and reinstatement cost 5. Generation costs to keep continuous supply to customers during construction work 6. Lane rental charges by local authorities

The above elements account for 90% of the total cost of a cable overlay project

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Appendix 3: Whole Systems consideration

In augmenting our decision-making processes to consider Whole System solutions, we have introduced an assessment to identify where a Whole Systems CBA would be a useful decision making tool for ED2 load and non-load schemes. While our work with the ENA to undertake Whole Systems CBAs is ongoing, we have introduced the ‘Whole Systems CBA test’ to identify where a scheme may be suitable for a Whole Systems CBA to be conducted. Where a Whole Systems CBA is determined to be a useful decision-making tool, these would be conducted in addition to the standard Ofgem CBA and/or SSEN’s flexibility CBA. We have introduced this test in line with Ofgem’s expectations for “proportionality when submitting a Whole System CBA. For example, smaller or simple projects following the standard CBA template, whereas larger or more complex projects requiring bespoke analytical approaches” (Ofgem BPG, section 4.28, p.34).

The ‘Whole Systems CBA test’ involves assessing each investment scheme of over £2m (the threshold to develop an EJP for load and non-load investments) against 5 tests. These 5 tests help determine whether a Whole Systems CBA is a useful decision-making tool based on the characteristics of the scheme, including whether it will have wider cross sector or societal impacts.

Details on each of the tests are provided in case study 6 in our Enabling Whole System Solutions business plan annex. Tests 1-3 are aligned with the ENA’s guidance for Whole System CBA tests. We have added Tests 4 and 5 to clarify whether a Whole Systems CBA is required based on the materiality / proportionality of the investment (Test 4) and whether a flexibility CBA only is sufficient (Test 5). Table 15 below outlines our Whole Systems CBA test for HV circuits investment.

Scheme

Test 1: Are there Whole

Systems interactions,

or is there potential for

it?

Test 2: Could a Whole

Systems CBA drive you to

make a different decision?

Test 3: Is a Whole

Systems CBA reasonable?

Test 4 - Is the project valued at

over £2m?

Test 5 - Is the investment plan related to procuring

flexible solutions

only?

HV Feeders

No – We consider there to be limited potential for

Whole Systems

interactions with third parties to

deliver this investment

programme, and

accordingly we do not

consider there to be potential

for Whole

No – As noted under Test 1 we do not consider there to be

potential for Whole

Systems solution(s) in

this case.

No – As noted under Test 1

we do not consider there to be potential

for Whole Systems

solution(s) in this case.

No No

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Systems solution(s).

Table 15 Whole Systems CBA test for SSEN’s HV Circuits Investment

As the result of tests 1, 2 and 3 above is “No”, a Whole Systems CBA is not required for this investment. It is not expected to have any wider Whole System interactions or potential Whole Systems solutions.

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Appendix 4: Relevant Policy, Standards, and Operational Restrictions

The policies, manuals and standards and operational restrictions which govern the management of HV feeders are listed below in Table 16.

Policy Number Policy Name / Description

ENA Engineering Recommendation P2, Issue 7, 2019, Security of Supply

PR-NET-NPL-010 Planning Standards for 11 kV and 6.6 kV Distribution Networks

TG-NET-CAB-009 Load Ratings of LV to 33kV Underground Cables-Design Data

ST-NET-ENG-010 SSEN Distribution Network Investment Strategy RIIO-ED1

TG-NET-CAB-011 Short Circuit Ratings of 6.6kV to 33kV Underground Cables-Design Data

TG-NET-OHL-010 Load Ratings of Overhead Lines- Data Sheet

Southern Electric Power Distribution RIIO-ED1– 11kV/6.6kV High Voltage Cable Reinforcement & Low Voltage Cable Overlay Supporting Paper

Table 16 HV Feeders Relevant Documents